### 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** We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone We t Lim estone

### 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)
**TOTA L COST** 

### TOTA **L 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 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) 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 ($/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) 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 Q B 

### = HVm-dot fuel QB = 10,418 Btu/lb * 878,999 lb/hr QB = 9,157 Btu/hr



### 2.7 CF Plant 

### = actual m fuel 

### /maximum m fuel CFPlant = 6.23E+09 lb/y r / 8760 hr/yr / 878,999 lb/hr CFPlant = 81%



### 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 = 81% * 100% CFTotal = 81%



### 2.12 q fluegas 

### = q fuel 

### Q B 

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

### F)n SCR 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 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 )**  **11,118**

**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 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 * 9157 = 25732



### 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 = 16,891 ft3 each = 479 m3 each



### 2.25 A catalyst



### = q fluegas 

### /(16 ft/sec x 60 sec/min) Acatalyst = 2,158,782 /( 16 * 60 ) Acatalyst = 2,249 ft2



### 2.26 A SCR



### = 1.15 x A catalyst ASCR = 1.15 * 2,249 ASCR = 2,586 ft2



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

l = w = 50.9 ft



### 2.28 n layer 

### = Vol catalyst 

### /(h’ layer



### x A catalyst 

### ) nlayer = 16,891 /( 3.1 * 2,249 ) nlayer (calc) = 2.0 nlayer = 2.0



### 2.29 h layer 

### = [Vol catalyst 

### /(n layer



### x A catalyst 

### )] + 1 hlayer = 16,891 /( 2.0 * 2,249 ) + 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 #3**

**Reagent Calculations**



## 2.32 m- dot reagent



## = NOx in 

## Q B 

## ASR

**η NOx**  

## M reagent



## /M NOx 

### m-dotreagent = 0.24 * 9157 * 1.05 * **79%** * 17.03 / 46.01 m-dotreagent = 676 lb/hr



## 2.33 m- dot sol 

## = m -dot reagent 

## /C sol 

### m-dotsol = 676 / 0.29 m-dotsol = 2300 lb/hr



## 2.34 q sol 

## = (m -dot vol 

## /ρ sol 

## )V sol 

### qsol = 2300 * 7.481 / 56 qsol = 307 gph



## 2.35 Tank Volume = q sol 

## t
Tank Volume = 307 * 14 * 24 Tank Volume = 103,239 gal**Salt River Project--Navajo Generating Station Unit #3** 

**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 = 4579 (( 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 * 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(Vol catalyst 

### ) = Vol catalyst 

### CCinitial 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 $ fo r each reactor DC = 48,576,702 $ fo r 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 = q reagent Cost reagent t op 2.47a t op = **CF total**  8760hr/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 (Cost elect) t op 2.48 **Power = 0.105Q B**  **[NOx in**  **ηNOx + 0.5(ΔP duct**  **+ n total**  **ΔP catalyst**  **)]**
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 = n SCR Vol catalyst CC replace /R layer Catalyst Replacement Cost = 2 * 16891 * 198 / 2 Catalyst Replacement Cost = 3,350,731 $
1 FWF = i{1/[(1+i) Y -1]}
2.53 Y = h catalyst

/h year 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 = NOx in η NOx Q B t op 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