OP_YEAR STATE FACILITY_NAME ORISPL_CODEUNITID 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 FGDLow NOx Burner Technology w/ Closed-coupled/Separated OFA

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

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

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

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

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

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

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

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

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

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

2011 ND Coal Creek 6030 1 Operating ARP Tangentially-fired Coal Wet Lime FGDLow 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

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) $ 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 QB = HVm-dotfuel

QB = 6,257 Btu/lb * 976,829 lb/hr

QB = 6,112 Btu/hr

2.7 CFPlant = actual mfuel/maximum mfuel

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

CFPlant = 94%

2.8 CFSCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

CFTotal = CFPlant x CFSCR

CFTotal = 94% * 100%

CFTotal = 94%

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

F)nSCR

qfluegas = 547 ft3/min/(mmBtu/hr)* 6112 mmBtu/hr*( 460 + 650 )/( 460 + 700 )/ 2

qfluegas = 1,599,584 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 * 6112 = 17175

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 = 10,708 ft3 each = 303.4 m3 each

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

Acatalyst = 1,599,584 /( 16 * 60 )

Acatalyst = 1,666 ft2

2.26 ASCR = 1.15 x Acatalyst

ASCR = 1.15 * 1666

ASCR = 1,916 ft2

2.27 l = w = ASCR

1/2

l = w = 43.8 ft

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

nlayer = 10,708 /( 3.1 * 1666 )

nlayer (calc) = 2.0

nlayer = 2.0

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

hlayer = 10,708 /( 2.0 * 1666 ) + 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 * 6112 * 1.05 * 71% * 17.03 / 46.01

m-dotreagent = 254 lb/hr

2.33 m-dotsol = m-dotreagent/Csol

m-dotsol = 254 / 0.29

m-dotsol = 876 lb/hr

2.34 qsol = (m-dotvol/ρsol)Vsol

qsol = 876 * 7.481 / 56

qsol = 117 gph

2.35 Tank Volume = qsolt

Tank Volume = 117 * 14 * 24

Tank Volume = 39,340 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 = 3056 (( $ 3,380 /mmBtu/hr * inflation = $ 4,529 $ 13,840,485

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 $ 580,144

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

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 for each reactor

DC = $ 35,626,462 for 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 Water 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 = qreagentCostreagenttop

2.47a top = CFtotal8760hr/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 (Costelect)top

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

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)FWF

2.5 Catalyst Replacement Cost = nSCRVolcatalystCCreplace/Rlayer

Catalyst Replacement Cost = 2 * 10,708 * 212.5 / 2

Catalyst Replacement Cost = $ 2,275,803

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

2.53 Y = hcatalyst/hyear

Y = 24000 /( 94% * 8760 )

Y = 2.91

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

FWF = 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 = NOxinηNOxQBtop

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 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) 6,112 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 hybrid

Annualized Cost $ 16,707,202 hybrid

Cost-Effectiveness ($/ton) $ 6,196 hybrid

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