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
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/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 

REPORTE

D 

 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

Ox Emissions (lb/m

m

Btu)

Coal Creek 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

Ox Emissions (lb/m

m

Btu)

Year
4000

5000

6000

7000

N

Ox Emissions (tpy)

Coal Creek NOx Mass Emissions

CCS #1

CCS #2

0

1000

2000

3000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (tpy)

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 QB = HVm-dotfuel

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

QB = 6,015 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

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

CFPlant = 96%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

CFTotal = CFPlant x CFSCR

CFTotal = 96% * 100%

CFTotal = 96%

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

F)nSCR

qfluegas = 547 ft3/min/(mmBtu/hr)* 6015 mmBtu/hr*( 460 + 650 )/( 460 + 700 )/ 2

qfluegas = 1,574,193 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) 5,294

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

Volcatalyst = 2.81 * 6015 = 16902

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 *

Tadj = 1.146

Volcatalyst = 10,538 ft3 each = 298.6 m3 each

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

Acatalyst = 1,574,193 /( 16 * 60 )

Acatalyst = 1,640 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 1640

ASCR = 1,886 ft2

2.27 l = w = ASCR

1/2

l = w = 43.4 ft

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

nlayer = 10,538 /( 3.1 * 1640 )

nlayer (calc) = 2.0

nlayer = 2.0

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

hlayer = 10,538 /( 2.0 * 1640 ) + 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
422500
Reagent Calculations

2.32 m-dotreagent = NOxinQBASRηNOxMreagent/MNOx

m-dotreagent = 0.15 * 6015 * 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 = 863 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 863 * 7.481 / 56

qsol = 115 gph

2.35 Tank Volume = qsolt

Tank Volume = 115 * 14 * 24

Tank Volume = 38,715 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 = 3008 (( $ 3,380 /mmBtu/hr * inflation = $ 4,529 $ 13,620,786

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 $ 570,935

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

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 for each reactor

DC = $ 35,232,687 for 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 Water 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 = qreagentCostreagenttop

2.47a top = CFtotal8760hr/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 (Costelect)top

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

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)FWF

2.5 Catalyst Replacement Cost = nSCRVolcatalystCCreplace/Rlayer

Catalyst Replacement Cost = 2 * 10,538 * 212.5 / 2

Catalyst Replacement Cost = $ 2,239,678

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

2.53 Y = hcatalyst/hyear

Y = 24000 /( 96% * 8760 )

Y = 2.86

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

FWF = 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 = NOxinηNOxQBtop

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 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) 6,015 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 hybrid

Annualized Cost $ 27,015,328 hybrid

Cost-Effectiveness ($/ton) $ 10,019 hybrid

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