## OP_YEAR STATE FACILITY_NAME ORISPL_CODE UNITID OP_STATUS_INFO

PRG_CODE_INFO

UIT_TYPE_INFO

PRIMARY_FUEL_INFO
2000 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2001 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2002 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2003 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2004 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2005 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2006 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2007 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2008 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2009 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2010 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal
2011 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal

## SO2_CONTROL_INFO

Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD
Wet Lime FGD

## NOX_CONTROL_INFO

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

## PART_CONTROL_INFO

Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator Electrostatic Precipitator

## STATE FACILITY NAME ORISPL
CODE UNIT ID OP YEAR SUM OP TIME NUM

MONTHS REPORTE D SO2

MASS


## ND Coal Creek 6030 CCS #1 2000 8,637 

## 12 14,332


## ND Coal Creek 6030 CCS #1 2001 8,547 

## 12 14,630


## ND Coal Creek 6030 CCS #1 2002 7,836 

## 12 11,910


## ND Coal Creek 6030 CCS #1 2003 8,567 

## 12 13,817


## ND Coal Creek 6030 CCS #1 2004 8,466 

## 12 15,742


## ND Coal Creek 6030 CCS #1 2005 7,863 

## 12 13,150


## ND Coal Creek 6030 CCS #1 2006 8,531 

## 12 16,425


## ND Coal Creek 6030 CCS #1 2007 8,586 

## 12 15,845


## ND Coal Creek 6030 CCS #1 2008 7,154 

## 12 10,735


## ND Coal Creek 6030 CCS #1 2009 8,583 

## 12 14,315


## ND Coal Creek 6030 CCS #1 2010 8,575 

## 12 9,438



## ND Coal Creek 6030 CCS #2 2000 8,430 

## 12 12,816


## ND Coal Creek 6030 CCS #2 2001 8,028 

## 12 11,683


## ND Coal Creek 6030 CCS #2 2002 8,661 

## 12 12,518


## ND Coal Creek 6030 CCS #2 2003 8,613 

## 12 13,547


## ND Coal Creek 6030 CCS #2 2004 7,949 

## 12 11,469


## ND Coal Creek 6030 CCS #2 2005 8,527 

## 12 14,240


## ND Coal Creek 6030 CCS #2 2006 8,591 

## 12 15,659


## ND Coal Creek 6030 CCS #2 2007 7,555 

## 12 12,462


## ND Coal Creek 6030 CCS #2 2008 8,352 

## 12 12,408


## ND Coal Creek 6030 CCS #2 2009 8,210 

## 12 14,323


## ND Coal Creek 6030 CCS #2 2010 7,307 

## 12 8,678

## SO2

RATE NOX
RATE NOX

MASS CO2 MASS HEAT INPUT (mmBtu/y r) HEAT

INPUT (mmBtu/hr)


## 0.565 0.215 5,376 5,526,540 50,762,867 5,878


## 0.564 0.212 5,483 5,649,335 51,890,722 6,071


## 0.511 0.210 4,863 5,077,116 46,634,656 5,952


## 0.539 0.204 5,197 5,584,300 51,293,286 5,987


## 0.612 0.217 5,552 5,598,944 51,427,776 6,074


## 0.547 0.234 5,594 5,232,335 48,060,404 6,112


## 0.646 0.237 6,006 5,538,103 50,868,954 5,963


## 0.634 0.249 6,203 5,443,133 49,996,622 5,823


## 0.511 0.253 5,331 4,577,606 42,046,482 5,878


## 0.577 0.244 6,023 5,402,721 49,625,416 5,782


## 0.382 0.211 5,199 5,379,248 49,409,811 5,762



## 0.533 0.223 5,291 5,234,588 48,081,394 5,703


## 0.507 0.230 5,250 5,019,726 46,107,773 5,744


## 0.495 0.218 5,492 5,509,932 50,610,222 5,843


## 0.535 0.221 5,556 5,513,004 50,638,401 5,880


## 0.499 0.236 5,391 5,000,236 45,928,500 5,778


## 0.566 0.243 6,084 5,481,116 50,345,570 5,904


## 0.614 0.255 6,483 5,556,375 51,036,813 5,940


## 0.577 0.198 4,260 4,698,631 43,158,180 5,713


## 0.520 0.174 4,126 5,194,201 47,710,283 5,713


## 0.594 0.192 4,623 5,249,772 48,220,581 5,873


## 0.413 0.166 3,473 4,572,384 41,998,558 5,748**CAMD Emissions Data**



### STATE FACILITY NAME ORISPL
CODE UNIT ID OP YEAR SUM OP TIME NUM

MONTHS REPORTE D SO2

MASS 

### SO2

RATE NOX
RATE NOX

MASS CO2 MASS HEAT INPUT (mmBtu/y r) HEAT

INPUT (mmBtu/hr)


### ND Coal Creek 6030 CCS #1 2000 8,637 

### 12 14,332 

### 0.565 0.215 5,376 5,526,540 50,762,867 5,878


### ND Coal Creek 6030 1 2001 8,547 

### 12 14,630 

### 0.564 0.212 5,483 5,649,335 51,890,722 6,071


### ND Coal Creek 6030 1 2002 7,836 

### 12 11,910 

### 0.511 0.210 4,863 5,077,116 46,634,656 5,952


### ND Coal Creek 6030 1 2003 8,567 

### 12 13,817 

### 0.539 0.204 5,197 5,584,300 51,293,286 5,987


### ND Coal Creek 6030 1 2004 8,466 

### 12 15,742 

### 0.612 0.217 5,552 5,598,944 51,427,776 6,074


### ND Coal Creek 6030 1 2005 7,863 

### 12 13,150 

### 0.547 0.234 5,594 5,232,335 48,060,404 6,112


### ND Coal Creek 6030 1 2006 8,531 

### 12 16,425 

### 0.646 0.237 6,006 5,538,103 50,868,954 5,963


### ND Coal Creek 6030 1 2007 8,586 

### 12 15,845 

### 0.634 0.249 6,203 5,443,133 49,996,622 5,823


### ND Coal Creek 6030 1 2008 7,154 

### 12 10,735 

### 0.511 0.253 5,331 4,577,606 42,046,482 5,878


### ND Coal Creek 6030 1 2009 8,583 

### 12 14,315 

### 0.577 0.244 6,023 5,402,721 49,625,416 5,782


### ND Coal Creek 6030 1 2010 8,575 

### 12 9,438 

### 0.382 0.211 5,199 5,379,248 49,409,811 5,762 

### Totals 91,345 150,337 60,826 59,009,382 542,016,996 65,282 

### Averages 8,304 13,667 

### 0.224 5,530 5,364,489 49,274,272 5,935 2000 - 2004 totals 42,053 70,431 26,470 27,436,235 252,009,307 29,962 2000 - 2004 Averages 8,411 0.210 5,294 50,401,861

### 0.2

0.25 0.3**N O** **x E** **m i** **s s** **i o** **n s** **( l** **b /** **m m** **B t** **u )**  

# Coal Cr **eek NOx Emission Rates**

CCS #1

CCS #2

0 0.05 0.1 0.15

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010**N O** **x E** **m i** **s s** **i o** **n s** **( l** **b /** **m m** **B t** **u )** 



### Year

### 4000

5000 6000 7000**N O** **x E** **m i** **s s** **i o** **n s** **( t** **p y** **)** 

# Coal Cr **eek NOx Mass Emissions**

CCS #1

CCS #2

0 1000 2000 3000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010**N O** **x E** **m i** **s s** **i o** **n s** **( t** **p y** **)**



### Year**Coal Creek Station 1**  **Modified from OAQPS Control Cost Manual Section 4.2, SCR**

**Given/Assumptions** New or Retrofit? Retrofit ND DOH SIP Appendix B.2 report Generation capacity (MW) 550 ND DOH SIP Appendix B.2 report Override Cost Manual TCC? ($/kW) 280 $ EPA IPM 2010 report SCR bypass included? Yes company 7/15/11 report Table A-13 Fuel High Heating Value (Btu/lb) 6,257 company 7/15/11 report Table A-15 Maximum Fuel Consumption Rate (lb/hr) 961,323 calculated from 6,015 mmBtu/hr ND DOH SIP Appendix B.2 report Average Annual Fuel Consumption (lb) 8.06E+09 calcuated from 50,401,861 mmBtu/yr from 2000 - 2004 CAM data Number of SCR Operating Days 365 calcuated from 8760 hr/yr Plant Capacity Factor 96% calcuated Uncontrolled NOx Concentration (lb/mmBtu) 0.210 from 2000 - 2004 CAM data LNB + OFA Total Capital Cost 4,913,299 $ company 7/15/11 report Table A-16 LNB + OFA Total Annual Cost 620,419 $ company 7/15/11 report Table A-16 LNB outlet = SCR inlet NOx Concentration (lb/mmBtu) 0.150 ND DOH SIP Appendix B.2 report Required Controlled NOx Concentration (lb/mmBtu) 0.043 ND DOH SIP Appendix B.2 report Acceptable Ammonia Slip (ppm) 2.0 OAQPS Control Cost Manual Fuel Volume Flow Rate (ft3/min/mmBtu/hr) 547 OAQPS Control Cost Manual Fuel Sulfur Content 0.61% company 12/07 report Table A-2 Fuel Ash Content 10.74% company 12/07 report Table A-2 Number of SCR reactor chambers 2 assumed Number of spare catalyst layers 2 assumed ASR 1.05 OAQPS Control Cost Manual Stored Ammonia Concentration 29% 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 OAQPS Control Cost Manual 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) 650 OAQPS Control Cost Manual Equipment Life (years) 20 OAQPS Control Cost Manual Annual Interest Rate 7% OAQPS Control Cost Manual Inflation Since 1998 1.34 CEPCI 2009/CEPCI 1998 Catalyst Cost, Initial ($/ft3) 213 $ calculated from 7,500 $ Fox LOS#2 report Catalyst Cost, Replacement ($/ft3) 213 $ calculated from 7,500 $ Fox LOS#2 report Electrical Power Cost ($/kWh) 0.051 $ company 7/15/11 report Table A-13 29% Ammonia Solution Cost ($/lb) 0.07 $ calcuated from 475 $ /ton from Fox LOS#2 report Operating Life of Catalyst (hours) 24,000 company 7/15/11 report Table A-13 Natural gas unit cost ($/mcf) 5.50 $ Fox report for LOS#2 Natural gas for reheat (mcf) 86 ratioed from LOS #2 1,549,999 scfm at CCS (company 7/15/11 report Table A-13) vs 1,199,789 scfm at LOS#2 requiring 66 mmBtu/hr according to Fox Lost ash sales ($/yr) 2,023,730 $ company 7/15/11 report Table A-13 Additional Ash Disposal Cost ($/ton) 2,023,730 $ company 7/15/11 report Table A-13

### LNB Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc ( 0.21

- 0.15 )/ 0.21 = 29%

**Boiler Calculations**

2.3 Q B 

### = HVm-dot fuel 

### QB = 6,257 Btu/lb * 961,323 lb/hr QB = 6,015 Btu/hr

2.7 CF Plant 

### = actual m fuel 

### /maximum m fuel 

### CFPlant = 8.06E+09 lb/yr / 8760 hr/yr / 961,323 lb/hr CFPlant = 96%

2.8 CF SCR 

### = t SCR 

### /365 days CFSCR = 365 days/ 365 days CFSCR = 100%

CF Total 

### = CF Plant 

### x CF SCR 

### CFTotal = 96% * 100% CFTotal = 96%

2.12 q fluegas 

### = q fuel 

### Q B 

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

### F)n SCR 

### qfluegas = 547 ft3/min/(mmBtu/hr)* 6015 mmBtu/hr*( 460 + 650 )/( 460 + 700 )/ 2 qfluegas = 1,574,193 acfm

2.9 η NOx 

### = (NOx in 

### – NOx out 

### ) / NOx in 

### ηNOx = ( 0.15 lb/mmBtu - 0.043 lb/mmBtu)/ 0.15 lb/mmBtu ηNOx = 71%

**Uncontrolled NOx emissions (tpy) 5,294** 

**Overall Control Efficiency = (Inlet Conc - Outlet Conc)/Inlet conc** ( 0.21

- 0.043 )/ 0.21 = 80%

**NOx removed =** 4,210 tpy

**Controlled NOx emissions (tpy) =** 1,084 tpy

### 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 

### Volcataly st = 2.81 * 6015 = 16902 2.2 η adj 

### = 0.2869 + (1.058 x η) ηadj = 0.2869 +( 1.058 * 0.71 ) ηadj = 1.042

2.22 Slip adj 

### = 1.2835 – (0.0567 x Slip) Slipadj = 1.2835 - ( 0.057 * 2 ) Slipadj = 1.170

2.21 NOx adj 

### = 0.8524 + (0.3208 x NOx in 

### ) NOxadj = 0.8524 + ( 0.321 * 0.15 ) NOxadj = 0.901

2.23 S adj 

### = 0.9636 + (0.0455 x S) Sadj = 0.9636 + ( 0.046 * 0.61 ) Sadj = 0.991

2.24 T adj 

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

### x T 2 

### ) Tadj = 15.16 - ( 0.039 * 650 ) + 2.74E-05 * Tadj = 1.146 Volcataly st = 10,538 ft3 each = 298.6 m3 each

2.25 A catalyst 

### = q fluegas 

### /(16 ft/sec x 60 sec/min) Acataly st = 1,574,193 /( 16 * 60 ) Acataly st = 1,640 ft2

2.26 A SCR 

### = 1.15 x A catalyst 

### ASCR = 1.15 * 1640 ASCR = 1,886 ft2

2.27 l = w = A SCR 1/2



### l = w = 43.4 ft

2.28 n layer



### = Vol catalyst 

### /(h’ layer



### x A catalyst 

### ) nlay er = 10,538 /( 3.1 * 1640 ) nlay er (calc) = 2.0 nlay er = 2.0

2.29 h layer



### = [Vol catalyst 

### /(n layer



### x A catalyst 

### )] + 1 hlay er = 10,538 /( 2.0 * 1640 ) + 1 hlay er = 4.2

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 + 4.2 ) + 9 hSCR = 54 ft

### 422500

### Reagent Calculations

2.32 m-dot reagent 

### = NOx in 

### Q B 

### ASR **η NOx**  

### M reagent 

### /M NOx 

### m-dotreagent = 0.15 * 6015 * 1.05 * **71%** * 17.03 / 46.01 m-dotreagent = 250 lb/hr

2.33 m-dot sol 

### = m-dot reagent 

### /C sol 

### m-dotsol = 250 / 0.29 m-dotsol = 863 lb/hr

2.34 q sol 

### = (m-dot vol 

### /ρ sol 

### )V sol 

### qsol = 863 * 7.481 / 56 qsol = 115 gph

2.35 Tank Volume = q sol 

### t Tank Volume = 115 * 14 * 24 Tank Volume = 38,715 gal**Direct Capital Cost**

2.36 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 = 3008 (( 3,380 $ /mmBtu/hr * inflation = 4,529 $ 13,620,786 $
2.37 f(h SCR ) = {[$612/(ft-mmBtu/hr)]h SCR } - $187.9/(mmBtu/hr) f(hSCR) = 6.12 * 54

- 187.9 f(hSCR) = 142

$ /mmBtu/hr * inflation = 190 $ 570,935 $

2.38 f(NH 3 rate) = [($411/lb/hr)(m-dot reagent /Q B )] - $47.3/(mmBtu/hr) f(NH3rate) = 411 * 125 / 3008

- 47.3 f(NH3rate) = (30)

$ /mmBtu/hr * inflation = (40) $ (121,735) $ 2.39 f(new) = $0/(mmBtu/hr) for retrofit f(new) =

-

$ /mmBtu/hr * inflation = 0

- $ 2.41 f(bypass) = $0/(mmBtu/hr) for no bypass f(bypass) = 127

$ /mmBtu/hr * inflation = 170 $ 511,787 $
2.43 f(Vol catalyst ) = Vol catalyst CCinitial f(Volcatalyst) = 10538 * 213 f(Volcatalyst) = 2,239,678

$ 2,239,678 $

DC = 3008 * ( 4,529 $ + 190

$ + (40)

$ +

-

$ + 170

$ )*( 3500 / 3008 )^ 0.35 + 2,239,678 $ DC = 3008 * ( 4,848 )*( 1.16 )^ 0.35 + 2,239,678 $ DC = 3008 * ( 4,848 )*( 1.05 ) + 2,239,678 $ DC = 3008 * ( 5,113 ) + 2,239,678 $ DC = 15,376,665 $ + 2,239,678 $ DC = 17,616,344 $ fo r each reactor DC = 35,232,687 $ fo r all reactors**Indirect Capital Costs** Cost Manual GRE Cost Cost Cost Cost **Total Direct Capital Costs, A** 35,232,687 $ ratios 40,951,514 $ company 7/15/11 report Table A-13 ratios Indirect Installation Costs

General Facilities 0.05 A $1,761,634 5% Engineering and Home Office Fees 0.10 A $3,523,269 10% Process Contingencies 0.05 A $1,761,634 5% **Total Indirect Installation Costs, B** 0.20 A = $7,046,537 20% 48,826,805 $ company 7/15/11 report Table A-13 119% Project Contingency, C = 0.15 (A+B) = $6,341,884 18% 0% **Total Plant Cost D =** A+B+C $48,621,108 138% 0%

Allowance for Funds During Construction, E = 0 $0 0% Royalty Allowance, F = 0 $0 0% Preproduction Cost, G = 0.02 (D+E) $972,422 3% Inventory Capital, H = Initial Catalyst and Chemicals, I = 0.0689 /lb * 863 lb/r * 24 hr/day * 14 days = $19,961 0% **Total Capital Investment TCI = D+G+H** +D+E+F+G+H+I $49,613,491 141% 70,440,281 $ company 7/15/11 report Table A-13 172% Cost/kW = $90 128 $

**Total Capital Investment TCI @** 280 $/kW = 154,000,000 $ 57,666,552

$ 105 $ **Total Capital Investment TCI =** 154,000,000 $**Annual Costs**

2.45 DAC = Annual Maintenance Cost + Annual Reagent Cost + Annual Electricity Cost + Annual W ater Cost + Annual Catalyst Cost 2.46 Annual Maintenance Cost = 0.015 TCI Annual Maintenance Cost = 0.015 * 154,000,000 $ Annual Maintenance Cost = 2,310,000 $ 1,031,652 $ company 7/15/11 report Table A-13 2.47 Annual Reagent Cost = q reagent Cost reagent t op 2.47a t op = **CF total**  8760hr/yr top = **96%** * 8760 top = **8379** Annual Reagent Cost = 863 * **8379** * 0.068875 Annual Reagent Cost = 497,789 $ 11,246,699 $ company 7/15/11 report Table A-13 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 * 6015 *( 0.15 * 71% + 0.5 * ( 3 + 4 * 1 )) Power = 2278 kW Annual Electricity Cost = 2278 * **8379** * 0.051 Annual Electricity Cost = 973,536 $ 2,258,130 $ company 7/15/11 report Table A-13 2.51 Annual Catalyst Replacement Cost = (Catalyst Replacement Cost)FW F 2.5 Catalyst Replacement Cost = n SCR Vol catalyst CC replace /R layer Catalyst Replacement Cost = 2 * 10,538 * 212.5 / 2 Catalyst Replacement Cost = 2,239,678 $
2.52 FW F = i{1/[(1+i) Y -1]} 2.53 Y = h catalyst

/h year Y = 24000 /( 96% * 8760 ) Y = 2.86 FW F = 0.07 *( 1 /( 1 + 0.07 )^ 3

- 1 ) FW F = 0.31 Annual Catalyst Cost = 696,656 $ 1,394,223 $ company 7/15/11 report Table A-13

Annual natural gas Cost = 86 mcf/hr * 8,379 * 5.50 $ /mcf Annual natural gas Cost = 3,953,376 $

- $ company report

Additional Ash Disposal Cost ($/ton) = 2,023,730 $ 2,023,720 $ company 7/15/11 report Table A-13 Lost Ash Sales = 2,023,730

$ 2,023,720 $ company 7/15/11 report Table A-13

DAC = **12,478,818**

**$** 19,978,144 $ company 7/15/11 report Table A-13

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 * 154,000,000 $ Indirect Annual Cost = 14,536,511 $ 5,998,573 $ company 7/15/11 report Table A-13

2.56 Total Annual Cost = Direct Annual Cost + Indirect Annual Cost SCR Total Annual Cost = 12,478,818 $ + 14,536,511 NOx control Total Annual Cost = 27,015,328 $ + 620,419 $ = 27,635,747

$ 44,806,984 $ company 7/15/11 report Table A-13

2.57 NOx Removed = NOx in η NOx Q B t op NOx Removed = 0.15 * 71% * 6015 * **8379** / 2000 SCR NOx Removed = 2,696 4,457 company 7/15/11 report Table A-13

Total NOx Removed = 4,210

2.58 Cost effectiveness = TAC/NOx removed SCR Cost effectiveness = 10,019 $ 10,051 $ company 7/15/11 report Table A-13 Total Cost effectiveness = 6,564 $**Coal Creek Station Unit 1, EPA's SCR Cost Analysis Summary (Alternate Analysis Using $280/kW Capital Cost)** 

**Operating company Great River Energy**  **Facility Coal Creek Station**  **State ND**  **Contact Tom Bachman**  **tbachman@nd.gov (701) 328-5188** 

**Proposed Controls rejected SCR**  Unit 1 Boiler Ty pe tangential ND DOH SIP Appendix B.2 report Fuel ND lignite ND DOH SIP Appendix B.2 report Rating (MW Gross) each 550 ND DOH SIP Appendix B.2 report **Presumptive BART limit (lb/mmBtu) 0.17**  **presumptive BART for tangential boiler at facility > 750 MW** Rating (mmBtu/hr) 6,015 ND DOH SIP Appendix B.2 report Uncontrolled Emissions (tpy ) 5,294 from 2000 - 2004 CAM data Uncontrolled Emissions (lb/mmBtu) 0.210 from 2000 - 2004 CAM data

**SOFA/LNB Option 1 Cost Analysis** Control Efficiency 28.6% calculated Controlled emissions (lb/mmBtu) 0.150 ND DOH SIP Appendix B.2 report Controlled Emissions (tpy ) 3,780 calculated Emissions Reduction (tpy ) 1,514 calculated Capital Cost 4,913,299 $ company 7/15/11 report Table A-16 Capital Cost ($/kW ) 9 $ calculated O&M Cost 7,966 $ company 7/15/11 report Table A-16 Annualized Cost 673,058 $ calculated from company 7/15/11 report Table A-16 Cost-Effectiveness ($/ton) 445 $ calculated

**SCR Cost Analysis** Control Efficiency 71% OAQPS Control Cost Manual Controlled emissions (lb/mmBtu) 0.043 ND DOH SIP Appendix B.2 report Controlled Emissions (tpy ) 1,084 calculated Emissions Reduction (tpy ) 2,696 OAQPS Control Cost Manual Capital Cost 154,000,000 $ EPA IPM 2010 report Capital Cost ($/kW ) 280 $ EPA IPM 2010 report O&M Cost 12,478,818 $ hy brid Annualized Cost 27,015,328 $ hy brid Cost-Effectiveness ($/ton) 10,019 $ hy brid

**SOFA/LNB + SCR Cost Analysis** Control Efficiency 80% calculated Controlled emissions (lb/mmBtu) 0.043 ND DOH SIP Appendix B.2 report Controlled Emissions (tpy ) 1,084 calculated Emissions Reduction (tpy ) 4,210 calculated Capital Cost 158,913,299 $ calculated Capital Cost ($/kW ) 289 $ calculated O&M Cost 12,486,784 $ calculated Annualized Cost 27,635,747 $ calculated Cost-Effectiveness ($/ton) 6,564 $ calculated