OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY AIR QUALITY DIVISION

MEMORANDUM July 9, 2010

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. 2005-037-TVR (M-1) Western Farmers Electric Cooperative Anadarko Power Plant (SIC 4911) NW/4 of Section 14, T7 N, R10W, Caddo County
Located 1 mile north of SH 62 and 7 th Street in Anadarko Latitude: 35.089° N; Longitude: 98.229° W

SECTION I. INTRODUCTION

Western Farmers Electric Cooperative (WFEC) ha s applied for a modification of their current Part 70 operating permit for the Anadarko Power Plan t. The facility is currently operating as authorized by Permit No. 2005-037-TVR, which was issued on July 11, 2005.

The proposed modification was submitted to addr ess the Best Available Retrofit Technology (BART) requirements contained in the regional haze program found in Title 40 Part 51, Subpart P, of the Clean Air Act and Oklahoma Administ rative Code (OAC) 252, Subchapter 8, Part 11. Facilities with affected equipmen t were required to either submit an application for a waiver or exemption from BART by December 1, 2006, or to submit a BART determination by March 30, 2007. However, facilities requir ed to submit a permit applicati on requesting enforceable limits to qualify for a waiver were gran ted until March 30, 2007, to submit an application. A facility can apply for a waiver if it can be demonstrat ed through modeling that the affected sources do not cause or contribute to visibility impairment in any mandatory Class I Federal area. These modeling thresholds are found in OAC 252:100-8-73. Facilities are required to be in compliance with any BART requirements within 5 years of EPA approval of the Oklahoma regional haze State Implementation Plan (SIP).PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 2

WFEC conducted a review of the impacts on Cl ass I areas by the affected sources at the
Anadarko Power Plant. This review indicated th at WFEC could control th eir affected equipment and apply enforceable limits in or der to assure the affected sources do not cause or contribute to visibility impairment in any mandatory Class I Federal area. WFEC submitted an application on March 26, 2007, to incorporate these emissions limits into their curr ent permit to be exempt from
BART. This modification will not only incorporate the requested emissions limits but will also update all rules and regulations.

SECTION II. FACILITY DESCRIPTION

Western Farmers Electric Cooperative (WFEC) ope rates the Anadarko Power Plant to generate wholesale electricity which is tr ansmitted over WFEC’s system. Th e electricity is sold in rural areas of approximately 3/4 of the state of Oklahoma. The facility consists of three natural gas fired high pressure boilers, three gas/oil fired combined cycle gas turbines, a fire pump diesel engine for emergency backup, and other insignifican t and trivial sources. The three boilers are backup units that only operate when it is feasib le, such as during peak demand. Two of the boilers that had been idle since 1984 were repl aced in 1999. There are also two simple cycle turbines located on-site permitted under a separate Part 70 operating permit which was issued to WFEC Genco, LLC., Permit No. 2000-273-TV.

The combined cycle units consists of three parallel lines of equi pment. Each line includes a gas/oil fired turbine and a condensing-type stea m turbine drive connected by tandem shafting to a single electrical generator. Exhaust gases from each turbine are used to heat separate waste heat steam generators (boilers). Exhaust gases from the steam generators then pass through separate stacks to the atmosphere.

The gas/oil fired turbines produce power in the form of electrical energy and supply preheated combustion gases to the heat recovery boilers. Each turbine draws in compressed ambient air which is used to ignite the gas/oil in th e combustion chamber and is expanded through the turbine driving the generator. The heat rec overy boilers then use an extended-fin tube construction to recover heat from the large volum es of exhaust gases. The condensate leaving the condenser hotwell is pumped into the three stage fin tube surface boiler.

There are three operating scenarios for the facility. For Scenario I, the boilers and turbines will be fueled with commercial-grade natural gas. Fo r Scenario II, the turbin es will be fueled with
fuel oil and the boilers will be fueled with natu ral gas. For Scenario III, the proposed BART emission limits have been incorporated and th e boilers and turbines will be fueled with commercial grade natural gas except during emerge ncies and testing for em ergency preparedness
when the turbines will be fired with very low sulfur fuel oil. Emission units (EUs) are arranged into Emission Unit Groups (EUGs) in the “Equipment” section.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 3

SECTION III. EQUIPMENT

EUG 1 Boilers
EU Manufacturer MMBTUH MW Serial # Const. Date

AN-UNIT1R Nebraska 223 15 A-3882 1998

AN-UNIT2R Nebraska 223 15 A-3648 1997

EUG 2 Grandfathered Boiler
EU Manufacturer MMBTUH MW Serial # Const. Date AN-UNIT3 Riley Stoker 531 44 3333 1958

EUG 3 Combined Cycle Gas Turbines
EU Manufacturer MMBTUH MW Serial # Const. Date

AN-UNIT4 General Electric 852 100 248851 1975

AN-UNIT5 General Electric 852 100 248852 1975

AN-UNIT6 General Electric 852 100 248853 1975

EUG 4 Internal Combustion Engine

EU Make/Model hp Serial # Const. Date AN-ENG1 Cummings NT-855-F 309 10531247 1975

EUG 5 Tanks

EU Point Contents Barrels Gallons Const. Date

Tanks T-1 Fuel Oil No. 2 443 18,600 1951

T-3 Fuel Oil No. 2 109,524 4,600,000 1975

T-4 Fuel Oil No. 2 109,524 4,600,000 1975 T-5 Unleaded Gasoline (UST) 238 10,000 1977 T-6 Unleaded Gasoline (UST) 238 10,000 1977 T-7 Diesel Fuel (UST) 286 12,000 1977

T-8 Condensate 298 12,500 1975

T-10 Lube Oil 71 3,000 1975

T-11 Mineral Oil 71 3,000 1975

T-12 Mineral Oil 71 3,000 1975PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 4

Stack Parameters

EU Height (feet) Diameter (feet) Flow (ACFM) Temperature ( ° F) AN-UNIT1R 51 4.4 60,405 390 AN-UNIT2R 51 4.4 60,405 390 AN-UNIT3 111 7.5 107,928 260 AN-UNIT4 80 14.9 872,590 325 AN-UNIT5 80 14.9 872,590 325 AN-UNIT6 80 14.9 872,590 325

SECTION IV. EMISSIONS

Potential emissions are listed in the emission tables and are based on c ontinuous operation of EUs AN-UNIT3 through AN-UNIT6 and operation of EU AN-UNIT1R and AN-UNIT2R for a total of 5,800 hours. This leads to overestimating the emi ssions from the source due to the fact that the boilers are only operate d during peak demand periods. Emissions from Scenario II are
also overestimated due to the fact that fuel oi l No. 2 is only used as an emergency backup fuel.

For Scenario I, the boilers and combined cycle gas turbines are fired with natural gas. Potential
emissions of NO X , CO, VOC, and PM 10 from EUs AN-UNIT1R and AN-UNIT2R are based on
manufacturer’s data for natural gas combustion (NO X : 0.035 lb/MMBTU, CO: 0.15 lb/MMBTU, VOC: 0.004 lb/MMBTU; PM 10 0.005 lb/MMBTU) and each unit operating a maximum of 2,900 hours per year. Potent ial emissions of SO 2 are based on AP-42 (3/9 8), Section 1.3, Table 1.3-2 and a maximum of 2,900 operating hours per year. The permit will allow operation of both units up to a combined total of 5,800 hours per year . Emission estimates for EU AN-UNIT3 fired with natural gas are based on continuous operation and AP-42 (2 /98), Section 1.4, Tables 1.4-1 and 1.4-2. Emission estimates of CO, VOC, PM 10 , and SO 2 for the combined cycle gas turbines fired with natural gas are based on continuous operation and AP-42 (1 0/96), Section 3.1, Table
3.1-1. Emission estimates of NO X for the combined cycle gas turbines fired with natural gas are based on stack testing conducted in Septembe r and October of 1998 (0.60 lb/MMBTU). The stack testing gave different emission rates of NO X for each unit. The maximum emission rate determined during the testing was used to predict the total potential emissions from the turbines. However, the individual emission factors will be used for emission inventory. Testing was not conducted at the maximum rating of the turbines but a linear relationship was shown between the heat input and emissions of NO X . Therefore, the maximum emission factor for NO X was extrapolated from the testing data.

For Scenario II, the combined cycle gas tu rbines (EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6) are fired with fuel oil No. 2 continuously and the boilers (EUs AN-UNIT1R, AN-UNIT2R, and AN-UNIT3) are fired with natural gas. Emission estimates of CO, VOC, PM 10 , and SO 2 for the combined cycle gas turbines fired with fuel oil No. 2 are based on continuous operation and AP42 (10/96), Section 3.1, Table 3.1-1. The NO X emissions from the combined cycle gas turbines are based on stack testing conducted at the faci lity in 1974 on EU AN-UNIT 5. Since distillate fuel oil is only used for emergencies, these emission factors have been determined to bePERMIT MEMORANDUM 2005-037-TVR (M-1) Page 5

sufficient. The maximum fuel oil sulfur conten t and maximum fuel oil fi ring rate are based on a
maximum SO 2 emission rate for the combined cycle gas tu rbines. The fuel oil firing rate varies for each unit depending upon the fuel oil sulfur content and how many units are being fired with
fuel oil.

Allowable Fuel Oil Sulfur Concentration for different Operating Scenarios

Fuel Oil
% Sulfur Maximum Firing Rate

When 3
Units Are Operating (gal/hr/unit) Fuel Oil
% Sulfur Maximum Firing Rate

When 2
Units Are Operating (gal/hr/unit) Fuel Oil
% Sulfur Maximum Firing Rate
For 1 Unit

(gal/hr)

0.340 1,000

0.330 1,100

0.320 1,200

0.310 1,300

0.185 1,000 0.300 1,400

0.180 1,100 0.290 1,500

0.140 1,000 0.175 1,200 0.280 1,600

0.135 1,100 0.170 1,300 0.275 1,700

0.130 1,200 0.165 1,400 0.270 1,800

0.125 1,300 0.160 1,500 0.265 2,000

0.120 1,500 0.155 1,600 0.260 2,100

0.115 1,700 0.150 1,900 0.255 2,300

0.110 2,000 0.145 2,200 0.250 2,700

0.105 2,500 0.140 2,800 0.245 4,600

0.100 5,000 0.135 4,600 0.240 4,800

0.095 5,300 0.130 4,900 0.235 5,000

0.090 5,700 0.125 5,200 0.230 5,200

0.085 6,100 0.120 5,500 0.225 5,300

0.080 6,500 0.115 5,700 0.220 5,400

0.110 6,000 0.215 5,600

0.105 6,500 0.210 5,700

0.205 5,900

0.200 6,100

0.195 6,200

0.190 6,500

For Scenario III, the boilers an d turbines are fired with commercial grade natural gas except during emergencies and testing for emergency prep aredness when the turbines will be fired with very low sulfur fuel oil. Scenario III incorporates the proposed BART emission limits for the
turbines.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 6

The boilers, turbines, and engine have emissions of toxic air cont aminants, the most significant being formaldehyde. Emissions of formaldehyde are based on the follo wing: boilers - AP-42 (7/98), Section 1.4; turbines - AP-42 (4/00), Section 3.1; and engine - AP-42 (10/96), Section 3.3. Total formaldehyde emissions are below the major source levels.

Formaldehyde Emissions from th e Boilers, Turbines, and Engine

Factor Emissions
Sources # Units MMBTUH lb/MMBTU lb/hr TPY

Nebraska Boilers 2 223 0.0001 0.045 0.065 Riley Stoker Boiler 1 528 0.0001 0.053 0.231

GE Turbines 3 828 0.0007 1.739 7.616 Cummings Engine 1 2.5 0.0012 0.003 0.001

Totals 1.84 7.913

Emission estimates for the 309-hp Cummings dies el fired engine are based on a maximum of 500 operating hours per year and AP-42 (1/95), S ection 3.3, Table 3.3-2, for uncontrolled diesel engines. Brake-specific fuel consumption for the 309-hp engine is 7,000 BTU/hp-hr for a fuel consumption of 15.5 gallons of diesel per hour. Because the engine will be limited to 500 hr per year, all emissions from the engine will be below 5 TPY.

Facility-Wide Emissions Scenario I (Natural Gas)

NO X CO VOC PM 10 SO 2 EU lb/hr TPY lb/hr TPY lb/h r TPY lb/hr TPY lb/hr TPY

AN-UNIT1R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT2R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT3 145.8 638.5 43.7 191.5 2.9 12.5 4.0 17.3 0.3 1.4

AN-UNIT4 580.0 1 2,239 93.7 410.5 20.5 89.6 35.7 156.4 0.6 2.4

AN-UNIT5 580.0 1 2,239 93.7 410.5 20.5 89.6 35.7 156.4 0.6 2.4

AN-UNIT6 580.0 1 2,239 93.7 410.5 20.5 89.6 35.7 156.4 0.6 2.4

AN-ENG1 9.6 2.4 2.1 0.5 0.8 0.2 0.7 0.2 0.6 0.2

Tanks --- --- --- --- 0.2 0.7 --- --- --- ---

TOTAL 1,911 7,381 393.9 1,521 67.2 284.8 114.0 489.9 2.9 9.2

1 Based on the December 1999 stack test results.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 7

Facility-Wide Emissions Scenario II (Fuel Oil No. 2)

NO X CO VOC PM 10 SO 2 EU lb/hr TPY lb/hr TPY lb/h r TPY lb/hr TPY lb/hr TPY

AN-UNIT1R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT2R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT3 145.8 638.5 43.7 191.5 2.9 12.5 4.0 17.3 0.3 1.4 AN-UNIT4 630.5 2,762 40.90 179.1 14.5 63.4 52.0 227.6 74.4 326.0 AN-UNIT5 630.5 2,762 40.90 179.1 14.5 63.4 52.0 227.6 74.4 326.0 AN-UNIT6 630.5 2,762 40.90 179.1 14.5 63.4 52.0 227.6 74.4 326.0

AN-ENG1 9.6 2.4 2.1 0.5 0.8 0.2 0.7 0.2 0.6 0.2

Tanks --- --- --- --- 0.15 0.65 --- --- --- ---

TOTAL 2,063 8,950 235.5 826.3 49.2 206.2 162.9 703.5 224.3 980.0

Facility-Wide Emissions Scenario III (BART)

NO X CO VOC PM 10 SO 2 EU lb/hr TPY lb/hr TPY lb/h r TPY lb/hr TPY lb/hr TPY

AN-UNIT1R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT2R 7.8 11.3 33.5 48.5 0.9 1.3 1.1 1.6 0.1 0.2

AN-UNIT3 145.8 638.5 43.7 191.5 2.9 12.5 4.0 17.3 0.3 1.4

AN-UNIT4 170.0 744.6 93.7 410.5 20.5 89.6 6.7 29.3 0.6 2.6

AN-UNIT5 170.0 744.6 93.7 410.5 20.5 89.6 6.7 29.3 0.6 2.6

AN-UNIT6 170.0 744.6 93.7 410.5 20.5 89.6 6.7 29.3 0.6 2.6

AN-ENG1 9.6 2.4 2.1 0.5 0.8 0.2 0.7 0.2 0.6 0.2

Tanks --- --- --- --- 0.2 0.7 --- --- --- ---

TOTAL 681.0 2,897 393.9 1,521 67.2 284.8 27.0 108.6 2.9 9.8

SECTION V. BART REVIEW

To be an affected BART source, a so urce must meet the following criteria:

3⁄4 the source must fall within the 26 source category list, 3⁄4 have units which were put in place during the 1962 to 1977 time frame, 3⁄4 and have potential emissi ons of air pollutants (NO X , SO 2 , PM 10 , PM 2.5 ) which may reasonably cause or contribute to visibility impairment above 250 TPY from affected units.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 8

The following units were determined to meet the time frame requirement.

EUG 3 Combined Cycle Gas Turbines
EU Manufacturer MMBTUH MW Serial # Const. Date

AN-UNIT4 General Electric 852 100 248851 1975

AN-UNIT5 General Electric 852 100 248852 1975

AN-UNIT6 General Electric 852 100 248853 1975

EUG 4 Internal Combustion Engine EU Make/Model hp Serial # Const. Date AN-ENG1 Cummings NT-855-F 309 10531247 1975

Maximum Potential Emissions from Affected Emission Units

NO X PM 10 SO 2 EU lb/hr TPY lb/hr TPY lb/hr TPY AN-UNIT4 630.5 2,762 52.0 227.6 74.4 326.0 AN-UNIT5 630.5 2,762 52.0 227.6 74.4 326.0 AN-UNIT6 630.5 2,762 52.0 227.6 74.4 326.0

AN-ENG1 9.6 2.4 0.7 0.2 0.6 0.2

TOTAL 8,288 683.0 978.2

Since the affected units have potential emissions above 250 TP Y, the units are BART-eligible. Subchapter 8 requires WFEC to either do a BA RT control review or to submit modeling demonstrating the affected equipment does not cause or contribute to visibility impairment in any mandatory Class I Federal area. Any BART controls or limits taken to assure the affected equipment does not cause or contribute to visibility impairment must be installed and operating within five years of approva l of the Regional Haze SIP.

As previously indicated, WFEC has proposed to in stall control equipment and to limit emissions within five years of SIP approval to assure affected units do not cau se or contribute to visibility impairment in any mandatory Class I Federal area. The following table details the new limits. Even though the turbines are capable of firing natural ga s or fuel oil No. 2, the limits are applicable when burning either fuel. WFEC is pr oposing to either modify the units and/or install appropriate controls to meet the following limits.

Proposed BART Emission Limits

NO X PM 10 SO 2 EU lb/hr TPY lb/hr TPY lb/hr TPY

AN-UNIT4 170.0 744.6 6.7 29.3 0.6 2.6

AN-UNIT5 170.0 744.6 6.7 29.3 0.6 2.6

AN-UNIT6 170.0 744.6 6.7 29.3 0.6 2.6

AN-ENG1 9.6 2.4 0.7 0.2 0.6 0.2PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 9

WFEC conducted a modeling review to demonstrat e that the affected units would not cause or contribute to visibility impairment in any mandatory Class I Federal area based on the newly proposed limits. Results of the modeling review ed are provided in Section VI. Class I Area Modeling indicates that the affected sources wo uld have a 0.461 deciview impact on the Wichita
Mountains Class I area. Since th is impact is below 0.5 deciview, th e facility has demonstrated it
will not cause or contribute to vi sibility impairment at the Wi chita Mountains Class I area. Based on this impact and the distance and direction to other Class I areas, WFEC will have negligible impacts at other Class I areas.

The permit has been modified to require complian ce with the proposed limits within five years of the Oklahoma Regional Haze SIP approval.

SECTION VI. CLASS I AREA MODELING

Background On July 1, 1999, the U.S. Environmental EPA published the final Regional Haze Rule (RHR). The objective of the RHR is to improve visibility in 156 specific areas across with United States,
known as Class I areas. The Clean Air Act defines Class I areas as certain national parks (over 6000 acres), wilderness areas (ove r 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-s pecific 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-imp airing pollutant, (2) Began operation between August 7, 1962 and August 7, 1977, and (3) Are listed as one of the 26 liste d source categories in the guidance.

A BART-eligible source is not automatically su bject to BART. Rather, BART-eligible sources are subject-to-BART if the sources are “reasonably anticipated to cause or contribute to visibility impairment in any federal mandatory Class I area.” EPA has determined that sources are reasonably anticipated to cause or contribute to visibility impairment if the visibility impacts from a source are greater than 0.5 deciviews (d v) when compared against a natural background.

Air quality modeling is the tool that is used to determine a s ource’s visibility impacts. States have the authority to exempt cer tain BART-eligible sources from installing BART controls if the results of the dispersion mode ling demonstrate that the source cannot reasonably be anticipated to cause or contribute to visibility impairment in a Class I area. Further, states also have the authority to define the modeli ng procedures for conducting m odeling related to making BART
determinations.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 10

To promote consistency between states in the development of BART mo deling protocols and to harmonize the approaches between adjacent RPO, the Central States Regional Air Planning (CENRAP) organization devel oped BART Modeling Guidelin es (December 15, 2005). The intent of the guidelines is to assist CENRAP st ates and source operators in the development of statewide and source-specif ic modeling protocols.

The following summarizes the modeling methods a nd procedures that were followed to conduct a refined CALPUFF modeling analys is for the WFEC Anadarko Power Plant. It was determined that the proposed emission limits would reduce the impact of the Anadarko Power Plant to a degree that the 98th percentile of the visibility impact predicted by the modeling due to all of the BART eligible sources at the station was be low EPA’s recommended vi sibility contribution
threshold of 0.5 Δ dv.

BART-Eligible Sources (Anadarko Power Plant)

EUG 3 Combined Cycle Gas Turbines
EU Manufacturer MMBTUH MW Serial # Const. Date

AN-UNIT4 General Electric 852 100 248851 1975

AN-UNIT5 General Electric 852 100 248852 1975

AN-UNIT6 General Electric 852 100 248853 1975

As required in CENRAP’s BART Modeling Guide lines, Class I areas within 300 km of the Anadarko Power Plant were included in the analysis.

CALPUFF Modeling System The main components of th e CALPUFF modeling system are CALMET, CALPUFF, and
CALPOST. CALMET is the me teorological model that genera tes hourly three-dimensional meteorological fields such as wind and temper ature. CALPUFF simulates the non-steady state transport, dispersion, and chemical transforma tion of air pollutants emitted from a source in “puffs.” CALPUFF calculates hou rly concentrations of visibil ity 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 we re output by CALPUFF.

The versions of the CALPUFF modeling syst em programs that were used for conducting WFEC’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 050413PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 11

CALPUFF Modeling System Versions (cont.)

Processor Version Level

CALMET 6.211 060414

CALPUFF 6.112 060412

POSTUTIL 1.4 040818

CALPOST 6.131 060410

Modeling Domain The CALPUFF modeling system u tilizes three modeling grids: the meteorological grid, the computational grid, and the sampli ng grid. The meteorological grid is the system of grid points at which meteorological fields are developed with CALMET. The computational grid determines the computational area for a CALPU FF run. Puffs are advected and tracked only while within the computational grid. The meteorol ogical grid is defined so that it covers the areas of concern and gives enough marginal buffe r area for puff transport and dispersion. The computational domain was set to extend at leas t 50 km in all directions beyond the Anadarko
Power Plant and the Class I areas of interest. The map projection for the modeling domain was Lambert Conformal Conic (LCC) and the datu m was the North American Datum 1927 (NAD27). The reference point for the modeling domai n is Latitude 33.25°N, L ongitude 100.5°W. The
northeast corner was Latitude 37.25 oN and Longitude 92oW. The meteorological grid spacing
was 3 km.

Vertical Layers Layer Cell Face Height (m)

1 20

2 40

3 80

4 160

5 320

6 640 7 1,200 8 2,000 9 3,000 10 4,000

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 observ ation data will be relied upon. The vertical dimension of the domain was divided into 10 laye rs. The vertical dime nsions were weighted
towards the surface to resolve th e mixing layer while using a somewhat coarser resolution for the layers aloft.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 12

Geophysical Data CALMET requires geophysical data to characteri ze the terrain and land use parameters that potentially affect dispersion. Terrain features affect flows and create turbulence in the atmosphere and are potentially subjected to higher concentrations of elevated puffs. Different
land uses exhibit variable characteristics su ch as surface roughness, albedo, Bowen ratio, and
leaf-area index that also eff ect turbulence and dispersion.

Terrain Data
Terrain data was obtained from the United Stat es Geological Survey (USGS) in 1-degree (1:250,000 scale or approximately 90 meter resolutio n) digital format. The USGS terrain data was then processed by the TERREL program to gene rate 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 us e data was not available, USGS data at 1:100,000 resolution was used. The USGS CTG form at LULC data files were compressed prior
to use in the CTGPROC utility processor using the CTGCOMP program. The LULC data were processed by the CTGPROC program to generate land use for each grid cell across the modeling
domain.

Compiling Terrain And Land Use Data The terrain data files output by the TERELL program and th e LULC files output by the CTGPROC program were then uploaded into th e MAKEGEO program to create a geophysical
data file that was used as the input for CALMET.

CALMET CALMET is the meteorological processor that compiles meteorological data from raw observations of surface and upper air conditions, precipitation measurements, mesoscale model output, and geophysical parameters into a singl e 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, preci pitation data, and mesoscale model output to develop the meteorological fiel ds. Upper air observations were not used in generating the meteorological fields.

MM5 Data Hourly mesoscale data was used as the in itial guess field in developing the CALMET meteorological data. The following 5 th generation mesoscale model me teorological 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 resolu tion generated by the Midwest RPOPERMIT MEMORANDUM 2005-037-TVR (M-1) Page 13

Surface Data Parameters affecting turbulent dispersion that are observed hourly at su rface stations include wind speed and direction, temperature, clou d cover and ceiling, relative humidity, and precipitation type. The stations were selected from the available data inventory to optimize spatial coverage and representation of the domain. Data from the stations was processed for use in CALMET using the SMERGE program.

Missing surface data was filled using procedures recommended by EPA. Mi ssing data periods of 5 hours or less were replaced using these procedures . For periods greater than 5 hours, data was
left either unfilled or was not used in CALMET processing. A large enough quantity of surface
stations were included in the domain so that ov erlapping areas of influence would allow data
from an alternate station to be used.

The use of multiple stations for meteorologi cal observations in CA LMET/CALPUFF provides a substantial enhancement over the steady-state treatment of observati ons from a single meteorological station. Surface da ta were extracted from the surface stations. Raw observations from these stations were obtained from the National Climatic Data Center (NCDC). The data was quality assured and then merged using the SMERGE pre-processor to create a single
assimilated data file of surface obs ervations for each year analyzed.

Precipitation Data
The effects of chemical transformation a nd deposition processes on ambient pollutant
concentrations will be considered in this anal ysis. Therefore, it wa s necessary to include observations of precipitation in the CALMET analysis. 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.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 14

CALMET Input Variables Where CENRAP Suggested Value was not Used Variable Suggested Used Description Reason DGRIDKM 6.0 3.0 Grid spacing (km) Refined grid spacing

NN2 1 2 Last time step for debug data to be printed Generated debug data for 2 time steps

NZPRN2 0 1 # Of levels at surface to print Default

NOOBS 2 1 No obs mode Used surface OBS

NSSTA 0 47 # Met stations in surf.dat # of stations

NPSTA 0 135 # Met stations in precip.dat # of stations

ICLOUD 3 0 Gridded Cloud Fields Default

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 s t guess surface field (km) IWAQM Phase 2 Study

R2 1 100 Weighting of 1 s t 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 pr edict hourly concen tration impacts.

Source Emissions WFEC proposes reduced NO X emission limitations for the three combustion turbines that constitute the BART-eligible sources at the Anadarko Plant. A summary of potential emissions
from the three turbines is summarized below. NO X emissions are based on manufacturersupplied estimates. SO 2 emissions are based on the turbines ' maximum heat duty and emission factors obtained from AP-42 (4/00), Section 3.1 for natural gas fired turbines for natural gas with
a maximum sulfur content of 6.2 ppmv sulfur (6.2E-4%). PM 10 emissions are based on the turbines' maximum heat duty and emission factor s obtained from AP-42 (4/00), Section 3.1 for natural gas fired turbines.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 15

Post Project PTE

NO X PM 10 SO 2 EU lb/hr TPY lb/hr TPY lb/hr TPY

AN-UNIT3 170.0 744.6 6.7 29.3 0.6 2.6

AN-UNIT4 170.0 744.6 6.7 29.3 0.6 2.6

AN-UNIT5 170.0 744.6 6.7 29.3 0.6 2.6

PM 10 Speciation
Total PM 10 emissions are not directly entered into the CALPUFF model but are instead input as
coarse and fine constituents. The PM 10 emissions from the turbines are speciated according to the Federal Land Managers' (FLM) gui dance to include the following:

3⁄4 Coarse particulate matter (PM C , considered PM 2.5-10 )

3⁄4 Fine particulate matter (PMF, considered PM <2.5 )

3⁄4 Sulfates (SO 4 )

3⁄4 Secondary organic aerosols (SOA)

3⁄4 Elemental carbon (EC)

Based upon FLM guidance, PM 10 emissions from natural gas combustion consist of coarse, fine, elemental carbon (EC), and secondary organic aerosol (SOA) components. The breakdown of these components is shown below.

PM SPECIATION PROFILE Particulate Matter Species Fraction PM Coarse (Soil) 25% Elemental Carbon (EC) 0%

PM Fine 75% Secondary Organic Aerosols 0% (organic carbon)

Total 100%

SO 4 emissions are primarily the result of su lfuric acid formed from conversion of SO 2 to SO 3 and are based on 5% conversion of SO 2 to SO 3 and 100% conversion of SO 3 to H 2 SO 4 . A summary of particulate emissions from the turbines is summarized below.

SPECIATED PM 10 EMISSIONS

Emissions Pollutant (lb/hr)

SO 4 0.045 PM (coarse) 5.024 PM (fine) 1.675PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 16

Reduction of NO X emissions at the turbines may result in changes to the exhaust profile of the turbines. Although the physical dimensions of th e stack will remain unchanged, the exhaust flow and temperature may vary. A summary of the stack parameters utilized in conducting the modeling were based on manufactur er data and are shown below.

Stack Parameters Emission Latitude Longitude Ex haust Stack Stack Exit Exit Unit degrees degrees Flow Height Diameter Velocity Temp.

NAD27 NAD27 ACFM feet feet ft/s °F AN-UNIT4 35.0826 98.2249 873,000 80 13.5 101 325
AN-UNIT5 35.0821 98.2243 873,000 80 13.5 101 325 AN-UNIT6 35.0826 98.2243 873,000 80 13.5 101 325

Base elevation of each of th e units is 360 meters (1,180 f eet) above MSL based upon visual inspection of USGS topographic maps.

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 were downloaded from the NPS website, converted in to the LCC NAD27 projection, and incorporated
into the CALPUFF model.

Background Ozone Background ozone concentrations we re required in orde r to model the phot ochemical 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 recomm ended either developing background ozone
concentrations from ambient monitors located within the domain being modeled or from the most recent CENRAP CMAQ/CAM X simulation for the 2002 base year. Modeling was conducted using a conservative background concentration of 40 ppb. This is the default background concentration from the CENRAP protocol.

Background Ammonia Background concentrations of ammonia were re quired to model the formation of ammonia
nitrates and sulfates. CENRAP recommended developing bac kground concentrations from the most recent CENRAP CMAQ or CAM X simulation for the 2002 base year. Since the CMAQ/CAM X modeled and observed monthly averaged concentrations exhibit wide spatial variability and the data is not readily available, a conservative background concentration of 3 ppb was used. This is the default backgr ound concentration from the CENRAP protocol.

CALPUFF Model 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.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 17

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

MOZ 1 0 Read Background
Ozone Concentrations Default

MH2O2 1 0 Background H2O2
Concentrations Need to chose 0 to use monthly background
value BCKH2O2 1 12*1 Background Monthly
H2O2 Concentrations Default

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 vi sibility change in deciview (dv) caused by WFEC’s BART-eligible source s when compared to a natural background.

Light Extinction Algorithm EPA's currently approved algorith m for reconstructing light exti nction (as opposed to the new equation for reconstructing light extinc tion recommended by the IMPROVE Steering Committee) was used. The background extinction coefficient b ext , background is affected by various chemical species and the Rayleigh sca ttering 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 extinction attributable to a natural background. The change in deciviews based on the source and b ackground light extinctions was evaluated using the equation below.

∆ dv = 1 0 *ln[(b ext, background + b ext, source )/b ext, background ]PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 18

CALPOST Processing Method CALPOST Method 6, which calcula tes hourly light extinction im pacts for the source and background using monthly average relative humidity adjustment factors was used in the refined BART analysis. Monthly Class I area-specific relative humidity adjustme nt 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

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 aeroso l concentrations for the U.S. th at are included in Table 2-1
of EPA’s Guidance for Estimating Natural Visibilit y Conditions Under the Regional Haze Program were used

.

Default Average Annual Natural Background Levels

Class I Area Region SO 4 NO 3 OC EC Soil Coarse Mass

Wichita Mountains WEST 0.12 0.10 0.47 0.02 0.50 3.00

Evaluating Visibility Results Trinity compared the high of the 2001 through 2003 daily ∆ dv values output by CALPOST to a
contribution threshold of 0.5 ∆ dv. If the 98th percentile ∆ dv values (the 7th highest value, 22nd highest over three years) out put by CALPOST is less 0.5 ∆ dv, then the source is exempt from BART requirements.

Summary of CALPOST Control Parameters A listing of the CALPOST parameters that Trinity used in OG&E's modeling analysis. In cases where a parameter to be used is different than what CENRAP recommen ded, a short explanation as to the difference is provided.

A summary of the top 25 visibility-impairing days at each of the relevant Class I areas over the modeled 2001-03 period is summari zed below. Shaded values indicate visibility impacts that
exceed the 0.5 ∆ dv threshold for contribution to visibility impairment. As shown in the table, the
98 th percentile values indicate that the Anadar ko Power Plant's contri bution to visibility impairment is below the 0.5 ∆ dv threshold. These results indicate that the Anadarko Power Plant therefore qualifies for a waiver from BART.

CALPOST Input Variables Where CENRAP Suggested Value was not Used Variable Suggested Used Description Reason BEXTBTBK 12 NA Background Extinction for

MVISBK=1 Not necessary since

MVISBK=6

RHFRAC 10 NA % of Particles affected by RH Not necessary since

MVISBK=6PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 19

Visibility Impact Modeling Results for Wichita Mountains 2001-2003

Rank Modeled Visibility Impact ( ∆ dv) Background Extinction by Species (%) Year Day

SO 4 NO 3 OC EC PMC PMF

2001

1 0.392 0.05 92.44 0 0 1.05 6.45 2001 66

2 0.364 0.15 94.04 0 0 0.85 4.96 2001 128

3 0.340 0.06 97.51 0 0 0.36 2.07 2001 15

4 0.338 0.17 98.24 0 0 0.23 1.36 2001 88

5 0.304 0.15 93.81 0 0 0.91 5.13 2001 261

6 0.302 0.26 95.42 0 0 0.67 3.66 2001 308

7 0.289 0.09 93.68 0 0 0.94 5.28 2001 127

8 0.260 0.06 93.98 0 0 0.88 5.09 2001 267

9 0.248 0.16 96.34 0 0 0.51 2.99 2001 364

10 0.225 0.05 97.57 0 0 0.29 2.09 2001 361

2002

1 0.607 0.21 96.74 0 0 0.44 2.61 2002 148

2 0.491 0.08 94.63 0 0 0.79 4.5 2002 290

3 0.451 0.16 98.84 0 0 0.15 0.86 2002 37

4 0.444 0.05 95.94 0 0 0.61 3.41 2002 66

5 0.431 0.04 94 0 0 0.82 5.14 2002 17

6 0.406 0.24 96.84 0 0 0.42 2.5 2002 282

7 0.277 0.19 95.4 0 0 0.62 3.8 2002 305

8 0.255 0.04 94.2 0 0 0.88 4.87 2002 51

9 0.248 0.08 98.41 0 0 0.2 1.32 2002 1

10 0.243 0.19 96.93 0 0 0.42 2.46 2002 301

2003

1 0.515 0.05 98.71 0 0 0.17 1.07 2003 320

2 0.480 0.05 97.07 0 0 0.39 2.49 2003 89

3 0.459 0.08 96.08 0 0 0.54 3.3 2003 69

4 0.410 0.04 96.89 0 0 0.46 2.6 2003 317

5 0.361 0.18 97.19 0 0 0.39 2.25 2003 57

6 0.325 0.04 93.62 0 0 0.95 5.38 2003 116

7 0.302 0.16 94.3 0 0 0.79 4.75 2003 277

8 0.282 0.06 96.27 0 0 0.49 3.18 2003 42

9 0.269 0.24 94.84 0 0 0.72 4.21 2003 305

10 0.266 0.06 94.09 0 0 0.87 4.98 2003 51

SECTION VII. INSI GNIFICANT ACTIVITIES

The insignificant activities identified and justif ied in the application are duplicated below. Appropriate recordkeeping of ac tivities indicated below with “* ” is specified in the Specific
Conditions.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 20

1. Space heaters, boilers, process heaters, and emergency flares less than or equal to 5 MMBTU/hr heat input (commercial natural gas). There are three small portable space
heaters located on-site and which ar e rated at 1 MMBTU/hr and others may be used in the
future.

2. Emissions from stationary internal com bustion engines rated less than 50 hp output. Currently, there are no stationa ry internal combustion engines rated less than 50 hp located at the facility but they may be used in the future.

3. * Emissions from fuel storag e/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. Tanks T-5 and T-6 are used to store and dispense unleaded gasoline and have an average throughput of 110 ga llons/day. Tank T-7 is used to store and dispense diesel fuel and has an average monthly throughput of 60 gallons/day.

4. Emissions from crude oil or condensate marine and truck loading equipment operations at crude oil and natural gas production sites wher e the loading rate does not exceed 10,000 gallons per day averaged over a 30-day period. Unloading of tank T-8 into tank trucks is less than 10,000 gallons per day. Tank T-8 stores condensate but has not had any throughput in recent years.

5. * Emissions from crude oil and condensate storage tanks with a capacity of less than or equal to 420,000 gallons that store crude oil and condensate prior to custody transfer. Tank T-8 stores condensate prior to custody tr ansfer and has a capacity of 12,500 gallons.

6. * Emissions from storage tanks constructed with a capacity less th an 39,894 gallons which store VOC with a vapor pressu re less than 1.5 psia at maximum storage temperature. Tanks T-1 and T-7 have capac ities less than 39,894 gallons and store products having a vapor pressure less than 1.5 psia.

7. Cold degreasing operations utilizing solvents that are denser than air. Three parts washers are located at the facility which use approxima tely 42 gallons/month of a solvent that is
denser than air.

8. Surface coating operations that do not exceed a combined total usage of more than 60 gallons/month of coatings, thinners, and clean-up solvents at any one emission unit. Surface coating is conducted at the facil ity as part of routine maintenance.

9. Exhaust systems for chemical, paint, and/or solvent storage rooms or cabinets, including hazardous waste satellite (accumulation) areas. There are four storage rooms/cabinets used for storing chemicals, paints, and solvents and others may be used in the future.

10. Hand wiping and spraying of solvents from contai ners with less than 1 liter capacity used for spot cleaning and/or degreasing in ozone attainment areas. Small amounts of solventPERMIT MEMORANDUM 2005-037-TVR (M-1) Page 21

used for degreasing are applied to facility components using a rag and emissions are
included in No. 8.

11. * Activities that have the potential to emit no more than 5 TPY (actual) of any criteria pollutant. The facility has not identified any ot her activities that have the potential to emit more than 5 TPY (actual) of any criteria pollu tant but it may have some in the future.

SECTION VIII. OKLAHOMA AI R POLLUTION CONTROL RULES

OAC 252:100-1 (General Provisions) [Applicable] Subchapter 1 includes definitions but there are no regulat ory requirements.

OAC 252:100-2 (Incorporati on by Reference) [Applicable] This subchapter incorporates by reference app licable provisions of Title 40 of the Code of Federal Regulations. These requirements are a ddressed in the “Federal Regulations” section.

OAC 252:100-3 (Air Quality Stan dards 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.

OAC 252:100-5 (Registration, Emission Inventory, and Annual Operating Fees) [Applicable] Subchapter 5 requires sources of air contaminants to register with Air Quality, file emission inventories annually, and pay annual operating fees based upon total annual emissions of regulated pollutants. Emission inventories have been submitted and fees paid for the past years.

OAC 252:100-8 (Permits for Part 70 Sources) [Applicable]
Part 5 includes the general administrative requirements for part 70 permits. Any planned changes in the operation of the facility which re sult in emissions not authorized in the permit and which exceed the “Insignificant Activities” or “Trivial Activities” thre sholds require prior notification to AQD and may require a permit modification. Insignif icant 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 HAP or 20% of any threshold less than 10 TPY for a HAP that the EPA may establish by rule

Emission limits for the facility are based on Permit No. 97-059-TV (M-1) and the proposed
BART emission limitations.

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 emi ssions in each excess emission event. No later than thirty (30) calendar days after the start of any excess emission event, the owner or operatorPERMIT MEMORANDUM 2005-037-TVR (M-1) Page 22

of an air contaminant source from which excess emissions have occurred shall submit a report for each excess emission event describing the ex tent of the event and the actions taken by the owner or operator of the facility in response to this event. Request for affirmative defense, as described in OAC 252:100-9-8, shall be included in the excess emission event report. Additional reporting may be required in the case of ongoi ng 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 cond itions listed in this subchapter.

OAC 252:100-19 (Particulate Matter) [Applicable] This subchapter specifies a pa rticulate matter (PM) emission limitation of 0.6 lb/MMBTU from existing fuel-burning equipment with a rated h eat input of 10 MMBTUH or less. For fuelburning equipment greater than 10 MMBTUH, th is subchapter specifi es a PM emission limitation based upon the heat input of the equipment. The two new boilers (AN-UNIT1 and AN-UNIT2) are rated at 233 MMBTUH and are su bject to a PM emission limitation of approximately 0.28 lb/MMBTU. The old boiler (AN-UNIT3) is rated at 531 MMBTUH and is subject to a PM emission limitation of approx imately 0.23 lb/MMBTU. The three combined cycle gas turbines (AN-UNIT4, AN-UNIT5, a nd AN-UNIT6) are rated at 828 MMBTUH and are subject to a PM emission limitation of appr oximately 0.21 lb/MMBTU. AP-42 (7/98), Table 1.4-2, lists the total PM emissions from natural gas combustion to be 7.6 lb/MMft 3 or about 0.0076 lb/MMBTU. AP-42 (10/96), Section 1.3, lists the total PM emissions for industrial boilers burning fuel oil No. 2 to be 3.3 lb /1,000 gallons or about 0.024 lb/MMBTU. AP-42 (1/95), Table 3.1-2, lists the total PM emissions for large uncontrolled gas turbines burning natural gas to be 0.041 lb/MMBTU and large uncontrolled gas turbines burning fuel oil No. 2 to
be 0.061 lb/MMBTU. All of these emission factors are in complian ce with this subchapter. The permit will require the use of natural gas or distillate fuel (f uel oil No. 2) for all fuel-burning equipment to ensure complia nce with Subchapter 19.

OAC 252:100-25 (Visible Emissions and Particulate Matter) [Applicable] No discharge of greater than 20% opacity is allowed except fo r 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 consecu tive 24 hours. In no case shall the average of any six-minute period exceed 60% opacity. When burning natural ga s there is little poss ibility of exceeding the opacity standards. When burning fuel oil in the turbines, the permit requires visible emission
observations.

OAC 252:100-29 (Fugitive Dust) [Applicable] No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the property line on which the emissions originate in such a manner as to damage or to interfere with the use of adjacent properties, or cause air quality standards to be exceede d, 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.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 23

OAC 252:100-31 (Sulfur Compounds) [Applicable]

Part 2 limits the impact of sulfur dioxide emissions from existing equipment. Modeling conducted using ISCST3 was used to show the impacts of the facility on the ambient air as shown below. EU AN-UNIT3 will always be fired with natural gas.

Ambient Impacts of SO 2 Standard Fuel Oil Natural Gas Averaging Time μ g/m 3 μ g/m 3 μ g/m 3

1-hour 1,200 471 3.34

3-hour 650 363 2.71

24-hour 130 130 1.49

Annual 80 15 0.27

Part 5 affects new fuel-burning equipment that was constructed after July 1, 1972. EU ANUNIT3 was constructed in 1958 and is applicable to the existing equipment emission limits. Fuel-burning equipment was defined as “any equipment, device, or contrivance, and all appurtenances thereto, including ducts, breeches, fuel-feeding equipment, ash-removal equipment, combustion controls, stacks, and chimneys, used primar ily to burn any fuel for the purpose of indirect heating in which the material being heated is not contacted by and adds no substance to the products of combustion” prior to July 1, 1977. EUs AN-UNIT4 through ANUNIT6, the combined cycle gas turbines, were c onstructed in 1975. Theref ore, they are existing equipment and are applicable to the existing equi pment standards. However, the two new boilers (AN-UNIT1R and AN-UNIT2R) are s ubject to the new equipment standard which limits sulfur dioxide emissions from gaseous fuels to 0.2 lb/MMBTU heat input, based on a three-hour average. This is equivalent to approximatel y 1,203 ppmv sulfur. AP-42 (7/98), Table 1.4-2, lists
the total SO 2 emissions for natural gas to be 0.6 lb/MMft 3 or about 0.0006 lb/MMBTU which is in compliance with Subchapter 31. The permit w ill require the use of commercial natural gas for
EUs AN-UNIT1R and AN-UNIT2R to ensure compliance with Subchapter 31.

OAC 252:100-33 (Nitrogen Oxides) [Applicable]

NO X emissions are limited to 0.20 lb/MMBTU, three- hour average, from a ll new gas-fired fuelburning equipment with a rated heat input of50 MMBTUH or greater. The old boiler (ANUNIT3) was constructed prior to th e effective date of this regul ation (February 14, 1972) and is not subject to these requirements. The combined cycle gas turbines were not affected units because they did not meet the definition of fuel -burning equipment in effect during construction. The two new boilers (AN-UNIT1R and AN-UNIT2 R) are subject to this requirement.
Manufacturers’ data based on stack testing estimates emissions of NO X from the new boilers at 0.035 lb/MMBTU, which is in complia nce with this subchapter. The new boilers are also subject to the NSPS, Subpart Db, NO X emission limit of 0.2 lb/MMBTU, which is as stringent.

OAC 252:100-37 (Volatile Or ganic Compounds) [Applicable]

Part 3 requires storage tanks constructed after De cember 28, 1974, with a capacity of 400 gallons or more and storing a VO C with a vapor pressure greater than 1.5 psia to be equipped with a permanent submerged fill pipe or with an orga nic vapor recovery system. The condensate and gasoline tanks are subject to this requirement.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 24

Part 3 requires VOC loading facilities with a throughput equal to or less than 40,000 gallons per day to be equipped with a system fo r submerged filling of ta nk trucks or trailers if the capacity of the vehicle is greater than 200 gallons. This fac ility does not have the physical equipment (loading arm and pump) to conduct this type of loading and is not subject to this requirement.
Part 5 limits the VOC content of coatings from any coating line or other coating operation. This facility does not normally conduct coating or pain ting operations except fo r routine maintenance of the facility and equipment, which is exempt.

Part 7 requires fuel-burning and refuse -burning equipment to be opera ted and maintained so as to minimize VOC emissions. Temperature and avai lable air must be sufficient to provide essentially complete combustion.

Part 7 requires all effluent water se parators openings or floating r oofs to be sealed or equipped with an organic vapor recovery system. There ar e no effluent water separators located at this facility.

OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable] This subchapter regulates toxic air contaminants (TAC) that are emitted in to the ambient air in areas of concern (AOC). Any wo rk practice, material substituti on, or control equipment required by the Department prior to June 11, 2004, to c ontrol a TAC, shall be retained, unless a modification is approved by the Director. Since no AOC has been designated there are no specific requirements for this facility at this time.

OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable] This subchapter provides general requirement s for testing, monitoring and recordkeeping and applies to any testing, monitoring or recordkeeping activity conducted at any stationary source. To determine compliance with emissions limitations or standards, the Air Quality Director may require the owner or operator of any source in the state of Okla homa 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 appr oved by the Air Quality Director and under the direction of qualified personnel. A no tice-of-intent to test and a testing protocol shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests. Emissions and other data required to demonstrate compliance with any fede ral or state emission limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained, and submitted as required by this subchapter, an applicable rule, or permit 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.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 25

The following Oklahoma Air Pollution Control Rules are not applicable to this facility:

OAC 252:100-11 Alternative Emi ssions Reduction not requested

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 Grain Elevator s not in source category

OAC 252:100-35 Carbon Dioxide not type of emission unit

OAC 252:100-39 Nonattainment Areas not in area category OAC 252:100-47 Municipal Solid Waste Landfills not in area category

SECTION IX. FEDERAL REGULATIONS

Protection of Visibility, 40 CFR 51 Subpart P [Applicable] The primary purposes of this subpart are to re quire States to develop programs to assure reasonable progress toward meeting the national goal of preventing any future, and remedying any existing, impairment of visibility in ma ndatory Class I Federal areas which impairment results from manmade air pollution; and to establish necessary additional procedures for new source permit applican ts, States and Federal Land Managers to use in conducting the visibility impact analysis required for new sources unde r §51.166. This subpart sets forth requirements addressing visibility impairment in its two principal forms: “reasonably attributable” impairment (i.e., impairment attributable to a single source/small group of sources) and regional haze (i.e., widespread haze from a multitude of sources whic h impairs visibility in every direction over a large area). Regional haze visibility impairment is partially addressed through the Best Available Retrofit Technology (BART) process. The facility has been determined to be subject to a BART
review.

Best Available Retrofit Technol ogy (BART) requirements for regional haze visibility impairment.
WFEC must either submit a BART review or a de monstration that the BART-eligible sources do not cause or contribute to any impairment of visib ility in any mandatory Class I Federal area. As indicated in Section V, WFEC proposed to modify the affected units and take enforceable limits, such that, they would not cause or contribute to any impairment of visibility in any mandatory Class I Federal area. Requirements to comply within 5 years of SIP approval have been added to the permit.

PSD, 40 CFR Part 52 [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 turbines if the modifications will result in a significant emission increase and a significant net emission increase of a regulated NSR pollutant.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 26

NSPS, 40 CFR Part 60 [Subpart Db is Applicable] Subpart D, Da , Electric Utility Steam Generating Units. All of the boilers are below the de minimis level of 250 MMBTUH for these subparts and EU AN-UNIT3 was c onstructed prior to the August 17, 1971, and September 18, 1978, app licability dates of these subparts. Subpart Db , Industrial-Commercial-Institutional Steam Generating Units. This subpart affects steam generating units with a heat input ca pacity greater than 100 MMBTUH and that commences construction, modification, or reco nstruction after June 19, 1984. The two new boilers (EUs AN-UNIT1R, AN-UNIT2R) will ha ve a heat input of 223 MMBTUH and are applicable to this subpart. EU AN-UNIT1R a nd AN-UNIT2R will only be permitted to combust natural gas and are subject to the NO X emission standard of § 60.44b(a)(1)(ii) (0.2 lb/MMBTU) and all applicable requirements. EU AN-UNIT 3 was constructed prior to the June 19, 1984, applicability date of this subpart.

The facility has requested use of a predictive emission monitoring system (PEMS) as allowed by § 60.48b(g)(2) instead of a continuous emission mon itoring system for the two new boilers. The PEMS has been approved and all monitoring an d recordkeeping requireme nts for the PEMS will be included in the permit. Subpart Dc , Small Industrial-Commercial-Institutional Steam Genera ting Units. This subpart affects steam generating units with a heat input capacity between 10 and 100 MMBTUH and that commences construction, modificat ion, or reconstruction after June 9, 1989. All emission units
are above the threshold level of 100 MMBTUH. Subpart K, Ka, Kb , VOL Storage Vessels. Subpart Kb regulates hydrocarbon storage tanks larger than 19,813 gallons capacity and built after July 23, 1984. The condensate storage tanks at this facility are below this threshold; theref ore, this subpart is not applicable. The 10,000 gallon gasoline tanks are not subject because the we re constructed prior to the effective date of Subpart Kb and are below the de minimis amount of 40,000 gallons for Subparts K, and Ka. The other large tanks are not subject because they stor e fuel oil No. 2 which has a vapor pressure of less than 1.5 psia. Subpart GG , Stationary Gas Turbines. This subpart a ffects stationary gas tu rbines with a heat input at peak load of greater than or equal to 10.7 gigajoules per hour (10 MMBTUH) based on the lower heating value (LHV) of the fuel and that commenced construction, reconstruction, or modification after October 3, 1977. The combined cycle gas turbines are not subject because they were constructed prior to the effective date and have not been modified or reconstruction as defined in NSPS, Subpart A. Subpart IIII , Stationary Compression Ignition (CI) Inte rnal Combustion Engines (ICE). This subpart affects CI ICE manufact ured after 2007. There are no CI ICE manufactured after 2007 at this facility. Subpart JJJJ , Stationary Spark Ignition Internal Com bustion Engines (SI ICE). This subpart
affects SI ICE ordered after June 12, 2006 and all SI ICE engines m odified or reconstructed after June 12, 2006, regardless of size. Ther e are no SI ICE at this facility. Subpart KKKK , Stationary Combustion Turbines. This subpart affects stationary combustion turbines with a heat input at peak load equal to or greater than 10.7 gi gajoules (10 MMBTU) per hour, based on the higher heating va lue of the fuel that commenced construction, modification, or reconstruction after February 18, 2005. Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. The turb ines at this facilityPERMIT MEMORANDUM 2005-037-TVR (M-1) Page 27

were not constructed, modified, or reconstructed af ter that date and would not be subject to this subpart unless the modifications implementing BA RT would be considered a modification or reconstruction as defined in NSPS, Subpart A.

NESHAP, 40 CFR Part 61 [Not Applicable] There are no emissions of any of the regulated po llutants: arsenic, asbest os, beryllium, benzene, coke oven emissions, mercury, radionuclides or vinyl chloride except for trace amounts of benzene. Subpart J , Equipment Leaks of Benzene only affects process streams which contain more than 10% benzene by weight. All process streams at this facility are below this threshold.

NESHAP, 40 CFR Part 63 [Not Applicable] Subpart YYYY , Combustion Turbines. This subpart was promulgated on March 5, 2004, and affects combustion gas turbines that are located at major sources. Emission calculations have shown this facility to be a minor source of HAP. Subpart ZZZZ , Reciprocating Internal Combustion Engine s (RICE). This subpart affects RICE with a site-rating greater than 500 brake horsepo wer that are located at a major source and new and reconstructed engines (after June 12, 2006) with a site rating less than or equal to 500 HP located at major sources, and for new and recons tructed engines (after June 12, 2006) located at area sources. Owners and operators of new or reconstructed engine s at area sources and of new or reconstructed engines with a si te rating equal to or less than 500 HP located at a major source (except new or reconstructed 4-stro ke lean-burn engines with a site rating greater than or equal to 250 HP and less than or equal to 500 HP located at a major source) must meet the requirements of Subpart ZZZZ by complying with either 40 CFR Pa rt 60 Subpart IIII (for CI engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines). Based on emission calc ulations, this facility is a
minor source of HAP. The 309- hp Cummings NT-855-F (EU AN-E NG1) was constructed prior to the applicability dates of this subpart and is not an affected emission unit.

On March 13, 2009, EPA proposed additional requireme nts for stationary CI RICE located at area sources. A summary of thes e proposed requirements for engine s located at this facility are
shown below.

Engine Category Normal Operation (During SSM) @ 15% O 2 Existing Emergency CI > 500-hp 40 ppmvd CO or 90% CO reduction (40 ppmvd CO) SSM – Startup, Shutdown & Malfunction

The existing CI engine will probably have to be equipped with an oxidation catalyst to meet the proposed CO emission limits.

Subpart DDDDD, National Emission Standards for Hazar dous Air Pollutants for Industrial,
Commercial and Institutional Boilers and Proc ess Heaters. In Ma rch, 2007, the EPA filed a
motion to vacate and remand this rule back to th e agency. The rule was vacated by court order, subject to appeal, on June 8, 2007. No appeals were made and the rule was vacated on July 30, 2007. Existing and new small gaseous fuel boilers and process heaters (less than 10 MMBtu/hr heat rating) were not subject to any standards, recordkeeping, or notifications under Subpart

DDDDD.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 28

EPA is planning on issuing guidance (or a rule) on what actions applicants and permitting authorities should take regarding MACT determin ations under either S ection112(g) or Section 112(j) for sources that were affected sources under Subpart DDDDD and other vacated MACTs. It is expected that the guidance (or rule) will establish a new timeline for submission of section 112(j) applications for vacated MACT standards. At this time, AQD has determined that a 112(j) determination is not needed for sources po tentially subject to a vacated MACT, including Subpart DDDDD. This permit may be reopened to address Section 112(j) when necessary. This facility is not a major source of HAP.

CAM, 40 CFR Part 64 [Not Applicable] Compliance Assurance Monitoring (CAM), as publis hed in the Federal Regi ster on October 22, 1997, applies to any pollutant specific emission unit at a major source, that is required to obtain a Title V permit, if it meets all of the following criteria:

• It is subject to an emission limit or standard for an applicable regulated air pollutant

• It uses a control device to achieve compliance wi th the applicable emission limit or standard

• It has potential emissions, prior to the contro l device, of the applicable regulated air pollutant of 100 TPY

The two new boilers in EUG 1 are subject to an emission limit (NSPS, Subpart Db, § 60.44b(a)(1)(ii), 0.2 lb/MMBTU) a nd they use a control device to achieve compliance with the applicable emission limit (Flue ga s recirculation systems are c onsidered a control device under CAM), but they do not have poten tial emissions prior to the cont rol device of the applicable pollutant of 100 TPY. The two emission units are limited to 100 TPY of CO combined. The boilers are also exempt because they are app licable to NSPS, Subpart Db, which requires a continuous compliance determination method to determine compliance with the emission limit.

None of the other emission units use a control device to achieve compliance with an applicable
emission limit or standard. EU AN-UNIT3 is subject to the requirements of 40 CFR 75 (Acid Rain) and is also exempt from additional CAM requirements. However, Specific Condition No. 4 requires recordkeeping of operation and main tenance activities for EU AN-UNIT3 through AN-UNIT6. Specific Condition 5 requires testing, ev ery five years, of the exhaust gases from
the emission units in EUG 3 for NO X and CO. Specific Condition No. 6 requires reporting of
excess emissions if emissions from EUG 1 or 2 exceed the limits of Sp ecific Condition No. 1.

Currently, WFEC is not proposing to use a cont rol device to comply with BART. If it is determined that a control device is necessary, WFEC will be required to submit a modification to incorporate any applicable requirements.

Chemical Accident Prevention Prov isions, 40 CFR Part 68 [Applicable] This facility does not store any regulated substance above the app licable threshold limits. More information on this federal program is available at the web site: http://www.epa.gov/ceppo/

.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 29

Acid Rain, 40 CFR Part 72 (Permit Requirements) [Applicable] The facility submitted a Phase II Monitoring Plan on December 15, 1995, and subsequently submitted a revised application on March 1, 1996. EPA issued a certificate of approval for the Continuous Emission Monitoring System (CEM) for EU AN-UNIT3 in March 1999. A separate Acid Rain Permit, No. 97-059-AR, was issued on April 15, 1999. The acid rain renewal permit, Permit No. 2004-189-ARR, was issued on November 23, 2004. The Acid Rain permit contained all of the Acid Rain requirements for EU AN-UNIT3. EUs AN-UNIT1 and AN-UNIT2 serve generators with a nameplate capacity below th e threshold level of 25 MWe and are therefore exempt from these requirements.

Acid Rain, 40 CFR Part 75 (Mon itoring Requirements) [Applicable] EUs AN-UNIT1 and AN-UNIT2 serve generators w ith a nameplate capacity below the threshold level of 25 MWe and are therefore exempt from these requirements. EUs AN-UNIT4, ANUNIT5, and AN-UNIT6 are combined cycle gas turb ines and do not meet the definition of an affected unit under the Acid Rain Program. EU AN-UNIT3 is the only affected unit and must meet the monitoring requirements of the Acid Rain Program when ever it is operated (typically only one week per year for preventativ e maintenance and testing purposes).

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 banning use of nonessential products containing ozone-deple ting substances (Subparts A & C) ; control servic ing of motor vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations which meet phase out requirements and which maximi ze 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 identify substitutes for ozon e-depleting compounds under the Significant New Alternativ es Program (Subpart G); and reduce the emissions of halons (Subpart H). Subpart A identifies ozone-depleting substances and divides them into two classes. Class I
controlled substances are divided into seve n groups; the chemicals typically used by the manufacturing industry include ca rbon tetrachloride (Class I, Gr oup IV) and methyl chloroform (Class I, Group V). A complete phase-out of production of Class I substances is required by January 1, 2000 (January 1, 2002, for methyl chlo roform). 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 disposi ng of appliances, includ ing 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.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 30

Conditions are included in the standard conditi ons of the permit to address the requirements specified at §82.156 for persons opening appliances fo r maintenance, service, repair, or disposal; §82.158 for equipment used during the maintenance, se rvice, repair, or disposal of appliances; §82.161 for certification by an approved technician certification program of persons performing maintenance, service, repair, or disposal of appliances; §82.1 66 for recordkeeping; § 82.158 for leak repair requirements; and §82.166 for refrigerant purchase records for appliances normally containing 50 or more pounds of refrigerant.

SECTION X. COMPLIANCE

Inspection On November 8, 2002, Laura Herron of Air Quality and other Air Quality personnel performed a compliance inspection. Mr. Gerald Butcher, E nvironmental Supervisor for Western Farmers Electric Cooperative and other Anadarko Plant pe rsonnel were present for the inspection. Only one combined cycle gas turbine was operating. The facility existed as described in the permit application and supplemental materials.

Testing Testing conducted on November 16 and 17, 2004, s hows compliance with the established permit
limits.

Permit Limitations Test Results

Load Heat Input NO X CO NO X CO Source (MW) (MMBTUH) lb/hr lb/hr lb/hr lb/hr

AN-UNIT4 50.4 480.0 580.0 93.7 112.2 7.6

AN-UNIT5 50.8 471.5 580.0 93.7 123.5 3.8

AN-UNIT6 54.3 537.9 580.0 93.7 139.8 2.9

Tier Classification and Public Review This application has been determined to be Tier II based on the re quest for a significant modification of a Part 70 operating permit. The permittee has submitted an affidavit that they are not seeking a permit for land use or for any operation upon land owned by others without their knowledge. The affidavit certifies that the a pplicant owns the land.

The applicant published the “Notice of Filing a Tier II Application” in The Anadarko Public

News , a daily newspaper, in Caddo County on Febr uary 26, 2009. The notice stated that the application was available for public review at the Anadarko Public Library located at 215 West Broadway Anadarko, Oklahoma and was also availa ble for review at the Air Quality Division main office. The applicant will publish the "Notice of Tier II Draft Permit" in The Anadarko
Public News , a daily newspaper, in Caddo County on April 17, 2010. The notice stated that the draft permit was available for public review at the Anadarko Public Library located at 215 West Broadway Anadarko, Oklahoma and was also availa ble for review at the Air Quality DivisionPERMIT MEMORANDUM 2005-037-TVR (M-1) Page 31

main office and on the Air Qualit y section of the DEQ Web Page: http://www.deq.state.ok.us/

. No comments were received from the public. Howe ver, the applicant has requested a change to the wording of Specific Condition 1, EUG 3 (b) to i ndicate that the facility is authorized to burn very low sulfur fuel oil during testing for emergency preparedness. Specific Condition 1, EUG 3 (b) was changed as follows {emphasis added}:

Wording from Draft Permit:

a. Prior to the BART Compliance Date, EU s AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with fuel oil, for Scenario II - up to the approved maximum firing rates and maximum fuel oil sulfur contents
indicated below. On and after the BA RT Compliance Date, EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with
fuel oil during emergencies , with a maximum sulfur content of 15 ppmw, during emergencies. “Emergencies” are defined as: [OAC 252:100-31] i. extreme and unusual fuel supply circumstan ces which prevent adequate supply of fuel (natural gas) to the facility; and
ii. such circumstances are the result of a natural disaster, an Act of God, an equipment failure associated with a pipeline, compre ssor station, or gas plant, and which could not have been reasonably foreseen or prevented.

Proposed Wording:

b. Prior to the BART Compliance Date, EU s AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with fuel oil, for Scenario II - up to the approved maximum firing rates and maximum fuel oil sulfur contents
indicated below. On and after the BA RT Compliance Date, EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with fuel oil, with a maximum sulfur content of 15 ppmw, during emerge ncies and short term periods for testing for emergency preparedness . “Emergencies” are defined as: [OAC 252:100-31] i. extreme and unusual fuel supply circumstan ces which prevent adequate supply of fuel (natural gas) to the facility; and
ii. such circumstances are the result of a natural disaster, an Act of God, an equipment failure associated with a pipeline, compre ssor station, or gas plant, and which could not have been reasonably foreseen or prevented.

State Review This facility is not located with in 50 miles of the Oklahoma border.

EPA Review The proposed permit was forwarded to EPA Re gion VI for a 45-day review period. No
comments were received from the EPA.

Fees Paid Part 70 operating permit significant m odification application fee of $1,000.PERMIT MEMORANDUM 2005-037-TVR (M-1) Page 32

SECTION XI. SUMMARY

The facility is operating as stated in the appl ication. 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 operating permit is recommended.PERMIT TO OPERATE
AIR POLLUTION CO NTROL FACILITY
SPECIFIC CONDITIONS

Western Farmers Electric Coopera tive Permit Number 2005-037-TVR (M-1)
Anadarko Power Plant

The permittee is authorized to operate in confor mity with the specifica tions submitted to Air Quality on September 6, 1996, June 19, 2003, January 31, 2005, and Marc h 20, 2007 and all supplemental materials. The Evaluation Memorandum , dated July 9, 2010, explains the derivation of applicable permit requirements and estimate s of emissions; however, it does not contain operating limitations or permit requi rements. Continuing operations under this permit constitutes acceptance of, and consent to, th e conditions contained herein:

1. Points of emissions and limitations for each point: [OAC 252:100-8-6(a)(1)]

EUG 1: Emission limitations for emission un its (EUs) AN-UNIT1R and AN-UNIT2R.

Emission Unit

Units NO X CO

AN-UNIT1R lb/hr 7.8 33.5

TPY 11.3 48.5
lb/MMBTU 0.2

AN-UNIT2R lb/hr 7.8 33.5

TPY 11.3 48.5
lb/MMBTU 0.2

a. The permittee shall be authorized to ope rate AN-UNIT1R and AN-UNIT2R up to a maximum combined total of 5,800 hours pe r 12-month period. [OAC 252:100-8-6(a)]
b. AN-UNIT1R and AN-UNIT2R shall only be fire d with commercial-grade natural gas. [OAC 252:100-31]

c. Each emission unit AN-UNIT1R and AN-UNIT2R shall have a permanent identification plate attached which shows the make , model number, and serial number. [OAC 252:100-43]
d. EU AN-UNIT1R and AN-UNIT2R ar e subject to New Source Performance Standards, 40 CFR 60, Subpart Db, and shall comply with all applicab le requirements. [§§ 60.40b through 60.49b] (1) Except as provided under § 60.44b (k), on and after the date on which the initial performance test is completed or is re quired to be completed under § 60.8, whichever date comes first, no owner or operator of an affected facility that is subject to the provisions of this section and that com busts only natural gas shall cause to be discharged into the atmosphere from that affected facility any gases that contain nitrogen oxides (expressed as NO 2 ) in excess of the following emission limit: (i) High heat release rate: 86 ng/J (0.20 lb/million Btu) [§ 60.44b(a)(1)]SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 2

(2) For purposes of § 60.44b (i), the nitrogen oxi de standards under this section apply at all times including periods of startu p, shutdown, or malfunction. [§ 60.44b(h)] (3) Except as provided under § 60.44b (j), co mpliance with the emission limits is determined on a 30-day rolling average basis. [§ 60.44b(i)] (4) The nitrogen oxides emission standa rds under § 60.44b apply at all times. [§ 60.46b(a)] (5) Compliance with the nitrogen oxides em ission standards under § 60.44b shall be determined through performance testing under § 60.46b(e). [§ 60.46b(c)] (6) To determine compliance with the emission limits for nitrogen oxides required under § 60.44b, the owner or operator of an affected facility sh all conduct the performance test as required under § 60.8 using the c ontinuous system fo r monitoring nitrogen oxides under § 60.48(b). [§ 60.46b(e)] (i) For the initial compliance test, nitroge n oxides from the steam generating unit are monitored for 30 successive steam generating unit operating days and the 30-day average emission rate is used to determine compliance with the nitrogen oxides emission standards under § 60.44b. The 30-day average emission rate is calculated as the averag e of all hourly emissions data recorded by the monitoring system during the 30-day test period. [§ 60.46b(e)(1)] (ii) Following the date on which the initial performance test is completed or required to be completed under § 60.8, whichever date comes first, the owner or operator of an affected f acility which has a heat i nput capacity of 73 MW (250 million Btu/hour) or less and which combus ts natural gas, distillate oil, or residual oil having a nitrogen content of 0.30 weight percent or less shall upon request determine compliance with th e nitrogen oxides standards under § 60.44b through the use of a 30-day performa nce test. During periods when performance tests are not requested, ni trogen oxides emissions data collected pursuant to § 60.48b(g)(1) or § 60.48b(g)(2) are used to calculate a 30-day rolling average emission rate on a daily basis and used to prepare excess emission reports, but will not be used to determine compliance with the nitrogen
oxides emission standards. A new 30-da y rolling average emission rate is calculated each steam genera ting unit operating day as th e average of all of the hourly nitrogen oxides emission data fo r the preceding 30 steam generating unit operating days. [§ 60.46b(e)(4)] (7) Except as provided under paragraphs § 60.48b(g) , (h), and (i), th e owner or operator of an affected facility subject to the nitrogen oxides standards under § 60.44b shall install, calibrate, maintain, and operate a continuous monitoring system for measuring nitrogen oxides emissions discharged to th e atmosphere and record the output of the system. [§ 60.48b(b)] (8) The continuous monitoring systems require d under § 60.48b(b) shall be operated and data recorded during all pe riods of operation of the affected facility except for continuous monitoring system breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments. [§ 60.48b(c)]SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 3

(9) The 1-hour average nitrogen oxides emission rates m easured by the continuous nitrogen oxides monitor required by § 60.48b(b) and required under § 60.13(h) shall be expressed in ng/J or lb/million Btu heat input and shall be used to calculate the average emission rates under § 60.44b. The 1-hour averages shall be calculated using the data points required under § 60.13(b). At least 2 data points must be used to
calculate each 1-hour average. [§ 60.48b(d)] (10) The procedures under § 60.13 shall be followed for in stallation, evaluation, and operation of the continuous monitoring systems. [§ 60.48b(e)] (i) For affected facilities combusting natura l gas the span value for nitrogen oxides is 500 ppm. [§ 60.48b(e)(2)] (11) When nitrogen oxides emission data are not obtained because of continuous monitoring system breakdowns , repairs, calibration ch ecks and zero and span adjustments, emission data will be obtained by using standby monitoring systems, Method 7, Method 7A, or other approved reference methods to provide emission data for a minimum of 75 percent of the opera ting hours in each steam generating unit operating day, in at least 22 out of 30 su ccessive steam generating unit operating days. [§ 60.48b(f)] (12) The owner or operator of each affected facility shall submit notification of the date of initial startup, as provided by § 60.7. This notification shall include: [§ 60.49b(a)] (i) The design heat input capacity of the affect ed facility and identification of the fuels to be combusted in the affected facility, (ii) If applicable, a copy of any Federally en forceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under §§ 60.44b(c), (d), (e), (i), (j), (k), or 60.48b(i), and (iii) The annual capacity factor at which the owner or operator anticipates operating the facility based on all fuels fired and based on each individual fuel fired. (13) The owner or operator of each affected facility subject to the nitrogen oxides emission limits under § 60.44b shall submit to the Administrator the performance test data from the initial performance test an d the performance evaluation of the CEMS using the applicable perf ormance specifications in appendix B. [§ 60.49b(b)] (14) The owner or operator of each affected facility subject to the nitrogen oxides standard of § 60.44b who seeks to demonstrate comp liance with those st andards through the monitoring of steam generating unit operati ng conditions under th e provisions of § 60.48b(g)(2) shall submit to the Administrator for approval a plan that identifies the operating conditions to be monitored unde r § 60.48b(g)(2) and the records to be maintained under § 60.49b(j). This plan shall be submitted to the DEQ for approval within 360 days of the initial startup of the affected f acility. The plan shall: [§ 60.49b(c)] (i) Identify the specific operating conditions to be monitored and the relationship between these operating conditions and nitrogen oxides emission rates (i.e., ng/J or lbs/million Btu heat input). Steam generating unit operating conditions include, but are not limited to, the degree of staged combustion (i.e., the ratio of primary air to secondary and/or tertiary air) and the level of excess air (i.e., flue gas oxygen level);SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 4

(ii) Include the data and information that the owner or operator us ed to identify the relationship between nitrogen oxides emission rates and these operating conditions; (iii) Identify how these operating conditions, including steam generating unit load, will be monitored under § 60.48b(g) on an hourly basis by the owner or operator during the period of operation of the a ffected facility; the quality assurance procedures or practices that will be employed to ensure that the data generated by monitoring these operating conditions will be representative and accurate; and the type and format of the record s of these operating conditions, including steam generating unit load, that will be maintained by the owner or operator under § 60.49b(j). If the plan is approved, the owner or operato r shall maintain records of predicted nitrogen oxide emi ssion rates and the monitored operating conditions, including steam generating un it load, identified in the plan. (15) The owner or operator of an affected facility shall record and maintain records of the amount of natural gas combusted each day and calculate the annual capacity factor for each calendar quarter. The annual cap acity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of each
calendar month. [§ 60.49b(d)] (16) Except as provided under § 60.49b(p), the owner or operator of an affected facility subject to the nitrogen ox ides standards under § 60.44b shal l maintain records of the following information for each steam gene rating unit operating day: [§ 60.49b(g)] (i) Calendar date. (ii) The average hourly nitrogen oxides emission rates (expressed as NO 2 ) (ng/J or lb/million Btu heat input) measured or predicted. (iii) The 30-day average nitrogen oxides emission rates (ng/J or lb/million Btu heat input) calculated at the end of each st eam generating unit operating day from the measured or predicted hourly nitrogen oxide emission rates for the preceding 30 steam generating unit operating days. (iv) Identification of the steam generating un it operating days when the calculated 30-day average nitrogen oxides emission ra tes are in excess of the nitrogen oxides emissions standards under § 60.44b, with the reasons for such excess emissions as well as a descripti on of corrective actions taken. (v) Identification of the steam generating unit operating days for which pollutant data have not been obtained, including r easons for not obtaining sufficient data and a description of co rrective actions taken. (vi) Identification of the times when emissi on data have been excluded from the calculation of average emission rates and the reasons for excluding data. (vii) Identification of ‘‘F’’ factor used for calculations, method of determination, and type of fuel combusted. (viii) Identification of the times when the po llutant concentration exceeded full span of the continuous monitoring system. (ix) Description of any modifications to the continuous monitoring system that could affect the ability of the conti nuous monitoring system to comply with Performance Specification 2 or 3.SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 5

(x) Results of daily CEMS drift tests a nd quarterly accuracy assessments as required under append ix F, Procedure 1. (17) The owner or operator of any a ffected facility in any catego ry listed in paragraphs § 60.49b(h)(1) or (2) is require d to submit excess emission reports for any calendar quarter during which there are excess emissions from the affected facility. If there are no excess emissions during the calenda r quarter, the owner or operator shall submit a report semiannually stating that no excess emissions occurred during the semiannual reporting period. [§ 60.49b(h)] (i) Any affected facility subject to the op acity standards under § 60.43b(e) or to the operating parameter monitoring requirements under § 60.13(i)(1). (ii) Any affected facility that is subject to the nitrog en oxides standard of § 60.44b, and that (i) Combusts natural gas, distillate oil, or residual oil with a nitrogen content of 0.3 weight percent or less, or (ii) Has a heat input capacity of 73 MW (250 million Btu/hour) or less and is required to monitor nitrogen oxides
emissions on a continuous basis under § 60.48b(g)(1) or steam generating unit operating conditions under § 60.48b(g)(2). (iii) For purposes of § 60.48b(g)(1), excess emissions are defined as any calculated 30-day rolling average nitrogen oxides emission rate, as determined under § 60.46b(e), which exceeds the applicab le emission limits in § 60.44b.

1. The owner or operator of any affected facility subject to the continuous monitoring requirement s for nitrogen oxides under § 60.48(b) shall submit a quarterly re port containing the information recorded under paragraph (g) of this section. All quarterly reports shall be postmarked by the 30th day following the end of each calendar quarter. (18) All records required under § 60.49b shall be ma intained by the ow ner or operator of the affected facility for a period of 2 years following the date of such record. [§ 60.49b(o)]

EUG 2: EU AN-UNIT3 is “grandfathered” (cons tructed prior to May 31, 1972). The equipment is limited to the existing equipment as it is.

EU Manufacturer MMBTUH MW Serial

Number AN-UNIT3 Riley Stoker 531 44 3333

a. EU AN-UNIT3 shall only be fired with commercial-grade natural gas. [OAC 252:100-31]SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 6

EUG 3: Emission limitations for emission un its (EUs) AN-UNIT4, AN-UNIT5, and ANUNIT6. Scenario I (Natural Gas)

Permitted Emissions

Emission Unit Units NO X CO VOC PM 10 SO 2

AN-UNIT4 lb/hr 580.0 93.7 20.5 35.7 0.5

TPY 2,239.1 410.5 89.6 156.4 2.4

AN-UNIT5 lb/hr 580.0 93.7 20.5 35.7 0.5

TPY 2,239.1 410.5 89.6 156.4 2.4

AN-UNIT6 lb/hr 580.0 93.7 20.5 35.7 0.5

TPY 2,239.1 410.5 89.6 156.4 2.4

Scenario II (Fuel Oil No. 2)

Emission Unit Permitted Emissions

Units NO X CO VOC PM 10 SO 2 AN-UNIT4 lb/hr 630.5 40.9 14.5 52.0 74.43

TPY 2,761.5 179.1 63.4 227.6 326.00

AN-UNIT5 lb/hr 630.5 40.9 14.5 52.0 74.43

TPY 2,761.5 179.1 63.4 227.6 326.00

AN-UNIT6 lb/hr 630.5 40.9 14.5 52.0 74.43

TPY 2,761.5 179.1 63.4 227.6 326.00

Scenario III (BART)

Permitted Emissions

Emission Unit Units NO X CO VOC PM 10 SO 2

AN-UNIT4 lb/hr 1 170.0 93.7 20.5 6.7 0.6

TPY 744.6 410.5 89.6 29.3 2.6

AN-UNIT5 lb/hr 1 170.0 93.7 20.5 6.7 0.6

TPY 744.6 410.5 89.6 29.3 2.6

AN-UNIT6 lb/hr 1 170.0 93.7 20.5 6.7 0.6

TPY 744.6 410.5 89.6 29.3 2.6

1 – Based on a 24-hour average.SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 7

c. The permittee shall conduct daily visual obser vations of the opacity from the exhausts associated with emission units burning fuel oil No. 2 and keep a record of these
observations. If visible emi ssions are detected, then the permittee shall c onduct a thirtyminute opacity reading in accordance with EPA Reference Method No. 9. [OAC 252:100-25]
d. Prior to the BART Compliance Date, EU s AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with fuel oil, for Scenario II - up to the approved maximum firing rates and maximum fuel oil sulfur contents
indicated below. On and after the BA RT Compliance Date, EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall be fueled with commercial-grade natural gas but may be fueled with fuel oil, with a maximum sulfur content of 15 ppmw, during emerge ncies and short term periods for testing for emergency prepar edness. “Emergencies” are defined as: [OAC 252:100-31] i. extreme and unusual fuel supply circumstan ces which prevent adequate supply of fuel (natural gas) to the facility; and
ii. such circumstances are the result of a natural disaster, an Act of God, an equipment failure associated with a pipeline, compre ssor station, or gas plant, and which could not have been reasonably foreseen or prevented.

e. The “BART Compliance Date” shall mean the date no later than five (5) years after EPA’s approval of Oklahoma’s regional haze State Im plementation Plan (SIP) incorporating the BART requirements, as publishe d in the Federal Register.
f. When firing fuel oil in EU AN-UNIT4, AN-UNIT5, and AN-UNIT6, as authorized by Scenario II, the permittee shall determine the sulfur content of the fuel oil being combusted and not exceed the following maximum fuel oil firing rates based on the fuel oil sulfur content and the number of units being fired with fuel oil. The fuel oil sulfur content can be determined using the following methods: a curr ent lab analysis or a supplier’s delivery
ticket.

Fuel Oil
% Sulfur Maximum Firing
Rate When 3 Units

Are Operating

(gal/hr/unit) Fuel Oil
% Sulfur Maximum Firing
Rate When 2 Units

Are Operating

(gal/hr/unit) Fuel Oil
% Sulfur Maximum Firing Rate
For 1 Unit

(gal/hr)
0.340 1,000

0.330 1,100

0.320 1,200

0.310 1,300

0.185 1,000 0.300 1,400

0.180 1,100 0.290 1,500

0.140 1,000 0.175 1,200 0.280 1,600

0.135 1,100 0.170 1,300 0.275 1,700

0.130 1,200 0.165 1,400 0.270 1,800

0.125 1,300 0.160 1,500 0.265 2,000

0.120 1,500 0.155 1,600 0.260 2,100

0.115 1,700 0.150 1,900 0.255 2,300

0.110 2,000 0.145 2,200 0.250 2,700SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 8

Fuel Oil
% Sulfur Maximum Firing
Rate When 3 Units

Are Operating

(gal/hr/unit) Fuel Oil
% Sulfur Maximum Firing
Rate When 2 Units

Are Operating

(gal/hr/unit) Fuel Oil
% Sulfur Maximum Firing Rate
For 1 Unit

(gal/hr)
0.105 2,500 0.140 2,800 0.245 4,600

0.100 5,000 0.135 4,600 0.240 4,800

0.095 5,300 0.130 4,900 0.235 5,000

0.090 5,700 0.125 5,200 0.230 5,200

0.085 6,100 0.120 5,500 0.225 5,300

0.080 6,500 0.115 5,700 0.220 5,400

0.110 6,000 0.215 5,600

0.105 6,500 0.210 5,700

0.205 5,900

0.200 6,100

0.195 6,200

0.190 6,500

EUG 4: Emission limitations for EU AN-ENG1. EU AN-ENG1 shall not be operated more than 500 hours per 12-month period.

Permitted Emissions

Emission Unit Units NO X CO VOC

AN-ENG1 lb/hr 8.93 2.33 0.29 309-hp Cummings TPY 39 10 1.27

EUG 5: Storage tank VOC emissions are estimated based on existing equipment items but do not have a specific limitation.

Point Contents Barrels Gallons

T-1 Fuel Oil No. 2 443 18,600

T-3 Fuel Oil No. 2 109,524 4,600,000

T-4 Fuel Oil No. 2 109,524 4,600,000 T-5 Unleaded Gasoline (UST) 238 10,000 T-6 Unleaded Gasoline (UST) 238 10,000 T-7 Diesel Fuel (UST) 286 12,000

T-8 Condensate 298 12,500

T-10 Lube Oil 71 3,000

T-11 Mineral Oil 71 3,000

T-12 Mineral Oil 71 3,000SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 9

2. The permittee shall be authorized to operate this facility conti nuously (24 hours per day, every day of the year) except as provided above. [OAC 252:100-8-6(a)]

3. Each emission unit at the facility (EUs AN-UNIT1 through AN-UNIT6 and AN-ENG1) shall have a permanent identification plate atta ched which shows the make, model number, and
serial number. [OAC 252:100-43]

4. The permittee shall keep operation an d maintenance (O&M) records for the “grandfathered” emission unit identified in EUG 2 and the combined cycle gas turbines in EUG
3. Such records shall at a minimum include th e dates of operation, and maintenance, type of work performed, and the increase, if any, in em issions as a result. [O AC 252:100-8-6 (a)(3)(B)]

5. At least every five years, the permittee shall conduct tests of NO X and CO concentrations in exhaust gases from AN-UNIT4 through AN-UNI T6 when operating under representative conditions for that period. Testing shall be conducted using approved reference methods and shall be submitted with the Title V permit re newal application. [OAC 252:100-8-6 (a)(3)(A)]

6. When operational data of the combined cycle gas turbines shows concentrations in excess of the established emission limits (in excess of lb/hr and lb/MMBTU), the owner or operator shall comply with the provisions of OAC 252:100-9. [OAC 252:100-9]

7. The facility is subject to Acid Rain Pr ogram and shall comply with all applicable requirements including the following:

a. SO 2 actual emissions shall be equal to or less than allowances held.
b. Report quarterly emissions to EPA per 40 CFR 75.

c. Maintain a QA/QC plan for mainte nance of the monitoring system.

8. Replacement (including temporary periods of 6 months or less for maintenance purposes, etc.), of the emergency pump engine with one of lesser or equal emissions of each pollutant (in lb/hr and TPY) is authorized under the fo llowing conditions: [OAC 252:100-8-6 (a)(3)(A)]

a. The permittee shall notify AQD in writing at least 7 days in advance of the replacement. Said notice shall include th e new engine make and model, horsepower rating, fuel usage, stack flow (ACFM), stack temperature ( o F), stack height (feet), stack diameter (inches), and pollutant emi ssion rates (g/hp-hr, lb s/hr, and TPY) at maximum rated horsepower for the altitude/location.

9. The following records shall be maintained on-s ite to verify Insignificant Activities. No recordkeeping is required for those operat ions which qualify as Trivial Activities. [OAC 252:100-8-6 (a)(3)(B)]

a. For fuel storage/dispensing equipment operated solely for facility ow ned vehicles: Records of the type and amount of fuel dispensed (annual).SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 10

b. For fluid storage tanks with a capacity of le ss than 39,894 gallons and a true vapor pressure less than 1.5 psia: Record s of the capacity of the tanks and the contents.

c. For crude oil and condensate storage tanks w ith a capacity of less than or equal to 420,000 gallons that store crude oil and condensate prior to custody transfer: Record s of capacity of
the tanks and the amount of throughput (annual).
d. For activities (except fo r trivial activities ) that have the potential to emit less than 5.0 TPY (actual) of any criteria pollutant: The type of activity and the amount of emissions or a surrogate measure of the activity (annual).

10. The permittee shall maintain records of operati ons as listed below. These records shall be
maintained on-site for at least five years after the date of r ecording and shall be provided to regulatory personnel upon request

. [OAC 252:100-8-6 (a)(3)(B)]

a. Total natural gas and/or distillate fuel oil usage for each boiler and each combined cycle gas turbine (annual).
b. Operating hours for the EU AN-UNIT 1R, AN-UNIT2R, AN-ENG1 (monthly 12- month rolling totals).

c. Operation, maintenance, and inspecti on log for EU AN-UNIT3 through AN-UNIT6.
d. Unit load for each combined cycle gas turbine.

e. Fuel oil sulfur content when firing fu el oil (analysis or delivery tickets).
f. Records of the date and time of visual emission observations, stack or emission point observed, operational status of the emission unit, observed results and conclusions, and
Reference Method No. 9 results.

11. No later than 30 days after each anniversary date of the issuance of the original Title V permit (June 26, 2000), the permittee shall submit to Air Quality Division of DEQ, with a copy to the US EPA, Region 6, a certification of comp liance with the terms and conditions of this permit. [OAC 252:100-8- 6 (c)(5)(A) & (D)]

12. The Permit Shield (Standard Conditions, Section VI) is extended to the following requirements that have been determin ed to be inapplicable to this facility or the listed emissions units: [OAC 252:100-8-6(d)(2)]

a. NSPS, Subpart D, Solid Fossil Fuel-Fired Steam Generators;
b. NSPS, Subpart Da, Electric Ut ility Steam Generating Units;

c. NSPS, Subpart GG, Stationary Gas Turbines;
d. AN-UNIT1R, AN-UNIT2R, and AN-UNIT4 th rough AN-UNIT6 are not subject to 40 CFR Part 72, Acid Rain Permit Application; and

e. Emission units AN-UNIT3 through AN-UNIT 6 are not subject to OAC 252:100-33, Control of Emissions of Nitrogen Oxides.SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 11

13. The turbines in EUG 3 (EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6) are exempt from
Best Available Retrofit Technol ogy (BART) requirements of 40 CF R Part 51, Subpart P, as long as the facility complies with the following applicable requirements: [40 CFR §§ 51.300-309 & Part 51, Appendix Y]

a. EUs AN-UNIT4, AN-UNIT5, and AN-UNIT6 shall meet the following emission limits no later than the BART Compliance Date as defined in Specific Condition 1, EUG 3, (c).

NO X PM 10 2 SO 2 EU lb/hr 1 TPY lb/hr 1 TPY lb/hr 1 TPY

AN-UNIT4 170.0 744.6 6.7 29.3 0.6 2.6

AN-UNIT5 170.0 744.6 6.7 29.3 0.6 2.6

AN-UNIT6 170.0 744.6 6.7 29.3 0.6 2.6

1 – 24-hour rolling average;

2

– includes condensable/filterable PM.

b. The permittee shall apply for and obtain a co nstruction permit prior to modification of
the turbines if the modifications will resu lt in a significant emission increase and a significant net emission increase of a regulat ed NSR pollutant. Af ter modification, the facility shall apply for and obtain an ope rating permit modification to remove any
emission limit in excess of the above emission limits.

c. The emission limits above shall apply at all times on or after the BART Compliance Date
unless otherwise modified.
d. Unit operating day shall have the same m eaning as in 40 CFR Part 60, Subpart KKKK.

e. Within 60 days of achieving the maximum production rate at which EUs AN-UNIT4, ANUNIT5, and AN-UNIT6 will be operated to meet the above established emission limits, not to exceed 180 days after the BART Co mpliance Date, the permittee shall conduct performance testing as follows and furnish a written report to Air Quality. Such report shall document compliance with the above emission limits for EUs AN-UNIT4, ANUNIT5, and AN-UNIT6. [OAC 252:100-8-6(a)] i. The permittee shall conduct NO X , PM 10 , and CO testing on the turbines at 60% and 100% of the maximum capacity. NO X and CO testing shall also be conducted at least
one additional intermediate point in the operating range. ii. Performance testing shall be conducted wh ile the units are operating within 10% of the desired testing rates. A testing prot ocol 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 te sting. 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 Ga s Velocity and Volumetric Flow

Rate.SPECIFIC CONDITIONS 2005-037-TVR (M-1) Page 12

Method 3: Gas Analysis for Car bon Dioxide, Excess Air, and Dry Molecular Weight.
Method 4: Determination of Moisture in Stack Gases.
Method 10: Determination of Carbon Monoxide Emissions from Stationary Sources. Method 6C: Quality Assurance Procedures (Range and Sensitivity, Measurement System Perf ormance Specification, and Measurement System Performance Test Procedures) shall be used in conducting Method 10.
Method 20: Determination of Nitr ogen Oxides and Oxygen Emissions from Stationary Gas Turbines.
Method 201/201A: Determination of PM 10 Emissions.
Method 202: Determination of Conde nsable Particulate Emissions.

14. This permit supersedes all previous Air Qualit y permits for this facility, which are now null
and void.Western Farmers Electric Cooperative
Attn: Mr. Gerald Butcher
Environmental Coordinator

701 NE 7 th Street Anadarko, OK 73005-0429

SUBJECT: Permit 2005-037-TVR (M-1)
Anadarko Power Plant
Location: Section 14-T7N- R10W, Caddo County, Oklahoma

Dear Mr. Butcher:

Enclosed is the permit authorizing operation of the referenced facility. Please note that this permit is issued subject to the certain standards and specific conditions th at are attached. These conditions must be carefully followed since they define the limits of the permit and will be confirmed by periodic inspections.

Also note that you are required to annually submit an emissions inve ntory for this facility. An emissions inventory must be completed on approved AQD forms and submitted (hardcopy or electronically) by March 1 st of every year. Any questions concerning the form or submittal process should be referred to the Em issions Inventory Staff at 405-702-4100.

If you have any questions, refer to the permit number above and contact Eric Milligan at eric.milligan@deq.ok.gov or at (405) 702-4217. Thank you for your cooperation.

Sincerely,

Eric L. Milligan, P.E. Engineering Section AIR QUALITY DIVISION

EnclosuresMAJOR 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. [Okl ahoma Clean Air Act, 27A O.S. § 2-5-112]

B. The issuing Authority for the permit is th e Air Quality Division (AQD) of the Oklahoma Department of Environmental Quality (DEQ). The permit does not relieve the holder of the obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or ordinances. [Oklahoma Clean Ai r Act, 27A O.S. § 2-5-112]

C. The permittee shall comply with all conditi ons of this permit. Any permit noncompliance
shall constitute a violation of the Oklahoma Cl ean Air Act and shall be grounds for enforcement action, permit termination, revocation and reissuance, or modifi cation, 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 a nd 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 haltin g or reducing operations would be more serious than the impacts of continuing operations. [O AC 252:100-8-6(a)(7)(B)]

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from an emergency and/or posing an imminent and substantial danger to public health, safety, or the environm ent shall be reported in accordance with Section XIV (Emergencies). [OAC 252:100- 8-6(a)(3)(C)(i ii)(I) & (II)]

B. Deviations that result in emissions exceedin g those allowed in this permit shall be reported consistent with the requirem ents of OAC 252:100-9, Excess Em ission Reporting Requirements. [OAC 252:100-8-6(a)(3)(C)(iv)]

C. Every written report submitted under this sectio n shall be certified as required by Section III (Monitoring, Testing, Re cordkeeping & Reporting), Paragraph F. [OAC 252:100-8-6(a)(3)(C)(iv)]TITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 2

SECTION III. MONITORING, TES TING, RECORDKEEPING & REPORTING

A. The permittee shall keep records as specified in this permit. These records, including monitoring data and necessary support information, shall be retained on-sit e or at a nearby field office for a period of at least five years from th e date of the monitoring sample, measurement, report, or application, and shall be made av ailable for inspection by regulatory personnel upon request. Support information includes all orig inal strip-chart recordings for continuous monitoring instrumentation, and copies of all repo rts required by this perm it. 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 techni ques or methods used; (5) the results of such analyses; and (6) the operating conditions existing at th e time of sampling or measurement. [OAC 252:100-8- 6(a)(3)(B)(i)]

C. No later than 30 days after each six (6) month period, after the date of the issuance of the original Part 70 operating permit or alternative date as specifically identified in a subsequent Part 70 operating permit, the permittee shall submit to AQD a report of the results of any required monitoring. All instances of deviations from permit requireme nts since the prev ious report shall be clearly identified in the report. Submission of these periodic reports will satisfy any reporting requirement of Paragraph E below that is duplicative of the periodic reports, if so noted on the submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)]

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or operator shall comply with the provisions of S ection II (Reporting Of Deviations From Permit Terms) of these standard conditi ons. [OAC 252:100-8-6( a)(3)(C)(iii)]

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this permit, monitoring and reporting may be re quired under the provisions of OAC 252:100-43, Testing, Monitoring, and Recordkeep ing, or as required by any pr ovision 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 Emi ssion Inventory submitted in accordance with this permit shall be certified by a responsible o fficial. This certification shall be signed by a responsible official, and shall contain the follow ing language: “I certif y, based on information and belief formed after reasonable inquiry, the st atements 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)]TITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 3

G. Any owner or operator subj ect to the provisions of Ne w Source Performance Standards (“NSPS”) under 40 CFR Part 60 or National Emi ssion Standards for Hazardous Air Pollutants (“NESHAPs”) under 40 CFR Parts 61 and 63 shall main tain a file of all measurements and other information required by the applicable general provi sions and subpart(s). These records shall be maintained in a permanent file suitable for insp ection, shall be retained for a period of at least five years as required by Paragraph A of this Section, and sh all include records of the occurrence and duration of any start-up, shutdo wn, or malfunction in the operati on of an affected facility, any malfunction of the air pollution control equipment; and any periods during which a continuous monitoring system or monitoring device is inoperative. [40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q]

H. The permittee of a facility that is operating subject to a schedule of compliance shall submit to the DEQ a progress report at least semi-annuall y. The progress reports shall contain dates for achieving the activities, milestones or compliance required in the schedule of compliance and the dates when such activities, milestones or comp liance was achieved. Th e progress reports shall also contain an explanation of why any dates in the schedule of compliance were not or will not be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)]

I. All testing must be conducted under the direction of qualified personnel by methods approved by the Division Director. All tests 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 ma nufacturer’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 Emissi on 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 b ack-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 equipment constructed or operated under this permit subject to such standards. [OAC 252: 100-8-6(c)(1) and OAC 252:100, Appendix Q]

SECTION IV. COMP LIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70 operating permit or alternative date as specificall y identified in a subsequent Part 70 operating permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a certification of compliance with the terms and conditions of this permit and of any other applicable requirements which have become ef fective since the issuance of this permit. [OAC 252:100-8-6(c)(5)(A), and (D)]TITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 4

B. The compliance certification sha ll describe the operating permit term or condition that is the basis of the certification; the current compliance status; whethe r compliance was continuous or intermittent; the methods used for determining compliance, currently and over the reporting period. The compliance certification shall also include such other facts as the permitting authority may require to determine th e compliance status of the source. [OAC 252:100-8-6(c)(5)(C)(i)-(v)]

C. The compliance certification sh all contain a certifica tion by a responsible official as to the results of the required monitoring. This certification shall be si gned by a responsible official, and shall contain the following language: “I certify, based on information and belief formed after reasonable inquiry, the statements and in formation 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 applicable requirements. This
schedule shall include a schedule of remedial measures, including an enforceable sequence of actions with milestones, leading to compliance w ith any applicable requirements for which the emissions unit or stationary source is in noncompliance. This compliance schedule shall resemble and be at least as stringent as that contained in any judicial consent decree or
administrative order to which the emissions unit or stationary source is subject. Any such schedule of compliance shall be supplemental to , and shall not sanction noncompliance with, the applicable requirements on which it is based, excep t that a compliance plan shall not be required for any noncompliance condition which is corrected within 24 hours of discovery. [OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)]

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE

PERMIT TERM

The permittee shall comply with any additional requirements that become effective during the permit term and that are applicable to the fac ility. Compliance with all new requirements shall
be certified in the next annual cer tification. [OAC 252:100-8-6(c)(6)]

SECTION VI. PERMIT SHIELD

A. Compliance with the terms and conditions of this permit (including terms and conditions established for alternate operating scenarios, emissions trading, and emissions averaging, but excluding terms and conditions for which the permit shield is expressly prohibited under OAC 252:100-8) shall be deemed compliance with the applicable requirements identified and included in this permit. [OAC 252:100-8-6(d)(1)]

B. Those requirements that are applicable are li sted in the Standard Conditions and the Specific Conditions of this permit. Thos e requirements that the applicant requested be determined as not applicable are summarized in the Specific Condi tions of this permit. [OAC 252:100-8-6(d)(2)]TITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 5

SECTION VII. ANNUAL EMISSI ONS 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 availa ble information accepted by AQD. [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, th e term of an operating permit sha ll 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 expirati on of its permit unless a timely and complete renewal application has been su bmitted 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 provi ded 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 sha ll 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 perm it, or the application of any provision of this permit to any circumstance, is held in valid, the application of such provision to other circumstances, a nd the remainder of this permit, shall not be affected thereby. [OAC 252:100-8-6 (a)(6)]

SECTION X. PROPERTY RIGHTS

A. This permit does not convey any proper ty rights of any sort, or any exclusive privilege. [OAC 252:100-8-6(a)(7)(D)]

B. This permit shall not be considered in a ny manner affecting the title of the premises upon which the equipment is located and does not rel ease the permittee from any liability for damage
to persons or property caused by or resulting from the mainte nance 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 r eceipt of a written requ est and within sixty (60) days of the request unless the DEQ specifi es another time period, any information that theTITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 6

DEQ may request to determine whether cause exists for modifying, reopening, revoking, reissuing, terminating th e 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)]

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 shal l be clearly la beled 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 f acility 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 modifications , the filing of a request by the permittee for a permit modification, revocation and reissuance, te rmination, notification of planned changes, or anticipated noncompliance does not stay any permit condition. [OAC 252:100-8-6(a)(7)( C) and OAC 252:100-8-7.2(b)]

B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the following circumstances: [OAC 252:100- 8-7.3 and OAC 252:100-8-7.4(a)(2)]

(1) Additional requirements under the Clean Air Ac t become applicable to a major source category three or more years prior to the expiration date of this permit. No such reopening is required if the effective date of the requirement is later than the expiration date of this permit. (2) The DEQ or the EPA determines that this perm it 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 dete rmines that the permittee has submitted false or misleading information to the DEQ. (4) DEQ determines that the permit should be amended under the di scretionary 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 ch anges other than those described in Section XVIII (Operational Flexibility), those qualifying fo r administrative permit amendments, or those defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). TheTITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 7

notification should include any changes which may alter the status of a “grandfathered source,” as defined under AQD rules. Such cha nges 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 th at exceed the trivial/insignificant levels and that are not specifically approved by this perm it are prohibited. [O AC 252:100-8-6(c)(6)]

SECTION XIII. IN SPECTION & ENTRY

A. Upon presentation of credentials and othe r documents as may be required by law, the permittee shall allow authorized regulatory offi cials to perform the following (subject to the permittee's right to seek conf idential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18)
for confidential information submitted to or obtained by the DEQ under this section):

(1) enter upon the permittee's premises during reasonable/normal working hours where a
source is located or emissions -related activity is conducted, or where records must be kept under the conditions of the permit; (2) have access to and copy, at reasonable times, any records that must be kept under the conditions of the permit; (3) inspect, at reasonable times and using reasonable safety practices, any facilities, equipment (including monitoring and air po llution 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 complian ce with the permit. [OAC 252:100-8-6(c)(2)]

SECTION XIV. EMERGENCIES

A. Any exceedance resulting from an emergenc y 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 descript ion of the emergency, the probable cause of the exceedance, any steps taken to mitigate emi ssions, and corrective actions taken. [OAC 252:100-8-6 (a)(3 )(C)(iii)(I) and (IV)]

B. Any exceedance that poses an imminent and subs tantial 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, including acts of God, which situation requires immediate corrective action to restore normal ope ration, and that causes the source to exceed a technology-based emission limitation under this permit, due to unavoidable increases in emissions attributable to the emergency. An 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]TITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 8

D. The affirmative defense of emergency sh all be demonstrated through properly signed, contemporaneous operating logs or other rele vant evidence that: [O AC 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; (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 (Mon itoring, Testing, Recordkeeping & Reporting), Paragraph F. [OAC 252:100-8-6(a)(3)(C)(iv)]

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of 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 eith er on the list in Appendix I to OAC Title 252, Chapter 100, or whose actual calendar year emissi ons do not exceed any of the limits below. Any activity to which a State or Federal applicab le 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 pol lutant (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]TITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 9

SECTION XVIII. OP ERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the need for any permit revision or any notification to the DEQ (unless specified otherwise in the permit). When an operating scenario is changed, th e permittee shall record in a log at the facility the scenario under which it is operati ng. [OAC 252:100-8-6(a)(10) and (f)(1)]

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 f acility 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 defi ned 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 re quired above shall include a br ief 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 a pply to any change made pursuant to this paragraph. [OAC 252:100-8-6(f)(2)]

SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS

A. The following applicable requirements and state-only requirements apply to the facility unless elsewhere covered by a mo re restrictive requirement:

(1) Open burning of refuse and other combustible material is prohibited except as authorized in the specific examples and under the conditi ons listed in the Open Burning Subchapter. [OAC 252:100-13] (2) No particulate emissions from any fuel-burni ng equipment with a ra ted 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 op acity 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 si x-minute period exceed 60% opacity; (b) Smoke resulting from fires covered by th e exceptions outlined in OAC 252:100-13-7; (c) An emission, where the presence of uncombi ned 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 a nd immediate control of the facility andTITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 10

the immediate constriction of the fuel flow at the fac ility would produce a hazard to life and/or property. (4) No visible fugitive dust emissions shall be discharged beyond the property line on which the emissions originate in such a manner as to damage or to interfere with the use of adjacent properties, or cause air quality standa rds 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 th e listed ambient air standards for sulfur dioxide. [OAC 252:100-31] (6) Volatile Organic Compound (VOC) storag e tanks built after December 28, 1974, and with a capacity of 400 gallons or more stori ng a liquid with a vapor pressure of 1.5 psia or greater under actual conditions shall be e quipped 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 followi ng standards for production and consumption of ozone-depleting substances: [40 CFR 82, Subpart A]

(1) Persons producing, importing, or placing an or der for production or im portation 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, tr ichloroethane (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 (fleet) vehicles when this service involves an ozone-depleting substance re frigerant (or regulated substitute s ubstance) in the motor vehicle air conditioner (MVAC), the permittee is subject to a ll applicable requirements. Note: The term
“motor vehicle” as used in S ubpart B does not include a vehicle in which final assembly of the vehicle has not been completed. The term “MVAC ” as used in Subpart B does not include the air-tight sealed refrigeration system used as re frigerated cargo, or the system used on passenger buses using HCFC-22 refrigeran t. [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 pract ices pursuant to § 82.156; (2) Equipment used during the maintenance, service, repair, or disposal of appliances mustTITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 11

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 be certified by an approved technician cert ification 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 pr ocess refrigeration equipment must comply with leak repair requireme nts pursuant to § 82.158; and (6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant must keep records of refriger ant purchased and added to su ch appliances pursuant to §

82.166.

SECTION XXI. TITLE V APPROVAL LANGUAGE

A. DEQ wishes to reduce the time and work asso ciated with permit revi ew and, wherever it is not inconsistent with Federal requirements, to provide for incorporation of requirements established through construction permitting into the Source’s Title V permit without causing redundant review. Requirements from construction permits may be incorporated into the Title V permit through the administrative amendment pro cess set forth in OAC 252:100-8-7.2(a) only if the following procedures are followed:

(1) The construction permit goes out for a 30-day public notice and comment using the procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice to the public that this permit is subject to EPA review, EPA objection, and petition to EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit will be incorporated into the Title V permit through the administrative amendment process; that the public will not receive another opportunity to provide comments when the requirements are incorporated into the Title V permit; and that EPA review, EPA objection, and petitions to EPA will not be available to the public when requirements from the construction permit are incorporated into the Title V permit. (2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR § 70.8(a)(1). (3) A copy of the draft construction permit is sent to any affected Stat e, as provided by 40 C.F.R. § 70.8(b). (4) A copy of the proposed construction permit is sent to EPA for a 45-day review period as provided by 40 C.F.R.§ 70.8(a) and (c). (5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day comment period of any EPA objection to the construction permit. The DEQ shall not issue the permit until EPA’s objections are resolved to the satisfaction of EPA. (6) The DEQ complies with 40 C.F.R. § 70.8(d). (7) A copy of the final construction permit is sent to EPA as provide d by 40 CFR § 70.8(a). (8) The DEQ shall not issue the proposed construction permit until any affected State and EPA have had an opportunity to review the proposed permit, as provided by these permit conditions. (9) Any requirements of the construction permit may be reopened for cause after incorporation into the Title V permit by th e administrative amendment process, byTITLE V PERMIT ST ANDARD CONDITIONS July 21, 2009 Page 12

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). (10) The DEQ shall not issue the administrativ e permit amendment if performance tests fail to demonstrate that the source is operati ng in substantial compliance with all permit requirements.

B. To the extent that these conditions are not followed, the Title V permit must go through the Title V review process.

SECTION XXII. CREDIBLE EVIDENCE

For the purpose of submitting compliance certifica tions or establishing whether or not a person
has violated or is in violat ion of any provision of the Okla homa implementation plan, nothing shall preclude the use, including the exclusive us e, of any credible evidence or information,
relevant to whether a source woul d have been in compliance with applicable requirements if the appropriate performance or compliance te st or procedure had been performed. [OAC 252:100-43-6]