OP_YEAR STATE FACILITY_NAME ORISPL_CODEUNITID OP_STATUS_INFO PRG_CODE_INFO UNIT_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 

REPORTED 

 SO2 

MASS 

ND Coal Creek 6030 CCS #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 CCS #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 0.224 5,396 48,273,258

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

Totals 100,479 153,965 71,922 63,592,462 632,388,220 69,741

Averages 12,560 19,246 0.227 7,991 7,949,058 70,265,358 8,718

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
0.200

0.250

0.300

N

Ox Emissions (lb/m

m

Btu)

Coal Creek NOx Emission Rates

CCS #1

CCS #2

0.000

0.050

0.100

0.150

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (lb/m

m

Btu)

Year
4,000 

5,000 

6,000 

7,000 

N

Ox Emissions (tpy)

Coal Creek NOx Mass Emissions

CCS #1

CCS #2

-

1,000 

2,000 

3,000 

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (tpy)

Year
Great River Energy--Coal Creek Station 2

SNCR from OAQPS Control Cost Manual, Section 4.2

Given/Assumptions

Rating (MW ) 550 ND DOH SIP Appendix B.2 report

Fuel High Heating Value (Btu/lb) 6,257 company 12/07 report Table A-3

Maximum Fuel Consumption Rate (lb/hr) 9.6E+05 calculated from 6,022 mmBtu/hr ND DOH report

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

Number of SNCR Operating Days 365 calculated from 8,760 hr/yr 

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

NOx concentration after combustion controls 0.150 ND DOH SIP Appendix B.2 report

SNCR Controlled NOx Concentration (lb/mmBtu) 0.108 ND DOH SIP Appendix B.2 report

Source/State Total Capital Investmant estimate $ 12,715,834 company 7/15/11 report Table A-15

ash product (Btu/mmBtu) 7.7E+04 OAQPS Control Cost Manual

Stored Urea Concentration 50% OAQPS Control Cost Manual

Injected Urea Concentration 10% OAQPS Control Cost Manual

Reagent Heat of vaporization Hv (lb/Btu) 900 OAQPS Control Cost Manual

Reagent Molecular Weight (g/mole) 60.06 OAQPS Control Cost Manual

SRT 2 OAQPS Control Cost Manual

Reagent Density (lb/ft3 @ 60F) 71.0 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 Urea 14 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

Water Consumption Cost ($/gal) 0.0004 OAQPS Control Cost Manual

Electrical Power Cost ($/kWh) $ 0.051 company 7/15/11 report Table A-15

50% Urea Solution Cost ($/gal) $ 1.92 calculated from $ 405 /ton 50% aqueous solution from company 7/15/11 report Table A-15

Coal Cost ($/mmBtu) $ 0.91 from Leland Olds company report

Ash Disposal Cost ($/ton) $ 7.19 OAQPS Control Cost Manual

Lost ash sales ($/yr) $ 2,023,730 company 7/15/11 report Table A-15

Additional Ash Disposal Cost ($/ton) $ 2,023,730 company 7/15/11 report Table A-15
Boiler Calculations

1.3 QB = HVm-dotfuel

QB = 6257 Btu/lb * 962,442 lb/hr

QB = 6022 mmBtu/hr

1.7 CFPlant = actual mfuel/maximum mfuel

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

CFPlant = 91.5%

1.8 CFSNCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

1.6 CFTotal = CFPlant x CFSNCR

CFTotal = 92% * 100%

CFTotal = 92%

1.9 ηNOx = (NOxin – NOxout) / NOxin

ηNOx = ( 0.150 lb/mmBtu - 0.108 lb/mmBtu)/ 0.15 lb/mmBtu

ηNOx = 28%

Uncontrolled NOx emissions (tpy) 5,396
Reagent Calculations

1.14 NSR = [2NOxin – 0.7] ηNOx/ NOxin

NSR = ( 2 * 0.15 + 0.7 ) * 28% / 0.15

NSR = 1.87

1.13 Utilization = ηNOx/NSR

Utilization = 15%

1.15 m-dotreagent = NOxinQBηNOxNSR Mreagent/MNOx/SRT

m-dotreagent = 0.150 * 6022 * 28% * 187% * 60.06 / 2 / 46.01

m-dotreagent = 308 lb/hr

1.16 m-dotsol = m-dotreagent/Csol

m-dotsol = 308 / 0.50

m-dotsol = 616 lb/hr

1.17 qsol = m-dotvol/ρsol

qsol = 616 * 7.481 / 71

qsol = 65 gph

2.35 Tank Volume = qsolt

Tank Volume = 65 * 14 * 24

Tank Volume = 21,819 gal
Direct Capital Cost

1.19 DC = ($950/mmBtu/hr) * QB(mmBtu/hr)[(2375/mmBtu/hr)/QB(mmBtu/hr]0.577 * (0.66 + 0.85* ηNOx)

DC = $ 950 * 6022 *( 2375 / 6022 )^ 0.577 *( 0.66 + 0.85 * 28% )

DC = $ 3,003,227

Inflation Adjustment = 1.34

DC = $ 4,024,324
Indirect Capital Costs Cost Manual GRE

Cost Cost Cost Cost

Total Direct Capital Costs, A $ 4,024,324 ratios $ 3,789,655 company 7/15/11 report Table A-15 ratios

Indirect Installation Costs 

General Facilities 0.05 A $201,216 5%

Engineering and Home Office Fees 0.10 A $402,432 10%

Process Contingencies 0.05 A $201,216 5%

Total Indirect Installation Costs, B 0.20 A $804,865 20%

Project Contingency, C = 0.15 (A+B) $724,378 18%

Total Plant Cost D = A+B+C $5,553,568 138%

Preproduction Cost 0.02 D $111,071 3%

Inventory Capital $41,933 1%

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $5,706,572 142% $ 13,283,414 company 7/15/11 report Table A-15 351%

TCI = company DCC * 142% $ 5,373,806
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 * $ 5,373,806

Annual Maintenance Cost = $ 80,607

1.22 Annual Reagent Cost = qsolCostreagenttop

1.22.a top = CFtotal8760hr/yr

top = 92% * 8760

top = 8016

Annual Reagent Cost = 65 * 1.921868734 * 8016

Annual Reagent Cost = $ 1,000,416

1.24 Annual Electricity Cost = Power (Costelect)top

1.23 Power = 0.47NOxinNSRQB/9.5

Power = 0.47 * 0.15 * 1.87 * 6022 / 9.5

Power = 83 kW

Annual Electricity Cost = 83 * 8016 * 0.051

Annual Electricity Cost = $ 34,104

1.27 Annual Water Cost = qwaterCostwater top

1.25 qwater = m-dotsol/ρwater[Cureastored/Curea sol inj -1]

qwater = 616 / 8.345 *( 50% / 10% - 1 )

qwater = 295

Annual Water Cost = 295 * 0.0004 * 8016

Annual Water Cost = $ 947

1.31 Annual ΔCoal cost = ΔCoal costcoal top

1.28 ΔCoal(Btu/hr) = Hv(Btu/lb)* m-dotreagent(lb/hr)[1/ Curea sol inj -1]

ΔCoal(Btu/hr) = 900 * 616 *( 1 / 10% - 1 )

ΔCoal(Btu/hr) = 4,992,004

Annual ΔCoal cost = 5.0 * $ 0.91 * 8016

Annual ΔCoal cost = $ 36,415

1.32 Annual ΔAsh cost = ΔAsh costash top

1.30 ΔAsh = ΔCoal ash product/HHV

ΔAsh = 5 * 77000 / 6257

ΔAsh = 61

Annual ΔAsh cost = 61 * $ 7.19 * 8016 / 2000

Annual ΔAsh cost = $ 1,770

Additional Ash Disposal Cost ($/ton) = $ 2,023,730

Lost ash sales ($/yr) = $ 2,023,730

Total Variable Cost = $ 5,121,113

Total Direct Annual Cost = $ 80,607 + $ 5,121,113

Total Direct Annual Cost = $ 5,201,721

1.34 CRF = i(1+i)n

/[(1+i)n-1]

CRF = 0.07 *( 1 + 0.07 )^ 20 /(( 1 + 0.07 )^ 20 - 1 )

CRF = 0.0944

1.33 IDAC = CRF*TCI

Indirect Annual Cost = 0.0944 * $ 5,373,806

Indirect Annual Cost = $ 507,249

1.35 Total Annual Cost = Direct Annual Cost + Indirect Annual Cost

Total Annual Cost = $ 5,201,721 + 507,249

Total Annual Cost = $ 5,708,970

1.36 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.150 * 28% * 6022 * 8016 / 2000

NOx Removed = 1014

1.37 Cost effectiveness = TAC/NOx

 removed

Cost effectiveness = $ 5,632
Coal Creek Station Unit 2, EPA's SNCR 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 proposed ASOFA + SNCR

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 report

Uncontrolled Emissions (tpy) 5,396 from 2000 - 2004 CAM data

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

SOFA/LNB Option 1 Cost Analysis

Control Efficiency 32.9% calculated

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

Controlled Emissions (tpy) 3,620 OAQPS Control Cost Manual

Emissions Reduction (tpy) 1,775 calculated

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

Capital Cost ($/kW) $ 8.9 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

SNCR Cost Analysis

Control Efficiency 28% OAQPS Control Cost Manual

Controlled emissions (lb/mmBtu) 0.108 ND DOH SIP Appendix B.2 report

Controlled Emissions (tpy) 2,607 calculated

Emissions Reduction (tpy) 1,014 OAQPS Control Cost Manual

Capital Cost $ 5,373,806 company 7/15/11 report Table A-15

Capital Cost ($/kW) $ 10 calculated

O&M Cost $ 5,201,721 hybrid

Annualized Cost $ 5,708,970 hybrid

Cost-Effectiveness ($/ton) $ 5,632 hybrid

SOFA/LNB1+SNCR Cost Analysis

Control Efficiency 52% calculated

Controlled emissions (lb/mmBtu) 0.108 ND DOH SIP Appendix B.2 report

Controlled Emissions (tpy) 2,607 calculated

Emissions Reduction (tpy) 2,789 calculated

Capital Cost $ 10,287,105 calculated

Capital Cost ($/kW) $ 19 calculated

O&M Cost $ 5,209,687 calculated

Annualized Cost $ 6,382,027 calculated

Cost-Effectiveness ($/ton) $ 2,288 calculated