OP_YEAR STATE FACILITY_NAME ORISPL_CODEUNITID 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

2000 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2001 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2002 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2003 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2004 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2005 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2006 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2007 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2008 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2009 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2010 ND Coal Creek 6030 2 Operating ARP Tangentially-fired Coal

2011 ND Coal Creek 6030 2 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

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

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 Overfire Air (Began Apr 30, 2007)

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

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

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

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

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 1 2000 8,637 12 14,332

ND Coal Creek 6030 1 2001 8,547 12 14,630

ND Coal Creek 6030 1 2002 7,836 12 11,910

ND Coal Creek 6030 1 2003 8,567 12 13,817

ND Coal Creek 6030 1 2004 8,466 12 15,742

ND Coal Creek 6030 1 2005 7,863 12 13,150

ND Coal Creek 6030 1 2006 8,531 12 16,425

ND Coal Creek 6030 1 2007 8,586 12 15,845

ND Coal Creek 6030 1 2008 7,154 12 10,735

ND Coal Creek 6030 1 2009 8,583 12 14,315

ND Coal Creek 6030 1 2010 8,575 12 9,438

ND Coal Creek 6030 2 2000 8,430 12 12,816

ND Coal Creek 6030 2 2001 8,028 12 11,683

ND Coal Creek 6030 2 2002 8,661 12 12,518

ND Coal Creek 6030 2 2003 8,613 12 13,547

ND Coal Creek 6030 2 2004 7,949 12 11,469

ND Coal Creek 6030 2 2005 8,527 12 14,240

ND Coal Creek 6030 2 2006 8,591 12 15,659

ND Coal Creek 6030 2 2007 7,555 12 12,462

ND Coal Creek 6030 2 2008 8,352 12 12,408

ND Coal Creek 6030 2 2009 8,210 12 14,323

ND Coal Creek 6030 2 2010 7,307 12 8,678
SO2 

RATE

NOX 

RATE

 NOX 

MASS CO2 MASS 

 HEAT INPUT 

(mmBtu/yr) 

 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 

REPORTED 

 SO2 

MASS 

SO2 

RATE

NOX 

RATE

 NOX 

MASS CO2 MASS 

 HEAT INPUT 

(mmBtu/yr) 

 HEAT 

INPUT 

(mmBtu/hr) 

ND Coal Creek 6030 2 2000 8,430 12 12,816 0.533 0.223 5,291 5,234,588 48,081,394 5,703

ND Coal Creek 6030 2 2001 8,028 12 11,683 0.507 0.230 5,250 5,019,726 46,107,773 5,744

ND Coal Creek 6030 2 2002 8,661 12 12,518 0.495 0.218 5,492 5,509,932 50,610,222 5,843

ND Coal Creek 6030 2 2003 8,613 12 13,547 0.535 0.221 5,556 5,513,004 50,638,401 5,880

ND Coal Creek 6030 2 2004 7,949 12 11,469 0.499 0.236 5,391 5,000,236 45,928,500 5,778

2000 - 2004 totals 41,680 62,033 26,980 26,277,486 241,366,290 28,948

2000 - 2004 Averages 8,336 0.224 5,396 48,273,258 5,790

ND Coal Creek 6030 2 2005 8,527 12 14,240 0.566 0.243 6,084 5,481,116 50,345,570 5,904

ND Coal Creek 6030 2 2006 8,591 12 15,659 0.614 0.255 6,483 5,556,375 51,036,813 5,940

ND Coal Creek 6030 2 2007 7,555 12 12,462 0.577 0.198 4,260 4,698,631 43,158,180 5,713

ND Coal Creek 6030 2 2008 8,352 12 12,408 0.520 0.174 4,126 5,194,201 47,710,283 5,713

ND Coal Creek 6030 2 2009 8,210 12 14,323 0.594 0.192 4,623 5,249,772 48,220,581 5,873

ND Coal Creek 6030 2 2010 7,307 12 8,678 0.413 0.166 3,473 4,572,384 41,998,558 5,748

Totals 23,869 35,408 12,222 15,016,357 137,929,423 17,334

Averages 7,956 11,803 0.177 4,074 5,005,452 45,976,474 5,778
0.2

0.25

0.3

N

Ox Emissions (lb/m

m

Btu)

Coal Creek NOx Emission Rates

1

2

0

0.05

0.1

0.15

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (lb/m

m

Btu)

Year
4000

5000

6000

7000

N

Ox Emissions (tpy)

Coal Creek NOx Mass Emissions

1

2

0

1000

2000

3000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (tpy)

Year
Coal Creek Station 2

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) $ 105 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) 962,442 calculated from 6,022 mmBtu/hr ND DOH SIP Appendix B.2 report

Average Annual Fuel Consumption (lb) 7.72E+09 calcuated from 48,273,258 mmBtu/yr from 2000 - 2004 CAM data

Number of SCR Operating Days 365 calcuated from 8760 hr/yr 

Plant Capacity Factor 92% calcuated

Uncontrolled NOx Concentration (lb/mmBtu) 0.224 from 2000 - 2004 CAM data

LNB + SOFA Total Capital Cost $ 4,913,299 company 7/15/11 report Table A-16

LNB + SOFA 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) $ 0.038 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 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

( 0.22 - 0.15 )/ 0.22 = 33%

Boiler Calculations

2.3 QB = HVm-dotfuel

QB = 6,257 Btu/lb * 962,442 lb/hr

QB = 6,022 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

CFPlant = 7.72E+09 lb/yr / 8760 hr/yr / 962,442 lb/hr

CFPlant = 92%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

CFTotal = CFPlant x CFSCR

CFTotal = 92% * 100%

CFTotal = 92%

2.12 qfluegas = qfuelQB(460+T)/(460+700o

F)nSCR

qfluegas = 547 ft3/min/(mmBtu/hr)* 6022 mmBtu/hr*( 460 + 650 )/( 460 + 700 )/ 2

qfluegas = 1,576,025 acfm

2.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.15 lb/mmBtu - 0.043 lb/mmBtu)/ 0.15 lb/mmBtu

ηNOx = 71%

Uncontrolled NOx emissions (tpy) 5,396

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

( 0.22 - 0.043 )/ 0.22 = 81%

NOx removed = 4,358 tpy

Controlled NOx emissions (tpy) = 1,038 tpy
SCR Reactor Calculations

2.19 Volcatalyst = 2.81 x QB x ηadj x Slipadj x NOxadj x Sadj x Tadj/NSCR

Volcatalyst = 2.81 * 6022 = 16922

2.2 ηadj = 0.2869 + (1.058 x η)

ηadj = 0.2869 +( 1.058 * 0.71 )

ηadj = 1.042

2.22 Slipadj = 1.2835 – (0.0567 x Slip)

Slipadj = 1.2835 - ( 0.057 * 2 )

Slipadj = 1.170

2.21 NOxadj = 0.8524 + (0.3208 x NOxin)

NOxadj = 0.8524 + ( 0.321 * 0.15 )

NOxadj = 0.901

2.23 Sadj = 0.9636 + (0.0455 x S)

Sadj = 0.9636 + ( 0.046 * 0.61 )

Sadj = 0.991

2.24 Tadj = 15.16 – (0.03937 x T) + (2.74 x 10-5 x T2

)

Tadj = 15.16 - ( 0.039 * 650 ) + 2.74E-05 * 422500

Tadj = 1.146

Volcatalyst = 10,550 ft3 each = 299 m3 each

2.25 Acatalyst = qfluegas/(16 ft/sec x 60 sec/min)

Acatalyst = 1,576,025 /( 16 * 60 )

Acatalyst = 1,642 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 1642

ASCR = 1,888 ft2

2.27 l = w = ASCR

1/2

l = w = 43.5 ft

2.28 nlayer = Volcatalyst/(h’layer x Acatalyst)

nlayer = 10,550 /( 3.1 * 1642 )

nlayer (calc) = 2.0

nlayer = 2.0

2.29 hlayer = [Volcatalyst/(nlayer x Acatalyst)] + 1

hlayer = 10,550 /( 2.0 * 1642 ) + 1

hlayer = 4.2

2.3 ntotal = nlayer + nempty

ntotal = 2 + 2

ntotal = 4

2.31 hSCR = ntotal(c1

 + hlayer) + c2

hSCR = 4 * ( 7 + 4.2 ) + 9

hSCR = 54 ft
Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.15 * 6022 * 1.05 * 71% * 17.03 / 46.01

m-dotreagent = 250 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 250 / 0.29

m-dotsol = 864 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 864 * 7.481 / 56

qsol = 115 gph

2.35 Tank Volume = qsolt

Tank Volume = 115 * 14 * 24

Tank Volume = 38,760 gal
Direct Capital Cost

2.36 DC = QB[($3380/MMBtu/hr) + f(hSCR) +f(NH3rate) + f(new) + f(bypass)](3500/QB)

0.35 + f(Volcatalyst)

DC = 3011 (( $ 3,380 /mmBtu/hr * inflation = $ 4,529 $ 13,636,637

2.37 f(hSCR) = {[$612/(ft-mmBtu/hr)]hSCR} - $187.9/(mmBtu/hr)

f(hSCR) = 6.12 * 54 - 187.9

f(hSCR) = $ 142 /mmBtu/hr * inflation = $ 190 $ 571,599

2.38 f(NH3rate) = [($411/lb/hr)(m-dotreagent/QB)] - $47.3/(mmBtu/hr)

f(NH3rate) = 411 * 125 / 3011 - 47.3

f(NH3rate) = $ (30) /mmBtu/hr * inflation = $ (40) $ (121,877)

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 $ 512,383

2.43 f(Volcatalyst) = VolcatalystCCinitial

f(Volcatalyst) = 10550 * 213

f(Volcatalyst) = $ 2,242,285 $ 2,242,285

DC = 3011 * ( $ 4,529 + $ 190 + $ (40) + $ - + $ 170 )*( 3500 / 3011 )^ 0.35 + $ 2,242,285

DC = 3011 * ( 4,848 )*( 1.16 )^ 0.35 + $ 2,242,285

DC = 3011 * ( 4,848 )*( 1.05 ) + $ 2,242,285

DC = 3011 * ( 5,111 ) + $ 2,242,285

DC = $ 15,388,295 + $ 2,242,285

DC = $ 17,630,579 for each reactor

DC = $ 35,261,158 for all reactors
Indirect Capital Costs Cost Manual GRE

Cost Cost Cost Cost

Total Direct Capital Costs, A $ 35,261,158 ratios $ 40,951,514 ratios

Indirect Installation Costs 

General Facilities 0.05 A $1,763,058 5%

Engineering and Home Office Fees 0.10 A $3,526,116 10%

Process Contingencies 0.05 A $1,763,058 5%

Total Indirect Installation Costs, B 0.20 A = $7,052,232 20% $ 48,826,805 119%

Project Contingency, C = 0.15 (A+B) = $6,347,009 18%

Total Plant Cost D = A+B+C $48,660,399 138%

Allowance for Funds During Construction, E = 0 $0 0%

Royalty Allowance, F = 0 $0 0%

Preproduction Cost, G = 0.02 (D+E) $973,208 3%

Inventory Capital, H =

Initial Catalyst and Chemicals, I = 0.0689 /lb * 864 lb/r * 24 hr/day * 14 days = $19,984 0%

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $49,653,590 141% $ 70,440,281 172%

Cost/kW = $90 $ 128

Total Capital Investment TCI @ 105 $/kW = $ 57,666,560 $ 57,666,560

$ 105

Total Capital Investment TCI = $ 57,666,560
Annual Costs

2.45 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 * $ 57,666,560

Annual Maintenance Cost = $ 864,998 $ 1,031,652 company 7/15/11 report Table A-13

2.47 Annual Reagent Cost = qreagentCostreagenttop

2.47a top = CFtotal8760hr/yr

top = 92% * 8760

top = 8016

Annual Reagent Cost = 864 * 8016 * 0.068875

Annual Reagent Cost = $ 476,766 $ 11,246,699 company 7/15/11 report Table A-13

2.49 Annual Electricity Cost = Power (Costelect)top

2.48 Power = 0.105QB[NOxinηNOx + 0.5(ΔPduct + ntotalΔPcatalyst)]

Power = 0.105 * 6022 *( 0.15 * 71% + 0.5 * ( 3 + 4 * 1 ))

Power = 2281 kW

Annual Electricity Cost = 2281 * 8016 * 0.038

Annual Electricity Cost = $ 694,745 $ 2,258,130 company 7/15/11 report Table A-13

2.51 Annual Catalyst Replacement Cost = (Catalyst Replacement Cost)FWF

2.5 Catalyst Replacement Cost = nSCRVolcatalystCCreplace/Rlayer

Catalyst Replacement Cost = 2 * 10,550 * 212.5 / 2

Catalyst Replacement Cost = $ 2,242,285

2.52 FWF = i{1/[(1+i)Y-1]}

2.53 Y = hcatalyst/hyear

Y = 24000 /( 92% * 8760 )

Y = 2.99

FWF = 0.07 *( 1 /( 1 + 0.07 )^ 3 - 1 )

FWF = 0.31

Annual Catalyst Cost = $ 697,466 $ 1,394,223 company 7/15/11 report Table A-13

Annual natural gas Cost = 86 mcf/hr * 8,016 * $ 5.50 /mcf

Annual natural gas Cost = $ 3,782,013 $ - 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 = $ 10,563,450 $ 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 * $ 57,666,560

Indirect Annual Cost = $ 5,443,315 $ 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 = $ 10,563,450 + 5,443,315

NOx control Total Annual Cost = $ 16,006,765 + $ 620,419 = $ 16,627,184 $ 44,806,984 company 7/15/11 report Table A-13

2.57 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.15 * 71% * 6022 * 8016 / 2000

SCR NOx Removed = 2,583 4,457 company 7/15/11 report Table A-13

Total NOx Removed = 4,358

2.58 Cost effectiveness = TAC/NOx removed

SCR Cost effectiveness = $ 6,198 $ 10,051 company 7/15/11 report Table A-13

Total Cost effectiveness = $ 3,815
Coal Creek Station Unit 2, 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 2

Boiler Type 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) 6,022 ND DOH SIP Appendix B.2 report

Uncontrolled Emissions (tpy) 5,396 OAQPS Control Cost Manual

Uncontrolled Emissions (lb/mmBtu) 0.224 from 2000 - 2004 CAM data

Combustion Controls Cost Analysis

Control Efficiency 33% calculated

Controlled emissions (lb/mmBtu) 0.150 ND DOH SIP Appendix B.2 report

Controlled Emissions (tpy) 3,620 calculated

Emissions Reduction (tpy) 1,775 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) $ 379 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) 1,038 calculated

Emissions Reduction (tpy) 2,583 OAQPS Control Cost Manual

Capital Cost $ 57,666,560 company 7/15/11 report Table A-15

Capital Cost ($/kW) $ 105 calculated from DCC in company 7/15/11 report Table A-16

O&M Cost $ 10,563,450 hybrid

Annualized Cost $ 16,006,765 hybrid

Cost-Effectiveness ($/ton) $ 6,198 hybrid

Combustion Controls + SCR Cost Analysis

Control Efficiency 81% calculated

Controlled emissions (lb/mmBtu) 0.043 ND DOH SIP Appendix B.2 report

Controlled Emissions (tpy) 1,038 calculated

Emissions Reduction (tpy) 4,358 calculated

Capital Cost $ 62,579,859 calculated

Capital Cost ($/kW) $ 114 calculated

O&M Cost $ 10,571,416 calculated

Annualized Cost $ 16,627,184 calculated

Cost-Effectiveness ($/ton) $ 3,815 calculated