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 2002 2003 2001

2001 2003

2002Highest 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 83.918432011

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** NOXRevised 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 PM10Revised 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 SO 2** **Em issions** 

**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 SO 2** **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**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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 0.0REV JJ **SN-03 - LNB at 30.0% control => 0.250 lb/MMBtu ( Mar 2014 Report**  **) Source Name**  **SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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**PM C**  **PM f**  **EC SOA**  **PM total** 

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

**PM C**  **PM f**  **EC SOA**  **PM total**  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

**PM C**  **PM f**  **EC SOA**  **PM total**  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

**PM C**  **PM f**  **EC SOA**  **PM total**  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

**PM C**  **PM f**  **EC SOA**  **PM total**  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 PM**  **f EC**  **SOA PM**  **total**

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**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  REV B Unit 2 788.2 0.0 526.8 0.0 0.0

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

**Source Name**

**SO 2**  **SO 4**  **NO X**  **HNO 3**  **NO 3**  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**

**SO** 2 **SO**4 **NO**X **HNO** 3 **NO** 3 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**

**SO** 2 **SO**4 **NO**X **HNO** 3 **NO** 3 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**

**SO** 2 **SO**4 **NO**X **HNO** 3 **NO** 3 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**  **SO** 2 **SO**4 **NO**X **HNO** 3 **NO** 3 REV DD Unit 2 788.2 0.0 368.8 0.0 0.0**PM C**  **PM f**  **EC SOA**  **PM total** 

0.0 81.6 0.0 0.0 81.6

**PM C**  **PM f**  **EC SOA**  **PM total**  0.0 81.6 0.0 0.0 81.6

**PM** C **PM** f **EC SOA**  **PM** total 0.0 81.6 0.0 0.0 81.6

**PM** C **PM** f **EC SOA**  **PM** total 0.0 81.6 0.0 0.0 81.6

**PM** C **PM** f **EC SOA**  **PM** total 0.0 81.6 0.0 0.0 81.6

**PM** C **PM** f **EC SOA**  **PM** total 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 visibility. (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

Since this is refined modeling (using the refined CALMET dataset), use the 98th percentile or 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 visibility. (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

Since this is refined modeling (using the refined CALMET dataset), use the 98th percentile or 8th 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

0 0 0.015 0.037 KAG 3/5/2014

0 0 0.091 0.128 KAG 3/5/2014 0 0 0.320 0.420 KAG 3/7/2014 0 0 0.004 0.017 KAG 3/5/2014 0 0 0.010 0.024 KAG 3/5/2014

18 6 0.146 0.453 JAT 5/29/2013 0 0 0.051 0.141 JAT 5/29/2013 0 0 0.026 0.072 JAT 5/29/2013 0 0 0.053 0.150 JAT 5/29/2013

30 7 0.296 0.280 JAT 11/8/2012 0 0 0.018 0.081 JAT 11/8/2012 0 0 0.008 0.080 JAT 11/8/2012 0 0 0.029 0.064 JAT 11/8/2012

17 5 0.181 0.167 JAT 11/12/2012 0 0 0.011 0.049 JAT 11/12/2012 0 0 0.005 0.048 JAT 11/12/2012 0 0 0.014 0.038 JAT 11/12/2012

14 5 0.166 0.153 JAT 4/17/2013 0 0 0.010 0.045 JAT 4/17/2013 0 0 0.005 0.044 JAT 4/17/2013 0 0 0.012 0.035 JAT 4/17/2013

19 6 0.212 0.195 JAT 4/17/2013 0 0 0.013 0.057 JAT 4/17/2013 0 0 0.006 0.056 JAT 4/17/2013 0 0 0.017 0.045 JAT 4/17/2013

17 5 0.181 0.167 KAG 3/5/2014 0 0 0.011 0.133 KAG 3/5/2014 0 0 0.005 0.048 KAG 3/5/2014 0 0 0.014 0.038 KAG 3/5/2014**Capital Costs**

Technology Wet Scrubber

/ESPfor No. 2 Power Boiler Max Heat I

nput (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 SO2Control Efficiency 1 90% ESP Plate Area (ft2)4 NA **Purchased Equipment Cost (PEC) 1**  **$2,050,000 Total Capital Investment (TCI)**  = PEC + Costs to Retrofit 11 **$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 Costs 6**  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 Pump 9 = 0.746 × Ql× Z × S g× 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) usage 12 = $0.875/lb × Annual sorbet use (5 lb/min) $2,300,000 **Total Variable (Direct) Annual Cost $8,833,382**  Fixed (I ndirect) Costs, IC Administrative charges 2% of Total Capital I nvestment $143,500 Property tax 1% of Total Capital I nvestment $71,750 I nsurance 1% of Total Capital I nvestment $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 I nvestment **$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 Em** **ission Rates:**

Total Uncontrolled NOx Emissions (tpy) 3351 Pollutant Removed (tpy) 3016 **Cost Effectiveness ($/ton removed)** $3,261 **Based on Actual Annual**  **Em ission Rates:**  Total Uncontrolled NOx Emissions (tpy) 2078 Pollutant Removed (tpy) 1870 **Cost Effectiveness ($/ton removed)** $5,258

1: From A.H. Lundberg Associates, I nc. Budget Proposal, June 22, 2012, amended April 17, 2014. 2: Electricity cost form Arkansas I ndustrial 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, I nc. 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 S g= 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. L undberg Associates, I

nc. 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: L undberg 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 Equation 1 Unit 1 Unit 1 Unit 1 Boiler design capacity, mmBtu/hr (QB) QB 580 580 580 Total operating time (top, hrs/y r) top= CFtotal× 8760 hrs/y r 8130.72 8130.72 8130.72 Total Capacity

Factor (CFtotal) CFtotal= CFplant × CF SNCR 0.93 0.93 0.93 Plant Capacity

Factor (CFplant)2 0.93 0.93 0.93 SNCR Capacity

Factor (CF SCNR) 3 CF SNCR = tSNCR /365 1 1 1 Electricity

Cost (Costelect, $/kwh) 6 $0.05 $0.05 $0.05 Water Cost (Cost water, $/gal) 7 $0.00008 $0.00008 $0.00008 Bark Cost (Cost

bark, $/MMBtu) 8 $5.57 $5.57 $5.57 Bark HHV (Btu/lb) 9 2,657 2,657 2,657 Cost of Ash Disposal (C ash, $/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-y

r life, 7% interest Cost Index 11

a. 2012Cost Index 584.6 b. 1998 Cost Index 389.5 **Capital Costs**Direct Capital Cost (A) DC ($) = ($950/MMBtu) × QB× ((2375 MMBtu/hr/QB)^0.577) × (0.66 + 0.85ηNOx) × (CI2011 /CI 1998) #REF! #REF! #REF! Indirect Installation Costs ($) 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 Roy alty Allowance (F) F = 0 (Assumed for SNCR) $0 $0 $0 Preproduction Cost (G) G = 0.02 × (D + E) #REF! #REF! #REF! Inventory Capital (H) 12 H = Volreagent(gal) × Cost reagent($/gal) $46,255 $33,635 $33,635 Cost reag, 50% Urea solution ($/gal) 13 1.77 1.77 1.77 Volume of Reagent Tank (Volreagent(gal)) Volreagent(gal) = qsolx day s 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 (m reagent, 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 Cataly

st and Chemicals (I) I = 0 (Assumed for SNCR due to no cataly st) $0 $0 $0 **Total Capital Investm ent (TCI) (Capital Cost)**  **TCI = D + E + F + G + H + I #REF!**  **#REF! #REF!** 
**Annual Costs ($)** Annual Maintenance Cost (J) J = 0.015 × TCI #REF! #REF! #REF! Annual Reagent Cost (K) K = qsol× Cost reag× 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× Cost water× top $225 $164 $164 Water flowrate for SNCR sy stem (qwater, gal/hr) 17 qwater= (msol/ρwater) × [(Cureasolstored/Cureasolinj) - 1] 353.82 257.28 257.28 Annual ΔBark Cost (N) N = ΔBark × Cost bark× top $135,268 $98,361 $98,361 Additional bark required (ΔBark, MMBtu/hr) 18 ΔBark = (Hv × mreagent× [(1/Cureasolinj) - 1])/10 6Btu/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**  **Em ission Rates:**  Total Uncontrolled NOx Emissions (tpy ) 843 843 843 Pollutant Removed (tpy

) 379 274 169 **Cost Effectiveness ($/ton rem oved)**  **#REF! #REF!**  **#REF! Based on**  **Actual Annual Em** **ission Rates:** Total Uncontrolled NOx Emissions (tpy ) 440 440 440 Pollutant Removed (tpy

) 198 143 88 **Cost Effectiveness ($/ton rem oved)**  **#REF! #REF!**  **#REF! SNCR** **Capital and O&M Cost Estim ate 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.
3tSCNR assumed to be 365 day

s

5 Baseline.
6Electricity

cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1
7Water cost estimate from Ashdown Mill 2013 Budget.
8Bark cost estimate from Ashdown Mill 2013 Budget.

11 From Chemical Engineering Plant Cost Index (CEPCI)
12Cost for urea stored on site, i.e., the first fill of the reagent tanks.

14ρreagent= 71.0 lb/ft3

15Cureasol= urea solution concentration = 50%

18A pproximate heat of vaporization of water at 310°F, Hv = 900 Btu/lbFrom EP A APCCM, 2002 17Concentration of stored urea, Cureasolstored= 50% Concentration of urea injected into SNCR sy stem, Cureasolinj= 10% From EPA APCCM, 2002 10Ash disposal cost estimate from contracts for ash transport, end use (as soil amendment), and ash pond management. 9Average from 2001 - 2003.

13 Five-y r 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 Equation 1 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 × CF SNCR 0.97 0.97 Plant Capacity Factor (CFplant) 2 0.97 0.97 SNCR Capacity Factor (CF SCNR) 3 CF SNCR = 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) 9 9,643 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 Index 11

a. 2012Cost 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 /CI 1998) $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) = qsolx 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 (m reagent, 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 Investm ent (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) 17 qwater= (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 × m reagent× [(1/Cureasolinj) - 1])/10 6Btu/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 × 10 6Btu/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 $843,575**  Removal Effciency 35.0% 27.5% **Based on Modeled Baseline Maximum Daily**  **Em ission Rates:**  Total Uncontrolled NOx Emissions (tpy) 2,240 2,240 Pollutant Removed (tpy) 784 616 **Cost Effectiveness ($/ton rem oved)**  **$1,309 $1,370**  **Based on Actual Annual**  **Em ission Rates:**  Total Uncontrolled NOx Emissions (tpy) 1,536 1,536 Pollutant Removed (tpy) 537 422 **Cost Effectiveness ($/ton rem oved)**  **$1,909 $1,998**  **SNCR Capital and O&M Cost Estim** **ate 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.
3tSCNR assumed to be 365 days

5 Baseline.
6Electricity cost form Arkansas Industrial Energy Clearinghouse, http://www.arkansasiec.org/newsmanager/templates/?a=71&z=1
7Water 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)
12Cost for urea stored on site, i.e., the first fill of the reagent tanks.

14ρreagent= 71.0 lb/ft3

15Cureasol= urea solution concentration = 50%

18Approximate heat of vaporization of water at 310°F, Hv = 900 Btu/lbFrom EP A 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. 9Average from 2001 - 2003.

17Concentration of stored urea, Cureasolstored= 50% Concentration of urea injected into SNCR system, Cureasolinj= 10% From EPA APCCM, 2002 10Ash 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.