draft design memo gas turbine/engine comparison for ...camp dresser & mckee, inc. icq pringle,...
TRANSCRIPT
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City of
SFUND RECORDS CTR
88111802
AR0116
SFUND RECORDS CTR
1751-00030
Public Works Department
City Hall • 209-498-1461 2326 Fresno St., Rm. 101 Fresno, California 93721-1898
Marvin D. Johnson, P.E. Director
May 5, 1992
PUBLIC WORKS DEPARTMENT
Wayne Pickus Camp Dresser & McKee, Inc. ICQ Pringle, Suite 300 Walnut Creek, CA 94596
SUBJECT: ENCLOSED DRAFT DESIGN MEMO
Enclosed i s a copy of the promised "Draft Design Memo Gas Turbine/Engine Comparison for the L a n d f i l l Gas Project" for your information.
Questions may be directed to George W. Slater at (209)498-2618
Sincerely,
George W. Slater, Assis
GWS/frk/0617F
City of Fresno " ~
Landfill Gas Project
DRAFT " DESIGN MEMORANDUM
GAS TURBINE/ENGINE COMPARISON
John Carollo Engineers in association vi/ith
O'Rourke & Company
April 1992
W3529:DM AOO CasTurbtne/EngCoinp COV
Design Memorandum
GAS TURBINE/ENGINE COMPARISON
1.0 PURPOSE
The purpose of this design memorandum is to perform a comparison of reciprocating engines and gas turbines, both simple and combined-cycle, to determine which prime mover is the overall best choice for the landfill gas (LFG) fueled power generation facility (PGF).
2.0 BACKGROUND
The Fresno Regional Wastewater Facilities November 1991 LFG Project Final Report recommended performing an economic analysis and using a weighted screening analysis to compare four engine/generators, two simple-cycle gas turbine/generators and two combined-cycle gas turbine generators (with one steam turbine/generator). Selection of the number, size and type of prime mover is a necessary step which must precede application for Authority to Construct from the San Joaquin Valley Unified Air Pollution Control District (SJVUAPCD). Obtaining Authority to Construct is an important element on the critical path to implementing the PGF.
3.0 COMBINED-CYCLE GAS TURBINE/GENERATORS
The exhaust heat recoverable from one 3,000 kW Centaur T4500 gas turbine could be used to produce sufficient steam to generate an additional 1,000 kW in a medium pressure steam turbine. The steam conditions would be approximately 350 psig at a temperature of 550°F.
Because there is no additional heat input, the heat rate of combined cycle gas turbines is reduced to 9,825 Btus per kWh at full load, compared to 13,100 Btus per kWh for simple cycle gas turbines. Because there is no additional power required for gas compression and additional power requirements are smsill, the parasitic losses of combined-cycle gas turbines goes down to 9.3 percent, compared to 10.6 percent for simple-cycle gas turbines. Maintenance costs for both combined-cycle and simple-cycle gas turbine systems are both assumed to be $0,009 per kWh. Total annual maintenance costs are higher for combined-cycle systems because of their greater output.
3.1 Single Combined-Cycle Gas Turbine/Generator
Though not part of the November 1991 LFG report recommendations, a single combined-cycle gas turbine is also evaluated to determine its relative economic ranking. This altemative would consist of one 3,000 kW Centaur T4500 gas turbine on the vacant foundation in the existing PGF, a heat recovery steam boiler outside the existing PGF and a 1,000 kW steam turbine located In place of one of the existing engines.
W3529:DM AOO Ga^Tuiblne/EiigCoinp
Using digester gas (DG) and BFI LFG. the project cost of the single gas turbine combined-cycle altemative is $13,066,000 compared to $11,006,000 for a single simple-cycle gas turbine. The net present worth of the combined-cycle gas turbine is $9,424,000 versus $2,490,000 for a simple cycle gas turbine. As shown in Table 1, the three engine/generator altemative has higher net present worth than either single gas turbine altemative. The single combined-cycle gas turbine therefore, will not be evaluated further. A single gas turbine might be viable, however, as the first phase of a facility with two gas turbines.
3.2 Two Combined-Cycle Gas Turbine/Generators
This altemative would consist of two 3,000 kW Centaur T4500 gas turbines located In place of the two existing engines in the PGF, two heat recovery steam boilers outside the PGF and a 2.000 kW steam turbine on the vacant foundation.
Using DG City and BFI LFG, the project cost of two combined-cycle gas turbines is $20,112,000 compared to $17,021,000 for two simple-cycle gas turbines. The net present worth of two combined-cycle gas turbines is $26,153,000 versus $16,479,000 for two simple-cycle gas turbines and $18,282,000 for four engine/generators. Thus, the two combined-cycle gas turbines have the highest net present worth of all the prime movers. None of these altematives include selective catalytic reduction (SCR) to reduce NO^ emissions.
4.0 ALTERNATIVE SCREENING ANALYSIS
Three altematives are compared: four 1,700 kW engine/generators, two simple cycle 3,000 kW gas turbine/generators, and a combined cycle system with two 3,000 kW gas turbine/generators with one 2,000 kW steam turbine/generator. All three altematives are assumed to be fueled using DG plus City and BFI LFG without any supplemental natural gas.
4.1 Methodology
Seven criteria are used to compare altematives: project cost, net present worth, reliability, maintenance, operational flexlbUlty, building requirements and emissions. These criteria are chosen to insure that the altemative selection process is not solely Influenced by monetary factors and reflect all of the City's concems. A narrative comparison of the altematives using these seven criteria is presented in Table 2.
A screening matrix is used to integrate the seven criteria and is presented in Table 3. Relative weights are established for each of the screening criteria. A relative weight of 5 is assigned to those criteria considered very important. Conversely, a relative weight of 1 is assigned for those criteria considered least Important. The rating for each of the alternatives is then determined. A rating of 5 is considered good and 1 Is considered poor. Next, the scores for each screening criteria are calculated by multiplying the relative weight by the rating for each altemative. Then the scores for each altemative are added together to find the total score. The altematives are then ranked, with a ranking of 1 assigned to the altemative with the highest score and so on.
W3S29:0M AOO CasTuibtne/EngConip
4.2 Emissions
During preparation of the November 1991 LFG report, a meeting was held with the SJVUAPCD. Their preliminary position is that BACT for engines would be lean combustion technology incorporating precomblnation chambers. The District is less clear on the BACT requirements for gas turbines but leans towards SCR for removal of oxides of nitrogen (NO^) based on the requirements of the South Coast Air Quality Management District (SCAQMD). Ammonia injected into an SCR catalyst reacts with NO^ in the presence of the catalyst to form water vapor and nitrogen gas.
Addition of SCR technology would affect the economics of the gas turbine alternatives, therefore, an economic analysis of the SCR system, presented in Appendix C, was performed. The estimated project cost of an SCR system for one gas turbine is $1,000,000 or $2,000,000 for two gas turbines. Operation and maintenance costs include salaries, ammonia and catalyst replacement. As shown in Table 1, addition of an SCR system does not affect the highest ranking altematives.
4.3 Conclusions
Based on the finding presented In Tables 1, 2 and 3, the conclusions are as follows:
1. If one of the LFG sources is uncertain or unavailable, the three-engine altemative will provide the most benefit.
2. If both LFG sources are available, the combined cycle gas turbine altemative will provide the greatest benefit.
5.0 RECOMMENDATIONS
1. Expedite negotiations and execution of an agreement with BFI to purchase LFG from the BFI landfill
2. Meet with the City's solids waste division. City's landfill consultant and EPA to confirm availability of LFG from the City's landfill.
3. Upon successful completion of Recommendation Nos. 1 and 2, proceed with preliminary design of PGF based on combined cycle gas turbines including two-3,000 kW gas turbines and one-2,000 kW steam turbine.
If landfill availability from the City landfill is doubtful, base the preliminary design pn three 1,700 kW clean-bum engines.
W3S29:DM AOO GajiTuititne/EngCoinp
Table 1 Economic Analysis of Alternatives Without Supplemental Natural Gas City of Fresno
Criteria 3EG11J
Fuel Combination, Prime Mover Configuration DG -I- BFI LFG DG + City & BFI LFG
4EG11J 1 IGT-i- 1ST 2GT+1ST
Project Cost^^^ Without SCR With SCR
Net Present Worth f2) Without SCR With SCR
Score^^J Without SCR With SCR
Ranking by Score^^' Without SCR With SCR
Ranking by Net Present Worth ^^ Without SCR With SCR
$14,786 $11,006 14.786 $12,066
$14,810 ^ $2,490 527
2.00 1.23 1.05
3 3
3 3
$13,066 $14,066
$9,424 7.461
1.72 1.57
2 2
2 2
$20,940 $20,940
$18,282
1.87
3 2
2 2
$17,021 $19,021
$16,479 12.553
1.97 1.74
2 3
3 3
$20,112 $22,112
$26,153 22,227
2.30 2.11
1. Based on November 1991 LFG Report, Table 5.4 2. In thousands of dollars. See Appendix A for cost breakdown. 3. Besl=largest number. Score=(net present worth + project cost)/project cost.) 4. Best=smallest number. NR=not recommended. Each fuel combination ranked separately.
(3 » o
I
3
Ol
Table 2 Altemative Comparison City of Fresno
Prime Mover Configuration Criteria 4EG 2GT 2GT+1ST
Project Cost High Lowest-best High
Net Present Worth Lower Lowest-worst Highest-best
Reliability Most, more proven in field. Intermediate Least, interdependent systems
Maintenance Best, trained personnel readily available.
Intermediate, longer repair times, cost may be higher.
Worst, requires multiple specialty training longer repair.
Operational Flexibility Best, more units provides greater flexibility.
Worse, fewer units, efficiency drops off sharply at part load (if less available In future).
Worse, fewer units, efficiency drops off sharply at part load (if less fuel available in future). No system responsibility.
Building Requirements Worst, PGF needs to be enlarged.
Better, fits in existing PGF. Better, fits in existing PGF.
Emlssions/Permittablllty Best, standard lean-bum technology satisfactory to SJVUAPCD as BACT
Worse, may require SCR-Increases project and O&M cost, lowers net present worth.
Worse, may require SCR-increases project and O&M cost, lowers net present worth.
Table 3 Screening Matrix City of Fresno
Prime Mover Configuration Relative 4EG 2GT 2GT-I-1ST
Screening Criteria Welght^lJ R S R S R S
Project Cost 4 4 16 5 20 4 16
Net Present Worth 5 3 15 1 5 5 25
Reliability 5 5 25 4 20 4 20
Maintenance 4 3 12 4 16 3 12
Operational Flexibility 3 5 15 3 9 3 9
BuUding Requirements 3 3 9 5 15 5 15
Emisslons/PermittabUity 4 5 20 4 16 4 16
Total Score^^J 112 101 113
Ranking'^)
i
1 2 1
1. Relative Weight: 5=Most Important, l=Ieast Important. 2. Ratlng=R: 5=good, l=poor. 3. Score=S: Relative weight x rating. 4. Maximum achievable score = 140 5. Ranking: l=besl. 3=worst
Appendix A
COST ESTIMATES
W3529:DM AOOGasTuifatne/EngCompAPP A - 1
Table A.1 One Gas Turbine and Standby Generator Cost City of Fresno
Estlmate^^J
Item Quantity Installed
Cost
Gas Turbine/Generator Heat Recovery System Standby Generator Demolition Building Modifications Electrical
1 @ 3.500 kW 1
2 @ 2,000 kW
$ 2.700,000 501.000
1,100.000 300,000
62,000 600,000
Subtotal Estimating Contingency
$ 5,263,000 526.000
CONSTRUCTION COST $ 5,789,000
Engineering. Inspection, Construction Contingency Compressor Facilities & Transmission Pipeline Costs
1.737,000 3.480,000
TOTAL PROJECT COST « i ENR CCI 5740 $11,006,000
1. From November 1991 LFG Report Table A. 1.
Table A.2 Two Gas Turbines Cost Estlmate^ ) City of Fresno
Item Quantity Installed
Cost
Gas Turbine/Generators Heat Recovery Systems Demolition Building Modifications Electrical
2 @ 3,500 kW 2
$ 5,400,000 992,000 297,000 123,000
1.000.000
Subtotal Estimating Contingency
$ 7,812,000 781,000
CONSTRUCTION COST $ 8,593,000
Engineering. Inspection. Constmction Contingency Compressor Facilities & Transmission Pipeline Costs
2,578,000 5,850,000
TOTAL PROJECT COST i 5 ENR CCI 5740 $17,021,000
1. From November 1991 LFG Report Table A.2.
W3529:DM AOO CasTuibtne/EngComp APP A-2
Table A.3 Three Engine Cost Estlmate^ ) City of Fresno
Item Quantity Installed
Cost
Engine / Generators 3 @ 1,700 kW $ 5,625.000 Heat Recovery Systems 3 764,000 Demolition 596,000 Building Modifications 138,000 Electrical 1.000.000
Subtotal $ 8,123,000 Estimating Contingency 812,000
CONSTRUCTION COST $ 8,935.000
Engineering, Inspection, Constmction Contingency 2.681.000 Compressor Facilities & Tn msmlssion Pipeline Costs 3.170,000
TOTAL PROJECT COST @ ENR CCI 5740 $14,786,000
1. From November 1991 LFG Report, Table A.3.
Table A.4 Four Engine Cost Estimate ^^ City of Fresno
Installed Item Quantity Cost
Engine / Generators 4 @ 1,700 kW $ 7,500,000 Heat Recovery Systems 4 1,017,000 Demolition 596,000 Building Modification 138,000 Building E^xpansion 1,200 sq. ft. 279,000 Electrical 1,400,000
Subtotal $ 10,930,000 Estimating Contingency 1,093,000
CONSTRUCTION COST $ 12,023,000
Engineering, Inspection, Constmction Contingency 3,607,000 Compressor Facilities & Transmission Pipeline Costs 5.310.000
TOTAL PROJECT COST @ ENR CCI 5740 $20,940,000
1. From November 1991 LFG Fleport, Table A.4.
W3529:0M AOO CaaTuibme/EngComp APP A-3
Table A.5 One Combined Cycle Gas Turbine Cost Estimate^ ) City of Fresno
Item Quantity Installed
Cost
Gas Turbine/Generator 1 @ 3,000 kW $2,700,000 Heat Recovery Boilers 541,000 Standby Generators 2 @ 2,000 kW 1,100,000 Steam Turbine Generator & Condenser 1 @ 1.000 kW 1,160,000 Piping and Pumps for Combined Cycle 120,000 Demolition 300,000 Building Modifications 62,000 Electrical 720,000
Subtotal $6,703,000 Estimating Contingency 670.000
CONSTRUCTION COST $7,373,000 Engineering Inspection, Constmction Contingency 2.213.000
Compressor Facilities & Transmission Pipeline Costs^^^ 3.480.000
TOTAL PROJECT COST ENRCCI 5740 $13,066,000
1. Based on November 1991 LFG Report, Table 5.1 2. Based on November 1991 LFG Report, Table 5.2.
Table A.6 Two Combined Cycle Gas Turbines Cost Estimate -'-) City of Fresno
Installed Item Quantity Cost
Gas Turbine/Generator 2 @ 3,000 kW $5,400,000 Heat Recovery Boilers 1.052.000 Steam Turbine Generator & Condenser 1 @ 2,000 kW 1.720.000 Piping and Pumps for Combined Cycle 180.000 Demolition 297.000 Building Modifications 123,000 Electrical 1,200.000
Subtotal $9,972,000 Estimating Contingency 997,000
CONSTRUCTION COST $10,969,000 Engineering Inspection, Constmction Contingency 3,293,000
Compressor Facilities & Transmission Pipeline Costs^^^ 5,850.000
TOTAL PROJECT COST ENRCCI 5740 $20,112,000
1. Based on November 1991 LFG Report, Table 5.1 2. Based on November 1991 LFG Report, Table 5.2.
W3S29:DM AOO GatfTUifatne/En^inp APP A-4
Appendix B
ECONOMIC ANALYSIS SPREADSHEETS WITHOUT SUPPLEMENTAL NATURAL GAS
W3529:D.M AOOCaaTuibtne/EngCompAPP B - 5
One Combined Cycle Gas Turbine
ACTIVE CASE VARIABLES:
DESIGN OPTIONS:
Rated Capacity Availability Parasitic Loss Heat Rate
Salaries, Gen* L ft Adtnin 0*H t Overhaul Compressors Maintenance Fuel Costs: UUTP D.Gas HnBTUs/hr C i t y U f Gas MMBTUs/hr 6FI L/F Gas HMBTUs/hr N.Gas (PG&E) HMBTUs/hr
Total Est. Capital Costs: nS
CASE S
4,000 9O,00X 9.30;: 9,825
330,000 253,7U} 100,000
20.40 0.00 14.97 0.00
13,066
1% OOO's) Period:
Year: 1
1995 2
1996 3
1997 4
1998 5
1999 6
2000 7
2001 8
2002 9
2003 10
2004 11
2005 12
2006 13
2007 14
2008 15
2009 16
2010 17
2011 18
2012 19
2013 20
2014
CASE 5: 6T
4,000 kU CVar kU Productive Capacity (Net) HkUhrs Fuel Availability HhBTUs Production (fuel constrnOMkUhrs Fuel Rqjnt a HR 9,825 HHBTUs
UUTP BTUs/hr MHBTUs City LandfiU HHBTUs BFI MHBTUs
Other Fuel Purchases HHBTUs Elec. Energy Purchases HkUhrs Energy Purchases Displc'd HkUhrs Excess Energy Avail/Sale HkUhrs
4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 4,000 28,603 515,088 28,603
309,840 178,704
0 131,136
0 11,658 28,603
0
28,603 513,511 28,603
309,840 182,208
0 127,632
0 12,560 28,603
0
28,603 512,986 28,603
309,840 186,588
0 123,252
0 13,480 28,603
0
28,603 512,460 28,603
309,840 190,968
0 118,872
0 14,417 28,603
0
28,603 512,022 28,603
309,840 195,348
0 114,492
0 15,381 28,603
0
28,603 509,832 28,603
309,840 198,852
0 110,988
0 16,353 28,603
0
28,603 506,416 28,603 309,840 202,356
0 107,484
0 17,133 28,603
0
28,603 503,174 28,603 309,840 206,736
0 103,104
0 17,930 28,603
0
28,603 499,320 28,603 309,840 210,240
0 99,600
0 18,736 28,603
0
28,603 495,553 28,603 309,840 213,744
0 96,096
0 19,559 28,603
0
28,603 492,312 28,603 309,840 217,248
0 92,592
0 20,383 28,603
0
4,000 28,603 489,859 28,603 309,840 221,628
0 83,212
0 21,294 28,603
0
4,000 28,603 486,618 28,603 309,840 225,132
0 84,708
0 22,223 28,603
0
4,000 28,603 484,428 28,603 309,840 229,512
0 80,328
0 23,169 28,603
0
4,000 28,603 482,501 28,603 309,840 233,892
0 75,948
0 24,132 28,603
0
4,000 28,603 480,048 28,603 309,840 238,272
0 71,568
0 25,096 28,603
0
4,000 28,603 477,683 28,603 309,840 242,652
0 67,188
0 26,129 28,603
0
4,000 28,603 475,493 28,603 309,840 247,032
0 62,808
0 27,181 28,603
0
4,000 28,603 474,354 28,603 309,840 252,288
0 57,552
0 28,249 28,603
0
4,000 28,603 472,514 28,603 309,840 256,668
0 53,172
0 29,344 28,603
0
CLIENT: CITY OF FRESNO PROJECT: LANDFILL GAS PROJECT SUBJECT: ECONOHIC ANALYSIS OF DESIGN OPTIONS BATE: 09/19/91
TUENTY-YEAR PROFORHA BASIS:
CASE 5 4,000 kU / 90.00X Availability / 9.i07. Parasitic Loss cont'd.
Period: (S OOO's)
REVENUES:
ELECTRIC: Demand Energy Excess
15 TOTAL VALUE OF PGF:
OPERATING COSTS:
16 Salaries, G«A 17 0«H, PGF 18 04H, Compressors
Unit Fuel Costs: 19 UUTP D.Gas 20 City LF Gas 21 BFI LF Gas 22 PGSE Cogen Gas 23 Debt Svc on Exist Bonds
24 TOTAL OPERATING COSTS:
25 EST PROJECT VALUE: (13,066)
26 CUH PROJECT VALUE: 27 NPV a 28 IRR:
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 •2008 2009 2010 2011 2012 2013 2014
478 492 507 522 537 553 569 601 635 671 708 748 789 837 886 938 992 1,050 1,110 1,175 2,174 2,238 2,306 2,373 2,444 2,514 2,587 2,732 2,884 3,047 3,218 3,398 3,587 3,802 4,027 4,260 4,507 4,768 5,045 5,337
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
2,652 2,730 2,813 2,895 2,981 3,067 3,156 3,333 3,519 3,718 3,926 4,146 4,376 4,639 4,913 5,198 5,499 5,818 6,155 6,512
401 421 U 2 464 487 512 537 564 592 622 653 686 720 756 794 834 875 919 965 1,013 297 309 321 334 347 361 376 391 406 423 440 457 476 495 514 535 556 579 602 - 626 117 122 127 132 137 142 148 154 160 167 173 ISO 187 195 203 211 219 228 237 247
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
142 141 139 137 134 133 131 128 126 124 122 119 116 112 108 104 100 95 89 84 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
409 409 409 407 405 405 403 402 400 398 0 0 0 0 0 0 0 0 0 0
1,366 1,402 1,438 1,474 1,510 1,553 1,596 1,639 1,685 1,734 1,388 1,442 1,499 1,558 1,619 1,683 1,750 1,821 1,893 1,970
I 1,286 1,328 1,375 1,421 1,471 1,514 1,560 1,694 1,834 1,984 2,538 2,704 2,877 3,081 3,294 3,515 3,749 3,997 4,262 4,542
(11,780) (10,453) (9,077) (7,656) (6,186) (4,671) (3,111) (1,417) 417 2,401 4,939 7,64J 10,519 13,600 16,895 20,409 24,158 28,155 32,417 36,959 : (11,865) (10,705) (9,582) (8,498) (7,450) (6,440) (5,469) (4,483) (3,485) (2,477) (1,271) (70) 1,123 2,318 3,512 4,703 5,889 7,072 8,250 9,424
-90.16-/! -62.82X -41.73% -27.53X -17.85X -11.09X -6.19X -2.38% 0.60% 2.97% 5.19% 6.91% 8.28% 9.40% 10.32% 11.09% 11.73% 12.2r,i 12.74% 13.13%
CLIENT; CITY OF FRESNO PROJECT: UNDFILL GAS PROJECT SUBJECT: ECONOHIC ANALYSIS OF DESIGN OPTIONS DATE: 09/19/91
TUENTY-YEAR PROFORHA BASIS:
CASE 5 4,000 kU / 90.00% A v a i l a b i l i t y / 9.30% P a r a s i t i c Loss con t ' d .
P e r i o d : 1 2 3 4 5 6 7 8 9 10 11 12 13 • 14 15 16 17 18 19 20 ( t OOO's) Year : 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
DEBT SERVICE SCHEDULE:
29 Inc r . Capaci ty 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282 1,282
30 PROJECT NET CASH FLOUS: 4 46 94 139 189 233 278 413 552 703 1,256 1,422 1,595 1,799 2,013 2,233 2,467 2,715 2,980 3,261
31 CUH CASH FLOUS: 4 50 144 283 472 705 983 1,396 1,948 2,650 3,906 5,329 6,924 8,723 10,736 12,969 15,435 18,151 21,131 24,392 32 NPV a 7.00% 4 U 120 227 361 516 690 930 1,230 1,587 2,184 2,816 3,477 4,175 4,905 5,661 6,442 7,246 8,070 8,912
FORECASTED PURCHASED DEHAND OFFSETS
4000 kU UINTER PERIOD B SUHHER PERIOD A PERIOD B TOTAL PERIODS: TOTAL ANNUAL
YEAR RATES JAN FEB HAR APR HAY JUN JUL AUG SEP OCT NOV DEC A B (A * B)
1994 0 00 Peak Demand 0 0 0 0 0 0 0 0 0 0 0 0 S 0 0 1 0 S 0 00 Hax Demand 0 0 0 0 0 0 0 0 0 0 0 0 S 0 0 S 0 t
1995 12 53 Peak Demand 0 0 0 0 50,120 50,120 50,120 50,120 50,120 50,120 0 0 t 300,720 0 S 300,720 t 3 69 Hax Demand 14,760 14,760 14,760 14,760 14,760 14,760 14,760 14,760 14,760 14,760 14,760 14,760 t 103,320 73,800 t 177,120 i
1996 12 90 Peak Demand 0 0 0 0 51,600 51,600 51,600 51,600 51,600 51,600 0 0 % . 309,600 0 t 309,600 t 3 80 Hax Demand 15,200 15,200 15,200 15,200 15,200 15,200 15,200 15,200 15,200 15,200 15,200 15,200 S 106,400 76,000 S 182,400 % 1997 13 29 Peak Demand 0 0 0 0 53,160 53,160 53,160 53,160 53,160 53,160 0 0 S 318,960 0 i 318,960 S 3 92 Hax Demand 15,680 15,680 15,680 15,680 15,680 15,680 15,680 15,680 15,680 15,680 15,680 15,680 % 109,760 78,400 $ 188,160 s
1998 13 68 Peak Demand 0 0 0 0 54,720 54,720 54,720 54,720 54,720 54,720 0 0 % 328,320 0 S 328,320 s 4 03 Hax Demand 16,120 16,120 16,120 16,120 16,120 16,120 16,120 16,120 16,120 16,120 16,120 16,120 S 112,840 80,600 S 193,440 t
1999 14 09 Peak Demand 0 0 0 0 56,360 56,360 56,360 56,360 56,360 56,360 0 0 $ 338,160 0 t 338,160 i 4 15 Hax Demand 16,600 16,600 16,600 16,600 16,600 16,600 16,600 16,600 16,600 16,600 16,600 16,600 S 116,200 83,000 t 199,200 i
2000 14 50 Peak Demand 0 0 0 0 58,000 58,000 58,000 58,000 58,000 58,000 0 0 ( 348,000 0 $ 348,000 t 4 27 Hax Demand 17,080 17,080 17,080 17,080 17,080 17,080 17,080 17,080 17,080 17,080 17,080 17,080 t 119,560 85,400 S 204,960 t
2001 14 92 Peak Demand 0 0 0 0 59,680 59,680 59,680 59,680 59,680 59,680 0 0 i 358,080 0 S 358,080 4 39 Hax Demand 17,560 17,560 17,560 17,560 17,560 17,560 17,560 17,560 17,560 17,560 17,560 17,560 t 122,920 87,800 S 210,720 % 2002 15 76 Peak Demand 0 0 0 0 63,040 63,040 63,040 63,040 63,040 63,040 0 0 t 378,240 0 % 378,240 % 4 64 Hax Demand 18,560 18,560 18,560 18,560 18,560 18,560 18,560 18,560 18,560 18,560 18,560 18,560 t 129,920 92,800 t 222,720 t
2003 16 64 Peak Demand 0 0 0 0 66,560 66,560 66,560 66,560 66,560 66,560 0 0 t 399,360 0 i 399,360 t 4 90 Hax Demand 19,600 19,600 19,600 19,600 19,600 19,600 19,600 19,600 19,600 19,600 19,600 19,600 $ 137,200 98,000 S 235,200 % 2004 17 58 Peak Demand 0 0 0 0 70,320 70,320 70,320 70,320 70,320 70,320 0 0 ( 421,920 Q S. 421,920 t 5 18 Hax Demand 20,720 20,720 20,720 20,720 20,720 20,720 20,720 20,720 20,720 20,720 20,720 20,720 t 145,040 103,600 S 248,640 t
2005 18 56 Peak Demand 0 0 0 0 74,240 74,240 74,240 74,240 74,240 74,240 0 0 t 445,440 0 S 445,440 $ 5 47 Max Demand 21,880 21,880 21,880 21,880 21,880 21,880 21,880 21,880 21,880 21,880 21,880 21,880 t 153,160 109,400 % 262,560 s
2006 19 60 Peak Demand 0 0 0 0 78,400 78,400 78,400 78,400 78,400 78,400 0 0 i 470,400 0 i 470,400 i 5 78 Hax Demand 23,120 23,120 23,120 23,120 23,120 23,120 23,120 23,120 23,120 23,120 23,120 23,120 S 161,840 115,600 t 277,440 i
2007 20 69 Peak Demand 0 0 0 0 82,760 82,760 82,760 82,760 82,760 82,760 0 0 t 496,560 0 S 496,560 t 6 10 Hax Demand 24,400 24,400 24,400 24,400 24,400 24,400 24,400 24,400 24,400 24,400 24,400 24,400 t 170,800 122,000 $ 292,800 s
2008 21 93 Peak Demand 0 0 0 0 87,720 87,720 87,720 87,720 87,720 87,720 0 0 t 526,320 0 i 526,320 $ 6 47 Hax Demand 25,880 25,880 25,880 25,880 25,880 25,880 25,880 25,880 25,880 25,880 25,880 25,880 % 181,160 129,400 ( 310,560 s
2009 23 23 Peak Demand 0 0 0 0 92,920 92,920 92,920 92,920 92,920 92,920 0 0 % 557,520 0 S 557,520 t 6 85 Hax Demand 27,400 27,400 27,400 27,400 27,400 27,400 27,400 27,400 27,400 27,400 27,400 27,400 » 191,800 137,000 S 328,800 i
2010 24 58 Peak Demand 0 0 0 0 98,320 98,320 98,320 98,320 98,320 98,320 0 0 t 589,920 0 i 589,920 i 7 25 Hax Demand 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 29,000 S 203,000 145,000 S 348,000 t
2011 26 00 Peak Demand 0 0 0 0 104,000 104,000 104,000 104,000 104,000 104,000 0 0 S 624,000 Q % 624,000 i 7 67 Hax Demand 30,680 30,680 30,680 30,680 30,680 30,680 30,680 30,680 30,680 30,680 30,680 30,680 S 214,760 153,400 $ 368,160 s
2012 27 51 Peak Demand 0 0 0 0 110,040 110,040 110,040 110,040 110,040 110,040 0 0 i 660,240 0 i 660,240 s 8 11 Hax Demand 32,440 32,440 32,440 32,440 32,440 32,440 32,440 32,440 32,440 32,440 32,440 32,440 t 227,080 162,200 t 389,280 $
2013 29 10 Peak Demand 0 0 0 0 116,400 116,400 116,400 116,400 116,400 116,400 0 0 t 698,400 0 t 698,400 t 8 58 Hax Demand 34,320 34,320 34,320 34,320 34,320 34,320 34,320 34,320 34,320 34,320 34,320 34,320 S 240,240 171,600 S 411,840 i
2014 30 79 Peak Demand 0 0 0 0 123,160 123,160 123,160 123,160 123,160 123,160 0 0 t 738,960 0 S 738,960 i 9 08 Hax Demand 36,320 36,320 36,320 36,320 36,320 36,320 36,320 36,320 36,320 36,320 36,320 36,320 S 254,240 181,600 t 435,840 i
Two Combined Cycle Gas Turbines
ACTIVE CASE VARIABLES:
DESIGN OPTIONS:
Rated Capacity Avai Labi Lity Parasitic Loss Heat Rate
CASE 8
8,000 90.00% 9.30% 9,825
Salaries, Gen'L & Adnin 0*n t Overhaul Compressors Maintenance Fuel Costs: UUTP D.Gas City L/F Gas BFI L/F Gas N.Gas (PGSE)
HHBTUs/hr MHBTUs/hr MMBTUs/hr MHBTUs/hr
330,000 507,480 152,000
20.40 28.80 21.54 0.00
Total Est. Capital Costs: MS 20,112
(S OOO's) Period:
Year: 1
1995 2
1996 3
1997 4
1998 5
1999 6
2000 7
2001 8
2002 9
2003 10
2004 11
2005 12
2006 13
2007 14
2008 15
2009 16
2010 17
2011 18
2012 19
2013 20
2014
GT CASE 8: 8,000 kU CVar kU: Productive Capacity (Net) HkUhrs Fuel Availability HHBTUs Production (fuel constrnt)HkUhrs FueL Requirement (var) HHBTUs
UUTP HHBTUs City Landfill MHBTUs BFI MHBTUs
Other Fuel Purchases HHBTUs Elec. Energy Purchases HkUhrs Energy Purchases Displcd HkUhrs Excess Energy Avail/ Sale HkUhrs
8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 8,000 57,206 57,206 57,206 57,206 57,206 57,206 57,206 57,206 57,206 57,206 767,376 57,206 619,679 178,704 252,288 188,687
0 0
40,261 16,945
760,718 57,206
619,679 182,208 247,207 190,264
0 0
41,163 16,043
755,112 57,206
619,679 186,588 242,126 190,965
0 0
42,083 15,123
749,506 57,206 619,679 190,968 237,046 191,665
0 0
43,020 14,186
743,987 57,206 619,679 195,348 231,965 192,366
0 0
43,984 13,222
736,716 57,206
619,679 198,852 226,884 193,943
0 0
44,956 12,250
728,219 57,206
619,679 202,356 221,803 195,520
0 0
45,736 11,470
719,896 57,206 619,679 206,736 216,722 196,221
0 0
46,533 10,673
710,962 57,206
619,679 210,240 211,642 197,797
0 0
47,339 9,867
702,114 57,206
619,679 213,744 206,561 199,374
0 0
48,162 9,044
8,000 57,206
693,792 57,206
619,679 217,248 201,480 200,951
0 0
48,986 8,220
8,000 57,206 684,331 57,206 619,679 221,628 194,472 203,579
0 0
49,897 7,309
8,000 57,206 674,082 57,206 619,679 225,132 187,464 207,083
0 0
50,826 6,380
8,000 57,206
664,884 57,206
619,679 229,512 180,456 209,711
0 0
51,772 5,434
8,000 57,206 655,949 57,206 619,679 233,892 173,448 212,339
0 0
52,735 4,471
8,000 57,206 654,372 57,206 619,679 238,272 174,324 207,083
0 0
53,699 3,507
8,000 57,206 646,925 57,206 619,679 242,652 169,243 207,784
0 0
54,732 2,474
8,000 57,206 639,655 57,206 619,679 247,032 164,162 203,485
0 0
55,784 1,422
8,000 57,206 633,436 57,206 619,679 252,288 159,082 208,309
0 0
56,852 354
8,000 57,206 626,515 57,206 619,679 256,668 154,001 209,010
0 741
57,206 0
CLIENT: CITY OF FRESNO PROJECT: LANDFILL GAS PROJECT SUBJECT: ECONOHIC ANALYSIS OF DESIGN OPTIONS OATE: 09/19/91
TUENTY-YEAR PROFORHA BASIS:
CASE 8
(S OOO's)
REVENUES:
ELECTRIC: Demand Energy Excess
Period: Year:
15 TOTAL VALUE OF PGF:
OPERATING COSTS:
16 SaLaries, G A 17 OtH, PGF IB 0+H, Compressors
Unit Fuel Costs: 19 UUTP D.Gas 20 City LF Gas 21 BFI LF Gas 22 PGSE Cogen Gas 23 Debt Svc on Exist Bonds
24 TOTAL OPERATING COSTS:
CInvestS] 25 EST PROJECT VALUE: (20,112)
26 CUH PROJECT VALUE: 27 NPV a 28 IRA:
' 90.00% Availability / 9.30% Parasitic Loss cont'd.
1 2 3 4 5 6 7 8 9 10 11 12 13 - 14 15 16 17 18 19 20 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
652 687 724 761 801 843 882 948 1,019 1,092 1,170 1,255 1,345 1,447 1,551 1,660 1,776 1,898 2,024 2,158 3,060 3,221 3,393 3,570 3,758 3,952 4,136 4,444 4,773 5,131 5,511 5,927 6,374 6,882 7,425 7,998 8,625 9,300 10,027 10,674 836 829 819 805 786 764 749 731 708 680 648 603 552 495 428 353 261 158 41 0
4,548 4,737 4,936 5,136 5,345 5,559 5,767 6,123 6,500 6,903 7,329 7,785 8,271 8,824 9,404 10,011 10,662 11,356 12,092 12,832
401 421 442 464 487 512 537 564 592 622 653 686 720 756 794 834 875 919 965 1,013 594 618 642 668 695 723 752 782 813 845 879 914 951 989 1029 1070 1113 1157 1203 1251 178 185 193 200 208 217 225 234 244 253 263 274 285 296 308 321 333 347 361 375
0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 273 273 273 272 272 271 270 269 268 267 266 262 257 253 248 254 251 249 246 243 204 210 215 220 225 232 238 244 251 258 265 274 284 294 303 302 309 316 322 330 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
409 409 409 407 405 405 403 402 400 398 0 0 0 0 0 0 0 0 0 0
2,059 2,116 2,174 2,232 2,293 2,359 2,426 2,495 2,569 2,644 2,327 2,410 2,497 2,589 2,682 2,780 2,882 2,988 3,097 3,212
2,489 2,621 2,762 2,904 3,052 3,200 3,341 3,628 3,931 4,259 5,002 5,375 5,774 6,235 6,722 7,231 7,780 8,368 8,995 9,620
(17,623) (15,003) (12,241) (9,336) (6,284) (3,084) 257 3,885 7,816 12,076 17,078 22,453 28,227 34,463 41,184 48,415 56,195 64,564 73,559 83,179 (17,786) (15,497) (13,243) (11,027) (8,851) (6,718) (4,638) (2,526) (388) 1,777 4,154 6,541 8,937 11,355 13,791 16,240 18,703 21,179 23,667 26,153 -87.63% -57.19% -35.03% -20.59% -10.99% -4.39% 0.30% 3.85% 6.58% 8.71% 10.52% 11.95% 13.09% 14.02% 14.79% 15.42% 15.95% 16.39% 16.77% 17.08%
CLIENT: CITY OF FRESNO PROJECT: UNDFILL GAS PROJECT SUBJECT: ECONOHIC ANALYSIS OF DESIGN OPTIONS DATE: 09/19/91
TUENTY-YEAR PROFORHA BASIS:
CASE 8 8,000 kU / 90.00% Availability / 9.30% Parasitic Loss cont'd.
Period: 1 2 3 4 5 6 7 8 9 10 11 12 13 . 14 15 16 17 18 19 20 (» OOO's) Year: 1995 1996 1997 1998 1999 20OO 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014
DEBT SERVICE SCHEDULE:
29 Incr . Capaci ty 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973 1,973
JO PROJECT NET CASH FLOUS: 516 648 789 932 1,079 1,227 1,368 1,655 1,959 2,287 3,029 3,402 3,801 4,263 4,749 5,258 5,807 6,395 7,023 7,647
31 CUH CASH FLOUS: 516 1,163 1,953 2,884 3,964 5,191 6,559 8,214 10,173 12,459 15,489 18,891 22,692 26,955 31,704 36,962 42,769 49,164 56,187 63,834 52 NPV a 7.00% 482 1,048 1,692 2,403 3,172 3,990 4,842 5,805 6,871 8,033 9,472 10,983 12,560 14,213 15,935 17,716 19,554 21,446 23,388 25,364
FORECASTED PURCHASED DEHAND OFFSETS
CASE:
YEAR
8000
RATES
kU UINTER PERIOD B SUMMER PERIOD A PERIOD B TOTAL PERIODS; TOTAL ANNUAL
(A . a>
CASE:
YEAR
8000
RATES
kU
JAN FEB HAR APR HAY JUN JUL AUG SEP OCT MOV DEC A B
TOTAL ANNUAL
(A . a>
1994 0 00 Peak Demand 0 0 0 0 0 0 0 0 0 0 0 0 S 0 0 S 0 S 0 00 Hax Demand 0 0 0 0 0 0 0 0 0 0 0 0 t 0 0 S 0 s
1995 12 53 Peak Demand 0 0 0 0 85,054 78,438 72,862 50,747 55,821 56,986 0 0 S 399,908 0 S 399,908 s 3 69 Hax Demand 18,948 22,546 23,026 21,952 25,048 23,099 21,457 15,247 19,483 19,454 21,037 21,181 i 145,740 106,738 S 252,478 S
1996 12 90 Peak Demand 0 0 0 0 89,526 82,560 76,691 53,419 58,760 59,985 0 0 S 420,941 0 S 420,941 i 3 80 Hax Demand 19,931 23,739 24,244 23,112 26,372 24,320 22,591 16,051 20,512 20,482 22,150 22,298 % • 153,440 112,362 S 265,802 i
1997 13 29 Peak Demand 0 0 0 0 94,293 86,956 80,777 56,270 61,892 63,181 0 0 t U 3 , 3 6 9 0 i 443,369 t 3 92 Hax Demand 21,019 25,033 25,570 24,375 27,812 25,649 23,826 16,930 21,634 21,603 23,359 23,516 t 161,829 118,497 S 280,326 t
1998 13 68 Peak Demand 0 0 0 0 99,221 91,506 84,994 59,207 65,130 66,485 0 0 t 466,543 0 S 466,543 i 4 03 Hax Demand 22,092 26,308 26,872 25,615 29,230 26,957 25,038 17,792 22,737 22, 705 24,551 24,716 t 170,074 124,539 t 294,613 s
1999 14 09 Peak Demand 0 0 0 0 104,477 96,347 89,500 62,348 68,576 69,999 0 0 t 491,247 0 S 491,247 t 4 15 Hax Demand 23,261 27,701 28,295 26,971 30,772 28,378 26,361 18,733 23,937 23,904 25,846 26,021 t 179,056 131,124 % 310,180 s
2000 14 50 Peak Demand 0 0 0 0 109,896 101,355 94,149 65,584 72,138 73,631 0 0 S 516,753 0 i 516,753 t 4 27 Hax Demand 24,450 29,130 29,753 28,361 32,362 29,847 27,725 19,698 25,176 25,137 27,183 27,366 t 188,306 137,882 $ 326,188 t
2001 14 92 Peak Demand 0 0 0 0 115,048 106,096 98,547 68,647 75,510 77,077 0 0 % 540,925 0 t 540,925 t 4 39 Hax Demand 25,585 30,467 31,121 29,663 33,851 31,217 28,996 20,602 26,331 26,292 28,434 28,623 t 196,952 144,230 t 341,182 i
2002 15 76 Peak Demand 0 0 0 0 123,637 114,024 105,907 73,773 81,164 82,835 0 0 t 581,340 0 S 581,340 % 4 64 Hax Demand 27,511 32,763 33,468 31,900 36,401 33,570 31,181 22,156 28,318 28,272 30,573 30,782 $ 211,798 155,097 t 366,895 i 2003 16 64 Peak Demand 0 0 0 0 132,804 122,470 113,768 79,240 87,177 88,974 0 0 S 624,433 0 S 624,433 t
4 90 Max Demand 29,557 35,202 35,956 34,271 39,107 36,064 33,501 23,804 30,419 30,375 32,850 33,070 t 227,541 166,635 $ 394,176 s 2C04 17 58 Peak Demand 0 0 0 0 140,640 131,639 122,286 85,175 93,701 95,653 0 0 i 669,094 0 i 669,094 s
5 IS Hax Demand 31,790 37,861 38,669 36,861 41,440 38,788 36,032 25,600 32,717 32,670 35,328 35,566 t 244,108 179,214 S 423,322 t 2005 18 56 Peak Demand 0 0 0 0 148,480 141,353 131,312 91,464 100,614 102,711 0 0 t 715,934 0 t 715,934 s
5 47 Hax Demand 34,133 40,664 41,534 39,592 43,760 41,660 38,700 27,498 35,139 35,090 37,945 38,197 $ 261,439 192,473 t 453,912 s 2006 19 60 Peak Demand 0 0 0 0 156,800 152,057 141,238 98,392 108,231 110,466 0 0 S 767,184 0 % 767,184 i
5 78 Hax Demand 36,749 43,766 44,703 42,610 46,240 44,841 41,651 29,594 37,824 37,767 40,841 41,113 t 280,527 207,172 S 487,699 I 2007 20 69 Peak Demand 0 0 0 0 165,520 163,492 151,865 105,788 116,381 118,781 0 0 t 821,827 0 S 821,827 s
6 10 Hax Demand 39,504 47,049 48,056 45,805 48,800 48,202 44,774 31,818 40,663 40,602 43,902 44,201 t 300,664 222,712 % 523,376 s 2008 21 93 Peak Demand 0 0 0 0 175,440 175,440 163,971 114,211 125,637 128,247 0 0 S 882,946 0 t 882,946 s
6 47 Hax Demand 42,683 50,828 51,760 49,489 51,760 51,760 48,376 34,375 43,931 43,860 47,432 47,755 $ 323,551 240,458 S 564,009 t 2009 23 23 Peak Demand 0 0 0 0 185,840 185,840 176,920 123,235 135,570 138,381 0 0 % 945,786 0 S 945,786 %
6 85 Hax Demand 46,032 54,800 54,800 53,375 54,800 54,800 52,170 37,072 47,375 47,306 51,156 51,498 t 346,898 258,286 $ 605,184 t 2010 24 58 Peak Demand 0 0 0 0 196,640 196,640 190,618 132,781 146,054 149,102 0 0 t 1,011,835 0 t 1,011,835 t
7 25 Max Demand 49,605 58,000 58,000 57,522 58,000 58,000 56,224 39,955 51,055 50,982 55,129 55,499 $ 371,738 276,233 % 647,971 I 2011 26 00 Peak Demand 0 0 0 0 208,000 208,000 205,530 143,156 157,482 160,758 0 0 S 1,082,926 0 t 1,082,926 t
7 67 Hax Demand 53,491 61,360 61,360 61,360 61,360 61,360 60,631 43,082 55,055 54,971 59,450 59,849 % 397,819 295,510 $ 693,329 t 2012 27 51 Peak Demand 0 0 0 0 220,080 220,080 220,080 154,386 169,819 173,341 0 0 S 1,157,786 0 t 1,157,786 i
8 11 Hax Demand 57,646 64,880 64,880 64,880 64,880 64,880 64,880 46,430 59,333 59,244 64,061 64,491 t 424,527 315,958 t 740,485 i 2013 29 10 Peak Demand 0 0 0 0 232,800 232,800 232,800 166,423 183,068 186,880 0 0 $ 1,234,771 0 « 1,234,771 I
8 58 Hax Demand 62,154 68,640 68,640 68,640 68,640 68,640 68,640 50,056 63,972 63,878 68,640 68,640 $ 452,466 336,714 $ 789,180 i 2014 30 79 Peak Demand 0 0 0 0 246,320 246,320 246,320 179,475 197,456 201,551 0 0 t 1,317,442 0 t 1,317,442 i
9 08 Hax Demand 67,047 72,640 72,640 72,640 72,640 72,640 72,640 53,999 69,008 68,899 72,640 72,640 t 482,466 357,607 S 840,073 t
Appendix C
SCR CALCULATIONS
W3529:DM AOO CasTuibtne/EngComp APP C - 6
Table C.l Economic Analyst* of an SCR Systein for One Gas Tmblne") City of Fresno
Economic Parameter 1
1995 2
1996 3
1997 4
1998 5
1999 6
2000 7
2001 8
2002 9
2003 10
2004 11
2005 12
2006 13
2007 14
2008 15
2009 16
2010 17
2011 18
2012 19
2013 20
2014
Operating Costs Salaries 6 6 7 7 7 8 8 8 9 9 10 10 11 11 12 13 13 14 14 15 AmmonJa 10 11 11 12 12 13 13 14 15 16 16 17 18 19 20 21 22 23 24 25 Catalyst Replacement ... ... — 60 63 66 70 73 76 80 84 69 93 98 103 108 113 119 125 131 Total Operallng Costs 16 17 18 79 82 87 91 95 100 105 UO 116 122 128 135 142 148 156 163 171
Project Cost (Invest $1.(XX)) 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98 98
Project Cash Flow 114 115 116 177 180 185 189 193 198 203 208 214 220 226 233 240 246 254 261 269
Present Worth Factor a 7.00% 0.9346 0.8734 0.8163 0.7629 0.7130 0.6663 0.6227 0.5820 0.5439 0.5083 0.4751 0.4440 0.4150 0.3878 0.3624 0.3387 0.3166 0.2959 0.2765 0.2584
Present Worth Cost 107 100 95 135 128 123 118 112 108 105 99 95 91 87 84 81 78 75 72 70
Cumulative Present Worth 107 207 302 437 565 688 806 918 1,026 1.131 1.230 1.325 1.416 1.503 1.587 1.668 1.746 1.821 1.893 1,963
1. All costs In thousands of dollars.