SUPPLEMENTAL BART DETERMINATION INFORMATION

DOMTAR A.W. LLC  ASHDOWN MILL (AFIN 41-00002) 

Prepared By: 

TRINITY CONSULTANTS, INC. 

201 N.W. 63rd St., Suite 220 

Oklahoma City, OK 73104 

(405) 848-3724 

1831 E. 71st St. 

Tulsa, OK 74136 

(918) 877-2742 

and 

DOMTAR A.W. LLC 

285 Highway 71 South 

Ashdown, AR 71822 

(870) 898-2711 

June 28, 2013 

Relevant Previous Submittals: 

October 31, 2006 

March 26, 2007 

June 25, 2007 

December 21, 2011 
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TABLE OF CONTENTS

1. INTRODUCTION ................................................................................................................ 1-1

2. BASELINE FOR NO. 1 POWER BOILER ............................................................................. 2-1

3. MODELING METHODOLOGY ........................................................................................... 3-1

4. SUPPLEMENTAL INFORMATION FOR THE PM BART DETERMINATIONS ..................... 4-1

5. SUPPLEMENTAL INFORMATION FOR THE SO2 BART DETERMINATIONS ..................... 5-1

5.1 NO. 1 POWER BOILER: FUEL OIL COMBUSTION AND SO2 BART .......................... 5-1

5.2 NO. 2 POWER BOILER: POTENTIAL SCRUBBER UPGRADES AND SO2 BART ......... 5-1

6. SUPPLEMENTAL INFORMATION FOR THE NOX BART DETERMINATIONS .................... 6-1

6.1 FEASIBILITY OF SELECTIVE NON-CATALYTIC REDUCTION ................................... 6-1

6.2 EVALUATION OF VISIBILITY IMPACTS FROM NOX CONTROLS ............................... 6-2

6.3 PROPOSED BART FOR NOX .................................................................................. 6-4

APPENDIX A – MODELING PROTOCOL ................................................................................ A-1

APPENDIX B – DETAILED CONTROL COST CALCULATIONS ................................................B-1

APPENDIX C – DETAILED MODELING RESULTS .................................................................. C-1

APPENDIX D – REFERENCE DOCUMENTS ............................................................................ D-1
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LIST OF TABLES AND FIGURES

TABLE 1-1. SUMMARY OF PROPOSED BART DETERMINATIONS........................................................ 1-2

TABLE 2-1. PROPOSED CHANGES IN BASELINE PARAMETERS FOR NO. 1 POWER BOILER ................. 2-1

TABLE 2-2. SUMMARY OF BASELINE 24-HOUR MAXIMUM ACTUAL EMISSION RATES ..................... 2-2

TABLE 2-3. SUMMARY OF BASELINE STACK PARAMETERS ............................................................... 2-2

TABLE 2-4. BASELINE VISIBILITY IMPAIRMENT ................................................................................. 2-2

TABLE 3-1. ANNUAL AVERAGE BACKGROUND CONCENTRATION ..................................................... 3-3

TABLE 3-2. FL(RH) LARGE RH ADJUSTMENT FACTORS ..................................................................... 3-3

TABLE 3-3. FS(RH) SMALL RH ADJUSTMENT FACTORS ..................................................................... 3-3

TABLE 3-4. FSS(RH) SEA SALT RH ADJUSTMENT FACTORS ............................................................... 3-3

TABLE 5-2. SO2 CONTROL SCENARIOS MODELED EMISSION RATES FOR NO. 2 POWER BOILER ....... 5-2

TABLE 5-3. VISIBILITY IMPAIRMENT IMPROVEMENT ATTRIBUTABLE TO SO2 CONTROL FOR NO. 2

POWER BOILER ....................................................................................................................... 5-2

FIGURE 6-1. SNCR OPERATING ESTIMATES PROVIDED BY FUELTECH, INC. ..................................... 6-2

TABLE 6-1. NOX CONTROLS COSTS SUMMARY .................................................................................. 6-2

TABLE 6-2. NOX ANALYSES MODELED EMISSION RATES .................................................................. 6-3

TABLE 6-3. VISIBILITY IMPAIRMENT IMPROVEMENT ATTRIBUTED TO NOX CONTROLS.................... 6-3

TABLE C-1. BASELINE VISIBILITY IMPAIRMENT ............................................................................... C-1
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1. INTRODUCTION

Domtar A.W. LLC (Domtar) is submitting supplemental information for consideration by the 

Arkansas Department of Environmental Quality (ADEQ) and the U.S. Environmental Protection 

Agency (EPA) in the determination of Best Available Retrofit Technology (BART) for Domtar’s two 

BART-affected sources – No. 1 and No. 2 Power Boilers – at its Ashdown, Arkansas kraft paper mill. 

Previous related analyses and other pertinent information were submitted on October 31, 2006, March 

26, 2007, June 25, 2007, and December 21, 2011. 

The supplemental information provided in this report is submitted in response to EPA’s final decision 

to partially disapprove the Arkansas Regional Haze (RH) State Implementation Plan (SIP).1

 

Specifically, Domtar is addressing the following five EPA concerns (two regarding NOX, two 

regarding SO2, and one regarding PM): 

 Feasibility of Selective Non-Catalytic Reduction (SNCR) technology for NOX control 

for No. 1 and No. 2 Power Boilers;2

 Consideration of visibility impacts for the theoretically feasible Methane De-NOX

(MdN) control option for No. 1 and No. 2 Power Boilers;3

 Evaluation of the type, frequency, and duration of fuel oil combustion in the No. 1 

Power Boiler and the SO2 BART determination of 1.12 lb/MMBtu;4

 Assessment of potential upgrades to the existing wet scrubber on No. 2 Power Boiler 

and the SO2 BART determination of 1.2 lb/MMBtu;5

 and 

 Consideration of the same 0.07-lb/MMBtu PM BART limit for No. 2 Power Boiler as 

approved for the No. 1 Power Boiler.6

These five issues are addressed in sections 4 – 6 of this report. The only other changes to the 

previously submitted information involve (1) updates to the baseline emissions and modeling 

parameters for No. 1 Power Boiler and (2) updates to the modeling methodology (as requested by 

EPA and ADEQ). Details of these updates are provided in Section 2 and Section 3, respectively. 

A summary of the proposed BART determinations presented in Section 4 – 6 is provided in Table 1-1 

below. 

 1 77 FR 14604 – 14677 

2 77 FR 14634 and 14677 

3 77 FR 14634 and 14677 

4 77 FR 14648 and 14677; see also the proposed rule at 76 FR 64208 

5 77 FR 14649 and 14677 

6 77 FR 14677; see also the proposed rule at 76 FR 64208 
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TABLE 1-1. SUMMARY OF PROPOSED BART DETERMINATIONS

Emission Unit Pollutant Proposed BART Limit 

No. 1 Power Boiler PM 0.07 lb/MMBtu 

 SO2 21 lb/hr 

 NOX 145 lb/hr 

No. 2 Power Boiler PM 0.07 lb/MMBtu 

 SO2 788.2 lb/hr 

 NOX 345 lb/hr 
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2. BASELINE FOR NO. 1 POWER BOILER

Domtar installed a wet electrostatic precipitator (WESP) on the No. 1 Power Boiler in 2007 to meet 

the then-applicable Boiler MACT emission standard of 0.07 lb/MMBtu. The WESP fundamentally 

changed the emissions and stack parameters for the No. 1 Power Boiler (e.g., there are now two 

stacks rather than one), and Domtar proposes to update the BART baseline modeling to reflect these 

changes (i.e., to reflect current operations). A comparison of the previous baseline modeling 

parameters and the proposed baseline modeling parameters is provided in Table 2-1. 

TABLE 2-1. PROPOSED CHANGES IN BASELINE PARAMETERS FOR NO. 1 POWER BOILER

No. 1 Power Boiler Parameter 

Original Baseline 

(2001 – 2003) 

Proposed Baseline 

(2009 – 2011) 

Number of Stacks 1 2 

Max. 24-hour PM10/PMF Emissions (lb/hr) 169.5 6.4 

Max. 24-hour SO2 Emissions (lb/hr) 442.5 17.5 

Max. 24-hour NOX Emissions (lb/hr) 179.6 121.2 

Lambert Conformal Conic (LCC) Projection 

Coordinates (km) 

267.47491, -698.66686 267.49713, -698.63952 

& 

267.49891, -698.63445 

Base Elevation (m) 97.5 99.58 & 99.51 

Stack Height (m) 66.1 66.14 ea. 

Stack Diameter (m) 1.89 2.1 ea. 

Exhaust Velocity (m/s) 26.76 11.06 ea. 

Exhaust Temperature (K) 522 342.04 ea. 

A Note about Baseline Emissions for No. 2 Power Boiler 

While comparing No. 1 Power Boiler emission rates from the two baseline periods, 

Domtar also compared emission rates for the No. 2 Power Boiler. While no definitive 

changes took place and no enforceable limitations were taken to ensure any decreases, the 

No. 2 Power Boiler has emitted at lower levels. Most notably the maximum daily SO2

and NOX emission rates dropped by 16 and 20 percent, respectively. These decreases can 

be attributed to the mill’s ongoing efforts to reduce energy and water consumption. 

Efficiency increases of 16 to 20 percent are not surprising considering the 2001-2003 

baseline period is ten years ago and not truly representative of current operations. 

However, these decreases are not considered in this report. 
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For ease of review, the following tables summarize the baseline emission rates and modeling 

parameters, respectively, for both boilers. 

TABLE 2-2. SUMMARY OF BASELINE 24-HOUR MAXIMUM ACTUAL EMISSION RATES

Emission Unit 

Baseline 

Period 

NOX

Emissions

(lb/hr) 

SO2

Emissions

(lb/hr) 

PM10/PMF 

Emissions 

(lb/hr) 

No. 1 Power Boiler 2009-2011 121.2 17.5 6.4 

No. 2 Power Boiler 2001-2003 526.8 788.2 81.6 

TABLE 2-3. SUMMARY OF BASELINE STACK PARAMETERS

Emission Unit, Stack 

LCC East 

(km) 

LCC North

(km) 

Base 

Elevation

(m) 

Stack 

Height

(m) 

Stack 

Diameter 

(m) 

Exhaust 

Temperature

(K) 

Exhaust 

Velocity

(m/s) 

No. 1 Power Boiler,A 267.49713 -698.63952 99.58 66.14 2.1 342.04 11.06 

No. 1 Power Boiler,B 267.49891 -698.63445 99.51 66.14 2.1 342.04 11.06 

No. 2 Power Boiler * 267.45242 -698.64643 99.95 71.63 3.66 324.82 11.92 

* All slight (less than a tenth in most cases) changes in modeling parameters for the No. 2 Power Boiler, compared to the 

original analysis, are from minor adjustments based on the most up-to-date information and/or rounding conventions. 

As a result of the 2007 WESP changes, revised modeling was conducted using the CALPUFF 

dispersion model to determine the baseline visibility impairment attributable to the No. 1 Power 

Boiler and No. 2 Power Boiler in four Class I Areas: Caney Creek Wilderness (CACR), Upper 

Buffalo Wilderness (UPBU), Hercules Glades Wilderness (HERC), and Mingo Wilderness (MING). 

Table 2-4 and Table 2-5 provide a summary of the modeled visibility impairment attributable to No. 1 

Power Boiler and No. 2 Power Boiler, respectively, based on the inputs shown in Table 2-2 and Table 

2-3. Note that detailed modeling results are provided in Appendix C and all of the CALMET, 

CALPUFF, and CALPOST modeling files are included as part of the electronic files submitted with 

this document. 

TABLE 2-4. BASELINE VISIBILITY IMPAIRMENT

Emission Unit 

Class I 

Area 

Number of Days 

≥ 0.5 Δdv a

Maximum 

(Δdv) b

98th %tile 

(Δdv) b

No. 1 Power Boiler CACR 0 0.266 0.190 

UPBU 0 0.052 0.022 

HERC 0 0.045 0.012 

MING 0 0.035 0.008 

No. 2 Power Boiler CACR 49 1.603 0.844 

UPBU 0 0.381 0.146 

HERC 0 0.329 0.105 

MING 0 0.246 0.065 

a

 Sum for all three modeled years. 

b Maximum value among the three modeled years.
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3. MODELING METHODOLOGY

The principle changes for the updated modeling compared to the originally submitted modeling are 

listed below with additional details following: 

 Use of refined meteorological data consistent with the met data used for other BART sources 

in Arkansas. 

 Use of 98th percentile (or 8th high) results rather than daily maximum results for 

demonstration of baseline and post-control visibility impairment. 

 Use of CALPOST version 6.221, Level 080724 based on the October 2010 guidance from the 

Federal Land Managers Air Quality Related Values Workgroup (FLAG). 

 Use of Method 8, Mode 5 as a visibility impairment prediction equation (i.e. the new 

IMPROVE equation). 

The CALPUFF data and parameters are based on the 2005 BART modeling guidelines prepared for 

the Central States Regional Air Planning Association (CENRAP). The CALMET data and 

parameters are based on the modeling protocol included in Appendix A. Note that the protocol 

included in Appendix A summarizes modeling methods and procedures that were followed to predict 

visibility impairment for several BART-eligible sources located in Oklahoma as part of the BART 

analyses for these sources. Several sources in Texas and Arkansas have also used the CALMET data 

that was generated in accordance with the protocol. 

ADEQ submitted a draft BART Modeling Protocol on June 7, 2006 to EPA. On July 26, 2012 

ADEQ updated the protocol including CALPUFF modeling components and the background 

concentrations in CALPOST. In addition, CALMET is being changed from not having observations 

(NO OBS = 1) to the hybrid which incorporates observations (NO OBS = 0). This change from NO 

OBS = 1 to NO OBS = 0 allows for the use of the 8th highest – rather than the 1st highest – model 

output. Also, the new IMPROVE Equations is used. 

The CALPOST visibility processing completed for this BART analysis is based on the October 2010 

guidance from the Federal Land Managers Air Quality Related Values Workgroup (FLAG). The 

2010 FLAG guidance, which was issued in draft form on July 8, 2008 and published as final guidance 

in December 2010, makes technical revisions to the previous guidance issued in December 2000. 

Visibility impairment is quantified using the light extinction coefficient (bext), which is expressed in 

terms of the haze index expressed in deciviews (dv). The haze index (HI) is calculated as follows: 





 



  10 (dv) 10 ln ext b HI

The impact of a source is determined by comparing the HI attributable to a source relative to 

estimated natural background conditions. The change in the haze index, also referred to as “delta dv,” 

or ∆dv, based on the source and background light extinction is based on the following equation: 
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 dv = 10*ln

b b

b

ext, background ext, source

ext, background

 















The Interagency Monitoring of Protected Visual Environments (IMPROVE) workgroup adopted an 

equation for predicting light extinction as part of the 2010 FLAG guidance (often referred to as the 

new IMPROVE equation). The new IMPROVE equation is as follows: 

bext 

         

     

        

    Site specificRayleigh Scattering 2

Small Large

4 3 Small 4 3 Large

4 4 2 Small 4 4 2 Large

1.4 Sea Salt 0.33 NO

2.8 OC 6.1 OC 10 EC 1 PMF 0.6 PMC

2.4 NH NO 5.1 NH NO

2.2 NH SO 4.8 NH SO

 

    

 

 

 f RH b

f RH f RH

f RH f RH

SS

S L

S L

Visibility impairment predictions relied upon in this BART analysis used the equation shown above. 

The use of this equation is referred to as “Method 8” in the CALPOST control file. The use of 

Method 8 requires that one of five different “modes” be selected. The modes specify the approach for 

addressing the growth of hygroscopic particles due to moisture in the atmosphere. “Mode 5” has 

been used in this BART analysis. Mode 5 addresses moisture in the atmosphere in a similar way as to 

“Method 6”, where “Method 6” is specified as the preferred approach for use with the old IMPROVE 

equation in the CENRAP BART modeling protocol. 

CALPOST Method 8, Mode 5 requires the following: 

 Annual average concentrations reflecting natural background for various particles and for sea 

salt 

 Monthly RH factors for large and small ammonium sulfates and nitrates and for sea salts 

 Rayleigh scattering parameter corrected for site-specific elevation 

Tables 3-1 to Table 3-4 below show the values for the data described above that were input to 

CALPOST for use with Method 8, Mode 5. The values were obtained from the 2010 FLAG 

guidance. 
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TABLE 3-1. ANNUAL AVERAGE BACKGROUND CONCENTRATION 

Class I Area 

(NH4)2SO4

(μg/m3

) 

NH4NO3

(μg/m3) 

OM 

(μg/m3) 

EC 

(μg/m3) 

Soil 

(μg/m3) 

CM 

(μg/m3) 

Sea Salt 

(μg/m3) 

Rayleigh 

(Mm-1) 

CACR 0.23 0.1 1.8 0.02 0.5 3 0.03 11 

UPBU 0.23 0.1 1.8 0.02 0.5 3 0.03 11 

HERC 0.23 0.1 1.8 0.02 0.5 3 0.02 11 

MING 0.23 0.1 1.83 0.02 0.51 3.05 0.04 12 

TABLE 3-2. FL(RH) LARGE RH ADJUSTMENT FACTORS

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

CACR 2.77 2.53 2.37 2.43 2.68 2.71 2.59 2.6 2.71 2.69 2.67 2.79 

UPBU 2.71 2.48 2.31 2.33 2.61 2.64 2.57 2.59 2.71 2.58 2.59 2.72 

HERC 2.7 2.48 2.3 2.3 2.57 2.59 2.56 2.6 2.69 2.54 2.57 2.72 

MING 2.73 2.52 2.34 2.28 2.53 2.6 2.64 2.67 2.71 2.56 2.56 2.73 

TABLE 3-3. FS(RH) SMALL RH ADJUSTMENT FACTORS 

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

CACR 3.85 3.44 3.14 3.24 3.66 3.71 3.49 3.51 3.73 3.72 3.68 3.88 

UPBU 3.73 3.33 3.03 3.07 3.54 3.57 3.43 3.5 3.71 3.51 3.52 3.74 

HERC 3.7 3.33 3.01 3.01 3.47 3.48 3.41 3.51 3.67 3.43 3.46 3.73 

MING 3.74 3.38 3.07 2.97 3.39 3.52 3.57 3.64 3.72 3.47 3.43 3.74 

TABLE 3-4. FSS(RH) SEA SALT RH ADJUSTMENT FACTORS 

Class I Area Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 

CACR 3.9 3.52 3.31 3.41 3.83 3.88 3.69 3.68 3.82 3.76 3.77 3.93 

UPBU 3.85 3.47 3.23 3.27 3.72 3.78 3.69 3.7 3.84 3.64 3.67 3.86 

HERC 3.86 3.51 3.23 3.22 3.66 3.72 3.69 3.73 3.81 3.57 3.65 3.88 

MING 3.92 3.58 3.3 3.19 3.58 3.72 3.8 3.82 3.85 3.61 3.66 3.9 
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4. SUPPLEMENTAL INFORMATION FOR THE PM BART DETERMINATIONS

For the No. 1 Power Boiler, Domtar originally proposed, ADEQ adopted, and EPA approved a PM 

BART determination of 0.07 lb/MMBtu. This value was based on the then-final Boiler MACT. The 

same approach was applied for the No. 2 Power Boiler, but ultimately a limitation of 0.1 lb/MMBtu 

was adopted. This value was disapproved by EPA. EPA’s disapproval is summarized in its proposed 

rule as follows: 

Concerning Power Boiler No. 2, Domtar stated that the unit was subject to the Boiler 

MACT PM emission standard in existence at the time (0.07 lb/MMBtu), and indicated 

its intent to presumptively rely on such standard to meet BART PM requirements for 

Power Boiler No. 2. However, instead of adopting 0.07 lb/MMBtu as the BART PM 

emission limit for Power Boiler No. 2, ADEQ adopted 0.10 lb/MMBtu as the BART 

PM emission limit. Since ADEQ did not select the Boiler MACT PM emission 

standard current at the time the BART determination was made as the BART PM 

emission limit for Power Boiler No. 2, ADEQ cannot elect to take the streamlined 

approach provided in the BART Guidelines. If ADEQ chooses to take the streamlined 

approach provided in the BART Guidelines, ADEQ must select the Boiler MACT PM 

standard if it determines there are no new and cost-effective technologies or 

available upgrades developed subsequent to the MACT standard.7

To remedy this issue, Domtar accepts the 0.07-lb/MMBtu BART limit for the No. 2 Power Boiler. 

 

 

 7 76 FR 64208 
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5. SUPPLEMENTAL INFORMATION FOR THE SO2 BART DETERMINATIONS

This section provides the following supplemental information: 

 Evaluation of the type, frequency, and duration of fuel oil combustion in the No. 1 

Power Boiler and the SO2 BART determination of 1.12 lb/MMBtu.8

 Assessment of potential upgrades to the existing wet scrubber on No. 2 Power Boiler 

and the SO2 BART determination of 1.2 lb/MMBtu.9

5.1 NO. 1 POWER BOILER: FUEL OIL COMBUSTION AND SO2 BART 

In re-evaluating baseline rates (see Section 2), Domtar revised the baseline rates to be reflective of the 

current WESP technology employed at the No. 1 Power Boiler. As a result, the original baseline rate 

of 1.12 lb/MMBtu is moot. The new baseline SO2 emission rate is 17.5 lb/hr. Modeling this revised 

emission rate shows zero days with maximum impacts greater than 0.5 ∆dv, and all 98th percentile 

impacts at all Class I areas are less than 0.5 ∆dv. The results are shown in Table 2-4. 

Because No. 1 Power Boiler does not contribute to visibility impairment greater than 0.5 ∆dv at any 

of the Class I areas, and moreover does not contribute to visibility impairment on even a single day, 

Domtar proposes no additional add-on controls and an emission limit of 21 lb/hr (representing a 20 

percent compliance margin above the baseline rate of 17.5 lb/hr). Domtar proposes to demonstrate 

compliance with this limit by calculating emissions on a monthly and rolling 12-month basis, updated 

within 15 days of the end of each month and submitted in semi-annual reports. 

5.2 NO. 2 POWER BOILER: POTENTIAL SCRUBBER UPGRADES AND SO2 BART 

The existing wet scrubber achieves an SO2 control efficiency of approximately 90 percent, which is 

within the normal range for the highest efficiency SO2 control strategies and is the BART-based 

control efficiency presumed by the Central Regional Air Planning Association (CENRAP) and the 

Midwest Regional Planning Organization (MRPO) for pulp and paper industry power boilers.10,11 

However, as requested, Domtar has considered potential upgrades that could potentially achieve even 

greater control efficiencies. 

Domtar contracted with A.H. Lundberg Associates, Inc. (Lundberg) to evaluate scrubber upgrades 

and also to provide a quote for a new, add-on scrubber system. The upgrades considered included, 

but were not limited to, those specifically mentioned by EPA, i.e., (1) the elimination of bypass 

reheat, (2) the installation of liquid distribution rings, (3) the installation of perforated trays, (4) 

improvements to the auxiliary system requirement, and (5) a redesign of spray header and nozzle 

configuration. Lundberg determined that any “upgrade” – for the purposes of achieving extra SO2

control – of the existing scrubber would essentially just involve efforts to increase pressure drop. 

 8 77 FR 14648 and 14677; see also the proposed rule at 76 FR 64208 

9 77 FR 14649 and 14677 

10 CENRAP’s Control Estimates Spreadsheet dated January 10, 2006. 11 MRPO, Interim White Paper – Midwest RPO Candidate Control Measures, March 29, 2005. 
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Domtar has been unable to quantify the marginal additional control that could possibly be achieved 

upon implementation of such upgrades. When comparing existing scrubber upgrades with the 

installation of a new, add-on system, a wet scrubber/wet electrostatic precipitator (WESP), to operate 

downstream of the existing scrubbers, it was decided that the add-on option was more feasible than 

any upgrade option, and furthermore only with the add-on option is additional control quantifiable. 

Therefore, the add-on option is considered further in this analysis. 

According to the vendor information, which is included in Appendix D, an add-on wet 

scrubber/WESP would utilize sodium hydroxide (NaOH) to absorb SO2 with a control efficiency of 

approximately 90 percent resulting in a post-control emission rate of 78.8 lb/hr (approximately 0.1 

lb/MMBtu at the maximum heat input rate). Note that this represents 99 percent control compared to 

uncontrolled emissions. Consideration of any further control – beyond 99 percent – is unreasonable. 

The total capital cost of the add-on scrubber/WESP, including purchased equipment cost (according 

to Lundberg) and the cost to retrofit the system at the Ashdown Mill where there is no existing clear 

property or adequate structure to support the equipment, is nearly $18.5MM. The total annual cost, 

including the annualized capital cost plus annual operating costs, is approximately $11.7 million 

resulting in a cost effectiveness of about $3,900/ton based on the removal of 3,016 tpy of SO2. The 

details of the capital and operating cost estimates for the add-on wet scrubber/WESP are provided in 

Appendix B of this report. 

A final impact analysis was conducted to assess the visibility improvement for the control option. 

The emission rates used in the modeling scenarios are presented in Table 5-2, and the results are 

summarized in Table 5-3. 

TABLE 5-2. SO2 CONTROL SCENARIOS MODELED EMISSION RATES FOR NO. 2 POWER BOILER

Emission Unit Scenario 

NOX

Emissions

(lb/hr)

SO2

Emissions 

(lb/hr)

PM10/PMF 

Emissions

(lb/hr)

No. 2 Power Boiler Baseline 526.8 788.2 81.6 

Add-on Scrubber/WESP 526.8 78.8 81.6 

TABLE 5-3. VISIBILITY IMPAIRMENT IMPROVEMENT ATTRIBUTABLE TO SO2 CONTROL FOR NO.

2 POWER BOILER

 CACR UPBU HERC MING 

Scenario 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

Baseline 0.844 49 0.146 0 0.105 0 0.065 0 

Add-on Scrubber/WESP 0.698 31 0.093 0 0.054 0 0.039 0 

 Improvement Over Baseline 0.146 18 0.053 0 0.051 0 0.026 0 

For CACR, the only Class I area with any impacts greater than 0.5 ∆dv, the addition of a 

scrubber/WESP reduces the maximum 98th percentile impact by 17 percent and the number of days 
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with visibility impairment greater than 0.5 ∆dv by 37 percent. Note that these modest improvement 

values would be even less if the baseline emission rates were adjusted from a 2001-2003 basis to be 

more representative of current operations. 

Nevertheless, the visibility improvement provided by the add-on scrubber/WESP is not justified by 

the cost and the additional energy and water use that it would require (at a time when industries are 

being pressured to reduce energy and water use). The capital cost of $18.5MM represents a 

significant burden to the Ashdown Mill. Moreover, from a cost-benefit perspective, where the benefit 

is measured in terms of visibility improvement – the goal of the regional haze program – the 

scrubber/WESP is approximately $80MM/dv. A precedent of not requiring controls at this costbenefit level is found in the June 30, 2011 Nebraska Regional Haze/BART SIP. For the Omaha 

Public Power District’s Nebraska City Station, the “determination was not to install control 

equipment for SO2 due to the high cost for the little benefit” referencing a value of $79,450,801/dv.12

Domtar proposes no additional add-on controls and the baseline emission limit of 788.2 lb/hr as 

BART for the No. 2 Power Boiler. Domtar proposes to demonstrate compliance with this limit on a 

30-day rolling average as measured by the existing continuous emissions monitoring system (CEMS). 

 12 Nebraska Department of Environmental Quality State Implementation Plan for Regional Haze and Best 

Available Retrofit Technology (BART), June 30, 2011, p. 69, Table 10.19, footnote 14. 
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6. SUPPLEMENTAL INFORMATION FOR THE NOX BART DETERMINATIONS

This section provides supplemental information regarding the feasibility of Selective NonCatalytic Reduction (SNCR). An updated evaluation of visibility impacts, including analyses 

for the theoretically feasible Methane De-NOX (MdN) technology, is also included. 

6.1 FEASIBILITY OF SELECTIVE NON-CATALYTIC REDUCTION

From NCASI’s 2008 Handbook for Pulp and Paper: 

"SNCR has been applied to several baseloaded wood-fired boilers. However, its efficacy 

(besides when used as a polishing step) on wood-fired boilers with changing loads has not 

been demonstrated. The use of ammonia injection (SNCR) on at least one pulp mill woodfired boiler met with significant problems and had to be abandoned." 

"The use of SNCR systems on coal-fired boilers is still in the development stage." 

The relevance and timeliness of these statements were confirmed with NCASI on January 17, 2013: 

“Our understanding about the applicability of SNCR systems to control NOX in industrial 

boilers has not changed. We agree that for a base loaded pulp mill bark or coal boiler or 

boiler with steady flue gas flow patterns and temperature distribution across the flue gas 

pathway, SNCR can be quite effective, resulting typically in about a 50% NOX reduction. 

We are not aware of a pulp mill bark boiler with fluctuating loads that has successfully 

operated an SNCR system and obtained >50% NOX control consistently. Either the boiler 

operates at more or less a steady load or the SNCR system is used for polishing (<20 to 30% 

NOX reduction) purposes.” 

Furthermore, Domtar has worked with NCASI to research the operation and effectiveness of the 

EPA-referenced SNCR in operation at the Temple-Inland paper mill in Orange, TX. NCASI has 

confirmed that the SNCR, which was installed per a Lowest Achievable Emission Rate (LAER) 

determination, is in operation and is achieving an overall control efficiency of approximately 20 

percent. 

Despite the fact that the technical feasibility of SNCR remains highly questionable, Domtar has 

prepared emission/control and cost estimates for SNCR for both No. 1 and No. 2 Power Boilers. The 

cost estimates are based on methods/assumptions found in EPA’s Control Cost Manual (CCM) 

supplemented with mill-specific cost information for water, fuels, and ash disposal and urea solution 

usage estimates from FuelTech Inc. (FTI), the vendor that supplied the SNCR in use at the abovereferenced Temple-Inland mill. The information supplied by FTI is shown in Figure 6-1. 
Domtar A.W. LLC 6-2 Trinity Consultants 

Ashdown Mill 

FIGURE 6-1. SNCR OPERATING ESTIMATES PROVIDED BY FUELTECH, INC. 

As shown in Figure 6-1, two cases, differentiated by NOX reduction rates and urea consumption rates, 

are considered for each boiler. A third scenario based on 20 percent reduction, consistent with the 

actual operation of the SNCR at Temple Inland, is considered for No. 1 Power Boiler. Cost estimates 

for each case are provided in Appendix B, and summary is shown in Table 6-1. 

TABLE 6-1. NOX CONTROLS COSTS SUMMARY

 

Total NOX

Cost 

Effectiveness 

Emission Unit Scenario 

Annualized 

Cost (MM$) 

Removed 

(tpy) 

Average 

($/ton)

No. 1 Power Boiler SNCR 20.0% 1.15 99 11,649 

 SNCR 32.5% 1.18 160 7,354 

 SNCR 45.0% 1.55 222 6,995 

No. 2 Power Boiler SNCR 27.5% 0.88 616 1,430 

 SNCR 35.0% 1.07 784 1,360 

6.2 EVALUATION OF VISIBILITY IMPACTS FROM NOX CONTROLS

A final impact analysis was conducted to assess the visibility improvement for the various SNCR 

scenarios and, as requested, MdN at each of the boilers. The emission rates used in the modeling 

scenarios are presented in Table 6-2 and the results are presented in Table 6-3. 
Domtar A.W. LLC 6-3 Trinity Consultants 

Ashdown Mill 

TABLE 6-2. NOX ANALYSES MODELED EMISSION RATES

Emission Unit Scenario 

NOX

Emissions

(lb/hr)

SO2

Emissions

(lb/hr)

PM10/PMF 

Emissions 

(lb/hr)

No. 1 Power Boiler Baseline 121.2 17.5 6.4 

SNCR 20.0% 97.0 17.5 6.4 

SNCR 32.5% 81.8 17.5 6.4 

SNCR 45.0% 66.7 17.5 6.4 

MdN 60.6 17.5 6.4 

No. 2 Power Boiler Baseline 526.8 788.2 81.6 

SNCR 27.5% 381.9 788.2 81.6 

SNCR 35.0% 342.4 788.2 81.6 

MdN 263.4 788.2 81.6 

TABLE 6-3. VISIBILITY IMPAIRMENT IMPROVEMENT ATTRIBUTED TO NOX CONTROLS

 CACR UPBU HERC MING 

Emission 

Unit Scenario 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

98th 

% 

∆dv 

Days 

> 0.5 

∆dv 

No. 1 

Power 

Boiler 

Baseline 0.190 0 0.022 0 0.012 0 0.008 0 

SNCR 20.0% 0.155 0 0.018 0 0.009 0 0.006 0 

 Improvement Over Baseline 0.035 0 0.004 0 0.003 0 0.002 0 

SNCR 32.5% 0.132 0 0.015 0 0.008 0 0.005 0 

 Improvement Over Baseline 0.058 0 0.007 0 0.004 0 0.003 0 

SNCR 45.0% 0.110 0 0.012 0 0.007 0 0.004 0 

 Improvement Over Baseline 0.080 0 0.010 0 0.005 0 0.004 0 

MdN 0.101 0 0.011 0 0.006 0 0.004 0 

 Improvement Over Baseline 0.089 0 0.011 0 0.006 0 0.004 0 

No. 2 

Power 

Boiler 

Baseline 0.844 49 0.146 0 0.105 0 0.065 0 

SNCR 27.5% 0.678 35 0.134 0 0.095 0 0.060 0 

 Improvement Over Baseline 0.166 14 0.012 0 0.010 0 0.005 0 

LNB 30.0% 0.663 32 0.132 0 0.094 0 0.060 0 

 Improvement Over Baseline 0.181 17 0.014 0 0.011 0 0.005 0 

 Improvement Over SNCR 27.5% 0.015 3 0.002 0 0.001 0 0.000 0 

SNCR 35.0% 0.632 30 0.129 0 0.092 0 0.059 0 

 Improvement Over Baseline 0.212 19 0.017 0 0.013 0 0.006 0 

 Improvement Over SNCR 27.5% 0.046 5 0.005 0 0.003 0 0.001 0 

 Improvement Over LNB 30.0% 0.031 2 0.003 0 0.002 0 0.001 0 

MdN 0.548 19 0.117 0 0.087 0 0.057 0 

 Improvement Over Baseline 0.296 30 0.029 0 0.018 0 0.008 0 

 
Domtar A.W. LLC 6-4 Trinity Consultants 

Ashdown Mill 

6.3 PROPOSED BART FOR NOX

The No. 1 Power Boiler does not contribute to visibility impairment greater than 0.5 ∆dv nor any 

single day of impairment at any of the Class I areas. Therefore, the considered control options 

provide no improvement in visibility impairment and the costs of the control options are not justified. 

Domtar proposes no controls with a BART emission determination of 145 lb/hr (representing a 20 

percent margin above the baseline of 121.2 lb/hr). Domtar proposes to demonstrate compliance with 

this limit by calculating emissions on a monthly and rolling 12-month basis, updated within 15 days 

of the end of each month and submitted in semi-annual reports. 

For the No. 2 Power Boiler, Domtar proposes a BART determination of 345 lb/hr (rounded up from 

342.4 lb/hr). This proposal represents a six percent decrease – and an accompanying visibility 

impairment improvement of two fewer days with impacts greater than 0.5 ∆dv – compared to the 

original BART proposal, which was based on the installation of low-NOX burners (LNB) and which 

represented a 30 percent decrease compared to baseline emissions. This level of emissions is 

potentially achievable through the use of SNCR. Because of the high level of uncertainly around the 

use and effectiveness of SNCR, Domtar does not feel it is prudent to add the full potential control 

efficiencies for both LNB and SNCR. Also, Domtar requests that a specific technology not be 

specified as BART so that it has flexibility to pursue any option that achieves the BART emissions 

level. Domtar proposes to demonstrate compliance with this limit on a 30-day rolling average as 

measured by the existing CEMS.
Domtar A.W. LLC A-1 Trinity Consultants 

Ashdown Mill 

APPENDIX A – MODELING PROTOCOL
CALMET DATA PROCESSING PROTOCOL  BART DETERMINATION

OKLAHOMA GAS & ELECTRIC

MUSKOGEE GENERATING STATION

SEMINOLE GENERATING STATION

SOONER GENERATING STATION

Prepared by:

Vern Choquette  Principal Consultant

Eugene Chen, PE  Senior Consultant

Jeremy Townley  Consultant

TRINITY CONSULTANTS

120 East Sheridan

Suite 205

Oklahoma City, OK 73104

(405) 228-3292

January 23, 2008

Project 083701.0004
OG&E i Trinity Consultants

CALMET Processing Protocol 083701.0004

TABLE OF CONTENTS

1. INTRODUCTION.................................................................................................... 1-1

1.1 BEST AVAILABLE RETROFIT TECHNOLOGY RULE BACKGROUND ......................... 1-1

1.2 OBJECTIVE ............................................................................................................ 1-2

1.3 LOCATION OF SOURCES AND RELEVANT CLASS I AREAS...................................... 1-2

2. CALPUFF MODEL SYSTEM ............................................................................... 2-1

2.1 MODEL VERSIONS................................................................................................. 2-1

2.2 MODELING DOMAIN ............................................................................................. 2-1

3. CALMET............................................................................................................ 3-1

3.1 GEOPHYSICAL DATA............................................................................................. 3-1

3.1.1 TERRAIN DATA ...................................................................................................3-1

3.1.2 LAND USE DATA.................................................................................................3-2

3.1.3 COMPILING TERRAIN AND LAND USE DATA.......................................................3-3

3.2 METEOROLOGICAL DATA ..................................................................................... 3-3

3.2.1 MESOSCALE MODEL METEOROLOGICAL DATA .................................................3-3

3.2.2 SURFACE METEOROLOGICAL DATA ...................................................................3-4

3.2.3 UPPER AIR METEOROLOGICAL DATA.................................................................3-5

3.2.4 PRECIPITATION METEOROLOGICAL DATA..........................................................3-6

3.2.5 BUOY METEOROLOGICAL DATA.........................................................................3-7

3.3 CALMET CONTROL PARAMETERS....................................................................... 3-8

3.3.1 VERTICAL METEOROLOGICAL PROFILE..............................................................3-8

3.3.2 INFLUENCES OF OBSERVATIONS .........................................................................3-9

APPENDIX A- METEOROLOGICAL STATIONS

APPENDIX B – SAMPLE CALMET CONTROL FILE (CALPUFF VERSION 5.8)

APPENDIX C – SAMPLE CALMET CONTROL FILE (CALPUFF VERSION 6)
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LIST OF TABLES

TABLE 1-1. BART-ELIGIBLE SOURCES ...............................................................................................1-2

TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS .......................................1-2

TABLE 2-1. CALPUFF MODELING SYSTEM VERSIONS .....................................................................2-1

TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN................................3-9

TABLE A-1. LIST OF SURFACE METEOROLOGICAL STATIONS ...........................................................A-1

TABLE A-2. LIST OF UPPER AIR METEOROLOGICAL STATIONS.........................................................A-5

TABLE A-3. LIST OF PRECIPITATION METEOROLOGICAL STATIONS..................................................A-6

TABLE A-4. LIST OF OVER WATER METEOROLOGICAL STATIONS..................................................A-14
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CALMET Processing Protocol 083701.0004

LIST OF FIGURES

FIGURE 1-1. PLOT OF SOURCES AND NEAREST CLASS I AREAS .........................................................1-3

FIGURE 2-1. REFINED METEOROLOGICAL MODELING DOMAIN.........................................................2-2

FIGURE 3-1. PLOT OF LAND ELEVATION USING USGS TERRAIN DATA ............................................3-2

FIGURE 3-2. PLOT OF LAND USE USING USGS LULC DATA.............................................................3-3

FIGURE 3-3. PLOT OF SURFACE STATION LOCATIONS........................................................................3-5

FIGURE 3-4. PLOT OF UPPER AIR STATIONS LOCATIONS ...................................................................3-6

FIGURE 3-5. PLOT OF PRECIPITATION METEOROLOGICAL STATIONS .................................................3-7

FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS ................................................................3-8
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1. INTRODUCTION

Oklahoma Gas & Electric (OG&E) owns and operates three electric generating stations near

Muskogee, Oklahoma (Muskogee Generating Station), Seminole, Oklahoma (Seminole Generating 

Station), and Stillwater, Oklahoma (Sooner Generating Station). These generating stations are

considered eligible to be regulated under the U.S. Environmental Protection Agency’s (EPA) Best 

Available Retrofit Technology (BART) provisions of the Regional Haze Rule. This protocol 

describes the proposed methodology for conducting the CALMET data processing for the refined 

CALPUFF BART modeling analysis for OG&E’s Muskogee, Seminole, and Sooner Generating 

Stations. A detailed CALPUFF BART modeling protocol will be submitted in the near future and 

will include a discussion of the CALPUFF parameters as well as the post processing methodologies 

to be used in the refined modeling analysis for each station.

1.1 BEST AVAILABLE RETROFIT TECHNOLOGY RULE BACKGROUND

On July 1, 1999, the U.S. Environmental EPA published the final Regional Haze Rule (RHR). The 

objective of the RHR is to improve visibility in 156 specific areas across with United States, known 

as Class I areas. The Clean Air Act defines Class I areas as certain national parks (over 6000 acres), 

wilderness areas (over 5000 acres), national memorial parks (over 5000 acres), and international 

parks that were in existence on August 7, 1977.

On July 6, 2005, the EPA published amendments to its 1999 RHR, often called the BART rule, which 

included guidance for making source-specific Best Available Retrofit Technology (BART) 

determinations. The BART rule defines BART-eligible sources as sources that meet the following 

criteria: 

(1) Have potential emissions of at least 250 tons per year of a visibility-impairing pollutant,

(2) Began operation between August 7, 1962 and August 7, 1977, and

(3) Are listed as one of the 26 listed source categories in the guidance.

A BART-eligible source is not automatically subject to BART. Rather, BART-eligible sources are 

subject-to-BART if the sources are “reasonably anticipated to cause or contribute to visibility 

impairment in any federal mandatory Class I area.” EPA has determined that sources are reasonably 

anticipated to cause or contribute to visibility impairment if the visibility impacts from a source are 

greater than 0.5 deciviews (dv) when compared against a natural background.

Air quality modeling is the tool that is used to determine a source’s visibility impacts. States have the 

authority to exempt certain BART-eligible sources from installing BART controls if the results of the 

dispersion modeling demonstrate that the source cannot reasonably be anticipated to cause or 

contribute to visibility impairment in a Class I area. Further, states also have the authority to define 

the modeling procedures for conducting modeling related to making BART determinations. 
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CALMET Processing Protocol 083701.0004

1.2 OBJECTIVE

The objective of this document is to provide a protocol summarizing the modeling methods and 

procedures that will be followed to conduct the CALMET data processing necessary to complete a

refined CALPUFF modeling analysis for the OG&E generating stations discussed above. The 

modeling methods and procedures contained in this protocol and the CALPUFF protocol yet to be 

submitted will be used to determine appropriate controls for OG&E’s BART-eligible sources that can 

reasonably be anticipated to reduce the sources’ effects on or contribution to visibility impairment in 

the surrounding Class I areas. It is OG&E’s intent to determine a combination of emissions controls 

that will reduce the impact of each generating station to a degree that the 98th percentile of the 

visibility impact predicted by the model due to all the BART eligible sources at each station 

collectively is below EPA’s recommended visibility contribution threshold of 0.5 dv.

1.3 LOCATION OF SOURCES AND RELEVANT CLASS I AREAS

The sources listed in Table 1-1 are the sources that have been identified by OG&E as sources that 

meet the three criteria for BART-eligible sources.

TABLE 1-1. BART-ELIGIBLE SOURCES

EPN Description

Muskogee Sources

Unit 4 5,480 MMBtu/hr Coal Fired Boiler

Unit 5 5,480 MMBtu/hr Coal Fired Boiler

Seminole Sources

SM1 5,480 MMBtu/hr Natural Gas Fired Boiler

SM2 5,480 MMBtu/hr Natural Gas Fired Boiler

SM3 5,496 MMBtu/hr Natural Gas Fired Boiler

Sooner Sources

Unit 1 5,116 MMBtu/hr Coal Fired Boiler

Unit 2 5,116 MMBtu/hr Coal Fired Boiler

As required in CENRAP’s BART Modeling Guidelines, Class I areas within 300 km of each station 

will be included in each analysis. The following table summarizes the distances of the four closest 

Class I areas to each station. As seen from this summary, some Class I areas are more than 300 km 

from the certain stations. However, in order to demonstrate that each station will not have an adverse 

effect on the visibility at any of the four nearest Class I areas, OG&E has opted to include those Class 

I areas more than 300 km away in this analysis. Note that the distances listed in the table below are 

the distances between the stations and the closest border of the Class I areas. 

TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS

CACR HEGL UPBU WIMO

Muskogee 180 230 164 324

Seminole 242 386 310 178

Sooner 345 363 327 234
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CALMET Processing Protocol 083701.0004

A plot of the Class I areas with respect to the each station is provided in Figure 1-1.

 FIGURE 1-1. PLOT OF SOURCES AND NEAREST CLASS I AREAS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas
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CALMET Processing Protocol 083701.0004

2. CALPUFF MODEL SYSTEM

The main components of the CALPUFF modeling system are CALMET, CALPUFF, and CALPOST. 

CALMET is the meteorological model that generates hourly three-dimensional meteorological fields 

such as wind and temperature. CALPUFF simulates the non-steady state transport, dispersion, and 

chemical transformation of air pollutants emitted from a source in “puffs”. CALPUFF calculates 

hourly concentrations of visibility affecting pollutants at each specified receptor in a modeling 

domain. CALPOST is the post-processor for CALPUFF that computes visibility impacts from a 

source based on the visibility affecting pollutant concentrations that were output by CALPUFF.

2.1 MODEL VERSIONS

The versions of the CALPUFF modeling system programs that are proposed for conducting OG&E’s 

BART modeling are listed in Table 2-1. A detailed refined CALPUFF BART modeling protocol will 

be submitted in the near future.

TABLE 2-1. CALPUFF MODELING SYSTEM VERSIONS

Processor Version Level

TERREL 3.3 030402

CTGCOMP 2.21 030402

CTGPROC 2.63 050128

MAKEGEO 2.2 030402

CALMET 5.53a 040716

CALPUFF 5.8 070623

POSTUTIL 1.3 030402

CALPOST 5.51 030709

2.2 MODELING DOMAIN

The CALPUFF modeling system utilizes three modeling grids: the meteorological grid, the 

computational grid, and the sampling grid. The meteorological grid is the system of grid points at 

which meteorological fields are developed with CALMET. The computational grid determines the 

computational area for a CALPUFF run. Puffs are advected and tracked only while within the 

computational grid. The meteorological grid is defined so that it covers the areas of concern and 

gives enough marginal buffer area for puff transport and dispersion. A plot of the proposed 

meteorological modeling domain with respect to the Class I areas being modeled is also provided in 
OG&E 2-2 Trinity Consultants

CALMET Processing Protocol 083701.0004

Figure 2-1. The computational domain will be set to extend at least 50 km in all directions beyond 

the Muskogee, Seminole, and Sooner Generating Stations and the Class I areas of interest. Note that 

the map projection for the modeling domain will be Lambert Conformal Conic (LCC) and the datum 

will be the World Geodetic System 84 (WGS-84). The reference point for the modeling domain is

Latitude 40oN, Longitude 97oW. The southwest corner will be set to -951.547 km LCC, -1646.637 

km LCC corresponding to Latitude 24.813 oN and Longitude 87.778oW. The meteorological grid 

spacing will be 4 km, resulting in 462 grid points in the X direction and 376 grid points in the Y 

direction.

FIGURE 2-1. REFINED METEOROLOGICAL MODELING DOMAIN

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

L

C

C

N

o

r

t

h

i

n

g

(

k

)m

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Meteorological Modeling Domain

Computational Modeling Domain 1
OG&E 3-1 Trinity Consultants

CALMET Processing Protocol 083701.0004

3. CALMET

The EPA Approved Version of the CALMET meteorological processor will be used to generate the 

meteorological data for CALPUFF. CALMET is the meteorological processor that compiles 

meteorological data from raw observations of surface and upper air conditions, precipitation 

measurements, mesoscale model output, and geophysical parameters into a single hourly, gridded 

data set for input into CALPUFF. CALMET will be used to assimilate data for 2001- 2003 using 

National Weather Service (NWS) surface station observations, upper air station observations, 

precipitation station observations, buoy station observations (for overwater areas), and mesoscale 

model output to develop the meteorological field. 

3.1 GEOPHYSICAL DATA

CALMET requires geophysical data to characterize the terrain and land use parameters that 

potentially affect dispersion. Terrain features affect flows and create turbulence in the atmosphere 

and are potentially subjected to higher concentrations of elevated puffs. Different land uses exhibit 

variable characteristics such as surface roughness, albedo, Bowen ratio, and leaf-area index that also 

effect turbulence and dispersion. 

3.1.1 TERRAIN DATA

Terrain data will be obtained from the United States Geological Survey (USGS) in 

1-degree (1:250,000 scale or approximately 90 meter resolution) digital format. The

USGS terrain data will then be processed by the TERREL program to generate grid-cell 

elevation averages across the modeling domain. A plot of the land elevations based on the 

USGS data for the modeling domain is provided in Figure 3-1.
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CALMET Processing Protocol 083701.0004

FIGURE 3-1. PLOT OF LAND ELEVATION USING USGS TERRAIN DATA

3.1.2 LAND USE DATA

The land use land cover (LULC) data from the USGS North American land cover 

characteristics data base in the Lambert Azimuthal equal area map projection will be used 

in order to determine the land use within the modeling domain. The LULC data will be 

processed by the CTGPROC program which will generate land use for each grid cell 

across the modeling domain. A plot of the land use based on the USGS data for the 

modeling domain is provided in Figure 3-2.

-800 -600 -400 -200 0 200 400 600 800

LCC Easting(km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

L

C

C

N

o

r

t

h

i

n

g

(

k

)m

Seminole Station

Muskogee Station

Sooner Station

0

982

1960

2950

3930

Terrain 

Elevation (m)
OG&E 3-3 Trinity Consultants

CALMET Processing Protocol 083701.0004

FIGURE 3-2. PLOT OF LAND USE USING USGS LULC DATA

3.1.3 COMPILING TERRAIN AND LAND USE DATA

The terrain data files output by the TERELL program and the LULC files output by the 

CTGPROC program will be uploaded into the MAKEGEO program to create a 

geophysical data file that will be input into CALMET. 

3.2 METEOROLOGICAL DATA 

CALMET will be used to assimilate data for 2001, 2002, and 2003 using mesoscale model output and 

National Weather Service (NWS) surface station observations, upper air station observations,

precipitation station observations, and National Oceanic and Atmosphere Administrations (NOAA) 

buoy station observations to develop the meteorological field. 

3.2.1 MESOSCALE MODEL METEOROLOGICAL DATA

Hourly mesoscale data will also be used as the initial guess field in developing the 

CALMET meteorological data. It is OG&E’s intent to use the following 5th generation 

mesoscale model meteorological data sets (or MM5 data) in the analysis:

 2001 MM5 data at 12 km resolution generated by the U.S. EPA 

 2002 MM5 data at 36 km resolution generated by the Iowa DNR

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

L

C

C

N

o

r

t

h

i

n

g

(

k

)m

10

27.5

45

62.5

80

Land Use

Sooner Station

Muskogee Station

Seminole Station
OG&E 3-4 Trinity Consultants

CALMET Processing Protocol 083701.0004

 2003 MM5 data set at 36 km resolution generated by the Midwest RPO

The specific MM5 data that will be used are subsets of the data listed above. As the 

contractor to CENRAP for developing the meteorological data sets for the BART 

modeling, Alpine Geophysics extracted three subsets of MM5 data for each year from 

2001 to 2003 from the data sets listed above using the CALMM5 extraction program. The 

three subsets covered the northern, central, and southern portions of CENRAP. TXI is 

proposing to use the southern set of the extracted MM5 data. 

The 2001 southern subset of the extracted MM5 data includes 30 files that are broken into 

10 to 11 day increments (3 files per month). The 2002 and 2003 southern subsets of 

extracted MM5 data include 12 files each of which are broken into 30 to 31 day increment

files (1 file per month). Note that the 2001 to 2003 MM5 data extracted by Alpine

Geophysics will not be able to be used directly in the modeling analysis. To run the Alpine 

Geophysics extracted MM data in the EPA approved CALMET program, each of the MM5 

files will need to be adjusted by appending an additional six (6) hours, at a minimum, to 

the end of each file to account for the shift in time zones from the Greenwich Mean Time 

(GMT) prepared Alpine Geophysics data to Time Zone 6 for this analysis. No change to 

the data will occur. 

The time periods covered by the data in each of the MM5 files extracted by Alpine 

Geophysics include a specific number of calendar days, where the data starts at Hour 0 in 

GMT for the first calendar day and ends at Hour 23 in GMT on the last calendar day. In 

order to run CALMET in the local standard time (LST), which is necessary since the 

surface meteorological observations are recorded in LST, there must be hours of MM5 data 

referenced in a CALMET run that match the LST observation hours. Since the LST hours 

in Central Standard Time (CST) are 6 hours behind GMT, it is necessary to adjust the data 

in each MM5 file so that the time periods covered in the files match CST. 

Based on the above discussion, the Alpine Geophysics MM5 data will not be used directly. 

Instead the data files will be modified to add 8 additional hours of data to the end of each

file from the beginning of the subsequent file. CALMET will then be run using the 

appended MM5 data to generate a contiguous set of CALMET output files. The converted 

MM5 data files occupy approximately 1.2 terabytes (TB) of hard drive space.

3.2.2 SURFACE METEOROLOGICAL DATA

Parameters affecting turbulent dispersion that are observed hourly at surface stations 

include wind speed and direction, temperature, cloud cover and ceiling, relative humidity, 

and precipitation type. It is OG&E’s intent to use the surface stations listed in Table A-1 

of Appendix A. The locations of the surface stations with respect to the modeling domain 

are shown in Figure 3-3. The stations were selected from the available data inventory to 

optimize spatial coverage and representation of the domain. Data from the stations will be 

processed for use in CALMET using EPA’s SMERGE program.
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FIGURE 3-3. PLOT OF SURFACE STATION LOCATIONS

3.2.3 UPPER AIR METEOROLOGICAL DATA

Observations of meteorological conditions in the upper atmosphere provide a profile of 

turbulence from the surface through the depth of the boundary layer in which dispersion 

occurs. Upper air data are collected by balloons launched simultaneously across the 

observation network at 0000 Greenwich Mean Time (GMT) (6 o’clock PM in Oklahoma) 

and 1200 GMT (6 o’clock AM in Oklahoma). Sensors observe pressure, wind speed and 

direction, and temperature (among other parameters) as the balloon rises through the 

atmosphere. The upper air observation network is less dense than surface observation 

points since upper air conditions vary less and are generally not as affected by local effects 

(e.g., terrain or water bodies). The upper air stations that are proposed for this analysis are 

listed in Table A-2 of Appendix A. The locations of the upper air stations with respect to 

the modeling domain are shown in Figure 3-4. These stations were selected from the 

available data inventory to optimize spatial coverage and representation of the domain. 

Data from the stations will be processed for use in CALMET using EPA’s READ62 

program.

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

L

C

C

N

o

r

t

h

i

n

g

(

k

m)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Surface Stations
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FIGURE 3-4. PLOT OF UPPER AIR STATIONS LOCATIONS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Upper Air Stations

3.2.4 PRECIPITATION METEOROLOGICAL DATA

The effects of chemical transformation and deposition processes on ambient pollutant 

concentrations will be considered in this analysis. Therefore, it is necessary to include 

observations of precipitation in the CALMET analysis. The precipitation stations that are 

proposed for this analysis are listed in Table A-3 of Appendix A. The locations of the 

precipitation stations with respect to the modeling domain are shown in Figure 3-5. These 

stations were selected from the available data inventory to optimize spatial coverage and 

representation of the domain. Data from the stations will be processed for use in 

CALMET using EPA’s PMERGE program.
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FIGURE 3-5. PLOT OF PRECIPITATION METEOROLOGICAL STATIONS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Precipitation Stations

3.2.5 BUOY METEOROLOGICAL DATA

The effects of land/sea breeze on ambient pollutant concentrations will be considered in 

this analysis. Therefore, it is necessary to include observations of buoy stations in the 

CALMET analysis. The buoy stations that are proposed for this analysis are listed in Table 

A-4 of Appendix A. The locations of the buoy stations with respect to the modeling 

domain are shown in Figure 3-6. These stations were selected from the available data 

inventory to optimize spatial coverage and representation of the domain along the 

coastline. Data from the stations will be prepared by filling missing hour records with the 

CALMET missing parameter value (9999). No adjustments to the data will occur. 
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FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS

-800 -600 -400 -200 0 200 400 600 800

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Buoy Stations

3.3 CALMET CONTROL PARAMETERS

Appendix B provides a sample CALMET input file used in OG&E’s modeling analysis. A few 

details of the CALMET model setup for sensitive parameters are also discussed below. 

3.3.1 VERTICAL METEOROLOGICAL PROFILE

The height of the top vertical layer will be set to 3,500 meters. This height corresponds to 

the top sounding pressure level for which upper air observation data will be relied upon. 

The vertical dimension of the domain will be divided into 12 layers with the maximum 

elevations for each layer shown in Table 3-1. The vertical dimensions are weighted 

towards the surface to resolve the mixing layer while using a somewhat coarser resolution 

for the layers aloft. 
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TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN

Layer Elevation (m)

1 20 

2 40

3 60

4 80

5 100

6 150

7 200

8 250

9 500

10 1000

11 2000

12 3500

CALMET allows for a bias value to be applied to each of the vertical layers. The bias 

settings for each vertical layer determine the relative weight given to the vertically 

extrapolated surface and upper air wind and temperature observations. The initial guess 

fields are computed with an inverse distance weighting (1/r

2

) of the surface and upper air 

data. The initial guess fields may be modified by a layer dependent bias factor. Values for 

the bias factor may range from -1 to +1. A bias of -1 eliminates upper-air observations in

the 1/r2interpolations used to initialize the vertical wind fields. Conversely, a bias of +1 

eliminates the surface observations in the interpolations for this layer. Normally, bias is set 

to zero (0) for each vertical layer, such that the upper air and surface observations are given 

equal weight in the 1/r2interpolations. The biases for each layer of the proposed modeling 

domain will be set to zero.

CALMET allows for vertical extrapolation of surface wind observations to layers aloft to 

be skipped if the surface station is close to the upper air station. Alternatively, CALMET 

allows data from all surface stations to be extrapolated. The CALMET parameter that 

controls this setting is IEXTRP. Setting IEXTRP to a value less than zero (0) means that 

layer 1 data from upper air soundings is ignored in any vertical extrapolations. IEXTRP 

will be set to -4 for this analysis (i.e., the similarity theory is used to extrapolate the surface 

winds into the layers aloft, which provides more information on observed local effects to 

the upper layers).

3.3.2 INFLUENCES OF OBSERVATIONS

Step 1 wind fields will be based on an initial guess using MM5 data and refined to reflect 

terrain affects. Step 2 wind fields will adjust the Step 1 wind field by incorporating the 

influence of local observations. An inverse distance method is used to determine the 

influence of observations to the Step 1 wind field. RMAX1 and RMAX2 define the radius 

of influence for data from surface stations to land in the surface layer and data from upper 

air stations to land in the layers aloft. In general, RMAX1 and RMAX2 are used to 

exclude observations from being inappropriately included in the development of the Step 2
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wind field if the distance from an observation station to a grid point exceeds the maximum 

radius of influence. 

If the distance from an observation station to a grid point is less than the value set for 

RMAX, the observation data will be used in the development of the Step 2 wind field. R1 

represents the distance from a surface observation station at which the surface observation 

and the Step 1 wind field are weighted equally. R2 represents the comparable distance for 

winds aloft. R1 and R2 are used to weight the observation data with respect to the MM5 

data that was used to generate the Step 1 wind field. Large values for R1 and R2 give 

more weight to the observations, where as small values give more weight to the MM5 data. 

In this BART modeling analysis, RMAX 1 will be set to 20 km, and R1 will be set to 10 

km. This will limit the influence of the surface observation data from all surface stations to 

20 km from each station, and will equally weight the MM5 and observation data at 10 km. 

RMAX2 will be set to 50 km, and R2 will be set to 25 km. This will limit the influence of 

the upper air observation data from all surface stations to 50 km from each station, and will 

equally weight the MM5 and observation data at 25 km. These settings of radius of 

influence will allow for adequate weighting of the MM5 data and the observation data 

across the modeling domain due to the vast domain to be modeled. RAMX 3 will be set to 

500 km. 
OG&E A-1 Trinity Consultants

CALMET Processing Protocol 083701.0004

APPENDIX A- METEOROLOGICAL STATIONS

TABLE A-1. LIST OF SURFACE METEOROLOGICAL STATIONS

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

1 KDYS 69019 -267.672 -834.095 96.9968 39.9925

2 KNPA 72222 932.565 -1020.909 97.0110 39.9908

3 KBFM 72223 857.471 -996.829 97.0101 39.9910

4 KGZH 72227 946.767 -899.515 97.0112 39.9919

5 KTCL 72228 870.843 -706.104 97.0103 39.9936

6 KNEW 53917 674.172 -1078.342 97.0080 39.9903

7 KNBG 12958 677.719 -1104.227 97.0080 39.9900

8 BVE 12884 741.996 -1153.463 97.0088 39.9896

9 KPTN 72232 550.88 -1124.295 97.0065 39.9898

10 KMEI 13865 774.911 -814.225 97.0092 39.9926

11 KPIB 72234 728.416 -915.165 97.0086 39.9917

12 KGLH 72235 557.072 -703.097 97.0066 39.9936

13 KHEZ 11111 540.777 -912.22 97.0064 39.9918

14 KMCB 11112 622.755 -949.618 97.0074 39.9914

15 KGWO 11113 640.102 -695.286 97.0076 39.9937

16 KASD 72236 692.381 -1043.261 97.0082 39.9906

17 KPOE 72239 363.294 -984.839 97.0043 39.9911

18 KBAZ 72241 -102.133 -1140.886 96.9988 39.9897

19 KGLS 72242 215.108 -1185.604 97.0025 39.9893

20 KDWH 11114 140.413 -1101.174 97.0017 39.9900

21 KIAH 12960 158.266 -1108.37 97.0019 39.9900

22 KHOU 72243 167.147 -1147.402 97.0020 39.9896

23 KEFD 12906 178.551 -1152.782 97.0021 39.9896

24 KCXO 72244 152.739 -1069.309 97.0018 39.9903

25 KCLL 11115 60.898 -1044.381 97.0007 39.9906

26 KLFK 93987 214.643 -969.355 97.0025 39.9912

27 KUTS 11116 136.056 -1026.773 97.0016 39.9907

28 KTYR 11117 150.451 -846.207 97.0018 39.9924

29 KCRS 72246 56.655 -882.642 97.0007 39.9920

30 KGGG 72247 214.572 -841.163 97.0025 39.9924

31 KGKY 11118 -9.365 -812.25 96.9999 39.9927

32 KDTN 72248 304.827 -821.713 97.0036 39.9926

33 KBAD 11119 312.743 -825.101 97.0037 39.9925

34 KMLU 11120 465.834 -816.211 97.0055 39.9926

35 KTVR 11121 561.446 -840.225 97.0066 39.9924

36 KTRL 11122 68.599 -806.417 97.0008 39.9927

37 KOCH 72249 216.81 -930.252 97.0026 39.9916

38 KBRO 12919 -44.167 -1571.387 96.9995 39.9858
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Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

39 KALI 72251 -103.012 -1363.74 96.9988 39.9877

40 KLRD 12920 -246.548 -1381.603 96.9971 39.9875

41 KSSF 72252 -143.386 -1183.35 96.9983 39.9893

42 KRKP 11123 -4.965 -1324.914 96.9999 39.9880

43 KCOT 11124 -219.097 -1280.964 96.9974 39.9884

44 KLBX 11125 150.245 -1207.466 97.0018 39.9891

45 KSAT 12921 -143.024 -1160.935 96.9983 39.9895

46 KHDO 12962 -211.702 -1178.172 96.9975 39.9894

47 KSKF 72253 -154.625 -1177.555 96.9982 39.9894

48 KHYI 11126 -84.156 -1122.487 96.9990 39.9899

49 KTKI 72254 38.788 -754.791 97.0005 39.9932

50 KBMQ 11127 -118.39 -1027.031 96.9986 39.9907

51 KATT 11128 -67.587 -1075.97 96.9992 39.9903

52 KSGR 11129 131.478 -1151.702 97.0016 39.9896

53 KGTU 11130 -65.624 -1033.173 96.9992 39.9907

54 KVCT 12912 6.587 -1236.788 97.0001 39.9888

55 KPSX 72255 73.878 -1253.33 97.0009 39.9887

56 KACT 13959 -22.12 -929.156 96.9997 39.9916

57 KPWG 72256 -30.147 -944.073 96.9996 39.9915

58 KILE 72257 -65.288 -988.507 96.9992 39.9911

59 KGRK 11131 -79.643 -990.173 96.9991 39.9911

60 KTPL 11132 -38.203 -981.19 96.9996 39.9911

61 KPRX 13960 143.317 -703.663 97.0017 39.9936

62 KDTO 72258 -17.018 -752.974 96.9998 39.9932

63 KAFW 11133 -29.564 -777.061 96.9997 39.9930

64 KFTW 72259 -34.302 -795.502 96.9996 39.9928

65 KMWL 11134 -99.769 -798.767 96.9988 39.9928

66 KRBD 11135 12.453 -810.467 97.0002 39.9927

67 KDRT 11136 -384.069 -1170.59 96.9955 39.9894

68 KFST 22010 -566.418 -988.838 96.9933 39.9911

69 KGDP 72261 -739.127 -873.302 96.9913 39.9921

70 KSJT 72262 -333.338 -952.54 96.9961 39.9914

71 KMRF 23034 -676.265 -1042.616 96.9920 39.9906

72 KMAF 72264 -489.668 -878.107 96.9942 39.9921

73 KINK 23023 -586.882 -890.654 96.9931 39.9920

74 KABI 72265 -252.044 -836.353 96.9970 39.9924

75 KLBB 13962 -445.006 -689.313 96.9948 39.9938

76 KATS 11137 -696.818 -763.258 96.9918 39.9931

77 KCQC 11138 -785.757 -515.724 96.9907 39.9953

78 KROW 23009 -698.822 -712.898 96.9918 39.9936

79 KSRR 72268 -789.593 -686.226 96.9907 39.9938

80 KCNM 11139 -682.79 -822.109 96.9919 39.9926

81 KALM 36870 -838.056 -752.338 96.9901 39.9932

82 KLRU 72269 -931.527 -804.112 96.9890 39.9927

83 KTCS 72271 -952.353 -695.469 96.9888 39.9937
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Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

84 KSVC 93063 -1042.03 -752.033 96.9877 39.9932

85 KDMN 72272 -1006.77 -799.231 96.9881 39.9928

86 KMSL 72323 854.846 -536.687 97.0101 39.9952

87 KPOF 72330 578.62 -336.733 97.0068 39.9970

88 KGTR 11140 779.065 -689.108 97.0092 39.9938

89 KTUP 93862 753.875 -600.337 97.0089 39.9946

90 KMKL 72334 727.051 -454.383 97.0086 39.9959

91 KLRF 72340 440.654 -550.661 97.0052 39.9950

92 KHKA 11141 643.365 -424.419 97.0076 39.9962

93 KHOT 72341 358.094 -604.603 97.0042 39.9945

94 KTXK 11142 278.022 -720.623 97.0033 39.9935

95 KLLQ 72342 488.655 -698.008 97.0058 39.9937

96 KMWT 72343 254.18 -599.224 97.0030 39.9946

97 KFSM 13964 237.97 -512.87 97.0028 39.9954

98 KSLG 72344 224.881 -419.064 97.0027 39.9962

99 KVBT 11143 248.074 -399.892 97.0029 39.9964

100 KHRO 11144 343.525 -405.601 97.0041 39.9963

101 KFLP 11145 404.239 -399.142 97.0048 39.9964

102 KBVX 11146 480.712 -457.853 97.0057 39.9959

103 KROG 11147 258.44 -397.685 97.0031 39.9964

104 KSPS 13966 -138.053 -664.886 96.9984 39.9940

105 KHBR 72352 -186.121 -551.123 96.9978 39.9950

106 KCSM 11148 -198.844 -513.911 96.9977 39.9954

107 KFDR 11149 -181.653 -625.205 96.9979 39.9944

108 KGOK 72353 -35.905 -458.97 96.9996 39.9959

109 KTIK 72354 -34.581 -506.938 96.9996 39.9954

110 KPWA 11150 -58.596 -493.951 96.9993 39.9955

111 KSWO 11151 -7.42 -425.828 96.9999 39.9962

112 KMKO 72355 146.972 -479.879 97.0017 39.9957

113 KRVS 72356 91.059 -438.276 97.0011 39.9960

114 KBVO 11152 87.136 -357.069 97.0010 39.9968

115 KMLC 11153 110.647 -563.566 97.0013 39.9949

116 KOUN 72357 -40.731 -527.298 96.9995 39.9952

117 KLAW 11154 -129.405 -600.222 96.9985 39.9946

118 KCDS 72360 -300.297 -610.668 96.9965 39.9945

119 KGNT 72362 -985.117 -475.563 96.9884 39.9957

120 KGUP 11155 -1059.48 -427.151 96.9875 39.9961

121 KAMA 23047 -425.319 -518.171 96.9950 39.9953

122 KBGD 72363 -395.603 -466.083 96.9953 39.9958

123 KFMN 72365 -993.449 -297.944 96.9883 39.9973

124 KSKX 72366 -770.464 -355.855 96.9909 39.9968

125 KTCC 23048 -597.271 -511.241 96.9930 39.9954

126 KLVS 23054 -732.565 -448.329 96.9914 39.9960

127 KEHR 72423 812.573 -199.695 97.0096 39.9982

128 KEVV 93817 822.929 -172.715 97.0097 39.9984
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Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC North

(km) Long Lat

129 KMVN 72433 704.666 -154.54 97.0083 39.9986

130 KMDH 11156 676.745 -218.041 97.0080 39.9980

131 KBLV 11157 617.659 -136.018 97.0073 39.9988

132 KSUS 3966 547.898 -130.122 97.0065 39.9988

133 KPAH 3816 725.985 -293.319 97.0086 39.9974

134 KJEF 72445 419.01 -145.496 97.0050 39.9987

135 KAIZ 11158 387.096 -200.609 97.0046 39.9982

136 KIXD 72447 182.322 -126.913 97.0022 39.9989

137 KWLD 72450 0 -298.57 97.0000 39.9973

138 KAAO 11159 -18.976 -248.773 96.9998 39.9978

139 KIAB 11160 -23.392 -263.471 96.9997 39.9976

140 KEWK 11161 -24.645 -215.58 96.9997 39.9981

141 KGBD 72451 -161.892 -180.781 96.9981 39.9984

142 KHYS 11162 -195.191 -124.723 96.9977 39.9989

143 KCFV 11163 126.442 -319.698 97.0015 39.9971

144 KFOE 72456 114.618 -115.26 97.0014 39.9990

145 KEHA 72460 -432.761 -320.089 96.9949 39.9971

146 KALS 72462 -777.592 -245.892 96.9908 39.9978

147 KDRO 11164 -945.713 -259.163 96.9888 39.9977

148 KLHX 72463 -568.426 -195.178 96.9933 39.9982

149 KSPD 2128 -494.076 -285.176 96.9942 39.9974

150 KCOS 93037 -664.022 -102.596 96.9922 39.9991

151 KGUC 72467 -857.452 -115.301 96.9899 39.9990

152 KMTJ 93013 -940.981 -109.358 96.9889 39.9990

153 KCEZ 72476 -1020.87 -233.14 96.9880 39.9979

154 KCPS 72531 591.652 -136.14 97.0070 39.9988

155 KLWV 72534 808.939 -94.46 97.0096 39.9992

156 KPPF 74543 130.433 -293.855 97.0015 39.9973

157 KHOP 74671 841.751 -324.569 97.0099 39.9971

158 KBIX 74768 778.252 -1028.514 97.0092 39.9907

159 KPQL 11165 814.599 -1019.583 97.0096 39.9908

160 MMPG 76243 -348.007 -1248.779 96.9959 39.9887

161 MMMV 76342 -446.576 -1449.334 96.9947 39.9869

162 MMMY 76394 -316.664 -1581.176 96.9963 39.9857
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TABLE A-2. LIST OF UPPER AIR METEOROLOGICAL STATIONS

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

1 KABQ 23050 -869.46 -501.713 96.9897 39.9955

2 KAMA 23047 -425.319 -518.171 96.9950 39.9953

3 KBMX 53823 951.609 -702.935 97.0112 39.9936

4 KBNA 13897 920.739 -377.164 97.0109 39.9966

5 KBRO 12919 -44.167 -1571.39 96.9995 39.9858

6 KCRP 12924 -51.535 -1360.35 96.9994 39.9877

7 KDDC 13985 -259.352 -242.681 96.9969 39.9978

8 KDRT 22010 -384.069 -1170.59 96.9955 39.9894

9 KEPZ 3020 -914.558 -852.552 96.9892 39.9923

10 KFWD 3990 -28.034 -793.745 96.9997 39.9928

11 KJAN 3940 650.105 -826.452 97.0077 39.9925

12 KLCH 3937 364.461 -1089.15 97.0043 39.9902

13 KLZK 3952 432.063 -560.441 97.0051 39.9949

14 KMAF 23023 -489.668 -878.107 96.9942 39.9921

15 KOUN 3948 -40.731 -527.298 96.9995 39.9952

16 KSHV 13957 298.869 -831.166 97.0035 39.9925

17 KSIL 53813 698.079 -1054.03 97.0082 39.9905
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TABLE A-3. LIST OF PRECIPITATION METEOROLOGICAL STATIONS

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

1 ADDI 10063 906.825 -601.428 97.0107 39.9946

2 ALBE 10140 917.606 -821.64 97.0108 39.9926

3 BERR 10748 892.454 -683.388 97.0105 39.9938

4 HALE 13620 881.928 -601.878 97.0104 39.9946

5 HAMT 13645 863.663 -612.725 97.0102 39.9945

6 JACK 14193 898.014 -915.623 97.0106 39.9917

7 MBLE 15478 851.953 -1022.41 97.0101 39.9908

8 MUSC 15749 880.113 -567.484 97.0104 39.9949

9 PETE 16370 935.558 -908.259 97.0110 39.9918

10 THOM 18178 900.858 -915.326 97.0106 39.9917

11 TUSC 18385 895.631 -713.223 97.0106 39.9936

12 VERN 18517 825.585 -685.773 97.0098 39.9938

13 BEEB 30530 462.394 -532.485 97.0055 39.9952

14 BRIG 30900 318.015 -554.857 97.0038 39.9950

15 CALI 31140 419.619 -731.44 97.0050 39.9934

16 CAMD 31152 386.546 -699.659 97.0046 39.9937

17 DIER 32020 268.114 -643.184 97.0032 39.9942

18 EURE 32356 286.738 -390.862 97.0034 39.9965

19 GILB 32794 383.362 -435.625 97.0045 39.9961

20 GREE 32978 450.594 -483.201 97.0053 39.9956

21 STUT 36920 509.943 -596.328 97.0060 39.9946

22 TEXA 37048 278.022 -720.623 97.0033 39.9935

23 ALAM 50130 -749.044 -267.856 96.9912 39.9976

24 ARAP 50304 -441.903 -152.324 96.9948 39.9986

25 COCH 51713 -819.794 -148.582 96.9903 39.9987

26 CRES 51959 -828.107 -119.911 96.9902 39.9989

27 GRAN 53477 -451.781 -203.82 96.9947 39.9982

28 GUNN 53662 -829.573 -141.995 96.9902 39.9987

29 HUGO 54172 -539.364 -81.948 96.9936 39.9993

30 JOHN 54388 -483.95 -201.915 96.9943 39.9982

31 KIM 54538 -544.501 -283.337 96.9936 39.9974

32 MESA 55531 -993.391 -256.696 96.9883 39.9977

33 ORDW 56136 -549.552 -55.741 96.9935 39.9995

34 OURA 56203 -904.197 -168.246 96.9893 39.9985

35 PLEA 56591 -1005.94 -229.472 96.9881 39.9979

36 PUEB 56740 -633.961 -176.872 96.9925 39.9984

37 TYE 57320 -662.095 -242.254 96.9922 39.9978

38 SAGU 57337 -790.269 -176.061 96.9907 39.9984
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Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

39 SANL 57428 -726.777 -285.47 96.9914 39.9974

40 SHEP 57572 -714.046 -252.189 96.9916 39.9977

41 TELL 58204 -920.205 -215.382 96.9891 39.9981

42 TERC 58220 -708.229 -296.023 96.9916 39.9973

43 TRIN 58429 -642.489 -293.805 96.9924 39.9973

44 TRLK 58436 -646.185 -295.727 96.9924 39.9973

45 WALS 58781 -654.989 -262.821 96.9923 39.9976

46 WHIT 58997 -619.615 -250.12 96.9927 39.9977

47 ASHL 110281 684.787 -169.285 97.0081 39.9985

48 CAIR 111166 697.177 -301.436 97.0082 39.9973

49 CARM 111302 772.938 -177.782 97.0091 39.9984

50 CISN 111664 758.146 -151.446 97.0090 39.9986

51 FLOR 113109 751.801 -139.837 97.0089 39.9987

52 HARR 113879 762.044 -246.62 97.0090 39.9978

53 KASK 114629 650.464 -239.886 97.0077 39.9978

54 LAWR 114957 829.038 -128.708 97.0098 39.9988

55 MTCA 115888 827.797 -149.966 97.0098 39.9986

56 MURP 115983 682.261 -251.649 97.0081 39.9977

57 NEWT 116159 766.098 -72.902 97.0090 39.9993

58 REND 117187 731.633 -185.058 97.0086 39.9983

59 SMIT 118020 770.027 -283.638 97.0091 39.9974

60 SPAR 118147 658.275 -185.973 97.0078 39.9983

61 VAND 118781 685.449 -127.048 97.0081 39.9989

62 WEST 119193 778.655 -147.215 97.0092 39.9987

63 EVAN 122738 842.476 -172.871 97.0100 39.9984

64 NEWB 126151 855.854 -223.713 97.0101 39.9980

65 PRIN 127125 836.901 -153.449 97.0099 39.9986

66 STEN 128442 859.099 -156.613 97.0101 39.9986

67 JTML 128967 788.703 -239.572 97.0093 39.9978

68 ARLI 140326 -101.734 -271.373 96.9988 39.9976

69 BAZI 140620 -210.423 -201.758 96.9975 39.9982

70 BEAU 140637 59.762 -288.39 97.0007 39.9974

71 BONN 140957 211.236 -103.29 97.0025 39.9991

72 CALD 141233 -32.689 -330.586 96.9996 39.9970

73 CASS 141351 54.006 -217.645 97.0006 39.9980

74 CENT 141404 170.503 -206.038 97.0020 39.9981

75 CHAN 141427 150.257 -286.094 97.0018 39.9974

76 CLIN 141612 155.623 -157.682 97.0018 39.9986

77 COLL 141730 -265.465 -156.95 96.9969 39.9986

78 COLU 141740 220.541 -316.555 97.0026 39.9971
OG&E A-8 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

79 CONC 141867 58.918 -175.589 97.0007 39.9984

80 DODG 142164 -226.497 -277.655 96.9973 39.9975

81 ELKH 142432 -400.112 -321.784 96.9953 39.9971

82 ENGL 142560 -264.927 -324.066 96.9969 39.9971

83 ERIE 142582 162.669 -291.383 97.0019 39.9974

84 FALL 142686 83.491 -288.177 97.0010 39.9974

85 GALA 142938 -136.931 -176.83 96.9984 39.9984

86 GARD 142980 -304.059 -215.308 96.9964 39.9981

87 GREN 143248 64.308 -307.161 97.0008 39.9972

88 HAYS 143527 -190.307 -161.342 96.9978 39.9985

89 HEAL 143554 -292.133 -175.921 96.9966 39.9984

90 HILL 143686 214.018 -174.006 97.0025 39.9984

91 INDE 143954 139.335 -315.058 97.0016 39.9972

92 IOLA 143984 153.451 -269.438 97.0018 39.9976

93 JOHR 144104 134.784 -203.41 97.0016 39.9982

94 KANO 144178 -50.289 -181.177 96.9994 39.9984

95 KIOW 144341 -113.967 -329.843 96.9987 39.9970

96 MARI 145039 -4.343 -195.712 97.0000 39.9982

97 MELV 145210 137.104 -186.781 97.0016 39.9983

98 MILF 145306 39.504 -106.05 97.0005 39.9990

99 MOUD 145536 152.624 -318.136 97.0018 39.9971

100 OAKL 145888 -306.378 -96.814 96.9964 39.9991

101 OTTA 146128 158.639 -178.635 97.0019 39.9984

102 POMO 146498 143.864 -176.707 97.0017 39.9984

103 SALI 147160 -29.426 -166.908 96.9997 39.9985

104 SMOL 147551 -34.639 -171.31 96.9996 39.9985

105 STAN 147756 225.026 -164.85 97.0027 39.9985

106 SUBL 147922 -303.514 -292.808 96.9964 39.9974

107 TOPE 148167 139.116 -104.91 97.0016 39.9991

108 TRIB 148235 -387.855 -180.643 96.9954 39.9984

109 UNIO 148293 211.43 -272.537 97.0025 39.9975

110 WALL 148535 -376.076 -152.432 96.9956 39.9986

111 WICH 148830 -23.729 -288.579 96.9997 39.9974

112 WILS 148946 -111.502 -156.22 96.9987 39.9986

113 BENT 150611 781.608 -348.109 97.0092 39.9969

114 CALH 151227 865.268 -261.635 97.0102 39.9976

115 CLTN 151631 749.287 -365.634 97.0088 39.9967

116 HERN 153798 859.01 -352.458 97.0101 39.9968

117 MADI 155067 854.116 -265.064 97.0101 39.9976

118 PADU 156110 753.185 -293.024 97.0089 39.9974
OG&E A-9 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

119 PCTN 156580 834.464 -280.496 97.0099 39.9975

120 ALEX 160103 433.824 -959.253 97.0051 39.9913

121 BATN 160549 562.794 -1032.4 97.0066 39.9907

122 CALH 161411 436.113 -817.451 97.0052 39.9926

123 CLNT 161899 578.969 -999.986 97.0068 39.9910

124 JENA 164696 455.225 -912.366 97.0054 39.9918

125 LACM 165078 364.784 -1089.92 97.0043 39.9901

126 MIND 166244 346.708 -812.651 97.0041 39.9927

127 MONR 166314 463.225 -814.905 97.0055 39.9926

128 NATC 166582 369.451 -905.316 97.0044 39.9918

129 SHRE 168440 299.526 -831.143 97.0035 39.9925

130 WINN 169803 408.309 -884.596 97.0048 39.9920

131 BROK 221094 621.827 -914.236 97.0073 39.9917

132 CONE 221900 737.007 -823.513 97.0087 39.9926

133 JAKS 224472 650.361 -826.097 97.0077 39.9925

134 LEAK 224966 805.886 -943.78 97.0095 39.9915

135 MERI 225776 774.942 -814.558 97.0092 39.9926

136 SARD 227815 658.33 -593.661 97.0078 39.9946

137 SAUC 227840 763.399 -1005.93 97.0090 39.9909

138 TUPE 229003 753.571 -600.03 97.0089 39.9946

139 ADVA 230022 657.892 -298.102 97.0078 39.9973

140 ALEY 230088 505.348 -305.864 97.0060 39.9972

141 BOLI 230789 331.651 -291.689 97.0039 39.9974

142 CASV 231383 310.855 -392.187 97.0037 39.9965

143 CLER 231674 575.868 -302.209 97.0068 39.9973

144 CLTT 231711 307.465 -190.83 97.0036 39.9983

145 COLU 231791 421.287 -155.672 97.0050 39.9986

146 DREX 232331 228.23 -185.776 97.0027 39.9983

147 ELM 232568 257.758 -159.419 97.0030 39.9986

148 FULT 233079 470.408 -150.668 97.0056 39.9986

149 HOME 233999 619.93 -415.469 97.0073 39.9962

150 JEFF 234271 424.774 -172.095 97.0050 39.9984

151 JOPL 234315 238.245 -318.262 97.0028 39.9971

152 LEBA 234825 402.239 -276.263 97.0048 39.9975

153 LICK 234919 480.849 -280.775 97.0057 39.9975

154 LOCK 235027 302.048 -300.612 97.0036 39.9973

155 MALD 235207 659.982 -377.876 97.0078 39.9966

156 MARS 235298 332.062 -94.655 97.0039 39.9991

157 MAFD 235307 391.968 -300.033 97.0046 39.9973

158 MCES 235415 471.737 -143.942 97.0056 39.9987
OG&E A-10 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

159 MILL 235594 309.516 -311.398 97.0037 39.9972

160 MTGV 235834 426.937 -310.43 97.0050 39.9972

161 NVAD 235987 243.915 -272.715 97.0029 39.9975

162 OZRK 236460 349.133 -390.626 97.0041 39.9965

163 PDTD 236777 334.055 -265.018 97.0039 39.9976

164 POTO 236826 572.215 -251.455 97.0068 39.9977

165 ROLL 237263 484.503 -253.958 97.0057 39.9977

166 ROSE 237300 500.59 -175.393 97.0059 39.9984

167 SALE 237506 498.94 -274.122 97.0059 39.9975

168 SENE 237656 233.959 -383.703 97.0028 39.9965

169 SPRC 237967 238.112 -373.616 97.0028 39.9966

170 SPVL 237976 332.385 -309.374 97.0039 39.9972

171 STEE 238043 503.354 -205.135 97.0059 39.9981

172 STOK 238082 310.911 -279.239 97.0037 39.9975

173 SWSP 238223 324.053 -150.325 97.0038 39.9986

174 TRKD 238252 340.418 -395.428 97.0040 39.9964

175 TRUM 238466 326.883 -197.796 97.0039 39.9982

176 UNIT 238524 238.567 -154.494 97.0028 39.9986

177 VIBU 238609 519.633 -267.258 97.0061 39.9976

178 VIEN 238620 470.383 -193.872 97.0056 39.9983

179 WAPP 238700 606.68 -358.746 97.0072 39.9968

180 WASG 238746 556.425 -164.993 97.0066 39.9985

181 WEST 238880 489.373 -377.809 97.0058 39.9966

182 ALBU 290234 -869.46 -501.713 96.9897 39.9955

183 ARTE 290600 -689.529 -773.897 96.9919 39.9930

184 AUGU 290640 -973.07 -598.391 96.9885 39.9946

185 CARL 291469 -680.335 -811.474 96.9920 39.9927

186 CARR 291515 -819.836 -665.132 96.9903 39.9940

187 CLAY 291887 -547.124 -374.102 96.9935 39.9966

188 CLOV 291939 -566.973 -599.296 96.9933 39.9946

189 CUBA 292241 -890.304 -392.495 96.9895 39.9965

190 CUBE 292250 -951.142 -489.293 96.9888 39.9956

191 DEMI 292436 -1007.99 -799.087 96.9881 39.9928

192 DURA 292665 -767.148 -577.618 96.9909 39.9948

193 EANT 292700 -735.089 -366.94 96.9913 39.9967

194 LAVG 294862 -738.245 -461.163 96.9913 39.9958

195 PROG 297094 -811.39 -578.971 96.9904 39.9948

196 RAMO 297254 -733.737 -615.175 96.9913 39.9944

197 ROSW 297610 -698.544 -712.921 96.9918 39.9936

198 ROY 297638 -644.735 -422.422 96.9924 39.9962
OG&E A-11 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

199 SANT 298085 -807.375 -445.708 96.9905 39.9960

200 SPRI 298501 -676.681 -374.272 96.9920 39.9966

201 STAY 298518 -810.491 -495.501 96.9904 39.9955

202 TNMN 299031 -912.488 -413.425 96.9892 39.9963

203 TUCU 299156 -604.359 -508.834 96.9929 39.9954

204 WAST 299569 -638.605 -820.288 96.9925 39.9926

205 WISD 299686 -856.967 -756.366 96.9899 39.9932

206 AIRS 340179 -212.731 -597.062 96.9975 39.9946

207 ARDM 340292 -12.242 -645.633 96.9999 39.9942

208 BENG 340670 174.368 -568.011 97.0021 39.9949

209 CANE 341437 71.857 -637.935 97.0009 39.9942

210 CHRT 341544 203.233 -632.067 97.0024 39.9943

211 CHAN 341684 10.494 -475.655 97.0001 39.9957

212 CHIK 341750 -83.175 -547.26 96.9990 39.9951

213 CCTY 342334 -165 -479.536 96.9981 39.9957

214 DUNC 342654 -88.38 -610.04 96.9990 39.9945

215 ELKC 342849 -216.769 -507.879 96.9974 39.9954

216 FORT 343281 -129.964 -541.113 96.9985 39.9951

217 GEAR 343497 -118.53 -482.187 96.9986 39.9956

218 HENN 344052 -31.964 -601.206 96.9996 39.9946

219 HOBA 344202 -189.062 -547.36 96.9978 39.9951

220 KING 344865 24.538 -664.103 97.0003 39.9940

221 LKEU 344975 141.702 -520.6 97.0017 39.9953

222 LEHI 345108 71.634 -612.05 97.0009 39.9945

223 MACI 345463 -254.63 -466.154 96.9970 39.9958

224 MALL 345589 -55.127 -425.644 96.9994 39.9962

225 MAYF 345648 -258.49 -512.583 96.9970 39.9954

226 MUSK 346130 149.764 -466.905 97.0018 39.9958

227 NOWA 346485 121.551 -364.038 97.0014 39.9967

228 OKAR 346620 -88.424 -473.338 96.9990 39.9957

229 OKEM 346638 63.188 -504.958 97.0008 39.9954

230 OKLA 346661 -54.198 -510.562 96.9994 39.9954

231 PAOL 346859 -23.665 -573.142 96.9997 39.9948

232 PAWH 346935 57.704 -369.174 97.0007 39.9967

233 PAWN 346944 16.927 -398.139 97.0002 39.9964

234 PONC 347196 -8.871 -363.068 96.9999 39.9967

235 PRYO 347309 150.763 -407.824 97.0018 39.9963

236 SHAT 348101 -256.963 -407.368 96.9970 39.9963

237 STIG 348497 171.02 -523.736 97.0020 39.9953

238 TULS 348992 99.361 -419.873 97.0012 39.9962
OG&E A-12 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

239 TUSK 349023 156.629 -592.395 97.0019 39.9946

240 WMWR 349629 -156.42 -581.308 96.9982 39.9947

241 WOLF 349748 30.212 -538.388 97.0004 39.9951

242 BOLI 400876 760.886 -500.256 97.0090 39.9955

243 BROW 401150 710.048 -480.346 97.0084 39.9957

244 CETR 401587 877.35 -456.294 97.0104 39.9959

245 DICS 402489 872.14 -391.132 97.0103 39.9965

246 DYER 402680 695.792 -409.316 97.0082 39.9963

247 GRNF 403697 760.795 -395.69 97.0090 39.9964

248 JSNN 404561 765.932 -476.414 97.0090 39.9957

249 LWER 405089 885.291 -487.757 97.0105 39.9956

250 LEXI 405210 790.003 -471.897 97.0093 39.9957

251 MASO 405720 694.163 -496.166 97.0082 39.9955

252 MEMP 405954 671.8 -522.492 97.0079 39.9953

253 MWFO 405956 681.292 -516.15 97.0080 39.9953

254 MUNF 406358 678.65 -495.241 97.0080 39.9955

255 SAMB 408065 697.077 -382.536 97.0082 39.9965

256 SAVA 408108 800.788 -498.682 97.0095 39.9955

257 UNCY 409219 711.595 -384.605 97.0084 39.9965

258 ABIL 410016 -251.753 -836.027 96.9970 39.9924

259 AMAR 410211 -425.302 -517.839 96.9950 39.9953

260 AUST 410428 -67.587 -1075.97 96.9992 39.9903

261 BRWN 411136 -43.861 -1571.39 96.9995 39.9858

262 COST 411889 60.611 -1044.72 97.0007 39.9906

263 COCR 412015 -51.832 -1360.01 96.9994 39.9877

264 CROS 412131 -204.599 -868.469 96.9976 39.9922

265 DFWT 412242 -1.867 -786.341 97.0000 39.9929

266 EAST 412715 -171.024 -840.253 96.9980 39.9924

267 ELPA 412797 -886.583 -860.763 96.9895 39.9922

268 HICO 414137 -97.323 -888.181 96.9989 39.9920

269 HUST 414300 157.976 -1108.38 97.0019 39.9900

270 KRES 414880 -434.746 -611.717 96.9949 39.9945

271 LKCK 414975 99.734 -693.521 97.0012 39.9937

272 LNGV 415348 220.962 -844.674 97.0026 39.9924

273 LUFK 415424 214.652 -969.69 97.0025 39.9912

274 MATH 415661 -86.438 -1330.47 96.9990 39.9880

275 MIDR 415890 -489.385 -878.123 96.9942 39.9921

276 MTLK 416104 -672.024 -1008.98 96.9921 39.9909

277 NACO 416177 223.065 -925.966 97.0026 39.9916

278 NAVA 416210 28.358 -892.028 97.0003 39.9919
OG&E A-13 Trinity Consultants

CALMET Processing Protocol 083701.0004

Number

Station 

Acronym

Station 

ID

LCC 

East 

(km)

LCC 

North

(km) Long Lat

279 NEWB 416270 239.111 -721.818 97.0028 39.9935

280 BPAT 417174 288.962 -1110.65 97.0034 39.9900

281 RANK 417431 -472.048 -959.488 96.9944 39.9913

282 SAAG 417943 -333.338 -952.54 96.9961 39.9914

283 SAAT 417945 -143.322 -1161.27 96.9983 39.9895

284 SHEF 418252 -463.759 -1019.19 96.9945 39.9908

285 STEP 418623 -112.988 -857.918 96.9987 39.9922

286 STER 418630 -376.683 -897.195 96.9956 39.9919

287 VALE 419270 -720.749 -1015.17 96.9915 39.9908

288 VICT 419364 6.882 -1236.45 97.0001 39.9888

289 WACO 419419 -21.834 -928.823 96.9997 39.9916

290 WATR 419499 -353.767 -916.015 96.9958 39.9917

291 WHEE 419665 57.489 -1008.99 97.0007 39.9909

292 WPDM 419916 262.792 -737.786 97.0031 39.9933

293 DORA 232302 433.256 -378.797 97.0051 39.9966

294 DIXN 112353 756.057 -267.193 97.0089 39.9976

295 DAUP 12172 864.408 -1050.41 97.0102 39.9905

296 FREV 123104 847.031 -117.884 97.0100 39.9989

297 WARR 18673 890.447 -788.703 97.0105 39.9929

298 MDTN 235562 493.264 -87.222 97.0058 39.9992
OG&E A-14 Trinity Consultants

CALMET Processing Protocol 083701.0004

TABLE A-4. LIST OF OVER WATER METEOROLOGICAL STATIONS

Number

Station 

ID

Input file 

Name

LCC 

East 

(km)

LCC North

(km) Long Lat

1 42001 42001 746.874 -1541.35 89.67 25.9

2 42002 42002 265.486 -1650.616 94.42 25.19

3 42007 42007 795.674 -1063.667 88.77 30.09

4 42019 42019 163.178 -1342.917 95.36 27.91

5 42020 42020 30.212 -1453.738 96.7 26.94

6 42035 42035 254.465 -1193.539 94.41 29.25

7 42040 42040 859.497 -1160.066 88.21 29.18

8 BURL1 42045 743.116 -1202.117 89.43 28.9

9 DPIA1 42046 861.385 -1039.466 88.07 30.25

10 GDIL1 42047 687.984 -1164.910 89.96 29.27

11 PTAT2 42048 -4.980 -1353.398 97.05 27.83

12 SRST2 42049 288.163 -1175.682 94.05 29.67
Domtar A.W. LLC B-1 Trinity Consultants 

Ashdown Mill 

APPENDIX B – DETAILED CONTROL COST CALCULATIONS

 ADD-ON SCRUBBER / WESP FOR NO. 2 POWER BOILER SO2 CONTROL

SNCR for No. 1 Power Boiler NOX Control 

SNCR for No. 2 Power Boiler NOX Control 
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 6,844

Purchased Equipment Cost (PEC)1 $5,270,000

Total Capital Investment (TCI) = PEC + Costs to Retrofit11 $18,445,000

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

life

0.09

a. Equipment CRF, 20-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 (normal)

 Labor For ESP plate area < 50,000 ft2

 = $4125 $4,125

 Material = 0.01 × Purchased Equipment Cost $52,700

 Maintenance (contractor labor and materials - 

 periodic plate realignment and cleaning)

Estimate based on costs to maintain existing WESP $310,000

 Utilities

 Fan7 = 0.000181× Q × ΔP × θ' × Costelect $63,336

 ESP operating power8 = 1.94 × 10-3 × A × θ' $112,896

 Pump9 = 0.746 × Ql

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

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

 Wastewater treatment = $3.25/1000 gal3

 × Annual water use $6,092,425

 Sorbent (caustic) usage12 $2,300,000

Total Variable (Direct) Annual Cost $9,160,526

Fixed (Indirect) Costs, IC

 Administrative charges 2% of Total Capital Investment $368,900

 Property tax 1% of Total Capital Investment $184,450

 Insurance 1% of Total Capital Investment $184,450

 Overhead 60% of total labor and material costs $34,095

Total Fixed (Indirect) Costs $771,895

Annualized Capital Cost Capital Recovery Factor * Total Capital Investment $1,741,078

TOTAL ANNUAL COST $11,673,498

Add-On Scrubber/WESP Capital and O&M Cost Estimate for No. 2 Power Boiler
Notes:

1: From A.H. Lundberg Associates, Inc. Budget Proposal, June 22, 2012

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.

4: For ESP Plate Area:

 ESCA (Specific Collecting Area, English Units) = -ln(p)/we × 5.080 × Q

 p = 1 - (Eff/100)

 Q = system flow rate (kacfm)

7: For fan power cost:

 Q = system flow rate (acfm)

 ΔP = system pressure drop (in. H2O)

 θ' = annual operating time (h/yr)

8: For ESP power cost 

 A = ESP plate area (ft2

)

 θ' = annual operating time (h/yr)

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.

12: Estimate from Domtar's engineers.

13: Contracted labor rate at the Ashdown Mill.

 we = effective migration velocity (m/s), assume we = 31.4 cm/s for bituminous coal fly ash for a design efficiency of 95% from Table 3.3 (the most 

representative of all the possibilities provided)

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

Electrostatic Precipitators 

 Assuming ΔP = 0.38 in. H2O for inlet diffuser plate, inlet and outlet transitions, baffles and plates from Table 3.11, assume ductwork contributres 4.1 

in. H2O (based on EPA Manual). Total pressure drop is 4.48 in. H2O

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/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)9 2,657 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 0.09 0.09 0.09

a. Equipment CRF, 20-yr life, 7% interest

Cost Index

11

a. 2011 Cost Index 585

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) $1,891,870 $1,699,054 $1,506,237

Indirect Installation Costs ($)

General Facilities 0.05 × A $94,594 $84,953 $75,312

Engineering and Home Office Fees 0.10 × A $189,187 $169,905 $150,624

Process Contingency 0.05 × A $94,594 $84,953 $75,312

Total Indirect Installation Costs (B)

= General Facilities Cost + Engineering and Home Office Fees + 

Process Contingency $378,374 $339,811 $301,247

Other Installation Costs ($)

Project Contingency (C) C = 0.15 × (A + B) $340,536.61 $305,829.64 $271,122.68

Total Plant Cost (D) D = A + B + C $2,610,781 $2,344,694 $2,078,607

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) $52,216 $46,894 $41,572.14

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 $2,709,252 $2,425,223 $2,153,814

Annual Costs ($)

Annual Maintenance Cost (J) J = 0.015 × TCI $40,639 $36,378 $32,307

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)17 qwater = (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 $1,295,447 $948,819 $944,748

Indirect Annual Costs (IDAC)/Annualized 

Capital Cost IDAC = CFR × TCI $255,734 $228,924 $203,305

Total Annualized Costs (TAC) TAC = DAC + IDAC $1,551,181 $1,177,743 $1,148,053

Total Uncontrolled NOx Emissions (tpy) 493 493 493

Removal Efficiency 45% 32.5% 20.0%

Pollutant Removed(tpy) 222 160 99

Cost Effectiveness ($/ton removed) $6,995 $7,354 $11,648.87

Selective Non-Catalytic Reduction 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=

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

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)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 0.09 0.09

a. Equipment CRF, 20-yr life, 7% interest

Cost Index11

a. 2011 Cost Index 585

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) $2,025,699 $1,890,829

Indirect Installation Costs ($)

General Facilities 0.05 × A $101,285 $94,541

Engineering and Home Office Fees 0.10 × A $202,570 $189,083

Process Contingency 0.05 × A $101,285 $94,541

Total Indirect Installation Costs (B)

= General Facilities Cost + Engineering and Home Office Fees + 

Process Contingency $405,140 $378,166

Other Installation Costs ($)

Project Contingency (C) C = 0.15 × (A + B) $364,626 $340,349

Total Plant Cost (D) D = A + B + C $2,795,465 $2,609,344

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) $55,909 $52,187

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 $2,879,473 $2,683,498

Annual Costs ($)

Annual Maintenance Cost (J) J = 0.015 × TCI $43,192 $40,252

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 × 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 $794,354 $627,496

Indirect Annual Costs (IDAC)/Annualized Capital Cost IDAC = CFR × TCI $271,802 $253,303

Total Annualized Costs (TAC) TAC = DAC + IDAC $1,066,156 $880,799

Total Uncontrolled NOx Emissions (tpy) 2240 2240

Removal Effciency 35.0% 27.5%

Pollutant Removed(tpy) 784 616

Cost Effectiveness ($/ton removed) $1,360 $1,430

Selective Non-Catalytic Reduction 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.

13 Five-yr average urea cost = $356.11/metric ton, from http://www.indexmundi.com/commodities/?commodity=urea&months=180

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

Equates to $1.54/gal

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.
Domtar A.W. LLC C-1 Trinity Consultants 

Ashdown Mill 

APPENDIX C – DETAILED MODELING RESULTS

TABLE C-1. BASELINE VISIBILITY IMPAIRMENT

Unit 

Class 

I Area Year 

Number 

of Days ≥

0.5 Δdv 

Maximum

(Δdv) 

98th

%tile 

(Δdv) 

Species Contribution to 98th %tile 

% 

SO4

% 

NO3

% 

PM10 

% 

NO2

No. 1 

Power 

Boiler 

CACR 2001 0 0.266 0.190 3.28 88.20 2.49 6.03 

2002 0 0.238 0.107 2.99 87.98 2.90 6.13 

2003 0 0.173 0.097 3.88 87.94 2.76 5.42 

UPBU 2001 0 0.038 0.013 9.32 83.85 3.54 3.29 

2002 0 0.052 0.022 3.42 93.10 1.60 1.88 

2003 0 0.033 0.014 2.23 91.17 2.46 4.14 

HERC 2001 0 0.035 0.007 5.63 91.96 1.87 0.54 

2002 0 0.045 0.012 3.88 93.11 1.44 1.56 

2003 0 0.027 0.012 4.50 88.99 2.75 3.76 

MING 2001 0 0.013 0.006 4.61 93.01 1.90 0.48 

2002 0 0.022 0.008 5.82 91.51 1.88 0.79 

2003 0 0.035 0.006 3.09 92.62 2.17 2.12 

No. 2 

Power 

Boiler 

CACR 2001 28 1.340 0.844 22.04 70.68 4.58 2.69 

2002 13 1.603 0.673 40.41 44.82 8.10 6.67 

2003 8 0.852 0.604 25.77 60.15 7.64 6.44 

UPBU 2001 0 0.349 0.146 76.99 20.76 2.26 0.00 

2002 0 0.332 0.127 30.27 57.93 7.56 4.24 

2003 0 0.381 0.117 41.02 54.57 3.58 0.83 

HERC 2001 0 0.239 0.080 44.59 51.57 3.70 0.13 

2002 0 0.329 0.083 38.51 55.05 5.24 1.20 

2003 0 0.196 0.105 61.17 37.68 1.06 0.09 

MING 2001 0 0.139 0.065 81.46 15.47 3.07 0.00 

2002 0 0.162 0.054 38.98 57.12 3.40 0.50 

2003 0 0.246 0.055 93.42 3.28 3.29 0.01 
Domtar A.W. LLC D-1 Trinity Consultants 

Ashdown Mill 

APPENDIX D – REFERENCE DOCUMENTS

Vendor (“Lundberg”) Information/Quote for No. 2 Power Boiler SO2 Control