Oklahoma Gas & Electric 

Seminole Generating Station 

Best Available Retrofit Control Technology Evaluation 

Prepare by: Sargent & Lundy LLC 

Chicago, Illinois

Trinity Consultants 

Oklahoma City, Oklahoma 

May 29, 2008 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

ES-2 

EXECUTIVE SUMMARY 

OG&E’s Seminole Generating Station is located northeast of the city of Konawa, Seminole 

County, Oklahoma. The station includes three (3) nominal 567 MW (gross) steam electric 

generating units designated as Seminole Units 1, 2 and 3. Seminole Units 1 and 2 became 

operational in 1968, and Unit 3 became operational in 1970. All three units are Babcock & 

Wilcox wall-fired boilers, and all three fire natural gas as their primary fuel. Because the units 

fire natural gas there are no sulfur dioxide (SO2) or particulate matter (PM) emission control 

systems. Seminole Unit 3 was designed with flue gas recirculation (FGR) for nitrogen oxide 

(NOx) 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). 

Seminole Units 1, 2 and 3 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. 

All three units were in existence prior to August 7, 1977, but not in operation prior to August 7, 

1962. Based on a review of existing emissions data, all three units have the potential to emit 

more than 250 tons per year of NOx, a visibility impairing pollutant. Therefore, Seminole Units 1, 

2 and 3 meet the definition of a BART-eligible 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 “contribute to visibility 

impairment” if emissions from the source result in a change in visibility, measured as a change in 
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Seminole Generating Station – BART Determination 

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ES-2 

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 Seminole Units 1, 2 and 3 exceeded the 0.5 ∆-dv threshold at the Wichita 

Mountains Class I Area. Therefore, Seminole Units 1, 2 and 3 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 Seminole Units 1, 2 and 3. Because the Seminole 

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 

Seminole Units 1, 2 and 3 

Proposed BART Permit Limits and Control Technologies 

Unit Proposed NOx BART 

 Emission Limit 

Proposed BART Technology 

Seminole Unit 1 0.203 lb/mmBtu 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

Seminole Unit 2 0.212 lb/mmBtu 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

Seminole Unit 3 0.164 lb/mmBtu 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 
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Seminole Generating Station – BART Determination 

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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 Seminole Generating Station 

OG&E’s Seminole Generating Station is located northeast of the city of Konawa, Seminole County, 

Oklahoma. The station includes three (3) nominal 567 MW (gross) steam electric generating units 

designated as Seminole Units 1, 2 and 3. Seminole Units 1 and 2 became operational in 1968, and 

Unit 3 became operational in 1970. All three units are Babcock & Wilcox wall-fired boilers, and 

all three units fire natural gas as their primary fuel. Number 2 fuel oil has been used as a secondary 

fuel on occasion in Unit 3 for limited durations. Because the units primarily fire natural gas there 

are no sulfur dioxide (SO2) or particulate matter (PM) emission control systems. Seminole Unit 3 

was designed with flue gas recirculation (FGR) for nitrogen oxide (NOx) 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). 

Seminole Units 1, 2 and 3 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. 

All three units were in existence prior to August 7, 1977, but not in operation prior to August 7, 

1962. Based on baseline emissions data, summarized below in Table 2-1, all three units have the 

potential to emit more than 250 tons per year of NOx, a visibility impairing pollutant. Therefore, all 

three units meet the definition of a BART-eligible 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 Seminole Station 

include: 

Distance from 

Class I Area Name Seminole Station (km)

• Wichita Mountains National Wildlife Refuge (Oklahoma) 178 

• Caney Creek Wilderness Area (Arkansas) 242 

• Upper Buffalo Wilderness Area (Arkansas) 310 

• Hercules-Glades Wilderness Area (Missouri) 387 

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

98th percentile ∆-dv visibility impact from the Seminole Generating Station. Although visibility 

impact modeling at existing actual emissions did not exceed the 0.5 ∆-dv threshold, modeling at the 

maximum 24-hour pound per hour (lb/hr) emission rate from all three units on a continuous basis 

(maximum baseline emissions) exceeded the 0.5 ∆-dv threshold at the Wichita Mountains Class I 

Area. 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 Seminole 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 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 SEMINOLE UNITS 1, 2 AND 3 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 Seminole Units 1, 2 and 3. Because all three units fire 

natural gas as their primary fuel, SO2 and PM10 emissions are minimal, and there are no SO2 or 

PM10 post-combustion control technologies with a practical application to a natural gas fired boiler. 

Therefore, the Appendix Y methodology was used to evaluate BART control technologies for NOx

emissions only. 

Existing operating parameters and baseline emissions for Seminole Units 1, 2 and 3 are summarized 

in Table 2-1. The operating parameters and emissions summarized in Table 2-1 form the basis for 

the Seminole Generating Station BART determination. 
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Baseline emissions from Seminole Units 1, 2 and 3 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 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 rates 

for each boiler by the boiler’s full load heat input. 

Table 2-1 

Seminole Generating Station 

Plant Operating Parameters for BART Evaluation

Parameter Seminole Unit 1 Seminole Unit 2 Seminole Unit 3 

Plant Configuration Natural Gas-Fired Boiler Natural Gas-Fired Boiler Natural Gas-Fired Boiler 

Firing Configuration wall-fired wall-fired wall-fired 

Gross Output (nominal) 567 MW 567 MW 567 MW 

Maximum Input to Boiler 5,480 mmBtu/hr 5,480 mmBtu/hr 5,496 mmBtu/hr 

Primary Fuel natural gas natural gas natural gas 

Existing NOx Controls none none flue gas recirculation 

Existing SO2 Controls NA NA NA 

Existing PM10 Controls NA NA NA 

Baseline Emissions 

Pollutant Baseline Actual Emissions Baseline Actual Emissions Baseline Actual Emissions 

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

NOx 1,859 0.339 1,940 0.354 1,204 0.219 

2.1 Presumptive BART Emission Rates 

In the final Regional Haze Rule EPA established presumptive BART emission limits for 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. Because Seminole 

Units 1, 2 and 3 are natural gas-fired units, the presumptive BART emission limits are not 

applicable. 

 

1

 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131. 
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In support of the Regional Haze Rule EPA also prepare a cost-effectiveness analysis for retrofit 

control technologies on oil- and gas-fired units. EPA’s analysis concluded that, although a number 

of oil- and gas-fired units could make significant cost-effective reductions in NOx emissions using 

currently available combustion control technologies, for a number of units the use of combustion 

controls did not appear to be cost effective. As a result, EPA determined that it would be 

inappropriate to establish a general presumption regarding likely BART limits for oil- and naturalgas fired units.2

 

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. The principal mechanism of NOx formation in natural 

gas combustion is thermal 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. Due to the characteristically 

low fuel nitrogen content of natural gas, NOx formation through the fuel NOx mechanism is 

insignificant. 

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. As these three factors increase, NOx emission levels increase. 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. 

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 Seminole Units 1, 2 and 3 are 

listed in Table 3-1. 

 

2

 See, 70 FR 39136 
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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) 

 Pahlman Process 

 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, with respect to natural-gas fired boilers, 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 Seminole boilers are described below. 

3.2.1.1 Low NOx Burners and Overfire Air 

Low NOx burners (LNB)3

 limit NOx formation by controlling both the stoichiometric and 

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

 

3

 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. 
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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, oil, and natural gas-fired boilers. Natural gas-fired boilers the size and age of 

Seminole Units 1, 2 and 3 retrofit with LNB/OFA combustion technologies would be 

expected to achieve average emission reductions in the range of 25% to 40% from baseline, 

depending on the baseline emission rate and boiler operating conditions. Depending on the 

baseline NOx concentration and boiler load, controlled emissions would vary between 

approximately 135 to 250 ppmvd @ 3% O2 (0.16 to 0.30 lb/mmBtu). 

Seminole Units 1, 2 and 3 do not operate as baseload units. In general, all three units have 

historically operated as “peaking units” responding to increased demand for electricity. As 

peaking units, operating loads and boiler heat inputs vary substantially on a daily and 

seasonal basis. Figures 3-1 thru 3-3 show the daily total heat input (mmBtu/day) to 

Seminole Units 1, 2 and 3, respectively, for the years 2002 thru 2005. It can be seen that 

daily heat input to each boiler varies significantly, that heat input to the boilers varies 

seasonally, and that the boilers typically operate at approximately 40% load. 
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Figure 3-1 

Seminole Unit 1 Daily Heat Input (2002-2005) 

Note: Full load heat input to Unit 1 is approximately 131,520 mmBtu/day 

Figure 3-2 

Seminole Unit 2 Daily Heat Input (2002-2005) 

Note: Full load heat input to Unit 2 is approximately 131,520 mmBtu/day

Seminole Unit 1 Daily Heat Input

2002 - 2005

0

20000

40000

60000

80000

100000

120000

140000

1/1/02 4/1/02 6/30/02 9/28/02 12/27/02 3/27/03 6/25/03 9/23/03 12/22/03 3/21/04 6/19/04 9/17/04 12/16/04 3/16/05 6/14/05 9/12/05 12/11/05

Date

Heat Input (mmBtu)

Seminole Unit 1 Daily Heat Input

Seminole Unit 2 Daily Heat Input

(2002 - 2005)

0

20000

40000

60000

80000

100000

120000

140000

01/01/02 05/01/02 08/29/02 12/27/02 04/26/03 08/24/03 12/22/03 04/20/04 08/18/04 12/16/04 04/15/05 08/13/05 12/11/05

Date

Heat Input (mmBtu)

Seminole Unit 2 Daily Heat Input
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Figure 3-3 

Seminole Unit 3 Daily Heat Input (2002-2005) 

Note: Full load heat input to Unit 3 is approximately 131,904 mmBtu/day

Although LNB/OFA controls are a technically feasible retrofit technology on natural gasfired boilers, combustion controls on gas-fired boilers may not be as effective under all 

boiler operating conditions, especially during load changes and at low and high operating 

loads. 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. As an example, Figure 3-4 shows the NOx emission rate 

(lb/mmBtu) as a function of heat input (mmBtu/hr) for Seminole Unit 1. Baseline NOx

emission rates are lowest at heat inputs in the range of approximately 1,500 to 2,100 

mmBtu/hr, however, NOx emissions tend to increase at lower and higher heat inputs. 

Finally, 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. 

Combustion control systems on gas-fired boilers must be designed to minimize NOx

formation while keeping CO and VOC emission rates within acceptable limits. 

 

Seminole Unit 3 Daily Heat Input

(2002 - 2005

0

20000

40000

60000

80000

100000

120000

140000

01/01/02 05/01/02 08/29/02 12/27/02 04/26/03 08/24/03 12/22/03 04/20/04 08/18/04 12/16/04 04/15/05 08/13/05 12/11/05

Date

Heat Input (mmBtu)

Seminole Unit 3 Daily Heat Input
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Figure 3-4 

Seminole Unit 1 

NOx Emission Rate vs. Boiler Heat Input 

Based on information available from burner control vendors and engineering judgment, it is 

expected that combustion controls, including LNB and OFA, on the wall-fired boilers can 

be designed to achieve an average control efficiency of 25% from baseline emissions under 

all normal operating conditions, including low load operation, load changes, and high load 

operation. Assuming 25% reduction from baseline emission rates, controlled NOx

emissions from Seminole Units 1, 2 and 3 would average: 

• Seminole Unit 1: 0.254 lb/mmBtu (approximately 210 ppmvd @ 3% O2) 

• Seminole Unit 2: 0.266 lb/mmBtu (approximately 220 ppmvd @ 3% O2) 

• Seminole Unit 3: 0.164 lb/mmBtu (approximately 135 ppmvd @ 3% O2) 

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 which are inert during combustion, lowers the 

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

Seminole Unit 1 

NOx Emission Rate vs. Heat Input

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0 1,000 2,000 3,000 4,000 5,000

Heat Input (mmBtu/hr)

NOx Emission Rate (lb/mmBtu)

Seminole Unit 1
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

14 

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

Unit 3 is currently designed with FGR control. 

FGR may be applied in one of two techniques. In the first type of application the FGR 

system takes flue gas from the outlet of the economizer through an FGR fan to supply FGR 

flow to the furnace or to the windbox. The mixed flue gas/combustion air flow supplied to 

the windbox should be controlled such that the windbox oxygen content is not lower than 

approximately 17%. Lower oxygen content would reduce the oxygen available for 

combustion and could promote the formation of excess CO and VOC emissions. This 

method of FGR is currently in service on Seminole Unit 3, and would be a technically 

feasible retrofit option for Units 1 and 2. 

The second type of FGR (referred to as Induced FGR) also takes flue gas from the outlet of 

the economizer but ducts it to the inlet of the existing forced draft (FD) fan. At the inlet of 

the FD fan, recycled flue gas is mixed with incoming combustion air and introduced into 

the windbox. With this design, the limitation resides in the construction of the FD fan. 

Recycled flue gas could increase total flow through the FD fan by about 20%. Therefore, 

the FD fan typically requires replacement. In addition, as the percentage of flue gas 

recirculated back through the FD fans increases, so does the overall temperature of the gas 

in the FD fan. In general the gas temperature in the FD fan should not be greater than 

approximately 175°F. Higher temperatures than 175°F would result in higher than normal 

maintenance on the FD fan and could lead to premature failure of the fan. 

Both FGR designs are technically feasible retrofit options for gas-fired boilers. Either 

system would be expected to achieve an additional 15% reduction (compared to LNB/OFA 

only), or approximately 40% overall reduction from baseline. Because of the requirement 

to replace the FD fan, the first FGR design option would most likely be the preferred 

retrofit design for Seminole Units 1 and 2. 

Assuming an overall NOx reduction of 40% from baseline, emissions from Seminole Units 

1, 2 and 3 with LNB/OFA and FGR would average: 

• Seminole Unit 1: 0.203 lb/mmBtu (approximately 165 ppmvd @ 3% O2) 

• Seminole Unit 2: 0.212 lb/mmBtu (approximately 175 ppmvd @ 3% O2) 

• Seminole Unit 3: 0.164 lb/mmBtu (approximately 135 ppmvd @ 3% O2)

4

 

4

 Note that Seminole Unit 3 is currently designed with FGR, therefore, emissions from Unit 3 under the FGR 

control option are the same and emissions under the LNB/OFA control option. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

15 

3.2.2 Post-Combustion Controls 

Post-combustion NOx control systems with potential application to Seminole Units 1, 2 and 3 

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 

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 in 

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 coal- and gas-fired boilers; however, SNCR has not been used on large 

boilers (i.e., boilers larger than approximately 300 MW). Large boilers, including 

Seminole Units 1, 2 and 3, would present several design problems making it difficult to 

ensure that the reagent (urea or ammonia) would be injected at the optimum fuel gas 

temperature, and that there would be adequate mixing and residence time. 

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

install ammonia injection points capable of achieving adequate mixing within the required 

temperature zone. Higher ammonia injection rates would be needed to achieve adequate 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

16 

mixing. This design would tend to result in relatively high levels of unreacted ammonia in 

the flue gas (ammonia slip). Furthermore, because the Seminole boilers are typically used 

as peaking units, boiler load is continually changing. Boiler load changes affect flue gas 

flow rates and temperatures, which would make it particularly difficult to inject the needed 

quantity of reactant at the requisite temperature. 

Installation of an SNCR control system on large boilers, such as those at Seminole, has not 

been demonstrated in practice. As described above, there are several currently unresolved 

technical difficulties with applying SNCR to large boilers (including the physical size of 

the boiler, and adequate reactant/flue gas mixing within the required temperature range). 

SNCR control would even be more difficult to design for boilers operating as peaking units 

due to the continuous changes in flue gas flow rates and temperatures. Assuming that 

SNCR could be installed on Seminole Units 1, 2 and 3, 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, large boilers, and because 

there remains several currently unresolved technical difficulties with applying SNCR to a 

large gas-fired boiler (especially boilers that typically operate as peaking units), it was 

determined that SNCR is not an available NOx retrofit control technology for Seminole 

Units 1, 2 and 3, 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 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

17 

heater in a large utility boiler. 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. 

SCR has been installed as NOx control technology on existing gas-fired boilers. Based on 

emissions data available from the EPA Electronic Reporting website, large gas-fired boilers 

(with heat inputs above approximately 1,000 mmBtu/hr) have achieved actual long-term 

average NOx emission rates in the range of approximately 0.02 to 0.05 lb/mmBtu.5

 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 temperature, and catalyst activity. 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. In addition, flue gas temperature is an important component of SCR 

effectiveness. SCR control systems on gas-fired units that operate as peaking units would 

require time to adjust to continuous changes in boiler load, flue gas flow rate, and flue gas 

temperature. 

Based on emission rates achieved in practice at existing gas-fired units, and taking into 

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

and deactivation) and the fact that the Seminole boilers typically operate as peaking units, it 

is anticipated that SCR could achieve a controlled NOx emission rate of 0.04 lb/mmBtu 

(30-day rolling average) on Seminole Units 1, 2 and 3. An emission rate of 0.04 lb/mmBtu 

is equivalent to an average NOx concentration in the flue gas of approximately 33 ppmvd @ 

3% O2. 

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. 

 

5

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

www.epa.gov/airmarkets/emissions/raw/index.html.
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

18 

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) coal-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 (SNCR) 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 boilers but have not been 

demonstrated in practice on boilers similar in size to Seminole Units 1, 2 and 3. 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 on Seminole Units 1, 2 and 3. 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 

 

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 

Seminole Generating Station – BART Determination 

May 29, 2008 

19 

as a specific 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, and 

flue gas temperatures, would apply equally to the Rotamix control system. There is no 

technical basis to conclude that the Rotamix design addresses these unresolved technical 

difficulties. Therefore, like other SNCR control systems, the Rotamix system is determined 

not to be available for Seminole Units 1, 2 and 3 (see, section 3.2.2.1), 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 

Seminole Generating Station – BART Determination 

May 29, 2008 

20 

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 natural gas-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 Seminole Units 1, 2 and 3. 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 Seminole Units 1, 2 

and 3, and will not be further evaluated in the BART Analysis. 

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 utility 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 systems are not 

considered available or technically feasible retrofit control systems for Seminole Units 1, 2 

and 3, and will not be further evaluated in this BART Analysis. 

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 

Seminole Generating Station – BART Determination 

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21 

Table 3-2 

Technical Feasibility of Potential NOx Control Technologies 

Seminole Generating Station 

In Service on 

Existing GasFired Boilers Control Technology 

NOx Control 

Efficiency from 

Baseline or 

Controlled Emission 

Rate 

Yes No 

In Service on 

Other 

Combustion 

Sources? 

Technically Feasible on Seminole 

Units 1, 2 and 3? 

Low NOx Burners and 

Overfire Air 

(LNB/OFA) 

25% reduction X Yes Technically feasible. 

LNB/OFA plus Flue 

Gas Recirculation 

(LNB/OFA+FGR) 

40% reduction X Yes Technically feasible. Note that 

Seminole Unit 3 is currently 

equipped with FGR control. 

SNCR NA X SNCR has 

been applied 

to smaller 

coal- and gasfired boilers. 

Not a technically feasible nor 

available retrofit technology for 

Seminole Units 1, 2 and 3. SNCR 

has been used as a retrofit 

technology on small and medium 

sized (<300 MW) boilers, but has 

not been demonstrated, and would 

present significant engineering and 

operational challenges, for a large 

utility boiler. There are several 

currently unresolved technical 

difficulties associated with 

applying SNCR on a large gasfired boiler. Furthermore, SNCR 

may not be effective on boilers that 

typically operate as peaking units. 

SCR 0.04 lb/mmBtu X 

 

Yes 

SCR is a technically feasible 

retrofit technology for Seminole 

Units 1, 2 and 3. 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 control systems have 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 control systems on Seminole 

Units 1, 2 and 3. Therefore, ROFA 

will be evaluated along with other 

OFA control systems. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

22 

Table 3-2 continued 

Control Technology 

NOx Control 

Efficiency from 

Baseline or 

Controlled Emission 

Rate 

In Service on 

Existing GasFired Boilers 

In Service on 

Other 

Combustion 

Sources? 

Technically Feasible on Seminole 

Units 1, 2 and 3? 

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 gas-fired boiler. Therefore, 

Rotamix is not considered an 

available retrofit control 

technology for Seminole Units 1, 2 

& 3. 

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 natural gas-fired boilers. 

This technology is not considered 

an available NOx control 

technology for Seminole Units 1, 2 

& 3. 

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 

natural gas-fired boilers. Wet NOx 

scrubbing systems are not available 

or technically feasible for 

Seminole Units 1, 2 and 3. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

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23 

3.3 Step 3: Rank the Technically Feasible NOx Control Options by Effectiveness 

The technically feasible and commercially available NOx control technologies are listed in Table 3-

3, in descending order of control efficiency. 

Table 3-3 

Technically Feasible NOx Control Technologies 

Seminole Station 

 Seminole Unit 1 Seminole Unit 2 Seminole Unit 3 

Control Technology Approximate NOx

Emission Rate* 

(lb/mmBtu) 

Approximate NOx

Emission Rate* 

(lb/mmBtu) 

Approximate NOx

Emission Rate* 

(lb/mmBtu) 

SCR 0.04 0.04 0.04 

LNB/OFA + FGR 0.203 0.212 0.164 

LNB/OFA 0.254 0.266 NA11

Baseline12 0.339 0.354 0.219 

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 Seminole Units 1, 2 and 3 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. Furthermore, SCR control may not be as effective on boilers that 

operate as peaking units, as NOx reduction in an SCR is a function of flue gas temperature. 

Based on emission rates achieved in practice at similar sources, and including a reasonable 

margin to account for normal system fluctuations and the fact that the Seminole boilers are 

 

11 Seminole Unit 3 is currently equipped with FGR. Consequently, it is assumed that LNB/OFA without 

FGR is not an available alternative for this unit. 

12 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 

Seminole Generating Station – BART Determination 

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24 

operated as peaking units, the combination of combustion controls and SCR should achieve an 

average controlled NOx emission rate of 0.04 lb/mmBtu (30-day average). 

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

Seminole Units 1, 2 and 3 includes combustion controls (LNB/OFA) and flue gas recirculation 

(FGR). The combination of LNB/OFA+FGR is expected to achieve an average control 

efficiency of approximately 40% from baseline on gas-fired units that operate at varying loads 

and are typically operated as peaking units. The third most effective NOx retrofit control 

system considered technically feasible is the combination of LNB/OFA without FGR.13 This 

combination of controls is expected to achieve an average control efficiency of approximately 

25% from baseline. 

Economic impacts associated with the LNB/OFA, FGR, and SCR control systems were 

evaluated in accordance with EPA guidelines (40 CFR Part 51 Appendix Y). In accordance 

with guidelines 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. 

Because Seminole Units 1, 2 and 3 have historically operated as peaking units, cost impact 

evaluations, including total annual costs and total annual emission reductions, were calculated 

using a more representative annual capacity factor. Table 3-4 provides a summary of Seminole 

Units 1, 2 and 3 capacity factors for the years 2002 through 2005. During this time period 

annual capacities for each unit were typically in the range of approximately 25% to 30%. 

Evaluating economic impacts of potential retrofit control technologies using a capacity of 100% 

would not be representative of actual operations. Using a more representative capacity factor 

would more accurately reflect actual economic impacts. For this evaluation, annual operating 

costs and annual emission reductions were calculated assuming a capacity factor of 50%. 

 

13 Seminole Unit 3 is currently designed with FGR control; therefore, for Unit 3 the retrofit option that 

includes LNB/OFA would also include the existing FGR control system. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

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Table 3-4 

Seminole Units 1, 2, and 3 

Annual Capacity Factor Estimates 

Unit Total Heat Input 2002 - 

2005 

(mmBtu) 

Potential Heat Input at 

100% Capacity Factor* 

(mmBtu) 

Approximate Annual 

Capacity Factor 

(%) 

Seminole Unit 1 50,674,995 192,019,200 26.4% 

Seminole Unit 2 49,114,291 192,019,200 25.6% 

Seminole Unit 3 47,356,409 192,579,840 24.6% 

*Potential heat input was calculated based on full load boiler heat inputs of 5,480 mmBtu/hr (Units 1 & 2) 

and 5,496 mmBtu/hr (Unit 3), and assuming 8,760 hours/year operation at full load. 

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.14 

Major equipment costs were developed based on publicly available cost data and equipment 

costs recently developed for similar projects, and include the equipment, material, labor, and all 

other direct costs needed to retrofit Seminole Units 1, 2 and 3 with the control technologies. 

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 fans as well as the power requirements for 

pumps, reagent handling, and by-product handling. 

Summarized in Table 3-5 are the expected controlled NOx emission rates, and annual NOx mass 

emissions (based on 50% capacity factor), associated with each technically feasible retrofit 

technology. A capacity factor of 50% was used because it represents a conservatively high 

annual capacity for each unit based on historical capacity factors (summarized in Table 3-4). 

Table 3-6 presents the capital costs and annual operating costs associated with building and 

operating each control system (based on 50% capacity factor). Table 3-7 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. 

 

14 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 

Seminole Generating Station – BART Determination 

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26 

Table 3-5 

Seminole Generating Station - Annual NOx Emissions 

NOx Emission Rate 

(lb/mmBtu) 

Maximum Annual NOx 

Emissions 

(tpy)(1)

Annual Reduction in 

Emissions 

Control (tpy from baseline)

Technology Unit 1 Unit 2 Unit 3 Unit 1 Unit 2 Unit 3 Unit 1 Unit 2 Unit 3 

LNB/OFA + SCR 0.04 0.04 0.04 480 480 481 3,588 3,768 2,155 

LNB/OFA + FGR 0.203 0.212 0.164 2,436 2,544 1,974 1,632 1,704 622 

LNB/OFA 0.254 0.266 NA 3,048 3,192 NA 1,020 1,056 NA 

Baseline 0.339 0.354 0.219 4,068 4,248 2,636 -- -- -- 

(1) Emissions for the BART analysis are based on maximum heat inputs of 5,480 mmBtu/hr (Units 1 & 2) and 5,496 

mmBtu/hr (Unit 3). Annual emissions were calculated assuming 4,380 hours/year per boiler (50% capacity factor). 

Table 3-6 

Seminole Generating Station - NOx Emission Control System Cost Summary (per boiler)(1)

Control Technology 

Total Capital 

Investment(3)

($) 

Total Capital 

Investment 

($/kW-net) 

Annual Capital 

Recovery Cost 

($/year) 

Annual 

Operating Costs 

($/year) 

Total Annual 

Costs 

($/year) 

LNB/OFA + SCR(2) $104,230,200 $221.8 $8,943,000 $8,175,600 $17,118,600 

LNB/OFA + FGR(2) $16,977,200 $36.1 $1,456,700 $1,190,900 $2,647,600 

LNB/OFA $9,432,200 $20.1 $809,300 $588,600 $1,397,900 

(1) Capital costs are similar for each unit, however, there are no FGR retrofit costs associated with Unit 3. A summary of the 

capital cost estimates for each unit is provided in Attachment A. 

(2 Capital costs for the SCR option include the cost of combustion controls (LNB/OFA) plus SCR. Capital costs for the FGR 

option include the costs of LNB/OFA plus FGR. 

(3) 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. 

Table 3-7 

Seminole Generating Station - NOx Emission Control System Cost Effectiveness (total for three boilers) 

Control Technology 

Total Annual 

Cost(1)

($/year) 

Annual Emission 

Reduction 

(tpy) 

Average Cost 

Effectiveness 

($/ton) 

Incremental Cost 

Effectiveness(2)

($/ton) 

LNB/OFA + SCR $51,233,000 9,511 $5,387 $8,078 

LNB/OFA + FGR $6,698,400 3,998 $1,675 $1,984 

LNB/OFA $4,199,000 2,738 1,534 -- 

(1) Total annual costs for all three units are not additive because Unit 3 is currently equipped with FGR control and Unit 3 has a

slightly higher heat input. 

(2) Incremental cost effectiveness of the FGR system is compared to costs/emissions associated with LNB/OFA controls. 

Similarly, incremental cost effectiveness of the SCR system is compared to costs/emissions associated with LNB/OFA+FGR 

controls. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

27 

The average annual cost effectiveness of NOx controls systems on Seminole Units 1, 2 and 3 range 

from approximately $1,534/ton for combustion controls (LNB/OFA) to approximately $5,387/ton 

for combustion controls plus SCR. FGR controls on Seminole Units 1 & 2 reduce NOx emissions 

at an average cost effectiveness of approximately $1,675/ton and an incremental cost effectiveness 

of approximately $1,984/ton (compared to LNB/OFA alone). 

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

annualized cost of SCR control systems. 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 reduce 

overall NOx emissions from Seminole Units 1, 2 and 3 by approximately 5,513 tpy (compared to 

combustion controls and flue gas recirculation); however, the incremental cost associated with this 

reduction is approximately $44,534,600 per year, or $8,078/ton. 

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

coal-fired EGUs greater than 200 MW at power plants with a generating capacity greater than 750 

MW. Although the presumptive levels do not apply to natural gas-fired units, EPA developed the 

limits based on control strategies considered to be generally cost-effective for such units (see, 70 

FR 39134). 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 and LNB/OFA+FGR) on 

Seminole Units 1, 2 and 3 are higher than the cost effectiveness of presumptive BART controls on 

large EGU boilers. The cost effectiveness of controls needed to achieve the BART presumptive 

levels on large coal-fired EGUs was estimated to be in the range of $100 to $1000/ton. Combustion 

controls on Seminole Units 1, 2 and 3 have cost effectiveness values of $1,534 to $1,675/ton for 

LNB/OFA and FGR controls, respectively. Although the cost effectiveness of combustion controls 

on Seminole Units 1, 2 and 3 are somewhat higher than EPA’s presumptive BART cost 

effectiveness evaluation, the costs are not so great as to exclude combustion controls as BART. 

Both the average and incremental cost effectiveness of SCR on Seminole Units 1, 2 and 3 are 

significantly worse than the cost effectiveness of NOx control at other BART-applicable units. The 

SCR would result in approximately $44,534,600 per-year additional costs at the Seminole 

Generating Station. 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. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

28 

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.15 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 NOx

emission rate of 0.04 lb/mmBtu (30-day average) on a gas-fired boiler would 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. 

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. 

A summary of the Step 4 economic and environmental impact analysis is provided in Table 3-8. 

 

15 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 

Seminole Generating Station – BART Determination 

May 29, 2008 

29 

Table 3-8 

Seminole Generating Station 

Summary of NOx BART Impact Analysis 

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 1,441 9,511 $5,387 $8,078 Ammonia emissions associated with 

ammonia slip and potential safety 

issues associated with ammonia 

storage and handling. 

LNB/OFA+FGR 6,954 3,998 $1,675 $1,984 Potential to increase CO/VOC 

emissions. 

LNB/OFA 8,214 2,738 $1,534 -- Potential to increase CO/VOC 

emissions. 

Baseline 10,952 base -- -- -- 

*Annual controlled emissions (total for 3 units) were calculated based on full load boiler heat inputs of 5,480 

mmBtu/hr (Units 1 & 2) and 5,496 mmBtu/hr (Unit 3), and assuming 4,380 hours/year operation per boiler (50% 

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.16 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 3-9 summarize the 98th percentile ∆-dv impact from NOx

emissions associated each NOx retrofit control scenario. 

. 

 

16 Because Seminole Units 1, 2 and 3 utilize natural gas as their primary fuel, SO2 and PM10 are minimal. For 

impact modeling purposes, SO2 and PM10 emissions were modeled at the existing baseline emission rates. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

30 

Table 3-9 

Seminole Units 1, 2 and 3 

NOx Visibility Assessment 

Visibility Improvement 

Wichita Mountains 

Wildlife Refuge 

Upper Buffalo 

Wilderness Area 

Hercules-Glades 

Wilderness Area 

Caney Creek 

NOx Control Wilderness Area 

Technology 

Option 98th % 

∆-dv*

% 

Improvement over 

Previous 

98th % 

∆-dv

% 

Improvement over 

Previous 

98th % 

∆-dv

% 

Improvement over 

Previous 

98th % 

∆-dv

% 

Improvement over 

Previous 

Baseline 1.073 -- 0.351 -- 0.336 -- 0.588 -- 

LNB/OFA 0.813 24% 0.262 25% 0.251 25% 0.438 26% 

LNB/OFA + FGR 0.707 13% 0.221 16% 0.218 13% 0.370 16% 

LNB/OFA + SCR 0.154 78% 0.044 80% 0.044 80% 0.074 80% 

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

with each NOx retrofit control scenario. 

Combustion controls (LNB/OFA) reduce modeled visibility impacts at each Class I area by 

approximately 25%. Combustion controls plus FGR reduce modeled visibility impacts by an 

additional 13 – 16% at each Class I area. SCR control provides additional improvement in modeled 

visibility impacts; however, it is important to note that visibility impacts at three of the Class I areas 

(Upper Buffalo, Hercules-Glades, and Caney Creek) are below the 0.5 ∆-dv threshold with 

combustion controls. It is also important to note that visibility impacts were modeled assuming full 

load heat input 8,760 hours per year. Seminole Units 1, 2 and 3 operate as peaking units and are 

typically operated at approximately 40% load and achieve capacity factors in the range of 25% to 

30%. 

Modeled visibility impacts at the Wichita Mountains Class I area at the 98th percentile level with 

combustion controls (LNB/OFA+FGR) are 0.707 ∆-dv. SCR controls designed to reduce emissions 

to 0.04 lb/mmBtu reduce modeled visibility impacts to 0.154 ∆-dv, a 0.564 ∆-dv improvement. As 

discussed in section 3.4.1, the incremental increase in total annual costs associated with SCR 

controls is approximately $44,534,600/year. Therefore, the incremental cost effectiveness of the 

SCR control systems would be in the range of approximately $79.0 MM/dv. The average cost 

effectiveness of the SCR controls systems (based on modeled impacts at the Wichita Mountains) 

would be in the range of $55.7 MM/dv (based on modeled visibility impacts of 1.073 ∆-dv 

(baseline) and 0.154 ∆-dv (LNB/OFA+SCR) and total annual costs of $51,233,000). Both of these 

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

preclude SCR from consideration as BART. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

31 

Tables 3-10 and 3-11 summarize the cost effectiveness of the technically feasible NOx retrofit 

control technologies on Seminole Units 1, 2 and 3 as a function of visibility impairment 

improvement at the Class I Areas. 

Table 3-10 

Seminole Units 1, 2 and 3 

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 -- 1.073 -- -- 

LNB/OFA $4,199,000 0.813 0.260 $16.15 MM/dv 

LNB/OFA + FGR $6,698,400 0.707 0.366 $18.30 MM/dv 

LNB/OFA + SCR $51,233,000 0.154 0.919 $55.75 MM/dv 

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

emissions associated with each NOx retrofit control scenario. Visibility impairment at the nearest 

Class I Area (Wichita Mountains) was used for the cost effectiveness evaluation. 

Table 3-11 

Seminole Units 1, 2 and 3 

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 -- -- 1.073 -- -- 

LNB/OFA $4,199,000 -- 0.813 -- -- 

LNB/OFA + FGR $6,698,400 $2,499,400 0.707 0.106 $23.58 MM/dv 

LNB/OFA + SCR $51,233,000 $44,534,600 0.154 0.553 $80.53 MM/dv 

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

associated with each NOx retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita 

Mountains) was used for the cost effectiveness evaluation. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

32 

3.6 Propose BART for NOx Control at Seminole Units 1, 2 and 3 

OG&E is proposing combustion controls and flue gas recirculation (LNB/OFA+FGR) as BART for 

Seminole Units 1, 2 and 3. This combination of control technologies represents the most effective 

technically and economically feasible NOx retrofit technology for the existing boilers. The 

combination of proposed combustion controls is expected to reduce NOx emissions by 40% from 

existing baseline emissions under all normal boiler operating conditions, including load changes, 

low load operations, and high load operations. A 40% reduction in emissions from baseline for 

each unit results in the following controlled NOx emission rates: 

• Seminole Unit 1: 0.203 lb/mmBtu 

• Seminole Unit 2: 0.212 lb/mmBtu 

• Seminole Unit 3: 0.164 lb/mmBtu17

The average cost effectiveness of LNB/OFA+FGR control systems is estimated to be in the range 

of $1,675/ton and $18.3 MM/dv/yr. While these cost effectiveness numbers are somewhat higher 

than EPA’s cost estimate for presumptive BART controls on large coal-fired EGUs, they are not of 

such magnitude as to exclude combustion controls as BART on the gas-fired units at Seminole. 

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

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

The average cost effectiveness of SCR control systems on all three units is estimated to be 

$5,387/ton and $55.75 MM/dv/yr. These costs are significantly higher than the average cost of NOx

control at similar sources. In the BART rule, EPA concluded that the cost of controls to meet the 

BART NOx presumptive level on large coal-fired EGUs “in most cases range from just over $100 to 

$1000 per ton” (see, 70 FR 39135). The average cost effectiveness of SCR on Seminole Units 1, 2 

and 3 are high because of the relatively low average NOx emission rates that can be achieved with 

combustion controls and the fact that Seminole Units 1, 2 and 3 are operated as peaking units 

(limiting annual mass emissions). 

Modeled incremental visibility improvements associated with SCR controls are less than 0.3 ∆-dv 

at all Class I areas, except the Wichita Mountains where SCR controls result in a modeled visibility 

improvement of 0.553 ∆-dv (compared to LNB/OFA+FGR controls). Because of the limited 

improvement in modeled visibility impacts, the cost effectiveness of SCR control, on a $/dv basis is 

significant. Furthermore, compared to the costs and modeled visibility impacts associated with 

LNB/OFA+FGR controls, the incremental cost effectiveness of SCR is estimated to be $8,078/ton 

 

17 Note that Seminole Unit 3 is currently designed with FGR; therefore, emissions from Unit 3 under the FGR 

control option only include LNB/OFA retrofit controls. 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

33 

and more than $80.5 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. 

4.0 BART SUMMARY 

Table 4-1 summarizes the proposed BART control technologies and associated emission limits for 

Seminole Units 1, 2 and 3. 

Table 4-1 

Seminole Units 1, 2 and 3 

Proposed BART Permit Limits and Control Technologies 

Unit Proposed NOx BART 

 Emission Limit 

Proposed BART Technology 

Seminole Unit 1 0.203 lb/mmBtu 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

Seminole Unit 2 0.212 lb/mmBtu 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

Seminole Unit 3 0.164 lb/mmBtu 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

Page A-1 

Attachment A 

Seminole Units 1, 2 and 3 

BART Determination - Cost Estimate Details 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 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.18 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. 

 

 

18 “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 

Seminole Generating Station – BART Determination 

May 29, 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 

Seminole Generating Station – BART Determination 

May 29, 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. 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 (LNB/OFA) plus Flue Gas Recirculation (FGR) 

- Combustion Controls (LNB/OFA) plus Selective Catalytic Reduction (SCR) 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination May 29, 2008 

Page A-5 

BART Economic Evaluation 

NOx Summary (Seminole Units 1 & 2) 

SEMINOLE GENERATING STATION UNITS 1, 2 AND 3NOx Retrofit Control Technology - Cost Effectiveness Summary

Unit Seminole 1 Seminole 2 Seminole 3

Design Heat Input at Full Load: mmBtu/hr 5,480 5,480 5,496

Net Capacity: MW 470 470 472

Capacity Factor 50% 50% 50%

Seminole 1

Control Technology

Expected Emission 

Rate Emissions

Tons of NOx 

Removed

Total Capital 

Requirement

Annual Capital Recovery 

Cost

Total Annual 

Operating Costs Total Annual Costs

A

(lb/mmBtu) (tpy) (tpy) ($) ($/year) ($/year) ($) 

Alternative 1: LNB/OFA + SCR 0.04 480 3,588 $104,230,200 $8,943,000 $8,152,800 $17,095,800 

Alternative 2: LNB/OFA + FGR 0.203 2,436 1,632 $16,977,200 $1,456,700 $1,190,900 $2,647,600 

Alternative 3: LNB/OFA 0.254 3,048 1,020 $9,432,200 $809,300 $588,600 $1,397,900 Baseline 0.339 4,068Seminole 2

Control Technology

Expected Emission 

Rate Emissions

Tons of NOx 

Removed

Total Capital 

Requirement

Annual Capital Recovery 

Cost

Total Annual 

Operating Costs Total Annual Costs

A

(lb/mmBtu) (tpy) (tpy) ($) ($/year) ($/year) ($) 

Alternative 1: LNB/OFA + SCR 0.04 480 3,768 $104,230,200 $8,943,000 $8,175,600 $17,118,600 

Alternative 2: LNB/OFA + FGR 0.212 2,544 1,704 $16,977,200 $1,456,700 $1,190,900 $2,647,600 

Alternative 3: LNB/OFA 0.266 3,192 1,056 $9,432,200 $809,300 $588,600 $1,397,900 Baseline 0.354 4,248

NotesFull load heat input to the boilers was assumed to be the same for each Because the Seminole Units have historically operated as peaking unitsthe average capacity factor between 2002 and 2005) was used to more 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination May 29, 2008 

Page A-6 

BART Economic Evaluation 

NOx Summary (Seminole Unit 2 and Seminole Station Totals) 

SEMINOLE GENERATING STATION UNITS 1, 2 AND 3NOx Retrofit Control Technology - Cost Effectiveness Summary

Unit Seminole 1 Seminole 2 Seminole 3

Design Heat Input at Full Load: mmBtu/hr 5,480 5,480 5,496

Net Capacity: MW 470 470 472

Capacity Factor 50% 50% 50%

Seminole 3

Control Technology

Expected Emission 

Rate Emissions

Tons of NOx 

Removed

Total Capital 

Requirement

Annual Capital Recovery 

Cost

Total Annual 

Operating Costs Total Annual Costs

Average Co

Efficienc

(lb/mmBtu) (tpy) (tpy) ($) ($/year) ($/year) ($) ($/ton) 

Alternative 1: LNB/OFA + SCR 0.04 481 2,155 $104,834,200 $8,994,800 $8,023,800 $17,018,600 $7,897 Alternative 2: LNB/OFA + FGR 0.164 1,974 662 $9,468,600 $812,400 $590,800 $1,403,200 $2,120 

Alternative 3: LNB/OFA 0.164 1,974 662 $9,468,600 $812,400 $590,800 $1,403,200 $2,120

Baseline 0.219 2,636Seminole Generating Station Totals

Control Technology

Expected Emission 

Rate Emissions

Tons of NOx 

Removed

Total Capital 

Requirement

Annual Capital Recovery 

Cost

Total Annual 

Operating Costs Total Annual Costs

Average Co

Efficienc

(lb/mmBtu) (tpy) (tpy) ($) ($/year) ($/year) ($) ($/ton) 

Alternative 1: LNB/OFA + SCR na 1,441 9,511 $313,294,600 $26,880,800 $24,352,200 $51,233,000 $5,387 Alternative 2: LNB/OFA + FGR na 6,954 3,998 $43,423,000 $3,725,800 $2,972,600 $6,698,400 $1,675 

Alternative 3: LNB/OFA na 8,214 2,738 $28,333,000 $2,431,000 $1,768,000 $4,199,000 $1,534Baseline na 10,952Notes:1. Capital costs for LNB/OFA + FGR include the costs for both systems.2. Capital costs for LNB/OFA + SCR include the costs for both systems, but do not incude any costs for FGR.3. Seminole 3 was originally constructed with FGR and therefore the costs (Capital & Operating) reflect this design.

NotesFull load heat input to the boilers was assumed to be the same for each retrofit coBecause the Seminole Units have historically operated as peaking units, a capacitthe average capacity factor between 2002 and 2005) was used to more accurately 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

Page A-7 

BART Economic Evaluation – NOx 

Retrofit Control Technologies – Capital Cost Summary 

Low NOX Burner Technology Capital Costs

Seminole 1 Seminole 2 Seminole 3

Cost Basis (Year) 2008 2008 2008

Total Capital Requirement with Retrofit (TCR) $ $9,432,200 $9,432,200 $9,468,600

$/kW-gross $19 $19 $19

FGR Capital Costs

Seminole 1 Seminole 2 Seminole 3

Cost Basis (Year) 2008 2008 2008

Total Capital Requirement with Retrofit (TCR) $ $7,545,000 $7,545,000 $0

$/kW-gross $15 $15 $0

SCR Capital Costs

Seminole 1 Seminole 2 Seminole 3

Cost Basis (Year) 2008 2008 2008

 SCR Area $1,071,000 $1,071,000 $1,078,000

 Civil/Site Work $328,000 $328,000 $330,000

 Flue Gas System/Ductwork $17,126,000 $17,126,000 $17,228,000

 Modifications $2,793,000 $2,793,000 $2,810,000

 Pipe Rack $4,106,000 $4,106,000 $4,130,000

 Miscellaneous Mechanical Items $583,000 $583,000 $587,000

 Urea to Ammonia System $2,598,000 $2,598,000 $2,613,000

 Booster Fans $2,823,000 $2,823,000 $2,840,000

 Allowance for Additional Cranes $463,000 $463,000 $465,000

 Electrical Modifications $6,005,000 $6,005,000 $6,041,000

Equipment Capital Cost Subtotal $ $37,896,000 $37,896,000 $38,122,000

 Instruments & Controls $ $757,900 $757,900 $762,400

 Taxes $ $2,273,800 $2,273,800 $2,287,300

 Freight $ $1,894,800 $1,894,800 $1,906,100

 Total Direct Cost $42,822,500 $42,822,500 $43,077,800

Other Costs

Total Direct Cost with Retrofit Factor $ $51,387,000 $51,387,000 $51,693,400

 General Facilities $ $2,569,400 $2,569,400 $2,584,700

 Engineering Fees $ $5,138,700 $5,138,700 $5,169,300

 Contingency $ $10,277,400 $10,277,400 $10,338,700

 EPC Fee (20% of total Cost) $10,277,400 $10,277,400 $10,338,700

Total Plant Cost (TPC) $ $79,649,900 $79,649,900 $80,124,800

Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $82,039,000 $82,039,000 $82,529,000

Allow. for Funds During Constr. (AFDC) $ $6,678,000 $6,678,000 $6,718,000

 Preproduction Costs $ $1,772,000 $1,772,000 $1,782,600

Inventory Capital

 Initial Ammonia (60 days) $ $46,000 $46,000 $47,000

 Initial Catalyst $ $4,263,000 $4,263,000 $4,289,000

Total Capital Requirement (TCR) $ $94,798,000 $94,798,000 $95,365,600

Initial capital cost estimates were based on detailed cost estimates recently prepared for other similar projects. Costs were compared to U.S.EPA's 

Coal Utility Environmental Cost (CUECost) Workbook (modified for natural-gas combustion) and to account for recent increases in purchased 

equipment costs and commodity costs. Cost estimates were also compared to vendor quotes provided on recent similar projects.
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination May 29, 2008 

Page A-8 

BART Economic Evaluation – LNB/OFA Control System Costs 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination May 29, 2008 

Page A-9 

BART Economic Evaluation – FGR Control System Costs 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination May 29, 2008 

Page A-10 

BART Economic Evaluation – SCR Control System Costs 
Oklahoma Gas & Electric 

Seminole Generating Station – BART Determination 

May 29, 2008 

Page B-1 

Attachment B 

Seminole Units 1, 2 and 3 

BART Determination – Visibility Impact Modeling Details 
 

CALPUFF MODELING REPORT S BART DETERMINATION

OKLAHOMA GAS & ELECTRIC

SEMINOLE 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..........................................................3-6

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
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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 – SEMINOLE STATION EMISSION SUMMARY
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BART Modeling Report 083701.0004 

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LIST OF TABLES

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

TABLE 1-2. DISTANCE FROM STATION TO SURROUNDING CLASS I AREAS .......................................1-3

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
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BART Modeling Report 083701.0004 

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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 

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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 Seminole 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. 
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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 Seminole Station. 

TABLE 1-1. BART-ELIGIBLE SOURCES (SEMINOLE STATION) 

EPN Description 

SM1 5,480 MMBtu/hr Natural Gas Fired Boiler 

SM2 5,480 MMBtu/hr Natural Gas Fired Boiler 

SM3 5,496 MMBtu/hr Natural Gas Fired Boiler 

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

CACR HEGL UPBU WIMO 

Seminole 242 386 310 178 

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

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LCC Easting (km)

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LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas
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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 

Figure 2-1. The computational domain will be set to extend at least 50 km in all directions beyond 
OG&E / Sargent & Lundy Trinity Consultants 

BART Modeling Report 083701.0004 

2-2

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

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Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Meteorological Modeling Domain

Computational Modeling Domain 1
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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. 
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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

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982

1960

2950

3930

Terrain 

Elevation (m)
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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 

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LCC Easting (km)

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Sooner Station

Muskogee Station

Seminole Station
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• 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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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) 

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

 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 

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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

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LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Upper Air Stations

3.2.4 PRECIPITATION METEOROLOGICAL DATA

The effects of chemical transformation and deposition processes on ambient pollutant 

concentrations will be considered in this analysis. Therefore, it is necessary to include 
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observations of precipitation in the CALMET analysis. The precipitation stations that are 

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

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

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

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

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

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

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Precipitation Stations

3.2.5 BUOY METEOROLOGICAL DATA

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

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

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

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

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

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

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

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

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

LCC Easting (km)

-1600

-1400

-1200

-1000

-800

-600

-400

-200

LCC Northing (km)

Seminole Station

Muskogee Station

Sooner Station

WIMO

CACR

UPBU

HEGL

Class I Areas

Buoy Stations

3.3 CALMET CONTROL PARAMETERS

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

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

3.3.1 VERTICAL METEOROLOGICAL PROFILE

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

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

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

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

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

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

Layer Elevation (m) 

1 20 

2 40 

3 60 

4 80 

5 100 

6 150 

7 200 

8 250 

9 500 

10 1000 

11 2000 

12 3500 

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

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

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

fields are computed with an inverse distance weighting (1/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 
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wind field if the distance from an observation station to a grid point exceeds the maximum 

radius of influence. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

500 km. 
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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. Since the 

units at the Seminole Station are natural-gas fired, NOx control technologies were primarily evaluated 

in this analysis, Emission estimates for various control 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 
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will evaluate the use of this option during the modeling analysis and provide details in the modeling 

report about its use. 
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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 Seminole 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: 

( ) ext background SO NO OC Soil Coarse ap Ray b Mm = b + b + b + b + b + b + b −

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
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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.). 
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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. SEMINOLE 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 1.812 -- -- 0.588 -- -- 

 LNB/OFA 1.370 24% 24% 0.438 26% 26% 

 LNB/OFA & FGR 1.158 15% 36% 0.370 16% 37% 

 LNB/OFA & SCR 0.236 80% 87% 0.074 80% 87% 

 Herc-Glades Baseline 1.577 -- -- 0.336 -- -- 

 LNB/OFA 1.199 24% 24% 0.251 25% 25% 

 LNB/OFA & FGR 1.024 15% 35% 0.218 13% 35% 

 LNB/OFA & SCR 0.217 79% 86% 0.044 80% 87% 

 Upper Buffalo Baseline 1.328 -- -- 0.351 -- -- 

 LNB/OFA 1.009 24% 24% 0.262 25% 25% 

 LNB/OFA & FGR 0.867 14% 35% 0.221 16% 37% 

 LNB/OFA & SCR 0.187 78% 86% 0.044 80% 87% 

 Wichita Mts Baseline 3.392 -- -- 1.073 -- -- 

 LNB/OFA 2.636 22% 22% 0.813 24% 24% 

 LNB/OFA & FGR 2.238 15% 34% 0.707 13% 34% 

 LNB/OFA & SCR 0.491 78% 86% 0.154 78% 86% 
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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 
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Number 

Station 

Acronym 

Station 

ID 

LCC 

East 

(km) 

LCC North

(km) Long Lat 

39 KALI 72251 -103.012 -1363.74 96.9988 39.9877 

40 KLRD 12920 -246.548 -1381.603 96.9971 39.9875 

41 KSSF 72252 -143.386 -1183.35 96.9983 39.9893 

42 KRKP 11123 -4.965 -1324.914 96.9999 39.9880 

43 KCOT 11124 -219.097 -1280.964 96.9974 39.9884 

44 KLBX 11125 150.245 -1207.466 97.0018 39.9891 

45 KSAT 12921 -143.024 -1160.935 96.9983 39.9895 

46 KHDO 12962 -211.702 -1178.172 96.9975 39.9894 

47 KSKF 72253 -154.625 -1177.555 96.9982 39.9894 

48 KHYI 11126 -84.156 -1122.487 96.9990 39.9899 

49 KTKI 72254 38.788 -754.791 97.0005 39.9932 

50 KBMQ 11127 -118.39 -1027.031 96.9986 39.9907 

51 KATT 11128 -67.587 -1075.97 96.9992 39.9903 

52 KSGR 11129 131.478 -1151.702 97.0016 39.9896 

53 KGTU 11130 -65.624 -1033.173 96.9992 39.9907 

54 KVCT 12912 6.587 -1236.788 97.0001 39.9888 

55 KPSX 72255 73.878 -1253.33 97.0009 39.9887 

56 KACT 13959 -22.12 -929.156 96.9997 39.9916 

57 KPWG 72256 -30.147 -944.073 96.9996 39.9915 

58 KILE 72257 -65.288 -988.507 96.9992 39.9911 

59 KGRK 11131 -79.643 -990.173 96.9991 39.9911 

60 KTPL 11132 -38.203 -981.19 96.9996 39.9911 

61 KPRX 13960 143.317 -703.663 97.0017 39.9936 

62 KDTO 72258 -17.018 -752.974 96.9998 39.9932 

63 KAFW 11133 -29.564 -777.061 96.9997 39.9930 

64 KFTW 72259 -34.302 -795.502 96.9996 39.9928 

65 KMWL 11134 -99.769 -798.767 96.9988 39.9928 

66 KRBD 11135 12.453 -810.467 97.0002 39.9927 

67 KDRT 11136 -384.069 -1170.59 96.9955 39.9894 

68 KFST 22010 -566.418 -988.838 96.9933 39.9911 

69 KGDP 72261 -739.127 -873.302 96.9913 39.9921 

70 KSJT 72262 -333.338 -952.54 96.9961 39.9914 

71 KMRF 23034 -676.265 -1042.616 96.9920 39.9906 

72 KMAF 72264 -489.668 -878.107 96.9942 39.9921 

73 KINK 23023 -586.882 -890.654 96.9931 39.9920 

74 KABI 72265 -252.044 -836.353 96.9970 39.9924 

75 KLBB 13962 -445.006 -689.313 96.9948 39.9938 

76 KATS 11137 -696.818 -763.258 96.9918 39.9931 

77 KCQC 11138 -785.757 -515.724 96.9907 39.9953 

78 KROW 23009 -698.822 -712.898 96.9918 39.9936 

79 KSRR 72268 -789.593 -686.226 96.9907 39.9938 

80 KCNM 11139 -682.79 -822.109 96.9919 39.9926 

81 KALM 36870 -838.056 -752.338 96.9901 39.9932 

82 KLRU 72269 -931.527 -804.112 96.9890 39.9927 
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 
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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= *

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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

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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

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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 !

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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)

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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

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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 !

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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]

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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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01Met01a.inp

 (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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01Met01a.inp

 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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01Met01a.inp

 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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! 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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! 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

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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

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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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2001_SO_NOx.inp

 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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2001_SO_NOx.inp

 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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2001_SO_NOx.inp

 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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2001_SO_NOx.inp

 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
Seminole Station

Baseline Heat Input mmBtu/hr 5,480 5,480 5,496Baseline NOx Emission Rate lb/mmBtu / lb/hr 0.339 1,859 0.354 1,940 0.219 1,204 NOx Rate with LNB/OFA lb/mmBtu 0.254 0.266 0.164 NOx Rate with LNB/OFA & FGR lb/mmBtu 0.203 0.212 0.164 NOx Rate with LNB/OFA & SCR lb/mmBtu 0.040 0.040 0.040Baseline SO2 Emission Rate lb/mmBtu 0.00055 2.992 0.00042 2.286 0.00060 3.3Baseline PM10 (filterable) Emission Rate lb/mmBtu 0.00186 10.2 0.00186 10.2 0.00186 10.2Baseline PM10 (condensible) Emission Rate lb/mmBtu 0.00559 30.6 0.00559 30.6 0.00559 30.7

Seminole Unit 1

Control Systems

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

Case 1 Baseline Case base 0.339 1858 0.00055 2.992 0.00186 10.2 0.00559 

Case 2 NOx Combustion Controls LNB/OFA 0.254 1392 0.00055 2.992 0.00186 10.2 0.00559 

Case 3 NOx Combustion Controls plus FGR FGR 0.203 1112 0.00055 2.992 0.00186 10.2 0.00559 Case 4 NOx Combustion Controls plus SCR SCR 0.040 219 0.00055 2.992 0.00186 10.2 0.00559 

Seminole Unit 2

Control Systems

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

Case 1 Baseline Case base 0.354 1940 0.00042 2.286 0.00186 10.2 0.00559 

Case 2 NOx Combustion Controls LNB/OFA 0.266 1458 0.00042 2.286 0.00186 10.2 0.00559 

Case 3 NOx Combustion Controls plus FGR FGR 0.212 1162 0.00042 2.286 0.00186 10.2 0.00559 Case 4 NOx Combustion Controls plus SCR SCR 0.040 219 0.00042 2.286 0.00186 10.2 0.00559 

Seminole Unit 3

Control Systems

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

Case 1 Baseline Case (includes existing FGR) base 0.219 1204 0.00060 3.3 0.00186 10.2 0.00559 

Case 2 NOx Combustion Controls LNB/OFA 0.164 901 0.00060 3.3 0.00186 10.2 0.00559 

Case 3 NOx Combustion Controls plus FGR FGR 0.164 901 0.00060 3.3 0.00186 10.2 0.00559 Case 4 NOx Combustion Controls plus SCR SCR 0.040 220 0.00060 3.3 0.00186 10.2 0.00559 

Note 1: Seminole Unit 3 is currently equipped with flue gas recirculation (FGR), therefore, the baseline emission rate includes FGR. Note 2: Baseline NOx emissions were based on the maximum 24-hr average emission rate (lb/hr) reported by each unit during the baseline period 2003-2005. Baseline emissions data were provided by OG&E. Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the  maximum heat input to the boiler. Note 3: Seminole Unit 3 is currently equipped with FGR. Case 2 includes LNB with the existing FGR system.Note 4: Seminole Unit 3 is currently equipped with FGR, therefore, Case 3 includes LNB with the existing FGR system (which is the same as Case 2).Note 5: Baseline SO2 emissions were based on the maximum 24-hr average emission rate (lb/hr) reported by each unit during the baseline period 2003-2005. Baseline emissions data were provided by OG&E. Baseline emission rates (lb/mmBtu) were calculated by dividing the maximum 24-hr lb/hr emission rate by the  maximum heat input to the boiler. Note that SO2 emissions associated with firing oil in Unit 3 were not included in the baseline evaluation. 

SO2 PM101

Assumed 40retrofit expeAssumed 25S&L retrofit Based on AP

SO2 PM10 (filterable)1

Seminole CA

Seminole Unit 1 Seminole Unit 2 Seminole Unit 3 (Note 1) 

NOx

Based on thof 2003-200

NOx

SO2 PM101 NOx

Based on exBased on thBased on AP
Seminole Generating Station

BART Emissions Modeling InputsSummary

Unit 1 Unit 2 Unit 3 Unit 1 Unit 2 Unit 3 Unit 1 Unit 2 Unit 3 Unit 1 

NOx Controls base base base LNB/OFA LNB/OFA LNB/OFA FGR FGR FGR SCR Emissions (lb/hr) NOx 1,858 1,940 1,204 1,392 1,458 901 1,112 1,162 901 219  SO2 2.992 2.286 3.30 2.992 2.286 3.3 2.992 2.286 3.3 2.992  PM10 (filterable) 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2 10.2  PM10 (condensible) 30.6 30.6 30.7 30.6 30.6 30.7 30.6 30.6 30.7 30.6 Stack ParametersEnglish Flow (acfm) 1,471,901 1,471,901 1,549,381 1,471,901 1,471,901 1,549,381 1,471,901 1,471,901 1,549,381 1,471,901  Temperature (oF) 247 247 282 247 247 282 247 247 282 247 

 Stack Height (feet) 178 178 350 178 178 350 178 178 350 178  Stack Diameter (feet) 15 15 18 15 15 18 15 15 18 15  Exit Velocity (ft/sec) 138.8 138.8 101.5 138.8 138.8 101.5 138.8 138.8 101.5 138.8 Metric

Temperature (K) 392.44 392.44 411.89 392.44 392.44 411.89 392.44 392.44 411.89 392.44 Stack Height (m) 54.27 54.27 106.71 54.27 54.27 106.71 54.27 54.27 106.71 54.27 Stack Diameter (m) 4.57 4.57 5.49 4.57 4.57 5.49 4.57 4.57 5.49 4.57 Exit Velocity (m/s) 42.32 42.32 30.95 42.32 42.32 30.95 42.32 42.32 30.95 42.32 

Case 1

(baseline)

Case 2

(NOx - LNB/OFA)

Case 3

(LNB/OFA+FGR)

(L