# 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) **TOTA L COST** 

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

## = HVm-dot fuel 

### QB = 10,418 Btu/lb * 911,711 lb/hr QB = 9,498 Btu/hr



## 2.7 CF Plant 

## = actual m fuel 

## /maximum m fuel 

### CFPlant = 6.24E+09 lb/y r / 8760 hr/yr / 911,711 lb/hr CFPlant = 78%



## 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 = 78% * 100% CFTotal = 78%



## 2.12 q fluegas 

## = q fuel 

## Q B 

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

## F)n SCR 

### 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 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 )**  **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 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 * 9498 = 26690



# 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 = 17,520 ft3 each = 496 m3 each



# 2.25 A catalyst



# = q fluegas 

# /(16 ft/sec x 60 sec/min) Acatalyst = 2,239,119 /( 16 * 60 ) Acatalyst = 2,332 ft2



# 2.26 A SCR



# = 1.15 x A catalyst 

## ASCR = 1.15 * 2,332 ASCR = 2,682 ft2



# 2.27 l = w = A SCR 1/2



## l = w = 51.8 ft



# 2.28 n layer 

# = Vol catalyst 

# /(h’ layer



# x A catalyst 

# ) nlayer = 17,520 /( 3.1 * 2,332 ) nlayer (calc) = 2.0 nlayer = 2.0



# 2.29 h layer 

# = [Vol catalyst 

# /(n layer



# x A catalyst 

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

**Reagent Calculations**



# 2.32 m- dot reagent



# = NOx in 

# Q B 

# ASR

**η NOx**  

# M reagent



# /M NOx 

## m-dotreagent = 0.24 * 9498 * 1.05 * **79%** * 17.03 / 46.01 m-dotreagent = 701 lb/hr



# 2.33 m- dot sol 

# = m -dot reagent 

# /C sol 

## m-dotsol = 701 / 0.29 m-dotsol = 2386 lb/hr



# 2.34 q sol 

# = (m -dot vol 

# /ρ sol 

# )V sol 

## qsol = 2386 * 7.481 / 56 qsol = 319 gph



# 2.35 Tank Volume = q sol 

# t Tank Volume = 319 * 14 * 24 Tank Volume = 107,080 gal

### Salt River Project--Navajo Generating Station **Unit #1**

**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 = 4749 (( 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 * 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(Vol catalyst 

## ) = Vol catalyst 

## CCinitial 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 $ fo r each reactor DC = 49,832,524 $ fo r 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 = q reagent Cost reagent t op 2.47a t op = **CF total**  8760hr/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 (Cost elect) t op 2.48 **Power = 0.105Q B**  **[NOx in**  **ηNOx + 0.5(ΔP duct**  **+ n total**  **ΔP catalyst**  **)]** 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 = n SCR Vol catalyst CC replace /R layer Catalyst Replacement Cost = 2 * 17520 * 198 / 2 Catalyst Replacement Cost = 3,475,425 $ 1 FWF = i{1/[(1+i) Y -1]} 2.53 Y = h catalyst

/h year 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 = NOx in η NOx Q B t op 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