OP YEAR STATE FACILITY NAME

ORISPL 

CODE UNIT ID UNIT TYPE INFO

2000 AZ Navajo Generating Station 4941 2 Tangentially-fired

2001 AZ Navajo Generating Station 4941 2 Tangentially-fired

2002 AZ Navajo Generating Station 4941 2 Tangentially-fired

2003 AZ Navajo Generating Station 4941 2 Tangentially-fired

2004 AZ Navajo Generating Station 4941 2 Tangentially-fired

2005 AZ Navajo Generating Station 4941 2 Tangentially-fired

2006 AZ Navajo Generating Station 4941 2 Tangentially-fired

2007 AZ Navajo Generating Station 4941 2 Tangentially-fired

2008 AZ Navajo Generating Station 4941 2 Tangentially-fired

2009 AZ Navajo Generating Station 4941 2 Tangentially-fired

2010 AZ Navajo Generating Station 4941 2 Tangentially-fired

2011 AZ Navajo Generating Station 4941 2 Tangentially-fired
PRIMARY 

FUEL INFO

SO2 CONTROL 

INFO

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone

Coal Wet Limestone
NOX CONTROL INFO

Other

Other

Other

Other

Other

Other

Other

Other

Other

Other

Low NOx Burner Technology w/ Closed-coupled/Separated OFA (Began Mar 30, 2010) Other

Low NOx Burner Technology w/ Closed-coupled/Separated OFA Other
PART CONTROL INFO

Electrostatic Precipitator

Baghouse (Began Apr 01, 2008)

Electrostatic Precipitator

Electrostatic Precipitator
FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

SUM OP 

TIME

NUM 

MONTHS 

REPORTED GLOAD

Navajo Generating Station 4941 2 1995 0

Navajo Generating Station 4941 2 1996 0

Navajo Generating Station 4941 2 1997 8,011 12

Navajo Generating Station 4941 2 1998 7,382 12

Navajo Generating Station 4941 2 1999 8,610 12

Navajo Generating Station 4941 2 2000 8,065 12

Navajo Generating Station 4941 2 2001 8,642 12

Navajo Generating Station 4941 2 2002 8,189 12

Navajo Generating Station 4941 2 2003 8,430 12

Navajo Generating Station 4941 2 2004 7,392 12

Navajo Generating Station 4941 2 2005 8,311 12

Navajo Generating Station 4941 2 2006 7,820 12

Navajo Generating Station 4941 2 2007 7,801 12

Navajo Generating Station 4941 2 2008 8,472 12

Navajo Generating Station 4941 2 2009 8,330 12

Navajo Generating Station 4941 2 2010 6,842 12 5,059,107

 8,075
SO2 MASS SO2 RATE NOX RATE NOX MASS CO2 MASS HEAT INPUT

CAPACITY 

INPUT

 23,785 0.902 0.370 9,755 5,417,609 52,736,561

 21,599 0.914 0.383 9,042 4,848,221 47,253,463

 27,145 0.967 0.371 10,670 5,758,314 56,123,903 7,006

 10,355 0.321 0.373 13,165 6,622,626 64,548,127 8,744

 1,822 0.053 0.335 11,471 7,004,319 68,268,218 7,929

 1,687 0.054 0.350 11,090 6,438,040 62,748,887 7,781

 1,183 0.034 0.357 12,356 7,043,405 68,649,158 7,944

 1,152 0.035 0.347 11,678 6,828,040 66,550,066 8,127

 1,232 0.035 0.358 12,686 7,170,757 69,890,459 8,290

 958 0.032 0.357 10,701 6,083,548 59,293,896 8,021

 1,125 0.033 0.369 12,674 6,943,991 67,680,284 8,144

 1,301 0.042 0.391 12,332 6,406,110 62,437,748 7,984

 1,333 0.043 0.355 11,270 6,423,284 62,605,067 8,026

 1,032 0.031 0.357 12,123 6,836,510 66,632,629 7,865

 1,565 0.046 0.343 11,816 6,945,198 67,692,020 8,127

 1,487 0.063 0.222 5,378 4,841,216 47,185,368 6,897

 15,877 130,198 74,123,200 722,448,433

 1,323 0.044 0.360 11,298 6,580,368 64,136,150 7,942
NOX CONTROL INFO

Low NOx Burner Technology w/ Closed-coupled/Separated OFA (Began Mar 30, 2010) Other
FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

SUM OP 

TIME

NUM 

MONTHS 

REPORTED GLOAD

Navajo Generating Station 4941 2 1995 0

Navajo Generating Station 4941 2 1996 0

Navajo Generating Station 4941 2 1997 8,011 12

Navajo Generating Station 4941 2 1998 7,382 12

Navajo Generating Station 4941 2 1999 8,610 12

Navajo Generating Station 4941 2 2000 8,065 12

Navajo Generating Station 4941 2 2001 8,642 12

Navajo Generating Station 4941 2 2002 8,189 12

Navajo Generating Station 4941 2 2003 8,430 12

Navajo Generating Station 4941 2 2004 7,392 12

Navajo Generating Station 4941 2 2005 8,311 12

Navajo Generating Station 4941 2 2006 7,820 12

Navajo Generating Station 4941 2 2007 7,801 12

Navajo Generating Station 4941 2 2008 8,472 12

Navajo Generating Station 4941 2 2009 8,330 12

Totals 90,061

Averages 8,187

Navajo Generating Station 4941 2 2010 6,842 12 5,059,107
SO2 MASS SO2 RATE NOX RATE NOX MASS CO2 MASS HEAT INPUT

CAPACITY 

INPUT

 23,785 0.902 0.370 9,755 5,417,609 52,736,561

 21,599 0.914 0.383 9,042 4,848,221 47,253,463

 27,145 0.967 0.371 10,670 5,758,314 56,123,903 7,006

 10,355 0.321 0.373 13,165 6,622,626 64,548,127 8,744

 1,822 0.053 0.335 11,471 7,004,319 68,268,218 7,929

 1,687 0.054 0.350 11,090 6,438,040 62,748,887 7,781

 1,183 0.034 0.357 12,356 7,043,405 68,649,158 7,944

 1,152 0.035 0.347 11,678 6,828,040 66,550,066 8,127

 1,232 0.035 0.358 12,686 7,170,757 69,890,459 8,290

 958 0.032 0.357 10,701 6,083,548 59,293,896 8,021

 1,125 0.033 0.369 12,674 6,943,991 67,680,284 8,144

 1,301 0.042 0.391 12,332 6,406,110 62,437,748 7,984

 1,333 0.043 0.355 11,270 6,423,284 62,605,067 8,026

 1,032 0.031 0.357 12,123 6,836,510 66,632,629 7,865

 1,565 0.046 0.343 11,816 6,945,198 67,692,020 8,127

 14,390 130,198 74,123,200 722,448,433 88,237

 1,308 0.040 0.360 11,836 6,738,473 65,677,130 8,022

 1,487 0.063 0.222 5,378 4,841,216 47,185,368 6,897
NOX CONTROL INFO

Low NOx Burner Technology w/ Closed-coupled/Separated OFA (Began Mar 30, 2010) Other
Common Costs attributed to NGS#3 but shared among all units

CODE OF ACCOUNT & DESCRIPTION

A-11-23-2 DEMO EXISTING MAINTENANCE FACILITY - FAB SHOP

A-11-25-1 DEMO EXISTING MAINTENANCE FACILITY - FAB SHOP FDN. 100'X200'

A-21-17-3 EARTHWORK, BACKFILL

A-21-17-7 EARTHWORK, BACKFILL

A-21-21-3 EARTHWORK, DISPOSAL

A-21-21-7 EARTHWORK, DISPOSAL

A-21-23-3 EARTHWORK, EXCAVATION

A-21-23-7 EARTHWORK, EXCAVATION

A-21-53-1 CAISSON - 30" DIA X 12' LONG

A-21-53-2 CAISSON - 30" DIA X 12' LONG

A-22-13-3 CONCRETE

A-22-13-7 CONCRETE

A-22-15-2 EMBEDMENT

A-22-15-7 EMBEDMENT

A-22-17-3 FORMWORK

A-22-17-7 FORMWORK

A-22-25-3 REINFORCING

A-22-25-7 REINFORCING

A-23-25-4 PIPE RACK STRUCTURAL STEEL, 10'WX25'HX700'L

A-23-25-5 PIPE RACK STRUCTURAL STEEL, 10'WX25'HX240'L

A-23-25-6 PIPE RACK ALLOWANCE ON DUCT SUPPORT STEEL,

A-24-35-2 REPLACEMENT MAINTENANCE FACILITY

A-31-41 FIRE PROTECTION EQUIPMENT & SYSTEM (COMMON)

A-33-99-1 ANHYDROUS AMMONIA UNLOADING & STORAGE

A-35-15-16 2" DIA, CS PLANT AIR - IN PROCESS AREA -

A-35-15-17 2" DIA, CS

A-35-15-18 2" DIA, 316L SS

A-35-15-19 2" DIA, 316L SS

A-35-15-20 2" DIA, CS

A-35-15-21 2" DIA, CS

A-35-15-22 2" DIA, SS WITH CS CARRIER

A-35-15-23 2" DIA, SS WITH CS CARRIER

A-35-15-24 2" DIA, 316L SS

A-35-15-25 2" DIA, 316L SS

A-35-35-18 1" DIA, CS BALL VALVE PLANT AIR - (COMMON)

A-35-35-19 1" DIA, 316L SS BALL VALVE INSTRUMENT AIR - (COMMON)

A-35-35-20 1" DIA, CS BALL VALVE SERVICE WATER - (COMMON)

A-35-35-21 2" DIA, 316L SS BALL VALVE INSTRUMENT AIR - (COMMON)

A-35-35-22 2" DIA, CS GLOBE VALVE SERVICE WATER - (COMMON)

A-35-35-23 2" DIA, 316L SS GLOBE VALVE AMMONIA - (COMMON

A-35-35-24 2" DIA, 316L SS GLOBE VALVE

A-35-35-25 2" DIA, CS BALL VALVE, AIR OPERATED, ON/OFF

A-35-35-26 2" DIA, SS GLOBE VALVE, AIR OPERATED, ON/OFF

A-36-15-5 2" PIPE, 1 " FIBERGLASS WITH ALUMINUM JACKET PLANT AIR - (COMMON)

A-36-15-6 2" PIPE, 1 " FIBERGLASS WITH ALUMINUM JACKET SERVICE WATER - COMMON
A-36-15-7 2" PIPE, 1 " FIBERGLASS WITH ALUMINUM JACKET POTABLE WATER - COMMON

C-41-35 LIGHTINING PROTECTION

C-41-12 TESTING TEST & DOCUMENTATIONS

D ELECTRICAL AND I & C FOR COMMON AREA

H SITEWORK - COMMON FOR UNITS 1, 2 & 3

TOTAL COST
TOTAL COST

$ 267,708

$ 81,619

$ 3,343

$ 846

$ 819

$ 443

$ 3,866

$ 1,450

$ 134,297

$ 50,361

$ 67,352

$ 224,019

$ 5,415

$ 7,736

$ 49,209

$ 16,403

$ 118,253

$ 197,089

$ 369,989

$ 134,542

$ 146,774

$ 4,032,186

$ 89,284

$ 1,847,027

$ 17,716

$ 39,525

$ 26,803

$ 80,264

$ 17,716

$ 39,525

$ 170,853

$ 354,282

$ 26,803

$ 80,264

$ 1,800

$ 6,000

$ 1,800

$ 2,600

$ 540

$ 2,680

$ 4,880

$ 5,100

$ 12,100

$ 17,183

$ 17,183
$ 17,183

$ 24,247

$ 10,442

$ 1,701,096

$ 1,266,525

$ 11,795,140
INDIRECT COST CODE OF ACCOUNT & DESCRIPTION

A-21-99 WOOD CRIBBING FOR CRANE PAD

91-9 CONTRACTOR'S GENERAL AND ADMINISTRATION EXPENSE - % of ACCT NO. 90 (5% on LABOR)

91-10 CONTRACTOR'S PROFIT - % of ACCT NO. 90

93-1 ENGINEERING, PROCUREMENT, & PROJECT SERVICES - 9% of ACCT NO. 92 

93-2 CONSTRUCTION MANAGEMENT/FIELD ENGINEERING/HOME OFFICE (INCLUDES PER DIEM) - 65% OF D.L. COSTS

93-3 S-U / COMMISSIONING - 4.0 % OF D.L. COSTS 

93-48 OWNER'S - LOST GENERATION DURING SHORT OUTAGES ($45/MWh @750MW x 24Hrs x 7 DAYS)

95 TOTAL CONTINGENCY 11.3 % 

97 AFUDC

TOTAL COST
TOTAL COST

$ 72,549

$ 7,894,783

$ 5,985,262

$ 14,141,710

$ 15,191,829

$ 934,882

$ 5,670,000

$ 23,051,807

$ 4,059,926

$ 77,002,748
INDIRECT COST CODE OF ACCOUNT & DESCRIPTION

93-41 OWNER'S CONSTRUCTION MANAGEMENT 5.0 %

93-43 OWNER'S LEGAL SUPPORT

93-44 OWNER'S INSURANCE

93-45 OWNER'S O&M SUPPORT DURING CONSTRUCTION / S-U

93-46 OWNER'S - SPARE PARTS & SPECIAL TOOLING (5% OF EQUIPMENT COSTS IN ACCT. 92)

93-47 OWNER'S - CONTRACT SERVICES (1% OF LABOR IN ACCT. 92)

TOTAL COST
TOTAL COST

$ 6,428,050

$ 3,000,000

$ 2,000,000

$ 1,000,000

$ 555,000

$ 735,000

$ 13,718,050
Salt River Project--Navajo Generating Station Unit #2

Modified from OAQPS Control Cost Manual Section 4.2, SCR

Given/Assumptions

New or Retrofit? Retrofit Company report

Generation capacity (MW) 750 from SRP presentation of 7/20/10

SCR bypass included? No from SRP 8/17/10 report

Fuel High Heating Value (Btu/lb) 10,418 from SRP 4/16/10 report, (Appendix A) 

Maximum Fuel Consumption Rate (lb/hr) 9.04E+05 calculated from 9,423 mmBtu/hr total of individual maximum hourly heat input for this boiler in 2002 from ENSR

Average Annual Fuel Consumption (lb) 6.30E+09 calculated from 65,677,130 mmBtu 2000 - 2009 average total heat input for this boiler from CAMD

Number of SCR Operating Days 365 assumed 8,760 assumed

Plant Capacity Factor 80% calculated from OAQPS Control Cost Manual

Uncontrolled NOx Concentration (lb/mmBtu) 0.360 EPA CAM data for 2000 - 2009

LNB + OFA Total Capital Cost $ 14,000,000 SRP 1/09 revised BART analysis Table ES-1

LNB + OFA Total Annual Cost $ 1,622,000 SRP 1/09 revised BART analysis Table ES-1

LNB outlet = SCR inlet NOx Concentration (lb/mmBtu) 0.24 from SRP 8/17/10 report, Table 2-1

Required Controlled NOx Concentration (lb/mmBtu) 0.05 from SRP 8/17/10 report, Table 2-1

Acceptable Ammonia Slip (ppm) 2 from SRP 8/17/10 report, Table 2-1

Fuel Volume Flow Rate (ft3/min/mmBtu/hr) 484 OAQPS Control Cost Manual

Fuel Sulfur Content (%) 0.63 from SRP 7/20/10 report, (slide 35) 

Number of SCR reactor chambers 2 from SRP 8/17/10 report

Number of spare catalyst layers 2 from SRP 8/17/10 report

ASR 1.05 OAQPS Control Cost Manual

Stored Ammonia Concentration 29.4% OAQPS Control Cost Manual

Reagent Molecular Weight (g/mole) 17.03 OAQPS Control Cost Manual

Reagent Density (lb/ft3 @ 60F) 56.0 OAQPS Control Cost Manual

Reagent Specific Volume (gal/ft3) 7.481 OAQPS Control Cost Manual

NOx Molecular Weight (g/mole) 46.01 OAQPS Control Cost Manual

Number of Days of Storage for Ammonia 14 from SRP 8/17/10 report

Pressure Drop for SCR Ductwork (H2O") 3 OAQPS Control Cost Manual

Pressure Drop for each Catalyst Layer (H2O") 1 OAQPS Control Cost Manual

Temperature at SCR Inlet (degrees F) 670 from SRP 8/17/10 report, Table 2-1

Equipment Life (years) 20 OAQPS Control Cost Manual

Annual Interest Rate 7.0% OAQPS Control Cost Manual SRP used 9.8% in its 8/17/10 report

Inflation Since 1998 1.43 CEPCI 2010/CEPCI 1998

Catalyst Cost, Initial ($/ft3) $ 198 calculated from $7,000 from SRP e-mail of 8/20/08 SRP used $ 8,000 /m3 in its 8/17/10 report

Adjusted Company SCR Direct Capital Cost (DCC) $ 119,018,820 SRP 8/06/10 report

Lost generation (weeks) 1 from SRP 8/17/10 report

Include Allowance for Funds Allocated During Construction (AFUDC)? Yes SRP 8/06/10 report

Override Cost Manual TCI? ($/kW) $ 224 calculated from DCC using OAQPS Control Cost Manual

Catalyst Cost, Replacement ($/ft3) $ 198 calculated from $7,000 from SRP e-mail of 8/20/08 SRP used $ 8,000 /m3 in its 8/17/10 report

Electrical Power Cost ($/kWh) 0.045 from SRP letter of 7/29/08 $ 45.00 /MWh from SRP 8/17/10 report, Table 2-1

29.4% Ammonia Solution Cost ($/lb) 0.069825 calculated from $ 475 /ton in its 8/17/10 report SRP used $ 400 /ton from company letter of 7/29/08

Operating Life of Catalyst (hours) 40,000 from SRP e-mail of 8/20/08 to EPA

Natural gas unit cost ($/mcf) $ 4.98 EIA 2010 price forecast

Natural gas for reheat (mcf) NA

Company SCR Total Capital Investment (TCI) $ 205,807,905 SRP 8/06/10 report

Adjustment for Common costs $ 3,931,713 SRP 8/06/10 report

Adjustment for included Indirect Capital Costs + AFUDC $ (77,002,748) SRP 8/06/10 report

Adjustment for included Owner's costs $ (13,718,050) SRP 8/06/10 report
Salt River Project--Navajo Generating Station Unit #2

LNB Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc

( 0.36 - 0.24 )/ 0.36 = 33%

Boiler Calculations

2.3 QB = HVm-dotfuel

QB = 10,418 Btu/lb * 904,492 lb/hr

QB = 9,423 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 6.30E+09 lb/yr / 8760 hr/yr / 904,492 lb/hr

CFPlant = 80%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

2.6 CFTotal = CFPlant x CFSCR

CFTotal = 80% * 100%

CFTotal = 80%

2.12 qfluegas = qfuelQB(460+T)/(460+700o

F)nSCR

qfluegas = 484 ft3/min/(mmBtu/hr)* 9423 mmBtu/hr*( 460 + 670 )/( 460 + 700 )/ 2

qfluegas = 2,221,391 acfm each of 2 reactors SRP estimated 4,179,000 acfm total

2.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.24 lb/mmBtu - 0.05 lb/mmBtu)/ 0.24 lb/mmBtu

ηNOx = 79%

Uncontrolled NOx emissions (tpy) 11,836

Overall Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc

( 0.36 - 0.05 )/ 0.36 = 86%

NOx removed = 10,194 tpy

Controlled NOx emissions (tpy) = 1,642 tpy
Salt River Project--Navajo Generating Station Unit #2

SCR Reactor Calculations

2.19 Volcatalyst = 2.81 x QB x ηadj x Slipadj x NOxadj x Sadj x Tadj/NSCR

Volcatalyst = 2.81 * 9423 = 26479

2.2 ηadj = 0.2869 + (1.058 x η)

ηadj = 0.2869 +( 1.058 * 0.79 )

ηadj = 1.124

2.22 Slipadj = 1.2835 – (0.0567 x Slip)

Slipadj = 1.2835 - ( 0.0567 * 2 )

Slipadj = 1.170

2.21 NOxadj = 0.8524 + (0.3208 x NOxin)

NOxadj = 0.8524 + ( 0.3208 * 0.24 )

NOxadj = 0.929

2.23 Sadj = 0.9636 + (0.0455 x S)

Sadj = 0.9636 + ( 0.0455 * 0.63 )

Sadj = 0.9923

2.24 Tadj = 15.16 – (0.03937 x T) + (2.74 x 10-5 x T2

)

Tadj = 15.16 - ( 0.0394 * 670 ) + 2.74E-05 * 448,900

Tadj = 1.082

Volcatalyst = 17,381 ft3 each = 493 m3 each

2.25 Acatalyst = qfluegas/(16 ft/sec x 60 sec/min)

Acatalyst = 2,221,391 /( 16 * 60 )

Acatalyst = 2,314 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 2,314

ASCR = 2,661 ft2

2.27 l = w = ASCR

1/2

l = w = 51.6 ft

2.28 nlayer = Volcatalyst/(h’layer x Acatalyst)

nlayer = 17,381 /( 3.1 * 2,314 )

nlayer (calc) = 2.0

nlayer = 2.0

2.29 hlayer = [Volcatalyst/(nlayer x Acatalyst)] + 1

hlayer = 17,381 /( 2.0 * 2,314 ) + 1

hlayer = 4.8

2.3 ntotal = nlayer + nempty

ntotal = 2 + 2

ntotal = 4

2.31 hSCR = ntotal(c1

 + hlayer) + c2

hSCR = 4 * ( 7 + 4.8 ) + 9

hSCR = 56 ft
Salt River Project--Navajo Generating Station Unit #2

Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.24 * 9423 * 1.05 * 79% * 17.03 / 46.01

m-dotreagent = 696 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 696 / 0.29

m-dotsol = 2367 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 2367 * 7.481 / 56

qsol = 316 gph

2.35 Tank Volume = qsolt

Tank Volume = 316 * 14 * 24

Tank Volume = 106,233 gal
Salt River Project--Navajo Generating Station Unit #2

Direct Capital Cost

########## DC = QB[($3380/MMBtu/hr) + f(hSCR) +f(NH3

rate) + f(new) + f(bypass)](3500/QB)

0.35 + f(Volcatalyst)

DC = 4712 (( $ 3,380 /mmBtu/hr * inflation = $4,827

2.37 f(hSCR) = {[$612/(ft-mmBtu/hr)]hSCR} - $187.9/(mmBtu/hr)

f(hSCR) = 6.12 * 56 - 187.9

f(hSCR) = $ 155 /mmBtu/hr * inflation = $ 221

2.38 f(NH3

rate) = [($411/lb/hr)(m-dotreagent/QB)] - $47.3/(mmBtu/hr)

f(NH3rate) = 411 * 696 / 9423 - 47.3

f(NH3rate) = $ (17) /mmBtu/hr * inflation = $ (24)

2.39 f(new) = $0/(mmBtu/hr) for retrofit

f(new) = $ - /mmBtu/hr * inflation = $ -

2.41 f(bypass) = $0/(mmBtu/hr) for no bypass

f(bypass) = $ - /mmBtu/hr * inflation = $ -

2.43 f(Volcatalyst) = VolcatalystCCinitial

f(Volcatalyst) = 17,381 * 198

f(Volcatalyst) = $ 3,447,909

DC = 4712 * ( $ 4,827 + $ 221 + $ (24) + $ - + $ - )*( 3500 / 4712 )^ 0.35 + $ 3,447,909

DC = $ 24,778,253 for each reactor

DC = $ 49,556,506 for all reactors
Salt River Project--Navajo Generating Station Unit #2

Indirect Capital Costs Cost Manual SRP

Cost Cost Cost Cost

Total Direct Capital Costs, A $ 49,556,506 ratios $ 119,018,820 ratios

Indirect Installation Costs 

General Facilities 0.05 A $2,477,825 5%

Engineering and Home Office Fees 0.10 A $4,955,651 10%

Process Contingencies 0.05 A $2,477,825 5%

Total Indirect Installation Costs, B 0.20 A = $9,911,301 20%

Project Contingency, C = 0.15 (A+B) = $8,920,171 18% $ 23,051,807 19%

Total Plant Cost D = A+B+C $68,387,978 138%

Allowance for Funds During Construction, E = 0 $0 0% $ 4,059,926 3%

Royalty Allowance, F = 0 $0 0%

Preproduction Cost, G = 0.02 (D+E) $1,367,760 3%

Inventory Capital, H =

Initial Catalyst and Chemicals, I = 0.0698 /lb * 2367 lb/r * 24 hr/day * 14 days = $55,526 0%

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $69,811,263 141% $ 205,807,905 173%

Cost/kW = $93 $ 274

Total Capital Investment TCI @ 224 $/kW = $167,664,247 $ 167,664,247

$ 224

Lost Generation cost = $ 5,670,000

Total Capital Investment TCI = $177,394,173

$ 237
Salt River Project--Navajo Generating Station Unit #2

Annual Costs

########## DAC = Annual Maintenance Cost + Annual Reagent Cost + Annual Electricity Cost + Annual Water Cost + Annual Catalyst Cost

2.46 Annual Maintenance Cost = 0.015 TCI

Annual Maintenance Cost = 0.015 * $ 177,394,173

Annual Maintenance Cost = $ 2,660,913 $ 395,000 SRP 8/17/10 report

2.47 Annual Reagent Cost = qreagentCostreagenttop

2.47a top = CFtotal8760hr/yr

top = 80% * 8760

top = 6970

Annual Reagent Cost = 2367 * 6970 * 0.069825

Annual Reagent Cost = $ 1,151,816 $ 1,035,000 SRP 8/17/10 report

2.49 Annual Electricity Cost = Power (Costelect)top

2.48 Power = 0.105QB[NOxinηNOx + 0.5(ΔPduct + ntotalΔPcatalyst)]

Power = 0.105 * 9423 *( 0.24 * 79% + 0.5 * ( 3 + 4 * 1 ))

Power = 3651 kW

Annual Electricity Cost = 3651 * 6970 * 0.045

Annual Electricity Cost = $ 1,145,097 $ 1,809,000 SRP 8/17/10 report

2.51 Annual Catalyst Replacement Cost = (Catalyst Replacement Cost)FWF

2.5 Catalyst Replacement Cost = nSCRVolcatalystCCreplace/Rlayer

Catalyst Replacement Cost = 2 * 17381 * 198 / 2

Catalyst Replacement Cost = $ 3,447,909

1 FWF = i{1/[(1+i)Y

-1]}

2.53 Y = hcatalyst/hyear

Y = 24000 /( 80% * 8760 )

Y = 3.44

FWF = 0.07 *( 1 /( 1 + 0.07 )^ 3 - 1 )

FWF = 0.31

Annual Catalyst Cost = $ 1,072,478 $ 672,000 SRP 8/17/10 report

Annual natural gas Cost = - mcf/yr * $ 4.98 /mcf

Annual natural gas Cost = $ -

Lost Ash Sales =

DAC = $ 6,030,304 $ 3,911,000

2.55 CRF = i(1+i)n

/[(1+i)n-1]

CRF = 0.07 *( 1 + 0.07 )^ 20 /(( 1 + 0.07 )^ 20 - 1 )

CRF = 0.0944

Indirect Annual Cost = CFR * TCI

Indirect Annual Cost = 0.0944 * $ 177,394,173

Indirect Annual Cost = $ 16,744,755 $ 27,835,000 SRP 8/17/10 report

2.56 Total Annual Cost = Direct Annual Cost + Indirect Annual Cost

Total Annual Cost = $ 6,030,304 + 16,744,755

Total Annual Cost = $ 22,775,059 + $ 1,622,000 = $ 24,397,059 $ 31,746,000

2.57 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.24 * 79% * 9423 * 6970 / 2000

NOx Removed = 6,239

Total NOx Removed = 10,194

2.58 Cost effectiveness = TAC/NOx removed

SCR Cost effectiveness = $ 3,650

Total Cost effectiveness = $ 2,393
Operating company Salt River Project

Facility Navajo Generating Station 

State NN

Contact

Proposed Controls SCR

Unit Unit #2

Boiler Type tangentially-fired

Fuel western bituminous

Rating (MW Gross) each 750 from SRP presentation of 7/20/10

Presumptive BART limit (lb/mmBtu) 0.28 BART Guidelines for tangentially-fired boiler > 200 MW firing bituminous coal at facility > 750 MW

Rating (mmBtu/hr) 9,423 mmBtu/hr total of individual maximum hourly heat input for this boiler in 2002 from ENSR

Uncontrolled Emissions (tpy) 11,836 OAQPS Control Cost Manual

Uncontrolled Emissions (lb/mmBtu) 0.36 EPA CAM data for 2000 - 2009

Combustion Controls Cost-benefit Analysis

Control Efficiency 33% calculated

Controlled emissions (lb/mmBtu) 0.24 from SRP 8/17/10 report, Table 2-1

Controlled Emissions (tpy) 7,881 calculated

Emissions Reduction (tpy) 3,955 calculated

Capital Cost $ 14,000,000 SRP 1/09 revised BART analysis Table ES-1

Capital Cost ($/kW) $ 19 calculated

O&M Cost 

Annualized Cost $ 1,622,000 SRP 1/09 revised BART analysis Table ES-1

Cost-Effectiveness ($/ton) $ 410 calculated

SCR Cost-benefit Analysis

Control Efficiency 79% OAQPS Control Cost Manual

Controlled emissions (lb/mmBtu) 0.05 from SRP 8/17/10 report, Table 2-1

Controlled Emissions (tpy) 1,642 calculated

Emissions Reduction (tpy) 6,239 OAQPS Control Cost Manual

Capital Cost $ 177,394,173 calculated

Capital Cost ($/kW) $ 237 calculated

O&M Cost $ 6,030,304 OAQPS Control Cost Manual

Annualized Cost $ 22,775,059 OAQPS Control Cost Manual

Cost-Effectiveness ($/ton) $ 3,650 OAQPS Control Cost Manual

Combustion Controls + SCR Cost-benefit Analysis

Control Efficiency 86% calculated

Controlled emissions (lb/mmBtu) 0.05 calculated

Controlled Emissions (tpy) 1,642 calculated

Emissions Reduction (tpy) 10,194 calculated

Capital Cost $ 191,394,173 calculated

Capital Cost ($/kW) $ 255 calculated

O&M Cost $ 6,030,304 calculated

Annualized Cost $ 24,397,059 calculated

Cost-Effectiveness ($/ton) $ 2,393 calculated