OP YEAR STATE FACILITY NAME

ORISPL 

CODE UNIT ID UNIT TYPE INFO

PRIMARY 

FUEL INFO

2000 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2001 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2002 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2003 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2004 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2005 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2006 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2007 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2008 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2009 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2010 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal

2011 AZ Navajo Generating Station 4941 1 Tangentially-fired Coal
SO2 CONTROL INFO NOX CONTROL INFO

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other

Wet Limestone Other
PART CONTROL INFO

Electrostatic Precipitator Wet Scrubber

Electrostatic Precipitator Wet Scrubber

Baghouse
FACILITY NAME

ORISPL 

CODE UNIT ID OP YEAR

SUM OP 

TIME

NUM 

MONTHS 

REPORTED GLOAD SO2 MASS SO2 RATE NOX RATE NOX MASS CO2 MASS HEAT INPUT

CAPACITY 

INPUT NOX CONTROL INFO

Navajo Generating Station 4941 1 1995 0 21,983 0.898 0.384 9,401 4,983,520 48,934,515

Navajo Generating Station 4941 1 1996 0 17,992 0.923 0.344 6,718 4,001,040 39,003,286

Navajo Generating Station 4941 1 1997 8,559 12 28,582 0.960 0.362 10,951 6,109,679 59,548,529 6,958

Navajo Generating Station 4941 1 1998 8,559 12 28,288 0.908 0.392 12,437 6,392,090 62,301,069 7,279

Navajo Generating Station 4941 1 1999 7,500 12 5,854 0.197 0.392 12,144 6,109,928 59,551,003 7,940

Navajo Generating Station 4941 1 2000 8,615 12 1,206 0.038 0.406 13,005 6,515,439 63,503,234 7,371

Navajo Generating Station 4941 1 2001 7,904 12 1,063 0.037 0.370 10,841 5,878,709 57,297,412 7,249

Navajo Generating Station 4941 1 2002 8,517 12 1,273 0.039 0.354 11,631 6,684,087 65,147,475 7,649

Navajo Generating Station 4941 1 2003 7,598 12 1,099 0.036 0.336 10,272 6,197,593 60,405,414 7,950

Navajo Generating Station 4941 1 2004 8,563 12 1,346 0.039 0.359 12,606 7,117,833 69,374,752 8,102

Navajo Generating Station 4941 1 2005 7,234 12 1,192 0.040 0.352 10,594 6,091,527 59,371,589 8,207

Navajo Generating Station 4941 1 2006 8,580 12 1,216 0.034 0.344 12,263 7,256,846 70,729,515 8,243

Navajo Generating Station 4941 1 2007 8,354 12 1,606 0.046 0.378 13,231 7,127,351 69,467,378 8,316

Navajo Generating Station 4941 1 2008 7,980 12 1,412 0.044 0.368 12,051 6,594,965 64,278,422 8,055

Navajo Generating Station 4941 1 2009 8,583 12 1,857 0.053 0.379 13,531 7,224,612 70,415,312 8,204

Navajo Generating Station 4941 1 2010 8,488 12 6,468,160 1,783 0.055 0.386 12,643 6,639,514 64,712,615 7,624

Totals 90,416 15,051 132,666 73,328,477 714,703,119 86,971

Averages 8,220 1,368 0.042 0.371 12,061 6,666,225 64,973,011 7,906

1
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 Common 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

$ 70,039

$ 5,754,981

$ 4,247,315

$ 9,506,574

$ 10,538,367

$ 648,515

$ 5,670,000

$ 15,224,333

$ 3,053,632

$ 54,713,756
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

$ 4,753,287

$ 3,000,000

$ 2,000,000

$ 1,000,000

$ 585,000

$ 491,000

$ 11,829,287
Salt River Project--Navajo Generating Station Unit #1

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) 9.12E+05 calculated from 9,498 mmBtu/hr maximum hourly heat input for this boiler in 2006 from CAM

Average Annual Fuel Consumption (lb) 6.24E+09 calculated from 64,973,011 mmBtu 2000 - 2010 average total heat input for this boiler from CAMD

Number of SCR Operating Days 365 assumed 8,760 assumed

Plant Capacity Factor 78% calculated from OAQPS Control Cost Manual

Uncontrolled NOx Concentration (lb/mmBtu) 0.371 EPA CAM data for 2000 - 2010

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) $ 89,213,417 calculated from SRP "Response to NPS for direct costs - SCR - U1"

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

Include Allowance for Funds Allocated During Construction (AFUDC)? Yes SRP "Response to NPS for direct costs - SCR - U1"

Override Cost Manual TCI? ($/kW) $ 168 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) $ 151,824,747 SRP "Response to NPS for direct costs - SCR - U1"

Adjustment for Common costs $ 3,931,713 SRP "Response to NPS for direct costs - SCR - U1"

Adjustment for included Indirect Capital Costs + AFUDC $ (54,713,756) SRP "Response to NPS for direct costs - SCR - U1"

Adjustment for included Owner's costs $ (11,829,287) SRP "Response to NPS for direct costs - SCR - U1"
Salt River Project--Navajo Generating Station Unit #1

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

( 0.37 - 0.24 )/ 0.37 = 35%

Boiler Calculations

2.3 QB = HVm-dotfuel

QB = 10,418 Btu/lb * 911,711 lb/hr

QB = 9,498 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 6.24E+09 lb/yr / 8760 hr/yr / 911,711 lb/hr

CFPlant = 78%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

2.6 CFTotal = CFPlant x CFSCR

CFTotal = 78% * 100%

CFTotal = 78%

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

F)nSCR

qfluegas = 484 ft3/min/(mmBtu/hr)* 9498 mmBtu/hr*( 460 + 670 )/( 460 + 700 )/ 2

qfluegas = 2,239,119 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) 12,061

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

( 0.37 - 0.05 )/ 0.37 = 87%

NOx removed = 10,436 tpy

Controlled NOx emissions (tpy) = 1,624 tpy
Salt River Project--Navajo Generating Station Unit #1

SCR Reactor Calculations

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

Volcatalyst = 2.81 * 9498 = 26690

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 = 17,520 ft3 each = 496 m3 each

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

Acatalyst = 2,239,119 /( 16 * 60 )

Acatalyst = 2,332 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 2,332

ASCR = 2,682 ft2

2.27 l = w = ASCR

1/2

l = w = 51.8 ft

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

nlayer = 17,520 /( 3.1 * 2,332 )

nlayer (calc) = 2.0

nlayer = 2.0

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

hlayer = 17,520 /( 2.0 * 2,332 ) + 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 #1

Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.24 * 9498 * 1.05 * 79% * 17.03 / 46.01

m-dotreagent = 701 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 701 / 0.29

m-dotsol = 2386 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 2386 * 7.481 / 56

qsol = 319 gph

2.35 Tank Volume = qsolt

Tank Volume = 319 * 14 * 24

Tank Volume = 107,080 gal
Salt River Project--Navajo Generating Station Unit #1

Direct Capital Cost

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

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

0.35 + f(Volcatalyst)

DC = 4749 (( $ 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 * 701 / 9498 - 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) = 17,520 * 198

f(Volcatalyst) = $ 3,475,425

DC = 4749 * ( $ 4,827 + $ 221 + $ (24) + $ - + $ - )*( 3500 / 4749 )^ 0.35 + $ 3,475,425

DC = $ 24,916,262 for each reactor

DC = $ 49,832,524 for all reactors
Salt River Project--Navajo Generating Station Unit #1

Indirect Capital Costs Cost Manual SRP

Cost Cost Cost Cost

Total Direct Capital Costs, A $ 49,832,524 ratios $ 89,213,417 ratios

Indirect Installation Costs 

General Facilities 0.05 A $2,491,626 5%

Engineering and Home Office Fees 0.10 A $4,983,252 10%

Process Contingencies 0.05 A $2,491,626 5%

Total Indirect Installation Costs, B 0.20 A = $9,966,505 20%

Project Contingency, C = 0.15 (A+B) = $8,969,854 18% $ 15,224,333 17%

Total Plant Cost D = A+B+C $68,768,883 138%

Allowance for Funds During Construction, E = 0 $0 0% $ 3,053,632 3%

Royalty Allowance, F = 0 $0 0%

Preproduction Cost, G = 0.02 (D+E) $1,375,378 3%

Inventory Capital, H =

Initial Catalyst and Chemicals, I = 0.0698 /lb * 2386 lb/r * 24 hr/day * 14 days = $55,969 0%

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $70,200,230 141% $ 151,824,747 170%

Cost/kW = $94 $ 202

Total Capital Investment TCI @ 168 $/kW = $125,677,006 $ 125,677,006

$ 168

Lost Generation cost = $ 5,670,000

Total Capital Investment TCI = $134,400,638

$ 179
Salt River Project--Navajo Generating Station Unit #1

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 * $ 134,400,638

Annual Maintenance Cost = $ 2,016,010 $ 395,000 SRP 8/17/10 report

2.47 Annual Reagent Cost = qreagentCostreagenttop

2.47a top = CFtotal8760hr/yr

top = 78% * 8760

top = 6841

Annual Reagent Cost = 2386 * 6841 * 0.069825

Annual Reagent Cost = $ 1,139,467 $ 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 * 9498 *( 0.24 * 79% + 0.5 * ( 3 + 4 * 1 ))

Power = 3680 kW

Annual Electricity Cost = 3680 * 6841 * 0.045

Annual Electricity Cost = $ 1,132,821 $ 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 * 17520 * 198 / 2

Catalyst Replacement Cost = $ 3,475,425

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

-1]}

2.53 Y = hcatalyst/hyear

Y = 24000 /( 78% * 8760 )

Y = 3.51

FWF = 0.07 *( 1 /( 1 + 0.07 )^ 4 - 1 )

FWF = 0.23

Annual Catalyst Cost = $ 782,763 $ 672,000 SRP 8/17/10 report

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

Annual natural gas Cost = $ -

Lost Ash Sales =

DAC = $ 5,071,061 $ 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 * $ 134,400,638

Indirect Annual Cost = $ 12,686,469 $ 17,597,000 SRP 8/17/10 report

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

Total Annual Cost = $ 5,071,061 + 12,686,469

Total Annual Cost = $ 17,757,531 + $ 1,622,000 = $ 19,379,531 $ 21,508,000

2.57 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.24 * 79% * 9498 * 6841 / 2000

NOx Removed = 6,172

Total NOx Removed = 10,436

2.58 Cost effectiveness = TAC/NOx removed

SCR Cost effectiveness = $ 2,877

Total Cost effectiveness = $ 1,857
Operating company Salt River Project

Facility Navajo Generating Station 

State NN

Contact

Proposed Controls SCR

Unit Unit #1

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) 9,498 mmBtu/hr maximum hourly heat input for this boiler in 2006 from CAM

Uncontrolled Emissions (tpy) 12,061 OAQPS Control Cost Manual

Uncontrolled Emissions (lb/mmBtu) 0.37 EPA CAM data for 2000 - 2010

Combustion Controls Cost-benefit Analysis

Control Efficiency 35% calculated

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

Controlled Emissions (tpy) 7,797 calculated

Emissions Reduction (tpy) 4,264 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) $ 380 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) 1,624 calculated

Emissions Reduction (tpy) 6,172 OAQPS Control Cost Manual

Capital Cost $ 134,400,638 calculated

Capital Cost ($/kW) $ 179 calculated

O&M Cost $ 5,071,061 OAQPS Control Cost Manual

Annualized Cost $ 17,757,531 OAQPS Control Cost Manual

Cost-Effectiveness ($/ton) $ 2,877 OAQPS Control Cost Manual

Combustion Controls + SCR Cost-benefit Analysis

Control Efficiency 87% calculated

Controlled emissions (lb/mmBtu) 0.05 calculated

Controlled Emissions (tpy) 1,624 calculated

Emissions Reduction (tpy) 10,436 calculated

Capital Cost $ 148,400,638 calculated

Capital Cost ($/kW) $ 198 calculated

O&M Cost $ 5,071,061 calculated

Annualized Cost $ 19,379,531 calculated

Cost-Effectiveness ($/ton) $ 1,857 calculated