OP YEAR STATE FACILITY NAME

ORISPL 

CODE

UNIT 

ID UNIT TYPE INFO

PRIMARY 

FUEL INFO

2000 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2001 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2002 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2003 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2004 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2005 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2006 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2007 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2008 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2009 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2010 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal

2011 AZ Navajo Generating Station 4941 3 Tangentially-fired Coal
SO2 CONTROL 

INFO

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone

Wet Limestone
NOX CONTROL INFO

Other

Other

Other

Other

Other

Other

Other

Other

Other

Low NOx Burner Technology w/ Closed-coupled/Separated OFA (Began Mar 20, 2009) Other

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

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

Baghouse
FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

SUM OP 

TIME

NUM 

MONTHS 

REPORTED GLOAD

Navajo Generating Station 4941 3 1995 0

Navajo Generating Station 4941 3 1996 0

Navajo Generating Station 4941 3 1997 7,216 12

Navajo Generating Station 4941 3 1998 8,589 12

Navajo Generating Station 4941 3 1999 7,892 12

Navajo Generating Station 4941 3 2000 8,470 12

Navajo Generating Station 4941 3 2001 7,841 12

Navajo Generating Station 4941 3 2002 8,543 12

Navajo Generating Station 4941 3 2003 7,152 12

Navajo Generating Station 4941 3 2004 8,781 12

Navajo Generating Station 4941 3 2005 8,292 12

Navajo Generating Station 4941 3 2006 7,983 12

Navajo Generating Station 4941 3 2007 8,238 12

Navajo Generating Station 4941 3 2008 8,419 12

Navajo Generating Station 4941 3 2009 6,250 12

Navajo Generating Station 4941 3 2010 8,235 12 6,340,964

 8,008
SO2 MASS SO2 RATE NOX RATE NOX MASS CO2 MASS HEAT INPUT

CAPACITY 

INPUT

 24,206 0.864 0.370 10,365 5,563,037 56,012,327

 24,287 0.907 0.359 9,603 5,492,449 53,532,138

 10,503 0.358 0.423 12,688 6,020,420 58,678,583 8,132

 1,202 0.036 0.395 13,556 6,786,280 66,143,069 7,701

 1,486 0.048 0.367 11,659 6,384,932 62,231,336 7,886

 1,944 0.056 0.371 13,172 7,184,242 70,021,854 8,268

 1,733 0.053 0.326 10,822 6,740,012 65,692,126 8,378

 1,583 0.047 0.358 12,260 6,946,138 67,701,146 7,925

 1,049 0.039 0.321 8,662 5,456,420 53,182,544 7,436

 1,615 0.047 0.311 10,679 7,036,164 68,578,638 7,810

 1,628 0.050 0.304 9,953 6,641,723 64,734,167 7,807

 1,326 0.042 0.322 10,149 6,408,624 62,462,256 7,824

 1,498 0.046 0.329 10,752 6,628,357 64,603,853 7,842

 1,371 0.040 0.305 10,629 6,999,915 68,225,288 8,104

 1,174 0.051 0.217 5,154 4,740,968 46,208,284 7,394

 1,828 0.059 0.206 6,406 6,317,654 61,575,632 7,477

 18,236 113,891 71,167,495 693,641,491

 1,520 0.053 0.328 10,025 6,457,096 62,934,760 7,859
NOX CONTROL INFO

Low NOx Burner Technology w/ Closed-coupled/Separated OFA Other
FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

SUM OP 

TIME

NUM 

MONTHS 

REPORTED GLOAD

Navajo Generating Station 4941 3 1995 0

Navajo Generating Station 4941 3 1996 0

Navajo Generating Station 4941 3 1997 7,216 12

Navajo Generating Station 4941 3 1998 8,589 12

Navajo Generating Station 4941 3 1999 7,892 12

Navajo Generating Station 4941 3 2000 8,470 12

Navajo Generating Station 4941 3 2001 7,841 12

Navajo Generating Station 4941 3 2002 8,543 12

Navajo Generating Station 4941 3 2003 7,152 12

Navajo Generating Station 4941 3 2004 8,781 12

Navajo Generating Station 4941 3 2005 8,292 12

Navajo Generating Station 4941 3 2006 7,983 12

Navajo Generating Station 4941 3 2007 8,238 12

Navajo Generating Station 4941 3 2008 8,419 12

Totals 90,198

Averages 8,200

Navajo Generating Station 4941 3 2009 6,250 12

Navajo Generating Station 4941 3 2010 8,235 12 6,340,964
SO2 MASS SO2 RATE NOX RATE NOX MASS CO2 MASS HEAT INPUT

CAPACITY 

INPUT

 24,206 0.864 0.370 10,365 5,563,037 56,012,327

 24,287 0.907 0.359 9,603 5,492,449 53,532,138

 10,503 0.358 0.423 12,688 6,020,420 58,678,583 8,132

 1,202 0.036 0.395 13,556 6,786,280 66,143,069 7,701

 1,486 0.048 0.367 11,659 6,384,932 62,231,336 7,886

 1,944 0.056 0.371 13,172 7,184,242 70,021,854 8,268

 1,733 0.053 0.326 10,822 6,740,012 65,692,126 8,378

 1,583 0.047 0.358 12,260 6,946,138 67,701,146 7,925

 1,049 0.039 0.321 8,662 5,456,420 53,182,544 7,436

 1,615 0.047 0.311 10,679 7,036,164 68,578,638 7,810

 1,628 0.050 0.304 9,953 6,641,723 64,734,167 7,807

 1,326 0.042 0.322 10,149 6,408,624 62,462,256 7,824

 1,498 0.046 0.329 10,752 6,628,357 64,603,853 7,842

 1,371 0.040 0.305 10,629 6,999,915 68,225,288 8,104

 16,435 122,294 73,212,808 713,576,276 86,981

 1,494 0.046 0.343 11,118 6,655,710 64,870,571 7,907

 1,174 0.051 0.217 5,154 4,740,968 46,208,284 7,394

 1,828 0.059 0.206 6,406 6,317,654 61,575,632 7,477
NOX CONTROL INFO

Low NOx Burner Technology w/ Closed-coupled/Separated OFA Other
Common Costs attributed to NGS#3 but shared among all units

CODE OF ACCOUNT & DESCRIPTION TOTAL COST

A-11-23-2 DEMO EXISTING MAINTENANCE FACILITY - FAB SHOP $ 267,708

A-11-25-1 DEMO EXISTING MAINTENANCE FACILITY - FAB SHOP FDN. 100'X200' $ 81,619

A-21-17-3 EARTHWORK, BACKFILL $ 3,343

A-21-17-7 EARTHWORK, BACKFILL $ 846

A-21-21-3 EARTHWORK, DISPOSAL $ 819

A-21-21-7 EARTHWORK, DISPOSAL $ 443

A-21-23-3 EARTHWORK, EXCAVATION $ 3,866

A-21-23-7 EARTHWORK, EXCAVATION $ 1,450

A-21-53-1 CAISSON - 30" DIA X 12' LONG $ 134,297

A-21-53-2 CAISSON - 30" DIA X 12' LONG $ 50,361

A-22-13-3 CONCRETE $ 67,352

A-22-13-7 CONCRETE $ 224,019

A-22-15-2 EMBEDMENT $ 5,415

A-22-15-7 EMBEDMENT $ 7,736

A-22-17-3 FORMWORK $ 49,209

A-22-17-7 FORMWORK $ 16,403

A-22-25-3 REINFORCING $ 118,253

A-22-25-7 REINFORCING $ 197,089

A-23-25-4 PIPE RACK STRUCTURAL STEEL, 10'WX25'HX700'L $ 369,989

A-23-25-5 PIPE RACK STRUCTURAL STEEL, 10'WX25'HX240'L $ 134,542

A-23-25-6 PIPE RACK ALLOWANCE ON DUCT SUPPORT STEEL, $ 146,774

A-24-35-2 REPLACEMENT MAINTENANCE FACILITY $ 4,032,186

A-31-41 FIRE PROTECTION EQUIPMENT & SYSTEM (COMMON) $ 89,284

A-33-99-1 ANHYDROUS AMMONIA UNLOADING & STORAGE $ 1,847,027

A-35-15-16 2" DIA, CS PLANT AIR - IN PROCESS AREA - $ 17,716

A-35-15-17 2" DIA, CS $ 39,525

A-35-15-18 2" DIA, 316L SS $ 26,803

A-35-15-19 2" DIA, 316L SS $ 80,264

A-35-15-20 2" DIA, CS $ 17,716

A-35-15-21 2" DIA, CS $ 39,525

A-35-15-22 2" DIA, SS WITH CS CARRIER $ 170,853

A-35-15-23 2" DIA, SS WITH CS CARRIER $ 354,282

A-35-15-24 2" DIA, 316L SS $ 26,803

A-35-15-25 2" DIA, 316L SS $ 80,264

A-35-35-18 1" DIA, CS BALL VALVE PLANT AIR - (COMMON) $ 1,800

A-35-35-19 1" DIA, 316L SS BALL VALVE INSTRUMENT AIR - (COMMON) $ 6,000

A-35-35-20 1" DIA, CS BALL VALVE SERVICE WATER - (COMMON) $ 1,800

A-35-35-21 2" DIA, 316L SS BALL VALVE INSTRUMENT AIR - (COMMON) $ 2,600

A-35-35-22 2" DIA, CS GLOBE VALVE SERVICE WATER - (COMMON) $ 540

A-35-35-23 2" DIA, 316L SS GLOBE VALVE AMMONIA - (COMMON $ 2,680

A-35-35-24 2" DIA, 316L SS GLOBE VALVE $ 4,880

A-35-35-25 2" DIA, CS BALL VALVE, AIR OPERATED, ON/OFF $ 5,100

A-35-35-26 2" DIA, SS GLOBE VALVE, AIR OPERATED, ON/OFF $ 12,100

A-36-15-5 2" PIPE, 1 " FIBERGLASS WITH ALUMINUM JACKET PLANT AIR - (COMMON) $ 17,183

A-36-15-6 2" PIPE, 1 " FIBERGLASS WITH ALUMINUM JACKET SERVICE WATER - COMMON $ 17,183

A-36-15-7 2" PIPE, 1 " FIBERGLASS WITH ALUMINUM JACKET POTABLE WATER - COMMON $ 17,183

C-41-35 LIGHTINING PROTECTION $ 24,247

C-41-12 TESTING TEST & DOCUMENTATIONS $ 10,442

D ELECTRICAL AND I & C FOR COMMON AREA $ 1,701,096

H SITEWORK - COMMON FOR UNITS 1, 2 & 3 $ 1,266,525

TOTAL COST $ 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

$ 70,039

$ 7,148,381

$ 5,356,583

$ 10,781,697

$ 13,950,067

$ 858,466

$ 5,670,000

$ 18,881,644

$ 3,796,509

$ 66,513,386
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

$ 5,989,832

$ 3,000,000

$ 2,000,000

$ 1,000,000

$ 748,000

$ 636,000

$ 13,373,832
Salt River Project--Navajo Generating Station Unit #3

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) 8.79E+05 calculated from 9,157 mmBtu/hr total of individual maximum hourly heat input for this boiler in 2002 from ENSR

Average Annual Fuel Consumption (lb) 6.23E+09 calculated from 64,870,571 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 81% calculated from OAQPS Control Cost Manual

Uncontrolled NOx Concentration (lb/mmBtu) 0.343 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) $ 102,021,708 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) $ 192 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) $ 189,772,353 SRP 8/06/10 report

Adjustment for Common costs $ (7,863,427) SRP 8/06/10 report

Adjustment for included Indirect Capital Costs + AFUDC $ (66,513,386) SRP 8/06/10 report

Adjustment for included Owner's costs $ (13,373,832) SRP 8/06/10 report
Salt River Project--Navajo Generating Station Unit #3

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

( 0.34 - 0.24 )/ 0.34 = 30%

Boiler Calculations

2.3 QB = HVm-dotfuel

QB = 10,418 Btu/lb * 878,999 lb/hr

QB = 9,157 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 6.23E+09 lb/yr / 8760 hr/yr / 878,999 lb/hr

CFPlant = 81%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

2.6 CFTotal = CFPlant x CFSCR

CFTotal = 81% * 100%

CFTotal = 81%

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

F)nSCR

qfluegas = 484 ft3/min/(mmBtu/hr)* 9157 mmBtu/hr*( 460 + 670 )/( 460 + 700 )/ 2

qfluegas = 2,158,782 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) 11,118

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

( 0.34 - 0.05 )/ 0.34 = 85%

NOx removed = 9,496 tpy

Controlled NOx emissions (tpy) = 1,622 tpy
Salt River Project--Navajo Generating Station Unit #3

SCR Reactor Calculations

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

Volcatalyst = 2.81 * 9157 = 25732

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 = 16,891 ft3 each = 479 m3 each

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

Acatalyst = 2,158,782 /( 16 * 60 )

Acatalyst = 2,249 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 2,249

ASCR = 2,586 ft2

2.27 l = w = ASCR

1/2

l = w = 50.9 ft

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

nlayer = 16,891 /( 3.1 * 2,249 )

nlayer (calc) = 2.0

nlayer = 2.0

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

hlayer = 16,891 /( 2.0 * 2,249 ) + 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 #3

Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.24 * 9157 * 1.05 * 79% * 17.03 / 46.01

m-dotreagent = 676 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 676 / 0.29

m-dotsol = 2300 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 2300 * 7.481 / 56

qsol = 307 gph

2.35 Tank Volume = qsolt

Tank Volume = 307 * 14 * 24

Tank Volume = 103,239 gal
Salt River Project--Navajo Generating Station Unit #3

Direct Capital Cost

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

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

0.35 + f(Volcatalyst)

DC = 4579 (( $ 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 * 676 / 9157 - 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) = 16,891 * 198

f(Volcatalyst) = $ 3,350,731

DC = 4579 * ( $ 4,827 + $ 221 + $ (24) + $ - + $ - )*( 3500 / 4579 )^ 0.35 + $ 3,350,731

DC = $ 24,288,351 for each reactor

DC = $ 48,576,702 for all reactors
Salt River Project--Navajo Generating Station Unit #3

Indirect Capital Costs Cost Manual SRP

Cost Cost Cost Cost

Total Direct Capital Costs, A $ 48,576,702 ratios $ 102,021,708 ratios

Indirect Installation Costs 

General Facilities 0.05 A $2,428,835 5%

Engineering and Home Office Fees 0.10 A $4,857,670 10%

Process Contingencies 0.05 A $2,428,835 5%

Total Indirect Installation Costs, B 0.20 A = $9,715,340 20%

Project Contingency, C = 0.15 (A+B) = $8,743,806 18% $ 18,881,644 19%

Total Plant Cost D = A+B+C $67,035,849 138%

Allowance for Funds During Construction, E = 0 $0 0% $ 3,796,509 4%

Royalty Allowance, F = 0 $0 0%

Preproduction Cost, G = 0.02 (D+E) $1,340,717 3%

Inventory Capital, H =

Initial Catalyst and Chemicals, I = 0.0698 /lb * 2300 lb/r * 24 hr/day * 14 days = $53,961 0%

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $68,430,527 141% $ 189,772,353 186%

Cost/kW = $91 $ 253

Total Capital Investment TCI @ 192 $/kW = $143,719,087 $ 143,719,087

$ 192

Lost Generation cost = $ 5,670,000

Total Capital Investment TCI = $153,185,596

$ 204
Salt River Project--Navajo Generating Station Unit #3

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 * $ 153,185,596

Annual Maintenance Cost = $ 2,297,784 $ 395,000 SRP 8/17/10 report

2.47 Annual Reagent Cost = qreagentCostreagenttop

2.47a top = CFtotal8760hr/yr

top = 81% * 8760

top = 7084

Annual Reagent Cost = 2300 * 7084 * 0.069825

Annual Reagent Cost = $ 1,137,671 $ 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 * 9157 *( 0.24 * 79% + 0.5 * ( 3 + 4 * 1 ))

Power = 3548 kW

Annual Electricity Cost = 3548 * 7084 * 0.045

Annual Electricity Cost = $ 1,131,035 $ 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 * 16891 * 198 / 2

Catalyst Replacement Cost = $ 3,350,731

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

-1]}

2.53 Y = hcatalyst/hyear

Y = 24000 /( 81% * 8760 )

Y = 3.39

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

FWF = 0.31

Annual Catalyst Cost = $ 1,042,251 $ 672,000 SRP 8/17/10 report

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

Annual natural gas Cost = $ -

Lost Ash Sales =

DAC = $ 5,608,740 $ 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 * $ 153,185,596

Indirect Annual Cost = $ 14,459,637 $ 27,835,000 SRP 8/17/10 report

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

Total Annual Cost = $ 5,608,740 + 14,459,637

Total Annual Cost = $ 20,068,377 + $ 1,622,000 = $ 21,690,377 $ 31,746,000

2.57 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.24 * 79% * 9157 * 7084 / 2000

NOx Removed = 6,163

Total NOx Removed = 9,496

2.58 Cost effectiveness = TAC/NOx removed

SCR Cost effectiveness = $ 3,256

Total Cost effectiveness = $ 2,284
Operating company Salt River Project

Facility Navajo Generating Station 

State NN

Contact

Proposed Controls SCR

Unit Unit #3

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) 9,157 mmBtu/hr total of individual maximum hourly heat input for this boiler in 2002 from ENSR

Uncontrolled Emissions (tpy) 11,118 OAQPS Control Cost Manual

Uncontrolled Emissions (lb/mmBtu) 0.34 EPA CAM data for 2000 - 2009

Combustion Controls Cost-benefit Analysis

Control Efficiency 30% calculated

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

Controlled Emissions (tpy) 7,784 calculated

Emissions Reduction (tpy) 3,333 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) $ 487 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) 1,622 calculated

Emissions Reduction (tpy) 6,163 OAQPS Control Cost Manual

Capital Cost $ 153,185,596 calculated

Capital Cost ($/kW) $ 204 calculated

O&M Cost $ 5,608,740 OAQPS Control Cost Manual

Annualized Cost $ 20,068,377 OAQPS Control Cost Manual

Cost-Effectiveness ($/ton) $ 3,256 OAQPS Control Cost Manual

Combustion Controls + SCR Cost-benefit Analysis

Control Efficiency 85% calculated

Controlled emissions (lb/mmBtu) 0.05 calculated

Controlled Emissions (tpy) 1,622 calculated

Emissions Reduction (tpy) 9,496 calculated

Capital Cost $ 167,185,596 calculated

Capital Cost ($/kW) $ 223 calculated

O&M Cost $ 5,608,740 calculated

Annualized Cost $ 21,690,377 calculated

Cost-Effectiveness ($/ton) $ 2,284 calculated