## OP_YEAR STATE FACILITY_NAME ORISPL_CODE UNITID OP_STATUS_INFO

PRG_CODE_INFO

UIT_TYPE_INFO

PRIMARY_FUEL_INFO SO2_CONTROL_INFO

NOX_CONTROL_INFO
2000 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2001 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2002 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2003 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2004 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2005 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2006 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2007 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2008 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2009 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2010 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

Low NOx Burner Technology w/ Closed-coupled/Separated OFA
2011 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGD

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 REPORTED SO2

MASS 

### SO2

RATE NOX
RATE NOX

MASS CO2 MASS HEAT INPUT (mmBtu/yr) 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 CCS #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 CCS #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 CCS #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 CCS #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 CCS #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 CCS #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 CCS #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 CCS #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 CCS #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 CCS #1 2010 8,575 

### 12 9,438 

### 0.382 0.211 5,199 5,379,248 49,409,811 5,762**CAMD Emissions Data**



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

MONTHS REPORTED SO2

MASS 

### SO2

RATE NOX
RATE NOX

MASS CO2 MASS HEAT INPUT (mmBtu/yr) 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) 110 $ calculated from DCC in company 7/15/11 report Table A-16 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) 976,829 calculated from 6,112 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 94% 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 Inflation Since 2006 1.04 CEPCI 2009/CEPCI 2006 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 * 976,829 lb/hr QB = 6,112 Btu/hr

2.7 CF Plant 

### = actual m fuel 

### /maximum m fuel 

### CFPlant = 8.06E+09 lb/yr / 8760 hr/yr / 976,829 lb/hr CFPlant = 94%

2.8 CF SCR 

### = t SCR 

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

CF Total 

### = CF Plant 

### x CF SCR 

### CFTotal = 94% * 100% CFTotal = 94%

2.12 q fluegas 

### = q fuel 

### Q B 

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

### F)n SCR 

### qfluegas = 547 ft3/min/(mmBtu/hr)* 6112 mmBtu/hr*( 460 + 650 )/( 460 + 700 )/ 2 qfluegas = 1,599,584 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 

### Volcatalyst = 2.81 * 6112 = 17175 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 * 422500 Tadj = 1.146 Volcatalyst = 10,708 ft3 each = 303.4 m3 each

2.25 A catalyst 

### = q fluegas 

### /(16 ft/sec x 60 sec/min) Acatalyst = 1,599,584 /( 16 * 60 ) Acatalyst = 1,666 ft2

2.26 A SCR 

### = 1.15 x A catalyst 

### ASCR = 1.15 * 1666 ASCR = 1,916 ft2

2.27 l = w = A SCR 1/2



### l = w = 43.8 ft

2.28 n layer



### = Vol catalyst 

### /(h’ layer



### x A catalyst 

### ) nlayer = 10,708 /( 3.1 * 1666 ) nlayer (calc) = 2.0 nlayer = 2.0

2.29 h layer



### = [Vol catalyst 

### /(n layer



### x A catalyst 

### )] + 1 hlayer = 10,708 /( 2.0 * 1666 ) + 1 hlayer = 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

### Reagent Calculations

2.32 m-dot reagent 

### = NOx in 

### Q B 

### ASR **η NOx**  

### M reagent 

### /M NOx 

### m-dotreagent = 0.15 * 6112 * 1.05 * **71%** * 17.03 / 46.01 m-dotreagent = 254 lb/hr

2.33 m-dot sol 

### = m-dot reagent 

### /C sol 

### m-dotsol = 254 / 0.29 m-dotsol = 876 lb/hr

2.34 q sol 

### = (m-dot vol 

### /ρ sol 

### )V sol 

### qsol = 876 * 7.481 / 56 qsol = 117 gph

2.35 Tank Volume = q sol 

### t Tank Volume = 117 * 14 * 24 Tank Volume = 39,340 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 = 3056 (( 3,380 $ /mmBtu/hr * inflation = 4,529 $ 13,840,485 $
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 $ 580,144 $

2.38 f(NH 3 rate) = [($411/lb/hr)(m-dot reagent /Q B )] - $47.3/(mmBtu/hr) f(NH3rate) = 411 * 127 / 3056

- 47.3 f(NH3rate) = (30)

$ /mmBtu/hr * inflation = (40) $ (123,699) $ 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 $ 520,042 $
2.43 f(Vol catalyst ) = Vol catalyst CCinitial f(Volcatalyst) = 10708 * 213 f(Volcatalyst) = 2,275,803

$ 2,275,803 $

DC = 3056 * ( 4,529 $ + 190

$ + (40)

$ +

-

$ + 170

$ )*( 3500 / 3056 )^ 0.35 + 2,275,803 $ DC = 3056 * ( 4,848 )*( 1.15 )^ 0.35 + 2,275,803 $ DC = 3056 * ( 4,848 )*( 1.05 ) + 2,275,803 $ DC = 3056 * ( 5,084 ) + 2,275,803 $ DC = 15,537,427 $ + 2,275,803 $ DC = 17,813,231 $ fo r each reactor DC = 35,626,462 $ fo r all reactors**Indirect Capital Costs** Cost Manual GRE Cost Cost Cost Cost **Total Direct Capital Costs, A** 35,626,462 $ ratios 42,779,414 $ company 7/15/11 report Table A-13 ratios Indirect Installation Costs

General Facilities 0.05 A $1,781,323 5% Engineering and Home Office Fees 0.10 A $3,562,646 10% Process Contingencies 0.05 A $1,781,323 5% **Total Indirect Installation Costs, B** 0.20 A = $7,125,292 20% 51,006,224 $ company 7/15/11 report Table A-13 119% Project Contingency, C = 0.15 (A+B) = $6,412,763 18% **Total Plant Cost D =** A+B+C $49,164,517 138%

Allowance for Funds During Construction, E = 0 $0 0% Royalty Allowance, F = 0 $0 0% Preproduction Cost, G = 0.02 (D+E) $983,290 3% Inventory Capital, H = Initial Catalyst and Chemicals, I = 0.06888 /lb * 876 lb/r * 24 hr/day * 14 days = $20,283 0% **Total Capital Investment TCI = D+G+H** +D+E+F+G+H+I $50,168,090 141% 73,584,433 $ company 7/15/11 report Table A-13 172% Cost/kW = $91 134 $

**Total Capital Investment TCI @** 110 $/kW = 60,240,658 $ 60,240,658 $ 110 $ **Total Capital Investment TCI =** 60,240,658 $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 * 60,240,658 $ Annual Maintenance Cost = 903,610 $ 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 = 94% * 8760 top = 8246 Annual Reagent Cost = 876 * 8246 * 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 * 6112 *( 0.15 * 71% + 0.5 * ( 3 + 4 * 1 )) Power = 2315 kW Annual Electricity Cost = 2315 * 8246 * 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 * 10,708 * 212.5 / 2 Catalyst Replacement Cost = 2,275,803 $
2.52 FW F = i{1/[(1+i) Y -1]} 2.53 Y = h catalyst

/h year Y = 24000 /( 94% * 8760 ) Y = 2.91 FW F = 0.07 *( 1 /( 1 + 0.07 )^ 3

- 1 ) FW F = 0.31 Annual Catalyst Cost = 707,892 $ 1,394,223 $ company 7/15/11 report Table A-13

Annual natural gas Cost = 86 mcf/hr * 8,246 * 5.50 $ /mcf Annual natural gas Cost = 3,890,622 $

- $ 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 = 11,020,910

$ 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 * 60,240,658 $ Indirect Annual Cost = 5,686,292 $ 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 = 11,020,910 $ + 5,686,292 NOx control Total Annual Cost = 16,707,202 $ + 620,419 $ = 17,327,621

$ 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% * 6112 * 8246 / 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 = 6,196 $ 10,051 $ company 7/15/11 report Table A-13 Total Cost effectiveness = 4,116 $

### Coal Creek Station Unit 1, EPA's SCR Cost Analysis Summary

**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) 6,112 ND DOH SIP Appendix B.2 report Uncontrolled Emissions (tpy ) 5,294 OAQPS Control Cost Manual 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 60,240,658 $ company 7/15/11 report Table A-15 Capital Cost ($/kW ) 110 $ calculated from DCC in company 7/15/11 report Table A-16 O&M Cost 11,020,910 $ hy brid Annualized Cost 16,707,202 $ hy brid Cost-Effectiveness ($/ton) 6,196 $ hy brid

**Combustion Controls + 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 65,153,957 $ calculated Capital Cost ($/kW ) 118 $ calculated O&M Cost 11,028,876 $ calculated Annualized Cost 17,327,621 $ calculated Cost-Effectiveness ($/ton) 4,116 $ calculated