# Exhibit 6

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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 propo sed BART analysis an d 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) natu ral circulation Babcock and Wilcox El-Paso type boilers capable of producing steam. The thermo dynamic 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 boile rs 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 fu el 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) 

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The facility utilizes a gas-fired au xiliary boiler to provide steam for heating the #6 fuel oil. The boiler has a rated capacity of 33.47 MMBTU H 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 va nes, tubes, and hoppers are used on Unit 3 to collect particulate matter and unburned carbon re sulting 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 fr om 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 non hazardous 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 5/28/70PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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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 conti nuous 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 NO X , 0.084 lb/MMBTU CO, 0.0055 lb/MMBTU VOC, 0.0076 lb/MMBTU PM 10 , and 0.0006 lb/MMBTU SO 2 . Although the two units are capable of burning liquid fuels, no modeling of SO 2 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 NO X , 0.084 lb/MMBTU CO, 0.0055 lb/MMBTU VOC,

0.0076 lb/MMBTU PM 10 , and 0.0006 lb/MMBTU SO 2 ; oil fuel emissions from AP-42 (9/98) for boilers larger than 100 MMBTUH burning No. 6 fuel oil: 47 lb/Mgal NO X , 5 lb/Mgal CO, 0.76 lb/Mgal VOC, 19.88 lb/Mgal PM 10 , and 260.05 lb/Mgal SO 2 (assuming 1.65% sulfur in fuel oil; the CEM equation in Part 75 gives a slightly different SO 2 emission rate). Residual oil has a heating value of 150,00 0 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 NO X , 0.084 lb/MMBTU CO, 0.0055 lb/MMBTU VOC, 0.0076

lb/MMBTU PM 10 , and 0.0006 lb/MMBTU SO 2 . Maximum annual emis sions were estimated at 2,900 hours.
3⁄4 Gas turbine: gas fuel emissions factors from AP-42 (4/00): 0.32 lb/MMBTU NO X , 0.082 lb/MMBTU CO, 0.0021 lb/MMBTU VOC, 0.0066 lb/MMBTU PM 10 , and 0.0006

lb/MMBTU SO 2 . 500 hours per year operations we re 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) 

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SCENARIO I: GAS FUEL

PM 10 SO 2 NO X 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)

PM 10 SO 2 NO X 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 5,051.8 0 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 0.245PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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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 th e regional haze requiremen ts (the Regional Haze SIP). The Regional Haze SIP must provide fo r 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 fire d boilers with heat inputs greater than 250 MMBTUH. All three units were in existence prio r to August 7, 1977, but not in operation prior to August 7, 1962. Based on a review of exis ting emissions data, all three units have the potential to emit more than 250 TPY of NO X , 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 sour ce 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 w ill 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 determ ined 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 th e BART determination requirements.

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

Step 1. Identify All Available Retrofit Control Technologies. Step 2. Eliminate Technically Infeasible Options. Step 3. Evaluate Control Effectiven ess of Remaining Control Technologies. Step 4. Evaluate Impacts and Document the Results. Step 5. Evaluate Visibility Impacts.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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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 technologie s, 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 NO X 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 fi re natural gas there are no sulfur dioxide (SO 2 ) or particulate matter (PM) emission control syst ems. Seminole Unit 3 was designed with flue gas recirculation (FGR) for nitrogen oxide (NO X ) 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 atthe 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 asso ciated 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 wh ich may reasonably be an ticipated to result from the use of such technology.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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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 fu ll range of demonstrated altern atives. Potentially applicable retrofit control alternatives can include pollu tion prevention strategi es, the use of add-on controls, or a combination of control strategi es. Control technologies required under the new source review (NSR) program as best available c ontrol technology (BACT) or lowest achievable emission rate (LAER) are available for BART purposes and must be included as potential

control alternatives. Ho wever, 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 informat ion 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 app lications submitted for coal-fired generating projects; and

• Technical journals, reports, newslette rs and air pollution control seminars.

Step 2. Eliminate Technically Infeasible Options. In step 2 of the BART determination, the technical feasibility of each potential retrofit technology is evaluated. Control technologies ar e considered technically feasible if either (1) they have been installed and ope rated 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 diffic ulties 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 feas ibility/infeasibility. Options that are technically infeasible for the intended applicatio n are eliminated from further review.

Step 3. Evaluate Control Effectiveness of Remaining Control Technologies. Step 3 of the BART determination involves ev aluating the control effectiveness of all the technically feasible control altern atives identified in Step 2 for the pollutant and emissions under review. Control effectiveness is generally expre ssed 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) 

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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 eval uations 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 do llar per ton of pollutant removed basis. Annual emissions using a particular control device are subtracted from baseline emissions to calculate tons of pollutant controlled per year. Annual co sts 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 stringe nt 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 significan t or unusual energy pena lties or benefits. Two forms of energy impacts associated with a cont rol 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 an d/or reliability of equipment. This reduction would result in decreased electricity availabl e to the power grid and/or increased fuel consumption due to use of less efficien t electrical and steam generation methods.

Non-Air Quality Environmental Impact Analysis The primary purpose of the environmental impact an alysis is to assess collateral environmental impacts due to control of the regulated polluta nt in question. Environmental impacts may

include solid or hazardous waste generation, discharges of pollute d water from a control device, increased water consumption, and land use im pacts from waste disposal. Impact analyses conducted in step 4 should take into considerati on 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 us e of a particular control technology. CALPUFF modeling, or other appropriate dispersion modeli ng, should be used to determine the visibility improvement expected from the potential BART control technology applied to the source. Modeling should be conducted for SO 2 , NO X , and direct PM emissions (PM 2.5 and/or PM 10 ).PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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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, AN D 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 us age for all three boilers to natural gas, SO 2 and PM 10 emissions are minimal. Also, there are no SO 2 or PM 10 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 NO X 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 NO X Controls None None FGR Existing SO 2 Controls None None None Existing PM 10 Controls None None None

Baseline emissions from Seminole Units 1, 2, a nd 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, Appe ndix Y, Part III, emission estimates used in the modeling analysis to determine visibility impairment impacts shoul d reflect steady-state operating conditions during periods of high capacity utilization. Therefore, baseline emissions (lb/hr) represent the highest 24-hour block em issions 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

NO X 1,859 0.339 1,940 0.354 1,204 0.219PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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Presumptive BART Emission Rates In the final Regional Haze Rule, EPA established presumptive BART emission limits for NO X 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 cap acity 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 al so 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 ma ke significant cost-effective reductions in NO X emissions using currently available combustion c ontrol technologies, for a number of units the use of combustion controls did not appear to be co st effective. As a result, EPA determined that it would be inappropriate to establish a genera l presumption regarding likely BART limits for oil- and natural gas-fired units.

BART DETERMINATION FOR NITROGEN OXIDES (NO X )
The formation of NO X is determined by the interaction of chemical and physical processes occurring primarily within the flame zone of the boiler. There are two principal forms of NO X designated as “thermal” NO X and “fuel” NO X . The principal mechanism of NO X formation in natural gas combustion is thermal NO X . Thermal NO X formation is the result of oxidation of atmospheric nitrogen contained in the inlet gas in the high-temperature, post-flame region of the

combustion zone. Fuel NO X is formed by the oxidation of nitrogen in the fuel. Due to the characteristically low fuel nitr ogen content of natural gas, NO X formation through the fuel NO X mechanism is insignificant.

The major factors influencing thermal NO X formation are temperature, the concentration of combustion gases (primarily nitrogen and oxygen) in the inlet air, and re sidence time within the combustion zone. As these three factors increase, NO X 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 NO X formation.

Step 1: Identify Potentially Feasible NO X Control Options Potentially available control op tions were identified based on a comprehensive review of

available information. NO X control technologies with potential application to Seminole Units 1, 2, and 3 are listed below.

List of Potential NO X Control Options 1) Combustion Controls i) Low NO X Burners & Overfire Air (LNB/OFA) ii) FGRPERMIT MEMORANDUM 2003-400-TVR (M-1) 

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2) Post-Combustion Controls i) Selective Non-Cataly tic 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 NO X Scrubbing

Step 2: Technical Feasibility of Potential Control Options

NO X control technologies can be divided into two general categor ies: combustion controls and post combustion controls. Combustion controls reduce the amount of NO X that is generated in

the boiler. Post-combustion controls remove NO X from the boiler exhaust gas. The technical feasibility of each potentially applicable NO X control technology, with respect to natural-gas fired boilers, is evaluated below.

Combustion Controls
The rate of NO X formation in the combustion zone is a function of free oxygen, peak flame temperature and residence time. Combustion techniques designed to minimize the formation of

NO X will minimize one or more of these variable s. Combustion control options that may be applicable to Seminole bo ilers are described below.

Low NO X Burners and Overfire Air (LNB/OFA)

LNB limit NO X formation by controlling both the stoichiometric and temperature profiles of the combustion flame in each burner flame envelope. This control is achieved with design features that regulate the aerodynamic distribution and mixing of the fuel and air, yielding reduced oxygen (O 2 ) in the primary combustion zone, reduced flame temperature and reduced residence time at peak combustion temperatures. The co mbination of these techniques produces lower

NO X emissions during the combustion process.

In the OFA process, the injection of air into the fi ring 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 leve l. Staging of the combustion air reduces NO X formation by two mechanisms. First, staged combustion results in a cooler flame, and second the staged combustion results in less oxygen reactin g 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 NO X concentration and boiler load, controlled emissi ons would vary between approximately 135 to 250 ppmvd @ 3% O 2 (0.16 to 0.30 lb/MMBTU).PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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Seminole Units 1, 2, and 3 do not operate as base load units. In general, all three units have historically operated as “peaking units” respondi ng to increased demand for electricity. As peaking units, operating loads and boiler heat inpu ts 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 typical ly operate at approximately 40% load.

Although LNB/OFA controls are a technically feas ible 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 NO X control, becomes more difficult under these operating scenarios. Baseline NO X emission rates are lowest at heat inputs in the range of approximately 1,500 to 2,100 MMBTUH. NO X emissions tend to increase at lower and higher heat inputs. Finally, the mechanisms used to reduce NO X formation (e.g., cooler flame and

reduced O 2 availability) also tend to increase the formation and emission of CO and VOC. Combustion control systems on gas-fired boi lers must be designed to minimize NO X formation while keeping CO and VOC emission rates within acceptable limits.

Based on information available from burner contro l vendors and engineering judgment, it is expected that combustion controls, including LN B and OFA, on the wall-fired boilers can be designed to achieve an average control effici ency 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 NO X emissions from Seminole Units 1, 2, and 3 would average:

• Seminole Unit 1: 0.254 lb/MMBTU (~ 210 ppmvd @ 3% O 2 )

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

• Seminole Unit 3: 0.164 lb/MMBTU (~ 135 ppmvd @ 3% O 2 )

Flue Gas Recirculation (FGR)

FGR controls NO X by recycling a portion of the flue gas back into the primary combustion zone. The recycled air lowers NO X emissions by two mechanisms: (1) the recycled gas, consisting of products which are inert during combustion, lo wers 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 av ailable 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) 

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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 fo rced draft (FD) fan. At the inlet of the FD fan, recycled flue gas is mixed with incomi ng combustion air and introduced into the windbox. With this design, the limitation resides in the co nstruction 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 percen tage 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 expe cted to achieve an additional 15% reduction (compared to LNB/OFA only), or approximatel y 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 NO X 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% O 2 )

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

• Seminole Unit 3: 0.164 lb/MMBTU (~ 135 ppmvd @ 3% O 2 )

Post-Combustion Controls
Post-combustion NO X control systems with potential applic ation to Seminole Units 1, 2, and 3

are discussed below.

Selective Non-Catalytic Reduction Selective non-catalytic reducti on (SNCR) involves the direct injection of ammonia (NH 3 ) or urea (CO(NH 2 ) 2 ) at high flue gas temperatures (approximately 1600°F - 1900°F). The NH 3 or urea reacts with NO X in the flue gas to produce N 2 and water as shown in the equations below.

(NH 2 ) 2 CO + 2NO + 1⁄2O 2 → 2H 2 O + CO 2 + 2N 2 2NH 3 + 2NO + 1⁄2O 2 → 2N 2 + 3H 2 O

Flue gas temperature at the point of reagent injection can greatly affect NO X removal efficiencies and the quantity of NH 3 or urea that will pass through the SNCR unreacted (referred to as NH 3 slip). In general, SNCR reacti ons are effective in the range of 1,700 °F. At temperatures below the desired operating range, the NO X reduction reactions diminish and unreacted NH 3 emissions increase. Above the desired temperature range, NH 3 is oxidized to NO X resulting in low NO X reduction efficiencies.

Mixing of the reactant and flue gas within the r eaction zone is also an important factor in SNCR performance. In large boilers, the physical di stance 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 resi dence time of the reagent and flue gas in thatPERMIT 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-NO X ratio, and fuel sulfur

content.

SNCR control systems have been installed as retrofit NO X control systems on small and medium sized coal- and gas-fired boilers; however, SNCR ha s not been used on larg e boilers (i.e., boilers larger than approximately 300 MW). Large boile rs, including Seminole Units 1, 2, and 3, would present several design problems making it diffic ult to ensure that the reagent (urea or NH 3 ) would be injected at the optimum fuel gas temp erature and that there w ould be adequate mixing

and residence time.

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

NH 3 injection points capable of achieving adequate mixing within the required temperature zone. Higher NH 3 injection rates would be needed to achi eve adequate mixing. This design would tend to result in relatively high levels of unreacted NH 3 in the flue gas (NH 3 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 quan tity 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 severa l currently unresolved technical difficulties with applying SNCR to large boilers (i ncluding the physical size of the boiler, and adequate reactant/flue gas mixing within the re quired temperature range). SNCR control would even be more difficult to design for boilers ope rating 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, NO X control effectiveness would be marginal, and, depending on boiler exit temperatures, could ac tually result in additional NO X formation.

Because SNCR has not been designe d for, or demonstrated on, la rge boilers, and because there remains several currently unresolved technical difficulties with applying SNCR to a large gasfired boiler (especially boilers that typically op erate as peaking units), it was determined that

SNCR is not an available NO X 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 NH 3 into boiler flue gas in the presence of a catalyst to reduce NO X to N2 and water. Anhydrous NH 3 injection systems may be used, or

NH 3 may be generated on-site from a urea f eedstock. The overall SCR reactions are:

4NH 3 + 4NO + O 2 → 4N 2 + 6H 2 O

8NH 3 + 4NO 2 + 2O 2 → 6N 2 + 12H 2 O

The performance of an SCR system is influe nced by several factors including flue gas temperature, SCR inlet NO X level, the catalyst surface area, volume and age of the catalyst, and

the amount of NH 3 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 NO X 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 temperatur e, the catalyst will sinter and thus deactivate rapidly. Another factor affecting SCR performanc e is the condition of the catalyst material. As the catalyst degrades over time or is damaged, NO X removal decreases.

SCR has been installed as NO X control technology on existing gas-fired boilers. Based on

emissions data available from the EPA Electr onic Reporting website, large gas-fired boilers (with heat inputs above approximately 1,000 MMBTUH) have achieved actual long-term average NO X emission rates in the range of approximately 0.02 to 0.05 lb/MMBTU. Several design and operating variables w ill influence the performance of the SCR system, including the volume, age and surface area of the cataly st (e.g., catalyst layers), uncontrolled NO X 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 ga s flow rate, and flue gas temperature.

Based on emission rates achieved in practic e at existing gas-fired units, and taking into consideration long-term operation of an SCR co ntrol system (including catalyst plugging and deactivation) and the fact that the Seminole bo ilers typically operate as peaking units, it is anticipated that SCR could achieve a controlled NO X 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 NO X concentration in the flue gas of approximately 33 ppmvd @ 3%

O 2

.

Innovative NO X Control Technologies

A number of innovative NO X control systems, including multi-pollutant control systems, were identified as potential retrofit cont rol technologies during the re view of available documents.

Innovative NO X control technologies with potential ap plication to the BART study include boosted over-fire air (e.g., MobotecUSA’s ROFA® system), advanced SNCR control systems (e.g., MobotecUSA’s Rotamix® system), Enviroscrub’s multi-pollutant PahlmanTM process, and

wet NO X scrubbing systems.

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 syst em 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 NO X 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 NO X 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 NO X emissions. The turbulent mixing created by the ROFA system is designed to improve distribution of the NH 3 /urea reagent and may reduce the NH 3 /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 demons trated 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 te chnology 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 NO X 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 c oupled with the ROFA rotating injection nozzle design. The technical limitations previously discu ssed, including the physical size of the boiler, inadequate NH 3 /NO X 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 diff iculties. Therefore, like other SNCR control systems, the Rotamix system is determined not to be available for Semi nole Units 1, 2, and 3 a nd will not be evaluated

further in the BART determination.

Pahlman Multi-Pollutant Control Process The PahlmanTM Process is a patented dry-mode mu lti-pollutant control system. The process uses a sorbent composed of oxides of manganese (the PahlmaniteTM sorbent) to remove NO X and SO 2 from the flue gas. Manganese compounds are sol uble 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 dissociate d and the Mn+2 to be oxidized again to Mn+4 and regenerated. In general, the liquid metal oxide Pahlmanite sorbent is injected as the flue gas enters a spray dryer. The sorbent dries as it passes through the spray dryer and is collected downstream at the fabric filter baghouse. NO X and SO 2 will react with the sorbent to form manganese sulfates and nitrates as the flue gas passes through the filter cake.

The filter cake is pulsed off-line into a wet rege neration 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 granul ar fertilizer by-products. To date, bench- and pilot-scale testing have been conducted to eval uate the technology on utility-sized boilers. ThePERMIT 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 devel opment and testing. The process is an emerging multi-pollutant control, and there is limited in formation available to evaluate its technical feasibility and long-term effectiveness on a large na tural gas-fired boiler. It is likely that OG&E would be required to conduct extensive design engi neering 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 co ntrol technique. Therefore, at this time the

Pahlman Process is not considered an available NO X control system for Seminole Units 1, 2, and 3 and will not be further evaluated in the BART Analysis.

Wet NO X Scrubbing Systems Wet scrubbing systems have been used to remove NO X 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 NO 2 to N 2 O 5 . This highly oxidized species

of NO X is very soluble and rapidly reacts with wate r to form nitric acid. The conversion of NO X to nitric acid occurs as the N 2 O 5 contacts liquid sprays in the scrubber.

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

boilers. The NEET Database classifies wet sc rubbing systems as commercially established for petroleum refining and oil/natural gas produc tion. 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 NO X scrubbing systems are not considered available or technically feasible retrofit control systems for Se minole Units 1, 2, and 3 and will not be further evaluated in this BART Analysis.

Technical Feasibility of Potential NO X Control Technologies

In Service On

Control Technology NO X Control Efficiency Gas-Fired

Boilers? Other

Sources? Technically

Feasible?

LNB/OFA 25% reduction Yes X Yes Yes

LNB/OFA+FGR 40% reduction Yes X Yes Yes 1

SNCR NA Yes X No No 2

SCR 0.04 lb/MMBTU Yes X Yes Yes 3

ROFA NA Yes X Yes Yes 4
Rotamix (SNCR) NA Yes X Yes Yes 5 No 5

Pahlman Process NA X No No No 6

Wet NO X Scrubbing NA X No Yes Yes 7 No 7

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 &

p aste issue.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 18

associated with applying SNCR on a large gas-fired boil er. 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 NH 3 injection rate, site-specific flue gas
characteristics, NH 3 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

NO X 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 NO X 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 NO X scrubbing systems are not available or technically feasible for Seminole Units 1, 2, and 3.

Step 3: Rank the Technically Feasible NO X Control Options by Effectiveness

Technically Feasible NO X Control Technologies

Seminole Unit 1 Seminole Unit 2 Seminole Unit 3

NO X Emission Rate NO X Emission Rate NO X 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 NA 1

Baseline 2 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 NO X emissions used in this BART analysis were based on the highest 24-hour block emissions reported by each unit during the baseline period. Baseline NO X 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 ef fectiveness 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 NO X Control Technologies

NO X Control Technologies – Economic Evaluation

The most effective NO X retrofit control system, in terms of reduced emissions, th at is considered to be technically feasible for Seminole Unit s 1, 2, and 3 include s combustion controls (LNB/OFA) and post-combustion SCR. This comb ination of controls should be capable of achieving the lowest controlled NO X emission rate on an on-going long-term basis. The effectiveness of the SCR system is dependent on se veral site-specific system variables, including the size of the SCR, catalyst layers, NH 3 /NO X stoichiometric ratio, NH 3 slip, and catalyst deactivation rate. Furthermore, SCR control may not be as effective on boilers that operate as peaking units, as NO X 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 NO X emission rate of 0.04 lb/MMBTU (30-day average). The second most effective

NO X retrofit control system that is considered tec hnically 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 effici ency of approximately 40% from baseline on gasfired units that operate at varying loads and are typically operated as peaking units. The third

most effective NO X retrofit control system considered tec hnically 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 estimat es used in the modeling analysis to determine visibility impairment impacts should reflect st eady-state operating conditions during periods of high capacity utilization. Therefore, projecte d emission rates (lb/hr) were calculated based on the expected controlled emission rate (lb/MMB TU) achievable on a 30-day rolling average and heat input to the boiler at full load.

Because Seminole Units 1, 2, and 3 have histor ically operated as peak ing units, cost impact evaluations, including total annual costs and tota l annual emission reductions, were calculated using a more representative annua l capacity factor. From 20 02 through 2005, annual capacities for each unit were typically in the range of approximately 25% to 30%. Evaluating economic impacts of potential retrofit control technologi es using a capacity of 100% would not be representative of actual operations. Using a mo re representative capacity factor would more accurately reflect actual econom ic impacts. For this evalua tion, annual operating costs and

annual emission reductions were calculated assu ming an annual capacity factor of 50%.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 20

Seminole Units 1, 2, and 3 Annua l Capacity Factor Estimates Unit Heat Input 2002-2005 Potential Heat Input at 100% Capacity

Factor 1 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 da ta sources. In genera l, 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 incl ude 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 ea ch control system. Fixed O&M costs include operating labor, maintenance labor, maintenance ma terial, and administrative labor. Variable O&M costs include the cost of consumables, including reagent (e.g., NH 3 ), byproduct management, water consumption, and auxilia ry power requirements. Auxiliary power requirements reflect the additional power requi rements associated with operation of the new control technology, including operation of any ne w fans as well as the power requirements for pumps, reagent handling, and by-product handling.

Summarized below are the expected controlled NO X emission rates, and annual NO X mass emissions (based on 50% capacity factor), associ ated with each technically feasible retrofit technology. A capacity factor of 50% was us ed because it represents a conservatively high annual capacity for each unit based on historical ca pacity 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. Fi nally, the average annual cost effectiveness and

incremental annual cost effectiveness for each NO X control system. A detailed summary of the

cost estimates used in this BART dete rmination was included in application.

Seminole Generating Station - Annual NO X Emissions

NO X Emission Rate (lb/MMBTU) Maximum Annual

NO X 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

Formatted: Superscript

Formatted: Font: 10 ptPERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 21

Seminole Generating Station - NO X Emission Control System Cost Summary (per boiler) 1

Total Capital

Investment 3 Total Capital

Investment Annual Capital Recovery Cost Annual Operating Costs Total Annual

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

LNB/OFA+SCR 2 $104,230,20

0 $221.8 $8,943,000 $8,175,600 $17,118,600

LNB/OFA+FGR 2 $16,977,200 $36.1 $1,456,700 $1,190,900 $2,647,600 LNB/OFA $9,432,200 $20.1 $809,300 $588,600 $1,397,900

1 Capital costs are similar for each unit, however, there are no FGR retrofit costs associated with Unit 3. A summary of the capital cost estimates for each unit is provided in Attachment A 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 - NO X Emission Control System Cost Effectiveness (total)

Total Annual Cost 1 Annual Emission

Reduction Average Cost

Effectiveness Incremental Cost

Effectiveness 2

Control Technology Tot al Annual

Cost 1 ($/year) (TPY) ($/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 th e SCR system is compared to costs/emissions associated

with LNB/OFA+FGR controls.

The average annual cost effectiveness of NO X 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

NO X 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 NO X 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 approxim ately $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 u pdated costs once

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

## DRAFT Page 22

As part of the BART rulemaking, EPA established presumptive NO X 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 base d 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 co st 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 cont rols, 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 th e cost effectiveness of NO X 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.

NO X Control Technologies – Environmental Impacts Combustion modifications designed to decrease NO X formation (lower temperature and less oxygen availability) also tend to increase th e formation and emission of CO and VOC. Therefore, the combustion controls must be designed to reduce the formation of NO X while maintaining CO and VOC formation at an acceptable level. Other than the NO X /CO-VOC tradeoff, there are no environmental issues associat ed with using combustion controls to reduce NO X emissions.

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

maintain low NO X emissions, some excess NH 3 will pass through the SCR. NH 3 slip will

increase with lower NO X emission limits, and will also tend to increase as the catalyst becomes

deactivated. NH 3 slip from an SCR designed to achieve a controlled NO X 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,

NH 3 slip can increase; however, the NH 3 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 NH 3 on-site increases the risks associated with an accidental NH 3 release. Depending on the type, concentration, and quantity of NH 3 used, NH 3 storage/handling will be subject to regulation as a haza rdous substance under CERCLA, Section 313 of the Emergency Planning and Community Right-to-Know Act, Sec tion 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 NH 3 handling is to design the ammoni a handling system as a urea-to-NH 3 conversion system. Urea ((NH 2 ) 2 CO) can be delivered to the station as an aqueous solution or as a dry solid, and urea storage/handling does not crea te the process safety c oncerns associated with handling anhydrous NH 3

.

Seminole Generating Station Summary of NO X 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 NH 3 emissions; &

NH 3 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 effectiv eness of potentially feasible NO X retrofit control technologies,

NO X emissions were modeled at the projected po st-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 determin e visibility impairment impacts reflect steadystate operating conditions during periods of high ca pacity utilization. Post-retrofit emission rates (average lb/hr rate on a 24-hour basis) were calculated using the expe cted controlled emission rate achievable on a 30-day rolling average mu ltiplied 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

NO X Visibility Assessment / Visibility Improvement 1

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 1.0 4 1.

073 -- 0.39 0.

351 -- 0.33 6
-- 0.69 0.

588 --

LNB/OFA 0.81 3 2 2 24 % 0.26 2 33 25 % 0.25 1 2 4 25 % 0.4 4 0.

438 3 6 26 %

LNB/OFA+FGR 0.67 0.

707 17 13 % 0.25 0.

221 4 16 % 0.21 8 16 13 % 0.44 0.

370 0 16 %

LNB/OFA+SCR 0.15 4 78% 0.04 4 84 80 % 0.04 4 8 1 80 % 0.07 4 84 80 %

1 Δ -dv values included in this table represent the modeled visibility impacts only from NO X emissions associated

with each NO X retrofit control scenario.

Combustion controls (LNB/OFA) reduce modeled visibility impacts at each Class I Area by approximately 2 6 25 %. Combustion controls plus FGR redu ce modeled visibility impacts by an

additional 4 13 - 16% at each Class I Area. SCR cont rol 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-Gla des, 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 Mounta ins 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 increm ental 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 cont rols 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.

NO X Average Visibility Cost Impact Evaluation 1

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 Determ ination 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 NO X emissions associated

with each NO X retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains)

was used for the cost effectiveness evaluation.

NO X 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 % Δ

dv* (dv) ($/dv/yr)

Baseline -- -- 1.073 -- -- LNB/OFA $4,199,000 -- 0.813 -- -- LNB/OFA+FGR $6,698,400 $2,499,400 0.707 0.106 $23.58

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

MM/dv

1 Δ -dv values included in this table represent the modeled visibility impacts only from NO X emissions associated

with each NO X retrofit control scenario. Visibility impairment at the nearest Class I Area (Wichita Mountains)

was used for the cost effectiveness evaluation.

Proposed BART for NO X 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 cont rol technologies represents the most effective technically and economically feasible NO X retrofit technology for the existing boilers. The combination of proposed combustion controls is expected to reduce NO X emissions by 40% from existing baseline emissions under all normal boiler operating conditio ns, 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 NO X 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 desi gned with FGR: therefore, emissions from Un it 3 under the FGR control option only inc lude 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 combus tion controls as BART on the gas-fired units at Seminole. The addition of an SCR control system could provide incremental NO X reductions; however, costs associated with SCR control are significant, and incremental visibility improvements are limited. The average cost effe ctiveness 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 NO X control at similar sources. In the BART rule, EPA concluded that

the cost of controls to meet the BART NO X presumptive level on large coal-fired EGUs “in most cases range from just over $100 to $1,000 pe r ton” (see, 70 FR 39135). The average cost Formatted: Font: 8 pt, Complex Script Font: 8 pt

Formatted: No bullets or numberingPERMIT 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 NO X 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 asso ciated with SCR controls are less than 0.3 Δ

dv at all Class I Areas, except the Wichita Mo untains 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 NO X 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 EP A 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 defi nes 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-spe cific 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 s ubject to BART. Rather, BART-eligible sources are subject-to-BART if the sources are “reasonably anticipated to ca use 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 determ ination 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 th at 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 RP O, the Central States Regional Air Planning (CENRAP) organization developed BART Mode ling Guidelines (December 15, 2005). The intent of the guidelines is to assist CENRAP st ates and source operators in the development of statewide and source-specific modeling protocols.

The following summarizes the modeling methods a nd 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 dete rmine appropriate controls for OG&E’s BARTeligible sources at the Seminole Generating Statio n 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 combinati on of emissions controls that would reduce the impact of the Seminole Generating Station to a de gree that the 98th percentile of the visibility impact predicted by the modeling due to all of the BART eligible sour ces at the station was below EPA’s recommended visibility contribution threshold of 0.5 Δ dv.

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 Guid elines, 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 mo del that generates hourly three-dimensional meteorological fields such as wind and temperat ure. CALPUFF simulates the non-steady state transport, dispersion, and chemical transformation of air pollutants emitted from a source in “puffs.” CALPUFF calculates hourly concentrati ons of visibility affecting pollutants at each specified receptor in a modeling domain. CALP OST 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 syst em 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 mete orological grid is the system of grid points at which meteorological fields are develo ped with CALMET. The computational grid determines the computational area for a CALPUF F run. Puffs are advected and tracked only while within the computational grid. The meteor ological 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 leas t 50 km in all directions beyond the Seminole Generating Station and the Class I Areas of in terest. 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 4,000PERMIT 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 observa tion data will be relied upon. The vertical dimension of the domain was divided into 10 laye rs. 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 characte rize 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 charac teristics 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 St ates 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 La nd 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 fo rmat 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 pr ogram 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 th at compiles meteorological data from raw observations of surface and upper air conditions , precipitation measurements, mesoscale model output, and geophysical paramete rs 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, prec ipitation data, and mesoscale model output to develop the meteorological fields. Upper air ob servations 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 5 th 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 th e data listed above. As the contractor to CENRAP for developing the meteorological da ta 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 extracti on program. The three subsets covered the northern, central, and southern portions of CE NRAP. 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 e nd of each file to account for the shift in time zones from the Greenwich Mean Time (GMT) prep ared 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 th e 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 Geophys ics MM5 data was not used directly. Instead the data files were modified by adding eight additio nal 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 ar e observed hourly at surface stations include wind speed and direction, temperature, cl oud cover and ceiling, relative humidity, and precipitation type. The stations were selected from the available data inventory to optimize spatial coverage and repr esentation of the domain. Data from the stations was processed for use in CALMET using the SMERGE program.

Missing surface data was filled us ing procedures recommended by EPA. Missing data periods of 5 hours or less were replaced using these proced ures. 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 ov erlapping areas of influence would allow data

from an alternate station to be used.

The use of multiple stations for meteorologic al observations in CALMET/CALPUFF provides a substantial enhancement over the steady-state treatment of observations from a single meteorological station. Surface data were extrac ted from the surface stations. Raw observations

from these stations were obtained from the Na tional Climatic Data Center (NCDC). The data was quality assured and then merged using th e SMERGE pre-processor to create a single

assimilated data file of surface obs ervations for each year analyzed.

Precipitation Data

The effects of chemical tr ansformation 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 analys is. The stations were selected from the available data inventory to optimize spatial cove rage 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 OBSPERMIT 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 1 st guess surface field (km) IWAQM Phase 2 Study

R2 1 100 Weighting of 1 st 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 pred ict hourly concentration impacts.

Source Emissions Baseline (pre-BART) emission data was base d 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 estab lish baseline emissions. The units at the Seminole Generating Station operate primarily on natural ga s 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 prof ile (i.e., peaking nature) of these units in the CALPUFF model, a variable emission rate da ta 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

SO 2 H 2 SO 4 NO X PM 10 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

N ovembe r 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

N ovembe r 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

N ovembe r 2.55 0.019 808 0.22

December 2.06 0.032 878 0.26PERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 35

Emission estimates for various control scenario s were developed by Sargent and Lundy. Since the units at the Seminole Station are natural-gas fired, NO X control technologies were primarily evaluated in this analysis. OG&E elected to ev aluate cost effectiveness on a facility-wide basis (as opposed to a unit-by-unit basis) and will insta ll 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, PM 10 emissions from natural gas combustion consists of primarily (75%) fine particulate matter (PM F , considered PM <2.5 ) and (25%) coarse particulate matter (PM C , considered PM 2.5-10 ).

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 SO 2 and NO X to sulfates (SO 4 ) and nitrates (NO 3 ). CALPUFF can use either a single background value representative of an area or hourly ozone 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 simulatio n for the 2002 base year. Modeling was conducted using a conservative background concen tration 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 de veloping background conc entrations from the most recent CENRAP CMAQ or CAMx simulation for the 2002 base year. Since the CMAQ/CAMx modeled and observed monthly aver aged concentrations exhibit wide spatial variability and the data is not readily availabl e, a conservative background concentration of 3 ppb was used. This is the default backgro und 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 th e 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 duri ng 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

NH 3 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 source s 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 reconstr ucting light extinction (as opposed to the new equation for reconstructing light extinct ion recommended by the IMPROVE Steering Committee) was used. The background extinction coefficient b ext , background is affected by various chemical species and the Rayleigh scatte ring phenomenon. The light extinction equation is provided below.

b ext = 3*f(RH)*[(NH 4 ) 2 SO 4 ] + 3*f(RH)*[NH 4 NO 3 ] + 4*[OC] + l*[PM F ] + 0.6*[PM C ] + 10*[EC] + b Ray

The algorithm was used to calculate the daily light extinction attributable to the Seminole Station's BART eligible sources and light extinc tion attributable to a natural background. The change in deciviews based on the source and ba ckground light extinctions was evaluated using the equation below.

∆ dv = 1 0 *ln[(b ext, background + b ext, source )/b ext, 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 re lative 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 Na tural Background Levels

Class I Area Region SO 4 NO 3 OC EC Soil Coarse Mass Caney Creek WEST 0.12 0.10 0.47 0.02 0.50 3.00

Hercules-Glades EAST 0.23 0.10 1.40 0.02 0.50 3.00 Upper Buffalo EAST 0.23 0.10 1.40 0.02 0.50 3.00

Wichita Mountains WEST 0.12 0.10 0.47 0.02 0.50 3.00PERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 38

Evaluating Visibility Results Trinity compared A 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 re gulations 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 justifie d in the application a nd listed in OAC 252:100- 8, Appendix I, are listed below. Recordkeeping fo r activities indicated with “*” is listed in the Specific Conditions.

* Stationary reciprocating engine s 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 ra rely-used 20,150kW emergency generator.

* Emissions from fuel storage/dispensing equi pment 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 thatare denser than air. Cold degreasing occurs in the maintenance shop.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 39

Hazardous waste and haza rdous materials drum staging areas. The facility stores used oil and used solvent in the machine shop and in th e basement between Units 1 and 2. Used antifreeze is stored in the garage building.

Sanitary sewage collection and treatment fac ilities other than incinerators and Publicly Owned Treatment Works (POTW). Stacks or ve nts for sanitary sewer plumbing traps are also included (i.e., lift station). The facilit y 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, thinne rs, clean-up solvents, and degreasing solvents at any one emissions unit. The facility conducts surface coatin g and degreasing operations in the maintenance shop. Maintenance is a listed “trivial activity,” therefore, no recordkeeping will be required.

Exhaust systems for chemical, pa int, and/or solvent storage rooms or cabinets, including hazardous waste satellite (accumula tion) areas. The facility maintains exhaust systems for the environmental laboratory.

Hand wiping and spraying of solvents from contai ners with less than 1 liter capacity used for spot cleaning and/or degreasi ng 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 applic able provisions of Title 40 of the Code of Federal Regulations. These requi rements are addressed in the “F ederal Regulations” section.

OAC 252:100-3 (Air Quality Standards and Increments) [Applicable] Primary Standards are in Appendix E and Seconda ry Standards are in Appendix F of the Air Pollution Control Rules. At this time, all of Ok lahoma is in attainment of these standards.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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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 operati ng fees based upon total annual emissions of regulated pollutants. Emission inventories have be en 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 resu lt in emissions not authorized in the permit and which exceed the “Insignificant Activities” or “Trivial Activities” th resholds 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 ta ken 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 emis sions 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 exce ss 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 th is 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 mate rial is prohibited except as authorized in the specific examples and under the c onditions listed in this subchapter.

OAC 252:100-19 (Particulate Matter) [Applicable] This subchapter specifies limits for fuel-burni ng equipment particulate emissions based on heat input capacity. Emissions limitations and an ticipated 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 a llowed 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 natura l 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 observa tion requirements when burning fuel oil if no visible emissions are detect ed 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 su ch 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 SO 2 . 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 SO 2 impacts are in compliance with the limitations of Subchapter 31.

SO 2 Ambient Impacts Averaging Time SC 31 Limits, μg/m 3 Maximum Impacts, μg/m 3

1-hour 1,200 792

3-hours 650 318

24-hours 130 100

Annual 80 4PERMIT 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 NO X 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 Decem ber 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, whic h is subject to the submerged fill requirement. The fuel oil storage tanks, emergency generator fu el 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 equa l 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 ta nks 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 coa tings 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 ope rated 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, mate rial 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. Si nce 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, monitori ng or recordkeeping activity conduc ted 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 mu st be conducted by methods approve d 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 Refere nce Method stack tests. Emissions and other data required to demonstrat e 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 pe rmit requirement. Data from any required testing or monitoring not conduc ted 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 re levant 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 Faci lity 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 expa nsion must be evaluated in the context of PSD significance levels (100 TPY CO, 40 TPY NO

x , 40 TPY SO 2 , 40 TPY VOC, 25 TPY PM, 15

TPY PM 10 , 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 signific ant 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 limit ed to furnaces or boilers. Subpart Da , Electric Utility Steam Generating Units. This subpart is a pplicable 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 Septem ber 18, 1978 and are not subject to this subpart. Subpart Db , Industrial-Commercial-Institutional Stea m Generating Units. This subpart affects steam generating units which were constructed, re constructed, 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 construc ted 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 cons tructed 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 comme nce 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 affe cts 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 modifica tion 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, reconstr uction, 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 subpar t 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 po llutants: arsenic, asbestos, beryllium, benzene, mercury, coke oven emissions, ra dionuclides or vinyl chloride.

NESHAP, 40 CFR Part 63 [Subp art 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 sour ces 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 ch romium-based water treatment chemicals. Subpart YYYY , Stationary Combustion Turbines. This subpart affects any existing, new, or reconstructed stationary combustion turbine loca ted 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 an d process heaters (< 10 MMBTUH heat rating) were not subject to any standards, recordke eping, or notifications under Subpart DDDDD.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

## DRAFT Page 45

EPA is planning on issuing guidance (or a ru le) on what actions applicants and permitting authorities should take regarding MACT determinations under eith er Section112(g) or Section 112(j) for sources that were affected source s 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 MA CT 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 reopene d 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 ope rating permit, if it meets all of the following

criteria:

1. It is subject to an emission limit or standa rd for an applicable regulated air pollutant;

2. It uses a control device to achieve comp liance with the applicable emission limit or standard; and

3. It has potential emissions, prior to the cont rol 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 wh ich 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 devi ces 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 substa nce 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 (SO 2 Requirements) [Applicable]

SO 2 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 Se ptember 22, 1997, for all three boilers.

Stratospheric Ozone Protection, 40 CFR Pa rt 82 [Subparts A and F are Applicable] These standards require phase out of Class I & II substances, reduc tions of emissions of Class I

& II substances to the lowest achievable level in all use sectors, and ba nning use of nonessential products containing ozone-deple ting substances (Subparts A & C) ; control servicing of motor vehicle air conditioners (Subpart B); require Fede ral agencies to adopt procurement regulations which meet phase out requirements and which maxi mize the substitution of safe alternatives to Class I and Class II substances (Subpart D); requi re 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 id entify 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 subs tances 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 s ubstances is required by January 1, 2000 (January 1, 2002, for methyl ch loroform). 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, mainta ining, or repairing appliances except for motor vehicle air conditioners; persons disposin g 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 maintena nce, service, repair, or disp osal; § 82.158 for equipment used during the maintenance, service, repair, or dispos al of appliances; § 82.161 for certification by an approved technician certif ication 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 applianc es normally containing 50 or more pounds of refrigerant.PERMIT MEMORANDUM 2003-400-TVR (M-1) 

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SECTION X. COMPLIANCE

Tier Classification a nd 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 ap plicant has submitted an affidavit that they are not seeking a permit for land use or for any ope ration 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 fo r review in the Air Quality section of the DEQ Web page: http://www.deq.state.ok.us/

.

Inspection A full compliance evaluation inspection was con ducted on March 9, 2005. Mr. Jason Lipscomb of Air Quality who was accompanied by Ms. Me lody Martin, Staff Chemist, conducted the inspection. The facility was physically as descri bed 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 de scribed 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.

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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 conf ormity 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 requiremen ts. Continuing operations under this permit constitutes acceptance of, an d consent to, the conditions contained herein.

1. Points of emissions and emissions limita tions 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 obs ervations. If a daily visual observation is the method of choice, then an EPA Refe rence 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 owne r 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 S 2 -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. SO 2 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 ob served, operational status of the emission unit, observed results and conclusions, and any required Reference Method No. 9 results; or continuous opacity monitor resu lts if used instead of visual monitoring.

f. Sulfur content of fuels per 40 CFR Part 75.

5. No later than 30 days after each anniversar y date of the issuance of the original permit (June 21, 1999), the permittee shall submit to Air Qu ality Division of DEQ, with a copy to the US EPA, Region 6, a certification of complianc e 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 le ss than 39,894 gallons and a true vapor pressure less than 1.5 psia: capa city 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 dete rmining 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 NO X 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 Qua lity 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 th at 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 ar e 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 re lated legal action wh ichever is later

.

c. The permittee shall apply for and obtain a construction permit prior to modification of

the boilers . I i f 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 in cause 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 NO X to below the emission limits below:

i. Low-NO X 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-NO X burners, overfire air, and flue gas recirculati on) and establish procedures to ensure the controls are properly operated and maintained.

f. Within 60 days of achieving the maximu m production rate at which the affected facilities will be operated, afte r modification or installation of BART, not to exceed 180 days from initial start-up of the affect ed 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 emis sion limits establishe d in the construction permit shall not exceed the following emission limits:

EU ID# Point ID# NO X 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 5SPECIFIC 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 mo dification of the boilers, not to exceed 180 days from initial start-up, the permittee sh all 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 NO X , CO, and VOC testing on the boilers at 60% and 100% of the maximum capacity. NO X and CO testing shall also be

conducted at least one additional interm ediate point in the operating range. ii. Performance testing shall be conduc ted while the units are operating within 10% of the desired testing rates. A te sting 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 Carb on 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 Proc edures (Range and Sensitivity, Measurement System Performance Specification, and Measurement System Performance Test Procedures) shall be used in conducting Method 10. Method 20: Determination of Nitrog en Oxides and Oxygen Emissions from Stationary Gas Turbines.

Method 25/25A: Determination of N on-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 pe rmit (one day) in at least one newspaper of general circulation within the county where the facility is located. (In structions 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 fo r 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 ques tions, 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 ENVI RONMENTAL 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 la w, 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, excep t as Authorized under Section VIII of the

Standard Conditions.

_________________________________ _____ Division Director, Air Quality Division DateMAJOR 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 a pplicable federal, state, or loca l statutes, regulations, rules, or ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

C. The permittee shall comply with all conditio ns 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 reissuan ce, or modification, or for denial of a permit renewal application. All terms and cond itions 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). Th is 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 th is 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 environm ental 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 emergenc y 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, TEST ING, RECORDKEEPING & REPORTINGTITLE 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 sup port 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 ava ilable for inspection by regulatory personnel upon request. Support information includes all original strip-chart recordings for continuous monitoring instrumentation, and copies of all repo rts 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) mont h period, after the date of the issuance of the original Part 70 operating permit or alternative date as specifically identifi ed 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 pe rmit 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 duplic ative 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 lim itations 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, recordkeepin g or reporting requirement specified in this permit, monitoring and reporting may be requir ed 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 In ventory submitted in accordance with this permit shall be certified by a responsible offi cial. This certification shall be signed by a responsible official, and shall c ontain 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 prov isions of New Source Performance Standards (“NSPS”) under 40 CFR Part 60 or National Emi ssion Standards for Haza rdous Air PollutantsTITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 3

(“NESHAPs”) under 40 CFR Parts 61 and 63 shall ma intain a file of all measurements and other information required by the applic able general provisions and subp art(s). These records shall be maintained in a permanent file suitable for inspecti on, shall be retained for a period of at least five years as required by Paragraph A of this Se ction, 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 su bject to a schedule of compliance shall submit to the DEQ a progress report at least semi-annua lly. The progress reports shall contain dates for achieving the activities, milestones or complianc e required in the schedule of compliance and the dates when such activities, milestones or compli ance 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 correctiv e measures adopted. [OAC 252:100-8-6(c)(4)]

I. All testing must be conducted under th e direction of qualified personnel by methods approved by the Division Director. All tests sh all 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 em issions 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 conduc ted 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 (PM 10 ). NSPS may allow reporting of only particulate matter emissions caught in the f ilter (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 equipm ent 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. COMP LIANCE CERTIFICATIONS

A. No later than 30 days after each anniversar y date of the issuance of the original Part 70 operating permit or alternative date as specificall y identified in a subse quent 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 a nd conditions of this permit and of any other applicable requirements which have become ef fective since the issuance of this permit. [OAC 252:100-8-6(c)(5)(A), and (D)] B. The compliance certification shall describe th e operating permit term or condition that is the basis of the certification; the current complianc e status; whether compliance was continuous orTITLE 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 al so include such other facts as the permitting authority may require to determine th e compliance status of the source. [OAC 252:100-8-6(c)(5)(C)(i)-(v)]

C. The compliance certification shall contain a ce rtification by a responsibl e official as to the results of the required monitoring. This certific ation shall be signed by a responsible official, and shall contain the following language: “I ce rtify, based on information and belief formed after reasonable inquiry, the statements and info rmation 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 comp liance with all applicab le requirements. This

schedule shall include a schedule of remedial me asures, including an en forceable sequence of actions with milestones, leading to compliance with any applicable re quirements for which the emissions unit or stationary source is in non compliance. 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, exce pt 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 applicab le to the facility. Compliance with all new requirements shall

be certified in the next annual ce rtification. [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 alte rnate operating scenarios, emissions tr ading, 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 ap plicable 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 th at 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 availabl e 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 op erating 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 applicati on 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 provide d 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 fi rst 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 circumst ance, 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 c onvey 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 rele ase the permittee from any liability for damage to persons or property caused by or resulting fro m 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 specifie s 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 cl early 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, reopene d and reissued, or terminated for cause. Except as provided for minor permit modificati ons, the filing of a request by the permittee for a permit modification, revocation and reissuance, term ination, 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 th is 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 effe ctive 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 ch anges 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 othe r 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 duri ng 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 prac tices, 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 af ter the permittee first becomes aware of the exceedance. This notice shall contain a descrip tion of the emergency, the probable cause of the exceedance, any steps taken to mitigate em issions, and corrective actions taken. [OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)]

B. Any exceedance that poses an imminent and su bstantial 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 arisi ng from sudden and reasonably unforeseeable events beyond the control of the source, incl uding acts of God, wh ich situation requires immediate corrective action to restore normal opera tion, and that causes the source to exceed a technology-based emission limitation under th is permit, due to unavoidable increases in emissions attributable to the emergency. An em ergency 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 sha ll be demonstrated through properly signed, contemporaneous operating logs or other rele vant evidence that: [OAC 252:100-8-6 (e)(2)]

(1) an emergency occurred and the permittee ca n 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 emissi on 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 unde r this section shall be certified as required by Section III (Monitoring, Testing, Reco rdkeeping & 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 Se ction 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 e ither 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 po llutant (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 emi ssions 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 scenar io 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 em ission 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, whic h shall be a minimum of seven (7) days, or twenty four (24) hours for emergencies as define d 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 sh all 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 longe r applicable as a result of the change. The permit shield provided by this permit does not apply to any ch ange made pursuant to this paragraph. [OAC 252:100-8-6(f)(2)]

SECTION XIX. OTHER APPLICAB LE & 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 ma terial is prohibited except as authorized in the specific examples and under the cond itions 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 opa city 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 su ch 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 ofTITLE 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-fi red 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 (lis ted at Appendix B to Subpart A) include

HCFCs.

B. If the permittee performs a service on motor (fle et) 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 a ll 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 “M VAC” as used in Subpart B does not include the air-tight sealed refrigeration system used as refr igerated 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, se rvice, 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, repa ir, or disposal of appliances must beTITLE V PERMIT STANDARD CONDITIONS July 21, 2009 Page 11

certified by an approved technician certif ication 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 proc ess refrigeration equipment must comply with leak repair requirements pursuant to § 82.158; and (6) Owners/operators of appliances normally co ntaining 50 or more pounds of refrigerant must keep records of refrigerant purchased a nd added to such appliances pursuant to §

82.166.

SECTION XXI. TITLE V APPROVAL LANGUAGE

A. DEQ wishes to reduce the time and work associ ated 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 fr om 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 av ailable to the public when requirements from the construction permit are incorporated into the Title V permit. (2) A copy of the construction permit applicati on 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 th e 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 cons truction permit until any affected State and EPA have had an opportunity to review th e proposed permit, as provided by these permit conditions. (9) Any requirements of the constructio n permit may be reope ned 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 operati ng in substantial comp liance 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 certifica tions 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 us e, 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]