# Oklahoma Gas & Electric

Muskogee Generating Station Best Available Retrofit Control Technology Evaluation

Prepared by: Sargent & Lundy LLC Chicago, Illinois

Trinity Consultants Oklahoma City, Oklahoma



# May 28, 2008Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### EXECUTIVE SUMMARY

OG&E’s Muskogee Generating Station is located at 5501 Three Forks Ro ad near Muskogee,
Oklahoma. The station has a total of four (4) generating units desi gnated as Muskogee Units 3, 4, 5 and 6. Muskogee Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit. Muskogee Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of Muskogee Units 4 & 5 commenced in the early 1970s, with Unit 4 coming on-line in 1977 and Unit 5 coming on-line in 1978. Construction commenced on Muskogee Unit 6 in 1980, and Unit 6 commenced commercial operation in mid-1984. All three coal-fired units at the Muskogee Generating Station are dry bottom ta ngentially-fired pulverized coal (P C) boilers. The boilers fire subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for particulate control.

On July 6, 2005, the U.S. Environmental Protection Agency (EPA) published the final “Regional Haze Regulations and Guidelines for Best Ava ilable Retrofit Technology Determinations” (the “Regional Haze Rule” 70 FR 39104). The Regional Haze Rule requires certain States, including Oklahoma, to develop programs to assure reasona ble 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 SI P must provide for a Best Available Retrofit Technology (BART) analysis of any existing stationary facility that might cause or contribute to impairment of visibility in a Class I Area.

BART-eligible sources include those sources that:
(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and (3) whose operations fall within one or more of the specifically listed source categories in 40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).

Muskogee Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BARTeligible source. Muskogee Unit 6 was not in existe nce prior to August 7, 1977; therefore, Unit 6 is not a BART-eligible source. Muskogee Units 4 & 5 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. Both units were in ex istence prior to August 7, 1977 (i.e., construction of the units has commenced), but not in operation prior to August 7, 1962. Based on a review of existing emissions data, both units have the pot ential to emit more than 250 tons per year ofvisibility impairing pollutants. Therefore, Muskogee Units 4 & 5 meet the definition of a BARTeligible source.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### BART is required for any BART-eligible source th at emits any air pollutant which may reasonably be anticipated to cause or contribute to any impa irment of visibility in a Class I Area. EPA has
determined that an individual source will be consid ered to “contribute to visibility impairment” if emissions from the source result in a change in visibility, measured as a change in deciviews ( ∆

- dv), that is greater than or equal to 0.5 dv in a Class I area. Visibility impact modeling previously conducted by OG&E determined that the maximu m predicted visibility impacts from Muskogee
Units 4 & 5 exceeded the 0.5 ∆ -dv threshold at the Upper Buffalo, Caney Creek, and Wichita Mountains Class I Areas. Therefore, Muskogee Units 4 & 5 were determined to be BARTapplicable sources, subject to the BART determination requirements.

Guidelines for making BART determinations are included in Appendix Y of 40 CFR Part 51 (Guidelines for BART Determinations Under the Regional Haze Rule). States are required to use the Appendix Y guidelines to make BART determinations for foss il-fuel-fired generating plants having a total generating capacity in excess of 750 MW. The BART determination process described in Appendix Y includes the following steps:

Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts.

This report is the BART determination for Muskogee Units 4 & 5. Because the Muskogee Generating Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used to prepare the BART determination. Based on an evaluation of potentially feasible retrofit control technologies, including an asse ssment of the costs and visibility improvements associated therewith, OG&E is proposing the BART control technologies and emission rates listed
in Table ES-1.

Table ES-1 Muskogee Units 4 & 5 Proposed BART Permit Limi ts and Control Technologies
Pollutant Proposed BART Emission Limit Proposed BART Technology

NO x 0.15 lb/mmBtu (30-day average) Combustion controls including LNB and OFA SO 2 Existing Permit Limits Low sulfur subbituminous coal

PM 10 filterable Existing Permit Limits NAOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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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 Availa ble 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 im pairment 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 b est 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 contri bute to any impairment of visibility in a Class I Area. BART-eligible sources which ma y reasonably be anticipated to cause or contribute to visibility impairment are classified as BART-applicable sources. 3⁄4 Require each BART-applicable source to identif y, install, operate, and maintain BART controls.

1.1 OG&E’s Muskogee Generating Station

OG&E’s Muskogee Generating Station is located at 5501 Three Forks Road near Muskogee, Oklahoma. The station has a total of four (4) ge nerating units designated as Muskogee Units 3, 4, 5 and 6. Muskogee Unit 3, which became operational in 1956, is a nominal 173-MW gas-fired unit. Muskogee Units 4, 5 and 6 are nominal 572-MW (gross) coal-fired units. Construction of Muskogee Units 4 & 5 commenced in the early 1 970s, with Unit 4 coming on-line in 1977 and Unit 5 coming on-line in 1978. Construction commenced on Muskogee Unit 6 in 1980, and Unit 6 commenced commercial operation in mid-1984. All three coal-fired units at the Muskogee Generating Station are dry bottom tangentially-fired pu lverized coal (PC) boilers. The boilers fire subbituminous coal as their primary fuel, and are equipped with electrostatic precipitators for particulate control.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### 1.2 BART Applicability Review

BART-eligible sources include those sources that:

(1) have the potential to emit 250 tons or more of a visibility-impairing air pollutant; (2) were in existence on August 7, 1977 but not in operation prior to August 7, 1962; and (3) whose operations fall within one or more of the specifically listed source categories in 40 CFR 51.301 (including fossil-fuel fired steam electric plants of more than 250 mmBtu/hr heat input and fossil-fuel boilers of more than 250 mmBtu/hr heat input).

Muskogee Unit 3 was in operation prior to August 7, 1962. Therefore, Unit 3 is not a BARTeligible source. Muskogee Unit 6 was not in existe nce prior to August 7, 1977; therefore, Unit 6 is not a BART-eligible source. Muskogee Units 4 & 5 are fossil-fuel fired boilers with heat inputs greater than 250 mmBtu/hr. Both units were in ex istence prior to August 7, 1977 (i.e., construction of the units has commenced), but not in operation pr ior to August 7, 1962. Based on a review of existing emissions data, both units have the poten tial to emit more than 250 tons per year ofvisibility impairing pollutants. Therefore, Muskogee Units 4 & 5 meet the definition of a BARTeligible source.

BART is required for any BART-eligible source th at emits any air pollutant which may reasonably be anticipated to cause or contribute to any impa irment 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 impairme nt” if emissions from the source result in a ∆ -dv change greater than or equal to 0.5 dv in a Cl ass I area. Class I areas nearest the Muskogee Station
include:

Distance from Class I Area Name Muskogee Station (km)

• Upper Buffalo Wildern ess Area (Arkansas) 165

• Caney Creek Wilderness Area (Arkansas) 181

• Hercules-Glades Wilderness Area (Missouri) 231

• Wichita Mountains National W ildlife Refuge (Oklahoma) 325

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

### percentile ∆ -dv visibility impact from Muskogee Un its 4 & 5. The maximum predicted visibility impact associated with the Muskogee Station exceeded the 0.5 ∆ -dv threshold at the Upper Buffalo, Caney Creek, and Wichita Mountains Class I Areas. Therefore, the facility was determined to be a BART-applicable source subj ect to the BART determination requirements.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### 1.3 BART Requirements

A determination of BART must be based on an anal ysis of the best system of continuous emission control technology available and associated emi ssion 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 ar e included in Appendix Y of 40 CFR Part 51 (Guidelines for BART Determinations Under the Re gional Haze Rule). States are required to use the Appendix Y guidelines to make BART determin ations 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 ty pes of sources. Because the Muskogee Generating Station has a total generating capacity in excess of 750 MW, the Appendix Y guidelines were used to prepare the BART determination.

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

Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts.

A more detailed description of each step is provided below.

Step 1. Identify all availabl e retrofit control technologies.

Available retrofit control options are those ai r pollution control technologies with a practical potential for application to the emissions unit a nd the regulated pollutant under evaluation (70 FR 39164 col. 1). Step 1 of the BART determin ation requires applicants to identify potentially applicable retrofit control technologies that represent the full range of demonstrated alternatives. Potentially applicable retrofit c ontrol alternatives can incl ude 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 em ission rate (LAER) are available for BART purposes and must be included as potential cont rol alternatives. However, EPA does notOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### consider BART as a requirement to redesign th e source when considering available control
alternatives.

In an effort to identify all potentially applicab le retrofit technologies appropriate for use at each station, information sources consulted include d, 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 a nd 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 sour ce 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 ar e considered technically feasible if either (1) they have been installed and operated successf ully for the type of source under review under similar conditions, or (2) the technology coul d 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 consider ation. 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 ev aluating the control effectiveness of all the technically feasible control alternatives identifie d 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:Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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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 do llar per ton of pollutant removed basis. Annual emissions using a particular control device are subtracted from baseline emissions to calculate tons of pollutant controlled pe r year. Annual costs are calculated by adding annual operation and maintenance costs to the a nnualized 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 relati ve 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 eff ectiveness 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 signi ficant 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 Bt u’s per ton of pollutant controlled. Second, the installation of a particular control opti on may reduce the output and/or reliability of equipment. This reduction would result in decr eased 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 re gulated pollutant in question. Environmental impacts may include solid or hazardous wast e generation, discharges of polluted water from a control device, increased water consumption, and land use impacts from waste disposal.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### Impact analyses conducted in step 4 should take in to 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 modeli ng, should be used to determine the visibility improvement expected from the potential BART control technology applied to the source. Modeling should be conducted for SO 2 

### , NO x 

### , and direct PM emissions (PM 2.5 

### and/or PM 10 

### ).

Although visibility improvement must be weighted among the five factors in a BART determination (along with the costs of complia nce, 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 tec hnologies meeting the other four factors were evaluated for visibility impacts. For example, potential retrofit technologies that are not technically feasible or cost effective will not be evaluated for visibility impacts. The final regulation also states that sources that elect to a pply the most stringent controls available need not conduct an air quality modeling analysis fo r the purpose of determining its visibility impacts (see, 70 FR 39170 col. 1).

BART control technologies and corresponding emission rates are established based on information developed from the 5-step BART determination process described above.

2.0 MUSKOGEE UNITS 4 & 5 BART DETERMINATION METHODOLOGY

The BART determination process described in Appendix Y of 40 CFR Part 51 (summarized above) was used to identify BART controls for Muskog ee Units 4 & 5. The methodology was used to evaluate BART control technologies for NO x 

### , SO 2 

### , and PM 10 

### . Existing operating parameters and baseline emissions for Muskogee Units 4 & 5 are summarized in Table 2-1. The operating parameters and emissions summarized in Table 2-1 form the basis for the Muskogee Units 4 & 5
BART determination.

Baseline emissions from Muskogee Units 4 & 5 were developed based on an evaluation of actual emissions data submitted by the facility pursuant to the federal Acid Rain Program. In accordance with EPA guidelines in 40 CFR 51 Appendix Y Part III, emission estimates used in the modeling analysis to determine visibility impairment imp acts should reflect steady-state operating conditionsOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### during periods of high capacity utilization. Th erefore, 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 ma ximum hourly mass emission rate by the full load heat input to the boiler.

Table 2-1 Plant Operating Parameters for BART Evaluation

Parameter Muskogee Unit 4 Muskogee Unit 5
Plant Configuration Pulverized Coal-Fired Boiler Pulverized Coal-Fired Boiler Firing Configuration tangentially-fired tangentially-fired Plant Output 572 MW (gross) 572 MW (gross) Maximum Input to Boiler 5,480 mmBtu/hr 5,480 mmBtu/hr Primary Fuel subbituminous coal subbituminous coal Existing NOx Controls combustion controls combustion controls Existing SO 2 Controls low-sulfur coal low-sulfur coal Existing PM 10 Controls electrostatic precip itator electrostatic precipitator
Baseline Emissions Pollutant Baseline Actual Emissions Baseline Actual Emissions lb/hr lb/mmBtu lb/hr lb/mmBtu NOx 2,710 0.495 2,863 0.522

SO 2 4,384 0.800 4,657 0.850

PM 10 101 0.018 134 0.024



### 2.1 Presumptive BART Emission Rates

In the final Regional Haze Rule EPA established presumptive BART emission limits for SO 2 

### and
NO x 

### 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-fire d EGUs greater than 200 MW in size. The presumptive levels are intended to reflect highly cost-effective technologies as well as provide enough flexibility to states to consider source sp ecific characteristics when evaluating BART.

The BART SO 2 

### presumptive emission limit for coal-fire d EGUs greater than 200 MW in size without existing SO 2 

### control is either 95% SO 2 

### removal, or an emission rate of 0.15 lb/mmBtu, unless a state determines that an alternative control level is justified based on a careful consideration of the statutory factors. For NO x 

### , EPA established a set of BART presumptive

1 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### emission limits for coal-fired EGUs greater than 200 MW in size based upon boiler size and coal type. The BART NO x 

### presumptive emission limit applicable to Muskogee Units 4 & 5 (tangentially-fired boilers firing subbituminous coal) is 0.15 lb/mmBtu.

States, as a general matter, should presume that owners and operators of greater than 750 MW power plants can cost effectively meet the presu mptive levels. However, the BART process allows consideration of site-specific retrofit costs and s ite-specific visibility impacts. States have the ability to consider the specific characteristics of th e source at issue and to find that the presumptive limits would not be appropriate for that source. Emission control technologies and emission limits that differ from the presumptive levels can be established if it can be demonstrated that an alternative emission rate is justified based on a cons ideration of the five statutory factors, including the costs of compliance and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.

3.0 BART DETERMINATION FOR NITROGEN OXIDES (NO x 

### )

The formation of NO x 

### is determined by the interaction of chemical and physical processes occurring primarily within the flame zone of th e boiler. There are two principal forms of NO x 

### designated as “thermal” NO x 

### and “fuel” NO x 

### . Thermal NO x 

### 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 NO x 

### is formed by the oxidation of nitrogen in the fuel. NO x 

### formation can be controlled by adjusting the combustion pro cess and/or installing post-combustion controls.

The major factors influencing thermal NO
x 

### formation are temperature, the concentration of combustion gases (primarily nitrogen and oxygen) in the inlet air, and residence time within the combustion zone. Advanced burner designs can regu late the distribution and mixing of the fuel and air to reduce flame temperatures and residen ce times at peak temperatures to reduce NO x 

### formation.

Coal properties have a major influence on the formation of fuel NO
x 

### . Nitrogen compounds are released from the coal during coal combustion. Fuel NO x 

### conversion is genera lly dependent on the fuel rank. In general, a higher percentage of fuel-NO x 

### is converted to NO x 

### as the rank of fuel decreases. In other words, units firing lower rank coals (e.g., subbituminous coal or lignite) will have higher uncontrolled NO x 

### emissions.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### 3.1 Step 1: Identify Potentially Feasible NOx Control Options

Potentially available control optio ns were identified based on a comprehensive review of available
information. NO x 

### control technologies with potential application to Muskogee Units 4 & 5 are
listed in Table 3-1.

Table 3-1 List of Potential NO x 

### Control Options

Control Technology

Combustion Controls

Low NO x 

### Burners & Overfire Air (LNB/OFA)
Flue Gas Recirculation (FGR)

Post-Combustion Controls
Selective Noncatalytic Reduction (SNCR)
Selective Catalytic Reduction (SCR)
Innovative Control Technologies
Rotating Overfire Air (ROFA)
ROFA + SNCR (Rotamix)

Wet NO x 

### Scrubbing

3.2 Step 2: Technical Feasibility of Potential Control Options

NO x 

### control technologies can be divided into two ge neral categories: combustion controls and postcombustion controls. Combustion controls reduce the amount of NO x 

### that is generated in the
boiler. Post-combustion controls remove NO x 

### from the boiler exhaust gas. The technical feasibility of each potentially applicable NO x 

### control technology is evaluated below.

3.2.1 Combustion Controls

The rate of NO x 

### formation in the combustion zone is a function of free oxygen, peak flame temperature and residence time. Combustion tec hniques designed to minimize the formation of
NO x 

### will minimize one or more of these variables. Combustion control options that may be applicable to the OG&E boilers are described below.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### 3.2.1.1 Low NO x 

### Burners and Overfire Air

Low NO x 

### burners (LNB) 2 

### limit NO x 

### formation by controlling both the stoichiometric and temperature profiles of the combustion flame in each burner flame envelope. This control is achieved with design features that regulate the aerodynamic distribution and mixing of the fuel and air, yielding reduced oxygen (O 2 

### ) in the primary combustion zone, reduced flame temperature and reduced residence time at peak combustion temperatures. The combination of these techniques produces lower NO x 

### 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 NO x 

### 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 comb ustion conditions and a longer flame.

LNB/OFA emission control systems have been installed as retrofit control technologies on existing coal-fired boilers. Coal-fired bo ilers retrofit with LNB/OFA combustion technologies would be expected to operate with actual average NO x 

### emission levels in the range of 85 to 180 ppmvd @ 3% O 2 

### (approximately 0.12 to 0.25 lb/mmBtu) depending on the fuel, burner configuration, and averaging time. Based on a review of emissions data
available from the EPA’s electronic emissions data reporting website, subbituminous-fired boilers retrofit with LNB/OFA have achieved actual average NO x 

### emission rates in the range of 0.12 to 0.18 lb/mmBtu. 3



### Although combustion control systems on coal-fire d boilers have demonstrated the ability to achieve average NO x 

### emission rates below 0.15 lb/mmBtu, combustion control systems may not be as effective under all boiler op erating conditions, especially during load changes and low load operations. Controlling the stoichiometric and temperature profiles of the combustion flame, and maintain ing the air/fuel mixing needed for NO x 

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

2 The term “LNB” is used generically in this BART analysis, and refers to advanced low-NOx burners available from leading boiler/ burner manufacturers. The term does not represent any vendor-specific trade name. As used in this BART analysis, the term “L NB” refers to the available advanced low-NOx burner technologies.
3 Emission data are available from EPA’s Electronic Data Reporting website: www.epa.gov/airmarkets/emissions/raw/index.html.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### term boiler NO x 

### emissions will be higher under certain operating conditions. Furthermore,
the mechanisms used to reduce NO x 

### formation (e.g., cooler flame and reduced O 2 

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

Based on information available from burner cont rol vendors, emissions achieved in practice at existing similar sources, and engineeri ng judgment, it is expected that combustion controls, including LNB and OFA, on the tangentially-fired Muskogee boilers can be designed to meet the presumptive NO x 

### BART emission rate of 0.15 lb/mmBtu (approximately 110 ppmvd @ 3% O 2 

### ). An average emission rate of 0.15 lb/mmBtu should be achievable on a 30-day rolling average basis under all normal boiler operating conditions and while maintaining acceptabl e CO and VOC emission rates.

3.2.1.2 Flue Gas Recirculation

Flue gas recirculation (FGR) controls NO x 

### by recycling a portion of the flue gas back into the primary combustion zone. The recycled air lowers NO x 

### emissions by two mechanisms: (1) the recycled gas, consisting of products that are inert during combustion, lowers the combustion temperatures; and (2) the recycled gas will reduce the oxygen content in the primary flame zone. The amount of reci rculation is based on flame stability.

FGR control systems have been used as a retr ofit NOx control strategy on natural gas-fired boilers, but have not generally been consider ed as a retrofit control technology on coalfired units. Natural gas-fired units tend to have lower O 2 

### concentrations in the flue gas and low particulate loading. In a coal-fired application, the FGR system would have to handle hot particulate-laden flue gas with a relatively high O 2 

### concentration. Although FGR has been used on coal-fired boilers for flue g as temperature control, it would not have application on a coal-fired boiler for NOx contro l. Because of the flue gas characteristics (e.g., particulate loading and O 2 

### concentration), FGR would not operate effectively as a NOx control system on a coal-fired boiler. Theref ore, FGR is not considered an applicable retrofit NOx control option for Muskogee Units 4 & 5, and will not be considered further in
the BART determination.

3.2.2 Post-Combustion Controls

Post-combustion NO x 

### control systems with potential application to Muskogee Units 4 & 5 are
discussed below.

3.2.2.1 Selective Non-Catalytic Reduction

Selective non-catalytic reduction (SNCR) involves the direct injection of ammonia (NH 3 

### ) or urea (CO(NH 2 

### ) 2 

### ) at high flue gas temperatures (approximately 1600oF - 1900oF). TheOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### ammonia or urea reacts with NO x 

### in the flue gas to produce N 2 

### and water as shown in the equations below.

(NH 2 

### ) 2 

### CO + 2NO + 1⁄2O 2 

### → 2H 2 

### O + CO 2 

### + 2N 2 

### 2NH 3 

### + 2NO + 1⁄2O 2 

### → 2N 2 

### + 3H 2 

### O

Flue gas temperature at the point of reagent injection can greatly affect NO
x 

### removal efficiencies and the quantity of NH 3 

### or urea that will pass through the SNCR unreacted (referred to as NH 3 

### slip). In general, SNCR reactions are effective in the range of 1,700 o 

### F. At temperatures below the desired operating range, the NO x 

### reduction reactions diminish
and unreacted NH 3 

### emissions increase. Above the desired temperature range, NH 3 

### is
oxidized to NO x 

### resulting in low NO x 

### reduction efficiencies.

Mixing of the reactant and flue gas within the r eaction zone is also an important factor to SNCR performance. In large boilers, the physical distance over which reagent must be dispersed increases, and the surface area/volum e 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 perform ance of an SNCR system, including residence time, reagent-to-NO x 

### ratio, and fuel sulfur content.

SNCR control systems have been installed as retrofit NO x 

### control systems on small and medium sized (i.e., less than approximately 300 MW) coal-fired boilers. However, becauseof design and operating limitations, SNCR has not been used on large subbituminous coalfired boilers. Large subbituminous coal-fire d boilers, including Muskogee Units 4 & 5, would not be able to achieve adequate re agent mixing and residence time within the required flue gas temperature window to achieve effective NOx reduction.

The physical size of the Muskogee boilers ma kes it technically infeasible to locate and install ammonia injection points capable of achieving adequate NH 3 

### /NOx contact within the required temperature zone. Higher ammonia injection rates would be needed to achieve adequate NH 3 

### /NOx contact. Higher ammonia injection rates would result in relatively high levels of unreacted ammonia in the flue gas (ammonia slip), which could lead to plugging of downstream equipment.

Another design factor limiting the applicability of SNCR control systems on large
subbituminous coal-fired boilers is related to the reflective nature of subbituminous ash. Subbituminous coals typically contain high leve ls of calcium oxide and magnesium oxideOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

15 

### that can result in reflective ash deposits on the waterwall surfaces. Because most heat transfer in the furnace is radiant, reflectiv e ash can result in less heat removal from the furnace and higher exit gas temperatures. If a mmonia is injected above the appropriate temperature window, it can actually lead to additional NO x 

### formation.

SNCR control systems have not been designed or installed on large subbituminous coalfired boilers, and, as described above, there are several currently unresolved technical difficulties with applying SNCR to large subbituminous coal-fired boilers (including the physical size of the boiler, inadequate NH 3 

### mixing, and ash characteristics). Even assuming that SNCR could be installed on Muskogee Units 4 & 5, NO x 

### control effectiveness would be marginal, and, dependi ng on boiler exit temperatures, could actually
result in additional NO x 

### formation. Because SNCR has not been designed for, or demonstrated on, a large subbituminous coal-fire d boiler, it was determined that the control technology is not applicable to Muskogee Un its 4 & 5, and SNCR will not be evaluated
further in the BART determination.

3.2.2.2 Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) involves inj ecting ammonia into boiler flue gas in the presence of a catalyst to reduce NO x 

### to N 2 

### 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:

4NH 3 

### + 4NO + O 2 

### → 4N 2 

### + 6H 2 

### O 8NH 3 

### + 4NO 2 

### + 2O 2 

### → 6N 2 

### + 12H 2 

### O

The performance of an SCR system is influen ced by several factors including flue gas temperature, SCR inlet NO x 

### 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 o 

### F to maximize NO x 

### reduction efficiency and minimize ammonium sulfate formation. This temperature range t ypically occurs between the economizer and air heater in a large utility boiler. Below this range, ammonium sulfate is formed resulting in catalyst deactivation. Above the optimum temp erature, the catalyst will sinter and thus deactivate rapidly. Another factor affect ing SCR performance is the condition of the catalyst material. As the catalyst degrades over time or is damaged, NO x 

### removal
decreases.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

16 

### SCR has been installed as a retrofit contro l technology on existing coal-fired boilers,including boilers firing subbituminous coal. SCR control systems on subbituminous coalfired boilers have achieved annual average NO x 

### emission rates in the range of 0.04 to approximately 0.10 lb/mmBtu. 4 

### Several design and operating variables will influence the performance of the SCR system, including the volume, age and surface area of the catalyst (e.g., catalyst layers), uncontrolled NO x 

### emission rate, flue gas characteristics (including temperature, sulfur content, and par ticulate loading), and catalyst activity. 5 

### Catalyst that has been in service for a period of time will have decreased performance because of normal deactivation and deterioration. Catalyst that is no longer effective due to plugging, blinding or deactivation must be replaced.

Based on emission rates achieved in practice at existing subbituminous coal-fired units, and taking into consideration long-term operation of an SCR control system (including catalyst plugging and deactivation) it is anticipated that SCR could achieve a controlled NO x 

### emission rate of 0.07 lb/mmBtu (30-day rolling average) on Muskogee Units 4 & 5. An emission rate of 0.07 lb/mmBtu is equivalent to an average NO x 

### concentration in the flue gas of approximately 50 ppmvd @ 3% O 2 

### . Reducing NOx emissions below 50 ppmvd @
3% O 2 

### would tend to increase collateral environmental impacts associated with the SCR, including increased ammonia slip, increased SO 2 

### to SO 3 

### oxidation, and more frequent catalyst changes.

3.2.3 Innovative NO x 

### Control Technologies

A number of innovative NO x 

### control systems, including multi-pollutant control systems, were identified as potential retrofit control technologies during the review of available documents.
Innovative NO x 

### 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 NO x 

### scrubbing systems.

4 Emission data are available from EPA’s Electronic Data Reporting website: www.epa.gov/airmarkets/emissions/raw/index.html.

5 See, e.g., Sanyal, A., Pircon, J.J., “What and How Should You Know About U.S. Coal to Predict and Improve SCR Performance”, proceedings of the USEP A, DOE, EPRI, Combined Power Plant Air Pollution Control Mega Symposium, Chicago, IL, August 2001. See also, Gutberlet, H., Schluter, A., Licata, A., “Deactivation of SCR Catalyst”, pr oceedings of the DOE’s 2000 Conf erence on Selective Catalytic and Selective Non-Catalytic Reduction for NOx Control, Pittsburgh, PA, 2000.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

17 

### 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 asy mmetrically placed air nozzles. 6 

### Like other OFA systems, ROFA stages the primary combusti on zone to burn overall rich, with excess air added higher in the furnace to burn out products of incomplete combustion. The ROFA nozzles are designed to increase turbulence within the furnace. Increased turbulence should prevent the formation of stratified laminar flow , enable the furnace volume to be used more effectively for the combustion process, and reduce the maximum temperatures of the
combustion zone.

The ROFA system consists of air injection boxes, duct work and supports, the ROFA fan, and control system instrumentation. A ROFA system was installed on an existing 80-MW (gross) bituminous-fired utility boiler in the summe r of 2002. Test results showed that the ROFA system reduced NO x 

### emissions from baseline le vels 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 NO x 

### emissions from 0.59 lb/mmBtu to 0.295 lb/mmBtu. 7



### The turbulent air injection and mixing provide d by ROFA allows for the effective mixing of chemical reagents with the combustio n products in the furnace. MobotecUSA’s
Rotamix ® 

### system combines the rotating opposed overfire air system with urea injection into the flue gas to reduce NO x 

### emissions. The turbulent mixing created by the ROFA system is designed to improve distribution of the ammonia/urea reagent and may reduce the ammonia/urea injection required by the SNCR control system. A Rotamix control system was installed on the same 80-MW unit in the spring of 2004.

ROFA and Rotamix ® 

### systems have been demonstrated on smaller coal-fired boilers but have not been demonstrated in practice on boile rs similar in size to Muskogee Units 4 & 5. As discussed in subsection 3.2.1.1, overfire air control systems are a technically feasible retrofit control technology, and, based on engineering judgment, the ROFA design could also be applied to Muskogee Units 4 & 5. Howe ver, there is no technical basis to conclude that the ROFA design would provide additional NO x 

### reduction beyond that achieved with other OFA designs. Therefore, ROFA control systems will not be evaluated as a specific

6 See, MobotecUSA at www.mobotecusa.com

.

7 Coombs, K.A., Crilley, J.S., Shilling, M., Higgins, B. , “SCR Levels of NOx Reduction with ROFA and Rotamix (SNCR) at Dynegy’s Vermilion Power Station,” Presented at 2004 Stack Emissions Symposium, Clearwater Beach, Florida, July 28-30, 2004.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

18 

### control system, but will be included in the ove rall 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 desi gn. The technical limitations discussed in section 3.2.2.1, including the physical size of the boiler, inadequate NH 3 

### /NOx contact, fly ash characteristics, and flue gas temperatures, would apply equally to the Rotamix control system. There is no technical basis to conclude that the Rotamix urea injection design
addresses these unresolved technical difficulti es. Therefore, like other SNCR control systems, the Rotamix system is determined not to be an applicable NOx control system for Muskogee Units 4 & 5, and will not be evaluate d further in the BART determination.

3.2.3.2 Pahlman Multi-Pollutant Control Process

The PahlmanTM Process is a patented dry-m ode multi-pollutant control system. The process uses a sorbent composed of oxides of manganese (the PahlmaniteTM sorbent) to
remove NO x 

### and SO 2 

### 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, allo wing 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. NO x 

### and SO 2 

### 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 re generation 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 convert ed 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 & E nvironmental Research Cent er, University of North Dakota, April 2004.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

19 

### development and testing. 10 

### The process is an emerging multi-pollutant control, and there is
limited information available to evaluate it’s technically feasibility and long-term effectiveness on a large subbituminous-fired bo iler. It is likely that OG&E would be required to conduct extensive design engineeri ng and testing to evaluate the technical feasibility and long-term effectiveness of the control system on Muskogee Units 4 & 5. BART does not require applicants to experien ce extended time delays or resource penalties to allow research to be conducted on an emergi ng control technique. Therefore, at this time
the Pahlman Process is not considered an available NO x 

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

3.2.3.3 Wet NO x 

### Scrubbing Systems

Wet scrubbing systems have been used to remove NO x 

### 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 NO 2 

### to N 2 

### O 5 

### . This highly oxidized species of NO x 

### is very soluble and rapidly reacts with water to form nitric acid.
The conversion of NO x 

### to nitric acid occurs as the N 2 

### O 5 

### 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/natur al gas production. However the technology has not been demonstrated on large coal-fired boilers and it is likely that OG&E would incur substantial engineering and testing to evaluate the scale-up potential and long-term effectiveness of the system. Therefore, at this time wet NO x 

### scrubbing is not considered to be an applicable or commercially available retrofit control system for Muskogee Units 4 & 5, and will not be further evaluate d in this BART determination.

The results of Step 2 of the NO x 

### BART Analysis (technical feasibility analysis of potential NO x 

### 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 Muskogee Generating Station – BART Determination May 28, 2008

20 

### Table 3-2 Technical Feasibility of Potential NO x 

### Control Technologies Muskogee Generating Station

In Service on Existing PC Boilers Control Technology Controlled NO x Emission Rate

(lb/mmBtu) Yes No In Service on Other Combustion

Sources? Technically Feasible on Muskogee Units 4 & 5?

Low NOx Burners and Overfire Air 0.15 lb/mmBtu X Yes Technically feasible.

SNCR NA X Yes SNCR has been applied

to severalsmaller coalfired boilers. Not a technically feasible retrofit technology for Muskogee Units 4 & 5. SNCR has been used as a retrofit technology on small andmedium sized (<300 MW) coalfired boilers, but has not been demonstrated on larger boilers. There are several currently unresolved technical difficulties associated with applying SNCR on a large subbituminous coal-fired boiler.

SCR 0.07 lb/mmBtu X Yes SCR is a technically feasible retrofit technology for Muskogee Units 4 & 5. The effectiveness of the SCR system will depend on site-specific considerations including the ammonia injection rate, site-specific flue gas characteristics, ammonia slip, and frequency of catalyst changes. ROFA NA X Yes ROFA has been demonstrated on small coal-fired boilers, and would be a technically feasible retrofit control technology. However, there is no technical basis to conclude that ROFA will provide additional NOx control beyond that achievable with other OFA systems. Therefore, ROFA will be evaluated along with other OFA control systems.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

21 Table 3-2 continued

Control Technology Controlled NO x Emission Rate

(lb/mmBtu) In Service on Existing PC Boilers In Service on Other Combustion

Sources? Technically Feasible on Muskogee Units 4 & 5?

Rotamix (SNCR) NA X Yes Rotamix control systems have been demonstrated on small coal-fired boilers. However, there are several currently unresolved technical difficulties associated with applying SNCR-type systems on a large subbituminous coal-fired boiler. Therefore, Rotamix is not considered an available retrofit control technology for Muskogee Units 4 & 5. Pahlman Process NA X No Bench- and pilot-scale testing has been conducted on coal-fired boilers, however, there is limited data available assessing the technical feasibility of this system on large coal-fired boilers. Wet NO x Scrubbing NA X Yes The system has been used on refinery fluid catalytic cracking units and small coal-fired boilers, but has not been used on large coal-fired boilers. Wet NOx scrubbing systems are not commercially available or technically feasible for 

### Muskogee Units 4 & 5

.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

22 

### 3.3 Step 3: Rank the Technically Feasible NO x 

### Control Options by Effectiveness

The technically feasible and commercially available NO x 

### control technologies for Muskogee Units 4 & 5 are listed in Table 3-3, in d escending order of control efficiency.

Table 3-3 Technically Feasible NO x 

### Control Technologies Muskogee Station

Muskogee Unit 4 Muskogee Unit 5
Control Technology Approximate NO x Emission Rate*

(lb/mmBtu) Approximate NO x Emission Rate*

(lb/mmBtu) Selective Catalytic Reduction (SCR) 0.07 0.07

Low-NOx Burners and Overfire Air 0.15 0.15

Baseline 11 0.495 0.522



### 3.4 Step 4: Evaluate the Technically Feasible NO x 

### Control Technologies

3.4.1 NO x 

### Control Technologies – Economic Evaluation

The most effective NO x 

### retrofit control system, in terms of reduced emissions, that is considered to be technically feasible for Mu skogee Units 4 & 5 includes combustion controls (LNB/OFA) and post-combustion SCR. This comb ination of controls should be capable of achieving the lowest controlled NO x 

### 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, NH 3 

### / NO x 

### stoichiometric ratio, NH 3 

### slip, and catalyst deactivation rate. Based on emission rates achieved in practice at similar sources, and including a reasonable margin to account for normal system fluctuations, the combination of
combustion controls and SCR should achieve a controlled NO x 

### emission rate of 0.07 lb/mmBtu (30-day average).

The next most effective NO x 

### retrofit control system that is considered technically feasible for Muskogee Units 4 & 5 includes combustion controls (LNB/OFA). The combination of

11 Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmBtu) were calculated by dividing the maximum hourly mass emission rate (lb/hr) by the full load heat input to each boiler. The relatively high short-term baseline emission rates were used to predict maximum potential visibility impacts, and to provide a conservativ e estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baseline emission rates shoul d 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 Muskogee Generating Station – BART Determination May 28, 2008

23 

### LNB/OFA on Muskogee Units 4 & 5 (large tangen tially fired boilers firing subbituminous coal) should be capable of meeting the BART presumptive limit of 0.15 lb/mmBtu.

Economic impacts associated with the SCR cont rol systems were evaluated in accordance with EPA guidelines (40 CFR Part 51 Appendix Y). In accordance with the guidelines in Part III of Appendix Y, emission estimates used in the modeling analysis to determine visibility impairment impacts should reflect steady-sta te operating conditions during periods of high capacity utilization. Therefore, projected emi ssion rates (lb/hr) were calculated based on the expected controlled emission rate (lb/mmBtu) achievable on a 30-day rolling average and heat input to the boiler at full load. Annual emi ssions (tpy) were calculated assuming a 90% capacity factor for each unit.

Cost estimates were compiled from a number of data sources. In general, the cost estimating methodology followed guidance provided in the EPA Air Pollution Cost Control Manual. 12 

### Major equipment costs were developed based on equipment costs recently developed for similar projects, and include the equipment, materi al, labor, and all other direct costs needed to retrofit Muskogee Units 4 & 5 with the control technology.

Fixed and variable O&M costs were develope d for each control system. Fixed O&M costs include operating labor, maintenance labor, main tenance material, and administrative labor.
Variable O&M costs include the cost of cons umables, including reagent (e.g., ammonia), byproduct management, water consumption, and aux iliary power requirements. Auxiliary power requirements reflect the additional power requirements associated with operation of the new control technology, including operation of any new ID fans as well as the power requirements for pumps, reagent handling, and by-product handling.

Summarized in Table 3-4 are the expected controlled NO x 

### emission rates, and maximum annual
NO x 

### mass emissions, associated with each technica lly feasible retrofit technology. Table 3-5 presents the capital costs and annual operati ng costs associated with building and operating each control system. Table 3-6 shows the aver age annual cost effectiveness and incremental
annual cost effectiveness for each NO x 

### control system. A detailed summary of the cost
estimates used in this BART determination is included in Attachment A.

12 U.S. Environmental Protection Agency, EPA Air Pollution Cost Control Manual , 6 th Ed., Publication Number EPA 452/B-02-001, January 2002.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

24 

### Table 3-4 Annual NOx Emissions

Control Technology NOx Emission Rate

(lb/mmBtu) Maximum Annual NOx Emissions

(tpy) * Annual Reduction in Emissions (tpy from baseline)
Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 LNB/OFA + SCR 0.07 0.07 1,512 1,512 9,181 9,764 LNB/OFA 0.15 0.15 3,240 3,240 7,453 8,036 Baseline NOx Emissions 0.495 0.522 10,693 11.276 -- --

* Maximum annual emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr per boiler for 7,884 hours per year (90% capacity factor).



### Table 3-5 NOx Emission Control System

Cost Summary (per boiler)

Control Technology Total Capital Investment* ($) Total Capital Investment ($/kW-gross) Annual Capital Recovery Cost ($/year) Annual Operating Costs ($/year) Total Annual Costs ($/year) LNB/OFA + SCR $193,077,000 $339 $16,568,000 $14,227,600 $30,795,600
LNB/OFA $14,113,700 $25 $1,211,100 $880,700 $2,091,800 * Capital costs for NOx retrofit control systems will be similar for both Units 4 & 5. Capital costs include the cost of major

components and indirect installation costs such as foundations, mechanical erection, electrical, piping, and insulation for the control system. Capital costs for the SCR system include costs associated with inst allation of LNB/OFA systems.



### Table 3-6 NOx Emission Control System Cost Effectiveness (total for both boilers)

Control Technology Total Annual Cost ($/year) Annual Emission Reduction (tpy) Average Cost Effectiveness ($/ton) Incremental Cost Effectiveness ($/ton) LNB/OFA + SCR $61,591,200 18,945 $3,251 $16,611
LNB/OFA $4,183,600 15,489 $270 NA



### The average annual cost effectiveness of LNB/OFA+SCR on Muskogee Units 4 & 5 is estimated to be approximately $3,251/ton. Th is cost compares to an average annual cost
effectiveness for LNB/OFA combustion controls of approximately $270/ton. Equipment costs, retrofit challenges, and annual operating costs all have a significant impact on the annualized cost of a SCR control system. Significant annual operating costs include the energy cost associated with the additional pressure drop acr oss the SCR and costs associated with replacing the SCR catalyst as it degrades over time. Based on projected actual emissions, SCR couldOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

25 

### reduce overall NO x 

### emissions from Muskogee Units 4 & 5 by approximately 3,456 tpy (compared to advanced combustion controls); however, the incremental cost associated with this reduction is approximately $57,407 ,600 per year, or $16,611/ton.

As part of the BART rulemaking, EPA established presumptive NO x 

### emission limits applicable to EGUs greater than 200 MW at power plants with a generating capacity greater than 750 MW. The presumptive NO x 

### emission limits were based on control strategies that EPA considered to be generally cost-effective for such units (see, 70 FR 39134). The presumptive
NO x 

### emission limit applicable to Muskogee Units 4 & 5 (tangentially-fired units firing subbituminous coal) is 0.15 lb/mmBtu. For all types of boilers, other than cyclone units, the presumptive limits were based on the use of co mbustion control technologies. EPA estimated
that the “costs of such controls in most cases range from just over $100 to $1000 per ton” (see, 70 FR 39135).

The average cost effectiveness of combustion controls (LNB/OFA) on Muskogee Units 4 & 5 is similar to the BART cost-effectiveness developed by EPA for NO x 

### control on large EGU boilers. Both the average and incremental co st effectiveness of SCR on Muskogee Units 4 & 5 are significantly greater than the cost effectiveness of NO x 

### control at other BART-applicable
units. The costs associated with SCR woul d result in significant economic impacts on the Muskogee Generating Station (approximately $57,407,600 per year additional costs). Therefore, SCR should not be selected as BART based on lack of cost effectiveness. Although SCR does not appear to be cost effective, it w ill be included in the evaluation of the remaining
factors to assure that the BART determinati on considers all relevant information.

3.4.2 NO x 

### Control Technologies – Environmental Impacts

Combustion modifications designed to decrease NO x 

### formation (lower temperature and less oxygen availability) also tend to increase th e formation and emission of CO and VOCs. Therefore, the combustion controls must be designed to reduce the formation of NO x 

### while maintaining CO and VOC formation at an acceptable level. Other than the NO x 

### /CO-VOC trade-off, there are no environmental issues as sociated with using combustion controls to
reduce NO x 

### emissions.

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

### First, in
order to maintain low NO x 

### emissions some excess ammonia will pass through the SCR. Ammonia slip will increase with lower NO x 

### emission limits, and will also tend to increase as the catalyst becomes deactivated. Ammonia slip from an SCR designed to achieve a controlled

13 See, Hinton, W.S., Cushing, K.M., Gooch, J.P., “B alance-of-Plant Impacts As sociated with SCR/SNCR Installations”, proceedings of the ICAC Forum, 2002.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

26 

### NO x 

### emission rate of 0.07 lb/mmBtu (30-day average) is expected to be in the range of 2-5 ppm during the initial operation of the SCR. As the catalyst ages and becomes either deactivated or blinded, ammonia slip can increase; however, the ammonia slip rate is not expected to exceed 7-10 ppm under normal operating conditions.

Second, undesirable reactions can occur in an SCR system, including the oxidation of NH 3 

### and
SO 2 

### and the formation of sulfate salts. A fraction of the SO 2 

### in the flue gas (approximately 1 - 1.5%) will oxidize to SO 3 

### in the presence of the SCR catalyst. SO 3 

### can react with water to form sulfuric acid mist or with the ammonia slip to form ammonium sulfate ((NH 4 

### ) 2 

### SO 4 

### ). Sulfuric acid mist and (NH 4 

### ) 2 

### SO 4 

### are classified as condensable particulates. The formation of condensible particulates will increase as the size of the SCR increases.

Finally, the storage of ammonia on-site incr eases the risks associated with an accidental ammonia release. Depending on the type, con centration, 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 ((NH 2 

### ) 2 

### CO) can be delivered to the station as an aqueous solution or as a dry solid, and urea storage/handling does not create the process sa fety concerns associated with handling anhydrous ammonia.

3.4.3 NO x 

### Control Technologies – Energy Impacts

Both NOx control systems require auxiliary po wer. Auxiliary power requirements associated with the LNB/OFA control systems are generally insignificant, but may include booster fans for the overfire air injection ports to increase tur bulence within the boiler. Auxiliary power requirements associated with the SCR include additional fan power to overcome pressure drop through the SCR. Energy impacts associated w ith each control technology were included in the BART economic impact evaluation as an auxiliary power cost.

A summary of the Step 4 economic and environmenta l impact analysis is provided in Table 3-7.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

27 

### Table 3-7 Summary of NO x 

### BART Impact Analysis (total for both boilers)

Control Technology Annual Controlled Emissions* (tpy) Annual Emission Reductions (tpy) Average Cost Effectiveness ($/ton) Incremental Cost Effectiveness ($/ton) Summary of Environmental Impacts

LNB/OFA+SCR 3,024 18,945 $3,251 $16,611 Increased SO 2 to SO 3 oxidation, and increased condensible PM emissions including H 2 SO 4 . Ammonia emissions associated with ammonia slip. LNB/OFA 6,480 15,489 $270

-- Potential to increase CO/VOC emissions. Baseline 21,969 base -- -- -- * Annual controlled emissions and annual emission reductions represent total emissions from both units. Annual

emissions for the BART analysis are based on a maximum heat input of 5,480 mmBtu/hr per boiler for 7,884 hours per year (90% capacity factor).



### 3.5 Step 5: Evaluate Visibility Impacts

To evaluate the relative effectiveness of potentially feasible NO x 

### retrofit control technologies, NO x 

### emissions were modeled at the projected pos t-retrofit controlled emission rates, while SO 2 

### and

PM 10 

### emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA guidelines (40 CFR Part 51 Appendix Y Part III), pos t-retrofit emission rates used in the modeling analysis to determine visibility impairment imp acts reflect steady-state operating conditions during periods of high capacity utilization. Post-retr ofit emission rates (average lb/hr rate on a 24-hour basis) were calculated using the expected cont rolled emission rate achievable on a 30-day rolling average multiplied by the boiler heat input ( mmBtu/hr) at full load. The visibility modeling methodology is described further in Attachment B of this document, including detailed inputs and
results. The results in Table 3-8 summarize the 98 th 

### percentile ∆ -dv impact from NO x 

### emissions
associated each NO x 

### retrofit control scenario.

The most significant improvement in visibility can be attributed to NO x 

### reductions associated with combustion controls (LNB/OFA). Visibility im provements in the range of 70% reductions in modeled impacts are achieved at each Class I Area. The largest reduction in visibility impairment (0.74 ∆ -dv) occurs at the Caney Creek Class I Area. Modeled impacts associated with NO x 

### emissions based on LNB/OFA controls at the presumptive NO x 

### emission limit (0.15 lb/mmBtu) are below the threshold impact level of 0.5 ∆ -dv level at all Class I Areas.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

28 

### Table 3-8 Muskogee Units 4 & 5 NO x 

### Visibility Assessment

Visibility Improvement Upper Buffalo Wilderness Area Caney Creek Wilderness Area Hercules-Glades Wilderness Area Wichita Mountains Wildlife Refuge NOx Control Technology

Option 98 th % ∆ -dv* %Improvement over Previous 98 th % ∆ -dv %Improvement over Previous 98 th % ∆ -dv %Improvement over Previous 98 th % ∆ -dv %Improvement over Previous

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

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

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

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

with each NOx retrofit control scenario.



### Post-combustion SCR control systems could reduce NO x 

### emissions from Muskogee Units 4 & 5 below the BART presumptive level; however, modeled visibility improvements at the lower NO x 

### emission rates do not justify the costs associated w ith SCR control. LNB/OFA control systems are expected to reduce overall NO x 

### emissions from Muskogee Units 4 & 5 by approximately 15,489 tpy (from baseline). SCR control systems would reduce overall NO x 

### emissions by an additional 3,456 tpy. At the lower NO x 

### emission rates, modeled visibility impairment at the Class I Areas would be reduced by only 0.08 to 0.18 ∆ -dv. Because only small improvement s in visibility impacts result from the lower emission rate, the cost effectiv eness of SCR control, on a $/dv basis, will be significant.

Tables 3-9 and 3-10 summarize the cost e ffectiveness of the technically feasible NO x 

### retrofit control technologies on Muskogee Units 4 & 5 as a function of visibility impairment improvement
at the Class I Areas.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

29 

### Table 3-9 Muskogee Units 4 & 5 NO x 

### Average Visibility Cost Impact Evaluation

Total Annual Cost Modeled Visibility Impairment* Visibility Impairment Improvement from Baseline Average Improvement Cost Effectiveness NOx Control Technology Option ($/yr) 98 th % ∆ -dv* (dv) ($/dv/yr)

Baseline -- 1.06 -- -- LNB/OFA $4,183,600 0.32 0.74 $5.65 MM/dv LNB/OFA + SCR $61,591,200 0.14 0.92 $66.9 MM/dv

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

associated with each NOx retrofit cont rol scenario. Modeled visibility impairment at the Caney Creek Class I Area was used for the cost effectiveness evalua tion because modeling indicated that the largest ∆ -dv improvements would occur at Caney Creek.



### Although SCR control systems reduce modeled visibility impacts at the four Class I Areas, the incremental cost effectiveness of SCR control (with r espect to visibility improvement) is very high.
Incremental cost effectiveness of SCR control is in the range of $319 million per dv improvement at the Wichita Mountains. This cost is signifi cantly higher than costs incurred at other BART applicable sources. A review of BART determina tions at other coal-fired units suggests that BART cost effectiveness values are typically in the range of less than $1.0 million to approximately $13 million per dv improvement. 14 

### The combination of low visibility impacts with LNB/OFA controls (less than 0.32 ∆ -dv at all Class I Areas) and the high cost of SCR controls contribute to the large incremental cost effectiveness of SCR at the Muskogee Station.

Table 3-10 Muskogee Units 4 & 5 NO x 

### 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) 98 th % ∆ -dv* (dv) ($/dv/yr)

Baseline -- -- 1.06 -- -- LNB/OFA $4,183,600 -- 0.32 -- -- LNB/OFA + SCR $61,591,200 $57,407,600 0.14 0.18 $319 MM/dv

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

each NOx retrofit control scenario. Modele d visibility impairment at the Caney Creek Class I Area was used for the cost effectiveness evaluation because m odeling indicated that the largest ∆ -dv improvements would occur at Caney Creek.

14 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy Co. (CO); Entergy White Bluff Power Plant (AR).Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

30 

### To determine whether alterative NOx control scenario s might provide more cost effective visibility improvements, cumulative impact modeling was conducted using a variety of SCR control scenarios. A goal of the cumulative impact mode ling was to determine whether alternative NOx control scenarios (i.e., SCR control on some, but not all of the OG&E BART applicable sources) would provide more cost effective NOx control. To quantify cost e ffectiveness, visibility impairment was modeled for several NOx control scenarios, while SO 2 

### and PM emissions were held constant at their respective baseline emissi on rates. Modeled NOx control scenarios are listed in Table 3-11. Results of the cumulative NOx impact modeling are summarized in Table 3-12.

Table 3-11 Cumulative NO x 

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

Unit Base Case Case 1 Case 2 Case 3 Case 4 NOx Controls (Emission Rate - lb/mmBtu) Muskogee Unit 4 LNB/OFA (0.15) SCR (0.07) SCR (0.07) SCR (0.07) SCR (0.07) Muskogee Unit 5 LNB/OFA (0.15) LNB/OFA (0.15) LNB/OFA (0.15) SCR (0.07) SCR (0.07) Sooner Unit 1 LNB/OFA (0.15) LNB/OFA (0.15) SCR (0.07) SCR (0.07) SCR (0.07) Sooner Unit 2 LNB/OFA (0.15) LNB/OFA (0.15) LNB/OFA (0.15) LNB/OFA (0.15) SCR (0.07) * For each case PM and SO 2 emissions were held constant at the baseline emission rates. Baseline emissions for SO 2

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



### Table 3-12 Cumulative NOx Visibility Modeling Results (Muskogee Units 4 & 5 and Sooner Units 1 & 2)

Modeled Visibility Impairment* Upper Buffalo Wilderness Area Caney Creek Wilderness Area Hercules-Glades Wilderness Area Wichita Mountains Wildlife Refuge NOx Control Technology

Option 98 th %
∆ -dv 98 th %
∆ -dv 98 th %
∆ -dv 98 th %
∆ -dv
Base Case 1.92 2.00 1.44 2.42
Case 1 1.94 1.99 1.43 2.41
Case 2 1.94 1.98 1.43 2.38
Case 3 1.95 1.97 1.46 2.35
Case 4 1.94 1.96 1.46 2.33

* ∆ -dv values included in this table reflect cumulative modeled contributions from NOx, SO 2 and PM emissions from both

the Sooner and Muskogee Stati ons. For each case PM and SO 2 emissions were held constant at their respective baseline emission rates, while NOx emissions varied depending the NOx control system on each unit (see Table 3-11). The dv values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO 2 ), which reflect modeled impacts from the Muskogee Station only for each individual pollutant.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

31 

### Results of the cumulative impact modeling sugg est that SCR controls would contribute only minimally to visibility improvement at the Class I Areas in comparison to LNB/OFA. Modeled impacts at the Wichita Mountains (at the 98 th 

### percentile ∆ -dv level) improved from 2.42 ∆ -dv with
LNB/OFA on all four units to 2.33 ∆ -dv with SCR on all four units, an improvement of approximately 4%. Modeled improvements were even lower at the other Class I Areas, and, in fact, modeled impairments at the Hercules-Glades and Upper Buffalo Wilderness Areas actually
increased with the addition of SCR controls. It is suspected that increased sulfuric acid mist emissions (associated with SO 2 

### to SO 3 

### conversion across the SCR) off-set reductions in controlled
NOx emissions.

3.6 Propose BART for NO x 

### Control at Muskogee Units 4 & 5

OG&E is proposing combustion contro ls (LNB/OFA), and a controlled NO x 

### emission rate of 0.15 lb/mmBtu (30-day average) as BART for Muskogee Units 4 & 5. This combination of control technologies represents the most cost effective technically feasible NO x 

### retrofit technology for the existing boilers. A controlled emission rate of 0. 15 lb/mmBtu is equivalent to the presumptive level for large tangentially-fired units firing subbitumi nous coals. The average cost effectiveness of LNB/OFA control systems is estimated to be in the range of $270/ton and $5.65 MM./dv/yr. These
cost effectiveness numbers are in-line with EPA’s cost estimate for BART controls on large EGUs, and are not of such magnitude as to exclude combustion controls as BART.

The addition of SCR control systems could provide incremental NO x 

### reductions; however, costs associated with SCR control are significant, and in cremental visibility improvements are limited. The average cost effectiveness of an SCR control system is estimated to be $3,251/ton and $66.9 MM/dv/yr. These costs are significantly higher than the average cost of NO x 

### control at similar sources. In the BART rule, EPA estimated that the cost of controls to meet the BART NO x 

### presumptive level on large EGUs “in most cases ra nge from just over $100 to $1000 per ton” (see, 70 FR 39135).

Furthermore, the modeled incremental visibility improvements associated with SCR control are only in the range of 0.08 to 0.18 ∆ -dv. Because of the limited improvement in modeled visibility impacts, the cost effectiveness of SCR control, on a $/dv basis is significant. Compared to the costs and modeled visibility impacts associated with LNB/OFA controls, the incremental cost effectiveness of SCR is estimated to be $16,611 /ton and more than $319 MM/dv/yr. Both costs are significantly higher than the expected cost of BART controls on large EGUs, and should preclude SCR from consideration as BART. Finally, cumulative impact modeling, summarized in Tables 3- 11 and 3-12, supports the conclusion that pos t-combustion SCR controls provide limited improvement in modeled visibility impairment.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

32 

### 4.0 BART ANALYSIS FOR MAIN BOILER SULFUR DIOXIDE (SO 2 

### )

SO X 

### emissions from coal combustion consis t primarily of sulfur dioxide (SO 2 

### ), with a much lower quantity of sulfur trioxide (SO 3 

### ) and gaseous sulfates. These compounds form as the organic and pyretic sulfur in the coal are oxidized during th e combustion process. On average, about 95% of the sulfur present in the fuel will be emitted as gaseous SO X, 15 

### Boiler size, firing configuration and boiler operations generally have little effect on the percent conversion of fuel sulfur to SO 2 

### .

The generation of SO 2 

### is directly related to the sulfur conten t and heating value of the fuel burned. The sulfur content and heating value of coal can vary dramatically depending on the source of the coal. Muskogee Units 4 & 5 utilize subbituminous coal as their primary fuel source. Heating values, ash contents, and sulfur contents for s ubbituminous fuel utilized at the Muskogee Station
are summarized in Table 4-1.

Table 4-1 Muskogee Generating Station Typical Coal Characteristics

Constituent Units Range Heating Value Btu/lb 8,490 - 8,900

Ash % 4.1 - 6.0

Sulfur Content % 0.20 – 0.37

Potential Uncontrolled SO 2 lb/mmBtu 0.50 – 0.86
* Coal characteristics included in this tabl e represent average values based on fuel

shipments to the Muskogee Station. Characteristics summarized in this table are not intended to limit the heating value, moisture c ontent, ash content, or sulfur content of fuels utilized at the Muskogee Station, as short-term coal characteristics may vary from the values summarized above.



### 4.1 Step 1: Identify Potentially Feasible SO 2 

### Control Options

Several techniques can be used to reduce SO 2 

### emissions from a pulverized coal-fired combustion
source. SO 2 

### control techniques can be divided into pre-combustion strategies and post-combustion
controls. SO 2 

### control options identified for potential app lication to Muskogee Units 4 & 5 are listed
in Table 4-2.

15 AP-42, Section 1.1 Bituminous and Sub-Bituminous Coal Combustion, page 1.1-3, September 1998.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

33 

### Table 4-2 Muskogee Generating Station List of Potential SO 2 

### Retrofit Control Options

Control Strategy/Technology

Pre-Combustion Controls Fuel Switching Coal Washing Coal Processing

Post-Combustion Controls

Wet Flue Gas Desulfurization

Wet Lime FGD

Wet Limestone FGD Wet Magnesium Enhanced Lime FGD Jet Bubbling Reactor FGD

Dual Alkali Scrubber Wet FGD with Wet Electrostatic Precipitator Dry Flue Gas Desulfurization Spray Dryer Absorber Dry Sorbent Injection Circulating Dry Scrubber



### 4.2 Step 2: Technical Feasibility of Potential Control Options

The technical feasibility of each potentia l control option is discussed below.

4.2.1 Pre-Combustion Control Strategy

The generation of SO 2 

### is related to the sulfur content and heating value of the fuel burned. The sulfur content and heating value of coal can vary dramatically depending on the source of the coal. Potentially feasible pre-combustion control strategies designed to reduce overall SO 2 

### emissions are described below.

4.2.1.1 Fuel Switching

One potential strategy for reducing SO 2 

### emissions is reducing the amount of sulfur contained in the coal. Muskogee Units 4 & 5 fire subbituminous coal as their primary fuel. Subbituminous coal has a relatively low heating value, low sulfur content, and low
uncontrolled SO 2 

### emission rate. Typical coal characteristics based on existingOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

34 

### subbituminous coal shipments to OG&E’s Musk ogee Generating Station are summarized in
Table 4-1 above.

Because of the relatively low sulfur conten t, subbituminous coals generate the lowest
uncontrolled SO 2 

### emissions. In fact, several coal-fire d utilities have switched to low-sulfur
coal as an SO 2 

### emission control strategy. Bituminous coals from mines in the Eastern and Midwestern U.S. generally have higher heati ng values but also have a significantly higher sulfur content. Lignites from the upper Midwest and Texas have a relatively low sulfur content (but higher than subbituminous) but also have high moisture contents and relatively low heating values.

Fuels currently used at the Muskogee Station generate low uncontrolled SO 2 

### emissions. Switching to alternative coals (i.e., 100% b ituminous coal or lignite) will not reduce potential uncontrolled SO 2 

### emissions or controlled SO 2 

### emissions from Muskogee Units 4
& 5. No environmental benefits accrue from burning an alternative coal; therefore, fuel switching is not considered a feasible option for this retrofit project.

4.2.1.2 Coal Washing

Coal washing, or beneficiation, is one pre- combustion method that has been used to reduce impurities in the coal such as ash and sulfur. In general, coal washing is accomplished by separating and removing inorganic impurities from organic coal particles. Inorganic impurities, including inorganic ash constituents and inorganic iron disulfide (FeS 2 

### or pyrite), are typically more dense than the coal pa rticles. This property is generally used in a wet cleaning process to separate coal particles from the inorganic impurities.

Each coal seam has different washability characteristics depending on the characteristics of the inorganic constituents. Based on inform ation available from the Kentucky Coal Council, inorganic sulfur in high-sulfur eastern bituminous coals may be reduced by 0.5 – 2.5% and inorganic ash may be reduced by 9 – 15% through coal washing. 16 

### Coal washing is generally done at the mine to maximize th e value of the coal and reduce freight charges to the power plant.

The coal washing process generates a solid wast e stream consisting of inorganic materials separated from the coal, and a wastewater stream that must be treated prior to discharge. Solids generated from wastewater processing a nd coarse material removed in the washing process must be disposed in a properly perm itted landfill. Solid wastes from coal washing

16 See, http://www.coaleducation.org/Ky_Coal_Fact s/coal_resources/coal_preparation.htm

.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

35 

### typically contain pyrites and other dense inorganic impurities including silica and trace metals. The solids are typically dewatered in a mechanical dewatering device and disposed
of in a landfill.

The wastewater stream generally consists of an acidic liquid slurry made up of water, uncombusted coal fines, and impurities in the coal, including calcium, trace metals, chloride, sulfate, and dissolved and suspended solids. 17 

### The wastewater slurry must be treated to remove solids, coal fines, and tr ace metals prior to discharge. Coal slurry treatment systems may include surface impoundments, mechanical dewatering systems, chemical processing systems, and/or thermal dryers.

While washing may be effective in removing ro ck inclusions from coal, including sulfurbearing pyrites, a significant amount of coal ma y also be lost in the washing process. An inherent consequence of coal washing, in a ddition to generating wastewater and solid waste streams, would be the need for the mine to process significantly more coal to make up for coal lost in the washing process.

Muskogee Units 4 & 5 are designed to utilize s ubbituminous coals. Based on a review of available information, no information w as identified regarding the washability or effectiveness of washing subbituminous coals. Subbituminous coals have a relatively high ash content and an excessive amount of fines, and significant dewatering equipment would be required to process and separate the fines from the wastewater stream. It is likely that the excess fines production, and the difficulti es associated with handling and dewatering the fines, have restricted the commercial viability of subbituminous coal washing. Furthermore, the coal washing process would generate significant solid and liquid waste streams that would require proper manageme nt and disposal. Based on a review of available information, there are currently no commercial subbituminous coal washing facilities, and washed subbituminous coals are not available through commercial channels. Therefore, coal washing is not considered an available retrofit control option for Muskogee
Units 4 & 5.

4.2.1.3 Coal Processing

Pre-combustion coal processing techniques have been proposed as one strategy to reduce the sulfur content of coal and help reduce uncontrolled SO 2 

### emissions. Coal processing

17 See, USEPA Report to Congress, Wastes from the Combustion of Fossil Fuels, Office of Solid Waste and Emergency Response, EPA 530-S-99-010, March 1999 (general composition of selected large-volume and low-volume wastes).Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

36 

### technologies are being developed to remove pot ential contaminants from the coal prior to

use.

These processes typically employ both mechan ical and thermal means to increase the quality of subbituminous coal and lignite by re moving moisture, sulfur, mercury, and heavy metals. In one process, raw coal from the mine enters a first stage separator where it is crushed and screened to remove large rock and rock material. 18 

### The processed coal is then passed on to an intermediate st orage facility. From the intermediate storage facility the coal goes to a thermal process. In this pro cess coal passes through pr essure locks into the thermal processors where steam at 460 o 

### F and 485 psi is injected. Moisture in the coal is
released under these conditions. Mineral inclusi ons are also fractured under thermal stress, removing both included rock and sulfur-forming pyrites. After it has been treated for a sufficient time in the main pr ocessor, the coal is discharged into a second pressurized lock. The second pressurized lock is vented into a water condenser to return the processor to atmospheric pressure and to flash cool the coal to approximately 200 o 

### F. Water is removed from the coal at various points in the process. This water, along with condensed process steam, is either reused within the pro cess or treated prior to being discharged.

To date, the use of processed fuels has only been demonstrated with test burns in a pulverized coal-fired boiler. No coal-fired boilers have utilized processed fuels as their primary fuel source on an on-going, long-term b asis. Although burning processed fuels, or a blend of processed fuels, has been tested ina pulverized coal-fired boiler, using processed fuels in Muskogee Units 4 & 5 would require significant research, test burns, and extended trials to identify potential impacts on plant systems, including the boiler, material handling, and emission control systems. Therefore, processed fuels are not considered commercially available, and will not be analyzed further in this BART analysis.

4.2.2 Post-Combustion Flue Gas Desulfurization

Over the past decade, post-combustion flue g as desulfurization (FGD) has been the most frequently used SO 2 

### control technology for large pulveri zed coal-fired utility boilers. FGD systems typically have been installed on boilers firing high-sulfur bituminous coals. FGD systems, including wet scrubbers and dry scrubbe rs, have been designed to effectively and economically remove SO 2 

### from pulverized coal-fired utility boiler flue gas. FGD systems with a potential applicability to Muskogee Units 4 & 5 are described below.

18 The coal processing description provided herein is based on the K-Fuel ® process under development by KFx, Inc.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

37 

### 4.2.2.1 Wet Scrubbing Systems

Wet FGD technology is an established SO 2 

### control technology. Wet scrubbing systems offered by vendors may vary in design; however, all wet scrubbing systems utilize an alkaline scrubber slurry to remove SO 2 

### from the flue gas. Design variations may include changes to increase the alkalinity of the scrubber slurry, increase slurry/SO 2 

### contact, and minimize scaling and equipment problems.

All wet scrubbing FGD systems use an alkaline slurry that reacts with SO 2 

### in the flue gas to form insoluble calcium sulfite (CaSO 3 

### ) and calcium sulfate (CaSO 4 

### ) salts. Wet FGD systems may be generally categorized as lime (CaO) or limestone (CaCO 3 

### ) scrubbing systems. The scrubbing process and equipment fo r either lime- or limestone scrubbing is similar. The alkaline slurry consisting of hydrated lime or limestone may be sprayed countercurrent to the flue gas, as in a spray tower, or the flue gas may be bubbled through the alkaline slurry as in a jet bubbling reactor . Equations 4-1 through 4-5 summarize the chemical reactions that take place within the wet scrubbing systems to remove SO 2 

### from flue gas.

SO 2 

### + CaO + 1⁄2H 2 

### O → CaSO 3 

### •1⁄2H 2 

### O ↓ (4-1) SO 2 

### + CaO + 2H 2 

### O → CaSO 4 

### •2H 2 

### O ↓ (4-2) SO 2 

### + CaCO 3 

### + H 2 

### O → CaSO 3 

### •H 2 

### O ↓ + CO 2 

### (4-3) CaSO 3 

### + 1⁄2O 2 

### + 2H 2 

### O → CaSO 4 

### •2H 2 

### O ↓ (4-4) SO 2 

### + 2H 2 

### O + 1⁄2 O 2 

### + CaCO 3 

### → CaSO 4 

### •2H 2 

### O ↓ + CO 2 

### (4-5)

Potentially feasible wet scrubbing systems are described below.

Wet Lime Scrubbing

The wet lime scrubbing process uses an alkaline slurry made by adding lime (CaO) to water. The alkaline slurry is spraye d in the absorber and reacts with SO 2 

### in the flue gas.
Insoluble CaSO 3 

### and CaSO 4 

### salts are formed in the chemic al reaction that occurs in the scrubber (see equations 4-1 and 4-2), and are removed as a solid waste by-product. The waste by-product is made up of mainly CaSO 3 

### , which is difficult to dewater. Solid waste by-products from wet lime scrubbing are typi cally managed in dewatering ponds and
landfills.

Wet Limestone Scrubbing

Limestone scrubbers are very similar to lime scrubbers except limestone (CaCO 3 

### ) is mixed with water to formulate the alkali scrubber slurry. SO 2 

### in the flue gas reacts with the limestone slurry to form insoluble CaSO 3 

### and CaSO 4 

### which is removed as a solid waste by-Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

38 

### product (see equations 4-3 and 4-4). The use of limestone instead of lime requires different feed preparation equipment and a higher liquid-to-gas ratio. The higher liquid-to-gas ratio typically requires a larger absorbing unit. Th e limestone slurry process also requires a ball
mill to crush the limestone feed.

Forced oxidation of the scrubber slurry can be u sed with either the lime or limestone wet FGD system to produce gypsum solids instead of the calcium sulfite by-product. Air blown into the reaction tank provides oxygen to convert most of the calcium sulfite (CaSO 3 

### ) to relatively pure gypsum (calcium sulfate) as show n in equation 4-4. Forced oxidation of the scrubber slurry provides a more stable by-pr oduct and reduces the potential for scaling in the FGD. The gypsum by-product from this pro cess must be dewatered, but may be salable thus reducing the quantity of solid waste that needs to be landfilled.

Wet scrubbing systems using limestone as the reactant have demonstrated the ability to achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing high-sulfur bituminous coals. Wet lime and limestone FGD control systems with forced oxidation are technically feasible SO 2 

### retrofit technologies. However, wet scrubbing systems have not been used on large boilers firing subbituminous coals, and the actual control efficiency of a wet FGD system will depend on several factors, including the
uncontrolled SO 2 

### concentration entering the system. Based on engineering judgment it is expected that a wet lime or limestone FGD control system with forced oxidation could achieve average controlled SO 2 

### emissions in the range of 0.08 lb/mmBtu (30-day rolling average) on Muskogee Units 4 & 5.

Wet lime and wet limestone scrubbing systems will achieve the same SO 2 

### control efficiencies; however, the higher cost of lime typically makes wet limestone scrubbing the more attractive option. For this reason, wet li me scrubbing will not be evaluated further in
this BART determination.

Wet Magnesium Enhanced Lime Scrubbing

Magnesium Enhanced Lime (MEL) scrubbers are another variation of wet FGD technology. Magnesium enhanced lime typically contains 3% to 7% magnesium oxide (MgO) and 90 – 95% calcium oxide (CaO). The presence of magnesium effectively
increases the dissolved alkalinit y, and consequently makes SO 2 

### removal less dependent on
the dissolution of the lime/limestone. In nor mal lime/limestone spray-tower operation the
amount of SO 2 

### absorbed depends principally upon the soluble-alkali content of the absorbing slurry. When magnesium is present, the soluble alkali level of the absorbent increases primarily because of the presence of sulfite and bicarbonate salts of magnesium.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

39 

### As these magnesium alkalies are more soluble than the corresponding calcium alkalies,
there is an increase in the SO 2 

### absorption capacity of the slurry. 19



### Commercial operation of wet FGD systems has shown that soluble Mg in the absorbing slurry can improve SO 2 

### removal efficiency. 20 

### MEL scrubbers have been installed on coalfired utility boilers located in the Ohio River Valley. 21 

### Most are located in a corridor from Pittsburgh, Pennsylvania to Evansville, Indiana, and use a reagent that naturally contains approximately 5% MgO. Because of the in creased alkalinity in the scrubbing liquid, MEL wet scrubbing systems have demonstrated the ability to achieve SO 2 

### removal efficiencies equivalent to wet lime/limestone scrubbers using smaller absorber towers.

Solids from the MEL FGD process consist primarily of calcium sulfite and magnesium sulfite solids. Dewatering the sulfite solid s from an unoxidized MEL FGD system can be difficult, and produces a filter cake consisting of approximately 40-50% solids. Typically, unoxidized MEL FGD filter cake is fixed using fly ash and landfilled. This continues to be
one of the drawbacks of the unoxidized M EL FGD process. Systems to oxidize the MEL solids to produce a usable gypsum byproduct c onsisting of calcium sulfate (gypsum) and magnesium sulfate continue to be developed. 22



### Wet limestone FGD control systems can be designed to achieve the same control efficiencies as the magnesium enhanced limestone systems. However, to achieve the same control efficiencies, limestone-based system s require a higher liquid-to-gas ratio, and therefore larger absorber towers. Coal-fire d units equipped with MEL FGD typically fire high-sulfur eastern bituminous coal and use locally available reagent. There are no subbituminous-fired units equipped with a MEL-FGD system.

Because MEL-FGD systems have not been used on subbituminous-fired boilers, and because of the cost and limited availability of magnesium enhanced reagent (either naturally occurring or blended), and because limestone-based wet FGD control systems can be designed to achieve the same control effici encies as the magnesium enhanced systems, MEL-FGD control systems will not be evaluated further as a commercially available retrofitted control system.

19 Combustion Fossil Power, page 15-43.
20 Combustion Fossil Power, page 15-42.
21 Nolan, P.S., “Flue Gas Desulfurization Technolo gies for Coal-Fired Powe r Plant,” Coal-Tech 2000 International Conference, November 13-14, 2000.
22 See, Benson, L., Babu, M., Smith, K., “New Magnesium-Enhanced Lime FGD Process,” Dravo Lime, Inc. – Technology Center.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

40 

### Jet Bubbling Reactor

Another variation of the wet FGD control system is the jet bubbling reactor (JBR). Unlike the spray tower wet FGD system s, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, in the JBR-F GD flue gas is bubbled through a limestone slurry. Spargers are used to create tur bulence within the reaction tank and maximize contact between the flue gas bubbles and scrubbing slurry. SO 2 

### in the flue gas reacts with the limestone slurry to form insoluble CaSO 3 

### and CaSO 4 

### which is removed as a solid waste by-product (see equations 4-3, 4-4, and 4-5). Flue gas exits from the reaction vessel through mist eliminators to reduce carryover of the reactant.

Although the reaction vessel used to contact fl ue gas with the scrubbing slurry is different than the spray tower used in a conventiona l wet FGD system, JBR-FGD systems use the same reaction chemistry to remove SO 2 

### from the flue gas. JBR-FGD systems do not require the large slurry pumps associated w ith other wet FGD technologies; however, auxiliary power is shifted to larger fans, boos ter fans, agitators, and oxidation air blowers to accommodate the larger pressure drop through the system.

There are currently a limited number of commercially operating JBR-WFGD control systems installed on coal-fired utility units in the U.S. A JBR-WFGD control system was installed at Georgia Power’s 100 MW coal-fired Yates plant in 1992. Based on publicly available emissions data, the Yates Plant has an average inlet SO 2 

### concentration of approximately 3,500 ppm, and has achieved average SO 2 

### removal efficiencies of approximately 93%. In addition to the Yates Plan t, a JBR control system has been in use at the 40 MW equivalent Abbott Steam plant at the University of Illinois.

Most of the JBR-WFGD control experience has been in Japan. Chiyoda Corporation has installed JBR-WFGD systems on several coal-fired plants overseas. Based on information available on Chiyoda’s website, a majority of the plants equipped with JBR-WFGD are smaller units (e.g., less then 200 MW); however, Chiyoda lists JBR-WFGD systems in operation on three plants located overseas in the 600 MW range. Commercial deployment of the JBR-WFGD control system continues to develop in the U.S. A project experience list available from Chiyoda identifies several U.S. power plants that have decided to install JBR-WFGD control systems, with control sy stem startup dates between 2008 and 2010.

Although the commercial deployment of the control system continues, there is still a very limited number of operating units in the U.S. Furthermore, coal-fired boilers currently considering the JBR-WFGD control system are all located in the eastern U.S., and all fire eastern bituminous coals. The control syst em has not been proposed as a retrofitOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

41 

### technology on any large subbituminous coal-fired boilers. However, other than scale-up issues, there do not appear to be any ove rriding technical issues that would exclude application of the control technology on a large subbituminous coal-fired unit.

Assuming that the JBR-WFGD control system is commercially available for Muskogee Units 4 & 5, the JBR is essentially a wet FGD scrubbing system. Unlike the spray tower systems, where the scrubbing slurry contacts the flue gas in a countercurrent reaction tower, in the JBR-WFGD flue gas is bubbled through the limestone slurry. SO 2 

### in the flue gas reacts with the limestone slurry to form in soluble calcium sulfate and calcium sulfite, which is removed as a solid waste by-product. Although the reaction vessel used to contact flue gas with the scrubbing slurry uses a differe nt design, the reaction chemistry to remove
SO 2 

### from the flue gas is the same for all wet FGD designs.

There are no data available to conclude that the JBR-WFGD control system will achieve a higher SO 2 

### removal efficiency than a more traditional spray tower WFGD design, especially on units firing low-sulfur subbitumi nous coal. Furthermore, the costs associated
with JBR-WFGD and the control efficiencies achievable with JBR-WFGD are similar to
the costs and control efficiencies achievable with spray tower WFGD control systems. Therefore, the JBR-WFGD will not be evaluate d as a unique retrofit technology, but will be
included in the overall assessment of WFGD controls.

Dual-Alkali Wet Scrubber

Dual-alkali scrubbing is a desulfurization pr ocess that uses a sodium -based alkali solution
to remove SO 2 

### from combustion exhaust gas. The process uses both sodium-based and calcium-based compounds. The sodium-based reagent absorbs SO 2 

### from the exhaust gas, and the calcium-based solution (lime or limestone ) regenerates the spent liquor. Calcium sulfites and sulfates are precipitated and discar ded as sludge, while the regenerated sodium
solution is returned to the absorber loop.

The dual-alkali process requires lower liquid-to-gas ratios then scrubbing with lime or limestone. The reduced liquid-to-gas ratios gene rally mean smaller reaction units, however additional regeneration and sludge proc essing equipment is necessary.

The sodium-based scrubbing liquor, typically consisting of a mixture of sodium hydroxide,
sodium carbonate and sodium sulfite, is an efficient SO 2 

### control reagent. However, the high cost of the sodium-based chemicals limits the feasibility of such a unit on a large utility boiler. In addition, the process generat es a less stable sludge that can create material handling and disposal problems.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

42 

### It is projected that a dual-alkali system could be designed to achieve SO 2 

### control similar to a limestone-based wet FGD. However, becau se of the limitations discussed above, and because dual-alkali systems are not currently commercially available, dual-alkali scrubbing systems will not be addressed further in this BART determination.

Wet FGD with Wet Electrostatic Precipitator

Wet FGD systems can result in increased emissions of condensable particulates and acid gases. In particular, SO 3 

### generated in the unit’s boiler can react with moisture in the wet FGD to generate sulfuric acid mist. Sulfur ic acid mist emissions from boilers firing high sulfur coals and equipped SCR and wet FGD can contribute to significant opacity problems
if the H 2 

### SO 4 

### concentration in the stack gas exceeds approximately 15 ppm. 23



### Wet electrostatic precipitation (WESP) has been proposed on other coal-fired projects as one technology to reduce sulfuric acid mist em issions from coal-fired boilers. WESPs have been proposed for boilers firing high-sulfur eastern bituminous coals controlled with wet
FGD. 24 

### WESP has been demonstrated as an eff ective control technology to abate sulfuric acid mist emissions from industrial applications with relatively low flue gas flow rates and high acid mist concentrations, such as sulfuric acid plants. However, until recently, the technology has not been applied to the u tility industry because of the high gas flow
volumes and low acid mist concentrations associated with utility flue gas.

In a utility application, the WESP would be located downstream from the wet FGD to
remove micron-sized sulfuric acid aerosols from the flue gas stream as a condensable particulate. Electrostatic precipitation consists of three steps: (1) charging the particles to be collected via a high-voltage electric dischar ge, (2) collecting the particles on the surface of an oppositely charged collection electrode surface, and (3) cleaning the surface of the collecting electrode. In a WESP system, the collecting electrodes are typically cleaned with a liquid wash. Particulate mass loading, particle size distribution, particulate electrical resistivity, and precipitator voltage and curre nt will influence ESP performance. The wet cleaning mechanism can also affect the nature of the particles that can be captured, and the performance efficiencies that can be achieved.

23 See, Duellman, D.M., Erickson, C.A., Licata, T., Oper ating Experience with SCR’s and High Sulfur Coals & SO 3 Plumes , presented at the ICAC NOx Forum, February 2002.

24 See for example, the Thoroughbred Generating Station PSD Permit Application submitted to the Kentucky Department of Environmental Protection, and the Prairie States Energy Center PSD Permit Application submitted to the Illinois Environmental Protection Agency.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

43 

### WESP has not been widely used in utility applications, and has only been proposed onboilers firing high sulfur coals and equipped with SCR. Muskogee Units 4 & 5 fire lowsulfur subbituminous coal. Based on the fuel characteristics listed in Table 4-1, and assuming 1% SO 2 

### to SO 3 

### conversion in the boiler, potential uncontrolled H 2 

### SO 4 

### emissions from Muskogee Units 4 & 5 will only be approxi mately 5 ppm. This emission rate does not take into account inherent acid gas removal associated with alkalinity in the subbituminous coal fly ash. Based on engin eering judgment, it is unlikely that a WESP control system would be needed to mitigate visible sulfuric acid mist emissions from Muskogee Units 4 & 5, even if WFGD control was installed.

WESPs have been proposed to control conde nsable particulate emissions from boilers firing a high-sulfur bituminous coal and equipped with SCR and wet FGD. This combination of coal and control equipment r esults in relatively high concentrations of sulfuric acid mist in the flue gas. WESP control systems have not been proposed on units firing subbituminous coals, and WESP would have no practical application on a subbituminous-fired units. Therefore, th e combination of WFGD+WESP will not be
evaluated further in this BART determination.

Wet FGD Scrubbing - Conclusions

Wet FGD technology is an established SO 2 

### control technology. Wet scrubbing systems have been designed to utilize various al kaline scrubbing solutions including lime, limestone, and magnesium-enhanced lime. Wet scrubbing systems may also be designed with spray tower reactors or reaction vessels (e .g., jet bubbling reactor). Although the flue gas/reactant contact systems may vary, the chemistry involved in all wet scrubbing systems is essentially identical. A large majority of the wet FGD systems designed to remove SO 2 

### from existing high-sulfur utility boilers have been designed as wet limestone scrubbers with spray towers and forced oxidation systems.

Wet scrubbing systems using limestone as the reactant have demonstrated the ability to achieve control efficiencies of greater than 95% on large pulverized coal-fired boilers firing high-sulfur bituminous coals. The chemistry of wet scrubbing consists of a complex series of kinetic and equilibrium-controlled reactions occurring in the gas, liquid and solid phases. In general, the amount of SO 2 

### removed from the flue gas is governed by the vapor-liquid equilibrium between SO 2 

### in the flue gas and the absorben t liquid. If no soluble alkaline species are present in the liquid, the liq uid quickly becomes saturated with SO 2 

### and absorption is limited. 25 

### Likewise, as the flue gas SO 2 

### concentration goes down, absorption

25 Combustion Fossil Power – A Reference Book on Fuel Burning and Steam Generation , edited by Joseph P. Singer, Combustion Engineering, Inc., 4 th ed., 1991 (pp. 15-41).Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

44 

### will be limited by the SO 2 

### equilibrium vapor pressure. Therefore, high control efficiencies would not be expected on a boiler firing low sulfur coals because of the reduced SO 2 

### concentration in the boiler flue gas.

Although WFGD control systems have not been used on subbituminous coal-fired units there are no technical limitations that would preclude its use on Muskogee Units 4 & 5. Therefore, WFGD is determined to be a technically feasible SO 2 

### control retrofit technology. Based on the fuel characteristics listed in Table 4-1, taking into consideration
the reduced SO 2 

### concentration in the flue gas and reduced SO 2 

### loading to the scrubbing system, and allowing a reasonable operati ng margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, and minor equipment upsets)
it is concluded that a WFGD retrofit cont rol system could achieve a controlled SO 2 

### rate of 0.08 lb/mmBtu (30-day average).

4.2.2.2 Dry Flue Gas Desulfurization

Another scrubbing system that has been designed to remove SO 2 

### from coal-fired combustion gases is dry scrubbing. Dry scrubbing involves the introduction of dry or hydrated lime slurry into a reaction tower where it reacts with SO 2 

### in the flue gas to form calcium sulfite solids (see equations 4-1 and 4-2). Dry scrubbing includes a separate lime preparation system and reaction tower. Unlik e wet FGD systems that produce a slurry byproduct that is collected separately from th e fly ash, dry FGD systems produce a dry byproduct that must be removed with the fly ash in the particulate control equipment. Therefore, dry FGD systems must be located upstream of the particulate control device to remove the reaction products and excess reactant material.

Various dry FGD systems have been designed for use with pulverized coal-fired boilers. Dry scrubbing systems that may be technically feasible on Muskogee Units 4 & 5 are
discussed below.

Spray Dryer Absorber

Spray dryer absorber (SDA) systems have been used in large coal-fired utility applications. SDA systems have demonstrated the ability to effectively reduce uncontrolled SO 2 

### emissions from pulverized coal units.

The typical spray dryer absorber uses a slurry of lime and wate r injected into the tower to
remove SO 2 

### from the combustion gases. The towers must be designed to provide adequate
contact and residence time between the exhaus t gas and the slurry to produce a relativelyOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

45 

### dry by-product. The process e quipment associated with a spra y dryer typically includes an alkaline storage tank, mixing and feed tanks, an atomizer, spray chamber, particulate control device and a recycle system. The recycle system collects solid reaction products and recycles them back to the spray dryer feed system to reduce alkaline sorbent use.

Various process parameters affect the efficiency of the SDA process including: the type and quality of the additive used for the reactant, reactant stoichiometric ratio, how close the SDA is operated to saturation conditions, and th e amount of solids product recycled to the atomizer. The control efficiency of a SDA system is limited to approximately 94% of the
SO 2 

### loading to the system, and is a function of numerous operating variables including gasto-liquid contact and system operating temperatures.

In a dry FGD system, the amount of reactant slurry introduced to the spray dryer must be controlled to insure that the reaction produc ts leaving the absorber vessel are dry. Therefore, the outlet temperature from the absorber must be maintained above the saturation temperature. SDA systems are typically designed to operate within approximately 30 o 

### F adiabatic approach to the saturation temperature. Operating closer to the adiabatic saturation temperature allows higher SO 2 

### control efficiencies; however, outlet temperatures too close to the saturation temperature will result in severe operating problems including reactant build-up in the absorber modules, blinding of the fabric filter bags, and corrosion in the fa bric filter and ductwork.

High SO 2 

### removal efficiencies in a SDA are also dependent upon good gas-to-liquid contact. Reactant spray nozzle designs are vendor-specific; however, both dual-fluid nozzles and rotary atomizers have been used in large coal-fired boiler applications.

Dual-fluid nozzles (slurry and atomizing air) typically consist of a stainless steel head with multiple, ceramic two-fluid nozzle inserts. Slur ry enters through the nozzle head and is distributed to the nozzle inserts. Atomizing air enters concentrically into a reservoir in the nozzle head and mixes with the slurry. Th e atomizing air expands as it passes through the air holes and nozzle exit. This expansion creates the shear necessary to atomize the slurry. Each nozzle is provided with a feed lance assembl y consisting of a concentric feed pipe (air around slurry), hose connections, and the nozzle head. The feed lance assembly is inserted down through the SDA roof through a nozzle shroud assembly.

Rotary atomizers are comprised basically of a high-speed rotating atomizer wheel coupled to a drive device and speed-increasing gear box. Because the reactant slurry is abrasive, the atomizing nozzles typically consist of a stainl ess steel head and multiple abrasion-resistantOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

46 

### ceramic nozzle inserts. The rotary atomizer s are inserted down through the SDA roof. The reactant slurry is atomized as it passe s through the rapidly rotating nozzles.

The atomizing nozzle assembly (either the duel-fluid feed lance assembly or the rotary atomizer assembly) is typically located in the SDA penthouse, and flange mounted to the
roof of the absorber vessel. Overhead cranes or hoists located in the penthouse can be used
to remove the nozzle assemblies from the absorb er vessel for repair and maintenance.
Because of the abrasive nature of the react ant slurry, nozzle assemblies must be removed and replaced on a routine basis. Depending on the design of the SDA system, one or more spare nozzle assemblies will be available for u se. The nozzle assemblies may be changed without shutting down the SDA system. During that time period, the SDA may not be able
to maintain maximum control efficiencies.

SDA control systems are a technically feasible and commercially available retrofit technology for Muskogee Units 4 & 5. Based on the fuel characteristics listed in Table 4-1 and allowing a reasonable margin to account for normal operating conditions (e.g., load changes, changes in fuel characteristics, reactant purity, atomizer change outs, and minor equipment upsets) it is concluded that dry FGD designed as SDA could achieve a
controlled SO 2 

### emission rate of 0.10 lb/mmBtu (30-day average) on an on-going long-term
basis.

Dry Sorbent Injection

Dry sorbent injection involves th e injection of powdered absorbent directly into the flue gas exhaust stream. Dry sorbent injection systems are simple systems, and generally require a sorbent storage tank, feeding mechanism, transfer line and blower and an injection device. The dry sorbent is typically injected countercu rrent to the gas flow. An expansion chamber is often located downstream of the injection poin t to increase residence time and efficiency. Particulates generated in the reaction are cont rolled in the system’s particulate control
device.

Typical SO 2 

### control efficiencies for a dry sorbent injection system are generally around 50%. Because the control efficiency of the dr y sorbent system is lower then the control efficiency of either the wet FGD or SDA, the system will not be evaluated further.

Circulating Dry Scrubber

A third type of dry scrubbing system is the circulating dry scrubber (CDS). A CDS system uses a circulating fluidized bed of dr y hydrated lime reagent to remove SO 2 

### . Flue gasOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

47 

### passes through a venturi at the base of a vertical reactor tower and is humidified by a water mist. The humidified flue gas then enters a fluidized bed of powdered hydrated lime where
SO 2 

### is removed. The dry by-product produced by this system is similar to the spray dry absorber by-product, and is routed with the flue gas to the particulate removal system.

Based on engineering judgment and informa tion available from equipment vendors, the CDS flue gas desulfurization system should be capable of achieving SO 2 

### removal
efficiencies similar to those achieved with a spray dryer absorber. In fact, vendors advise that the CDS system is capable of achievi ng even higher removal efficiencies with increased reactant injection rates and higher Ca/S stoichiometric ratios. However, to date the CDS has had limited application, and h as not been used on large pulverized coal boilers. The largest CDS unit, in Austria, is on a 275 MW size oil-fired boiler burning oil with a sulfur content of 1.0 to 2.0%. Op erating experience on smaller pulverized coal boilers in the U.S. has shown high lime consum ption rates, and significant fluctuations in
lime utilization based on inlet SO 2 

### loading. 26 

### Furthermore, CDS systems result in high particulate loading to the unit’s particulate control device.

Based on the limited application of CDS dry scrubbing systems on large boilers, it is likely that OG&E would be required to conduct extensive design engineering to scale up the technology for boilers the size of Muskogee Units 4 & 5, and that OG&E would incur significant time and resource penalties evaluati ng the technical feasibility and long-term effectiveness of the control system. Because of these limitations, CDS dry scrubbing systems are not currently commercially available as a retrofit control technology for Muskogee Units 4 & 5, and will not be evaluate d further in this BART determination.

The results of Step 2 of the SO 2 

### BART analysis (technical feasibility analysis of potential SO 2 

### control technologies) are summarized in Table 4-3.

26 See, Lavely, L.L., Schild, V.S., and Toher, J., “F irst North American Circulating Dry Scrubber and Precipitator Remove High Levels of SO2 and Particulate”,Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

48 

### Table 4-3 Muskogee Units 4 & 5 Technical Feasibility of Potential SO 2 

### Control Technologies

In Service on Existing PC

Boilers? Control Technology SO 2 Emission Rate

(lb/mmBtu) Yes No In Service on Other Combustion

Sources? Technically Feasible Retrofit Technology for Muskogee Units 4 & 5? Fuel Switching NA X PCs have been designed to burn a variety of fuels. Not technically feasible. The fuel currently used is low-sulfur and fuel switching will not reduce controlled SO 2 emissions.
Coal Washing NA X Washing has notbeen used on subbituminous coals. Not technically feasible nor commercially available. Coal washing has not been used on subbituminous coals and washed subbituminous coal is not commercially available. Furthermore, it is unlikely that firing a washed subbituminous coal would result in any significant reduction in controlled SO 2 emissions.
Coal Processing -- X Processed coal has been demonstrated in PC boilers. Not technically available nor commercially available. Processed coal has not been demonstrated on a long-term basis as the primary flue in a PC boiler, and is not commercially available as a retrofit technology. Wet FGD (lime, limestone, or magnesium enhanced lime) 0.08 lb/mmBtu (approx. 40 ppmvd @ 3% O 2 ) X Wet FGD has been used on bituminous coal-fired PC boilers. Technically feasible, however limited commercial experience with wet FGD on large subbituminous fired units.

Jet Bubbling Reactor Wet FGD Control System 0.08 lb/mmBtu (approx. 40 ppmvd @ 3% O 2 ) X JBR-FGD systems are in use on a limited number of coal-fired boilers. Technically feasible, but may not be commercially available forMuskogee Units 4 & 5 (large subbituminous fired units). Because there is no operating experience with JBR-WFGD systems on large subbituminous-fired units, the control system was evaluated as an alternative WFGD control system.

Dual-Alkali Wet Scrubber NA X In use at a limitednumber of coalfired facilities. Not commercially available.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

49 Table 4-3 continued:
In Service on Existing PC

Boilers? Control Technology SO 2 Emission Rate

(lb/mmBtu) Yes No In Service on Other Combustion

Sources? Technically Feasible Retrofit Technology for Muskogee Units 4 & 5?

Wet FGD with WESP NA X The WESP control system is in use at a limited number ofhigh-sulfur coalfired units. Not technically feasible nor commercially available for units firing a low-sulfur subbituminous coal.

Dry FGD – Spray Dryer Absorber 0.10 lb/mmBtu (approx. 50 ppmvd @ 3% O 2 ) X In use on subbituminous coalfired boilers. Technically feasible.

Dry Sorbent Injection 0.4 lb/mmBtu (approx. 200 ppmvd @ 3% O 2 ) X Dry sorbent injection has been used on a limitednumber of coalfired units. Technically feasible, but not as effective as other SO 2 control options therefore excluded as BART.

Circulating Dry Scrubber NA X CDS is in use at a limited number of coal-fired boilers. CDS Dry FGD was determined not to be commercially available for Muskogee Units 4 & 5 (large sub- bituminous fired units). In addition, there is no commercial experience with units similar toMuskogee Units 4 & 5, so CDSDFGD was excluded as BART.



### Step 3: Rank the Technically Feasible SO 2 

### Control Options by Effectiveness

Both technically feasible SO 2 

### retrofit technologies (i.e., Wet- and Dry-FGD) are capable of meeting the BART presumptive level of 0.15 lb/mmBtu. However, in order to evaluate the cost effectiveness of each control technology, annual em issions and costs were estimated at the design emission limits of 0.08 lb/mmBtu for WFGD and 0.10 lb/mmBtu for DFGD. This approach was
taken in order to determine whether either contro l technology was cost effective at the anticipated design emission rate. The technically feasible SO 2 

### control technologies are listed in Table 4-4 in descending order of control efficiency ba sed on anticipated design emission rates.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

50 

### Table 4-4 Summary of Technically Feasible SO 2 

### Control Technologies

SO 2 Emission Rate* (lb/mmBtu) Control Technology

Muskogee 4 Muskogee 5

Wet FGD 0.08 0.08
Dry FGD – Spray Dryer Absorber 0.10 0.10

Baseline Uncontrolled SO 2 Emissions 0.80 0.85 * Emission rates are based on 30-day rolling averages that can be achieved on

an on-going long-term basis under all normal operating conditions.



### 4.3 Step 4: Evaluate the Technically Feasible SO 2 

### Control Technologies

Two post-combustion flue gas desulfurization control system designs (WFGD and SDA) are technically feasible and capable of achieving very low SO 2 

### emission rates. An evaluation of the economic, energy and environmental impacts associated with each control system is provided
below.

4.3.1 Economic Evaluation Summarized in Table 4-5 are the expected controlled SO 2 

### emission rates and annual SO 2 

### mass emissions associated with each technically feasibl e control technology. Table 4-6 presents the capital costs and annual operating costs associat ed with building and operating each control system on Muskogee Units 4 & 5. Table 4-7 s hows the average annual and incremental cost
effectiveness for each SO 2 

### control system.

Table 4-5 Muskogee Units 4 & 5 Annual SO 2 

### Emissions (per boiler)

Muskogee 4 Muskogee 5 Control Technology SO 2 Emissions

(lb/mmBtu) Emissions (tpy)* Reduction in Emissions (tpy)* Emissions (tpy)* Reduction in Emissions (tpy)* Wet FGD 0.08 1,728 15,554 1,728 16,634 Dry FGD – SDA 0.10 2,160 15,122 2,160 16,202 Baseline 0.80 (Unit 4) 0.85 (Unit 5) 17,282 -- 18,362 --

* Annual emissions and annual emission reductions for the BART analysis were calculated based on a full

load heat input of 5,480 mmBtu/hr (per boiler), and assuming 7,884 hours/year (90% capacity factor).Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

51 

### Table 4-6 Muskogee Units 4 & 5 SO 2 

### Emission Control System Cost Summary (each boiler)*

Control Technology Total Capital Investment ($) Total Capital Investment ($/kW-gross) Annual Capital Recovery Cost ($/year) Annual Operating Costs ($/year) Total Annual Costs ($/year) Wet FGD $418,567,000 $732 $35,917,500 $41,412,800 $77,067,900 Dry FGD – SDA $373,106,000 $708 $32,016,400 $39,051,500 $71,330,300 * Capital costs for SO 2 control systems will be essentially equal for Units 4 and 5. Capital costs include the cost of

major components and indirect installation costs such as foundations, mechanical erec tion, electrical, piping, and insulation for the control system. Capital costs for the Wet FGD scenario include the cost of new chimneys on both units, and capital costs for the Dry FGD scenario include the cost of a post-scrubber fabric filter baghouse.



### Table 4-7 Muskogee Units 4 & 5 SO 2 

### Emission Control System Cost Effectiveness (total for two boilers)

Control Technology Total Annual Cost*

($/year) Annual Emission Reduction

(tpy) Average Annual Cost Effectiveness ($/ton) Incremental Annual Cost Effectiveness** ($/ton) Wet FGD $154,135,800 32,188 $4,789 $13,281 Dry FGD – SDA $142,660,600 31,324 $4,554 -- * Total annual costs in this table reflect total costs (c apital and O&M) for both units. Costs are slightly more

than double the tota l annual costs for Unit 4 because of the hi gher baseline emission rate on Unit 5. **Incremental cost effectiveness of the wet FGD control systems comp ared to the SDA control system.



### The average cost effectiveness of the potentially feasible SO 2 

### control technologies range from approximately $4,554/ton for dry FGD to $4,789/ton for wet FGD. To support the BART rulemaking process, EPA calculated the cost effectiveness of both wet- and dry-FGD systems. Based on EPA’s analysis, the average cost e ffectiveness for controlling all BART-eligible EGUs greater than 200 MW without existing SO 2 

### controls was estimated at $919 per ton SO 2 

### removed. Moreover, the range of cost effectiv eness numbers demonstrated that the majority of these units could meet the presumptive SO 2 

### emission limits at a cost of $400 to $2,000 per ton
of SO 2 

### removed (see, 70 FR 39133). Therefore, the average effectiveness of SO 2 

### removal at Muskogee Units 4 & 5 is more than double the average cost effectiveness calculated by EPA
for SO 2 

### control on large EGUs. EPA’s calculation of average cost effectiveness included specific estimates for the Muskogee Generating St ation. EPA estimated that the least cost alternative for Muskogee would be dry FGD w ith estimated cost effectiveness ranging from $1,690/ton to $1,697/ton. As demonstrated by Table 4-7, the actual cost effectiveness of dry FGD is actually over 265% worse than the cost effectiveness estimated by EPA for a least cost scrubber installation at Muskogee.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

52 

### Although the wet FGD control system may provi de an incremental reduction in overall SO 2 

### emissions from Muskogee Units 4 & 5, the increm ental costs associated with the additional SO 2 

### reductions are significantly higher than the averag e cost effectiveness of either control system. Wet FGD systems have a higher initial capital re quirement (compared to dry systems), require more energy to operate, and have somewhat hi gher annual operating costs. The total annual costs for wet FGD control systems on Muskogee Un its 4 & 5 are estimated to be approximately $11,465,200/year higher than the total annual costs for dry FGD systems. The incremental cost effectiveness of the wet FGD systems is estimat ed to be approximately $13,281/ton, which is substantially higher than the average cost e ffectiveness of the dry FGD control systems ($4,554/ton). The additional costs associat ed with wet FGD would result in significant economic impacts on the Muskogee Generating St ation (e.g., $11,465,200 per year additional costs). Therefore, wet FGD should not be selected as BART based on lack of cost
effectiveness.

4.3.2 Environmental Impacts of Wet FGD

In addition to the economic impacts, there are several collateral environmental impacts associated with a wet FGD system. First, wet FGD systems generate a calcium sulfate waste by-product that must be properly managed. Hi storically, solid wastes generated from wet FGD systems have been dewatered and disposed of in landfills. Most new wet FGD systems utilize a forced oxidation system that results in a gypsum by-product that can sometimes be sold into the local gypsum market. If an adequate local gyps um market is not available, the gypsum byproduct will require proper disposal.

Second, wet FGD systems will result in greater particulate matter emissions from the following

sources:

1. SO 3 

### remaining in the flue gas will react with moisture in the wet FGD to generate sulfuric acid mist. Sulfuric acid mist is classified as a condensable particulate. Condensable particulates from the wet FGD system can be captured using additional emission controls (e.g., WE SP). However the effectiveness of a WESP system on a subbituminous fired unit has not been demonstrated and the additional cost of the WESP system significantly increases the cost of SO 2 

### control.

2. Wet FGD systems must be located downstream of the unit’s particulate control device; therefore, dissolved solids from the wet F GD system will be emitted with the wet FGD plume. Wet FGD control systems also generate lower stack temperatures that can reduce plume rise and result in a visible moisture plume.

3. Wet FGD systems use more reactant (e.g., limestone) than do dry systems, therefore the limestone handling system and storage piles will generate more fugitive dust emissions.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

53 

### Third, wet FGD systems also require significantl y more water than the dry systems. Based on preliminary engineering calculations, it is estimated that a wet FGD system would require approximately 650 million gallons per year (t otal for both units based on a 90% capacity), which represents an increase of about 30% ove r water consumption associated with dry FGD control systems. Water consumption is an important factor when assessing potential environmental impacts, and it is beneficial to minimize water consum ption and maximize water recycle/reuse as much as practical.

Finally, wet FGD systems generate a wastewater stream that must be treated and discharged. Wet FGD wastewater consists of a saturated solution of calcium sulfate, calcium sulfite, sodium chloride, with trace amounts of flyash and unreacted limestone. Traces of metal ions will also be present due to flyash carryover fro m the flue gas to the FGD scrubber liquor. Wet FGD wastewater treatment systems typically requi re calcium sulfate/sulfite desaturation, heavy metals precipitation, coagulation/precipitation, and sludge dewatering. Treated wastewater is typically discharged to surface water pursuant to an NPDES discharge permit, and solids are typically disposed of in a landfill. Dry FGD control systems are designed to evaporate water within the reaction vessel, and therefore do not generate a wastewater stream.

4.3.3 Environmental Impacts of Dry Scrubbing

Collateral environmental impacts are less signifi cant with dry scrubbing systems (spray dryer absorber). First, dry scrubbing systems utilize lim e as the reactant rather than limestone. Limebased scrubbing systems use less reactant than limestone-based systems, reducing overall particulate matter emission from the facility’s material handling system. Lime in a dry scrubbing system will be hydrated prior to use. It is estimated, based on preliminary engineering calculations, that a dry system would require approxima tely 440 million gallons per year (total for both units based on 90% capac ity factor); however, water consumption with a dry system is approximately 30% less than the water requirements for a wet system. Furthermore, water used to hydrate the lime w ill be evaporated in the absorber vessel, and dry FGD systems will not generate a wastewater stream.

Dry scrubbing systems are located upstream of the unit’s particulate control device. FGD solids mixed with fly ash will be captured in the particulate control device. The mixture of dry FGD solids and fly ash is generally not salab le, however the material does not require dewatering and is easily landfilled. Assuming th e unit is equipped with a fabric filter baghouse for particulate control, the alkaline filter cake associated with the dry scrubber will augment the capture of acid gases (including sulfuric acid) , and will minimize condensable particulate
emissions without the need for a dditional controls (e.g., WESP).Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

54 

### 4.3.4 SO 2 

### Control – Energy Impacts

Both FGD control systems have significant auxilia ry power requirements. Auxiliary power is required for material handling, reactant prep aration, pumps, mixers, and to overcome significant pressure drops through the reacti on vessels. Based on engineering estimates, auxiliary power requirement for wet and dry FGD control systems are approximately 2.25% and 1.5% of the gross energy output of the generating unit, respectively. Muskogee Units 1 & 2 have a gross rating of 572 MW (each); ther efore, annual auxiliary power requirements for FGD control systems would be in the range of 135,000 to 200,000 MWh per year (at a 90% capacity factor). Energy impacts associated w ith each control technology were included in the BART economic impact evaluation as an auxiliary power cost.

A summary of the Step 4 economic and environmenta l BART impact analysis is provided in Table
4-8. Table 4-8 Muskogee Units 4 & 5 Summary of SO 2 

### BART Impact Analysis*

Control Technology Annual Emissions

(tpy) Annual Emission Reductions (tpy) Total Annual

Costs ($/year) Average Cost Effectiveness ($/ton) Incremental Cost Effectiveness ($/ton) Summary of Collateral Environmental Impacts

Wet FGD 3,456 32,188 $154,135,800 $4,789 $13,281 Increased PM emissions, including sulfuric acid mist and other condensable particulates. Increased NOx, CO, VOC, and PM 10 emissions associated with decreased unit heat rate and increased energy consumption. Increased water use and wastewater treatment/discharge. DFGD-SDA 4,320 31,342 $142,660,600 $4,554 NA Less water required. Increased solid waste generation rates (compared to wet FGD with forced oxidation and gypsum byproduct market). No wastewater generation or discharge. *Emissions and costs summarized in this table represent tota ls for both boilers. Emissions and costs were estimated based on a full load boiler heat input of 5,480 mmBtu/hr and a 90% capacity factor.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

55 

### 4.5 Step 5: Evaluate Visibility Impacts
To evaluate the relative effectiveness of potentially feasible SO 2 

### retrofit control technologies, SO 2 

### emissions were modeled at the projected pos t-retrofit controlled emission rates, while NO x 

### and

PM 10 

### emissions were modeled at the pre-BART baseline emission rates. In accordance with EPA guidelines (40 CFR Part 51 Appendix Y Part III), pos t-retrofit emission rates used in the modeling analysis to determine visibility impairment imp acts reflect steady-state operating conditions during periods of high capacity utilization. Post-retr ofit emission rates (average lb/hr rate on a 24-hour basis) were calculated using the expected cont rolled emission rate achievable on a 30-day rolling average multiplied by the boiler heat input ( mmBtu/hr) at full load. The visibility modeling methodology is described further in Attachment B of this document, including detailed inputs and
results. The results in Table 4-9 summarize the 98 th 

### percentile ∆ -dv impact from SO 2 

### emissions
associated each SO 2 

### retrofit control scenario.
Table 4-9 Muskogee Units 4 & 5 SO 2 

### Visibility Assessment

Visibility Improvement Upper Buffalo Wilderness Area Caney Creek Wilderness Area Hercules-Glades Wilderness Area Wichita Mountains Wildlife Refuge

SO 2 Control Technology Option 98 th % ∆ -dv* %Improvement

over Baseline 98 th % ∆ -dv %Improvement

over Baseline 98 th % ∆ -dv* %Improvement

over Baseline 98 th % ∆ -dv %Improvement

over Baseline Baseline 1.277 -- 1.471 -- 0.92 -- 1.176 --
DFGD – SDA 0.167 87% 0.196 87% 0.116 87% 0.148 87%

WFGD 0.194 85% 0.243 83% 0.127 86% 0.143 88% * ∆ -dv values included in this table represen t the modeled visibility impacts only from SO 2 emissions associated with

each SO 2 retrofit control scenario.



### With either FGD control system, modeled visibilit y impact improvements at the four Class I Areas are reduced by an average of approximately 1.0 ∆ -dv, ranging from a 0.739 ∆ -dv improvement (Hercules-Glades with wet FGD) to 1.275 ∆ -dv (Caney Creek with dry FGD). Although the wet FGD control systems result in lower SO 2 

### mass emission rates, modeled visibility impairments are generally less with dry FGD controls. Modeled impacts associated with SO 2 

### emissions with either FGD control system are below the threshold impact level of 0.5 ∆ -dv level at all Class I Areas. A summary of the cost effectiveness of both FGD control systems as a function of visibility impairment improvement at the Class I Areas is provided in Table 4-10.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

56 

### Table 4-10 Muskogee Units 4 & 5 SO 2 

### Average Visibility Cost Impact Evaluation

Total Annual Cost Modeled Visibility Impairment* Visibility Impairment Improvement from Baseline Average Improvement Cost Effectiveness SO 2 Control Technology Option ($/yr) 98 th % ∆ -dv* (dv) ($/dv/yr)
Baseline -- 1.471 -- -- DFGD – SDA $142,660,600 0.196 1.275 $111.9 MM/dv WFGD $154,135,800 0.243 1.228 $125.5 MM/dv

* ∆ -dv values included in this table represen t the modeled visibility impacts only from SO 2

emissions associated with each SO 2 retrofit control scenario. Modeled visibility impairment at the Caney Creek Class I Area was used for the co st effectiveness evaluation because modeling indicated that the largest ∆ -dv improvements would occur at Caney Creek.



### Although FGD control systems reduce modeled visibility impacts at the four Class I Areas, the cost effectiveness of FGD control (with respect to visi bility improvement) is very high. With either FGD control system, cost effectiveness ranges fro m approximately $111.9 million to $125.5 million per dv improvement at the Wichita Mountains. These costs are significan tly higher than costs incurred at other BART applicable sources. A revi ew of BART determinations at other coal-fired units suggests that BART cost effectiveness valu es are typically in the range of less than $1.0 million to approximately $ 13 million per dv improvement. 27 

### The combination of relatively low
baseline SO 2 

### emissions, low baseline visibility impacts (less than 1.5 ∆ -dv at all Class I Areas), and distance to the Class I Areas, all contribute to th e large cost effectiveness values at the Muskogee
Station.

To determine whether alterative SO 2 

### control scenarios might provide more cost effective visibility improvements, cumulative impact modeling was conducted using a variety of FGD control scenarios. A goal of the cumulative impact m odeling was to determine whether alternative SO 2 

### control scenarios (i.e., FGD control on some, but not all of the OG&E BART applicable sources) would provide more cost effective SO 2 

### control. To quantify cost effectiveness, visibility impairment was modeled for several SO 2 

### control scenarios, while NOx and PM emissions were held constant at their respective baseline emission rates. Modeled SO 2 

### control scenarios are listed
in Table 4-11. Results of the cumulative SO 2 

### impact modeling are summarized in Table 4-12.

27 See e.g., BART evaluations for Xcel (Sherco, MN); Great River Energy (Coal Creek, ND); Trigen Energy Co. (CO); Entergy White Bluff Power Plant (AR).Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

57 

### Table 4-11 Cumulative SO 2 

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

Unit Base Case Case 1 Case 2 Case 3 Case 4 

### SO 2 Controls (Emission Rate - lb/mmBtu) Muskogee Unit 4 Baseline (0.80) DFGD (0.10) DFGD (0.10) DFGD (0.10) DFGD (0.10) Muskogee Unit 5 Baseline (0.85) Baseline (0.85) Baseline (0.85) DFGD (0.10) DFGD (0.10) Sooner Unit 1 Baseline (0.86) Baseline (0.86) DFGD (0.10) DFGD (0.10) DFGD (0.10) Sooner Unit 2 Baseline (0.860) Baseline (0.86) Baseline (0.86) Baseline (0.86) DFGD (0.10) * For each case PM and NOx emissions were held constant at the baseline emission rates. Baseline emissions for NOx were: 0.15 lb/mmBtu for both Muskogee units (assuming LNB/OFA controls).



### Table 4-12 Cumulative SO 2 

### Visibility Modeling Results (Muskogee Units 4 & 5 and Sooner Units 1 & 2)

Modeled Visibility Impairment* Upper Buffalo Wilderness Area Caney Creek Wilderness Area Hercules-Glades Wilderness Area Wichita Mountains Wildlife Refuge SO 2 Control Technology

Option 98 th % ∆ -dv 98 th % ∆ -dv 98 th % ∆ -dv 98 th % ∆ -dv

Base Case 1.92 2.00 1.44 2.42

Case 1 1.46 1.69 1.05 2.16

Case 2 1.26 1.48 0.90 1.60

Case 3 0.78 0.91 0.52 1.33

Case 4 0.57 0.68 0.38 0.74

* ∆ -dv values included in this table reflect cumulative modeled contributions from NOx, SO 2 and PM emissions from

both the Sooner and Muskogee Stations. For each case, PM and NOx emissions were held constant at their respective baseline emission rates, while SO 2 emissions varied depending the SO 2 control system on each unit (see Table 4-11). The dv values in this table are not directly related to dv values in Tables 3-8 (NOx) and 4-9 (SO2), which reflect modeled impacts from the Muskogee Station only for each individual pollutant.



### Results of the cumulative impact modeling suggest that visibility improvement at the Class I Areas is essentially linear with SO 2 

### emission reductions from the OG&E generating stations (see, Figure 4-1). For example, modeled visibility impairment at the Wichita Mountains was reduced by 0.26
∆ -dv with one FGD at the Muskogee Station, and by an additional 0.27 ∆ -dv with a second FGD at Muskogee. Similarly, visibility impairment at the Wichita Mountains was reduced by 0.56 ∆ -dv with one FGD control system at the S ooner Station, and by an additional 0.59 ∆ -dv with a second FGD at Sooner. However, because of the relativ ely small improvement in visibility impairment, the cost effectiveness for FGD control systems ranged from approximately $120 MM/dv (SoonerOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

58 

### Station) to more than $260 MM/dv (Muskogee Sta tion). Cost effectiveness values associated with the cumulative impact modeling at the Wichita Mountains Wildlife Refuge are summarized in
Table 4-13.

Figure 4-1 Cumulative SO 2 

### Visibility Modeling Results (Muskogee Units 4 & 5 and Sooner Units 1 & 2)

Table 4-12 Cumulative SO 2 

### Visibility Modeling Results Wichita Mountains

Case 98 th % ∆ -dv Incremental Improvement Incremental Increase in Annual Cost Cost Effectiveness

Base Case 2.42 -- -- $MM/dv

Case 1 2.16 0.26 $71,067,900 $273.3

Case 2 1.60 0.56 $70,415,900 $125.7

Case 3 1.33 0.27 $71,067,900 $263.2

Case 4 0.74 0.59 $70,415,900 $119.3 Wichita Mountains Modeled Visibility Impairment vs. FGD Control Systems

0.00 0.50 1.00 1.50 2.00 2.50 3.00

Baseline Case 1 (Muskogee Unit 4) Case 2 (Muskogee Unit 4 and Sooner Unit 1) Case 3 (Muskogee 4 & 5 and Sooner Unit 1) Case 4 (Muskogee 4 & 4 and Sooner 1 & 2)

FGD Control ScenarioModeled Visibility Impairment (delta-dv Wichita Mts Caney Creek Herc-Glades Upper BuffaloOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

59 

### 4.6 Propose BART for SO 2 

### Control

OG&E is proposing that no additional SO 2 

### controls (beyond baseline low sulfur subbituminous coal) are BART for Muskogee Units 4 & 5. In the final Regional Haze Rule EPA established presumptive BART emission limits for SO 2 

### from coal-fired EGUs greater than 200 MW at power plants with a total generating capacity in excess of 750 MW. 28 

### The BART SO 2 

### presumptive
emission limit for these units is either 95% SO 2 

### removal or an emission rate of 0.15 lb/mmBtu, unless an alternative control level is justified b ased on a careful consideration of the statutory factors. Statutory factors include the costs of compliance and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology. In the case of the Muskogee Station, the poor cost effectiv eness of the feasible controls dictates a decision
that no additional controls are warranted.

The cost effectiveness of FGD cont rol on Muskogee Units 4 & 5 is poor in comparison to the cost effectiveness estimates used by EPA in establis hing presumptive BART. EPA believed the average cost effectiveness would be $919 per ton SO 2 

### removed, with the majority of the BART applicable units meeting the presumptive standards at a cost of $400 to $2,000 per ton of SO 2 

### removed. To support the presumptive BART analysis, EPA develo ped cost effectiveness estimates for Muskogee Units 4 & 5 of $1,690 to $1,697 per ton of SO 2 

### removed. In fact, the actual cost effectiveness of the potentially feasible SO 2 

### control technologies at the Muskogee Station is $4,554 to $4,789 per
ton of SO 2 

### removed. Therefore, SO 2 

### removal at Muskogee Units 4 & 5 is over two-and-a-half times less cost effective than EPA expected, and it is well outside of the cost effectiveness range that EPA used to support its presumptive BART determination. The cost effectiveness of FGD controls at the Muskogee Station calculated on the ba sis of visibility improvement also is poor. The
cost effectiveness is estimated to be in the ra nge of $111.9 to $125.5 million per dv improvement, which is significantly less effective than at other BART applicable sources.

Although FGD control systems (either wet or dry FGD) will reduce SO 2 

### emissions and modeled visibility impairment at the Class I Areas, th e combination of relatively low baseline SO 2 

### emissions, low baseline visibility im pacts (less than 1.5 ∆ -dv at all Class I Areas), and distance to the Class I Areas, all contribute to the poor cost effectiveness values. Based on the poor cost effectiveness of FGD retrofit controls and the relatively small de gree of improvement in visibility, FGD control systems should not be selected as BART on Muskogee Units 4 & 5. As a result, OG&E is proposing low sulfur subbituminous coal a nd the existing permit limits as BART for SO 2 

### .

28 See, 40 CFR 51 Appendix Y Part IV, and 70 FR 39131.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

60 

### 5.0 BART ANALYSIS FOR MAIN BOILER PARTICULATE MATTER

PM composition and emission levels are a comple x function of boiler firing configuration, boiler operation, pollution control equipment and coal pr operties. Uncontrolled PM emissions from coalfired boilers include the ash from combustion of the fuel, noncombustible metals present in trace quantities and unburned carbon resulting from incomplete combustion. Other sources of PM include condensable organics and minerals present in the combustion air.

Coal ash may either settle out in the boiler (bottom ash) or be entrained in the flue gas (fly ash). The distribution of ash between the bottom ash and fly ash fractions affects the PM emission rate and is a function of the boiler firing method and fu rnace type. With a PC boiler approximately 80% of the ash will be emitted with the flue gas as fly ash and 20% will settle out in the combustion bed
as bottom ash. PM 10 

### emissions from Muskogee Units 4 & 5 ar e currently controlled with cold-side electrostatic precipitators (ESPs).

5.1 Step 1: Identify Available Retrofit PM 10 

### Control Options

The principal techniques for PM control are post- combustion methods (applicable to most boiler types and sizes). There are two generally recognized PM control devices that are used to control
PM emission from PC boilers: ESPs and fabric f ilters (or baghouses). Muskogee Units 4 & 5 are currently equipped with ESP control systems.

Retrofit PM 10 

### control options with potential application to a subbituminous-fired PC boiler are listed in Table 5-1. The technical feasibility of each potential control option is discussed below.

Table 5-1 PM 10 

### Retrofit Control Options with Potential Application to a Subbituminous-Fired PC Boiler

PM 10 

### Control Technologies Electrostatic Precipitation (ESP) – existing Fabric Filtration (FF)

5.2 Step 2: Eliminate Technically Infeasible Retrofit Options

5.2.1 Electrostatic Precipitators (ESPs)

Muskogee Units 4 & 5 are currently equipped with ESPs for PM 10 

### control. ESP technology consists of three steps: (1) charging the partic les to be collected via a high-voltage electric discharge, (2) collecting the particles on the surf ace of an oppositely charged collection electrodeOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

61 

### surface, and (3) cleaning the surface of the collecting electrode. Particulate material captured on the collecting electrodes is removed by rapping the el ectrodes. The collected particulates drop into hoppers below the precipitator and are periodically removed with the fly ash handling system.

Operating parameters that influence ESP performan ce include fly ash mass loading, particle size distribution, fly ash electrical resistivity, and preci pitator voltage and current. Other factors that determine ESP collection efficiency are collection pl ate area, gas flow velocity, and cleaning cycle.
Baseline controlled PM 10 

### emissions from Muskogee Units 4 & 5 are approximately 101 lb/hr and 134 lb/hr, respectively. Based on a maximum heatinput of 5,480 mmBtu/hr (each boiler), baseline

PM 10 

### emission rates from Units 4 & 5 are 0.0184 and 0.0244 lb/mmBtu, respectively. 29 

### These controlled rates require the existing ESPs to ach ieve average overall particulate matter control efficiencies of greater than 99%.

5.2.2 Fabric Filters

Fabric filtration consists of a number of filtering elements (bags) along with a bag cleaning system contained in a main shell structure incorpora ting dust hoppers. Particulate-laden gas enters a fabric filter compartment and passes through a layer of filter bags. The collected particulate forms a cake on the bag that enhances the bag’s filteri ng efficiency. Excessive caking will increase the pressure drop across the fabric filter at which point the filters must be cleaned.

The particulate removal efficiency of fabric filte rs is dependent upon a va riety of particle and operational characteristics. Particle characteristi cs that affect the collection efficiency include particle size distribution and particle cohesion ch aracteristics. Operational parameters that may affect fabric filter collection efficiency incl ude bag material, air-to-cloth ratio, and operating pressure loss. In addition, certain filter prope rties (e.g., structure of the fabric and fiber composition) can affect the system's particle collection efficiency.

Fabric filter baghouses are considered a technically feasible particulate matter control option for Muskogee Units 4 & 5, and a fabric filter baghou se (or polishing baghouse) would be required if the units were retrofit with dry FGD. However, retrofitting the existing units with baghouses for particulate matter control only (i.e., not in conjun ction with a dry FGD) would require substantial modifications to the units without providing any si gnificant reduction in controlled PM emissions.

29 Baseline PM 10 emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline PM 10 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 conservativ e estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baseline emission rates shoul d 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 Muskogee Generating Station – BART Determination May 28, 2008

62



### Extensive ductwork would be required to redirect fl ue gas flow though the fabric filter and back to the existing stacks. Furthermore, baghouses would provide only an incremental reduction in PM/

PM 10 

### control compared to the existing ESP control systems.

5.3 Step 3: Rank the Technically Feasible PM 10 

### Control Options by Effectiveness

The effectiveness of each retrofit technology identified as being technically feasible for PM 10 

### control is summarized in Table 5-2 in descending order of control efficiency.

Table 5-2 Summary of Technically Feasible Main Boiler PM 10 

### Control Technologies

Control Technology PM10 Emissions* (lb/mmBtu) % Reduction (from base case) Fabric Filter Baghouse 0.015 99.7 ESP - Existing 0.025 99.6

Potential PM Emissions 5.65 -
* The PM 10 emission rate for the baghouse case is based on filterable PM 10 emission limits

included in recently issued PSD permits for new coal-fired units. The PM 10 emission rate for the ESP case is based on the Units’ baseline PM 10 emission rates (e.g., approximately 0.025 lb/mmBtu on Unit 5). Potential PM emissions were calculated assuming an average fuel heating value of 8,500 Btu/lb and an ash content of 6.0%, and assuming 80% of the fuel ash will be emitted as fly ash.



### 5.4 Step 4: Evaluate Impacts and Document the Results

5.4.1 Economic Evaluation

Based on the controlled PM 10 

### emission rates included in Table 5-2, and assuming a maximum heat input to each boiler of 5,480 mmBtu/hr and 7,884 hours/year operation (90% capacity factor), potential PM 10 

### emissions from Muskogee Units 4 & 5 would be reduced from approximately 1,080 tpy to 648 tpy with a fabr ic filter baghouse (total potential emissions from both units). Equipment costs associated with retrofitting Muskogee Units 4 & 5 with a baghouse are estimated to be in the range of $125 to 135/kW-gross, or in the range of $75,000,000 per unit. Taking into considerati on indirect installation costs for foundations, mechanical erection, electrical, piping, and insulation, and including engineering, and contingencies, total capital requirement for a fa bric filter baghouse would be in the range of $104,000,000/unit. The annualized capital recovery cost for the baghouse control systems (assuming equipment life of 25 years and 7% pr etax marginal rate of return) would be approximately $8,900,000/yr (per unit). Ignoring O&M costs associated with baghouse operation (including bag replacement costs and energy cost associated with increased pressureOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

63 

### drop) the cost effectiveness of the retrofit baghouse control system would be more than $41,000/ton of PM removed (e.g., $8.9 MM/yr/unit x 2 units / 432 tpy potential emission reductions).

It is apparent that a retrofit baghouse control syst em would not be cost effective for particulate matter control only. Although baghouses ma y provide an incremental reduction in PM 10 

### emissions, the costs associated with a fabric f ilter retrofit project are significant. Retrofitting Muskogee Units 4 & 5 with baghouses for particul ate matter control would require a significant capital investment for a minimal reduction in emissi ons. The cost effectiveness of the retrofit baghouse control systems is excessive, and should preclude fabric filter control systems from
consideration as BART for PM control.

5.4.2 Environmental Evaluation

There are no environmental considerations that woul d preclude the use of either fabric filters or ESP control systems as BART on Muskogee Units 4 & 5. Both PM control systems generate a fly ash solid waste that must be properly managed.

5.4.3 PM Control - Energy Impact Evaluation

There are significant auxiliary power requirement s associated with the fabric filter control system. Auxiliary power is required to overcome pressure drop through the baghouse and filter cake. Based on engineering estimates, auxiliary power requirements for a fabric filter baghouse are approximately 0.5% of the gross energy output of the generating unit. Muskogee Units 4 & 5 have a gross rating of 572 MW (each); theref ore, annual auxiliary power requirements for a baghouse control system would be in the range of 45,000 MWh per year (at a 90% capacity factor). Annual operating costs associated w ith the auxiliary power requirement would be significant, and the increased auxiliary power re quirement would reduce the overall efficiency
of both units.

5.5 Step 5: Evaluate Visibility Impacts

Replacing the existing ESPs on Muskogee Units 4 & 5 with baghouses is not a cost effective retrofit control option for PM control. Furt hermore, based on visibility impact modeling, particulate matter emissions from Muskogee Units 4 & 5 contribute only minimally to modeled visibility impacts at the Class I Areas (see, Attach ment B). A majority (more than 90%) of the modeled visibility impacts are associated with NO x 

### and SO 2 

### emissions. Reducing particulate matter emissions from the existing baseline rate (with ESP control) would provide no discernible reduction in modeled visibility impacts at the Class I areas.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

64 

### 5.6 Propose BART for PM 10 

### Control

Based on visibility impact modeling, and economic impacts associated with retrofit PM controls, OG&E is not proposing any change to its existing PM/ PM 10 

### emission limits as BART. Therefore, OG&E is proposing no change to existing permitte d PM emission limits as BART for particulate
matter control.

6.0 BART SUMMARY

Table 6-1 summarizes the proposed BART control technologies and associated emission limits for Muskogee Units 4 & 5.

Table 6-1 Proposed BART Permit Limi ts and Control Technologies

Pollutant Proposed BART Emission Limit Proposed BART Technology

NO x 0.15 lb/mmBtu (30-day average) Combustion controls including LNB and OFA

SO 2 Existing Permit Limits Low sulfur subbituminous coal

PM 10 filterable Existing Permit Limits NAOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-1 

### Attachment A

Muskogee Units 4 & 5 BART Determination - Cost Estimate DetailsOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-2 

### Economic Evaluation Methodology for Technically Feasible Control Options

Summarized below are the basi c principles and methodologies used to prepare the economic analysis of technologically feasible control opt ions. The cost-effectiveness evaluations were "study" estimates of ±30% accuracy, based on: (1 ) engineering estimates; (2) vendor quotations provided for similar projects and similar equipm ent; (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 system s, increased significantly in response to the Clean Air Interstate Rule (CAIR). CAIR, pub lished May 12, 2005, mandates specific emission caps on SO 2 

### and NOx emissions from power plants located in 28 Eastern and Midwestern states. CAIR emission caps will be imposed in two ph ases, with the first phase beginning in 2009 for NOx and 2010 for SO 2 

### . The second phase of emission reductio ns 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 sel ective catalytic reduction technology on existing coal-fired generation capacity. 30 

### This increase in demand for retrofit emission control systems created a “sellers market” in the U.S. Pollution control equipment vendors, their fabricators and material suppliers currently have significant back logs and are able to charge higher margins, contributing to the recent escalation in retrofit control technology costs.

Construction contractors and cons truction 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 pu ll 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 fo rce is able to demand more lucrative contracts in order to be attracted to an area that is s hort 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 al so increased significantly. Commodity price data available from the U.S. Department of La bor’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 be tween 2003 and 2006. Pollution control projects require large quantities of basic commodities, in cluding steel, concrete, and copper. Increased commodity prices have a significant impact on the cost of large emission control retrofit projects.

30 “Regulatory Impact Analysis for the Final Clean Air Interstate Rule,” U.S. EPA Office of Air and Radiation, EPA-452/R-05-002, March 2005.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-3 

### BART Economic Evaluation

Average and incremental cost effectiveness were the two economic criteria considered in the BART analysis. Effectiveness of a control opti on is measured in terms of tons of pollutant emissions removed per year (E annual 

### ). Cost is measured in term s of the total annualized cost (TAC) associated with the control system. The annual cost effectiveness of a particular control system (expressed in $/ton) is cal culated using the following equation:

Average Cost Effectiveness = E annual 

### / 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 purch ased equipment cost plus direct installation costs (such as foundations and supports, erecti on, electrical, and piping), and indirect capital costs (such as engineering, contractor fees, performance testing and contingencies).

To calculate the CRC, the equivalent unifor m 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 - RCOklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-4 

### Direct O&M costs are those costs that tend to be proportional to the quantity of exhaust gas processed by the control system. These may include costs for catalysts, utilities (steam, electricity, and water), waste treatment and dispo sal, maintenance materials, replacement parts, and operating and maintenance labor. Of these dire ct O&M costs, costs fo r catalysts, utilities, waste treatment, and disposal are variable. Emission allowance costs associated with certain regulatory programs may also be represented as a variable O&M costs, but have not been included in this cost estimate. Labor costs, maintenance materials and replacement parts are semi-variable direct costs as they are only pa rtly dependent upon the exhaust flow rate.

Indirect or “Fixed" annual costs are those who se 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, propert y 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 require d 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 contro l system was calculated based on the Capital Recovery Cost and Annual Operating Costs.

5. The Annual Control Effectiveness, in te rms of Total Annualized Costs divided by annual emission reductions, was calculated for each control system.

BART economic evaluations were prepared for the following control systems:

NOx Control Cost Summary - Combustion Controls (LNB/OFA) - Combustion Controls plus Sel ective Catalytic Reduction (SCR)

SO 2 

### Control Cost Summary - Dry FGD (Spray Dry Absorber) - Wet FGDOklahoma Gas & ElectricMuskogee Generating Station – BART DeterminationMay 28, 2008Page A-5BART Economic EvaluationNOx SummaryMUSKOGEE GENERATING STATION UNITS 4 & 5NOx CONTROL SUMMARYMuskogee 4 Muskogee 5 UnitDesign Heat Input:5,480 5,480mmBtu/hrNet Capacity:532 532MWCapacity Factor90% 90%Maximum Hours/year:8,760 8,760hoursMuskogee 4Control TechnologyExpected EmissionRateExpectedEmissionsExpectedEmissionsReductionTotal CapitalRequirementAnnual Capital RecoveryCostTotal AnnualOperating Costs Total Annual CostsAverage ControlEfficiencyIncremental ControlEfficiency(lb/mmBtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton) ($/ton)Baseline Emissions0.49510,693 NAAlternative 1: LNB / OFA0.1503,240 7,453 $14,113,700 $1,211,100 $880,700 $2,091,800$281--Alternative 2: LNB/OFA + SCR0.0701,512 9,181 $193,077,000 $16,568,000 $14,227,600 $30,795,600$3,35416,611Note: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR.Muskogee 5Control TechnologyExpected EmissionRateExpectedEmissionsExpectedEmissionsReductionTotal CapitalRequirementAnnual Capital RecoveryCostTotal AnnualOperating Costs Total Annual CostsAverage ControlEfficiencyIncremental ControlEfficiency(lb/MMBtu) (ton/year) (ton/year) ($) ($/year) ($/year) ($) ($/ton) ($/ton)Baseline Emissions0.52211,276 NAAlternative 1: LNB / OFA0.1503,240 8,036 $14,113,700 $1,211,100 $880,700 $2,091,800$260--Alternative 2: LNB/OFA + SCR0.0701,512 9,764 $193,077,000 $16,568,000 $14,227,600 $30,795,600$3,15416,611NotesNote 1: Costs for Alternative 2 include the costs of the combustion controls (Alternative 1) plus the costs of SCR.Note 2: Baseline NOx emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline NOx emission rates (lb/mmBtu) were calculated bydividing 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 aconservative estimate of the cost effectiveness of potentially feasible retrofit control technologies. The short-term baselineemission rates should in no way be interpreted as apotential violation of the facility’s permitted emissionlimits, which are averaged over a longer period of time.Assuming 90% capacity factor for cost evaluations.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-6 

### BART Economic Evaluation – NOx Retrofit Control Technologies – Capital Cost Summary

MUSKOGEE GENERATING STATION UNITS 4 & 5 Capital Cost Worksheet

Case 1 x 572 MW-gross PC Boiler 1 x 572 MW-gross PC Boiler Gross Plant Output (MW- g ross) MW- g ross 572.0 572.0 Net Plant Output (MW-net) MW-net 532.0 532.0 Maximum Heat Input (mmBtu/hr) mmBtu/hr 5,480 5,480 Uncontrolled NOx Emission Rate (lb/mmBtu) lb/mmBtu 0.495 0.522 Capacit y Factor Used for Cost Estimates (%) % 90% 90% Capital Cost Recover y Factor Equipment Life y ears 25 25

Low NOX Burner Technology Capital Costs Muskogee 4 Muskogee 5

Cost Basis (Year) 2008 2008 Total Capital Requirement with Retrofit (TCR) $ $14,113,700 $14,113,700

SCR Capital Costs

Muskogee 4 Muskogee 5 Cost Basis (Year) 2008 2008 SCR Area $2,023,000 $2,023,000 Civil/Site Work $620,000 $620,000 Flue Gas System/Ductwork $32,331,000 $32,331,000 Modifications $5,273,000 $5,273,000 Pipe Rack $7,751,000 $7,751,000 Miscellaneous Mechanical Items $1,101,000 $1,101,000 Urea to Ammonia System $4,904,000 $4,904,000 Booster Fans $5,329,000 $5,329,000 Allowance for Additional Cranes $873,000 $873,000 Electrical Modifications $11,336,000 $11,336,000 Equipment Capital Cost Subtotal $ $71,541,000 $71,541,000 Instruments & Controls $ $1,430,800 $1,430,800 Taxes $ $4,292,500 $4,292,500 Freight $ $3,577,100 $3,577,100 Total Direct Cost $80,841,400 $80,841,400 Other Costs Total Direct Cost with Retrofit Factor $ $97,009,700 $97,009,700 General Facilities $ $4,850,500 $4,850,500 Engineering Fees $ $9,701,000 $9,701,000 Contingency $ $19,401,900 $19,401,900 EPC Fee (20% of total Cost) $19,401,900 $19,401,900 Total Plant Cost (TPC) $ $150,365,000 $150,365,000 Total Plant Cost (TPC) w/ Prime Contractor's Markup $ $154,876,000 $154,876,000 Allow. for Funds During Constr. (AFDC) $ $12,607,000 $12,607,000 Preproduction Costs $ $3,345,300 $3,345,300 Inventory Capital Initial Ammonia (60 days) $ $87,000 $87,000 Initial Catalyst $ $8,048,000 $8,048,000 Total Capital Requirement (TCR) $ $178,963,300 $178,963,300 Total Capital Requirement ($/kW-gross) $/kW-gross $313 $313 Total Capital Requirement ($/kW-net) $/kW-net $336 $336 Capital Cost Estimates were based on detailed cost estimates recently prepared for similar projects. Capital costs were compared to U.S.EPA's Coal Utility Environmental Cost (CUECost) Workbook, modified to account for recent increases in

p urchased equipment costs and commodity costs. Estimates were also compared to vendor quotes provided on recent similar projects.Oklahoma Gas & ElectricMuskogee Generating Station – BART DeterminationMay 28, 2008Page A-7BART Economic Evaluation – NOxLNB/OFA Combustion DetailsMUSKOGEE GENERATING STATION UNITS 4 & 5BART COST EVALUATION - LOW NOx BURNER WORKSHEETMuskogee 4 Muskogee 5Gross Plant Output (MW-gross) 572 572Net Plant Output (MW-net)532 532Maximum Heat Input (mmBtu/hr) 5,480 5,480Uncontrolled NOx Emission Rate (lb/mmBtu) 0.495 0.522Post Low Nox Burner Emission Rate (lb/mmBtu) 0.150 0.150CapacityFactor used of Cost Estimates (%) 90% 90%Capital Cost RecoveryFactor Equipment Life25CAPITAL COSTSBasisTotal Capital Requirement (TCR)$14,113,700 $14,113,700Total Capital Investment ($/kW - net) $27 $27Capital Recovery Factor = i(1+ i)n/ (1 + i)n- 1 0.0858 0.0858 EPA Air Pollution Control Cost Manual 6th Ed., page 2-21.Annualized Capital Costs(Capital Recover Factor x Total Capital Investment)$1,211,100 $1,211,1007%Assumed pretax marginal rate of return on private investment.OPERATING & MAINTENANCE COSTSBasisVariable O&M CostsAmmonia Reagent Cost $0 $0 Assumed no variable O&M costs with the LNB/OFA retrofit control system.Catalyst Replacement Cost $0 $0Auxiliary Power Cost$0 $0Total Variable O&M Cost$0 $0Fixed O&M CostsAdditional Operators per shift 0.00 0.00 Assumed no additional operators needed for the LNB/OFA retrofit control system.Operating LaborMaintenance Labor $112,900 $112,9000.80%CUECost Maintenance Labor Default for emission control systems (0.8%/yr * Total Plant Cost)Maintenance Materials $169,400 $169,4001.20%CUECost Maintenance Default Factor for control systems (1.2% of installed cost).Control, Administration, Overhead $33,900 $33,90030%of Maintenance Labor Cost (CUECost Default of control systems)Total Fixed O&M Costs$316,200 $316,200Indirect Operating CostProperty Taxes $141,100 $141,1001%of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.Insurance $141,100 $141,1001%of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.Administration $282,300 $282,3002%of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.Total Indirect Operating Cost$564,500 $564,500Total Annual Operating Cost$880,700$880,700TOTAL ANNUAL COSTAnnualized Capital Cost$1,211,100 $1,211,100Annual OperatingCost$880,700 $880,700Total Annual Cost$2,091,800 $2,091,800See, Input Sheet. TCR includes all costs required to purchase and install control equipment, includingmaterials, labor, site preparation, engineering, contingencies, and retrofit costs.Oklahoma Gas & ElectricMuskogee Generating Station – BART DeterminationMay 28, 2008Page A-8BART Economic Evaluation – NOxSCR DetailsMUSKOGEE GENERATING STATION UNITS 4 & 5BACT COST EVALUATION - SCR WORKSHEETMuskogee 4Muskogee 5Gross Plant Output (MW-gross) 572.0572.0Net Plant Output (MW-net)532.0 532.0Maximum Heat Input (mmBtu/hr) 5,4805,480Post Boiler NOx Emission Rate (lb/mmBtu) 0.150.15PostSCR NOx Emission Rate (lb/mmBtu) 0.070.07CapacityFactor used of Cost Estimates (%) 90% 90%Capital Cost RecoveryFactor Equipment Life (years) 25Cost CostCAPITAL COSTS [$] [$]BasisTotal Capital Requirement (TCR)178,963,300$ 178,963,300$Total Capital Investment ($/kW-net) $336 336$Capital Recovery Factor = i(1+ i)n/ (1 + i)n- 1 0.0858 0.0858 EPA Air Pollution Control Cost Manual 6th Ed., page 2-21.Annualized Capital Costs(Capital Recover Factor x Total Capital Investment)$15,356,900 $15,356,9007% Assumed pretax marginal rate of return on private investment.OPERATING COSTSBasisOperating & Maintenance Costs (based on 90% capacity factor)Variable O&M CostsAmmonia Reagent Cost $272,900 $272,900 370$Based on maximum heat input, NOx removal rate (lb/hr), NH2/N2 ratio of approximately 1.1, 90%capacity factor, and $370/ton reagent cost.Catalyst Replacement Cost $1,701,700 $1,701,700 7,000$ Based on 1.7 M3catalyst per MW-gross, 4 year catalyst life, and $7,000/M3catalyst cost.Auxiliary Power Cost $869,000 $869,000 32$Based on 9" pressure drop across the SCR, 0.065 MWh/inch auxiliary power requirement, and$32/MWh.Total Variable O&M Cost$2,843,600 $2,843,600Fixed O&M CostsAdditional Operators per shift 1.00 1.00 Based on S&L O&M estimate for SCR control system.Operating Labor $293,500 $293,5003 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an annual operatorsalary of $70,000/year.Supervisory Labor $44,000 $44,000 15.0% of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page 2-31.Maintenance Materials $2,684,400 $2,684,400 1.5% CUECost Maintenance Default Factor for SCR (1.5% of installed cost).Maintenance Labor $322,900 $322,900 110.0% of operating labor. EPA Air Pollution Control Cost Manual 6th Ed., page 2-31.Total Fixed O&M Cost$3,344,800 $3,344,800Indirect Operating CostProperty Taxes $1,789,600 $1,789,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.Insurance $1,789,600 $1,789,600 1% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.Administration $3,579,300 $3,579,300 2% of total capital investment (TCR). EPA Air Pollution Control Cost Manual 6th Ed., page 2-34.Total Indirect Operating Cost$7,158,500 $7,158,500Total Annual Operating Cost $13,346,900 $13,346,900TOTAL ANNUAL COSTAnnualized Capital Cost$15,356,900 $15,356,900Annual OperatingCost$13,346,900 $13,346,900Total Annual Cost$28,703,800 $28,703,800See, Input Sheet. TCR includes all costs required to purchase and install control equipment,including materials, labor, site preparation, engineering, contingencies, and retrofit costs.Oklahoma Gas & ElectricMuskogee Generating Station – BART DeterminationMay 28, 2008Page A-9BART Economic EvaluationSO2Summary – Muskogee Unit 4MUSKOGEE STATION UNIT 4SO2 CONTROL SUMMARYPollutant: SO2 UnitDesign Heat Input:5,480mmBtu/hrCapacity Factor90%%Maximum Hours/year:8,760hoursControl TechnologyExpected EmissionRateExpectedEmissionsExpectedEmissionsReduction(lb/MMBtu) (ton/year) (ton/year)Baseline Emissions0.8017,2820Alternative 1: DFGD-SDA0.102,160 15,122Alternative 2: WFGD0.081,728 15,554Control Technology EmissionsTons of SO2RemovedTotal CapitalRequirementAnnual CapitalRecovery CostTotal AnnualOperating Costs Total Annual CostsAverage ControlEfficiencyIncrementalControl Efficiency(tpy) (tpy) ($) ($/year) ($/year) ($) ($/ton) ($/ton)Baseline Emissions17,282Alternative 1: DFGD-SDA2,16015,122$372,609,000 $31,973,800 $38,630,200 $70,604,000$4,669Alternative 2: WFGD1,72815,554$417,788,000 $35,850,600 $41,204,700 $77,055,300$4,95414,934$Assumed 90% capacity factor for cost evaluations.NotesDesign heat input was held constant for both FGD control technologies. Net plant output willdecrease with the wet FGD system due toincreased auxiliary power requirements.Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

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### BART Economic Evaluation – SO 2 

### Retrofit Control Technology – Capital Cost Summary – Muskogee Unit 4Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-11 

### BART Economic Evaluation – SO 2 

### Dry FGD Control System – Muskogee Unit 4

EQUIPMENT CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $270,087,000 General Facilities $27,009,000 Engineering Fees $27,009,000 Contingenc y $54,017,000 Total Plant Cos t $378,122,000 Total Plant Cost (TPC) w/ Prime Contractor's Markup $389,466,000 Total Cash Expended (TCE) $330,579,000 Allow. for Funds During Constr. (AFDC) $32,661,000 Total Plant Investment (TPI) $363,240,000 Preproduction Costs $9,324,000 Inventory Capital $45,000 Total Capital Requirement (TCR) $372,609,000 Total Capital Investment ($/kW - gross) $651 Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.0858 25 years. Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $31,973,800 7% Assumed pretax marginal rate of return on private investment.

OPERATING COSTS Basis Operating & Maintenance Costs Variable O&M Costs

Lime Reagent Cos t $4,410,400 200 $ Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 90% CaO, 90% capacity factor, and $200/ton for lime. Water Cos t $276,000 1.20 $ Based on 0.85 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal

FGD Waste Disposal Cos t $964,000 30 $ Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, and $30/ton on-site disposal cost. Disposal cost only includes FGD b y-products and does not include fly ash.

Bag and Cage Replacement Costs $581,300 2.85 $ Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 for pulse jet baghouse, $2.85/ft2 bag cost (including fabric and hangers), 4% contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0 Assumed no increase in ash disposal with the fabric filter compared to the existing ESP control system.

Auxiliary Power Cos t $3,044,000 45 $ Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% (gross) for the baghouse, 90% capacity factor, and $45/MW. Total Variable O&M Costs $9,275,700

Fixed O&M Costs Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.

Operating Labor $586,900 3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an annual operator salary of $70,000/year. Supervisor Labo r $88,000 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $13,504,400 5.0% Maintenance Default Factor for lime spray dryer from EPA's Coal Utility Environmental Cost (CUECost) Workbook. Maintenance Labor $645,600 110.0% of operating labor. EPA Control Cost Manual, page 2-31 Total Fixed O&M Cos t $14,824,900

Indirect Operating Cost Property Taxes $3,632,400 1% Insurance $3,632,400 1% Administratio n $7,264,800 2% Total Indirect Operating Cos t $14,529,600

Total Annual Operating Cost $38,630,200

TOTAL ANNUAL COST Annualized Capital Cost $31,973,800 Annual Operating Cost $38,630,200 Total Annual Cost $70,604,000 Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost (CUECost) Worksheet, using Sooner specific fuel specifications and boiler configuration.

Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet, modified to account for recent increases in equipment costs and commodities. Costs were compared to vendor quotes provided on other recent similar projects. TCR includes all costs required to purchase equipment, costs of labor and materials for installing teh equipment, costs for site preparation and buildings, and retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost Manual 6th Ed., page 2-34). Musko g ee Unit 4Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-12 

### BART Economic Evaluation – SO 2 

### Wet FGD Control System – Muskogee Unit 4

CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $302,835,000 General Facilities $30,284,000 Engineering Fees $30,284,000 Contingenc y $60,567,000 Total Plant Cost $423,970,000 Total Plant Cost (TPC) w/ Prime Contractor's Markup $436,689,000 Total Cash Expended (TCE) $370,662,000 Allow. for Funds During Constr. (AFDC) $36,621,000 Total Plant Investment (TPI) $407,283,000 Preproduction Costs $10,455,000 Inventory Capital $50,000 Total Capital Requirement (TCR) $417,788,000 Total Capital Investment ($/kW - gross) $730 Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.0858 25 years. Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $35,850,600 7% Assumed pretax marginal rate of return on private investment.

OPERATING COSTS Basis Operating & Maintenance Costs (based on 90% capacity factor) Variable O&M Costs

Limestone Reagent Cost $742,600 25 $ Based on maximum heat input, SO2 removal rate (lb/hr), 1.05 stoichiometry, 95% CaCO3, 90% capacity factor, and $25/ton for limestone. Water Cost $405,900 1.20 $ Based on 1.25 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal.

FGD Waste Disposal Cost $1,416,000 30 $ Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, forced oxidation 90% dry, and $30/ton on-site disposal cost. Disposal cost only includes additional WFGD by-products and does not include fly ash. No credit is assumed for by-product sales.

Auxiliary Power Cos t $4,566,000 45 $ Based on auxiliary power requirement of 2% (gross), 90% capacity factor, and $45/MW. Total Variable O&M Costs $7,130,500

Fixed O&M Costs
Additional Operators per shift 4.0 Based on S&L O&M estimate for wet FGD.

Operating Labor $1,173,800 3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an annual operator salary of $70,000/year. Supervisor Labor $176,100 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $15,141,800 5.0% Maintenance Default Factor for limestone scrubber with forced oxidation from EPA's Coal Utility Environmental Cost (CUECost) Workbook. Maintenance Labor $1,291,200 110.0% of operating labor. EPA Control Cost Manual, page 2-31 Total Fixed O&M Cos t $17,782,900

Indirect Operating Cost Property Taxes $4,072,800 1% Insurance $4,072,800 1% Administration $8,145,700 2% Total Indirect Operating Cost $16,291,300

Total Annual Operating Cost $41,204,700

TOTAL ANNUAL COST Annualized Capital Cost $35,850,600 Annual Operatin g Cost $41,204,700 Total Annual Cost $77,055,300 Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost (CUECost) Worksheet, using Sooner specific fuel specifications and boiler configuration.

Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet, modified to account for recent increases in equipment costs and commodities. Costs were compared to vendor quotes provided on other recent similar projects. TCR includes all costs required to purchase equipment, costs of labor and materials for installing teh equipment, costs for site preparation and buildin g s, and retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost Manual 6th Ed., page 2-34). Musko g ee Unit 4Oklahoma Gas & ElectricMuskogee Generating Station – BART DeterminationMay 28, 2008Page A-10BART Economic EvaluationSO2Summary – Muskogee Unit 5Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-10 

### BART Economic Evaluation – SO 2 

### Retrofit Control Technology – Capital Cost Summary – Muskogee Unit 5Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-11 

### BART Economic Evaluation – SO 2 

### Dry FGD Control System – Muskogee Unit 5

EQUIPMENT CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $270,447,000 General Facilities $27,045,000 Engineering Fees $27,045,000 Contingency $54,089,000 Total Plant Cost $378,626,000 Total Plant Cost (TPC) w/ Prime Contractor's Markup $389,985,000 Total Cash Expended (TCE) $331,019,000 Allow. for Funds During Constr. (AFDC) $32,705,000 Total Plant Investment (TPI) $363,724,000 Preproduction Costs $9,337,000 Inventory Capital $45,000 Total Capital Requirement (TCR) $373,106,000 Total Capital Investment ($/kW - gross) $652 Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.0858 25 years. Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $32,016,400 7% Assumed pretax marginal rate of return on private investment.

OPERATING COSTS Basis

Operating & Maintenance Costs Variable O&M Costs

Lime Reagent Cost $4,725,500 200 $ Based on maximum heat input, SO2 removal rate (lb/hr), 0.90 stoichiometry, 90% CaO, 90% capacity factor, and $200/ton for lime. Water Cost $276,000 1.20 $ Based on 0.85 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal

FGD Waste Disposal Cost $1,032,900 30 $ Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, and $30/ton on-site disposal cost. Disposal cost only includes FGD by-products and does not include fly ash.

Bag and Cage Replacement Costs $581,300 2.85 $ Based on the exhaust gas flow through the baghouse, air-to-cloth ratio of 3.5 for pulse jet baghouse, $2.85/ft2 bag cost (including fabric and hangers), 4% contingency for bag cleaning, and 3 year bag life.

Ash Disposal Costs $0 Assumed no increase in ash disposal with the fabric filter compared to the existing ESP control system.

Auxiliary Power Cost $3,044,000 45 $ Based on auxiliary power requirement of 1% (gross) for DFGD plus 0.5% (gross) for the baghouse, 90% capacity factor, and $45/MW. Total Variable O&M Costs $9,659,700

Fixed O&M Costs Additional Operators per shift 2.0 Based on S&L O&M estimate for dry FGD.

Operating Labor $586,900 3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an annual operato r salary of $70,000/year. Supervisor Labor $88,000 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $13,522,400 5.0% Maintenance Default Factor for lime spray dryer from EPA's Coal Utility Environmental Cost (CUECost) Workbook. Maintenance Labor $645,600 110.0% of operating labor. EPA Control Cost Manual, page 2-31 Total Fixed O&M Cost $14,842,900

Indirect Operating Cost Property Taxes $3,637,200 1% Insurance $3,637,200 1% Administration $7,274,500 2% Total Indirect Operating Cost $14,548,900

Total Annual Operating Cost $39,051,500

TOTAL ANNUAL COST Annualized Capital Cost $32,016,400 Annual Operatin g Cost $39,051,500 Total Annual Cost $71,067,900 Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost (CUECost) Worksheet, using Sooner specific fuel specifications and boiler configuration.

Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet, modified to account for recent increases in equipment costs and commodities. Costs were compared to vendor quotes provided on other recent similar projects. TCR includes all costs required to purchase equipment, costs of labor and materials for installing teh equipment, costs for site preparation and buildings, and retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost Manual 6th Ed., page 2-34). Musko g ee Unit 5Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page A-12 

### BART Economic Evaluation – SO 2 

### Wet FGD Control System – Muskogee Unit 5

CAPITAL COSTS Basis

Total Purchased Equipment Cost (PEC) $303,400,000 General Facilities $30,340,000 Engineering Fees $30,340,000 Contingenc y $60,680,000 Total Plant Cos t $424,760,000 Total Plant Cost (TPC) w/ Prime Contractor's Markup $437,503,000 Total Cash Expended (TCE) $371,353,000 Allow. for Funds During Constr. (AFDC) $36,690,000 Total Plant Investment (TPI) $408,043,000 Preproduction Costs $10,474,000 Inventory Capital $50,000 Total Capital Requirement (TCR) $418,567,000 Total Capital Investment ($/kW - gross) $732 Capital Recovery Factor = i(1+ i) n / (1 + i) n - 1 0.0858 25 years. Annualized Capital Costs (Capital Recover Factor x Total Capital Investment) $35,917,500 7% Assumed pretax marginal rate of return on private investment.

OPERATING COSTS Basis Operating & Maintenance Costs (based on 90% capacity factor) Variable O&M Costs

Limestone Reagent Cost $794,100 25 $ Based on maximum heat input, SO2 removal rate (lb/hr), 1.05 stoichiometry, 95% CaCO3, 90% capacity factor, and $25/ton for limestone. Water Cos t $405,900 1.20 $ Based on 1.25 gpm/MW-gross, 90% capacity factor, and $1.2/1000 gal.

FGD Waste Disposal Cos t $1,514,000 30 $ Based on maximum heat input, SO2 removal rate (lb/hr), 90% capacity factor, forced oxidation 90% dry, and $30/ton on-site disposal cost. Disposal cost only includes additional WFGD by-products and does not include fly ash. No credit is assumed for by-product sales.

Auxiliary Power Cos t $4,566,000 45 $ Based on auxiliary power requirement of 2% (gross), 90% capacity factor, and $45/MW. Total Variable O&M Costs $7,280,000

Fixed O&M Costs
Additional Operators per shift 4.0 Based on S&L O&M estimate for wet FGD.

Operating Labor $1,173,800 3 shifts/day, 365 days/year @ $33.50/hour (salary + benefits) which is equal to an annual operator salary of $70,000/year. Supervisor Labo r $176,100 15.0% of operating labor. EPA Control Cost Manual, page 2-31

Maintenance Materials $15,170,000 5.0% Maintenance Default Factor for limestone scrubber with forced oxidation from EPA's Coal Utility Environmental Cost (CUECost) Workbook. Maintenance Labor $1,291,200 110.0% of operating labor. EPA Control Cost Manual, page 2-31 Total Fixed O&M Cos t $17,811,100

Indirect Operating Cost Property Taxes $4,080,400 1% Insurance $4,080,400 1% Administratio n $8,160,900 2% Total Indirect Operating Cos t $16,321,700

Total Annual Operating Cost $41,412,800

TOTAL ANNUAL COST Annualized Capital Cost $35,917,500 Annual Operating Cost $41,412,800 Total Annual Cost $77,330,300 Equipment capital costs were based on U.S.EPA's Coal Utility Environmental Cost (CUECost) Worksheet, using Sooner specific fuel specifications and boiler configuration.

Total Capital Requirements were calculated using U.S.EPA's CUECost Worksheet, modified to account for recent increases in equipment costs and commodities. Costs were compared to vendor quotes provided on other recent similar projects. TCR includes all costs required to purchase equipment, costs of labor and materials for installing teh equipment, costs for site preparation and buildings, and retrofit costs.

Calculated as % of total capital investment (EPA Air Pollution Control Cost Manual 6th Ed., page 2-34). Musko g ee Unit 5Oklahoma Gas & Electric Muskogee Generating Station – BART Determination May 28, 2008

Page B-1 

### Attachment B

Muskogee Units 4 & 5

BART Determination – Visibility Impact Modeling Details

# CALPUFF M ODELING 

# R EPORT S 

# BART D ETERMINATION 

# O KLAHOMA 

# G AS 

# & E LECTRIC

M USKOGEE 

### G ENERATING 

### S TATION



### Prepared by:

T RINITY 

### C ONSULTANTS 

### 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 

## T ABLE OF 

## C ONTENTS



### 1. I NTRODUCTION 

### .................................................................................................... 1-1 1.1 B EST 

### A VAILABLE 

### R ETROFIT 

### T ECHNOLOGY 

### R ULE 

### B ACKGROUND 

### ......................... 1-1 1.2 M ODELING 

### P ROTOCOL 

### B ACKGROUND 

### .................................................................. 1-2 1.3 O BJECTIVE 

### ............................................................................................................ 1-2 1.4 L OCATION OF 

### S OURCES AND 

### R ELEVANT 

### C LASS 

### I A REAS 

### ...................................... 1-2

2. CALPUFF M ODEL 

### S YSTEM 

### ............................................................................... 2-1 2.1 M ODEL 

### V ERSIONS 

### ................................................................................................. 2-1 2.2 M ODELING 

### D OMAIN 

### ............................................................................................. 2-1

3. CALMET............................................................................................................ 3-1 3.1 G EOPHYSICAL 

### D ATA 

### ............................................................................................. 3-1
3.1.1 T ERRAIN 

### D ATA 

### ...................................................................................................3-1 3.1.2 L AND 

### U SE 

### D ATA 

### .................................................................................................3-2 3.1.3 C OMPILING 

### T ERRAIN AND LAND 

### U SE 

### D ATA 

### .......................................................3-3 

### 3.2 M ETEOROLOGICAL 

### D ATA 

### ..................................................................................... 3-3
3.2.1 M ESOSCALE 

### M ODEL 

### M ETEOROLOGICAL 

### D ATA 

### .................................................3-3 3.2.2 S URFACE 

### M ETEOROLOGICAL 

### D ATA 

### ...................................................................3-4 3.2.3 U PPER 

### A IR 

### M ETEOROLOGICAL 

### D ATA 

### .................................................................3-5 3.2.4 P RECIPITATION 

### M ETEOROLOGICAL 

### D ATA 

### ..........................................................3-7 3.2.5 B UOY 

### M ETEOROLOGICAL 

### D ATA 

### .........................................................................3-8 

### 3.3 CALMET C ONTROL 

### P ARAMETERS 

### ....................................................................... 3-9
3.3.1 V ERTICAL 

### M ETEOROLOGICAL 

### P ROFILE 

### ..............................................................3-9 3.3.2 I NFLUENCES OF 

### O BSERVATIONS 

### .......................................................................3-10



### 4. CALPUFF........................................................................................................... 4-1 4.1 S OURCE 

### E MISSIONS 

### ............................................................................................... 4-1 4.2 R ECEPTOR 

### L OCATIONS 

### .......................................................................................... 4-1 4.3 B ACKGROUND 

### O ZONE AND 

### A MMONIA 

### .................................................................. 4-1 4.4 CALPUFF M ODEL 

### C ONTROL 

### P ARAMETERS 

### ......................................................... 4-1

5. CALPOST........................................................................................................... 5-1

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 ii 

### 5.1 CALPOST

– L IGHT 

### E XTINCTION 

### A LGORITHM 

### ..................................................... 5-1 5.2 CALPOST P ROCESSING METHOD 

### ......................................................................... 5-2 5.3 N ATURAL 

### B ACKGROUND 

### ...................................................................................... 5-2 5.4 E VALUATING 

### V ISIBILITY 

### R ESULTS 

### ....................................................................... 5-2 5.5 S UMMARY OF 

### CALPOST C ONTROL 

### P ARAMETERS 

### ............................................... 5-2

6. V ISIBILITY 

### R ESULTS 

### ........................................................................................... 6-1

A PPENDIX 

### A- M ETEOROLOGICAL 

### S TATIONS



### A PPENDIX 

### B

– S AMPLE 

### CALMET C ONTROL 

### F ILE



### A PPENDIX 

### C

– S AMPLE 

### CALPUFF C ONTROL 

### F ILE



### A PPENDIX 

### D

– S AMPLE 

### CALPOST C ONTROL 

### F ILE



### A PPENDIX 

### E

– M USKOGEE 

### S TATION 

### E MISSION 

### S UMMARY

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 iii 

## L IST OF 

## T ABLES

T ABLE 

### 1-1. BART-E LIGIBLE 

### S OURCES 

### ...............................................................................................1-2

T ABLE 

### 1-2. D ISTANCE 

### F ROM 

### S TATION TO 

### S URROUNDING 

### C LASS 

### I A REAS 

### .......................................1-3

T ABLE 

### 2-1. CALPUFF M ODELING 

### S YSTEM 

### V ERSIONS 

### .....................................................................2-1

T ABLE 

### 3-1. V ERTICAL 

### L AYERS OF THE 

### CALMET M ETEOROLOGICAL 

### D OMAIN 

### ..............................3-10

T ABLE 

### 5-1. M ONTHLY 

### H UMIDITY 

### F ACTORS 

### .......................................................................................5-2

T ABLE 

### 5-2. D EFAULT 

### A VERAGE 

### A NNUAL 

### N ATURAL 

### B ACKGROUND 

### L EVELS 

### ...................................5-2

T ABLE 

### A-1. L IST OF 

### S URFACE METEOROLOGICAL 

### S TATIONS 

### ...........................................................A-1

T ABLE 

### A-2. L IST OF 

### U PPER 

### A IR METEOROLOGICAL 

### S TATIONS 

### .........................................................A-5

T ABLE 

### A-3. L IST OF 

### P RECIPITATION METEOROLOGICAL 

### S TATIONS 

### ..................................................A-6

T ABLE 

### A-4. L IST OF 

### O VER 

### W ATER METEOROLOGICAL 

### S TATIONS 

### ..................................................A-14

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 iv 

## L IST OF 

## F IGURES

F IGURE 

### 1-1. P LOT OF 

### S OURCES AND 

### N EAREST 

### C LASS 

### I A REAS 

### .........................................................1-3

F IGURE 

### 2-1. R EFINED 

### M ETEOROLOGICAL 

### M ODELING 

### D OMAIN 

### .........................................................2-2

F IGURE 

### 3-1. P LOT OF 

### L AND 

### E LEVATION 

### U SING 

### USGS T ERRAIN 

### D ATA 

### ............................................3-2

F IGURE 

### 3-2. P LOT OF 

### L AND 

### U SE 

### U SING 

### USGS LULC D ATA 

### .............................................................3-3

F IGURE 

### 3-3. P LOT OF 

### S URFACE 

### S TATION 

### L OCATIONS 

### ........................................................................3-5

F IGURE 

### 3-4. P LOT OF 

### U PPER 

### A IR 

### S TATIONS 

### L OCATIONS 

### ...................................................................3-6

F IGURE 

### 3-5. P LOT OF 

### P RECIPITATION METEOROLOGICAL 

### S TATIONS 

### .................................................3-8

F IGURE 

### 3-6. P LOT OF 

### B UOY 

### M ETEOROLOGICAL 

### S TATIONS 

### ................................................................3-9

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 1-1 

## 1. I NTRODUCTION

Oklahoma Gas & Electric (OG&E) owns and operates three electric generating stations near Muskogee, Oklahoma (Muskogee Generating Stati on), Seminole, Oklahoma (Seminole Generating Station), and Stillwater, Oklahoma (Sooner Genera ting Station). These generating stations are considered eligible to be regulated under the U. S. Environmental Protection Agency’s (EPA) Best Available Retrofit Technology (BART) pr ovisions of the Regional Haze Rule.

This report summarizes the results of CALPUFF modeling performed for the Muskogee Generating Station. Modeling methodology used in the analys is is described in this report along with final visibility impact results.



## 1.1 B EST 

## A VAILABLE 

## R ETROFIT 

## T ECHNOLOGY 

## R ULE 

## B ACKGROUND

On July 1, 1999, the U.S. Environmental EPA pub lished 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 B est Available Retrofit Technology (BART) determinations. The BART rule defines BART-e ligible 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 an ticipated 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 impa irment 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 dete rmine a source’s visibility impacts. States have the authority to exempt certain BART-eligible sources fro m installing BART controls if the results of the dispersion modeling demonstrate that the source cannot reasonably be anticipated to cause or contribute to visibility impairment in a Class I area. Further, states also have the authority to define the modeling procedures for conducting modeling related to making BART determinations.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 1-2 

## 1.2 M ODELING 

## P ROTOCOL 

## B ACKGROUND

To promote consistency between states in the de velopment of BART modeling protocols and to harmonize the approaches between adjacent RPOs, the Central States Regional Air Planning (CENRAP) organization developed BART Modeling Gu idelines (December 15, 2005). The intent of the guidelines is to assist CENRAP states and sour ce operators in the development of statewide and source-specific modeling protocols.



## 1.3 O BJECTIVE

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 me thods and procedures will be used to determine appropriate controls for OG&E’s BART-eligible so urces 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 emissi ons controls that will reduce the impact of each generating station to a degree that the 98 th 

### 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 L OCATION OF 

## S OURCES AND 

## R ELEVANT 

## C LASS 

## I A REAS

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-eligib le sources at the Muskogee Station.

T ABLE 

### 1-1. BART-E LIGIBLE 

### S OURCES 

### (M USKOGEE 

### S TATION 

### )

EPN Description Unit 4 5,480 MMBtu/hr Coal Fired Boiler Unit 5 5,480 MMBtu/hr Coal Fired Boiler



### As required in CENRAP’s BART Modeling Guidelines, Class I areas within 300 km of each station will be included in each analysis. The following tables summarize the distances of the four closest Class I areas to each station. As seen from this summ ary, some Class I areas are more than 300 km from the certain stations. However, in order to de monstrate that each station will not have an adverse effect on the visibility at any of the four nearest Class I areas, OG&E has opted to include those Class I areas more than 300 km away in this analysis. Note that the distances listed in the tables below are the distances between the stations and the closest border of the Class I areas.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 1-3 T ABLE 

### 1-2. D ISTANCE 

### F ROM 

### S TATION TO 

### S URROUNDING 

### C LASS 

### I A REAS

CACR HEGL UPBU WIMO Muskogee 180 230 164 324



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



### F IGURE 

### 1-1. P LOT OF 

### S OURCES AND 

### N EAREST 

### C LASS 

### I A REAS

-800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000

-800 -600 -400 -200LCC Northing (km) Seminole Station Muskogee Station Sooner Station

WIMO CACR UPBU HEGL

Class I Areas

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 2-1 

## 2. CALPUFF M ODEL 

## S YSTEM

The main components of the CALPUFF modeling system are CALMET, CALPUFF, and CALPOST. CALMET is the meteorological model that generat es hourly three-dimensional meteorological fields such as wind and temperature. CALPUFF simulates the non-steady state transport, dispersion, and chemical transformation of air pollutants emitte d from a source in “puffs.” CALPUFF calculates hourly concentrations of visibility affecting po llutants at each specified receptor in a modeling domain. CALPOST is the post-processor for CA LPUFF that computes visibility impacts from a source based on the visibility affecting pollutant concentrations that were output by CALPUFF.



## 2.1 M ODEL 

## V ERSIONS

The versions of the CALPUFF modeling system programs that are proposed for conducting OG&E’s BART modeling are listed in Table 2-1.

T ABLE 

### 2-1. CALPUFF M ODELING 

### S YSTEM 

### V ERSIONS



### 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 M ODELING 

## D OMAIN

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 ar e advected and tracked only while within the computational grid. The meteorological grid is de fined so that it covers the areas of concern and gives enough marginal buffer area for puff transport and dispersion. A plot of the proposed meteorological modeling domain with respect to the Class I areas being modeled is also provided in

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 2-2 Figure 2-1. The computational domain will be set to extend at least 50 km in all directions beyond the Muskogee, Seminole, and Sooner Generating Stati ons 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.



### F IGURE 

### 2-1. R EFINED 

### M ETEOROLOGICAL 

### M ODELING 

### D OMAIN

-800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000

-800 -600 -400 -200

L C C N o r t h i n g ( k m ) Seminole Station Muskogee Station Sooner Statio n

WIMO CAC R UPBU HEGL

Class I Areas Meteorological Modeling Domain

Computational Modeling Domain 1

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-1 

## 3. CALMET

CALMET is the meteorological processor that compiles meteorological data from raw observations of surface and upper air conditions, precipitation measurements, mesoscale model output, and geophysical parameters into a single hourly, gr idded data set for input into CALPUFF. CALMET will be used to assimilate data for 2001- 2003 us ing National Weather Service (NWS) surface station observations, upper air station observations, preci pitation station observations, buoy station observations (for overwater areas), and mesoscale mode l output to develop the meteorological field.



## 3.1 G EOPHYSICAL 

## D ATA

CALMET requires geophysical data to characteri ze the terrain and land use parameters that potentially affect dispersion. Terrain features affe ct flows and create turbulence in the atmosphere and are potentially subjected to hi gher concentrations of elevated puffs. Different land uses exhibit variable characteristics such as surface roughness, al bedo, Bowen ratio, and leaf-area index that also effect turbulence and dispersion.



### 3.1.1 T ERRAIN 

### D ATA



### Terrain data will be obtained from the Unite d States Geological Survey (USGS) in 1-degree (1:250,000 scale or approximately 90 meter resolution) digital format. The USGS terrain data will then be processed by the TERREL program to generate grid-cell elevation averages across the modeling domain. A plot of the land elevations based on the USGS data for the modeling domain is provided in Figure 3-1.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-2 

### F IGURE 

### 3-1. P LOT OF 

### L AND 

### E LEVATION 

### U SING 

### USGS T ERRAIN 

### D ATA



### 3.1.2 L AND 

### U SE 

### D ATA



### 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 th e modeling domain. The LULC data will be processed by the CTGPROC program which w ill generate land use for each grid cell across the modeling domain. A plot of th e land use based on the USGS data for the modeling domain is provided in Figure 3-2. -800 -600 -400 -200 0 200 400 600 800 LCC Easting(km) -1600 -1400 -1200 -1000

-800 -600 -400 -200

L C C N o r t h i n g ( k m ) Seminole Station Muskogee Station Sooner Station

0 982 1960 2950 3930

Terrain Elevation (m)

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-3 

### F IGURE 

### 3-2. P LOT OF 

### L AND 

### U SE 

### U SING 

### USGS LULC D ATA



### 3.1.3 C OMPILING 

### T ERRAIN AND LAND 

### U SE 

### D ATA



### 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 M ETEOROLOGICAL 

## D ATA

CALMET will be used to assimilate data for 2001, 2002, and 2003 using mesoscale model output and National Weather Service (NWS) surface stati on observations, upper air station observations, precipitation station observations, and National O ceanic and Atmosphere Administrations (NOAA) buoy station observations to develop the meteorological field.



### 3.2.1 M ESOSCALE 

### M ODEL 

### M ETEOROLOGICAL 

### D ATA



### 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 5 th 

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

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

• 2002 MM5 data at 36 km resolution generated by the Iowa DNR -800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000 -800 -600 -400 -200

L C C N o r t h i n g ( k m )

10 27.5 45 62.5 80

Land Use Sooner Station

Muskogee Station

Seminole Station

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-4 • 2003 MM5 data set at 36 km resolution generated by the Midwest RPO

The specific MM5 data that will be used are subsets of the data listed above. As the contractor to CENRAP for developing the meteorological data sets for the BART modeling, Alpine Geophysics extracted thr ee 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 wh ich 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 H our 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 behi nd 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 S URFACE 

### M ETEOROLOGICAL 

### D ATA


### Parameters affecting turbulent dispersion that are observed hourly at surface stations include wind speed and direction, temperatur e, 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 th e domain. Data from the stations will be processed for use in CALMET using EPA’s SMERGE program.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-5 Missing surface data was filled using procedures recommended by U.S. EPA. 1 

### Missing data periods of 5 hours or less were replaced using these procedures. For periods greater than 5 hours, data was left either unfilled or was not used in CALMET processing. A large enough quantity of surface stations was included in the domain that overlapping areas of influence allowed data from an alternate station to be used.



### F IGURE 

### 3-3. P LOT OF 

### S URFACE 

### S TATION 

### L OCATIONS



### 3.2.3 U PPER 

### A IR 

### M ETEOROLOGICAL 

### D ATA



### Observations of meteorological conditions in the upper atmosphere provide a profile of turbulence from the surface through the depth of the boundary layer in which dispersion occurs. Upper air data are collected by balloons launched simultaneously across the observation network at 0000 Greenwich Mean Time (GMT) (6 o’clock PM in Oklahoma)

1 “Procedures for Substituting Values for Missing NWS Me teorological Data for Use in Regulatory Air Quality Models”, Dennis Atkinson and Russe ll F. Lee, July 7, 1992, http://www. epa.gov/scram001/surfa ce/missdata.txt -800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000

-800 -600 -400 -200

L C C N o r t h i n g ( k m ) Seminole Station Muskogee Station Sooner Statio n

WIMO CACR UPBU HEGL

Class I Areas Surface Stations

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-6 and 1200 GMT (6 o’clock AM in Oklahoma). Sensors observe pressure, wind speed and direction, and temperature (among other pa rameters) 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 sta tions that are proposed for this analysis are listed in Table A-2 of Appendix A. The locati ons 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 hour s are representative of the missing period. Data from either the preceding or following hours were extrapolated to fill the missing hour.



### F IGURE 

### 3-4. P LOT OF 

### U PPER 

### A IR 

### S TATIONS 

### L OCATIONS

-800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000

-800 -600 -400 -200LCC Northing (km) Seminole Station Muskogee Station Sooner Station

WIMO CACR UPBU HEGL

Class I Areas

Upper Air Stations

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-7 

### 3.2.4 P RECIPITATION 

### M ETEOROLOGICAL 

### D ATA



### The effects of chemical transformation and deposition processes on ambient pollutant concentrations will be considered in this an alysis. Therefore, it is necessary to include observations of precipitation in the CALMET anal ysis. The precipitation stations that are proposed for this analysis are listed in Table A-3 of Appendix A. The locations of the precipitation stations with respect to the modeling domain are shown in Figure 3-5. These stations were selected from the available data inventory to optimize spatial coverage and representation of the domain. Data from the stations will be processed for use in CALMET using EPA’s PMERGE program.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-8 

### F IGURE 

### 3-5. P LOT OF 

### P RECIPITATION METEOROLOGICAL 

### S TATIONS

-800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000

-800 -600 -400 -200LCC Northing (km) Seminole Station Muskogee Station Sooner Station

WIMO CACR UPBU HEGL

Class I Areas Precipitation Stations



### 3.2.5 B UOY 

### M ETEOROLOGICAL 

### D ATA



### The effects of land/sea breeze on ambient polluta nt 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 sta tions 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 pr epared by filling missing hour records with the CALMET missing parameter value (9999). No adjustments to the data will occur.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-9 

### F IGURE 

### 3-6. P LOT OF 

### B UOY 

### M ETEOROLOGICAL 

### S TATIONS

-800 -600 -400 -200 0 200 400 600 800 LCC Easting (km) -1600 -1400 -1200 -1000

-800 -600 -400 -200LCC Northing (km) Seminole Station Muskogee Station Sooner Station

WIMO CACR UPBU HEGL

Class I Areas Buoy Stations



## 3.3 CALMET C ONTROL 

## P ARAMETERS

Appendix B provides a sample CALMET input file used in OG&E’s modeling analysis. A few details of the CALMET model setup for sensitiv e parameters are also discussed below.



### 3.3.1 V ERTICAL 

### M ETEOROLOGICAL 

### P ROFILE


### 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 w ill 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 laye r while using a somewhat coarser resolution for the layers aloft.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-10 T ABLE 

### 3-1. V ERTICAL 

### L AYERS OF THE 

### CALMET M ETEOROLOGICAL 

### D OMAIN

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 th e relative weight given to the vertically extrapolated surface and upper air wind and temperature observations. The initial guess fields are computed with an inverse distance weighting (1/r 2 

### ) of the surface and upper air data. The initial guess fields may be modified by a layer dependent bias factor. Values for the bias factor may range from -1 to +1. A bias of -1 eliminates upper-air observations in the 1/r 2 

### interpolations used to initialize the vertical wind fields. Conversely, a bias of +1 eliminates the surface observations in the interpola tions 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/r 2 

### 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 IEXT RP 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 sim ilarity 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 I NFLUENCES OF 

### O BSERVATIONS



### 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 adju st the Step 1 wind field by incorporating the influence of local observations. An inver se distance method is used to determine the influence of observations to the Step 1 wind field. RMAX1 and RMAX2 define the radius of influence for data from surface stations to land in the surface layer and data from upper air stations to land in the layers aloft. In general, RMAX1 and RMAX2 are used to exclude observations from being inappropriately included in the development of the Step 2

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 3-11 wind field if the distance from an observation station to a grid point exceeds the maximum radius of influence.

If the distance from an observation station to a grid point is less than the value set for RMAX, the observation data will be used in the development of the Step 2 wind field. R1 represents the distance from a surface observa tion 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 va lues 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 surf ace observation data from all surface stations to 20 km from each station, and will equally wei ght 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 domai n to be modeled. RAMX 3 will be set to 500 km.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 4-1 

## 4. CALPUFF

The CALPUFF model uses the output file from CA LMET together with source, receptor, and chemical reaction information to predict hourly c oncentration impacts. OG&E proposes to conduct a three-year CALPUFF analysis using data and model settings as described below.



## 4.1 S OURCE 

## E MISSIONS

Baseline (pre-BART) emission data is based upon CEMS data collected by OG&E over the 2002- 2005 time frame. In accordance with CENRAP guidelines, the emission rate over the highest calendar day (24-hr average) was used to establish baseline emissions.

Emission estimates for various control scenarios were developed by Sargent and Lundy. The effectiveness of a number of different control technologies for NOx, SO 2 

### , and PM 10 

### were examined. Emission estimates for these various scenarios are included in Appendix E. Please note that OG&E has elected to evaluate co st effectiveness on a facility-wide basi s (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 R ECEPTOR 

## L OCATIONS

The National Park Service (NPS) has electronic f iles 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 B ACKGROUND 

## O ZONE AND 

## A MMONIA

Background ozone concentrations ar e required in order to model the photochemical conversion of SO 2 

### and NO X 

### to sulfates (SO 4 

### ) and nitrates (NO 3 

### ). CALPUFF can use either a single background value representative of an area or hourly ozone da ta from one or more ozone monitoring stations. Hourly ozone data files will be used in the CA LPUFF simulation. As provided by the Oklahoma DEQ, hourly ozone data from the Oklahoma C ity, Glenpool, and Lawton monitors over the 2001- 2003 time frame will be used. Background concen trations for ammonia will be assumed to be temporally and spatially invarian t and will be set to 3 ppb.



## 4.4 CALPUFF M ODEL 

## C ONTROL 

## P ARAMETERS

Appendix C provides a sample CALPUFF input file th at is proposed for the OG&E refined modeling analyses. Please note that puff splitting is a generally accepted option in refined modeling analyses over large model domains for assessing impacts on Class I areas; however, this option would require significant computer resources and longer runtime. Based upon previous model runs performed on domains (and restricted computational grids) of the size described in this report, it is expected that runtimes could increase by a factor for 4 to 5 with the inclusion of puff-splitting. Due to this, OG&E

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 4-2 will evaluate the use of this option during the mode ling analysis and provide details in the modeling report about its use.

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 5-1 

## 5. CALPOST

A three-year CALPOST analysis will be conducted to determine the visibility change in deciview (dv) caused by OG&E’s BART-eligible sources when compared to a natural background.



## 5.1 CALPOST

– L IGHT 

## E XTINCTION 

## A LGORITHM

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 lig ht extinction and the u pdated light extinction calculation algorithms developed by the Interagency Monitoring of Protected Visual Environments (IMPROVE) workgroup will be used to assess vi sibility impacts from the Muskogee Station.

The background extinction coefficient b ext, background 

### is affected by various chemical species and the Rayleigh scattering phenomenon. The original equati on for the background extinction coefficient in the FLM’s FLAG guidance is as follows: 

# ( )
Ray ap Coarse Soil OC NO SO background ext 

### b b b b b b b Mm b + + + + + + = − 3 4 1

,



### where,


## ( ) 

## [ ] ( ) 

## [ ] ( ) 

## [ ] [ ] [ ] [ ] 

# ( ) ( ) 

## [ ] 3 1 3 4 3 4 2 4 4

m μg in ion Concentrat Function Humidity Relative default by Mm 10 Scattering Rayleigh

EC 10 Mass Coarse 6

. 0 Soil 1 OC 4 NO NH 3 SO

NH 3

= =

= = = = = = =

−

RH f b b b b b RH f b RH f b

Ray

ap Coarse Soil OC NO SO 

## ( ) 

## [ ] [ ] [ ] [ ] [ ] [ ]

molecules air to due scattering is Scattering Rayleigh carbon elemental of ion concentrat the denotes EC dusts coarse of ion concentrat the denotes Mass Coarse soils fine of ion concentrat the denotes Soil carbon organic of ion concentrat the denotes OC ion concentrat nitrate ammonium the denotes NO NH ion concentrat sulfate ammonium the denotes SO NH

3 4 4 2 4

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 5-2 

## 5.2 CALPOST P ROCESSING METHOD

CALPOST Method 6, which calculates hourly light ex tinction 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 humid ity 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.

T ABLE 

### 5-1. M ONTHLY 

### H UMIDITY 

### F ACTORS



### 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 N ATURAL 

## B ACKGROUND

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.

T ABLE 

### 5-2. D EFAULT 

### A VERAGE 

### A NNUAL 

### N ATURAL 

### B ACKGROUND 

### L EVELS



### Class I Area Region SO 4 

### NO 3 

### 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 E VALUATING 

## V ISIBILITY 

## R ESULTS

When evaluating cost-control effectiveness of the various control scenarios, OG&E will examine the 98 th 

### percentile of the 2001-2003 daily ∆ dv values output by CALPOST. Peak 24-hr impact values will be included for reference.



## 5.5 S UMMARY OF 

## CALPOST C ONTROL 

## P ARAMETERS

Appendix E provides a sample CALPOST input f ile that OG&E is proposing for the modeling analysis. Variable values that differ from the CE NRAP protocol are generally the result of data input/output handling issues (e.g., types of output, receptor numbers, etc.).

### OG&E / Sargent & Lundy Trinity Consultants BART Modeling Report 083701.0004 6-1 

## 6. V ISIBILITY 

## R ESULTS

A summary of visibility impacts from the various co ntrol scenarios described in Section 4 is included below. In addition to the 98 th 

### percentile values typically examined in BART analyses, peak 24-hr impacts are also included below.



### T ABLE 

### 6-1. M USKOGEE 

### S TATION 

### V ISIBILITY 

### R ESULTS

Peak Impact 98th Percentile

Pollutant Class I Area Control Technology ( ∆ dv) % Reduction from previous % Reduction from Baseline ( ∆ dv) % Reduction from previous % Reduction from Baseline NOx Caney Creek Baseline 3.54 -- -- 1.06 -- -- LNB/OFA 1.11 69% 69% 0.32 70% 70% SCR 0.54 52% 85% 0.14 56% 87% Herc-Glades Baseline 2.21 -- -- 0.47 -- -- LNB/OFA 0.69 69% 69% 0.14 71% 71% SCR 0.31 55% 86% 0.06 54% 87% Upper Buffalo Baseline 3.66 -- -- 0.84 -- -- LNB/OFA 1.21 67% 67% 0.24 71% 71% SCR 0.58 52% 84% 0.11 53% 86% Wichita Mts Baseline 2.16 -- -- 0.61 -- -- LNB/OFA 0.69 68% 68% 0.18 71% 71% SCR 0.31 55% 86% 0.08 55% 87% PM 10 Caney Creek Baseline 0.52 -- -- 0.17 -- -- Polishing Filter 0.31 41% 41% 0.11 38% 38% Herc-Glades Baseline 0.23 -- -- 0.09 -- -- Polishing Filter 0.15 38% 38% 0.05 45% 45% Upper Buffalo Baseline 0.51 -- -- 0.14 -- -- Polishing Filter 0.33 35% 35% 0.09 41% 41% Wichita Mts Baseline 0.21 -- -- 0.08 -- -- Polishing Filter 0.13 39% 39% 0.04 41% 41% SO 2 /H 2 SO 4 Caney Creek Baseline 4.17 -- -- 1.47 -- -- DFGD 0.65 84% 84% 0.20 87% 87% WFGD 0.64 2% 85% 0.24 -24% 83% Herc-Glades Baseline 2.52 -- -- 0.92 -- -- DFGD 0.43 83% 83% 0.12 87% 87% WFGD 0.50 -14% 80% 0.13 -9% 86% Upper Buffalo Baseline 3.72 -- -- 1.28 -- -- DFGD 0.60 84% 84% 0.17 87% 87% WFGD 0.74 -25% 80% 0.19 -16% 85% Wichita Mts Baseline 3.13 -- -- 1.18 -- -- DFGD 0.51 84% 84% 0.15 87% 87% WFGD 0.54 -5% 83% 0.14 3% 88%

### OG&E / Sargent & Lundy A-1 Trinity Consultants BART Modeling Report 083701.0004 

## A PPENDIX 

## A- M ETEOROLOGICAL 

## S TATIONS

T ABLE 

### A-1. L IST OF 

### S URFACE METEOROLOGICAL 

### S TATIONS

Number Station Acronym Station ID LCC East (km) LCC North (km) Long Lat
1 KDYS 69019 -267.672 -834.095 96.9968 39.9925
2 KNPA 72222 932.565 -1020.909 97.0110 39.9908
3 KBFM 72223 857.471 -996.829 97.0101 39.9910
4 KGZH 72227 946.767 -899.515 97.0112 39.9919
5 KTCL 72228 870.843 -706.104 97.0103 39.9936
6 KNEW 53917 674.172 -1078.342 97.0080 39.9903
7 KNBG 12958 677.719 -1104.227 97.0080 39.9900
8 BVE 12884 741.996 -1153.463 97.0088 39.9896
9 KPTN 72232 550.88 -1124.295 97.0065 39.9898
10 KMEI 13865 774.911 -814.225 97.0092 39.9926
11 KPIB 72234 728.416 -915.165 97.0086 39.9917
12 KGLH 72235 557.072 -703.097 97.0066 39.9936
13 KHEZ 11111 540.777 -912.22 97.0064 39.9918
14 KMCB 11112 622.755 -949.618 97.0074 39.9914
15 KGWO 11113 640.102 -695.286 97.0076 39.9937
16 KASD 72236 692.381 -1043.261 97.0082 39.9906
17 KPOE 72239 363.294 -984.839 97.0043 39.9911
18 KBAZ 72241 -102.133 -1140.886 96.9988 39.9897
19 KGLS 72242 215.108 -1185.604 97.0025 39.9893
20 KDWH 11114 140.413 -1101.174 97.0017 39.9900
21 KIAH 12960 158.266 -1108.37 97.0019 39.9900
22 KHOU 72243 167.147 -1147.402 97.0020 39.9896
23 KEFD 12906 178.551 -1152.782 97.0021 39.9896
24 KCXO 72244 152.739 -1069.309 97.0018 39.9903
25 KCLL 11115 60.898 -1044.381 97.0007 39.9906
26 KLFK 93987 214.643 -969.355 97.0025 39.9912
27 KUTS 11116 136.056 -1026.773 97.0016 39.9907
28 KTYR 11117 150.451 -846.207 97.0018 39.9924
29 KCRS 72246 56.655 -882.642 97.0007 39.9920
30 KGGG 72247 214.572 -841.163 97.0025 39.9924
31 KGKY 11118 -9.365 -812.25 96.9999 39.9927
32 KDTN 72248 304.827 -821.713 97.0036 39.9926
33 KBAD 11119 312.743 -825.101 97.0037 39.9925
34 KMLU 11120 465.834 -816.211 97.0055 39.9926
35 KTVR 11121 561.446 -840.225 97.0066 39.9924
36 KTRL 11122 68.599 -806.417 97.0008 39.9927
37 KOCH 72249 216.81 -930.252 97.0026 39.9916
38 KBRO 12919 -44.167 -1571.387 96.9995 39.9858

### OG&E / Sargent & Lundy A-2 Trinity Consultants BART Modeling Report 083701.0004 Number Station Acronym Station ID LCC East (km) LCC North (km) Long Lat
39 KALI 72251 -103.012 -1363.74 96.9988 39.9877
40 KLRD 12920 -246.548 -1381.603 96.9971 39.9875
41 KSSF 72252 -143.386 -1183.35 96.9983 39.9893
42 KRKP 11123 -4.965 -1324.914 96.9999 39.9880
43 KCOT 11124 -219.097 -1280.964 96.9974 39.9884
44 KLBX 11125 150.245 -1207.466 97.0018 39.9891
45 KSAT 12921 -143.024 -1160.935 96.9983 39.9895
46 KHDO 12962 -211.702 -1178.172 96.9975 39.9894
47 KSKF 72253 -154.625 -1177.555 96.9982 39.9894
48 KHYI 11126 -84.156 -1122.487 96.9990 39.9899
49 KTKI 72254 38.788 -754.791 97.0005 39.9932 50 KBMQ 11127 -118.39 -1027.031 96.9986 39.9907
51 KATT 11128 -67.587 -1075.97 96.9992 39.9903
52 KSGR 11129 131.478 -1151.702 97.0016 39.9896
53 KGTU 11130 -65.624 -1033.173 96.9992 39.9907
54 KVCT 12912 6.587 -1236.788 97.0001 39.9888
55 KPSX 72255 73.878 -1253.33 97.0009 39.9887
56 KACT 13959 -22.12 -929.156 96.9997 39.9916
57 KPWG 72256 -30.147 -944.073 96.9996 39.9915
58 KILE 72257 -65.288 -988.507 96.9992 39.9911
59 KGRK 11131 -79.643 -990.173 96.9991 39.9911
60 KTPL 11132 -38.203 -981.19 96.9996 39.9911
61 KPRX 13960 143.317 -703.663 97.0017 39.9936
62 KDTO 72258 -17.018 -752.974 96.9998 39.9932
63 KAFW 11133 -29.564 -777.061 96.9997 39.9930
64 KFTW 72259 -34.302 -795.502 96.9996 39.9928
65 KMWL 11134 -99.769 -798.767 96.9988 39.9928
66 KRBD 11135 12.453 -810.467 97.0002 39.9927
67 KDRT 11136 -384.069 -1170.59 96.9955 39.9894
68 KFST 22010 -566.418 -988.838 96.9933 39.9911
69 KGDP 72261 -739.127 -873.302 96.9913 39.9921
70 KSJT 72262 -333.338 -952.54 96.9961 39.9914
71 KMRF 23034 -676.265 -1042.616 96.9920 39.9906
72 KMAF 72264 -489.668 -878.107 96.9942 39.9921
73 KINK 23023 -586.882 -890.654 96.9931 39.9920
74 KABI 72265 -252.044 -836.353 96.9970 39.9924
75 KLBB 13962 -445.006 -689.313 96.9948 39.9938
76 KATS 11137 -696.818 -763.258 96.9918 39.9931 77 KCQC 11138 -785.757 -515.724 96.9907 39.9953
78 KROW 23009 -698.822 -712.898 96.9918 39.9936
79 KSRR 72268 -789.593 -686.226 96.9907 39.9938
80 KCNM 11139 -682.79 -822.109 96.9919 39.9926
81 KALM 36870 -838.056 -752.338 96.9901 39.9932
82 KLRU 72269 -931.527 -804.112 96.9890 39.9927

### OG&E / Sargent & Lundy A-3 Trinity Consultants BART Modeling Report 083701.0004 Number Station Acronym Station ID LCC East (km) LCC North (km) Long Lat
83 KTCS 72271 -952.353 -695.469 96.9888 39.9937
84 KSVC 93063 -1042.03 -752.033 96.9877 39.9932
85 KDMN 72272 -1006.77 -799.231 96.9881 39.9928
86 KMSL 72323 854.846 -536.687 97.0101 39.9952
87 KPOF 72330 578.62 -336.733 97.0068 39.9970
88 KGTR 11140 779.065 -689.108 97.0092 39.9938
89 KTUP 93862 753.875 -600.337 97.0089 39.9946
90 KMKL 72334 727.051 -454.383 97.0086 39.9959
91 KLRF 72340 440.654 -550.661 97.0052 39.9950
92 KHKA 11141 643.365 -424.419 97.0076 39.9962
93 KHOT 72341 358.094 -604.603 97.0042 39.9945
94 KTXK 11142 278.022 -720.623 97.0033 39.9935 95 KLLQ 72342 488.655 -698.008 97.0058 39.9937
96 KMWT 72343 254.18 -599.224 97.0030 39.9946
97 KFSM 13964 237.97 -512.87 97.0028 39.9954
98 KSLG 72344 224.881 -419.064 97.0027 39.9962
99 KVBT 11143 248.074 -399.892 97.0029 39.9964
100 KHRO 11144 343.525 -405.601 97.0041 39.9963
101 KFLP 11145 404.239 -399.142 97.0048 39.9964
102 KBVX 11146 480.712 -457.853 97.0057 39.9959
103 KROG 11147 258.44 -397.685 97.0031 39.9964
104 KSPS 13966 -138.053 -664.886 96.9984 39.9940
105 KHBR 72352 -186.121 -551.123 96.9978 39.9950
106 KCSM 11148 -198.844 -513.911 96.9977 39.9954
107 KFDR 11149 -181.653 -625.205 96.9979 39.9944
108 KGOK 72353 -35.905 -458.97 96.9996 39.9959
109 KTIK 72354 -34.581 -506.938 96.9996 39.9954
110 KPWA 11150 -58.596 -493.951 96.9993 39.9955
111 KSWO 11151 -7.42 -425.828 96.9999 39.9962
112 KMKO 72355 146.972 -479.879 97.0017 39.9957
113 KRVS 72356 91.059 -438.276 97.0011 39.9960
114 KBVO 11152 87.136 -357.069 97.0010 39.9968
115 KMLC 11153 110.647 -563.566 97.0013 39.9949
116 KOUN 72357 -40.731 -527.298 96.9995 39.9952
117 KLAW 11154 -129.405 -600.222 96.9985 39.9946
118 KCDS 72360 -300.297 -610.668 96.9965 39.9945
119 KGNT 72362 -985.117 -475.563 96.9884 39.9957
120 KGUP 11155 -1059.48 -427.151 96.9875 39.9961
121 KAMA 23047 -425.319 -518.171 96.9950 39.9953
122 KBGD 72363 -395.603 -466.083 96.9953 39.9958
123 KFMN 72365 -993.449 -297.944 96.9883 39.9973
124 KSKX 72366 -770.464 -355.855 96.9909 39.9968
125 KTCC 23048 -597.271 -511.241 96.9930 39.9954
126 KLVS 23054 -732.565 -448.329 96.9914 39.9960

### OG&E / Sargent & Lundy A-4 Trinity Consultants BART Modeling Report 083701.0004 Number Station Acronym Station ID LCC East (km) LCC North (km) Long Lat
127 KEHR 72423 812.573 -199.695 97.0096 39.9982
128 KEVV 93817 822.929 -172.715 97.0097 39.9984
129 KMVN 72433 704.666 -154.54 97.0083 39.9986
130 KMDH 11156 676.745 -218.041 97.0080 39.9980
131 KBLV 11157 617.659 -136.018 97.0073 39.9988
132 KSUS 3966 547.898 -130.122 97.0065 39.9988
133 KPAH 3816 725.985 -293.319 97.0086 39.9974
134 KJEF 72445 419.01 -145.496 97.0050 39.9987
135 KAIZ 11158 387.096 -200.609 97.0046 39.9982
136 KIXD 72447 182.322 -126.913 97.0022 39.9989
137 KWLD 72450 0 -298.57 97.0000 39.9973
138 KAAO 11159 -18.976 -248.773 96.9998 39.9978
139 KIAB 11160 -23.392 -263.471 96.9997 39.9976
140 KEWK 11161 -24.645 -215.58 96.9997 39.9981
141 KGBD 72451 -161.892 -180.781 96.9981 39.9984
142 KHYS 11162 -195.191 -124.723 96.9977 39.9989
143 KCFV 11163 126.442 -319.698 97.0015 39.9971
144 KFOE 72456 114.618 -115.26 97.0014 39.9990
145 KEHA 72460 -432.761 -320.089 96.9949 39.9971
146 KALS 72462 -777.592 -245.892 96.9908 39.9978
147 KDRO 11164 -945.713 -259.163 96.9888 39.9977
148 KLHX 72463 -568.426 -195.178 96.9933 39.9982
149 KSPD 2128 -494.076 -285.176 96.9942 39.9974
150 KCOS 93037 -664.022 -102.596 96.9922 39.9991
151 KGUC 72467 -857.452 -115.301 96.9899 39.9990
152 KMTJ 93013 -940.981 -109.358 96.9889 39.9990
153 KCEZ 72476 -1020.87 -233.14 96.9880 39.9979
154 KCPS 72531 591.652 -136.14 97.0070 39.9988
155 KLWV 72534 808.939 -94.46 97.0096 39.9992
156 KPPF 74543 130.433 -293.855 97.0015 39.9973
157 KHOP 74671 841.751 -324.569 97.0099 39.9971
158 KBIX 74768 778.252 -1028.514 97.0092 39.9907 159 KPQL 11165 814.599 -1019.583 97.0096 39.9908
160 MMPG 76243 -348.007 -1248.779 96.9959 39.9887
161 MMMV 76342 -446.576 -1449.334 96.9947 39.9869
162 MMMY 76394 -316.664 -1581.176 96.9963 39.9857

### OG&E / Sargent & Lundy A-5 Trinity Consultants BART Modeling Report 083701.0004 T ABLE 

### A-2. L IST OF 

### U PPER 

### A IR METEOROLOGICAL 

### S TATIONS

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 T ABLE 

### A-3. L IST OF 

### P RECIPITATION METEOROLOGICAL 

### S TATIONS

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 T ABLE 

### A-4. L IST OF 

### O VER 

### W ATER METEOROLOGICAL 

### S TATIONS

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 

## A PPENDIX 

## B

– S AMPLE 

## CALMET C ONTROL 

## F ILE01Met01a.inp2001 - 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 CASET = 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------------ ---- ---------Page 101Met01a.inpUP1.DAT input 1 ! UPDAT=UPABQ01.DAT! !END!UP2.DAT input 2 ! UPDAT=UPAMA01.DAT! !END!UP3.DAT input 3 ! UPDAT=UPBMX01.DAT! !END!UP4.DAT input 4 ! UPDAT=UPBNA01.DAT! !END!UP5.DAT input 5 ! UPDAT=UPBRO01.DAT! !END!UP6.DAT input 6 ! UPDAT=UPCRP01.DAT! !END!UP7.DAT input 7 ! UPDAT=UPDDC01.DAT! !END!UP8.DAT input 8 ! UPDAT=UPDRT01.DAT! !END!UP9.DAT input 9 ! UPDAT=UPEPZ01.DAT! !END!UP10.DAT input 10 ! UPDAT=UPFWD01.DAT! !END!UP11.DAT input 11 ! UPDAT=UPJAN01.DAT! !END!UP12.DAT input 12 ! UPDAT=UPLCH01.DAT! !END!UP13.DAT input 13 ! UPDAT=UPLZK01.DAT! !END!UP14.DAT input 14 ! UPDAT=UPMAF01.DAT! !END!UP15.DAT input 15 ! UPDAT=UPOUN01.DAT! !END!UP16.DAT input 16 ! UPDAT=UPSHV01.DAT! !END!UP17.DAT input 17 ! UPDAT=UPSIL01.DAT! !END!--------------------------------------------------------------------------------Subgroup (c)-----------------------------------------Overwater station files (one per station)-----------------------------------------Default Name Type File Name------------ ---- ---------OW1.DAT input 1 ! SEADAT=42001_01_sea.dat! !END!OW2.DAT input 2 ! SEADAT=42002_01_sea.dat! !END!OW3.DAT input 3 ! SEADAT=42007_01_sea.dat! !END!OW4.DAT input 4 ! SEADAT=42019_01_sea.dat! !END!OW5.DAT input 5 ! SEADAT=42020_01_sea.dat! !END!OW6.DAT input 6 ! SEADAT=42035_01_sea.dat! !END!OW7.DAT input 7 ! SEADAT=42040_01_sea.dat! !END!OW8.DAT input 8 ! SEADAT=42045_01_sea.dat! !END!OW9.DAT input 9 ! SEADAT=42046_01_sea.dat! !END!OW10.DAT input 10 ! SEADAT=42047_01_sea.dat! !END!OW11.DAT input 11 ! SEADAT=42048_01_sea.dat! !END!OW12.DAT input 12 ! SEADAT=42049_01_sea.dat! !END!--------------------------------------------------------------------------------Subgroup (d)----------------Other file names----------------Default Name Type File Name------------ ---- ---------DIAG.DAT input * DIADAT= *PROG.DAT input * PRGDAT= *Page 201Met01a.inpTEST.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 bydelimiters) at the end of the group(3) Subgroups (b) and (c) must have an 'END' (surround bydelimiters) 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 = 07CST = 06, EST = 05Length of run (hours) (IRLG) -- No default ! IRLG= 240 !Run type (IRTYPE) -- Default: 1 ! IRTYPE= 1 !0 = Computes wind fields only1 = Computes wind fields and micrometeorological variables(u*, w*, L, zi, etc.)(IRTYPE must be 1 to run CALPUFF or CALGRID)Compute special data fields requiredby CALGRID (i.e., 3-D fields of W windcomponents and temperature)in additional to regular Default: T ! LCALGRD = T !fields ? (LCALGRD)(LCALGRD must be T to run CALGRID)Flag to stop run afterPage 301Met01a.inpSETUP phase (ITEST) Default: 2 ! ITEST= 2 !(Used to allow checkingof the model inputs, files, etc.)ITEST = 1 - STOPS program after SETUP phaseITEST = 2 - Continues with execution ofCOMPUTATIONAL 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 MercatorTTM : Tangential Transverse MercatorLCC : Lambert Conformal ConicPS : Polar StereographicEM : Equatorial MercatorLAZA : Lambert Azimuthal Equal AreaFalse 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 projectionS : Southern hemisphere projectionLatitude 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 projectionPage 401Met01a.inpRLAT0 selected for convenienceLCC : RLON0 identifies central (true N/S) meridian of projectionRLAT0 selected for conveniencePS : RLON0 identifies central (grid N/S) meridian of projectionRLAT0 selected for convenienceEM : RLON0 identifies central meridian of projectionRLAT0 is REPLACED by 0.0N (Equator)LAZA: RLON0 identifies longitude of tangent-point of mapping planeRLAT0 identifies latitude of tangent-point of mapping planeMatching 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 XLAT2PS : Projection plane slices through Earth at XLAT1(XLAT2 is not used)----------Note: Latitudes and longitudes should be positive, and include aletter N,S,E, or W indicating north or south latitude, andeast or west longitude. For example,35.9 N Latitude = 35.9N118.7 E Longitude = 118.7EDatum-region------------The Datum-Region for the coordinates is identified by a characterstring. Many mapping products currently available use the model of theEarth known as the World Geodetic System 1984 (WGS-G ). Other localmodels may be in use, and their selection in CALMET will make its outputconsistent with local mapping products. The list of Datum-Regions withofficial transformation parameters is provided by the National Imagery andMapping 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, SphereNWS-84 NWS 6370KM Radius, SphereESR-S ESRI REFERENCE 6371KM Radius, SphereDatum-region for output coordinates(DATUM) Default: WGS-G ! DATUM = WGS-G !Page 501Met01a.inpHorizontal grid definition:---------------------------Rectangular grid defined for projection PMAP,with X the Easting and Y the Northing coordinateNo. 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: kmReference grid coordinate ofSOUTHWEST corner of grid cell (1,1)X coordinate (XORIGKM) No default ! XORIGKM = -951.547 !Y coordinate (YORIGKM) No default ! YORIGKM = -1646.637 !Units: kmVertical grid definition:-------------------------No. of vertical layers (NZ) No default ! NZ = 12 !Cell face heights in arbitraryvertical grid (ZFACE(NZ+1)) No defaultsUnits: m! ZFACE = 0.,20.,40.,60.,80.,100.,150.,200.,250.,500.,1000.,2000.,3500. !!END!-------------------------------------------------------------------------------INPUT GROUP: 3 -- Output Options--------------DISK OUTPUT OPTIONSave met. fields in an unformattedoutput file ? (LSAVE) Default: T ! LSAVE = T !(F = Do not save, T = Save)Type of unformatted output file:Page 601Met01a.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 whichmet. variables are printed)Print interval(IPRINF) in hours Default: 1 ! IPRINF = 1 !(Meteorological fields are printedevery 1 hours)Specify which layers of U, V wind componentto 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 fieldsto print(used only if LPRINT=T) Defaults: 0 (all variables)Page 701Met01a.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 modulePrint input meteorological data andinternal 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 dataare printed (NN1) Default: 1 ! NN1 = 1 !Last time step for which debug dataare printed (NN2) Default: 1 ! NN2 = 1 !Testing and debug print options for wind field module(all of the following print options control output towind field module's output files: TEST.PRT, TEST.OUT,TEST.KIN, TEST.FRD, and TEST.SLP)Control variable for writing the test/debugwind 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 windPage 801Met01a.inpcomponents ?(IPR1) (0=no, 1=yes) Default: 0 ! IPR1 = 0 !Print the SMOOTHED wind components andthe INITIAL DIVERGENCE fields ?(IPR2) (0=no, 1=yes) Default: 0 ! IPR2 = 0 !Print the FINAL wind speed and directionfields ?(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 effectsare added ?(IPR5) (0=no, 1=yes) Default: 0 ! IPR5 = 0 !Print the winds after the FROUDE NUMBERadjustment is made ?(IPR6) (0=no, 1=yes) Default: 0 ! IPR6 = 0 !Print the winds after SLOPE FLOWSare 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 stations1 = Use surface and overwater stations (no upper air observations)Use MM5 for upper air data2 = No surface, overwater, or upper air observationsUse MM5 for surface, overwater, and upper air dataNUMBER OF SURFACE & PRECIP. METEOROLOGICAL STATIONSNumber of surface stations (NSSTA) No default ! NSSTA = 162 !Page 901Met01a.inpNumber of precipitation stations(NPSTA=-1: flag for use of MM5 precip data)(NPSTA) No default ! NPSTA = 298 !CLOUD DATA OPTIONSGridded cloud fields:(ICLOUD) Default: 0 ! ICLOUD = 0 !ICLOUD = 0 - Gridded clouds not usedICLOUD = 1 - Gridded CLOUD.DAT generated as OUTPUTICLOUD = 2 - Gridded CLOUD.DAT read as INPUTICLOUD = 3 - Gridded cloud cover from Prognostic Rel. HumidityFILE FORMATSSurface 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 OPTIONSModel selection variable (IWFCOD) Default: 1 ! IWFCOD = 1 !0 = Objective analysis only1 = Diagnostic wind moduleCompute Froude number adjustmenteffects ? (IFRADJ) Default: 1 ! IFRADJ = 1 !(0 = NO, 1 = YES)Compute kinematic effects ? (IKINE) Default: 0 ! IKINE = 0 !Page 1001Met01a.inp(0 = NO, 1 = YES)Use O'Brien procedure for adjustmentof 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 observationsto upper layers ? (IEXTRP) Default: -4 ! IEXTRP = -4 !(1 = no extrapolation is done,2 = power law extrapolation used,3 = user input multiplicative factorsfor layers 2 - NZ used (see FEXTRP array)4 = similarity theory used-1, -2, -3, -4 = same as above except layer 1 dataat upper air stations are ignoredExtrapolate surface winds evenif calm? (ICALM) Default: 0 ! ICALM = 0 !(0 = NO, 1 = YES)Layer-dependent biases modifying the weights ofsurface and upper air stations (BIAS(NZ))-1<=BIAS<=1Negative BIAS reduces the weight of upper air stations(e.g. BIAS=-0.1 reduces the weight of upper air stationsby 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 stationsby 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 , 0 , 0 !Minimum distance from nearest upper air stationto surface station for which extrapolationof surface winds at surface station will be allowed(RMIN2: Set to -1 for IEXTRP = 4 or other situationswhere all surface stations should be extrapolated)Default: 4. ! RMIN2 = -1.0 !Use gridded prognostic wind field modeloutput fields as input to the diagnosticwind field model (IPROG) Default: 0 ! IPROG = 14 !(0 = No, [IWFCOD = 0 or 1]1 = Yes, use CSUMM prog. winds as Step 1 field, [IWFCOD = 0]Page 1101Met01a.inp2 = 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 prognosticmodel input data (ISTEPPG) Default: 1 ! ISTEPPG = 1 !RADIUS OF INFLUENCE PARAMETERSUse 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 landin the surface layer (RMAX1) No default ! RMAX1 = 20. !Units: kmMaximum radius of influence over landaloft (RMAX2) No default ! RMAX2 = 50. !Units: kmMaximum radius of influence over water(RMAX3) No default ! RMAX3 = 500. !Units: kmOTHER WIND FIELD INPUT PARAMETERSMinimum radius of influence used inthe wind field interpolation (RMIN) Default: 0.1 ! RMIN = 0.1 !Units: kmRadius of influence of terrainfeatures (TERRAD) No default ! TERRAD = 10. !Units: kmRelative weighting of the firstguess field and observations in theSURFACE layer (R1) No default ! R1 = 10. !(R1 is the distance from an Units: kmobservational station at which theobservation and first guess field areequally weighted)Relative weighting of the firstguess field and observations in thelayers ALOFT (R2) No default ! R2 = 25. !Page 1201Met01a.inp(R2 is applied in the upper layers Units: kmin the same manner as R1 is used inthe surface layer).Relative weighting parameter of theprognostic wind field data (RPROG) No default ! RPROG = 54. !(Used only if IPROG = 1) Units: km------------------------Maximum acceptable divergence in thedivergence minimization procedure(DIVLIM) Default: 5.E-6 ! DIVLIM= 5.0E-06 !Maximum number of iterations in thedivergence min. procedure (NITER) Default: 50 ! NITER = 50 !Number of passes in the smoothingprocedure (NSMTH(NZ))NOTE: NZ values must be enteredDefault: 2,(mxnz-1)*4 ! NSMTH =2 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 , 4 !Maximum number of stations used ineach layer for the interpolation ofdata 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 theinfluence of kinematic effects(ALPHA) Default: 0.1 ! ALPHA = 0.1 !Multiplicative scaling factor forextrapolation of surface observationsto 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 INFORMATIONNumber of barriers to interpolationof the wind fields (NBAR) Default: 0 ! NBAR = 0 !THE FOLLOWING 4 VARIABLES ARE INCLUDEDONLY IF NBAR > 0Page 1301Met01a.inpNOTE: NBAR values must be entered No defaultsfor each variable Units: kmX coordinate of BEGINNINGof each barrier (XBBAR(NBAR)) ! XBBAR = 0. !Y coordinate of BEGINNINGof each barrier (YBBAR(NBAR)) ! YBBAR = 0. !X coordinate of ENDINGof each barrier (XEBAR(NBAR)) ! XEBAR = 0. !Y coordinate of ENDINGof each barrier (YEBAR(NBAR)) ! YEBAR = 0. !DIAGNOSTIC MODULE DATA INPUT OPTIONSSurface temperature (IDIOPT1) Default: 0 ! IDIOPT1 = 0 !0 = Compute internally fromhourly surface observations1 = Read preprocessed values froma data file (DIAG.DAT)Surface met. station to use forthe surface temperature (ISURFT) No default ! ISURFT = 64 !(Must be a value from 1 to NSSTA)(Used only if IDIOPT1 = 0)--------------------------Domain-averaged temperature lapserate (IDIOPT2) Default: 0 ! IDIOPT2 = 0 !0 = Compute internally fromtwice-daily upper air observations1 = Read hourly preprocessed valuesfrom a data file (DIAG.DAT)Upper air station to use forthe 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-scalelapse rate is computed (ZUPT) Default: 200. ! ZUPT = 200. !(Used only if IDIOPT2 = 0) Units: meters--------------------------Domain-averaged wind components(IDIOPT3) Default: 0 ! IDIOPT3 = 0 !Page 1401Met01a.inp0 = Compute internally fromtwice-daily upper air observations1 = Read hourly preprocessed valuesa data file (DIAG.DAT)Upper air station to use forthe 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 throughwhich the domain-scale windsare computed(ZUPWND(1), ZUPWND(2)) Defaults: 1., 1000. ! ZUPWND= 1., 2000. !(Used only if IDIOPT3 = 0) Units: meters--------------------------Observed surface wind componentsfor wind field module (IDIOPT4) Default: 0 ! IDIOPT4 = 0 !0 = Read WS, WD from a surfacedata file (SURF.DAT)1 = Read hourly preprocessed U, V froma data file (DIAG.DAT)Observed upper air wind componentsfor wind field module (IDIOPT5) Default: 0 ! IDIOPT5 = 0 !0 = Read WS, WD from an upperair data file (UP1.DAT, UP2.DAT, etc.)1 = Read hourly preprocessed U, V froma data file (DIAG.DAT)LAKE BREEZE INFORMATIONUse 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. !Page 1501Met01a.inpX 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 CONSTANTSNeutral, 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 Coriolisparameter (FCORIOL) Default: 1.E-4 ! FCORIOL = 1.0E-04!Units: (1/s)SPATIAL AVERAGING OF MIXING HEIGHTSConduct spatial averaging(IAVEZI) (0=no, 1=yes) Default: 1 ! IAVEZI = 1 !Max. search radius in averagingPage 1601Met01a.inpprocess (MNMDAV) Default: 1 ! MNMDAV = 1 !Units: GridcellsHalf-angle of upwind looking conefor averaging (HAFANG) Default: 30. ! HAFANG = 30. !Units: deg.Layer of winds used in upwindaveraging (ILEVZI) Default: 1 ! ILEVZI = 1 !(must be between 1 and NZ)OTHER MIXING HEIGHT VARIABLESMinimum potential temperature lapserate in the stable layer above thecurrent convective mixing ht. Default: 0.001 ! DPTMIN = 0.001 !(DPTMIN) Units: deg. K/mDepth of layer above current conv.mixing height through which lapse Default: 200. ! DZZI = 200. !rate is computed (DZZI) Units: metersMinimum overland mixing height Default: 50. ! ZIMIN = 20. !(ZIMIN) Units: metersMaximum overland mixing height Default: 3000. ! ZIMAX = 3500. !(ZIMAX) Units: metersMinimum overwater mixing height Default: 50. ! ZIMINW = 20. !(ZIMINW) -- (Not used if observed Units: metersoverwater mixing hts. are used)Maximum overwater mixing height Default: 3000. ! ZIMAXW = 3500. !(ZIMAXW) -- (Not used if observed Units: metersoverwater mixing hts. are used)TEMPERATURE PARAMETERS3D temperature from observations orfrom 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 observationsUse 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 !Page 1701Met01a.inpRadius of influence for temperatureinterpolation (TRADKM) Default: 500. ! TRADKM = 500. !Units: kmMaximum Number of stations to includein 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,HAFANGso make sure they are correct)Default temperature gradient Default: -.0098 ! TGDEFB = -0.0098 !below the mixing height overwater (K/m) (TGDEFB)Default temperature gradient Default: -.0045 ! TGDEFA = -0.0045 !above the mixing height overwater (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 disablePRECIP INTERPOLATION PARAMETERSMethod 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. btwnnearest stns w & w/outprecip 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)Page 1801Met01a.inp1 2Name 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 !Page 1901Met01a.inp! 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 !Page 2001Met01a.inp! 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 !Page 2101Met01a.inp! 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 !-------------------1Four character string for station name(MUST START IN COLUMN 9)2Five 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 2Name ID X coord. Y coord. Time zone(km) (km)-----------------------------------------------Page 2201Met01a.inp! 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 !-------------------1Four character string for station name(MUST START IN COLUMN 9)2Five 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 2Name 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 !Page 2301Met01a.inp! 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 !Page 2401Met01a.inp! 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 !Page 2501Met01a.inp! PS102='POMO' 146498 123.872 -148.785 !! PS103='SALI' 147160 -56.156 -132.792 !! PS104='SMOL' 147551 -57.589 -138.771 !! PS105='STAN' 147756 201.192 -129.364 !! PS106='SUBL' 147922 -337.056 -271.996 !! PS107='TOPE' 148167 116.838 -102.08 !! PS108='TRIB' 148235 -413.288 -158.742 !! PS109='UNIO' 148293 176.609 -236.016 !! PS110='WALL' 148535 -394.195 -111.564 !! PS111='WICH' 148830 -38.795 -259.177 !! PS112='WILS' 148946 -127.991 -113.209 !! PS113='BENT' 150611 765.835 -310.871 !! PS114='CALH' 151227 852.121 -227.267 !! PS115='CLTN' 151631 713.076 -341.509 !! PS116='HERN' 153798 835.039 -324.875 !! PS117='MADI' 155067 831.766 -250.005 !! PS118='PADU' 156110 725.315 -292.67 !! PS119='PCTN' 156580 804.246 -277.545 !! PS120='ALEX' 160103 433.936 -959.371 !! PS121='BATN' 160549 563.036 -1031.572 !! PS122='CALH' 161411 436.36 -818.181 !! PS123='CLNT' 161899 577.635 -999.204 !! PS124='JENA' 164696 455.137 -911.689 !! PS125='LACM' 165078 364.877 -1088.263 !! PS126='MIND' 166244 347.179 -812.044 !! PS127='MONR' 166314 462.55 -814.477 !! PS128='NATC' 166582 369.813 -903.938 !! PS129='SHRE' 168440 298.233 -831.498 !! PS130='WINN' 169803 409.193 -884.925 !! PS131='BROK' 221094 621.134 -914.907 !! PS132='CONE' 221900 725.078 -804.862 !! PS133='JAKS' 224472 650.598 -826.11 !! PS134='LEAK' 224966 805.886 -943.78 !! PS135='MERI' 225776 775.44 -813.985 !! PS136='SARD' 227815 659.252 -594.021 !! PS137='SAUC' 227840 763.366 -1005.558 !! PS138='TUPE' 229003 753.481 -600.441 !! PS139='ADVA' 230022 625.39 -296.764 !! PS140='ALEY' 230088 489.607 -299.884 !! PS141='BOLI' 230789 316.095 -257.265 !! PS142='CASV' 231383 278.848 -363.145 !! PS143='CLER' 231674 548.572 -298.367 !! PS144='CLTT' 231711 279.768 -172.497 !! PS145='COLU' 231791 411.752 -119.977 !! PS146='DREX' 232331 206.841 -165.718 !! PS147='ELM ' 232568 255.182 -120.998 !! PS148='FULT' 233079 436.302 -114.093 !! PS149='HOME' 233999 616.121 -414.248 !Page 2601Met01a.inp! PS150='JEFF' 234271 416.131 -145.612 !! PS151='JOPL' 234315 220.234 -312.505 !! PS152='LEBA' 234825 376.787 -247.055 !! PS153='LICK' 234919 448.45 -257.796 !! PS154='LOCK' 235027 268.099 -284.021 !! PS155='MALD' 235207 622.264 -352.069 !! PS156='MARS' 235298 323.881 -89.005 !! PS157='MAFD' 235307 359.618 -286.265 !! PS158='MCES' 235415 438.31 -103.798 !! PS159='MILL' 235594 279.592 -303.243 !! PS160='MTGV' 235834 417.444 -303.975 !! PS161='NVAD' 235987 229.38 -235.588 !! PS162='OZRK' 236460 332.595 -322.715 !! PS163='PDTD' 236777 321.295 -225.142 !! PS164='POTO' 236826 535.474 -215.124 !! PS165='ROLL' 237263 455.277 -212.788 !! PS166='ROSE' 237300 486.744 -156.257 !! PS167='SALE' 237506 478.319 -247.284 !! PS168='SENE' 237656 212.232 -346.356 !! PS169='SPRC' 237967 217.784 -330.588 !! PS170='SPVL' 237976 317.872 -298.923 !! PS171='STEE' 238043 490.224 -205.375 !! PS172='STOK' 238082 282.366 -249.68 !! PS173='SWSP' 238223 307.988 -108.584 !! PS174='TRKD' 238252 327.995 -369.664 !! PS175='TRUM' 238466 312.604 -186.416 !! PS176='UNIT' 238524 223.807 -113.079 !! PS177='VIBU' 238609 512.995 -236.439 !! PS178='VIEN' 238620 435.914 -186.806 !! PS179='WAPP' 238700 593.558 -318.328 !! PS180='WASG' 238746 520.949 -143.874 !! PS181='WEST' 238880 457.784 -347.238 !! PS182='ALBU' 290234 -871.609 -503.095 !! PS183='ARTE' 290600 -689.914 -774.455 !! PS184='AUGU' 290640 -974.149 -598.824 !! PS185='CARL' 291469 -682.406 -821.637 !! PS186='CARR' 291515 -821.335 -664.892 !! PS187='CLAY' 291887 -547.48 -374.232 !! PS188='CLOV' 291939 -566.944 -597.754 !! PS189='CUBA' 292241 -891.039 -392.352 !! PS190='CUBE' 292250 -951.736 -488.294 !! PS191='DEMI' 292436 -1010.101 -798.493 !! PS192='DURA' 292665 -783.906 -760.939 !! PS193='EANT' 292700 -733.551 -347.353 !! PS194='LAVG' 294862 -731.851 -447.93 !! PS195='PROG' 297094 -812.31 -577.673 !! PS196='RAMO' 297254 -734.136 -615.047 !! PS197='ROSW' 297610 -696.498 -712.285 !Page 2701Met01a.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 !Page 2801Met01a.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 !Page 2901Met01a.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 !-------------------1Four character string for station name(MUST START IN COLUMN 9)2Six digit station code composed of statecode (first 2 digits) and station ID (last4 digits)!END!Page 30

### OG&E Trinity Consultants BART Modeling Report 083701.0004 

## A PPENDIX 

## C

– S AMPLE 

## CALPUFF C ONTROL 

## F ILE2001_SO_NOx.inpOG&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= *Page 12001_SO_NOx.inpCOASTLN.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 CASET = 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!Page 22001_SO_NOx.inpnone 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 foundin the met. file (METRUN) Default: 0 ! METRUN = 0 !METRUN = 0 - Run period explicitly defined belowMETRUN = 1 - Run all periods in met. fileStarting 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.Page 32001_SO_NOx.inpCST = 6., EST = 5.Length of run (hours) (IRLG) -- No default ! IRLG = 8760 !Number of chemical species (NSPEC)Default: 5 ! NSPEC = 10 !Number of chemical speciesto be emitted (NSE) Default: 3 ! NSE = 7 !Flag to stop run afterSETUP phase (ITEST) Default: 2 ! ITEST = 2 !(Used to allow checkingof the model inputs, files, etc.)ITEST = 1 - STOPS program after SETUP phaseITEST = 2 - Continues with execution of programafter SETUPRestart Configuration:Control flag (MRESTART) Default: 0 ! MRESTART = 0 !0 = Do not read or write a restart file1 = Read a restart file at the beginning ofthe run2 = Write a restart file during run3 = Read a restart file at beginning of runand write a restart file during runNumber of periods in Restartoutput cycle (NRESPD) Default: 0 ! NRESPD = 0 !0 = File written only at last period>0 = File updated every NRESPD periodsMeteorological 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) andsurface parameters file (SURFACE.DAT)PG sigma-y is adjusted by the factor (AVET/PGTIME)**0.2Averaging Time (minutes) (AVET)Default: 60.0 ! AVET = 60. !PG Averaging Time (minutes) (PGTIME)Page 42001_SO_NOx.inpDefault: 60.0 ! PGTIME = 60. !!END!-------------------------------------------------------------------------------INPUT GROUP: 2 -- Technical options--------------Vertical distribution used in thenear field (MGAUSS) Default: 1 ! MGAUSS = 1 !0 = uniform1 = GaussianTerrain adjustment method(MCTADJ) Default: 3 ! MCTADJ = 3 !0 = no adjustment1 = ISC-type of terrain adjustment2 = simple, CALPUFF-type of terrainadjustment3 = partial plume path adjustmentSubgrid-scale complex terrainflag (MCTSG) Default: 0 ! MCTSG = 0 !0 = not modeled1 = modeledNear-field puffs modeled aselongated 0 (MSLUG) Default: 0 ! MSLUG = 0 !0 = no1 = 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 buildingdownwash? (MBDW) Default: 1 ! MBDW = 1 !1 = ISC method2 = PRIME methodPage 52001_SO_NOx.inpVertical wind shear modeled abovestack 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 notmodeled1 = transformation rates computedinternally (MESOPUFF II scheme)2 = user-specified transformationrates used3 = transformation rates computedinternally (RIVAD/ARM3 scheme)4 = secondary organic aerosol formationcomputed (MESOPUFF II scheme for OH)Aqueous phase transformation flag (MAQCHEM)(Used only if MCHEM = 1, or 3) Default: 0 ! MAQCHEM = 0 !0 = aqueous phase transformationnot modeled1 = transformation rates adjustedfor aqueous phase reactionsWet removal modeled ? (MWET) Default: 1 ! MWET = 1 !0 = no1 = yesDry deposition modeled ? (MDRY) Default: 1 ! MDRY = 1 !0 = no1 = yes(dry deposition method specifiedfor each species in Input Group 3)Method used to compute dispersioncoefficients (MDISP) Default: 3 ! MDISP = 3 !1 = dispersion coefficients computed from measured valuesof turbulence, sigma v, sigma w2 = dispersion coefficients from internally calculatedsigma v, sigma w using micrometeorological variables(u*, w*, L, etc.)3 = PG dispersion coefficients for RURAL areas (computed usingPage 62001_SO_NOx.inpthe ISCST multi-segment approximation) and MP coefficients inurban areas4 = same as 3 except PG coefficients computed usingthe MESOPUFF II eqns.5 = CTDM sigmas used for stable and neutral conditions.For unstable conditions, sigmas are computed as inMDISP = 3, described above. MDISP = 5 assumes thatmeasured values are readSigma-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 measurementsfrom PROFILE.DAT to compute sigma-y(valid for METFM = 1, 2, 3, 4)2 = use sigma-w measurementsfrom PROFILE.DAT to compute sigma-z(valid for METFM = 1, 2, 3, 4)3 = use both sigma-(v/theta) and sigma-wfrom PROFILE.DAT to compute sigma-y and sigma-z(valid for METFM = 1, 2, 3, 4)4 = use sigma-theta measurementsfrom PLMMET.DAT to compute sigma-y(valid only if METFM = 3)Back-up method used to compute dispersionwhen measured turbulence data aremissing (MDISP2) Default: 3 ! MDISP2 = 3 !(used only if MDISP = 1 or 5)2 = dispersion coefficients from internally calculatedsigma v, sigma w using micrometeorological variables(u*, w*, L, etc.)3 = PG dispersion coefficients for RURAL areas (computed usingthe ISCST multi-segment approximation) and MP coefficients inurban areas4 = same as 3 except PG coefficients computed usingthe MESOPUFF II eqns.PG sigma-y,z adj. for roughness? Default: 0 ! MROUGH = 0 !(MROUGH)0 = no1 = yesPartial plume penetration of Default: 1 ! MPARTL = 1 !elevated inversion?(MPARTL)0 = no1 = yesPage 72001_SO_NOx.inpStrength of temperature inversion Default: 0 ! MTINV = 0 !provided in PROFILE.DAT extended records?(MTINV)0 = no (computed from measured/default gradients)1 = yesPDF used for dispersion under convective conditions?Default: 0 ! MPDF = 0 !(MPDF)0 = no1 = yesSub-Grid TIBL module used for shore line?Default: 0 ! MSGTIBL = 0 !(MSGTIBL)0 = no1 = yesBoundary conditions (concentration) modeled?Default: 0 ! MBCON = 0 !(MBCON)0 = no1 = yes, using formatted BCON.DAT file2 = yes, using unformatted CONC.DAT fileAnalyses of fogging and icing impacts due to emissions fromarrays of mechanically-forced cooling towers can be performedusing CALPUFF in conjunction with a cooling tower emissionsprocessor (CTEMISS) and its associated postprocessors. Hourlyemissions of water vapor and temperature from each cooling towercell are computed for the current cell configuration and ambientconditions by CTEMISS. CALPUFF models the dispersion of theseemissions and provides cloud information in a specialized formatfor 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 = no1 = yes - report results in PLUME Mode format2 = yes - report results in RECEPTOR Mode formatTest options specified to see ifthey conform to regulatoryvalues? (MREG) Default: 1 ! MREG = 0 !Page 82001_SO_NOx.inp0 = NO checks are made1 = Technical options must conform to USEPALong Range Transport (LRT) guidanceMETFM 1 or 2AVET 60. (min)PGTIME 60. (min)MGAUSS 1MCTADJ 3MTRANS 1MTIP 1MCHEM 1 or 3 (if modeling SOx, NOx)MWET 1MDRY 1MDISP 2 or 3MPDF 0 if MDISP=31 if MDISP=2MROUGH 0MPARTL 1SYTDEP 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!Page 92001_SO_NOx.inpDry OUTPUT GROUPSPECIES MODELED EMITTED DEPOSITED NUMBERNAME (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 resultsfor certain species are combined (added) prior to output. TheCGRUP name will be used as the species name in output files.Use this feature to model specific particle-size distributionsby 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 MercatorTTM : Tangential Transverse MercatorLCC : Lambert Conformal ConicPS : Polar StereographicPage 102001_SO_NOx.inpEM : Equatorial MercatorLAZA : Lambert Azimuthal Equal AreaFalse 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 projectionS : Southern hemisphere projectionLatitude 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 projectionRLAT0 selected for convenienceLCC : RLON0 identifies central (true N/S) meridian of projectionRLAT0 selected for conveniencePS : RLON0 identifies central (grid N/S) meridian of projectionRLAT0 selected for convenienceEM : RLON0 identifies central meridian of projectionRLAT0 is REPLACED by 0.0N (Equator)LAZA: RLON0 identifies longitude of tangent-point of mapping planeRLAT0 identifies latitude of tangent-point of mapping planeMatching 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 XLAT2PS : Projection plane slices through Earth at XLAT1(XLAT2 is not used)----------Note: Latitudes and longitudes should be positive, and include aletter N,S,E, or W indicating north or south latitude, andeast or west longitude. For example,35.9 N Latitude = 35.9NPage 112001_SO_NOx.inp118.7 E Longitude = 118.7EDatum-region------------The Datum-Region for the coordinates is identified by a characterstring. Many mapping products currently available use the model of theEarth known as the World Geodetic System 1984 (WGS-G ). Other localmodels may be in use, and their selection in CALMET will make its outputconsistent with local mapping products. The list of Datum-Regions withofficial transformation parameters is provided by the National Imagery andMapping 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, SphereNWS-84 NWS 6370KM Radius, SphereESR-S ESRI REFERENCE 6371KM Radius, SphereDatum-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 coordinateNo. 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: kmCell face heights(ZFACE(nz+1)) No defaultsUnits: m! ZFACE = 0.,20.,40.,60.,80.,100.,150.,200.,250.,500.,1000.,2000.,3500. !Reference Coordinatesof SOUTHWEST corner ofgrid cell(1, 1):Page 122001_SO_NOx.inpX 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 thecomputational 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 thesampling grid is at grid point (IESAMP, JESAMP) of the MET. grid.The sampling grid must be identical to or a subset of the computationalgrid. It may be a nested grid inside the computational grid.The grid spacing of the sampling grid is DGRIDKM/MESHDN.Logical flag indicating if griddedreceptors 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)Page 132001_SO_NOx.inpX 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 samplinggrid (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 isrequired for visibilityanalysis)Use data compression option in output file?(LCOMPRS) Default: T ! LCOMPRS = T !*0 = Do not create file, 1 = create fileDIAGNOSTIC MASS FLUX OUTPUT OPTIONS:Mass flux across specified boundariesfor selected species reported hourly?(IMFLX) Default: 0 ! IMFLX = 0 !0 = no1 = yes (FLUXBDY.DAT and MASSFLX.DAT filenamesare specified in Input Group 0)Mass balance for each speciesPage 142001_SO_NOx.inpreported hourly?(IMBAL) Default: 0 ! IMBAL = 0 !0 = no1 = yes (MASSBAL.DAT filename isspecified 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 forConcentration Deposition1 = g/m**3 g/m**2/s2 = mg/m**3 mg/m**2/s3 = ug/m**3 ug/m**2/s4 = ng/m**3 ng/m**2/s5 = Odour UnitsMessages tracking progress of runwritten to the screen ?(IMESG) Default: 2 ! IMESG = 2 !0 = no1 = 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 ------ -- MASSFLUX --SPECIES/GROUP PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? PRINTED? SAVED ON DISK? SAVED ONDISK?------- ------------------------ ------------------------ ---------------------------------------Page 152001_SO_NOx.inp! SO2 = 0, 1, 0, 1, 0, 1, 1 !! SO4 = 0, 1, 0, 1, 0, 1, 1 !! NOX = 0, 1, 0, 1, 0, 1, 1 !! HNO3 = 0, 1, 0, 1, 0, 1, 1 !! NO3 = 0, 1, 0, 1, 0, 1, 1 !! PMC = 0, 1, 0, 1, 0, 1, 1 !! PMF = 0, 1, 0, 1, 0, 1, 1 !! EC = 0, 1, 0, 1, 0, 1, 1 !! SOA = 0, 1, 0, 1, 0, 1, 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 terrainreceptors (NCTREC) Default: 0 ! NCTREC = 0 !Terrain and CTSG Receptor data forCTSG hills input in CTDM format ?(MHILL) No Default ! MHILL = 2 !1 = Hill and Receptor data createdPage 162001_SO_NOx.inpby CTDM processors & read fromHILL.DAT and HILLRCT.DAT files2 = 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 SCALE 2 AMAX1AMAX2NO. (km) (km) (deg.) (m) (m) (m) (m) (m) (m) (m)(m)---- ---- ---- ------ ----- ------ ------ ------ ------- ------- -------------------------Subgroup (6c)---------------COMPLEX TERRAIN RECEPTOR INFORMATIONXRCT YRCT ZRCT XHH(km) (km) (m)------ ----- ------ -----------------------1Page 172001_SO_NOx.inpDescription of Complex Terrain Variables:XC, YC = Coordinates of center of hillTHETAH = Orientation of major axis of hill (clockwise fromNorth)ZGRID = Height of the 0 of the grid above mean sealevelRELIEF = Height of the crest of the hill above the grid elevationEXPO 1 = Hill-shape exponent for the major axisEXPO 2 = Hill-shape exponent for the major axisSCALE 1 = Horizontal length scale along the major axisSCALE 2 = Horizontal length scale along the minor axisAMAX = Maximum allowed axis length for the major axisBMAX = Maximum allowed axis length for the major axisXRCT, YRCT = Coordinates of the complex terrain receptorsZRCT = Height of the ground (MSL) at the complex terrainReceptorXHH = 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 separateinput 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 HENRY'S LAWCOEFFICIENTNAME (cm**2/s) (s/cm)(dimensionless)------- ----------- ---------- ---------- -------------------------------------------! SO2 = 0.1509, 1000., 8., 0., 0.04 !! NOX = 0.1656, 1., 8., 5., 3.5 !! HNO3 = 0.1628, 1., 18., 0., 0.00000008 !!END!-------------------------------------------------------------------------------INPUT GROUP: 8 -- Size parameters for dry deposition of particlesPage 182001_SO_NOx.inp--------------For SINGLE SPECIES, the mean and standard deviation are used tocompute 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 explicitlyspecified (by the 'species' in the group), and the standard deviationfor each should be entered as 0. The model will then use thedeposition velocity for the stated mean diameter.SPECIES GEOMETRIC MASS MEAN GEOMETRIC STANDARDNAME 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 toevaluate 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 vegetationIVEG=2 for active and stressed vegetationIVEG=3 for inactive vegetationPage 192001_SO_NOx.inp!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 value1 = read hourly ozone concentrations fromthe OZONE.DAT data fileMonthly ozone concentrations(Used only if MCHEM = 1, 3, or 4 andMOZ = 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, 40.00 !Monthly ammonia concentrations(Used only if MCHEM = 1, or 3)(BCKNH3) in ppb Default: 12*10.Page 202001_SO_NOx.inp! 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 value1 = read hourly H2O2 concentrations fromthe H2O2.DAT data fileMonthly H2O2 concentrations(Used only if MQACHEM = 1 andMH2O2 = 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 computingthe 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 12Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov DecClean ContinentalBCKPMF 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1. 1.OFRAC .15 .15 .20 .20 .20 .20 .20 .20 .20 .20 .20 .15VCNX 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 .5OFRAC .25 .25 .30 .30 .30 .30 .30 .30 .30 .30 .30 .25VCNX 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50. 50.Page 212001_SO_NOx.inpUrban - 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 .20VCNX 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 .25VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.Regional PlumeBCKPMF 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20. 20.OFRAC .20 .20 .25 .35 .25 .40 .40 .40 .30 .30 .30 .20VCNX 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15. 15.Urban - no controls presentBCKPMF 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100. 100.OFRAC .30 .30 .35 .35 .35 .55 .55 .55 .35 .35 .35 .30VCNX 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, 50.00, 50.00 !!END!-------------------------------------------------------------------------------INPUT GROUP: 12 -- Misc. Dispersion and Computational Parameters---------------Horizontal size of puff (m) beyond whichtime-dependent dispersion equations (Heffter)are used to determine sigma-y andsigma-z (SYTDEP) Default: 550. ! SYTDEP = 5.5E02 !Switch for using Heffter equation for sigma zas above (0 = Not use Heffter; 1 = use Heffter(MHFTSZ) Default: 0 ! MHFTSZ = 0 !Stability class used to determine plumegrowth rates for puffs above the boundarylayer (JSUP) Default: 5 ! JSUP = 5 !Page 222001_SO_NOx.inpVertical dispersion constant for stableconditions (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 fromSchulman-Scire to Huber-Snyder Building Downwashscheme (SS used for Hs < Hb + TBD * HL)(TBD) Default: 0.5 ! TBD = .5 !TBD < 0 ==> always use Huber-SnyderTBD = 1.5 ==> always use Schulman-ScireTBD = 0.5 ==> ISC Transition-pointRange of land use categories for whichurban 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)Page 232001_SO_NOx.inp(ISIGMAV) Default: 1 ! ISIGMAV = 1 !0 = read sigma-theta1 = read sigma-vChoice of mixing heights (Used only if METFM = 4)(IMIXCTDM) Default: 0 ! IMIXCTDM = 0 !0 = read PREDICTED mixing heights1 = read OBSERVED mixing heightsMaximum length of a slug (met. grid units)(XMXLEN) Default: 1.0 ! XMXLEN = 1.0 !Maximum travel distance of a puff/slug (ingrid units) during one sampling step(XSAMLEN) Default: 1.0 ! XSAMLEN = 10 !Maximum Number of slugs/puffs release fromone source during one time step(MXNEW) Default: 99 ! MXNEW = 60 !Maximum Number of sampling steps forone puff/slug during one time step(MXSAM) Default: 99 ! MXSAM = 60 !Number of iterations used when computingthe transport wind for a sampling stepthat includes gradual rise (for CALMETand 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 velocitiessigma-v and sigma-w for eachstability class (m/s)(SVMIN(6) and SWMIN(6)) Default SVMIN : .50, .50, .50, .50, .50, .50Default SWMIN : .20, .12, .08, .06, .03, .016Stability 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 puffPage 242001_SO_NOx.inpused to initiate adjustment for horizontalconvergence (1/s)Partial adjustment starts at CDIV(1), andfull adjustment is reached at CDIV(2)(CDIV(2)) Default: 0.0,0.0 ! CDIV = 0.01, 0.01 !Minimum wind speed (m/s) allowed fornon-calm conditions. Also used as minimumspeed returned when using power-lawextrapolation 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-lawexponents for stabilities 1-6(PLX0(6)) Default : ISC RURAL valuesISC RURAL : .07, .07, .10, .15, .35, .55ISC URBAN : .15, .15, .20, .25, .30, .30Stability Class : A B C D E F--- --- --- --- --- ---! PLX0 = 0.07, 0.07, 0.10, 0.15, 0.35, 0.55 !Default potential temperature gradientfor stable classes E, F (degK/m)(PTG0(2)) Default: 0.020, 0.035! PTG0 = 0.020, 0.035 !Default plume path coefficients foreach stability class (used when optionfor partial plume height terrain adjustmentis selected -- MCTADJ=3)(PPC(6)) Stability Class : A B C D E FPage 252001_SO_NOx.inpDefault 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 factorequal 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 puffis split - nsplit=2 means that 1 puff splitsinto 2(NSPLIT) Default: 3 ! NSPLIT = 3 !Time(s) of a day when split puffs are eligible tobe split once again; this is typically set onceper 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 mixingheight (m) exceeds a minimum value(ZISPLIT) Default: 100. ! ZISPLIT = 100.0 !Split is allowed only if ratio of last hour'smixing ht to the maximum mixing ht experiencedby the puff is less than a maximum value (thispostpones a split until a nocturnal layer develops)(ROLDMAX) Default: 0.25 ! ROLDMAX = 0.25 !HORIZONTAL SPLIT----------------Number of puffs that result every time a puffis split - nsplith=5 means that 1 puff splitsinto 5(NSPLITH) Default: 5 ! NSPLITH = 5 !Minimum sigma-y (Grid Cells Units) of puffbefore it may be split(SYSPLITH) Default: 1.0 ! SYSPLITH = 1.0 !Page 262001_SO_NOx.inpMinimum puff elongation rate (SYSPLITH/hr) due towind shear, before it may be split(SHSPLITH) Default: 2. ! SHSPLITH = 2.0 !Minimum concentration (g/m^3) of eachspecies in puff before it may be splitEnter array of NSPEC values; if a single value isentered, it will be used for ALL species(CNSPLITH) Default: 1.0E-07 ! CNSPLITH = 1.0E-07 !Integration control variables ------------------------Fractional convergence criterion for numerical SLUGsampling integration(EPSSLUG) Default: 1.0e-04 ! EPSSLUG = 1.0E-04 !Fractional convergence criterion for numerical AREAsource integration(EPSAREA) Default: 1.0e-06 ! EPSAREA = 1.0E-06 !Trajectory step-length (m) used for numerical riseintegration(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 heightat the release point if greater than this minimum.(HTMINBC) Default: 500. ! HTMINBC = 500.0 !Search radius (in BC segment lengths) about a receptor for samplingnearest BC puff. BC puffs are emitted with a spacing of one segmentlength, so the search radius should be greater than 1.(RSAMPBC) Default: 4. ! RSAMPBC = 10.0 !Near-Surface depletion adjustment to concentration profile used whensampling BC puffs?(MDEPBC) Default: 1 ! MDEPBC = 1 !0 = Concentration is NOT adjusted for depletion1 = Adjust Concentration for depletion!END!-------------------------------------------------------------------------------Page 272001_SO_NOx.inpINPUT GROUPS: 13a, 13b, 13c, 13d -- Point source parameters-----------------------------------------------Subgroup (13a)---------------Number of point sources withparameters provided below (NPT1) No default ! NPT1 = 2 !Units used for point sourceemissions below (IPTU) Default: 1 ! IPTU = 3 !1 = g/s2 = kg/hr3 = lb/hr4 = tons/yr5 = Odour Unit * m**3/s (vol. flux of odour compound)6 = Odour Unit * m**3/min7 = metric tons/yrNumber of source-speciescombinations with variableemissions scaling factorsprovided below in (13d) (NSPT1) Default: 0 ! NSPT1 = 0 !Number of point sources withvariable emission parametersprovided in external file (NPT2) No default ! NPT2 = 0 !(If NPT2 > 0, these pointsource emissions are read fromthe file: PTEMARB.DAT)!END!---------------Subgroup (13b)---------------aPOINT SOURCE: CONSTANT DATA-----------------------------b cSource X Y Stack Base Stack Exit Exit Bldg. EmissionNo. Coordinate Coordinate Height Elevation Diameter Vel. Temp. Dwash Rates(km) (km) (m) (m) (m) (m/s) (deg. K)------ ---------- ---------- ------ ------ -------- ----- -------- ----- --------1 ! SRCNAM = SO1 ! Sooner Unit 1Page 282001_SO_NOx.inp1 ! 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 22 ! 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 !--------aData for each source are treated as a separate input subgroupand 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 representthe effect of rain-caps or other physical configurations thatreduce momentum rise associated with the actual exit velocity.(Default: 1.0 -- full momentum used)b0. = No building downwash modeled, 1. = downwash modeledNOTE: must be entered as a REAL number (i.e., with decimal point)cAn emission rate must be entered for every pollutant modeled.Enter emission rate of zero for secondary pollutants that aremodeled, 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 aNo. Effective building height, width, length and X/Y offset (in meters)every 10 degrees. LENGTH, XBADJ, and YBADJ are only needed forMBDW=2 (PRIME downwash option)------ --------------------------------------------------------------------Page 292001_SO_NOx.inp--------aBuilding height, width, length, and X/Y offset from the source are treatedas a separate input subgroup for each source and therefore must end withan input group terminator. The X/Y offset is the position, relative to thestack, of the center of the upwind face of the projected building, with thex-axis pointing along the flow direction.---------------Subgroup (13d)---------------aPOINT SOURCE: VARIABLE EMISSIONS DATA---------------------------------------Use this subgroup to describe temporal variations in the emissionrates given in 13b. Factors entered multiply the rates in 13b.Skip sources here that have constant emissions. For more elaboratevariation in source parameters, use PTEMARB.DAT and NPT2 > 0.IVARY determines the type of variation, and is source-specific:(IVARY) Default: 00 = Constant1 = 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, wherefirst group is Stability Class A,and the speed classes have upperbounds (m/s) defined in Group 125 = Temperature (12 scaling factors, where temperatureclasses have upper bounds (C) of:0, 5, 10, 15, 20, 25, 30, 35, 40,45, 50, 50+)--------aData for each species are treated as a separate input subgroupand therefore must end with an input group terminator.-------------------------------------------------------------------------------Page 302001_SO_NOx.inpINPUT GROUPS: 14a, 14b, 14c, 14d -- Area source parameters-----------------------------------------------Subgroup (14a)---------------Number of polygon area sources withparameters specified below (NAR1) No default ! NAR1 = 0 !Units used for area sourceemissions below (IARU) Default: 1 ! IARU = 1 !1 = g/m**2/s2 = kg/m**2/hr3 = lb/m**2/hr4 = tons/m**2/yr5 = Odour Unit * m/s (vol. flux/m**2 of odour compound)6 = Odour Unit * m/min7 = metric tons/m**2/yrNumber of source-speciescombinations with variableemissions scaling factorsprovided below in (14d) (NSAR1) Default: 0 ! NSAR1 = 0 !Number of buoyant polygon area sourceswith variable location and emissionparameters (NAR2) No default ! NAR2 = 0 !(If NAR2 > 0, ALL parameter data forthese sources are read from the file: BAEMARB.DAT)!END!---------------Subgroup (14b)---------------aAREA SOURCE: CONSTANT DATA----------------------------bSource Effect. Base Initial EmissionNo. Height Elevation Sigma z Rates(m) (m) (m)------- ------ ------ -------- -----------------Page 312001_SO_NOx.inpaData for each source are treated as a separate input subgroupand therefore must end with an input group terminator.bAn emission rate must be entered for every pollutant modeled.Enter emission rate of zero for secondary pollutants that aremodeled, 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 aNo. Ordered list of X followed by list of Y, grouped by source------ --------------------------------------------------------------------aData for each source are treated as a separate input subgroupand therefore must end with an input group terminator.---------------Subgroup (14d)---------------aAREA SOURCE: VARIABLE EMISSIONS DATA--------------------------------------Use this subgroup to describe temporal variations in the emissionrates given in 14b. Factors entered multiply the rates in 14b.Skip sources here that have constant emissions. For more elaboratevariation in source parameters, use BAEMARB.DAT and NAR2 > 0.IVARY determines the type of variation, and is source-specific:(IVARY) Default: 00 = Constant1 = 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, wherefirst group is Stability Class A,and the speed classes have upperPage 322001_SO_NOx.inpbounds (m/s) defined in Group 125 = Temperature (12 scaling factors, where temperatureclasses have upper bounds (C) of:0, 5, 10, 15, 20, 25, 30, 35, 40,45, 50, 50+)--------aData for each species are treated as a separate input subgroupand therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUPS: 15a, 15b, 15c -- Line source parameters------------------------------------------Subgroup (15a)---------------Number of buoyant line sourceswith variable location and emissionparameters (NLN2) No default ! NLN2 = 0 !(If NLN2 > 0, ALL parameter data forthese sources are read from the file: LNEMARB.DAT)Number of buoyant line sources (NLINES) No default ! NLINES = 0 !Units used for line sourceemissions below (ILNU) Default: 1 ! ILNU = 3 !1 = g/s2 = kg/hr3 = lb/hr4 = tons/yr5 = Odour Unit * m**3/s (vol. flux of odour compound)6 = Odour Unit * m**3/min7 = metric tons/yrNumber of source-speciescombinations with variableemissions scaling factorsprovided below in (15c) (NSLN1) Default: 0 ! NSLN1 = 0 !Maximum number of segments used to modelPage 332001_SO_NOx.inpeach line (MXNSEG) Default: 7 ! MXNSEG = 7 !The following variables are required only if NLINES > 0. They areused in the buoyant line source plume rise calculations.Number of distances at which Default: 6 ! NLRISE = 6 !transitional rise is computedAverage 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 EmissionNo. Coordinate Coordinate Coordinate Coordinate Height Elevation Rates(km) (km) (km) (km) (m) (m)------ ---------- ---------- --------- ---------- ------- --------- -----------------aData for each source are treated as a separate input subgroupand therefore must end with an input group terminator.bAn emission rate must be entered for every pollutant modeled.Page 342001_SO_NOx.inpEnter emission rate of zero for secondary pollutants that aremodeled, but not emitted. Units are specified by ILNTU(e.g. 1 for g/s).---------------Subgroup (15c)---------------aBUOYANT LINE SOURCE: VARIABLE EMISSIONS DATA----------------------------------------------Use this subgroup to describe temporal variations in the emissionrates 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: 00 = Constant1 = 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, wherefirst group is Stability Class A,and the speed classes have upperbounds (m/s) defined in Group 125 = Temperature (12 scaling factors, where temperatureclasses have upper bounds (C) of:0, 5, 10, 15, 20, 25, 30, 35, 40,45, 50, 50+)--------aData for each species are treated as a separate input subgroupand therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUPS: 16a, 16b, 16c -- Volume source parameters------------------------------------------Subgroup (16a)---------------Page 352001_SO_NOx.inpNumber of volume sources withparameters provided in 16b,c (NVL1) No default ! NVL1 = 0 !Units used for volume sourceemissions below in 16b (IVLU) Default: 1 ! IVLU = 3 !1 = g/s2 = kg/hr3 = lb/hr4 = tons/yr5 = Odour Unit * m**3/s (vol. flux of odour compound)6 = Odour Unit * m**3/min7 = metric tons/yrNumber of source-speciescombinations with variableemissions scaling factorsprovided below in (16c) (NSVL1) Default: 0 ! NSVL1 = 0 !Number of volume sources withvariable location and emissionparameters (NVL2) No default ! NVL2 = 0 !(If NVL2 > 0, ALL parameter data forthese sources are read from the VOLEMARB.DAT file(s) )!END!---------------Subgroup (16b)---------------aVOLUME SOURCE: CONSTANT DATA------------------------------bX Y Effect. Base Initial Initial EmissionCoordinate Coordinate Height Elevation Sigma y Sigma z Rates(km) (km) (m) (m) (m) (m)---------- ---------- ------ ------ -------- -------- ----------------aData for each source are treated as a separate input subgroupand therefore must end with an input group terminator.bAn emission rate must be entered for every pollutant modeled.Page 362001_SO_NOx.inpEnter emission rate of zero for secondary pollutants that aremodeled, but not emitted. Units are specified by IVLU(e.g. 1 for g/s).---------------Subgroup (16c)---------------aVOLUME SOURCE: VARIABLE EMISSIONS DATA----------------------------------------Use this subgroup to describe temporal variations in the emissionrates given in 16b. Factors entered multiply the rates in 16b.Skip sources here that have constant emissions. For more elaboratevariation in source parameters, use VOLEMARB.DAT and NVL2 > 0.IVARY determines the type of variation, and is source-specific:(IVARY) Default: 00 = Constant1 = 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, wherefirst group is Stability Class A,and the speed classes have upperbounds (m/s) defined in Group 125 = Temperature (12 scaling factors, where temperatureclasses have upper bounds (C) of:0, 5, 10, 15, 20, 25, 30, 35, 40,45, 50, 50+)--------aData for each species are treated as a separate input subgroupand therefore must end with an input group terminator.-------------------------------------------------------------------------------INPUT GROUPS: 17a & 17b -- Non-gridded (discrete) receptor information--------------------------------------Subgroup (17a)---------------Page 372001_SO_NOx.inpNumber of non-gridded receptors (NREC) No default ! NREC = 291 !!END!---------------Subgroup (17b)---------------aNON-GRIDDED (DISCRETE) RECEPTOR DATA------------------------------------X Y Ground Height bReceptor Coordinate Coordinate Elevation Above GroundNo. (km) (km) (m) (m)-------- ---------- ---------- --------- ------------1 ! X = 359.836, -362.005, 274, 0 ! !END! HG12 ! X = 360.575, -361.972, 299, 0 ! !END! HG23 ! X = 361.314, -361.939, 328, 0 ! !END! HG34 ! X = 362.053, -361.906, 365, 0 ! !END! HG45 ! X = 358.316, -361.150, 250, 0 ! !END! HG56 ! X = 359.055, -361.117, 278, 0 ! !END! HG67 ! X = 359.794, -361.084, 335, 0 ! !END! HG78 ! X = 360.533, -361.051, 307, 0 ! !END! HG89 ! X = 361.272, -361.018, 345, 0 ! !END! HG910 ! X = 357.537, -360.261, 261, 0 ! !END! HG1011 ! X = 358.275, -360.228, 271, 0 ! !END! HG1112 ! X = 359.014, -360.195, 274, 0 ! !END! HG1213 ! X = 359.753, -360.162, 331, 0 ! !END! HG1314 ! X = 360.492, -360.129, 327, 0 ! !END! HG1415 ! X = 361.231, -360.096, 304, 0 ! !END! HG1516 ! X = 361.970, -360.063, 335, 0 ! !END! HG1617 ! X = 362.709, -360.030, 312, 0 ! !END! HG1718 ! X = 363.448, -359.997, 340, 0 ! !END! HG1819 ! X = 364.187, -359.963, 361, 0 ! !END! HG1920 ! X = 364.926, -359.930, 382, 0 ! !END! HG2021 ! X = 357.496, -359.340, 274, 0 ! !END! HG2122 ! X = 358.235, -359.307, 274, 0 ! !END! HG2223 ! X = 358.973, -359.274, 335, 0 ! !END! HG2324 ! X = 359.712, -359.241, 294, 0 ! !END! HG2425 ! X = 360.451, -359.208, 304, 0 ! !END! HG2526 ! X = 361.190, -359.175, 279, 0 ! !END! HG2627 ! X = 361.929, -359.142, 304, 0 ! !END! HG2728 ! X = 362.668, -359.109, 318, 0 ! !END! HG2829 ! X = 363.406, -359.075, 335, 0 ! !END! HG2930 ! X = 364.145, -359.042, 347, 0 ! !END! HG3031 ! X = 364.884, -359.008, 340, 0 ! !END! HG3132 ! X = 358.932, -358.353, 247, 0 ! !END! HG32Page 382001_SO_NOx.inp33 ! X = 359.671, -358.320, 271, 0 ! !END! HG3334 ! X = 360.410, -358.287, 275, 0 ! !END! HG3435 ! X = 361.149, -358.254, 274, 0 ! !END! HG3536 ! X = 361.887, -358.220, 277, 0 ! !END! HG3637 ! X = 362.626, -358.187, 304, 0 ! !END! HG3738 ! X = 363.365, -358.154, 330, 0 ! !END! HG3839 ! X = 364.104, -358.121, 357, 0 ! !END! HG3940 ! X = 364.842, -358.087, 384, 0 ! !END! HG4041 ! X = 365.581, -358.054, 372, 0 ! !END! HG4142 ! X = 356.675, -357.530, 274, 0 ! !END! HG4243 ! X = 357.414, -357.497, 293, 0 ! !END! HG4344 ! X = 358.153, -357.464, 272, 0 ! !END! HG4445 ! X = 358.891, -357.431, 271, 0 ! !END! HG4546 ! X = 359.630, -357.398, 274, 0 ! !END! HG4647 ! X = 360.369, -357.365, 327, 0 ! !END! HG4748 ! X = 361.107, -357.332, 316, 0 ! !END! HG4849 ! X = 361.846, -357.299, 304, 0 ! !END! HG4950 ! X = 362.585, -357.266, 354, 0 ! !END! HG5051 ! X = 363.323, -357.233, 346, 0 ! !END! HG5152 ! X = 364.062, -357.199, 335, 0 ! !END! HG5253 ! X = 364.801, -357.166, 344, 0 ! !END! HG5354 ! X = 365.539, -357.132, 364, 0 ! !END! HG5455 ! X = 357.373, -356.576, 243, 0 ! !END! HG5556 ! X = 358.112, -356.543, 335, 0 ! !END! HG5657 ! X = 358.850, -356.510, 324, 0 ! !END! HG5758 ! X = 359.589, -356.477, 335, 0 ! !END! HG5859 ! X = 360.327, -356.444, 341, 0 ! !END! HG5960 ! X = 361.066, -356.411, 333, 0 ! !END! HG6061 ! X = 361.805, -356.378, 306, 0 ! !END! HG6162 ! X = 362.543, -356.345, 304, 0 ! !END! HG6263 ! X = 363.282, -356.311, 365, 0 ! !END! HG6364 ! X = 364.020, -356.278, 304, 0 ! !END! HG6465 ! X = 364.759, -356.245, 309, 0 ! !END! HG6566 ! X = 365.497, -356.211, 307, 0 ! !END! HG6667 ! X = 357.332, -355.654, 270, 0 ! !END! HG6768 ! X = 358.071, -355.622, 274, 0 ! !END! HG6869 ! X = 358.809, -355.589, 301, 0 ! !END! HG6970 ! X = 359.548, -355.556, 274, 0 ! !END! HG7071 ! X = 360.286, -355.523, 274, 0 ! !END! HG7172 ! X = 361.025, -355.490, 312, 0 ! !END! HG7273 ! X = 361.763, -355.457, 274, 0 ! !END! HG7374 ! X = 362.502, -355.423, 322, 0 ! !END! HG7475 ! X = 363.240, -355.390, 304, 0 ! !END! HG7576 ! X = 363.979, -355.357, 275, 0 ! !END! HG7677 ! X = 364.717, -355.323, 304, 0 ! !END! HG7778 ! X = 365.456, -355.290, 290, 0 ! !END! HG7879 ! X = 362.460, -354.502, 249, 0 ! !END! HG7980 ! X = 363.199, -354.469, 274, 0 ! !END! HG80Page 392001_SO_NOx.inp81 ! X = -159.867, -584.484, 454, 0 ! !END! WM182 ! X = -159.108, -584.499, 486, 0 ! !END! WM283 ! X = -158.348, -584.513, 487, 0 ! !END! WM384 ! X = -157.589, -584.528, 478, 0 ! !END! WM485 ! X = -156.829, -584.542, 518, 0 ! !END! WM586 ! X = -156.070, -584.557, 518, 0 ! !END! WM687 ! X = -161.368, -583.531, 510, 0 ! !END! WM788 ! X = -160.609, -583.546, 493, 0 ! !END! WM889 ! X = -159.849, -583.560, 488, 0 ! !END! WM990 ! X = -159.090, -583.575, 615, 0 ! !END! WM1091 ! X = -158.331, -583.589, 522, 0 ! !END! WM1192 ! X = -157.571, -583.604, 494, 0 ! !END! WM1293 ! X = -156.812, -583.618, 609, 0 ! !END! WM1394 ! X = -156.052, -583.633, 518, 0 ! !END! WM1495 ! X = -162.110, -582.592, 487, 0 ! !END! WM1596 ! X = -161.350, -582.607, 518, 0 ! !END! WM1697 ! X = -160.591, -582.622, 609, 0 ! !END! WM1798 ! X = -159.832, -582.636, 554, 0 ! !END! WM1899 ! X = -159.072, -582.651, 578, 0 ! !END! WM19100 ! X = -158.313, -582.666, 557, 0 ! !END! WM20101 ! X = -157.554, -582.680, 571, 0 ! !END! WM21102 ! X = -156.794, -582.694, 670, 0 ! !END! WM22103 ! X = -156.035, -582.709, 518, 0 ! !END! WM23104 ! X = -160.573, -581.698, 518, 0 ! !END! WM24105 ! X = -159.814, -581.712, 548, 0 ! !END! WM25106 ! X = -159.054, -581.727, 548, 0 ! !END! WM26107 ! X = -158.295, -581.742, 518, 0 ! !END! WM27108 ! X = -160.555, -580.774, 517, 0 ! !END! WM28109 ! X = -159.796, -580.789, 579, 0 ! !END! WM29110 ! X = -159.037, -580.803, 613, 0 ! !END! WM30111 ! X = -158.278, -580.818, 548, 0 ! !END! WM31112 ! X = -157.518, -580.832, 523, 0 ! !END! WM32113 ! X = -161.296, -579.835, 542, 0 ! !END! WM33114 ! X = -160.537, -579.850, 545, 0 ! !END! WM34115 ! X = -159.778, -579.865, 552, 0 ! !END! WM35116 ! X = -152.895, -577.222, 579, 0 ! !END! WM36117 ! X = -155.913, -576.242, 609, 0 ! !END! WM37118 ! X = -155.154, -576.256, 654, 0 ! !END! WM38119 ! X = -154.396, -576.270, 621, 0 ! !END! WM39120 ! X = -153.637, -576.284, 629, 0 ! !END! WM40121 ! X = -152.878, -576.298, 579, 0 ! !END! WM41122 ! X = -152.119, -576.312, 560, 0 ! !END! WM42123 ! X = -156.654, -575.304, 615, 0 ! !END! WM43124 ! X = -155.896, -575.318, 641, 0 ! !END! WM44125 ! X = -155.137, -575.332, 640, 0 ! !END! WM45126 ! X = -154.378, -575.346, 662, 0 ! !END! WM46127 ! X = -153.620, -575.361, 618, 0 ! !END! WM47128 ! X = -152.861, -575.375, 630, 0 ! !END! WM48Page 402001_SO_NOx.inp129 ! X = -152.102, -575.389, 534, 0 ! !END! WM49130 ! X = -156.637, -574.380, 606, 0 ! !END! WM50131 ! X = -155.878, -574.394, 566, 0 ! !END! WM51132 ! X = -155.120, -574.408, 633, 0 ! !END! WM52133 ! X = -154.361, -574.423, 670, 0 ! !END! WM53134 ! X = -153.603, -574.437, 609, 0 ! !END! WM54135 ! X = -152.844, -574.451, 579, 0 ! !END! WM55136 ! X = -152.085, -574.465, 535, 0 ! !END! WM56137 ! X = -155.102, -573.485, 548, 0 ! !END! WM57138 ! X = -154.344, -573.499, 518, 0 ! !END! WM58139 ! X = -153.585, -573.513, 506, 0 ! !END! WM59140 ! X = 318.344, -456.077, 555, 0 ! !END! UB1141 ! X = 319.091, -456.047, 589, 0 ! !END! UB2142 ! X = 321.334, -455.959, 563, 0 ! !END! UB3143 ! X = 318.308, -455.154, 549, 0 ! !END! UB4144 ! X = 319.055, -455.125, 487, 0 ! !END! UB5145 ! X = 319.803, -455.096, 487, 0 ! !END! UB6146 ! X = 320.551, -455.067, 490, 0 ! !END! UB7147 ! X = 318.272, -454.232, 650, 0 ! !END! UB8148 ! X = 319.019, -454.203, 563, 0 ! !END! UB9149 ! X = 319.767, -454.174, 540, 0 ! !END! UB10150 ! X = 320.514, -454.144, 502, 0 ! !END! UB11151 ! X = 321.262, -454.115, 526, 0 ! !END! UB12152 ! X = 322.757, -454.056, 534, 0 ! !END! UB13153 ! X = 323.504, -454.026, 563, 0 ! !END! UB14154 ! X = 318.236, -453.310, 548, 0 ! !END! UB15155 ! X = 318.983, -453.281, 628, 0 ! !END! UB16156 ! X = 319.731, -453.252, 623, 0 ! !END! UB17157 ! X = 320.478, -453.222, 579, 0 ! !END! UB18158 ! X = 321.225, -453.193, 469, 0 ! !END! UB19159 ! X = 321.973, -453.163, 457, 0 ! !END! UB20160 ! X = 322.720, -453.134, 573, 0 ! !END! UB21161 ! X = 323.468, -453.104, 605, 0 ! !END! UB22162 ! X = 324.215, -453.074, 588, 0 ! !END! UB23163 ! X = 318.200, -452.388, 608, 0 ! !END! UB24164 ! X = 318.947, -452.359, 660, 0 ! !END! UB25165 ! X = 319.694, -452.329, 598, 0 ! !END! UB26166 ! X = 320.442, -452.300, 599, 0 ! !END! UB27167 ! X = 321.189, -452.271, 639, 0 ! !END! UB28168 ! X = 321.937, -452.241, 457, 0 ! !END! UB29169 ! X = 322.684, -452.212, 568, 0 ! !END! UB30170 ! X = 318.164, -451.466, 730, 0 ! !END! UB31171 ! X = 318.911, -451.437, 681, 0 ! !END! UB32172 ! X = 319.658, -451.407, 640, 0 ! !END! UB33173 ! X = 320.406, -451.378, 625, 0 ! !END! UB34174 ! X = 321.153, -451.348, 426, 0 ! !END! UB35175 ! X = 321.900, -451.319, 555, 0 ! !END! UB36176 ! X = 322.647, -451.289, 612, 0 ! !END! UB37Page 412001_SO_NOx.inp177 ! X = 317.380, -450.573, 667, 0 ! !END! UB38178 ! X = 318.128, -450.544, 580, 0 ! !END! UB39179 ! X = 318.875, -450.514, 656, 0 ! !END! UB40180 ! X = 319.622, -450.485, 640, 0 ! !END! UB41181 ! X = 320.369, -450.456, 487, 0 ! !END! UB42182 ! X = 321.116, -450.426, 457, 0 ! !END! UB43183 ! X = 321.864, -450.397, 654, 0 ! !END! UB44184 ! X = 322.611, -450.367, 548, 0 ! !END! UB45185 ! X = 323.358, -450.338, 622, 0 ! !END! UB46186 ! X = 324.105, -450.308, 683, 0 ! !END! UB47187 ! X = 317.345, -449.651, 579, 0 ! !END! UB48188 ! X = 318.092, -449.621, 554, 0 ! !END! UB49189 ! X = 318.839, -449.592, 609, 0 ! !END! UB50190 ! X = 319.586, -449.563, 622, 0 ! !END! UB51191 ! X = 320.333, -449.534, 427, 0 ! !END! UB52192 ! X = 321.080, -449.504, 555, 0 ! !END! UB53193 ! X = 321.827, -449.475, 502, 0 ! !END! UB54194 ! X = 322.574, -449.445, 639, 0 ! !END! UB55195 ! X = 323.322, -449.416, 580, 0 ! !END! UB56196 ! X = 324.069, -449.386, 639, 0 ! !END! UB57197 ! X = 318.803, -448.670, 548, 0 ! !END! UB58198 ! X = 319.550, -448.641, 548, 0 ! !END! UB59199 ! X = 320.297, -448.612, 438, 0 ! !END! UB60200 ! X = 321.044, -448.582, 579, 0 ! !END! UB61201 ! X = 322.538, -448.523, 620, 0 ! !END! UB62202 ! X = 320.261, -447.689, 579, 0 ! !END! UB63203 ! X = 321.007, -447.660, 426, 0 ! !END! UB64204 ! X = 321.754, -447.631, 611, 0 ! !END! UB65205 ! X = 318.731, -446.826, 604, 0 ! !END! UB66206 ! X = 319.477, -446.797, 548, 0 ! !END! UB67207 ! X = 320.224, -446.767, 488, 0 ! !END! UB68208 ! X = 320.971, -446.738, 402, 0 ! !END! UB69209 ! X = 321.718, -446.708, 579, 0 ! !END! UB70210 ! X = 322.465, -446.679, 573, 0 ! !END! UB71211 ! X = 323.212, -446.649, 609, 0 ! !END! UB72212 ! X = 269.710, -618.629, 365, 0 ! !END! CC1213 ! X = 270.473, -618.605, 365, 0 ! !END! CC2214 ! X = 271.235, -618.580, 368, 0 ! !END! CC3215 ! X = 268.155, -617.755, 411, 0 ! !END! CC4216 ! X = 268.917, -617.730, 462, 0 ! !END! CC5217 ! X = 269.680, -617.705, 431, 0 ! !END! CC6218 ! X = 270.443, -617.681, 518, 0 ! !END! CC7219 ! X = 271.205, -617.656, 487, 0 ! !END! CC8220 ! X = 271.968, -617.631, 396, 0 ! !END! CC9221 ! X = 265.075, -616.929, 518, 0 ! !END! CC10222 ! X = 265.838, -616.904, 523, 0 ! !END! CC11223 ! X = 266.600, -616.880, 548, 0 ! !END! CC12224 ! X = 267.363, -616.855, 579, 0 ! !END! CC13Page 422001_SO_NOx.inp225 ! X = 268.125, -616.831, 547, 0 ! !END! CC14226 ! X = 268.888, -616.806, 538, 0 ! !END! CC15227 ! X = 269.650, -616.781, 640, 0 ! !END! CC16228 ! X = 270.412, -616.757, 608, 0 ! !END! CC17229 ! X = 259.709, -616.173, 335, 0 ! !END! CC18230 ! X = 260.472, -616.149, 431, 0 ! !END! CC19231 ! X = 261.234, -616.125, 457, 0 ! !END! CC20232 ! X = 261.996, -616.101, 414, 0 ! !END! CC21233 ! X = 262.759, -616.077, 426, 0 ! !END! CC22234 ! X = 263.521, -616.053, 426, 0 ! !END! CC23235 ! X = 264.283, -616.029, 388, 0 ! !END! CC24236 ! X = 265.046, -616.005, 388, 0 ! !END! CC25237 ! X = 265.808, -615.980, 365, 0 ! !END! CC26238 ! X = 266.571, -615.956, 386, 0 ! !END! CC27239 ! X = 267.333, -615.931, 396, 0 ! !END! CC28240 ! X = 268.095, -615.907, 426, 0 ! !END! CC29241 ! X = 268.858, -615.882, 446, 0 ! !END! CC30242 ! X = 269.620, -615.857, 441, 0 ! !END! CC31243 ! X = 270.382, -615.833, 457, 0 ! !END! CC32244 ! X = 271.145, -615.808, 465, 0 ! !END! CC33245 ! X = 271.907, -615.783, 442, 0 ! !END! CC34246 ! X = 272.670, -615.758, 426, 0 ! !END! CC35247 ! X = 259.680, -615.249, 304, 0 ! !END! CC36248 ! X = 260.443, -615.225, 304, 0 ! !END! CC37249 ! X = 261.205, -615.201, 319, 0 ! !END! CC38250 ! X = 261.967, -615.177, 334, 0 ! !END! CC39251 ! X = 262.730, -615.153, 370, 0 ! !END! CC40252 ! X = 263.492, -615.129, 405, 0 ! !END! CC41253 ! X = 264.254, -615.105, 409, 0 ! !END! CC42254 ! X = 265.016, -615.081, 450, 0 ! !END! CC43255 ! X = 265.779, -615.056, 518, 0 ! !END! CC44256 ! X = 266.541, -615.032, 609, 0 ! !END! CC45257 ! X = 267.303, -615.007, 534, 0 ! !END! CC46258 ! X = 268.066, -614.983, 517, 0 ! !END! CC47259 ! X = 268.828, -614.958, 575, 0 ! !END! CC48260 ! X = 269.590, -614.933, 600, 0 ! !END! CC49261 ! X = 270.352, -614.909, 609, 0 ! !END! CC50262 ! X = 271.115, -614.884, 609, 0 ! !END! CC51263 ! X = 271.877, -614.859, 561, 0 ! !END! CC52264 ! X = 260.414, -614.301, 335, 0 ! !END! CC53265 ! X = 261.176, -614.277, 432, 0 ! !END! CC54266 ! X = 261.938, -614.253, 487, 0 ! !END! CC55267 ! X = 262.700, -614.229, 499, 0 ! !END! CC56268 ! X = 263.463, -614.205, 514, 0 ! !END! CC57269 ! X = 264.225, -614.181, 442, 0 ! !END! CC58270 ! X = 264.987, -614.157, 439, 0 ! !END! CC59271 ! X = 265.749, -614.132, 395, 0 ! !END! CC60272 ! X = 266.511, -614.108, 400, 0 ! !END! CC61Page 432001_SO_NOx.inp273 ! X = 267.274, -614.083, 426, 0 ! !END! CC62274 ! X = 268.036, -614.059, 487, 0 ! !END! CC63275 ! X = 268.798, -614.034, 548, 0 ! !END! CC64276 ! X = 269.560, -614.010, 548, 0 ! !END! CC65277 ! X = 270.322, -613.985, 548, 0 ! !END! CC66278 ! X = 271.085, -613.960, 535, 0 ! !END! CC67279 ! X = 261.147, -613.353, 304, 0 ! !END! CC68280 ! X = 261.909, -613.329, 334, 0 ! !END! CC69281 ! X = 262.671, -613.305, 396, 0 ! !END! CC70282 ! X = 263.433, -613.281, 457, 0 ! !END! CC71283 ! X = 264.195, -613.257, 457, 0 ! !END! CC72284 ! X = 264.958, -613.233, 426, 0 ! !END! CC73285 ! X = 265.720, -613.208, 411, 0 ! !END! CC74286 ! X = 266.482, -613.184, 406, 0 ! !END! CC75287 ! X = 267.244, -613.159, 396, 0 ! !END! CC76288 ! X = 268.006, -613.135, 401, 0 ! !END! CC77289 ! X = 268.768, -613.110, 397, 0 ! !END! CC78290 ! X = 261.118, -612.429, 322, 0 ! !END! CC79291 ! X = 261.880, -612.405, 334, 0 ! !END! CC80-------------aData for each receptor are treated as a separate input subgroupand therefore must end with an input group terminator.bReceptor height above ground is optional. If no value is entered,the receptor is placed on the ground.Page 44

### OG&E Trinity Consultants BART Modeling Report 083701.0004 

## A PPENDIX 

## D

– S AMPLE 

## CALPOST C ONTROL 

## F ILESO01_CC_vis.INPOGE 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 ifproviding NON-BLANK character string)User Character String (U) to augment default filenames(activate with exclamation points only ifproviding NON-BLANK character string)Timeseries TSttUUUU.DAT * TSUNAM = *Top Nth Rank Plot RttUUUUU.DATor RttiiUUU.GRD * TUNAM = *Page 1SO01_CC_vis.INPExceedance Plot XttUUUUU.DATor 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 CASET = 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 constructedusing a template that includes a pathname, user-suppliedcharacter(s), and fixed strings (tt,ii,jjj, and hh), wherett = Averaging Period (e.g. 03)ii = Rank (e.g. 02)jjj= Julian Dayhh = Hour(ending)are determined internally based on selections made below.If a path or user-supplied character(s) are supplied, eachmust contain at least 1 non-blank character.!END!--------------------------------------------------------------------------------INPUT GROUP: 1 -- General run control parameters--------------Option to run all periods foundin the met. file(s) (METRUN) Default: 0 ! METRUN = 0 !METRUN = 0 - Run period explicitly defined belowMETRUN = 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,Page 2SO01_CC_vis.INP5 = 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 = 0.0Add 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;ORSelect SPECIFIC DISCRETE receptors by entering a flag (0,1) for each0 = discrete receptor not processed1 = discrete receptor processedusing repeated value notation to select blocks of receptors:416*0, 1048*1, 1482*0Flag 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):Page 3SO01_CC_vis.INPX 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 CALPOSTprocessing by filling a processing grid array with 0s and 1s. If theprocessing flag for receptor index (i,j) is 1 (ON), that receptorwill 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 beprocessed in the run. By default, all array values are set to 1 (ON).Number of gridded receptor rows provided in Subgroup (1a) toidentify 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 processingby filling a processing grid array with 0s and 1s. A total ofNGONOFF lines are read here. Each line corresponds to one 'row'in the sampling grid, starting with the NORTHERNMOST row thatcontains receptors that you wish to exclude, and finishing withrow 1 to the SOUTH (no intervening rows may be skipped). Withina row, each receptor position is assigned either a 0 or 1,starting with the westernmost receptor.0 = gridded receptor not processed1 = gridded receptor processedRepeated value notation may be used to select blocks of receptors:23*1, 15*0, 12*1Because all values are initially set to 1, any receptors north ofPage 4SO01_CC_vis.INPthe 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 extinctionInclude 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 fileCOARSE (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 !Page 5SO01_CC_vis.INP1 = Supply single light extinction and hygroscopic fraction- IWAQM (1993) RH adjustment applied to hygroscopic backgroundand modeled sulfate and nitrate2 = Compute extinction from speciated PM measurements (A)- Hourly RH adjustment applied to observed and modeled sulfateand nitrate- RH factor is capped at RHMAX3 = Compute extinction from speciated PM measurements (B)- Hourly RH adjustment applied to observed and modeled sulfateand nitrate- Receptor-hour excluded if RH>RHMAX- Receptor-day excluded if fewer than 6 valid receptor-hours4 = 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-hours5 = 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-hours6 = Compute extinction from speciated PM measurements- FLAG RH adjustment factor applied to observed andmodeled sulfate and nitrateAdditional 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 andbackground) are computed using a monthly RH adjustment factorin 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:----------------------------------------Page 6SO01_CC_vis.INPBackground extinction coefficients are computed from monthlyCONCENTRATIONS of ammonium sulfate (BKSO4), ammonium nitrate (BKNO3),coarse particulates (BKPMC), organic carbon (BKOC), soil (BKSOIL), andelemental 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 theCALPUFF 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 forPage 7SO01_CC_vis.INPConcentration Deposition1 = g/m**3 g/m**2/s2 = mg/m**3 mg/m**2/s3 = ug/m**3 ug/m**2/s4 = ng/m**3 ng/m**2/s5 = Odour UnitsVisibility: 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 foran averaging time of NAVG hours are reported forNAVG greater than 0:(NAVG) -- Default: 0 ! NAVG = 0 !Types of tabulations reported------------------------------1) Visibility: daily visibility tabulations are always reportedfor the selected receptors when ASPEC = VISIB.In addition, any of the other tabulations listedbelow may be chosen to characterize the lightextinction 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 receptorselected (NTOP must be <= 4)Page 8SO01_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 !1,2,3,44) Threshold exceedance counts for each receptor and each averagingtime selected[List file or Plot file](LEXCD) -- Default: F ! LEXCD = F !-- Identify the threshold for each averaging time by assigning anon-negative value (output units).-- Default: -1.0Threshold 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 betallied daily, and receptors that experience more than NCOUNTcounts over any NDAY period will be reported. This type ofexceedance 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 periodselected and output is grouped by day[List file or Plot file](LECHO) -- Default: F ! LECHO = F !Timeseries Option -- Averages at all selected receptors foreach selected averaging period are written to timeseries files.Each file contains one averaging period, and all receptors arewritten to a single record each averaging time.[TSttUUUU.DAT files](LTIME) -- Default: F ! LTIME = F !Page 9SO01_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 Echotables selected above. Two formats for these files are available,DATA and GRID. In the DATA format, results at all receptors arelisted 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 inrows (x varies), starting with the most southern row of the grid.The GRID format is given the .GRD extension, and includes headerscompatible with the SURFER(R) plotting software.A plotting and analysis file can also be created for the dailypeak visibility summary output, in DATA format only.Generate Plot file output in addition to writing tablesto 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 filefor debugging?(LDEBUG) -- Default: F ! LDEBUG = F !!END!Page 10

### OG&E Trinity Consultants BART Modeling Report 083701.0004 

## A PPENDIX 

## E

– M USKOGEE 

## S TATION 

## E MISSION 

## S UMMARYMuskogee Generating StationBART Emissions Modeling InputsSource Emission SummaryBaseline Heat Input mmBtu/hr 5480 5480Baseline NOx Emission Rate lb/mmBtu 0.495 2710 0.522 2863NOx Rate with LNB/OFA lb/mmBtu 0.15 0.15NOx Rate with SCR lb/mmBtu 0.07 0.07Baseline SO2 Emission Rate lb/mmBtu 0.80 4384 0.85 4657SO2 Rate with DFGD lb/mmBtu 0.10 0.10SO2 Rate with WFGD lb/mmBtu 0.08 0.08Baseline PM10 Emission Rate lb/mmBtu 0.0184 100.9 0.0244 133.84PM10 Rate with DFGD/PBH lb/mmBtu 0.012 0.012Baseline H2SO4 Conversion Rate % 1% 1%H2SO4 Conversion with SCR % 2% 2%Baseline H2SO4 Control Efficiency % 0% 0%H2SO4 Control with DFGD % 90% 90%H2SO4 Control with WFGD % 40% 40%Muskogee Unit 4NOx SO2 lb/mmBtu lb/hr lb/mmBtu lb/hr conversion control eff lb/hr lb/mmBtu lb/hrCase 1 Baseline Case base base 0.495 2710 0.80 4384 1% 0% 67.1 0.0184 100.8Case 2 NOx Combustion Controls LNB/OFA base 0.15 822 0.80 4384 1% 0% 67.1 0.0184 100.8Case 3 NOx Combustion Controls plus SCR SCR base 0.070 384 0.80 4384 2% 0% 134.3 0.0184 100.8Case 4 SO2 DFGD Case base DFGD 0.495 2710 0.10 548 1% 90% 6.7 0.012 65.8Case 5 SO2 WFGD Case base WFGD 0.495 2710 0.08 438 1% 40% 40.3 0.0184 100.8Case 6NOx / SO2 Control Case LNB/OFADFGD 0.15 822 0.10 548 1% 90% 6.7 0.012 65.8Muskogee Unit 4 PM SpeciationSO4 (from PM) PM (coarse)1PM (fine)1EC SOAlb/hr lb/hr lb/hr lb/hr lb/hrCase 1 Baseline Case 62.0 11.1 11.7 0.5 15.5Case 2 NOx Combustion Controls 62.0 11.1 11.7 0.5 15.5Case 3 NOx Combustion Controls plus SCR 62.0 11.1 11.7 0.5 15.5Case 4 SO2 DFGD Case 40.5 7.2 7.7 0.3 10.1Case 5 SO2 WFGD Case 62.0 11.1 11.7 0.5 15.5Case 6NOx / SO2 Control Case 40.5 7.2 7.7 0.3 10.1BART Alternative Report, page 4-1Assumed 90% H2SO4 control with DFGD/PBHAssumed 40% H2SO4 controlw with WFGDBasis / NotesDFGD requires polishing baghouse which will reduce PM emissions.Assumed SO2 to SO3 conversion in the boiler.Assumed SO2 to SO3 conversion in the boiler and SCR.Assumed no inherent SO3/H2SO4 control with the baseline technologies.Based on design target of 0.05 lb/mmBtu plus operating margin.BART Alternative Report, page 4-1Design removal efficiency of 92% plus operating margin.Design removal efficiency of 95% plus operating margin.Muskogee Unit 4 Muskogee Unit 5BART Alternative Report, page 1-1BART Alternative Report, page 4-1DBTF Boiler firing subbituminous coalControl Systems NOxPM10H2SO4 (in model as SO4 from SO2)SO2Muskogee Unit 5NOx SO2 lb/mmBtu lb/hr lb/mmBtu lb/hr conversion control eff lb/hr lb/mmBtu lb/hrCase 1 Baseline Case base base 0.522 2863 0.85 4657 1% 0% 71.3 0.024 133.7Case 2 NOx Combustion Controls LNB/OFA base 0.150 822 0.85 4657 1% 0% 71.3 0.024 133.7Case 3 NOx Combustion Controls plus SCR SCR base 0.070 384 0.85 4657 2% 0% 142.6 0.024 133.7Case 4 SO2 DFGD Case base DFGD 0.522 2863 0.10 548 1% 90% 7.1 0.012 65.8Case 5 SO2 WFGD Case base WFGD 0.522 2863 0.08 438 1% 40% 42.8 0.024 133.7Case 6NOx / SO2 Control Case LNB/OFADFGD 0.150 822 0.10 548 1% 90% 7.1 0.012 65.8Muskogee Unit 5 PM SpeciationSO4 (from PM) PM (coarse)1PM (fine)1EC SOAlb/hr lb/hr lb/hr lb/hr lb/hrCase 1 Baseline Case 82.3 14.7 15.6 0.6 20.6Case 2 NOx Combustion Controls 82.3 14.7 15.6 0.6 20.6Case 3 NOx Combustion Controls plus SCR 82.3 14.7 15.6 0.6 20.6Case 4 SO2 DFGD Case 40.5 7.2 7.7 0.3 10.1Case 5 SO2 WFGD Case 82.3 14.7 15.6 0.6 20.6Case 6NOx / SO2 Control Case 40.5 7.2 7.7 0.3 10.11Condensible/filterable PM speciation were based on the following profiles:For Coal, National Park Service guidance for PC Wet Bottom ESP. http://www2.nature.nps.gov/air/Permits/ect/ectCoalFiredBoiler.cfmCoarse 10.99%Fine Soil 11.64% Fine soil included in model as PM (fine)Fine EC 0.45%CPM IOR 61.54% Inorganic condensible PM considered sulfates per NPS guidanceCPM OR 15.38% Organic condensible PM considered secondary organic aerosols per NPSPM10H2SO4 (in model as SO4 from SO2)Control Systems NOx SO2Muskogee Generating StationBART Emissions Modeling InputsStack ParametersUnit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5 Unit 4 Unit 5NOx Controls base base LNB/OFA LNB/OFA SCR SCR base base base base LNB/OFA LNB/OFASO2 Controls base base base base base base DFGD DFGD WFGD WFGD DFGD DFGDEmissions (lb/hr)NOx 2710 2863 822 822 384 384 2710 2863 2710 2863 822 822SO2 4384 4657 4384 4657 4384 4657 548 548 438 438 548 548PM10 100.8 133.7 100.8 133.7 100.8 133.7 65.8 65.8 100.8 133.7 65.8 65.8H2SO4 67.1 71.3 67.1 71.3 134.3 142.6 6.7 7.1 40.3 42.8 6.7 7.1Stack ParametersEnglishFlow (acfm) 2,260,202 2,260,202 2,260,202 2,260,202 2,376,222 2,376,222 2,028,009 2,028,009 1,878,400 1,878,400 2,045,112 2,045,112Temperature (oF) 316 316 316 316 323 323 187 187 138 138 192 192Stack Height (feet) 350 350 350 350 350 350 350 350 350 350 350 350Stack Diameter (feet) 24 24 24 24 24 24 24 24 24 24 24 24Exit Velocity (ft/sec) 83.3 83.3 83.3 83.3 87.5 87.5 74.7 74.7 69.2 69.2 75.3 75.3MetricTemperature (K) 430.78 430.78 430.78 430.78 434.67 434.67 359.11 359.11 331.89 331.89 361.89 361.89Stack Height (m) 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71 106.71Stack Diameter (m) 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32 7.32Exit Velocity (m/s) 25.40 25.40 25.40 25.40 26.68 26.68 22.77 22.77 21.10 21.10 22.96 22.96Case 5(SO2 -WFGD)Case 6(LNB/OFA + DFGD)Case 1(baseline)Case 2(NOx - LNB/OFA)Case 3(LNB/OFA+SCR)Case 4(SO2 - DFGD)