No. 1 PB

Fuel 

Yearly Heat 

Input 

(MMBtu)

Yearly Heat 

Input 

(MMBtu)

Yearly Heat 

Input 

(MMBtu)

Yearly Heat 

Input 

(MMBtu)

Natural gas 298407 341341 294717 311489

GP/Internal Bark 477623 628825 493286 533245

Pur/Rec Bark 576712 449244 474792 500249

Pelletized Waste 3796 6138 67103 25679

Tire Derived Fuel 1299 152 430 627

Fuel Oil 83814 0 0 27938

Total 1,441,651 1,425,700 1,330,329 1,399,227

No. 2 PB

Fuel

Yearly Heat 

Input 

(MMBtu)

Yearly Heat 

Input 

(MMBtu)

Yearly Heat 

Input 

(MMBtu)

Yearly Heat 

Input 

(MMBtu)

Natural gas 29844 28995 23653 27497

GP/Internal Bark 442170 484091 375226 433829

Pur/Rec Bark 422062 256457 294706 324409

Pelletized Waste 4011 3449 41222 16227

Tire Derived Fuel 982 79 207 423

Fuel Oil 0 0 0 0

Coal 4436887 4267767 3856601 4187085

Total 5,335,957 5,040,839 4,591,616 4,989,471

Coal HHV, Btu/lb 9819.5 9631.4 9477.1 9642.7

Bark HHV, Btu/lb 2555.6 2784.7 2630.8 2657.0

Average

Average

2001 2002 2003

2001 2002 2003
Highest Day 2009-2011

22.26148 MM BTU

38.10997 2009 2010

35.75185 No.1 Power Boiler 11069.67 9994.54

1.835221

0.044805

1.996678

Highest Day 2009-2011

0.551109 MM BTU

8.694895 2009 2010

6.501864 No. 2 Power Boiler 37809.34 33509.86

0.325235

0.008472

0

83.91843
2011

9917.84

2011

30793.69
Operational Data

Power Boiler 1 Power Boiler 2

Maximum Heat Input (MMBtu/hr) 580 820

Average Operation '01-'03 8,379.12 8,502.47

Average Operation '09-'11 8,130.72 8,308.57
Emission Rates

No. 1 Power Boiler (SN-03)

(lb/day) (lb/hr) (lb/MMBtu) (tpy, max day avg) (tpy, actual from EI submittals)

09-11 Baseline Rates

NOX Revised Mar 2014 report 4976.9 207.4 0.358 843.041 440.2

SO2 Revised Mar 2014 report 504.0 21.00 0.036 85.373 14.57

PM10 Revised Mar 2014 report 728.4 30.35 0.052 123.381 26.4

NOX Controlled (from the 09-11 baseline) Rates (Control Eff.) (tpy removed, max day avg) (tpy removed, actual)

MdN 50% CE Revised Mar 2014 report 2488.5 103.7 0.179 50% 421.521 421.521 220.117 220.12

SNCR 20% Revised Mar 2014 report 3981.5 165.9 0.286 20% 674.433 168.608 352.187 88.05

SNCR 32.5% Revised Mar 2014 report 3359.4 140.0 0.241 33% 569.053 273.988 297.158 143.08

SNCR 45.0% Revised Mar 2014 report 2737.3 114.1 0.197 45% 463.673 379.368 242.128 198.11

LNB 30% CE Revised Mar 2014 report 3483.8 145.2 0.250 30% 590.129 252.912 308.163 132.07

No. 2 Power Boiler (SN-05)

(lb/day) (lb/hr) (lb/MMBtu) (tpy, max day avg) (tpy, actual from EI submittals)

01-03 Baseline (previously used) Rates

NOx 12643.2 526.8 0.642 2239.551 1535.6

SO2 18916.8 788.2 0.961 3350.825 2078.0

PM10/PMF 1958.4 81.6 0.100 346.901 199.2

NOX Controlled (from the 01-03 baseline) Rates (Control Eff.) (tpy removed, max day avg) (tpy removed, actual)

MdN 50% CE 6321.6 263.4 0.321 50% 1119.776 1119.776 767.815 767.815

SNCR 20% 10114.6 421.44 0.514 20% 1791.641 447.910 1228.504 307.126

SNCR 27.5% 9166.3 381.93 0.466 27.5% 1623.675 615.877 1113.332 422.298

SNCR 35% 8218.1 342.42 0.418 35.0% 1455.708 783.843 998.160 537.471

LNB 30% CE Revised Mar 2014 report 8850.2 368.8 0.450 30% 1567.686 671.865 1074.941 460.69

SO2 Controlled (from the 01-03 baseline) Rates

Wet Scrubbing/ESP SO2 1891.7 78.82 0.096 90% 335.082 3015.742 207.803 1870.224


Recent No. 1 Power Boiler PM Testing

Run 1 Run 2 Run 3 Average

Test Date (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

8/7/2007 0.0124 0.0177 0.0113 0.0138

2/26/2008 0.0368 0.0434 0.0468 0.0423

2/28/2008 0.0389 0.0619 0.0475 0.0494

4/22/2010 0.0190 0.0128 0.0098 0.0139

Mean Average (MA): 0.0299

Standard Deviation (SD): 0.0180

Mean + 2 SD: 0.0658

Recent No. 1 Power Boiler NOX Testing

Run 1 Run 2 Run 3 Average

Test Date (lb/MMBtu) (lb/MMBtu) (lb/MMBtu) (lb/MMBtu)

3/10/2004 0.3518 0.4048 0.3893 0.3820

10/25/2005 0.3446 0.3706 0.3582 0.3578

4/22/2010 0.2400 0.2641 0.2843 0.2628

Mean Average (MA): 0.3342

Standard Deviation (SD): 0.0577

Mean + 2 SD: 0.4496

No. 1 Power Boiler Monthly SO2 Emissions

Month 2009 2010 2011

January 0.263 0.374 0.27

February 0.294 0.26 0.24

March 0.04 0.3 0.27

April 0.08 0.2 0.18

May 0.02 0.28 0.23

June 0 0.08 0.21

July 0.19 0.22 0.21

August 0.23 0.79 0.18

September 0.13 0.2 0.21

October 0.19 0.14 0.21

November 0.18 0.11 0.2

December 0.13 0.13 0.21

No. 1 Power Boiler SO2 Emissions 

(tons/month)
Mean Average (MA): 0.2070

Standard Deviation (SD): 0.1285

SD as a % of MA 62

The 1/09, 2/09, and 1/10 values are adjusted from Domtar’s official emissions 

records to include consideration of the 97.5 % control efficiency on SO2 

emissions from fuel oil combustion provided by the WESP. The consideration 

was not applied in the official records until 2011. Only three months are adjusted 

because those are the only months in 2009 and 2010 during which fuel oil was 

combusted.
`
REV EE SN-03 - (Baseline Mar 2014 Report )

 Source Name

SO2 SO4 NOX HNO3 NO3

Unit 1 21.0 0.0 207.4 0.0 0.0

SN-03A 10.5 0.0 103.7 0.0 0.0

SN-03B 10.5 0.0 103.7 0.0 0.0

REV FF SN-03 - MdN 50% CE => 0.179 lb/MMBtu (Mar 2014 Report )

 Source Name

SO2 SO4 NOX HNO3 NO3

Unit 1 21.0 0.0 103.7 0.0 0.0

SN-03A 10.5 0.0 51.8 0.0 0.0

SN-03B 10.5 0.0 51.8 0.0 0.0

REV GG SN-03 - SNCR at 20% control => 0.286 lb/MMBtu (Mar 2014 Report )

 Source Name

SO2 SO4 NOX HNO3 NO3

Unit 1 21.0 0.0 165.9 0.0 0.0

SN-03A 10.5 0.0 82.9 0.0 0.0

SN-03B 10.5 0.0 82.9 0.0 0.0

REV HH SN-03 - SNCR at 32.5% control => 0.241 lb/MMBtu (Mar 2014 Report )

 Source Name

SO2 SO4 NOX HNO3 NO3

Unit 1 21.0 0.0 140.0 0.0 0.0

SN-03A 10.5 0.0 70.0 0.0 0.0

SN-03B 10.5 0.0 70.0 0.0 0.0

REV II SN-03 - SNCR at 45.0% control => 0.197 lb/MMBtu (Mar 2014 Report )

 Source Name

SO2 SO4 NOX HNO3 NO3

Unit 1 21.0 0.0 114.1 0.0 0.0

SN-03A 10.5 0.0 57.0 0.0 0.0

SN-03B 10.5 0.0 57.0 0.0 0.0
REV JJ SN-03 - LNB at 30.0% control => 0.250 lb/MMBtu (Mar 2014 Report )

 Source Name

SO2 SO4 NOX HNO3 NO3

Unit 1 21.0 0.0 145.2 0.0 0.0

SN-03A 10.5 0.0 72.6 0.0 0.0

SN-03B 10.5 0.0 72.6 0.0 0.0
PMC PMf EC SOA PMtotal

0.0 30.3 0.0 0.0 30.3

0.0 15.2 0.0 0.0 15.2

0.0 15.2 0.0 0.0 15.2

PMC PMf EC SOA PMtotal

0.0 30.3 0.0 0.0 30.3

0.0 15.2 0.0 0.0 15.2

0.0 15.2 0.0 0.0 15.2

PMC PMf EC SOA PMtotal

0.0 30.3 0.0 0.0 30.3

0.0 15.2 0.0 0.0 15.2

0.0 15.2 0.0 0.0 15.2

PMC PMf EC SOA PMtotal

0.0 30.3 0.0 0.0 30.3

0.0 15.2 0.0 0.0 15.2

0.0 15.2 0.0 0.0 15.2

PMC PMf EC SOA PMtotal

0.0 30.3 0.0 0.0 30.3

0.0 15.2 0.0 0.0 15.2

0.0 15.2 0.0 0.0 15.2

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr
PM

C PMf EC SOA PMtotal

0.0 30.3 0.0 0.0 30.3

0.0 15.2 0.0 0.0 15.2

0.0 15.2 0.0 0.0 15.2

Input to CALPUFF 
SN-05 - (Baseline)

 Source Name

SO2 SO4 NOX HNO3 NO3

REV B Unit 2 788.2 0.0 526.8 0.0 0.0

SN-05 - Wet Scrubber/ESP (Control 4)

 Source Name

SO2 SO4 NOX HNO3 NO3

REV L Unit 2 78.8 0.0 526.8 0.0 0.0

SN-05 - 50% CE => 0.321 lb/MMBtu (Control 8) SAME AS REV N, CONTROL 5

 Source Name

SO2 SO4 NOX HNO3 NO3

REV T Unit 1 788.2 0.0 263.4 0.0 0.0

SN-05 - SNCR at 27.5% control => 0.466 lb/MMBtu (Control 10)

 Source Name

SO2 SO4 NOX HNO3 NO3

REV AA Unit 2 788.2 0.0 381.9 0.0 0.0

SN-05 - SNCR at 35% control => 0.418 lb/MMBtu (Control 11)

 Source Name

SO2 SO4 NOX HNO3 NO3

REV BB Unit 2 788.2 0.0 342.4 0.0 0.0

SN-05 - LNB at 30% control => 0.418 lb/MMBtu (Control 12)

 Source Name

SO2 SO4 NOX HNO3 NO3

REV DD Unit 2 788.2 0.0 368.8 0.0 0.0
PMC PMf EC SOA PMtotal

0.0 81.6 0.0 0.0 81.6

PMC PMf EC SOA PMtotal

0.0 81.6 0.0 0.0 81.6

PMC PMf EC SOA PMtotal

0.0 81.6 0.0 0.0 81.6

PMC PMf EC SOA PMtotal

0.0 81.6 0.0 0.0 81.6

PMC PMf EC SOA PMtotal

0.0 81.6 0.0 0.0 81.6

PMC PMf EC SOA PMtotal

0.0 81.6 0.0 0.0 81.6

Input to CALPUFF 

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr

Input to CALPUFF 

 Emission Rate 

lb/hr
Domtar - Ashdown Facility

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact ∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Baseline - SN-03 (REV A)

Caney Creek 0 0 0.190 0.266 0 0 0.107

Hercules-Glades 0 0 0.007 0.035 0 0 0.012

Mingo 0 0 0.006 0.013 0 0 0.008

Upper Buffalo 0 0 0.013 0.038 0 0 0.022

Baseline - SN-05 (REV B) June 2013 Report

Caney Creek 28 6 0.844 1.340 13 2 0.673

Hercules-Glades 0 0 0.080 0.239 0 0 0.083

Mingo 0 0 0.065 0.139 0 0 0.054

Upper Buffalo 0 0 0.146 0.349 0 0 0.127

Baseline - SN-03 (REV EE) Mar 2014 Report

Caney Creek 0 0 0.335 0.476 0 0 0.191

Hercules-Glades 0 0 0.013 0.061 0 0 0.020

Mingo 0 0 0.010 0.023 0 0 0.014

Upper Buffalo 0 0 0.023 0.065 0 0 0.038

Note: 

Since this is refined modeling (using the refined CALMET dataset), use the 98th percentile or 8th highest value in analyzing v

(Source: Letter from Guy Donaldson at EPA to Anthony Davis at ADEQ, dated 4/26/12)

2001 2002
Total Total Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact ∆dv

No. of Days 

with ∆dv ≥ 

0.5 

No. of Days 

with ∆dv ≥ 

1.0 

98th 

Percentile 

∆dv

0.238 0 0 0.097 0.173 0 0 0.190

0.045 0 0 0.012 0.027 0 0 0.012

0.022 0 0 0.006 0.035 0 0 0.008

0.052 0 0 0.014 0.033 0 0 0.022

1.603 8 0 0.604 0.852 49 8 0.844

0.329 0 0 0.105 0.196 0 0 0.105

0.162 0 0 0.055 0.246 0 0 0.065

0.332 0 0 0.117 0.381 0 0 0.146

0.406 0 0 0.171 0.308 0 0 0.335

0.077 0 0 0.020 0.047 0 0 0.020

0.038 0 0 0.011 0.060 0 0 0.014

0.090 0 0 0.025 0.055 0 0 0.038

8th highest value in analyzing visibility.

2003
Highest

Max 

Impact 

∆dv

QA 

Person QA Date

0.266 JAT 5/28/2013

0.045 JAT 5/28/2013

0.035 JAT 5/28/2013

0.052 JAT 5/28/2013

1.603 KRD 9/11/2012

0.329 KRD 9/11/2012

0.246 KRD 9/11/2012

0.381 KRD 9/11/2012

0.476 KRD 10/2/2013

0.077 KRD 10/2/2013

0.060 KRD 10/2/2013

0.090 KRD 10/2/2013
Domtar - Ashdown Facility

Post Control Emissions

Class I Area

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

SN-03 Post-Control - 50% CE => 0.104 lb/MMBtu (Control 6, REV R)

Caney Creek 0 0 0.101 0.141 0 0 0.057

Hercules-Glades 0 0 0.004 0.019 0 0 0.006

Mingo 0 0 0.003 0.007 0 0 0.004

Upper Buffalo 0 0 0.007 0.021 0 0 0.011

SN-03 Post-Control - SNCR at 20% control (Control 8, REV W)

Caney Creek 0 0 0.155 0.216 0 0 0.087

Hercules-Glades 0 0 0.006 0.029 0 0 0.009

Mingo 0 0 0.005 0.011 0 0 0.006

Upper Buffalo 0 0 0.011 0.032 0 0 0.018

SN-03 Post-Control - SNCR at 32.5% control (Control 9, REV X)

Caney Creek 0 0 0.132 0.185 0 0 0.075

Hercules-Glades 0 0 0.005 0.024 0 0 0.008

Mingo 0 0 0.004 0.009 0 0 0.005

Upper Buffalo 0 0 0.010 0.027 0 0 0.015

SN-03 Post-Control - SNCR at 45.0% control (Control 10, REV Y)

Caney Creek 0 0 0.110 0.153 0 0 0.062

Hercules-Glades 0 0 0.005 0.020 0 0 0.007

Mingo 0 0 0.004 0.008 0 0 0.004

Upper Buffalo 0 0 0.008 0.023 0 0 0.012

SN-03 Post-Control - MdN at 50.0% control (Control 11, REV FF)

Caney Creek 0 0 0.183 0.263 0 0 0.105

Hercules-Glades 0 0 0.007 0.033 0 0 0.011

Mingo 0 0 0.006 0.013 0 0 0.007

Upper Buffalo 0 0 0.013 0.036 0 0 0.021

SN-03 Post-Control - SNCR at 20.0% control (Control 12, REV GG)

Caney Creek 0 0 0.274 0.391 0 0 0.157

Hercules-Glades 0 0 0.010 0.050 0 0 0.016

Mingo 0 0 0.008 0.019 0 0 0.011

Upper Buffalo 0 0 0.019 0.053 0 0 0.031

SN-03 Post-Control - SNCR at 32.5% control (Control 13, REV HH)

Caney Creek 0 0 0.237 0.338 0 0 0.135

Hercules-Glades 0 0 0.009 0.043 0 0 0.014

Mingo 0 0 0.007 0.016 0 0 0.009

Upper Buffalo 0 0 0.017 0.046 0 0 0.027

SN-03 Post-Control - SNCR at 45.0% control (Control 14, REV II)

Caney Creek 0 0 0.199 0.284 0 0 0.114

Hercules-Glades 0 0 0.008 0.036 0 0 0.012

2001 2002
Mingo 0 0 0.006 0.014 0 0 0.008

Upper Buffalo 0 0 0.014 0.039 0 0 0.023

SN-03 Post-Control - LNB at 30.0% control (Control 15, REV JJ)

Caney Creek 0 0 0.244 0.348 0 0 0.140

Hercules-Glades 0 0 0.009 0.044 0 0 0.014

Mingo 0 0 0.007 0.017 0 0 0.010

Upper Buffalo 0 0 0.017 0.048 0 0 0.028

SN-05 Post-Control - Wet Scrubber/ESP (Control 4, REV L)

Caney Creek 19 2 0.698 1.150 7 0 0.468

Hercules-Glades 0 0 0.035 0.158 0 0 0.054

Mingo 0 0 0.029 0.073 0 0 0.039

Upper Buffalo 0 0 0.066 0.177 0 0 0.093

SN-05 Post-Control - MdN, 0.321 lb/MMBtu (Control 5, REV N = Control 8, REV T)

Caney Creek 11 0 0.548 0.854 5 1 0.449

Hercules-Glades 0 0 0.076 0.168 0 0 0.060

Mingo 0 0 0.057 0.130 0 0 0.043

Upper Buffalo 0 0 0.117 0.274 0 0 0.087

SN-05 Post-Control - LNB, 0.450 lb/MMBtu (Control 6, REV P)

Caney Creek 18 2 0.663 1.051 8 1 0.545

Hercules-Glades 0 0 0.077 0.196 0 0 0.069

Mingo 0 0 0.060 0.133 0 0 0.047

Upper Buffalo 0 0 0.132 0.304 0 0 0.103

SN-05 Post-Control - SNCR at 27.5% control (Control 10, REV AA)

Caney Creek 20 2 0.678 1.075 8 1 0.557

Hercules-Glades 0 0 0.077 0.200 0 0 0.070

Mingo 0 0 0.060 0.133 0 0 0.048

Upper Buffalo 0 0 0.134 0.308 0 0 0.105

SN-05 Post-Control - SNCR at 35% control (Control 11, REV BB)

Caney Creek 16 1 0.632 1.002 8 1 0.521

Hercules-Glades 0 0 0.076 0.189 0 0 0.067

Mingo 0 0 0.059 0.132 0 0 0.045

Upper Buffalo 0 0 0.129 0.296 0 0 0.099

SN-05 Post-Control - LNB at 30% control (Control 12, REV DD)

Caney Creek 18 2 0.663 1.051 8 1 0.545

Hercules-Glades 0 0 0.077 0.196 0 0 0.054

Mingo 0 0 0.060 0.133 0 0 0.047

Upper Buffalo 0 0 0.132 0.304 0 0 0.103

Note: 

Since this is refined modeling (using the refined CALMET dataset), use the 98th percentile or 8th highest value in analyzing v

(Source: Letter from Guy Donaldson at EPA to Anthony Davis at ADEQ, dated 4/26/12)
Total Total Highest Highest

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv

No. of 

Days with 

∆dv ≥ 0.5 

No. of 

Days with 

∆dv ≥ 1.0 

98th 

Percentile 

∆dv

Max 

Impact 

∆dv

0.136 0 0 0.052 0.091 0 0 0.101 0.141

0.025 0 0 0.006 0.014 0 0 0.006 0.025

0.012 0 0 0.003 0.019 0 0 0.004 0.019

0.028 0 0 0.007 0.019 0 0 0.011 0.028

0.197 0 0 0.079 0.141 0 0 0.155 0.216

0.037 0 0 0.009 0.022 0 0 0.009 0.037

0.018 0 0 0.005 0.029 0 0 0.006 0.029

0.042 0 0 0.012 0.027 0 0 0.018 0.042

0.172 0 0 0.067 0.120 0 0 0.132 0.185

0.032 0 0 0.008 0.019 0 0 0.008 0.032

0.015 0 0 0.004 0.024 0 0 0.005 0.024

0.036 0 0 0.010 0.024 0 0 0.015 0.036

0.146 0 0 0.056 0.099 0 0 0.110 0.153

0.027 0 0 0.007 0.016 0 0 0.007 0.027

0.013 0 0 0.004 0.020 0 0 0.004 0.020

0.030 0 0 0.008 0.020 0 0 0.012 0.030

0.233 0 0 0.095 0.169 0 0 0.183 0.263

0.042 0 0 0.011 0.025 0 0 0.011 0.042

0.020 0 0 0.006 0.032 0 0 0.007 0.032

0.049 0 0 0.014 0.032 0 0 0.021 0.049

0.337 0 0 0.140 0.253 0 0 0.274 0.391

0.063 0 0 0.017 0.038 0 0 0.017 0.063

0.031 0 0 0.009 0.049 0 0 0.011 0.049

0.074 0 0 0.021 0.046 0 0 0.031 0.074

0.294 0 0 0.121 0.218 0 0 0.237 0.338

0.054 0 0 0.014 0.032 0 0 0.014 0.054

0.026 0 0 0.008 0.042 0 0 0.009 0.042

0.064 0 0 0.018 0.040 0 0 0.027 0.064

0.250 0 0 0.102 0.183 0 0 0.199 0.284

0.046 0 0 0.012 0.027 0 0 0.012 0.046

2003
0.022 0 0 0.006 0.035 0 0 0.008 0.035

0.053 0 0 0.015 0.034 0 0 0.023 0.053

0.302 0 0 0.125 0.225 0 0 0.244 0.348

0.056 0 0 0.015 0.034 0 0 0.015 0.056

0.027 0 0 0.008 0.043 0 0 0.010 0.043

0.066 0 0 0.018 0.041 0 0 0.028 0.066

0.946 5 0 0.383 0.636 31 2 0.698 1.150

0.188 0 0 0.053 0.122 0 0 0.054 0.188

0.105 0 0 0.031 0.174 0 0 0.039 0.174

0.231 0 0 0.071 0.163 0 0 0.093 0.231

1.323 3 0 0.402 0.630 19 1 0.548 1.323

0.248 0 0 0.087 0.156 0 0 0.087 0.248

0.114 0 0 0.050 0.166 0 0 0.057 0.166

0.231 0 0 0.092 0.317 0 0 0.117 0.317

1.436 6 0 0.486 0.708 32 3 0.663 1.436

0.280 0 0 0.094 0.172 0 0 0.094 0.280

0.133 0 0 0.051 0.198 0 0 0.060 0.198

0.271 0 0 0.100 0.343 0 0 0.132 0.343

1.450 7 0 0.496 0.720 35 3 0.678 1.450

0.284 0 0 0.095 0.174 0 0 0.095 0.284

0.135 0 0 0.051 0.202 0 0 0.060 0.202

0.276 0 0 0.100 0.346 0 0 0.134 0.346

1.408 6 0 0.467 0.683 30 2 0.632 1.408

0.272 0 0 0.092 0.168 0 0 0.092 0.272

0.128 0 0 0.051 0.190 0 0 0.059 0.190

0.261 0 0 0.099 0.336 0 0 0.129 0.336

1.436 6 0 0.486 0.708 32 3 0.663 1.436

0.081 0 0 0.094 0.172 0 0 0.094 0.196

0.133 0 0 0.051 0.198 0 0 0.060 0.198

0.271 0 0 0.100 0.343 0 0 0.132 0.343

th highest value in analyzing visibility.
Total Total Highest Highest

No. of Days 

with ∆dv ≥ 

0.5 

No. of Days 

with ∆dv ≥ 

1.0 

98th 

Percentile 

∆dv

Max Impact 

∆dv QA Person QA Date

0 0 0.089 0.125 JAT 5/28/2013

0 0 0.006 0.020 JAT 5/28/2013

0 0 0.004 0.016 JAT 5/28/2013

0 0 0.011 0.024 JAT 5/28/2013

0 0 0.035 0.050 JAT 5/28/2013

0 0 0.003 0.008 JAT 5/28/2013

0 0 0.002 0.006 JAT 5/28/2013

0 0 0.004 0.010 JAT 5/28/2013

0 0 0.058 0.081 JAT 5/28/2013

0 0 0.004 0.013 JAT 5/28/2013

0 0 0.003 0.011 JAT 5/28/2013

0 0 0.007 0.016 JAT 5/28/2013

0 0 0.080 0.113 JAT 5/29/2013

0 0 0.005 0.018 JAT 5/29/2013

0 0 0.004 0.015 JAT 5/29/2013

0 0 0.010 0.022 JAT 5/29/2013

0 0 0.152 0.213 KAG 3/4/2014

0 0 0.009 0.035 KAG 3/4/2014

0 0 0.007 0.028 KAG 3/4/2014

0 0 0.017 0.041 KAG 3/4/2014

0 0 0.061 0.085 KAG 3/4/2014

0 0 0.003 0.014 KAG 3/4/2014

0 0 0.003 0.011 KAG 3/4/2014

0 0 0.007 0.016 KAG 3/4/2014

0 0 0.098 0.138 KAG 3/4/2014

0 0 0.006 0.023 KAG 3/4/2014

0 0 0.005 0.018 KAG 3/4/2014

0 0 0.011 0.026 KAG 3/4/2014

0 0 0.136 0.192 KAG 3/5/2014

0 0 0.008 0.031 KAG 3/5/2014

Difference Between Baseline and Post-Control

QA - Entering of Results
0

0 0.006 0.025 KAG 3/5/2014

00 0.015 0.037 KAG 3/5/2014

00 0.091 0.128 KAG 3/5/2014

00 0.320 0.420 KAG 3/7/2014

00 0.004 0.017 KAG 3/5/2014

00 0.010 0.024 KAG 3/5/2014

186 0.146 0.453 JAT 5/29/2013

00 0.051 0.141 JAT 5/29/2013

00 0.026 0.072 JAT 5/29/2013

00 0.053 0.150 JAT 5/29/2013

307 0.296 0.280 JAT 11/8/2012

00 0.018 0.081 JAT 11/8/2012

00 0.008 0.080 JAT 11/8/2012

00 0.029 0.064 JAT 11/8/2012

175 0.181 0.167 JAT 11/12/2012

00 0.011 0.049 JAT 11/12/2012

00 0.005 0.048 JAT 11/12/2012

00 0.014 0.038 JAT 11/12/2012

145 0.166 0.153 JAT 4/17/2013

00 0.010 0.045 JAT 4/17/2013

00 0.005 0.044 JAT 4/17/2013

00 0.012 0.035 JAT 4/17/2013

196 0.212 0.195 JAT 4/17/2013

00 0.013 0.057 JAT 4/17/2013

00 0.006 0.056 JAT 4/17/2013

00 0.017 0.045 JAT 4/17/2013

175 0.181 0.167 KAG 3/5/2014

00 0.011 0.133 KAG 3/5/2014

00 0.005 0.048 KAG 3/5/2014

00 0.014 0.038 KAG 3/5/2014


Capital Costs

Technology

Wet Scrubber/ESP for No. 2 Power Boiler

Max Heat Input (MMBtu/hr) 820

System Flow Rate (SCFM dry)1

142,737

Scrubber Exit Gas Temp. (°F)1

136

Exit Moisture (% wt)1

12.3

System Flow Rate (ACFM) 183,730

Annual Operating Time (θ') , 2001-2003 average 8,502

Water Use (gal/yr)10 1,874,592,263

Electricity Cost (Costelect, $/kwh)2

$0.05

Water Cost (Costwater, $/gal)3

$0.00008

SO2 Control Efficiency1

90%

ESP Plate Area (ft2)

4 NA

Purchased Equipment Cost (PEC)1

$2,050,000

Total Capital Investment (TCI) = PEC + Costs to Retrofit11 $7,175,000

Capital recovery factor (CRF) CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment 

life

0.0806

a. Equipment CRF, 30-yr life, 7% interest5

Annual Costs6

Variable (Direct) Annual Costs - Table 2.9

 Operating Labor

 Operator 13 3hr/shift*2shifts/day*360 days/yr * $22/hr $47,520

 Supervisor 15% of operator labor $7,128

 Maintenance

 Labor Estimated based on past site-specific $60,000

 Material experience / maintenace costs for other scrubbers $110,000

 Utilities

 Fan7

 = 108 kW × Costelect $45,913

 ESP operating power8= 1.94 × 10-3 × A × θ' NA

 Pump9 = 0.746 × Ql

 × Z × Sg × θ' / 3,960η × Costelect $23,803

 Water Cost = Water use × water cost $146,593

 Wastewater treatment3 = $3.25/1000 gal × Annual water use $6,092,425

 Sorbent (caustic) usage12 = $0.875/lb × Annual sorbet use (5 lb/min) $2,300,000

Total Variable (Direct) Annual Cost $8,833,382

Fixed (Indirect) Costs, IC

 Administrative charges 2% of Total Capital Investment $143,500

 Property tax 1% of Total Capital Investment $71,750

 Insurance 1% of Total Capital Investment $71,750

 Overhead 60% of total labor and material costs $134,789

Total Fixed (Indirect) Costs $421,789

Annualized Capital Cost Capital Recovery Factor * Total Capital Investment $578,207

Total Annual Cost $9,833,378

Add-On Scrubber/WESP Capital and O&M Cost Estimate for No. 2 Power Boiler
Based on Modeled Baseline Maximum Daily Emission Rates:

Total Uncontrolled NOx Emissions (tpy) 3351

Pollutant Removed (tpy) 3016

Cost Effectiveness ($/ton removed) $3,261

Based on Actual Annual Emission Rates:

Total Uncontrolled NOx Emissions (tpy) 2078

Pollutant Removed (tpy) 1870

Cost Effectiveness ($/ton removed) $5,258

1: From A.H. Lundberg Associates, Inc. Budget Proposal, June 22, 2012, amended April 17, 2014.

2: Electricity cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1

3: Water cost estimate from Ashdown Mill 2013 Budget.

7: Fan power demand from A.H. Lundberg Associates, Inc. Budget Proposal, April 17, 2014.

9: For pump power cost:

 Ql = water flow rate (gal/min)

 Z = Fluid head (ft), assume maximum fluid heat is 50 ft

 Sg = specific gravity of water being pumped compared to water at 70 °F and 29.92 in. Hg, assume 1

 θ' = annual operating time (h/yr)

 η = pump motor efficiency (fractional), assume efficiency of 60%

10: Liquid to gas ratio: 20 gal/1,000 acf, from A.H. Lundberg Associates, Inc. Budget Proposal, June 22, 2012 - Process description section 

11: Domtar's engineers estimate that PEC accounts for only approximately 40 % of the total investment to place a new WESP into service.

This estimate, equivalent to a 2.5 factor, or an even greater factor (up to 3.5) in some cases, is used by Domtar's engineers for all non-Appropriations 

Request (AR) level sales proposal cost estimates. Additionaly, in this specific case, because there is no room (real estate) at the Ashdown Mill

to place a WESP, an additional 1.0 factor is included to account for the need to build a substantial support structure - most likely over a road.

If the extra retrofit factor is not included, then the TCI is $13,175,000 and the cost effectiveness decreases by $200 to $300/ton depending on which

baseline averaging period is used.

12: Lundberg estimated a sorbent usage rate of 5 lb/min (2,628,000 lb/yr) is needed to achieve the additional 90 percent (overall 99 percent).

13: Contracted labor rate at the Ashdown Mill.

14: Based on historical annual cost for maintenance and cleaning for the existing WESP on the No. 1 Power Boiler.

6: Annual Cost estimates made using the EPA Air Pollution Control Cost Manual (APCCM), 6th Edition (January 2002). Section 6, Chapter 3 - Electrostatic 

Precipitators 

5: Capital recovery interest rate and equipment life from EPA Air Pollution Control Cost Manual (APCCM), 6th Edition (January 2002). Section 6, Chapter 

3 - Electrostatic Precipitators, pp. 3-50 and 3-51.
Technology

SNCR Case 1 Case 2 Case 3

Parameters/Costs Equation1 Unit 1 Unit 1 Unit 1

Boiler design capacity, mmBtu/hr (QB) QB 580 580 580

Total operating time (top, hrs/yr) top = CFtotal × 8760 hrs/yr 8130.72 8130.72 8130.72

Total Capacity Factor (CFtotal) CFtotal = CFplant × CFSNCR 0.93 0.93 0.93

Plant Capacity Factor (CFplant)

2

0.93 0.93 0.93

SNCR Capacity Factor (CFSCNR)

3 CFSNCR = tSNCR/365 1 1 1

Electricity Cost (Costelect, $/kwh)6$0.05 $0.05 $0.05

Water Cost (Costwater, $/gal)7$0.00008 $0.00008 $0.00008

Bark Cost (Costbark, $/MMBtu)8$5.57 $5.57 $5.57

Bark HHV (Btu/lb)92,657 2,657 2,657

Cost of Ash Disposal (Cash, $/ton)10 $23.06 $23.06 $23.06

Capital recovery factor (CRF)

CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = 

equipment life 0.0806 0.0806 0.0806

a. Equipment CRF, 30-yr life, 7% interest

Cost Index11

a. 2012 Cost Index 584.6

b. 1998 Cost Index 389.5

Capital Costs 

Direct Capital Cost (A)

DC ($) = ($950/MMBtu) × QB × ((2375 MMBtu/hr/QB)^0.577) × (0.66 

+ 0.85ηNOx) × (CI2011/CI1998) #REF! #REF! #REF!

Indirect Installation Costs ($)

General Facilities 0.05 × A #REF! #REF! #REF!

Engineering and Home Office Fees 0.10 × A #REF! #REF! #REF!

Process Contingency 0.05 × A #REF! #REF! #REF!

Total Indirect Installation Costs (B)

= General Facilities Cost + Engineering and Home Office Fees + 

Process Contingency #REF! #REF! #REF!

Other Installation Costs ($)

Project Contingency (C) C = 0.15 × (A + B) #REF! #REF! #REF!

Total Plant Cost (D) D = A + B + C #REF! #REF! #REF!

Allowance for Funds During Construction (E) E = 0 (Assumed for SNCR) $0 $0 $0

Royalty Allowance (F) F = 0 (Assumed for SNCR) $0 $0 $0

Preproduction Cost (G) G = 0.02 × (D + E) #REF! #REF! #REF!

Inventory Capital (H)12 H = Volreagent (gal) × Costreagent ($/gal) $46,255 $33,635 $33,635

Costreag, 50% Urea solution ($/gal)13 1.77 1.77 1.77

Volume of Reagent Tank (Volreagent (gal)) Volreagent (gal) = qsol x days of reagent supply × 24 hr/day 26,107 18,984 18,984

Urea solution volumetric flow rate (qsol, gal/hr)14 Estimated by SNCR vendor, Fuel Tech 77.7 56.5 56.5

Mass flow rate of urea solution (msol, lb/hr)15 Estimated by SNCR vendor, Fuel Tech 738.15 536.75 536.75

Mass flow rate of reagent (mreagent, lb/hr)15 Estimated by SNCR vendor, Fuel Tech 369.08 268.38 268.38

Normalized Stoichiometric Ratio (NSR) Not needed since usage estimates were provided

Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no catalyst) $0 $0 $0

Total Capital Investment (TCI) (Capital Cost) TCI = D + E + F + G + H + I #REF! #REF! #REF!

Annual Costs ($)

Annual Maintenance Cost (J) J = 0.015 × TCI #REF! #REF! #REF!

Annual Reagent Cost (K) K = qsol × Costreag × top $1,119,315 $813,917 $813,917

Annual Electricity Cost (L) Not Estimated

Power (P, kW) Not Estimated

Annual Water Cost (M) M = qwater × Costwater × top $225 $164 $164

Water flowrate for SNCR system (qwater, gal/hr)17qwater = (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 353.82 257.28 257.28

Annual ΔBark Cost (N) N = ΔBark × Costbark × top $135,268 $98,361 $98,361

Additional bark required (ΔBark, MMBtu/hr)18 ΔBark = (Hv × mreagent × [(1/Cureasolinj) - 1])/106

 Btu/MMBtu 2.99 2.17 2.17

Annual ΔAsh Cost (O) Not Estimated

Additional ash generated (ΔAsh , lb/hr) Not Estimated

Direct Annual Costs (DAC)/Variable O&M DAC = J + K + L + M + N + O #REF! #REF! #REF!

Indirect Annual Costs (IDAC)/Annualized 

Capital Cost IDAC = CFR × TCI #REF! #REF! #REF!

Total Annualized Costs (TAC) TAC = DAC + IDAC #REF! #REF! #REF!

Removal Efficiency #REF! #REF! #REF!

Based on Modeled Baseline Maximum Daily Emission Rates:

Total Uncontrolled NOx Emissions (tpy) 843 843 843

Pollutant Removed (tpy) 379 274 169

Cost Effectiveness ($/ton removed) #REF! #REF! #REF!

Based on Actual Annual Emission Rates:

Total Uncontrolled NOx Emissions (tpy) 440 440 440

Pollutant Removed (tpy) 198 143 88

Cost Effectiveness ($/ton removed) #REF! #REF! #REF!

SNCR Capital and O&M Cost Estimate for No. 1 Power Boiler
1

 All SNCR costing equations from EPA Air Pollution Control Cost Manual (APCCM), 6th Edition (January 2002)

2 Average from 2001 - 2003.

3

 tSCNR assumed to be 365 days

5 Baseline.

6

 Electricity cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1

7

 Water cost estimate from Ashdown Mill 2013 Budget.

8

 Bark cost estimate from Ashdown Mill 2013 Budget.

11 From Chemical Engineering Plant Cost Index (CEPCI) 

12 Cost for urea stored on site, i.e., the first fill of the reagent tanks. 

14

 ρreagent = 71.0 lb/ft3

15 Cureasol = urea solution concentration = 50%

18 Approximate heat of vaporization of water at 310°F, Hv = 900 Btu/lb From EPA APCCM, 2002

17 Concentration of stored urea, Cureasolstored = 50%

 Concentration of urea injected into SNCR system, Cureasolinj = 10%

 From EPA APCCM, 2002

10 Ash disposal cost estimate from contracts for ash transport, end use (as soil amendment), and ash pond management.

9

 Average from 2001 - 2003.

13 Five-yr average urea cost = $373/metric ton, from http://www.indexmundi.com/commodities/?commodity=urea&months=180. Confirmed as an accurate price with a local supplier, CDI, Inc. 

(Corporate office: Brea, CA; Local distribution point: Crossett, AR) on January 27, 2014.

Density of 50% urea solution = 9.5 lb/gal (50% urea solution) based on EPA APCCM, 2002.
Technology

SNCR Case 1 Case 2

Parameters/Costs Equation1 Unit 2 Unit 2

Boiler design capacity, mmBtu/hr (QB) QB 820 820

Total operating time (top, hrs/yr) top = CFtotal × 8760 hrs/yr 8502.47 8502.47

Total Capacity Factor (CFtotal) CFtotal = CFplant × CFSNCR 0.97 0.97

Plant Capacity Factor (CFplant)

2

0.97 0.97

SNCR Capacity Factor (CFSCNR)

3 CFSNCR = tSNCR/365 1 1

Electricity Cost (Costelect, $/kwh)6$0.05 $0.05

Water Cost (Costwater, $/gal)7$0.00008 $0.00008

Coal Cost (Costcoal, $/MMBtu)8$2.50 $2.50

Coal HHV (Btu/lb)99,643 9,643

Cost of Ash Disposal (Cash, $/ton)10 $23.06 $23.06

Capital recovery factor (CRF)

CRF = [ I x (1+i)^a]/[(1+i)^a - 1], where I = interest rate, a = equipment 

life 0.0806 0.0806

a. Equipment CRF, 30-yr life, 7% interest

Cost Index11

a. 2012 Cost Index 584.6

b. 1998 Cost Index 389.5

Capital Costs 

Direct Capital Cost (A) DC ($) = ($950/MMBtu) × QB × ((2375 MMBtu/hr/QB)^0.577) × (0.66 + 

0.85ηNOx) × (CI2011/CI1998) $2,024,314 $1,889,536

Indirect Installation Costs ($)

General Facilities 0.05 × A $101,216 $94,477

Engineering and Home Office Fees 0.10 × A $202,431 $188,954

Process Contingency 0.05 × A $101,216 $94,477

Total Indirect Installation Costs (B)

= General Facilities Cost + Engineering and Home Office Fees + Process 

Contingency $404,863 $377,907

Other Installation Costs ($)

Project Contingency (C) C = 0.15 × (A + B) $364,377 $340,116

Total Plant Cost (D) D = A + B + C $2,793,553 $2,607,560

Allowance for Funds During Construction (E) E = 0 (Assumed for SNCR) $0 $0

Royalty Allowance (F) F = 0 (Assumed for SNCR) $0 $0

Preproduction Cost (G) G = 0.02 × (D + E) $55,871 $52,151

Inventory Capital (H)12 H = Volreagent (gal) × Costreagent ($/gal) $28,099 $21,967

Costreag, 50% Urea solution ($/gal)13 1.77 1.77

Volume of Reagent Tank (Volreagent (gal)) Volreagent (gal) = qsol x days of reagent supply × 24 hr/day 15,859 12,398

Urea solution volumetric flow rate (qsol, gal/hr)14 Estimated by SNCR vendor, Fuel Tech 47.2 36.9

Mass flow rate of urea solution (msol, lb/hr)15 Estimated by SNCR vendor, Fuel Tech 448.40 350.55

Mass flow rate of reagent (mreagent, lb/hr)15 Estimated by SNCR vendor, Fuel Tech 224.20 175.28

Normalized Stoichiometric Ratio (NSR) Not needed since usage estimates were provided

Initial Catalyst and Chemicals (I) I = 0 (Assumed for SNCR due to no catalyst) $0 $0

Total Capital Investment (TCI) (Capital Cost) TCI = D + E + F + G + H + I $2,877,523 $2,681,678

Annual Costs ($)

Annual Maintenance Cost (J) J = 0.015 × TCI $43,163 $40,225

Annual Reagent Cost (K) K = qsol × Costreag × top $711,033 $555,871

Annual Electricity Cost (L) Not Estimated

Power (P, kW) Not Estimated

Annual Water Cost (M) M = qwater × Costwater × top $143 $112

Water flowrate for SNCR system (qwater, gal/hr)17qwater = (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 214.93 168.03

Annual ΔCoal Cost (N) N = ΔCoal × Costcoal × top $38,602 $30,178

Additional coal required (ΔCoal, MMBtu/hr)18 ΔCoal = (Hv × mreagent × [(1/Cureasolinj) - 1])/106

 Btu/MMBtu 1.82 1.42

Annual ΔAsh Cost (O) O = (ΔAsh × Costash × top)/2000 lb/ton $1,385 $1,083

Additional ash generated (ΔAsh , lb/hr)19 ΔAsh = (ΔCoal × ashproduct × 106 Btu/MMBtu)/HHV 14.12 11.04

Direct Annual Costs (DAC)/Variable O&M DAC = J + K + L + M + N + O $794,325 $627,469

Indirect Annual Costs (IDAC)/Annualized Capital Cost IDAC = CFR × TCI $231,889 $216,107

Total Annualized Costs (TAC) TAC = DAC + IDAC $1,026,214 $843,575

Removal Effciency 35.0% 27.5%

Based on Modeled Baseline Maximum Daily Emission Rates:

Total Uncontrolled NOx Emissions (tpy) 2,240 2,240

Pollutant Removed (tpy) 784 616

Cost Effectiveness ($/ton removed) $1,309 $1,370

Based on Actual Annual Emission Rates:

Total Uncontrolled NOx Emissions (tpy) 1,536 1,536

Pollutant Removed (tpy) 537 422

Cost Effectiveness ($/ton removed) $1,909 $1,998

SNCR Capital and O&M Cost Estimate for No. 2 Power Boiler
1

 All SNCR costing equations from EPA Air Pollution Control Cost Manual (APCCM), 6th Edition (January 2002)

2 Average from 2001 - 2003.

3

 tSCNR assumed to be 365 days

5 Baseline.

6

 Electricity cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1

7

 Water cost estimate from Ashdown Mill 2013 Budget.

8 Cost of coal from Lazard's 2009 Levelized Cost of Energy Analysis (LCOE)

11 From Chemical Engineering Plant Cost Index (CEPCI) 

12 Cost for urea stored on site, i.e., the first fill of the reagent tanks. 

14

 ρreagent = 71.0 lb/ft3

15 Cureasol = urea solution concentration = 50%

18 Approximate heat of vaporization of water at 310°F, Hv = 900 Btu/lb From EPA APCCM, 2002

19 Ashproduct is the fraction of ash produced as a byproduct of burning a given type of coal. Assumed ashproduct = 0.075 from EPA 

APCCM, 2002 for subbituminous coal.

9

 Average from 2001 - 2003.

17 Concentration of stored urea, Cureasolstored = 50%

 Concentration of urea injected into SNCR system, Cureasolinj = 10%

 From EPA APCCM, 2002

10 Ash disposal cost estimate from contracts for ash transport, end use (as soil amendment), and ash pond management.

13 Five-yr average urea cost = $373/metric ton, from http://www.indexmundi.com/commodities/?commodity=urea&months=180. Confirmed as an accurate price with a local supplier, CDI, 

Inc. (Corporate office: Brea, CA; Local distribution point: Crossett, AR) on January 27, 2014.

Density of 50% urea solution = 9.5 lb/gal (50% urea solution) based on EPA APCCM, 2002.