UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

75 Hawthorne Street 

San Francisco, CA 94105 

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 9 

PSD PERMIT NUMBER: NU 05-01 

PERMITTEE: Resolute Natural Resources Company 

1675 Broadway, Suite 1950 

Denver, Colorado 80202 

FACILITY NAME McElmo Creek Unit Oil Production 

Facility 

FACILITY LOCATION: Section 31, Township 40 South, Range 

25 East within the Four Comers Area 

on the Navajo Nation Indian 

Reservation near the city of Aneth, San 

Juan County, Utah 

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C ( 42 U.S.C. § 7470, 

et. seq.), and the Code of Federal Regulations (CFR) Title 40, Section 52.21, the United States 

Environmental Protection Agency (EPA), Region 9 is issuing this amended Prevention of 

Significant Deterioration (PSD) air quality permit to Resolute Natural Resources Company 

(Resolute) for the McElmo Creek Unit Oil Production Facility as described herein, in accordance 

with the permit application (and plans submitted with the permit application), federal regulations 

governing the Prevention of Significant Deterioration of air quality (40 CFR § 52.21), and other 

terms and conditions set forth in this amended PSD Permit. 

Failure to comply with any condition or term set forth in this amended PSD Permit is subject to 

enforcement action pursuant to Section 113 of the Clean Air Act. This permit does not relieve 

Resolute from the responsibility to comply with any other applicable provisions of the CAA 

(including applicable implementing regulations in 40 CFR Parts 51, 52, 60, 61 and 63), or other 

federal, tribal, and local requirements. 

Per 40 CFR § 124.15(b ), this PSD Permit becomes effective 30 days after the service of notice of 

this final permit decision unless review is requested on the permit pursuant to 40 CFR § 124.19. 

,f;� fft=ltl�v 5D1 2LJ f lo

Date 
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ABBREVIATIONS & ACRONYMS

Act Clean Air Act [42 U.S.C. § 7401 et seq.]

BACT Best Available Control Technology

BTU British thermal units

CAA Clean Air Act [42 U.S.C. § 7401 et seq.]

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations

CMS Continuous Monitoring System

CO Carbon Monoxide

CO2 Carbon Dioxide

CPMS Continuous Parameter Measurement System

EPA United States Environmental Protection Agency

H2S Hydrogen Sulfide

hp Horsepower

hr Hour

lb, lbs Pound, pounds

MCU Facility / 

Facility McElmo Creek Unit Oil Production Facility

min Minute

MMBTU Million British thermal units

MMCFD Million cubic feet per day

NAAQS National Ambient Air Quality Standards

NHVdil Net heating value of dilution

NHVvg Net heating value of vent gas

NOx Oxides of nitrogen

O2 Oxygen

Permittee / Owner or 

Operator

Resolute Natural Resources Company, or the owner and/or operator 

of the McElmo Creek Unit Oil Production Facility

PSD Prevention of Significant Deterioration

scf Standard cubic feet

scfm Standard cubic feet permit minute

SO2 Sulfur Dioxide

tpy Tons per year

VOC Volatile Organic Compounds as defined in 40 CFR § 51.100(s)
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MCELMO CREEK UNIT OIL PRODUCTION FACILITY

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT

PROJECT DESCRIPTION

The McElmo Creek Unit Oil Production Facility (MCU Facility or Facility) is an existing oil and 

gas production operation located within the Four Corners Area on the Navajo Nation Indian 

Reservation near the city of Aneth, San Juan County, Utah. The Facility is owned, in partnership 

with the Navajo Nation Oil and Gas Company, and operated by the Resolute Natural Resources 

Company. The Facility is on the McElmo Creek Unit oilfield, which includes field operations 

and a gas compression plant. 

The field operations consist of approximately 90 producing wells where petroleum crude oil is 

recovered from producing strata, and brought to the surface to be stored at either a satellite tank 

battery (i.e., in general, a sub-tank battery that is located between wells and the main tank 

battery) or a main tank battery. There are eleven satellite tank batteries that function as testing 

facilities for producing wells and four main tank batteries.

The gas compression plant serves tertiary oil recovery operations for the McElmo Creek Unit 

oilfield. The gas compression plant receives produced gas through a gathering system, pressures 

the gas up to a suitable working pressure, and re-injects the gas to maintain reservoir pressure in 

the oilfield. The natural gas is injected with produced water in a dual injection system. The 

Main Flare is located at the gas compression plant.

This PSD Permit amendment revises the existing PSD permit by incorporating Best Available 

Control Technology (BACT) requirements for the Main Flare, including emission limitations for 

emissions of sulfur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide (CO), and volatile 

organic compounds (VOC). Air pollution emissions associated with this permit amendment will 

not cause or contribute to violations of any National Ambient Air Quality Standards (NAAQS) 

or any applicable PSD increments for the pollutants regulated under the PSD permit.
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EQUIPMENT LIST

The following devices and activities are subject to this PSD Permit.

Unit ID Description

Main Flare One (1) air-assist flare, rated at 618,104 scf/hr, which combusts 

produced field gas in excess of the facility compression capacity

Glycol Dehydrator

One (1) Glycol Dehydrator with one (1) Triethylene Glycol (TEG)

Reboiler rated at 0.75 MMBtu/hr, which combusts purchased 

pipeline quality natural gas to provide heat to the Glycol Heater

Glycol Heater One (1) Glycol Heater (TEG regenerator), rated at 12 MMCFD, 

which provides inter-stage dehydration for the HOS-6 compressor

Gasoline Storage Tank One (1) 10,000 gallon nominal capacity gasoline storage tank that 

is used for refueling of vehicles

Aerial C-5 Compressor Ariel JGD-6 electrically-driven compressor, driven by a Reliance 

model 9240 AC induction motor rated at 2,500 hp

HOS-4 Compressor Dresser Rand HOS-4 electrically-driven compressor, driven by a 

General Electric model EK AC induction motor rated at 2,000 hp

HOS-6 Compressor Dresser Rand HOS-6 electrically-driven compressor, driven by an 

Allis Chalmers model 6802 AC induction motor rated at 5,000 hp

Acid Gas A Compressor Worthington Cub-4 electrically-driven compressor, driven by a 

Westinghouse model 6808 AC induction motor rated at 400 hp

Acid Gas B Compressor Worthington Cub-4 electrically-driven compressor, driven by a 

Westinghouse model 6808 AC induction motor rated at 400 hp

PERMIT CONDITIONS

I. PERMIT EXPIRATION

As provided in 40 CFR § 52.21(r), this PSD Permit shall become invalid if construction:

A. is not commenced (as defined in 40 CFR § 52.21(b)(9)) within 18 months after 

the approval takes effect; or

B. is discontinued for a period of 18 months or more; or 

C. is not completed within a reasonable time. 
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II. PERMIT NOTIFICATION REQUIREMENTS

The Permittee shall notify the EPA Region 9 by letter or by electronic mail of the:

A. date construction is commenced, postmarked within 30 days of such date; 

B. actual date of initial startup, as defined in 40 CFR § 60.2, postmarked within 15 

days of such date; 

C. date upon which initial performance tests will commence postmarked not less 

than 30 days prior to such date. Notification may be provided with the submittal 

of the performance test protocol; and 

D. date upon which initial performance evaluation of the continuous emissions 

monitoring system (CEMS) will commence in accordance with 40 CFR § 

60.13(c), postmarked not less than 30 days prior to such date. Notification may 

be provided with the submittal of the CEMS performance test. 

III. FACILITY OPERATION

A. At all times, including periods of startup, shutdown, shakedown, and malfunction, 

the Permittee shall, to the extent practicable, maintain and operate the Facility,

including associated air pollution control equipment, in a manner consistent with 

good air pollution control practice for minimizing emissions. Determination of 

whether acceptable operating and maintenance procedures are being used will be 

based on information available to the EPA, which may include, but is not limited 

to, monitoring results, opacity observations, review of operating maintenance 

procedures, and inspection of the Facility. 

B. The operating staff with management authority at this Facility shall be advised of 

and be familiar with all the conditions of this PSD Permit.

IV. GENERAL MALFUNCTION REPORTING

A. The Permittee shall notify the EPA at AEO_R9@epa.gov within two (2) working 

days following the discovery of any failure of air pollution control equipment or 

process equipment, or failure of a process to operate in a normal manner, which 

results in an increase in emissions above the allowable emission limits stated in 

Section IX of this permit.

B. In addition, the Permittee shall provide an additional notification to the EPA in 

writing or electronic mail within fifteen (15) days of any such failure described 
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under Condition IV.A. This notification shall include a description of the 

malfunctioning equipment or abnormal operation, the date of the initial 

malfunction, the period of time over which emissions were increased due to the 

failure, the cause of the failure, the estimated resultant emissions in excess of 

those allowed in Section IX, and the methods utilized to mitigate emissions and 

restore normal operations. 

C. Compliance with this malfunction notification provision shall not excuse or 

otherwise constitute a defense to any violation of this permit or any law or 

regulation such malfunction may cause. 

V. RIGHT OF ENTRY

A. The EPA and its contractors, consultants, and agents shall have authority to enter 

the Facility at all reasonable times, and upon presentation of credentials, shall be 

permitted to:

1. Enter the premises where the Facility is located or where any records are 

required to be kept under the terms and conditions of this PSD Permit; 

2. During normal business hours, have access to and to copy any records 

required to be kept under the terms and conditions of this PSD Permit; 

3. Inspect any equipment, operation, or method subject to requirements in 

this PSD Permit; and

4. Sample materials and emissions from the Facility.

B. This provision in no way limits or otherwise affects any right of entry held by the 

EPA pursuant to applicable federal, state, or local laws, regulations, or permits.

VI. TRANSFER OF OWNERSHIP

In the event of any changes in control or ownership of the Facility, this PSD Permit shall 

be binding on all subsequent owners or operators. Within 14 days of any such change in 

control or ownership, the Permittee shall notify the succeeding owner or operator of the 

existence of this PSD Permit and its conditions by letter. The Permittee shall send a copy 

of this letter to the EPA Region 9 within thirty (30) days of its issuance.

VII. SEVERABILITY
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The provisions of this PSD Permit are severable, and, if any provision of the PSD Permit 

is held invalid, the remainder of this PSD Permit shall not be affected.

VIII. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LAWS

The Permittee shall construct in accordance with this PSD Permit, the application on 

which this permit is based, and all other applicable federal, state, and local air quality 

regulations. This PSD Permit does not release the Permittee from any liability for 

compliance with other applicable federal, state, and local environmental laws and 

regulations, including the Clean Air Act.

IX. SPECIAL CONDITIONS FOR THE MAIN FLARE

A. Definitions

1. “CO2 Breakthrough” shall mean an event where a gas or fluid injected in 

the Facility’s oil field for the purpose of promoting the production of oil 

contacts a producing well and results in an increase in gas volume to 

compressor station equipment.

2. “Day” shall mean a calendar day, unless expressly stated to be a working 

day. In computing any period of time under Section IX of this PSD 

Permit, where the last day of such period would fall on a Saturday, 

Sunday, or federal holiday, the period shall run until the close of business 

on the next day that is not a Saturday, Sunday, or federal holiday.

3. “Facility” shall mean the Permittee’s McElmo Creek Unit Oil Production 

Facility and associated oil fields, located near Aneth, Utah, on the Navajo 

Nation Indian Reservation. 

4. “Field Flares” shall mean the following flares at the Facility: (i) Tank 

Battery Flares at MCU Area 1 Battery, MCU Area 2 Battery, MCU Area 4 

Battery, and MCU Area 6 Battery; and (ii) Satellite Flares at MCU Section 

2, MCU Section 3, MCU Section 5, MCU Section 6, MCU Section 9, 

MCU Section 11, MCU Section 17, MCU Section 19, MCU Section 32, 

and MCU Section 33.

5. “Flaring Incident” shall mean continuous or intermittent flaring at the 

Main Flare that results in the emissions of SO2 equal to, or greater than, 

500 pounds in any 24-hour period; provided, however, that if 500 pounds 

or more of SO2 have been emitted in a 24-hour period and the flaring 
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continues into subsequent, contiguous, non-overlapping 24-hour period(s), 

each period of which results in emissions equal to, or greater than, five

hundred (500) pounds of SO2, then only one Flaring Incident shall have 

occurred. Subsequent, contiguous, non-overlapping periods are measured 

from the initial commencement of flaring within the Flaring Incident.

6. “Main Flare” shall mean the flare installed as part of the Facility’s former 

gas processing plant. 

7. “Main Flare Emissions” shall mean the emissions from the Main Flare at 

the Facility as well as all emissions that result from: (1) combustion of 

fuel gas in the Main Flare’s pilot, (2) the closed drain and filter backwash 

operations, (3) CO2 Breakthroughs, (4) any Scheduled Maintenance, and 

(5) unscheduled maintenance of the Facility’s compressors.

8. “Malfunction” shall mean, for the purposes of reporting under Condition 

IX.H.3 of this PSD Permit only, any sudden and unavoidable breakdown 

of process or pollution control equipment. CO2 Breakthroughs and 

Scheduled Maintenance of the Facility’s compressors are not 

Malfunctions. 

9. “Root Cause” shall mean the primary cause of a Flaring Incident as 

determined through a process of investigation; provided, however, that if a 

Flaring Incident encompasses multiple releases of SO2, the “Root Cause” 

may encompass multiple primary causes.

10. “Scheduled Maintenance” shall mean work that is part of the routine work 

plan for the compressors located at the Facility's former gas processing 

plant. This work is typically planned and arranged on a set frequency, 

usually based on periods of time (e.g., daily, weekly or monthly) or on the 

operating hours of the equipment. Scheduled Maintenance shall not 

include work necessitated by the failure of a part of a compressor.

B. Air Pollution Control Equipment 

The Main Flare shall be an automatic air-assisted flare system.

C. Emission Limitations

1. The Permittee shall not discharge or cause the discharge of Main Flare 

Emissions from the Main Flare into the atmosphere in excess of the 
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following the emission limitations, based on a cumulative 365-day rolling 

total. 

SO2 NOx CO VOC

60.0 tpy 13.4 tpy 73.0 tpy 95.4 tpy

2. The Permittee shall calculate the 365-day rolling emissions totals for SO2, 

NOx, CO, and VOC each day for the Main Flare.

3. The Permittee shall not use the Field Flares to circumvent the emission 

limitations in Condition IX.C.1. 

4. All emissions during all modes of operation (including, but not limited to, 

emissions during periods of startup, shutdown, or malfunction) shall be 

used in determining compliance with the emission limitations in Condition 

IX.C.1.

D. Main Flare Operational Requirements

1. The Permittee shall install, operate and maintain an automatic air-assisted 

flare system on the Main Flare, pursuant to the provisions of 40 CFR §

60.18(c)(5) and (f)(6). 

2. The Permittee shall operate and maintain the Main Flare in compliance 

with 40 CFR § 60.18(c)(l), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (f)(1) through 

(f)(4), and (f)(6). 

3. The Main Flare shall be operated with a flame present at all times when 

emissions may be vented to it.

4. The Permittee shall comply with the following requirements for ensuring 

proper combustion efficiency:

The net heating value air assist dilution parameter (NHVdil) shall be 

greater than or equal to 24 BTU/ft2

, on a daily basis, calculated in 

accordance with the following equations. If NHVdil is less than 24 

BTU/ft2, the Permittee shall take actions as expeditiously as 

practicable to raise NHVdil to comply with the limit. The Permittee 

shall determine NHVdil in BTU/ft2 as specified in Condition IX.E.2 of 

this Permit.
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Equation 1: DDDD = QQvvvv × DDDDDDDD

QQvvvv + QQpppppppppppp aa + QQpppppppppppppppppp aa

Equation 2: NNNNNNdd dd = NNNNNNvvvv × DDDD

where:

DF = Dilution factor, feet (ft).

Qvg = Volumetric flow rate of the flare vent gas, scfm. 

Qpremix air = Cumulative volumetric flow of premix assist air, scfm

(Premix assist air means the portion of assist air that is introduced to 

the flare vent gas, whether injected or induced, prior to the flare tip)

Qperimeter air = Cumulative volumetric flow of perimeter assist air, scfm.

(Perimeter assist air means the portion of assist air introduced at the 

perimeter of the flare tip or above the flare tip. Perimeter assist air 

includes all assist air except premix assist air.)

Diam = Diameter of the flare vent gas release stack, ft. 

NHVvg = Net heating value of flare vent gas, BTU/scf.

NHVdil = Net heating value air assist dilution parameter, BTU/ft2.

5. The Permittee shall also perform any necessary operations to minimize 

emissions so that emissions are at or below the emission limits specified in 

this Permit. 

E. Monitoring, Testing, and Emissions Calculations

1. The Permittee shall use the following requirements to determine 

compliance with the emission limitations in Condition IX.C.1 for the Main 

Flare.
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The Permittee shall measure and record the H2S concentration in the 

field gas at the Facility in each calendar month at the inlet to the 

Facility’s former gas processing plant where the Main Flare is located. 

The Permittee shall measure and record the volume of gas combusted 

in the Main Flare in scfm when the flare is in use. 

Each and every calendar day, the Permittee shall calculate and record 

the daily emissions from the Main Flare based on the last recorded 

measurement of H2S concentration in the field gas at the Facility and 

that day’s recorded volume of gas combusted in the Main Flare. 

Each and every calendar day, the Permittee shall calculate the 365-day 

rolling total of emissions of SO2, NOx, CO, and VOC for the Main 

Flare, using best available data and good engineering practices. Each 

365-day rolling total shall be calculated using data from the previous 

365 days. The Permittee shall maintain all records of actual operating 

data and calculations. 

If the Permittee is unable to measure the volume of gas combusted in 

the Main Flare on any day, the volume of gas for that day shall be 

deemed to be equal to the daily average volume of gas combusted in 

the Main Flare based on the previous 12 months’ emissions data. 

However, the use of this daily average as substitute data neither 

relieves nor excuses the Permittee from complying with the sampling, 

data collection, and monitoring requirements. 

2. Determination of Net Heating Value Air Assist Dilution Parameter

Flare vent gas and air assist flowrate monitoring

(1) The Permittee shall use one or more of the following methods

to monitor flare vent gas flowrate or comply with Condition 

IX.E.2.(a)(3) of this PSD Permit. In addition, the Permittee 

shall use a monitoring system capable of correcting any such 

measured flow rates to standard conditions, as specified in 

Condition IX.E.2.(a)(4).

Continuously monitor and record the volume of gas 

combusted in the Main Flare in scfm per Condition 

IX.E.1.(b) of this PSD Permit; or
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Install, operate, and maintain a mass flow monitor and 

determine volumetric flow rate of flare vent gas using 

Equation 3 below to convert mass flow rates to volumetric 

flowrate. For the flare vent gas, molecular weight must be 

determined using compositional analysis.

Equation 3: QQvvvv = QQ mmmm × 385.3

MMMMMM

Where:

Qvol = Volumetric flow rate, standard cubic feet per second.

Qmass = Mass flow rate, pounds per second.

385.3 = Conversion factor, standard cubic feet per poundmole.

MWt = Molecular weight of the gas at the flow monitoring 

location, pounds per pound-mole.

(2) The Permittee shall use one or more of the following methods 

to monitor assist air flowrate or comply with Condition 

IX.E.2.(a)(3) of this PSD Permit. In addition, the Permittee 

shall use a monitoring system capable of correcting any such 

measured flow rates to standard conditions, as specified in 

Condition IX.E.2.(a)(4).

Monitor the fan speed or power, and use fan curves and 

appropriate engineering calculations to determine assist air 

flow rates; or

Install, operate, calibrate, and maintain a monitoring system 

capable of continuously measuring, calculating, and 

recording the volumetric flow rate of assist air used with 

the flare. If premix assist air and perimeter assist air are 

both used, install, operate, calibrate, and maintain a 

monitoring system capable of separately measuring, 

calculating, and recording the volumetric flow rate of 

premix assist air and perimeter assist air used with the flare; 

or
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Install, operate, calibrate, and maintain a mass flow 

monitor and determine the volumetric flow rate of assist air 

using Equation 3 above to convert mass flow rates to 

volumetric flow rate (use a molecular weight of 29 pounds 

per pound-mole for assist air).

(3) Continuous pressure/temperature monitoring system(s) (i.e., at 

least once every 15-minutes) and appropriate engineering 

calculations may be used in lieu of a volumetric flow 

monitoring systems provided the molecular weight of the gas is 

known. For assist air, use a molecular weight of 29 pounds per 

pound-mole. For flare vent gas, molecular weight must be 

determined using compositional analysis per Condition 

IX.E.2.(b) of this PSD Permit.

(4) The flow rate monitoring systems must be able to correct for 

the temperature and pressure of the system and output 

parameters in standard conditions (i.e., a temperature of 20°C 

(68°F) and a pressure of 1 atmosphere).

The Permittee shall use one or more of the following methods to 

monitor the net heating value of the flare vent gas.

(1) Each month, measure and record the concentration of 

individual components in the flare vent gas at the Facility in 

each calendar month at the inlet to the Facility’s former gas 

processing plant where the Main Flare is located and use this 

information to calculate NHVvg using Equation 4 in Condition 

IX.E.2.(c) of this PSD permit; or

(2) Each month, measure and record with a calorimeter the net 

heating value of the flare vent gas at standard conditions at the 

Facility in each calendar month at the inlet to the Facility’s 

former gas processing plant where the Main Flare is located; or

(3) The owner or operator may elect to use a different monitoring 

method, determined on a monthly basis, for the vent gas 

provided the composition or NHVvg are determined consistent 

with good engineering practices.
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Each month, the Permittee shall determine the net heating value of the 

flare vent gas (NHVvg) based on compositional analysis performed per 

Condition IX.E.2.(b)(1) of this PSD Permit using Equation 4 below, by 

direct measurement of the net heating value of the flare vent gas at 

standard conditions as specified in Condition IX.E.2.(b)(2) of this PSD 

Permit, or as allowed by Condition IX.E.2.(b)(3) of this PSD Permit.

Equation 4: NNNNNNvvvv = �xx

nn

=1

NNNNNN

Where:

NHVvg = Net heating value of flare vent gas, BTU/scf.

i = Individual component in flare vent gas.

n = Number of components in flare vent gas.

xi = Concentration of component i in flare vent gas, volume fraction.

NHVi = Net heating value of component i according to Table 1

below, Btu/scf. If the component is not specified in Table 

1 below, the heats of combustion may be determined using 

any published values where the net enthalpy per mole of 

offgas is based on combustion at 25°C and 1 atmosphere 

(or constant pressure) with offgas water in the gaseous 

state, but the standard temperature for determining the

volume corresponding to one mole of vent gas is 20°C.
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Table 1— Individual Component Properties

Component

Molecular 

Formula

MWi

(pounds per 

pound-mole)

NHVi

(British thermal units 

per standard cubic foot)

Acetylene C2H2 26.04 1,404

Benzene C6H6 78.11 3,591

1,2-Butadiene C4H6 54.09 2,794

1,3-Butadiene C4H6 54.09 2,690

iso-Butane C4H10 58.12 2,957

n-Butane C4H10 58.12 2,968

cis-Butene C4H8 56.11 2,830

iso-Butene C4H8 56.11 2,928

trans-Butene C4H8 56.11 2,826

Carbon Dioxide CO2 44.01 0

Carbon Monoxide CO 28.01 316

Cyclopropane C3H6 42.08 2,185

Ethane C2H6 30.07 1,595

Ethylene C2H4 28.05 1,477

Hydrogen H2 2.02 274

Hydrogen Sulfide H2S 34.08 587

Methane CH4 16.04 896

Methyl-Acetylene C3H4 40.06 2,088

Nitrogen N2 28.01 0

Oxygen O2 32.00 0

Pentane+ (C5+) C5H12 72.15 3,655

Propadiene C3H4 40.06 2,066

Propane C3H8 44.10 2,281

Propylene C3H6 42.08 2,150

Water H2O 18.02 0

Each and every calendar day, the Permittee shall determine the net 

heating value air assist dilution parameter (NHVdil) based on the flare 

vent gas flowrates per Condition IX.E.2(a)(1), air assist flowrates per 

Condition IX.E.2(a)(2), and NHVvg per Condition IX.E.2(b) and (c) of 

this PSD Permit, and using the equations in Condition IX.D.4 of this 

PSD Permit. 

3. The Permittee shall continuously monitor the Main Flare for the presence 

of a flare pilot flame using a device (including, but not limited to, a 

thermocouple, ultraviolet beam sensor, or infrared sensor) capable of 
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detecting that the pilot flame is present. The Main Flare shall be equipped 

with an alarm that informs Facility operators of any period when a pilot 

flame is not present in the flare and no gas shall be sent to the flare until a 

pilot flame is restored.

4. The Permittee shall operate the Main Flare with no visible emissions, 

except for periods not to exceed a total of 5 minutes during any 2 

consecutive hours. EPA Test Method 22 in Appendix A of 40 CFR Part 

60 shall be used to determine the compliance of flares with the visible 

emission provisions. The observation period is 2 hours and shall be used 

according to Method 22. The Permittee shall perform monthly visible 

emissions tests during a flaring event using Method 22. 

5. If applicable, the Permittee shall follow the calibration and quality control 

requirements below for any corresponding continuous parameter 

measurement systems (CPMS) if used at the Facility to comply with the 

requirements in Condition IX.D or IX.E of this PSD Permit.

For flare vent gas volumetric flowrates, the following requirements 

apply:

Minimum accuracy requirements Calibration requirements

±20 percent of flow rate at velocities 

ranging from 0.03 to 0.3 meters per 

second (0.1 to 1 feet per second)

±5 percent of flow rate at velocities 

greater than 0.3 meters per second (1 

feet per second)

Conduct a flow sensor calibration check at least biennially (every two 

years); conduct a calibration check following any period of more than 

24 hours throughout which the flow rate exceeded the manufacturer's 

specified maximum rated flow rate or install a new flow sensor.

At least quarterly, inspect all components for leakage, unless the 

CPMS has a redundant flow sensor.

Record the results of each calibration check and inspection.

Locate the flow sensor(s) and other necessary equipment (such as 

straightening vanes) in a position that provides representative flow; 

reduce swirling flow or abnormal velocity distributions due to 

upstream and downstream disturbances.

For flowrate and all flows other than the flare vent gas, the following 

requirements apply:

Minimum accuracy requirements Calibration requirements

±5 percent over the normal range of 

flow measured or 1.9 liters per minute 

Conduct a flow sensor calibration check at least biennially (every two 

years); conduct a calibration check following any period of more than 
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(0.5 gallons per minute), whichever is 

greater, for liquid flow

24 hours throughout which the flow rate exceeded the manufacturer's 

specified maximum rated flow rate or install a new flow sensor.

±5 percent over the normal range of 

flow measured or 280 liters per minute 

(10 cubic feet per minute), whichever is 

greater, for gas flow

At least quarterly, inspect all components for leakage, unless the 

CPMS has a redundant flow sensor.

±5 percent over the normal range 

measured for mass flow

Record the results of each calibration check and inspection.

Locate the flow sensor(s) and other necessary equipment (such as 

straightening vanes) in a position that provides representative flow; 

reduce swirling flow or abnormal velocity distributions due to 

upstream and downstream disturbances.

For net heating value determinations by calorimeter, the following 

requirements apply:

Minimum accuracy requirements Calibration requirements

±2 percent of span Specify calibration requirements in your site specific CPMS 

monitoring plan. Calibration requirements should follow 

manufacturer's recommendations at a minimum.

Temperature control (heated and/or cooled as necessary) the sampling 

system to ensure proper year-round operation.

Where feasible, select a sampling location at least two equivalent 

diameters downstream from and 0.5 equivalent diameters upstream 

from the nearest disturbance. Select the sampling location at least two 

equivalent duct diameters from the nearest control device, point of 

pollutant generation, air in-leakages, or other point at which a change 

in the pollutant concentration or emission rate occurs.

For net heating value determinations by gas chromatograph, the 

following requirements apply:

Minimum accuracy requirements Calibration requirements

As specified in Performance 

Specification 9 of 40 CFR part 60, 

appendix B

Follow the procedure in Performance Specification 9 of 40 CFR part 

60, appendix B, except that a single weekly mid-level calibration 

check can be used (rather than triplicate analysis), the multi-point 

calibration can be conducted quarterly (rather than monthly), and the 

sampling line temperature must be maintained at a minimum 

temperature of 60 °C (rather than 120 °C).
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The following requirements apply for temperature monitoring systems:

Minimum accuracy requirements Calibration requirements

±1 percent over the normal range of 

temperature measured, expressed in 

degrees Celsius (C), or 2.8 degrees C, 

whichever is greater

Conduct calibration checks at least annually; conduct calibration 

checks following any period of more than 24 hours throughout which 

the temperature exceeded the manufacturer's specified maximum 

rated temperature or install a new temperature sensor.

At least quarterly, inspect all components for integrity and all 

electrical connections for continuity, oxidation, and galvanic 

corrosion, unless the CPMS has a redundant temperature sensor.

Record the results of each calibration check and inspection.

Locate the temperature sensor in a position that provides a 

representative temperature; shield the temperature sensor system from 

electromagnetic interference and chemical contaminants.

The following requirements apply for pressure monitoring systems:

Minimum accuracy requirements Calibration requirements

±5 percent over the normal operating 

range or 0.12 kilopascals (0.5 inches of 

water column), whichever is greater

Review pressure sensor readings at least once a week for straightline 

(unchanging) pressure and perform corrective action to ensure proper 

pressure sensor operation if blockage is indicated.

Using an instrument recommended by the sensor's manufacturer, 

check gauge calibration and transducer calibration annually; conduct 

calibration checks following any period of more than 24 hours 

throughout which the pressure exceeded the manufacturer's specified 

maximum rated pressure or install a new pressure sensor.

At least quarterly, inspect all components for integrity, all electrical 

connections for continuity, and all mechanical connections for 

leakage, unless the CPMS has a redundant pressure sensor.

Record the results of each calibration check and inspection.

Locate the pressure sensor(s) in a position that provides a 

representative measurement of the pressure and minimizes or 

eliminates pulsating pressure, vibration, and internal and external 

corrosion.

F. Operation and Maintenance of Main Flare and Compressors

1. The Permittee shall at all times and to the extent practicable, including 

during periods of startup, shutdown, malfunction, CO2 Breakthrough, 
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Scheduled Maintenance, or unscheduled maintenance of the Facility’s 

compressors, operate and maintain the compressor station equipment and 

Main Flare in a manner consistent with good air pollution control practices 

for minimizing emissions.

2. The Permittee shall comply with the provisions of the Operations and 

Maintenance Plan in Appendix A of this PSD Permit. The Permittee’s 

failure to comply with any requirement of the Operations and Maintenance 

Plan shall constitute a violation.

3. The Permittee shall follow the procedures for the inspection of the 

Facility’s compressors and associated equipment as set forth in the Life 

Cycle Maintenance Plan of the Operations and Maintenance Plan in 

Appendix A of this PSD Permit, and shall maintain inspection logs at the 

Facility documenting that these inspections have been conducted. 

4. The Permittee shall maintain daily records at the Facility regarding 

operation of the Facility’s compressors on a Daily Plant Reading Form in 

the Operations and Maintenance Plan in Appendix A of this PSD Permit.

5. The Permittee shall maintain a supply of designated spare parts for the 

Facility’s compressors and associated equipment that includes all of the 

equipment on the Spare Parts List in the Operations and Maintenance Plan 

in Appendix A of this PSD Permit.

6. After using equipment on its Spare Parts List, the Permittee shall replace 

such equipment as expeditiously as possible. The Permittee shall place a 

purchase order for such equipment within 45 days after it is used. 

7. The Permittee shall conduct training of Facility operators in accordance 

with the Training Program for Plant Operators in Section 5 of the 

Operations and Maintenance Plan in Appendix A of this PSD Permit. The 

Permittee shall maintain records documenting that the training has been 

conducted. 

8. The Permittee shall retain copies of inspection logs and other records 

required by Section IX.F (Operations and Maintenance of Main Flare and 

Compressors) of this PSD Permit. 

9. The Permittee shall maintain inspection, maintenance and repair log(s) or 

other similar records and identify any occasion when the Permittee was 
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unable to carry out its established maintenance procedures, with 

explanation.

10. The Operations and Maintenance Plan in Appendix A of this PSD Permit

shall be updated periodically to account for changes in the operation of the 

Main Flare, but the plan need be resubmitted to the EPA only if the owner 

or operator adds new equipment or removes existing equipment listed in 

this PSD Permit. If such revision is needed, Resolute shall request a 

permit amendment (Attn: AIR-3). The owner or operator must comply 

with the updated plan as submitted.

G. Flare Minimization for the Main Flare

1. Flare Minimization Plan

The Permittee shall develop and implement a written Flare 

Minimization Plan (FMP) for the Main Flare that contains information 

about the operation of the flare to minimize Flaring Incidents. At 

minimum, the FMP must include all of the following information:

(1) A listing of all process units and ancillary equipment connected 

to the flare.

Flare design parameters including:

(A)A general description of the flare, including whether it 

is a ground flare or elevated (including height);

(B) Information regarding design capacity;

(C) General description of flare tip (date installed, 

manufacturer, nominal and effective tip diameter, tip 

drawing);

(D)A description of the assist system and an indication of 

whether the fan/blower is single speed, multi-fixed 

speed (e.g., high, medium, and low speeds), or variable 

speeds; and

(E) The flame detection system and pilot ignition system.

(2) Detailed description of the manufacturer’s specifications, 

including, but not limited to, make, model, type, range, 

precision, accuracy, calibration, maintenance and quality 

assurance procedures.
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(3) A simple process flow diagram of the flare system illustrating 

all connections to the flare including all pipelines, process 

units, compressors and other ancillary equipment that vent to 

the flare.

(4) A description of the locations of all associated monitoring and 

of the methods for monitoring flow rate to the flare (including 

a detailed description of the manufacturer’s specifications for 

each flow monitoring system including but not limited to make, 

model, type, range, precision, accuracy, calibration, 

maintenance, and quality assurance procedures for flare gas 

monitoring devices).

(5) A description of the data recording, collection and management 

for the flare monitoring system.

(6) An assessment of whether discharges to the flare from these 

process units and ancillary equipment can be minimized or 

prevented during periods of upsets, malfunctions, or 

emergency releases.

(7) A description of the method to alert personnel designated to 

collect samples that a Flare Incident has started.

The Permittee shall develop and implement a written FMP no later 

than three (3) years after the final PSD permit amendment becomes 

effective pursuant to 40 CFR 124.15(b).

The FMP shall be updated periodically to account for changes in the 

operation of the Main Flare, such as new connections to the Main 

Flare, at least once every five (5) years since the previous update of the 

plan. The owner or operator need not resubmit the plan to the EPA 

unless the owner or operator alters the design capacity of the Main 

Flare. The owner or operator must comply with the updated plan as 

submitted.

2. Root Cause Analysis 

For a Flaring Incident caused by Scheduled Maintenance or a CO2

Breakthrough, the Permittee shall submit a report to the EPA, at the 

address in Condition X.C of this PSD Permit, no later than sixty (60) 

days following the end of such a Flaring Incident that sets forth the 
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following information listed below. Except for those Flaring Incidents 

caused by Scheduled Maintenance or a CO2 Breakthrough, the 

Permittee shall conduct a Root Cause Analysis in accordance with the 

Root Cause Failure Analysis Program in Appendix B of this PSD 

Permit to evaluate the cause of each Flaring Incident and shall submit 

a report to the EPA, at the address in Condition X.C of this PSD 

Permit, no later than sixty (60) days following the end of a Flaring 

Incident, that sets forth all of the following: 

(1) The date and time that the Flaring Incident started and ended. 

To the extent that the Flaring Incident involved multiple 

releases either within a 24-hour period or within subsequent, 

contiguous, non-overlapping 24-hour periods, the Permittee 

shall set forth the starting and ending dates and times of each 

release;

(2) An estimate of the quantity of SO2 that was emitted and the 

calculations that were used to determine that quantity;

(3) The steps, if any, that the Permittee took to limit the duration 

and/or quantity of SO2 emissions associated with the Flaring 

Incident;

(4) Except for those Flaring Incidents caused by Scheduled 

Maintenance or a CO2 Breakthrough, a detailed analysis that 

sets forth the Root Cause and all contributing causes of that 

Flaring Incident, to the extent determinable; however, if a 

Flaring Incident is caused by Scheduled Maintenance or CO2

Breakthrough, then the Permittee need only identify the Root 

Cause as Scheduled Maintenance or CO2 Breakthrough 

(whichever is applicable), and either (i) describe the nature of 

the work done for Scheduled Maintenance or (ii) identify the 

specific wells that most likely experienced the CO2

Breakthrough;

(5) An analysis of the measures, including possible design, 

operational, and maintenance changes, that are available to 

reduce the likelihood of a recurrence of a Flaring Incident 

resulting from the same Root Cause or contributing causes in 

the future. If the Permittee concludes that corrective action(s) 

is (are) required under Section IX.G.3 (Corrective Action) of 

this PSD Permit, the report shall include a description of the 
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action(s) and, if not already completed, a schedule for its (their) 

implementation, including proposed commencement and 

completion dates. If the Permittee concludes that corrective 

action is not required under Section IX.G.3 (Corrective Action) 

of this PSD Permit, the report shall explain the basis for that 

conclusion;

(6) To the extent that investigations of the causes and/or possible 

corrective actions still are under way on the due date of the 

report, a statement of the anticipated date by which a follow-up 

report fully conforming to the requirements of Conditions 

IX.G.2.(a)(4) and (5) of this PSD Permit will be submitted. 

Nothing in this Permit Condition shall be deemed to excuse the 

Permittee from its investigation, notification, reporting, and 

corrective action obligations in this PSD Permit for any Flaring 

Incident that occurs after the Flaring Incident for which the

Permittee has requested an extension of time under this Permit 

Condition.

(7) To the extent that completion of the implementation of 

corrective action(s), if any, is not finalized at the time of the 

submission of the report required under this Permit Condition, 

then, by no later than thirty (30) days after completion of the 

implementation of corrective action(s), the Permittee shall 

submit a report identifying the corrective action(s) taken and 

the dates of commencement and completion of implementation.

The Root Cause Failure Analysis Program in Appendix B of this PSD 

Permit shall be updated periodically to account for changes in the 

operation of the Main Flare, but the plan need be resubmitted to the 

EPA only if the owner or operator adds new equipment or removes 

existing equipment listed in the permit. If such revision is needed, 

Resolute shall request a permit amendment (Attn: AIR-3). The owner 

or operator must comply with the updated Root Cause Failure Analysis 

Program as submitted.

No later than 72 hours after an event first qualifies as a Flaring 

Incident, the Permittee shall notify by electronic mail, at 

AEO_R9@epa.gov, the Manager of the Air/TRI Enforcement Office, 

Enforcement Division, EPA Region 9, of such Flaring Incident. 

Telephone notification shall be followed by a detailed written 

notification to the EPA, at the address in Condition X.C of this PSD 
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Permit, made within seven (7) working days after the event first 

qualifies as a Flaring Incident. 

3. Corrective Action 

In response to any Flaring Incident, the Permittee shall take, as 

expeditiously as practicable, such interim and/or long-term corrective 

actions, if any, as are consistent with good engineering practice to 

minimize the likelihood of a recurrence of the Root Cause and all 

contributing causes of that Flaring Incident.

H. Compliance Reporting 

1. Within thirty (30) days following the end of each calendar semiannual 

period (i.e., January 1 to June 30, and July 1 to December 31), the 

Permittee shall submit to the EPA a semiannual report.

2. All semiannual reports shall be signed and affirmed by a responsible 

official, and bearing the certification statement as follows:

“I certify under penalty of law that I have examined and am familiar with 

the information submitted in this document and all attachments and that 

this document and its attachments were prepared either by me personally 

or under my direction or supervision in a manner designed to ensure that 

qualified and knowledgeable personnel properly gathered and presented 

the information contained therein. I further certify, based on my personal 

knowledge or on my inquiry of those individuals immediately responsible 

for obtaining the information, that the information is true, accurate, and 

complete. I am aware that there are significant penalties for submitting 

false information, including the possibility of fines and imprisonment for 

knowing and willful submission of a materially false statement.”

3. All semiannual reports shall include the following information:

A list of the rolling 365-day cumulative Main Flare Emissions for each 

day in that semiannual period;

A list of the NHVdil in BTU/ft2 determined for each day in that 

semiannual period.
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A list of each day in the semiannual period when the emissions limits 

that apply to the Main Flare were exceeded and, for each such day, the 

limit(s) exceeded and the amount(s) of excess emissions;

A list of all emissions for the semiannual period that the Permittee 

claims are attributable to Malfunctions; 

A list of all emissions for the semiannual period that may be 

attributable to CO2 Breakthroughs, Scheduled Maintenance, or 

unscheduled maintenance of the Facility’s compressors; 

The date(s) and time(s) during the semiannual period when the 

thermocouple or flow meter associated with the Main Flare was 

inoperative; 

The date(s) and time(s) during the semiannual period when the 

Permittee failed to measure or record the H2S concentration in the field 

gas at the Facility or failed to continuously measure or record the 

volume of gas combusted in the Main Flare; 

A certification that during the semiannual period the Permittee 

operated and maintained the compressor station equipment and Main 

Flare in a manner consistent with good air pollution control practices 

for minimizing emissions, and performed all of the obligations 

(including, but not limited to, inspection and training obligations) 

contained in the Operations and Maintenance Plan in Appendix A of 

this PSD Permit; 

A certification that the Field Flares have not been used to circumvent 

the emission limits that apply to the Main Flare; 

A list of total emissions from the Field Flares and the reason for 

Flaring; and

Any and all reports generated from the FMP, and root cause analysis 

and corrective action program of Condition IX.G of this PSD Permit.

I. Recordkeeping Requirements 
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1. The Permittee shall maintain a file of all records, data, measurements, 

reports, and documents related to operation of the Facility. All records 

shall be in a permanent form suitable for inspection.

2. The Permittee shall retain the following records at the facility for a period 

of at least five (5) years from the date of monitoring, sampling, 

measurement, or reporting. All applicable records shall be maintained at 

the nearest manned facility and shall be readily accessible.

Each 365-day rolling total for SO2, NOx, CO, and VOC emissions;

Daily calculations of NHVdil in BTU/ft2, and the methods used to 

determine NHVdil in Condition IX.E.2 of this PSD Permit.

Emissions calculations of SO2, NOx, CO, and VOC for the Main Flare, 

which shall include the emission factors, operating data and other 

supporting documentation that the Permittee used to calculate 

emissions of each pollutant;

Monthly H2S concentration in the field gas at the Facility;

Daily total volume of gas combusted in the Main Flare;

Gas throughput;

Records of gas analyses and testing;

Records of flare design for the Main Flare in accordance with 40 CFR 

60.18 (including whether the flare is steam-assisted, air-assisted, or 

non- assisted);

Semiannual reports required in Section IX.H (Compliance Reporting), 

of this PSD Permit;

A written log of the monthly inspections of the Main Flare containing 

the following information for each inspection: (i) the date and time of 

the inspection, and the name of the observer; (ii) a description of any 

corrective actions taken and repairs made; and (iii) the date(s) of 

corrective actions and repairs; 

Visible emission readings, heat content determinations, flowrate 

measurements, and exit velocity determinations made;
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Periods when the pilot flame is absent or spark igniter(s) is inoperable;

Any and all reports generated from the root cause analysis and 

corrective action program, which shall include the following:

(1) Date, time and duration of flaring;

(2) Description of the event, including the flare(s) involved in the 

event and a discussion of the cause(s) and probable cause(s) of 

the event;

(3) Confirmation that the flare(s) functioned properly, i.e., a flame 

was present and any visible emissions that occurred were in 

compliance with 40 CFR 60.18(f)(1);

(4) Corrective actions taken during the event; and

(5) A description of any actions taken to prevent or reduce the 

likelihood of similar future occurrences.

Inspection, maintenance and repair log(s) or other similar records; and 

Any other records and reports required by this PSD permit.

X. AGENCY NOTIFICATION 

A. Permit Applications & Permit-Related Requests

The owner or operator shall submit permit applications, permit amendments, and 

other applicable permit information, which includes but not limited to installation 

of control equipment, replacement of an emissions unit, and changes that 

contravene permit terms, to:

Director, Air Division (Attn: AIR-3)

U. S. Environmental Protection Agency Region 9

75 Hawthorne Street

San Francisco, CA 94105
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B. Submittals to Navajo Nation Environmental Protection Agency

The owner or operator shall submit copies of all correspondence required by this 

PSD Permit to:

Navajo Nation Environmental Protection Agency

Air Quality Control Program and Operating Permits Program

P.O. Box 529

Fort Defiance, AZ 86504

C. Compliance Reporting

Unless otherwise directed by the EPA or this PSD Permit, the owner or operator 

shall submit a copy of all test plans, reports, certifications, notifications, and other 

information pertaining to compliance with this PSD Permit to the following 

address. All notices and submissions shall be sent by certified mail, express mail, 

or similar overnight mail delivery with return receipt requested and addressed to:

Director, Enforcement Division (Attn: ENF-2-1)

U.S. Environmental Protection Agency, Region 9

75 Hawthorne Street

San Francisco, California 94105

All notices and submission made in accordance to Condition X.C shall be deemed 

submitted on the date postmarked. All notices and submissions made in 

accordance to Condition X.C shall be signed and affirmed by a responsible 

official, and bearing the certification statement as follows:

“I certify under penalty of law that I have examined and am familiar with the 

information submitted in this document and all attachments and that this 

document and its attachments were prepared either by me personally or under my 

direction or supervision in a manner designed to ensure that qualified and 

knowledgeable personnel properly gathered and presented the information 

contained therein. I further certify, based on my personal knowledge or on my 

inquiry of those individuals immediately responsible for obtaining the 

information, that the information is true, accurate, and complete. I am aware that 

there are significant penalties for submitting false information, including the 

possibility of fines and imprisonment for knowing and willful submission of a 

materially false statement.”