### 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)
**TOTA L COST** **TOTA L 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 W eight (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 W eight (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 ($/kW h) 0.045 from SRP letter of 7/29/08 45.00 $ /MW h 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 Q B 

### = HVm-dot fuel QB = 10,418 Btu/lb * 904,492 lb/hr QB = 9,423 Btu/hr



### 2.7 CF Plant 

### = actual m fuel 

### /maximum m fuel CFPlant = 6.30E+09 lb/y r / 8760 hr/yr / 904,492 lb/hr CFPlant = 80%



### 2.8 CF SCR 

### = t SCR



### /365 day s CFSCR = 365 day s/ 365 day s CFSCR = 100%

2.6 

### CF Total 

### = CF Plant 

### x CF SCR CFTotal = 80% * 100% CFTotal = 80%



### 2.12 q fluegas 

### = q fuel 

### Q B 

### (460+T)/(460+700 o 

### F)n SCR 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 η NOx 

### = (NOx in 

### – NOx out 

### ) / NOx in 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 Vol catalyst



### = 2.81 x Q B 

### x η adj 

### x Slip adj 

### x NOx adj 

### x S adj 

### x T adj 

### /N SCR Volcatalyst = 2.81 * 9423 = 26479



### 2.2 η adj 

### = 0.2869 + (1.058 x η) ηadj = 0.2869 +( 1.058 * 0.79 ) ηadj = 1.124 

### 2.22 Slip adj 

### = 1.2835 – (0.0567 x Slip) Slipadj = 1.2835 - ( 0.0567 * 2 ) Slipadj = 1.170 

### 2.21 NOx adj 

### = 0.8524 + (0.3208 x NOx in 

### ) NOxadj = 0.8524 + ( 0.3208 * 0.24 ) NOxadj = 0.929 

### 2.23 S adj 

### = 0.9636 + (0.0455 x S) Sadj = 0.9636 + ( 0.0455 * 0.63 ) Sadj = 0.9923 

### 2.24 T adj 

### = 15.16 – (0.03937 x T) + (2.74 x 10 -5 

### x T 2 

### ) Tadj = 15.16 - ( 0.0394 * 670 ) + 2.74E-05 * 448,900 Tadj = 1.082 Volcatalyst = 17,381 ft3 each = 493 m3 each



### 2.25 A catalyst



### = q fluegas 

### /(16 ft/sec x 60 sec/min) Acatalyst = 2,221,391 /( 16 * 60 ) Acatalyst = 2,314 ft2



### 2.26 A SCR



### = 1.15 x A catalyst ASCR = 1.15 * 2,314 ASCR = 2,661 ft2



### 2.27 l = w = A SCR 1/2

l = w = 51.6 ft



### 2.28 n layer 

### = Vol catalyst 

### /(h’ layer



### x A catalyst 

### ) nlayer = 17,381 /( 3.1 * 2,314 ) nlayer (calc) = 2.0 nlayer = 2.0



### 2.29 h layer 

### = [Vol catalyst 

### /(n layer



### x A catalyst 

### )] + 1 hlayer = 17,381 /( 2.0 * 2,314 ) + 1 hlayer = 4.8



### 2.3 n total 

### = n layer



### + n empty ntotal = 2 + 2 ntotal = 4



### 2.31 h SCR 

### = n total 

### (c 1 

### + h laye 

### r) + c 2 hSCR = 4 * ( 7 + 4.8 ) + 9 hSCR = 56 ft

### Salt River Project--Navajo Generating Station **Unit #2**

**Reagent Calculations**



### 2.32 m- dot reagent



### = NOx in 

### Q B 

### ASR

**η NOx**  

### M reagent



### /M NOx 

### m-dotreagent = 0.24 * 9423 * 1.05 * **79%** * 17.03 / 46.01 m-dotreagent = 696 lb/hr



### 2.33 m- dot sol 

### = m -dot reagent 

### /C sol 

### m-dotsol = 696 / 0.29 m-dotsol = 2367 lb/hr



### 2.34 q sol 

### = (m -dot vol 

### /ρ sol 

### )V sol 

### qsol = 2367 * 7.481 / 56 qsol = 316 gph



### 2.35 Tank Volume = q sol 

### t Tank Volume = 316 * 14 * 24 Tank Volume = 106,233 gal**Salt River Project--Navajo Generating Station Unit #2** 

**Direct Capital Cost**

########## DC = Q B [($3380/MMBtu/hr) + f(h SCR ) +f(NH 3 rate) + f(new) + f(bypass)](3500/Q B ) 0.35 + f(Vol catalyst )

DC = 4712 (( 3,380 $ /mmBtu/hr * inflation = 4,827 $ 2.37 f(h SCR ) = {[$612/(ft-mmBtu/hr)]h SCR } - $187.9/(mmBtu/hr) f(hSCR) = 6.12 * 56

- 187.9 f(hSCR) = 155

$ /mmBtu/hr * inflation = 221 $

2.38 f(NH 3 rate) = [($411/lb/hr)(m-dot reagent /Q B )] - $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(Vol catalyst ) = Vol catalyst CCinitial 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 $ fo r each reactor DC = 49,556,506 $ fo r 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 = q reagent Cost reagent t op 2.47a t op = **CF total**  8760hr/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 (Cost elect) t op 2.48 **Power = 0.105Q B**  **[NOx in**  **ηNOx + 0.5(ΔP duct**  **+ n total**  **ΔP catalyst**  **)]** 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 = n SCR Vol catalyst CC replace /R layer Catalyst Replacement Cost = 2 * 17381 * 198 / 2 Catalyst Replacement Cost = 3,447,909 $ 1 FWF = i{1/[(1+i) Y -1]} 2.53 Y = h catalyst

/h year 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 = NOx in η NOx Q B t op 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