Oklahoma Gas & Electric 

Muskogee Generating Station 

Best Available Retrofit Control Technology Evaluation 

Prepared by: Sargent & Lundy LLC 

Chicago, Illinois

Trinity Consultants 

Oklahoma City, Oklahoma 

May 28, 2008 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

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EXECUTIVE SUMMARY 

OG&E’s Muskogee Generating Station is located at 5501 Three Forks Road near Muskogee, 

Oklahoma. The station has a total of four (4) generating units designated as Muskogee Units 3, 4, 5 

and 6. Muskogee Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit. 

Muskogee Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of 

Muskogee Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit 

5 coming on-line in 1978. Construction commenced on Muskogee Unit 6 in 1980, and Unit 6 

commenced commercial operation in mid-1984. All three coal-fired units at the Muskogee 

Generating Station are dry bottom tangentially-fired pulverized coal (PC) boilers. The boilers fire 

subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for 

particulate control. 

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the 

“Regional Haze Rule” 70 FR 39104). The Regional Haze Rule requires certain States, including 

Oklahoma, to develop programs to assure reasonable progress toward meeting the national goal of 

preventing any future, and remedying any existing, impairment of visibility in Class I Areas. The 

Regional Haze Rule requires states to submit a plan to implement the regional haze requirements 

(the Regional Haze SIP). The Regional Haze SIP must provide for a Best Available Retrofit 

Technology (BART) analysis of any existing stationary facility that might cause or contribute to 

impairment of visibility in a Class I Area. 

BART-eligible sources include those sources that: 

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; 

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and 

(3) whose operations fall within one or more of the specifically listed source categories in 40 

CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr 

heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input). 

Muskogee Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BARTeligible source. Muskogee Unit 6 was not in existence prior to August 7, 1977; therefore, Unit 6 is 

not a BART-eligible source. Muskogee Units 4 & 5 are fossil-fuel fired boilers with heat inputs 

greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 (i.e., construction 

of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of 

existing emissions data, both units have the potential to emit more than 250 tons per year of 

visibility impairing pollutants. Therefore, Muskogee Units 4 & 5 meet the definition of a BARTeligible source. 
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BART is required for any BART-eligible source that emits any air pollutant which may reasonably 

be anticipated to cause or contribute to any impairment of visibility in a Class I Area. EPA has 

determined that an individual source will be considered to “contribute to visibility impairment” if 

emissions from the source result in a change in visibility, measured as a change in deciviews (∆-

dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling previously 

conducted by OG&E determined that the maximum predicted visibility impacts from Muskogee 

Units 4 & 5 exceeded the 0.5 ∆-dv threshold at the Upper Buffalo, Caney Creek, and Wichita 

Mountains Class I Areas. Therefore, Muskogee Units 4 & 5 were determined to be BARTapplicable sources, subject to the BART determination requirements. 

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 

(Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use 

the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants 

having a total generating capacity in excess of 750 MW. The BART determination process 

described in Appendix Y includes the following steps: 

Step 1. Identify All Available Retrofit Control Technologies. 

Step 2. Eliminate Technically Infeasible Options. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 4. Evaluate Impacts and Document the Results. 

Step 5. Evaluate Visibility Impacts. 

This report is the BART determination for Muskogee Units 4 & 5. Because the Muskogee 

Generating Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines 

were used to prepare the BART determination. Based on an evaluation of potentially feasible 

retrofit control technologies, including an assessment of the costs and visibility improvements 

associated therewith, OG&E is proposing the BART control technologies and emission rates listed 

in Table ES-1. 

Table ES-1 

Muskogee Units 4 & 5 

Proposed BART Permit Limits and Control Technologies 

Pollutant Proposed BART 

 Emission Limit 

Proposed BART Technology 

NOx 0.15 lb/mmBtu 

(30-day average) 

Combustion controls including LNB 

and OFA 

SO2 Existing Permit Limits Low sulfur subbituminous coal 

PM10 filterable Existing Permit Limits NA 
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1.0 INTRODUCTION 

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional 

Haze Regulations and Guidelines for Best Available Retrofit Technology Determinations” (the 

“Regional Haze Rule” 70 FR 39104). EPA issued the Regional Haze Rule under the authority and 

requirements of sections 169A and 169B of the Clean Air Act (CAA). Sections 169A and 169B 

require EPA to address regional haze visibility impairment in 156 federally-protected parks and 

wilderness areas (Class I Areas). As mandated by the CAA, the Regional Haze Rule requires 

certain large stationary sources to install the best available retrofit technology (BART) to reduce 

emissions of pollutants that may impact visibility in a Class I Area. 

The Regional Haze Rule requires certain States, including Oklahoma, to develop programs to 

assure reasonable progress toward meeting the national goal of preventing any future, and 

remedying any existing, impairment of visibility in Class I Areas. The Regional Haze Rule requires 

states to submit a plan to implement the regional haze requirements (the Regional Haze SIP). The 

Regional Haze SIP must provide for a BART analysis of any existing stationary facility that might 

cause or contribute to impairment of visibility in a Class I Area. To address the requirements for 

BART, Oklahoma must: 

3⁄4 Identify all BART-eligible sources within the State. 

3⁄4 Determine whether each BART-eligible source emits any air pollutant which may 

reasonably be anticipated to cause or contribute to any impairment of visibility in a 

Class I Area. BART-eligible sources which may reasonably be anticipated to cause or 

contribute to visibility impairment are classified as BART-applicable sources. 

3⁄4 Require each BART-applicable source to identify, install, operate, and maintain BART 

controls. 

1.1 OG&E’s Muskogee Generating Station 

OG&E’s Muskogee Generating Station is located at 5501 Three Forks Road near Muskogee, 

Oklahoma. The station has a total of four (4) generating units designated as Muskogee Units 3, 4, 5 

and 6. Muskogee Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit. 

Muskogee Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of 

Muskogee Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit 

5 coming on-line in 1978. Construction commenced on Muskogee Unit 6 in 1980, and Unit 6 

commenced commercial operation in mid-1984. All three coal-fired units at the Muskogee 

Generating Station are dry bottom tangentially-fired pulverized coal (PC) boilers. The boilers fire 

subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for 

particulate control. 
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1.2 BART Applicability Review 

BART-eligible sources include those sources that: 

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; 

(2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and 

(3) whose operations fall within one or more of the specifically listed source categories in 40 

CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr 

heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input). 

Muskogee Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BARTeligible source. Muskogee Unit 6 was not in existence prior to August 7, 1977; therefore, Unit 6 is 

not a BART-eligible source. Muskogee Units 4 & 5 are fossil-fuel fired boilers with heat inputs 

greater than 250 mmBtu/hr. Both units were in existence prior to August 7, 1977 (i.e., construction 

of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of 

existing emissions data, both units have the potential to emit more than 250 tons per year of 

visibility impairing pollutants. Therefore, Muskogee Units 4 & 5 meet the definition of a BARTeligible source. 

BART is required for any BART-eligible source that emits any air pollutant which may reasonably 

be anticipated to cause or contribute to any impairment of visibility in a Class I Area. EPA has 

determined that an individual source will be considered to “cause visibility impairment” if 

emissions from the source result in a change in visibility, measured as a change in deciviews (∆-

dv), that is greater than or equal to 1.0 dv on the visibility in a Class I area. An individual source is 

considered to “contribute to visibility impairment” if emissions from the source result in a ∆-dv 

change greater than or equal to 0.5 dv in a Class I area. Class I areas nearest the Muskogee Station 

include: 

Distance from 

Class I Area Name Muskogee Station (km)

• Upper Buffalo Wilderness Area (Arkansas) 165 

• Caney Creek Wilderness Area (Arkansas) 181 

• Hercules-Glades Wilderness Area (Missouri) 231 

• Wichita Mountains National Wildlife Refuge (Oklahoma) 325 

Visibility impact modeling was conducted by OG&E to determine the baseline predicted maximum 

98th percentile ∆-dv visibility impact from Muskogee Units 4 & 5. The maximum predicted 

visibility impact associated with the Muskogee Station exceeded the 0.5 ∆-dv threshold at the 

Upper Buffalo, Caney Creek, and Wichita Mountains Class I Areas. Therefore, the facility was 

determined to be a BART-applicable source subject to the BART determination requirements. 
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1.3 BART Requirements 

A determination of BART must be based on an analysis of the best system of continuous emission 

control technology available and associated emission reductions achievable. The BART analysis 

must take into consideration: (1) the technology available; (2) the costs of compliance; (3) the 

energy and non-air-quality environmental impacts of compliance; (4) any pollution control 

equipment in use at the source; (5) the remaining useful life of the source; and (6) the degree of 

improvement in visibility which may reasonably be anticipated to result from the use of such 

technology. 

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 

(Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use 

the Appendix Y guidelines to make BART determinations for fossil-fuel-fired generating plants 

having a total generating capacity in excess of 750 MW, but are not required to use the guidelines 

when making BART determinations for other types of sources. Because the Muskogee Generating 

Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used 

to prepare the BART determination. 

 

The Appendix Y guidelines for BART determinations identify the following five steps in a case-bycase BART analysis: 

Step 1. Identify All Available Retrofit Control Technologies. 

Step 2. Eliminate Technically Infeasible Options. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 4. Evaluate Impacts and Document the Results. 

Step 5. Evaluate Visibility Impacts. 

A more detailed description of each step is provided below. 

Step 1. Identify all available retrofit control technologies. 

Available retrofit control options are those air pollution control technologies with a practical 

potential for application to the emissions unit and the regulated pollutant under evaluation (70 

FR 39164 col. 1). Step 1 of the BART determination requires applicants to identify potentially 

applicable retrofit control technologies that represent the full range of demonstrated 

alternatives. Potentially applicable retrofit control alternatives can include pollution prevention 

strategies, the use of add-on controls, or a combination of control strategies. Control 

technologies required under the new source review (NSR) program as best available control 

technology (BACT) or lowest achievable emission rate (LAER) are available for BART 

purposes and must be included as potential control alternatives. However, EPA does not 
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consider BART as a requirement to redesign the source when considering available control 

alternatives. 

In an effort to identify all potentially applicable retrofit technologies appropriate for use at each 

station, information sources consulted included, but were not necessarily limited to, the 

following: 

3⁄4 EPA's RACT/BACT/LAER Clearinghouse (RBLC) Database; 

3⁄4 New & Emerging Environmental Technologies (NEET) Database; 

3⁄4 EPA’s New Source Review bulletin board; 

3⁄4 Information from control technology vendors and engineering/environmental consultants; 

3⁄4 Federal and State new source review permits and BACT determinations for coal-fired 

power plants; 

3⁄4 Recently submitted Federal and State new source review permit applications submitted for 

coal-fired generating projects; and 

3⁄4 Technical journals, reports, newsletters and air pollution control seminars. 

Step 2. Eliminate Technically Infeasible Options. 

In step 2 of the BART determination, the technical feasibility of each potential retrofit 

technology is evaluated. Control technologies are considered technically feasible if either (1) 

they have been installed and operated successfully for the type of source under review under 

similar conditions, or (2) the technology could be applied to the source under review. A 

demonstration of technical infeasibility must be based on physical, chemical and engineering 

principles, and must show that technical difficulties would preclude the successful use of the 

control option on the emission unit under consideration. The economics of an option are not 

considered in the determination of technical feasibility/infeasibility. Options that are 

technically infeasible for the intended application are eliminated from further review. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 3 of the BART determination involves evaluating the control effectiveness of all the 

technically feasible control alternatives identified in Step 2 for the pollutant and emissions 

under review. Control effectiveness is generally expressed as the rate at which a pollutant is 

emitted after the control system has been installed. The most effective control option is the 

system that achieves the lowest emissions level. 

Step 4. Evaluate Impacts and Document the Results. 

Step 4 of the BART determination involves an evaluation of potential impacts associated with 

the technically feasible retrofit technologies. The following evaluations should be conducted 

for each technically feasible technology: 
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(1) costs of compliance; 

(2) energy impacts; and 

(3) non-air quality environmental impacts. 

Costs of Compliance

The economic analysis performed as part of the BART determination examines the costeffectiveness of each control technology, on a dollar per ton of pollutant removed basis. 

Annual emissions using a particular control device are subtracted from baseline emissions 

to calculate tons of pollutant controlled per year. Annual costs are calculated by adding 

annual operation and maintenance costs to the annualized capital cost of an option. Cost 

effectiveness ($/ton) of an option is simply the annual cost ($/yr) divided by the annual 

pollution controlled (ton/yr). 

In addition to the cost effectiveness relative to the base case, the incremental costeffectiveness to go from one level of control to the next more stringent level of control may 

also be calculated to evaluate the cost effectiveness of the more stringent control. 

Energy Impact Analysis

The energy requirements of a control technology should be examined to determine whether 

the use of that technology results in any significant or unusual energy penalties or benefits. 

Two forms of energy impacts associated with a control option can normally be quantified. 

First, increases in energy consumption resulting from increased heat rate may be shown as 

total Btu’s or fuel consumed per year or as Btu’s per ton of pollutant controlled. Second, 

the installation of a particular control option may reduce the output and/or reliability of 

equipment. This reduction would result in decreased electricity available to the power grid 

and/or increased fuel consumption due to use of less efficient electrical and steam 

generation methods. 

Non-Air Quality Environmental Impact Analysis

The primary purpose of the environmental impact analysis is to assess collateral 

environmental impacts due to control of the regulated pollutant in question. Environmental 

impacts may include solid or hazardous waste generation, discharges of polluted water 

from a control device, increased water consumption, and land use impacts from waste 

disposal. 
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Impact analyses conducted in step 4 should take into consideration the remaining useful life of 

the source. For example, the remaining useful life of the source may affect the cost analysis 

(specifically, the annualized costs of retrofit controls). 

Step 5. Evaluate Visibility Impacts. 

Step 5 of the BART determination addresses the degree of improvement in visibility that may 

reasonably be anticipated to result from the use of a particular control technology. CALPUFF 

modeling, or other appropriate dispersion modeling, should be used to determine the visibility 

improvement expected from the potential BART control technology applied to the source. 

Modeling should be conducted for SO2, NOx, and direct PM emissions (PM2.5 and/or PM10). 

Although visibility improvement must be weighted among the five factors in a BART 

determination (along with the costs of compliance, energy and non-air-quality environmental 

impacts, existing pollution control technologies in use at the source, and the remaining life of 

the source) only potential retrofit control technologies meeting the other four factors were 

evaluated for visibility impacts. For example, potential retrofit technologies that are not 

technically feasible or cost effective will not be evaluated for visibility impacts. The final 

regulation also states that sources that elect to apply the most stringent controls available need 

not conduct an air quality modeling analysis for the purpose of determining its visibility 

impacts (see, 70 FR 39170 col. 1). 

BART control technologies and corresponding emission rates are established based on 

information developed from the 5-step BART determination process described above. 

 

2.0 MUSKOGEE UNITS 4 & 5 BART DETERMINATION METHODOLOGY 

The BART determination process described in Appendix Y of 40 CFR Part 51 (summarized above) 

was used to identify BART controls for Muskogee Units 4 & 5. The methodology was used to 

evaluate BART control technologies for NOx, SO2, and PM10. Existing operating parameters and 

baseline emissions for Muskogee Units 4 & 5 are summarized in Table 2-1. The operating 

parameters and emissions summarized in Table 2-1 form the basis for the Muskogee Units 4 & 5 

BART determination. 

Baseline emissions from Muskogee Units 4 & 5 were developed based on an evaluation of actual 

emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance 

with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling 

analysis to determine visibility impairment impacts should reflect steady-state operating conditions 
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during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the 

highest 24-hour block emissions reported during the baseline period. Baseline emission rates 

(lb/mmBtu) were calculated by dividing the maximum hourly mass emission rate by the full load 

heat input to the boiler. 

Table 2-1 

Plant Operating Parameters for BART Evaluation

Parameter Muskogee Unit 4 Muskogee Unit 5 

Plant Configuration Pulverized Coal-Fired Boiler Pulverized Coal-Fired Boiler 

Firing Configuration tangentially-fired tangentially-fired 

Plant Output 572 MW (gross) 572 MW (gross) 

Maximum Input to Boiler 5,480 mmBtu/hr 5,480 mmBtu/hr 

Primary Fuel subbituminous coal subbituminous coal 

Existing NOx Controls combustion controls combustion controls 

Existing SO2 Controls low-sulfur coal low-sulfur coal 

Existing PM10 Controls electrostatic precipitator electrostatic precipitator 

Baseline Emissions 

Pollutant Baseline Actual Emissions Baseline Actual Emissions 

 lb/hr lb/mmBtu lb/hr lb/mmBtu 

NOx 2,710 0.495 2,863 0.522 

SO2 4,384 0.800 4,657 0.850 

PM10 101 0.018 134 0.024 

2.1 Presumptive BART Emission Rates 

In the final Regional Haze Rule EPA established presumptive BART emission limits for SO2 and 

NOx for certain electric generating units (EGUs) based on fuel type, unit size, cost effectiveness, 

and the presence or absence of pre-existing controls.1

 The presumptive limits apply to EGUs at 

power plants with a total generating capacity in excess of 750 MW. For these sources, EPA 

established presumptive emission limits for coal-fired EGUs greater than 200 MW in size. The 

presumptive levels are intended to reflect highly cost-effective technologies as well as provide 

enough flexibility to states to consider source specific characteristics when evaluating BART. 

The BART SO2 presumptive emission limit for coal-fired EGUs greater than 200 MW in size 

without existing SO2 control is either 95% SO2 removal, or an emission rate of 0.15 lb/mmBtu, 

unless a state determines that an alternative control level is justified based on a careful 

consideration of the statutory factors. For NOx, EPA established a set of BART presumptive 

 

1

 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131. 
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emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal 

type. The BART NOx presumptive emission limit applicable to Muskogee Units 4 & 5 

(tangentially-fired boilers firing subbituminous coal) is 0.15 lb/mmBtu. 

States, as a general matter, should presume that owners and operators of greater than 750 MW 

power plants can cost effectively meet the presumptive levels. However, the BART process allows 

consideration of site-specific retrofit costs and site-specific visibility impacts. States have the 

ability to consider the specific characteristics of the source at issue and to find that the presumptive 

limits would not be appropriate for that source. Emission control technologies and emission limits 

that differ from the presumptive levels can be established if it can be demonstrated that an 

alternative emission rate is justified based on a consideration of the five statutory factors, including 

the costs of compliance and the degree of improvement in visibility which may reasonably be 

anticipated to result from the use of such technology. 

3.0 BART DETERMINATION FOR NITROGEN OXIDES (NOx) 

 

The formation of NOx is determined by the interaction of chemical and physical processes 

occurring primarily within the flame zone of the boiler. There are two principal forms of NOx

designated as “thermal” NOx and “fuel” NOx. Thermal NOx formation is the result of oxidation of 

atmospheric nitrogen contained in the inlet gas in the high-temperature, post-flame region of the 

combustion zone. Fuel NOx is formed by the oxidation of nitrogen in the fuel. NOx formation can 

be controlled by adjusting the combustion process and/or installing post-combustion controls. 

The major factors influencing thermal NOx formation are temperature, the concentration of 

combustion gases (primarily nitrogen and oxygen) in the inlet air, and residence time within the 

combustion zone. Advanced burner designs can regulate the distribution and mixing of the fuel and 

air to reduce flame temperatures and residence times at peak temperatures to reduce NOx formation. 

Coal properties have a major influence on the formation of fuel NOx. Nitrogen compounds are 

released from the coal during coal combustion. Fuel NOx conversion is generally dependent on the 

fuel rank. In general, a higher percentage of fuel-NOx is converted to NOx as the rank of fuel 

decreases. In other words, units firing lower rank coals (e.g., subbituminous coal or lignite) will 

have higher uncontrolled NOx emissions. 
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3.1 Step 1: Identify Potentially Feasible NOx Control Options 

Potentially available control options were identified based on a comprehensive review of available 

information. NOx control technologies with potential application to Muskogee Units 4 & 5 are 

listed in Table 3-1. 

Table 3-1 

List of Potential NOx Control Options 

Control Technology 

Combustion Controls 

Low NOx Burners & Overfire Air (LNB/OFA) 

 Flue Gas Recirculation (FGR) 

Post-Combustion Controls 

Selective Noncatalytic Reduction (SNCR) 

Selective Catalytic Reduction (SCR) 

Innovative Control Technologies 

 Rotating Overfire Air (ROFA) 

 ROFA + SNCR (Rotamix) 

 Wet NOx Scrubbing 

3.2 Step 2: Technical Feasibility of Potential Control Options 

NOx control technologies can be divided into two general categories: combustion controls and postcombustion controls. Combustion controls reduce the amount of NOx that is generated in the 

boiler. Post-combustion controls remove NOx from the boiler exhaust gas. The technical feasibility 

of each potentially applicable NOx control technology is evaluated below. 

3.2.1 Combustion Controls 

The rate of NOx formation in the combustion zone is a function of free oxygen, peak flame 

temperature and residence time. Combustion techniques designed to minimize the formation of 

NOx will minimize one or more of these variables. Combustion control options that may be 

applicable to the OG&E boilers are described below. 
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3.2.1.1 Low NOx Burners and Overfire Air 

Low NOx burners (LNB)2

 limit NOx formation by controlling both the stoichiometric and 

temperature profiles of the combustion flame in each burner flame envelope. This control 

is achieved with design features that regulate the aerodynamic distribution and mixing of 

the fuel and air, yielding reduced oxygen (O2) in the primary combustion zone, reduced 

flame temperature and reduced residence time at peak combustion temperatures. The 

combination of these techniques produces lower NOx emissions during the combustion 

process. 

In the OFA process, the injection of air into the firing chamber is staged into two zones, in 

which approximately 5% to 20% of the total combustion air is diverted from the burners 

and injected through ports located above the top burner level. Staging of the combustion 

air reduces NOx formation by two mechanisms. First, staged combustion results in a cooler 

flame, and second the staged combustion results in less oxygen reacting with fuel 

molecules. The degree of staging is limited by operational problems since the staged 

combustion results in incomplete combustion conditions and a longer flame. 

LNB/OFA emission control systems have been installed as retrofit control technologies on 

existing coal-fired boilers. Coal-fired boilers retrofit with LNB/OFA combustion 

technologies would be expected to operate with actual average NOx emission levels in the 

range of 85 to 180 ppmvd @ 3% O2 (approximately 0.12 to 0.25 lb/mmBtu) depending on 

the fuel, burner configuration, and averaging time. Based on a review of emissions data 

available from the EPA’s electronic emissions data reporting website, subbituminous-fired 

boilers retrofit with LNB/OFA have achieved actual average NOx emission rates in the 

range of 0.12 to 0.18 lb/mmBtu. 3 

Although combustion control systems on coal-fired boilers have demonstrated the ability to 

achieve average NOx emission rates below 0.15 lb/mmBtu, combustion control systems 

may not be as effective under all boiler operating conditions, especially during load 

changes and low load operations. Controlling the stoichiometric and temperature profiles 

of the combustion flame, and maintaining the air/fuel mixing needed for NOx control, 

becomes more difficult under these operating scenarios. Therefore, it is likely that short-

 

2

 The term “LNB” is used generically in this BART analysis, and refers to advanced low-NOx burners 

available from leading boiler/burner manufacturers. The term does not represent any vendor-specific trade 

name. As used in this BART analysis, the term “LNB” refers to the available advanced low-NOx burner 

technologies. 

3

 Emission data are available from EPA’s Electronic Data Reporting website: 

www.epa.gov/airmarkets/emissions/raw/index.html.
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term boiler NOx emissions will be higher under certain operating conditions. Furthermore, 

the mechanisms used to reduce NOx formation (e.g., cooler flame and reduced O2

availability) also tend to increase the formation and emission of CO and VOCs. 

Based on information available from burner control vendors, emissions achieved in practice 

at existing similar sources, and engineering judgment, it is expected that combustion 

controls, including LNB and OFA, on the tangentially-fired Muskogee boilers can be 

designed to meet the presumptive NOx BART emission rate of 0.15 lb/mmBtu 

(approximately 110 ppmvd @ 3% O2). An average emission rate of 0.15 lb/mmBtu should 

be achievable on a 30-day rolling average basis under all normal boiler operating 

conditions and while maintaining acceptable CO and VOC emission rates. 

3.2.1.2 Flue Gas Recirculation 

Flue gas recirculation (FGR) controls NOx by recycling a portion of the flue gas back into 

the primary combustion zone. The recycled air lowers NOx emissions by two mechanisms: 

(1) the recycled gas, consisting of products that are inert during combustion, lowers the 

combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the 

primary flame zone. The amount of recirculation is based on flame stability. 

FGR control systems have been used as a retrofit NOx control strategy on natural gas-fired 

boilers, but have not generally been considered as a retrofit control technology on coalfired units. Natural gas-fired units tend to have lower O2 concentrations in the flue gas and 

low particulate loading. In a coal-fired application, the FGR system would have to handle 

hot particulate-laden flue gas with a relatively high O2 concentration. Although FGR has 

been used on coal-fired boilers for flue gas temperature control, it would not have 

application on a coal-fired boiler for NOx control. Because of the flue gas characteristics 

(e.g., particulate loading and O2 concentration), FGR would not operate effectively as a 

NOx control system on a coal-fired boiler. Therefore, FGR is not considered an applicable 

retrofit NOx control option for Muskogee Units 4 & 5, and will not be considered further in 

the BART determination. 

3.2.2 Post-Combustion Controls 

Post-combustion NOx control systems with potential application to Muskogee Units 4 & 5 are 

discussed below. 

3.2.2.1 Selective Non-Catalytic Reduction 

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH3) 

or urea (CO(NH2)2) at high flue gas temperatures (approximately 1600oF - 1900oF). The 
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ammonia or urea reacts with NOx in the flue gas to produce N2 and water as shown in the 

equations below. 

(NH2) 2CO + 2NO + 1⁄2O2 → 2H2O + CO2 + 2N2 

2NH3 + 2NO + 1⁄2O2 → 2N2 + 3H2O 

Flue gas temperature at the point of reagent injection can greatly affect NOx removal 

efficiencies and the quantity of NH3 or urea that will pass through the SNCR unreacted 

(referred to as NH3 slip). In general, SNCR reactions are effective in the range of 1,700 o

F. 

At temperatures below the desired operating range, the NOx reduction reactions diminish 

and unreacted NH3 emissions increase. Above the desired temperature range, NH3 is 

oxidized to NOx resulting in low NOx reduction efficiencies. 

Mixing of the reactant and flue gas within the reaction zone is also an important factor to 

SNCR performance. In large boilers, the physical distance over which reagent must be 

dispersed increases, and the surface area/volume ratio of the convective pass decreases. 

Both of these factors make it difficult to achieve good mixing of reagent and flue gas, 

delivery of reagent in the proper temperature window, and sufficient residence time of the 

reagent and flue gas in that temperature window. In addition to temperature and mixing, 

several other factors influence the performance of an SNCR system, including residence 

time, reagent-to-NOx ratio, and fuel sulfur content. 

SNCR control systems have been installed as retrofit NOx control systems on small and 

medium sized (i.e., less than approximately 300 MW) coal-fired boilers. However, because 

of design and operating limitations, SNCR has not been used on large subbituminous coalfired boilers. Large subbituminous coal-fired boilers, including Muskogee Units 4 & 5, 

would not be able to achieve adequate reagent mixing and residence time within the 

required flue gas temperature window to achieve effective NOx reduction. 

The physical size of the Muskogee boilers makes it technically infeasible to locate and 

install ammonia injection points capable of achieving adequate NH3/NOx contact within 

the required temperature zone. Higher ammonia injection rates would be needed to achieve 

adequate NH3/NOx contact. Higher ammonia injection rates would result in relatively high 

levels of unreacted ammonia in the flue gas (ammonia slip), which could lead to plugging 

of downstream equipment. 

Another design factor limiting the applicability of SNCR control systems on large 

subbituminous coal-fired boilers is related to the reflective nature of subbituminous ash. 

Subbituminous coals typically contain high levels of calcium oxide and magnesium oxide 
Oklahoma Gas & Electric 

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15 

that can result in reflective ash deposits on the waterwall surfaces. Because most heat 

transfer in the furnace is radiant, reflective ash can result in less heat removal from the 

furnace and higher exit gas temperatures. If ammonia is injected above the appropriate 

temperature window, it can actually lead to additional NOx formation. 

SNCR control systems have not been designed or installed on large subbituminous coalfired boilers, and, as described above, there are several currently unresolved technical 

difficulties with applying SNCR to large subbituminous coal-fired boilers (including the 

physical size of the boiler, inadequate NH3 mixing, and ash characteristics). Even 

assuming that SNCR could be installed on Muskogee Units 4 & 5, NOx control 

effectiveness would be marginal, and, depending on boiler exit temperatures, could actually 

result in additional NOx formation. Because SNCR has not been designed for, or 

demonstrated on, a large subbituminous coal-fired boiler, it was determined that the control 

technology is not applicable to Muskogee Units 4 & 5, and SNCR will not be evaluated 

further in the BART determination. 

3.2.2.2 Selective Catalytic Reduction 

Selective Catalytic Reduction (SCR) involves injecting ammonia into boiler flue gas in the 

presence of a catalyst to reduce NOx to N2 and water. Anhydrous ammonia injection 

systems may be used, or ammonia may be generated on-site from a urea feedstock. The 

overall SCR reactions are: 

4NH3 + 4NO + O2 → 4N2 + 6H2O 

8NH3 + 4NO2 + 2O2 → 6N2 + 12H2O 

The performance of an SCR system is influenced by several factors including flue gas 

temperature, SCR inlet NOx level, the catalyst surface area, volume and age of the catalyst, 

and the amount of ammonia slip that is acceptable. 

The optimal temperature range depends on the type of catalyst used, but is typically 

between 560 o

F and 750 oF to maximize NOx reduction efficiency and minimize ammonium 

sulfate formation. This temperature range typically occurs between the economizer and air 

heater in a large utility boiler. Below this range, ammonium sulfate is formed resulting in 

catalyst deactivation. Above the optimum temperature, the catalyst will sinter and thus 

deactivate rapidly. Another factor affecting SCR performance is the condition of the 

catalyst material. As the catalyst degrades over time or is damaged, NOx removal 

decreases. 
Oklahoma Gas & Electric 

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SCR has been installed as a retrofit control technology on existing coal-fired boilers, 

including boilers firing subbituminous coal. SCR control systems on subbituminous coalfired boilers have achieved annual average NOx emission rates in the range of 0.04 to 

approximately 0.10 lb/mmBtu.4

 Several design and operating variables will influence the 

performance of the SCR system, including the volume, age and surface area of the catalyst 

(e.g., catalyst layers), uncontrolled NOx emission rate, flue gas characteristics (including 

temperature, sulfur content, and particulate loading), and catalyst activity.5

 Catalyst that 

has been in service for a period of time will have decreased performance because of normal 

deactivation and deterioration. Catalyst that is no longer effective due to plugging, blinding 

or deactivation must be replaced. 

Based on emission rates achieved in practice at existing subbituminous coal-fired units, and 

taking into consideration long-term operation of an SCR control system (including catalyst 

plugging and deactivation) it is anticipated that SCR could achieve a controlled NOx

emission rate of 0.07 lb/mmBtu (30-day rolling average) on Muskogee Units 4 & 5. An 

emission rate of 0.07 lb/mmBtu is equivalent to an average NOx concentration in the flue 

gas of approximately 50 ppmvd @ 3% O2. Reducing NOx emissions below 50 ppmvd @ 

3% O2 would tend to increase collateral environmental impacts associated with the SCR, 

including increased ammonia slip, increased SO2 to SO3 oxidation, and more frequent 

catalyst changes. 

3.2.3 Innovative NOx Control Technologies 

A number of innovative NOx control systems, including multi-pollutant control systems, were 

identified as potential retrofit control technologies during the review of available documents. 

Innovative NOx control technologies with potential application to the BART study include 

boosted over-fire air (e.g., MobotecUSA’s ROFA® system), advanced SNCR control systems 

(e.g., MobotecUSA’s Rotamix® system), Enviroscrub’s multi-pollutant PahlmanTM process, and 

wet NOx scrubbing systems. 

 

4

 Emission data are available from EPA’s Electronic Data Reporting website: 

www.epa.gov/airmarkets/emissions/raw/index.html.

5

 See, e.g., Sanyal, A., Pircon, J.J., “What and How Should You Know About U.S. Coal to Predict and 

Improve SCR Performance”, proceedings of the USEPA, DOE, EPRI, Combined Power Plant Air Pollution 

Control Mega Symposium, Chicago, IL, August 2001. See also, Gutberlet, H., Schluter, A., Licata, A., 

“Deactivation of SCR Catalyst”, proceedings of the DOE’s 2000 Conference on Selective Catalytic and 

Selective Non-Catalytic Reduction for NOx Control, Pittsburgh, PA, 2000. 
Oklahoma Gas & Electric 

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3.2.3.1 Rotating Opposed Fired Air and Rotomix 

Rotating opposed fired air (ROFA) is a boosted overfire air system that includes a patented 

rotation process which includes asymmetrically placed air nozzles.6

 Like other OFA 

systems, ROFA stages the primary combustion zone to burn overall rich, with excess air 

added higher in the furnace to burn out products of incomplete combustion. The ROFA 

nozzles are designed to increase turbulence within the furnace. Increased turbulence should 

prevent the formation of stratified laminar flow, enable the furnace volume to be used more 

effectively for the combustion process, and reduce the maximum temperatures of the 

combustion zone. 

The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan, 

and control system instrumentation. A ROFA system was installed on an existing 80-MW 

(gross) bituminous-fired utility boiler in the summer of 2002. Test results showed that the 

ROFA system reduced NOx emissions from baseline levels between 0.58 and 0.62 

lb/mmBtu to approximately 0.22 lb/mmBtu at full load. At lower loads (approximately 40 

MW), the ROFA system reduced NOx emissions from 0.59 lb/mmBtu to 0.295 lb/mmBtu.7

 

The turbulent air injection and mixing provided by ROFA allows for the effective mixing 

of chemical reagents with the combustion products in the furnace. MobotecUSA’s 

Rotamix® system combines the rotating opposed overfire air system with urea injection into 

the flue gas to reduce NOx emissions. The turbulent mixing created by the ROFA system is 

designed to improve distribution of the ammonia/urea reagent and may reduce the 

ammonia/urea injection required by the SNCR control system. A Rotamix control system 

was installed on the same 80-MW unit in the spring of 2004. 

ROFA and Rotamix® systems have been demonstrated on smaller coal-fired boilers but 

have not been demonstrated in practice on boilers similar in size to Muskogee Units 4 & 5. 

As discussed in subsection 3.2.1.1, overfire air control systems are a technically feasible 

retrofit control technology, and, based on engineering judgment, the ROFA design could 

also be applied to Muskogee Units 4 & 5. However, there is no technical basis to conclude 

that the ROFA design would provide additional NOx reduction beyond that achieved with 

other OFA designs. Therefore, ROFA control systems will not be evaluated as a specific 

 

6

 See, MobotecUSA at www.mobotecusa.com. 

7

 Coombs, K.A., Crilley, J.S., Shilling, M., Higgins, B., “SCR Levels of NOx Reduction with ROFA and 

Rotamix (SNCR) at Dynegy’s Vermilion Power Station,” Presented at 2004 Stack Emissions Symposium, 

Clearwater Beach, Florida, July 28-30, 2004. 
Oklahoma Gas & Electric 

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control system, but will be included in the overall evaluation of combustion controls (e.g., 

LNB/OFA). 

The Rotamix system is a SNCR control system (i.e., ammonia injection system) coupled 

with the ROFA rotating injection nozzle design. The technical limitations discussed in 

section 3.2.2.1, including the physical size of the boiler, inadequate NH3/NOx contact, fly 

ash characteristics, and flue gas temperatures, would apply equally to the Rotamix control 

system. There is no technical basis to conclude that the Rotamix urea injection design 

addresses these unresolved technical difficulties. Therefore, like other SNCR control 

systems, the Rotamix system is determined not to be an applicable NOx control system for 

Muskogee Units 4 & 5, and will not be evaluated further in the BART determination. 

3.2.3.2 Pahlman Multi-Pollutant Control Process 

The PahlmanTM Process is a patented dry-mode multi-pollutant control system. The 

process uses a sorbent composed of oxides of manganese (the PahlmaniteTM sorbent) to 

remove NOx and SO2 from the flue gas.8

 Manganese compounds are soluble in water in the 

+2 valence state but not in the +4 state. This property is used in the Pahlman sorbent 

capture and regeneration procedure, in that Pahlmanite sorbent is reduced from the 

insoluble +4 state to the +2 state during the formation of manganese nitrates and sulfates. 

These species are water-soluble, allowing the sulfate, nitrate and Mn+2 ions to be 

dissociated and the Mn+2 to be oxidized again to Mn+4 and regenerated. In general, the 

liquid metal oxide Pahlmanite sorbent is injected as the flue gas enters a spray dryer. The 

sorbent dries as it passes through the spray dryer and is collected downstream at the fabric 

filter baghouse. NOx and SO2 will react with the sorbent to form manganese sulfates and 

nitrates as the flue gas passes through the filter cake. 

The filter cake is pulsed off-line into a wet regeneration process. The regenerated sorbent 

is stored in liquid form to be employed again via the spray dryer. The captured nitrogen 

and sulfur can be purified and may be converted into granular fertilizer by-products. 

To date, bench- and pilot-scale testing have been conducted to evaluate the technology on 

utility-sized boilers.9

 The New & Emerging Environmental Technologies (NEET) 

Database identifies the development status of the Pahlman Process as full-scale 

 

8

 See, Enviroscrub Technologies Corporation, www.enviroscrub.com. 

9

 See, Wocken, C.A., “Evaluation of Enviroscrub’s Multipollutant PahlmanTM Process for Mercury Removal 

at a Facility Burning Subbituminous Coal,” Energy & Environmental Research Center, University of North 

Dakota, April 2004. 
Oklahoma Gas & Electric 

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19 

development and testing. 10 The process is an emerging multi-pollutant control, and there is 

limited information available to evaluate it’s technically feasibility and long-term 

effectiveness on a large subbituminous-fired boiler. It is likely that OG&E would be 

required to conduct extensive design engineering and testing to evaluate the technical 

feasibility and long-term effectiveness of the control system on Muskogee Units 4 & 5. 

BART does not require applicants to experience extended time delays or resource penalties 

to allow research to be conducted on an emerging control technique. Therefore, at this time 

the Pahlman Process is not considered an available NOx control system for Muskogee Units 

4 & 5, and will not be further evaluated in the BART determination. 

3.2.3.3 Wet NOx Scrubbing Systems 

Wet scrubbing systems have been used to remove NOx emissions from fluid catalytic 

cracking units (FCCUs) at petroleum refineries. An example of a wet scrubbing system is 

Balco Technologies’ LoTOxTM system. The LoTOx system is a patented process, wherein 

ozone is injected into the flue gas stream to oxidize NO and NO2 to N2O5. This highly 

oxidized species of NOx is very soluble and rapidly reacts with water to form nitric acid. 

The conversion of NOx to nitric acid occurs as the N2O5 contacts liquid sprays in the 

scrubber. 

Wet scrubbing systems have been installed at chemical processing plants and smaller coalfired boilers. The NEET Database classifies wet scrubbing systems as commercially 

established for petroleum refining and oil/natural gas production. However the technology 

has not been demonstrated on large coal-fired boilers and it is likely that OG&E would 

incur substantial engineering and testing to evaluate the scale-up potential and long-term 

effectiveness of the system. Therefore, at this time wet NOx scrubbing is not considered to 

be an applicable or commercially available retrofit control system for Muskogee Units 4 & 

5, and will not be further evaluated in this BART determination. 

The results of Step 2 of the NOx BART Analysis (technical feasibility analysis of potential NOx

control technologies) are summarized in Table 3-2. 

 

10 NEET is an on-line repository for information about emerging technologies that reduce emissions from 

stationary, mobile, and indoor sources. NEET was developed and is operated by RTI International with 

support from the EPA Office of Air Quality Planning and Standards. 
Oklahoma Gas & Electric 

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Table 3-2 

Technical Feasibility of Potential NOx Control Technologies 

Muskogee Generating Station 

In Service on 

Existing PC 

Boilers Control Technology Controlled NOx

Emission Rate 

(lb/mmBtu) Yes No 

In Service on 

Other 

Combustion 

Sources? 

Technically Feasible on 

Muskogee Units 4 & 5? 

Low NOx Burners and 

Overfire Air 

0.15 lb/mmBtu X Yes Technically feasible. 

SNCR NA X Yes 

SNCR has 

been applied 

to several 

smaller coalfired boilers. 

Not a technically feasible retrofit 

technology for Muskogee Units 4 

& 5. SNCR has been used as a 

retrofit technology on small and 

medium sized (<300 MW) coalfired boilers, but has not been 

demonstrated on larger boilers. 

There are several currently 

unresolved technical difficulties 

associated with applying SNCR on 

a large subbituminous coal-fired 

boiler. 

SCR 0.07 lb/mmBtu X 

 

Yes 

SCR is a technically feasible 

retrofit technology for Muskogee 

Units 4 & 5. The effectiveness of 

the SCR system will depend on 

site-specific considerations 

including the ammonia injection 

rate, site-specific flue gas 

characteristics, ammonia slip, and 

frequency of catalyst changes. 

ROFA NA X Yes ROFA has been demonstrated on 

small coal-fired boilers, and would 

be a technically feasible retrofit 

control technology. However, 

there is no technical basis to 

conclude that ROFA will provide 

additional NOx control beyond that 

achievable with other OFA 

systems. Therefore, ROFA will be 

evaluated along with other OFA 

control systems. 
Oklahoma Gas & Electric 

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Table 3-2 continued 

Control Technology Controlled NOx

Emission Rate 

(lb/mmBtu) 

In Service on 

Existing PC 

Boilers 

In Service on 

Other 

Combustion 

Sources? 

Technically Feasible on 

Muskogee Units 4 & 5? 

Rotamix (SNCR) NA X Yes Rotamix control systems have been 

demonstrated on small coal-fired 

boilers. However, there are several 

currently unresolved technical 

difficulties associated with 

applying SNCR-type systems on a 

large subbituminous coal-fired 

boiler. Therefore, Rotamix is not 

considered an available retrofit 

control technology for Muskogee 

Units 4 & 5. 

Pahlman Process NA X No Bench- and pilot-scale testing has 

been conducted on coal-fired 

boilers, however, there is limited 

data available assessing the 

technical feasibility of this system 

on large coal-fired boilers. 

Wet NOx Scrubbing NA X Yes The system has been used on 

refinery fluid catalytic cracking 

units and small coal-fired boilers, 

but has not been used on large 

coal-fired boilers. Wet NOx 

scrubbing systems are not 

commercially available or 

technically feasible for Muskogee 

Units 4 & 5. 
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3.3 Step 3: Rank the Technically Feasible NOx Control Options by Effectiveness 

The technically feasible and commercially available NOx control technologies for Muskogee Units 

4 & 5 are listed in Table 3-3, in descending order of control efficiency. 

Table 3-3 

Technically Feasible NOx Control Technologies 

Muskogee Station 

 Muskogee Unit 4 Muskogee Unit 5 

Control Technology Approximate NOx

Emission Rate* 

(lb/mmBtu) 

Approximate NOx

Emission Rate* 

(lb/mmBtu) 

Selective Catalytic Reduction (SCR) 0.07 0.07 

Low-NOx Burners and Overfire Air 0.15 0.15 

Baseline11 0.495 0.522 

3.4 Step 4: Evaluate the Technically Feasible NOx Control Technologies 

3.4.1 NOx Control Technologies – Economic Evaluation 

The most effective NOx retrofit control system, in terms of reduced emissions, that is 

considered to be technically feasible for Muskogee Units 4 & 5 includes combustion controls 

(LNB/OFA) and post-combustion SCR. This combination of controls should be capable of 

achieving the lowest controlled NOx emission rate on an on-going long-term basis. The 

effectiveness of the SCR system is dependent on several site-specific system variables, 

including the size of the SCR, catalyst layers, NH3/ NOx stoichiometric ratio, NH3 slip, and 

catalyst deactivation rate. Based on emission rates achieved in practice at similar sources, and 

including a reasonable margin to account for normal system fluctuations, the combination of 

combustion controls and SCR should achieve a controlled NOx emission rate of 0.07 lb/mmBtu 

(30-day average). 

The next most effective NOx retrofit control system that is considered technically feasible for 

Muskogee Units 4 & 5 includes combustion controls (LNB/OFA). The combination of 

 

11 Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions 

reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmBtu) were calculated 

by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The 

relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts, 

and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control 

technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation 

of the facility’s permitted emission limits, which are averaged over a longer period of time. 
Oklahoma Gas & Electric 

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LNB/OFA on Muskogee Units 4 & 5 (large tangentially fired boilers firing subbituminous coal) 

should be capable of meeting the BART presumptive limit of 0.15 lb/mmBtu. 

Economic impacts associated with the SCR control systems were evaluated in accordance with 

EPA guidelines (40 CFR Part 51 Appendix Y). In accordance with the guidelines in Part III of 

Appendix Y, emission estimates used in the modeling analysis to determine visibility 

impairment impacts should reflect steady-state operating conditions during periods of high 

capacity utilization. Therefore, projected emission rates (lb/hr) were calculated based on the 

expected controlled emission rate (lb/mmBtu) achievable on a 30-day rolling average and heat 

input to the boiler at full load. Annual emissions (tpy) were calculated assuming a 90% 

capacity factor for each unit. 

Cost estimates were compiled from a number of data sources. In general, the cost estimating 

methodology followed guidance provided in the EPA Air Pollution Cost Control Manual.12 

Major equipment costs were developed based on equipment costs recently developed for 

similar projects, and include the equipment, material, labor, and all other direct costs needed to 

retrofit Muskogee Units 4 & 5 with the control technology. 

Fixed and variable O&M costs were developed for each control system. Fixed O&M costs 

include operating labor, maintenance labor, maintenance material, and administrative labor. 

Variable O&M costs include the cost of consumables, including reagent (e.g., ammonia), byproduct management, water consumption, and auxiliary power requirements. Auxiliary power 

requirements reflect the additional power requirements associated with operation of the new 

control technology, including operation of any new ID fans as well as the power requirements 

for pumps, reagent handling, and by-product handling. 

Summarized in Table 3-4 are the expected controlled NOx emission rates, and maximum annual 

NOx mass emissions, associated with each technically feasible retrofit technology. Table 3-5 

presents the capital costs and annual operating costs associated with building and operating 

each control system. Table 3-6 shows the average annual cost effectiveness and incremental 

annual cost effectiveness for each NOx control system. A detailed summary of the cost 

estimates used in this BART determination is included in Attachment A. 

 

12 U.S. Environmental Protection Agency, EPA Air Pollution Cost Control Manual, 6th Ed., Publication 

Number EPA 452/B-02-001, January 2002. 
Oklahoma Gas & Electric 

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Table 3-4 

Annual NOx Emissions 

Control Technology 

NOx Emission Rate 

(lb/mmBtu) 

Maximum Annual NOx 

Emissions 

(tpy)*

Annual Reduction in 

Emissions 

(tpy from baseline) 

 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 

LNB/OFA + SCR 0.07 0.07 1,512 1,512 9,181 9,764 

LNB/OFA 0.15 0.15 3,240 3,240 7,453 8,036 

Baseline NOx Emissions 0.495 0.522 10,693 11.276 -- -- 

* Maximum annual emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr 

per boiler for 7,884 hours per year (90% capacity factor). 

Table 3-5 

NOx Emission Control System 

Cost Summary (per boiler) 

Control Technology 

Total Capital 

Investment* 

($) 

Total Capital 

Investment 

($/kW-gross) 

Annual Capital 

Recovery Cost 

($/year) 

Annual 

Operating Costs 

($/year) 

Total Annual 

Costs 

($/year) 

LNB/OFA + SCR $193,077,000 $339 $16,568,000 $14,227,600 $30,795,600 

LNB/OFA $14,113,700 $25 $1,211,100 $880,700 $2,091,800 

* Capital costs for NOx retrofit control systems will be similar for both Units 4 & 5. Capital costs include the cost of major

components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the

control system. Capital costs for the SCR system include costs associated with installation of LNB/OFA systems. 

Table 3-6 

NOx Emission Control System 

Cost Effectiveness (total for both boilers) 

Control Technology 

Total Annual 

Cost 

($/year) 

Annual Emission 

Reduction 

(tpy) 

Average Cost 

Effectiveness 

($/ton) 

Incremental Cost 

Effectiveness 

($/ton) 

LNB/OFA + SCR $61,591,200 18,945 $3,251 $16,611 

LNB/OFA $4,183,600 15,489 $270 NA 

The average annual cost effectiveness of LNB/OFA+SCR on Muskogee Units 4 & 5 is 

estimated to be approximately $3,251/ton. This cost compares to an average annual cost 

effectiveness for LNB/OFA combustion controls of approximately $270/ton. Equipment costs, 

retrofit challenges, and annual operating costs all have a significant impact on the annualized 

cost of a SCR control system. Significant annual operating costs include the energy cost 

associated with the additional pressure drop across the SCR and costs associated with replacing 

the SCR catalyst as it degrades over time. Based on projected actual emissions, SCR could 
Oklahoma Gas & Electric 

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25 

reduce overall NOx emissions from Muskogee Units 4 & 5 by approximately 3,456 tpy 

(compared to advanced combustion controls); however, the incremental cost associated with 

this reduction is approximately $57,407,600 per year, or $16,611/ton. 

As part of the BART rulemaking, EPA established presumptive NOx emission limits applicable 

to EGUs greater than 200 MW at power plants with a generating capacity greater than 750 

MW. The presumptive NOx emission limits were based on control strategies that EPA 

considered to be generally cost-effective for such units (see, 70 FR 39134). The presumptive 

NOx emission limit applicable to Muskogee Units 4 & 5 (tangentially-fired units firing 

subbituminous coal) is 0.15 lb/mmBtu. For all types of boilers, other than cyclone units, the 

presumptive limits were based on the use of combustion control technologies. EPA estimated 

that the “costs of such controls in most cases range from just over $100 to $1000 per ton” (see, 

70 FR 39135). 

The average cost effectiveness of combustion controls (LNB/OFA) on Muskogee Units 4 & 5 is 

similar to the BART cost-effectiveness developed by EPA for NOx control on large EGU 

boilers. Both the average and incremental cost effectiveness of SCR on Muskogee Units 4 & 5 

are significantly greater than the cost effectiveness of NOx control at other BART-applicable 

units. The costs associated with SCR would result in significant economic impacts on the 

Muskogee Generating Station (approximately $57,407,600 per year additional costs). 

Therefore, SCR should not be selected as BART based on lack of cost effectiveness. Although 

SCR does not appear to be cost effective, it will be included in the evaluation of the remaining 

factors to assure that the BART determination considers all relevant information. 

3.4.2 NOx Control Technologies – Environmental Impacts 

Combustion modifications designed to decrease NOx formation (lower temperature and less 

oxygen availability) also tend to increase the formation and emission of CO and VOCs. 

Therefore, the combustion controls must be designed to reduce the formation of NOx while 

maintaining CO and VOC formation at an acceptable level. Other than the NOx/CO-VOC 

trade-off, there are no environmental issues associated with using combustion controls to 

reduce NOx emissions. 

Operation of an SCR system has certain collateral environmental consequences.13 First, in 

order to maintain low NOx emissions some excess ammonia will pass through the SCR. 

Ammonia slip will increase with lower NOx emission limits, and will also tend to increase as 

the catalyst becomes deactivated. Ammonia slip from an SCR designed to achieve a controlled 

 

13 See, Hinton, W.S., Cushing, K.M., Gooch, J.P., “Balance-of-Plant Impacts Associated with SCR/SNCR 

Installations”, proceedings of the ICAC Forum, 2002. 
Oklahoma Gas & Electric 

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NOx emission rate of 0.07 lb/mmBtu (30-day average) is expected to be in the range of 2-5 ppm 

during the initial operation of the SCR. As the catalyst ages and becomes either deactivated or 

blinded, ammonia slip can increase; however, the ammonia slip rate is not expected to exceed 

7-10 ppm under normal operating conditions. 

Second, undesirable reactions can occur in an SCR system, including the oxidation of NH3 and 

SO2 and the formation of sulfate salts. A fraction of the SO2 in the flue gas (approximately 1 - 

1.5%) will oxidize to SO3 in the presence of the SCR catalyst. SO3 can react with water to form 

sulfuric acid mist or with the ammonia slip to form ammonium sulfate ((NH4)2SO4). Sulfuric 

acid mist and (NH4)2SO4 are classified as condensable particulates. The formation of 

condensible particulates will increase as the size of the SCR increases. 

Finally, the storage of ammonia on-site increases the risks associated with an accidental 

ammonia release. Depending on the type, concentration, and quantity of ammonia used, 

ammonia storage/handling will be subject to regulation as a hazardous substance under 

CERCLA, Section 313 of the Emergency Planning and Community Right-to-Know Act, 

Section 112(r) of the Clean Air Act, and Section 311(b)(4) of the Clean Water Act. One 

strategy that can be used to minimize the risk associated with on-site ammonia handling is to 

design the ammonia handling system as a urea-to-ammonia conversion system. Urea 

((NH2)2CO) can be delivered to the station as an aqueous solution or as a dry solid, and urea 

storage/handling does not create the process safety concerns associated with handling 

anhydrous ammonia. 

3.4.3 NOx Control Technologies – Energy Impacts 

Both NOx control systems require auxiliary power. Auxiliary power requirements associated 

with the LNB/OFA control systems are generally insignificant, but may include booster fans for 

the overfire air injection ports to increase turbulence within the boiler. Auxiliary power 

requirements associated with the SCR include additional fan power to overcome pressure drop 

through the SCR. Energy impacts associated with each control technology were included in the 

BART economic impact evaluation as an auxiliary power cost. 

A summary of the Step 4 economic and environmental impact analysis is provided in Table 3-7. 
Oklahoma Gas & Electric 

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Table 3-7 

Summary of NOx BART Impact Analysis (total for both boilers) 

Control 

Technology 

Annual 

Controlled 

Emissions* 

(tpy) 

Annual 

Emission 

Reductions 

(tpy) 

Average Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

($/ton) 

Summary of Environmental 

Impacts 

LNB/OFA+SCR 3,024 18,945 $3,251 $16,611 Increased SO2 to SO3 oxidation, and 

increased condensible PM emissions 

including H2SO4. Ammonia 

emissions associated with ammonia 

slip. 

LNB/OFA 6,480 15,489 $270 -- Potential to increase CO/VOC 

emissions. 

Baseline 21,969 base -- -- -- 

* Annual controlled emissions and annual emission reductions represent total emissions from both units. Annual 

emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr per boiler for 7,884 hours 

per year (90% capacity factor). 

3.5 Step 5: Evaluate Visibility Impacts 

To evaluate the relative effectiveness of potentially feasible NOx retrofit control technologies, NOx

emissions were modeled at the projected post-retrofit controlled emission rates, while SO2 and 

PM10 emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA 

guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling 

analysis to determine visibility impairment impacts reflect steady-state operating conditions during 

periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour 

basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling 

average multiplied by the boiler heat input (mmBtu/hr) at full load. The visibility modeling 

methodology is described further in Attachment B of this document, including detailed inputs and 

results. The results in Table 3-8 summarize the 98th percentile ∆-dv impact from NOx emissions 

associated each NOx retrofit control scenario. 

The most significant improvement in visibility can be attributed to NOx reductions associated with 

combustion controls (LNB/OFA). Visibility improvements in the range of 70% reductions in 

modeled impacts are achieved at each Class I Area. The largest reduction in visibility impairment 

(0.74 ∆-dv) occurs at the Caney Creek Class I Area. Modeled impacts associated with NOx

emissions based on LNB/OFA controls at the presumptive NOx emission limit (0.15 lb/mmBtu) are 

below the threshold impact level of 0.5 ∆-dv level at all Class I Areas. 
Oklahoma Gas & Electric 

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Table 3-8 

Muskogee Units 4 & 5 

NOx Visibility Assessment 

Visibility Improvement 

Upper Buffalo 

Wilderness Area 

Caney Creek 

Wilderness Area 

Hercules-Glades 

Wilderness Area 

Wichita Mountains 

NOx Control Wildlife Refuge

Technology 

Option 98th % 

∆-dv*

% 

Improvement over 

Previous 

98th % 

∆-dv

% 

Improvement over 

Previous 

98th % 

∆-dv

% 

Improvement over 

Previous 

98th % 

∆-dv

% 

Improvement over 

Previous 

Baseline 0.84 -- 1.06 -- 0.47 -- 0.61 -- 

LNB/OFA 0.24 71% 0.32 70% 0.14 71% 0.18 71% 

LNB/OFA + SCR 0.11 53% 0.14 56% 0.06 54% 0.08 55% 

* ∆-dv values included in this table represent the modeled visibility impacts only from NOx emissions associated 

with each NOx retrofit control scenario. 

Post-combustion SCR control systems could reduce NOx emissions from Muskogee Units 4 & 5 

below the BART presumptive level; however, modeled visibility improvements at the lower NOx

emission rates do not justify the costs associated with SCR control. LNB/OFA control systems are 

expected to reduce overall NOx emissions from Muskogee Units 4 & 5 by approximately 15,489 tpy 

(from baseline). SCR control systems would reduce overall NOx emissions by an additional 3,456 

tpy. At the lower NOx emission rates, modeled visibility impairment at the Class I Areas would be 

reduced by only 0.08 to 0.18 ∆-dv. Because only small improvements in visibility impacts result 

from the lower emission rate, the cost effectiveness of SCR control, on a $/dv basis, will be 

significant. 

Tables 3-9 and 3-10 summarize the cost effectiveness of the technically feasible NOx retrofit 

control technologies on Muskogee Units 4 & 5 as a function of visibility impairment improvement 

at the Class I Areas. 
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Table 3-9 

Muskogee Units 4 & 5 

NOx Average Visibility Cost Impact Evaluation 

Total Annual 

Cost

Modeled 

Visibility 

Impairment*

Visibility 

Impairment 

Improvement 

from Baseline 

Average 

Improvement 

Cost 

Effectiveness

NOx Control 

Technology Option 

($/yr) 98th % ∆-dv* (dv) ($/dv/yr) 

Baseline -- 1.06 -- -- 

LNB/OFA $4,183,600 0.32 0.74 $5.65 MM/dv 

LNB/OFA + SCR $61,591,200 0.14 0.92 $66.9 MM/dv 

* ∆-dv values included in this table represent the modeled visibility impacts only from NOx emissions 

associated with each NOx retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I 

Area was used for the cost effectiveness evaluation because modeling indicated that the largest ∆-dv 

improvements would occur at Caney Creek. 

Although SCR control systems reduce modeled visibility impacts at the four Class I Areas, the 

incremental cost effectiveness of SCR control (with respect to visibility improvement) is very high. 

Incremental cost effectiveness of SCR control is in the range of $319 million per dv improvement 

at the Wichita Mountains. This cost is significantly higher than costs incurred at other BART 

applicable sources. A review of BART determinations at other coal-fired units suggests that BART 

cost effectiveness values are typically in the range of less than $1.0 million to approximately $13 

million per dv improvement.14 The combination of low visibility impacts with LNB/OFA controls 

(less than 0.32 ∆-dv at all Class I Areas) and the high cost of SCR controls contribute to the large 

incremental cost effectiveness of SCR at the Muskogee Station. 

Table 3-10 

Muskogee Units 4 & 5 

NOx Incremental Visibility Cost Impact Evaluation 

Total Annual 

Cost

Incremental 

Annual Cost 

Modeled 

Visibility 

Impairment

Incremental 

Visibility 

Impairment 

Improvement 

Incremental 

Improvement 

Cost 

Effectiveness

NOx Control 

Technology Option 

($/yr) ($/yr) 98th % ∆-dv* (dv) ($/dv/yr) 

Baseline -- -- 1.06 -- -- 

LNB/OFA $4,183,600 -- 0.32 -- -- 

LNB/OFA + SCR $61,591,200 $57,407,600 0.14 0.18 $319 MM/dv 

* ∆-dv values included in this table represent the modeled visibility impacts only from NOx emissions associated with 

each NOx retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I Area was used for the cost 

effectiveness evaluation because modeling indicated that the largest ∆-dv improvements would occur at Caney Creek. 

 

14 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy 

Co. (CO); Entergy White Bluff Power Plant (AR). 
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To determine whether alterative NOx control scenarios might provide more cost effective visibility 

improvements, cumulative impact modeling was conducted using a variety of SCR control 

scenarios. A goal of the cumulative impact modeling was to determine whether alternative NOx 

control scenarios (i.e., SCR control on some, but not all of the OG&E BART applicable sources) 

would provide more cost effective NOx control. To quantify cost effectiveness, visibility 

impairment was modeled for several NOx control scenarios, while SO2 and PM emissions were 

held constant at their respective baseline emission rates. Modeled NOx control scenarios are listed 

in Table 3-11. Results of the cumulative NOx impact modeling are summarized in Table 3-12. 

Table 3-11 

Cumulative NOx Visibility Assessment 

(Muskogee Units 4 & 5 and Sooner Units 1 & 2)* 

Unit Base Case Case 1 Case 2 Case 3 Case 4 

 NOx Controls 

(Emission Rate - lb/mmBtu) 

Muskogee Unit 4 LNB/OFA 

(0.15) 

SCR 

(0.07) 

SCR 

(0.07) 

SCR 

(0.07) 

SCR 

(0.07) 

Muskogee Unit 5 LNB/OFA 

(0.15) 

LNB/OFA 

(0.15) 

LNB/OFA 

(0.15) 

SCR 

(0.07) 

SCR 

(0.07) 

Sooner Unit 1 LNB/OFA 

(0.15) 

LNB/OFA 

(0.15) 

SCR 

(0.07) 

SCR 

(0.07) 

SCR 

(0.07) 

Sooner Unit 2 LNB/OFA 

(0.15) 

LNB/OFA 

(0.15) 

LNB/OFA 

(0.15) 

LNB/OFA 

(0.15) 

SCR 

(0.07) 

* For each case PM and SO2 emissions were held constant at the baseline emission rates. Baseline emissions for SO2

were: 0.80 lb/mmBtu (Muskogee Unit 4), 0.85 lb/mmBtu (Muskogee Unit 5), and 0.86 lb/mmBtu (Sooner Units 1 & 2). 

Table 3-12 

Cumulative NOx Visibility Modeling Results 

(Muskogee Units 4 & 5 and Sooner Units 1 & 2) 

Modeled Visibility Impairment* 

Upper Buffalo 

Wilderness Area 

Caney Creek 

Wilderness Area 

Hercules-Glades 

Wilderness Area 

Wichita Mountains 

Wildlife Refuge

NOx Control 

Technology 

Option 98th % 

∆-dv

98th % 

∆-dv

98th % 

∆-dv

98th % 

∆-dv

Base Case 1.92 2.00 1.44 2.42 

Case 1 1.94 1.99 1.43 2.41 

Case 2 1.94 1.98 1.43 2.38 

Case 3 1.95 1.97 1.46 2.35 

Case 4 1.94 1.96 1.46 2.33 

* ∆-dv values included in this table reflect cumulative modeled contributions from NOx, SO2 and PM emissions from both 

the Sooner and Muskogee Stations. For each case PM and SO2 emissions were held constant at their respective baseline 

emission rates, while NOx emissions varied depending the NOx control system on each unit (see Table 3-11). The dv 

values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2), which reflect modeled impacts 

from the Muskogee Station only for each individual pollutant. 
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Results of the cumulative impact modeling suggest that SCR controls would contribute only 

minimally to visibility improvement at the Class I Areas in comparison to LNB/OFA. Modeled 

impacts at the Wichita Mountains (at the 98th percentile ∆-dv level) improved from 2.42 ∆-dv with 

LNB/OFA on all four units to 2.33 ∆-dv with SCR on all four units, an improvement of 

approximately 4%. Modeled improvements were even lower at the other Class I Areas, and, in fact, 

modeled impairments at the Hercules-Glades and Upper Buffalo Wilderness Areas actually 

increased with the addition of SCR controls. It is suspected that increased sulfuric acid mist 

emissions (associated with SO2 to SO3 conversion across the SCR) off-set reductions in controlled 

NOx emissions. 

3.6 Propose BART for NOx Control at Muskogee Units 4 & 5 

OG&E is proposing combustion controls (LNB/OFA), and a controlled NOx emission rate of 0.15 

lb/mmBtu (30-day average) as BART for Muskogee Units 4 & 5. This combination of control 

technologies represents the most cost effective technically feasible NOx retrofit technology for the 

existing boilers. A controlled emission rate of 0.15 lb/mmBtu is equivalent to the presumptive level 

for large tangentially-fired units firing subbituminous coals. The average cost effectiveness of 

LNB/OFA control systems is estimated to be in the range of $270/ton and $5.65 MM./dv/yr. These 

cost effectiveness numbers are in-line with EPA’s cost estimate for BART controls on large EGUs, 

and are not of such magnitude as to exclude combustion controls as BART. 

The addition of SCR control systems could provide incremental NOx reductions; however, costs 

associated with SCR control are significant, and incremental visibility improvements are limited. 

The average cost effectiveness of an SCR control system is estimated to be $3,251/ton and $66.9 

MM/dv/yr. These costs are significantly higher than the average cost of NOx control at similar 

sources. In the BART rule, EPA estimated that the cost of controls to meet the BART NOx

presumptive level on large EGUs “in most cases range from just over $100 to $1000 per ton” (see, 

70 FR 39135). 

Furthermore, the modeled incremental visibility improvements associated with SCR control are 

only in the range of 0.08 to 0.18 ∆-dv. Because of the limited improvement in modeled visibility 

impacts, the cost effectiveness of SCR control, on a $/dv basis is significant. Compared to the 

costs and modeled visibility impacts associated with LNB/OFA controls, the incremental cost 

effectiveness of SCR is estimated to be $16,611/ton and more than $319 MM/dv/yr. Both costs are 

significantly higher than the expected cost of BART controls on large EGUs, and should preclude 

SCR from consideration as BART. Finally, cumulative impact modeling, summarized in Tables 3-

11 and 3-12, supports the conclusion that post-combustion SCR controls provide limited 

improvement in modeled visibility impairment. 
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4.0 BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (SO2) 

SOX emissions from coal combustion consist primarily of sulfur dioxide (SO2), with a much lower 

quantity of sulfur trioxide (SO3) and gaseous sulfates. These compounds form as the organic and 

pyretic sulfur in the coal are oxidized during the combustion process. On average, about 95% of 

the sulfur present in the fuel will be emitted as gaseous SOX,

15 Boiler size, firing configuration and 

boiler operations generally have little effect on the percent conversion of fuel sulfur to SO2. 

The generation of SO2 is directly related to the sulfur content and heating value of the fuel burned. 

The sulfur content and heating value of coal can vary dramatically depending on the source of the 

coal. Muskogee Units 4 & 5 utilize subbituminous coal as their primary fuel source. Heating 

values, ash contents, and sulfur contents for subbituminous fuel utilized at the Muskogee Station 

are summarized in Table 4-1. 

Table 4-1 

Muskogee Generating Station 

Typical Coal Characteristics

Constituent Units Range 

Heating Value Btu/lb 8,490 - 8,900 

Ash % 4.1 - 6.0 

Sulfur Content % 0.20 – 0.37 

Potential Uncontrolled SO2 lb/mmBtu 0.50 – 0.86 

* Coal characteristics included in this table represent average values based on fuel 

shipments to the Muskogee Station. Characteristics summarized in this table are not 

intended to limit the heating value, moisture content, ash content, or sulfur content of 

fuels utilized at the Muskogee Station, as short-term coal characteristics may vary 

from the values summarized above. 

4.1 Step 1: Identify Potentially Feasible SO2 Control Options 

Several techniques can be used to reduce SO2 emissions from a pulverized coal-fired combustion 

source. SO2 control techniques can be divided into pre-combustion strategies and post-combustion 

controls. SO2 control options identified for potential application to Muskogee Units 4 & 5 are listed 

in Table 4-2. 

 

15 AP-42, Section 1.1 Bituminous and Sub-Bituminous Coal Combustion, page 1.1-3, September 1998. 
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Table 4-2 

Muskogee Generating Station 

List of Potential SO2 Retrofit Control Options

Control Strategy/Technology 

Pre-Combustion Controls 

Fuel Switching 

Coal Washing 

Coal Processing 

Post-Combustion Controls 

Wet Flue Gas Desulfurization 

Wet Lime FGD 

Wet Limestone FGD 

Wet Magnesium Enhanced Lime FGD 

Jet Bubbling Reactor FGD 

Dual Alkali Scrubber 

Wet FGD with Wet Electrostatic Precipitator 

Dry Flue Gas Desulfurization 

Spray Dryer Absorber 

Dry Sorbent Injection 

Circulating Dry Scrubber 

4.2 Step 2: Technical Feasibility of Potential Control Options 

The technical feasibility of each potential control option is discussed below. 

4.2.1 Pre-Combustion Control Strategy 

The generation of SO2 is related to the sulfur content and heating value of the fuel burned. The 

sulfur content and heating value of coal can vary dramatically depending on the source of the 

coal. Potentially feasible pre-combustion control strategies designed to reduce overall SO2

emissions are described below. 

4.2.1.1 Fuel Switching 

One potential strategy for reducing SO2 emissions is reducing the amount of sulfur 

contained in the coal. Muskogee Units 4 & 5 fire subbituminous coal as their primary fuel. 

Subbituminous coal has a relatively low heating value, low sulfur content, and low 

uncontrolled SO2 emission rate. Typical coal characteristics based on existing 
Oklahoma Gas & Electric 

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subbituminous coal shipments to OG&E’s Muskogee Generating Station are summarized in 

Table 4-1 above. 

Because of the relatively low sulfur content, subbituminous coals generate the lowest 

uncontrolled SO2 emissions. In fact, several coal-fired utilities have switched to low-sulfur 

coal as an SO2 emission control strategy. Bituminous coals from mines in the Eastern and 

Midwestern U.S. generally have higher heating values but also have a significantly higher 

sulfur content. Lignites from the upper Midwest and Texas have a relatively low sulfur 

content (but higher than subbituminous) but also have high moisture contents and relatively 

low heating values. 

Fuels currently used at the Muskogee Station generate low uncontrolled SO2 emissions. 

Switching to alternative coals (i.e., 100% bituminous coal or lignite) will not reduce 

potential uncontrolled SO2 emissions or controlled SO2 emissions from Muskogee Units 4 

& 5. No environmental benefits accrue from burning an alternative coal; therefore, fuel 

switching is not considered a feasible option for this retrofit project. 

4.2.1.2 Coal Washing 

Coal washing, or beneficiation, is one pre-combustion method that has been used to reduce 

impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by 

separating and removing inorganic impurities from organic coal particles. Inorganic 

impurities, including inorganic ash constituents and inorganic iron disulfide (FeS2 or 

pyrite), are typically more dense than the coal particles. This property is generally used in 

a wet cleaning process to separate coal particles from the inorganic impurities. 

Each coal seam has different washability characteristics depending on the characteristics of 

the inorganic constituents. Based on information available from the Kentucky Coal 

Council, inorganic sulfur in high-sulfur eastern bituminous coals may be reduced by 0.5 – 

2.5% and inorganic ash may be reduced by 9 – 15% through coal washing.16 Coal washing 

is generally done at the mine to maximize the value of the coal and reduce freight charges 

to the power plant. 

The coal washing process generates a solid waste stream consisting of inorganic materials 

separated from the coal, and a wastewater stream that must be treated prior to discharge. 

Solids generated from wastewater processing and coarse material removed in the washing 

process must be disposed in a properly permitted landfill. Solid wastes from coal washing 

 

16 See, http://www.coaleducation.org/Ky_Coal_Facts/coal_resources/coal_preparation.htm. 
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typically contain pyrites and other dense inorganic impurities including silica and trace 

metals. The solids are typically dewatered in a mechanical dewatering device and disposed 

of in a landfill. 

The wastewater stream generally consists of an acidic liquid slurry made up of water, 

uncombusted coal fines, and impurities in the coal, including calcium, trace metals, 

chloride, sulfate, and dissolved and suspended solids.17 The wastewater slurry must be 

treated to remove solids, coal fines, and trace metals prior to discharge. Coal slurry 

treatment systems may include surface impoundments, mechanical dewatering systems, 

chemical processing systems, and/or thermal dryers. 

While washing may be effective in removing rock inclusions from coal, including sulfurbearing pyrites, a significant amount of coal may also be lost in the washing process. An 

inherent consequence of coal washing, in addition to generating wastewater and solid waste 

streams, would be the need for the mine to process significantly more coal to make up for 

coal lost in the washing process. 

Muskogee Units 4 & 5 are designed to utilize subbituminous coals. Based on a review of 

available information, no information was identified regarding the washability or 

effectiveness of washing subbituminous coals. Subbituminous coals have a relatively high 

ash content and an excessive amount of fines, and significant dewatering equipment would 

be required to process and separate the fines from the wastewater stream. It is likely that 

the excess fines production, and the difficulties associated with handling and dewatering 

the fines, have restricted the commercial viability of subbituminous coal washing. 

Furthermore, the coal washing process would generate significant solid and liquid waste 

streams that would require proper management and disposal. Based on a review of 

available information, there are currently no commercial subbituminous coal washing 

facilities, and washed subbituminous coals are not available through commercial channels. 

Therefore, coal washing is not considered an available retrofit control option for Muskogee 

Units 4 & 5. 

4.2.1.3 Coal Processing 

Pre-combustion coal processing techniques have been proposed as one strategy to reduce 

the sulfur content of coal and help reduce uncontrolled SO2 emissions. Coal processing 

 

17 See, USEPA Report to Congress, Wastes from the Combustion of Fossil Fuels, Office of Solid Waste and 

Emergency Response, EPA 530-S-99-010, March 1999 (general composition of selected large-volume and 

low-volume wastes). 
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technologies are being developed to remove potential contaminants from the coal prior to 

use. 

These processes typically employ both mechanical and thermal means to increase the 

quality of subbituminous coal and lignite by removing moisture, sulfur, mercury, and heavy 

metals. In one process, raw coal from the mine enters a first stage separator where it is 

crushed and screened to remove large rock and rock material.18 The processed coal is then 

passed on to an intermediate storage facility. From the intermediate storage facility the 

coal goes to a thermal process. In this process coal passes through pressure locks into the 

thermal processors where steam at 460 o

F and 485 psi is injected. Moisture in the coal is 

released under these conditions. Mineral inclusions are also fractured under thermal stress, 

removing both included rock and sulfur-forming pyrites. After it has been treated for a 

sufficient time in the main processor, the coal is discharged into a second pressurized lock. 

The second pressurized lock is vented into a water condenser to return the processor to 

atmospheric pressure and to flash cool the coal to approximately 200 o

F. Water is removed 

from the coal at various points in the process. This water, along with condensed process 

steam, is either reused within the process or treated prior to being discharged. 

To date, the use of processed fuels has only been demonstrated with test burns in a 

pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their 

primary fuel source on an on-going, long-term basis. Although burning processed fuels, or 

a blend of processed fuels, has been tested in a pulverized coal-fired boiler, using processed 

fuels in Muskogee Units 4 & 5 would require significant research, test burns, and extended 

trials to identify potential impacts on plant systems, including the boiler, material handling, 

and emission control systems. Therefore, processed fuels are not considered commercially 

available, and will not be analyzed further in this BART analysis. 

4.2.2 Post-Combustion Flue Gas Desulfurization 

Over the past decade, post-combustion flue gas desulfurization (FGD) has been the most 

frequently used SO2 control technology for large pulverized coal-fired utility boilers. FGD 

systems typically have been installed on boilers firing high-sulfur bituminous coals. FGD 

systems, including wet scrubbers and dry scrubbers, have been designed to effectively and 

economically remove SO2 from pulverized coal-fired utility boiler flue gas. FGD systems with 

a potential applicability to Muskogee Units 4 & 5 are described below. 

 

18 The coal processing description provided herein is based on the K-Fuel® process under development by 

KFx, Inc. 
Oklahoma Gas & Electric 

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4.2.2.1 Wet Scrubbing Systems 

Wet FGD technology is an established SO2 control technology. Wet scrubbing systems 

offered by vendors may vary in design; however, all wet scrubbing systems utilize an 

alkaline scrubber slurry to remove SO2 from the flue gas. Design variations may include 

changes to increase the alkalinity of the scrubber slurry, increase slurry/SO2 contact, and 

minimize scaling and equipment problems. 

All wet scrubbing FGD systems use an alkaline slurry that reacts with SO2 in the flue gas to 

form insoluble calcium sulfite (CaSO3) and calcium sulfate (CaSO4) salts. Wet FGD 

systems may be generally categorized as lime (CaO) or limestone (CaCO3) scrubbing 

systems. The scrubbing process and equipment for either lime- or limestone scrubbing is 

similar. The alkaline slurry consisting of hydrated lime or limestone may be sprayed 

countercurrent to the flue gas, as in a spray tower, or the flue gas may be bubbled through 

the alkaline slurry as in a jet bubbling reactor. Equations 4-1 through 4-5 summarize the 

chemical reactions that take place within the wet scrubbing systems to remove SO2 from 

flue gas. 

SO2 + CaO + 1⁄2H2O → CaSO3•1⁄2H2O↓ (4-1) 

SO2 + CaO + 2H2O → CaSO4•2H2O↓ (4-2) 

SO2 + CaCO3 + H2O → CaSO3•H2O↓ + CO2 (4-3) 

CaSO3 + 1⁄2O2 + 2H2O → CaSO4•2H2O↓ (4-4) 

SO2 + 2H2O + 1⁄2 O2 + CaCO3 → CaSO4•2H2O↓ + CO2 (4-5) 

Potentially feasible wet scrubbing systems are described below. 

Wet Lime Scrubbing

The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to 

water. The alkaline slurry is sprayed in the absorber and reacts with SO2 in the flue gas. 

Insoluble CaSO3 and CaSO4 salts are formed in the chemical reaction that occurs in the 

scrubber (see equations 4-1 and 4-2), and are removed as a solid waste by-product. The 

waste by-product is made up of mainly CaSO3, which is difficult to dewater. Solid waste 

by-products from wet lime scrubbing are typically managed in dewatering ponds and 

landfills. 

Wet Limestone Scrubbing

Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO3) is mixed 

with water to formulate the alkali scrubber slurry. SO2 in the flue gas reacts with the 

limestone slurry to form insoluble CaSO3 and CaSO4 which is removed as a solid waste by-
Oklahoma Gas & Electric 

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product (see equations 4-3 and 4-4). The use of limestone instead of lime requires different 

feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio 

typically requires a larger absorbing unit. The limestone slurry process also requires a ball 

mill to crush the limestone feed. 

Forced oxidation of the scrubber slurry can be used with either the lime or limestone wet 

FGD system to produce gypsum solids instead of the calcium sulfite by-product. Air blown 

into the reaction tank provides oxygen to convert most of the calcium sulfite (CaSO3) to 

relatively pure gypsum (calcium sulfate) as shown in equation 4-4. Forced oxidation of the 

scrubber slurry provides a more stable by-product and reduces the potential for scaling in 

the FGD. The gypsum by-product from this process must be dewatered, but may be salable 

thus reducing the quantity of solid waste that needs to be landfilled. 

Wet scrubbing systems using limestone as the reactant have demonstrated the ability to 

achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing 

high-sulfur bituminous coals. Wet lime and limestone FGD control systems with forced 

oxidation are technically feasible SO2 retrofit technologies. However, wet scrubbing 

systems have not been used on large boilers firing subbituminous coals, and the actual 

control efficiency of a wet FGD system will depend on several factors, including the 

uncontrolled SO2 concentration entering the system. Based on engineering judgment it is 

expected that a wet lime or limestone FGD control system with forced oxidation could 

achieve average controlled SO2 emissions in the range of 0.08 lb/mmBtu (30-day rolling 

average) on Muskogee Units 4 & 5. 

Wet lime and wet limestone scrubbing systems will achieve the same SO2 control 

efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the 

more attractive option. For this reason, wet lime scrubbing will not be evaluated further in 

this BART determination. 

Wet Magnesium Enhanced Lime Scrubbing

Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD 

technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide 

(MgO) and 90 – 95% calcium oxide (CaO). The presence of magnesium effectively 

increases the dissolved alkalinity, and consequently makes SO2 removal less dependent on 

the dissolution of the lime/limestone. In normal lime/limestone spray-tower operation the 

amount of SO2 absorbed depends principally upon the soluble-alkali content of the 

absorbing slurry. When magnesium is present, the soluble alkali level of the absorbent 

increases primarily because of the presence of sulfite and bicarbonate salts of magnesium. 
Oklahoma Gas & Electric 

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As these magnesium alkalies are more soluble than the corresponding calcium alkalies, 

there is an increase in the SO2 absorption capacity of the slurry.19

Commercial operation of wet FGD systems has shown that soluble Mg in the absorbing 

slurry can improve SO2 removal efficiency.20 MEL scrubbers have been installed on coalfired utility boilers located in the Ohio River Valley.21 Most are located in a corridor from 

Pittsburgh, Pennsylvania to Evansville, Indiana, and use a reagent that naturally contains 

approximately 5% MgO. Because of the increased alkalinity in the scrubbing liquid, MEL 

wet scrubbing systems have demonstrated the ability to achieve SO2 removal efficiencies 

equivalent to wet lime/limestone scrubbers using smaller absorber towers. 

Solids from the MEL FGD process consist primarily of calcium sulfite and magnesium 

sulfite solids. Dewatering the sulfite solids from an unoxidized MEL FGD system can be 

difficult, and produces a filter cake consisting of approximately 40-50% solids. Typically, 

unoxidized MEL FGD filter cake is fixed using fly ash and landfilled. This continues to be 

one of the drawbacks of the unoxidized MEL FGD process. Systems to oxidize the MEL 

solids to produce a usable gypsum byproduct consisting of calcium sulfate (gypsum) and 

magnesium sulfate continue to be developed.22

Wet limestone FGD control systems can be designed to achieve the same control 

efficiencies as the magnesium enhanced limestone systems. However, to achieve the same 

control efficiencies, limestone-based systems require a higher liquid-to-gas ratio, and 

therefore larger absorber towers. Coal-fired units equipped with MEL FGD typically fire 

high-sulfur eastern bituminous coal and use locally available reagent. There are no 

subbituminous-fired units equipped with a MEL-FGD system. 

Because MEL-FGD systems have not been used on subbituminous-fired boilers, and 

because of the cost and limited availability of magnesium enhanced reagent (either 

naturally occurring or blended), and because limestone-based wet FGD control systems can 

be designed to achieve the same control efficiencies as the magnesium enhanced systems, 

MEL-FGD control systems will not be evaluated further as a commercially available 

retrofitted control system. 

 

19 Combustion Fossil Power, page 15-43. 

20 Combustion Fossil Power, page 15-42. 

21 Nolan, P.S., “Flue Gas Desulfurization Technologies for Coal-Fired Power Plant,” Coal-Tech 2000 

International Conference, November 13-14, 2000. 22 See, Benson, L., Babu, M., Smith, K., “New Magnesium-Enhanced Lime FGD Process,” Dravo Lime, Inc. 

– Technology Center. 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

40 

Jet Bubbling Reactor

Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike 

the spray tower wet FGD systems, where the scrubbing slurry contacts the flue gas in a 

countercurrent reaction tower, in the JBR-FGD flue gas is bubbled through a limestone 

slurry. Spargers are used to create turbulence within the reaction tank and maximize 

contact between the flue gas bubbles and scrubbing slurry. SO2 in the flue gas reacts with 

the limestone slurry to form insoluble CaSO3 and CaSO4 which is removed as a solid waste 

by-product (see equations 4-3, 4-4, and 4-5). Flue gas exits from the reaction vessel 

through mist eliminators to reduce carryover of the reactant. 

Although the reaction vessel used to contact flue gas with the scrubbing slurry is different 

than the spray tower used in a conventional wet FGD system, JBR-FGD systems use the 

same reaction chemistry to remove SO2 from the flue gas. JBR-FGD systems do not 

require the large slurry pumps associated with other wet FGD technologies; however, 

auxiliary power is shifted to larger fans, booster fans, agitators, and oxidation air blowers to 

accommodate the larger pressure drop through the system. 

There are currently a limited number of commercially operating JBR-WFGD control 

systems installed on coal-fired utility units in the U.S. A JBR-WFGD control system was 

installed at Georgia Power’s 100 MW coal-fired Yates plant in 1992. Based on publicly 

available emissions data, the Yates Plant has an average inlet SO2 concentration of 

approximately 3,500 ppm, and has achieved average SO2 removal efficiencies of 

approximately 93%. In addition to the Yates Plant, a JBR control system has been in use at 

the 40 MW equivalent Abbott Steam plant at the University of Illinois. 

Most of the JBR-WFGD control experience has been in Japan. Chiyoda Corporation has 

installed JBR-WFGD systems on several coal-fired plants overseas. Based on information 

available on Chiyoda’s website, a majority of the plants equipped with JBR-WFGD are 

smaller units (e.g., less then 200 MW); however, Chiyoda lists JBR-WFGD systems in 

operation on three plants located overseas in the 600 MW range. Commercial deployment 

of the JBR-WFGD control system continues to develop in the U.S. A project experience 

list available from Chiyoda identifies several U.S. power plants that have decided to install 

JBR-WFGD control systems, with control system startup dates between 2008 and 2010. 

Although the commercial deployment of the control system continues, there is still a very 

limited number of operating units in the U.S. Furthermore, coal-fired boilers currently 

considering the JBR-WFGD control system are all located in the eastern U.S., and all fire 

eastern bituminous coals. The control system has not been proposed as a retrofit 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

41 

technology on any large subbituminous coal-fired boilers. However, other than scale-up 

issues, there do not appear to be any overriding technical issues that would exclude 

application of the control technology on a large subbituminous coal-fired unit. 

Assuming that the JBR-WFGD control system is commercially available for Muskogee 

Units 4 & 5, the JBR is essentially a wet FGD scrubbing system. Unlike the spray tower 

systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, 

in the JBR-WFGD flue gas is bubbled through the limestone slurry. SO2 in the flue gas 

reacts with the limestone slurry to form insoluble calcium sulfate and calcium sulfite, 

which is removed as a solid waste by-product. Although the reaction vessel used to contact 

flue gas with the scrubbing slurry uses a different design, the reaction chemistry to remove 

SO2 from the flue gas is the same for all wet FGD designs. 

There are no data available to conclude that the JBR-WFGD control system will achieve a 

higher SO2 removal efficiency than a more traditional spray tower WFGD design, 

especially on units firing low-sulfur subbituminous coal. Furthermore, the costs associated 

with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to 

the costs and control efficiencies achievable with spray tower WFGD control systems. 

Therefore, the JBR-WFGD will not be evaluated as a unique retrofit technology, but will be 

included in the overall assessment of WFGD controls. 

Dual-Alkali Wet Scrubber

Dual-alkali scrubbing is a desulfurization process that uses a sodium-based alkali solution 

to remove SO2 from combustion exhaust gas. The process uses both sodium-based and 

calcium-based compounds. The sodium-based reagent absorbs SO2 from the exhaust gas, 

and the calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium 

sulfites and sulfates are precipitated and discarded as sludge, while the regenerated sodium 

solution is returned to the absorber loop. 

The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with lime or 

limestone. The reduced liquid-to-gas ratios generally mean smaller reaction units, however 

additional regeneration and sludge processing equipment is necessary. 

The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide, 

sodium carbonate and sodium sulfite, is an efficient SO2 control reagent. However, the 

high cost of the sodium-based chemicals limits the feasibility of such a unit on a large 

utility boiler. In addition, the process generates a less stable sludge that can create material 

handling and disposal problems. 
Oklahoma Gas & Electric 

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42 

It is projected that a dual-alkali system could be designed to achieve SO2 control similar to 

a limestone-based wet FGD. However, because of the limitations discussed above, and 

because dual-alkali systems are not currently commercially available, dual-alkali scrubbing 

systems will not be addressed further in this BART determination. 

 

Wet FGD with Wet Electrostatic Precipitator

Wet FGD systems can result in increased emissions of condensable particulates and acid 

gases. In particular, SO3 generated in the unit’s boiler can react with moisture in the wet 

FGD to generate sulfuric acid mist. Sulfuric acid mist emissions from boilers firing high 

sulfur coals and equipped SCR and wet FGD can contribute to significant opacity problems 

if the H2SO4 concentration in the stack gas exceeds approximately 15 ppm.23 

Wet electrostatic precipitation (WESP) has been proposed on other coal-fired projects as 

one technology to reduce sulfuric acid mist emissions from coal-fired boilers. WESPs have 

been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet 

FGD.24 WESP has been demonstrated as an effective control technology to abate sulfuric 

acid mist emissions from industrial applications with relatively low flue gas flow rates and 

high acid mist concentrations, such as sulfuric acid plants. However, until recently, the 

technology has not been applied to the utility industry because of the high gas flow 

volumes and low acid mist concentrations associated with utility flue gas. 

In a utility application, the WESP would be located downstream from the wet FGD to 

remove micron-sized sulfuric acid aerosols from the flue gas stream as a condensable 

particulate. Electrostatic precipitation consists of three steps: (1) charging the particles to 

be collected via a high-voltage electric discharge, (2) collecting the particles on the surface 

of an oppositely charged collection electrode surface, and (3) cleaning the surface of the 

collecting electrode. In a WESP system, the collecting electrodes are typically cleaned 

with a liquid wash. Particulate mass loading, particle size distribution, particulate electrical 

resistivity, and precipitator voltage and current will influence ESP performance. The wet 

cleaning mechanism can also affect the nature of the particles that can be captured, and the 

performance efficiencies that can be achieved. 

 

23 See, Duellman, D.M., Erickson, C.A., Licata, T., Operating Experience with SCR’s and High Sulfur Coals 

& SO3 Plumes, presented at the ICAC NOx Forum, February 2002. 

24 See for example, the Thoroughbred Generating Station PSD Permit Application submitted to the Kentucky 

Department of Environmental Protection, and the Prairie States Energy Center PSD Permit Application 

submitted to the Illinois Environmental Protection Agency. 
Oklahoma Gas & Electric 

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43 

WESP has not been widely used in utility applications, and has only been proposed on 

boilers firing high sulfur coals and equipped with SCR. Muskogee Units 4 & 5 fire lowsulfur subbituminous coal. Based on the fuel characteristics listed in Table 4-1, and 

assuming 1% SO2 to SO3 conversion in the boiler, potential uncontrolled H2SO4 emissions 

from Muskogee Units 4 & 5 will only be approximately 5 ppm. This emission rate does 

not take into account inherent acid gas removal associated with alkalinity in the 

subbituminous coal fly ash. Based on engineering judgment, it is unlikely that a WESP 

control system would be needed to mitigate visible sulfuric acid mist emissions from 

Muskogee Units 4 & 5, even if WFGD control was installed. 

WESPs have been proposed to control condensable particulate emissions from boilers 

firing a high-sulfur bituminous coal and equipped with SCR and wet FGD. This 

combination of coal and control equipment results in relatively high concentrations of 

sulfuric acid mist in the flue gas. WESP control systems have not been proposed on units 

firing subbituminous coals, and WESP would have no practical application on a 

subbituminous-fired units. Therefore, the combination of WFGD+WESP will not be 

evaluated further in this BART determination. 

Wet FGD Scrubbing - Conclusions

Wet FGD technology is an established SO2 control technology. Wet scrubbing systems 

have been designed to utilize various alkaline scrubbing solutions including lime, 

limestone, and magnesium-enhanced lime. Wet scrubbing systems may also be designed 

with spray tower reactors or reaction vessels (e.g., jet bubbling reactor). Although the flue 

gas/reactant contact systems may vary, the chemistry involved in all wet scrubbing systems 

is essentially identical. A large majority of the wet FGD systems designed to remove SO2

from existing high-sulfur utility boilers have been designed as wet limestone scrubbers with 

spray towers and forced oxidation systems. 

Wet scrubbing systems using limestone as the reactant have demonstrated the ability to 

achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing 

high-sulfur bituminous coals. The chemistry of wet scrubbing consists of a complex series 

of kinetic and equilibrium-controlled reactions occurring in the gas, liquid and solid phases. 

In general, the amount of SO2 removed from the flue gas is governed by the vapor-liquid 

equilibrium between SO2 in the flue gas and the absorbent liquid. If no soluble alkaline 

species are present in the liquid, the liquid quickly becomes saturated with SO2 and 

absorption is limited.25 Likewise, as the flue gas SO2 concentration goes down, absorption 

 

25 Combustion Fossil Power – A Reference Book on Fuel Burning and Steam Generation, edited by Joseph P. 

Singer, Combustion Engineering, Inc., 4th ed., 1991 (pp. 15-41). 
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44 

will be limited by the SO2 equilibrium vapor pressure. Therefore, high control efficiencies 

would not be expected on a boiler firing low sulfur coals because of the reduced SO2

concentration in the boiler flue gas. 

Although WFGD control systems have not been used on subbituminous coal-fired units 

there are no technical limitations that would preclude its use on Muskogee Units 4 & 5. 

Therefore, WFGD is determined to be a technically feasible SO2 control retrofit 

technology. Based on the fuel characteristics listed in Table 4-1, taking into consideration 

the reduced SO2 concentration in the flue gas and reduced SO2 loading to the scrubbing 

system, and allowing a reasonable operating margin to account for normal operating 

conditions (e.g., load changes, changes in fuel characteristics, and minor equipment upsets) 

it is concluded that a WFGD retrofit control system could achieve a controlled SO2 rate of 

0.08 lb/mmBtu (30-day average). 

4.2.2.2 Dry Flue Gas Desulfurization 

Another scrubbing system that has been designed to remove SO2 from coal-fired 

combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or 

hydrated lime slurry into a reaction tower where it reacts with SO2 in the flue gas to form 

calcium sulfite solids (see equations 4-1 and 4-2). Dry scrubbing includes a separate lime 

preparation system and reaction tower. Unlike wet FGD systems that produce a slurry byproduct that is collected separately from the fly ash, dry FGD systems produce a dry byproduct that must be removed with the fly ash in the particulate control equipment. 

Therefore, dry FGD systems must be located upstream of the particulate control device to 

remove the reaction products and excess reactant material. 

Various dry FGD systems have been designed for use with pulverized coal-fired boilers. 

Dry scrubbing systems that may be technically feasible on Muskogee Units 4 & 5 are 

discussed below. 

Spray Dryer Absorber

Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications. 

SDA systems have demonstrated the ability to effectively reduce uncontrolled SO2

emissions from pulverized coal units. 

The typical spray dryer absorber uses a slurry of lime and water injected into the tower to 

remove SO2 from the combustion gases. The towers must be designed to provide adequate 

contact and residence time between the exhaust gas and the slurry to produce a relatively 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

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45 

dry by-product. The process equipment associated with a spray dryer typically includes an 

alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate 

control device and a recycle system. The recycle system collects solid reaction products 

and recycles them back to the spray dryer feed system to reduce alkaline sorbent use. 

Various process parameters affect the efficiency of the SDA process including: the type and 

quality of the additive used for the reactant, reactant stoichiometric ratio, how close the 

SDA is operated to saturation conditions, and the amount of solids product recycled to the 

atomizer. The control efficiency of a SDA system is limited to approximately 94% of the 

SO2 loading to the system, and is a function of numerous operating variables including gasto-liquid contact and system operating temperatures. 

In a dry FGD system, the amount of reactant slurry introduced to the spray dryer must be 

controlled to insure that the reaction products leaving the absorber vessel are dry. 

Therefore, the outlet temperature from the absorber must be maintained above the 

saturation temperature. SDA systems are typically designed to operate within 

approximately 30 o

F adiabatic approach to the saturation temperature. Operating closer to 

the adiabatic saturation temperature allows higher SO2 control efficiencies; however, outlet 

temperatures too close to the saturation temperature will result in severe operating 

problems including reactant build-up in the absorber modules, blinding of the fabric filter 

bags, and corrosion in the fabric filter and ductwork. 

High SO2 removal efficiencies in a SDA are also dependent upon good gas-to-liquid 

contact. Reactant spray nozzle designs are vendor-specific; however, both dual-fluid 

nozzles and rotary atomizers have been used in large coal-fired boiler applications. 

Dual-fluid nozzles (slurry and atomizing air) typically consist of a stainless steel head with 

multiple, ceramic two-fluid nozzle inserts. Slurry enters through the nozzle head and is 

distributed to the nozzle inserts. Atomizing air enters concentrically into a reservoir in the 

nozzle head and mixes with the slurry. The atomizing air expands as it passes through the 

air holes and nozzle exit. This expansion creates the shear necessary to atomize the slurry. 

Each nozzle is provided with a feed lance assembly consisting of a concentric feed pipe (air 

around slurry), hose connections, and the nozzle head. The feed lance assembly is inserted 

down through the SDA roof through a nozzle shroud assembly. 

Rotary atomizers are comprised basically of a high-speed rotating atomizer wheel coupled 

to a drive device and speed-increasing gear box. Because the reactant slurry is abrasive, the 

atomizing nozzles typically consist of a stainless steel head and multiple abrasion-resistant 
Oklahoma Gas & Electric 

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46 

ceramic nozzle inserts. The rotary atomizers are inserted down through the SDA roof. The 

reactant slurry is atomized as it passes through the rapidly rotating nozzles. 

The atomizing nozzle assembly (either the duel-fluid feed lance assembly or the rotary 

atomizer assembly) is typically located in the SDA penthouse, and flange mounted to the 

roof of the absorber vessel. Overhead cranes or hoists located in the penthouse can be used 

to remove the nozzle assemblies from the absorber vessel for repair and maintenance. 

Because of the abrasive nature of the reactant slurry, nozzle assemblies must be removed 

and replaced on a routine basis. Depending on the design of the SDA system, one or more 

spare nozzle assemblies will be available for use. The nozzle assemblies may be changed 

without shutting down the SDA system. During that time period, the SDA may not be able 

to maintain maximum control efficiencies. 

SDA control systems are a technically feasible and commercially available retrofit 

technology for Muskogee Units 4 & 5. Based on the fuel characteristics listed in Table 4-1 

and allowing a reasonable margin to account for normal operating conditions (e.g., load 

changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor 

equipment upsets) it is concluded that dry FGD designed as SDA could achieve a 

controlled SO2 emission rate of 0.10 lb/mmBtu (30-day average) on an on-going long-term 

basis. 

Dry Sorbent Injection

Dry sorbent injection involves the injection of powdered absorbent directly into the flue gas 

exhaust stream. Dry sorbent injection systems are simple systems, and generally require a 

sorbent storage tank, feeding mechanism, transfer line and blower and an injection device. 

The dry sorbent is typically injected countercurrent to the gas flow. An expansion chamber 

is often located downstream of the injection point to increase residence time and efficiency. 

Particulates generated in the reaction are controlled in the system’s particulate control 

device. 

Typical SO2 control efficiencies for a dry sorbent injection system are generally around 

50%. Because the control efficiency of the dry sorbent system is lower then the control 

efficiency of either the wet FGD or SDA, the system will not be evaluated further. 

Circulating Dry Scrubber

A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system 

uses a circulating fluidized bed of dry hydrated lime reagent to remove SO2. Flue gas 
Oklahoma Gas & Electric 

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47 

passes through a venturi at the base of a vertical reactor tower and is humidified by a water 

mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime where 

SO2 is removed. The dry by-product produced by this system is similar to the spray dry 

absorber by-product, and is routed with the flue gas to the particulate removal system. 

Based on engineering judgment and information available from equipment vendors, the 

CDS flue gas desulfurization system should be capable of achieving SO2 removal 

efficiencies similar to those achieved with a spray dryer absorber. In fact, vendors advise 

that the CDS system is capable of achieving even higher removal efficiencies with 

increased reactant injection rates and higher Ca/S stoichiometric ratios. However, to date 

the CDS has had limited application, and has not been used on large pulverized coal 

boilers. The largest CDS unit, in Austria, is on a 275 MW size oil-fired boiler burning oil 

with a sulfur content of 1.0 to 2.0%. Operating experience on smaller pulverized coal 

boilers in the U.S. has shown high lime consumption rates, and significant fluctuations in 

lime utilization based on inlet SO2 loading.26 Furthermore, CDS systems result in high 

particulate loading to the unit’s particulate control device. 

Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely 

that OG&E would be required to conduct extensive design engineering to scale up the 

technology for boilers the size of Muskogee Units 4 & 5, and that OG&E would incur 

significant time and resource penalties evaluating the technical feasibility and long-term 

effectiveness of the control system. Because of these limitations, CDS dry scrubbing 

systems are not currently commercially available as a retrofit control technology for 

Muskogee Units 4 & 5, and will not be evaluated further in this BART determination. 

The results of Step 2 of the SO2 BART analysis (technical feasibility analysis of potential SO2

control technologies) are summarized in Table 4-3. 

 

26 See, Lavely, L.L., Schild, V.S., and Toher, J., “First North American Circulating Dry Scrubber and 

Precipitator Remove High Levels of SO2 and Particulate”, 
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Table 4-3 

Muskogee Units 4 & 5 

Technical Feasibility of Potential SO2 Control Technologies 

In Service on 

Existing PC 

Boilers? 

Control 

Technology 

SO2 Emission Rate 

(lb/mmBtu) Yes No 

In Service on 

Other 

Combustion 

Sources? 

Technically Feasible Retrofit 

Technology for Muskogee Units 

4 & 5? 

Fuel Switching NA X PCs have been 

designed to burn a 

variety of fuels. 

Not technically feasible. The fuel 

currently used is low-sulfur and 

fuel switching will not reduce 

controlled SO2 emissions. 

Coal Washing NA X Washing has not 

been used on subbituminous coals. 

Not technically feasible nor 

commercially available. 

Coal washing has not been used 

on subbituminous coals and 

washed subbituminous coal is not 

commercially available. 

Furthermore, it is unlikely that 

firing a washed subbituminous 

coal would result in any 

significant reduction in controlled 

SO2 emissions. 

Coal Processing -- X Processed coal has 

been demonstrated 

in PC boilers. 

Not technically available nor 

commercially available. 

Processed coal has not been 

demonstrated on a long-term 

basis as the primary flue in a PC 

boiler, and is not commercially 

available as a retrofit technology. 

Wet FGD 

(lime, limestone, 

or magnesium 

enhanced lime) 

0.08 lb/mmBtu 

(approx. 40 ppmvd @ 

3% O2) 

X 

Wet FGD has been 

used on bituminous 

coal-fired PC 

boilers. 

Technically feasible, however 

limited commercial experience 

with wet FGD on large 

subbituminous fired units. 

Jet Bubbling 

Reactor Wet 

FGD Control 

System 

0.08 lb/mmBtu 

(approx. 40 ppmvd @ 

3% O2) 

X 

JBR-FGD systems 

are in use on a 

limited number of 

coal-fired boilers. 

Technically feasible, but may not 

be commercially available for 

Muskogee Units 4 & 5 (large subbituminous fired units). Because 

there is no operating experience 

with JBR-WFGD systems on 

large subbituminous-fired units, 

the control system was evaluated 

as an alternative WFGD control 

system. 

Dual-Alkali Wet 

Scrubber NA X 

In use at a limited 

number of coalfired facilities. 

Not commercially available. 
Oklahoma Gas & Electric 

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Table 4-3 continued: 

In Service on 

Existing PC 

Boilers? 

Control 

Technology 

SO2 Emission Rate 

(lb/mmBtu) Yes No 

In Service on 

Other 

Combustion 

Sources? 

Technically Feasible Retrofit 

Technology for Muskogee Units 

4 & 5? 

Wet FGD with 

WESP NA X 

The WESP control 

system is in use at 

a limited number of 

high-sulfur coalfired units. 

Not technically feasible nor 

commercially available for units 

firing a low-sulfur subbituminous 

coal. 

Dry FGD – Spray 

Dryer Absorber 

0.10 lb/mmBtu 

(approx. 50 ppmvd @ 

3% O2) 

X 

In use on subbituminous coalfired boilers. 

Technically feasible. 

Dry Sorbent 

Injection 

0.4 lb/mmBtu 

(approx. 200 ppmvd 

@ 3% O2) 

X 

Dry sorbent 

injection has been 

used on a limited 

number of coalfired units. 

Technically feasible, but not as 

effective as other SO2 control 

options therefore excluded as 

BART. 

Circulating Dry 

Scrubber NA X 

CDS is in use at a 

limited number of 

coal-fired boilers. 

CDS Dry FGD was determined 

not to be commercially available 

for Muskogee Units 4 & 5 (large 

sub- bituminous fired units). In 

addition, there is no commercial 

experience with units similar to 

Muskogee Units 4 & 5, so CDSDFGD was excluded as BART. 

Step 3: Rank the Technically Feasible SO2 Control Options by Effectiveness 

Both technically feasible SO2 retrofit technologies (i.e., Wet- and Dry-FGD) are capable of meeting 

the BART presumptive level of 0.15 lb/mmBtu. However, in order to evaluate the cost 

effectiveness of each control technology, annual emissions and costs were estimated at the design 

emission limits of 0.08 lb/mmBtu for WFGD and 0.10 lb/mmBtu for DFGD. This approach was 

taken in order to determine whether either control technology was cost effective at the anticipated 

design emission rate. The technically feasible SO2 control technologies are listed in Table 4-4 in 

descending order of control efficiency based on anticipated design emission rates. 
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Table 4-4 

Summary of Technically Feasible SO2 Control Technologies 

SO2 Emission Rate* 

(lb/mmBtu) 

Control Technology 

Muskogee 4 Muskogee 5 

Wet FGD 0.08 0.08 

Dry FGD – Spray Dryer Absorber 0.10 0.10 

Baseline Uncontrolled SO2 Emissions 0.80 0.85 

* Emission rates are based on 30-day rolling averages that can be achieved on 

an on-going long-term basis under all normal operating conditions. 

4.3 Step 4: Evaluate the Technically Feasible SO2 Control Technologies 

Two post-combustion flue gas desulfurization control system designs (WFGD and SDA) are 

technically feasible and capable of achieving very low SO2 emission rates. An evaluation of the 

economic, energy and environmental impacts associated with each control system is provided 

below. 

4.3.1 Economic Evaluation 

 Summarized in Table 4-5 are the expected controlled SO2 emission rates and annual SO2 mass 

emissions associated with each technically feasible control technology. Table 4-6 presents the 

capital costs and annual operating costs associated with building and operating each control 

system on Muskogee Units 4 & 5. Table 4-7 shows the average annual and incremental cost 

effectiveness for each SO2 control system. 

Table 4-5 

Muskogee Units 4 & 5 

Annual SO2 Emissions (per boiler) 

Control Muskogee 4 Muskogee 5

Technology

SO2 Emissions 

(lb/mmBtu)

Emissions 

(tpy)*

Reduction in 

Emissions (tpy)*

Emissions 

(tpy)*

Reduction in 

Emissions (tpy)*

Wet FGD 0.08 1,728 15,554 1,728 16,634 

Dry FGD – SDA 0.10 2,160 15,122 2,160 16,202 

Baseline 0.80 (Unit 4) 

0.85 (Unit 5) 

17,282 -- 18,362 -- 

* Annual emissions and annual emission reductions for the BART analysis were calculated based on a full 

load heat input of 5,480 mmBtu/hr (per boiler), and assuming 7,884 hours/year (90% capacity factor). 
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Table 4-6 

Muskogee Units 4 & 5 

SO2 Emission Control System Cost Summary (each boiler)* 

Control 

Technology 

Total Capital 

Investment 

($) 

Total Capital 

Investment 

($/kW-gross) 

Annual Capital 

Recovery Cost 

($/year) 

Annual 

Operating Costs 

($/year) 

Total Annual 

Costs 

($/year) 

Wet FGD $418,567,000 $732 $35,917,500 $41,412,800 $77,067,900 

Dry FGD – SDA $373,106,000 $708 $32,016,400 $39,051,500 $71,330,300 

* Capital costs for SO2 control systems will be essentially equal for Units 4 and 5. Capital costs include the cost of 

major components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and 

insulation for the control system. Capital costs for the Wet FGD scenario include the cost of new chimneys on both 

units, and capital costs for the Dry FGD scenario include the cost of a post-scrubber fabric filter baghouse. 

Table 4-7 

Muskogee Units 4 & 5 

SO2 Emission Control System Cost Effectiveness (total for two boilers) 

Control Technology 

Total Annual 

Cost* 

($/year) 

Annual Emission 

Reduction 

(tpy) 

Average Annual 

Cost 

Effectiveness 

($/ton) 

Incremental 

Annual Cost 

Effectiveness** 

($/ton) 

Wet FGD $154,135,800 32,188 $4,789 $13,281 

Dry FGD – SDA $142,660,600 31,324 $4,554 -- 

* Total annual costs in this table reflect total costs (capital and O&M) for both units. Costs are slightly more 

than double the total annual costs for Unit 4 because of the higher baseline emission rate on Unit 5. 

**Incremental cost effectiveness of the wet FGD control systems compared to the SDA control system. 

The average cost effectiveness of the potentially feasible SO2 control technologies range from 

approximately $4,554/ton for dry FGD to $4,789/ton for wet FGD. To support the BART 

rulemaking process, EPA calculated the cost effectiveness of both wet- and dry-FGD systems. 

Based on EPA’s analysis, the average cost effectiveness for controlling all BART-eligible 

EGUs greater than 200 MW without existing SO2 controls was estimated at $919 per ton SO2

removed. Moreover, the range of cost effectiveness numbers demonstrated that the majority of 

these units could meet the presumptive SO2 emission limits at a cost of $400 to $2,000 per ton 

of SO2 removed (see, 70 FR 39133). Therefore, the average effectiveness of SO2 removal at 

Muskogee Units 4 & 5 is more than double the average cost effectiveness calculated by EPA 

for SO2 control on large EGUs. EPA’s calculation of average cost effectiveness included 

specific estimates for the Muskogee Generating Station. EPA estimated that the least cost 

alternative for Muskogee would be dry FGD with estimated cost effectiveness ranging from 

$1,690/ton to $1,697/ton. As demonstrated by Table 4-7, the actual cost effectiveness of dry 

FGD is actually over 265% worse than the cost effectiveness estimated by EPA for a least cost 

scrubber installation at Muskogee. 
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Although the wet FGD control system may provide an incremental reduction in overall SO2

emissions from Muskogee Units 4 & 5, the incremental costs associated with the additional SO2

reductions are significantly higher than the average cost effectiveness of either control system. 

Wet FGD systems have a higher initial capital requirement (compared to dry systems), require 

more energy to operate, and have somewhat higher annual operating costs. The total annual 

costs for wet FGD control systems on Muskogee Units 4 & 5 are estimated to be approximately 

$11,465,200/year higher than the total annual costs for dry FGD systems. The incremental cost 

effectiveness of the wet FGD systems is estimated to be approximately $13,281/ton, which is 

substantially higher than the average cost effectiveness of the dry FGD control systems 

($4,554/ton). The additional costs associated with wet FGD would result in significant 

economic impacts on the Muskogee Generating Station (e.g., $11,465,200 per year additional 

costs). Therefore, wet FGD should not be selected as BART based on lack of cost 

effectiveness. 

4.3.2 Environmental Impacts of Wet FGD 

In addition to the economic impacts, there are several collateral environmental impacts 

associated with a wet FGD system. First, wet FGD systems generate a calcium sulfate waste 

by-product that must be properly managed. Historically, solid wastes generated from wet FGD 

systems have been dewatered and disposed of in landfills. Most new wet FGD systems utilize a 

forced oxidation system that results in a gypsum by-product that can sometimes be sold into the 

local gypsum market. If an adequate local gypsum market is not available, the gypsum byproduct will require proper disposal. 

Second, wet FGD systems will result in greater particulate matter emissions from the following 

sources: 

1. SO3 remaining in the flue gas will react with moisture in the wet FGD to generate 

sulfuric acid mist. Sulfuric acid mist is classified as a condensable particulate. 

Condensable particulates from the wet FGD system can be captured using additional 

emission controls (e.g., WESP). However the effectiveness of a WESP system on a 

subbituminous fired unit has not been demonstrated and the additional cost of the 

WESP system significantly increases the cost of SO2 control. 

2. Wet FGD systems must be located downstream of the unit’s particulate control device; 

therefore, dissolved solids from the wet FGD system will be emitted with the wet FGD 

plume. Wet FGD control systems also generate lower stack temperatures that can 

reduce plume rise and result in a visible moisture plume. 

3. Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore 

the limestone handling system and storage piles will generate more fugitive dust 

emissions. 
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Third, wet FGD systems also require significantly more water than the dry systems. Based on 

preliminary engineering calculations, it is estimated that a wet FGD system would require 

approximately 650 million gallons per year (total for both units based on a 90% capacity), 

which represents an increase of about 30% over water consumption associated with dry FGD 

control systems. Water consumption is an important factor when assessing potential 

environmental impacts, and it is beneficial to minimize water consumption and maximize water 

recycle/reuse as much as practical. 

Finally, wet FGD systems generate a wastewater stream that must be treated and discharged. 

Wet FGD wastewater consists of a saturated solution of calcium sulfate, calcium sulfite, 

sodium chloride, with trace amounts of flyash and unreacted limestone. Traces of metal ions 

will also be present due to flyash carryover from the flue gas to the FGD scrubber liquor. Wet 

FGD wastewater treatment systems typically require calcium sulfate/sulfite desaturation, heavy 

metals precipitation, coagulation/precipitation, and sludge dewatering. Treated wastewater is 

typically discharged to surface water pursuant to an NPDES discharge permit, and solids are 

typically disposed of in a landfill. Dry FGD control systems are designed to evaporate water 

within the reaction vessel, and therefore do not generate a wastewater stream. 

4.3.3 Environmental Impacts of Dry Scrubbing 

Collateral environmental impacts are less significant with dry scrubbing systems (spray dryer 

absorber). First, dry scrubbing systems utilize lime as the reactant rather than limestone. Limebased scrubbing systems use less reactant than limestone-based systems, reducing overall 

particulate matter emission from the facility’s material handling system. Lime in a dry 

scrubbing system will be hydrated prior to use. It is estimated, based on preliminary 

engineering calculations, that a dry system would require approximately 440 million gallons 

per year (total for both units based on 90% capacity factor); however, water consumption with a 

dry system is approximately 30% less than the water requirements for a wet system. 

Furthermore, water used to hydrate the lime will be evaporated in the absorber vessel, and dry 

FGD systems will not generate a wastewater stream. 

Dry scrubbing systems are located upstream of the unit’s particulate control device. FGD 

solids mixed with fly ash will be captured in the particulate control device. The mixture of dry 

FGD solids and fly ash is generally not salable, however the material does not require 

dewatering and is easily landfilled. Assuming the unit is equipped with a fabric filter baghouse 

for particulate control, the alkaline filter cake associated with the dry scrubber will augment the 

capture of acid gases (including sulfuric acid), and will minimize condensable particulate 

emissions without the need for additional controls (e.g., WESP). 
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4.3.4 SO2 Control – Energy Impacts 

Both FGD control systems have significant auxiliary power requirements. Auxiliary power is 

required for material handling, reactant preparation, pumps, mixers, and to overcome 

significant pressure drops through the reaction vessels. Based on engineering estimates, 

auxiliary power requirement for wet and dry FGD control systems are approximately 2.25% 

and 1.5% of the gross energy output of the generating unit, respectively. Muskogee Units 1 & 

2 have a gross rating of 572 MW (each); therefore, annual auxiliary power requirements for 

FGD control systems would be in the range of 135,000 to 200,000 MWh per year (at a 90% 

capacity factor). Energy impacts associated with each control technology were included in the 

BART economic impact evaluation as an auxiliary power cost. 

A summary of the Step 4 economic and environmental BART impact analysis is provided in Table 

4-8. 

Table 4-8 

Muskogee Units 4 & 5 

Summary of SO2 BART Impact Analysis*

Control 

Technology 

Annual 

Emissions 

(tpy) 

Annual 

Emission 

Reductions 

(tpy) 

Total 

Annual 

Costs 

($/year) 

Average 

Cost 

Effectiveness 

($/ton) 

Incremental 

Cost 

Effectiveness 

($/ton) 

Summary of Collateral 

Environmental Impacts 

Wet FGD 3,456 32,188 $154,135,800 $4,789 $13,281 Increased PM emissions, 

including sulfuric acid mist and 

other condensable particulates. 

Increased NOx, CO, VOC, and 

PM10 emissions associated with 

decreased unit heat rate and 

increased energy consumption. 

Increased water use and 

wastewater treatment/discharge. 

DFGD-SDA 4,320 31,342 $142,660,600 $4,554 NA Less water required. Increased 

solid waste generation rates 

(compared to wet FGD with 

forced oxidation and gypsum 

byproduct market). No 

wastewater generation or 

discharge. 

*Emissions and costs summarized in this table represent totals for both boilers. Emissions and costs were estimated 

based on a full load boiler heat input of 5,480 mmBtu/hr and a 90% capacity factor. 
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4.5 Step 5: Evaluate Visibility Impacts 

To evaluate the relative effectiveness of potentially feasible SO2 retrofit control technologies, SO2

emissions were modeled at the projected post-retrofit controlled emission rates, while NOx and 

PM10 emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA 

guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission rates used in the modeling 

analysis to determine visibility impairment impacts reflect steady-state operating conditions during 

periods of high capacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour 

basis) were calculated using the expected controlled emission rate achievable on a 30-day rolling 

average multiplied by the boiler heat input (mmBtu/hr) at full load. The visibility modeling 

methodology is described further in Attachment B of this document, including detailed inputs and 

results. The results in Table 4-9 summarize the 98th percentile ∆-dv impact from SO2 emissions 

associated each SO2 retrofit control scenario. 

Table 4-9 

Muskogee Units 4 & 5 

SO2 Visibility Assessment 

Visibility Improvement 

Upper Buffalo 

Wilderness Area 

Caney Creek 

Wilderness Area 

Hercules-Glades 

Wilderness Area 

Wichita Mountains 

Wildlife Refuge

SO2 Control 

Technology Option 

98th % 

∆-dv*

% 

Improvement 

over 

Baseline 

98th % 

∆-dv

% 

Improvement 

over 

Baseline 

98th % 

∆-dv*

% 

Improvement 

over 

Baseline 

98th % 

∆-dv

% 

Improvement 

over 

Baseline 

Baseline 1.277 -- 1.471 -- 0.92 -- 1.176 -- 

DFGD – SDA 0.167 87% 0.196 87% 0.116 87% 0.148 87% 

WFGD 0.194 85% 0.243 83% 0.127 86% 0.143 88% 

* ∆-dv values included in this table represent the modeled visibility impacts only from SO2 emissions associated with 

each SO2 retrofit control scenario. 

With either FGD control system, modeled visibility impact improvements at the four Class I Areas 

are reduced by an average of approximately 1.0 ∆-dv, ranging from a 0.739 ∆-dv improvement 

(Hercules-Glades with wet FGD) to 1.275 ∆-dv (Caney Creek with dry FGD). Although the wet 

FGD control systems result in lower SO2 mass emission rates, modeled visibility impairments are 

generally less with dry FGD controls. Modeled impacts associated with SO2 emissions with either 

FGD control system are below the threshold impact level of 0.5 ∆-dv level at all Class I Areas. A 

summary of the cost effectiveness of both FGD control systems as a function of visibility 

impairment improvement at the Class I Areas is provided in Table 4-10. 
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Table 4-10 

Muskogee Units 4 & 5 

SO2 Average Visibility Cost Impact Evaluation 

Total Annual 

Cost

Modeled 

Visibility 

Impairment*

Visibility 

Impairment 

Improvement 

from Baseline 

Average 

Improvement 

Cost 

Effectiveness

SO2 Control 

Technology Option 

($/yr) 98th % ∆-dv* (dv) ($/dv/yr) 

Baseline -- 1.471 -- -- 

DFGD – SDA $142,660,600 0.196 1.275 $111.9 MM/dv 

WFGD $154,135,800 0.243 1.228 $125.5 MM/dv 

* ∆-dv values included in this table represent the modeled visibility impacts only from SO2

emissions associated with each SO2 retrofit control scenario. Modeled visibility impairment at the 

Caney Creek Class I Area was used for the cost effectiveness evaluation because modeling 

indicated that the largest ∆-dv improvements would occur at Caney Creek. 

Although FGD control systems reduce modeled visibility impacts at the four Class I Areas, the cost 

effectiveness of FGD control (with respect to visibility improvement) is very high. With either 

FGD control system, cost effectiveness ranges from approximately $111.9 million to $125.5 million 

per dv improvement at the Wichita Mountains. These costs are significantly higher than costs 

incurred at other BART applicable sources. A review of BART determinations at other coal-fired 

units suggests that BART cost effectiveness values are typically in the range of less than $1.0 

million to approximately $13 million per dv improvement.27 The combination of relatively low 

baseline SO2 emissions, low baseline visibility impacts (less than 1.5 ∆-dv at all Class I Areas), and 

distance to the Class I Areas, all contribute to the large cost effectiveness values at the Muskogee 

Station. 

To determine whether alterative SO2 control scenarios might provide more cost effective visibility 

improvements, cumulative impact modeling was conducted using a variety of FGD control 

scenarios. A goal of the cumulative impact modeling was to determine whether alternative SO2

control scenarios (i.e., FGD control on some, but not all of the OG&E BART applicable sources) 

would provide more cost effective SO2 control. To quantify cost effectiveness, visibility 

impairment was modeled for several SO2 control scenarios, while NOx and PM emissions were 

held constant at their respective baseline emission rates. Modeled SO2 control scenarios are listed 

in Table 4-11. Results of the cumulative SO2 impact modeling are summarized in Table 4-12. 

 

27 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy 

Co. (CO); Entergy White Bluff Power Plant (AR). 
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Table 4-11 

Cumulative SO2 Visibility Assessment 

(Muskogee Units 4 & 5 and Sooner Units 1 & 2)* 

Unit Base Case Case 1 Case 2 Case 3 Case 4 

SO2 Controls 

(Emission Rate - lb/mmBtu) 

Muskogee Unit 4 Baseline 

(0.80) 

DFGD 

(0.10) 

DFGD 

(0.10) 

DFGD 

(0.10) 

DFGD 

(0.10) 

Muskogee Unit 5 Baseline 

(0.85) 

Baseline 

(0.85) 

Baseline 

(0.85) 

DFGD 

(0.10) 

DFGD 

(0.10) 

Sooner Unit 1 Baseline 

(0.86) 

Baseline 

(0.86) 

DFGD 

(0.10) 

DFGD 

(0.10) 

DFGD 

(0.10) 

Sooner Unit 2 Baseline 

(0.860) 

Baseline 

(0.86) 

Baseline 

(0.86) 

Baseline 

(0.86) 

DFGD 

(0.10) 

* For each case PM and NOx emissions were held constant at the baseline emission rates. Baseline emissions for 

NOx were: 0.15 lb/mmBtu for both Muskogee units (assuming LNB/OFA controls). 

Table 4-12 

Cumulative SO2 Visibility Modeling Results 

(Muskogee Units 4 & 5 and Sooner Units 1 & 2) 

Modeled Visibility Impairment* 

Upper Buffalo 

Wilderness Area 

Caney Creek 

Wilderness Area 

Hercules-Glades 

Wilderness Area 

Wichita Mountains 

Wildlife Refuge

SO2 Control 

Technology 

Option 98th % 

∆-dv

98th % 

∆-dv

98th % 

∆-dv

98th % 

∆-dv

Base Case 1.92 2.00 1.44 2.42 

Case 1 1.46 1.69 1.05 2.16 

Case 2 1.26 1.48 0.90 1.60 

Case 3 0.78 0.91 0.52 1.33 

Case 4 0.57 0.68 0.38 0.74 

* ∆-dv values included in this table reflect cumulative modeled contributions from NOx, SO2 and PM emissions from 

both the Sooner and Muskogee Stations. For each case, PM and NOx emissions were held constant at their 

respective baseline emission rates, while SO2 emissions varied depending the SO2 control system on each unit (see 

Table 4-11). The dv values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2), 

which reflect modeled impacts from the Muskogee Station only for each individual pollutant. 

Results of the cumulative impact modeling suggest that visibility improvement at the Class I Areas 

is essentially linear with SO2 emission reductions from the OG&E generating stations (see, Figure 

4-1). For example, modeled visibility impairment at the Wichita Mountains was reduced by 0.26 

∆-dv with one FGD at the Muskogee Station, and by an additional 0.27 ∆-dv with a second FGD at 

Muskogee. Similarly, visibility impairment at the Wichita Mountains was reduced by 0.56 ∆-dv 

with one FGD control system at the Sooner Station, and by an additional 0.59 ∆-dv with a second 

FGD at Sooner. However, because of the relatively small improvement in visibility impairment, 

the cost effectiveness for FGD control systems ranged from approximately $120 MM/dv (Sooner 
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Station) to more than $260 MM/dv (Muskogee Station). Cost effectiveness values associated with 

the cumulative impact modeling at the Wichita Mountains Wildlife Refuge are summarized in 

Table 4-13. 

Figure 4-1 

Cumulative SO2 Visibility Modeling Results 

(Muskogee Units 4 & 5 and Sooner Units 1 & 2) 

Table 4-12 

Cumulative SO2 Visibility Modeling Results 

Wichita Mountains 

Case 98th % 

∆-dv 

Incremental 

Improvement 

Incremental 

Increase in 

Annual Cost 

Cost 

Effectiveness 

Base Case 2.42 -- -- $MM/dv 

Case 1 2.16 0.26 $71,067,900 $273.3 

Case 2 1.60 0.56 $70,415,900 $125.7 

Case 3 1.33 0.27 $71,067,900 $263.2 

Case 4 0.74 0.59 $70,415,900 $119.3 

Wichita Mountains

Modeled Visibility Impairment vs. FGD Control Systems

0.00

0.50

1.00

1.50

2.00

2.50

3.00

Baseline Case 1 (Muskogee Unit 4) Case 2 (Muskogee Unit 4

and Sooner Unit 1)

Case 3 (Muskogee 4 & 5 and

Sooner Unit 1)

Case 4 (Muskogee 4 & 4 and

Sooner 1 & 2)

FGD Control Scenario

Modeled Visibility Impairment (delta-dv

Wichita Mts Caney Creek Herc-Glades Upper Buffalo
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4.6 Propose BART for SO2 Control 

OG&E is proposing that no additional SO2 controls (beyond baseline low sulfur subbituminous 

coal) are BART for Muskogee Units 4 & 5. In the final Regional Haze Rule EPA established 

presumptive BART emission limits for SO2 from coal-fired EGUs greater than 200 MW at power 

plants with a total generating capacity in excess of 750 MW.28 The BART SO2 presumptive 

emission limit for these units is either 95% SO2 removal or an emission rate of 0.15 lb/mmBtu, 

unless an alternative control level is justified based on a careful consideration of the statutory 

factors. Statutory factors include the costs of compliance and the degree of improvement in 

visibility which may reasonably be anticipated to result from the use of such technology. In the 

case of the Muskogee Station, the poor cost effectiveness of the feasible controls dictates a decision 

that no additional controls are warranted. 

The cost effectiveness of FGD control on Muskogee Units 4 & 5 is poor in comparison to the cost 

effectiveness estimates used by EPA in establishing presumptive BART. EPA believed the average 

cost effectiveness would be $919 per ton SO2 removed, with the majority of the BART applicable 

units meeting the presumptive standards at a cost of $400 to $2,000 per ton of SO2 removed. To 

support the presumptive BART analysis, EPA developed cost effectiveness estimates for Muskogee 

Units 4 & 5 of $1,690 to $1,697 per ton of SO2 removed. In fact, the actual cost effectiveness of 

the potentially feasible SO2 control technologies at the Muskogee Station is $4,554 to $4,789 per 

ton of SO2 removed. Therefore, SO2 removal at Muskogee Units 4 & 5 is over two-and-a-half 

times less cost effective than EPA expected, and it is well outside of the cost effectiveness range 

that EPA used to support its presumptive BART determination. The cost effectiveness of FGD 

controls at the Muskogee Station calculated on the basis of visibility improvement also is poor. The 

cost effectiveness is estimated to be in the range of $111.9 to $125.5 million per dv improvement, 

which is significantly less effective than at other BART applicable sources. 

Although FGD control systems (either wet or dry FGD) will reduce SO2 emissions and modeled 

visibility impairment at the Class I Areas, the combination of relatively low baseline SO2 emissions, 

low baseline visibility impacts (less than 1.5 ∆-dv at all Class I Areas), and distance to the Class I 

Areas, all contribute to the poor cost effectiveness values. Based on the poor cost effectiveness of 

FGD retrofit controls and the relatively small degree of improvement in visibility, FGD control 

systems should not be selected as BART on Muskogee Units 4 & 5. As a result, OG&E is 

proposing low sulfur subbituminous coal and the existing permit limits as BART for SO2. 

 

28 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131. 
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5.0 BART ANALYSIS FOR MAIN BOILER PARTICULATE MATTER 

PM composition and emission levels are a complex function of boiler firing configuration, boiler 

operation, pollution control equipment and coal properties. Uncontrolled PM emissions from coalfired boilers include the ash from combustion of the fuel, noncombustible metals present in trace 

quantities and unburned carbon resulting from incomplete combustion. Other sources of PM 

include condensable organics and minerals present in the combustion air. 

Coal ash may either settle out in the boiler (bottom ash) or be entrained in the flue gas (fly ash). 

The distribution of ash between the bottom ash and fly ash fractions affects the PM emission rate 

and is a function of the boiler firing method and furnace type. With a PC boiler approximately 80% 

of the ash will be emitted with the flue gas as fly ash and 20% will settle out in the combustion bed 

as bottom ash. PM10 emissions from Muskogee Units 4 & 5 are currently controlled with cold-side 

electrostatic precipitators (ESPs). 

5.1 Step 1: Identify Available Retrofit PM10 Control Options 

The principal techniques for PM control are post-combustion methods (applicable to most boiler 

types and sizes). There are two generally recognized PM control devices that are used to control 

PM emission from PC boilers: ESPs and fabric filters (or baghouses). Muskogee Units 4 & 5 are 

currently equipped with ESP control systems. 

Retrofit PM10 control options with potential application to a subbituminous-fired PC boiler are 

listed in Table 5-1. The technical feasibility of each potential control option is discussed below. 

Table 5-1 

PM10 Retrofit Control Options with Potential Application to a 

Subbituminous-Fired PC Boiler 

PM10 Control Technologies 

 Electrostatic Precipitation (ESP) – existing 

 Fabric Filtration (FF) 

5.2 Step 2: Eliminate Technically Infeasible Retrofit Options 

5.2.1 Electrostatic Precipitators (ESPs) 

Muskogee Units 4 & 5 are currently equipped with ESPs for PM10 control. ESP technology 

consists of three steps: (1) charging the particles to be collected via a high-voltage electric 

discharge, (2) collecting the particles on the surface of an oppositely charged collection electrode 
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61 

surface, and (3) cleaning the surface of the collecting electrode. Particulate material captured on 

the collecting electrodes is removed by rapping the electrodes. The collected particulates drop into 

hoppers below the precipitator and are periodically removed with the fly ash handling system. 

Operating parameters that influence ESP performance include fly ash mass loading, particle size 

distribution, fly ash electrical resistivity, and precipitator voltage and current. Other factors that 

determine ESP collection efficiency are collection plate area, gas flow velocity, and cleaning cycle. 

Baseline controlled PM10 emissions from Muskogee Units 4 & 5 are approximately 101 lb/hr and 

134 lb/hr, respectively. Based on a maximum heat input of 5,480 mmBtu/hr (each boiler), baseline 

PM10 emission rates from Units 4 & 5 are 0.0184 and 0.0244 lb/mmBtu, respectively.29 These 

controlled rates require the existing ESPs to achieve average overall particulate matter control 

efficiencies of greater than 99%. 

5.2.2 Fabric Filters 

Fabric filtration consists of a number of filtering elements (bags) along with a bag cleaning system 

contained in a main shell structure incorporating dust hoppers. Particulate-laden gas enters a 

fabric filter compartment and passes through a layer of filter bags. The collected particulate forms 

a cake on the bag that enhances the bag’s filtering efficiency. Excessive caking will increase the 

pressure drop across the fabric filter at which point the filters must be cleaned. 

The particulate removal efficiency of fabric filters is dependent upon a variety of particle and 

operational characteristics. Particle characteristics that affect the collection efficiency include 

particle size distribution and particle cohesion characteristics. Operational parameters that may 

affect fabric filter collection efficiency include bag material, air-to-cloth ratio, and operating 

pressure loss. In addition, certain filter properties (e.g., structure of the fabric and fiber 

composition) can affect the system's particle collection efficiency. 

Fabric filter baghouses are considered a technically feasible particulate matter control option for 

Muskogee Units 4 & 5, and a fabric filter baghouse (or polishing baghouse) would be required if 

the units were retrofit with dry FGD. However, retrofitting the existing units with baghouses for 

particulate matter control only (i.e., not in conjunction with a dry FGD) would require substantial 

modifications to the units without providing any significant reduction in controlled PM emissions. 

 

29 Baseline PM10 emissions used in this BART analysis were based on the highest 24-hour block emissions 

reported by each unit during the baseline period. Baseline PM10 emission rates (lb/mmBtu) were calculated 

by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The 

relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts, 

and to provide a conservative estimate of the cost effectiveness of potentially feasible retrofit control 

technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation 

of the facility’s permitted emission limits, which are averaged over a longer period of time. 
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Extensive ductwork would be required to redirect flue gas flow though the fabric filter and back to 

the existing stacks. Furthermore, baghouses would provide only an incremental reduction in PM/ 

PM10 control compared to the existing ESP control systems. 

5.3 Step 3: Rank the Technically Feasible PM10 Control Options by Effectiveness 

The effectiveness of each retrofit technology identified as being technically feasible for PM10

control is summarized in Table 5-2 in descending order of control efficiency. 

Table 5-2 

Summary of Technically Feasible 

Main Boiler PM10 Control Technologies 

Control Technology 

PM10 Emissions* 

(lb/mmBtu) 

% Reduction 

(from base case) 

Fabric Filter Baghouse 0.015 99.7 

ESP - Existing 0.025 99.6 

Potential PM Emissions 5.65 - 

* The PM10 emission rate for the baghouse case is based on filterable PM10 emission limits 

included in recently issued PSD permits for new coal-fired units. The PM10 emission rate for the 

ESP case is based on the Units’ baseline PM10 emission rates (e.g., approximately 0.025 

lb/mmBtu on Unit 5). Potential PM emissions were calculated assuming an average fuel heating 

value of 8,500 Btu/lb and an ash content of 6.0%, and assuming 80% of the fuel ash will be 

emitted as fly ash. 

5.4 Step 4: Evaluate Impacts and Document the Results 

5.4.1 Economic Evaluation 

 

Based on the controlled PM10 emission rates included in Table 5-2, and assuming a maximum 

heat input to each boiler of 5,480 mmBtu/hr and 7,884 hours/year operation (90% capacity 

factor), potential PM10 emissions from Muskogee Units 4 & 5 would be reduced from 

approximately 1,080 tpy to 648 tpy with a fabric filter baghouse (total potential emissions from 

both units). Equipment costs associated with retrofitting Muskogee Units 4 & 5 with a 

baghouse are estimated to be in the range of $125 to 135/kW-gross, or in the range of 

$75,000,000 per unit. Taking into consideration indirect installation costs for foundations, 

mechanical erection, electrical, piping, and insulation, and including engineering, and 

contingencies, total capital requirement for a fabric filter baghouse would be in the range of 

$104,000,000/unit. The annualized capital recovery cost for the baghouse control systems 

(assuming equipment life of 25 years and 7% pretax marginal rate of return) would be 

approximately $8,900,000/yr (per unit). Ignoring O&M costs associated with baghouse 

operation (including bag replacement costs and energy cost associated with increased pressure 
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63 

drop) the cost effectiveness of the retrofit baghouse control system would be more than 

$41,000/ton of PM removed (e.g., $8.9 MM/yr/unit x 2 units / 432 tpy potential emission 

reductions). 

It is apparent that a retrofit baghouse control system would not be cost effective for particulate 

matter control only. Although baghouses may provide an incremental reduction in PM10

emissions, the costs associated with a fabric filter retrofit project are significant. Retrofitting 

Muskogee Units 4 & 5 with baghouses for particulate matter control would require a significant 

capital investment for a minimal reduction in emissions. The cost effectiveness of the retrofit 

baghouse control systems is excessive, and should preclude fabric filter control systems from 

consideration as BART for PM control. 

5.4.2 Environmental Evaluation 

There are no environmental considerations that would preclude the use of either fabric filters or 

ESP control systems as BART on Muskogee Units 4 & 5. Both PM control systems generate a 

fly ash solid waste that must be properly managed. 

5.4.3 PM Control - Energy Impact Evaluation 

There are significant auxiliary power requirements associated with the fabric filter control 

system. Auxiliary power is required to overcome pressure drop through the baghouse and filter 

cake. Based on engineering estimates, auxiliary power requirements for a fabric filter baghouse 

are approximately 0.5% of the gross energy output of the generating unit. Muskogee Units 4 & 

5 have a gross rating of 572 MW (each); therefore, annual auxiliary power requirements for a 

baghouse control system would be in the range of 45,000 MWh per year (at a 90% capacity 

factor). Annual operating costs associated with the auxiliary power requirement would be 

significant, and the increased auxiliary power requirement would reduce the overall efficiency 

of both units. 

5.5 Step 5: Evaluate Visibility Impacts 

Replacing the existing ESPs on Muskogee Units 4 & 5 with baghouses is not a cost effective 

retrofit control option for PM control. Furthermore, based on visibility impact modeling, 

particulate matter emissions from Muskogee Units 4 & 5 contribute only minimally to modeled 

visibility impacts at the Class I Areas (see, Attachment B). A majority (more than 90%) of the 

modeled visibility impacts are associated with NOx and SO2 emissions. Reducing particulate matter 

emissions from the existing baseline rate (with ESP control) would provide no discernible reduction 

in modeled visibility impacts at the Class I areas. 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

64 

5.6 Propose BART for PM10 Control 

Based on visibility impact modeling, and economic impacts associated with retrofit PM controls, 

OG&E is not proposing any change to its existing PM/ PM10 emission limits as BART. Therefore, 

OG&E is proposing no change to existing permitted PM emission limits as BART for particulate 

matter control. 

6.0 BART SUMMARY 

Table 6-1 summarizes the proposed BART control technologies and associated emission limits for 

Muskogee Units 4 & 5. 

Table 6-1 

Proposed BART Permit Limits and Control Technologies 

Pollutant Proposed BART 

 Emission Limit 

Proposed BART Technology 

NOx 0.15 lb/mmBtu 

(30-day average) 

Combustion controls including LNB 

and OFA 

SO2 Existing Permit Limits Low sulfur subbituminous coal 

PM10 filterable Existing Permit Limits NA 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-1 

Attachment A 

Muskogee Units 4 & 5 

BART Determination - Cost Estimate Details 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-2 

Economic Evaluation Methodology for 

Technically Feasible Control Options 

Summarized below are the basic principles and methodologies used to prepare the economic 

analysis of technologically feasible control options. The cost-effectiveness evaluations were 

"study" estimates of ±30% accuracy, based on: (1) engineering estimates; (2) vendor quotations 

provided for similar projects and similar equipment; (2) S&L’s internal cost database; and (4) 

cost estimating guidelines provided in EPA’s, “EPA Air Pollution Control Cost Manual, Sixth 

Edition” EPA-452/B-02-001, January 2002. 

Over the past several years, prices on air pollution control equipment have increased 

significantly. Several trends have contributed to the rapid escalation in costs, including the 

greater demand for equipment and materials, significant increases in commodity prices, and 

greater demand for skilled labor and construction contractors. 

 

Over the past 4-year period the demand for electric utility steam generating emission control 

equipment, including FGD and SCR control systems, increased significantly in response to the 

Clean Air Interstate Rule (CAIR). CAIR, published May 12, 2005, mandates specific emission 

caps on SO2 and NOx emissions from power plants located in 28 Eastern and Midwestern states. 

CAIR emission caps will be imposed in two phases, with the first phase beginning in 2009 for 

NOx and 2010 for SO2. The second phase of emission reductions are required in 2015 for both 

pollutants. CAIR is projected to result in the installation of an additional 64 GW of flue gas 

desulfurization and an additional 34 GW of selective catalytic reduction technology on existing 

coal-fired generation capacity.30 This increase in demand for retrofit emission control systems 

created a “sellers market” in the U.S. Pollution control equipment vendors, their fabricators and 

material suppliers currently have significant backlogs and are able to charge higher margins, 

contributing to the recent escalation in retrofit control technology costs. 

Construction contractors and construction labor are currently in high demand in the U.S., not only 

in the electric power generating industry but also in the petroleum refining, chemical processing, 

and ethanol industries. All of these industries pull from the same labor force. Due to increased 

demand, construction contractors are more selective with the projects that they bid, and are able 

to demand higher margins. Similarly, the labor force is able to demand more lucrative contracts 

in order to be attracted to an area that is short of labor. Per diems and mandatory overtime are 

often needed to attract sufficient labor to support major construction projects. 

 

During the same period, commodity prices have also increased significantly. Commodity price 

data available from the U.S. Department of Labor’s Bureau of Labor Statistics show a sharp 

upturn in metals prices since 2004. For example, steel increased 47% from January 2004 to 

January 2005. Prices for copper wire doubled between 2003 and 2006. Pollution control projects 

require large quantities of basic commodities, including steel, concrete, and copper. Increased 

commodity prices have a significant impact on the cost of large emission control retrofit projects. 

 

 

30 “Regulatory Impact Analysis for the Final Clean Air Interstate Rule,” U.S. EPA Office of Air and 

Radiation, EPA-452/R-05-002, March 2005. 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-3 

BART Economic Evaluation

Average and incremental cost effectiveness were the two economic criteria considered in the 

BART analysis. Effectiveness of a control option is measured in terms of tons of pollutant 

emissions removed per year (Eannual). Cost is measured in terms of the total annualized cost 

(TAC) associated with the control system. The annual cost effectiveness of a particular control 

system (expressed in $/ton) is calculated using the following equation: 

Average Cost Effectiveness = Eannual / TAC 

Capital Recovery Cost

One important component of the TAC is the annualized cost to recover the initial capital 

investment, termed the Capital Recovery Cost (CRC). CRC is a function of the total capital 

investment, an assumed interest rate, and the estimated economic life of the control equipment. 

Total Capital Investment 

Total Capital Investment (TCI) includes all costs required to purchase equipment needed 

for the control system, and includes the purchased equipment cost plus direct installation 

costs (such as foundations and supports, erection, electrical, and piping), and indirect 

capital costs (such as engineering, contractor fees, performance testing and 

contingencies). 

To calculate the CRC, the equivalent uniform annual cash flow (EUAC) method was used to 

annualize the total capital investment. Using the EUAC method, the CRC is determined by 

multiplying the TCI by a capital recovery factor (CRF), as shown in the following equation: 

CRC = Capital Recovery Factor (CRF) x TCI 

The product of the TCI and CRF gives a uniform end-of-year payment necessary to repay the 

initial capital investment in "n" years at an interest rate of "i". 

The CRF is calculated using the following equation: 

(1 i) 1

i * (1 i) CRF n

n

+ −

+ =

Where: 

i = interest rate; and 

n = economic life of the emission control system 

Total Annual Cost 

The Total Annual Cost (TAC) is comprised of the following elements: capital recovery costs 

(CRC), direct O&M costs (DC), indirect operating costs (IC), and recovery credits (RC) as 

follows: 

TAC = CRC + DC + IC - RC 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-4 

Direct O&M costs are those costs that tend to be proportional to the quantity of exhaust gas 

processed by the control system. These may include costs for catalysts, utilities (steam, 

electricity, and water), waste treatment and disposal, maintenance materials, replacement parts, 

and operating and maintenance labor. Of these direct O&M costs, costs for catalysts, utilities, 

waste treatment, and disposal are variable. Emission allowance costs associated with certain 

regulatory programs may also be represented as a variable O&M costs, but have not been 

included in this cost estimate. Labor costs, maintenance materials and replacement parts are 

semi-variable direct costs as they are only partly dependent upon the exhaust flow rate. 

Indirect or “Fixed" annual costs are those whose values are totally independent of the exhaust 

flow rate and, in fact, would be incurred even if the control system were shut down. They include 

such categories as administrative charges, property taxes, and insurance, and include the capital 

recovery cost. 

The direct and indirect annual costs are offset by recovery credits, taken for materials or energy 

recovered by the control system, which may be sold, recycled to the process, or reused elsewhere 

at the site. 

Summary

In summary, the following methodology was used to calculate the cost effectiveness of various 

pollution control systems. 

1. The effectiveness of each control system, in terms of annual reduction of pollutant 

emissions, was calculated. 

2. The Total Capital Investment required for each control system was estimated. 

3. The Capital Recovery Cost of each control system was calculated based on an assumed 

interest rate and estimated economic life of 20 years for the control equipment. 

4. The Total Annualized Cost of each control system was calculated based on the Capital 

Recovery Cost and Annual Operating Costs. 

5. The Annual Control Effectiveness, in terms of Total Annualized Costs divided by 

annual emission reductions, was calculated for each control system. 

BART economic evaluations were prepared for the following control systems: 

NOx Control Cost Summary 

- Combustion Controls (LNB/OFA) 

- Combustion Controls plus Selective Catalytic Reduction (SCR) 

SO2 Control Cost Summary 

- Dry FGD (Spray Dry Absorber) 

- Wet FGD 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination May 28, 2008 

Page A-5 

BART Economic Evaluation 

NOx Summary 

MUSKOGEE GENERATING STATION UNITS 4 & 5NOx CONTROL SUMMARY

Muskogee 4 Muskogee 5 Unit

Design Heat Input: 5,480 5,480 mmBtu/hr

Net Capacity: 532 532 MW

Capacity Factor 90% 90%

Maximum Hours/year: 8,760 8,760 hours

Muskogee 4

Control Technology

Expected Emission 

Rate

Expected 

Emissions

Expected 

Emissions 

Reduction

Total Capital 

Requirement

Annual Capital Recovery 

Cost

Total Annual 

Operating Costs Total Annual Costs

Average C

Efficie

(lb/mmBtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton

Baseline Emissions 0.495 10,693 NA

Alternative 1: LNB / OFA 0.150 3,240 7,453 $14,113,700 $1,211,100 $880,700 $2,091,800 $281 

Alternative 2: LNB/OFA + SCR 0.070 1,512 9,181 $193,077,000 $16,568,000 $14,227,600 $30,795,600 $3,35Note: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR.

Muskogee 5

Control Technology

Expected Emission 

Rate

Expected 

Emissions

Expected 

Emissions 

Reduction

Total Capital 

Requirement

Annual Capital Recovery 

Cost

Total Annual 

Operating Costs Total Annual Costs

Average C

Efficie

(lb/MMBtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton

Baseline Emissions 0.522 11,276 NA

Alternative 1: LNB / OFA 0.150 3,240 8,036 $14,113,700 $1,211,100 $880,700 $2,091,800 $260 

Alternative 2: LNB/OFA + SCR 0.070 1,512 9,764 $193,077,000 $16,568,000 $14,227,600 $30,795,600 $3,15

Notes

Note 1: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR.Note 2: Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmBdividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The relatively high short-term baseline emission rates were used to predict maximum potential visibilconservative estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baseline emission rates should in no way be interpreted as a potential violation of the 

limits, which are averaged over a longer period of time. 

Assuming 90% capacity factor for cost evaluations.
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-6 

BART Economic Evaluation – NOx 

Retrofit Control Technologies – Capital Cost Summary 

MUSKOGEE GENERATING STATION UNITS 4 & 5

Capital Cost Worksheet

Case

1 x 572 MW-gross 

PC Boiler

1 x 572 MW-gross 

PC Boiler

Gross Plant Output (MW-gross) MW-gross 572.0 572.0

Net Plant Output (MW-net) MW-net 532.0 532.0

Maximum Heat Input (mmBtu/hr) mmBtu/hr 5,480 5,480

Uncontrolled NOx Emission Rate (lb/mmBtu) lb/mmBtu 0.495 0.522

Capacity Factor Used for Cost Estimates (%) % 90% 90%

Capital Cost Recovery Factor Equipment Life years 25 25

Low NOX Burner Technology Capital Costs

Muskogee 4 Muskogee 5

Cost Basis (Year) 2008 2008

Total Capital Requirement with Retrofit (TCR) $ $14,113,700 $14,113,700

SCR Capital Costs

Muskogee 4 Muskogee 5

Cost Basis (Year) 2008 2008

 SCR Area $2,023,000 $2,023,000

 Civil/Site Work $620,000 $620,000

 Flue Gas System/Ductwork $32,331,000 $32,331,000

 Modifications $5,273,000 $5,273,000

 Pipe Rack $7,751,000 $7,751,000

 Miscellaneous Mechanical Items $1,101,000 $1,101,000

 Urea to Ammonia System $4,904,000 $4,904,000

 Booster Fans $5,329,000 $5,329,000

 Allowance for Additional Cranes $873,000 $873,000

 Electrical Modifications $11,336,000 $11,336,000

Equipment Capital Cost Subtotal $ $71,541,000 $71,541,000

 Instruments & Controls $ $1,430,800 $1,430,800

 Taxes $ $4,292,500 $4,292,500

 Freight $ $3,577,100 $3,577,100

 Total Direct Cost $80,841,400 $80,841,400

Other Costs

Total Direct Cost with Retrofit Factor $ $97,009,700 $97,009,700

 General Facilities $ $4,850,500 $4,850,500

 Engineering Fees $ $9,701,000 $9,701,000

 Contingency $ $19,401,900 $19,401,900

 EPC Fee (20% of total Cost) $19,401,900 $19,401,900

Total Plant Cost (TPC) $ $150,365,000 $150,365,000

Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $154,876,000 $154,876,000

Allow. for Funds During Constr. (AFDC) $ $12,607,000 $12,607,000

 Preproduction Costs $ $3,345,300 $3,345,300

Inventory Capital

 Initial Ammonia (60 days) $ $87,000 $87,000

 Initial Catalyst $ $8,048,000 $8,048,000

Total Capital Requirement (TCR) $ $178,963,300 $178,963,300

 Total Capital Requirement ($/kW-gross) $/kW-gross $313 $313

 Total Capital Requirement ($/kW-net) $/kW-net $336 $336

Capital Cost Estimates were based on detailed cost estimates recently prepared for similar projects. Capital costs were 

compared to U.S.EPA's Coal Utility Environmental Cost (CUECost) Workbook, modified to account for recent increases in 

purchased equipment costs and commodity costs. Estimates were also compared to vendor quotes provided on recent similar 

projects.
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination May 28, 2008 

Page A-7 

BART Economic Evaluation – NOx 

LNB/OFA Combustion Details 

MUSKOGEE GENERATING STATION UNITS 4 & 5BART COST EVALUATION - LOW NOx BURNER WORKSHEET

Muskogee 4 Muskogee 5

Gross Plant Output (MW-gross) 572 572

Net Plant Output (MW-net) 532 532

Maximum Heat Input (mmBtu/hr) 5,480 5,480

Uncontrolled NOx Emission Rate (lb/mmBtu) 0.495 0.522Post Low Nox Burner Emission Rate (lb/mmBtu) 0.150 0.150Capacity Factor used of Cost Estimates (%) 90% 90%

Capital Cost Recovery Factor Equipment Life 25

CAPITAL COSTS Basis

Total Capital Requirement (TCR) $14,113,700 $14,113,700Total Capital Investment ($/kW - net) $27 $27Capital Recovery Factor = i(1+ i)n / (1 + i)n - 1 0.0858 0.0858 EPA Air Pollution Control Cost Manual 6th Ed., page 2-21.

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $1,211,100 $1,211,100 7% Assumed pretax marginal rate of return on private investment.

OPERATING & MAINTENANCE COSTS Basis

 Variable O&M Costs

Ammonia Reagent Cost $0 $0 Assumed no variable O&M costs with the LNB/OFA retrofit control system.Catalyst Replacement Cost $0 $0Auxiliary Power Cost $0 $0

 Total Variable O&M Cost $0 $0

 Fixed O&M Costs

Additional Operators per shift 0.00 0.00 Assumed no additional operators needed for the LNB/OFA retrofit control sysOperating LaborMaintenance Labor $112,900 $112,900 0.80% CUECost Maintenance Labor Default for emission control systems (0.8%/yr * 

Maintenance Materials $169,400 $169,400 1.20% CUECost Maintenance Default Factor for control systems (1.2% of installed c

Control, Administration, Overhead $33,900 $33,900 30% of Maintenance Labor Cost (CUECost Default of control systems) Total Fixed O&M Costs $316,200 $316,200

Indirect Operating Cost

Property Taxes $141,100 $141,100 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Insurance $141,100 $141,100 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Administration $282,300 $282,300 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th  Total Indirect Operating Cost $564,500 $564,500Total Annual Operating Cost $880,700 $880,700

TOTAL ANNUAL COST

Annualized Capital Cost $1,211,100 $1,211,100

Annual Operating Cost $880,700 $880,700

 Total Annual Cost $2,091,800 $2,091,800

See, Input Sheet. TCR includes all costs required to purchase and install contrmaterials, labor, site preparation, engineering, contingencies, and retrofit costs
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination May 28, 2008 

Page A-8 

BART Economic Evaluation – NOx 

SCR Details 

MUSKOGEE GENERATING STATION UNITS 4 & 5BACT COST EVALUATION - SCR WORKSHEET

Muskogee 4 Muskogee 5

Gross Plant Output (MW-gross) 572.0 572.0

Net Plant Output (MW-net) 532.0 532.0

Maximum Heat Input (mmBtu/hr) 5,480 5,480Post Boiler NOx Emission Rate (lb/mmBtu) 0.15 0.15PostSCR NOx Emission Rate (lb/mmBtu) 0.07 0.07Capacity Factor used of Cost Estimates (%) 90% 90%

Capital Cost Recovery Factor Equipment Life (years) 25

Cost Cost

CAPITAL COSTS [$] [$] Basis

Total Capital Requirement (TCR) $ 178,963,300 178,963,300 $ 

Total Capital Investment ($/kW-net) $336 336 $ Capital Recovery Factor = i(1+ i)n / (1 + i)n - 1 0.0858 0.0858 EPA Air Pollution Control Cost Manual 6th Ed., page 2-21.

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $15,356,900 $15,356,900 7% Assumed pretax marginal rate of return on private investment.

OPERATING COSTS Basis

Operating & Maintenance Costs (based on 90% capacity factor) Variable O&M Costs

Ammonia Reagent Cost $272,900 $272,900 370 $ 

Based on maximum heat input, NOx removal rate (lb/hr), NH2/N2 ratio of appcapacity factor, and $370/ton reagent cost.

Catalyst Replacement Cost $1,701,700 $1,701,700 7,000 $ Based on 1.7 M3 catalyst per MW-gross, 4 year catalyst life, and $7,000/M3 ca

Auxiliary Power Cost $869,000 $869,000 32 $ 

Based on 9" pressure drop across the SCR, 0.065 MWh/inch auxiliary power r$32/MWh.

 Total Variable O&M Cost $2,843,600 $2,843,600

 Fixed O&M Costs

Additional Operators per shift 1.00 1.00 Based on S&L O&M estimate for SCR control system.Operating Labor $293,500 $293,500

3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to salary of $70,000/year.

Supervisory Labor $44,000 $44,000 15.0% of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page 2-31Maintenance Materials $2,684,400 $2,684,400 1.5% CUECost Maintenance Default Factor for SCR (1.5% of installed cost).Maintenance Labor $322,900 $322,900 110.0% of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page 2-31 Total Fixed O&M Cost $3,344,800 $3,344,800

Indirect Operating Cost

Property Taxes $1,789,600 $1,789,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Insurance $1,789,600 $1,789,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Administration $3,579,300 $3,579,300 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th  Total Indirect Operating Cost $7,158,500 $7,158,500

Total Annual Operating Cost $13,346,900 $13,346,900

TOTAL ANNUAL COST

Annualized Capital Cost $15,356,900 $15,356,900

Annual Operating Cost $13,346,900 $13,346,900

 Total Annual Cost $28,703,800 $28,703,800

See, Input Sheet. TCR includes all costs required to purchase and install contrincluding materials, labor, site preparation, engineering, contingencies, and ret
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination May 28, 2008 

Page A-9 

BART Economic Evaluation 

SO2 Summary – Muskogee Unit 4 

MUSKOGEE STATION UNIT 4SO2 CONTROL SUMMARY

Pollutant: SO2 Unit

Design Heat Input: 5,480 mmBtu/hr

Capacity Factor 90% %Maximum Hours/year: 8,760 hours

Control Technology

Expected Emission 

Rate

Expected 

Emissions

Expected 

Emissions 

Reduction

(lb/MMBtu) (ton/year) (ton/year)

Baseline Emissions 0.80 17,282 0

Alternative 1: DFGD-SDA 0.10 2,160 15,122Alternative 2: WFGD 0.08 1,728 15,554

Control Technology Emissions

Tons of SO2 

Removed

Total Capital 

Requirement

Annual Capital 

Recovery Cost

Total Annual 

Operating Costs Total Annual Costs

Average 

Effic

(tpy) (tpy) ($) ($/year) ($/year) ($) ($/

Baseline Emissions 17,282

Alternative 1: DFGD-SDA 15,122 2,160 $372,609,000 $31,973,800 $38,630,200 $70,604,000 $4,6Alternative 2: WFGD 15,554 1,728 $417,788,000 $35,850,600 $41,204,700 $77,055,300 $4,9

Assumed 90% capacity factor for cost evaluations.NotesDesign heat input was held constant for both FGD control technologies. Net plant output wdecrease with the wet FGD system due to increased auxiliary power requirements.
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-10 

BART Economic Evaluation – SO2

Retrofit Control Technology – Capital Cost Summary – Muskogee Unit 4 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-11 

BART Economic Evaluation – SO2

Dry FGD Control System – Muskogee Unit 4 

EQUIPMENT CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $270,087,000

General Facilities $27,009,000

Engineering Fees $27,009,000

Contingency $54,017,000

Total Plant Cost $378,122,000

Total Plant Cost (TPC) w/ Prime Contractor's Markup $389,466,000

Total Cash Expended (TCE) $330,579,000

Allow. for Funds During Constr. (AFDC) $32,661,000

Total Plant Investment (TPI) $363,240,000

 Preproduction Costs $9,324,000

 Inventory Capital $45,000

Total Capital Requirement (TCR) $372,609,000

Total Capital Investment ($/kW - gross) $651

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.0858 25 years. 

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $31,973,800 7% Assumed pretax marginal rate of return on private investment. 

OPERATING COSTS Basis

Operating & Maintenance Costs

 Variable O&M Costs

Lime Reagent Cost $4,410,400 $ 200

Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 

90% CaO, 90% capacity factor, and $200/ton for lime.

Water Cost $276,000 $ 1.20 Based on 0.85 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal

FGD Waste Disposal Cost $964,000 $ 30

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity 

factor, and $30/ton on-site disposal cost. Disposal cost only includes FGD 

by-products and does not include fly ash.

Bag and Cage Replacement Costs $581,300 $ 2.85

Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 

for pulse jet baghouse, $2.85/ft2 bag cost (including fabric and hangers), 4% 

contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0

Assumed no increase in ash disposal with the fabric filter compared to the 

existing ESP control system.

Auxiliary Power Cost $3,044,000 $ 45

Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% 

(gross) for the baghouse, 90% capacity factor, and $45/MW.

 Total Variable O&M Costs $9,275,700

 Fixed O&M Costs

Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.

Operating Labor $586,900

3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal 

to an annual operator salary of $70,000/year.

Supervisor Labor $88,000 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $13,504,400 5.0%

Maintenance Default Factor for lime spray dryer from EPA's Coal Utility 

Environmental Cost (CUECost) Workbook.

Maintenance Labor $645,600 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $14,824,900

Indirect Operating Cost

Property Taxes $3,632,400 1%

Insurance $3,632,400 1%

Administration $7,264,800 2%

 Total Indirect Operating Cost $14,529,600

Total Annual Operating Cost $38,630,200

TOTAL ANNUAL COST

Annualized Capital Cost $31,973,800

Annual Operating Cost $38,630,200

 Total Annual Cost $70,604,000

Equipment capital costs were based on U.S.EPA's Coal Utility 

Environmental Cost (CUECost) Worksheet, using Sooner specific fuel 

specifications and boiler configuration. 

Total Capital Requirements were calculated using U.S.EPA's CUECost 

Worksheet, modified to account for recent increases in equipment costs and 

commodities. Costs were compared to vendor quotes provided on other 

recent similar projects. TCR includes all costs required to purchase 

equipment, costs of labor and materials for installing teh equipment, costs for 

site preparation and buildings, and retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34).

Muskogee Unit 4
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-12 

BART Economic Evaluation – SO2

Wet FGD Control System – Muskogee Unit 4 

CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $302,835,000

General Facilities $30,284,000

Engineering Fees $30,284,000

Contingency $60,567,000

Total Plant Cost $423,970,000

Total Plant Cost (TPC) w/ Prime Contractor's Markup $436,689,000

Total Cash Expended (TCE) $370,662,000

Allow. for Funds During Constr. (AFDC) $36,621,000

Total Plant Investment (TPI) $407,283,000

 Preproduction Costs $10,455,000

 Inventory Capital $50,000

Total Capital Requirement (TCR) $417,788,000

Total Capital Investment ($/kW - gross) $730

Capital Recovery Factor = i(1+ i)n / (1 + i)n

 - 1 0.0858 25 years. 

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $35,850,600 7% Assumed pretax marginal rate of return on private investment. 

OPERATING COSTS Basis

Operating & Maintenance Costs (based on 90% capacity factor)

 Variable O&M Costs

Limestone Reagent Cost $742,600 $ 25

Based on maximum heat input, SO2 removal rate (lb/hr), 1.05 stoichiometry, 

95% CaCO3, 90% capacity factor, and $25/ton for limestone.

Water Cost $405,900 $ 1.20 Based on 1.25 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal.

FGD Waste Disposal Cost $1,416,000 $ 30

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity 

factor, forced oxidation 90% dry, and $30/ton on-site disposal cost. Disposal 

cost only includes additional WFGD by-products and does not include fly 

ash. No credit is assumed for by-product sales.

Auxiliary Power Cost $4,566,000 $ 45

Based on auxiliary power requirement of 2% (gross), 90% capacity factor, 

and $45/MW.

 Total Variable O&M Costs $7,130,500

 Fixed O&M Costs

Additional Operators per shift 4.0 Based on S&L O&M estimate for wet FGD.

Operating Labor $1,173,800

3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal 

to an annual operator salary of $70,000/year.

Supervisor Labor $176,100 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $15,141,800 5.0%

Maintenance Default Factor for limestone scrubber with forced oxidation 

from EPA's Coal Utility Environmental Cost (CUECost) Workbook.

Maintenance Labor $1,291,200 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $17,782,900

Indirect Operating Cost

Property Taxes $4,072,800 1%

Insurance $4,072,800 1%

Administration $8,145,700 2%

 Total Indirect Operating Cost $16,291,300

Total Annual Operating Cost $41,204,700

TOTAL ANNUAL COST

Annualized Capital Cost $35,850,600

Annual Operating Cost $41,204,700

 Total Annual Cost $77,055,300

Equipment capital costs were based on U.S.EPA's Coal Utility 

Environmental Cost (CUECost) Worksheet, using Sooner specific fuel 

specifications and boiler configuration. 

Total Capital Requirements were calculated using U.S.EPA's CUECost 

Worksheet, modified to account for recent increases in equipment costs and 

commodities. Costs were compared to vendor quotes provided on other 

recent similar projects. TCR includes all costs required to purchase 

equipment, costs of labor and materials for installing teh equipment, costs for 

site preparation and buildings, and retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34).

Muskogee Unit 4
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination May 28, 2008 

Page A-10 

BART Economic Evaluation 

SO2 Summary – Muskogee Unit 5 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-10 

BART Economic Evaluation – SO2

Retrofit Control Technology – Capital Cost Summary – Muskogee Unit 5 
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-11 

BART Economic Evaluation – SO2

Dry FGD Control System – Muskogee Unit 5 

EQUIPMENT CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $270,447,000

General Facilities $27,045,000

Engineering Fees $27,045,000

Contingency $54,089,000

Total Plant Cost $378,626,000

Total Plant Cost (TPC) w/ Prime Contractor's Markup $389,985,000

Total Cash Expended (TCE) $331,019,000

Allow. for Funds During Constr. (AFDC) $32,705,000

Total Plant Investment (TPI) $363,724,000

 Preproduction Costs $9,337,000

 Inventory Capital $45,000

Total Capital Requirement (TCR) $373,106,000

Total Capital Investment ($/kW - gross) $652

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.0858 25 years. 

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $32,016,400 7% Assumed pretax marginal rate of return on private investment. 

OPERATING COSTS Basis

Operating & Maintenance Costs

 Variable O&M Costs

Lime Reagent Cost $4,725,500 $ 200

Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 90% 

CaO, 90% capacity factor, and $200/ton for lime.

Water Cost $276,000 $ 1.20 Based on 0.85 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal

FGD Waste Disposal Cost $1,032,900 $ 30

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, and 

$30/ton on-site disposal cost. Disposal cost only includes FGD by-products and 

does not include fly ash.

Bag and Cage Replacement Costs $581,300 $ 2.85

Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 for 

pulse jet baghouse, $2.85/ft2 bag cost (including fabric and hangers), 4% 

contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0

Assumed no increase in ash disposal with the fabric filter compared to the existing 

ESP control system.

Auxiliary Power Cost $3,044,000 $ 45

Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% (gross) 

for the baghouse, 90% capacity factor, and $45/MW.

 Total Variable O&M Costs $9,659,700

 Fixed O&M Costs

Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.

Operating Labor $586,900

3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an 

annual operator salary of $70,000/year.

Supervisor Labor $88,000 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $13,522,400 5.0%

Maintenance Default Factor for lime spray dryer from EPA's Coal Utility 

Environmental Cost (CUECost) Workbook.

Maintenance Labor $645,600 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $14,842,900

Indirect Operating Cost

Property Taxes $3,637,200 1%

Insurance $3,637,200 1%

Administration $7,274,500 2%

 Total Indirect Operating Cost $14,548,900

Total Annual Operating Cost $39,051,500

TOTAL ANNUAL COST

Annualized Capital Cost $32,016,400

Annual Operating Cost $39,051,500

 Total Annual Cost $71,067,900

Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost 

(CUECost) Worksheet, using Sooner specific fuel specifications and boiler 

configuration. 

Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet, 

modified to account for recent increases in equipment costs and commodities. 

Costs were compared to vendor quotes provided on other recent similar projects. 

TCR includes all costs required to purchase equipment, costs of labor and 

materials for installing teh equipment, costs for site preparation and buildings, and 

retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34).

Muskogee Unit 5
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page A-12 

BART Economic Evaluation – SO2

Wet FGD Control System – Muskogee Unit 5 

CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $303,400,000

General Facilities $30,340,000

Engineering Fees $30,340,000

Contingency $60,680,000

Total Plant Cost $424,760,000

Total Plant Cost (TPC) w/ Prime Contractor's Markup $437,503,000

Total Cash Expended (TCE) $371,353,000

Allow. for Funds During Constr. (AFDC) $36,690,000

Total Plant Investment (TPI) $408,043,000

 Preproduction Costs $10,474,000

 Inventory Capital $50,000

Total Capital Requirement (TCR) $418,567,000

Total Capital Investment ($/kW - gross) $732

Capital Recovery Factor = i(1+ i)n

 / (1 + i)n - 1 0.0858 25 years. 

Annualized Capital Costs 

(Capital Recover Factor x Total Capital Investment) $35,917,500 7% Assumed pretax marginal rate of return on private investment. 

OPERATING COSTS Basis

Operating & Maintenance Costs (based on 90% capacity factor)

 Variable O&M Costs

Limestone Reagent Cost $794,100 $ 25

Based on maximum heat input, SO2 removal rate (lb/hr), 1.05 stoichiometry, 95% 

CaCO3, 90% capacity factor, and $25/ton for limestone.

Water Cost $405,900 $ 1.20 Based on 1.25 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal.

FGD Waste Disposal Cost $1,514,000 $ 30

Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, 

forced oxidation 90% dry, and $30/ton on-site disposal cost. Disposal cost only 

includes additional WFGD by-products and does not include fly ash. No credit is 

assumed for by-product sales.

Auxiliary Power Cost $4,566,000 $ 45

Based on auxiliary power requirement of 2% (gross), 90% capacity factor, and 

$45/MW.

 Total Variable O&M Costs $7,280,000

 Fixed O&M Costs

Additional Operators per shift 4.0 Based on S&L O&M estimate for wet FGD.

Operating Labor $1,173,800

3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an 

annual operator salary of $70,000/year.

Supervisor Labor $176,100 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $15,170,000 5.0%

Maintenance Default Factor for limestone scrubber with forced oxidation from 

EPA's Coal Utility Environmental Cost (CUECost) Workbook.

Maintenance Labor $1,291,200 110.0% of operating labor. EPA Control Cost Manual, page 2-31

 Total Fixed O&M Cost $17,811,100

Indirect Operating Cost

Property Taxes $4,080,400 1%

Insurance $4,080,400 1%

Administration $8,160,900 2%

 Total Indirect Operating Cost $16,321,700

Total Annual Operating Cost $41,412,800

TOTAL ANNUAL COST

Annualized Capital Cost $35,917,500

Annual Operating Cost $41,412,800

 Total Annual Cost $77,330,300

Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost 

(CUECost) Worksheet, using Sooner specific fuel specifications and boiler 

configuration. 

Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet, 

modified to account for recent increases in equipment costs and commodities. 

Costs were compared to vendor quotes provided on other recent similar projects. 

TCR includes all costs required to purchase equipment, costs of labor and 

materials for installing teh equipment, costs for site preparation and buildings, and 

retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost 

Manual 6th Ed., page 2-34).

Muskogee Unit 5
Oklahoma Gas & Electric 

Muskogee Generating Station – BART Determination 

May 28, 2008 

Page B-1 

Attachment B 

Muskogee Units 4 & 5 

BART Determination – Visibility Impact Modeling Details 
 

CALPUFF MODELING REPORT S BART DETERMINATION

OKLAHOMA GAS & ELECTRIC

MUSKOGEE GENERATING STATION

Prepared by: 

TRINITY CONSULTANTS

120 East Sheridan 

Suite 205 

Oklahoma City, OK 73104 

(405) 228-3292 

March 17, 2008 

Project 083701.0004 
OG&E / Sargent & Lundy i Trinity Consultants 

BART Modeling Protocol 083701.0004 

TABLE OF CONTENTS

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

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

1.2 MODELING PROTOCOL BACKGROUND .................................................................. 1-2 

1.3 OBJECTIVE ............................................................................................................ 1-2 

1.4 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..........................................................3-7

3.2.5 BUOY METEOROLOGICAL DATA.........................................................................3-8

3.3 CALMET CONTROL PARAMETERS....................................................................... 3-9 

3.3.1 VERTICAL METEOROLOGICAL PROFILE..............................................................3-9

3.3.2 INFLUENCES OF OBSERVATIONS .......................................................................3-10

4. CALPUFF........................................................................................................... 4-1

4.1 SOURCE EMISSIONS............................................................................................... 4-1 

4.2 RECEPTOR LOCATIONS.......................................................................................... 4-1 

4.3 BACKGROUND OZONE AND AMMONIA.................................................................. 4-1 

4.4 CALPUFF MODEL CONTROL PARAMETERS......................................................... 4-1 

5. CALPOST........................................................................................................... 5-1
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

ii

5.1 CALPOST – LIGHT EXTINCTION ALGORITHM ..................................................... 5-1 

5.2 CALPOST PROCESSING METHOD......................................................................... 5-2 

5.3 NATURAL BACKGROUND ...................................................................................... 5-2 

5.4 EVALUATING VISIBILITY RESULTS ....................................................................... 5-2 

5.5 SUMMARY OF CALPOST CONTROL PARAMETERS............................................... 5-2 

6. VISIBILITY RESULTS ........................................................................................... 6-1

APPENDIX A- METEOROLOGICAL STATIONS

APPENDIX B – SAMPLE CALMET CONTROL FILE

APPENDIX C – SAMPLE CALPUFF CONTROL FILE

APPENDIX D – SAMPLE CALPOST CONTROL FILE

APPENDIX E – MUSKOGEE STATION EMISSION SUMMARY
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

iii

LIST OF TABLES

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

TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS .......................................1-3

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

TABLE 3-1. VERTICAL LAYERS OF THE CALMET METEOROLOGICAL DOMAIN..............................3-10

TABLE 5-1. MONTHLY HUMIDITY FACTORS.......................................................................................5-2

TABLE 5-2. DEFAULT AVERAGE ANNUAL NATURAL BACKGROUND LEVELS ...................................5-2

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
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

iv

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 .................................................3-8

FIGURE 3-6. PLOT OF BUOY METEOROLOGICAL STATIONS ................................................................3-9

 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

1-1

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 report summarizes the results of CALPUFF modeling performed for the Muskogee Generating 

Station. Modeling methodology used in the analysis is described in this report along with final 

visibility impact results. 

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. 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

1-2

1.2 MODELING PROTOCOL BACKGROUND

To promote consistency between states in the development of BART modeling protocols and to 

harmonize the approaches between adjacent RPOs, the Central States Regional Air Planning 

(CENRAP) organization developed BART Modeling Guidelines (December 15, 2005). The intent of 

the guidelines is to assist CENRAP states and source operators in the development of statewide and 

source-specific modeling protocols. 

1.3 OBJECTIVE

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

procedures that will be followed to conduct a refined CALPUFF modeling analysis for the OG&E 

generating stations discussed above. The modeling methods and procedures 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. 

1.4 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 at the Muskogee Station. 

TABLE 1-1. BART-ELIGIBLE SOURCES (MUSKOGEE STATION) 

EPN Description 

Unit 4 5,480 MMBtu/hr Coal Fired Boiler 

Unit 5 5,480 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 tables summarize 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 tables below are 

the distances between the stations and the closest border of the Class I areas. 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

1-3

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

CACR HEGL UPBU WIMO 

Muskogee 180 230 164 324 

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
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

2-1

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. 

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 5.6394 070622 

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 / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

2-2

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 / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

3-1

3. CALMET

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. 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

3-2

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 / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

3-3

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 / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

3-4

• 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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3-5

Missing surface data was filled using procedures recommended by U.S. EPA.1 Missing 

data periods of 5 hours or less were replaced using these procedures. For periods greater 

than 5 hours, data was left either unfilled or was not used in CALMET processing. A large 

enough quantity of surface stations was included in the domain that overlapping areas of 

influence allowed data from an alternate station to be used. 

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) 

 1

 “Procedures for Substituting Values for Missing NWS Meteorological Data for Use in Regulatory Air Quality 

Models”, Dennis Atkinson and Russell F. Lee, July 7, 1992, http://www.epa.gov/scram001/surface/missdata.txt 

-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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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. Missing upper air data was replaced using a persistence method- the assumption 

that data from the preceding or following hours are representative of the missing period. 

Data from either the preceding or following hours were extrapolated to fill the missing 

hour. 

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
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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. 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

3-8

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. 
OG&E / Sargent & Lundy Trinity Consultants 

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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/r2

) 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/r2

 interpolations 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/r2

 interpolations. 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 
OG&E / Sargent & Lundy Trinity Consultants 

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3-11

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 / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

4-1

4. CALPUFF

The CALPUFF model uses the output file from CALMET together with source, receptor, and 

chemical reaction information to predict hourly concentration impacts. OG&E proposes to conduct a 

three-year CALPUFF analysis using data and model settings as described below. 

4.1 SOURCE EMISSIONS

Baseline (pre-BART) emission data is based upon CEMS data collected by OG&E over the 2002-

2005 time frame. In accordance with CENRAP guidelines, the emission rate over the highest 

calendar day (24-hr average) was used to establish baseline emissions. 

Emission estimates for various control scenarios were developed by Sargent and Lundy. The 

effectiveness of a number of different control technologies for NOx, SO2, and PM10 were examined. 

Emission estimates for these various scenarios are included in Appendix E. Please note that OG&E 

has elected to evaluate cost effectiveness on a facility-wide basis (as opposed to a unit-by-unit basis) 

and would install the final selected control technology on each of the affected units at the facility. 

4.2 RECEPTOR LOCATIONS

The National Park Service (NPS) has electronic files available on their website that include the 

discrete locations and elevations of receptors to be evaluated in Class I area analyses. These receptor 

sets will be used in the CALPUFF model. 

4.3 BACKGROUND OZONE AND AMMONIA

Background ozone concentrations are required in order to model the photochemical conversion of 

SO2 and NOX to sulfates (SO4) and nitrates (NO3). CALPUFF can use either a single background 

value representative of an area or hourly ozone data from one or more ozone monitoring stations. 

Hourly ozone data files will be used in the CALPUFF simulation. As provided by the Oklahoma 

DEQ, hourly ozone data from the Oklahoma City, Glenpool, and Lawton monitors over the 2001-

2003 time frame will be used. Background concentrations for ammonia will be assumed to be 

temporally and spatially invariant and will be set to 3 ppb. 

4.4 CALPUFF MODEL CONTROL PARAMETERS

Appendix C provides a sample CALPUFF input file that is proposed for the OG&E refined modeling 

analyses. Please note that puff splitting is a generally accepted option in refined modeling analyses 

over large model domains for assessing impacts on Class I areas; however, this option would require 

significant computer resources and longer runtime. Based upon previous model runs performed on 

domains (and restricted computational grids) of the size described in this report, it is expected that 

runtimes could increase by a factor for 4 to 5 with the inclusion of puff-splitting. Due to this, OG&E 
OG&E / Sargent & Lundy Trinity Consultants 

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4-2

will evaluate the use of this option during the modeling analysis and provide details in the modeling 

report about its use. 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

5-1

5. CALPOST 

A three-year CALPOST analysis will be conducted to determine the visibility change in deciview 

(dv) caused by OG&E’s BART-eligible sources when compared to a natural background. 

5.1 CALPOST – LIGHT EXTINCTION ALGORITHM 

The algorithm will be used to calculate the daily light extinction attributable to OG&E’s BARTeligible sources and light extinction attributable to a natural background. The change in deciviews 

based on the source and background light extinctions will be evaluated using the equation below. 

∆ dv = 10*ln

b b

b

ext, background ext, source

ext, background

 +















EPA’s currently approved algorithm for assessing light extinction and the updated light extinction 

calculation algorithms developed by the Interagency Monitoring of Protected Visual Environments 

(IMPROVE) workgroup will be used to assess visibility impacts from the Muskogee Station. 

The background extinction coefficient bext, background is affected by various chemical species and the 

Rayleigh scattering phenomenon. The original equation for the background extinction coefficient in 

the FLM’s FLAG guidance is as follows: 

( ) bext background Mm = bSO + bNO + bOC + bSoil + bCoarse + bap + bRay

−

4 3

1

, 

where, 

[ ] ( ) ( )

[ ] ( )

[ ]

[ ]

[ ]

[ ]

( )

( )

[ ] 3

1

3 4 3

4 2 4 4

Concentration in μg m

Relative Humidity Function

Rayleigh Scattering 10 Mm by default

10 EC

0.6 Coarse Mass

1Soil

4 OC

3 NH NO

3 NH SO

=

=

=

=

=

=

=

=

=

−

f RH

b

b

b

b

b

b f RH

b f RH

Ray

ap

Coarse

Soil

OC

NO

SO [( ) ]

[ ]

[ ]

[ ]

[ ]

[ ]

Rayleigh Scattering isscattering due to air molecules

EC denotes the concentration of elemental carbon

Coarse Mass denotes the concentration of coarse dusts

Soil denotes the concentration of fine soils

OC denotes the concentration of organic carbon

NH NO denotes the ammonium nitrate concentration

NH SO denotes the ammonium sulfate concentration

4 3

4 2 4
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

5-2

5.2 CALPOST PROCESSING METHOD

CALPOST Method 6, which calculates hourly light extinction impacts for the source and background 

using monthly average relative humidity adjustment factors will be used in the refined BART 

analysis. Monthly Class I area-specific relative humidity adjustment factors based on the centroid of 

the Class I areas as included in Table A-3 of EPA’s Guidance for Estimating Natural Visibility 

Conditions Under the Regional Haze Program will be used. The factors for the Class I areas listed to 

be evaluated in the analysis are provided in Table 5-1. 

TABLE 5-1. MONTHLY HUMIDITY FACTORS

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

Caney Creek 3.4 3.1 2.9 3.0 3.6 3.6 3.4 3.4 3.6 3.5 3.4 3.5 

Hercules-Glades 3.2 2.9 2.7 2.7 3.3 3.3 3.3 3.3 3.4 3.1 3.1 3.3 

Upper Buffalo 3.3 3.0 2.7 2.8 3.4 3.4 3.4 3.4 3.6 3.3 3.2 3.3 

Wichita Mountains 2.7 2.6 2.4 2.4 3.0 2.7 2.3 2.5 2.9 2.6 2.7 2.8 

5.3 NATURAL BACKGROUND

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 of 

EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze Program will 

be used. The annual average concentrations are provided in Table 5-2. 

TABLE 5-2. DEFAULT AVERAGE ANNUAL NATURAL BACKGROUND LEVELS

Class I Area Region SO4 NO3 OC EC Soil Coarse Mass

Caney Creek WEST 0.12 0.10 0.47 0.02 0.50 3.00

Hercules-Glades EAST 0.23 0.10 1.40 0.02 0.50 3.00

Upper Buffalo EAST 0.23 0.10 1.40 0.02 0.50 3.00

Wichita Mountains WEST 0.12 0.10 0.47 0.02 0.50 3.00 

5.4 EVALUATING VISIBILITY RESULTS

When evaluating cost-control effectiveness of the various control scenarios, OG&E will examine the 

98th percentile of the 2001-2003 daily ∆dv values output by CALPOST. Peak 24-hr impact values 

will be included for reference. 

5.5 SUMMARY OF CALPOST CONTROL PARAMETERS

Appendix E provides a sample CALPOST input file that OG&E is proposing for the modeling 

analysis. Variable values that differ from the CENRAP protocol are generally the result of data 

input/output handling issues (e.g., types of output, receptor numbers, etc.). 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

6-1

6. VISIBILITY RESULTS

A summary of visibility impacts from the various control scenarios described in Section 4 is included 

below. In addition to the 98th percentile values typically examined in BART analyses, peak 24-hr 

impacts are also included below. 

TABLE 6-1. MUSKOGEE STATION VISIBILITY RESULTS

 Peak Impact 98th Percentile 

Pollutant Class I Area 

Control 

Technology (∆dv) 

% 

Reduction 

from 

previous 

% 

Reduction 

from 

Baseline (∆dv) 

% 

Reduction 

from 

previous 

% 

Reduction 

from 

Baseline 

NOx Caney Creek Baseline 3.54 -- -- 1.06 -- --

 LNB/OFA 1.11 69% 69% 0.32 70% 70%

 SCR 0.54 52% 85% 0.14 56% 87%

 Herc-Glades Baseline 2.21 -- -- 0.47 -- --

 LNB/OFA 0.69 69% 69% 0.14 71% 71%

 SCR 0.31 55% 86% 0.06 54% 87%

 Upper Buffalo Baseline 3.66 -- -- 0.84 -- --

 LNB/OFA 1.21 67% 67% 0.24 71% 71%

 SCR 0.58 52% 84% 0.11 53% 86%

 Wichita Mts Baseline 2.16 -- -- 0.61 -- --

 LNB/OFA 0.69 68% 68% 0.18 71% 71%

 SCR 0.31 55% 86% 0.08 55% 87%

PM10 Caney Creek Baseline 0.52 -- -- 0.17 -- --

 Polishing Filter 0.31 41% 41% 0.11 38% 38%

 Herc-Glades Baseline 0.23 -- -- 0.09 -- --

 Polishing Filter 0.15 38% 38% 0.05 45% 45%

 Upper Buffalo Baseline 0.51 -- -- 0.14 -- --

 Polishing Filter 0.33 35% 35% 0.09 41% 41%

 Wichita Mts Baseline 0.21 -- -- 0.08 -- --

 Polishing Filter 0.13 39% 39% 0.04 41% 41%

SO2/H2SO4 Caney Creek Baseline 4.17 -- -- 1.47 -- --

 DFGD 0.65 84% 84% 0.20 87% 87%

 WFGD 0.64 2% 85% 0.24 -24% 83%

 Herc-Glades Baseline 2.52 -- -- 0.92 -- --

 DFGD 0.43 83% 83% 0.12 87% 87%

 WFGD 0.50 -14% 80% 0.13 -9% 86%

 Upper Buffalo Baseline 3.72 -- -- 1.28 -- --

 DFGD 0.60 84% 84% 0.17 87% 87%

 WFGD 0.74 -25% 80% 0.19 -16% 85%

 Wichita Mts Baseline 3.13 -- -- 1.18 -- --

 DFGD 0.51 84% 84% 0.15 87% 87%

 WFGD 0.54 -5% 83% 0.14 3% 88%
OG&E / Sargent & Lundy A-1 Trinity Consultants 

BART Modeling Report 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 
OG&E / Sargent & Lundy A-2 Trinity Consultants 

BART Modeling Report 083701.0004 

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 
OG&E / Sargent & Lundy A-3 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC North

(km) Long Lat 

83 KTCS 72271 -952.353 -695.469 96.9888 39.9937 

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 
OG&E / Sargent & Lundy A-4 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC North

(km) Long Lat 

127 KEHR 72423 812.573 -199.695 97.0096 39.9982 

128 KEVV 93817 822.929 -172.715 97.0097 39.9984 

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 
OG&E / Sargent & Lundy A-5 Trinity Consultants 

BART Modeling Report 083701.0004 

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 
OG&E / Sargent & Lundy A-6 Trinity Consultants 

BART Modeling Report 083701.0004 

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 
OG&E / Sargent & Lundy A-7 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

38 SAGU 57337 -790.269 -176.061 96.9907 39.9984 

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 
OG&E / Sargent & Lundy A-8 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

78 COLU 141740 220.541 -316.555 97.0026 39.9971 

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 
OG&E / Sargent & Lundy A-9 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

118 PADU 156110 753.185 -293.024 97.0089 39.9974 

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 
OG&E / Sargent & Lundy A-10 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

158 MCES 235415 471.737 -143.942 97.0056 39.9987 

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 
OG&E / Sargent & Lundy A-11 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

198 ROY 297638 -644.735 -422.422 96.9924 39.9962 

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 
OG&E / Sargent & Lundy A-12 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

238 TULS 348992 99.361 -419.873 97.0012 39.9962 

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 
OG&E / Sargent & Lundy A-13 Trinity Consultants 

BART Modeling Report 083701.0004 

Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC 

North 

(km) Long Lat 

278 NAVA 416210 28.358 -892.028 97.0003 39.9919 

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 / Sargent & Lundy A-14 Trinity Consultants 

BART Modeling Report 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 
OG&E Trinity Consultants 

BART Modeling Protocol 083701.0004 

APPENDIX B – SAMPLE CALMET CONTROL FILE
01Met01a.inp

2001 - RefinedJanuary 1 - January 10---------------- Run title (3 lines) ------------------------------------------ CALMET MODEL CONTROL FILE ---------------------------------------------------------------------------------------------------------INPUT GROUP: 0 -- Input and Output File NamesSubgroup (a)------------Default Name Type File Name------------ ---- ---------GEO.DAT input ! GEODAT=GEO.DAT !SURF.DAT input ! SRFDAT=SURF2001.DAT !CLOUD.DAT input * CLDDAT= *PRECIP.DAT input ! PRCDAT=precip01.DAT !MM4.DAT input ! MM4DAT=W:\01CENRAPMM\extracted_2001_01a_epa_12km.unx !WT.DAT input * WTDAT= *CALMET.LST output ! METLST=01Met01a.LST !CALMET.DAT output ! METDAT=01MET01a.MET !PACOUT.DAT output * PACDAT= *All file names will be converted to lower case if LCFILES = TOtherwise, if LCFILES = F, file names will be converted to UPPER CASE T = lower case ! LCFILES = T ! F = UPPER CASENUMBER OF UPPER AIR & OVERWATER STATIONS: Number of upper air stations (NUSTA) No default ! NUSTA = 17 ! Number of overwater met stations (NOWSTA) No default ! NOWSTA = 12 ! !END!--------------------------------------------------------------------------------Subgroup (b)---------------------------------Upper air files (one per station)---------------------------------Default Name Type File Name------------ ---- ---------

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01Met01a.inp

UP1.DAT input 1 ! UPDAT=UPABQ01.DAT! !END!UP2.DAT input 2 ! UPDAT=UPAMA01.DAT! !END!UP3.DAT input 3 ! UPDAT=UPBMX01.DAT! !END!UP4.DAT input 4 ! UPDAT=UPBNA01.DAT! !END!UP5.DAT input 5 ! UPDAT=UPBRO01.DAT! !END!UP6.DAT input 6 ! UPDAT=UPCRP01.DAT! !END!UP7.DAT input 7 ! UPDAT=UPDDC01.DAT! !END!UP8.DAT input 8 ! UPDAT=UPDRT01.DAT! !END!UP9.DAT input 9 ! UPDAT=UPEPZ01.DAT! !END!UP10.DAT input 10 ! UPDAT=UPFWD01.DAT! !END!UP11.DAT input 11 ! UPDAT=UPJAN01.DAT! !END!UP12.DAT input 12 ! UPDAT=UPLCH01.DAT! !END!UP13.DAT input 13 ! UPDAT=UPLZK01.DAT! !END!UP14.DAT input 14 ! UPDAT=UPMAF01.DAT! !END!UP15.DAT input 15 ! UPDAT=UPOUN01.DAT! !END!UP16.DAT input 16 ! UPDAT=UPSHV01.DAT! !END!UP17.DAT input 17 ! UPDAT=UPSIL01.DAT! !END!--------------------------------------------------------------------------------Subgroup (c)-----------------------------------------Overwater station files (one per station)-----------------------------------------Default Name Type File Name------------ ---- ---------OW1.DAT input 1 ! SEADAT=42001_01_sea.dat! !END!OW2.DAT input 2 ! SEADAT=42002_01_sea.dat! !END!OW3.DAT input 3 ! SEADAT=42007_01_sea.dat! !END!OW4.DAT input 4 ! SEADAT=42019_01_sea.dat! !END!OW5.DAT input 5 ! SEADAT=42020_01_sea.dat! !END!OW6.DAT input 6 ! SEADAT=42035_01_sea.dat! !END!OW7.DAT input 7 ! SEADAT=42040_01_sea.dat! !END!OW8.DAT input 8 ! SEADAT=42045_01_sea.dat! !END!OW9.DAT input 9 ! SEADAT=42046_01_sea.dat! !END!OW10.DAT input 10 ! SEADAT=42047_01_sea.dat! !END!OW11.DAT input 11 ! SEADAT=42048_01_sea.dat! !END!OW12.DAT input 12 ! SEADAT=42049_01_sea.dat! !END!--------------------------------------------------------------------------------Subgroup (d)----------------Other file names----------------Default Name Type File Name------------ ---- ---------DIAG.DAT input * DIADAT= *PROG.DAT input * PRGDAT= *

Page 2
01Met01a.inp

TEST.PRT output * TSTPRT= *TEST.OUT output * TSTOUT= *TEST.KIN output * TSTKIN= *TEST.FRD output * TSTFRD= *TEST.SLP output * TSTSLP= *--------------------------------------------------------------------------------NOTES: (1) File/path names can be up to 70 characters in length (2) Subgroups (a) and (d) must have ONE 'END' (surround by delimiters) at the end of the group (3) Subgroups (b) and (c) must have an 'END' (surround by delimiters) at the end of EACH LINE !END!-------------------------------------------------------------------------------INPUT GROUP: 1 -- General run control parameters-------------- Starting date: Year (IBYR) -- No default ! IBYR= 2001 ! Month (IBMO) -- No default ! IBMO= 1 ! Day (IBDY) -- No default ! IBDY= 1 ! Hour (IBHR) -- No default ! IBHR= 0 ! Base time zone (IBTZ) -- No default ! IBTZ= 6 ! PST = 08, MST = 07 CST = 06, EST = 05 Length of run (hours) (IRLG) -- No default ! IRLG= 240 ! Run type (IRTYPE) -- Default: 1 ! IRTYPE= 1 ! 0 = Computes wind fields only 1 = Computes wind fields and micrometeorological variables (u*, w*, L, zi, etc.) (IRTYPE must be 1 to run CALPUFF or CALGRID) Compute special data fields required by CALGRID (i.e., 3-D fields of W wind components and temperature) in additional to regular Default: T ! LCALGRD = T ! fields ? (LCALGRD) (LCALGRD must be T to run CALGRID) Flag to stop run after

Page 3
01Met01a.inp

 SETUP phase (ITEST) Default: 2 ! ITEST= 2 ! (Used to allow checking of the model inputs, files, etc.) ITEST = 1 - STOPS program after SETUP phase ITEST = 2 - Continues with execution of COMPUTATIONAL phase after SETUP!END!-------------------------------------------------------------------------------INPUT GROUP: 2 -- Map Projection and Grid control parameters-------------- Projection for all (X,Y): ------------------------- Map projection (PMAP) Default: UTM ! PMAP = LCC ! UTM : Universal Transverse Mercator TTM : Tangential Transverse Mercator LCC : Lambert Conformal Conic PS : Polar Stereographic EM : Equatorial Mercator LAZA : Lambert Azimuthal Equal Area False Easting and Northing (km) at the projection origin (Used only if PMAP= TTM, LCC, or LAZA) (FEAST) Default=0.0 ! FEAST = 0.000 ! (FNORTH) Default=0.0 ! FNORTH = 0.000 ! UTM zone (1 to 60) (Used only if PMAP=UTM) (IUTMZN) No Default ! IUTMZN = 0 ! Hemisphere for UTM projection? (Used only if PMAP=UTM) (UTMHEM) Default: N ! UTMHEM = N ! N : Northern hemisphere projection S : Southern hemisphere projection Latitude and Longitude (decimal degrees) of projection origin (Used only if PMAP= TTM, LCC, PS, EM, or LAZA) (RLAT0) No Default ! RLAT0 = 40N ! (RLON0) No Default ! RLON0 = 97W ! TTM : RLON0 identifies central (true N/S) meridian of projection

Page 4
01Met01a.inp

 RLAT0 selected for convenience LCC : RLON0 identifies central (true N/S) meridian of projection RLAT0 selected for convenience PS : RLON0 identifies central (grid N/S) meridian of projection RLAT0 selected for convenience EM : RLON0 identifies central meridian of projection RLAT0 is REPLACED by 0.0N (Equator) LAZA: RLON0 identifies longitude of tangent-point of mapping plane RLAT0 identifies latitude of tangent-point of mapping plane Matching parallel(s) of latitude (decimal degrees) for projection (Used only if PMAP= LCC or PS) (XLAT1) No Default ! XLAT1 = 33N ! (XLAT2) No Default ! XLAT2 = 45N ! LCC : Projection cone slices through Earth's surface at XLAT1 and XLAT2 PS : Projection plane slices through Earth at XLAT1 (XLAT2 is not used) ---------- Note: Latitudes and longitudes should be positive, and include a letter N,S,E, or W indicating north or south latitude, and east or west longitude. For example, 35.9 N Latitude = 35.9N 118.7 E Longitude = 118.7E Datum-region ------------ The Datum-Region for the coordinates is identified by a character string. Many mapping products currently available use the model of the Earth known as the World Geodetic System 1984 (WGS-G ). Other local models may be in use, and their selection in CALMET will make its output consistent with local mapping products. The list of Datum-Regions with official transformation parameters is provided by the National Imagery and Mapping Agency (NIMA). NIMA Datum - Regions(Examples) ------------------------------------------------------------------------------ WGS-G WGS-84 GRS 80 Spheroid, Global coverage (WGS84) NAS-C NORTH AMERICAN 1927 Clarke 1866 Spheroid, MEAN FOR CONUS (NAD27) NWS-27 NWS 6370KM Radius, Sphere NWS-84 NWS 6370KM Radius, Sphere ESR-S ESRI REFERENCE 6371KM Radius, Sphere Datum-region for output coordinates (DATUM) Default: WGS-G ! DATUM = WGS-G !

Page 5
01Met01a.inp

 Horizontal grid definition: --------------------------- Rectangular grid defined for projection PMAP, with X the Easting and Y the Northing coordinate No. X grid cells (NX) No default ! NX = 462 ! No. Y grid cells (NY) No default ! NY = 376 ! Grid spacing (DGRIDKM) No default ! DGRIDKM = 4. ! Units: km Reference grid coordinate of SOUTHWEST corner of grid cell (1,1) X coordinate (XORIGKM) No default ! XORIGKM = -951.547 ! Y coordinate (YORIGKM) No default ! YORIGKM = -1646.637 ! Units: km Vertical grid definition: ------------------------- No. of vertical layers (NZ) No default ! NZ = 12 ! Cell face heights in arbitrary vertical grid (ZFACE(NZ+1)) No defaults Units: m ! ZFACE = 0.,20.,40.,60.,80.,100.,150.,200.,250.,500.,1000.,2000.,3500. !!END!-------------------------------------------------------------------------------INPUT GROUP: 3 -- Output Options-------------- DISK OUTPUT OPTION Save met. fields in an unformatted output file ? (LSAVE) Default: T ! LSAVE = T ! (F = Do not save, T = Save) Type of unformatted output file:

Page 6
01Met01a.inp

 (IFORMO) Default: 1 ! IFORMO = 1 ! 1 = CALPUFF/CALGRID type file (CALMET.DAT) 2 = MESOPUFF-II type file (PACOUT.DAT) LINE PRINTER OUTPUT OPTIONS: Print met. fields ? (LPRINT) Default: F ! LPRINT = T ! (F = Do not print, T = Print) (NOTE: parameters below control which met. variables are printed) Print interval (IPRINF) in hours Default: 1 ! IPRINF = 1 ! (Meteorological fields are printed every 1 hours) Specify which layers of U, V wind component to print (IUVOUT(NZ)) -- NOTE: NZ values must be entered (0=Do not print, 1=Print) (used only if LPRINT=T) Defaults: NZ*0  ! IUVOUT = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 ! ----------------------- Specify which levels of the W wind component to print (NOTE: W defined at TOP cell face -- 12 values) (IWOUT(NZ)) -- NOTE: NZ values must be entered (0=Do not print, 1=Print) (used only if LPRINT=T & LCALGRD=T) ----------------------------------- Defaults: NZ*0  ! IWOUT = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 ! Specify which levels of the 3-D temperature field to print (ITOUT(NZ)) -- NOTE: NZ values must be entered (0=Do not print, 1=Print) (used only if LPRINT=T & LCALGRD=T) ----------------------------------- Defaults: NZ*0  ! ITOUT = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 ! Specify which meteorological fields to print (used only if LPRINT=T) Defaults: 0 (all variables)

Page 7
01Met01a.inp

 ----------------------- Variable Print ? (0 = do not print, 1 = print) -------- ------------------ ! STABILITY = 0 ! - PGT stability class ! USTAR = 0 ! - Friction velocity ! MONIN = 0 ! - Monin-Obukhov length ! MIXHT = 0 ! - Mixing height ! WSTAR = 0 ! - Convective velocity scale ! PRECIP = 0 ! - Precipitation rate ! SENSHEAT = 0 ! - Sensible heat flux ! CONVZI = 0 ! - Convective mixing ht. Testing and debug print options for micrometeorological module Print input meteorological data and internal variables (LDB) Default: F ! LDB = F ! (F = Do not print, T = print) (NOTE: this option produces large amounts of output) First time step for which debug data are printed (NN1) Default: 1 ! NN1 = 1 ! Last time step for which debug data are printed (NN2) Default: 1 ! NN2 = 1 ! Testing and debug print options for wind field module (all of the following print options control output to wind field module's output files: TEST.PRT, TEST.OUT, TEST.KIN, TEST.FRD, and TEST.SLP) Control variable for writing the test/debug wind fields to disk files (IOUTD) (0=Do not write, 1=write) Default: 0 ! IOUTD = 0 ! Number of levels, starting at the surface, to print (NZPRN2) Default: 1 ! NZPRN2 = 0 ! Print the INTERPOLATED wind components ? (IPR0) (0=no, 1=yes) Default: 0 ! IPR0 = 0 ! Print the TERRAIN ADJUSTED surface wind

Page 8
01Met01a.inp

 components ? (IPR1) (0=no, 1=yes) Default: 0 ! IPR1 = 0 ! Print the SMOOTHED wind components and the INITIAL DIVERGENCE fields ? (IPR2) (0=no, 1=yes) Default: 0 ! IPR2 = 0 ! Print the FINAL wind speed and direction fields ? (IPR3) (0=no, 1=yes) Default: 0 ! IPR3 = 0 ! Print the FINAL DIVERGENCE fields ? (IPR4) (0=no, 1=yes) Default: 0 ! IPR4 = 0 ! Print the winds after KINEMATIC effects are added ? (IPR5) (0=no, 1=yes) Default: 0 ! IPR5 = 0 ! Print the winds after the FROUDE NUMBER adjustment is made ? (IPR6) (0=no, 1=yes) Default: 0 ! IPR6 = 0 ! Print the winds after SLOPE FLOWS are added ? (IPR7) (0=no, 1=yes) Default: 0 ! IPR7 = 0 ! Print the FINAL wind field components ? (IPR8) (0=no, 1=yes) Default: 0 ! IPR8 = 0 !!END!-------------------------------------------------------------------------------INPUT GROUP: 4 -- Meteorological data options-------------- NO OBSERVATION MODE (NOOBS) Default: 0 ! NOOBS = 0 ! 0 = Use surface, overwater, and upper air stations 1 = Use surface and overwater stations (no upper air observations) Use MM5 for upper air data 2 = No surface, overwater, or upper air observations Use MM5 for surface, overwater, and upper air data NUMBER OF SURFACE & PRECIP. METEOROLOGICAL STATIONS Number of surface stations (NSSTA) No default ! NSSTA = 162 !

Page 9
01Met01a.inp

 Number of precipitation stations (NPSTA=-1: flag for use of MM5 precip data) (NPSTA) No default ! NPSTA = 298 ! CLOUD DATA OPTIONS Gridded cloud fields: (ICLOUD) Default: 0 ! ICLOUD = 0 ! ICLOUD = 0 - Gridded clouds not used ICLOUD = 1 - Gridded CLOUD.DAT generated as OUTPUT ICLOUD = 2 - Gridded CLOUD.DAT read as INPUT ICLOUD = 3 - Gridded cloud cover from Prognostic Rel. Humidity FILE FORMATS Surface meteorological data file format (IFORMS) Default: 2 ! IFORMS = 2 ! (1 = unformatted (e.g., SMERGE output)) (2 = formatted (free-formatted user input)) Precipitation data file format (IFORMP) Default: 2 ! IFORMP = 2 ! (1 = unformatted (e.g., PMERGE output)) (2 = formatted (free-formatted user input)) Cloud data file format (IFORMC) Default: 2 ! IFORMC = 1 ! (1 = unformatted - CALMET unformatted output) (2 = formatted - free-formatted CALMET output or user input)!END!-------------------------------------------------------------------------------INPUT GROUP: 5 -- Wind Field Options and Parameters-------------- WIND FIELD MODEL OPTIONS Model selection variable (IWFCOD) Default: 1 ! IWFCOD = 1 ! 0 = Objective analysis only 1 = Diagnostic wind module Compute Froude number adjustment effects ? (IFRADJ) Default: 1 ! IFRADJ = 1 ! (0 = NO, 1 = YES) Compute kinematic effects ? (IKINE) Default: 0 ! IKINE = 0 !

Page 10
01Met01a.inp

 (0 = NO, 1 = YES) Use O'Brien procedure for adjustment of the vertical velocity ? (IOBR) Default: 0 ! IOBR = 0 ! (0 = NO, 1 = YES) Compute slope flow effects ? (ISLOPE) Default: 1 ! ISLOPE = 1 ! (0 = NO, 1 = YES) Extrapolate surface wind observations to upper layers ? (IEXTRP) Default: -4 ! IEXTRP = -4 ! (1 = no extrapolation is done, 2 = power law extrapolation used, 3 = user input multiplicative factors for layers 2 - NZ used (see FEXTRP array) 4 = similarity theory used -1, -2, -3, -4 = same as above except layer 1 data at upper air stations are ignored Extrapolate surface winds even if calm? (ICALM) Default: 0 ! ICALM = 0 ! (0 = NO, 1 = YES) Layer-dependent biases modifying the weights of surface and upper air stations (BIAS(NZ)) -1<=BIAS<=1 Negative BIAS reduces the weight of upper air stations (e.g. BIAS=-0.1 reduces the weight of upper air stations by 10%; BIAS= -1, reduces their weight by 100 %) Positive BIAS reduces the weight of surface stations (e.g. BIAS= 0.2 reduces the weight of surface stations by 20%; BIAS=1 reduces their weight by 100%) Zero BIAS leaves weights unchanged (1/R**2 interpolation) Default: NZ*0 ! BIAS = 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 , 0 ,  Minimum distance from nearest upper air station to surface station for which extrapolation of surface winds at surface station will be allowed (RMIN2: Set to -1 for IEXTRP = 4 or other situations where all surface stations should be extrapolated) Default: 4. ! RMIN2 = -1.0 ! Use gridded prognostic wind field model output fields as input to the diagnostic wind field model (IPROG) Default: 0 ! IPROG = 14 ! (0 = No, [IWFCOD = 0 or 1] 1 = Yes, use CSUMM prog. winds as Step 1 field, [IWFCOD = 0]

Page 11
01Met01a.inp

 2 = Yes, use CSUMM prog. winds as initial guess field [IWFCOD = 1] 3 = Yes, use winds from MM4.DAT file as Step 1 field [IWFCOD = 0] 4 = Yes, use winds from MM4.DAT file as initial guess field [IWFCOD = 1] 5 = Yes, use winds from MM4.DAT file as observations [IWFCOD = 1] 13 = Yes, use winds from MM5.DAT file as Step 1 field [IWFCOD = 0] 14 = Yes, use winds from MM5.DAT file as initial guess field [IWFCOD = 1] 15 = Yes, use winds from MM5.DAT file as observations [IWFCOD = 1] Timestep (hours) of the prognostic model input data (ISTEPPG) Default: 1 ! ISTEPPG = 1 ! RADIUS OF INFLUENCE PARAMETERS Use varying radius of influence Default: F ! LVARY = T! (if no stations are found within RMAX1,RMAX2, or RMAX3, then the closest station will be used) Maximum radius of influence over land in the surface layer (RMAX1) No default ! RMAX1 = 20. ! Units: km Maximum radius of influence over land aloft (RMAX2) No default ! RMAX2 = 50. ! Units: km Maximum radius of influence over water (RMAX3) No default ! RMAX3 = 500. ! Units: km OTHER WIND FIELD INPUT PARAMETERS Minimum radius of influence used in the wind field interpolation (RMIN) Default: 0.1 ! RMIN = 0.1 ! Units: km Radius of influence of terrain features (TERRAD) No default ! TERRAD = 10. ! Units: km Relative weighting of the first guess field and observations in the SURFACE layer (R1) No default ! R1 = 10. ! (R1 is the distance from an Units: km observational station at which the observation and first guess field are equally weighted) Relative weighting of the first guess field and observations in the layers ALOFT (R2) No default ! R2 = 25. !

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 (R2 is applied in the upper layers Units: km in the same manner as R1 is used in the surface layer). Relative weighting parameter of the prognostic wind field data (RPROG) No default ! RPROG = 54. ! (Used only if IPROG = 1) Units: km ------------------------ Maximum acceptable divergence in the divergence minimization procedure (DIVLIM) Default: 5.E-6 ! DIVLIM= 5.0E-06 ! Maximum number of iterations in the divergence min. procedure (NITER) Default: 50 ! NITER = 50 ! Number of passes in the smoothing procedure (NSMTH(NZ)) NOTE: NZ values must be entered Default: 2,(mxnz-1)*4 ! NSMTH =  2 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 ! Maximum number of stations used in each layer for the interpolation of data to a grid point (NINTR2(NZ)) NOTE: NZ values must be entered Default: 99. ! NINTR2 =  99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 , 99 ! Critical Froude number (CRITFN) Default: 1.0 ! CRITFN = 1. ! Empirical factor controlling the influence of kinematic effects (ALPHA) Default: 0.1 ! ALPHA = 0.1 ! Multiplicative scaling factor for extrapolation of surface observations to upper layers (FEXTR2(NZ)) Default: NZ*0.0  ! FEXTR2 = 0., 0., 0., 0., 0., 0., 0., 0., 0., 0., 0., 0. ! (Used only if IEXTRP = 3 or -3) BARRIER INFORMATION Number of barriers to interpolation of the wind fields (NBAR) Default: 0 ! NBAR = 0 ! THE FOLLOWING 4 VARIABLES ARE INCLUDED ONLY IF NBAR > 0

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 NOTE: NBAR values must be entered No defaults for each variable Units: km X coordinate of BEGINNING of each barrier (XBBAR(NBAR)) ! XBBAR = 0. ! Y coordinate of BEGINNING of each barrier (YBBAR(NBAR)) ! YBBAR = 0. ! X coordinate of ENDING of each barrier (XEBAR(NBAR)) ! XEBAR = 0. ! Y coordinate of ENDING of each barrier (YEBAR(NBAR)) ! YEBAR = 0. ! DIAGNOSTIC MODULE DATA INPUT OPTIONS Surface temperature (IDIOPT1) Default: 0 ! IDIOPT1 = 0 ! 0 = Compute internally from hourly surface observations 1 = Read preprocessed values from a data file (DIAG.DAT) Surface met. station to use for the surface temperature (ISURFT) No default ! ISURFT = 64 ! (Must be a value from 1 to NSSTA) (Used only if IDIOPT1 = 0) -------------------------- Domain-averaged temperature lapse rate (IDIOPT2) Default: 0 ! IDIOPT2 = 0 ! 0 = Compute internally from twice-daily upper air observations 1 = Read hourly preprocessed values from a data file (DIAG.DAT) Upper air station to use for the domain-scale lapse rate (IUPT) No default ! IUPT = 10 ! (Must be a value from 1 to NUSTA) (Used only if IDIOPT2 = 0) -------------------------- Depth through which the domain-scale lapse rate is computed (ZUPT) Default: 200. ! ZUPT = 200. ! (Used only if IDIOPT2 = 0) Units: meters -------------------------- Domain-averaged wind components (IDIOPT3) Default: 0 ! IDIOPT3 = 0 !

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 0 = Compute internally from twice-daily upper air observations 1 = Read hourly preprocessed values a data file (DIAG.DAT) Upper air station to use for the domain-scale winds (IUPWND) Default: -1 ! IUPWND = -1 ! (Must be a value from -1 to NUSTA) (Used only if IDIOPT3 = 0) -------------------------- Bottom and top of layer through which the domain-scale winds are computed (ZUPWND(1), ZUPWND(2)) Defaults: 1., 1000. ! ZUPWND= 1., 2000. ! (Used only if IDIOPT3 = 0) Units: meters -------------------------- Observed surface wind components for wind field module (IDIOPT4) Default: 0 ! IDIOPT4 = 0 ! 0 = Read WS, WD from a surface data file (SURF.DAT) 1 = Read hourly preprocessed U, V from a data file (DIAG.DAT) Observed upper air wind components for wind field module (IDIOPT5) Default: 0 ! IDIOPT5 = 0 ! 0 = Read WS, WD from an upper air data file (UP1.DAT, UP2.DAT, etc.) 1 = Read hourly preprocessed U, V from a data file (DIAG.DAT) LAKE BREEZE INFORMATION Use Lake Breeze Module (LLBREZE) Default: F ! LLBREZE = F ! Number of lake breeze regions (NBOX) ! NBOX = 0 ! X Grid line 1 defining the region of interest ! XG1 = 0. ! X Grid line 2 defining the region of interest ! XG2 = 0. ! Y Grid line 1 defining the region of interest ! YG1 = 0. ! Y Grid line 2 defining the region of interest ! YG2 = 0. !

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 X Point defining the coastline (Straight line) (XBCST) (KM) Default: none ! XBCST = 0. ! Y Point defining the coastline (Straight line) (YBCST) (KM) Default: none ! YBCST = 0. ! X Point defining the coastline (Straight line) (XECST) (KM) Default: none ! XECST = 0. ! Y Point defining the coastline (Straight line) (YECST) (KM) Default: none ! YECST = 0. ! Number of stations in the region Default: none ! NLB = 0 !  (Surface stations + upper air stations) Station ID's in the region (METBXID(NLB)) (Surface stations first, then upper air stations) ! METBXID = 0 !!END!-------------------------------------------------------------------------------INPUT GROUP: 6 -- Mixing Height, Temperature and Precipitation Parameters-------------- EMPIRICAL MIXING HEIGHT CONSTANTS Neutral, mechanical equation (CONSTB) Default: 1.41 ! CONSTB = 1.41 ! Convective mixing ht. equation (CONSTE) Default: 0.15 ! CONSTE = 0.15 ! Stable mixing ht. equation (CONSTN) Default: 2400. ! CONSTN = 2400.! Overwater mixing ht. equation (CONSTW) Default: 0.16 ! CONSTW = 0.16 ! Absolute value of Coriolis parameter (FCORIOL) Default: 1.E-4 ! FCORIOL = 1.0E-04! Units: (1/s) SPATIAL AVERAGING OF MIXING HEIGHTS Conduct spatial averaging (IAVEZI) (0=no, 1=yes) Default: 1 ! IAVEZI = 1 ! Max. search radius in averaging

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 process (MNMDAV) Default: 1 ! MNMDAV = 1 ! Units: Grid cells Half-angle of upwind looking cone for averaging (HAFANG) Default: 30. ! HAFANG = 30. ! Units: deg. Layer of winds used in upwind averaging (ILEVZI) Default: 1 ! ILEVZI = 1 ! (must be between 1 and NZ) OTHER MIXING HEIGHT VARIABLES Minimum potential temperature lapse rate in the stable layer above the current convective mixing ht. Default: 0.001 ! DPTMIN = 0.001 ! (DPTMIN) Units: deg. K/m Depth of layer above current conv. mixing height through which lapse Default: 200. ! DZZI = 200. ! rate is computed (DZZI) Units: meters Minimum overland mixing height Default: 50. ! ZIMIN = 20. ! (ZIMIN) Units: meters Maximum overland mixing height Default: 3000. ! ZIMAX = 3500. ! (ZIMAX) Units: meters Minimum overwater mixing height Default: 50. ! ZIMINW = 20. ! (ZIMINW) -- (Not used if observed Units: meters overwater mixing hts. are used) Maximum overwater mixing height Default: 3000. ! ZIMAXW = 3500. ! (ZIMAXW) -- (Not used if observed Units: meters overwater mixing hts. are used) TEMPERATURE PARAMETERS 3D temperature from observations or from prognostic data? (ITPROG) Default:0 !ITPROG = 0 ! 0 = Use Surface and upper air stations (only if NOOBS = 0) 1 = Use Surface stations (no upper air observations) Use MM5 for upper air data (only if NOOBS = 0,1) 2 = No surface or upper air observations Use MM5 for surface and upper air data (only if NOOBS = 0,1,2) Interpolation type (1 = 1/R ; 2 = 1/R**2) Default:1 ! IRAD = 1 !

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 Radius of influence for temperature interpolation (TRADKM) Default: 500. ! TRADKM = 500. ! Units: km Maximum Number of stations to include in temperature interpolation (NUMTS) Default: 5 ! NUMTS = 5 ! Conduct spatial averaging of temp- eratures (IAVET) (0=no, 1=yes) Default: 1 ! IAVET = 1 ! (will use mixing ht MNMDAV,HAFANG so make sure they are correct) Default temperature gradient Default: -.0098 ! TGDEFB = -0.0098 ! below the mixing height over water (K/m) (TGDEFB) Default temperature gradient Default: -.0045 ! TGDEFA = -0.0045 ! above the mixing height over water (K/m) (TGDEFA) Beginning (JWAT1) and ending (JWAT2) land use categories for temperature ! JWAT1 = 55 ! interpolation over water -- Make ! JWAT2 = 55 ! bigger than largest land use to disable PRECIP INTERPOLATION PARAMETERS Method of interpolation (NFLAGP) Default = 2 ! NFLAGP = 2 ! (1=1/R,2=1/R**2,3=EXP/R**2) Radius of Influence (km) (SIGMAP) Default = 100.0 ! SIGMAP = 100. ! (0.0 => use half dist. btwn nearest stns w & w/out precip when NFLAGP = 3) Minimum Precip. Rate Cutoff (mm/hr) Default = 0.01 ! CUTP = 0.01 ! (values < CUTP = 0.0 mm/hr)!END!-------------------------------------------------------------------------------INPUT GROUP: 7 -- Surface meteorological station parameters-------------- SURFACE STATION VARIABLES (One record per station -- 15 records in all)

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 1 2 Name ID X coord. Y coord. Time Anem. (km) (km) zone Ht.(m) ----------------------------------------------------------! SS1 ='KDYS' 69019 -267.672 -834.095 6 4 !! SS2 ='KNPA' 72222 932.565 -1020.909 6 10 !! SS3 ='KBFM' 72223 857.471 -996.829 6 10 !! SS4 ='KGZH' 72227 946.767 -899.515 6 10 !! SS5 ='KTCL' 72228 870.843 -706.104 6 10 !! SS6 ='KNEW' 53917 674.172 -1078.342 6 8 !! SS7 ='KNBG' 12958 677.719 -1104.227 6 10 !! SS8 ='BVE ' 12884 741.996 -1153.463 6 10 !! SS9 ='KPTN' 72232 550.88 -1124.295 6 10 !! SS10 ='KMEI' 13865 774.911 -814.225 6 10 !! SS11 ='KPIB' 72234 728.416 -915.165 6 10 !! SS12 ='KGLH' 72235 557.072 -703.097 6 6 !! SS13 ='KHEZ' 11111 540.777 -912.22 6 10 !! SS14 ='KMCB' 11112 622.755 -949.618 6 10 !! SS15 ='KGWO' 11113 640.102 -695.286 6 10 !! SS16 ='KASD' 72236 692.381 -1043.261 6 10 !! SS17 ='KPOE' 72239 363.294 -984.839 6 4 !! SS18 ='KBAZ' 72241 -102.133 -1140.886 6 10 !! SS19 ='KGLS' 72242 215.108 -1185.604 6 8 !! SS20 ='KDWH' 11114 140.413 -1101.174 6 10 !! SS21 ='KIAH' 12960 158.266 -1108.37 6 10 !! SS22 ='KHOU' 72243 167.147 -1147.402 6 10 !! SS23 ='KEFD' 12906 178.551 -1152.782 6 4 !! SS24 ='KCXO' 72244 152.739 -1069.309 6 10 !! SS25 ='KCLL' 11115 60.898 -1044.381 6 8 !! SS26 ='KLFK' 93987 214.643 -969.355 6 8 !! SS27 ='KUTS' 11116 136.056 -1026.773 6 10 !! SS28 ='KTYR' 11117 150.451 -846.207 6 10 !! SS29 ='KCRS' 72246 56.655 -882.642 6 10 !! SS30 ='KGGG' 72247 214.572 -841.163 6 10 !! SS31 ='KGKY' 11118 -9.365 -812.25 6 10 !! SS32 ='KDTN' 72248 304.827 -821.713 6 10 !! SS33 ='KBAD' 11119 312.743 -825.101 6 4 !! SS34 ='KMLU' 11120 465.834 -816.211 6 10 !! SS35 ='KTVR' 11121 561.446 -840.225 6 10 !! SS36 ='KTRL' 11122 68.599 -806.417 6 10 !! SS37 ='KOCH' 72249 216.81 -930.252 6 10 !! SS38 ='KBRO' 12919 -44.167 -1571.387 6 10 !! SS39 ='KALI' 72251 -103.012 -1363.74 6 10 !! SS40 ='KLRD' 12920 -246.548 -1381.603 6 5 !! SS41 ='KSSF' 72252 -143.386 -1183.35 6 10 !! SS42 ='KRKP' 11123 -4.965 -1324.914 6 10 !! SS43 ='KCOT' 11124 -219.097 -1280.964 6 10 !! SS44 ='KLBX' 11125 150.245 -1207.466 6 10 !

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! SS45 ='KSAT' 12921 -143.024 -1160.935 6 10 !! SS46 ='KHDO' 12962 -211.702 -1178.172 6 10 !! SS47 ='KSKF' 72253 -154.625 -1177.555 6 4 !! SS48 ='KHYI' 11126 -84.156 -1122.487 6 10 !! SS49 ='KTKI' 72254 38.788 -754.791 6 10 !! SS50 ='KBMQ' 11127 -118.39 -1027.031 6 10 !! SS51 ='KATT' 11128 -67.587 -1075.97 6 10 !! SS52 ='KSGR' 11129 131.478 -1151.702 6 10 !! SS53 ='KGTU' 11130 -65.624 -1033.173 6 10 !! SS54 ='KVCT' 12912 6.587 -1236.788 6 10 !! SS55 ='KPSX' 72255 73.878 -1253.33 6 10 !! SS56 ='KACT' 13959 -22.12 -929.156 6 10 !! SS57 ='KPWG' 72256 -30.147 -944.073 6 10 !! SS58 ='KILE' 72257 -65.288 -988.507 6 10 !! SS59 ='KGRK' 11131 -79.643 -990.173 6 5 !! SS60 ='KTPL' 11132 -38.203 -981.19 6 10 !! SS61 ='KDAL' 13960 14.014 -791.89 6 10 !! SS62 ='KPRX' 72258 143.317 -703.663 6 10 !! SS63 ='KDTO' 11133 -17.018 -752.974 6 10 !! SS64 ='KAFW' 72259 -29.564 -777.061 6 10 !! SS65 ='KFTW' 11134 -34.302 -795.502 6 8 !! SS66 ='KMWL' 11135 -99.769 -798.767 6 10 !! SS67 ='KRBD' 11136 12.453 -810.467 6 10 !! SS68 ='KDRT' 22010 -384.069 -1170.59 6 7 !! SS69 ='KFST' 72261 -566.418 -988.838 6 10 !! SS70 ='KGDP' 72262 -739.127 -873.302 6 10 !! SS71 ='KSJT' 23034 -333.338 -952.54 6 10 !! SS72 ='KMRF' 72264 -676.265 -1042.616 6 10 !! SS73 ='KMAF' 23023 -489.668 -878.107 6 8 !! SS74 ='KINK' 72265 -586.882 -890.654 6 10 !! SS75 ='KABI' 13962 -252.044 -836.353 6 10 !! SS76 ='KATS' 11137 -696.818 -763.258 7 21 !! SS77 ='KCQC' 11138 -785.757 -515.724 7 10 !! SS78 ='KROW' 23009 -698.822 -712.898 7 8 !! SS79 ='KSRR' 72268 -789.593 -686.226 7 11 !! SS80 ='KCNM' 11139 -682.79 -822.109 7 10 !! SS81 ='KALM' 36870 -838.056 -752.338 7 7 !! SS82 ='KLRU' 72269 -931.527 -804.112 7 8 !! SS83 ='KTCS' 72271 -952.353 -695.469 7 10 !! SS84 ='KSVC' 93063 -1042.029 -752.033 7 10 !! SS85 ='KDMN' 72272 -1006.77 -799.231 7 10 !! SS86 ='KMSL' 72323 854.846 -536.687 6 10 !! SS87 ='KPOF' 72330 578.62 -336.733 6 8 !! SS88 ='KGTR' 11140 779.065 -689.108 6 10 !! SS89 ='KTUP' 93862 753.875 -600.337 6 10 !! SS90 ='KMKL' 72334 727.051 -454.383 6 10 !! SS91 ='KLRF' 72340 440.654 -550.661 6 10 !! SS92 ='KHKA' 11141 643.365 -424.419 6 10 !

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! SS93 ='KHOT' 72341 358.094 -604.603 6 8 !! SS94 ='KTXK' 11142 278.022 -720.623 6 8 !! SS95 ='KLLQ' 72342 488.655 -698.008 6 10 !! SS96 ='KMWT' 72343 254.18 -599.224 6 10 !! SS97 ='KFSM' 13964 237.97 -512.87 6 10 !! SS98 ='KSLG' 72344 224.881 -419.064 6 10 !! SS99 ='KVBT' 11143 248.074 -399.892 6 10 !! SS100='KHRO' 11144 343.525 -405.601 6 8 !! SS101='KFLP' 11145 404.239 -399.142 6 10 !! SS102='KBVX' 11146 480.712 -457.853 6 10 !! SS103='KROG' 11147 258.44 -397.685 6 10 !! SS104='KSPS' 13966 -138.053 -664.886 6 10 !! SS105='KHBR' 72352 -186.121 -551.123 6 10 !! SS106='KCSM' 11148 -198.844 -513.911 6 10 !! SS107='KFDR' 11149 -181.653 -625.205 6 10 !! SS108='KGOK' 72353 -35.905 -458.97 6 10 !! SS109='KTIK' 72354 -34.581 -506.938 6 5 !! SS110='KPWA' 11150 -58.596 -493.951 6 8 !! SS111='KSWO' 11151 -7.42 -425.828 6 10 !! SS112='KMKO' 72355 146.972 -479.879 6 10 !! SS113='KRVS' 72356 91.059 -438.276 6 10 !! SS114='KBVO' 11152 87.136 -357.069 6 9 !! SS115='KMLC' 11153 110.647 -563.566 6 10 !! SS116='KOUN' 72357 -40.731 -527.298 6 10 !! SS117='KLAW' 11154 -129.405 -600.222 6 10 !! SS118='KCDS' 72360 -300.297 -610.668 6 10 !! SS119='KGNT' 72362 -985.117 -475.563 6 10 !! SS120='KGUP' 11155 -1059.475 -427.151 6 10 !! SS121='KAMA' 23047 -425.319 -518.171 6 10 !! SS122='KBGD' 72363 -395.603 -466.083 6 10 !! SS123='KFMN' 72365 -993.449 -297.944 7 10 !! SS124='KSKX' 72366 -770.464 -355.855 7 10 !! SS125='KTCC' 23048 -597.271 -511.241 7 10 !! SS126='KLVS' 23054 -732.565 -448.329 7 10 !! SS127='KEHR' 72423 812.573 -199.695 6 10 !! SS128='KEVV' 93817 822.929 -172.715 6 10 !! SS129='KMVN' 72433 704.666 -154.54 6 7 !! SS130='KMDH' 11156 676.745 -218.041 6 11 !! SS131='KBLV' 11157 617.659 -136.018 6 4 !! SS132='KSUS' 3966 547.898 -130.122 6 10 !! SS133='KPAH' 3816 725.985 -293.319 6 10 !! SS134='KJEF' 72445 419.01 -145.496 6 10 !! SS135='KAIZ' 11158 387.096 -200.609 6 10 !! SS136='KIXD' 72447 182.322 -126.913 6 10 !! SS137='KWLD' 72450 0 -298.57 6 10 !! SS138='KAAO' 11159 -18.976 -248.773 6 10 !! SS139='KIAB' 11160 -23.392 -263.471 6 10 !! SS140='KEWK' 11161 -24.645 -215.58 6 10 !

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! SS141='KGBD' 72451 -161.892 -180.781 6 11 !! SS142='KHYS' 11162 -195.191 -124.723 6 10 !! SS143='KCFV' 11163 126.442 -319.698 6 10 !! SS144='KFOE' 72456 114.618 -115.26 6 10 !! SS145='KEHA' 72460 -432.761 -320.089 6 10 !! SS146='KALS' 72462 -777.592 -245.892 7 10 !! SS147='KDRO' 11164 -945.713 -259.163 7 10 !! SS148='KLHX' 72463 -568.426 -195.178 7 10 !! SS149='KSPD' 2128 -494.076 -285.176 7 10 !! SS150='KCOS' 93037 -664.022 -102.596 7 10 !! SS151='KGUC' 72467 -857.452 -115.301 7 10 !! SS152='KMTJ' 93013 -940.981 -109.358 7 10 !! SS153='KCEZ' 72476 -1020.867 -233.14 7 10 !! SS154='KCPS' 72531 591.652 -136.14 6 10 !! SS155='KLWV' 72534 808.939 -94.46 6 10 !! SS156='KPPF' 74543 130.433 -293.855 6 10 !! SS157='KHOP' 74671 841.751 -324.569 6 3 !! SS158='KBIX' 74768 778.252 -1028.514 6 15 !! SS159='KPQL' 11165 814.599 -1019.583 6 10 !! SS160='MMPG' 76243 -348.007 -1248.779 6 10 !! SS161='MMMV' 76342 -446.576 -1449.334 6 10 !! SS162='MMMY' 76394 -316.664 -1581.176 6 10 !! END !------------------- 1 Four character string for station name (MUST START IN COLUMN 9) 2 Five digit integer for station ID!END!-------------------------------------------------------------------------------INPUT GROUP: 8 -- Upper air meteorological station parameters-------------- UPPER AIR STATION VARIABLES (One record per station -- 2 records in all) 1 2 Name ID X coord. Y coord. Time zone (km) (km)  -----------------------------------------------

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! US1 ='KABQ' 23050 -869.46 -501.713 7 !! US2 ='KAMA' 23047 -425.319 -518.171 6 !! US3 ='KBMX' 53823 951.609 -702.935 6 !! US4 ='KBNA' 13897 920.739 -377.164 6 !! US5 ='KBRO' 12919 -44.167 -1571.387 6 !! US6 ='KCRP' 12924 -51.535 -1360.349 6 !! US7 ='KDDC' 13985 -259.352 -242.681 6 !! US8 ='KDRT' 22010 -384.069 -1170.59 6 !! US9 ='KEPZ' 3020 -914.558 -852.552 7 !! US10 ='KFWD' 3990 -28.034 -793.745 6 !! US11 ='KJAN' 3940 650.105 -826.452 6 !! US12 ='KLCH' 3937 364.461 -1089.145 6 !! US13 ='KLZK' 3952 432.063 -560.441 6 !! US14 ='KMAF' 23023 -489.668 -878.107 6 !! US15 ='KOUN' 3948 -40.731 -527.298 6 !! US16 ='KSHV' 13957 298.869 -831.166 6 !! US17 ='KSIL' 53813 698.079 -1054.027 6 !! END !------------------- 1 Four character string for station name (MUST START IN COLUMN 9) 2 Five digit integer for station ID!END!-------------------------------------------------------------------------------INPUT GROUP: 9 -- Precipitation station parameters-------------- PRECIPITATION STATION VARIABLES (One record per station -- 2 records in all) (NOT INCLUDED IF NPSTA = 0) 1 2 Name Station X coord. Y coord. Code (km) (km) ------------------------------------! PS1 ='ADDI' 10063 901.489 -592.955 !! PS2 ='ALBE' 10140 899.884 -812.458 !! PS3 ='BERR' 10748 867.154 -661.971 !! PS4 ='HALE' 13620 857.62 -594.261 !! PS5 ='HAMT' 13645 826.544 -612.409 !

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! PS6 ='JACK' 14193 860.868 -896.436 !! PS7 ='MBLE' 15478 839.791 -992.343 !! PS8 ='MUSC' 15749 854.937 -537.327 !! PS9 ='PETE' 16370 922.473 -882.847 !! PS10 ='THOM' 18178 864.891 -894.227 !! PS11 ='TUSC' 18385 873.09 -706.684 !! PS12 ='VERN' 18517 817.964 -653.134 !! PS13 ='BEEB' 30530 462.78 -533.08 !! PS14 ='BRIG' 30900 318.637 -553.97 !! PS15 ='CALI' 31140 419.129 -730.939 !! PS16 ='CAMD' 31152 386.263 -700.784 !! PS17 ='DIER' 32020 267.307 -643.487 !! PS18 ='EURE' 32356 285.714 -391.299 !! PS19 ='GILB' 32794 383.775 -434.343 !! PS20 ='GREE' 32978 450.616 -483.139 !! PS21 ='STUT' 36920 510.166 -595.821 !! PS22 ='TEXA' 37048 277.314 -720.245 !! PS23 ='ALAM' 50130 -777.038 -245.291 !! PS24 ='ARAP' 50304 -445.453 -114.1 !! PS25 ='COCH' 51713 -843.702 -126.461 !! PS26 ='CRES' 51959 -856.972 -76.909 !! PS27 ='GRAN' 53477 -462.184 -201.033 !! PS28 ='GUNN' 53662 -860.363 -115.346 !! PS29 ='HUGO' 54172 -556.037 -74.8 !! PS30 ='JOHN' 54388 -515.918 -197.306 !! PS31 ='KIM ' 54538 -554.68 -262.307 !! PS32 ='MESA' 55531 -1009.654 -245.882 !! PS33 ='ORDW' 56136 -579.524 -141.149 !! PS34 ='OURA' 56203 -927.308 -164.38 !! PS35 ='PLEA' 56591 -1029.946 -199.897 !! PS36 ='PUEB' 56740 -650.053 -162.245 !! PS37 ='TYE ' 57320 -690.994 -182.032 !! PS38 ='SAGU' 57337 -793.779 -171.571 !! PS39 ='SANL' 57428 -740.179 -277.141 !! PS40 ='SHEP' 57572 -719.528 -220.042 !! PS41 ='TELL' 58204 -945.961 -170.11 !! PS42 ='TERC' 58220 -710.321 -292.412 !! PS43 ='TRIN' 58429 -659.183 -284.829 !! PS44 ='TRLK' 58436 -665.568 -287.445 !! PS45 ='WALS' 58781 -680.162 -233.45 !! PS46 ='WHIT' 58997 -620.426 -211.536 !! PS47 ='ASHL' 110281 677.366 -155.437 !! PS48 ='CAIR' 111166 689.241 -297.405 !! PS49 ='CARM' 111302 766.305 -175.312 !! PS50 ='CISN' 111664 742.235 -130.227 !! PS51 ='FLOR' 113109 725.194 -108.412 !! PS52 ='HARR' 113879 740.195 -215.267 !! PS53 ='KASK' 114629 613.959 -199.069 !

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! PS54 ='LAWR' 114957 801.433 -99.657 !! PS55 ='MTCA' 115888 799.41 -135.062 !! PS56 ='MURP' 115983 666.735 -219.575 !! PS57 ='NEWT' 116159 762.897 -82.814 !! PS58 ='REND' 117187 696.872 -185.925 !! PS59 ='SMIT' 118020 754.325 -277.976 !! PS60 ='SPAR' 118147 632.989 -182.867 !! PS61 ='VAND' 118781 678.924 -84.301 !! PS62 ='WEST' 119193 775.327 -124.149 !! PS63 ='EVAN' 122738 824.11 -173.364 !! PS64 ='NEWB' 126151 838.034 -184.189 !! PS65 ='PRIN' 127125 814.415 -139.507 !! PS66 ='STEN' 128442 852.345 -145.206 !! PS67 ='JTML' 128967 785.86 -204.812 !! PS68 ='ARLI' 140326 -110.926 -231.799 !! PS69 ='BAZI' 140620 -238.84 -188.104 !! PS70 ='BEAU' 140637 40.693 -259.137 !! PS71 ='BONN' 140957 180.603 -101.448 !! PS72 ='CALD' 141233 -54.366 -327.856 !! PS73 ='CASS' 141351 31.591 -215.278 !! PS74 ='CENT' 141404 167.504 -197.961 !! PS75 ='CHAN' 141427 132.698 -256.506 !! PS76 ='CLIN' 141612 142.776 -115.841 !! PS77 ='COLL' 141730 -267.979 -117.405 !! PS78 ='COLU' 141740 189.045 -311.581 !! PS79 ='CONC' 141867 40.931 -146.37 !! PS80 ='DODG' 142164 -259.414 -242.501 !! PS81 ='ELKH' 142432 -431.524 -319.478 !! PS82 ='ENGL' 142560 -264.379 -322.362 !! PS83 ='ERIE' 142582 153.917 -265.803 !! PS84 ='FALL' 142686 80.834 -259.783 !! PS85 ='GALA' 142938 -170.268 -147.301 !! PS86 ='GARD' 142980 -332.149 -214.978 !! PS87 ='GREN' 143248 48.554 -292 !! PS88 ='HAYS' 143527 -201.021 -123.653 !! PS89 ='HEAL' 143554 -312.756 -148.447 !! PS90 ='HILL' 143686 182.105 -145.591 !! PS91 ='INDE' 143954 114.638 -304.755 !! PS92 ='IOLA' 143984 137.393 -228.466 !! PS93 ='JOHR' 144104 108.586 -192.14 !! PS94 ='KANO' 144178 -82.923 -153.502 !! PS95 ='KIOW' 144341 -131.156 -328.843 !! PS96 ='MARI' 145039 -6.525 -179.369 !! PS97 ='MELV' 145210 112.198 -164.627 !! PS98 ='MILF' 145306 9.466 -102.305 !! PS99 ='MOUD' 145536 136.55 -309.82 !! PS100='OAKL' 145888 -338.36 -90.757 !! PS101='OTTA' 146128 148.524 -151.952 !

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01Met01a.inp

! PS102='POMO' 146498 123.872 -148.785 !! PS103='SALI' 147160 -56.156 -132.792 !! PS104='SMOL' 147551 -57.589 -138.771 !! PS105='STAN' 147756 201.192 -129.364 !! PS106='SUBL' 147922 -337.056 -271.996 !! PS107='TOPE' 148167 116.838 -102.08 !! PS108='TRIB' 148235 -413.288 -158.742 !! PS109='UNIO' 148293 176.609 -236.016 !! PS110='WALL' 148535 -394.195 -111.564 !! PS111='WICH' 148830 -38.795 -259.177 !! PS112='WILS' 148946 -127.991 -113.209 !! PS113='BENT' 150611 765.835 -310.871 !! PS114='CALH' 151227 852.121 -227.267 !! PS115='CLTN' 151631 713.076 -341.509 !! PS116='HERN' 153798 835.039 -324.875 !! PS117='MADI' 155067 831.766 -250.005 !! PS118='PADU' 156110 725.315 -292.67 !! PS119='PCTN' 156580 804.246 -277.545 !! PS120='ALEX' 160103 433.936 -959.371 !! PS121='BATN' 160549 563.036 -1031.572 !! PS122='CALH' 161411 436.36 -818.181 !! PS123='CLNT' 161899 577.635 -999.204 !! PS124='JENA' 164696 455.137 -911.689 !! PS125='LACM' 165078 364.877 -1088.263 !! PS126='MIND' 166244 347.179 -812.044 !! PS127='MONR' 166314 462.55 -814.477 !! PS128='NATC' 166582 369.813 -903.938 !! PS129='SHRE' 168440 298.233 -831.498 !! PS130='WINN' 169803 409.193 -884.925 !! PS131='BROK' 221094 621.134 -914.907 !! PS132='CONE' 221900 725.078 -804.862 !! PS133='JAKS' 224472 650.598 -826.11 !! PS134='LEAK' 224966 805.886 -943.78 !! PS135='MERI' 225776 775.44 -813.985 !! PS136='SARD' 227815 659.252 -594.021 !! PS137='SAUC' 227840 763.366 -1005.558 !! PS138='TUPE' 229003 753.481 -600.441 !! PS139='ADVA' 230022 625.39 -296.764 !! PS140='ALEY' 230088 489.607 -299.884 !! PS141='BOLI' 230789 316.095 -257.265 !! PS142='CASV' 231383 278.848 -363.145 !! PS143='CLER' 231674 548.572 -298.367 !! PS144='CLTT' 231711 279.768 -172.497 !! PS145='COLU' 231791 411.752 -119.977 !! PS146='DREX' 232331 206.841 -165.718 !! PS147='ELM ' 232568 255.182 -120.998 !! PS148='FULT' 233079 436.302 -114.093 !! PS149='HOME' 233999 616.121 -414.248 !

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01Met01a.inp

! PS150='JEFF' 234271 416.131 -145.612 !! PS151='JOPL' 234315 220.234 -312.505 !! PS152='LEBA' 234825 376.787 -247.055 !! PS153='LICK' 234919 448.45 -257.796 !! PS154='LOCK' 235027 268.099 -284.021 !! PS155='MALD' 235207 622.264 -352.069 !! PS156='MARS' 235298 323.881 -89.005 !! PS157='MAFD' 235307 359.618 -286.265 !! PS158='MCES' 235415 438.31 -103.798 !! PS159='MILL' 235594 279.592 -303.243 !! PS160='MTGV' 235834 417.444 -303.975 !! PS161='NVAD' 235987 229.38 -235.588 !! PS162='OZRK' 236460 332.595 -322.715 !! PS163='PDTD' 236777 321.295 -225.142 !! PS164='POTO' 236826 535.474 -215.124 !! PS165='ROLL' 237263 455.277 -212.788 !! PS166='ROSE' 237300 486.744 -156.257 !! PS167='SALE' 237506 478.319 -247.284 !! PS168='SENE' 237656 212.232 -346.356 !! PS169='SPRC' 237967 217.784 -330.588 !! PS170='SPVL' 237976 317.872 -298.923 !! PS171='STEE' 238043 490.224 -205.375 !! PS172='STOK' 238082 282.366 -249.68 !! PS173='SWSP' 238223 307.988 -108.584 !! PS174='TRKD' 238252 327.995 -369.664 !! PS175='TRUM' 238466 312.604 -186.416 !! PS176='UNIT' 238524 223.807 -113.079 !! PS177='VIBU' 238609 512.995 -236.439 !! PS178='VIEN' 238620 435.914 -186.806 !! PS179='WAPP' 238700 593.558 -318.328 !! PS180='WASG' 238746 520.949 -143.874 !! PS181='WEST' 238880 457.784 -347.238 !! PS182='ALBU' 290234 -871.609 -503.095 !! PS183='ARTE' 290600 -689.914 -774.455 !! PS184='AUGU' 290640 -974.149 -598.824 !! PS185='CARL' 291469 -682.406 -821.637 !! PS186='CARR' 291515 -821.335 -664.892 !! PS187='CLAY' 291887 -547.48 -374.232 !! PS188='CLOV' 291939 -566.944 -597.754 !! PS189='CUBA' 292241 -891.039 -392.352 !! PS190='CUBE' 292250 -951.736 -488.294 !! PS191='DEMI' 292436 -1010.101 -798.493 !! PS192='DURA' 292665 -783.906 -760.939 !! PS193='EANT' 292700 -733.551 -347.353 !! PS194='LAVG' 294862 -731.851 -447.93 !! PS195='PROG' 297094 -812.31 -577.673 !! PS196='RAMO' 297254 -734.136 -615.047 !! PS197='ROSW' 297610 -696.498 -712.285 !

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01Met01a.inp

! PS198='ROY ' 297638 -644.494 -422.842 !! PS199='SANT' 298085 -806.849 -444.709 !! PS200='SPRI' 298501 -676.057 -373.646 !! PS201='STAY' 298518 -808.857 -493.806 !! PS202='TNMN' 299031 -912.622 -413.503 !! PS203='TUCU' 299156 -604.957 -508.728 !! PS204='WAST' 299569 -638.519 -820.543 !! PS205='WISD' 299686 -856.457 -756.231 !! PS206='AIRS' 340179 -213.107 -595.912 !! PS207='ARDM' 340292 -11.884 -645.109 !! PS208='BENG' 340670 175.595 -567.462 !! PS209='CANE' 341437 72.343 -638.116 !! PS210='CHRT' 341544 203.973 -632.111 !! PS211='CHAN' 341684 10.792 -474.978 !! PS212='CHIK' 341750 -83.1 -547.384 !! PS213='CCTY' 342334 -164.531 -479.853 !! PS214='DUNC' 342654 -87.336 -609.835 !! PS215='ELKC' 342849 -217.232 -508.297 !! PS216='FORT' 343281 -130.039 -541.081 !! PS217='GEAR' 343497 -119.041 -482.918 !! PS218='HENN' 344052 -31.628 -599.42 !! PS219='HOBA' 344202 -189.838 -548.204 !! PS220='KING' 344865 28.421 -670.751 !! PS221='LKEU' 344975 141.785 -519.552 !! PS222='LEHI' 345108 71.833 -611.555 !! PS223='MACI' 345463 -253.239 -466.413 !! PS224='MALL' 345589 -55.647 -425.395 !! PS225='MAYF' 345648 -259.989 -511.519 !! PS226='MUSK' 346130 151.113 -543.185 !! PS227='NOWA' 346485 120.357 -364.978 !! PS228='OKAR' 346620 -88.212 -472.171 !! PS229='OKEM' 346638 62.894 -505.853 !! PS230='OKLA' 346661 -54.219 -509.977 !! PS231='PAOL' 346859 -25.939 -572.797 !! PS232='PAWH' 346935 57.943 -368.158 !! PS233='PAWN' 346944 16.863 -402.936 !! PS234='PONC' 347196 -8.402 -362.214 !! PS235='PRYO' 347309 148.985 -406.842 !! PS236='SHAT' 348101 -258.12 -406.316 !! PS237='STIG' 348497 170.629 -524.268 !! PS238='TULS' 348992 99.361 -419.873 !! PS239='TUSK' 349023 156.947 -594.453 !! PS240='WMWR' 349629 -156.042 -581.407 !! PS241='WOLF' 349748 29.378 -537.437 !! PS242='BOLI' 400876 723.871 -492.235 !! PS243='BROW' 401150 696.499 -458.224 !! PS244='CETR' 401587 858.366 -415.773 !! PS245='DICS' 402489 858.059 -388.772 !

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01Met01a.inp

! PS246='DYER' 402680 681.365 -409.615 !! PS247='GRNF' 403697 732.076 -390.773 !! PS248='JSNN' 404561 734.39 -451.872 !! PS249='LWER' 405089 871.334 -477.677 !! PS250='LEXI' 405210 773.155 -444.948 !! PS251='MASO' 405720 673.594 -479.476 !! PS252='MEMP' 405954 635.711 -522.428 !! PS253='MWFO' 405956 651.601 -513.031 !! PS254='MUNF' 406358 648.045 -477.095 !! PS255='SAMB' 408065 684.448 -363.311 !! PS256='SAVA' 408108 785.195 -498.799 !! PS257='UNCY' 409219 709.079 -367.88 !! PS258='ABIL' 410016 -251.992 -837.072 !! PS259='AMAR' 410211 -425.807 -517.874 !! PS260='AUST' 410428 -73.36 -1073.563 !! PS261='BRWN' 411136 -43.145 -1569.786 !! PS262='COST' 411889 61.112 -1043.691 !! PS263='COCR' 412015 -51.11 -1359.669 !! PS264='CROS' 412131 -203.641 -870.07 !! PS265='DFWT' 412242 -1.764 -786.588 !! PS266='EAST' 412715 -170.74 -840.382 !! PS267='ELPA' 412797 -886.293 -861.789 !! PS268='HICO' 414137 -97.472 -887.436 !! PS269='HUST' 414300 158.985 -1110.596 !! PS270='KRES' 414880 -434.589 -611.633 !! PS271='LKCK' 414975 100.038 -693.147 !! PS272='LNGV' 415348 220.658 -845.053 !! PS273='LUFK' 415424 214.211 -969.019 !! PS274='MATH' 415661 -86.679 -1329.651 !! PS275='MIDR' 415890 -490.426 -878.838 !! PS276='MTLK' 416104 -673.955 -1004.875 !! PS277='NACO' 416177 223.545 -926.17 !! PS278='NAVA' 416210 28.358 -892.028 !! PS279='NEWB' 416270 240.125 -721.264 !! PS280='BPAT' 417174 288.906 -1110.59 !! PS281='RANK' 417431 -471.686 -959.663 !! PS282='SAAG' 417943 -332.751 -952.407 !! PS283='SAAT' 417945 -143.316 -1160.893 !! PS284='SHEF' 418252 -463.535 -1020.511 !! PS285='STEP' 418623 -112.577 -858.48 !! PS286='STER' 418630 -376.93 -896.223 !! PS287='VALE' 419270 -719.824 -1014.032 !! PS288='VICT' 419364 6.856 -1237.418 !! PS289='WACO' 419419 -21.705 -929.783 !! PS290='WATR' 419499 -353.588 -915.496 !! PS291='WHEE' 419665 57.941 -1008.958 !! PS292='WPDM' 419916 262.52 -737.331 !! PS293='DORA' 232302 422.323 -345.052 !

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01Met01a.inp

! PS294='DIXN' 112353 730.842 -249.922 !! PS295='DAUP' 12172 860.103 -1039.592 !! PS296='FREV' 123104 832.766 -80.805 !! PS297='WARR' 18673 856.047 -757.08 !! PS298='MDTN' 235562 478.829 -82.092 !! END !------------------- 1 Four character string for station name (MUST START IN COLUMN 9) 2 Six digit station code composed of state code (first 2 digits) and station ID (last 4 digits)!END!

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OG&E Trinity Consultants 

BART Modeling Report 083701.0004 

APPENDIX C – SAMPLE CALPUFF CONTROL FILE
2001_SO_NOx.inp

OG&E Sooner BART Refined Analysis2001---------------- Run title (3 lines) ------------------------------------------ CALPUFF MODEL CONTROL FILE ---------------------------------------------------------------------------------------------------------INPUT GROUP: 0 -- Input and Output File Names--------------Default Name Type File Name------------ ---- ---------CALMET.DAT input * METDAT = * orISCMET.DAT input * ISCDAT = * orPLMMET.DAT input * PLMDAT = * orPROFILE.DAT input * PRFDAT = *SURFACE.DAT input * SFCDAT = *RESTARTB.DAT input * RSTARTB= *--------------------------------------------------------------------------------CALPUFF.LST output ! PUFLST =2001_SO_NOx.LST !CONC.DAT output ! CONDAT =2001_SO_NOx.DAT !DFLX.DAT output * DFDAT = *WFLX.DAT output * WFDAT = *VISB.DAT output ! VISDAT =2001_SO_NOx.VIS !RESTARTE.DAT output * RSTARTE= *--------------------------------------------------------------------------------Emission Files--------------PTEMARB.DAT input * PTDAT = *VOLEMARB.DAT input * VOLDAT = *BAEMARB.DAT input * ARDAT = *LNEMARB.DAT input * LNDAT = *--------------------------------------------------------------------------------Other Files-----------OZONE.DAT input ! OZDAT =ozone_2001.dat!VD.DAT input * VDDAT = *CHEM.DAT input * CHEMDAT= *H2O2.DAT input * H2O2DAT= *HILL.DAT input * HILDAT= *HILLRCT.DAT input * RCTDAT= *

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2001_SO_NOx.inp

COASTLN.DAT input * CSTDAT= *FLUXBDY.DAT input * BDYDAT= *BCON.DAT input * BCNDAT= *DEBUG.DAT output * DEBUG = *MASSFLX.DAT output * FLXDAT= *MASSBAL.DAT output * BALDAT= *FOG.DAT output * FOGDAT= *--------------------------------------------------------------------------------All file names will be converted to lower case if LCFILES = TOtherwise, if LCFILES = F, file names will be converted to UPPER CASE T = lower case ! LCFILES = F ! F = UPPER CASENOTE: (1) file/path names can be up to 70 characters in lengthProvision for multiple input files---------------------------------- Number of CALMET.DAT files for run (NMETDAT) Default: 1 ! NMETDAT = 36 ! Number of PTEMARB.DAT files for run (NPTDAT) Default: 0 ! NPTDAT = 0 ! Number of BAEMARB.DAT files for run (NARDAT) Default: 0 ! NARDAT = 0 ! Number of VOLEMARB.DAT files for run (NVOLDAT) Default: 0 ! NVOLDAT = 0 !!END!-------------Subgroup (0a)------------- The following CALMET.DAT filenames are processed in sequence if NMETDAT>1Default Name Type File Name------------ ---- --------- none input ! METDAT=D:\2001\01Met01a.met ! !END! none input ! METDAT=D:\2001\01Met01b.met ! !END! none input ! METDAT=D:\2001\01Met01c.met ! !END! none input ! METDAT=D:\2001\01Met02a.met ! !END! none input ! METDAT=D:\2001\01Met02b.met ! !END! none input ! METDAT=D:\2001\01Met02c.met ! !END! none input ! METDAT=D:\2001\01Met03a.met ! !END! none input ! METDAT=D:\2001\01Met03b.met ! !END!

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2001_SO_NOx.inp

 none input ! METDAT=D:\2001\01Met03c.met ! !END! none input ! METDAT=D:\2001\01Met04a.met ! !END! none input ! METDAT=D:\2001\01Met04b.met ! !END! none input ! METDAT=D:\2001\01Met04c.met ! !END! none input ! METDAT=D:\2001\01Met05a.met ! !END! none input ! METDAT=D:\2001\01Met05b.met ! !END! none input ! METDAT=D:\2001\01Met05c.met ! !END! none input ! METDAT=D:\2001\01Met06a.met ! !END! none input ! METDAT=D:\2001\01Met06b.met ! !END! none input ! METDAT=D:\2001\01Met06c.met ! !END! none input ! METDAT=D:\2001\01Met07a.met ! !END! none input ! METDAT=D:\2001\01Met07b.met ! !END! none input ! METDAT=D:\2001\01Met07c.met ! !END! none input ! METDAT=D:\2001\01Met08a.met ! !END! none input ! METDAT=D:\2001\01Met08b.met ! !END! none input ! METDAT=D:\2001\01Met08c.met ! !END! none input ! METDAT=D:\2001\01Met09a.met ! !END! none input ! METDAT=D:\2001\01Met09b.met ! !END! none input ! METDAT=D:\2001\01Met09c.met ! !END! none input ! METDAT=D:\2001\01Met10a.met ! !END! none input ! METDAT=D:\2001\01Met10b.met ! !END! none input ! METDAT=D:\2001\01Met10c.met ! !END! none input ! METDAT=D:\2001\01Met11a.met ! !END! none input ! METDAT=D:\2001\01Met11b.met ! !END! none input ! METDAT=D:\2001\01Met11c.met ! !END! none input ! METDAT=D:\2001\01Met12a.met ! !END! none input ! METDAT=D:\2001\01Met12b.met ! !END! none input ! METDAT=D:\2001\01Met12c.met ! !END!--------------------------------------------------------------------------------INPUT GROUP: 1 -- General run control parameters-------------- Option to run all periods found in the met. file (METRUN) Default: 0 ! METRUN = 0 ! METRUN = 0 - Run period explicitly defined below METRUN = 1 - Run all periods in met. file Starting date: Year (IBYR) -- No default ! IBYR = 2001 ! (used only if Month (IBMO) -- No default ! IBMO = 1 ! METRUN = 0) Day (IBDY) -- No default ! IBDY = 1 ! Hour (IBHR) -- No default ! IBHR = 0 ! Base time zone (XBTZ) -- No default ! XBTZ = 6.0 ! PST = 8., MST = 7.

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2001_SO_NOx.inp

 CST = 6., EST = 5. Length of run (hours) (IRLG) -- No default ! IRLG = 8760 ! Number of chemical species (NSPEC) Default: 5 ! NSPEC = 10 ! Number of chemical species to be emitted (NSE) Default: 3 ! NSE = 7 ! Flag to stop run after SETUP phase (ITEST) Default: 2 ! ITEST = 2 ! (Used to allow checking of the model inputs, files, etc.) ITEST = 1 - STOPS program after SETUP phase ITEST = 2 - Continues with execution of program after SETUP Restart Configuration: Control flag (MRESTART) Default: 0 ! MRESTART = 0 ! 0 = Do not read or write a restart file 1 = Read a restart file at the beginning of the run 2 = Write a restart file during run 3 = Read a restart file at beginning of run and write a restart file during run Number of periods in Restart output cycle (NRESPD) Default: 0 ! NRESPD = 0 ! 0 = File written only at last period >0 = File updated every NRESPD periods Meteorological Data Format (METFM) Default: 1 ! METFM = 1 ! METFM = 1 - CALMET binary file (CALMET.MET) METFM = 2 - ISC ASCII file (ISCMET.MET) METFM = 3 - AUSPLUME ASCII file (PLMMET.MET) METFM = 4 - CTDM plus tower file (PROFILE.DAT) and surface parameters file (SURFACE.DAT) PG sigma-y is adjusted by the factor (AVET/PGTIME)**0.2 Averaging Time (minutes) (AVET) Default: 60.0 ! AVET = 60. ! PG Averaging Time (minutes) (PGTIME)

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2001_SO_NOx.inp

 Default: 60.0 ! PGTIME = 60. !!END!-------------------------------------------------------------------------------INPUT GROUP: 2 -- Technical options-------------- Vertical distribution used in the near field (MGAUSS) Default: 1 ! MGAUSS = 1 ! 0 = uniform 1 = Gaussian Terrain adjustment method (MCTADJ) Default: 3 ! MCTADJ = 3 ! 0 = no adjustment 1 = ISC-type of terrain adjustment 2 = simple, CALPUFF-type of terrain adjustment  3 = partial plume path adjustment Subgrid-scale complex terrain flag (MCTSG) Default: 0 ! MCTSG = 0 ! 0 = not modeled 1 = modeled Near-field puffs modeled as elongated 0 (MSLUG) Default: 0 ! MSLUG = 0 ! 0 = no 1 = yes (slug model used) Transitional plume rise modeled ? (MTRANS) Default: 1 ! MTRANS = 1 ! 0 = no (i.e., final rise only) 1 = yes (i.e., transitional rise computed) Stack tip downwash? (MTIP) Default: 1 ! MTIP = 1 ! 0 = no (i.e., no stack tip downwash) 1 = yes (i.e., use stack tip downwash) Method used to simulate building downwash? (MBDW) Default: 1 ! MBDW = 1 ! 1 = ISC method 2 = PRIME method

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2001_SO_NOx.inp

 Vertical wind shear modeled above stack top? (MSHEAR) Default: 0 ! MSHEAR = 0 ! 0 = no (i.e., vertical wind shear not modeled) 1 = yes (i.e., vertical wind shear modeled) Puff splitting allowed? (MSPLIT) Default: 0 ! MSPLIT = 0 ! 0 = no (i.e., puffs not split) 1 = yes (i.e., puffs are split) Chemical mechanism flag (MCHEM) Default: 1 ! MCHEM = 1 ! 0 = chemical transformation not modeled 1 = transformation rates computed internally (MESOPUFF II scheme) 2 = user-specified transformation rates used 3 = transformation rates computed internally (RIVAD/ARM3 scheme) 4 = secondary organic aerosol formation computed (MESOPUFF II scheme for OH) Aqueous phase transformation flag (MAQCHEM) (Used only if MCHEM = 1, or 3) Default: 0 ! MAQCHEM = 0 ! 0 = aqueous phase transformation not modeled 1 = transformation rates adjusted for aqueous phase reactions Wet removal modeled ? (MWET) Default: 1 ! MWET = 1 ! 0 = no 1 = yes Dry deposition modeled ? (MDRY) Default: 1 ! MDRY = 1 ! 0 = no 1 = yes (dry deposition method specified for each species in Input Group 3) Method used to compute dispersion coefficients (MDISP) Default: 3 ! MDISP = 3 ! 1 = dispersion coefficients computed from measured values of turbulence, sigma v, sigma w 2 = dispersion coefficients from internally calculated  sigma v, sigma w using micrometeorological variables (u*, w*, L, etc.) 3 = PG dispersion coefficients for RURAL areas (computed using

Page 6
2001_SO_NOx.inp

 the ISCST multi-segment approximation) and MP coefficients in urban areas 4 = same as 3 except PG coefficients computed using the MESOPUFF II eqns. 5 = CTDM sigmas used for stable and neutral conditions. For unstable conditions, sigmas are computed as in MDISP = 3, described above. MDISP = 5 assumes that measured values are read Sigma-v/sigma-theta, sigma-w measurements used? (MTURBVW) (Used only if MDISP = 1 or 5) Default: 3 ! MTURBVW = 3 ! 1 = use sigma-v or sigma-theta measurements from PROFILE.DAT to compute sigma-y (valid for METFM = 1, 2, 3, 4) 2 = use sigma-w measurements from PROFILE.DAT to compute sigma-z (valid for METFM = 1, 2, 3, 4) 3 = use both sigma-(v/theta) and sigma-w from PROFILE.DAT to compute sigma-y and sigma-z (valid for METFM = 1, 2, 3, 4) 4 = use sigma-theta measurements from PLMMET.DAT to compute sigma-y (valid only if METFM = 3) Back-up method used to compute dispersion when measured turbulence data are missing (MDISP2) Default: 3 ! MDISP2 = 3 ! (used only if MDISP = 1 or 5) 2 = dispersion coefficients from internally calculated  sigma v, sigma w using micrometeorological variables (u*, w*, L, etc.) 3 = PG dispersion coefficients for RURAL areas (computed using the ISCST multi-segment approximation) and MP coefficients in urban areas 4 = same as 3 except PG coefficients computed using the MESOPUFF II eqns. PG sigma-y,z adj. for roughness? Default: 0 ! MROUGH = 0 ! (MROUGH) 0 = no 1 = yes Partial plume penetration of Default: 1 ! MPARTL = 1 ! elevated inversion? (MPARTL) 0 = no 1 = yes

Page 7
2001_SO_NOx.inp

 Strength of temperature inversion Default: 0 ! MTINV = 0 ! provided in PROFILE.DAT extended records? (MTINV) 0 = no (computed from measured/default gradients) 1 = yes PDF used for dispersion under convective conditions? Default: 0 ! MPDF = 0 ! (MPDF) 0 = no 1 = yes Sub-Grid TIBL module used for shore line? Default: 0 ! MSGTIBL = 0 ! (MSGTIBL) 0 = no 1 = yes Boundary conditions (concentration) modeled? Default: 0 ! MBCON = 0 ! (MBCON) 0 = no 1 = yes, using formatted BCON.DAT file 2 = yes, using unformatted CONC.DAT file Analyses of fogging and icing impacts due to emissions from arrays of mechanically-forced cooling towers can be performed using CALPUFF in conjunction with a cooling tower emissions processor (CTEMISS) and its associated postprocessors. Hourly emissions of water vapor and temperature from each cooling tower cell are computed for the current cell configuration and ambient conditions by CTEMISS. CALPUFF models the dispersion of these emissions and provides cloud information in a specialized format for further analysis. Output to FOG.DAT is provided in either 'plume mode' or 'receptor mode' format. Configure for FOG Model output? Default: 0 ! MFOG = 0 ! (MFOG) 0 = no 1 = yes - report results in PLUME Mode format 2 = yes - report results in RECEPTOR Mode format Test options specified to see if they conform to regulatory values? (MREG) Default: 1 ! MREG = 0 !

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 0 = NO checks are made 1 = Technical options must conform to USEPA Long Range Transport (LRT) guidance METFM 1 or 2 AVET 60. (min) PGTIME 60. (min) MGAUSS 1 MCTADJ 3 MTRANS 1 MTIP 1 MCHEM 1 or 3 (if modeling SOx, NOx) MWET 1 MDRY 1 MDISP 2 or 3 MPDF 0 if MDISP=3 1 if MDISP=2 MROUGH 0 MPARTL 1 SYTDEP 550. (m) MHFTSZ 0!END!-------------------------------------------------------------------------------INPUT GROUP: 3a, 3b -- Species list-------------------------------Subgroup (3a)------------ The following species are modeled:! CSPEC = SO2 ! !END!! CSPEC = SO4 ! !END!! CSPEC = NOX ! !END!! CSPEC = HNO3 ! !END!! CSPEC = NO3 ! !END!! CSPEC = NH3 ! !END!! CSPEC = PMC ! !END!! CSPEC = PMF ! !END!! CSPEC = EC ! !END!! CSPEC = SOA ! !END!

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 Dry OUTPUT GROUP SPECIES MODELED EMITTED DEPOSITED NUMBER NAME (0=NO, 1=YES) (0=NO, 1=YES) (0=NO, (0=NONE, (Limit: 12 1=COMPUTED-GAS 1=1st CGRUP, Characters 2=COMPUTED-PARTICLE 2=2nd CGRUP, in length) 3=USER-SPECIFIED) 3= etc.)! SO2 = 1, 1, 1, 0 !! SO4 = 1, 1, 2, 0 !! NOX = 1, 1, 1, 0 !! HNO3 = 1, 0, 1, 0 !! NO3 = 1, 0, 2, 0 !! NH3 = 1, 0, 1, 0 !! PMC = 1, 1, 2, 0 !! PMF = 1, 1, 2, 0 !! EC = 1, 1, 2, 0 !! SOA = 1, 1, 2, 0 !!END!-------------Subgroup (3b)------------- The following names are used for Species-Groups in which results for certain species are combined (added) prior to output. The CGRUP name will be used as the species name in output files. Use this feature to model specific particle-size distributions by treating each size-range as a separate species. Order must be consistent with 3(a) above.-------------------------------------------------------------------------------INPUT GROUP: 4 -- Map Projection and Grid control parameters-------------- Projection for all (X,Y): ------------------------- Map projection (PMAP) Default: UTM ! PMAP = LCC ! UTM : Universal Transverse Mercator TTM : Tangential Transverse Mercator LCC : Lambert Conformal Conic PS : Polar Stereographic

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 EM : Equatorial Mercator LAZA : Lambert Azimuthal Equal Area False Easting and Northing (km) at the projection origin (Used only if PMAP= TTM, LCC, or LAZA) (FEAST) Default=0.0 ! FEAST = 0.000 ! (FNORTH) Default=0.0 ! FNORTH = 0.000 ! UTM zone (1 to 60) (Used only if PMAP=UTM) (IUTMZN) No Default ! IUTMZN = 0 ! Hemisphere for UTM projection? (Used only if PMAP=UTM) (UTMHEM) Default: N ! UTMHEM = N ! N : Northern hemisphere projection S : Southern hemisphere projection Latitude and Longitude (decimal degrees) of projection origin (Used only if PMAP= TTM, LCC, PS, EM, or LAZA) (RLAT0) No Default ! RLAT0 = 40N ! (RLON0) No Default ! RLON0 = 97W ! TTM : RLON0 identifies central (true N/S) meridian of projection RLAT0 selected for convenience LCC : RLON0 identifies central (true N/S) meridian of projection RLAT0 selected for convenience PS : RLON0 identifies central (grid N/S) meridian of projection RLAT0 selected for convenience EM : RLON0 identifies central meridian of projection RLAT0 is REPLACED by 0.0N (Equator) LAZA: RLON0 identifies longitude of tangent-point of mapping plane RLAT0 identifies latitude of tangent-point of mapping plane Matching parallel(s) of latitude (decimal degrees) for projection (Used only if PMAP= LCC or PS) (XLAT1) No Default ! XLAT1 = 33N ! (XLAT2) No Default ! XLAT2 = 45N ! LCC : Projection cone slices through Earth's surface at XLAT1 and XLAT2 PS : Projection plane slices through Earth at XLAT1 (XLAT2 is not used) ---------- Note: Latitudes and longitudes should be positive, and include a letter N,S,E, or W indicating north or south latitude, and east or west longitude. For example, 35.9 N Latitude = 35.9N

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 118.7 E Longitude = 118.7E Datum-region ------------ The Datum-Region for the coordinates is identified by a character string. Many mapping products currently available use the model of the Earth known as the World Geodetic System 1984 (WGS-G ). Other local models may be in use, and their selection in CALMET will make its output consistent with local mapping products. The list of Datum-Regions with official transformation parameters is provided by the National Imagery and Mapping Agency (NIMA). NIMA Datum - Regions(Examples) ------------------------------------------------------------------------------ WGS-G WGS-84 GRS 80 Spheroid, Global coverage (WGS84) NAS-C NORTH AMERICAN 1927 Clarke 1866 Spheroid, MEAN FOR CONUS (NAD27) NWS-27 NWS 6370KM Radius, Sphere NWS-84 NWS 6370KM Radius, Sphere ESR-S ESRI REFERENCE 6371KM Radius, Sphere Datum-region for output coordinates (DATUM) Default: WGS-G ! DATUM = WGS-G !METEOROLOGICAL Grid: Rectangular grid defined for projection PMAP, with X the Easting and Y the Northing coordinate No. X grid cells (NX) No default ! NX = 462 ! No. Y grid cells (NY) No default ! NY = 376 ! No. vertical layers (NZ) No default ! NZ = 12 ! Grid spacing (DGRIDKM) No default ! DGRIDKM = 4. ! Units: km Cell face heights (ZFACE(nz+1)) No defaults Units: m ! ZFACE = 0.,20.,40.,60.,80.,100.,150.,200.,250.,500.,1000.,2000.,3500. ! Reference Coordinates of SOUTHWEST corner of grid cell(1, 1):

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 X coordinate (XORIGKM) No default ! XORIGKM = -951.547 ! Y coordinate (YORIGKM) No default ! YORIGKM = -1646.637 ! Units: kmCOMPUTATIONAL Grid: The computational grid is identical to or a subset of the MET. grid. The lower left (LL) corner of the computational grid is at grid point (IBCOMP, JBCOMP) of the MET. grid. The upper right (UR) corner of the computational grid is at grid point (IECOMP, JECOMP) of the MET. grid. The grid spacing of the computational grid is the same as the MET. grid. X index of LL corner (IBCOMP) No default ! IBCOMP = 165 ! (1 <= IBCOMP <= NX) Y index of LL corner (JBCOMP) No default ! JBCOMP = 220 ! (1 <= JBCOMP <= NY) X index of UR corner (IECOMP) No default ! IECOMP = 375 ! (1 <= IECOMP <= NX) Y index of UR corner (JECOMP) No default ! JECOMP = 348 ! (1 <= JECOMP <= NY)SAMPLING Grid (GRIDDED RECEPTORS): The lower left (LL) corner of the sampling grid is at grid point (IBSAMP, JBSAMP) of the MET. grid. The upper right (UR) corner of the sampling grid is at grid point (IESAMP, JESAMP) of the MET. grid. The sampling grid must be identical to or a subset of the computational grid. It may be a nested grid inside the computational grid. The grid spacing of the sampling grid is DGRIDKM/MESHDN. Logical flag indicating if gridded receptors are used (LSAMP) Default: T ! LSAMP = F ! (T=yes, F=no) X index of LL corner (IBSAMP) No default ! IBSAMP = 1 ! (IBCOMP <= IBSAMP <= IECOMP) Y index of LL corner (JBSAMP) No default ! JBSAMP = 1 ! (JBCOMP <= JBSAMP <= JECOMP)

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 X index of UR corner (IESAMP) No default ! IESAMP = 462 ! (IBCOMP <= IESAMP <= IECOMP) Y index of UR corner (JESAMP) No default ! JESAMP = 376 ! (JBCOMP <= JESAMP <= JECOMP) Nesting factor of the sampling grid (MESHDN) Default: 1 ! MESHDN = 1 ! (MESHDN is an integer >= 1)!END!-------------------------------------------------------------------------------INPUT GROUP: 5 -- Output Options-------------- * * FILE DEFAULT VALUE VALUE THIS RUN ---- ------------- -------------- Concentrations (ICON) 1 ! ICON = 1 ! Dry Fluxes (IDRY) 1 ! IDRY = 1 ! Wet Fluxes (IWET) 1 ! IWET = 1 ! Relative Humidity (IVIS) 1 ! IVIS = 1 ! (relative humidity file is required for visibility analysis) Use data compression option in output file? (LCOMPRS) Default: T ! LCOMPRS = T ! * 0 = Do not create file, 1 = create file DIAGNOSTIC MASS FLUX OUTPUT OPTIONS: Mass flux across specified boundaries for selected species reported hourly? (IMFLX) Default: 0 ! IMFLX = 0 ! 0 = no 1 = yes (FLUXBDY.DAT and MASSFLX.DAT filenames are specified in Input Group 0) Mass balance for each species

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 reported hourly? (IMBAL) Default: 0 ! IMBAL = 0 ! 0 = no 1 = yes (MASSBAL.DAT filename is specified in Input Group 0) LINE PRINTER OUTPUT OPTIONS: Print concentrations (ICPRT) Default: 0 ! ICPRT = 0 ! Print dry fluxes (IDPRT) Default: 0 ! IDPRT = 0 ! Print wet fluxes (IWPRT) Default: 0 ! IWPRT = 0 ! (0 = Do not print, 1 = Print) Concentration print interval (ICFRQ) in hours Default: 1 ! ICFRQ = 1 ! Dry flux print interval (IDFRQ) in hours Default: 1 ! IDFRQ = 1 ! Wet flux print interval (IWFRQ) in hours Default: 1 ! IWFRQ = 1 ! Units for Line Printer Output (IPRTU) Default: 1 ! IPRTU = 3 ! for for Concentration Deposition 1 = g/m**3 g/m**2/s 2 = mg/m**3 mg/m**2/s 3 = ug/m**3 ug/m**2/s 4 = ng/m**3 ng/m**2/s 5 = Odour Units Messages tracking progress of run written to the screen ? (IMESG) Default: 2 ! IMESG = 2 ! 0 = no 1 = yes (advection step, puff ID) 2 = yes (YYYYJJJHH, # old puffs, # emitted puffs) SPECIES (or GROUP for combined species) LIST FOR OUTPUT OPTIONS ---- CONCENTRATIONS ---- ------ DRY FLUXES ------ ------ WET FLUXES --FLUX -- SPECIES /GROUP PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? PRINTED? SAVED ON DDISK? ------- ------------------------ ------------------------ -----------------------------------

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! SO2 = 0, 1, 0, 1, 0, 1, ! SO4 = 0, 1, 0, 1, 0, 1, ! NOX = 0, 1, 0, 1, 0, 1, ! HNO3 = 0, 1, 0, 1, 0, 1, ! NO3 = 0, 1, 0, 1, 0, 1, ! PMC = 0, 1, 0, 1, 0, 1, ! PMF = 0, 1, 0, 1, 0, 1, ! EC = 0, 1, 0, 1, 0, 1, ! SOA = 0, 1, 0, 1, 0, 1,  OPTIONS FOR PRINTING "DEBUG" QUANTITIES (much output)  Logical for debug output (LDEBUG) Default: F ! LDEBUG = F ! First puff to track (IPFDEB) Default: 1 ! IPFDEB = 1 ! Number of puffs to track (NPFDEB) Default: 1 ! NPFDEB = 1 ! Met. period to start output (NN1) Default: 1 ! NN1 = 1 ! Met. period to end output (NN2) Default: 10 ! NN2 = 10 !!END!-------------------------------------------------------------------------------INPUT GROUP: 6a, 6b, & 6c -- Subgrid scale complex terrain inputs----------------------------------------Subgroup (6a)--------------- Number of terrain features (NHILL) Default: 0 ! NHILL = 0 ! Number of special complex terrain receptors (NCTREC) Default: 0 ! NCTREC = 0 ! Terrain and CTSG Receptor data for  CTSG hills input in CTDM format ? (MHILL) No Default ! MHILL = 2 ! 1 = Hill and Receptor data created

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 by CTDM processors & read from HILL.DAT and HILLRCT.DAT files 2 = Hill data created by OPTHILL & input below in Subgroup (6b); Receptor data in Subgroup (6c) Factor to convert horizontal dimensions Default: 1.0 ! XHILL2M = 1. ! to meters (MHILL=1) Factor to convert vertical dimensions Default: 1.0 ! ZHILL2M = 1. ! to meters (MHILL=1) X-origin of CTDM system relative to No Default ! XCTDMKM = 0.0E00 ! CALPUFF coordinate system, in Kilometers (MHILL=1) Y-origin of CTDM system relative to No Default ! YCTDMKM = 0.0E00 ! CALPUFF coordinate system, in Kilometers (MHILL=1)! END !---------------Subgroup (6b)--------------- 1 ** HILL informationHILL XC YC THETAH ZGRID RELIEF EXPO 1 EXPO 2 SCALE 1 SC AMAX2 NO. (km) (km) (deg.) (m) (m) (m) (m) (m)  (m)---- ---- ---- ------ ----- ------ ------ ------ ------- -- --------------------Subgroup (6c)--------------- COMPLEX TERRAIN RECEPTOR INFORMATION XRCT YRCT ZRCT XHH (km) (km) (m) ------ ----- ------ -----------------------1

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 Description of Complex Terrain Variables: XC, YC = Coordinates of center of hill THETAH = Orientation of major axis of hill (clockwise from North) ZGRID = Height of the 0 of the grid above mean sea level RELIEF = Height of the crest of the hill above the grid elevation EXPO 1 = Hill-shape exponent for the major axis EXPO 2 = Hill-shape exponent for the major axis SCALE 1 = Horizontal length scale along the major axis SCALE 2 = Horizontal length scale along the minor axis AMAX = Maximum allowed axis length for the major axis BMAX = Maximum allowed axis length for the major axis XRCT, YRCT = Coordinates of the complex terrain receptors ZRCT = Height of the ground (MSL) at the complex terrain Receptor XHH = Hill number associated with each complex terrain receptor (NOTE: MUST BE ENTERED AS A REAL NUMBER) ** NOTE: DATA for each hill and CTSG receptor are treated as a separate input subgroup and therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUP: 7 -- Chemical parameters for dry deposition of gases-------------- SPECIES DIFFUSIVITY ALPHA STAR REACTIVITY MESOPHYLL RESISTANCE HCOEFFICIENT NAME (cm**2/s) (s/cm) (dimensionless) ------- ----------- ---------- ---------- -------------------- -----------------------! SO2 = 0.1509, 1000., 8., 0., ! NOX = 0.1656, 1., 8., 5., ! HNO3 = 0.1628, 1., 18., 0., 0!END!-------------------------------------------------------------------------------INPUT GROUP: 8 -- Size parameters for dry deposition of particles

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-------------- For SINGLE SPECIES, the mean and standard deviation are used to compute a deposition velocity for NINT (see group 9) size-ranges, and these are then averaged to obtain a mean deposition velocity. For GROUPED SPECIES, the size distribution should be explicitly specified (by the 'species' in the group), and the standard deviation for each should be entered as 0. The model will then use the deposition velocity for the stated mean diameter. SPECIES GEOMETRIC MASS MEAN GEOMETRIC STANDARD NAME DIAMETER DEVIATION (microns) (microns) ------- ------------------- ------------------! SO4 = 0.48, 2. !! NO3 = 0.48, 2. !! PMC = 6.00, 2. !! PMF = 0.48, 2. !! EC = 0.48, 2. !! SOA = 0.48, 2. !!END!-------------------------------------------------------------------------------INPUT GROUP: 9 -- Miscellaneous dry deposition parameters-------------- Reference cuticle resistance (s/cm) (RCUTR) Default: 30 ! RCUTR = 30.0 ! Reference ground resistance (s/cm) (RGR) Default: 10 ! RGR = 10.0 ! Reference pollutant reactivity (REACTR) Default: 8 ! REACTR = 8.0 ! Number of particle-size intervals used to  evaluate effective particle deposition velocity (NINT) Default: 9 ! NINT = 9 ! Vegetation state in unirrigated areas (IVEG) Default: 1 ! IVEG = 1 ! IVEG=1 for active and unstressed vegetation IVEG=2 for active and stressed vegetation IVEG=3 for inactive vegetation

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!END!-------------------------------------------------------------------------------INPUT GROUP: 10 -- Wet Deposition Parameters--------------- Scavenging Coefficient -- Units: (sec)**(-1) Pollutant Liquid Precip. Frozen Precip. --------- -------------- --------------! SO2 = 3.21E-05, 0.0E00 !! SO4 = 1.0E-04, 3.0E-05 !! HNO3 = 6.0E-05, 0.0E00 !! NO3 = 1.0E-04, 3.0E-05 !! NH3 = 8.0E-05, 0.0E00 !! PMC = 1.0E-04, 3.0E-05 !! PMF = 1.0E-04, 3.0E-05 !! EC = 1.0E-04, 3.0E-05 !! SOA = 1.0E-04, 3.0E-05 !!END!-------------------------------------------------------------------------------INPUT GROUP: 11 -- Chemistry Parameters--------------- Ozone data input option (MOZ) Default: 1 ! MOZ = 1 ! (Used only if MCHEM = 1, 3, or 4) 0 = use a monthly background ozone value 1 = read hourly ozone concentrations from the OZONE.DAT data file Monthly ozone concentrations (Used only if MCHEM = 1, 3, or 4 and  MOZ = 0 or MOZ = 1 and all hourly O3 data missing) (BCKO3) in ppb Default: 12*80. ! BCKO3 = 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00, 40.00 Monthly ammonia concentrations (Used only if MCHEM = 1, or 3) (BCKNH3) in ppb Default: 12*10. 

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 ! BCKNH3 = 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00, 3.00 ! Nighttime SO2 loss rate (RNITE1) in percent/hour Default: 0.2 ! RNITE1 = .2 ! Nighttime NOx loss rate (RNITE2) in percent/hour Default: 2.0 ! RNITE2 = 2.0 ! Nighttime HNO3 formation rate (RNITE3) in percent/hour Default: 2.0 ! RNITE3 = 2.0 ! H2O2 data input option (MH2O2) Default: 1 ! MH2O2 = 0 ! (Used only if MAQCHEM = 1) 0 = use a monthly background H2O2 value 1 = read hourly H2O2 concentrations from the H2O2.DAT data file Monthly H2O2 concentrations (Used only if MQACHEM = 1 and MH2O2 = 0 or MH2O2 = 1 and all hourly H2O2 data missing) (BCKH2O2) in ppb Default: 12*1.  ! BCKH2O2 = 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00 ! --- Data for SECONDARY ORGANIC AEROSOL (SOA) Option (used only if MCHEM = 4) The SOA module uses monthly values of: Fine particulate concentration in ug/m^3 (BCKPMF) Organic fraction of fine particulate (OFRAC) VOC / NOX ratio (after reaction) (VCNX) to characterize the air mass when computing the formation of SOA from VOC emissions. Typical values for several distinct air mass types are: Month 1 2 3 4 5 6 7 8 9 10 11 12 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Clean Continental BCKPMF 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. OFRAC .15 .15 .20 .20 .20 .20 .20 .20 .20 .20 .20 .15 VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. Clean Marine (surface) BCKPMF .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 .5 OFRAC .25 .25 .30 .30 .30 .30 .30 .30 .30 .30 .30 .25 VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.

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 Urban - low biogenic (controls present) BCKPMF 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. 30. OFRAC .20 .20 .25 .25 .25 .25 .25 .25 .20 .20 .20 .20 VCNX 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. 4. Urban - high biogenic (controls present) BCKPMF 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. 60. OFRAC .25 .25 .30 .30 .30 .55 .55 .55 .35 .35 .35 .25 VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. Regional Plume BCKPMF 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. OFRAC .20 .20 .25 .35 .25 .40 .40 .40 .30 .30 .30 .20 VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. Urban - no controls present BCKPMF 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. OFRAC .30 .30 .35 .35 .35 .55 .55 .55 .35 .35 .35 .30 VCNX 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. 2. Default: Clean Continental ! BCKPMF = 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00, 1.00 ! ! OFRAC = 0.15, 0.15, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.20, 0.15 ! ! VCNX = 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.00, 50.0!END!-------------------------------------------------------------------------------INPUT GROUP: 12 -- Misc. Dispersion and Computational Parameters--------------- Horizontal size of puff (m) beyond which time-dependent dispersion equations (Heffter) are used to determine sigma-y and sigma-z (SYTDEP) Default: 550. ! SYTDEP = 5.5E02 ! Switch for using Heffter equation for sigma z  as above (0 = Not use Heffter; 1 = use Heffter (MHFTSZ) Default: 0 ! MHFTSZ = 0 ! Stability class used to determine plume growth rates for puffs above the boundary layer (JSUP) Default: 5 ! JSUP = 5 !

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 Vertical dispersion constant for stable conditions (k1 in Eqn. 2.7-3) (CONK1) Default: 0.01 ! CONK1 = .01 ! Vertical dispersion constant for neutral/ unstable conditions (k2 in Eqn. 2.7-4) (CONK2) Default: 0.1 ! CONK2 = .1 ! Factor for determining Transition-point from Schulman-Scire to Huber-Snyder Building Downwash scheme (SS used for Hs < Hb + TBD * HL) (TBD) Default: 0.5 ! TBD = .5 ! TBD < 0 ==> always use Huber-Snyder TBD = 1.5 ==> always use Schulman-Scire TBD = 0.5 ==> ISC Transition-point Range of land use categories for which urban dispersion is assumed (IURB1, IURB2) Default: 10 ! IURB1 = 10 ! 19 ! IURB2 = 19 ! Site characterization parameters for single-point Met data files --------- (needed for METFM = 2,3,4) Land use category for modeling domain (ILANDUIN) Default: 20 ! ILANDUIN = 20 ! Roughness length (m) for modeling domain (Z0IN) Default: 0.25 ! Z0IN = .25 ! Leaf area index for modeling domain (XLAIIN) Default: 3.0 ! XLAIIN = 3.0 ! Elevation above sea level (m) (ELEVIN) Default: 0.0 ! ELEVIN = .0 ! Latitude (degrees) for met location (XLATIN) Default: -999. ! XLATIN = -999.0 ! Longitude (degrees) for met location (XLONIN) Default: -999. ! XLONIN = -999.0 ! Specialized information for interpreting single-point Met data files ----- Anemometer height (m) (Used only if METFM = 2,3) (ANEMHT) Default: 10. ! ANEMHT = 10.0 ! Form of lateral turbulance data in PROFILE.DAT file (Used only if METFM = 4 or MTURBVW = 1 or 3)

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 (ISIGMAV) Default: 1 ! ISIGMAV = 1 ! 0 = read sigma-theta 1 = read sigma-v Choice of mixing heights (Used only if METFM = 4) (IMIXCTDM) Default: 0 ! IMIXCTDM = 0 ! 0 = read PREDICTED mixing heights 1 = read OBSERVED mixing heights Maximum length of a slug (met. grid units) (XMXLEN) Default: 1.0 ! XMXLEN = 1.0 ! Maximum travel distance of a puff/slug (in grid units) during one sampling step (XSAMLEN) Default: 1.0 ! XSAMLEN = 10 ! Maximum Number of slugs/puffs release from one source during one time step  (MXNEW) Default: 99 ! MXNEW = 60 ! Maximum Number of sampling steps for  one puff/slug during one time step  (MXSAM) Default: 99 ! MXSAM = 60 ! Number of iterations used when computing the transport wind for a sampling step that includes gradual rise (for CALMET and PROFILE winds) (NCOUNT) Default: 2 ! NCOUNT = 2 ! Minimum sigma y for a new puff/slug (m)  (SYMIN) Default: 1.0 ! SYMIN = 1.0 ! Minimum sigma z for a new puff/slug (m)  (SZMIN) Default: 1.0 ! SZMIN = 1.0 ! Default minimum turbulence velocities sigma-v and sigma-w for each stability class (m/s) (SVMIN(6) and SWMIN(6)) Default SVMIN : .50, .50, .50, .50, .50, .50 Default SWMIN : .20, .12, .08, .06, .03, .016 Stability Class : A B C D E F --- --- --- --- --- --- ! SVMIN = 0.500, 0.500, 0.500, 0.500, 0.500, 0.500! ! SWMIN = 0.200, 0.120, 0.080, 0.060, 0.030, 0.016! Divergence criterion for dw/dz across puff

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 used to initiate adjustment for horizontal convergence (1/s) Partial adjustment starts at CDIV(1), and full adjustment is reached at CDIV(2) (CDIV(2)) Default: 0.0,0.0 ! CDIV = 0.01, 0.01 ! Minimum wind speed (m/s) allowed for non-calm conditions. Also used as minimum speed returned when using power-law  extrapolation toward surface (WSCALM) Default: 0.5 ! WSCALM = .5 ! Maximum mixing height (m)  (XMAXZI) Default: 3000. ! XMAXZI = 3000.0 ! Minimum mixing height (m)  (XMINZI) Default: 50. ! XMINZI = 20.0 ! Default wind speed classes -- 5 upper bounds (m/s) are entered; the 6th class has no upper limit (WSCAT(5)) Default :  ISC RURAL : 1.54, 3.09, 5.14, 8.23, 10.8 (10.8+) Wind Speed Class : 1 2 3 4 5  --- --- --- --- ---  ! WSCAT = 1.54, 3.09, 5.14, 8.23, 10.80 ! Default wind speed profile power-law exponents for stabilities 1-6 (PLX0(6)) Default : ISC RURAL values ISC RURAL : .07, .07, .10, .15, .35, .55 ISC URBAN : .15, .15, .20, .25, .30, .30 Stability Class : A B C D E F --- --- --- --- --- --- ! PLX0 = 0.07, 0.07, 0.10, 0.15, 0.35, 0.55 ! Default potential temperature gradient for stable classes E, F (degK/m) (PTG0(2)) Default: 0.020, 0.035 ! PTG0 = 0.020, 0.035 ! Default plume path coefficients for each stability class (used when option for partial plume height terrain adjustment is selected -- MCTADJ=3) (PPC(6)) Stability Class : A B C D E F

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 Default PPC : .50, .50, .50, .50, .35, .35 --- --- --- --- --- --- ! PPC = 0.50, 0.50, 0.50, 0.50, 0.35, 0.35 ! Slug-to-puff transition criterion factor equal to sigma-y/length of slug (SL2PF) Default: 10. ! SL2PF = 10.0 ! Puff-splitting control variables ------------------------ VERTICAL SPLIT -------------- Number of puffs that result every time a puff is split - nsplit=2 means that 1 puff splits into 2 (NSPLIT) Default: 3 ! NSPLIT = 3 ! Time(s) of a day when split puffs are eligible to be split once again; this is typically set once per day, around sunset before nocturnal shear develops. 24 values: 0 is midnight (00:00) and 23 is 11 PM (23:00) 0=do not re-split 1=eligible for re-split (IRESPLIT(24)) Default: Hour 17 = 1 ! IRESPLIT = 0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,0,1,0,0,0,0,0,0,0 ! Split is allowed only if last hour's mixing height (m) exceeds a minimum value (ZISPLIT) Default: 100. ! ZISPLIT = 100.0 ! Split is allowed only if ratio of last hour's mixing ht to the maximum mixing ht experienced by the puff is less than a maximum value (this postpones a split until a nocturnal layer develops) (ROLDMAX) Default: 0.25 ! ROLDMAX = 0.25 ! HORIZONTAL SPLIT ---------------- Number of puffs that result every time a puff is split - nsplith=5 means that 1 puff splits into 5 (NSPLITH) Default: 5 ! NSPLITH = 5 ! Minimum sigma-y (Grid Cells Units) of puff before it may be split (SYSPLITH) Default: 1.0 ! SYSPLITH = 1.0 !

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 Minimum puff elongation rate (SYSPLITH/hr) due to wind shear, before it may be split (SHSPLITH) Default: 2. ! SHSPLITH = 2.0 ! Minimum concentration (g/m^3) of each species in puff before it may be split Enter array of NSPEC values; if a single value is entered, it will be used for ALL species (CNSPLITH) Default: 1.0E-07 ! CNSPLITH = 1.0E-07 ! Integration control variables ------------------------ Fractional convergence criterion for numerical SLUG sampling integration (EPSSLUG) Default: 1.0e-04 ! EPSSLUG = 1.0E-04 ! Fractional convergence criterion for numerical AREA source integration (EPSAREA) Default: 1.0e-06 ! EPSAREA = 1.0E-06 ! Trajectory step-length (m) used for numerical rise integration (DSRISE) Default: 1.0 ! DSRISE = 1.0 ! Boundary Condition (BC) Puff control variables ------------------------ Minimum height (m) to which BC puffs are mixed as they are emitted (MBCON=2 ONLY). Actual height is reset to the current mixing height at the release point if greater than this minimum. (HTMINBC) Default: 500. ! HTMINBC = 500.0 ! Search radius (in BC segment lengths) about a receptor for sampling nearest BC puff. BC puffs are emitted with a spacing of one segment length, so the search radius should be greater than 1. (RSAMPBC) Default: 4. ! RSAMPBC = 10.0 ! Near-Surface depletion adjustment to concentration profile used when sampling BC puffs? (MDEPBC) Default: 1 ! MDEPBC = 1 ! 0 = Concentration is NOT adjusted for depletion 1 = Adjust Concentration for depletion!END!-------------------------------------------------------------------------------

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INPUT GROUPS: 13a, 13b, 13c, 13d -- Point source parameters-----------------------------------------------Subgroup (13a)--------------- Number of point sources with parameters provided below (NPT1) No default ! NPT1 = 2 ! Units used for point source emissions below (IPTU) Default: 1 ! IPTU = 3 ! 1 = g/s 2 = kg/hr 3 = lb/hr 4 = tons/yr 5 = Odour Unit * m**3/s (vol. flux of odour compound) 6 = Odour Unit * m**3/min 7 = metric tons/yr Number of source-species combinations with variable emissions scaling factors provided below in (13d) (NSPT1) Default: 0 ! NSPT1 = 0 ! Number of point sources with variable emission parameters provided in external file (NPT2) No default ! NPT2 = 0 ! (If NPT2 > 0, these point source emissions are read from the file: PTEMARB.DAT)!END!---------------Subgroup (13b)--------------- a POINT SOURCE: CONSTANT DATA ----------------------------- b c Source X Y Stack Base Stack Exit Exit Bldg. Emission No. Coordinate Coordinate Height Elevation Diameter Vel. Temp. Dwash Rates (km) (km) (m) (m) (m) (m/s) (deg. K)  ------ ---------- ---------- ------ ------ -------- ----- -------- ----- -------- 1 ! SRCNAM = SO1 ! Sooner Unit 1

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 1 ! X = -4.646, -392.196, 152.44, 326, 6.10, 34.12, 430.78, 0, 0,0,3075,0,0,0,0,0,0,0! 1 ! FMFAC = 1 ! 1 ! END ! 2 ! SRCNAM = SO2 ! Sooner Unit 2 2 ! X = -4.721, -392.165, 152.44, 326, 6.10, 34.12, 430.78, 0, 0,0,2988,0,0,0,0,0,0,0! 2 ! FMFAC = 1 ! 2 ! END !-------- a Data for each source are treated as a separate input subgroup and therefore must end with an input group terminator. SRCNAM is a 12-character name for a source (No default) X is an array holding the source data listed by the column headings (No default) SIGYZI is an array holding the initial sigma-y and sigma-z (m) (Default: 0.,0.) FMFAC is a vertical momentum flux factor (0. or 1.0) used to represent the effect of rain-caps or other physical configurations that reduce momentum rise associated with the actual exit velocity. (Default: 1.0 -- full momentum used) b 0. = No building downwash modeled, 1. = downwash modeled NOTE: must be entered as a REAL number (i.e., with decimal point) c An emission rate must be entered for every pollutant modeled. Enter emission rate of zero for secondary pollutants that are modeled, but not emitted. Units are specified by IPTU (e.g. 1 for g/s).---------------Subgroup (13c)--------------- BUILDING DIMENSION DATA FOR SOURCES SUBJECT TO DOWNWASH -------------------------------------------------------Source a No. Effective building height, width, length and X/Y offset (in meters) every 10 degrees. LENGTH, XBADJ, and YBADJ are only needed for MBDW=2 (PRIME downwash option)------ --------------------------------------------------------------------

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-------- a Building height, width, length, and X/Y offset from the source are treated as a separate input subgroup for each source and therefore must end with an input group terminator. The X/Y offset is the position, relative to the stack, of the center of the upwind face of the projected building, with the x-axis pointing along the flow direction.---------------Subgroup (13d)--------------- a POINT SOURCE: VARIABLE EMISSIONS DATA --------------------------------------- Use this subgroup to describe temporal variations in the emission rates given in 13b. Factors entered multiply the rates in 13b. Skip sources here that have constant emissions. For more elaborate variation in source parameters, use PTEMARB.DAT and NPT2 > 0. IVARY determines the type of variation, and is source-specific: (IVARY) Default: 0 0 = Constant 1 = Diurnal cycle (24 scaling factors: hours 1-24) 2 = Monthly cycle (12 scaling factors: months 1-12) 3 = Hour & Season (4 groups of 24 hourly scaling factors, where first group is DEC-JAN-FEB) 4 = Speed & Stab. (6 groups of 6 scaling factors, where first group is Stability Class A, and the speed classes have upper bounds (m/s) defined in Group 12 5 = Temperature (12 scaling factors, where temperature classes have upper bounds (C) of: 0, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 50+)-------- a Data for each species are treated as a separate input subgroup and therefore must end with an input group terminator.-------------------------------------------------------------------------------

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INPUT GROUPS: 14a, 14b, 14c, 14d -- Area source parameters-----------------------------------------------Subgroup (14a)--------------- Number of polygon area sources with parameters specified below (NAR1) No default ! NAR1 = 0 ! Units used for area source emissions below (IARU) Default: 1 ! IARU = 1 ! 1 = g/m**2/s 2 = kg/m**2/hr 3 = lb/m**2/hr 4 = tons/m**2/yr 5 = Odour Unit * m/s (vol. flux/m**2 of odour compound) 6 = Odour Unit * m/min 7 = metric tons/m**2/yr Number of source-species combinations with variable emissions scaling factors provided below in (14d) (NSAR1) Default: 0 ! NSAR1 = 0 ! Number of buoyant polygon area sources with variable location and emission parameters (NAR2) No default ! NAR2 = 0 ! (If NAR2 > 0, ALL parameter data for these sources are read from the file: BAEMARB.DAT)!END!---------------Subgroup (14b)--------------- a AREA SOURCE: CONSTANT DATA ---------------------------- bSource Effect. Base Initial Emission No. Height Elevation Sigma z Rates (m) (m) (m) ------- ------ ------ -------- -----------------

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 a Data for each source are treated as a separate input subgroup and therefore must end with an input group terminator. b An emission rate must be entered for every pollutant modeled. Enter emission rate of zero for secondary pollutants that are modeled, but not emitted. Units are specified by IARU  (e.g. 1 for g/m**2/s).---------------Subgroup (14c)--------------- COORDINATES (km) FOR EACH VERTEX(4) OF EACH POLYGON --------------------------------------------------------Source a No. Ordered list of X followed by list of Y, grouped by source------ -------------------------------------------------------------------- a Data for each source are treated as a separate input subgroup and therefore must end with an input group terminator.---------------Subgroup (14d)--------------- a AREA SOURCE: VARIABLE EMISSIONS DATA -------------------------------------- Use this subgroup to describe temporal variations in the emission rates given in 14b. Factors entered multiply the rates in 14b. Skip sources here that have constant emissions. For more elaborate variation in source parameters, use BAEMARB.DAT and NAR2 > 0. IVARY determines the type of variation, and is source-specific: (IVARY) Default: 0 0 = Constant 1 = Diurnal cycle (24 scaling factors: hours 1-24) 2 = Monthly cycle (12 scaling factors: months 1-12) 3 = Hour & Season (4 groups of 24 hourly scaling factors, where first group is DEC-JAN-FEB) 4 = Speed & Stab. (6 groups of 6 scaling factors, where first group is Stability Class A, and the speed classes have upper

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 bounds (m/s) defined in Group 12 5 = Temperature (12 scaling factors, where temperature classes have upper bounds (C) of: 0, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 50+)-------- a Data for each species are treated as a separate input subgroup and therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUPS: 15a, 15b, 15c -- Line source parameters------------------------------------------Subgroup (15a)--------------- Number of buoyant line sources with variable location and emission parameters (NLN2) No default ! NLN2 = 0 ! (If NLN2 > 0, ALL parameter data for these sources are read from the file: LNEMARB.DAT) Number of buoyant line sources (NLINES) No default ! NLINES = 0 ! Units used for line source emissions below (ILNU) Default: 1 ! ILNU = 3 ! 1 = g/s 2 = kg/hr 3 = lb/hr 4 = tons/yr 5 = Odour Unit * m**3/s (vol. flux of odour compound) 6 = Odour Unit * m**3/min 7 = metric tons/yr Number of source-species combinations with variable emissions scaling factors provided below in (15c) (NSLN1) Default: 0 ! NSLN1 = 0 ! Maximum number of segments used to model

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 each line (MXNSEG) Default: 7 ! MXNSEG = 7 ! The following variables are required only if NLINES > 0. They are used in the buoyant line source plume rise calculations. Number of distances at which Default: 6 ! NLRISE = 6 ! transitional rise is computed Average building length (XL) No default ! XL = .0 ! (in meters) Average building height (HBL) No default ! HBL = .0 ! (in meters) Average building width (WBL) No default ! WBL = .0 ! (in meters) Average line source width (WML) No default ! WML = .0 ! (in meters) Average separation between buildings (DXL) No default ! DXL = .0 ! (in meters) Average buoyancy parameter (FPRIMEL) No default ! FPRIMEL = .0 ! (in m**4/s**3)!END!---------------Subgroup (15b)--------------- BUOYANT LINE SOURCE: CONSTANT DATA ---------------------------------- aSource Beg. X Beg. Y End. X End. Y Release Base Emission No. Coordinate Coordinate Coordinate Coordinate Height Elevation Rates (km) (km) (km) (km) (m) (m) ------ ---------- ---------- --------- ---------- ------- --------- ----------------- a Data for each source are treated as a separate input subgroup and therefore must end with an input group terminator. b An emission rate must be entered for every pollutant modeled.

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 Enter emission rate of zero for secondary pollutants that are modeled, but not emitted. Units are specified by ILNTU  (e.g. 1 for g/s).---------------Subgroup (15c)--------------- a BUOYANT LINE SOURCE: VARIABLE EMISSIONS DATA ---------------------------------------------- Use this subgroup to describe temporal variations in the emission rates given in 15b. Factors entered multiply the rates in 15b. Skip sources here that have constant emissions. IVARY determines the type of variation, and is source-specific: (IVARY) Default: 0 0 = Constant 1 = Diurnal cycle (24 scaling factors: hours 1-24) 2 = Monthly cycle (12 scaling factors: months 1-12) 3 = Hour & Season (4 groups of 24 hourly scaling factors, where first group is DEC-JAN-FEB) 4 = Speed & Stab. (6 groups of 6 scaling factors, where first group is Stability Class A, and the speed classes have upper bounds (m/s) defined in Group 12 5 = Temperature (12 scaling factors, where temperature classes have upper bounds (C) of: 0, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 50+)-------- a Data for each species are treated as a separate input subgroup and therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUPS: 16a, 16b, 16c -- Volume source parameters------------------------------------------Subgroup (16a)---------------

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 Number of volume sources with parameters provided in 16b,c (NVL1) No default ! NVL1 = 0 ! Units used for volume source emissions below in 16b (IVLU) Default: 1 ! IVLU = 3 ! 1 = g/s 2 = kg/hr 3 = lb/hr 4 = tons/yr 5 = Odour Unit * m**3/s (vol. flux of odour compound) 6 = Odour Unit * m**3/min 7 = metric tons/yr Number of source-species combinations with variable emissions scaling factors provided below in (16c) (NSVL1) Default: 0 ! NSVL1 = 0 ! Number of volume sources with variable location and emission parameters (NVL2) No default ! NVL2 = 0 ! (If NVL2 > 0, ALL parameter data for these sources are read from the VOLEMARB.DAT file(s) )!END!---------------Subgroup (16b)--------------- a VOLUME SOURCE: CONSTANT DATA ------------------------------ b X Y Effect. Base Initial Initial Emission Coordinate Coordinate Height Elevation Sigma y Sigma z Rates (km) (km) (m) (m) (m) (m)  ---------- ---------- ------ ------ -------- -------- ---------------- a Data for each source are treated as a separate input subgroup and therefore must end with an input group terminator. b An emission rate must be entered for every pollutant modeled.

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 Enter emission rate of zero for secondary pollutants that are modeled, but not emitted. Units are specified by IVLU  (e.g. 1 for g/s).---------------Subgroup (16c)--------------- a VOLUME SOURCE: VARIABLE EMISSIONS DATA ---------------------------------------- Use this subgroup to describe temporal variations in the emission rates given in 16b. Factors entered multiply the rates in 16b. Skip sources here that have constant emissions. For more elaborate variation in source parameters, use VOLEMARB.DAT and NVL2 > 0. IVARY determines the type of variation, and is source-specific: (IVARY) Default: 0 0 = Constant 1 = Diurnal cycle (24 scaling factors: hours 1-24) 2 = Monthly cycle (12 scaling factors: months 1-12) 3 = Hour & Season (4 groups of 24 hourly scaling factors, where first group is DEC-JAN-FEB) 4 = Speed & Stab. (6 groups of 6 scaling factors, where first group is Stability Class A, and the speed classes have upper bounds (m/s) defined in Group 12 5 = Temperature (12 scaling factors, where temperature classes have upper bounds (C) of: 0, 5, 10, 15, 20, 25, 30, 35, 40, 45, 50, 50+)-------- a Data for each species are treated as a separate input subgroup and therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUPS: 17a & 17b -- Non-gridded (discrete) receptor information--------------------------------------Subgroup (17a)---------------

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 Number of non-gridded receptors (NREC) No default ! NREC = 291 !!END!---------------Subgroup (17b)--------------- a NON-GRIDDED (DISCRETE) RECEPTOR DATA ------------------------------------ X Y Ground Height bReceptor Coordinate Coordinate Elevation Above Ground No. (km) (km) (m) (m)-------- ---------- ---------- --------- ------------ 1 ! X = 359.836, -362.005, 274, 0 ! !END! HG1 2 ! X = 360.575, -361.972, 299, 0 ! !END! HG2 3 ! X = 361.314, -361.939, 328, 0 ! !END! HG3 4 ! X = 362.053, -361.906, 365, 0 ! !END! HG4 5 ! X = 358.316, -361.150, 250, 0 ! !END! HG5 6 ! X = 359.055, -361.117, 278, 0 ! !END! HG6 7 ! X = 359.794, -361.084, 335, 0 ! !END! HG7 8 ! X = 360.533, -361.051, 307, 0 ! !END! HG8 9 ! X = 361.272, -361.018, 345, 0 ! !END! HG9 10 ! X = 357.537, -360.261, 261, 0 ! !END! HG10 11 ! X = 358.275, -360.228, 271, 0 ! !END! HG11 12 ! X = 359.014, -360.195, 274, 0 ! !END! HG12 13 ! X = 359.753, -360.162, 331, 0 ! !END! HG13 14 ! X = 360.492, -360.129, 327, 0 ! !END! HG14 15 ! X = 361.231, -360.096, 304, 0 ! !END! HG15 16 ! X = 361.970, -360.063, 335, 0 ! !END! HG16 17 ! X = 362.709, -360.030, 312, 0 ! !END! HG17 18 ! X = 363.448, -359.997, 340, 0 ! !END! HG18 19 ! X = 364.187, -359.963, 361, 0 ! !END! HG19 20 ! X = 364.926, -359.930, 382, 0 ! !END! HG20 21 ! X = 357.496, -359.340, 274, 0 ! !END! HG21 22 ! X = 358.235, -359.307, 274, 0 ! !END! HG22 23 ! X = 358.973, -359.274, 335, 0 ! !END! HG23 24 ! X = 359.712, -359.241, 294, 0 ! !END! HG24 25 ! X = 360.451, -359.208, 304, 0 ! !END! HG25 26 ! X = 361.190, -359.175, 279, 0 ! !END! HG26 27 ! X = 361.929, -359.142, 304, 0 ! !END! HG27 28 ! X = 362.668, -359.109, 318, 0 ! !END! HG28 29 ! X = 363.406, -359.075, 335, 0 ! !END! HG29 30 ! X = 364.145, -359.042, 347, 0 ! !END! HG30 31 ! X = 364.884, -359.008, 340, 0 ! !END! HG31 32 ! X = 358.932, -358.353, 247, 0 ! !END! HG32

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 33 ! X = 359.671, -358.320, 271, 0 ! !END! HG33 34 ! X = 360.410, -358.287, 275, 0 ! !END! HG34 35 ! X = 361.149, -358.254, 274, 0 ! !END! HG35 36 ! X = 361.887, -358.220, 277, 0 ! !END! HG36 37 ! X = 362.626, -358.187, 304, 0 ! !END! HG37 38 ! X = 363.365, -358.154, 330, 0 ! !END! HG38 39 ! X = 364.104, -358.121, 357, 0 ! !END! HG39 40 ! X = 364.842, -358.087, 384, 0 ! !END! HG40 41 ! X = 365.581, -358.054, 372, 0 ! !END! HG41 42 ! X = 356.675, -357.530, 274, 0 ! !END! HG42 43 ! X = 357.414, -357.497, 293, 0 ! !END! HG43 44 ! X = 358.153, -357.464, 272, 0 ! !END! HG44 45 ! X = 358.891, -357.431, 271, 0 ! !END! HG45 46 ! X = 359.630, -357.398, 274, 0 ! !END! HG46 47 ! X = 360.369, -357.365, 327, 0 ! !END! HG47 48 ! X = 361.107, -357.332, 316, 0 ! !END! HG48 49 ! X = 361.846, -357.299, 304, 0 ! !END! HG49 50 ! X = 362.585, -357.266, 354, 0 ! !END! HG50 51 ! X = 363.323, -357.233, 346, 0 ! !END! HG51 52 ! X = 364.062, -357.199, 335, 0 ! !END! HG52 53 ! X = 364.801, -357.166, 344, 0 ! !END! HG53 54 ! X = 365.539, -357.132, 364, 0 ! !END! HG54 55 ! X = 357.373, -356.576, 243, 0 ! !END! HG55 56 ! X = 358.112, -356.543, 335, 0 ! !END! HG56 57 ! X = 358.850, -356.510, 324, 0 ! !END! HG57 58 ! X = 359.589, -356.477, 335, 0 ! !END! HG58 59 ! X = 360.327, -356.444, 341, 0 ! !END! HG59 60 ! X = 361.066, -356.411, 333, 0 ! !END! HG60 61 ! X = 361.805, -356.378, 306, 0 ! !END! HG61 62 ! X = 362.543, -356.345, 304, 0 ! !END! HG62 63 ! X = 363.282, -356.311, 365, 0 ! !END! HG63 64 ! X = 364.020, -356.278, 304, 0 ! !END! HG64 65 ! X = 364.759, -356.245, 309, 0 ! !END! HG65 66 ! X = 365.497, -356.211, 307, 0 ! !END! HG66 67 ! X = 357.332, -355.654, 270, 0 ! !END! HG67 68 ! X = 358.071, -355.622, 274, 0 ! !END! HG68 69 ! X = 358.809, -355.589, 301, 0 ! !END! HG69 70 ! X = 359.548, -355.556, 274, 0 ! !END! HG70 71 ! X = 360.286, -355.523, 274, 0 ! !END! HG71 72 ! X = 361.025, -355.490, 312, 0 ! !END! HG72 73 ! X = 361.763, -355.457, 274, 0 ! !END! HG73 74 ! X = 362.502, -355.423, 322, 0 ! !END! HG74 75 ! X = 363.240, -355.390, 304, 0 ! !END! HG75 76 ! X = 363.979, -355.357, 275, 0 ! !END! HG76 77 ! X = 364.717, -355.323, 304, 0 ! !END! HG77 78 ! X = 365.456, -355.290, 290, 0 ! !END! HG78 79 ! X = 362.460, -354.502, 249, 0 ! !END! HG79 80 ! X = 363.199, -354.469, 274, 0 ! !END! HG80

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 81 ! X = -159.867, -584.484, 454, 0 ! !END! WM1 82 ! X = -159.108, -584.499, 486, 0 ! !END! WM2 83 ! X = -158.348, -584.513, 487, 0 ! !END! WM3 84 ! X = -157.589, -584.528, 478, 0 ! !END! WM4 85 ! X = -156.829, -584.542, 518, 0 ! !END! WM5 86 ! X = -156.070, -584.557, 518, 0 ! !END! WM6 87 ! X = -161.368, -583.531, 510, 0 ! !END! WM7 88 ! X = -160.609, -583.546, 493, 0 ! !END! WM8 89 ! X = -159.849, -583.560, 488, 0 ! !END! WM9 90 ! X = -159.090, -583.575, 615, 0 ! !END! WM10 91 ! X = -158.331, -583.589, 522, 0 ! !END! WM11 92 ! X = -157.571, -583.604, 494, 0 ! !END! WM12 93 ! X = -156.812, -583.618, 609, 0 ! !END! WM13 94 ! X = -156.052, -583.633, 518, 0 ! !END! WM14 95 ! X = -162.110, -582.592, 487, 0 ! !END! WM15 96 ! X = -161.350, -582.607, 518, 0 ! !END! WM16 97 ! X = -160.591, -582.622, 609, 0 ! !END! WM17 98 ! X = -159.832, -582.636, 554, 0 ! !END! WM18 99 ! X = -159.072, -582.651, 578, 0 ! !END! WM19 100 ! X = -158.313, -582.666, 557, 0 ! !END! WM20 101 ! X = -157.554, -582.680, 571, 0 ! !END! WM21 102 ! X = -156.794, -582.694, 670, 0 ! !END! WM22 103 ! X = -156.035, -582.709, 518, 0 ! !END! WM23 104 ! X = -160.573, -581.698, 518, 0 ! !END! WM24 105 ! X = -159.814, -581.712, 548, 0 ! !END! WM25 106 ! X = -159.054, -581.727, 548, 0 ! !END! WM26 107 ! X = -158.295, -581.742, 518, 0 ! !END! WM27 108 ! X = -160.555, -580.774, 517, 0 ! !END! WM28 109 ! X = -159.796, -580.789, 579, 0 ! !END! WM29 110 ! X = -159.037, -580.803, 613, 0 ! !END! WM30 111 ! X = -158.278, -580.818, 548, 0 ! !END! WM31 112 ! X = -157.518, -580.832, 523, 0 ! !END! WM32 113 ! X = -161.296, -579.835, 542, 0 ! !END! WM33 114 ! X = -160.537, -579.850, 545, 0 ! !END! WM34 115 ! X = -159.778, -579.865, 552, 0 ! !END! WM35 116 ! X = -152.895, -577.222, 579, 0 ! !END! WM36 117 ! X = -155.913, -576.242, 609, 0 ! !END! WM37 118 ! X = -155.154, -576.256, 654, 0 ! !END! WM38 119 ! X = -154.396, -576.270, 621, 0 ! !END! WM39 120 ! X = -153.637, -576.284, 629, 0 ! !END! WM40 121 ! X = -152.878, -576.298, 579, 0 ! !END! WM41 122 ! X = -152.119, -576.312, 560, 0 ! !END! WM42 123 ! X = -156.654, -575.304, 615, 0 ! !END! WM43 124 ! X = -155.896, -575.318, 641, 0 ! !END! WM44 125 ! X = -155.137, -575.332, 640, 0 ! !END! WM45 126 ! X = -154.378, -575.346, 662, 0 ! !END! WM46 127 ! X = -153.620, -575.361, 618, 0 ! !END! WM47 128 ! X = -152.861, -575.375, 630, 0 ! !END! WM48

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 129 ! X = -152.102, -575.389, 534, 0 ! !END! WM49 130 ! X = -156.637, -574.380, 606, 0 ! !END! WM50 131 ! X = -155.878, -574.394, 566, 0 ! !END! WM51 132 ! X = -155.120, -574.408, 633, 0 ! !END! WM52 133 ! X = -154.361, -574.423, 670, 0 ! !END! WM53 134 ! X = -153.603, -574.437, 609, 0 ! !END! WM54 135 ! X = -152.844, -574.451, 579, 0 ! !END! WM55 136 ! X = -152.085, -574.465, 535, 0 ! !END! WM56 137 ! X = -155.102, -573.485, 548, 0 ! !END! WM57 138 ! X = -154.344, -573.499, 518, 0 ! !END! WM58 139 ! X = -153.585, -573.513, 506, 0 ! !END! WM59 140 ! X = 318.344, -456.077, 555, 0 ! !END! UB1 141 ! X = 319.091, -456.047, 589, 0 ! !END! UB2 142 ! X = 321.334, -455.959, 563, 0 ! !END! UB3 143 ! X = 318.308, -455.154, 549, 0 ! !END! UB4 144 ! X = 319.055, -455.125, 487, 0 ! !END! UB5 145 ! X = 319.803, -455.096, 487, 0 ! !END! UB6 146 ! X = 320.551, -455.067, 490, 0 ! !END! UB7 147 ! X = 318.272, -454.232, 650, 0 ! !END! UB8 148 ! X = 319.019, -454.203, 563, 0 ! !END! UB9 149 ! X = 319.767, -454.174, 540, 0 ! !END! UB10 150 ! X = 320.514, -454.144, 502, 0 ! !END! UB11 151 ! X = 321.262, -454.115, 526, 0 ! !END! UB12 152 ! X = 322.757, -454.056, 534, 0 ! !END! UB13 153 ! X = 323.504, -454.026, 563, 0 ! !END! UB14 154 ! X = 318.236, -453.310, 548, 0 ! !END! UB15 155 ! X = 318.983, -453.281, 628, 0 ! !END! UB16 156 ! X = 319.731, -453.252, 623, 0 ! !END! UB17 157 ! X = 320.478, -453.222, 579, 0 ! !END! UB18 158 ! X = 321.225, -453.193, 469, 0 ! !END! UB19 159 ! X = 321.973, -453.163, 457, 0 ! !END! UB20 160 ! X = 322.720, -453.134, 573, 0 ! !END! UB21 161 ! X = 323.468, -453.104, 605, 0 ! !END! UB22 162 ! X = 324.215, -453.074, 588, 0 ! !END! UB23 163 ! X = 318.200, -452.388, 608, 0 ! !END! UB24 164 ! X = 318.947, -452.359, 660, 0 ! !END! UB25 165 ! X = 319.694, -452.329, 598, 0 ! !END! UB26 166 ! X = 320.442, -452.300, 599, 0 ! !END! UB27 167 ! X = 321.189, -452.271, 639, 0 ! !END! UB28 168 ! X = 321.937, -452.241, 457, 0 ! !END! UB29 169 ! X = 322.684, -452.212, 568, 0 ! !END! UB30 170 ! X = 318.164, -451.466, 730, 0 ! !END! UB31 171 ! X = 318.911, -451.437, 681, 0 ! !END! UB32 172 ! X = 319.658, -451.407, 640, 0 ! !END! UB33 173 ! X = 320.406, -451.378, 625, 0 ! !END! UB34 174 ! X = 321.153, -451.348, 426, 0 ! !END! UB35 175 ! X = 321.900, -451.319, 555, 0 ! !END! UB36 176 ! X = 322.647, -451.289, 612, 0 ! !END! UB37

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 177 ! X = 317.380, -450.573, 667, 0 ! !END! UB38 178 ! X = 318.128, -450.544, 580, 0 ! !END! UB39 179 ! X = 318.875, -450.514, 656, 0 ! !END! UB40 180 ! X = 319.622, -450.485, 640, 0 ! !END! UB41 181 ! X = 320.369, -450.456, 487, 0 ! !END! UB42 182 ! X = 321.116, -450.426, 457, 0 ! !END! UB43 183 ! X = 321.864, -450.397, 654, 0 ! !END! UB44 184 ! X = 322.611, -450.367, 548, 0 ! !END! UB45 185 ! X = 323.358, -450.338, 622, 0 ! !END! UB46 186 ! X = 324.105, -450.308, 683, 0 ! !END! UB47 187 ! X = 317.345, -449.651, 579, 0 ! !END! UB48 188 ! X = 318.092, -449.621, 554, 0 ! !END! UB49 189 ! X = 318.839, -449.592, 609, 0 ! !END! UB50 190 ! X = 319.586, -449.563, 622, 0 ! !END! UB51 191 ! X = 320.333, -449.534, 427, 0 ! !END! UB52 192 ! X = 321.080, -449.504, 555, 0 ! !END! UB53 193 ! X = 321.827, -449.475, 502, 0 ! !END! UB54 194 ! X = 322.574, -449.445, 639, 0 ! !END! UB55 195 ! X = 323.322, -449.416, 580, 0 ! !END! UB56 196 ! X = 324.069, -449.386, 639, 0 ! !END! UB57 197 ! X = 318.803, -448.670, 548, 0 ! !END! UB58 198 ! X = 319.550, -448.641, 548, 0 ! !END! UB59 199 ! X = 320.297, -448.612, 438, 0 ! !END! UB60 200 ! X = 321.044, -448.582, 579, 0 ! !END! UB61 201 ! X = 322.538, -448.523, 620, 0 ! !END! UB62 202 ! X = 320.261, -447.689, 579, 0 ! !END! UB63 203 ! X = 321.007, -447.660, 426, 0 ! !END! UB64 204 ! X = 321.754, -447.631, 611, 0 ! !END! UB65 205 ! X = 318.731, -446.826, 604, 0 ! !END! UB66 206 ! X = 319.477, -446.797, 548, 0 ! !END! UB67 207 ! X = 320.224, -446.767, 488, 0 ! !END! UB68 208 ! X = 320.971, -446.738, 402, 0 ! !END! UB69 209 ! X = 321.718, -446.708, 579, 0 ! !END! UB70 210 ! X = 322.465, -446.679, 573, 0 ! !END! UB71 211 ! X = 323.212, -446.649, 609, 0 ! !END! UB72 212 ! X = 269.710, -618.629, 365, 0 ! !END! CC1 213 ! X = 270.473, -618.605, 365, 0 ! !END! CC2 214 ! X = 271.235, -618.580, 368, 0 ! !END! CC3 215 ! X = 268.155, -617.755, 411, 0 ! !END! CC4 216 ! X = 268.917, -617.730, 462, 0 ! !END! CC5 217 ! X = 269.680, -617.705, 431, 0 ! !END! CC6 218 ! X = 270.443, -617.681, 518, 0 ! !END! CC7 219 ! X = 271.205, -617.656, 487, 0 ! !END! CC8 220 ! X = 271.968, -617.631, 396, 0 ! !END! CC9 221 ! X = 265.075, -616.929, 518, 0 ! !END! CC10 222 ! X = 265.838, -616.904, 523, 0 ! !END! CC11 223 ! X = 266.600, -616.880, 548, 0 ! !END! CC12 224 ! X = 267.363, -616.855, 579, 0 ! !END! CC13

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 225 ! X = 268.125, -616.831, 547, 0 ! !END! CC14 226 ! X = 268.888, -616.806, 538, 0 ! !END! CC15 227 ! X = 269.650, -616.781, 640, 0 ! !END! CC16 228 ! X = 270.412, -616.757, 608, 0 ! !END! CC17 229 ! X = 259.709, -616.173, 335, 0 ! !END! CC18 230 ! X = 260.472, -616.149, 431, 0 ! !END! CC19 231 ! X = 261.234, -616.125, 457, 0 ! !END! CC20 232 ! X = 261.996, -616.101, 414, 0 ! !END! CC21 233 ! X = 262.759, -616.077, 426, 0 ! !END! CC22 234 ! X = 263.521, -616.053, 426, 0 ! !END! CC23 235 ! X = 264.283, -616.029, 388, 0 ! !END! CC24 236 ! X = 265.046, -616.005, 388, 0 ! !END! CC25 237 ! X = 265.808, -615.980, 365, 0 ! !END! CC26 238 ! X = 266.571, -615.956, 386, 0 ! !END! CC27 239 ! X = 267.333, -615.931, 396, 0 ! !END! CC28 240 ! X = 268.095, -615.907, 426, 0 ! !END! CC29 241 ! X = 268.858, -615.882, 446, 0 ! !END! CC30 242 ! X = 269.620, -615.857, 441, 0 ! !END! CC31 243 ! X = 270.382, -615.833, 457, 0 ! !END! CC32 244 ! X = 271.145, -615.808, 465, 0 ! !END! CC33 245 ! X = 271.907, -615.783, 442, 0 ! !END! CC34 246 ! X = 272.670, -615.758, 426, 0 ! !END! CC35 247 ! X = 259.680, -615.249, 304, 0 ! !END! CC36 248 ! X = 260.443, -615.225, 304, 0 ! !END! CC37 249 ! X = 261.205, -615.201, 319, 0 ! !END! CC38 250 ! X = 261.967, -615.177, 334, 0 ! !END! CC39 251 ! X = 262.730, -615.153, 370, 0 ! !END! CC40 252 ! X = 263.492, -615.129, 405, 0 ! !END! CC41 253 ! X = 264.254, -615.105, 409, 0 ! !END! CC42 254 ! X = 265.016, -615.081, 450, 0 ! !END! CC43 255 ! X = 265.779, -615.056, 518, 0 ! !END! CC44 256 ! X = 266.541, -615.032, 609, 0 ! !END! CC45 257 ! X = 267.303, -615.007, 534, 0 ! !END! CC46 258 ! X = 268.066, -614.983, 517, 0 ! !END! CC47 259 ! X = 268.828, -614.958, 575, 0 ! !END! CC48 260 ! X = 269.590, -614.933, 600, 0 ! !END! CC49 261 ! X = 270.352, -614.909, 609, 0 ! !END! CC50 262 ! X = 271.115, -614.884, 609, 0 ! !END! CC51 263 ! X = 271.877, -614.859, 561, 0 ! !END! CC52 264 ! X = 260.414, -614.301, 335, 0 ! !END! CC53 265 ! X = 261.176, -614.277, 432, 0 ! !END! CC54 266 ! X = 261.938, -614.253, 487, 0 ! !END! CC55 267 ! X = 262.700, -614.229, 499, 0 ! !END! CC56 268 ! X = 263.463, -614.205, 514, 0 ! !END! CC57 269 ! X = 264.225, -614.181, 442, 0 ! !END! CC58 270 ! X = 264.987, -614.157, 439, 0 ! !END! CC59 271 ! X = 265.749, -614.132, 395, 0 ! !END! CC60 272 ! X = 266.511, -614.108, 400, 0 ! !END! CC61

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 273 ! X = 267.274, -614.083, 426, 0 ! !END! CC62 274 ! X = 268.036, -614.059, 487, 0 ! !END! CC63 275 ! X = 268.798, -614.034, 548, 0 ! !END! CC64 276 ! X = 269.560, -614.010, 548, 0 ! !END! CC65 277 ! X = 270.322, -613.985, 548, 0 ! !END! CC66 278 ! X = 271.085, -613.960, 535, 0 ! !END! CC67 279 ! X = 261.147, -613.353, 304, 0 ! !END! CC68 280 ! X = 261.909, -613.329, 334, 0 ! !END! CC69 281 ! X = 262.671, -613.305, 396, 0 ! !END! CC70 282 ! X = 263.433, -613.281, 457, 0 ! !END! CC71 283 ! X = 264.195, -613.257, 457, 0 ! !END! CC72 284 ! X = 264.958, -613.233, 426, 0 ! !END! CC73 285 ! X = 265.720, -613.208, 411, 0 ! !END! CC74 286 ! X = 266.482, -613.184, 406, 0 ! !END! CC75 287 ! X = 267.244, -613.159, 396, 0 ! !END! CC76 288 ! X = 268.006, -613.135, 401, 0 ! !END! CC77 289 ! X = 268.768, -613.110, 397, 0 ! !END! CC78 290 ! X = 261.118, -612.429, 322, 0 ! !END! CC79 291 ! X = 261.880, -612.405, 334, 0 ! !END! CC80------------- a Data for each receptor are treated as a separate input subgroup and therefore must end with an input group terminator. b Receptor height above ground is optional. If no value is entered, the receptor is placed on the ground.

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OG&E Trinity Consultants 

BART Modeling Report 083701.0004 

APPENDIX D – SAMPLE CALPOST CONTROL FILE
SO01_CC_vis.INP

OGE Sooner Station - BART DeterminationVisibility Impact---------------- Run title (3 lines) ------------------------------------------ CALPOST MODEL CONTROL FILE ---------------------------------------------------------------------------------------------------------INPUT GROUP: 0 -- Input and Output File Names--------------Input Files-----------File Default File Name---- -----------------Conc/Dep Flux File MODEL.DAT ! MODDAT =..\2001_SO_NOX.DAT !Relative Humidity File VISB.DAT ! VISDAT =..\2001_SO_NOX.VIS ! Background Data File BACK.DAT *BACKDAT = *Transmissometer/ VSRN.DAT *VSRDAT = *Nephelometer Data FileOutput Files------------File Default File Name---- -----------------List File CALPOST.LST ! PSTLST =SO01_CC_vis.lst !Pathname for Timeseries Files (blank) * TSPATH = *(activate with exclamation points only ifproviding NON-BLANK character string)Pathname for Plot Files (blank) * PLPATH = *(activate with exclamation points only if providing NON-BLANK character string)User Character String (U) to augment default filenames(activate with exclamation points only if providing NON-BLANK character string)Timeseries TSttUUUU.DAT * TSUNAM = *Top Nth Rank Plot RttUUUUU.DAT or RttiiUUU.GRD * TUNAM = *

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SO01_CC_vis.INP

Exceedance Plot XttUUUUU.DAT or XttUUUUU.GRD * XUNAM = *Echo Plot jjjtthhU.DAT(Specific Days) or jjjtthhU.GRD * EUNAM = *Visibility Plot V24UUUUU.DAT * VUNAM = *(Daily Peak Summary) --------------------------------------------------------------------------------All file names will be converted to lower case if LCFILES = TOtherwise, if LCFILES = F, file names will be converted to UPPER CASE T = lower case ! LCFILES = T ! F = UPPER CASENOTE: (1) file/path names can be up to 70 characters in lengthNOTE: (2) Filenames for ALL PLOT and TIMESERIES FILES are constructed using a template that includes a pathname, user-supplied  character(s), and fixed strings (tt,ii,jjj, and hh), where tt = Averaging Period (e.g. 03) ii = Rank (e.g. 02) jjj= Julian Day hh = Hour(ending) are determined internally based on selections made below. If a path or user-supplied character(s) are supplied, each must contain at least 1 non-blank character.!END!--------------------------------------------------------------------------------INPUT GROUP: 1 -- General run control parameters-------------- Option to run all periods found in the met. file(s) (METRUN) Default: 0 ! METRUN = 0 ! METRUN = 0 - Run period explicitly defined below METRUN = 1 - Run all periods in CALPUFF data file(s) Starting date: Year (ISYR) -- No default ! ISYR = 2001 ! (used only if Month (ISMO) -- No default ! ISMO = 1 ! METRUN = 0) Day (ISDY) -- No default ! ISDY = 1 ! Hour (ISHR) -- No default ! ISHR = 0 ! Number of hours to process (NHRS) -- No default ! NHRS = 8753 ! Process every hour of data?(NREP) -- Default: 1 ! NREP = 1 ! (1 = every hour processed, 2 = every 2nd hour processed,

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SO01_CC_vis.INP

 5 = every 5th hour processed, etc.)Species & Concentration/Deposition Information---------------------------------------------- Species to process (ASPEC) -- No default ! ASPEC = VISIB ! (ASPEC = VISIB for visibility processing) Layer/deposition code (ILAYER) -- Default: 1 ! ILAYER = 1 ! '1' for CALPUFF concentrations, '-1' for dry deposition fluxes, '-2' for wet deposition fluxes, '-3' for wet+dry deposition fluxes. Scaling factors of the form: -- Defaults: ! A = 0.0 ! X(new) = X(old) * A + B A = 0.0 ! B = 0.0 ! (NOT applied if A = B = 0.0) B = 0.0 Add Hourly Background Concentrations/Fluxes? (LBACK) -- Default: F ! LBACK = F !Receptor information-------------------- Gridded receptors processed? (LG) -- Default: F ! LG = F ! Discrete receptors processed? (LD) -- Default: F ! LD = T ! CTSG Complex terrain receptors processed? (LCT) -- Default: F ! LCT = F !--Report results by DISCRETE receptor RING? (only used when LD = T) (LDRING) -- Default: F ! LDRING = F !--Select range of DISCRETE receptors (only used when LD = T): Select ALL DISCRETE receptors by setting NDRECP flag to -1; OR Select SPECIFIC DISCRETE receptors by entering a flag (0,1) for each 0 = discrete receptor not processed 1 = discrete receptor processed using repeated value notation to select blocks of receptors: 416*0, 1048*1, 1482*0 Flag for all receptors after the last one assigned is set to 0 (NDRECP) -- Default: -1 ! NDRECP = 80*0, 59*0, 72*0, 80*1!--Select range of GRIDDED receptors (only used when LG = T):

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SO01_CC_vis.INP

 X index of LL corner (IBGRID) -- Default: -1 ! IBGRID = -1 ! (-1 OR 1 <= IBGRID <= NX) Y index of LL corner (JBGRID) -- Default: -1 ! JBGRID = -1 ! (-1 OR 1 <= JBGRID <= NY) X index of UR corner (IEGRID) -- Default: -1 ! IEGRID = -1 ! (-1 OR 1 <= IEGRID <= NX) Y index of UR corner (JEGRID) -- Default: -1 ! JEGRID = -1 ! (-1 OR 1 <= JEGRID <= NY) Note: Entire grid is processed if IBGRID=JBGRID=IEGRID=JEGRID=-1--Specific gridded receptors can also be excluded from CALPOST processing by filling a processing grid array with 0s and 1s. If the processing flag for receptor index (i,j) is 1 (ON), that receptor will be processed if it lies within the range delineated by IBGRID, JBGRID,IEGRID,JEGRID and if LG=T. If it is 0 (OFF), it will not be processed in the run. By default, all array values are set to 1 (ON). Number of gridded receptor rows provided in Subgroup (1a) to identify specific gridded receptors to process (NGONOFF) -- Default: 0 ! NGONOFF = 0 !!END!--------------Subgroup (1a) -- Specific gridded receptors included/excluded-------------- Specific gridded receptors are excluded from CALPOST processing by filling a processing grid array with 0s and 1s. A total of NGONOFF lines are read here. Each line corresponds to one 'row' in the sampling grid, starting with the NORTHERNMOST row that contains receptors that you wish to exclude, and finishing with row 1 to the SOUTH (no intervening rows may be skipped). Within a row, each receptor position is assigned either a 0 or 1, starting with the westernmost receptor. 0 = gridded receptor not processed 1 = gridded receptor processed Repeated value notation may be used to select blocks of receptors: 23*1, 15*0, 12*1 Because all values are initially set to 1, any receptors north of

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SO01_CC_vis.INP

 the first row entered, or east of the last value provided in a row, remain ON. (NGXRECP) -- Default: 1-------------------------------------------------------------------------------INPUT GROUP: 2 -- Visibility Parameters (ASPEC = VISIB)-------------- Maximum relative humidity (%) used in particle growth curve (RHMAX) -- Default: 98 ! RHMAX = 95.0 ! Modeled species to be included in computing the light extinction Include SULFATE? (LVSO4) -- Default: T ! LVSO4 = T ! Include NITRATE? (LVNO3) -- Default: T ! LVNO3 = T ! Include ORGANIC CARBON? (LVOC) -- Default: T ! LVOC = T ! Include COARSE PARTICLES? (LVPMC) -- Default: T ! LVPMC = T ! Include FINE PARTICLES? (LVPMF) -- Default: T ! LVPMF = T ! Include ELEMENTAL CARBON? (LVEC) -- Default: T ! LVEC = T ! And, when ranking for TOP-N, TOP-50, and Exceedance tables, Include BACKGROUND? (LVBK) -- Default: T ! LVBK = T ! Species name used for particulates in MODEL.DAT file COARSE (SPECPMC) -- Default: PMC ! SPECPMC = PMC ! FINE (SPECPMF) -- Default: PMF ! SPECPMF = PMF !Extinction Efficiency (1/Mm per ug/m**3)---------------------------------------- MODELED particulate species: PM COARSE (EEPMC) -- Default: 0.6 ! EEPMC = 0.6 ! PM FINE (EEPMF) -- Default: 1.0 ! EEPMF = 1.0 ! BACKGROUND particulate species: PM COARSE (EEPMCBK) -- Default: 0.6 ! EEPMCBK = 0.6 ! Other species: AMMONIUM SULFATE (EESO4) -- Default: 3.0 ! EESO4 = 3.0 ! AMMONIUM NITRATE (EENO3) -- Default: 3.0 ! EENO3 = 3.0 ! ORGANIC CARBON (EEOC) -- Default: 4.0 ! EEOC = 4.0 ! SOIL (EESOIL)-- Default: 1.0 ! EESOIL = 1.0 ! ELEMENTAL CARBON (EEEC) -- Default: 10. ! EEEC = 10.0 !Background Extinction Computation--------------------------------- Method used for background light extinction (MVISBK) -- Default: 2 ! MVISBK = 6 !

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SO01_CC_vis.INP

 1 = Supply single light extinction and hygroscopic fraction - IWAQM (1993) RH adjustment applied to hygroscopic background and modeled sulfate and nitrate 2 = Compute extinction from speciated PM measurements (A) - Hourly RH adjustment applied to observed and modeled sulfate and nitrate - RH factor is capped at RHMAX 3 = Compute extinction from speciated PM measurements (B) - Hourly RH adjustment applied to observed and modeled sulfate and nitrate - Receptor-hour excluded if RH>RHMAX - Receptor-day excluded if fewer than 6 valid receptor-hours 4 = Read hourly transmissometer background extinction measurements - Hourly RH adjustment applied to modeled sulfate and nitrate - Hour excluded if measurement invalid (missing, interference, or large RH) - Receptor-hour excluded if RH>RHMAX - Receptor-day excluded if fewer than 6 valid receptor-hours 5 = Read hourly nephelometer background extinction measurements - Rayleigh extinction value (BEXTRAY) added to measurement - Hourly RH adjustment applied to modeled sulfate and nitrate - Hour excluded if measurement invalid (missing, interference, or large RH) - Receptor-hour excluded if RH>RHMAX - Receptor-day excluded if fewer than 6 valid receptor-hours 6 = Compute extinction from speciated PM measurements - FLAG RH adjustment factor applied to observed and modeled sulfate and nitrate Additional inputs used for MVISBK = 1: -------------------------------------- Background light extinction (1/Mm) (BEXTBK) -- No default ! BEXTBK = 12.0 ! Percentage of particles affected by relative humidity (RHFRAC) -- No default ! RHFRAC = 10.0 ! Additional inputs used for MVISBK = 6: -------------------------------------- Extinction coefficients for hygroscopic species (modeled and background) are computed using a monthly RH adjustment factor in place of an hourly RH factor (VISB.DAT file is NOT needed). Enter the 12 monthly factors here (RHFAC). Month 1 is January. (RHFAC) -- No default ! RHFAC = 3.4,3.1,2.9,3.0,3.6,3.6,3.4,3.4,3.6,3.5,3.4,3.5! Additional inputs used for MVISBK = 2,3,6: ----------------------------------------

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SO01_CC_vis.INP

 Background extinction coefficients are computed from monthly CONCENTRATIONS of ammonium sulfate (BKSO4), ammonium nitrate (BKNO3), coarse particulates (BKPMC), organic carbon (BKOC), soil (BKSOIL), and elemental carbon (BKEC). Month 1 is January. (ug/m**3) (BKSO4) -- No default ! BKSO4 = 0.12, 0.12, 0.12, 0.12,  0.12, 0.12, 0.12, 0.12,  0.12, 0.12, 0.12, 0.12! (BKNO3) -- No default ! BKNO3 = 0.10, 0.10, 0.10, 0.10,  0.10, 0.10, 0.10, 0.10,  0.10, 0.10, 0.10, 0.10 ! (BKPMC) -- No default ! BKPMC = 3.0, 3.0, 3.0, 3.0,  3.0, 3.0, 3.0, 3.0,  3.0, 3.0, 3.0, 3.0 ! (BKOC) -- No default ! BKOC = 0.47, 0.47, 0.47, 0.47,  0.47, 0.47, 0.47, 0.47,  0.47, 0.47, 0.47, 0.47! (BKSOIL) -- No default ! BKSOIL= 0.50, 0.50, 0.50, 0.50,  0.50, 0.50, 0.50, 0.50,  0.50, 0.50, 0.50, 0.50 ! (BKEC) -- No default ! BKEC = 0.02, 0.02, 0.02, 0.02,  0.02, 0.02, 0.02, 0.02,  0.02, 0.02, 0.02, 0.02 ! Additional inputs used for MVISBK = 2,3,5,6: ------------------------------------------ Extinction due to Rayleigh scattering is added (1/Mm) (BEXTRAY) -- Default: 10.0 ! BEXTRAY = 10.0!!END!-------------------------------------------------------------------------------INPUT GROUP: 3 -- Output options--------------Documentation------------- Documentation records contained in the header of the CALPUFF output file may be written to the list file. Print documentation image? (LDOC) -- Default: F ! LDOC = F !Output Units------------ Units for All Output (IPRTU) -- Default: 1 ! IPRTU = 3 ! for for

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SO01_CC_vis.INP

 Concentration Deposition 1 = g/m**3 g/m**2/s 2 = mg/m**3 mg/m**2/s 3 = ug/m**3 ug/m**2/s 4 = ng/m**3 ng/m**2/s 5 = Odour Units Visibility: extinction expressed in 1/Mega-meters (IPRTU is ignored)Averaging time(s) reported-------------------------- 1-hr averages (L1HR) -- Default: T ! L1HR = F ! 3-hr averages (L3HR) -- Default: T ! L3HR = F ! 24-hr averages (L24HR) -- Default: T ! L24HR = T ! Run-length averages (LRUNL) -- Default: T ! LRUNL = F ! User-specified averaging time in hours - results for an averaging time of NAVG hours are reported for NAVG greater than 0: (NAVG) -- Default: 0 ! NAVG = 0 !Types of tabulations reported------------------------------ 1) Visibility: daily visibility tabulations are always reported for the selected receptors when ASPEC = VISIB. In addition, any of the other tabulations listed below may be chosen to characterize the light extinction coefficients. [List file or Plot/Analysis File] 2) Top 50 table for each averaging time selected [List file only] (LT50) -- Default: T ! LT50 = T ! 3) Top 'N' table for each averaging time selected [List file or Plot file] (LTOPN) -- Default: F ! LTOPN = F ! -- Number of 'Top-N' values at each receptor selected (NTOP must be <= 4)

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SO01_CC_vis.INP

 (NTOP) -- Default: 4 ! NTOP = 4 ! -- Specific ranks of 'Top-N' values reported (NTOP values must be entered) (ITOP(4) array) -- Default: ! ITOP = 1, 2, 3, 4 ! 1,2,3,4 4) Threshold exceedance counts for each receptor and each averaging time selected [List file or Plot file] (LEXCD) -- Default: F ! LEXCD = F ! -- Identify the threshold for each averaging time by assigning a non-negative value (output units). -- Default: -1.0 Threshold for 1-hr averages (THRESH1) ! THRESH1 = -1.0 ! Threshold for 3-hr averages (THRESH3) ! THRESH3 = -1.0 ! Threshold for 24-hr averages (THRESH24) ! THRESH24 = -1.0 ! Threshold for NAVG-hr averages (THRESHN) ! THRESHN = -1.0 ! -- Counts for the shortest averaging period selected can be tallied daily, and receptors that experience more than NCOUNT counts over any NDAY period will be reported. This type of exceedance violation output is triggered only if NDAY > 0. Accumulation period(Days) (NDAY) -- Default: 0 ! NDAY = 0 ! Number of exceedances allowed (NCOUNT) -- Default: 1 ! NCOUNT = 1 ! 5) Selected day table(s) Echo Option -- Many records are written each averaging period selected and output is grouped by day [List file or Plot file] (LECHO) -- Default: F ! LECHO = F ! Timeseries Option -- Averages at all selected receptors for each selected averaging period are written to timeseries files. Each file contains one averaging period, and all receptors are written to a single record each averaging time. [TSttUUUU.DAT files] (LTIME) -- Default: F ! LTIME = F !

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SO01_CC_vis.INP

 -- Days selected for output (IECHO(366)) -- Default: 366*0 ! IECHO = 366*0 ! (366 values must be entered)Plot output options------------------- Plot files can be created for the Top-N, Exceedance, and Echo tables selected above. Two formats for these files are available, DATA and GRID. In the DATA format, results at all receptors are listed along with the receptor location [x,y,val1,val2,...]. In the GRID format, results at only gridded receptors are written, using a compact representation. The gridded values are written in rows (x varies), starting with the most southern row of the grid. The GRID format is given the .GRD extension, and includes headers compatible with the SURFER(R) plotting software. A plotting and analysis file can also be created for the daily peak visibility summary output, in DATA format only. Generate Plot file output in addition to writing tables to List file? (LPLT) -- Default: F ! LPLT = F ! Use GRID format rather than DATA format, when available? (LGRD) -- Default: F ! LGRD = F !Additional Debug Output----------------------- Output selected information to List file for debugging? (LDEBUG) -- Default: F ! LDEBUG = F !!END!

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OG&E Trinity Consultants 

BART Modeling Report 083701.0004 

APPENDIX E – MUSKOGEE STATION EMISSION SUMMARY
Muskogee Generating Station

BART Emissions Modeling InputsSource Emission Summary

Baseline Heat Input mmBtu/hr 5480 5480Baseline NOx Emission Rate lb/mmBtu 0.495 2710 0.522 2863 NOx Rate with LNB/OFA lb/mmBtu 0.15 0.15 NOx Rate with SCR lb/mmBtu 0.07 0.07Baseline SO2 Emission Rate lb/mmBtu 0.80 4384 0.85 4657 SO2 Rate with DFGD lb/mmBtu 0.10 0.10 SO2 Rate with WFGD lb/mmBtu 0.08 0.08Baseline PM10 Emission Rate lb/mmBtu 0.0184 100.9 0.0244 133.84 PM10 Rate with DFGD/PBH lb/mmBtu 0.012 0.012Baseline H2SO4 Conversion Rate % 1% 1% H2SO4 Conversion with SCR % 2% 2%Baseline H2SO4 Control Efficiency % 0% 0% H2SO4 Control with DFGD % 90% 90% H2SO4 Control with WFGD % 40% 40%

Muskogee Unit 4

NOx SO2 lb/mmBtu lb/hr lb/mmBtu lb/hr conversion control e

Case 1 Baseline Case base base 0.495 2710 0.80 4384 1% 0% Case 2 NOx Combustion Controls LNB/OFA base 0.15 822 0.80 4384 1% 0% Case 3 NOx Combustion Controls plus SCR SCR base 0.070 384 0.80 4384 2% 0% Case 4 SO2 DFGD Case base DFGD 0.495 2710 0.10 548 1% 90% Case 5 SO2 WFGD Case base WFGD 0.495 2710 0.08 438 1% 40% Case 6 NOx / SO2 Control Case LNB/OFA DFGD 0.15 822 0.10 548 1% 90% 

Muskogee Unit 4 PM Speciation

SO4 (from PM) PM (coarse)1 PM (fine)1 EC SOA

lb/hr lb/hr lb/hr lb/hr lb/hr

Case 1 Baseline Case 62.0 11.1 11.7 0.5 15.5Case 2 NOx Combustion Controls 62.0 11.1 11.7 0.5 15.5Case 3 NOx Combustion Controls plus SCR 62.0 11.1 11.7 0.5 15.5Case 4 SO2 DFGD Case 40.5 7.2 7.7 0.3 10.1Case 5 SO2 WFGD Case 62.0 11.1 11.7 0.5 15.5Case 6 NOx / SO2 Control Case 40.5 7.2 7.7 0.3 10.1

BART Alternative Report, page 4-1Assumed 90% H2SO4 control with DFGD/Assumed 40% H2SO4 controlw with WFG

Basis / No

DFGD requires polishing baghouse which wAssumed SO2 to SO3 conversion in the boiAssumed SO2 to SO3 conversion in the boiAssumed no inherent SO3/H2SO4 control wBased on design target of 0.05 lb/mmBtu pBART Alternative Report, page 4-1Design removal efficiency of 92% plus opeDesign removal efficiency of 95% plus ope

Muskogee Unit 4 Muskogee Unit 5

BART Alternative Report, page 1-1BART Alternative Report, page 4-1DBTF Boiler firing subbituminous coal

Control Systems NOx SO2 H2SO4 (in model as S
Muskogee Unit 5

NOx SO2 lb/mmBtu lb/hr lb/mmBtu lb/hr conversion control e

Case 1 Baseline Case base base 0.522 2863 0.85 4657 1% 0% Case 2 NOx Combustion Controls LNB/OFA base 0.150 822 0.85 4657 1% 0% Case 3 NOx Combustion Controls plus SCR SCR base 0.070 384 0.85 4657 2% 0% Case 4 SO2 DFGD Case base DFGD 0.522 2863 0.10 548 1% 90% Case 5 SO2 WFGD Case base WFGD 0.522 2863 0.08 438 1% 40% Case 6 NOx / SO2 Control Case LNB/OFA DFGD 0.150 822 0.10 548 1% 90% 

Muskogee Unit 5 PM Speciation

SO4 (from PM) PM (coarse)1 PM (fine)1 EC SOA

lb/hr lb/hr lb/hr lb/hr lb/hr

Case 1 Baseline Case 82.3 14.7 15.6 0.6 20.6Case 2 NOx Combustion Controls 82.3 14.7 15.6 0.6 20.6Case 3 NOx Combustion Controls plus SCR 82.3 14.7 15.6 0.6 20.6Case 4 SO2 DFGD Case 40.5 7.2 7.7 0.3 10.1Case 5 SO2 WFGD Case 82.3 14.7 15.6 0.6 20.6Case 6 NOx / SO2 Control Case 40.5 7.2 7.7 0.3 10.1

1 Condensible/filterable PM speciation were based on the following profiles: 

For Coal, National Park Service guidance for PC Wet Bottom ESP. http://www2.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfm

Coarse 10.99%

Fine Soil 11.64% Fine soil included in model as PM (fine)

Fine EC 0.45%

CPM IOR 61.54% Inorganic condensible PM considered sulfates per NPS guidance

CPM OR 15.38% Organic condensible PM considered secondary organic aerosols per NPS

Control Systems NOx SO2 H2SO4 (in model as S
Muskogee Generating Station

BART Emissions Modeling InputsStack Parameters

Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 

NOx Controls base base LNB/OFA LNB/OFA SCR SCR base base base base LNB/OFSO2 Controls base base base base base base DFGD DFGD WFGD WFGD DFGD Emissions (lb/hr) NOx 2710 2863 822 822 384 384 2710 2863 2710 2863 822  SO2 4384 4657 4384 4657 4384 4657 548 548 438 438 548  PM10 100.8 133.7 100.8 133.7 100.8 133.7 65.8 65.8 100.8 133.7 65.8  H2SO4 67.1 71.3 67.1 71.3 134.3 142.6 6.7 7.1 40.3 42.8 6.7 Stack ParametersEnglish Flow (acfm) 2,260,202 2,260,202 2,260,202 2,260,202 2,376,222 2,376,222 2,028,009 2,028,009 1,878,400 1,878,400 2,045,1 Temperature (oF) 316 316 316 316 323 323 187 187 138 138 192 

 Stack Height (feet) 350 350 350 350 350 350 350 350 350 350 350  Stack Diameter (feet) 24 24 24 24 24 24 24 24 24 24 24  Exit Velocity (ft/sec) 83.3 83.3 83.3 83.3 87.5 87.5 74.7 74.7 69.2 69.2 75.3 Metric

Temperature (K) 430.78 430.78 430.78 430.78 434.67 434.67 359.11 359.11 331.89 331.89 361.89 Stack Height (m) 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.7Stack Diameter (m) 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 Exit Velocity (m/s) 25.40 25.40 25.40 25.40 26.68 26.68 22.77 22.77 21.10 21.10 22.96 

Case 5 

(SO2 -WFGD)

(LNB/

Case 1 

(baseline)

Case 2 

(NOx - LNB/OFA)

Case 3 

(LNB/OFA+SCR)

Case 4 

(SO2 - DFGD)