Exhibit 6 
 DRAFT

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY 

AIR QUALITY DIVISION 

MEMORANDUM October 27, 2009 

TO: Phillip Fielder, P.E., Permits and Engineering Group Manager 

 Air Quality Division 

THROUGH: Kendal Stegmann, Senior Environmental Manager 

Compliance and Enforcement 

THROUGH: Phil Martin, P.E., Engineering Section

THROUGH: Peer Review

FROM: Eric L. Milligan, P.E., Engineering Section 

SUBJECT: Evaluation of Permit Application No. 2003-400-TVR (M-1) 

Oklahoma Gas & Electric Company 

 Seminole Generating Station (4911) 

 Section 25, T6N, R5E, Seminole County 

 Latitude: 34.9705°N; Longitude: 96.7335°W 

Located Two Miles Northeast of Konawa 

SECTION I. INTRODUCTION 

The Oklahoma Gas & Electric Company (OG&E) has requested a modification of their current 

Part 70 operating permit to incorporate the proposed BART analysis and requirements. The 

facility is currently operating under Permit No. 2003-400-TVR issued May 9, 2006. 

SECTION II. FACILITY DESCRIPTION 

The Seminole facility consists of three (3) natural circulation Babcock and Wilcox El-Paso type 

boilers capable of producing steam. The thermodynamic energy in the steam is converted to 

mechanical energy and then to electrical energy by the steam turbine/generator unit capable of 

producing electricity. Both Unit 1 and Unit 2 boilers use natural gas as their primary fuel and 

are capable of using #2 fuel oil as a secondary fuel. The fuel oil is stored in two (2) 55,000-barrel 

storage tanks and is fed into the boilers by pipeline. Unit 3 boiler uses natural gas as its primary 

fuel and #6 fuel oil as secondary fuel. The #6 fuel oil is stored in one (1) 300,000-barrel storage 

tank, transferred to a 126,000 gallon surge tank and is fed into the boiler by pipeline. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 2 

The facility utilizes a gas-fired auxiliary boiler to provide steam for heating the #6 fuel oil. The 

boiler has a rated capacity of 33.47 MMBTUH at 80% boiler efficiency. The boiler was 

manufactured by Cleaver-Brooks and is a horizontal, multiple pass, dry type, fire tube boiler 

with a forced draft fan. 

A gas-turbine generator is present for a “black” start of the plant and peaking duty. The gas 

turbine is a simple cycle, single shaft, two bearing, dual fired turbine capable of producing 

20,150 kW of electricity. 

Two (2) mechanical dust collectors with inlet vanes, tubes, and hoppers are used on Unit 3 to 

collect particulate matter and unburned carbon resulting from the combustion of #6 fuel oil. The 

collectors are designed to remove particulate matter from 4.4 million pounds per hour of flue gas 

exhaust. The collected material is removed from the hoppers and transported to OG&E's Sooner 

Generating Station where it is incinerated in the boilers. 

In 1993, OG&E received permission to burn waste oil and nonhazardous waste (BIF) at this 

facility. Approval has also been granted to burn up to 3,000 gallons per year of antifreeze in the 

boilers. 

SECTION III. EQUIPMENT 

EUG 1 Facility Wide

EU ID# Point ID# EU Name/Model Construction Date

None None Facility 1968 - 1970 

EUG 2 Boilers

EU ID# Point ID# EU Name/Model Heat Capacity (MMBTUH) Construction Date

2-B 01 Unit 1 Boiler 5,480 1968 

2-B 02 Unit 2 Boiler 5,480 1968 

2-B 03 Unit 3 Boiler 5,496 (gas fuel) 

3,681 (oil fuel) 

5/28/70 

EUG 3 Auxiliary Boiler

EU ID# Point ID# EU Name/Model Heat Capacity (MMBTUH) Construction Date

3-B 02 Auxiliary Boiler 33.47 1974 

EUG 4 Gas Turbine

EU ID# Point ID# EU Name/Model Heat Capacity (MMBTUH) Construction Date

4-B 01 Gas Turbine 300 5/28/70 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 3 

EUG 5 Storage Tanks

EU ID# Point ID# EU Name/Model Capacity (Gallons) Installation Date

5-B 01 #1 Light Fuel Oil Tank 2,310,000 1970 

5-B 02 #2 Light Fuel Oil Tank 2,310,000 1972 

5-B 03 Heavy Fuel Oil Tank 12,600,000 1975 

5-B 04 Heavy Fuel Oil Tank 126,000 1975 

5-B 05 Gasoline Tank 1,500 1992 

Stack Parameters

Point Height (ft) Diameter (ft) Flow (ACFM) Temperature (°F) 

2-B-01 178 15 472,075 247 

2-B-02 178 15 472,075 247 

2-B-03 350 18 1,383,374 304 

SECTION IV. EMISSIONS 

Emission estimates reflect continuous operations (8,760 hr/yr) using emission factors as follow: 

3⁄4 Boilers 1 and 2: gas fuel emissions factors from AP-42 (7/98) for boilers larger than 100 

MMBTUH and pre-NSPS: 0.28 lb/MMBTU NOX, 0.084 lb/MMBTU CO, 0.0055 

lb/MMBTU VOC, 0.0076 lb/MMBTU PM10, and 0.0006 lb/MMBTU SO2. Although the 

two units are capable of burning liquid fuels, no modeling of SO2 impacts has been done, so 

usage of liquid fuels will not be discussed or authorized. 

3⁄4 Boiler 3: gas fuel emissions factors from AP-42 (7/98) for boilers larger than 100 MMBTUH 

and pre-NSPS: 0.28 lb/MMBTU NOX, 0.084 lb/MMBTU CO, 0.0055 lb/MMBTU VOC, 

0.0076 lb/MMBTU PM10, and 0.0006 lb/MMBTU SO2; oil fuel emissions from AP-42 (9/98) 

for boilers larger than 100 MMBTUH burning No. 6 fuel oil: 47 lb/Mgal NOX, 5 lb/Mgal 

CO, 0.76 lb/Mgal VOC, 19.88 lb/Mgal PM10, and 260.05 lb/Mgal SO2 (assuming 1.65% 

sulfur in fuel oil; the CEM equation in Part 75 gives a slightly different SO2 emission rate). 

Residual oil has a heating value of 150,000 BTU/gal. Although the facility may burn 

distillate fuel instead of residual, residual oil constitutes the worst-case emissions case. 

3⁄4 Tank emissions: EPA’s “TANKS4.09.” 

3⁄4 Auxiliary boiler: gas fuel emissions factors from AP-42 (7/98) for boilers smaller than 100 

MMBTUH: 0.10 lb/MMBTU NOX, 0.084 lb/MMBTU CO, 0.0055 lb/MMBTU VOC, 0.0076 

lb/MMBTU PM10, and 0.0006 lb/MMBTU SO2. Maximum annual emissions were estimated 

at 2,900 hours. 

3⁄4 Gas turbine: gas fuel emissions factors from AP-42 (4/00): 0.32 lb/MMBTU NOX, 0.082 

lb/MMBTU CO, 0.0021 lb/MMBTU VOC, 0.0066 lb/MMBTU PM10, and 0.0006 

lb/MMBTU SO2. 500 hours per year operations were used for annual emissions. 

3⁄4 HAP emissions from gas burning: factors in AP-42 (7/00) Section 1.4. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 4 

SCENARIO I: GAS FUEL 

 PM10 SO2 NOX VOC CO 

EU lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY 

2-B-01 41.65 182.42 3.29 14.40 1,534.4 6,720.7 30.14 132.01 460.32 2016.20 

2-B-02 41.65 182.42 3.29 14.40 1,534.4 6,720.7 30.14 132.01 460.32 2016.20 

2-B-03 41.77 182.95 3.30 14.44 1,538.9 6,740.3 30.23 132.40 461.66 2022.09 

4-B-01 1.98 0.50 0.18 0.05 96.00 24.00 0.63 0.16 24.60 6.15 

3-B-02 0.25 0.37 0.02 0.03 3.35 4.85 0.18 0.27 2.81 4.08 

5-B-01 -- -- -- -- -- -- 0.12 0.53 -- -- 

5-B-02 -- -- -- -- -- -- 0.12 0.53 -- -- 

5-B-03 -- -- -- -- -- -- 0.01 0.01 -- -- 

5-B-04 -- -- -- -- -- -- 0.01 0.01 -- -- 

Totals 127.30 548.66 10.08 43.32 4,707.1 20,211 91.58 397.93 1,409.7 6,064.7 

SCENARIO II: OIL FUEL (BOILER 3) 

 PM10 SO2 NOX VOC CO 

EU lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY lb/hr TPY 

2-B-01 41.65 182.42 3.29 14.40 1,534.4 6,720.7 30.14 132.01 460.32 2,016.20

2-B-02 41.65 182.42 3.29 14.40 1,534.4 6,720.7 30.14 132.01 460.32 2,016.20

2-B-03 487.94 2,137.186,381.64 27,951.6 1,153.38 5,051.80 18.65 81.69 122.70 537.43 

4-B-01 1.98 0.50 0.18 0.05 96.00 24.00 0.63 0.16 24.60 6.15 

3-B-02 0.25 0.37 0.02 0.03 3.35 4.85 0.18 0.27 2.81 4.08 

5-B-01 -- -- -- -- -- -- 0.12 0.53 -- -- 

5-B-02 -- -- -- -- -- -- 0.12 0.53 -- -- 

5-B-03 -- -- -- -- -- -- 0.01 0.01 -- -- 

5-B-04 -- -- -- -- -- -- 0.01 0.01 -- -- 

Totals 573.47 2,502.9 6,388.4 27,980 4,321.5 18,522 80.00 347.22 1,070.8 4,580.1 

FACILITY WIDE HAP EMISSIONS 

 Emissions 

Pollutant lb/hr TPY 

Benzene 0.035 0.151 

Dichlorobenzene 0.020 0.086 

Formaldehyde 1.234 5.405 

Hexane 29.621 129.739 

Toluene 0.056 0.245 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 5 

SECTION V. BART ANALYSIS 

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

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

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

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

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

analysis of any existing stationary facility that might cause or contribute to impairment of 

visibility in a Class I Area. 

BART-eligible sources include the following sources: 

(1) Sources that have the PTE 250 TPY or more of a visibility-impairing air pollutant; 

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

(3) Sources 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 MMBTUH heat input and fossil-fuel boilers of more than 250 MMBTUH heat input). 

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

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

to August 7, 1962. Based on a review of existing emissions data, all three units have the 

potential to emit more than 250 TPY of NOX, a visibility impairing pollutant. Therefore, 

Seminole Units 1, 2, and 3 meet the definition of a BART-eligible source. 

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

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

EPA has determined that an individual source will be considered to “contribute to visibility 

impairment” if emissions from the source result in a change in visibility, measured as a change in 

deciviews (Δ-dv), that is greater than or equal to 0.5 dv in a Class I Area. Visibility impact 

modeling previously conducted by OG&E determined that the maximum predicted visibility 

impacts from Seminole Units 1, 2, and 3 exceeded the 0.5 Δ-dv threshold at the Wichita 

Mountains Class I Area. Therefore, Seminole Units 1, 2, and 3 were determined to be BART 

applicable sources, subject to the BART determination requirements. 

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

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

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

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

process described in Appendix Y includes the following steps: 

Step 1. Identify All Available Retrofit Control Technologies. 

Step 2. Eliminate Technically Infeasible Options. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

Step 4. Evaluate Impacts and Document the Results. 

Step 5. Evaluate Visibility Impacts. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 6 

This review summarizes the BART determination for Seminole Units 1, 2, and 3. Because the 

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

Y guidelines were used in preparing the BART determination. Based on an evaluation of 

potentially feasible retrofit control technologies, including an assessment of the costs and 

visibility improvements associated therewith, OG&E is proposing the following BART control 

technologies and emission rates. 

Seminole Units 1, 2, and 3 Proposed BART Permit Limits and Control Technologies 

Unit Proposed NOX Emission Limit Proposed BART Technology 

1 0.203 lb/MMBTU (30-day average) Combustion Controls (LNB/OFA+FGR) 

2 0.212 lb/MMBTU (30-day average) Combustion Controls (LNB/OFA+FGR) 

3 0.164 lb/MMBTU (30-day average) Combustion Controls (LNB/OFA+FGR) 

Seminole Units 1 and 2 became operational in 1968, and Unit 3 became operational in 1970. All 

three units are Babcock & Wilcox wall-fired boilers, and all three units fire natural gas as their 

primary fuel. Number 2 fuel oil has been used as a secondary fuel on occasion in Unit 3 for 

limited durations. Because the units primarily fire natural gas there are no sulfur dioxide (SO2) 

or particulate matter (PM) emission control systems. Seminole Unit 3 was designed with flue 

gas recirculation (FGR) for nitrogen oxide (NOX) control. 

Class I Areas Near the Seminole Station

• Wichita Mountains Wildlife Refuge (WMWR - Oklahoma) 178 km 

• Caney Creek Wilderness Area (CCWA - Arkansas) 242 km 

• Upper Buffalo Wilderness Area (UBWA - Arkansas) 310 km 

• Hercules-Glades Wilderness Area (HGWA - Missouri) 387 km 

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

maximum 98th percentile Δ-dv visibility impact from the Seminole Generating Station. 

Although visibility impact modeling at existing actual emissions did not exceed the 0.5 Δ-dv 

threshold, modeling at the maximum 24-hour pound per hour (lb/hr) emission rate from all three 

units on a continuous basis (maximum baseline emissions) exceeded the 0.5 Δ-dv threshold at 

the Wichita Mountains Class I Area. Therefore, the facility was determined to be a BARTapplicable source subject to the BART determination requirements. 

BART Requirements 

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

emission control technology available and associated emission reductions achievable. The 

BART analysis must take into consideration: (1) the technology available; (2) the costs of 

compliance; (3) the energy and non-air-quality environmental impacts of compliance; (4) any 

pollution control equipment in use at the source; (5) the remaining useful life of the source; and 

(6) the degree of improvement in visibility which may reasonably be anticipated to result from 

the use of such technology. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 7 

Step 1. Identify all available retrofit control technologies. 

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

potential for application to the emissions unit and the regulated pollutant under evaluation. Step 

1 of the BART determination requires applicants to identify potentially applicable retrofit control 

technologies that represent the full range of demonstrated alternatives. Potentially applicable 

retrofit control alternatives can include pollution prevention strategies, the use of add-on 

controls, or a combination of control strategies. Control technologies required under the new 

source review (NSR) program as best available control technology (BACT) or lowest achievable 

emission rate (LAER) are available for BART purposes and must be included as potential 

control alternatives. However, EPA does not consider BART as a requirement to redesign the 

source when considering available control alternatives. 

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

station, the following information sources were consulted: 

• EPA's RACT/BACT/LAER Clearinghouse (RBLC) Database; 

• New & Emerging Environmental Technologies (NEET) Database; 

• EPA’s New Source Review bulletin board; 

• Information from control technology vendors and engineering/environmental consultants; 

• Federal and State new source review permits and BACT determinations for coal-fired 

power plants; 

• Recently submitted Federal and State new source review permit applications submitted for 

coal-fired generating projects; and 

• Technical journals, reports, newsletters and air pollution control seminars. 

Step 2. Eliminate Technically Infeasible Options. 

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

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

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

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

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

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

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

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

infeasible for the intended application are eliminated from further review. 

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. 

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

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

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

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

achieves the lowest emissions level. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 8 

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: 

(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 cost 

effectiveness of each control technology, on a dollar per ton of pollutant removed basis. Annual 

emissions using a particular control device are subtracted from baseline emissions to calculate 

tons of pollutant controlled per year. Annual costs are calculated by adding annual operation and 

maintenance costs to the annualized capital cost of an option. Cost effectiveness ($/ton) of an 

option is simply the annual cost ($/yr) divided by the annual pollution controlled (ton/yr). In 

addition to the cost effectiveness relative to the base case, the incremental cost effectiveness to 

go from one level of control to the next more stringent level of control may also be calculated to 

evaluate the cost effectiveness of the more stringent control. 

Energy Impact Analysis

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

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

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

increases in energy consumption resulting from increased heat rate may be shown as total BTU 

or fuel consumed per year, or as BTU per ton of pollutant controlled. Second, the installation of 

a particular control option may reduce the output and/or reliability of equipment. This reduction 

would result in decreased electricity available to the power grid and/or increased fuel 

consumption due to use of less efficient electrical and steam generation methods. 

Non-Air Quality Environmental Impact Analysis

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

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

include solid or hazardous waste generation, discharges of polluted water from a control device, 

increased water consumption, and land use impacts from waste disposal. Impact analyses 

conducted in step 4 should take into consideration the remaining useful life of the source. For 

example, the remaining useful life of the source may affect the cost analysis (specifically, the 

annualized costs of retrofit controls). 

Step 5. Evaluate Visibility Impacts. 

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

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

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

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

Modeling should be conducted for SO2, NOX, and direct PM emissions (PM2.5 and/or PM10). 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 9 

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

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

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

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

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

feasible will not be evaluated for visibility impacts. The final regulation also states that sources 

that elect to apply the most stringent controls available need not conduct an air quality modeling 

analysis for the purpose of determining its visibility impacts. 

SEMINOLE UNITS 1, 2, AND 3 BART DETERMINATION 

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

above) was used to identify BART controls for Seminole Units 1, 2, and 3. Because the 

applicant has proposed to restrict fuel usage for all three boilers to natural gas, SO2 and PM10

emissions are minimal. Also, there are no SO2 or PM10 post-combustion control technologies 

with a practical application to a natural gas fired boiler. Therefore, the Appendix Y 

methodology was used to evaluate BART control technologies for NOX emissions only. 

Existing Operating Parameters for Seminole Units 1, 2, and 3 

Parameter Unit 1 Unit 2 Unit 3 

Configuration Wall-Fired Boiler Wall-Fired Boiler Wall-Fired Boiler 

Gross Output (nominal) 567 MW 567 MW 567 MW 

Maximum Input (MMBTUH) 5,480 5,480 5,496 

Primary Fuel Natural Gas Natural Gas Natural Gas 

Existing NOX Controls None None FGR 

Existing SO2 Controls None None None 

Existing PM10 Controls None None None 

Baseline emissions from Seminole Units 1, 2, and 3 were developed based on an evaluation of 

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

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

the modeling analysis to determine visibility impairment impacts should reflect steady-state 

operating conditions during periods of high capacity utilization. Therefore, baseline emissions 

(lb/hr) represent the highest 24-hour block emissions reported during the baseline period. 

Baseline emission rates (lb/MMBTU) were calculated by dividing the maximum hourly mass 

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

Baseline Actual Emissions for Seminole Units 1, 2, and 3 

Unit 1 Unit 2 Unit 3 

Pollutant lb/hr lb/MMBTU lb/hr lb/MMBTU lb/hr lb/MMBTU 

NOX 1,859 0.339 1,940 0.354 1,204 0.219 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 10 

Presumptive BART Emission Rates

In the final Regional Haze Rule, EPA established presumptive BART emission limits for NOX

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

the presence or absence of pre-existing controls. The presumptive limits apply to EGU at power 

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

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

Seminole Units 1, 2, and 3 are natural gas-fired units, the presumptive BART emission limits are 

not applicable. 

In support of the Regional Haze Rule, EPA also prepared a cost-effectiveness analysis for 

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

a number of oil- and gas-fired units could make significant cost-effective reductions in NOX

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

use of combustion controls did not appear to be cost effective. As a result, EPA determined that 

it would be inappropriate to establish a general presumption regarding likely BART limits for 

oil- and natural gas-fired units. 

BART DETERMINATION FOR NITROGEN OXIDES (NOX) 

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

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

designated as “thermal” NOX and “fuel” NOX. The principal mechanism of NOX formation in 

natural gas combustion is thermal NOX. Thermal NOX formation is the result of oxidation of 

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

combustion zone. Fuel NOX is formed by the oxidation of nitrogen in the fuel. Due to the 

characteristically low fuel nitrogen content of natural gas, NOX formation through the fuel NOX

mechanism is insignificant. 

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

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

combustion zone. As these three factors increase, NOX emission levels increase. Advanced 

burner designs can regulate the distribution and mixing of the fuel and air to reduce flame 

temperatures and residence times at peak temperatures to reduce NOX formation. 

Step 1: Identify Potentially Feasible NOX Control Options 

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

available information. NOX control technologies with potential application to Seminole Units 1, 

2, and 3 are listed below. 

List of Potential NOX Control Options

1) Combustion Controls 

i) Low NOX Burners & Overfire Air (LNB/OFA) 

ii) FGR 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 11 

2) Post-Combustion Controls 

i) Selective Non-Catalytic Reduction (SNCR) 

ii) Selective Catalytic Reduction (SCR) 

3) Innovative Control Technologies 

i) Rotating Overfire Air (ROFA) 

ii) ROFA + SNCR (Rotamix) 

iii) Pahlman Process 

iv) Wet NOX Scrubbing 

Step 2: Technical Feasibility of Potential Control Options 

NOX control technologies can be divided into two general categories: combustion controls and 

post combustion controls. Combustion controls reduce the amount of NOX that is generated in 

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

feasibility of each potentially applicable NOX control technology, with respect to natural-gas 

fired boilers, is evaluated below. 

Combustion Controls

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

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

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

applicable to Seminole boilers are described below. 

Low NOX Burners and Overfire Air (LNB/OFA)

LNB limit NOX formation by controlling both the stoichiometric and temperature profiles of the 

combustion flame in each burner flame envelope. This control is achieved with design features 

that regulate the aerodynamic distribution and mixing of the fuel and air, yielding reduced 

oxygen (O2) in the primary combustion zone, reduced flame temperature and reduced residence 

time at peak combustion temperatures. The combination of these techniques produces lower 

NOX emissions during the combustion process. 

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

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

through ports located above the top burner level. Staging of the combustion air reduces NOX

formation by two mechanisms. First, staged combustion results in a cooler flame, and second 

the staged combustion results in less oxygen reacting with fuel molecules. The degree of staging 

is limited by operational problems since the staged combustion results in incomplete combustion 

conditions and a longer flame. 

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

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

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

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

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

concentration and boiler load, controlled emissions would vary between approximately 135 to 

250 ppmvd @ 3% O2 (0.16 to 0.30 lb/MMBTU). 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 12 

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

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

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

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

seasonally, and that the boilers typically operate at approximately 40% load. 

Although LNB/OFA controls are a technically feasible retrofit technology on natural gas-fired 

boilers, combustion controls on gas-fired boilers may not be as effective under all boiler 

operating conditions, especially during load changes and at low and high operating loads. 

Controlling the stoichiometric and temperature profiles of the combustion flame, and 

maintaining the air/fuel mixing needed for NOX control, becomes more difficult under these 

operating scenarios. Baseline NOX emission rates are lowest at heat inputs in the range of 

approximately 1,500 to 2,100 MMBTUH. NOX emissions tend to increase at lower and higher 

heat inputs. Finally, the mechanisms used to reduce NOX formation (e.g., cooler flame and 

reduced O2 availability) also tend to increase the formation and emission of CO and VOC. 

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

while keeping CO and VOC emission rates within acceptable limits. 

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

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

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

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

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

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

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

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

• Seminole Unit 3: 0.164 lb/MMBTU (~ 135 ppmvd @ 3% O2) 

Flue Gas Recirculation (FGR)

FGR controls NOX by recycling a portion of the flue gas back into the primary combustion zone. 

The recycled air lowers NOX emissions by two mechanisms: (1) the recycled gas, consisting of 

products which are inert during combustion, lowers the combustion temperatures; and (2) the 

recycled gas will reduce the oxygen content in the primary flame zone. The amount of 

recirculation is based on flame stability. Seminole Unit 3 is currently designed with FGR 

control. 

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

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

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

should be controlled such that the windbox oxygen content is not lower than approximately 17%. 

Lower oxygen content would reduce the oxygen available for combustion and could promote the 

formation of excess CO and VOC emissions. This method of FGR is currently in service on 

Seminole Unit 3, and would be a technically feasible retrofit option for Units 1 and 2. 

Comment [A1]: Found on page 12 of 

BART Determination and appears to be 

part of the example that has been 

removed. This sentence and following 

sentence appear to state similar things. 

Prefer to strike this statement since it 

could also be construed as part of the 

example language that was removed. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 13 

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

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

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

With this design, the limitation resides in the construction of the FD fan. Recycled flue gas 

could increase total flow through the FD fan by about 20%. Therefore, the FD fan typically 

requires replacement. In addition, as the percentage of flue gas recirculated back through the FD 

fans increases, so does the overall temperature of the gas in the FD fan. In general, the gas 

temperature in the FD fan should not be greater than approximately 175°F. Higher temperatures 

than 175°F would result in higher than normal maintenance on the FD fan and could lead to 

premature failure of the fan. Both FGR designs are technically feasible retrofit options for gasfired boilers. Either system would be expected to achieve an additional 15% reduction 

(compared to LNB/OFA only), or approximately 40% overall reduction from baseline. Because 

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

preferred retrofit design for Seminole Units 1 and 2. 

Assuming an overall NOX reduction of 40% from baseline, emissions from Seminole Units 1, 2, 

and 3 with LNB/OFA and FGR would average: 

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

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

• Seminole Unit 3: 0.164 lb/MMBTU (~ 135 ppmvd @ 3% O2) 

Post-Combustion Controls

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

are discussed below. 

Selective Non-Catalytic Reduction

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

(CO(NH2)2) at high flue gas temperatures (approximately 1600°F - 1900°F). The NH3 or urea 

reacts with NOX in the flue gas to produce N2 and water as shown in the equations below. 

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

2NH3 + 2NO + 1⁄2O2 → 2N2 + 3H2O 

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

and the quantity of NH3 or urea that will pass through the SNCR unreacted (referred to as NH3

slip). In general, SNCR reactions are effective in the range of 1,700 °F. At temperatures below 

the desired operating range, the NOX reduction reactions diminish and unreacted NH3 emissions 

increase. Above the desired temperature range, NH3 is oxidized to NOX resulting in low NOX

reduction efficiencies. 

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

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

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

factors make it difficult to achieve good mixing of reagent and flue gas, delivery of reagent in 

the proper temperature window, and sufficient residence time of the reagent and flue gas in that 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 14 

temperature window. In addition to temperature and mixing, several other factors influence the 

performance of an SNCR system, including residence time, reagent-to-NOX ratio, and fuel sulfur 

content. 

SNCR control systems have been installed as retrofit NOX control systems on small and medium 

sized coal- and gas-fired boilers; however, SNCR has not been used on large boilers (i.e., boilers 

larger than approximately 300 MW). Large boilers, including Seminole Units 1, 2, and 3, would 

present several design problems making it difficult to ensure that the reagent (urea or NH3) 

would be injected at the optimum fuel gas temperature and that there would be adequate mixing 

and residence time. 

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

NH3 injection points capable of achieving adequate mixing within the required temperature zone. 

Higher NH3 injection rates would be needed to achieve adequate mixing. This design would 

tend to result in relatively high levels of unreacted NH3 in the flue gas (NH3 slip). Furthermore, 

because the Seminole boilers are typically used as peaking units, boiler load is continually 

changing. Boiler load changes affect flue gas flow rates and temperatures, which would make it 

particularly difficult to inject the needed quantity of reactant at the requisite temperature. 

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

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

difficulties with applying SNCR to large boilers (including the physical size of the boiler, and 

adequate reactant/flue gas mixing within the required temperature range). SNCR control would 

even be more difficult to design for boilers operating as peaking units due to the continuous 

changes in flue gas flow rates and temperatures. Assuming that SNCR could be installed on 

Seminole Units 1, 2, and 3, NOX control effectiveness would be marginal, and, depending on 

boiler exit temperatures, could actually result in additional NOX formation. 

Because SNCR has not been designed for, or demonstrated on, large boilers, and because there 

remains several currently unresolved technical difficulties with applying SNCR to a large gasfired boiler (especially boilers that typically operate as peaking units), it was determined that 

SNCR is not an available NOX retrofit control technology for Seminole Units 1, 2, and 3, and 

SNCR will not be evaluated further in the BART determination. 

Selective Catalytic Reduction

Selective Catalytic Reduction (SCR) involves injecting NH3 into boiler flue gas in the presence 

of a catalyst to reduce NOX to N2 and water. Anhydrous NH3 injection systems may be used, or 

NH3 may be generated on-site from a urea feedstock. The overall SCR reactions are: 

4NH3 + 4NO + O2 → 4N2 + 6H2O 

8NH3 + 4NO2 + 2O2 → 6N2 + 12H2O 

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

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

the amount of NH3 slip that is acceptable. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 15 

The optimal temperature range depends on the type of catalyst used, but is typically between 560 

°F and 750 °F to maximize NOX reduction efficiency and minimize ammonium sulfate 

formation. This temperature range typically occurs between the economizer and air heater in a 

large utility boiler. Above the optimum temperature, the catalyst will sinter and thus deactivate 

rapidly. Another factor affecting SCR performance is the condition of the catalyst material. As 

the catalyst degrades over time or is damaged, NOX removal decreases. 

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

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

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

average NOX emission rates in the range of approximately 0.02 to 0.05 lb/MMBTU. Several 

design and operating variables will influence the performance of the SCR system, including the 

volume, age and surface area of the catalyst (e.g., catalyst layers), uncontrolled NOX emission 

rate, flue gas temperature, and catalyst activity. Catalyst that has been in service for a period of 

time will have decreased performance because of normal deactivation and deterioration. 

Catalyst that is no longer effective due to plugging, blinding or deactivation must be replaced. In 

addition, flue gas temperature is an important component of SCR effectiveness. SCR control 

systems on gas-fired units that operate as peaking units would require time to adjust to 

continuous changes in boiler load, flue gas flow rate, and flue gas temperature. 

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

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

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

anticipated that SCR could achieve a controlled NOX emission rate of 0.04 lb/MMBTU (30-day 

rolling average) on Seminole Units 1, 2, and 3. An emission rate of 0.04 lb/MMBTU is 

equivalent to an average NOX concentration in the flue gas of approximately 33 ppmvd @ 3% 

O2. 

Innovative NOX Control Technologies

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

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

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

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

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

wet NOX scrubbing systems. 

Rotating Opposed Fired Air (ROFA) and Rotomix

ROFA is a boosted OFA system that includes a patented rotation process which includes 

asymmetrically placed air nozzles. Like other OFA systems, ROFA stages the primary 

combustion zone to burn overall rich, with excess air added higher in the furnace to burn out 

products of incomplete combustion. The ROFA nozzles are designed to increase turbulence 

within the furnace. Increased turbulence should prevent the formation of stratified laminar flow, 

enable the furnace volume to be used more effectively for the combustion process, and reduce 

the maximum temperatures of the combustion zone. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 16 

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

control system instrumentation. A ROFA system was installed on an existing 80-MW (gross) 

coal-fired utility boiler in the summer of 2002. Test results showed that the ROFA system 

reduced NOX emissions from baseline levels 0.6 lb/MMBTU to approximately 0.2 lb/MMBTU 

at full load. At lower loads (approximately 40 MW), the ROFA system reduced NOX emissions 

from 0.6 lb/MMBTU to 0.3 lb/MMBTU. The turbulent air injection and mixing provided by 

ROFA allows for the effective mixing of chemical reagents with the combustion products in the 

furnace. MobotecUSA’s Rotamix® system combines the ROFA system with urea injection into 

the flue gas (SNCR) to reduce NOX emissions. The turbulent mixing created by the ROFA 

system is designed to improve distribution of the NH3/urea reagent and may reduce the NH3/urea 

injection required by the SNCR control system. A Rotamix control system was installed on the 

same 80-MW unit in the spring of 2004. 

ROFA and Rotamix® systems have been demonstrated on smaller boilers but have not been 

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

systems are a technically feasible retrofit control technology and the ROFA design could also be 

applied on Seminole Units 1, 2, and 3. However, there is no technical basis to conclude that the 

ROFA design would provide additional NOX reduction beyond that achieved with other OFA 

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

but will be included in the overall evaluation of combustion controls (e.g., LNB/OFA). 

The Rotamix system is a SNCR control system coupled with the ROFA rotating injection nozzle 

design. The technical limitations previously discussed, including the physical size of the boiler, 

inadequate NH3/NOX contact, and flue gas temperatures, would apply equally to the Rotamix 

control system. There is no technical basis to conclude that the Rotamix design addresses these 

unresolved technical difficulties. Therefore, like other SNCR control systems, the Rotamix 

system is determined not to be available for Seminole Units 1, 2, and 3 and will not be evaluated 

further in the BART determination. 

Pahlman Multi-Pollutant Control Process

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

a sorbent composed of oxides of manganese (the PahlmaniteTM sorbent) to remove NOX and SO2

from the flue gas. Manganese compounds are soluble in water in the +2 valence state but not in 

the +4 state. This property is used in the Pahlman sorbent capture and regeneration procedure, in 

that Pahlmanite sorbent is reduced from the insoluble +4 state to the +2 state during the 

formation of manganese nitrates and sulfates. These species are water-soluble, allowing the 

sulfate, nitrate and Mn+2 ions to be dissociated and the Mn+2 to be oxidized again to Mn+4 and 

regenerated. In general, the liquid metal oxide Pahlmanite sorbent is injected as the flue gas 

enters a spray dryer. The sorbent dries as it passes through the spray dryer and is collected 

downstream at the fabric filter baghouse. NOX and SO2 will react with the sorbent to form 

manganese sulfates and nitrates as the flue gas passes through the filter cake. 

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

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

can be purified and may be converted into granular fertilizer by-products. To date, bench- and 

pilot-scale testing have been conducted to evaluate the technology on utility-sized boilers. The 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 17 

New & Emerging Environmental Technologies (NEET) Database identifies the development 

status of the Pahlman Process as full-scale development and testing. The process is an emerging 

multi-pollutant control, and there is limited information available to evaluate its technical 

feasibility and long-term effectiveness on a large natural gas-fired boiler. It is likely that OG&E 

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

feasibility and long-term effectiveness of the control system on Seminole Units 1, 2, and 3. 

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

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

Pahlman Process is not considered an available NOX control system for Seminole Units 1, 2, and 

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

Wet NOX Scrubbing Systems

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

units (FCCU) at petroleum refineries. An example of a wet scrubbing system is Balco 

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

injected into the flue gas stream to oxidize NO and NO2 to N2O5. This highly oxidized species 

of NOX is very soluble and rapidly reacts with water to form nitric acid. The conversion of NOX

to nitric acid occurs as the N2O5 contacts liquid sprays in the scrubber. 

Wet scrubbing systems have been installed at chemical processing plants and smaller coal-fired 

boilers. The NEET Database classifies wet scrubbing systems as commercially established for 

petroleum refining and oil/natural gas production. However the technology has not been 

demonstrated on large utility boilers and it is likely that OG&E would incur substantial 

engineering and testing to evaluate the scale-up potential and long-term effectiveness of the 

system. Therefore, at this time wet NOX scrubbing systems are not considered available or 

technically feasible retrofit control systems for Seminole Units 1, 2, and 3 and will not be further 

evaluated in this BART Analysis. 

Technical Feasibility of Potential NOX Control Technologies 

 In Service On 

Control Technology NOX Control Efficiency

Gas-Fired 

Boilers?

Other 

Sources?

Technically 

Feasible?

LNB/OFA 25% reduction YesX Yes Yes 

LNB/OFA+FGR 40% reduction Yes X Yes Yes1

SNCR NA Yes X No No2

SCR 0.04 lb/MMBTU Yes X Yes Yes3

ROFA NA Yes X Yes Yes4

Rotamix (SNCR) NA Yes X Yes Yes5No5

Pahlman Process NA XNo No No6

Wet NOX Scrubbing NA XNo Yes Yes7No7

1 Seminole Unit 3 is currently equipped with FGR control 

2

 SNCR has been applied to smaller coal- and gas-fired boilers. Not a technically feasible nor available retrofit 

technology for Seminole Units 1, 2, and 3. SNCR has been used as a retrofit technology on small and medium 

sized (<300 MW) boilers, but has not been demonstrated, and would present significant engineering and 

operational challenges for a large utility boiler. There are several currently unresolved technical difficulties 

Comment [A2]: This table is a copy of 

Table 3-2 on pages 21 & 22 of the BART 

Determination. Appears to be a cut & 

paste issue.
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 18 

associated with applying SNCR on a large gas-fired boiler. Furthermore, SNCR may not be effective on boilers 

that typically operate as peaking units. 

3

 SCR is a technically feasible retrofit technology for Seminole Units 1, 2, and 3. The effectiveness of the SCR 

system will depend on site-specific considerations including the NH3 injection rate, site-specific flue gas 

characteristics, NH3 slip, and frequency of catalyst changes. 

4

 ROFA control systems have been demonstrated on small coal-fired boilers, and would be a technically feasible 

retrofit control technology. However, there is no technical basis to conclude that ROFA will provide additional 

NOX control beyond that achievable with other OFA control systems on Seminole Units 1, 2, and 3. Therefore, 

ROFA will be evaluated along with other OFA control systems. 5

 Rotamix control systems have been demonstrated on small coal-fired boilers. However, there are several 

currently unresolved technical difficulties associated with applying SNCR-type systems on a large gas-fired 

boiler. Therefore, Rotamix is not considered an available retrofit control technology for Seminole Units 1, 2 & 

3. 

6

 Bench- and pilot-scale testing has been conducted on coal-fired boilers, however, there is limited data available 

assessing the technical feasibility of this system on large natural gas-fired boilers. This technology is not 

considered an available NOX control technology for Seminole Units 1, 2 & 3. 

7

 The system has been used on refinery fluid catalytic cracking units and small coal-fired boilers, but has not 

been used on large natural gas-fired boilers. Wet NOX scrubbing systems are not available or technically 

feasible for Seminole Units 1, 2, and 3. 

Step 3: Rank the Technically Feasible NOX Control Options by Effectiveness 

Technically Feasible NOX Control Technologies 

Seminole Unit 1 Seminole Unit 2 Seminole Unit 3 

 NOX Emission Rate NOX Emission Rate NOX Emission Rate 

Control Technology (lb/MMBTU) (lb/MMBTU) (lb/MMBTU)

SCR 0.040 0.040 0.040 

LNB/OFA + FGR 0.203 0.212 0.164 

LNB/OFA 0.254 0.266 NA1

Baseline2 0.339 0.354 0.219 

1

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

not an available alternative for this unit. 

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 

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

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

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

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

the facility’s permitted emission limits, which are averaged over a longer period of time. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 19 

Step 4: Evaluate the Technically Feasible NOX Control Technologies 

NOX Control Technologies – Economic Evaluation

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

to be technically feasible for Seminole Units 1, 2, and 3 includes combustion controls 

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

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

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

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

deactivation rate. Furthermore, SCR control may not be as effective on boilers that operate as 

peaking units, as NOX reduction in an SCR is a function of flue gas temperature. Based on 

emission rates achieved in practice at similar sources, and including a reasonable margin to 

account for normal system fluctuations and the fact that the Seminole boilers are operated as 

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

controlled NOX emission rate of 0.04 lb/MMBTU (30-day average). The second most effective 

NOX retrofit control system that is considered technically feasible for Seminole Units 1, 2, and 3 

includes combustion controls (LNB/OFA+FGR). The combination of LNB/OFA+FGR is 

expected to achieve an average control efficiency of approximately 40% from baseline on gasfired units that operate at varying loads and are typically operated as peaking units. The third 

most effective NOX retrofit control system considered technically feasible is the combination of 

LNB/OFA without FGR. This combination of controls is expected to achieve an average control 

efficiency of approximately 25% from baseline. 

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

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

guidelines Part III of Appendix Y, emission estimates used in the modeling analysis to determine 

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

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

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

heat input to the boiler at full load. 

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

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

using a more representative annual capacity factor. From 2002 through 2005, annual capacities 

for each unit were typically in the range of approximately 25% to 30%. Evaluating economic 

impacts of potential retrofit control technologies using a capacity of 100% would not be 

representative of actual operations. Using a more representative capacity factor would more 

accurately reflect actual economic impacts. For this evaluation, annual operating costs and 

annual emission reductions were calculated assuming an annual capacity factor of 50%. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 20 

Seminole Units 1, 2, and 3 Annual Capacity Factor Estimates 

Unit Heat Input 2002-2005 Potential Heat Input at 

100% Capacity 

Factor1

Annual Capacity Factor 

 (MMBTU) (MMBTU) (%) 

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

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

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

1

Potential heat input was calculated based on full load boiler heat inputs of 5,480 mmBtu/hr (Units 1 & 2) and 5,496 

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

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

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

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

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

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

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

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

O&M costs include the cost of consumables, including reagent (e.g., NH3), byproduct 

management, water consumption, and auxiliary power requirements. Auxiliary power 

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

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

pumps, reagent handling, and by-product handling. 

Summarized below are the expected controlled NOX emission rates, and annual NOX mass 

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

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

annual capacity for each unit based on historical capacity factors. The capital costs and annual 

operating costs associated with building and operating each control system (based on 50% 

capacity factor) is also included below. Finally, the average annual cost effectiveness and 

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

cost estimates used in this BART determination was included in application. 

Seminole Generating Station - Annual NOX Emissions 

 NOX Emission Rate 

(lb/MMBTU)

Maximum Annual 

NOX Emissions (TPY)1

Annual Reduction 

(TPY from baseline)

Control 

Technology 

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

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

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

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

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

1

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

5,496 MMBTUH (Unit 3). Annual emissions were calculated assuming 4,380 hours/year per boiler (50% 

capacity factor). 

Formatted: Superscript

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Formatted: Font: 10 pt
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 21 

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

 Total Capital 

Investment3

Total Capital 

Investment 

Annual Capital 

Recovery Cost 

Annual 

Operating Costs 

Total Annual 

Costs 

Control Technology ($) ($/kW-net) ($/year) ($/year) ($/year) 

LNB/OFA+SCR2 $104,230,20

0 

$221.8 $8,943,000 $8,175,600 $17,118,600 

LNB/OFA+FGR2 $16,977,200 $36.1 $1,456,700 $1,190,900 $2,647,600 

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

1

 Capital costs are similar for each unit, however, there are no FGR retrofit costs associated with Unit 3. A 

summary of the capital cost estimates for each unit is provided in Attachment A of the analysis. 2

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

for the FGR option include the costs of LNB/OFA plus FGR. 

3

 Capital costs include the cost of major components and indirect installation costs such as foundations, 

mechanical erection, electrical, piping, and insulation for the control system. 

Seminole Generating Station - NOX Emission Control System Cost Effectiveness (total) 

Total Annual Cost1 Annual Emission 

Reduction 

Average Cost 

Effectiveness 

Incremental Cost 

Effectiveness2

Control Technology Total Annual 

Cost1($/year)

(TPY) ($/Ton) ($/Ton)

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

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

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

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

Unit 3 has a slightly higher heat input. 

2

 Incremental cost effectiveness of the FGR system is compared to costs/emissions associated with LNB/OFA 

controls. Similarly, incremental cost effectiveness of the SCR system is compared to costs/emissions associated 

with LNB/OFA+FGR controls. 

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

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

$5,387/ton for combustion controls plus SCR. FGR controls on Seminole Units 1 & 2 reduce 

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

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

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

the annualized cost of SCR control systems. Significant annual operating costs include the 

energy cost associated with the additional pressure drop across the SCR and costs associated 

with replacing the SCR catalyst as it degrades over time. Based on projected actual emissions, 

SCR could reduce overall NOX emissions from Seminole Units 1, 2, and 3 by ~ approximately

5,513 TPY (compared to combustion controls and FGR); however, the incremental cost 

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

Formatted: Complex Script Font:

Times New Roman, 10 pt, Not Bold,

Not Superscript/ Subscript

Comment [A3]: The cost 

effectiveness for Seminole’s NOx control 

is not correct and will need to be 

reevaluated similar to the 

Sooner/Muskogee SO2 emission control 

cost effectiveness done earlier. OG&E 

will provided the updated costs once 

available. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 22 

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

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

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

developed the limits based on control strategies considered to be generally cost-effective for 

such units. For all types of boilers, other than cyclone units, the presumptive limits were based 

on the use of combustion control technologies. EPA estimated that the “costs of such controls in 

most cases range from just over $100 to $1,000 per ton” (see, 70 FR 39135). 

The average cost effectiveness of combustion controls (LNB/OFA and LNB/OFA+FGR) on 

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

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

presumptive levels on large coal-fired EGU was estimated to be in the range of $100 to 

$1,000/ton. Combustion controls on Seminole Units 1, 2, and 3 have cost effectiveness values of 

$1,534 to $1,675/ton for LNB/OFA and FGR controls, respectively. Although the cost 

effectiveness of combustion controls on Seminole Units 1, 2, and 3 are somewhat higher than 

EPA’s presumptive BART cost effectiveness evaluation, the costs are not so great as to exclude 

combustion controls as BART. 

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

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

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

Generating Station. Therefore, SCR should not be selected as BART based on lack of cost 

effectiveness. Although SCR does not appear to be cost effective, it will be included in the 

evaluation of the remaining factors to assure that the BART determination considers all relevant 

information. 

NOX Control Technologies – Environmental Impacts

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

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

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

maintaining CO and VOC formation at an acceptable level. Other than the NOX/CO-VOC tradeoff, there are no environmental issues associated with using combustion controls to reduce NOX

emissions. 

Operation of an SCR system has certain collateral environmental consequences. In order to 

maintain low NOX emissions, some excess NH3 will pass through the SCR. NH3 slip will 

increase with lower NOX emission limits, and will also tend to increase as the catalyst becomes 

deactivated. NH3 slip from an SCR designed to achieve a controlled NOX emission rate of 0.04 

lb/MMBTU (30-day average) on a gas-fired boiler would be in the range of 2-5 ppm during the 

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

NH3 slip can increase; however, the NH3 slip rate is not expected to exceed 7-10 ppm under 

normal operating conditions. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 23 

The storage of NH3 on-site increases the risks associated with an accidental NH3 release. 

Depending on the type, concentration, and quantity of NH3 used, NH3 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 NH3 handling is to design the ammonia handling system as a urea-to-NH3

conversion system. Urea ((NH2)2CO) can be delivered to the station as an aqueous solution or as 

a dry solid, and urea storage/handling does not create the process safety concerns associated with 

handling anhydrous NH3. 

Seminole Generating Station Summary of NOX BART Impact Analysis 

Control 

Technology 

Annual 

Controlled 

Emissions

1

Annual 

Emission 

Reduction

s 

Average Cost 

Effectiveness 

Incremental 

Cost 

Effectivenes

s 

Summary of 

Environmental Impacts 

(TPY) (TPY) ($/Ton) ($/Ton) 

LNB/OFA+SCR 1,441 9,511 $5,387 $8,078 NH3 emissions; & 

NH3 storage & 

handling. 

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

CO/VOC emissions. 

LNB/OFA 8,214 2,738 $1,534 -- Potential increase in 

CO/VOC emissions. 

Baseline 10,952 base -- -- -- 

1

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

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

(50% capacity factor). 

Step 5: Evaluate Visibility Impacts 

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

NOX emissions were modeled at the projected post-retrofit controlled emission rates. In 

accordance with EPA guidelines (40 CFR Part 51 Appendix Y Part III), post-retrofit emission 

rates used in the modeling analysis to determine visibility impairment impacts reflect steadystate operating conditions during periods of high capacity utilization. Post-retrofit emission rates 

(average lb/hr rate on a 24-hour basis) were calculated using the expected controlled emission 

rate achievable on a 30-day rolling average multiplied by the boiler heat input (MMBTUH) at 

full load. The visibility modeling methodology is described further in Section VI. CALPUFF 

Modeling. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 24 

NOX Visibility Assessment / Visibility Improvement1

WMWR UBWA HGWA CCWA 

Control 

Technology 

98th % 

Δ-dv 

% 

Improve

ment 

98th % 

Δ-dv 

% 

Improve

ment 

98th % 

Δ-dv 

% 

Improve

ment 

98th % 

Δ-dv 

% 

Improve

ment 

Baseline 1.041.

073

-- 0.390.

351

-- 0.336 -- 0.690.

588

-- 

LNB/OFA 0.813 2224% 0.262 3325% 0.251 2425% 0.440.

438

3626% 

LNB/OFA+FGR 0.670.

707

1713% 0.250.

221

416% 0.218 1613% 0.440.

370

016% 

LNB/OFA+SCR 0.154 78% 0.044 8480% 0.044 8180% 0.074 8480% 

1 Δ-dv values included in this table represent the modeled visibility impacts only from NOX emissions associated 

with each NOX retrofit control scenario. 

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

approximately 2625%. Combustion controls plus FGR reduce modeled visibility impacts by an 

additional 4 13 - 16% at each Class I Area. SCR control provides additional improvement in 

modeled visibility impacts; however, it is important to note that visibility impacts at three of the 

Class I Areas (Upper Buffalo, Hercules-Glades, and Caney Creek) are below the 0.5 Δ-dv 

threshold with combustion controls. It is also important to note that visibility impacts were 

modeled assuming full load heat input 8,760 hours per year. Seminole Units 1, 2, and 3 operate 

as peaking units and are typically operated at approximately 40% load and achieve capacity 

factors in the range of 25% to 30%. 

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

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

emissions to 0.04 lb/MMBTU reduce modeled visibility impacts to 0.154 Δ-dv, a 0.564 Δ-dv 

improvement. As discussed previously, the incremental increase in total annual costs associated 

with SCR controls is approximately $44,534,600/year. Therefore, the incremental cost 

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

The average cost effectiveness of the SCR controls systems (based on modeled impacts at the 

Wichita Mountains) would be in the range of $55.7 MM/dv (based on modeled visibility impacts 

of 1.073 Δ-dv (baseline) and 0.154 Δ-dv (LNB/OFA+SCR) and total annual costs of 

$51,233,000). Both of these costs are significantly higher than the expected cost of BART 

controls on large EGU, and should preclude SCR from consideration as BART. 

NOX Average Visibility Cost Impact Evaluation1

Control 

Technology

Total Annual 

Cost 

Modeled 

Visibility 

Impairment 

Visibility Impairment 

Improvement from 

Baseline 

Average 

Improvement Cost 

Effectiveness 

 ($/yr) 98th % Δ-dv* (dv) ($/dv/yr) 

Baseline -- 1.073 -- -- 

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

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

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

Comment [A4]: Several of the Δ-dv 

and % Improvement numbers do not 

match what was submitted in Table 3-9 

on page 30 of the BART Determination. 

Do not know if this is a typo or if some 

parameter change occurred and the 

numbers were recalculated and 

resubmitted?

Comment [A5]: This was noted as 

25% in BART Determination see page 

30. 

Comment [A6]: The range was noted 

as 13-16% in BART Determination see 

page 30. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 25 

1 Δ-dv values included in this table represent the modeled visibility impacts only from NOX emissions associated 

with each NOX retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains) 

was used for the cost effectiveness evaluation. 

NOX Incremental Visibility Cost Impact Evaluation 

Control 

Technology 

Total Annual 

Cost 

Incremental 

Annual Cost 

Modeled 

Visibility 

Impairment 

Incremental 

Visibility 

Impairment 

Improvement 

Incremental 

Improvement 

Cost 

Effectiveness 

($/yr) ($/yr) 98th % Δdv* (dv) ($/dv/yr) 

Baseline -- -- 1.073 -- -- 

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

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

MM/dv 

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

MM/dv 

1 Δ-dv values included in this table represent the modeled visibility impacts only from NOX emissions associated 

with each NOX retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains) 

was used for the cost effectiveness evaluation. 

Proposed BART for NOX Control at Seminole Units 1, 2, and 3

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

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

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

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

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

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

each unit results in the following controlled NOX emission rates: 

• Seminole Unit 1: 0.203 lb/MMBTU 

• Seminole Unit 2: 0.212 lb/MMBTU 

• Seminole Unit 3: 0.164 lb/MMBTU

Note that Seminole Unit3 is currently designed with FGR: therefore, emissions from Unit 3 under the FGR control option only include LNB/OFA 

retrofit controls.

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

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

higher than EPA’s cost estimate for presumptive BART controls on large coal-fired EGUs, they 

are not of such magnitude as to exclude combustion controls as BART on the gas-fired units at 

Seminole. The addition of an SCR control system could provide incremental NOX reductions; 

however, costs associated with SCR control are significant, and incremental visibility 

improvements are limited. The average cost effectiveness of SCR control systems on all three 

units is estimated to be $5,387/ton and $55.75 MM/dv/yr. These costs are significantly higher 

than the average cost of NOX control at similar sources. In the BART rule, EPA concluded that 

the cost of controls to meet the BART NOX presumptive level on large coal-fired EGUs “in most 

cases range from just over $100 to $1,000 per ton” (see, 70 FR 39135). The average cost 

Formatted: Font: 8 pt, Complex

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numbering
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 26 

effectiveness of SCR on Seminole Units 1, 2, and 3 are high because of the relatively low 

average NOX emission rates that can be achieved with combustion controls and the fact that 

Seminole Units 1, 2, and 3 are operated as peaking units (limiting annual mass emissions). 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 27 

Modeled incremental visibility improvements associated with SCR controls are less than 0.3 Δdv at all Class I Areas, except the Wichita Mountains where SCR controls result in a modeled 

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

limited improvement in modeled visibility impacts, the cost effectiveness of SCR control, on a 

$/dv basis is significant. Furthermore, compared to the costs and modeled visibility impacts 

associated with LNB/OFA+FGR controls, the incremental cost effectiveness of SCR is estimated 

to be $8,078/ton and more than $80.5 MM/dv/yr. Both costs are significantly higher than the 

expected cost of BART controls on large EGUs, and should preclude SCR from consideration as 

BART. 

Proposed BART Permit Limits and Control Technologies 

Unit NOX BART Emission Limit BART Technology 

Seminole Unit 1 0.203 lb/MMBTU 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

Seminole Unit 2 0.212 lb/MMBTU 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

Seminole Unit 3 0.164 lb/MMBTU 

(30-day average) 

Combustion controls including 

LNB/OFA and FGR 

SECTION VI. CALPUFF MODELING 

Background

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

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

known as Class I Areas. The Clean Air Act defines Class I Areas as certain national parks (over 

6000 acres), wilderness areas (over 5000 acres), national memorial parks (over 5000 acres), and 

international parks that were in existence on August 7, 1977. 

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

which included guidance for making source-specific Best Available Retrofit Technology 

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

following criteria: 

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

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

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

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

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

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

reasonably anticipated to cause or contribute to visibility impairment if the visibility impacts 

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

Comment [A7]: This section of the 

memorandum does not reflect the most 

recent BART determination submitted in 

May 2008. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 28 

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

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

results of the dispersion modeling demonstrate that the source cannot reasonably be anticipated 

to cause or contribute to visibility impairment in a Class I Area. Further, states also have the 

authority to define the modeling procedures for conducting modeling related to making BART 

determinations. 

To promote consistency between states in the development of BART modeling protocols and to 

harmonize the approaches between adjacent RPO, the Central States Regional Air Planning 

(CENRAP) organization developed BART Modeling Guidelines (December 15, 2005). The 

intent of the guidelines is to assist CENRAP states and source operators in the development of 

statewide and source-specific modeling protocols. 

The following summarizes the modeling methods and procedures that were followed to conduct 

a refined CALPUFF modeling analysis for the OG&E Seminole Generating Station. The 

modeling methods and procedures used to determine appropriate controls for OG&E’s BARTeligible sources at the Seminole Generating Station that can reasonably be anticipated to reduce 

the sources’ effects on or contribution to visibility impairment in the surrounding Class I Areas. 

It was OG&E’s intent to determine a combination of emissions controls that would reduce the 

impact of the Seminole Generating Station to a degree that the 98th percentile of the visibility 

impact predicted by the modeling due to all of the BART eligible sources at the station was 

below EPA’s recommended visibility contribution threshold of 0.5 Δdv. 

Bart-Eligible Sources (Seminole Station)

• Unit 1 - 5,480 MMBTUH Natural Gas Fired Boiler 

• Unit 2 - 5,480 MMBTUH Natural Gas Fired Boiler 

• Unit 3 - 5,496 MMBTUH Natural Gas Fired Boiler 

As required in CENRAP’s BART Modeling Guidelines, Class I Areas within 300 km of the 

Seminole Generating Station were included in the analysis. 

CALPUFF Modeling System

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

CALPOST. CALMET is the meteorological model that generates hourly three-dimensional 

meteorological fields such as wind and temperature. CALPUFF simulates the non-steady state 

transport, dispersion, and chemical transformation of air pollutants emitted from a source in 

“puffs.” CALPUFF calculates hourly concentrations of visibility affecting pollutants at each 

specified receptor in a modeling domain. CALPOST is the post-processor for CALPUFF that 

computes visibility impacts from a source based on the visibility affecting pollutant 

concentrations that were output by CALPUFF. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 29 

The versions of the CALPUFF modeling system programs that were used for conducting 

OG&E’s BART modeling are listed below. 

CALPUFF Modeling System Versions 

Processor Version Level 

TERREL 3.311 030709 

CTGCOMP 2.22 030528 

CTGPROC 2.42 030709 

MAKEGEO 2.22 030709 

CALMM5 2.4 050413 

CALMET 6.211 060414 

CALPUFF 6.112 060412 

POSTUTIL 1.4 040818 

CALPOST 6.131 060410 

Modeling Domain

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

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

at which meteorological fields are developed with CALMET. The computational grid 

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

while within the computational grid. The meteorological grid is defined so that it covers the 

areas of concern and gives enough marginal buffer area for puff transport and dispersion. The 

computational domain was set to extend at least 50 km in all directions beyond the Seminole 

Generating Station and the Class I Areas of interest. The map projection for the modeling 

domain was Lambert Conformal Conic (LCC) and the datum was the North American Datum 

1927 (NAD-27). The reference point for the modeling domain is Latitude 34oN, Longitude 

100.5oW. The northeast corner was Latitude 37.25oN and Longitude 92oW. The meteorological 

grid spacing was 3 km. 

Vertical Layers 

Layer Cell Face 

Height (m) 

1 20 

2 40 

3 80 

4 160 

5 320 

6 640 

7 1,200 

8 2,000 

9 3,000 

10 4,000 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 30 

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

sounding pressure level for which upper air observation data will be relied upon. The vertical 

dimension of the domain was divided into 10 layers. The vertical dimensions were weighted 

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

layers aloft. 

Geophysical Data

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

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

atmosphere and are potentially subjected to higher concentrations of elevated puffs. Different 

land uses exhibit variable characteristics such as surface roughness, albedo, Bowen ratio, and 

leaf-area index that also effect turbulence and dispersion. 

Terrain Data

Terrain data was obtained from the United States Geological Survey (USGS) in 1-degree 

(1:250,000 scale or approximately 90 meter resolution) digital format. The USGS terrain data 

was then processed by the TERREL program to generate grid-cell elevation averages across the 

modeling domain. 

Land Use Data

USGS Composite Theme Grid (CTG) format Land Use and Land Cover (LULC) data files at 

1:250,000 resolution were used. Where 1:250,000 land use data was not available, USGS data at 

1:100,000 resolution was used. The USGS CTG format LULC data files were compressed prior 

to use in the CTGPROC utility processor using the CTGCOMP program. The LULC data were 

processed by the CTGPROC program to generate land use for each grid cell across the modeling 

domain. 

Compiling Terrain And Land Use Data

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

CTGPROC program were then uploaded into the MAKEGEO program to create a geophysical 

data file that was used as the input for CALMET. 

CALMET

CALMET is the meteorological processor that compiles meteorological data from raw 

observations of surface and upper air conditions, precipitation measurements, mesoscale model 

output, and geophysical parameters into a single hourly, gridded data set for input into 

CALPUFF. CALMET was used to assimilate data for 2001- 2003 using National Weather 

Service (NWS) surface station observations, precipitation data, and mesoscale model output to 

develop the meteorological fields. Upper air observations were not used in generating the 

meteorological fields. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 31 

MM5 Data

Hourly mesoscale data was used as the initial guess field in developing the CALMET 

meteorological data. The following 5th generation mesoscale model meteorological data sets (or 

MM5 data) was used 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 

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

The specific MM5 data used were subsets of the data listed above. As the contractor to 

CENRAP for developing the meteorological data sets for the BART modeling, Alpine 

Geophysics extracted three subsets of MM5 data for each year from 2001 to 2003 from the data 

sets listed above using the CALMM5 extraction program. The three subsets covered the 

northern, central, and southern portions of CENRAP. The southern set of the extracted MM5 

data was used. 

The 2001 southern subset of the extracted MM5 data included 30 files that were broken into 10 

to 11 day increments (3 files per month). The 2002 and 2003 southern subsets of extracted MM5 

data include 12 files each of which were broken into 30 to 31 day increment files (1 file per 

month). The 2001 to 2003 MM5 data extracted by Alpine Geophysics were not able to be used 

directly in the modeling analysis. To run the Alpine Geophysics extracted MM5 data in the EPA 

approved CALMET program, each of the MM5 files had 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 occurred. 

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

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

calendar day and ends at Hour 23 in GMT on the last calendar day. In order to run CALMET in 

the local standard time (LST), which is necessary, since the surface meteorological observations 

are recorded in LST, there must be hours of MM5 data referenced in a CALMET run that match 

the LST observation hours. Since the LST hours in Central Standard Time (CST) are 6 hours 

behind GMT, it was 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 was not used directly. Instead 

the data files were modified by adding eight additional hours of data to the end of each file from 

the beginning of the subsequent file. CALMET was then run using the appended MM5 data to 

generate a contiguous set of CALMET output files. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 32 

Surface Data

Parameters affecting turbulent dispersion that are observed hourly at surface stations include 

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

precipitation type. The stations were selected from the available data inventory to optimize 

spatial coverage and representation of the domain. Data from the stations was processed for use 

in CALMET using the SMERGE program. 

Missing surface data was filled using procedures recommended by EPA. 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 were included in the domain so that overlapping areas of influence would allow data 

from an alternate station to be used. 

The use of multiple stations for meteorological observations in CALMET/CALPUFF provides a 

substantial enhancement over the steady-state treatment of observations from a single 

meteorological station. Surface data were extracted from the surface stations. Raw observations 

from these stations were obtained from the National Climatic Data Center (NCDC). The data 

was quality assured and then merged using the SMERGE pre-processor to create a single 

assimilated data file of surface observations for each year analyzed. 

Precipitation Data

The effects of chemical transformation and deposition processes on ambient pollutant 

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

observations of precipitation in the CALMET analysis. The stations were selected from the 

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

from the stations will be processed for use in CALMET using the PMERGE program. 

Upper Air Data

Upper Air observations were not used in the CALMET analysis (i.e. NOOBS=1). 

CALMET Control Parameters

The modeling was conducted using the CENRAP recommended parameters, except the ones 

listed below. A explanation is also provided as to why the CENRAP recommended parameters 

were not used for these variables. Most of the differences are due to the inclusion of observation 

data into the modeling analysis. 

CALMET Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

DGRIDKM 6.0 3.0 Grid spacing (km) Refined grid spacing 

NN2 1 2 Last time step for debug data 

to be printed 

Generated debug data for 2 

time steps 

NZPRN2 0 1 # Of levels at surface to print Default 

NOOBS 2 1 No obs mode Used surface OBS 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 33 

CALMET Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

NSSTA 0 47 # Met stations in surf.dat # of stations 

NPSTA 0 135 # Met stations in precip.dat # of stations 

IFORMC 2 1 Format cloud data N/A - no cloud data used 

IKINE 0 1 Adjust winds using 

kinematic effects 

Computed kinematic effects 

RMAX1 30 100 Max radius of influence over 

land in surface layer (km) 

IWAQM Phase 2 Study 

RMAX2 30 500 Max radius of influence over 

land aloft (km) 

IWAQM Phase 2 Study 

RMAX3 30 36 Max radius of influence over 

water (km) 

Used MM5 data spacing 

R1 1 50 Weighting of 1st guess 

surface field (km) 

IWAQM Phase 2 Study 

R2 1 100 Weighting of 1st guess aloft 

field (km) 

IWAQM Phase 2 Study 

ITPROG 2 1 3D temp from observations 

or MM5 

Used surface observations 

CALPUFF

The CALPUFF model uses the output file from CALMET together with source, receptor, and 

chemical reaction information to predict hourly concentration impacts. 

Source Emissions

Baseline (pre-BART) emission data was based on CEMS data collected by OG&E over the 

2001-03 time frame. In accordance with CENRAP guidelines, the emission rate over the highest 

calendar day (24-hr average) was used to establish baseline emissions. The units at the Seminole 

Generating Station operate primarily on natural gas and occasionally fuel oil. During the 2001-

03 time frame, only Seminole Unit 3 consumed fuel oil. In addition, these units are operated as 

peaking units, resulting in an operating profile that varies substantially on a daily and a seasonal 

basis. 

Based on CEM data over the 2001-03 time period, modeled emissions are based on the highest 

hourly emission rate (based on a 24-hour calendar day average) that occurred from 2001 to 2003. 

In order to accurately reflect the operating profile (i.e., peaking nature) of these units in the 

CALPUFF model, a variable emission rate data file was utilized (PTEMARB.dat). This 

emission data file was developed by utilizing the highest 24-hour emission rate for each calendar 

month over the 2001-03 time frame. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 34 

BASELINE 24-HOUR AVERAGE EMISSION RATES 

 SO2 H2SO4 NOX PM10

EGU Month (lb/hr) (lb/hr) (lb/hr) (lb/hr) 

Unit 1 January 1.99 0.026 941 0.25 

 February 1.69 0.025 718 0.21 

 March 2.28 0.035 1048 0.29 

 April 2.10 0.032 915 0.27 

 May 1.95 0.025 936 0.25 

 June 2.06 0.032 942 0.27 

 July 2.12 0.032 751 0.27 

 August 1.98 0.027. 862 0.25 

 September 2.15 0.030 860 0.27 

 October 1.68 0.026 595 0.22 

November 2.03 0.025 1072 0.26 

 December 2.08 0.028 883 0.27 

Unit 2 January 1.89 0.012 954 0.25 

 February 1.82 0.021 1,103 0.23 

 March 1.94 0.024 1,240 0.25 

 April 2.21 0.034 1,209 0.29 

 May 2.34 0.031 1,196 0.30 

 June 2.15 0.033 1,125 0.28 

 July 2.33 0.028 1,322 0.30 

 August 2.15 0.033 1,285 0.28 

 September 2.44 0.028 1,525 0.31 

 October 1.98 0.025 1,026 0.26 

November 1.82 0.000 874 0.23 

 December 1.83 0.000 982 0.23 

Unit 3 January 2.15 0.025 1,184 0.27 

 February 1,142.29 25.148 890 0.22 

 March 1,145.01 25.207 857 0.21 

 April 1.56 0.024 747 0.20 

 May 2.25 0.028 1,055 0.29 

 June 204.62 4.505 656 0.23 

 July 2.20 0.027 1,136 0.28 

 August 2.00 0.030 837 0.26 

 September 2.44 0.031 1,226 0.32 

 October 2.07 0.026 916 0.26 

November 2.55 0.019 808 0.22 

 December 2.06 0.032 878 0.26 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 35 

Emission estimates for various control scenarios were developed by Sargent and Lundy. Since 

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

evaluated in this analysis. OG&E elected to evaluate cost effectiveness on a facility-wide basis 

(as opposed to a unit-by-unit basis) and will install the final selected control technology on each 

of the affected units at the facility. 

Point Source Stack Parameters 

 UTM E UTM N Velocity Height Diameter Temp 

Unit (m) (m) (ft/s) (ft) (ft) (°F) 

Unit 1 707,651 3,871,616 13.58 54.27 4.57 393 

Unit 2 707,650 3,871,678 13.58 54.27 4.57 393 

Unit 3 707,649 3,871,740 19.85 106.71 5.49 412 

The base elevation of each of the units is 290 meters (950 feet) above MSL based on visual 

inspection of USGS topographic maps. Based on FLM guidance, PM10 emissions from natural 

gas combustion consists of primarily (75%) fine particulate matter (PMF, considered PM<2.5) and 

(25%) coarse particulate matter (PMC, considered PM2.5-10). 

Receptor Locations

The National Park Service (NPS) provides electronic files that include the discrete locations and 

elevations of receptors to be evaluated in Class I Area analyses. The receptor files for were 

downloaded from the NPS website, converted into the LCC NAD27 projection, and incorporated 

into the CALPUFF model. 

Background Ozone

Background ozone concentrations were required in order to model the photochemical conversion 

of SO2 and NOX to sulfates (SO4) and nitrates (NO3). CALPUFF can use either a single 

background value representative of an area or hourly ozone data from one or more ozone 

monitoring stations. CENRAP recommended either developing background ozone 

concentrations from ambient monitors located within the domain being modeled or from the 

most recent CENRAP CMAQ/CAMx simulation for the 2002 base year. Modeling was 

conducted using a conservative background concentration of 40 ppb. This is the default 

background concentration from the CENRAP protocol. 

Background Ammonia

Background concentrations of ammonia were required to model the formation of ammonia 

nitrates and sulfates. CENRAP recommended developing background concentrations from the 

most recent CENRAP CMAQ or CAMx simulation for the 2002 base year. Since the 

CMAQ/CAMx modeled and observed monthly averaged concentrations exhibit wide spatial 

variability and the data is not readily available, a conservative background concentration of 3 

ppb was used. This is the default background concentration from the CENRAP protocol. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 36 

CALPUFF Model Control Parameters

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 have required 

significant computer resources and longer runtime. Based on 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 evaluated the use of this option during the modeling analysis and provide details in 

the modeling report about its use. 

The modeling was conducted using the CENRAP recommended parameters, except the ones 

listed below. A explanation is also provided as to why the CENRAP recommended parameters 

were not used for these variables. 

CALPUFF Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

NSE 8 6 # Chemical Species to be 

emitted 

SOA and EC not included 

MSPLIT 0 1 Puff splitting Allowed for puff splitting 

due to distances 

DGRIDKM 6.0 3.0 Grid Spacing (km) Refined Grid Spacing 

NH3 8.0E-5 NA Scavenging Coefficient for 

liquid precipitation (s-1) 

 0 NA Scavenging Coefficient for 

frozen precipitation (s-1) 

MH2O2 1 0 Background H2O2 

Concentrations 

Need to chose 0 to use 

monthly background value 

BCKH2O2 1 12*1 Background Monthly H2O2 

Concentrations 

OFRAC 0.2 0.15, 

0.15, 0.2, 

0.2, 0.2, 

0.2, 0.2, 

0.2, 0.2, 

0.2, 0.2, 

0.15 

Organic Fraction for SOA 

option 

Irrelevant 

MCHEM ≠ 4 

IPTU 1 3 Units for Point Source 

emissions 

Used lb/hr 

CALPOST

A three-year CALPOST analysis was conducted to determine the visibility change in deciview 

(dv) caused by OG&E’s BART-eligible sources when compared to a natural background. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 37 

Light Extinction Algorithm

EPA's currently approved algorithm for reconstructing light extinction (as opposed to the new 

equation for reconstructing light extinction recommended by the IMPROVE Steering 

Committee) was used. The background extinction coefficient bext, background is affected by 

various chemical species and the Rayleigh scattering phenomenon. The light extinction equation 

is provided below. 

bext = 3*f(RH)*[(NH4)2SO4] + 3*f(RH)*[NH4NO3] + 4*[OC] + l*[PMF] + 0.6*[PMC] + 10*[EC] + bRay

The algorithm was used to calculate the daily light extinction attributable to the Seminole 

Station's BART eligible sources and light extinction attributable to a natural background. The 

change in deciviews based on the source and background light extinctions was evaluated using 

the equation below. 

∆ dv = 1 0 *ln[(bext, background + bext, source)/bext, background] 

CALPOST Processing Method

CALPOST Method 6, which calculates hourly light extinction impacts for the source and 

background using monthly average relative humidity adjustment factors was used in the refined 

BART analysis. Monthly Class I Area-specific relative humidity adjustment factors based on the 

centroid of the Class I Areas as included in Table A-3 of EPA’s Guidance for Estimating 

Natural Visibility Conditions Under the Regional Haze Program were used. 

Monthly Humidity Factors 

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

Caney Creek 3.4 3.1 2.9 3.0 3.6 3.6 3.4 3.4 3.6 3.5 3.4 3.5 

Hercules-Glades 3.2 2.9 2.7 2.7 3.3 3.3 3.3 3.3 3.4 3.1 3.1 3.3 

Upper Buffalo 3.3 3.0 2.7 2.8 3.4 3.4 3.4 3.4 3.6 3.3 3.2 3.3 

Wichita Mountains 2.7 2.6 2.4 2.4 3.0 2.7 2.3 2.5 2.9 2.6 2.7 2.8 

Natural Background

EPA’s default average annual aerosol concentrations for the U.S. that are included in Table 2-1 

of EPA’s Guidance for Estimating Natural Visibility Conditions Under the Regional Haze 

Program were used.

Default Average Annual Natural Background Levels 

Class I Area Region SO4 NO3 OC EC Soil Coarse Mass 

Caney Creek WEST 0.12 0.10 0.47 0.02 0.50 3.00 

Hercules-Glades EAST 0.23 0.10 1.40 0.02 0.50 3.00 

Upper Buffalo EAST 0.23 0.10 1.40 0.02 0.50 3.00 

Wichita Mountains WEST 0.12 0.10 0.47 0.02 0.50 3.00 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 38 

Evaluating Visibility Results

Trinity comparedA comparison of the high of the 2001 through 2003 daily ∆ dv values output by 

CALPOST to a contribution threshold of 0.5 ∆ dv. Since the 98th percentile ∆ dv values (the 7th 

highest value, 22nd highest over three years) output by CALPOST was greater than 0.5 ∆ dv, the 

source was subject to BART regulations and submitted their BART determination to AQD. 

Summary of CALPOST Control Parameters

A listing of the CALPOST parameters that Trinity used in OG&E's modeling analysis is 

referenced in the table below. In cases where a parameter to be used is different than what 

CENRAP recommended, a short explanation as to the difference is provided. 

CALPUFF Input Variables Where CENRAP Suggested Value was not Used 

Variable Suggested Used Description Reason 

BEXTBTB

K 

12 NA Background Extinction for 

MVISBK=1 

Not necessary since 

MVISBK=6 

RHFRAC 10 NA % of Particles affected by 

RH 

Not necessary since 

MVISBK=6 

SECTION VII. INSIGNIFICANT ACTIVITIES 

The insignificant activities identified and justified in the application and listed in OAC 252:100-

8, Appendix I, are listed below. Recordkeeping for activities indicated with “*” is listed in the 

Specific Conditions. 

* Stationary reciprocating engines burning natural gas, gasoline, aircraft fuels, or diesel fuel 

which are either used exclusively for emergency power or for peaking power service not 

exceeding 500 hours/year. There is one rarely-used 20,150kW emergency generator. 

* Emissions from fuel storage/dispensing equipment operated solely for facility owned 

vehicles if fuel throughput is not more than 2,175 gallons/day, averaged over a 30-day 

period. One 1,500-gallon gasoline tank is located on-site and records are kept which 

demonstrate the facility uses much less than the 2,175 gallons/day. 

* Storage tanks with less than or equal to 10,000 gallons capacity that store volatile organic 

liquids with a true vapor pressure less than or equal to 1.0 psia at maximum storage 

temperature. There is one 550 gallon vehicle diesel storage tank on site. 

Cold degreasing operations utilizing solvents that are denser than air. Cold degreasing occurs 

in the maintenance shop. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 39 

Hazardous waste and hazardous materials drum staging areas. The facility stores used oil and 

used solvent in the machine shop and in the basement between Units 1 and 2. Used 

antifreeze is stored in the garage building. 

Sanitary sewage collection and treatment facilities other than incinerators and Publicly 

Owned Treatment Works (POTW). Stacks or vents for sanitary sewer plumbing traps are 

also included (i.e., lift station). The facility operates a sanitary sewage collection and 

treatment facility. 

Surface coating and degreasing operations which do not exceed a combined total usage of 

more than 60 gallons/month of coatings, thinners, clean-up solvents, and degreasing solvents 

at any one emissions unit. The facility conducts surface coating and degreasing operations in 

the maintenance shop. Maintenance is a listed “trivial activity,” therefore, no recordkeeping 

will be required. 

Exhaust systems for chemical, paint, and/or solvent storage rooms or cabinets, including 

hazardous waste satellite (accumulation) areas. The facility maintains exhaust systems for the 

environmental laboratory. 

Hand wiping and spraying of solvents from containers with less than 1 liter capacity used for 

spot cleaning and/or degreasing in ozone attainment areas. The facility performs small 

amounts of hand wiping and spraying of solvents. 

* Activities that have the potential to emit no more than 5 TPY (actual) of any criteria 

pollutant. This covers the auxiliary boiler and fuel oil storage tanks; records of throughput 

and calculated emissions will be required. 

SECTION VIII. OKLAHOMA AIR POLLUTION CONTROL RULES 

OAC 252:100-1 (General Provisions) [Applicable] 

Subchapter 1 includes definitions but there are no regulatory requirements. 

OAC 252:100-2 (Incorporation by Reference) [Applicable] 

This subchapter incorporates by reference applicable provisions of Title 40 of the Code of 

Federal Regulations. These requirements are addressed in the “Federal Regulations” section. 

OAC 252:100-3 (Air Quality Standards and Increments) [Applicable] 

Primary Standards are in Appendix E and Secondary Standards are in Appendix F of the Air 

Pollution Control Rules. At this time, all of Oklahoma is in attainment of these standards. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 40 

OAC 252:100-5 (Registration of Air Contaminant Sources) [Applicable] 

Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission 

inventories annually, and pay annual operating fees based upon total annual emissions of 

regulated pollutants. Emission inventories have been submitted and fees paid for the past years. 

OAC 252:100-8 (Permits for Part 70 Sources) [Applicable] 

Part 5 includes the general administrative requirements for part 70 permits. Any planned 

changes in the operation of the facility which result in emissions not authorized in the permit and 

which exceed the “Insignificant Activities” or “Trivial Activities” thresholds require prior 

notification to AQD and may require a permit modification. Insignificant activities mean 

individual emission units that either are on the list in Appendix I (OAC 252:100) or whose actual 

calendar year emissions do not exceed the following limits: 

• 5 TPY of any one criteria pollutant 

• 2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAPs or 20% 

of any threshold less than 10 TPY for a HAP that the EPA may establish by rule 

Emission limitations and operational requirements necessary to assure compliance with all 

applicable requirements for all sources are taken from the operating permit application, or 

developed from the applicable requirement. 

OAC 252:100-9 (Excess Emissions Reporting Requirements) [Applicable] 

Except as provided in OAC 252:100-9-7(a)(1), the owner or operator of a source of excess 

emissions shall notify the Director as soon as possible but no later than 4:30 p.m. the following 

working day of the first occurrence of excess emissions in each excess emission event. No later 

than thirty (30) calendar days after the start of any excess emission event, the owner or operator 

of an air contaminant source from which excess emissions have occurred shall submit a report 

for each excess emission event describing the extent of the event and the actions taken by the 

owner or operator of the facility in response to this event. Request for affirmative defense, as 

described in OAC 252:100-9-8, shall be included in the excess emission event report. Additional 

reporting may be required in the case of ongoing emission events and in the case of excess 

emissions reporting required by 40 CFR Parts 60, 61, or 63. 

OAC 252:100-13 (Open Burning) [Applicable] 

Open burning of refuse and other combustible material is prohibited except as authorized in the 

specific examples and under the conditions listed in this subchapter. 

OAC 252:100-19 (Particulate Matter) [Applicable] 

This subchapter specifies limits for fuel-burning equipment particulate emissions based on heat 

input capacity. Emissions limitations and anticipated emissions are shown in the following 

table. Emissions listed for the boilers are based on the allowable emissions. All units are in 

compliance with this subchapter. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 41 

 SC 19 Limit Calculated Emissions, lb/hr 

EU Description MMBTUH lb/hr Scenario I Scenario II 

2B-01 Unit 1 boiler 5,480 656.77 41.65 41.65 

2B-02 Unit 2 boiler 5,480 656.77 41.65 41.65 

2B-03 Unit 3 boiler 5,496 gas 

3,681 oil 

658.11 gas 

497.31 oil 

41.77 487.94 

3B-01 Gas turbine 300 80.24 1.98 1.98 

3B-02 Aux boiler 33.47 15.11 0.25 0.25 

AP-42 (7/1998), Section 1.4 lists the total PM emissions for natural gas to be 0.0076 

lb/MMBTU. 

OAC 252:100-25 (Visible Emissions and Particulates) [Applicable] 

No discharge of greater than 20% opacity is allowed except for short-term occurrences which 

consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed 

three such periods in any consecutive 24 hours. In no case shall the average of any six-minute 

period exceed 60% opacity. When burning natural gas, there is very little possibility of 

exceeding the opacity standards. When burning fuel oil, the permit will require either using a 

continuous opacity monitor (COMS) or Method 22 and then Method 9 if visible emissions are 

detected. The permit will also include reduced visible emission observation requirements when 

burning fuel oil if no visible emissions are detected or if visible emissions observations using 

Method 9 are below the 20 % opacity limitation. 

OAC 252:100-29 (Fugitive Dust) [Applicable] 

No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the 

property line on which the emissions originate in such a manner as to damage or to interfere with 

the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the 

maintenance of air quality standards. Under normal operating conditions, this facility will not 

cause a problem in this area, therefore it is not necessary to require specific precautions to be 

taken. 

OAC 252:100-31 (Sulfur Compounds) [Applicable] 

Part 3 establishes short-term ambient standards for SO2. Air dispersion modeling of Unit 3 was 

conducted burning 24,521 gal/hr of No. 6 fuel oil with a sulfur content of 1.65% by weight. 

Results of the modeling are tabulated following. All ambient SO2 impacts are in compliance 

with the limitations of Subchapter 31. 

SO2 Ambient Impacts 

Averaging Time SC 31 Limits, μg/m3 Maximum Impacts, μg/m3

 1-hour 1,200 792 

 3-hours 650 318 

24-hours 130 100 

Annual 80 4 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 42 

Part 5 limits sulfur dioxide emissions from new fuel-burning equipment (constructed after July 1, 

1972). All of the fuel-burning equipment at this facility was constructed prior to the 

applicability date. 

OAC 252:100-33 (Nitrogen Oxides) [Not Applicable] 

This subchapter limits NOX emissions from new fuel-burning equipment with rated heat input 

greater than or equal to 50 MMBTUH. All of the emission units that exceed the 50 MMBTUH 

threshold are considered existing emission units. 

OAC 252:100-37 (Volatile Organic Compounds) [Applicable] 

Part 3 requires storage tanks constructed after December 24, 1974, with a capacity of 400 gallons 

or more and storing a VOC with a vapor pressure greater than 1.5 psia to be equipped with a 

permanent submerged fill pipe or with an organic vapor recovery system. The facility includes a 

1,500-gallon gasoline tank installed in 1992, which is subject to the submerged fill requirement. 

The fuel oil storage tanks, emergency generator fuel tank, and diesel vehicle fuel tank are not 

subject since they do not store a VOC with a vapor pressure greater than 1.5 psia. 

Part 3 requires loading facilities with a throughput equal to or less than 40,000 gallons per day to 

be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the 

vehicle is greater than 200 gallons. This facility does not load tanks with a capacity greater than 

200 gallons. Therefore, this requirement is not applicable. 

Part 5 limits the VOC content of coatings used in coating lines or operations of parts and products. 

Any painting operation will involve maintenance coatings of buildings and equipment and emit less 

than 100 pounds per day of VOC and so is exempt. 

Part 7 requires fuel-burning equipment to be operated and maintained so as to minimize 

emissions. Temperature and available air must be sufficient to provide essentially complete 

combustion. 

OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable] 

This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in 

areas of concern (AOC). Any work practice, material substitution, or control equipment required 

by the Department prior to June 11, 2004, to control a TAC, shall be retained, unless a 

modification is approved by the Director. Since no AOC has been designated there are no 

specific requirements for this facility at this time. 

OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable] 

This subchapter provides general requirements for testing, monitoring and recordkeeping and 

applies to any testing, monitoring or recordkeeping activity conducted at any stationary source. 

To determine compliance with emissions limitations or standards, the Air Quality Director may 

require the owner or operator of any source in the state of Oklahoma to install, maintain and 

operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant 

source. All required testing must be conducted by methods approved by the Air Quality Director 

and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol 

shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests. 

Emissions and other data required to demonstrate compliance with any federal or state emission 

limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 43 

and submitted as required by this subchapter, an applicable rule, or permit requirement. Data 

from any required testing or monitoring not conducted in accordance with the provisions of this 

subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive 

use, of any credible evidence or information relevant to whether a source would have been in 

compliance with applicable requirements if the appropriate performance or compliance test or 

procedure had been performed. 

The following Oklahoma Air Pollution Control Rules are not applicable to this facility: 

OAC 252:100-7 Minor Facility Permits not in source category 

OAC 252:100-11 Alternative Reduction Plans not eligible 

OAC 252:100-15 Mobile Sources not in source category 

OAC 252:100-17 Incinerators not type of emission unit 

OAC 252:100-23 Cotton Gins not type of emission unit 

OAC 252:100-24 Feed & Grain Facility not in source category 

OAC 252:100-35 Carbon Monoxide not in source category 

OAC 252:100-39 Nonattainment Areas not in a subject area 

OAC 252:100-47 Landfills not type of emission unit 

SECTION IX. FEDERAL REGULATIONS 

PSD, 40 CFR Part 52 [Not Applicable]

Emissions of several regulated pollutants exceed 100 TPY, the level at which PSD defines the 

facility to be a major source. Any future expansion must be evaluated in the context of PSD 

significance levels (100 TPY CO, 40 TPY NOx, 40 TPY SO2, 40 TPY VOC, 25 TPY PM, 15 

TPY PM10, or 0.6 TPY lead). The permit will require the facility to apply for and obtain a PSD 

construction permit prior to modification of the boilers if the modifications will result in a 

significant emission increase and a significant net emission increase of a regulated NSR 

pollutant. 

NSPS, 40 CFR Part 60 [Not Applicable] 

Subpart D, Fossil-Fuel-Fired Steam Generators. This subpart is applicable to steam generating 

units constructed after August 17, 1971, which have a capacity greater than 250 MMBTUH heat 

input. Boilers No. 1, 2, and 3 commenced construction prior to August 17, 1971. The definition 

of steam generating unit is limited to furnaces or boilers. 

Subpart Da, Electric Utility Steam Generating Units. This subpart is applicable to steam 

generating units constructed, reconstructed, or modified after September 18, 1978, which have a 

capacity greater than 250 MMBTUH heat input. Boilers No. 1, 2, and 3 and Turbine No. 1 have 

not been modified or reconstructed after September 18, 1978 and are not subject to this subpart. 

Subpart Db, Industrial-Commercial-Institutional Steam Generating Units. This subpart affects 

steam generating units which were constructed, reconstructed, or modified after June 19, 1984, 

but on or before June 19, 1986, and which have a heat input capacity of 100 MMBTUH or more. 

All of the steam generating units were constructed prior to June 19, 1984 and have not been 

reconstructed or modified. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 44 

Subpart Dc, Small Industrial-Commercial-Institutional Steam Generating Units. This subpart 

affects steam generating units constructed after June 9, 1989, and with capacity between 10 and 

100 MMBTUH. The 33.47 MMBTUH steam generating unit was constructed prior to June 9, 

1989, and is not subject to this subpart. 

Subpart K, Petroleum Liquid Storage Vessels. This subpart affects petroleum liquid storage 

vessels with a capacity greater than 40,000 gallons and that commence construction or 

modification after June 11, 1973, and prior to May 19, 1978. The fuel oil tanks were installed 

prior to June 11, 1973. 

Subpart Kb, VOL Storage Vessels. This subpart affects VOL storage vessels with a capacity 

greater than or equal to 19,813-gallons that is used to store volatile organic liquids (VOL) for 

which construction, reconstruction, or modification is commenced after July 23, 1984. The 

gasoline tank is below the 19,813-gallon threshold for this subpart. 

Subpart GG, Stationary Gas Turbines. This subpart affects combustion turbines which 

commenced construction, reconstruction, or modification after October 3, 1977, and which have 

a heat input rating of 10 MMBTUH or more. The combustion turbine was constructed prior to 

the effective date of Subpart GG. 

Subpart KKKK, Stationary Gas Turbines. This subpart affects stationary combustion turbines 

that commenced construction, modification or reconstruction after February 18, 2005. The 

combustion turbine was constructed prior to the effective date of this subpart. 

NESHAP, 40 CFR Part 61 [Not Applicable]

There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene, 

mercury, coke oven emissions, radionuclides or vinyl chloride. 

NESHAP, 40 CFR Part 63 [Subpart DDDDD Is Applicable]

Subpart Q, Industrial Cooling Towers. This subpart applies to all new and existing industrial 

process cooling towers that are operated with chromium-based water treatment chemicals on or 

after September 8, 1994, and are either major sources or are integral parts of facilities that are 

major sources as defined in § 63.401. This facility does not have or use industrial process 

cooling towers that are operated with chromium-based water treatment chemicals. 

Subpart YYYY, Stationary Combustion Turbines. This subpart affects any existing, new, or 

reconstructed stationary combustion turbine located at a major source of HAP emissions. The 

turbine located at this facility is considered an existing turbine since it commenced construction 

before January 14, 2003. Per § 63.6090(b)(4), existing stationary combustion turbines in all 

subcategories do not have to meet the requirements of this subpart and of subpart A of this part. 

Subpart DDDDD, Industrial Boilers and Process Heaters. Subpart DDDDD regulated HAP 

emissions from industrial boilers and process heaters. In March, 2007, the EPA filed a motion to 

vacate and remand this rule back to the agency. The rule was vacated by court order, subject to 

appeal, on June 8, 2007. No appeals were made and the rule was vacated on July 30, 2007. 

Existing and new small gaseous fuel boilers and process heaters (< 10 MMBTUH heat rating) 

were not subject to any standards, recordkeeping, or notifications under Subpart DDDDD. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 45 

EPA is planning on issuing guidance (or a rule) on what actions applicants and permitting 

authorities should take regarding MACT determinations under either Section112(g) or Section 

112(j) for sources that were affected sources under Subpart DDDDD and other vacated MACT. 

It is expected that the guidance (or rule) will establish a new timeline for submission of section 

112(j) applications for vacated MACT standards. Until such time as more guidance is received, 

AQD has determined that a 112(j) determination is not needed for sources potentially subject to 

a vacated MACT, including Subpart DDDDD. This permit may be reopened to address Section 

112(j) when necessary. 

CAM, 40 CFR Part 64 [Not Applicable] 

Compliance Assurance Monitoring (CAM) applies to any pollutant specific EU at a major 

source, that is required to obtain a Part 70 operating permit, if it meets all of the following 

criteria: 

1. It is subject to an emission limit or standard for an applicable regulated air pollutant; 

2. It uses a control device to achieve compliance with the applicable emission limit or 

standard; and 

3. It has potential emissions, prior to the control device, of the applicable regulated air 

pollutant greater than major source thresholds. 

The requirements of this part do not apply to any of the following emission limitations or 

standards: 

1. Emission limitations or standards proposed by the Administrator after November 15, 

1990 pursuant to section 111 or 112 of the Act; and 

2. Acid Rain Program requirements pursuant to sections 404, 405, 406, 407(a), 407(b), 

or 410 of the Act. 

3. Emission limitations or standards for which a part 70 or 71 permit specifies a 

continuous compliance determination method, as defined in § 64.1. 

In addition, the boilers do not use control devices to achieve compliance with an applicable 

emission limit. 

Chemical Accident Prevention Provisions, 40 CFR Part 68 [Not Applicable] 

This facility does not store any regulated substance above the applicable threshold limits. More 

information on this federal program is available at the web site: http://www.epa.gov/ceppo/. 

Acid Rain, 40 CFR Part 72 (Permit Requirements) [Applicable] 

Acid Rain Permit No. 2004-186-ARR was issued on November 4, 2004, and remains in effect. 

Acid Rain, 40 CFR Part 73 (SO2 Requirements) [Applicable] 

SO2 initial allowances as published in 40 CFR 73.10 are listed in Acid Rain Permit No. 96-285-

AR. However, allowances can be traded, bought, and sold. Therefore, the actual allowances held 

by an affected unit may change which will not necessitate a revision to the permit. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 46 

Acid Rain, 40 CFR Part 75 (Monitoring Requirements) [Applicable] 

Certification testing has been completed for the CEM system required for each unit, and the EPA 

has issued approval of certification on September 22, 1997, for all three boilers. 

Stratospheric Ozone Protection, 40 CFR Part 82 [Subparts A and F are Applicable] 

These standards require phase out of Class I & II substances, reductions of emissions of Class I 

& II substances to the lowest achievable level in all use sectors, and banning use of nonessential 

products containing ozone-depleting substances (Subparts A & C); control servicing of motor 

vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations 

which meet phase out requirements and which maximize the substitution of safe alternatives to 

Class I and Class II substances (Subpart D); require warning labels on products made with or 

containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon 

disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds 

under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons 

(Subpart H). 

Subpart A identifies ozone-depleting substances and divides them into two classes. Class I 

controlled substances are divided into seven groups; the chemicals typically used by the 

manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform 

(Class I, Group V). A complete phase-out of production of Class I substances is required by 

January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are 

hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs. 

Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances, 

scheduled in phases starting by 2002, is required by January 1, 2030. 

Subpart F requires that any persons servicing, maintaining, or repairing appliances except for 

motor vehicle air conditioners; persons disposing of appliances, including motor vehicle air 

conditioners; refrigerant reclaimers, appliance owners, and manufacturers of appliances and 

recycling and recovery equipment comply with the standards for recycling and emissions 

reduction. 

The standard conditions of the permit address the requirements specified at § 82.156 for persons 

opening appliances for maintenance, service, repair, or disposal; § 82.158 for equipment used 

during the maintenance, service, repair, or disposal of appliances; § 82.161 for certification by an 

approved technician certification program of persons performing maintenance, service, repair, or 

disposal of appliances; § 82.166 for recordkeeping; § 82.158 for leak repair requirements; and § 

82.166 for refrigerant purchase records for appliances normally containing 50 or more pounds of 

refrigerant. 
PERMIT MEMORANDUM 2003-400-TVR (M-1) DRAFT Page 47 

SECTION X. COMPLIANCE 

Tier Classification and Public Review 

This application has been determined to be Tier II based on the request for a significant 

modification of a Part 70 operating permit. The applicant has submitted an affidavit that they are 

not seeking a permit for land use or for any operation upon land owned by others without their 

knowledge. The affidavit certifies that the applicant owns the real property. 

The applicant published the “Notice of Filing a Tier II Application” in the Newspaper, a daily 

newspaper, in Seminole County, on DATE. The notice stated that the application was available 

for public review LOCATION. The applicant will publish the "Notice of Tier II Draft Permit" in 

the Newspaper, a daily newspaper, in Seminole County. This facility is not located within 50 

miles of the Oklahoma border. The draft permit will also be available for pubic review on the 

Air Quality section of the DEQ Web Page: http://www.deq.state.ok.us/.

Information on all permit actions is available for review in the Air Quality section of the DEQ 

Web page: http://www.deq.state.ok.us/. 

Inspection 

A full compliance evaluation inspection was conducted on March 9, 2005. Mr. Jason Lipscomb 

of Air Quality who was accompanied by Ms. Melody Martin, Staff Chemist, conducted the 

inspection. The facility was physically as described in the permit application and supplemental 

materials. No violations were noted during the inspection. 

Fees Paid 

Significant modification of a Part 70 source operating permit application fee of $1,000. 

SECTION XI. SUMMARY 

The facility was constructed and is operating as described in the permit application. Ambient air 

quality standards are not threatened at this site. There are no active Air Quality compliance or 

enforcement issues concerning this facility. Issuance of the modified operating permit is 

recommended, contingent on EPA and public review. 
DRAFT 

PERMIT TO OPERATE 

AIR POLLUTION CONTROL FACILITY 

SPECIFIC CONDITIONS 

Oklahoma Gas & Electric Company 

Seminole Generating Station Permit No. 2003-400-TVR (M-1) 

The permittee is authorized to operate in conformity with the specifications submitted to Air 

Quality on December 19, 2003, July 22, 2005, and March 30, 2007, and all supplemental 

information. The Evaluation Memorandum dated October 27, 2009, explains the derivation of 

applicable permit requirements and estimates of emissions; however, it does not contain 

operating permit limitations or permit requirements. Continuing operations under this permit 

constitutes acceptance of, and consent to, the conditions contained herein. 

1. Points of emissions and emissions limitations for each point: [OAC 252:100-8-6(a)] 

All units in EUG 2, EUG 3 and EUG 4 are “grandfathered” (pre-October 1972 construction) or 

are an “insignificant activity.” There are no hourly or annual emission limits applied to the 

following units under Part 70, but they are limited to the equipment as is. 

Point Manufacturer MMBTUH kW 

Serial 

Number 

2-B-01 Babcock & Wilcox El-Paso 5,480 509,719 BW-22731 

2-B-02 Babcock & Wilcox El-Paso 5,480 504,604 BW-22826 

2-B-03 Babcock & Wilcox El-Paso 5,496 505,980 BW-23416 

4-B-01 General Electric 300 20,150 179530 

3-B-02 Cleaver-Brooks 33.47 N/A L-58163 

a. The permittee shall either monitor the opacity of discharges using a continuous 

opacity monitor or conduct daily visual observations. If a daily visual observation is 

the method of choice, then an EPA Reference Method 22 shall be conducted while 

burning No. 2 or No. 6 fuel oil for more than 24 continuous hours and records kept of 

these observations. If visible emissions are detected, then the permittee shall conduct 

a thirty-minute opacity reading in accordance with EPA Reference Method No. 9. 

i. If a Method 9 observation exceeds 20% opacity the permittee shall conduct at 

least two additional Method 9 observations within the next 24-hours. 

ii. If more than one six-minute Method 9 observation exceeds 20% opacity in any 

consecutive 60 minutes; or more than three six-minute Method 9 observations 

in any consecutive 24 hours exceeds 20% opacity; or if any six-minute Method 

9 observation exceeds 60% opacity; the owner or operator shall comply with the 

provisions for excess emissions in OAC 252:100-9. [OAC 252:100-25] 
SPECIFIC CONDITIONS 2003-400-TVR (M-1) DRAFT Page 2 

b. The permittee shall be authorized to utilize natural gas as the primary fuel. Fuel oil 

(#2 or #6) may be utilized as a secondary fuel in Unit 2-B-03. A permit modification 

shall be required to burn fuel oil in Units 1 and 2 dependent on a demonstration of 

compliance with OAC 252:100-31. [OAC 252:100-31] 

c. Boilers S2-B-01, 2-B-02, and 2-B-03 are authorized to combust non-hazardous waste 

on an as-needed basis, generated on-site, from other OG&E facilities, or from OG&E 

employees and retired employees. The waste combusted may include, but is not 

limited to, used oil, EH fluid and used antifreeze. [OAC 252:100-31] 

d. Fuel oil may be burned in only Unit 3. Residual fuel oil shall contain no more than 

1.65% by weight sulfur and distillate fuel oil shall contain no more than 1.84% by 

weight sulfur. [OAC 252:100-31] 

EUG 5 (Storage Tanks): VOC emissions from storage tanks are insignificant based on existing 

equipment items and do not have a specific limitation. 

EU ID# Point ID# EU Name/Model Capacity (Gallons) InstallationDate

5-B 01 #1 Light Fuel Oil Tank 2,310,000 1970 

5-B 02 #2 Light Fuel Oil Tank 2,310,000 1972 

5-B 03 Heavy Fuel Oil Tank 12,600,000 1975 

5-B 04 Heavy Fuel Oil Tank 126,000 1975 

5-B 05 Gasoline Tank 1,500 1992 

a. Gasoline Tank 5-B-05 shall be operated with a submerged fill pipe.[OAC 252:100-37] 

2. The permittee shall be authorized to operate the facility continuously (24 hours per day, 

every day of the year). [OAC 252:100-8-6(a)] 

3. The facility is subject to the Acid Rain Program and shall comply with all applicable 

requirements including the following: [40 CFR Part 72, 73, and 75] 

a. SO2 allowances. 

b. Report quarterly emissions to EPA. 

c. Conduct RATA tests. 

d. QA/QC plan for maintenance of the CEMS. 

4. The following records shall be maintained on-site. All such records shall be made available 

to regulatory personnel upon request. These records shall be maintained for a period of at least 

five years after the time they are made. [OAC 252:100-8-6 (a)(3)(B)] 

a. Quantity of each type of fuel and other materials burned (monthly). 

b. Emissions data as required by the Acid Rain Program. 

c. RATA test results from periodic CEMS quality assurance tests. 

d. Operating hours for each boiler. 
SPECIFIC CONDITIONS 2003-400-TVR (M-1) DRAFT Page 3 

e. Date and time of visual emission observations (Method 22 of 40 CFR Part 60) when 

burning fuel oil, stack or emission point observed, operational status of the emission 

unit, observed results and conclusions, and any required Reference Method No. 9 

results; or continuous opacity monitor results if used instead of visual monitoring. 

f. Sulfur content of fuels per 40 CFR Part 75. 

5. No later than 30 days after each anniversary date of the issuance of the original permit 

(June 21, 1999), the permittee shall submit to Air Quality Division of DEQ, with a copy to the 

US EPA, Region 6, a certification of compliance with the terms and conditions of this permit. 

 [OAC 252:100-8-6 (c)(5)(a)&(d)] 

6. The following records shall be maintained on-site to verify insignificant activities. 

 [OAC 252:8-6(a)(3)(b)] 

a. Fuel storage/dispensing equipment operated solely for facility owned vehicles if fuel 

throughput is not more than 2,175 gallons/day, averaged over a 30-day period: 

capacity of the tanks and the amount of throughput (annual). 

b. Fluid storage tanks with a capacity of less than 39,894 gallons and a true vapor 

pressure less than 1.5 psia: capacity of the tanks and contents. 

c. Activities that have the potential to emit less than 5 TPY (actual) of any criteria 

pollutant: the type of activity and the amount of emissions from that activity (annual). 

7. The permittee shall have the discretion of determining which records will be maintained in 

digital format. 

8. The Permit Shield (Standard Conditions, Section VI) is extended to the following 

requirements that have been determined to be inapplicable to this facility. 

 [OAC 252:100-8-6(d)(2)] 

a. OAC 252:100-11 Alternative Emissions Reduction 

b. OAC 252:100-15 Mobile Sources 

c. OAC 252:100-17 Incinerators 

d. OAC 252:100-23 Cotton Gins 

e. OAC 252:100-24 Grain elevators 

f. OAC 252:100-33 NOX

g. OAC 252:100-35 Carbon Monoxide 

h. OAC 252:100-39 Organic Materials 

i. OAC 252:100-47 Landfills 

9. This permit supersedes all previous Air Quality permits for this facility, except Acid Rain 

Permit No. 2004-186-ARR, which are now null and void. 

10. Boiler 3-B-02 (the auxiliary boiler) is subject to NESHAP, Subpart DDDDD with a 

compliance date of September 13, 2007. As of that date, the permittee shall comply with all 

applicable provisions. [40 CFR Part 63, Subpart DDDDD] 
SPECIFIC CONDITIONS 2003-400-TVR (M-1) DRAFT Page 4 

11. The boilers in EUG 2 are subject to the Best Available Retrofit Technology (BART) 

requirements of 40 CFR Part 51, Subpart P, and shall comply with all applicable requirements 

including but not limited to the following: [40 CFR §§ 51.300-309 & Part 51, Appendix Y] 

a. Affected facilities. The following sources are affected facilities and are subject to the 

requirements of this Specific Condition, the Protection of Visibility and Regional 

Haze Requirements of 40 CFR Part 51, and all applicable SIP requirements: 

EU ID# Point ID# EU Name

Heat Capacity

(MMBTUH)

Construction

Date

2-B 01 Unit 1 Boiler 5,480 1968 

2-B 02 Unit 2 Boiler 5,480 1968 

2-B 03 Unit 3 Boiler 5,496 5/28/70 

b. Each existing affected facility shall install and operate the SIP approved BART as 

expeditiously as practicable but in equipment listed in Specific Condition 11.d. no 

later than five years after USEPA approval of the SIP incorporating the BART 

requirements or final resolution to any BART related legal action whichever is later. 

c. The permittee shall apply for and obtain a construction permit prior to modification of 

the boilers. I if the modifications result in an increase in any air pollutant or results in 

the emissions of any air pollutant not previously emitted. If the modification will 

result incause a significant emission increase and a significant net emission increase 

of a regulated NSR pollutant, the applicant shall apply for a PSD construction permit. 

d. The affected facilities shall be equipped with the following current combustion 

control technology, as determined in the submitted BART analysis, to reduce 

emissions of NOX to below the emission limits below: 

i. Low-NOX Burners, 

ii. Overfire Air, and 

iii. Flue Gas Recirculation.

Note that Seminole Unit3 is currently designed with FGR.

e. The permittee shall maintain the combustion controls (Low-NOX burners, overfire 

air, and flue gas recirculation) and establish procedures to ensure the controls are 

properly operated and maintained. 

f. Within 60 days of achieving the maximum production rate at which the affected 

facilities will be operated, after modification or installation of BART, not to exceed 

180 days from initial start-up of the affected facility the permittee shall comply with 

the emission limits established in the construction permit. The emission limits 

established in the construction permit shall be consistent with manufacturer’s data 

and an agreed upon safety factor. The emission limits established in the construction 

permit shall not exceed the following emission limits: 

EU ID# Point ID# NOX Emission Limit Averaging Period 

2-B 01 0.203 lb/MMBTU 30-day rolling 

2-B 02 0.212 lb/MMBTU 30-day rolling 

2-B 03 0.164 lb/MMBTU 30-day rolling 

Formatted: Indent: Before: 0.75",

First line: 0.25"
SPECIFIC CONDITIONS 2003-400-TVR (M-1) DRAFT Page 5 
SPECIFIC CONDITIONS 2003-400-TVR (M-1) DRAFT Page 6 

g. Boiler operating day shall have the same meaning as in 40 CFR Part 60, Subpart Da. 

h. After installation of the BART, the affected facilities shall only be fired with natural 

gas. 

i. Within 60 days of achieving achieving the maximum production rate at which the 

affected facilities will be operated, after modification of the boilers, not to exceed 180 

days from initial start-up, the permittee shall conduct performance testing as follows 

and furnish a written report to Air Quality. Such report shall document compliance 

with BART emission limits for the affected facilities. [OAC 252:100-8-6(a)] 

i. The permittee shall conduct NOX, CO, and VOC testing on the boilers at 60% 

and 100% of the maximum capacity. NOX and CO testing shall also be 

conducted at least one additional intermediate point in the operating range. 

ii. Performance testing shall be conducted while the units are operating within 

10% of the desired testing rates. A testing protocol describing how the testing 

will be performed shall be provided to the AQD for review and approval at least 

30 days prior to the start of such testing. The permittee shall also provide notice 

of the actual test date to AQD. 

iii. The following USEPA methods shall be used for testing of emissions, unless 

otherwise approved by Air Quality: 

Method 1: Sample and Velocity Traverses for Stationary Sources. 

Method 2: Determination of Stack Gas Velocity and Volumetric Flow 

Rate. 

Method 3: Gas Analysis for Carbon Dioxide, Excess Air, and Dry 

Molecular Weight. 

Method 4: Determination of Moisture in Stack Gases. 

Method 10: Determination of Carbon Monoxide Emissions from 

Stationary Sources. 

Method 6C: Quality Assurance Procedures (Range and Sensitivity, 

Measurement System Performance Specification, and 

Measurement System Performance Test Procedures) shall be 

used in conducting Method 10. 

Method 20: Determination of Nitrogen Oxides and Oxygen Emissions 

from Stationary Gas Turbines. 

Method 25/25A: Determination of Non-Methane Organic Emissions From 

Stationary Sources. 

Comment [A8]: If the BART emission 

limit is for NOx are we required to test 

for CO and VOC? 

Comment [A9]: Method 10 references 

method 7e unsure why 6C is required 

instead? 
Oklahoma Gas & Electric 

Attn: David Branecky 

Environmental Administrator 

P. O. Box 321 

Oklahoma City, OK 73101 

Re: Permit Application No. 2003-400-TVR (M-1)

 Seminole Generating Station 

 Seminole County, Oklahoma 

Dear Mr. Branecky: 

Air Quality has received the permit application for the referenced facility and completed initial 

review. This application has been determined to be a Tier II application. In accordance with 

27A O.S. 2-14-301 and 302 and OAC 252:4-7-13(c) the application and enclosed draft permit 

are now ready for public review. The requirements for public review of the draft permit include 

the following steps, which you must accomplish: 

1. Publish at least one legal notice for the draft permit (one day) in at least one newspaper of 

general circulation within the county where the facility is located. (Instructions enclosed) 

2. Provide for public review (for a period of 30 days following the date of the newspaper 

announcement) a copy of the draft permit at a convenient location (preferentially at a 

public location) within the county of the facility. 

3. Send AQD a written affidavit of publication for the notice from Item #1 above together 

with any additional comments or requested changes, which you may have for the permit 

application within 20 days of publication. 

The permit review time is hereby tolled pending the receipt of the affidavit of publication. Thank 

you for your cooperation. If you have any questions, please refer to the permit number above 

and contact the permit writer at eric.milligan@deq.ok.gov or at (405) 702-4217. 

Sincerely, 

Phillip Fielder, P.E. 

Permits and Engineering Group Manager 

AIR QUALITY DIVISION 

Enclosures 
PART 70 PERMIT 

AIR QUALITY DIVISION 

STATE OF OKLAHOMA 

DEPARTMENT OF ENVIRONMENTAL QUALITY 

707 N. ROBINSON STREET, SUITE 4100 

P.O. BOX 1677 

OKLAHOMA CITY, OKLAHOMA 73101-1677 

Permit No. 2003-400-TVR (M-1)

__ Oklahoma Gas & Electric_ 

having complied with the requirements of the law, is hereby granted permission to operate 

the Seminole Generating Station, Section 25, T6N, R5E, Seminole County, Oklahoma, 

subject to the Standard Conditions dated July 21, 2009, and Specific Conditions, both of 

which are attached.

This permit shall expire May 9, 2011, except as Authorized under Section VIII of the 

Standard Conditions. 

_________________________________ _____

Division Director, Air Quality Division Date 
MAJOR SOURCE AIR QUALITY PERMIT 

STANDARD CONDITIONS

(July 21, 2009)

SECTION I. DUTY TO COMPLY

A. This is a permit to operate / construct this specific facility in accordance with the federal 

Clean Air Act (42 U.S.C. 7401, et al.) and under the authority of the Oklahoma Clean Air Act 

and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112] 

B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma 

Department of Environmental Quality (DEQ). The permit does not relieve the holder of the 

obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or 

ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112] 

C. The permittee shall comply with all conditions of this permit. Any permit noncompliance 

shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement 

action, permit termination, revocation and reissuance, or modification, or for denial of a permit 

renewal application. All terms and conditions are enforceable by the DEQ, by the 

Environmental Protection Agency (EPA), and by citizens under section 304 of the Federal Clean 

Air Act (excluding state-only requirements). This permit is valid for operations only at the 

specific location listed. 

 [40 C.F.R. §70.6(b), OAC 252:100-8-1.3 and OAC 252:100-8-6(a)(7)(A) and (b)(1)] 

D. It shall not be a defense for a permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

conditions of the permit. However, nothing in this paragraph shall be construed as precluding 

consideration of a need to halt or reduce activity as a mitigating factor in assessing penalties for 

noncompliance if the health, safety, or environmental impacts of halting or reducing operations 

would be more serious than the impacts of continuing operations. [OAC 252:100-8-6(a)(7)(B)] 

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from an emergency and/or posing an imminent and substantial 

danger to public health, safety, or the environment shall be reported in accordance with Section 

XIV (Emergencies). [OAC 252:100-8-6(a)(3)(C)(iii)(I) & (II)] 

B. Deviations that result in emissions exceeding those allowed in this permit shall be reported 

consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements. 

 [OAC 252:100-8-6(a)(3)(C)(iv)] 

C. Every written report submitted under this section shall be certified as required by Section III 

(Monitoring, Testing, Recordkeeping & Reporting), Paragraph F. 

 [OAC 252:100-8-6(a)(3)(C)(iv)] 

SECTION III. MONITORING, TESTING, RECORDKEEPING & REPORTING 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 2 

A. The permittee shall keep records as specified in this permit. These records, including 

monitoring data and necessary support information, shall be retained on-site or at a nearby field 

office for a period of at least five years from the date of the monitoring sample, measurement, 

report, or application, and shall be made available for inspection by regulatory personnel upon 

request. Support information includes all original strip-chart recordings for continuous 

monitoring instrumentation, and copies of all reports required by this permit. Where appropriate, 

the permit may specify that records may be maintained in computerized form. 

 [OAC 252:100-8-6 (a)(3)(B)(ii), OAC 252:100-8-6(c)(1), and OAC 252:100-8-6(c)(2)(B)] 

B. Records of required monitoring shall include: 

(1)the date, place and time of sampling or measurement; 

(2)the date or dates analyses were performed; 

(3)the company or entity which performed the analyses; 

(4)the analytical techniques or methods used; 

(5)the results of such analyses; and 

(6)the operating conditions existing at the time of sampling or measurement. 

 [OAC 252:100-8-6(a)(3)(B)(i)] 

C. No later than 30 days after each six (6) month period, after the date of the issuance of the 

original Part 70 operating permit or alternative date as specifically identified in a subsequent Part 

70 operating permit, the permittee shall submit to AQD a report of the results of any required 

monitoring. All instances of deviations from permit requirements since the previous report shall 

be clearly identified in the report. Submission of these periodic reports will satisfy any reporting 

requirement of Paragraph E below that is duplicative of the periodic reports, if so noted on the 

submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)] 

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or 

operator shall comply with the provisions of Section II (Reporting Of Deviations From Permit 

Terms) of these standard conditions. [OAC 252:100-8-6(a)(3)(C)(iii)] 

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this 

permit, monitoring and reporting may be required under the provisions of OAC 252:100-43, 

Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean 

Air Act or Oklahoma Clean Air Act. [OAC 252:100-43] 

F. Any Annual Certification of Compliance, Semi Annual Monitoring and Deviation Report, 

Excess Emission Report, and Annual Emission Inventory submitted in accordance with this 

permit shall be certified by a responsible official. This certification shall be signed by a 

responsible official, and shall contain the following language: “I certify, based on information 

and belief formed after reasonable inquiry, the statements and information in the document are 

true, accurate, and complete.” 

 [OAC 252:100-8-5(f), OAC 252:100-8-6(a)(3)(C)(iv), OAC 252:100-8-6(c)(1), OAC 

252:100-9-7(e), and OAC 252:100-5-2.1(f)] 

G. Any owner or operator subject to the provisions of New Source Performance Standards 

(“NSPS”) under 40 CFR Part 60 or National Emission Standards for Hazardous Air Pollutants 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 3 

(“NESHAPs”) under 40 CFR Parts 61 and 63 shall maintain a file of all measurements and other 

information required by the applicable general provisions and subpart(s). These records shall be 

maintained in a permanent file suitable for inspection, shall be retained for a period of at least 

five years as required by Paragraph A of this Section, and shall include records of the occurrence 

and duration of any start-up, shutdown, or malfunction in the operation of an affected facility, 

any malfunction of the air pollution control equipment; and any periods during which a 

continuous monitoring system or monitoring device is inoperative. 

 [40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q] 

H. The permittee of a facility that is operating subject to a schedule of compliance shall submit 

to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for 

achieving the activities, milestones or compliance required in the schedule of compliance and the 

dates when such activities, milestones or compliance was achieved. The progress reports shall 

also contain an explanation of why any dates in the schedule of compliance were not or will not 

be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)] 

I. All testing must be conducted under the direction of qualified personnel by methods 

approved by the Division Director. All tests shall be made and the results calculated in 

accordance with standard test procedures. The use of alternative test procedures must be 

approved by EPA. When a portable analyzer is used to measure emissions it shall be setup, 

calibrated, and operated in accordance with the manufacturer’s instructions and in accordance 

with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document 

or an equivalent method approved by Air Quality. 

 [OAC 252:100-8-6(a)(3)(A)(iv), and OAC 252:100-43] 

J. The reporting of total particulate matter emissions as required in Part 7 of OAC 252:100-8 

(Permits for Part 70 Sources), OAC 252:100-19 (Control of Emission of Particulate Matter), and 

OAC 252:100-5 (Emission Inventory), shall be conducted in accordance with applicable testing 

or calculation procedures, modified to include back-half condensables, for the concentration of 

particulate matter less than 10 microns in diameter (PM10). NSPS may allow reporting of only 

particulate matter emissions caught in the filter (obtained using Reference Method 5). 

K. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required 

by 40 C.F.R. Part 60, 61, and 63, for all equipment constructed or operated under this permit 

subject to such standards. [OAC 252:100-8-6(c)(1) and OAC 252:100, Appendix Q] 

SECTION IV. COMPLIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70 

operating permit or alternative date as specifically identified in a subsequent Part 70 operating 

permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a 

certification of compliance with the terms and conditions of this permit and of any other 

applicable requirements which have become effective since the issuance of this permit. 

 [OAC 252:100-8-6(c)(5)(A), and (D)] 

B. The compliance certification shall describe the operating permit term or condition that is the 

basis of the certification; the current compliance status; whether compliance was continuous or 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 4 

intermittent; the methods used for determining compliance, currently and over the reporting 

period. The compliance certification shall also include such other facts as the permitting 

authority may require to determine the compliance status of the source. 

 [OAC 252:100-8-6(c)(5)(C)(i)-(v)] 

C. The compliance certification shall contain a certification by a responsible official as to the 

results of the required monitoring. This certification shall be signed by a responsible official, 

and shall contain the following language: “I certify, based on information and belief formed 

after reasonable inquiry, the statements and information in the document are true, accurate, and 

complete.” [OAC 252:100-8-5(f) and OAC 252:100-8-6(c)(1)] 

D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions 

units or stationary sources that are not in compliance with all applicable requirements. This 

schedule shall include a schedule of remedial measures, including an enforceable sequence of 

actions with milestones, leading to compliance with any applicable requirements for which the 

emissions unit or stationary source is in noncompliance. This compliance schedule shall 

resemble and be at least as stringent as that contained in any judicial consent decree or 

administrative order to which the emissions unit or stationary source is subject. Any such 

schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the 

applicable requirements on which it is based, except that a compliance plan shall not be required 

for any noncompliance condition which is corrected within 24 hours of discovery. 

 [OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)] 

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE 

PERMIT TERM 

The permittee shall comply with any additional requirements that become effective during the 

permit term and that are applicable to the facility. Compliance with all new requirements shall 

be certified in the next annual certification. [OAC 252:100-8-6(c)(6)] 

SECTION VI. PERMIT SHIELD 

A. Compliance with the terms and conditions of this permit (including terms and conditions 

established for alternate operating scenarios, emissions trading, and emissions averaging, but 

excluding terms and conditions for which the permit shield is expressly prohibited under OAC 

252:100-8) shall be deemed compliance with the applicable requirements identified and included 

in this permit. [OAC 252:100-8-6(d)(1)] 

B. Those requirements that are applicable are listed in the Standard Conditions and the Specific 

Conditions of this permit. Those requirements that the applicant requested be determined as not 

applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6(d)(2)] 

SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT

The permittee shall file with the AQD an annual emission inventory and shall pay annual fees 

based on emissions inventories. The methods used to calculate emissions for inventory purposes 

shall be based on the best available information accepted by AQD. 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 5 

 [OAC 252:100-5-2.1, OAC 252:100-5-2.2, and OAC 252:100-8-6(a)(8)] 

SECTION VIII. TERM OF PERMIT

A. Unless specified otherwise, the term of an operating permit shall be five years from the date 

of issuance. [OAC 252:100-8-6(a)(2)(A)] 

B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely 

and complete renewal application has been submitted at least 180 days before the date of 

expiration. [OAC 252:100-8-7.1(d)(1)] 

C. A duly issued construction permit or authorization to construct or modify will terminate and 

become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction 

is not commenced within 18 months after the date the permit or authorization was issued, or if 

work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)] 

D. The recipient of a construction permit shall apply for a permit to operate (or modified 

operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)] 

SECTION IX. SEVERABILITY 

The provisions of this permit are severable and if any provision of this permit, or the application 

of any provision of this permit to any circumstance, is held invalid, the application of such 

provision to other circumstances, and the remainder of this permit, shall not be affected thereby. 

 [OAC 252:100-8-6 (a)(6)] 

SECTION X. PROPERTY RIGHTS 

A. This permit does not convey any property rights of any sort, or any exclusive privilege. 

 [OAC 252:100-8-6(a)(7)(D)] 

B. This permit shall not be considered in any manner affecting the title of the premises upon 

which the equipment is located and does not release the permittee from any liability for damage 

to persons or property caused by or resulting from the maintenance or operation of the equipment 

for which the permit is issued. [OAC 252:100-8-6(c)(6)] 

SECTION XI. DUTY TO PROVIDE INFORMATION

A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty 

(60) days of the request unless the DEQ specifies another time period, any information that the 

DEQ may request to determine whether cause exists for modifying, reopening, revoking, 

reissuing, terminating the permit or to determine compliance with the permit. Upon request, the 

permittee shall also furnish to the DEQ copies of records required to be kept by the permit. 

 [OAC 252:100-8-6(a)(7)(E)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 6 

B. The permittee may make a claim of confidentiality for any information or records submitted 

pursuant to 27A O.S. § 2-5-105(18). Confidential information shall be clearly labeled as such 

and shall be separable from the main body of the document such as in an attachment. 

 [OAC 252:100-8-6(a)(7)(E)] 

C. Notification to the AQD of the sale or transfer of ownership of this facility is required and 

shall be made in writing within thirty (30) days after such sale or transfer. 

 [Oklahoma Clean Air Act, 27A O.S. § 2-5-112(G)] 

SECTION XII. REOPENING, MODIFICATION & REVOCATION

A. The permit may be modified, revoked, reopened and reissued, or terminated for cause. 

Except as provided for minor permit modifications, the filing of a request by the permittee for a 

permit modification, revocation and reissuance, termination, notification of planned changes, or 

anticipated noncompliance does not stay any permit condition. 

 [OAC 252:100-8-6(a)(7)(C) and OAC 252:100-8-7.2(b)] 

B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the 

following circumstances: [OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)] 

(1) Additional requirements under the Clean Air Act become applicable to a major source 

category three or more years prior to the expiration date of this permit. No such 

reopening is required if the effective date of the requirement is later than the expiration 

date of this permit. 

(2) The DEQ or the EPA determines that this permit contains a material mistake or that the 

permit must be revised or revoked to assure compliance with the applicable 

requirements. 

(3) The DEQ or the EPA determines that inaccurate information was used in establishing the 

emission standards, limitations, or other conditions of this permit. The DEQ may revoke 

and not reissue this permit if it determines that the permittee has submitted false or 

misleading information to the DEQ. 

(4) DEQ determines that the permit should be amended under the discretionary reopening 

provisions of OAC 252:100-8-7.3(b). 

C. The permit may be reopened for cause by EPA, pursuant to the provisions of OAC 100-8-

7.3(d). [OAC 100-8-7.3(d)] 

D. The permittee shall notify AQD before making changes other than those described in Section 

XVIII (Operational Flexibility), those qualifying for administrative permit amendments, or those 

defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). The 

notification should include any changes which may alter the status of a “grandfathered source,” 

as defined under AQD rules. Such changes may require a permit modification. 

 [OAC 252:100-8-7.2(b) and OAC 252:100-5-1.1] 

E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that 

are not specifically approved by this permit are prohibited. [OAC 252:100-8-6(c)(6)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 7 

SECTION XIII. INSPECTION & ENTRY 

A. Upon presentation of credentials and other documents as may be required by law, the 

permittee shall allow authorized regulatory officials to perform the following (subject to the 

permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18) 

for confidential information submitted to or obtained by the DEQ under this section): 

(1) enter upon the permittee's premises during reasonable/normal working hours where a 

source is located or emissions-related activity is conducted, or where records must be 

kept under the conditions of the permit; 

(2) have access to and copy, at reasonable times, any records that must be kept under the 

conditions of the permit; 

(3) inspect, at reasonable times and using reasonable safety practices, any facilities, 

equipment (including monitoring and air pollution control equipment), practices, or 

operations regulated or required under the permit; and 

(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times 

substances or parameters for the purpose of assuring compliance with the permit. 

 [OAC 252:100-8-6(c)(2)] 

SECTION XIV. EMERGENCIES 

A. Any exceedance resulting from an emergency shall be reported to AQD promptly but no later 

than 4:30 p.m. on the next working day after the permittee first becomes aware of the 

exceedance. This notice shall contain a description of the emergency, the probable cause of the 

exceedance, any steps taken to mitigate emissions, and corrective actions taken. 

 [OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)] 

B. Any exceedance that poses an imminent and substantial danger to public health, safety, or the 

environment shall be reported to AQD as soon as is practicable; but under no circumstance shall 

notification be more than 24 hours after the exceedance. [OAC 252:100-8-6(a)(3)(C)(iii)(II)] 

C. An "emergency" means any situation arising from sudden and reasonably unforeseeable 

events beyond the control of the source, including acts of God, which situation requires 

immediate corrective action to restore normal operation, and that causes the source to exceed a 

technology-based emission limitation under this permit, due to unavoidable increases in 

emissions attributable to the emergency. An emergency shall not include noncompliance to the 

extent caused by improperly designed equipment, lack of preventive maintenance, careless or 

improper operation, or operator error. [OAC 252:100-8-2] 

D. The affirmative defense of emergency shall be demonstrated through properly signed, 

contemporaneous operating logs or other relevant evidence that: [OAC 252:100-8-6 (e)(2)] 

(1)an emergency occurred and the permittee can identify the cause or causes of the 

emergency; 

(2)the permitted facility was at the time being properly operated; 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 8 

(3)during the period of the emergency the permittee took all reasonable steps to minimize 

levels of emissions that exceeded the emission standards or other requirements in this 

permit. 

E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an 

emergency shall have the burden of proof. [OAC 252:100-8-6(e)(3)] 

F. Every written report or document submitted under this section shall be certified as required 

by Section III (Monitoring, Testing, Recordkeeping & Reporting), Paragraph F. 

 [OAC 252:100-8-6(a)(3)(C)(iv)] 

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop 

and register with the appropriate agency a risk management plan by June 20, 1999, or the 

applicable effective date. [OAC 252:100-8-6(a)(4)] 

SECTION XVI. INSIGNIFICANT ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to 

operate individual emissions units that are either on the list in Appendix I to OAC Title 252, 

Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below. 

Any activity to which a State or Federal applicable requirement applies is not insignificant even 

if it meets the criteria below or is included on the insignificant activities list. 

(1)5 tons per year of any one criteria pollutant. 

(2)2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an 

aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per 

year for single HAP that the EPA may establish by rule. 

 [OAC 252:100-8-2 and OAC 252:100, Appendix I] 

SECTION XVII. TRIVIAL ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to 

operate any individual or combination of air emissions units that are considered inconsequential 

and are on the list in Appendix J. Any activity to which a State or Federal applicable 

requirement applies is not trivial even if included on the trivial activities list. 

 [OAC 252:100-8-2 and OAC 252:100, Appendix J] 

SECTION XVIII. OPERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the 

need for any permit revision or any notification to the DEQ (unless specified otherwise in the 

permit). When an operating scenario is changed, the permittee shall record in a log at the facility 

the scenario under which it is operating. [OAC 252:100-8-6(a)(10) and (f)(1)] 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 9 

B. The permittee may make changes within the facility that: 

(1) result in no net emissions increases, 

(2) are not modifications under any provision of Title I of the federal Clean Air Act, and 

(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit 

to be exceeded; 

provided that the facility provides the EPA and the DEQ with written notification as required 

below in advance of the proposed changes, which shall be a minimum of seven (7) days, or 

twenty four (24) hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the 

DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such 

change, the written notification required above shall include a brief description of the change 

within the permitted facility, the date on which the change will occur, any change in emissions, 

and any permit term or condition that is no longer applicable as a result of the change. The 

permit shield provided by this permit does not apply to any change made pursuant to this 

paragraph. [OAC 252:100-8-6(f)(2)] 

SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS 

A. The following applicable requirements and state-only requirements apply to the facility 

unless elsewhere covered by a more restrictive requirement: 

(1) Open burning of refuse and other combustible material is prohibited except as authorized 

in the specific examples and under the conditions listed in the Open Burning Subchapter. 

 [OAC 252:100-13] 

(2) No particulate emissions from any fuel-burning equipment with a rated heat input of 10 

MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19] 

(3) For all emissions units not subject to an opacity limit promulgated under 40 C.F.R., Part 

60, NSPS, no discharge of greater than 20% opacity is allowed except for: 

 [OAC 252:100-25] 

(a) Short-term occurrences which consist of not more than one six-minute period in any 

consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours. 

In no case shall the average of any six-minute period exceed 60% opacity; 

(b) Smoke resulting from fires covered by the exceptions outlined in OAC 252:100-13-7; 

(c) An emission, where the presence of uncombined water is the only reason for failure 

to meet the requirements of OAC 252:100-25-3(a); or 

(d) Smoke generated due to a malfunction in a facility, when the source of the fuel 

producing the smoke is not under the direct and immediate control of the facility and 

the immediate constriction of the fuel flow at the facility would produce a hazard to 

life and/or property. 

(4) No visible fugitive dust emissions shall be discharged beyond the property line on which 

the emissions originate in such a manner as to damage or to interfere with the use of 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 10 

adjacent properties, or cause air quality standards to be exceeded, or interfere with the 

maintenance of air quality standards. [OAC 252:100-29] 

(5) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2 

lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur 

dioxide. [OAC 252:100-31] 

(6) Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and 

with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia 

or greater under actual conditions shall be equipped with a permanent submerged fill pipe 

or with a vapor-recovery system. [OAC 252:100-37-15(b)] 

(7) All fuel-burning equipment shall at all times be properly operated and maintained in a 

manner that will minimize emissions of VOCs. [OAC 252:100-37-36] 

SECTION XX. STRATOSPHERIC OZONE PROTECTION 

A. The permittee shall comply with the following standards for production and consumption of 

ozone-depleting substances: [40 CFR 82, Subpart A] 

(1) Persons producing, importing, or placing an order for production or importation of 

certain class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the 

requirements of §82.4; 

(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain 

class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping 

requirements at §82.13; and 

(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons, 

HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane 

(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include 

HCFCs. 

B. If the permittee performs a service on motor (fleet) vehicles when this service involves an 

ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air 

conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term 

“motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the 

vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the 

air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger 

buses using HCFC-22 refrigerant. [40 CFR 82, Subpart B] 

C. The permittee shall comply with the following standards for recycling and emissions 

reduction except as provided for MVACs in Subpart B: [40 CFR 82, Subpart F] 

(1)Persons opening appliances for maintenance, service, repair, or disposal must comply 

with the required practices pursuant to § 82.156; 

(2)Equipment used during the maintenance, service, repair, or disposal of appliances must 

comply with the standards for recycling and recovery equipment pursuant to § 82.158; 

(3)Persons performing maintenance, service, repair, or disposal of appliances must be 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 11 

certified by an approved technician certification program pursuant to § 82.161; 

(4)Persons disposing of small appliances, MVACs, and MVAC-like appliances must 

comply with record-keeping requirements pursuant to § 82.166; 

(5)Persons owning commercial or industrial process refrigeration equipment must comply 

with leak repair requirements pursuant to § 82.158; and 

(6)Owners/operators of appliances normally containing 50 or more pounds of refrigerant 

must keep records of refrigerant purchased and added to such appliances pursuant to § 

82.166. 

SECTION XXI. TITLE V APPROVAL LANGUAGE 

A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is 

not inconsistent with Federal requirements, to provide for incorporation of requirements 

established through construction permitting into the Source’s Title V permit without causing 

redundant review. Requirements from construction permits may be incorporated into the Title V 

permit through the administrative amendment process set forth in OAC 252:100-8-7.2(a) only if 

the following procedures are followed: 

(1) The construction permit goes out for a 30-day public notice and comment using the 

procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice 

to the public that this permit is subject to EPA review, EPA objection, and petition to 

EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit 

will be incorporated into the Title V permit through the administrative amendment 

process; that the public will not receive another opportunity to provide comments when 

the requirements are incorporated into the Title V permit; and that EPA review, EPA 

objection, and petitions to EPA will not be available to the public when requirements 

from the construction permit are incorporated into the Title V permit. 

(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR § 

70.8(a)(1). 

(3) A copy of the draft construction permit is sent to any affected State, as provided by 40 

C.F.R. § 70.8(b). 

(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period 

as provided by 40 C.F.R.§ 70.8(a) and (c). 

(5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day 

comment period of any EPA objection to the construction permit. The DEQ shall not 

issue the permit until EPA’s objections are resolved to the satisfaction of EPA. 

(6) The DEQ complies with 40 C.F.R. § 70.8(d). 

(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8(a). 

(8) The DEQ shall not issue the proposed construction permit until any affected State and 

EPA have had an opportunity to review the proposed permit, as provided by these 

permit conditions. 

(9) Any requirements of the construction permit may be reopened for cause after 

incorporation into the Title V permit by the administrative amendment process, by 

DEQ as provided in OAC 252:100-8-7.3(a), (b), and (c), and by EPA as provided in 40 

C.F.R. § 70.7(f) and (g). 
TITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 12 

(10) The DEQ shall not issue the administrative permit amendment if performance tests fail 

to demonstrate that the source is operating in substantial compliance with all permit 

requirements. 

B. To the extent that these conditions are not followed, the Title V permit must go through the 

Title V review process. 

SECTION XXII. CREDIBLE EVIDENCE 

For the purpose of submitting compliance certifications or establishing whether or not a person 

has violated or is in violation of any provision of the Oklahoma implementation plan, nothing 

shall preclude the use, including the exclusive use, of any credible evidence or information, 

relevant to whether a source would have been in compliance with applicable requirements if the 

appropriate performance or compliance test or procedure had been performed. 

 [OAC 252:100-43-6]