oklahoma department of environmental quality · oklahoma department of environmental quality ......

DRAFT/PROPOSED

OKLAHOMA DEPARTMENT OF ENVIRONMENTAL QUALITY

AIR QUALITY DIVISION

MEMORANDUM January 21, 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: Donna Lautzenhiser, E.I., New Source Permit Section

SUBJECT: Evaluation of Permit Application No. 2009-177-C

Devon Gas Services, L.P.

Cana Gas Plant

Section 12, T12N, R9W, Canadian County, Oklahoma

Latitude: 35.535°, Longitude: -98.099°

Directions: From the intersection of US-81 and OK-66 in El Reno, travel five

(5) miles west on OK-66, continue for four (4) miles on I-40, go north for

three-quarters (3/4) of a mile on US-270, and go east for one (1) mile on OK-

66 to Facility location.

SECTION I. INTRODUCTION

Devon Gas Services, L.P. (Devon) has requested a construction permit for their Cana Gas Plant

(SIC 1321) which will be located near the city of El Reno in Canadian County. This is a new

“grass roots” facility that is scheduled to be operational by early 2011.

The facility will not be subject to any existing Title 40 Code of Federal Regulations (CFR) Part

61 National Emission Standards for Hazardous Air Pollutants (NESHAP) or Prevention of

Significant Deterioration (PSD) permitting. However, the facility will be subject to Title V

permitting required under OAC 252:100-8 and 40 CFR Part 60 New Source Performance

Standards (NSPS) Subparts KKK, JJJJ, IIII, and KKKK and 40 CFR Part 63 Subpart ZZZZ.

Upon completion, the facility will consist of three (3) natural gas-fired turbines, three (3) diesel-

fired internal combustion power generation units, two (2) natural gas-fired compressor engines,

one (1) amine unit, one (1) regeneration heater, twelve (12) condensate storage tanks, one (1)

plant flare, one (1) thermal oxidizer, and various support operations.

Emission units (EUs) have been arranged into Emission Unit Groups (EUGs) in the following

outline. Field-grade natural gas is the primary fuel with the engines being operated continuously.

PERMIT MEMORANDUM 2009-177-C 2 DRAFT/PROPOSED

SECTION II. PROCESS DESCRIPTION

The facility is a natural gas liquids (NGL) recovery plant with a nominal design throughput of

200 MMSCFD. Natural gas is transported to the facility via a pipeline gathering system.

INLET SEPARATION AND CONDENSATE HANDLING

Initial Operation:

The inlet stream enters the facility at 650 to 950 psig through two inlet pressurized receivers for

separation of water and condensate from the gas. Free water from the inlet stream is sent to

atmospheric tanks and transported by truck for disposal. Condensate will pass through a heat

exchanger on its way to a condensate flash tank for removal of light hydrocarbons. Condensate

will then be pumped to (4) 80,000 gallon pressurized storage tanks for storage. Flash gas from

the condensate flash tanks will be compressed through (2) electric-drive compressors then

returned to the inlet of the facility. Flash vapors in excess of the compression capacity will be

sent to the flare. Condensate at approximately 200 psi TVP will be pumped into trucks; the

pumps have a vapor return line that is routed to the emergency storage tanks for vapor balancing.

Long Term Operation:

After the facility has started up, Devon anticipates installing full condensate stabilization to

reduce the vapor pressure of condensate. The (4) 80,000 gallon pressurized vessels that initially

stored condensate will then handle emergency product in the event of a pipeline or stabilizer

outage. The low RVP condensate will be stored in twelve (12) 400-bbl atmospheric condensate

tanks. The stabilized condensate will be trucked off site.

Devon also anticipates the need to install an amine treating unit for removal of CO2 as the Cana

Field develops. The amine unit will not be part of the initial installation and operation. The

amine unit would be installed downstream of the inlet separation, and upstream of the mol sieve

dehydrators. In the amine unit, CO2 will be removed from the inlet gas by contact and reaction

with an appropriate amine solution selected for the gas composition. The amine unit will be

equipped with a 25.2-MMBtu/hr regeneration heater, with heat provided by waste heat recovery

from the residue gas turbines. The amine unit waste gas will be vented to a thermal oxidizer for

control of emissions.

NGL PROCESS UNIT:

The inlet gas is then dehydrated in a molecular sieve dehydration unit. After dehydration, the

pressure and temperature of the gas is manipulated in a cryogenic NGL recovery skid for

removal of NGL products. The NGL is pumped directly to a products pipeline with emergency

storage and trucking available for short term pipeline outage. Residue gas from the NGL

recovery unit will then be compressed by three (3) natural gas-fired turbines and two (2) natural

gas-fired compressor engines. In addition, the facility will include a plant flare for combustion


of emergency release of hydrocarbons and three (3) diesel-fired engines for emergency power

generation; each engine will be limited to 500 hours per year.

SECTION III. EQUIPMENT

Sources of emissions are listed in the following table. The facility may also contain ancillary

equipment such as lube oil, ethylene glycol, and TEG storage tanks that are not subject to any

emissions limitations or requirements and are not addressed any further.

EUG-01A: Stationary Engines Subject to NSPS Subpart JJJJ

EU Emission Unit Description Construction

Date

Manufacture

Date

Serial

Number

E-07 4,735-hp Caterpillar 3616 TALE

w/oxidation catalyst NA NA NA


w/oxidation catalyst NA NA NA

NA = Not yet available

EUG-01B: Stationary Gas Turbines Subject to NSPS Subpart KKKK


Date

Manufacture

Date

Serial

Number

E-01 11,571-hp Solar Taurus 70-10302 NA NA NA

E-02 11,571-hp Solar Taurus 70-10302 NA NA NA

E-03 11,571-hp Solar Taurus 70-10302 NA NA NA NA = Not yet available

EUG-01C: Stationary Engines Subject to NSPS IIII


Date

Manufacture

Date

Serial

Number

E-04 3,634-hp Caterpillar 3516CDITA NA NA NA

E-05 3,634-hp Caterpillar 3516CDITA NA NA NA

E-06 3,634-hp Caterpillar 3516CDITA NA NA NA NA = Not yet available

EUG-02: Amine Unit

EU Emission Unit Description Construction Date

A-01 200-MMSCFD Amine Unit 2009-2010

EUG-03: Regeneration Heater


H-01 25.2-MMBTUH Regeneration Heater 2009-2011


EUG-04: Condensate Tanks


T-01 400-bbl Condensate Storage Tank 2009-2011












EUG-05: Truck Loading


L-01 Condensate Truck Loading 2009-2011

EUG-06: Process Piping Fugitive Emissions


SF-01 Process Piping Fugitive Emissions 2009-2011

EUG-07: Plant Flare


F-01 Plant Flare 2009-2011

EUG-08: Thermal Oxidizer


T-01 Thermal Oxidizer 2009-2011

EUG-09: Miscellaneous Storage Tanks


T-13 Amine Tank 2009-2011

T-14 Lube Oil Tank 2009-2011

T-15 Antifreeze Tank 2009-2011

T-16 Methanol Tank 2009-2011


SECTION IV. POTENTIAL EMISSIONS

Criteria Pollutants

Estimated emissions from the engines are based on manufacturer’s data, maximum rated

horsepower, continuous operations except as noted, and a 93% reduction of CO across the

oxidation catalyst. Emissions factors are shown in the table following.

Description NOX CO VOC

g/hp-hr g/hp-hr g/hp-hr

11,571-hp Solar Taurus 70-10302

(E-01, 2, 3) 0.20 0.20 0.11

3,634-hp Caterpillar 3516CDITA*

(E-04, 5, 6) 5.05 0.41 0.10

4,735-hp Caterpillar 3616 TALE w/oxidation catalyst

(E-07, 8) 0.50 0.25 0.50

*Emissions are based on 500 hr/yr of operation for emergency power

Emissions from the amine unit A-01 are calculated using process simulation and a natural gas

feed rate of 200-MMCFD, a maximum amine circulation rate of 487 GPM, and an extended gas

analysis, and a 98% control efficiency from the thermal oxidizer.

Emissions from the amine regeneration heater were calculated using the actual burner rating of

25.2 MMBTU/hr and emission factors obtained from manufacturer’s data along with current AP-

42 factors for commercial boilers based on AP-42 (7/98), Tables 1.4-1 and Table 1.4-2.

Emissions from the plant flare are based on the actual pilot burner rating of 0.5 MMBTUH and

AP-42 (9/91), Table 13.5 for industrial flares.

VOC emissions from the twelve (12) condensate storage tanks are calculated using EPA’s

TANKS 4.0 computer program with a maximum throughput of 54,750 bbl/year total. The

condensate is stabilized prior to entering the facility; therefore, there are no flashing losses.

Estimated VOC emissions from the tank truck loading are based on AP-42 (1/95), Chapter 5.2,

an emission factor of 5.7 lb/1,000 gallons, and 54,750 bbl/year (total). 95% control is claimed for

venting to the plant flare.

VOC emissions from process piping fugitives are based on EPA’s document, “1995 Protocol for

Equipment Leak Emission Estimates (EPA-453/R-95-017)”, an estimated number of components,

and a representative gas analysis with VOC content of 18% for components in gas service.


Potential Facility-wide Emissions

EU Description NOX CO VOC

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

E-01 11,571-hp Solar Taurus 70-10302S 5.10 22.35 5.10 22.35 2.81 12.29



E-04 3,634-hp Caterpillar 3516CDITA 40.46 10.11 3.28 0.82 0.80 0.20




w/oxidation catalyst 5.22 22.86 5.22 22.86 2.61 11.43



A-01 200-MMSCFD Amine Unit - - - - 0.72 3.14

H-01 25.2 MMBTUH Regeneration

Heater 1.64 7.17 1.92 8.39 0.14 0.60

TANK

S (12) 400-BBL Condensate Tanks - - - - - 16.08

F-01 Plant Flare 0.03 0.15 0.19 0.81 0.15 0.64

TO-01 Thermal Oxidizer 1.96 8.59 1.65 7.21 0.11 0.47

L-01 Tank Truck Load-Out Operations * - - - - - -

SF-01 Process Piping Fugitive Emissions - - - - 0.73 3.22

Total 150.75 159.01 39.35 131.64 17.81 90.72

*Truck loading emissions are vented to the plant flare.

Since emissions are less than the PSD threshold of 250 TPY, the construction project was not

subject to PSD review.

Hazardous Air Pollutants (HAP)

The compressor engines have emissions of HAP, the most significant being formaldehyde.

Emissions of formaldehyde for the lean-burn engines are based on potential emissions and a

control efficiency of 70% for the oxidation catalyst. The applicant is required to test each model

of engine for formaldehyde emissions to verify compliance with the facility-wide cap on HAP

emissions. The table below lists estimated potential controlled formaldehyde emissions for the

compressor engines based on continuous operation.


Controlled Formaldehyde Emissions from Engines

EU Description

Emission

Factor

(g/hp-hr)

Emissions

lb/hr TPY

E-01 11,571-hp Solar Taurus 70-10302 0.00071

lb/MMBtu 0.06 0.26

E-02 11,571-hp Solar Taurus 70-10302 0.00071

lb/MMBtu 0.06 0.26

E-03 11,571-hp Solar Taurus 70-10302 0.00071

lb/MMBtu 0.06 0.26


w/oxidation catalyst 0.063 0.66 2.88


w/oxidation catalyst 0.063 0.66 2.88

Totals 1.49 6.54

Amine units emit benzene, toluene, xylene and n-hexane from the exhaust. The applicant has

analyzed the incoming wet gas for concentrations of HAPs and estimated the HAP emissions

using a simulation program with a gas throughput of 200 MMSCFD, and an amine circulation

rate of 487 GPM. Unit A-01 is equipped with a Thermal Oxidizer (98% control efficiency) rated

at 20.0-MMBtu/hr on the exhaust.

Total HAP Emissions from Amine Unit

Pollutant A-01

lb/hr TPY

Benzene 0.02 0.10

Toluene 0.06 0.25

Xylene 0.06 0.28

n-Hexane 0.03 0.13

TOTALS 0.17 0.76

SECTION V. STATE BACT REVIEW

Since emissions of NOX and CO exceed 100 TPY for the facility, a state BACT review was

required by OAC 252:100-8-5(d). The applicant submitted the following BACT analysis based

on discussions with AQD.

Turbines:

The three (3) Solar Taurus 70-10302 natural gas-fired turbines (E-01, E-02, and E-03), rated at

11,571-hp each, have a NOx emission factor of 0.2 grams per horsepower-hour (g/hp-hr), a CO

factor of 0.2 g/hp-hr and a VOC emission factor of 0.11 g/hp-hr. The only add-on NOx control

available to reduce emissions from turbines is urea-injection which produces a by-product of

ammonia slip and is cost prohibitive. Additionally, these turbines are required to meet the

emission limitations for NOx under 40 CFR Part 60 Subpart KKKK. Devon proposes and DEQ

accepts no additional control for these turbines.


IC Engines:

For internal reciprocating engines, a review of the RBLC database and recently issued ODEQ

PSD permits indicates that BACT for emissions from natural gas-fired compressor engines has

been determined to be no more than 2.0 g/hp-hr for NOx, 2.0 g/hp-hr for CO, and 1.0 g/hp-hr for

VOC. This requires add-on catalytic converters for rich-burn engines or the use of low-NOX

lean-burn engines with oxidation catalysts. The natural gas-fired engines proposed by Devon

have NOx emissions equal to or less than 2.0 g/hp-hr, CO emissions less than 2.0 g/hp-hr, and

VOC emissions less than 1.0 g/hp-hr. The two (2) Caterpillar 3616 TALE natural gas-fired

engine driven compressors (E-07 and E-08), rated at 4,735-hp each, are lean-burn engines and

are each equipped with oxidation catalysts. Additionally, the engines are subject to emission

limitations of 40 CFR Part 60 Subpart JJJJ and 40 CFR Part 63 Subpart ZZZZ. For diesel-fired

generators, a review of the RBLC database indicates that the EPA Tier Certifications for the

model year are BACT. The three (3) Caterpillar 3516CDITA diesel-fired power generation

engines (E-04 through E-06), rated at 3,634-hp each, and are Tier II certified engines.

Additionally, the engines are subject to emission limitations of 40 CFR Part 60 Subpart IIII.

Therefore Devon proposes and DEQ accepts oxidation catalyst and catalytic convertor controls

as BACT for the natural gas-fired engines and the EPA Tier certification for the diesel–fired

generators.

Heaters:

A review of the RBLC database and recently issued ODEQ PSD permit applications indicates

that BACT for natural gas-fired heaters rated less than 100 MMBTUH has been determined to be

the use of Low-NOX burners with emission rates between 0.10 lb/MMBTU and 0.01

lb/MMBTU. No add-on controls are utilized for the reduction of CO emissions from heaters of

this size, typically only good combustion practice is required. The applicant has proposed the

use of a Low-NOX burner with an emissions rate of 0.065 lb/MMBTU for the 25.2 MMBTUH

regeneration heater. This is acceptable as BACT.

SECTION VI. INSIGNIFICANT ACTIVITIES

The insignificant activities identified and justified in the application are duplicated below.

Records are available to confirm the insignificance of the activities. Appropriate recordkeeping

of activities indicated below with “*” is specified in the Specific Conditions.

1. *Space heaters, boilers, process heaters and emergency flares less than or equal to 5

MMBTUH heat input fired by commercial natural gas. There are no emission units in this

category at this time.

2. *Storage tanks with less than or equal to 10,000 gallons capacity that store volatile organic

liquids with a true vapor pressure less than or equal to 1.0 psia at maximum storage

temperature. The miscellaneous storage tanks and oily wastewater storage tanks listed in

EUG 9 are in this category.

3. *Activities having the potential to emit no more than 5 TPY (actual) of any criteria pollutant.

The methanol storage tanks fit in this category. Potential emissions of VOC from the

methanol storage tanks are negligible.


SECTION VII. NAAQS COMPLIANCE

NOx

The applicant conducted air dispersion modeling to demonstrate that NOX emissions from the

facility would not cause or contribute to a violation of the NAAQS. The modeling was

performed using the conservative EPA SCREEN3 model. All NOX emissions were modeled as if

from a single source which provides a conservative prediction of ambient ground-level

concentrations. Total facility NOX emissions of 150.75 lb/hr were modeled from a single stack

using the worst-case stack conditions for all the engines, i.e., lowest stack temperature, lowest

stack flowrate, and lowest stack height and assuming the emergency generators operate

continuously. The SCREEN3 model run predicted a maximum 1-hour NOX concentration of

932.54-µg/m3 at a distance of 183 meters. This 1-hour concentration was multiplied by a

conversion factor of 0.08 to obtain a maximum annual concentration, which was then multiplied

by the NO2/NOX ambient ratio of 0.75. The maximum annual NO2 concentration is 55.95-

µg/m3. The facility will not cause or contribute to a violation of the NAAQS.

Compliance with NAAQS for NO2 - Facility Total PTE

Parameter NO2 Annual Average

Background Concentration, ug/m3 18.8

Maximum Impacts, ug/m3 55.95

Total Impacts, ug/m3 74.75

NAAQS, ug/m3 100

CO

The applicant conducted air dispersion modeling to demonstrate that CO emissions from the

facility would not cause or contribute to a violation of the NAAQS. The modeling was

performed using the conservative EPA SCREEN3 model. All CO emissions were modeled as if

from a single source which provides a conservative prediction of ambient ground-level

concentrations. Total facility CO emissions of 39.35 lb/hr were modeled from a single stack

using the worst-case stack conditions for all the engines, i.e., lowest stack temperature, lowest

stack flowrate, and lowest stack height. The SCREEN3 model run predicted a maximum 1-hour

CO concentration of 243.42-µg/m3 at a distance of 183 meters. This 1-hour concentration was

multiplied by a conversion factor of 0.7 to obtain a maximum 8-hour concentration of 170.39-

µg/m3. The maximum 1-hr CO concentration of 243.42-µg/m

3 is less than the NAAQS of

40,000-µg/m3

and the 8-hr CO concentration of 170.39-µg/m3

is less than the NAAQS of 10,000-

µg/m3. The facility will not cause or contribute to a violation of the NAAQS.

Compliance with NAAQS for CO - Facility Total PTE

Parameter CO 1-hr Average CO 8-hr Average

Background Concentration, ug/m3 2,394 1,254

Maximum Impacts, ug/m3 243.42 170.39

Total Impacts, ug/m3 2,637.42 1,424.39

NAAQS, ug/m3 40,000 10,000


SECTION VIII. OKLAHOMA AIR POLLUTION CONTROL RULES

OAC 252:100-1 (General Provisions) [Applicable]

Subchapter 1 includes definitions but there are no regulatory requirements.

OAC 252:100-2 (Incorporation by Reference) [Applicable]

This subchapter incorporates by reference applicable provisions of Title 40 of the Code of

Federal Regulations. These requirements are addressed in the “Federal Regulations” section.

OAC 252:100-3 (Air Quality Standards and Increments) [Applicable]

Subchapter 3 enumerates the primary and secondary ambient air quality standards and the

significant deterioration increments. At this time, all of Oklahoma 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. The applicant will be required to maintain an emissions inventory and

submit fees.

OAC 252:100-8 (Permits for Part 70 Sources) [Applicable]

Part 5 includes the general administrative requirements for Part 70 permits. Any planned

changes in the operation of the facility which result in emissions not authorized in the permit and

which exceed the “Insignificant Activities” or “Trivial Activities” thresholds require prior

notification to AQD and may require a permit modification. Insignificant activities mean

individual emission units that either are on the list in Appendix I (OAC 252:100), or whose

actual calendar year emissions do not exceed the following limits:

5 TPY of any one criteria pollutant

2 TPY of any one hazardous air pollutant (HAP) or 5 TPY of multiple HAP or 20% of

any threshold less than 10 TPY for single HAP that the EPA may establish by rule

Emission limitations and operational requirements necessary to assure compliance with all

applicable requirements for all sources are taken from the permit application, or developed from

the applicable requirements.

Part 7 summarizes Prevention of Significant Deterioration (PSD) requirements. See the “Federal

Regulations” section for a discussion of PSD regulations.

OAC 252:100-9 (Excess Emission Reporting Requirements) [Applicable]

Except as provided in OAC 252:100-9-7(a)(1), the owner or operator of a source of excess

emissions shall notify the Director as soon as possible but no later than 4:30 p.m. the following

working day of the first occurrence of excess emissions in each excess emission event. No later

than thirty (30) calendar days after the start of any excess emission event, the owner or operator

of an air contaminant source from which excess emissions have occurred shall submit a report

for each excess emission event describing the extent of the event and the actions taken by the


owner or operator of the facility in response to this event. Request for affirmative defense, as

described in OAC 252:100-9-8, shall be included in the excess emission event report. Additional

reporting may be required in the case of ongoing emission events and in the case of excess

emissions reporting required by 40 CFR Parts 60, 61, or 63.

OAC 252:100-13 (Open Burning) [Applicable]

Open burning of refuse and other combustible material is prohibited except as authorized in the

specific examples and under the conditions listed in this subchapter.

OAC 252:100-19 (Control of Emission of Particulate Matter) [Applicable]

Section 19-4 regulates emissions of particulate matter (PM) from new and existing fuel-burning

equipment, with emission limits based on maximum design heat input rating. Fuel-burning

equipment is defined in OAC 252:100-1 as “combustion devices used to convert fuel or wastes

to usable heat or power.” Thus, the gas-fired heaters and reboilers and engines are subject to the

requirements of this subchapter. The facility’s flare is not subject since it does not produce any

“usable heat or power”. Appendix C specifies a PM emission limitation range of 0.6 lb/MMBTU

to 0.35 for fuel-burning equipment with a rated heat input range of 10 MMBTUH or less up to

100 MMBTUH. AP-42 (7/98) Table 1.4-2 lists total PM emissions as 0.0076 lb/MMBTU for

natural gas combustion. AP-42 (7/00) Section 3.2 lists total PM emissions from natural gas-fired

reciprocating internal combustion engines as about 0.01 lb/MMBTU. AP-42 (4/00) Table 3.1-2a

lists total PM emissions from stationary gas turbines as about 0.007 lb/MMBTU. This permit

requires the use of natural gas for all fuel-burning units except for the three diesel-burning

emergency power generators to ensure compliance with Subchapter 19.

OAC 252:100-25 (Visible Emissions and Particulates) [Applicable]

No discharge of greater than 20% opacity is allowed except for short-term occurrences that

consist of not more than one six-minute period in any consecutive 60 minutes, not to exceed

three such periods in any consecutive 24 hours. In no case shall the average of any six-minute

period exceed 60% opacity. There is little possibility of exceeding these standards when burning

natural gas. This permit requires the use of natural gas for all fuel-burning units to ensure

compliance with Subchapter 25.

OAC 252:100-29 (Control of Fugitive Dust) [Applicable]

No person shall cause or permit the discharge of any visible fugitive dust emissions beyond the

property line on which the emissions originate in such a manner as to damage or to interfere with

the use of adjacent properties, or cause air quality standards to be exceeded, or interfere with the

maintenance of air quality standards. Under normal operating conditions, this facility has

negligible potential to violate this requirement; therefore, it is not necessary to require specific

precautions to be taken.

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

Part 2 limits emissions of sulfur dioxide from any one existing source or any one new petroleum

and natural gas process source subject to OAC 252:100-31-26(a)(1). Ambient air concentration

of sulfur dioxide at any given point shall not be greater than 1,300 g/m3 in a 5-minute period of

any hour, 1,200 g/m3 for a 1-hour average, 650 g/m

3 for a 3-hour average, 130 g/m

3 for a 24-

hour average, and 80 g/m3 for an annual average. Part 2 also limits the ambient air impact of

hydrogen sulfide emissions from any new or existing source to 0.2-ppm for a 24-hour average


(equivalent to 280 g/m3). The gas processed at this facility has negligible amounts of H2S

therefore, compliance with these standards is assured.

Part 5 limits sulfur dioxide emissions from new equipment (constructed after July 1, 1972). For

gaseous fuels, the limit is 0.2 lb/MMBTU heat input. For fuel gas having a gross calorific value

of 1,000 BTU/scf, this limit corresponds to a fuel sulfur content of approximately 1,200-ppmv.

Thus, a limitation of 343-ppmv sulfur in a field gas supply will be in compliance. The permit

requires the use of natural gas with a maximum sulfur content of 343-ppmv for all fuel-burning

equipment to ensure compliance with Subchapter 31.

Subchapter 31 limits SO2 emissions from new liquid fueled equipment to 0.8 lb/MMBTU. This

is equivalent to a sulfur content of 0.79% by weight. Subpart IIII currently limits sulfur to 500-

ppm (0.05% by weight) and, after October 1, 2010, limits sulfur to 15-ppm. Using No. 2 diesel

with 0.05% sulfur will result in SO2 emissions of 0.05 lb/MMBTU, which is in compliance with

Subchapter 31.

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

This subchapter limits new gas-fired fuel-burning equipment with rated heat input greater than or

equal to 50 MMBTUH to emissions of 0.2 lb of NOX per MMBTU, three-hour average. This

applies to the gas turbines. The manufacturer of the turbines guaranteed a NOx emission rate of

0.06 lb/MMBTU, which is in compliance with this subchapter.

OAC 252:100-35 (Carbon Monoxide) [Not Applicable]

None of the following affected processes are located at this facility: gray iron cupola, blast

furnace, basic oxygen furnace, petroleum catalytic cracking unit, or petroleum catalytic

reforming unit.

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

Part 3 requires storage tanks constructed after December 28, 1974, with a capacity of 400 gallons

or more and storing a VOC with a vapor pressure greater than 1.5-psia to be equipped with a

permanent submerged fill pipe or with an organic vapor recovery system. The condensate storage

tanks are subject to this requirement.

Part 3 requires loading facilities with a throughput equal to or less than 40,000 gallons per day to

be equipped with a system for submerged filling of tank trucks or trailers if the capacity of the

vehicle is greater than 200 gallons. This facility does not have the physical equipment (loading

arm and pump) to conduct this type of loading. Therefore, this requirement is not applicable.

Part 7 requires fuel-burning equipment to be operated and maintained to minimize emissions of

VOC. All fuel-burning equipment at this location is subject to this requirement.

Part 7 regulates VOC/water separators that receive water containing more than 200 gallons per

day of VOC. There is no VOC/water separator at this facility.

OAC 252:100-42 (Toxic Air Contaminants (TAC)) [Applicable]

This subchapter regulates toxic air contaminants (TAC) that are emitted into the ambient air in

areas of concern (AOC). Any work practice, material substitution, or control equipment required

by the Department prior to June 11, 2004, to control a TAC, shall be retained unless a

modification is approved by the Director. Since no AOC has been designated anywhere in the

state, there are no specific requirements for this facility at this time.


OAC 252:100-43 (Testing, Monitoring, and Recordkeeping) [Applicable]

This subchapter provides general requirements for testing, monitoring and recordkeeping and

applies to any testing, monitoring or recordkeeping activity conducted at any stationary source.

To determine compliance with emissions limitations or standards, the Air Quality Director may

require the owner or operator of any source in the state of Oklahoma to install, maintain and

operate monitoring equipment or to conduct tests, including stack tests, of the air contaminant

source. All required testing must be conducted by methods approved by the Air Quality Director

and under the direction of qualified personnel. A notice-of-intent to test and a testing protocol

shall be submitted to Air Quality at least 30 days prior to any EPA Reference Method stack tests.

Emissions and other data required to demonstrate compliance with any federal or state emission

limit or standard, or any requirement set forth in a valid permit shall be recorded, maintained,

and submitted as required by this subchapter, an applicable rule, or permit requirement. Data

from any required testing or monitoring not conducted in accordance with the provisions of this

subchapter shall be considered invalid. Nothing shall preclude the use, including the exclusive

use, of any credible evidence or information relevant to whether a source would have been in

compliance with applicable requirements if the appropriate performance or compliance test or

procedure had been performed.

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

OAC 252:100-7 Permits for Minor Facilities not in source category

OAC 252:100-11 Alternative Emissions Reduction not eligible

OAC 252:100-15 Mobile Sources not in source category

OAC 252:100-17 Incinerators not type of emission unit

OAC 252:100-23 Cotton Gins not type of emission unit

OAC 252:100-24 Grain, Feed, or Seed Facility not in source category

OAC 252:100-39 Non-attainment Areas not in a subject area

OAC 252:100-47 Municipal Solid Waste Landfills not type of source category

SECTION IX. FEDERAL REGULATIONS

PSD, 40 CFR Part 52 [Not Applicable]

Potential emissions for NOx, CO, and VOC are less than the level of significance of 250 TPY for

this source category.

NSPS, 40 CFR Part 60 [Subparts A, KKK, IIII, JJJJ and KKKK are Applicable]

Subpart A, 60.18, General Control Device Requirement, January 21, 1986. The plant flare is

used as a control device to meet equipment leak standards in 40 CFR Part 60 Subpart KKK.

Thus, a performance test will be required on the flare to demonstrate that it meets performance

standards in 40 CFR Part 60 Subpart A for heating value, visible emissions, and velocity.

Subpart Dc, Small Industrial-Commercial-Institutional Steam Generating Units. This subpart

affects steam generating units constructed after June 9, 1989, and with capacity between 10 and

100 MMBTUH. Subpart Dc excludes “process heaters,” and the regeneration heater does not meet

the definition of “steam generating unit” in Subpart Dc.

Subparts K, Ka, Kb, Volatile Organic Liquid (VOL) Storage Vessels. All tanks are below the

19, 813 gallon threshold for Subpart Kb.


Subpart KKK, Equipment Leaks of VOC from Onshore Natural Gas Processing Plants

constructed, reconstructed, or modified after January 20, 1984. This subpart sets standards for

natural gas processing plants, which are defined as any site engaged in the extraction of natural

gas liquids from field gas, fractionation of natural gas liquids, or both. The facility will be

subject to Subpart KKK once the gas plant is constructed. Subpart KKK specifically exempts

reciprocating compressors in wet gas service, and compressors that are not in VOC service, from

all but notification and recordkeeping requirements. The compressors are subject to the

monitoring, demonstration, and recordkeeping requirements of §60.486(j) and §60.635(a) and (c).

The permittee will be required to maintain a leak detection and repair (LDAR) program for all

equipment that is “in VOC service”.

Subpart LLL sets standards for natural gas sweetening units, and sweetening units followed by a

sulfur recovery unit, which commenced construction or modification after January 20, 1984. The

facility will have an amine unit. However, Devon does not anticipate processing natural gas

which contains H2S through the amine unit at the facility. If it is determined that H2S will be

present in the natural gas, Devon will evaluate the facility for applicability. Subpart LLL affects

gas streams above 4-ppm H2S only.

Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion

Engines. This subpart affects stationary compression ignition (CI) internal combustion engines

(ICE) based on power and displacement ratings, depending on date of construction, beginning

with those constructed after July 11, 2005. For the purposes of this subpart, the date that

construction commences is the date the engine is ordered by the owner or operator. Compliance

with this subpart is required in this permit for engines E-04, E-05 and E-06 (EUG-01C).

Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion

Engines (SI-ICE). This subpart was published in the Federal Register on January 18, 2008. It

promulgates emission standards for new SI engines ordered after June 12, 2006, that are

manufactured after certain dates, and for SI engines modified or reconstructed after June 12,

2006. The specific emission standards (either in g/hp-hr or as a concentration limit) vary based

on engine class, engine power rating, lean-burn or rich-burn, fuel type, duty (emergency or non-

emergency), and manufacture date. Engine manufacturers are required to certify certain engines

to meet the emission standards and may voluntarily certify other engines. An initial notification

is required only for owners and operators of engines greater than 500 HP that are non-certified.

Emergency engines will be required to be equipped with a non-resettable hour meter and are

limited to 100 hours per year of operation excluding use in an emergency (the length of operation

and the reason the engine was in operation must be recorded). Engines E-07 and E-08 (EUG-01)

are subject to Subpart JJJJ.

Owners and operators of certified engines may demonstrate compliance by operating and

maintaining their stationary engine and after-treatment control device (if any) according to the

manufacturer’s emission-related written instructions and do not have to conduct any performance

testing. Owners and operators of all SI engines (certified and non-certified) must keep records of

maintenance conducted on the engine. If an owner or operator of a certified engine does not

follow the manufacturer’s emission-related operation and maintenance instructions, that engine

is considered a non-certified engine and is subject to performance testing, unless the engine is

less than 100 HP. Owners and operators of non-certified engines, which include certified engines

operating in a non-certified manner, must keep a maintenance plan. An initial performance test

must be conducted within the first year of operation for any certified engine operating in a non-


certified manner that is equal to or greater than 100 HP. In addition, non-certified engines,

including certified engines operating in a non-certified manner, that are greater than 500 HP

must conduct the initial performance test and a performance test every 8,760 hours of operation

or every 3 years thereafter, whichever comes first. Rich-burn engines operating with three-way

catalysts or non-selective catalytic reduction must be equipped with an air-to-fuel ratio controller

operated in an appropriate manner to ensure proper operation of the engine and control device in

order to minimize emissions.

Engine

ID Description

Effective

Date

NOx CO VOC

g/hp-hr ppm * g/hp-hr ppm * g/hp-hr ppm *

E-07 &

08

4,735-hp Caterpillar

G3616 TALE 7/1/07 2.0 160 4.0 540 1.0 86

* corrected to 15% oxygen.

Subpart KKKK, Standards of Performance for Stationary Combustion Turbines, establishes

emission standards and compliance schedules for the control of emissions from stationary

combustion turbines with a heat input at peak load equal to or greater than 10-MMBtu/h, based

on the higher heating value of the fuel, which commenced construction, modification, or

reconstruction after February 18, 2005. Turbines applicable to this subpart (E-01, E-02, and E-

03) will be subject to the NOx emission limitations of §60.4320(a), the SO2 emission limitations

of §60.4330(a)(1) or (a)(2), the performance testing requirements under §60.4340(a) and the fuel

monitoring requirements of §60.4360. Monitoring of the fuel total sulfur content is not required

if the fuel is demonstrated to not exceed potential sulfur emissions of 0.06 lb SO2/MMBTU. All

turbines on-site were constructed after February 18, 2005 and are subject to the requirements of

this subpart.

NESHAP, 40 CFR Part 61 [Not Applicable]

There are no emissions of any of the regulated pollutants: arsenic, asbestos, beryllium, benzene,

coke oven emissions, mercury, radionuclides, or vinyl chloride except for trace amounts of

benzene. Subpart J (Equipment Leaks of Benzene) concerns only 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 [Subpart ZZZZ is Applicable]

Subpart HH, Oil and Natural Gas Production Facilities. This subpart applies to affected emission

points that are located at facilities which are major sources of HAP, or TEG dehydration units

only located at an area source, and either process, upgrade, or store hydrocarbons prior to the

point of custody transfer or prior to which the natural gas enters the natural gas transmission and

storage source category. Subpart HH affects glycol dehydration unit process vents, storage

vessels with potential for flash emissions, and compressors and ancillary equipment (valves,

flanges, etc.) in VHAP service (i.e., more than 10% by weight HAP) that are located at gas

processing plants. The facility will not include any TEG dehydration units; therefore subpart HH

area source requirements will not be applicable.

Subpart ZZZZ, Reciprocating Internal Combustion Engines (RICE). This subpart previously

affected only RICE with a site-rating greater than 500 brake horsepower that are located at a

major source of HAP emissions. On January 18, 2008, the EPA published a final rule that

promulgates standards for 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 reconstructed engines

(after June 12, 2006) located at area sources. Owners and operators of new engines and

reconstructed engines at area sources and of new or reconstructed engines with a site rating equal

to or less than 500 HP located at a major source (except new or reconstructed 4-stroke 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) meet the requirements of Subpart ZZZZ by complying with either 40

CFR Part 60 Subpart IIII (for CI engines) or 40 CFR Part 60 Subpart JJJJ (for SI engines).

Owners and operators of new or reconstructed 4SLB 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 are subject to the

same MACT standards previously established for 4SLB engines above 500 HP at a major source,

and must also meet the requirements of 40 CFR Part 60 Subpart JJJJ, except for the emissions

standards for CO. Engines E-04 through E-08 are subject to Subpart ZZZZ.

Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Industrial,

Commercial and Institutional Boilers and Process Heaters. In March, 2007, the EPA filed a

motion to vacate and remand this rule back to the agency. The rule was vacated by court order,

subject to appeal, on June 8, 2007. No appeals were made and the rule was vacated on July 30,

2007. Existing and new small gaseous fuel boilers and process heaters (less than 10 MMBTUH

heat rating) were not subject to any standards, recordkeeping, or notifications under Subpart

DDDDD.

EPA is planning on issuing guidance (or a rule) on what actions applicants and permitting

authorities should take regarding MACT determinations under either Section112(g) or Section

112(j) for sources that were affected sources under Subpart DDDDD and other vacated 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 potentially subject to a vacated MACT, including

Subpart DDDDD. This permit may be reopened to address Section 112(j) when necessary.

CAM, 40 CFR Part 64 [Not Applicable]

Compliance Assurance Monitoring (CAM) applies to any pollutant specific emission unit at a

major source that is required to obtain a Title V permit, if it meets all of the following criteria:

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

2. It uses a control device to achieve compliance with the applicable emission limit or

standard.

3. It has potential emissions, prior to the control device, of the applicable regulated air

pollutant of 100 TPY for a criteria pollutant, 10 TPY for an individual HAP, or 25 TPY

for all HAP.

Based on manufacturer’s emission factors, the turbines do not have pre-control emissions greater

than 100 TPY. Based on manufacturer’s emissions factors for formaldehyde, engines E-04 thru

E-08 have pre-control emissions greater than 10 TPY; however, the applicant will be testing

these engines to demonstrate compliance with a facility-wide cap on HAP emissions and it is

expected, based on previous stack tests for similar engines, that pre-control formaldehyde

emissions will be less than 10 TPY for all of these engines. If the testing shows any model of

engine has pre-control emissions of over 10 TPY of formaldehyde, that model engine will be


subject to CAM and the permittee must submit a CAM plan in the application for renewal of the

TV permit. The two lean-burn engines and the three rich-burn engines are subject to NSPS

Subpart JJJJ and NESHAP Subpart ZZZZ. Under 40 CFR Part 60.64.2(b)(i), CAM does not

affect emissions limits or standards proposed by the Administrator after November 15, 1990,

pursuant to Section 111 or 112 of the Act.

Chemical Accident Prevention Provisions, 40 CFR Part 68 [Applicable]

This facility handles naturally occurring hydrocarbon mixtures at a natural gas processing plant

and is subject to this Subpart (Section 112r of the Clean Air Act 1990 Amendments). A Risk

Management Plan was submitted to EPA Region 6 on June 14, 1999 and deemed complete on

June 16, 1999. An update to the RMP was received on September 23, 1999 and judged complete

on September 28, 1999. An update to the RMP was submitted on September 16, 2004. EPA

Notice of Confirmation was dated September 24, 2004. More information on this federal

program is available on the web page: www.epa.gov/ceppo

Stratospheric Ozone Protection, 40 CFR Part 82 [Subparts A and F are Applicable]

These standards require phase out of Class I & II substances, reductions of emissions of Class I

& II substances to the lowest achievable level in all use sectors, and banning use of nonessential

products containing ozone-depleting substances (Subparts A & C); control servicing of motor

vehicle air conditioners (Subpart B); require Federal agencies to adopt procurement regulations

which meet phase out requirements and which maximize the substitution of safe alternatives to

Class I and Class II substances (Subpart D); require warning labels on products made with or

containing Class I or II substances (Subpart E); maximize the use of recycling and recovery upon

disposal (Subpart F); require producers to identify substitutes for ozone-depleting compounds

under the Significant New Alternatives Program (Subpart G); and reduce the emissions of halons

(Subpart H).

Subpart A identifies ozone-depleting substances and divides them into two classes. Class I

controlled substances are divided into seven groups; the chemicals typically used by the

manufacturing industry include carbon tetrachloride (Class I, Group IV) and methyl chloroform

(Class I, Group V). A complete phase-out of production of Class I substances is required by

January 1, 2000 (January 1, 2002, for methyl chloroform). Class II chemicals, which are

hydrochlorofluorocarbons (HCFCs), are generally seen as interim substitutes for Class I CFCs.

Class II substances consist of 33 HCFCs. A complete phase-out of Class II substances,

scheduled in phases starting by 2002, is required by January 1, 2030.

This facility does not produce, consume, recycle, import, or export any controlled substances or

controlled products as defined in this part, nor does this facility perform service on motor (fleet)

vehicles that involves ozone-depleting substances. Therefore, as currently operated, this facility

is not subject to these requirements. To the extent that the facility has air-conditioning units that

apply, the permit requires compliance with Part 82.


SECTION X. COMPLIANCE

Tier Classification and Public Review

This application has been determined to be a Tier II based on the request for a construction permit

for a new Part 70 source. The applicant published the DEQ “Notice of Tier II Permit Application

Filing” in the El Reno Tribune, a newspaper of semi-weekly circulation in Canadian County, on

June 7, 2009. The notice stated that the application was available for public review at the

Carnegie Library located at 215 E. Wade in El Reno or at the DEQ main office in Oklahoma

City. The facility will publish the DEQ “Notice of Tier II Draft Permit.” The facility has

requested and been granted concurrent public and EPA review.

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

applicant notified the landowner by certified mail, restricted delivery, for which the applicant has a

signed return receipt.

Information on all permit actions is available for review by the public in the Air Quality section

of the DEQ Web Page: www.deq.state.ok.us.

Fees Paid

Application fee of $2,000 for a Part 70 source construction permit has been paid.

SECTION XI. SUMMARY

The facility has demonstrated the ability to comply with the requirements of the several air

pollution control rules and regulations. 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 construction permit is recommended, contingent on public and EPA review.

DRAFT/PROPOSED

PERMIT TO CONSTRUCT

AIR POLLUTION CONTROL FACILITY

SPECIFIC CONDITIONS

Devon Gas Services, L.P. Permit Number 2009-177-C

Cana Gas Plant

The permittee is authorized to construct in conformity with the specifications submitted to Air

Quality on June 3, 2009. The Evaluation Memorandum dated January 21, 2010 explains the

derivation of applicable permit requirements and estimates of emissions; however, it does not

contain operating limitations or permit requirements. Commencing construction under this

permit constitutes acceptance of, and consent to, the conditions contained herein:

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

A. Emissions from EUG 01 are limited as follows.

EUG-01A: Stationary Engines Subject to NSPS Subpart JJJJ







i. Engines E-07 and E-08 shall be equipped with oxidation catalysts to control

emissions of CO and HAP. [OAC 252:100-8-5 (a]

ii. Engines E-07 and E-08 are subject to 40 CFR Part 63 Subpart ZZZZ. Per 40 CFR

63.6590(c), the permittee must meet the requirements of this part by meeting the

requirements of 40 CFR Part 60 Subpart JJJJ, and no further requirements apply to the

engines under this part. [40 CFR§63.6590(c)]

iii. The permittee shall comply with all applicable requirements in 40 CFR Part 60

Subpart JJJJ for all stationary spark ignition (SI) internal combustion engines (ICE)

Engines E-07 and E-08 including, but not limited to, the following.

[40 CFR §§ 60.4230 to 60.4246]

a. §60.4230 Am I subject to this subpart? Any of the engines ordered after June 12,

2006 with a maximum engine power of greater than 1,350 HP that are

manufactured after July 1, 2007 are subject to this subpart. Any of the engines

ordered after June 12, 2006 with a maximum engine power less than 1,350 HP

that are manufactured after January 1, 2008 are subject to this subpart.

b. The emission standards of §60.4233 and §60.4234.

SPECIFIC CONDITIONS 2009-177-C 2 DRAFT/PROPOSED

c. The fuel requirements of §60.4235 for gasoline fired engines.

d. The deadlines for importing or installing SI ICE produced in the previous model

year in accordance with §60.4236.

e. The monitoring requirements of §60.4237 for emergency engines.

f. The compliance requirements of §60.4243.

g. The performance test methods and other procedures of §60.4244.

h. The notification, reporting, and recordkeeping requirements of §60.4245.

i. §60.4246 What parts of the General Provisions apply to me?

j. §60.4248 What definitions apply to this subpart?

EUG 01B: Stationary Gas Turbines



E-01 11,571-hp Solar Taurus 70-10302 5.10 22.35 5.10 22.35 2.81 12.29

E-02 11,571-hp Solar Taurus 70-10302 5.10 22.35 5.10 22.35 2.81 12.29

E-03 11,571-hp Solar Taurus 70-10302 5.10 22.35 5.10 22.35 2.81 12.29

iv. The turbines (E-01, E-02 and E-03) have LHV heat input capacities at peak load of

84-MMBTUH and are subject to the requirements of NSPS, 40 CFR, Part 60, Subpart

KKKK including but not limited to the following: [40 CFR §§ 60.4300 to 60.4380]

a. §60.4300 What is the purpose of this subpart?

b. §60.4305 Does this subpart apply to my stationary combustion turbine?

c. §60.4310 What types of operations are exempt from these standards of

performance?

d. §60.4315 What pollutants are regulated by this subpart?

e. §60.4320 What emission limits must I meet for nitrogen oxides (NO)?

f. §60.4325 What emission limits must I meet for NO if my turbine burns both natural

gas and distillate oil (or some other combination of fuels)?

g. §60.4330 What emission limits must I meet for sulfur dioxide (SO2)?

h. §60.4333 What are my general requirements for complying with this subpart?


i. §60.4335 How do I demonstrate compliance for NO if I use water or steam

injection?

j. §60.4340 How do I demonstrate continuous compliance for NO if I do not use

water or steam injection?

k. §60.4345 What are the requirements for the continuous emission monitoring system

equipment, if I choose to use this option?

l. §60.4350 How do I use data from the continuous emission monitoring equipment to

identify excess emissions?

m. §60.4355 How do I establish and document a proper parameter monitoring plan?

n. §60.4360 How do I determine the total sulfur content of the turbine's combustion

fuel?

o. §60.4365 How can I be exempted from monitoring the total sulfur content of the

fuel?

p. §60.4370 How often must I determine the sulfur content of the fuel?

q. §60.4375 What reports must I submit?

r. §60.4380 How are excess emissions and monitor downtime defined for NO? What

This Subpart Covers

EUG-01C: Stationary Engines Subject to NSPS IIII






v. Engines E-04 through E-06 shall be certified to meet NSPS Subpart IIII.

[OAC 252:100-8-5 (a)]

a. The engines E-04 through E-06 shall be fueled with No. 2 diesel with a maximum

sulfur content of 0.05% by weight. [OAC 252:100-31]

b. The engines shall be operated no more than 500 hours per year, 12-month rolling

total.

c. The emergency generators are subject to 40 CFR Part 60, Subpart IIII, and shall

comply with all applicable requirements including, but not limited to, the

following.


1. 60.4200: Am I subject to this subpart?

2. 60.4202: What emissions standards must I meet for emergency engines

if I am a stationary CI internal combustion engine manufacture?

3. 60.4204: What emissions standards must I meet for non-emergency

engines if I am an owner or operator of a stationary CI internal

combustion engine?

4. 60.4205: What emissions standards must I meet for emergency engines

if I am an owner or operator of a stationary CI internal combustion

engine?

5. 60.4206: How long must my engines meet the emissions standards if I

am a owner or operator of a stationary CI internal combustion engine?

6. 60.4207: What fuel requirements must I meet if I am an owner or

operator of a stationary CI internal combustion engine subject to this

subpart?

7. 60.4208: What is the deadline for importing or installing stationary CI

ICE produced in the previous model year?

8. 60.4209: What are the monitoring requirements if I am an owner or

operator of a stationary CI internal combustion engine?

9. 60.4211: What are my compliance requirements if I am an owner or

operator of a stationary CI internal combustion engine?

10. 60.4212: What test methods and other procedures must I use if I am an

owner or operator of a stationary CI internal combustion engine with a

displacement of less than 30 liters per cylinder?

11. 60.4213: What test methods and other procedures must I use if I am an

owner or operator of a stationary CI internal combustion engine with a

displacement of greater than or equal to 30 liters per cylinder?

12. 60.4214: What are my notification, reporting, and recordkeeping

requirements if I am an owner or operator of a stationary CI internal

combustion engine?

13. 60.4217: What emission standards must I meet if I am an owner or

operator of a stationary internal combustion engine using special fuels?

14. 60.4218: What parts of the General Provisions apply to me?

15. 60.4219: What definitions apply to this subpart?

Requirements for all engines:

vi. Each engine at the facility shall have a permanent identification plate attached that is

accessible and legible, which shows the make, model number, and serial number.

[OAC 252:100-43]

vii. The permittee shall at all times properly operate and maintain all engines in a manner

that will minimize emissions of hydrocarbons or other organic materials.

[OAC 252:100-37-36]


viii. The permittee shall keep operation and maintenance (O&M) records for each engine

that is not tested in a quarter. Such records shall at a minimum include the dates of

operation and maintenance and type of work performed. [OAC 252:100-8-6 (a)(3)(B)]

ix. At least once per calendar quarter, the permittee shall conduct tests of NOX and CO

emissions in exhaust gases from each engine/turbine and from each replacement

engine/turbine when operating under representative conditions for that period. Testing is

required for each engine or any replacement engine/turbine that runs for more than 220

hours during that calendar quarter. A quarterly test may be conducted no sooner than 20

calendar days after the most recent test. Testing shall be conducted using a portable

analyzer in accordance with a protocol meeting the requirements of the latest AQD

Portable Analyzer Guidance document, or an equivalent method approved by Air

Quality. When four consecutive quarterly tests show the engine/turbine to be in

compliance with the emissions limitations shown in the permit, then the testing frequency

may be reduced to semi-annual testing. A semi-annual test may be conducted no sooner

than 60 calendar days, nor later than 180 calendar days after the most recent test.

Likewise, when the following two consecutive semi-annual tests show compliance, the

testing frequency may be reduced to annual testing. An annual test may be conducted no

sooner than 120 calendar days, nor later than 365 calendar days after the most recent test.

Upon any showing of non-compliance with emissions limitations or testing that indicates

that emissions are within 10% of the emission limitations, the testing frequency shall

revert to quarterly. Reduced testing frequency does not apply to engines with catalytic

converters. Any reduction in the testing frequency shall be noted in the next required

compliance certification. [OAC 252:100-8-6 (a)(3)(A)]

x. When periodic compliance testing shows exhaust emissions from the engines in

excess of the lb/hr limits in Specific Condition No. 1, the permittee shall comply with the

provisions of OAC 252:100-9. Requirements of OAC 252:100-9 include immediate

notification and written notification of Air Quality and demonstrations that the excess

emissions meet the criteria specified in OAC 252:100-9. [OAC 252:100-9]

xi. Replacement (including temporary periods of 6 months or less for maintenance

purposes) of internal combustion engines/turbines with emissions limitations specified in

this permit with engines/turbines of lesser or equal emissions of each pollutant (in lb/hr

and TPY) are authorized under the following conditions. [OAC 252:100-8-6 (a)(3)(A)]

a. The permittee shall notify AQD in writing not later than 7 days in advance of the

start-up of the replacement engine(s)/turbine(s). Said notice shall identify the

equipment removed and shall include the new engine/turbine make, model, and

horsepower; date of the change, and any change in emissions.

b. Quarterly emissions tests for the replacement engine(s)/turbine(s) shall be

conducted to confirm continued compliance with NOX and CO emission limitations.

A copy of the first quarter testing shall be provided to AQD within 60 days of start-up

of each replacement engine/turbine. The test report shall include the engine/turbine

fuel usage, serial number, stack flow (ACFM), stack temperature (oF), stack height


(feet), stack diameter (inches), and pollutant emission rates (g/hp-hr, lbs/hr, and TPY)

at maximum rated horsepower for the altitude/location.

c. Replacement equipment and emissions are limited to equipment and emissions

which are not a modification under NSPS or NESHAP, or a significant modification

under PSD. For existing PSD facilities, the permittee shall calculate the PTE or the

net emissions increase resulting from the replacement to document that it does not

exceed significance levels and submit the results with the notice required by a. of this

Specific Condition.

d. Engines installed as allowed under the replacement allowances in this Specific

Condition that are subject to 40 CFR Part 63, Subpart ZZZZ and/or 40 CFR Part 60,

Subpart IIII or JJJJ shall comply with all applicable requirements.

B. Emissions from EUG 02 are limited as follows.

EU Description VOC Benzene

TPY TPY

A-01 200-MMSCFD Amine Unit 3.14 0.99

Compliance with the following specific conditions demonstrates compliance with the VOC and

benzene emission limits above.

i. The Amine unit, A-01, shall be maintained and operated as follows:

a. The natural gas throughput of A-01 shall not exceed 200 MMSCFD based on a

monthly average (30-day rolling total).

b. In accordance with OAC 252:100, Subchapter 31, the amine unit shall comply with

the following standards:

1. Emissions of hydrogen sulfide from the amine unit shall be oxidized to sulfur

dioxide by a thermal oxidizer/flare designed for a 98% control efficiency.

2. The thermal oxidizer/flare shall have an alarm system to signal non combustion of

the exhaust gases.

3. The amine unit flash tank shall be vented to the plant flare.

ii. At least once per month, the inlet natural gas shall be analyzed for sulfur content. Testing

shall be conducted using the Tutwiler Method, ASTM E-260 as specified in NSPS

Subpart LLL, or an equivalent method approved by Air Quality.

iii. The following formula shall be used to show compliance with the lb/hr emission limits

for SO2:

SO2 lb/hr = (Qinlet, MMSCFD)(Cinlet – Cresidue, ppmv)(1 lbmol H2S/ lbmol SO2)(64 lb SO2/lbmol)

(380 ft3/lbmol)(24 hr/day)


a. Compliance with the annual emission limits of SO2 shall be based on a 12-month

rolling total. The permittee shall calculate the total SO2 emissions from the acid gas

flare stack based on 98% conversion of H2S. The calculations shall be based on

monthly tested H2S concentration measured at the following locations: (1) plant inlet

gas streams, and (2) plant outlet gas stream and the daily average inlet gas flow rate

for that month. These calculations will be submitted with the semiannual monitoring

and deviation report.

b. The permittee maintain records of actual average benzene emissions in accordance

with 40 CFR 63.774(d)(1)(ii).

C. Emissions from EUG-03, heater H-01, are limited as follows.

EU Description NOx CO VOC

TPY TPY TPY

H-01 25.2 MMBTUH Regeneration Heater 7.17 8.39 0.60

i. Heater H-01 shall be constructed with Low-NOX burners with a manufacturer’s design

NOX emissions rate of 0.065 lb/MMBTU or lower.

ii. Compliance with the emissions limits for H-01 is demonstrated by the heater’s design

heat input rating of 25.2 MMBTUH and by firing natural gas. [OAC 252:100-43]

D. Emissions from EUG-04, the storage tanks T-01 through T-12, are limited as follows.

EU Description VOC

TPY

Tanks Oily Water and Condensate Tanks 16.1

i. Condensate throughput is limited to 2,299,500 gallons/year for a 12-month rolling

average. [OAC 252:100-43]

ii. Compliance with the emissions limits for the tanks is demonstrated by compliance with

the throughput limit for condensate. [OAC 252:100-43]

iii. The tanks shall be equipped with submerged fill. [OAC 252:100-37-15(b)]

E. EUG-05, emissions of VOC from fugitive components are estimated at 3.22 TPY, but there

is no emissions limit or component count limit for this construction permit.

i. After startup of the gas plant, the facility will be subject to NSPS 40 CFR Part 60 Subpart

KKK. The permittee shall comply with all applicable requirements of this subpart including,

but not limited to, the following: [40 CFR 60.630-636]


a. §60.632: Standards

b. §60.635: Recordkeeping requirements.

c. §60.636: Reporting requirements.

d. Information and data used to demonstrate that ancillary equipment is not in VOC

service shall be recorded in a log that is kept in a readily accessible location as per

§60.486(j).

F. EUG-07, the plant flare (F-1) is subject to NSPS, Subpart A, and shall comply with §60.18.

The process/emergency flare is subject to 40 CFR §60.18 General Control Requirements and the

permittee shall comply with all requirements, including, but not limited to, the following.

[40 CFR §60.18]

a. The flare shall be operated at all times when emissions may be vented to it.

b. The presence of a pilot flame shall be monitored using a thermocouple or any other

equivalent device to detect the presence of a flame.

c. Performance testing as stated in 40 CFR Part 60.18(d) and (f) shall be conducted

within 180 days of start-up.

2. The fuel-burning equipment (except for the diesel-fired IC power generation units) shall be

fired with pipeline grade natural gas or other gaseous fuel with a sulfur content less than 343-

ppmv. Compliance can be shown by the following methods: for pipeline grade natural gas, a

current gas company bill; for other gaseous fuel, a current lab analysis, stain-tube analysis,

gas contract, tariff sheet, or other approved methods. Compliance shall be demonstrated at

least once annually.

With respect to the diesel-fired IC power generation units, Subpart IIII limits sulfur to 500-

ppm (0.05% by weight). Using No. 2 diesel with 0.05% sulfur will result in SO2 emissions of

0.05 lb/MMBTU, which is in compliance with Subchapter 31. Compliance shall be

demonstrated at least once annually. [OAC 252:100-8-6(a)]

3. Upon issuance of an operating permit, the permittee shall be authorized to operate this facility

continuously (24 hours per day, every day of the year). [OAC 252:100-8-6(a)]

4. The following records shall be maintained on-site to verify Insignificant Activities. No

recordkeeping is required for those operations that qualify as Trivial Activities.

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

a. For stationary reciprocating engines burning natural gas, gasoline, aircraft fuels, or diesel

fuel which are either used exclusively for emergency power generation or for peaking

power service not exceeding 500 hours/year: records of engine service and annual

operating hours.


b. For space heaters, boilers, process heaters, and emergency flares less than or equal to 5

MMBTUH heat input fired by commercial natural gas: records of design heat input and

type of gas fired.

c. For storage tanks with less than or equal to 10,000 gallons capacity that store volatile

organic liquids with a true vapor pressure less than or equal to 1.0 psia at maximum

storage temperature: records of tank capacity and true vapor pressure at maximum

storage temperature.

d. For emissions from storage tanks constructed with a capacity less than 39,894 gallons

which store VOC with a vapor pressure less than 1.5 psia at maximum storage

temperature: records of tank capacity and true vapor pressure at maximum storage

temperature.

e. For activities having the potential to emit no more than 5 TPY (actual) of any criteria

pollutant: records of the type of activity and the amount of emissions from that activity

(annual).

5. The permittee shall maintain records of operations as listed below. These records shall be

maintained on-site for at least five years after the date of recording and shall be provided to

regulatory personnel upon request. [OAC 252:100-43]

a. O&M records for any engine if operated less than 220 hours per quarter and not tested.

b. Periodic testing for NOX and CO for each engine/turbine.

c. For the fuel burned the appropriate document(s) as described in Specific Condition No. 2.

d. Records required by 40 CFR §60, Subpart KKK, including, but not limited to, records

demonstrating that a reciprocating compressor is in wet gas service or is not in VOC

service, records demonstrating that equipment components are not in VOC service, and

records required by LDAR program provisions.

e. Condensate throughput (monthly and 12-month rolling total).

f. Manufacturer’s documents for heater H-01 demonstrating a design NOX emissions rate of

no more than 0.065 lb/MMBTU.

g. Records required by NSPS Subpart IIII, JJJJ, and KKKK and NESHAP Subpart ZZZZ.

6. The permittee shall apply for an operating permit within 180 days of startup.

Devon Gas Services, L.P.

Mr. Joe Grossman, EHS Specialist

20 North Broadway

Oklahoma City, OK 73102-8260

SUBJECT: Permit No. 2009-177-C

Cana Gas Plant

Section 12, T12N, R9W, Canadian County, Oklahoma

Dear Mr. Grossman:

Air Quality Division has completed the initial review of your major source construction permit

application referenced above. This application has been determined to be a Tier II. In

accordance with 27A O.S. §2-14-302 and OAC 252:002-31 the enclosed draft permit is now

ready for public review. The requirements for public review include the following steps which

you must accomplish:

1. Publish at least one legal notice (one day) in at least one newspaper of general circulation

within the county where the facility is located. (Instruction enclosed)

2. Provide for public review (for a period of 30 days following the date of the newspaper

announcement) a copy of this draft permit and a copy of the application at a convenient

location (preferably a public location) within the county of the facility.

3. Send to AQD a copy of the proof of publication notice from Item #1 above together with any

additional comments or requested changes, which you may have on the draft permit.

Thank you for your cooperation. If you have any questions, please refer to the permit number

above and contact me or the permit writer at (405) 702-4100.

Sincerely,

Phillip Fielder, P.E.

Permits & Engineering Group Manager


Enclosure

PART 70 PERMIT


STATE OF OKLAHOMA

DEPARTMENT OF ENVIRONMENTAL QUALITY

707 N. ROBINSON, SUITE 4100

P.O. BOX 1677

OKLAHOMA CITY, OKLAHOMA 73101-1677

Permit No. 2009-177-C

Devon Gas Services, L.P.,

having complied with the requirements of the law, is hereby granted permission to

construct the Cana Gas Plant, Section 12, T12N, R9W, Canadian County, Oklahoma

subject to the Standard Conditions dated July 21, 2009 and Specific Conditions, both

attached.

In the absence of construction commencement, this permit shall expire 18 months

from the issuance date, except as authorized under Section VIII of the Standard

Conditions.

_________________________________

Division Director, Date

Air Quality Division

DEQ Form #100-890 Revised 10/20/06

MAJOR SOURCE AIR QUALITY PERMIT

STANDARD CONDITIONS

(July 21, 2009)

SECTION I. DUTY TO COMPLY

A. This is a permit to operate / construct this specific facility in accordance with the federal

Clean Air Act (42 U.S.C. 7401, et al.) and under the authority of the Oklahoma Clean Air Act

and the rules promulgated there under. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

B. The issuing Authority for the permit is the Air Quality Division (AQD) of the Oklahoma

Department of Environmental Quality (DEQ). The permit does not relieve the holder of the

obligation to comply with other applicable federal, state, or local statutes, regulations, rules, or

ordinances. [Oklahoma Clean Air Act, 27A O.S. § 2-5-112]

C. The permittee shall comply with all conditions of this permit. Any permit noncompliance

shall constitute a violation of the Oklahoma Clean Air Act and shall be grounds for enforcement

action, permit termination, revocation and reissuance, or modification, or for denial of a permit

renewal application. All terms and conditions are enforceable by the DEQ, by the

Environmental Protection Agency (EPA), and by citizens under section 304 of the Federal Clean

Air Act (excluding state-only requirements). This permit is valid for operations only at the

specific location listed.

[40 C.F.R. §70.6(b), OAC 252:100-8-1.3 and OAC 252:100-8-6(a)(7)(A) and (b)(1)]

D. It shall not be a defense for a permittee in an enforcement action that it would have been

necessary to halt or reduce the permitted activity in order to maintain compliance with the

conditions of the permit. However, nothing in this paragraph shall be construed as precluding

consideration of a need to halt or reduce activity as a mitigating factor in assessing penalties for

noncompliance if the health, safety, or environmental impacts of halting or reducing operations

would be more serious than the impacts of continuing operations. [OAC 252:100-8-6(a)(7)(B)]

SECTION II. REPORTING OF DEVIATIONS FROM PERMIT TERMS

A. Any exceedance resulting from an emergency and/or posing an imminent and substantial

danger to public health, safety, or the environment shall be reported in accordance with Section

XIV (Emergencies). [OAC 252:100-8-6(a)(3)(C)(iii)(I) & (II)]

B. Deviations that result in emissions exceeding those allowed in this permit shall be reported

consistent with the requirements of OAC 252:100-9, Excess Emission Reporting Requirements.

[OAC 252:100-8-6(a)(3)(C)(iv)]

C. Every written report submitted under this section shall be certified as required by Section III

(Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.

[OAC 252:100-8-6(a)(3)(C)(iv)]

MAJOR SOURCE STANDARD CONDITIONS July 21, 2009 2

SECTION III. MONITORING, TESTING, 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-site or at a nearby field

office for a period of at least five years from the date of the monitoring sample, measurement,

report, or application, and shall be made available for inspection by regulatory personnel upon

request. Support information includes all original strip-chart recordings for continuous

monitoring instrumentation, and copies of all reports required by this permit. Where appropriate,

the permit may specify that records may be maintained in computerized form.

[OAC 252:100-8-6 (a)(3)(B)(ii), OAC 252:100-8-6(c)(1), and OAC 252:100-8-6(c)(2)(B)]

B. Records of required monitoring shall include:

(1) the date, place and time of sampling or measurement;

(2) the date or dates analyses were performed;

(3) the company or entity which performed the analyses;

(4) the analytical techniques or methods used;

(5) the results of such analyses; and

(6) the operating conditions existing at the time of sampling or measurement.

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

C. No later than 30 days after each six (6) month period, after the date of the issuance of the

original Part 70 operating permit or alternative date as specifically identified in a subsequent Part

70 operating permit, the permittee shall submit to AQD a report of the results of any required

monitoring. All instances of deviations from permit requirements since the previous report shall

be clearly identified in the report. Submission of these periodic reports will satisfy any reporting

requirement of Paragraph E below that is duplicative of the periodic reports, if so noted on the

submitted report. [OAC 252:100-8-6(a)(3)(C)(i) and (ii)]

D. If any testing shows emissions in excess of limitations specified in this permit, the owner or

operator shall comply with the provisions of Section II (Reporting Of Deviations From Permit

Terms) of these standard conditions. [OAC 252:100-8-6(a)(3)(C)(iii)]

E. In addition to any monitoring, recordkeeping or reporting requirement specified in this

permit, monitoring and reporting may be required under the provisions of OAC 252:100-43,

Testing, Monitoring, and Recordkeeping, or as required by any provision of the Federal Clean

Air Act or Oklahoma Clean Air Act. [OAC 252:100-43]

F. Any Annual Certification of Compliance, Semi Annual Monitoring and Deviation Report,

Excess Emission Report, and Annual Emission Inventory submitted in accordance with this

permit shall be certified by a responsible official. This certification shall be signed by a

responsible official, and shall contain the following language: “I certify, based on information

and belief formed after reasonable inquiry, the statements and information in the document are

true, accurate, and complete.”

[OAC 252:100-8-5(f), OAC 252:100-8-6(a)(3)(C)(iv), OAC 252:100-8-6(c)(1), OAC

252:100-9-7(e), and OAC 252:100-5-2.1(f)]


G. Any owner or operator subject to the provisions of New Source Performance Standards

(“NSPS”) under 40 CFR Part 60 or National Emission Standards for Hazardous Air Pollutants

(“NESHAPs”) under 40 CFR Parts 61 and 63 shall maintain a file of all measurements and other

information required by the applicable general provisions and subpart(s). These records shall be

maintained in a permanent file suitable for inspection, shall be retained for a period of at least

five years as required by Paragraph A of this Section, and shall include records of the occurrence

and duration of any start-up, shutdown, or malfunction in the operation of an affected facility,

any malfunction of the air pollution control equipment; and any periods during which a

continuous monitoring system or monitoring device is inoperative.

[40 C.F.R. §§60.7 and 63.10, 40 CFR Parts 61, Subpart A, and OAC 252:100, Appendix Q]

H. The permittee of a facility that is operating subject to a schedule of compliance shall submit

to the DEQ a progress report at least semi-annually. The progress reports shall contain dates for

achieving the activities, milestones or compliance required in the schedule of compliance and the

dates when such activities, milestones or compliance was achieved. The progress reports shall

also contain an explanation of why any dates in the schedule of compliance were not or will not

be met, and any preventive or corrective measures adopted. [OAC 252:100-8-6(c)(4)]

I. All testing must be conducted under the direction of qualified personnel by methods

approved by the Division Director. All tests shall be made and the results calculated in

accordance with standard test procedures. The use of alternative test procedures must be

approved by EPA. When a portable analyzer is used to measure emissions it shall be setup,

calibrated, and operated in accordance with the manufacturer’s instructions and in accordance

with a protocol meeting the requirements of the “AQD Portable Analyzer Guidance” document

or an equivalent method approved by Air Quality.

[OAC 252:100-8-6(a)(3)(A)(iv), and OAC 252:100-43]

J. The reporting of total particulate matter emissions as required in Part 7 of OAC 252:100-8

(Permits for Part 70 Sources), OAC 252:100-19 (Control of Emission of Particulate Matter), and

OAC 252:100-5 (Emission Inventory), shall be conducted in accordance with applicable testing

or calculation procedures, modified to include back-half condensables, for the concentration of

particulate matter less than 10 microns in diameter (PM10). NSPS may allow reporting of only

particulate matter emissions caught in the filter (obtained using Reference Method 5).

K. The permittee shall submit to the AQD a copy of all reports submitted to the EPA as required

by 40 C.F.R. Part 60, 61, and 63, for all equipment constructed or operated under this permit

subject to such standards. [OAC 252:100-8-6(c)(1) and OAC 252:100, Appendix Q]

SECTION IV. COMPLIANCE CERTIFICATIONS

A. No later than 30 days after each anniversary date of the issuance of the original Part 70

operating permit or alternative date as specifically identified in a subsequent Part 70 operating

permit, the permittee shall submit to the AQD, with a copy to the US EPA, Region 6, a

certification of compliance with the terms and conditions of this permit and of any other

applicable requirements which have become effective since the issuance of this permit.

[OAC 252:100-8-6(c)(5)(A), and (D)]


B. The compliance certification shall describe the operating permit term or condition that is the

basis of the certification; the current compliance status; whether compliance was continuous or

intermittent; the methods used for determining compliance, currently and over the reporting

period. The compliance certification shall also include such other facts as the permitting

authority may require to determine the compliance status of the source.

[OAC 252:100-8-6(c)(5)(C)(i)-(v)]

C. The compliance certification shall contain a certification by a responsible official as to the

results of the required monitoring. This certification shall be signed by a responsible official,

and shall contain the following language: “I certify, based on information and belief formed

after reasonable inquiry, the statements and information in the document are true, accurate, and

complete.” [OAC 252:100-8-5(f) and OAC 252:100-8-6(c)(1)]

D. Any facility reporting noncompliance shall submit a schedule of compliance for emissions

units or stationary sources that are not in compliance with all applicable requirements. This

schedule shall include a schedule of remedial measures, including an enforceable sequence of

actions with milestones, leading to compliance with any applicable requirements for which the

emissions unit or stationary source is in noncompliance. This compliance schedule shall

resemble and be at least as stringent as that contained in any judicial consent decree or

administrative order to which the emissions unit or stationary source is subject. Any such

schedule of compliance shall be supplemental to, and shall not sanction noncompliance with, the

applicable requirements on which it is based, except that a compliance plan shall not be required

for any noncompliance condition which is corrected within 24 hours of discovery.

[OAC 252:100-8-5(e)(8)(B) and OAC 252:100-8-6(c)(3)]

SECTION V. REQUIREMENTS THAT BECOME APPLICABLE DURING THE

PERMIT TERM

The permittee shall comply with any additional requirements that become effective during the

permit term and that are applicable to the facility. Compliance with all new requirements shall

be certified in the next annual certification. [OAC 252:100-8-6(c)(6)]

SECTION VI. PERMIT SHIELD

A. Compliance with the terms and conditions of this permit (including terms and conditions

established for alternate operating scenarios, emissions trading, and emissions averaging, but

excluding terms and conditions for which the permit shield is expressly prohibited under OAC

252:100-8) shall be deemed compliance with the applicable requirements identified and included

in this permit. [OAC 252:100-8-6(d)(1)]

B. Those requirements that are applicable are listed in the Standard Conditions and the Specific

Conditions of this permit. Those requirements that the applicant requested be determined as not

applicable are summarized in the Specific Conditions of this permit. [OAC 252:100-8-6(d)(2)]


SECTION VII. ANNUAL EMISSIONS INVENTORY & FEE PAYMENT

The permittee shall file with the AQD an annual emission inventory and shall pay annual fees

based on emissions inventories. The methods used to calculate emissions for inventory purposes

shall be based on the best available information accepted by AQD.

[OAC 252:100-5-2.1, OAC 252:100-5-2.2, and OAC 252:100-8-6(a)(8)]

SECTION VIII. TERM OF PERMIT

A. Unless specified otherwise, the term of an operating permit shall be five years from the date

of issuance. [OAC 252:100-8-6(a)(2)(A)]

B. A source’s right to operate shall terminate upon the expiration of its permit unless a timely

and complete renewal application has been submitted at least 180 days before the date of

expiration. [OAC 252:100-8-7.1(d)(1)]

C. A duly issued construction permit or authorization to construct or modify will terminate and

become null and void (unless extended as provided in OAC 252:100-8-1.4(b)) if the construction

is not commenced within 18 months after the date the permit or authorization was issued, or if

work is suspended for more than 18 months after it is commenced. [OAC 252:100-8-1.4(a)]

D. The recipient of a construction permit shall apply for a permit to operate (or modified

operating permit) within 180 days following the first day of operation. [OAC 252:100-8-4(b)(5)]

SECTION IX. SEVERABILITY

The provisions of this permit are severable and if any provision of this permit, or the application

of any provision of this permit to any circumstance, is held invalid, the application of such

provision to other circumstances, and the remainder of this permit, shall not be affected thereby.

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

SECTION X. PROPERTY RIGHTS

A. This permit does not convey any property rights of any sort, or any exclusive privilege.

[OAC 252:100-8-6(a)(7)(D)]

B. This permit shall not be considered in any manner affecting the title of the premises upon

which the equipment is located and does not release the permittee from any liability for damage

to persons or property caused by or resulting from the maintenance or operation of the equipment

for which the permit is issued. [OAC 252:100-8-6(c)(6)]

SECTION XI. DUTY TO PROVIDE INFORMATION

A. The permittee shall furnish to the DEQ, upon receipt of a written request and within sixty

(60) days of the request unless the DEQ specifies another time period, any information that the

DEQ may request to determine whether cause exists for modifying, reopening, revoking,


reissuing, terminating the permit or to determine compliance with the permit. Upon request, the

permittee shall also furnish to the DEQ copies of records required to be kept by the permit.

[OAC 252:100-8-6(a)(7)(E)]

B. The permittee may make a claim of confidentiality for any information or records submitted

pursuant to 27A O.S. § 2-5-105(18). Confidential information shall be clearly labeled as such

and shall be separable from the main body of the document such as in an attachment.

[OAC 252:100-8-6(a)(7)(E)]

C. Notification to the AQD of the sale or transfer of ownership of this facility is required and

shall be made in writing within thirty (30) days after such sale or transfer.

[Oklahoma Clean Air Act, 27A O.S. § 2-5-112(G)]

SECTION XII. REOPENING, MODIFICATION & REVOCATION

A. The permit may be modified, revoked, reopened and reissued, or terminated for cause.

Except as provided for minor permit modifications, the filing of a request by the permittee for a

permit modification, revocation and reissuance, termination, notification of planned changes, or

anticipated noncompliance does not stay any permit condition.

[OAC 252:100-8-6(a)(7)(C) and OAC 252:100-8-7.2(b)]

B. The DEQ will reopen and revise or revoke this permit prior to the expiration date in the

following circumstances: [OAC 252:100-8-7.3 and OAC 252:100-8-7.4(a)(2)]

(1) Additional requirements under the Clean Air Act become applicable to a major source

category three or more years prior to the expiration date of this permit. No such

reopening is required if the effective date of the requirement is later than the expiration

date of this permit.

(2) The DEQ or the EPA determines that this permit contains a material mistake or that the

permit must be revised or revoked to assure compliance with the applicable requirements.

(3) The DEQ or the EPA determines that inaccurate information was used in establishing the

emission standards, limitations, or other conditions of this permit. The DEQ may revoke

and not reissue this permit if it determines that the permittee has submitted false or

misleading information to the DEQ.

(4) DEQ determines that the permit should be amended under the discretionary reopening

provisions of OAC 252:100-8-7.3(b).

C. The permit may be reopened for cause by EPA, pursuant to the provisions of OAC 100-8-

7.3(d). [OAC 100-8-7.3(d)]

D. The permittee shall notify AQD before making changes other than those described in Section

XVIII (Operational Flexibility), those qualifying for administrative permit amendments, or those

defined as an Insignificant Activity (Section XVI) or Trivial Activity (Section XVII). The

notification should include any changes which may alter the status of a “grandfathered source,”

as defined under AQD rules. Such changes may require a permit modification.

[OAC 252:100-8-7.2(b) and OAC 252:100-5-1.1]


E. Activities that will result in air emissions that exceed the trivial/insignificant levels and that

are not specifically approved by this permit are prohibited. [OAC 252:100-8-6(c)(6)]

SECTION XIII. INSPECTION & ENTRY

A. Upon presentation of credentials and other documents as may be required by law, the

permittee shall allow authorized regulatory officials to perform the following (subject to the

permittee's right to seek confidential treatment pursuant to 27A O.S. Supp. 1998, § 2-5-105(18)

for confidential information submitted to or obtained by the DEQ under this section):

(1) enter upon the permittee's premises during reasonable/normal working hours where a

source is located or emissions-related activity is conducted, or where records must be

kept under the conditions of the permit;

(2) have access to and copy, at reasonable times, any records that must be kept under the

conditions of the permit;

(3) inspect, at reasonable times and using reasonable safety practices, any facilities,

equipment (including monitoring and air pollution control equipment), practices, or

operations regulated or required under the permit; and

(4) as authorized by the Oklahoma Clean Air Act, sample or monitor at reasonable times

substances or parameters for the purpose of assuring compliance with the permit.

[OAC 252:100-8-6(c)(2)]

SECTION XIV. EMERGENCIES

A. Any exceedance resulting from an emergency shall be reported to AQD promptly but no later

than 4:30 p.m. on the next working day after the permittee first becomes aware of the

exceedance. This notice shall contain a description of the emergency, the probable cause of the

exceedance, any steps taken to mitigate emissions, and corrective actions taken.

[OAC 252:100-8-6 (a)(3)(C)(iii)(I) and (IV)]

B. Any exceedance that poses an imminent and substantial danger to public health, safety, or the

environment shall be reported to AQD as soon as is practicable; but under no circumstance shall

notification be more than 24 hours after the exceedance. [OAC 252:100-8-6(a)(3)(C)(iii)(II)]

C. An "emergency" means any situation arising from sudden and reasonably unforeseeable

events beyond the control of the source, including acts of God, which situation requires

immediate corrective action to restore normal operation, and that causes the source to exceed a

technology-based emission limitation under this permit, due to unavoidable increases in

emissions attributable to the emergency. An emergency shall not include noncompliance to the

extent caused by improperly designed equipment, lack of preventive maintenance, careless or

improper operation, or operator error. [OAC 252:100-8-2]

D. The affirmative defense of emergency shall be demonstrated through properly signed,

contemporaneous operating logs or other relevant evidence that: [OAC 252:100-8-6 (e)(2)]


(1) an emergency occurred and the permittee can identify the cause or causes of the

emergency;

(2) the permitted facility was at the time being properly operated;

(3) during the period of the emergency the permittee took all reasonable steps to minimize

levels of emissions that exceeded the emission standards or other requirements in this

permit.

E. In any enforcement proceeding, the permittee seeking to establish the occurrence of an

emergency shall have the burden of proof. [OAC 252:100-8-6(e)(3)]

F. Every written report or document submitted under this section shall be certified as required

by Section III (Monitoring, Testing, Recordkeeping & Reporting), Paragraph F.

[OAC 252:100-8-6(a)(3)(C)(iv)]

SECTION XV. RISK MANAGEMENT PLAN

The permittee, if subject to the provision of Section 112(r) of the Clean Air Act, shall develop

and register with the appropriate agency a risk management plan by June 20, 1999, or the

applicable effective date. [OAC 252:100-8-6(a)(4)]

SECTION XVI. INSIGNIFICANT ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to

operate individual emissions units that are either on the list in Appendix I to OAC Title 252,

Chapter 100, or whose actual calendar year emissions do not exceed any of the limits below.

Any activity to which a State or Federal applicable requirement applies is not insignificant even

if it meets the criteria below or is included on the insignificant activities list.

(1) 5 tons per year of any one criteria pollutant.

(2) 2 tons per year for any one hazardous air pollutant (HAP) or 5 tons per year for an

aggregate of two or more HAP's, or 20 percent of any threshold less than 10 tons per year

for single HAP that the EPA may establish by rule.

[OAC 252:100-8-2 and OAC 252:100, Appendix I]

SECTION XVII. TRIVIAL ACTIVITIES

Except as otherwise prohibited or limited by this permit, the permittee is hereby authorized to

operate any individual or combination of air emissions units that are considered inconsequential

and are on the list in Appendix J. Any activity to which a State or Federal applicable

requirement applies is not trivial even if included on the trivial activities list.

[OAC 252:100-8-2 and OAC 252:100, Appendix J]

SECTION XVIII. OPERATIONAL FLEXIBILITY

A. A facility may implement any operating scenario allowed for in its Part 70 permit without the

need for any permit revision or any notification to the DEQ (unless specified otherwise in the


permit). When an operating scenario is changed, the permittee shall record in a log at the facility

the scenario under which it is operating. [OAC 252:100-8-6(a)(10) and (f)(1)]

B. The permittee may make changes within the facility that:

(1) result in no net emissions increases,

(2) are not modifications under any provision of Title I of the federal Clean Air Act, and

(3) do not cause any hourly or annual permitted emission rate of any existing emissions unit

to be exceeded;

provided that the facility provides the EPA and the DEQ with written notification as required

below in advance of the proposed changes, which shall be a minimum of seven (7) days, or

twenty four (24) hours for emergencies as defined in OAC 252:100-8-6 (e). The permittee, the

DEQ, and the EPA shall attach each such notice to their copy of the permit. For each such

change, the written notification required above shall include a brief description of the change

within the permitted facility, the date on which the change will occur, any change in emissions,

and any permit term or condition that is no longer applicable as a result of the change. The

permit shield provided by this permit does not apply to any change made pursuant to this

paragraph. [OAC 252:100-8-6(f)(2)]

SECTION XIX. OTHER APPLICABLE & STATE-ONLY REQUIREMENTS

A. The following applicable requirements and state-only requirements apply to the facility

unless elsewhere covered by a more restrictive requirement:

(1) Open burning of refuse and other combustible material is prohibited except as authorized

in the specific examples and under the conditions listed in the Open Burning Subchapter.

[OAC 252:100-13]

(2) No particulate emissions from any fuel-burning equipment with a rated heat input of 10

MMBTUH or less shall exceed 0.6 lb/MMBTU. [OAC 252:100-19]

(3) For all emissions units not subject to an opacity limit promulgated under 40 C.F.R., Part

60, NSPS, no discharge of greater than 20% opacity is allowed except for:

[OAC 252:100-25]

(a) Short-term occurrences which consist of not more than one six-minute period in any

consecutive 60 minutes, not to exceed three such periods in any consecutive 24 hours.

In no case shall the average of any six-minute period exceed 60% opacity;

(b) Smoke resulting from fires covered by the exceptions outlined in OAC 252:100-13-7;

(c) An emission, where the presence of uncombined water is the only reason for failure

to meet the requirements of OAC 252:100-25-3(a); or

(d) Smoke generated due to a malfunction in a facility, when the source of the fuel

producing the smoke is not under the direct and immediate control of the facility and

the immediate constriction of the fuel flow at the facility would produce a hazard to

life and/or property.


(4) No visible fugitive dust emissions shall be discharged beyond the property line on which

the emissions originate in such a manner as to damage or to interfere with the use of

adjacent properties, or cause air quality standards to be exceeded, or interfere with the

maintenance of air quality standards. [OAC 252:100-29]

(5) No sulfur oxide emissions from new gas-fired fuel-burning equipment shall exceed 0.2

lb/MMBTU. No existing source shall exceed the listed ambient air standards for sulfur

dioxide. [OAC 252:100-31]

(6) Volatile Organic Compound (VOC) storage tanks built after December 28, 1974, and

with a capacity of 400 gallons or more storing a liquid with a vapor pressure of 1.5 psia

or greater under actual conditions shall be equipped with a permanent submerged fill pipe

or with a vapor-recovery system. [OAC 252:100-37-15(b)]

(7) All fuel-burning equipment shall at all times be properly operated and maintained in a

manner that will minimize emissions of VOCs. [OAC 252:100-37-36]

SECTION XX. STRATOSPHERIC OZONE PROTECTION

A. The permittee shall comply with the following standards for production and consumption of

ozone-depleting substances: [40 CFR 82, Subpart A]

(1) Persons producing, importing, or placing an order for production or importation of certain

class I and class II substances, HCFC-22, or HCFC-141b shall be subject to the

requirements of §82.4;

(2) Producers, importers, exporters, purchasers, and persons who transform or destroy certain

class I and class II substances, HCFC-22, or HCFC-141b are subject to the recordkeeping

requirements at §82.13; and

(3) Class I substances (listed at Appendix A to Subpart A) include certain CFCs, Halons,

HBFCs, carbon tetrachloride, trichloroethane (methyl chloroform), and bromomethane

(Methyl Bromide). Class II substances (listed at Appendix B to Subpart A) include

HCFCs.

B. If the permittee performs a service on motor (fleet) vehicles when this service involves an

ozone-depleting substance refrigerant (or regulated substitute substance) in the motor vehicle air

conditioner (MVAC), the permittee is subject to all applicable requirements. Note: The term

“motor vehicle” as used in Subpart B does not include a vehicle in which final assembly of the

vehicle has not been completed. The term “MVAC” as used in Subpart B does not include the

air-tight sealed refrigeration system used as refrigerated cargo, or the system used on passenger

buses using HCFC-22 refrigerant. [40 CFR 82, Subpart B]

C. The permittee shall comply with the following standards for recycling and emissions

reduction except as provided for MVACs in Subpart B: [40 CFR 82, Subpart F]

(1) Persons opening appliances for maintenance, service, repair, or disposal must comply

with the required practices pursuant to § 82.156;

(2) Equipment used during the maintenance, service, repair, or disposal of appliances must


comply with the standards for recycling and recovery equipment pursuant to § 82.158;

(3) Persons performing maintenance, service, repair, or disposal of appliances must be

certified by an approved technician certification program pursuant to § 82.161;

(4) Persons disposing of small appliances, MVACs, and MVAC-like appliances must comply

with record-keeping requirements pursuant to § 82.166;

(5) Persons owning commercial or industrial process refrigeration equipment must comply

with leak repair requirements pursuant to § 82.158; and

(6) Owners/operators of appliances normally containing 50 or more pounds of refrigerant

must keep records of refrigerant purchased and added to such appliances pursuant to §

82.166.

SECTION XXI. TITLE V APPROVAL LANGUAGE

A. DEQ wishes to reduce the time and work associated with permit review and, wherever it is

not inconsistent with Federal requirements, to provide for incorporation of requirements

established through construction permitting into the Source’s Title V permit without causing

redundant review. Requirements from construction permits may be incorporated into the Title V

permit through the administrative amendment process set forth in OAC 252:100-8-7.2(a) only if

the following procedures are followed:

(1) The construction permit goes out for a 30-day public notice and comment using the

procedures set forth in 40 C.F.R. § 70.7(h)(1). This public notice shall include notice to

the public that this permit is subject to EPA review, EPA objection, and petition to

EPA, as provided by 40 C.F.R. § 70.8; that the requirements of the construction permit

will be incorporated into the Title V permit through the administrative amendment

process; that the public will not receive another opportunity to provide comments when

the requirements are incorporated into the Title V permit; and that EPA review, EPA

objection, and petitions to EPA will not be available to the public when requirements

from the construction permit are incorporated into the Title V permit.

(2) A copy of the construction permit application is sent to EPA, as provided by 40 CFR §

70.8(a)(1).

(3) A copy of the draft construction permit is sent to any affected State, as provided by 40

C.F.R. § 70.8(b).

(4) A copy of the proposed construction permit is sent to EPA for a 45-day review period

as provided by 40 C.F.R.§ 70.8(a) and (c).

(5) The DEQ complies with 40 C.F.R. § 70.8(c) upon the written receipt within the 45-day

comment period of any EPA objection to the construction permit. The DEQ shall not

issue the permit until EPA’s objections are resolved to the satisfaction of EPA.

(6) The DEQ complies with 40 C.F.R. § 70.8(d).

(7) A copy of the final construction permit is sent to EPA as provided by 40 CFR § 70.8(a).

(8) The DEQ shall not issue the proposed construction permit until any affected State and

EPA have had an opportunity to review the proposed permit, as provided by these

permit conditions.

(9) Any requirements of the construction permit may be reopened for cause after

incorporation into the Title V permit by the administrative amendment process, by


DEQ as provided in OAC 252:100-8-7.3(a), (b), and (c), and by EPA as provided in 40

C.F.R. § 70.7(f) and (g).

(10) The DEQ shall not issue the administrative permit amendment if performance tests fail

to demonstrate that the source is operating in substantial compliance with all permit

requirements.

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

Title V review process.

SECTION XXII. CREDIBLE EVIDENCE

For the purpose of submitting compliance certifications or establishing whether or not a person

has violated or is in violation of any provision of the Oklahoma implementation plan, nothing

shall preclude the use, including the exclusive use, of any credible evidence or information,

relevant to whether a source would have been in compliance with applicable requirements if the

appropriate performance or compliance test or procedure had been performed.

[OAC 252:100-43-6]

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