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 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 average Averages 0.212

2000 - 2004 totals 42,053 70,431 26,470 27,436,235 252,009,307 29,962

2000 - 2004 Averages 0.210 5,294 50,401,861
0.150

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

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (lb/m

m

Btu)

Year
3,000 

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 

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

N

Ox Emissions (tpy)

Year
Great River Energy--Coal Creek Station 1

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) 9.8E+05 calculated from 6,112 mmBtu/hr maximum annual average from 2005 CAMD

Average Annual Fuel Consumption (lb) 8.06E+09 calculated 50,401,861 mmBtu/yr from 2000 - 2004 CAM data

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

Uncontrolled NOx Concentration (lb/mmBtu) 0.210 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) $ 11.28 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 * 976,829 lb/hr

QB = 6112 mmBtu/hr

1.7 CFPlant = actual mfuel/maximum mfuel

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

CFPlant = 94.1%

1.8 CFSNCR = tSCR/365 days

CFSCR = 365 days/ 365 days

CFSCR = 100%

1.6 CFTotal = CFPlant x CFSNCR

CFTotal = 94% * 100%

CFTotal = 94%

1.9 ηNOx = (NOxin – NOxout) / NOxin

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

28%

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

ηNOx = 28%

Uncontrolled NOx emissions (tpy) 5,294
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 * 6112 * 28% * 187% * 60.06 / 2 / 46.01

m-dotreagent = 313 lb/hr

1.16 m-dotsol = m-dotreagent/Csol

m-dotsol = 313 / 0.50

m-dotsol = 626 lb/hr

1.17 qsol = m-dotvol/ρsol

qsol = 626 * 7.481 / 71

qsol = 66 gph

2.35 Tank Volume = q t sol

Tank Volume = 66 * 14 * 24

Tank Volume = 22,145 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 * 6112 *( 2375 / 6112 )^ 0.577 *( 0.66 + 0.85 * 28% )

DC = $ 3,022,136

Inflation Adjustment = 1.34

DC = $ 4,049,662
Indirect Capital Costs Cost Manual GRE

Cost Cost Cost Cost

Total Direct Capital Costs, A $ 4,049,662 ratios $ 3,789,655 company 7/15/11 report Table A-15 ratios

Indirect Installation Costs 

General Facilities 0.05 A $202,483 5%

Engineering and Home Office Fees 0.10 A $404,966 10%

Process Contingencies 0.05 A $202,483 5%

Total Indirect Installation Costs, B 0.20 A $809,932 20%

Project Contingency, C = 0.15 (A+B) $728,939 18%

Total Plant Cost D = A+B+C $5,588,534 138%

Preproduction Cost 0.02 D $111,771 3%

Inventory Capital $42,560 1%

Total Capital Investment TCI = D+G+H +D+E+F+G+H+I $5,742,864 142% $ 13,283,414 company 7/15/11 report Table A-15 351%

TCI = company DCC * 142% $ 5,374,146
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 * $ 5,374,146

Annual Maintenance Cost = $ 80,612

1.22 Annual Reagent Cost = qsolCostreagenttop

1.22.a top = CFtotal8760hr/yr

top = 94% * 8760

top = 8246

Annual Reagent Cost = 66 * 1.921868734 * 8246

Annual Reagent Cost = $ 1,044,530

1.24 Annual Electricity Cost = Power (Costelect)top

1.23 Power = 0.47NOxinNSRQB/9.5

Power = 0.47 * 0.15 * 1.87 * 6112 / 9.5

Power = 85 kW

Annual Electricity Cost = 85 * 8246 * 0.051

Annual Electricity Cost = $ 35,608

1.27 Annual Water Cost = qwaterCostwater top

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

qwater = 626 / 8.345 *( 50% / 10% - 1 )

qwater = 300

Annual Water Cost = 300 * 0.0004 * 8246

Annual Water Cost = $ 989

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 * 626 *( 1 / 10% - 1 )

ΔCoal(Btu/hr) = 5,066,627

Annual ΔCoal cost = 5.1 * $ 0.91 * 8246

Annual ΔCoal cost = $ 38,021

1.32 Annual ΔAsh cost = ΔAsh costash top

1.30 ΔAsh = ΔCoal ash product/HHV

ΔAsh = 5 * 77000 / 6257

ΔAsh = 62

Annual ΔAsh cost = 62 * $ 11.28 * 8246 / 2000

Annual ΔAsh cost = $ 2,900

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

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

Total Variable Cost = $ 5,169,508

Total Direct Annual Cost = $ 80,612 + $ 5,169,508

Total Direct Annual Cost = $ 5,250,120

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 * $ 5,374,146

Indirect Annual Cost = $ 507,281

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

Total Annual Cost = $ 5,250,120 + 507,281

Total Annual Cost = $ 5,757,401

1.36 NOx Removed = NOxinηNOxQBtop

NOx Removed = 0.150 * 28% * 6112 * 8246 / 2000

NOx Removed = 1058

1.37 Cost effectiveness = TAC/NOx

 removed

Cost effectiveness = $ 5,440
Coal Creek Station Unit 1, 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 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) $ 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) $ 445 calculated

SNCR Cost Analysis

Control Efficiency 28.0% OAQPS Control Cost Manual

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

Controlled Emissions (tpy) 2,722 calculated

Emissions Reduction (tpy) 1,058 OAQPS Control Cost Manual

Capital Cost $ 5,374,146 company 7/15/11 report Table A-15

Capital Cost ($/kW) $ 10 calculated

O&M Cost $ 5,250,120 hybrid

Annualized Cost $ 5,757,401 hybrid

Cost-Effectiveness ($/ton) $ 5,440 hybrid

SOFA/LNB1+SNCR Cost Analysis

Control Efficiency 49% calculated

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

Controlled Emissions (tpy) 2,722 calculated

Emissions Reduction (tpy) 2,572 calculated

Capital Cost $ 10,287,445 calculated

Capital Cost ($/kW) $ 19 calculated

O&M Cost $ 5,258,086 calculated

Annualized Cost $ 6,430,459 calculated

Cost-Effectiveness ($/ton) $ 2,500 calculated