### OP_YEAR STATE FACILITY_NAME ORISPL_CODE UNITID 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 O** **x E** **m i** **s s** **i o** **n s** **( l** **b /** **m m** **B t** **u )**  

# Coal Cr **eek 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 O** **x E** **m i** **s s** **i o** **n s** **( l** **b /** **m m** **B t** **u )** 



### Year

### 3,000

4,000 5,000 6,000 7,000**N O** **x E** **m i** **s s** **i o** **n s** **( t** **p y** **)** 

# Coal Cr **eek NOx Mass Emissions**

CCS #1

CCS #2

- 1,000 2,000

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010**N O** **x E** **m i** **s s** **i o** **n s** **( t** **p y** **)**



### 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/y r 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 W eight (g/mole) 60.06 OAQPS Control Cost Manual SR T 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 W eight (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 Wa ter Consumption Cost ($/gal) 0.0004 OAQPS Control Cost Manual Electrical Power Cost ($/kW h) 0.051 $ company 7/15/11 report Table A-15 50% Urea Solution Cost ($/gal) 0.96 $ 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)

- $ company 7/15/11 report Table A-15 Additional Ash Disposal Cost ($/ton)

- $ company 7/15/11 report Table A-15

### Boiler Calculations



## 1.3 Q B 

## = HVm-dot fuel 

### QB = 6257 Btu/lb * 

### 976,829 lb/hr QB = 6112 mmB tu/hr



## 1.7 CF Plant 

## = actual m fuel 

## /maximum m fuel 

### CFPlant = 8.06E+09 lb/y r / 8760 hr/y r / 

### 976,829 lb/hr
CFPlant = 

### 94.1%



## 1.8 CF SNCR 

## = t SCR



## /365 day s CFSCR = 365 day s/ 365 day s CFSCR = 

### 100%

1.6 

## CF Total 

## = CF Plant 

## x CF SNCR 

### CFTotal = 94% * 100% CFTotal = 

### 94%



## 1.9 η NOx 

## = (NOx in 

## – NOx out 

## ) / NOx in 

### ηNOx = ( 0.150 lb/m mB tu - 0.108 lb/m mB tu)/ 0.15 lb/m mB tu



### 28% ηNOx = ( 0.150 lb/m mB tu - 0.108 lb/m mB tu)/ 0.15 lb/m mB tu ηNOx = 

### 28%

**Uncontrolled NOx emissions (tpy) 5,294** 

### Reagent Calculations 1.14 NSR = [2NOx in 

### – 0.7] η NOx 

### / NOx in 

### NSR = ( 2 * 0.15 + 0.7 ) * 28% / 0.15 NSR = 1.87

1.13 Utilization = η NOx



### /NSR
Utilization = 15%

1.15 m-dot reagent 

### = NOx in 

### Q B 

### η NOx 

### NSR M reagent 

### /M NOx 

### /SR T 

### m-dotreagent = 0.150 * 6112 * 100% * 187% * 60.06 / 2 / 46.01 m-dotreagent = 1117 lb/hr

1.16 m-dot sol 

### = m -dot reagent 

### /C sol 

### m-dotsol = 1117 / 0.50 m-dotsol = 2234 lb/hr

1.17 q sol 

### = m -dot vol 

### /ρ sol 

### qsol = 2234 * 7.481 / 71 qsol = 235 gph

2.35 Tank Volume = q t sol 

### Tank Volume = 235 * 14 * 24 Tank Volume = 79,089 gal**Direct Capital Cost**

1.19 DC = ($950/mmBtu/hr) * Q B (mmBtu/hr)[(2375/mmBtu/hr)/Q B (mmBtu/hr] 0.577 * (0.66 + 0.85* η NOx ) 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 $75,999 2% **Total Capital Investment TCI = D+G+H** +D+E+F+G+H+I $5,776,304 143% 11,803,820 $ company 1/11/11 report Table A-8 311%

TCI = company DCC * 143% 5,405,439 $**Annual Costs**

2.45 DAC = Annual Maintenance Cost + Annual Reagent Cost + Annual Electricity Cost + Annual W ater Cost + Annual Catalyst Cost 2.46 Annual Maintenance Cost = 0.015 TCI Annual Maintenance Cost = 0.015 * 5,405,439 $ Annual Maintenance Cost = 81,082 $
1.22 Annual Reagent Cost = q sol Cost reagent t op 1.22.a t op = CF total 8760hr/yr top = 94% * 8760 top = 8246 Annual Reagent Cost = 235 * 0.960934367 * 8246 Annual Reagent Cost = 1,865,231 $
1.24 Annual Electricity Cost = Power (Cost elect )t op 1.23 Power = 0.47NOx in NSRQ B /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 W ater Cost = q water Cost water t op 1.25 q water

= m-dot sol /ρ water [Curea stored /Curea sol inj -1] qwater = 2234 / 8.345 *( 50% / 10%

- 1 ) qwater = 1071 Annual W ater Cost = 1071 * 0.0004 * 8246 Annual W ater Cost = 3,532 $ 1.31 Annual ΔCoal cost = ΔCoal cost coal t op 1.28 ΔCoal(Btu/hr) = Hv(Btu/lb)* m-dot reagent (lb/hr)[1/ Curea sol inj -1] ΔCoal(Btu/hr) = 900 * 2234 *( 1 / 10%

- 1 ) ΔCoal(Btu/hr) = 18,095,097 Annual ΔCoal cost = 18.1 * 0.91 $ * 8246 Annual ΔCoal cost = 135,789

$

1.32 Annual ΔAsh cost = ΔAsh cost ash t op 1.30 ΔAsh = ΔCoal ash product/HHV ΔAsh = 18 * 77000 / 6257 ΔAsh = 223 Annual ΔAsh cost = 223 * 11.28 $ * 8246 / 2000 Annual ΔAsh cost = 10,357

$

Additional Ash Disposal Cost ($/ton) =

- $ Lost ash sales ($/yr)

- $

Total Variable Cost = 2,050,517

$

Total Direct Annual Cost = 81,082 $ + 2,050,517 $ Total Direct Annual Cost = 2,131,599 $

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 * 11,803,820 $ Indirect Annual Cost = 1,114,197 $

1.35 Total Annual Cost = Direct Annual Cost + Indirect Annual Cost Total Annual Cost = 2,131,599

$ + 1,114,197 Total Annual Cost = 3,245,796

$

1.36 NOx Removed = NOx in η NOx Q B t op NOx Removed = 0.150 * 28% * 6112 * **8246** / 2000 NOx Removed = 1058

1.37 Cost effectiveness = TAC/NO x removed Cost effectiveness = 3,067

$**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 11,803,820 $ company 1/11/11 report Table A-8 Capital Cost ($/kW ) 21 $ calculated O&M Cost 2,131,599 $ hybrid Annualized Cost 3,245,796 $ hybrid Cost-Effectiveness ($/ton) 3,067 $ 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 16,717,119 $ calculated Capital Cost ($/kW ) 30 $ calculated O&M Cost 2,139,565 $ calculated Annualized Cost 3,918,854 $ calculated Cost-Effectiveness ($/ton) 1,524 $ calculated