U.S. ENVIRONMENTAL PROTECTION AGENCY 

REGION IX 

AMBIENT AIR QUALITY IMPACT REPORT 

& FACT SHEET 

For a Clean Air Act 

Prevention of Significant Deterioration Permit Amendment 

Resolute Natural Resources Company 

McElmo Creek Unit Oil Production Facility 

PSD Permit No. NU 05-01 

October 2014 
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i 

PROPOSED CLEAN AIR ACT 

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT AMENDMENT 

RESOLUTE NATURAL RESOURCES COMPANY 

MCELMO CREEK UNIT OIL PRODUCTION FACILITY 

PSD Permit NU 05-01 

Ambient Air Quality Impact Report & Fact Sheet 

Table of Contents 

ACRONYMSACRONYMS & ABBREVIATIONS ................................................................................. IV

EXECUTIVE SUMMARY ................................................................................................................... 1

1. PURPOSE OF THIS DOCUMENT ................................................................................................. 2

2. APPLICANT ............................................................................................................................... 2

3. FACILITY LOCATION ................................................................................................................ 2

4. PROJECT DESCRIPTION ............................................................................................................ 3

4.1 Facility History ............................................................................................................. 3

4.2 Facility Operations ........................................................................................................ 4

4.2.1 Field Operations ......................................................................................... 4

4.2.2 Gas Compression Plant .............................................................................. 4

4.3 PSD Permit History....................................................................................................... 6

4.4 PSD Permit Changes ..................................................................................................... 7

5. PROJECT EMISSIONS .............................................................................................................. 10

6. APPLICABILITY OF THE PREVENTION OF SIGNIFICANT DETERIORATION REGULATIONS ... 11

7. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS ........................................................ 12

7.1 BACT for Sulfur Dioxides .......................................................................................... 13

7.1.1 Step 1 - Identify All Control Technologies for SO2 ................................... 13

7.1.2 Step 2 - Eliminate Technically Infeasible Options for SO2 ....................... 14

7.1.3 Step 3 - Rank Control Technologies ......................................................... 15

7.1.4 Step 4 – Economic, Energy and Environmental Impacts for SO2 ............. 16

7.1.5 Step 5 – Select BACT for SO2 ................................................................... 16

7.2 BACT for Carbon Monoxide ...................................................................................... 18

7.2.1 Step 1 - Identify All Control Technologies for CO ................................... 18

7.2.2 Step 2 - Eliminate Technically Infeasible Options for CO ....................... 18

7.2.3 Step 3 - Rank Control Technologies for CO ............................................. 18
ii 

7.2.4 Step 4 – Economic, Energy and Environmental Impacts for CO ............. 20

7.2.5 Step 5 – Select BACT for CO .................................................................... 20

7.3 BACT for Nitrogen Oxides ......................................................................................... 21

7.3.1 Step 1 - Identify All Control Technologies for NOX .................................. 21

7.3.2 Step 2 - Eliminate Technically Infeasible Options for NOX ...................... 22

7.3.3 Step 3 - Rank Control Technologies for NOX ........................................... 23

7.3.4 Step 4 – Economic, Energy and Environmental Impacts for NOX ............ 25

7.3.5 Step 5 – Select BACT for NOX .................................................................. 25

7.4 BACT for Volatile Organic Compounds .................................................................... 26

7.4.1 Step 1 - Identify All Control Technologies for VOC ................................. 26

7.4.2 Step 2 - Eliminate Technically Infeasible Options for VOC ..................... 26

7.4.3 Step 3 - Rank Control Technologies ......................................................... 29

7.4.4 Step 4 –Economic, Energy and Environmental Impacts for VOC ............ 32

7.4.5 Step 5 – Select BACT for VOC .................................................................. 33

8. AIR QUALITY IMPACTS ANALYSIS ......................................................................................... 34

8.1 Introduction ................................................................................................................. 34

8.1.1 Overview of PSD Air Impact Requirements .............................................. 34

8.1.2 Identification of MCU Facility Main Flare Modeling Documentation .... 35

8.2 Background Ambient Air Quality ............................................................................... 35

8.3 Modeling Methodology for Class II areas .................................................................. 36

8.3.1 Model selection ......................................................................................... 36

8.3.2 Meteorology model inputs......................................................................... 37

8.3.3 Land characteristics model inputs ............................................................ 37

8.3.4 Model receptors ........................................................................................ 38

8.3.5 Stack parameter model inputs ................................................................... 38

8.3.6 Good Engineering Practice (GEP) Analysis ............................................ 39

8.4 National Ambient Air Quality Standards (NAAQS) and PSD Class II Increment 

Consumption Analysis ................................................................................................ 40

8.4.1 Pollutants with Significant Emissions ....................................................... 40

8.4.2 Preliminary Analysis: Project-Only Impacts ............................................ 40

8.4.3 Cumulative Impact Analysis ..................................................................... 41

8.5 Class I Area Analysis .................................................................................................. 43

8.5.1 Air Quality Related Values ....................................................................... 43

8.5.2 Class I Increment Consumption Analysis ................................................. 44

9. ADDITIONAL IMPACT ANALYSIS ............................................................................................ 45

9.1 Soils and Vegetation ................................................................................................... 45

9.2 Visibility Impairment .................................................................................................. 47

9.3 Growth ........................................................................................................................ 48

10. ENDANGERED SPECIES ACT ................................................................................................... 49

11. NATIONAL HISTORIC PRESERVATION ACT ........................................................................... 49
iii 

12. MAGNUSON-STEVENS FISHERY CONSERVATION AND MANAGEMENT ACT .......................... 50

13. COASTAL ZONE MANAGEMENT ACT ..................................................................................... 50

14. ENVIRONMENTAL JUSTICE ANALYSIS ................................................................................... 50

15. CLEAN AIR ACT TITLE V OPERATING PERMIT .................................................................... 51

16. PUBLIC PARTICIPATION ......................................................................................................... 51

16.1 Public Comments ........................................................................................................ 51

16.2 Public Information Meeting & Public Hearing ........................................................... 51

16.3 Availability of Permit Documents .............................................................................. 52

16.4 Final Permit Decision ................................................................................................. 53

16.5 Contact Information .................................................................................................... 54

17. CONCLUSION AND PROPOSED ACTION .................................................................................. 54

 
iv 

ACRONYMS & ABBREVIATIONS 

AAQIR Ambient Air Quality Impact Report and Fact Sheet 

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

Applicant Resolute Natural Resources Company 

bext Light extinction coefficient 

BA Biological Assessment 

BACT Best Available Control Technology 

BTU British thermal units 

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

CMS Continuous Monitoring System 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CO2 Carbon Dioxide 

Consent Decree United States v. Mobil Exploration and Producing U.S. Inc., Case No. 2:05–

CV–319, filed June 8, 2005 

CZMA Coastal Zone Management Act 

DSCFM Dry standard cubic feet per minute 

e-mail Electronic mail 

g grams 

gr grains 

gr/scf Grains per Standard Cubic Feet 

EAB Environmental Appeals Board 

EPA United States Environmental Protection Agency 

ESA Endangered Species Act 

ESP Electrostatic Precipitator 

Facility McElmo Creek Unit Oil Production Facility 

Fact Sheet Ambient Air Quality Impact Report and Fact Sheet 

FLM Federal Land Manager 

FWS United States Fish and Wildlife Service 

GHG Greenhouse Gases 

HP Horsepower 

HHV higher heating value 

hr hour 

ISO International Organization for Standards 

lb, lbs pound, pounds 

km kilometers 

kW kilowatts of electrical power 

lb, lbs pound, pounds 

m meters 

m/s meters per second 

MCU Facility McElmo Creek Unit Oil Production Facility 

min minute 

μg/m3 microgram per cubic meter 

MMBTU million British thermal units 
v 

MSFCMA Magnuson-Stevens Fishery Conservation and Management Act 

MW Megawatts of electrical power 

NAAQS National Ambient Air Quality Standards 

NESHAP National Emission Standards for Hazardous Air Pollutants 

NHPA National Historic Preservation Act 

NMFS National Marine Fisheries Service

NNEPA Navajo Nation Environmental Protection Agency 

NO Nitrogen Oxide or Nitric Oxide 

NO2 Nitrogen Dioxide 

NOx Nitrogen Oxides or Oxides of Nitrogen (NO + NO2) 

NP National Park 

NPS National Park Service 

NSPS New Source Performance Standards, 40 CFR Part 60 

NSR New Source Review 

O2 Oxygen 

Permittee Resolute Natural Resources Company; or the owner and/or operator of the 

McElmo Creek Unit Oil Production Facility 

PM Total Particulate Matter 

PM2.5 Particulate Matter less than 2.5 micrometers (μm) in diameter 

PM10 Particulate Matter less than 10 micrometers (μm) in diameter 

ppm parts per million 

PSD Prevention of Significant Deterioration 

PTE Potential to Emit 

PUC Public Utilities Commission 

RATA Relative Accuracy Test Audit 

RBLC U.S. EPA RACT/BACT/LAER Clearinghouse 

scf standard cubic foot 

SIL Significant Impact Level 

SNCR Selective Non-Catalytic Reduction 

SO2 Sulfur Dioxide 

SOx Sulfur Oxides 

tpy tons per year 

USFS United States Forest Service 

VOC Volatile Organic Compounds 

WA Wilderness Area 
McElmo Creek Unit Oil Production Facility (PSD Permit No. NU 05-01) 

Ambient Air Quality Impact Report & Fact Sheet 

October 2014 

Page 1

Proposed Prevention of Significant Deterioration Permit Amendment 

Ambient Air Quality Impact Report and Fact Sheet 

RESOLUTE NATURAL RESOURCES COMPANY 

MCELMO CREEK OIL UNIT PRODUCTION FACILITY 

EXECUTIVE SUMMARY 

The United States Environmental Protection Agency (EPA) is amending the Clean Air Act 

(CAA) Prevention of Significant Deterioration (PSD) permit for the McElmo Creek Unit Oil 

Production Facility (MCU Facility or Facility) to incorporate pollution limits, terms, and 

conditions of a federal Consent Decree that applies to the Main Flare at the Facility. The MCU 

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 on the McElmo Creek Unit oilfield, which includes field operations and a gas 

compression plant. It is owned and operated by the Resolute Natural Resources Company 

(Resolute). 

EPA is issuing a proposed amended PSD permit to Resolute for the MCU Facility, which is 

consistent with the requirements of the PSD program for the following reasons: 

 The proposed amended PSD permit requires the Best Available Control Technology (BACT) 

to limit emissions of volatile organic compounds (VOC), nitrogen oxides (NOx), sulfur 

dioxide (SO2), and carbon monoxide (CO). 

 The proposed emission limits will protect the National Ambient Air Quality Standards 

(NAAQS) for ozone, nitrogen dioxide (NO2), SO2, and CO. Since VOC is a precursor in the 

formation of ground level ozone, there is a NAAQS for ozone, but no NAAQS specifically 

for VOC. 

 The proposed emission limits will not cause or contribute to violations of any applicable PSD 

increments for the pollutants regulated under the PSD permit; 

 The Facility will not adversely impact soils and vegetation, or air quality, visibility, and 

deposition in Class I areas, which are parks or wilderness areas given special protection 

under the Clean Air Act; 
McElmo Creek Unit Oil Production Facility (PSD Permit No. NU 05-01) 

Ambient Air Quality Impact Report & Fact Sheet 

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1. PURPOSE OF THIS DOCUMENT 

This document serves as the Ambient Air Quality Impact Report and Fact Sheet for the proposed 

amended PSD permit for the MCU Facility. This document describes the legal and factual basis 

for the proposed amended PSD permit, including requirements under the CAA, Subchapter I, 

Part C (42 U.S.C. Section 7470, et. seq.) and the PSD regulations at Title 40 of the Code of 

Federal Regulations (CFR) § 52.21. This document also serves as a Fact Sheet for the proposed 

amended PSD permit per 40 CFR § 124.8. 

2. APPLICANT 

Resolute Natural Resources Company 

1675 Broadway, Suite 1950 

Denver, Colorado 80202 

3. FACILITY LOCATION 

The MCU Facility is located in Section 31, Township 40 South, Range 25 East within the Four 

Corners Interstate Air Quality Control Region on the Navajo Nation Indian Reservation near the 

city of Aneth, San Juan County, Utah. The map in Figure 3-1 shows the location of the Facility. 

Figure 3-1: Location of McElmo Creek Unit Oil Production Facility 
McElmo Creek Unit Oil Production Facility (PSD Permit No. NU 05-01) 

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October 2014 

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The Four Corners Interstate Air Quality Control Region is currently designated as attainment or 

unclassifiable for all criteria pollutants: nitrogen dioxide (NO2), sulfur dioxide (SO2), carbon 

monoxide (CO), particulate matter less than 10 microns in aerodynamic diameter (PM10), fine 

particulate matter less than 2.5 microns (PM2.5), lead, and ozone (regulated as volatile organic 

compounds (VOC) and oxides of nitrogen (NOx), which are precursors to ozone formation). The 

U.S. Environmental Protection Agency (EPA) is the PSD permitting authority for stationary 

source located on the Navajo Nation Indian Reservation because Navajo Nation Environmental 

Protection Agency (NNEPA) currently does not have a delegated or federally-approved PSD 

permitting program. 

4. PROJECT DESCRIPTION 

4.1 FACILITY HISTORY

The MCU Facility began operation in the 1950s. At that time, it was owned and operated by 

Superior Oil. Mobil purchased the Facility from Superior Oil in 1984.1 

In 1986, Mobil constructed a natural gas processing plant at the Facility, which included 

dehydrator, amine treater, refrigeration separation unit, a natural gas liquids recovery unit and 

compressors to transport the produced liquid natural gas. Mobil installed an upright flare (Main 

Flare) as part of the emergency relief system for the gas processing plant, and has used it as a 

control device to combust process upset gas. At that time, Mobil did not obtain a permit for the 

Main Flare. Petroleum liquid storage tanks and heater treaters were also installed in the early 

1990s. Mobil stopped operating the equipment at the gas processing plant to separate out the 

natural gas liquids in 1996, but continued to operate the Main Flare at the gas processing plant. 

In 1997, following a fire, most all processing equipment was removed. The Main Flare was kept 

for emergency flaring, flaring closed drain system fumes, and control of dehydrator emissions. 

The former gas processing plant is now referred to as the gas compression plant. The 

compressors were later converted to run on electricity. 

In 1997 and 1999, EPA issued Notice of Violations for, among other things, permitting violations 

relating to the Main Flare. The Facility is currently subject to a federal Consent Decree for the 

Main Flare.2

 The Consent Decree imposes interim emission limitations, monitoring, operation 

and maintenance, and reporting requirements that apply to the Main Flare until these 

requirements are incorporated into the PSD permit. 

In April 2006, Resolute, in partnership with Navajo Nation Oil and Gas Company, acquired 

ownership of the MCU Facility, and assumed operation of the Facility on June 1, 2006. 

 

1

 Mobil includes Mobil Exploration & Producing U.S., Inc. and ExxonMobil Production Company. The 

ExxonMobil Production Corporation was formed in 1999 by the merger of Exxon and Mobil, and ExxonMobil 

became the owner and operator of the MCU facility that year. 2 United States v. Mobil Exploration and Producing U.S. Inc., filed June 8, 2005.
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4.2 FACILITY OPERATIONS

The MCU Facility is on McElmo Creek Unit oilfield, which is primarily involved in crude 

petroleum oil production. The McElmo Creek Unit oilfield operation includes field operations 

and a gas compression plant. 

4.2.1 Field Operations 

The field operations located on the McElmo Creek Unit oilfield consist of approximately 90 

producing wells where petroleum crude oil is recovered from producing strata, brought to the 

surface to be stored at either a satellite or a tank battery. There are eleven satellites that function 

as testing facilities for producing wells and four tank batteries. 

Crude oil is recovered using water alternating gas (WAG) injection, which is a tertiary recovery 

method. WAG injection is where water is injected into the producing strata, followed by carbon 

dioxide (CO2) gas, and again by water to enhance crude oil recovery to the surface. CO2 is 

delivered to the MCU Facility via pipeline from the KinderMorgan gas plant at the Shell Dome, 

which is approximately 25 miles north of the Facility. 

Natural gas, water, and solids that are extracted from the producing strata with the crude oil are 

separated before the oil is stored. Separated water is re-injected back into the producing strata 

via the water injection station. Separated gas is sent to the gas compression plant at the MCU 

Facility and processed as described in Section 4.2.2 below. Crude oil is sold at the lease 

automatic custody transfer (LACT) unit at each central tank battery and transported to Western 

Refining’s Ciniza Refinery in Gallup, New Mexico, via the Running Horse Pipeline, which is 

owned and operated by the Navajo Nation Oil and Gas Company. 

Gases sent to the gas compression plant are compressed, dried through a glycol dehydrator, 

blended with carbon dioxide (CO2), and re-injected into the field. Liquids are further separated at 

the central tank batteries, with oil being sold and transported through a pipeline system. Water 

from the central tank batteries is pumped to the water flood injection plant. 

4.2.2 Gas Compression Plant 

The gas compression plant is used to support tertiary recovery of crude oil in the McElmo Creek 

Unit oilfield. The goal of the plant is to receive produced gas through a gathering system, 

pressure the gas up to a suitable working pressure, and then re-inject the gas into the producing 

strata to maintain reservoir pressure. The natural gas is injected with produced water into the 

producing strata using a dual injection system. Due to varying water injection demands in the 

field, and to the number of wells being serviced at any time, the gas volume entering the plant 

can vary between 10 and 18 million standard cubic feet per day (MSCFD). 
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October 2014 

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The gas is processed in three main steps: inlet separation, compression and re-injection. The 

inlet separation consists of an inlet slug receiver which collects free liquids. The gas then passes 

through filter vessels which collect any incoming solids. During the compression stage, 4 highspeed electrically-driven reciprocating compressors, which utilize 6300 brake horsepower 

(BHP), are used to compress the gas. Each compressor consists of four stages which raise the 

pressure of the incoming gas from 40 psig to 2900 psig. Each stage has a dedicated aerial cooler 

and liquid scrubber vessel. On the largest compressor, inter stage dehydration takes place to 

remove water for corrosion mitigation. During re-injection, the gases from the four compressors 

discharge into a single header, where purchased CO2 is co-mingled to achieve a daily injection 

goal of 24 MSCFD. The gas is then distributed to the field. During plant upsets, additional CO2

is purchased to meet the daily injection goal. 

The Main Flare at the gas compression plant combusts gases that have been bypassed around the 

facility’s electric-driven compressors or that come through various emergency relief valves in the 

compression plant. Additionally, the vent stream from the plant’s glycol dehydrator is directed 

to the Main Flare. 

A flow diagram of the Facility’s gathering system operations is presented in Figure 4-1, 

illustrating the flow through the satellite facilities, central tank batteries, water flood injection 

plant, and gas compression plant. Figure 4-1 presents a simple block flow diagram for the gas 

compression plant, including the streams directed to the Main Flare. 
McElmo Creek Unit Oil Production Facility (PSD Permit No. NU 05-01) 

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October 2014 

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Figure 4-1: McElmo Creek Unit Oil Production Facility Operations

Source: April 2008 PSD Application, Figure 2-2 

4.3 PSD PERMIT HISTORY

The PSD permit history associated with the MCU Facility is as follows.3

February 2, 1987 – EPA issued the initial PSD permit to Mobil for the modification of the MCU 

Facility for the MCU Stage 2 CO2 Project. The permit authorized the construction and operation 

of three 1730 horsepower (HP) reciprocating internal combustion engines. 

October 27, 1987 – EPA amended the PSD permit to replace the three reciprocating internal 

combustion engines with two 3216 HP natural gas-fired turbines. 

 

3 The previous PSD permits for the MCU facility were issued by the United States Environmental Protection 

Agency, Region 8 Office (EPA Region 8). EPA Region 8 was the PSD permitting authority for the portion of the 

Navajo Nation Indian Reservation in southeastern Utah, until October 9, 1991. According to a Memorandum of 

Agreement dated October 9, 1991 between EPA Regions 6, 8, 9 and the Navajo Nation Indian Reservation regarding 

the implementation of EPA-related activities on the reservation, this authority was transferred to EPA Region 9. 

The Navajo Nation Indian Reservation covers portions of northeastern Arizona, southeastern Utah, and northwestern 

New Mexico. 
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March 21, 1989 – EPA issued a letter to Mobil amending stack heights in the PSD permit. 

EPA’s letter was in response to a January 25, 1989 letter from the Mobil to EPA stating that the 

height of the MCU Facility stacks had been increased from the height in the amended PSD 

permit issued on October 27, 1987. Mobil’s January 25, 1989 letter stated that the height of the 

stacks were approximately 40 feet instead of 20 feet. 

April 19, 1991 – EPA amended the PSD permit to (1) replace existing heating equipment at the 

Facility with a waste heat recovery unit; (2) temporarily replace the existing gas turbine with an 

identical unit during maintenance overhaul of the turbine, (3) change the rating of the existing 

gas turbine one gas turbine which was installed from 3216 HP to 4390 HP and add requirements 

for the New Source Performance Standard for Gas Turbines (40 CFR Part 60, Subpart GG); and 

(4) remove the second gas turbine from the permit since it was never installed. 

Several pieces of equipment have been removed from MCU Facility.4

 During the mid-1990s, the 

natural gas liquids facility was shut down. With the shutdown of the natural gas liquids facility, 

all gas-driven compressors and turbines at the gas compression plant were converted to electric 

units and sulfur recovery was ceased. The natural gas liquids and sulfur recovery processes were 

discontinued and dismantled in June 1998. Also, the only remaining gas turbine was removed in 

June 1998. During that same time period, gas dehydration was reduced. The plant currently 

operates one TEG dehydration unit. The CO2 line heater, which was used during severe cold 

weather, was removed from the MCU Facility in March 2004. 

4.4 PSD PERMIT CHANGES

This permit action consists of incorporating pollution limits, terms, and conditions for the 

already existing Main Flare into the PSD Permit for the MCU Facility pursuant to a federal 

Consent Decree, which was filed and became effective on June 8, 2005. Paragraph 14.a of the 

Consent Decree requires the owner and operator of the MCU Facility to submit, to EPA, a PSD 

permit application in accordance with the CAA and the PSD regulations at 40 CFR § 52.21 for 

the MCU Facility’s Main Flare not later than the 180 days after the effective date of the Consent 

Decree. The Consent Decree requires that the PSD application include, among other things, 

BACT and air quality analyses for SO2, CO, NOx, and VOC for the Main Flare. It also requires 

that the PSD application include terms and conditions that are at least as stringent as the 

following Consent Decree requirements.5

 

 Paragraph 9.a (Emission Limits) 

 Paragraph 10 (Monitoring) 

 Paragraph 11 (Operation and Maintenance of Main Flare and Compressors) 

 Paragraph 25(i)-(ix) (Reporting and Recordkeeping Requirements) 

 

4

 See letter from ExxonMobil Production Company (Neil J. Ryan) to EPA Region 9 (Gerardo C. Rios), dated 

May 27, 2004. 

5

 See Paragraph 4.o of the Consent Decree. 
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Mobil submitted a PSD application dated December 5, 2005 for the Main Flare, and also 

provided supplemental information in 2006 and 2007. Resolute, which acquired ownership of 

the MCU Facility in 2006, submitted a revised PSD application dated April 2008 for the Main 

Flare, as well as various supplemental information thereafter. 

This permit action also consists of updating the equipment covered in the PSD Permit, which 

includes removing emission units that have been shut down and removed from the MCU Facility 

site and the associated requirements that apply to these units. Table 4-1 shows the equipment 

and activities listed in Tables 1 and 2 of the PSD Permit, and Table 4-2 shows other operations at 

the Facility that are not explicitly listed in the permit. Both tables also show the current status of 

these equipment and operations. 

Table 4-1: Equipment in Tables 1 & 2 of the MCU Facility’s 1991 PSD Permit6 

Operation Status 

T4500 Gas Turbine (4390 HP) Shutdown 1997 

Waste Heat Recovery Unit (11 MMBtu/hr) Shutdown 1997 

Ingersoll Rand IC Engine (491 HP) Shutdown 1993 

Fairbanks Morse IC Engine (1712 HP) Shutdown 1997 

Fairbanks Morse IC Engine (1712 HP) Shutdown 1997 

Fairbanks Morse IC Engine (1848 HP) Shutdown 1997 

Fairbanks Morse IC Engine (1848 HP) Shutdown 1997 

DPC-540 IC Engine (470 HP) Shutdown 1998 

HC Liquid Reboiler (1 MMBtu/hr) Shutdown 1993 

Heat Medium Heater (4 MMBtu/hr) Shutdown 1993 

Heat Medium Heater (12.2 MMBtu/hr) Shutdown 1991 

TEG Reboiler (0.33 MMBtu/hr) Shutdown 1991 

TEG Reboiler (0.33 MMBtu/hr) Shutdown 1991 

TEG Reboiler (0.33 MMBtu/hr) Shutdown 1991 

TEG Reboiler (0.1 MMBtu/hr) Shutdown 1991 

Sources: Letter from ExxonMobil Production Company (Neil J. Ryan) to EPA Region 9 (Gerardo C. Rios), dated May 27, 2004; 

Email from Resolute to EPA Region 9 regarding additional information, dated December 4, 2012 

 

6

 The MCU Facility’s most recent PSD permit was issued by EPA on April 19, 1991. 
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Table 4-2: Other Equipment and Operations at the MCU Facility7

Operation Status

Natural Gas Liquids Processing Shutdown 1998 

Natural Gas Processing Facility Shutdown 1998 

Main Flare (618,104 scf/hr) Operational 

TEG Reboiler (0.75 MMBtu/hr) Operational 

Gasoline Storage Tank Shutdown 1993 

Gasoline Storage Tank Shutdown 1993 

Gasoline Storage Tank (10,000 gallon nominal capacity) Operational 

Diesel Storage Tank Shutdown 1993 

CO2 line heater Shutdown 2004 

Glycol Heater for TEG regenerator (12 MMcfd) Operational 

Sources: Letter from ExxonMobil Production Company (Neil J. Ryan) to EPA Region 9 (Gerardo C. Rios), dated May 27, 2004; 

Email from Resolute to EPA Region 9 regarding additional information, dated December 4, 2012 

The Facility currently operates the following air emission units remaining at the site: Main Flare, 

gasoline tank, triethylene glycol (TEG) dehydration unit reboiler, and glycol heater. Other than 

the replacement of a fixed speed fan with a variable speed fan to provide better pollution control 

at the Main Flare, this permit action does not authorize any new construction or modification of 

existing equipment at the MCU Facility. 

 

 

7

 The listed equipment and operations were located at the MCU site, but were not included in Tables 1 and 2 of the 

MCU Facility’s 1991 PSD Permit. 
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5. PROJECT EMISSIONS 

This section describes the emission levels of SO2, CO, NOx, and VOC from the Main Flare, and 

the emission requirements in the Consent Decree. 

Table 5-1 shows the actual emissions for the Facility, and Table 5-2 shows the greenhouse gas 

emission estimates. 

Table 5-1: Actual Emissions (2011) for MCU Facility 

Operation Size / 

Throughput 

SO2 

(tpy)

NOx 

(tpy)

CO 

(tpy) 

VOC 

(tpy) 

PM 

(tpy) 

Main Flare 618,104 scf/hr 26.7 8.4 45.4 54.9 0.9 

Glycol Heater 12 MMscf/day 0.0 0.1 0.5 2.7 0.0 

TEG Reboiler 0.75 MMBtu/hr 0.0 0.3 0.3 0.0 0.0 

Gasoline Storage Tank 10,000 Gallons 0.0 0.0 0.0 2.0 0.0 

Total 26.7 8.8 46.2 59.6 0.9 

Source: Email from Resolute to EPA Region 9 regarding additional information, dated December 4, 2012 

Table 5-2: CO2e Emission Estimates for MCU Facility 

Operation Emissions (Metric Tons CO2e) 

Main Flare 26,122 

Glycol Dehydrator 1,092 

Compressor Rod Packing Venting 242 

Equipment Leaks 51 

Total Facility GHG Emissions 27,507 

Source: Email from Resolute to EPA Region 9 regarding additional information, dated April 18, 2012 

Paragraphs 14.a and 9.a of the Consent Decree requires that BACT for the Main Flare be at least 

as stringent as the limits, based on rolling 365-day cumulative amounts (to be calculated each 

day), in Table 5-3. Paragraph 9.a of the Consent Decree also requires that the field flares shall 

not be used to circumvent these emission limits. 

Table 5-3: Minimum Consent Decree BACT Requirements 

SO2 NOx CO VOC 

60 tpy 13.4 tpy 73 tpy 95.4 tpy 

Source: Consent Decree, Paragraph 9.a
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6. APPLICABILITY OF THE PREVENTION OF SIGNIFICANT 

DETERIORATION REGULATIONS 

The PSD program of the Clean Air Act is a preconstruction permitting program and is intended 

to protect air quality in “attainment/unclassified areas”, which are areas that meet the National 

Ambient Air Quality Standards (NAAQS) or where the attainment status is uncertain. As shown 

in Table 6-1, the Navajo Nation Indian Reservation is in attainment or unclassifiable for all 

NAAQS pollutants. EPA is currently the PSD permitting authority for stationary sources located 

on the Navajo Nation Indian Reservation. 

Table 6-1: NAAQS Attainment Status for Navajo Nation 

Pollutant Attainment Status 

SO2 Attainment or Unclassifiable 

CO Attainment or Unclassifiable 

Nitrogen Dioxide (NO2) Attainment or Unclassifiable 

Ozone8 Attainment or Unclassifiable 

Particulate Matter (PM2.5)

9

 Attainment or Unclassifiable 

Particulate Matter (PM10)

10 Attainment or Unclassifiable 

Lead Attainment or Unclassifiable 

Pursuant to the federal Consent Decree, Resolute is required to submit a PSD application to EPA 

for the Main Flare in accordance with the PSD regulations at 40 CFR § 52.21 for the following 

pollutants: SO2, CO, NOx, and VOC. EPA issued a PSD permit to the MCU Facility on 

February 2, 1987, and the permit was last amended on April 19, 1991. EPA received a PSD 

application for the Main Flare in 2005 from Mobil, and has received revised applications in 2007 

and 2008 and other supplemental information for the PSD application from Mobil and Resolute. 

 

8 Troposheric, or ground level ozone, is not emitted directly into the air, but is created by chemical reactions 

between NOx and VOC. Thus, both NOx and VOC precursors in the formation of ozone and are regulated under the 

CAA. 

9 Fine particulate matter, or PM2.5, is particulate matter with diameters that are 2.5 micrometers and smaller. Some 

PM2.5 is emitted directly from a stationary source, such as construction sites, unpaved roads, fields, or smokestacks. 

SO2 and NOx are precursors in the formation of PM2.5 since these pollutants form in complicated reactions in the 

atmosphere after being emitted from smokestacks. 

10 Coarse particulate matter, or PM10, includes “inhalable coarse particles,” with diameters larger than 2.5 

micrometers and smaller than 10 micrometers.
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7. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS 

This section describes EPA’s BACT analysis for the control of SO2, CO, NOx and VOC 

emissions at the MCU Facility’s Main Flare. Section 169(3) of the CAA defines BACT as 

follows: 

“The term ‘best available control technology’ means an emission limitation based on the 

maximum degree of reduction of each pollutant subject to regulation under the Clean Air Act 

emitted from or which results from any major emitting facility, which the permitting authority, 

on a case-by-case basis, taking into account energy, environmental, and economic impacts and 

other costs, determines is achievable through application of production processes and available 

methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel 

combustion techniques for control of each such pollutant. In no event shall application of ‘best 

available control technology’ result in emissions of any pollutants which will exceed the 

emissions allowed by any applicable standard established pursuant to section 111 [New Source 

Performance Standards or NSPS] or 112 [or NESHAPS] of the Clean Air Act.” 

See also 40 CFR § 52.21(b)(12). In accordance with 40 CFR § 52.21(j), a new major stationary 

source is required to apply BACT for each regulated NSR pollutant that it would have the 

potential to emit (PTE) in significant amounts. 

EPA outlines the process it generally uses to do this case-by-case analysis (referred to as a “topdown” BACT analysis) in a June 13, 1989 memorandum. The top-down BACT analysis is a 

well-established procedure that EPA’s Environmental Appeals Board (EAB) has consistently 

followed in adjudicating PSD permit appeals. See, e.g., In re Knauf, 8 E.A.D. 121, 129-31 (EAB 

1999); In re Maui Electric, 8 E.A.D. 1, 5-6 (EAB 1998). 

In brief, under the top-down process, all available control technologies are ranked in descending 

order of control effectiveness. The PSD applicant first examines the most stringent technology. 

That technology is established as BACT unless it is demonstrated that technical considerations, 

or energy, environmental, or economic impacts justify a conclusion that the most stringent 

technology is not achievable for the case at hand. If the most stringent technology is eliminated, 

then the next most stringent option is evaluated until BACT is determined. The top-down BACT 

analysis is a case-by-case exercise for the particular source under evaluation. In summary, the 

five steps involved in a top-down BACT evaluation are: 

1. Identify all available control options with practical potential for application to the 

specific emission unit for the regulated pollutant under evaluation; 

2. Eliminate technically infeasible technology options; 

3. Rank remaining control technologies by control effectiveness; 

4. Evaluate the most effective control alternative and document results, considering 

energy, environmental, and economic impacts as appropriate; if top option is not 
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selected as BACT, evaluate next most effective control option; and 

5. Select BACT, which will be the most stringent technology not rejected based on 

technical, energy, environmental, and economic considerations. 

A BACT analysis was conducted for the Main Flare. Table 7-1 provides a summary of the 

BACT determinations for SO2, CO, NOx, and VOC emissions. EPA evaluated the information 

that Resolute and Mobil submitted. The analyses and our evaluation for each pollutant are 

presented below. 

Table 7-1: Summary of BACT Limits and Requirements for the Main Flare11

SO2 CO NOx VOC 

 60.0 tpy, based on a 

cumulative 365-day 

rolling total 

 Monitor sulfur content 

(in terms of H2S) of the 

gas stream to the flare for 

calculating SO2

emissions. 

 Follow manufacturer’s 

specifications for Main 

Flare 

 Operate and maintain in 

accordance with the flare 

requirements in 40 CFR 

§ 60.18 

 Follow the operations 

and maintenance, root 

cause, and corrective 

action requirements of 

the Consent Decree 

 73.0 tpy, based on a 

cumulative 365-day 

rolling total 

 Follow manufacturer’s 

specifications for Main 

Flare 

 Operate and maintain in 

accordance with the flare 

requirements in 40 CFR § 

60.18 

 Follow the operations and 

maintenance, root cause, 

and corrective action 

requirements of the 

Consent Decree 

 13.4 tpy, based on a 

cumulative 365-day rolling 

total 

 Follow manufacturer’s 

specifications for Main Flare 

 Operate and maintain in 

accordance with the flare 

requirements in 40 CFR § 

60.18 

 Follow the operations and 

maintenance, root cause, and 

corrective action 

requirements of the Consent 

Decree 

 95.4 tpy, based on a 

cumulative 365-day rolling 

total 

 Operating the Main Flare 

using air-assist technology. 

 Ensure that the net heating 

value for dilution is greater 

than or equal to 24.4 

BTU/scf2 

 Follow manufacturer’s 

specifications for Main 

Flare 

 Operate and maintain Main 

Flare in accordance with 

the flare requirements in 40 

CFR § 60.18 

 Follow the operations and 

maintenance, root cause, 

and corrective action 

requirements of the 

Consent Decree 

7.1 BACT FOR SULFUR DIOXIDES 

SO2 emissions are formed as a result of the combustion of gasses containing reduced sulfur 

compounds. Typically, sulfur dioxide from combustion processes can be controlled by limiting 

the sulfur content in the fuel or by end-of-pipe control technology. 

7.1.1 Step 1 - Identify All Control Technologies for SO2

The available add-on control technologies for reducing SO2 emissions are as follows. 

 Absorption (e.g., absorbers or scrubbers for acid gases) 

 Dry injection (e.g., hydrated lime or sodium bicarbonate for acid gases) 

 

11 The owner and operator of the MCU facility must keep all records of all testing, fuel use, and fuel testing 

requirements for a period of five (5) years and must report excess emissions to EPA semi-annually, except when: 

more frequent reporting is specifically required by an applicable subpart; or the Administrator, on a case-by-case 

basis, determines that more frequent reporting is necessary to accurately assess the compliance status of the source. 
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 Spray dryer (e.g., slurry for acid gases) 

 Soda ash tower (for acid gases) 

 Flue gas desulfurization (e.g., wet scrubbing, spray-dry scrubbing, sulfur recovery, dry 

sorbent injection systems) 

The following pre-treatment control options for reducing SO2 emissions are as follows. 

 Limiting the fuel type 

 Limiting the sulfur content 

Other control options for reducing SO2 emissions are as follows. 

 Natural gas combustion in flare 

 Proper operation and maintenance 

7.1.2 Step 2 - Eliminate Technically Infeasible Options for SO2

Add-On Control Technologies 

The add-on control technology options are not technically feasible for flare systems, due to the 

inherent design of flaring and the fact that literally, no end-of-pipe exists after the combustion 

zone. Additionally, we found no known demonstrations of add-on control options such as 

absorbers or other scrubbing techniques for open, elevated flares. Because these controls are 

neither available in the marketplace for flares nor applicable to them, all of the add-on control 

technology options listed above are eliminated as technically infeasible for the Main Flare. 

Pre-Treatment Control Options 

Limiting the fuel type is not technically feasible because the gasses cannot be switched with 

other process or vent streams without changing the inherent purpose and design of the 

compressor plant. Likewise, limiting the sulfur content or flue gas desulfurization is not 

technically feasible because they would inherently change the plant’s purpose and design. 

During normal operation, the process and vent gas streams are re-injected into the oilfield 

without any sweetening process. Therefore, the options of limiting the fuel type and sulfur 

content of the gas before it is flared are not technically feasible for the Main Flare. 

Other Control Options 

EPA’s New Source Performance Standards (NSPS) regulations at 40 CFR part 60 define natural 

gas as the following: “a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, 

or propane) produced in geological formations beneath the Earth’s surface that maintains a 

gaseous state at standard atmospheric temperature and pressure under ordinary conditions. 

Natural gas contains 20.0 grains or less of total sulfur per 100 standard cubic feet. Equivalents 

of this in other units are as follows: 0.068 weight percent total sulfur, 680 parts per million by 

weight (ppmw) total sulfur, and 338 parts per million by volume (ppmv) at 20 degrees Celsius 

total sulfur. Additionally, natural gas must either be composed of at least 70 percent methane by 

volume or have a gross calorific value between 950 and 1100 British thermal units per standard 

cubic foot (BTU/scf). Natural gas does not include the following gaseous fuels: landfill gas, 

digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven 

gas, or any gaseous fuel produced in a process which might result in highly variable sulfur 
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content or heating value.” 

The MCU Facility’s Main Flare is used to burn dehydrated produced gas from the MCU oilfield. 

According to Resolute’s PSD Application, this dehydrated produced gas is approximately 70 

percent CO2 and 0.05 percent H2S, and does not include natural gas as defined above. Thus, 

requiring combustion of natural gas in the Main Flare to control SO2 emissions is not technically 

feasible. 

Proper operation and maintenance is typically specific to a facility and could entail work 

practices to ensure that the flare is being maintained and operated properly. For the Main Flare, 

proper operation and maintenance include (1) following the manufacturer’s specifications for the 

flare, (2) operating and maintaining the flare in accordance with the flare requirements in 40 

CFR § 60.18, and (3) following the operations and maintenance, root cause, and corrective action 

requirements of the Consent Decree. Proper operation and maintenance is technically feasible 

for the Main Flare.

7.1.3 Step 3 - Rank Control Technologies 

Proper operation and maintenance is the remaining technically feasible control option. Table 7-1 

shows a summary of recent SO2 BACT determinations for flares at other facilities. These control 

determinations include combustion of natural gas or refinery gas in the flare, limiting the sulfur 

content in the feedstock, and proper operation and maintenance. As described in Step 2, natural 

and refinery gases are part of the dehydrated produced gas stream that is vented to the flare for 

combustion, and are not technically feasible control options. In addition, as described in Step 2, 

limiting the sulfur content in the feedstock is not technically feasible for the Main Flare. 

Sulfur compounds contained in a flare gas stream are converted to SO2 when burned. The 

amount of SO2 emitted depends directly on the quantity of sulfur in the flared gases. The SO2

BACT emission levels in Table 7-1 vary for each facility listed. This indicates that the sulfur 

content also varies for each of these facilities and that the SO2 BACT emission levels are facilityspecific. Thus, the SO2 BACT emission level for the MCU Facility’s Main Flare will be based 

on the expected sulfur content in it flare gas stream. 

The SO2 emission rate specified in the Consent Decree is 60 tpy based on a cumulative 365-day 

rolling total. The sulfur content of the dehydrated produced gas that is burned in the MCU’s 

Main Flare is approximately 0.05 percent H2S, but may also result in highly variable sulfur 

content or heating value. 
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Table 7-1: SO2 BACT Determinations for Flares 

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Oil and Gas 

Production Facility UT Proposed Main Flare Proper operation 

and maintenance 

60 tpy, 365-day rolling 

total N/A 

Valero TX 8/19/2010 Flare None listed 1.38 lb/hr TX-0574 

St. Charles Refinery LA 11/17/2009 Flares (2) 

Natural gas or 

refinery fuel gas 

combustion in flare 

None listed LA-0213 

Lake Charles 

Gasification Facility LA 6/22/2009 Flares (2) No additional control 0.01 lb/hr; 1303.99 lb/hr LA-0231 

Sun Company, Inc., 

Toledo Refinery OH 2/23/2009 Flare None listed 4.2 lb/hr, 18. 4 tpy OH-0308 

Rumpke Sanitary 

Landfill OH 12/23/2008 

Candlestick 

flares (5), open 

flare (1) 

None listed 0.47 lb/hr, 2.05 tpy; 0.47 

lb/hr, 2.05 tpy OH-0330 

Homeland Energy 

Solutions, LLC IA 8/8/2007 Biomethanator 

flare None listed 0.0007 lb/MMBtu IA-0089 

Garyville Refinery LA 12/27/2006 Flare None listed 0.01 lb/hr LA-0211 

Air Products 

Hydrogen, Steam, 

and Electricity 

Production 

TX 8/18/2006 Flares (2) None listed 1.38 lb/hr, 0.01 tpy; 1.38 

lb/hr, 0.1 tpy TX-0526 

BASF TX 2/3/2006 Flare None listed 1.38 lb/hr, 7 tpy TX-0511 

Enterprise Mont 

Belvieu Complex TX 1/24/2006 Flare None listed 1.38 lb/hr, 0.6 tpy TX-0514 

Formosa Point 

Comfort Plant TX 5/9/2005 Flares (3) None listed 

1.38 lb/hr, 0.05 tpy; 1.38 

lb/hr, 0.02 tpy; 1.38 lb/hr, 

0.08 tpy 

TX-0475 

Virtex Petroleum 

Company Doering 

Ranch Gas Plant 

TX 5/5/2005 Flare None listed 1.38 lb/hr, 615.39 tpy TX-0492 

Citgo Corpus Christi 

Refinery TX 4/20/2005 Flares (3) None listed 

1.38 lb/hr, 0.9 tpy; 1.38 

lb/hr, 0.8 tpy; 1.38 lb/hr, 

116 tpy 

TX-0478 

Rohm and Haas TX 3/24/2005 Flares (2) None listed 1.38 lb/hr, 0.03 tpy; 1.38 

lb/hr, 0.01 tpy TX-0487 

Continental Carbon 

Sunray Plant TX 3/18/2005 Flare None listed 1.38 lb/hr, 1487.05 tpy TX-0464 

Flint Hills Resources TX 1/24/2005 Flares (2) None listed 1.38 lb/hr, 965.79 tpy TX-0494 

Source: RACT/BACT/LAER Clearinghouse (RBLC)

7.1.4 Step 4 – Economic, Energy and Environmental Impacts for SO2

No significant economic, energy, or environmental impacts are expected from proper operation 

and maintenance of the Main Flare. 

7.1.5 Step 5 – Select BACT for SO2

Based on the above analysis, BACT for SO2 emissions from the Main Flare are the following 

requirements. 

 SO2 emissions not to exceed an emission limit of 60 tpy based on a cumulative 365-day 

rolling total. 

 Proper operation and maintenance which include: 

(1) following the manufacturer’s specifications for the flare; 
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(2) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; 

(3) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit); and 

(4) monitoring of the sulfur content (in terms of H2S) of the gas stream to the flare for 

calculating SO2 emissions. 
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7.2 BACT FOR CARBON MONOXIDE

Flaring is a high-temperature oxidation process used to burn combustible components, mostly 

hydrocarbons (i.e., VOC), of waste gases from industrial operations. In some waste gas streams 

sent to a flare, CO is the major combustible component. However, for the MCU Facility, is not 

part of the gas stream sent to the Main Flare and is formed from by incomplete combustion of the 

dehydrated produced gas from the MCU oilfield in the Main Flare. 

7.2.1 Step 1 - Identify All Control Technologies for CO 

The CO control options for the Main Flare are listed as follows. 

 Proper operation and maintenance 

7.2.2 Step 2 - Eliminate Technically Infeasible Options for CO 

Proper operation and maintenance, the only control option for the Main Flare, is technically 

feasible. Proper operation and maintenance include (1) following the manufacturer’s 

specifications for the flare, (2) operating and maintaining the flare in accordance with the flare 

requirements in 40 CFR § 60.18, and (3) following the operations and maintenance, root cause, 

and corrective action requirements of the Consent Decree. 

7.2.3 Step 3 - Rank Control Technologies for CO 

Proper operation and maintenance is the only control option for the Main Flare. Table 7-2 shows 

a summary of recent CO BACT determinations for flares at other facilities. 

These control determinations include proper operation and maintenance, comply with the flare 

requirements in 40 CFR §§ 60.18 and 63.11, and good combustion practices. Proper operation 

and maintenance for the Main Flare include maintaining and operating the flare in accordance 

with the flare requirements in 40 CFR § 60.18. The flare requirements of 40 CFR § 60.18 are 

substantively the same as those in 40 CFR § 63.11. Proper operation and maintenance for the 

Main Flare also include good combustion practices which require Resolute to operate the flare in 

accordance with the manufacturer’s specifications for the flare to ensure complete combustion. 

The CO emission rate specified in the Consent Decree is 73 tpy based on a cumulative 365-day 

rolling total. This is based on an emission factor of 0.37 lb/MMBtu. This level is within the 

range of BACT determinations listed in Table 7-2. 
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Table 7-2: CO BACT Determinations for Flares

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Oil and Gas 

Production Facility UT Proposed Main Flare Proper operation and 

maintenance 

73 tpy, 365-day 

rolling total N/A 

Sabine Pass LNG 

Terminal LA 12/6/2011 

Marine Flare 

(1) and 

Wet/Dry Gas 

Flares (4) 

Proper operation and 

maintenance None listed LA-0257 

Direct Reduction Iron 

Plant LA 1/27/2011 Flares (2) Proper operation and 

maintenance None listed LA-0248 

Valero Three Rivers 

Refinery TX 8/19/2010 Flare Proper operation and 

maintenance None listed TX-0574 

Breitburn Energy – 

Newlove Lease CA 7/17/2009 

Horizontal 

Enclosed 

Flare (forced 

draft) 

None listed 

0.0371 lb/MMBtu, 

40 min avg CA-1171 

Lake Charles Gasification 

Facility LA 6/22/2009 Flares (2) Proper operation and 

maintenance None listed LA-0231 

Rhode Island Central 

Genco LLC RI 5/12/2009 ULE flare, 

enclosed flare None listed 

0.06 lb/MMBtu, 

1.25 lb/hr; 

0.2 lb/MMBtu, 

19.8 lb/hr 

RI-0023 

St. Charles Refinery LA 11/17/2009 Flares Comply with 40 CFR 

60.18/63.11 None listed LA-0213 

Sun Company, Inc., 

Toledo Refinery OH 2/23/2009 Flare (steam 

assisted) 

Comply with 40 CFR 

60.18/63.11 

0.082 lb/MMBtu OH-0308 

Power County Advanced 

Energy Center ID 2/10/2009 Flares (3) 

Good combustion 

practices; comply with 40 

CFR 60.18 

None listed ID-0017 

Rumpke Sanitary Landfill OH 12/23/2008 

Candlestick 

flare (5), open 

flare 

None listed 

0.37 lb/MMBtu 

OH-0330 

Homeland Energy 

Solutions, LLC PN 06-

672 

IA 8/8/2007 Biomethanator 

Flare None listed 

0.37 lb/MMBtu 

IA-0089 

University of New 

Hampshire NH 7/25/2007 Utility Flare Good combustion practices 0.37 lb/MMBtu, 3-

hr avg NH-0014 

Garyville Refinery LA 12/27/2006 Flare Comply with 40 CFR 

60.18/63.11 None listed LA-0211 

Air Products Hydrogen, 

Steam, and Electricity 

Production 

TX 8/18/2006 Flares (2) Proper operation and 

maintenance None listed TX-0526 

Bethel Landfill VA 7/25/2006 Flares Proper operation and 

maintenance None listed VA-0301 

Fountain Avenue Landfill NY 6/29/2006 Flare Good combustion practices None listed NY-0096 

BASF 

Ethylene/Propylene 

Cracker 

TX 2/3/2006 

Ground flare 

(high 

pressure) 

None listed None listed TX-0511 

Enterprise Mont Belvieu 

Complex TX 1/24/2006 Flares (2) None listed None listed TX-0514 

Formosa Point Comfort 

Plant TX 5/9/2005 Flares (3) None listed None listed TX-0475 

Citgo Corpus Christi 

Refinery – West Plant TX 4/20/2005 Flares (3) Proper operation and 

maintenance None listed TX-0478 

Rohm and Haas 

Chemicals LLC Lone Star 

Plant 

TX 3/24/2005 Flares (2) Flare used to control CO 

emissions None listed TX-0487 

Continental Carbon 

Sunray Plant TX 3/18/2005 Flare Proper operation and 

maintenance None listed TX-0464 

Flint Hills Resources 

Installation of Boilers TX 1/24/2005 Flares (2) None listed None listed TX-0494 

Source: RBLC 
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7.2.4 Step 4 – Economic, Energy and Environmental Impacts for CO 

No significant economic, energy, or environmental impacts are expected from proper operation 

and maintenance of the Main Flare. 

7.2.5 Step 5 – Select BACT for CO 

Based on the above analysis, BACT for CO emissions from the Main Flare are the following 

requirements. 

 CO emissions not to exceed an emission limit of 73 tpy based on a cumulative 365-day 

rolling total. 

 Proper operation and maintenance which include: 

(1) following the manufacturer’s specifications for the flare to ensure complete 

combustion in the flare; 

(2) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; and 

(3) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit). 

 
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7.3 BACT FOR NITROGEN OXIDES

NOx is formed as a result of the combustion of hydrocarbons (which are entrained in the vent gas 

streams) at the flare (through ignition with natural gas at the flare pilot) in the presence of 

ambient air. There are three principal forms of NOx, designated as “thermal” NOx, “prompt 

NOx,” and “fuel” NOx. Thermal NOx formation is the result of oxidation of atmospheric 

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

zone. The major factors influencing thermal NOx formation are temperature, concentrations of 

nitrogen and oxygen in the inlet air, and residence time within the combustion zone. Prompt 

NOx is formed through relatively fast reaction between nitrogen, oxygen, and hydrocarbon 

radicals and is an important mechanism in lower temperature combustion processes. Fuel NOx is 

formed by the oxidation of fuel-bound nitrogen. It is not a concern for high-quality gaseous 

fuels such as natural gas or propane, because these fuels normally have no organically-bound 

nitrogen. Fuel NOx is a concern when burning oil, coal, or waste fuels. NOx emissions from the 

flare can be best reduced by minimizing the frequency and amount of vent gases flared and by 

promoting optimal conditions upon combustion. 

7.3.1 Step 1 - Identify All Control Technologies for NOX

Generally, several options exist to reduce NOx emissions from combustion processes, such as 

pre-treating the fuel or switching fuels and/or oxidizers to prevent NOx formation, modifying the 

combustion process or equipment to lower NOx formation, and add-on control technologies to 

remove NOx. These options are listed below. 

The available add-on control technologies are listed as follows. 

 Selective Catalytic Reduction (SCR) 

 Selective Non-Catalytic Reduction (SNCR) 

The following inherently lower-emitting control options are listed as follows. 

 Air Preheat Reduction 

 Burners Out of Service 

 Low NOx burners (LNB) 

The following pre-treatment control options for NOx emissions are listed as follows. 

 Fuel Switching 

 Fuel Additives 

 Oxidizer Switching 

Other control options for NOx emissions are listed as follows. 

 Proper operation and maintenance 
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7.3.2 Step 2 - Eliminate Technically Infeasible Options for NOX

Add-On Control Technologies 

The add-on control technology options are not technically feasible for flare systems, due to the 

inherent design of flaring and the fact that literally, no end-of-pipe exists after the combustion 

zone. Additionally, we found no known demonstrations of add-on control options such as 

absorbers or other scrubbing techniques for open, elevated flares. Because these controls are 

neither available in the marketplace for flares nor applicable to them, all of the add-on control 

technology options listed above are eliminated as technically infeasible for the Main Flare. 

Inherently Lower-Emitting Control Options 

Reducing the amount of air preheat and taking burners out of service are options intended for 

process heaters and boilers, where the combustion air is heated for more efficiency and where 

multiple burners exist. LNB incorporate concepts such as lowering excess air, fuel staging, and 

gas recirculation, which can be successfully implemented with process heaters and boilers. 

However, flare burner design differs substantially from process heater and boiler burner design, 

because the primary objective of flare burner design is to achieve safe and complete combustion 

of unwanted hydrocarbons during unpredictable circumstances such as upsets, malfunctions, and 

emergencies. Therefore, air preheat reduction, taking burners out of service, and LNB are not 

technically feasible for the Main Flare. 

Pre-Treatment Control Options 

Fuel additives, which are intended to change the chemistry of the combustion process, operate 

under specific temperature conditions and stable operations, neither of which is possible with 

flare systems. Oxidizer switching, where pure oxygen is used for combustion rather than air, is 

not widely used in the hydrocarbon, petrochemical, and power generation industries due to the 

cost and energy requirements of producing pure oxygen. Fuel switching from fuels with higher 

fuel-bound nitrogen contents to those with lower fuel-bound nitrogen contents is a possible 

option for reducing NOx from flare systems, but only in specific cases where the fuel to the flare 

can be controlled and predicted. 

Fuel switching, fuel additives, and oxidizer switching are not technically infeasible for the Main 

Flare as the fuel stream to the flare cannot be switched without inherently changing the 

compressor plant’s purpose and design. Primarily, fuel is sent to the Main Flare through various 

pressure-relief piping or compressor bypass piping, as a result of emergency or maintenance 

situations, and also continuously from the dehydration reboiler. Secondly, the fuel to the Main 

Flare consists of light hydrocarbons (methane, ethane, propane) and carbon dioxide, with very 

little (fuel-bound) nitrogen content. Therefore, these NOx control options are eliminated for 

technical infeasibility. 
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Other NOx Control Options 

Proper operation and maintenance is typically specific to a facility and could entail work 

practices to ensure that the flare is being maintained and operated properly. For the Main Flare, 

proper operation and maintenance include (1) following the manufacturer’s specifications for the 

flare, (2) operating and maintaining the flare in accordance with the flare requirements in 40 

CFR § 60.18, and (3) following the operations and maintenance, root cause, and corrective action 

requirements of the Consent Decree. Proper operation and maintenance is technically feasible 

for the Main Flare.

7.3.3 Step 3 - Rank Control Technologies for NOX

Proper operation and maintenance is the only control option for the Main Flare. Table 7-3 shows 

a summary of recent NOx BACT determinations for flares at other facilities. 

These control determinations include proper operation and maintenance, comply with the flare 

requirements in 40 CFR § 60.18, and good combustion practices. Proper operation and 

maintenance for the Main Flare include operating and maintaining the flare in accordance with 

the flare requirements in 40 CFR § 60.18. Proper operation and maintenance for the Main Flare 

include good combustion practices. 

The NOx emission rate specified in the Consent Decree is 13.4 tpy based on a cumulative 365-

day rolling total. This is based on an emission factor of 0.068 lb/MMBtu. This level is within 

the range of BACT determinations listed in Table 7-3. 
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Table 7-3: NOx BACT Determinations for Flares

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Facility UT Proposed Main Flare Proper operation and 

maintenance 

13.4 tpy, 365-day rolling 

total N/A 

Petrorock - Tunnell 

Lease CA 1/24/2012 Enclosed 

Ground Flare 

Good combustion 

practices 

15 ppmvd@ 3% O2, 40 

min avg CA-1187 

Sabine Pass LNG 

Terminal LA 12/6/2011 

Marine Flare, 

Wet/Dry Gas 

Flares (4) 

Proper operation and 

maintenance 

185.1 lb/hr, 2.13 tpy; 

0.03 lb/hr, 0.11 tpy LA-0257 

Direct Reduction Iron 

Plant LA 1/27/2011 Flare Proper operation and 

maintenance 

1.27 lb/hr, 2.58 tpy 

(each) LA-0248 

Sabina Petrochemicals 

LLC TX 8/20/2010 Flares (2, HP 

and LP) 

Proper operation and 

maintenance 9.07 tpy TX-0575 

Evonik Degussa 

Corporation AL 1/7/2010 Flares (4) Good combustion 

practices 

14.29 lb/hr; 14.29 lb/hr; 

1.79 lb/hr; 20.01 lb/hr AL-0249 

St. Charles Refinery LA 11/17/2009 Flares (2) None listed None provided LA-0213 

Breitburn Energy – 

Newlove Lease CA 7/17/2009 

Horizontal 

Enclosed Flare 

(forced draft) 

None listed 0.0146 lb/MMBtu, 40 min 

avg 

CA-1171 

Lake Charles Gasification 

Facility LA 6/22/2009 Flare None listed 0.05 lb/hr; 48.81 lb/hr LA-0231 

Rhode Island Central 

Genco LLC RI 5/12/2009 ULE flare, 

enclosed flares None listed 

0.025 lb/MMBtu, 0.52 

lb/hr; 0.06 lb/MMBtu, 

5.94 lb/hr 

RI-0023 

Sun Company, Inc., 

Toledo Refinery OH 2/23/2009 Flare None listed 

15.23 lb/hr, 66.71 tpy 

based on 365-day sum 

of daily emissions 

OH-0308 

Power County Advanced 

Energy Center ID 2/10/2009 Flares (3) Good combustion 

practices None listed ID-0017 

Rumpke Sanitary Landfill OH 12/23/2008 

Candlestick 

flares (5), Open 

LFG flare 

None listed 1.2 lb/hr, 5.26 tpy (each) OH-0330 

Homeland Energy 

Solutions, LLC IA 8/8/2007 Biomethanator 

flare None listed 0.07 lb/MMBtu IA-0089 

University of New 

Hampshire NH 7/25/2007 Utility flare Good combustion 

practices 

0.068 lb/MMBtu, 3-hour 

avg 

NH-0014 

Garyville Refinery LA 12/27/2006 Flare None listed 1.8 lb/hr LA-0211 

Air Products Hydrogen, 

Steam, and Electricity 

Production 

TX 8/18/2006 Flares (2) Proper operation and 

maintenance 

0.022 lb/hr, 0.1 tpy; 160 

lb/hr, 2.9 tpy TX-0526 

Bethel Landfill VA 7/25/2006 Flares Proper operation and 

maintenance 13.4 lb/hr, 58.6 tpy VA-0301 

Fountain Avenue Landfill NY 6/29/2006 LFG flare None listed 39 tpy NY-0096 

BASF 

Ethylene/Propylene 

Cracker 

TX 2/3/2006 Ground flare None listed 2219.7 lb/hr, 452.7 tpy TX-0511 

Enterprise Mont Belvieu 

Complex TX 1/24/2006 Flares (2) None listed 376.6 lb/hr, 153 tpy; 154.1 lb/hr, 1.1 tpy TX-0514 

Formosa Point Comfort 

Plant TX 5/9/2005 Flares (3) None listed 

1.14 lb/hr, 2.38 tpy; 1.92 

lb/hr, 8.39 tpy; 1.45 lb/hr, 

6.34 tpy 

TX-0475 

Virtex Petroleum 

Company Doering Ranch 

Gas Plant 

TX 5/5/2005 Flare None listed 0.19 lb/hr, 0.85 tpy TX-0492 

Citgo Corpus Christi 

Refinery – West Plant TX 4/20/2005 Flares (2) None listed 0.6 lb/hr, 2.6 tpy; 0.36 

lb/hr, 1.6 tpy TX-0478 

Rohm and Haas 

Chemicals LLC Lone Star 

Plant 

TX 3/24/2005 Flares (2) None listed 152.13 lb/hr, 48.41 tpy; 

130.65 lb/hr, 7.78 tpy TX-0487 

Continental Carbon 

Sunray Plant TX 3/18/2005 Flare None listed 25.96 lb/hr, 113.72 tpy TX-0464 

Flint Hills Resources TX 1/24/2005 Flares (2) None listed 1150.9 lb/hr, 3123.7 tpy 

(each) TX-0494 

Source: RBLC
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7.3.4 Step 4 – Economic, Energy and Environmental Impacts for NOX

No significant economic, energy, or environmental impacts are expected from proper operation 

and maintenance of the Main Flare. 

7.3.5 Step 5 – Select BACT for NOX

Based on the above analysis, BACT for NOx emissions from the Main Flare are the following 

requirements. 

 NOx emissions not to exceed an emission limit of 13.4 tpy based on a cumulative 365-day 

rolling total. 

 Proper operation and maintenance which include: 

(1) following the manufacturer’s specifications for the flare; 

(2) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; and 

(3) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit). 
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7.4 BACT FOR VOLATILE ORGANIC COMPOUNDS 

The purpose of a flare system is to control process equipment operation through the safe and 

effective disposal of gases and liquids. Flare systems are considered as an emission control 

device for VOC, since combustion through a flaring system prevents the release of hydrocarbons 

to the atmosphere. When combustion is incomplete, flares will emit VOC in the form of 

unburned hydrocarbons. 

7.4.1 Step 1 - Identify All Control Technologies for VOC 

The VOC control options for the Main Flare are listed as follows. 

 Compressor engine modifications 

 Flare Gas Recovery System 

 Proper operation and maintenance which include supplemental external momentum 

design (i.e., steam, air, or gas-assist technology) 

7.4.2 Step 2 - Eliminate Technically Infeasible Options for VOC 

Compressor engine modifications 

The Applicant evaluated minimizing flaring events due to compressor downtime, and considered 

various options to improve the reliability of the HOS-6 compression engine operations, and 

considered other compressor changes. 

Flaring Due to Compressor Downtime: The majority of the flaring at the MCU Facility is a 

result of downtime associated with the HOS-6 compressor. This unit is a 4-stage, 6-cylinder 

Dresser HOS model compressor, which is driven by an electric motor. HOS-6 compressor 

reliability is influenced by the interaction of the gas composition and process requirements at 

MCU. The gas is primarily composed of carbon dioxide and has a tendency to liquefy at relative 

low temperatures. The gas pressure between the 3rd and 4th stages of compression is 

approximately 1000 psi. The gas at this pressure liquefies at approximately 85°F. Additionally, 

the discharge pressure is above the critical pressure of the gas. Therefore, the process stream 

actually leaves the compressor and can simultaneously have the properties of a liquid and a gas. 

It is when the gas behaves as a liquid that compressor damage can occur. This mixed gas stream 

allows for the potential of liquid drop-out throughout the compression process. 

In an effort to reduce the potential for damage on the 4th stage of the compressor, the field 

operations group attempts to maintain the suction temperature of the 4th stage near 100° F. 

However, the large temperature swings that can occur in the MCU Gas Compression Plant area, 

especially in the winter months, make this difficult. Some of the issues are: 

 No automatic controls on the coolers 

 Gas separation between stages located remotely from the compressor 

 Piping between the separation equipment and the compressor having multiple elevation 

changes, which increase the potential for liquid accumulation in the lines. 
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The compressor has had downtime associated with 2nd stage failures due to liquids entering the 

cylinder. The implemented solution was to remove the liquid traps between the separation and 

compression equipment. This eliminated liquid collection and slugging, thereby reducing 

downtime events significantly. 

Reliability of HOS-6 Compressor Engine Operations: The Applicant evaluated two options to 

increase reliability of compressor engine operation: (1) changing the compressor process and (2) 

replacing the HOS-6 compressor. The option to change the compressor process would consist of 

reducing the discharge pressure of the reciprocating compression, cooling the gas stream to 

liquefy it, and utilizing pumps to reach the required pipeline pressure. This could provide 

increased reliability and minimize potential compression failures at the MCU Gas Compression 

Plant. This option would require new refrigeration equipment, new pumps, and, at a minimum, 

restaging of the existing compression. Further corrective actions would also be necessary, as 

described below, if the existing HOS-6 compressor was used. 

The option to replacing the HOS-6 compressor would entail replacing the HOS-6 unit with one 

or more reciprocating compressors. The basic process would not change. Replacing the existing 

compressor may reduce the potential for liquid retention by utilizing different piping 

configurations. However, problems inherent with the process would still remain. 

Other Compression Changes: The Applicant considered three options for potential changes to 

compression operations. These options are (1) relocating the HOS-6 separation equipment, (2) 

reconfiguring piping, and (3) insulate and heat trace the piping. The option to relocate the HOS6 equipment would consist of moving the HOS-6 separation equipment closer to the compression 

equipment. By doing this, the potential for liquid forming in the intermediate piping and 

entering the compressor would be reduced. However, the potential for liquid entering the 

compressor equipment would still remain because of the size of the separation equipment 

required on the HOS-6 compressor. Additionally, relocation of the separation equipment would 

not remove the inherent process issues and there would be no assurance of flaring frequency and 

duration reductions. 

Reconfiguring the piping between the separation and compression equipment, similar to 

replacing the compressor or relocating the separation equipment, would reduce the potential for 

liquids to enter the compression equipment by removing liquid traps. The potential for 

downtime occurrences would still remain, however, and there would be no assurance of flaring 

frequency and duration reductions. 

By insulating and heat-tracing the piping between the separation and compression equipment, the 

probability of the gas cooling and liquids forming would be reduced. The potential for liquids 

entering the compression equipment would still remain and there would be no assurance of 

flaring frequency and duration reductions. 
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Flare Gas Recovery System 

Another method of reducing flaring emissions is to recover gas that would otherwise be flared 

and redirect for further processing in the existing gas compression facility. Flare gas recovery 

systems recover fuel gas from the flare gas header prior to the flare’s liquid seal. A flare gas 

recovery system consists of a compressor, separator, and process controls (to maintain slight 

positive pressure on the flare header). Flare gas recovery systems are typically designed to 

recover fuel gas from miscellaneous processes that might regularly be relieved to the flare header 

system and can effectively recover 100 percent of these fuel gases. However, flare gas recovery 

systems cannot recover large quantities of fuel gas that might be suddenly released to the flare 

header system as a result of a process upset or malfunction.12 These gases would still be flared 

as necessary to maintain the integrity of the process units and the safety of the plant personnel. 

Flare gas recovery systems have been used at refineries and has been required in EPA’s final 

standards for petroleum refineries.13 These systems have been considered at facilities, such as 

petroleum refineries, that have flares receiving high gas flows. 

Proper Operation and Maintenance (Use of Steam, Air, or Gas-Assist Technology) 

The flare requirements in 40 CFR § 60.18 establish specifications on visible emissions, 

continuous presence of a flame, exit velocities, fuel heating value, and monitoring for flare 

systems with the intent to ensure 98 percent control (hydrocarbon destruction) efficiency for 

applicable flares. In order to achieve the visible emission requirements of 40 CFR § 60.18, 

smokeless flare systems are designed with some type of external momentum force, such as 

steam, air, water spray, natural gas, or a specialized high velocity vortex design. An external 

momentum force provides for more complete combustion by improving the fuel flow 

momentum, which allows a sufficient amount of combustion air to be educted into the 

combustion zone just outside the flare burner. 

Steam, air, or gas-assist technology allows flare systems to achieve smokeless operation and 98 

percent control efficiency. Steam injection is common, as it can add sufficient momentum and 

aid the chemistry of the combustion process. Low-pressure air can be used as an assist medium 

in locations where steam, water, or gas is not readily available or where cold temperatures 

present freezing issues. In this case, a blower is utilized to inject approximately 15 to 50 percent 

of the stoichiometric air requirement into the flame, providing adequate momentum to achieve 

smokeless and complete combustion. Air-assist design is often used in remote locations. Gasassist with natural gas can provide an additional benefit by increasing the heating value to the 

fuel stream, in situations where the waste gas to be combusted does not have a sufficient heating 

value for safe combustion. 

Of the steam, air, and gas-assist technology options, steam-assisted technology is immediately 

determined to be infeasible. The MCU Facility is located in a remote area, where steam is not 

readily available. Therefore, the only feasible supplemental external momentum designs are air 

and gas-assist technologies. The MCU’s Main Flare employs air-assist technology. 

 

12 See 72 Federal Register 27187, Standards of Performance for Petroleum Refineries. 

13 See 73 FR 35837 (June 24, 2008) and 77 FR 56422 (September 12, 2012).
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Proper operation and maintenance is typically specific to a facility and could entail work 

practices to ensure that the flare is being maintained and operated properly. For the Main Flare, 

proper operation and maintenance include (1) the use of using air-assist technology, (2) 

following the manufacturer’s specifications for the flare and taking other measures to ensure 

complete combustion and proper flare performance, (3) maintaining and operating the flare in 

accordance with the flare requirements in 40 CFR § 60.18, and (4) following the operations and 

maintenance, root cause, and corrective action requirements of the Consent Decree. Proper 

operation and maintenance is technically feasible for the Main Flare. 

7.4.3 Step 3 - Rank Control Technologies 

The technically feasible control options are listed in order of control effectiveness for VOC (with 

the most effective alternative at the top) as follows in Table 7-4. 

Table 7-4: Control Effectiveness for VOC Control Options

Control Option Control Effectiveness 

 Compressor engine modifications  75-95% VOC control at facility 

 98% VOC control by Main Flare 

 Flare gas recovery system  75% VOC control at facility 

 98% VOC control by Main Flare 

 Proper operation and maintenance with 

air-assist technology  98% VOC control by Main Flare 

Table 7.5 shows a summary of recent VOC BACT determinations for flares at other facilities. 

These control determinations include proper operation and maintenance, comply with the flare 

requirements in 40 CFR §§ 60.18 and 63.11, good combustion practices, and 98% VOC control. 

The VOC emission rate specified in the Consent Decree is 95.4 tpy based on a cumulative 365-

day rolling total. 

Proper operation and maintenance for the Main Flare include operating and maintaining the flare 

in accordance with the flare requirements in 40 CFR § 60.18, which are substantively the same 

as the flare requirements in 40 CFR § 63.11. These federal requirements for flares include the 

following minimum requirements: 

 Designed and operated with no visible emissions using EPA Method 22 (except for 

periods not to exceed 5 minutes in 2 hours); 

 Operated with a flame present at all times, confirmed by the use of a thermocouple or 

equivalent device; 

 Used only when the net heating value of the gas to be combusted is 300 BTU per 

standard cubic foot (BTU/scf) or greater (if the flare is steam- or air-assisted), or 200 

BTU/scf or greater (if the flare is nonassisted); and 

 Designed for and operated with an exit velocity less than 60 feet per second (ft/sec). An 

exit velocity of greater than 60 ft/sec but less than 400 ft/sec may be used if the net 

heating value of the gas being combusted is sufficiently high. 
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Proper operation and maintenance include other measures that ensure complete combustion and 

proper flare performance. EPA supported a study to better understand flare performance and to 

identify key operating/monitoring parameters that would ensure adequate performance of flares 

at all times. Based on this study EPA established that, while there are many parameters that 

affect combustion efficiency of a flare, proper mixing at the flare tip and the heating value of 

vent gas to be combusted are two important factors for achieving high combustion efficiency. 14 

Proper mixing at the flare tip, which is where combustion occurs, is needed to prevent 

overaeration in air-assisted flares. EPA has found that facilities can use either or both of the 

following techniques to ensure proper mixing for air-assisted flares:15

 Continuously measure the flow rate of the waste gas and continuously measure, and 

then control, the air being added as assist gas. Follow the manufacturer’s 

recommendations and publicly available documents in setting proper assist gas rates. 

 Utilize automatic damper actuators or variable frequency drives on the air supply 

system. 

Ensuring that the heating value, often measured in BTU/scf, of the vent gas is sufficient is 

important in maintaining flame stability and achieving high combustion efficiency. The heating 

value is a measure of the combustibility of the gas. The flare requirements in 40 CFR part 60 

and 40 CFR part 63 regulate the net heating value and require gases contain at least 300 BTU/scf 

if they are being combusted in an air or steam assisted flare. If this heating value minimum 

cannot be met by the vent gases alone, then supplemental gas, such as natural gas, must be 

added. EPA has found that facilities can use one or a combination of the following techniques to 

ensure high combustion efficiency and prevent low heat value in the vent gas stream:16

 Ensure that the flare waste gas meets the current regulatory heating value limits of 300 

BTU/scf for assisted flares, and 200 BTU/scf for unassisted flares, at all times. This 

will require evaluating the heating value of vent gas over the full range of operating 

scenarios. 

 Determine the heating value of the flare vent gas as a whole, not only the hydrocarbons 

in the vent gas, just before it leaves the flare tip (flare vent gas to includes all flare 

waste gas, sweep gas, purge gas and supplemental gas, but not include pilot gas or 

assist media). The heating value evaluation includes nitrogen and any other 

compounds that make up the gas mixture that is present just inside the flare tip. 

 Monitor the vent gas flow and automatically supply supplemental fuel if the vent gas 

does not have sufficient heating value. 

 Evaluate other control options and limit flare use to true emergency situations. 

EPA has incorporated requirements for ensuring proper mixing at the flare tip and sufficient 

heating value of the vent gas to be combusted in the flares in recent consent decrees for refinery 

 

14 See Enforcement Alert: EPA Enforcement Targets Flaring Efficiency Violations, EPA 325-F-012-002, August 

2012

15 Ibid. 16 Ibid.
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flares.17 EPA has also included such requirements for flares in the proposed revisions to the 

federal air quality refinery standards.18 EPA’s studies that provide the basis for the flare 

requirements in these proposed revisions estimate that the vent gas in an air-assisted flare should 

have a combustion zone heating value that is greater than or equal to 270 BTU/scf and a net 

heating value air assist dilution parameter that is greater than or equal to 22 BTU/ft2

.

19 Since the 

Main Flare does not employ premix air or steam, the combustion zone heating value would equal 

the heating value of the vent gas. The Main Flare must comply with the heating value of the vent 

gas of 300 BTU/scf required by 40 CFR§ 60.18(c)(3)(ii). Thus, for this unit, the net heating 

value air assist dilution parameter would need to be greater than or equal to 24.4 BTU/ft2

 (i.e., 22 

BTU/ ft2 x [(300 BTU/scf)/(270 BTU/scf)]). 

A properly operated flare can achieve a destruction efficiency of 98% or greater when 

controlling emission streams with heat contents greater than 300 BTU/scf.20 Resolute’s Main 

Flare will achieve this 98% destruction efficiency through compliance with the heat content 

requirements of 40 CFR § 60.18 and the combustion efficiency provisions discussed above. 

 

17 See Consent Decrees for Marathon Petroleum Company, LP and Catlettsburg Refining, LLC Settlement dated 

April 5, 2012; and Consent Decree for BP Products North America, Inc., case 2:12-cv-00207, filed 09/18/12 18 See Petroleum Refinery Sector Risk and Technology Review and New Source Performance Standards at 79 

Federal Register 36880. 

19 Memorandum regarding Petroleum Refinery Sector Rule: Operating Limits for Flares, Jeff Coburn, RTI 

International to Andrew Bouchard and Brenda Shine, EPA/OAQPS, December 12, 2013 

20 EPA Air Pollution Control Fact Sheet for Industrial Flares (EPA 452/F-03-019) 
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Table 7-5: VOC BACT Determinations for Flares 

Facility State Permit Date Process Control Method Emission Limits RBLC ID

MCU Facility UT Proposed Main Flare Proper operation and 

maintenance 

95.4 tpy, 365-day 

rolling total N/A 

Petrorock - Tunnell Lease CA 1/24/2012 Enclosed Ground 

Flare Good combustion practices None listed *CA-1187 

Sabine Pass LNG Terminal LA 12/6/2011 

Marine Flare, 

Wet/Dry Gas 

Flares (4) 

Proper maintenance and 

operation None listed LA-0257 

Sabina Petrochemicals LLC TX 8/20/2010 Flare 98% VOC control with flare 98% control TX-0575 

Highlands Ethanol Facility FL 12/10/2009 Flares (2) Proper maintenance and 

operation None listed FL-0318 

St. Charles Refinery LA 11/17/2009 Flares (2) Comply with 40 CFR 60.18 

and 63.11 None listed LA-0213 

Breitburn Energy – Newlove 

Lease CA 7/17/2009 Horizontal enclosed flare Forced draft enclosed flare 10 ppmvd @3% O2, 40 min avg CA-1171 

Rhode Island Central Genco, 

LLC RI 5/12/2009 ULE flare, enclosed flares None listed None listed RI-0023 

Sun Company, Inc., Toledo 

Refinery OH 2/23/2009 Flare (steam assisted) 

Comply with 40 CFR 60.18 

and 63.11 5 lb/MMscf OH-0308 

Rumpke Sanitary Landfill OH 12/23/2008 Candlestick flares 

(5), open flare None listed None listed OH-0330 

Homeland Energy Solutions, 

LLC IA 8/8/2007 Biomethanator flare 98% VOC control with flare 0.052 lb/MMBtu, 98% control IA-0089 

Garyville Refinery LA 12/27/2006 Flare Comply with 40 CFR 60.18 None listed LA-0211 

Valero Three Rivers Refinery TX 8/19/2006 Flares (HP and LP) Proper maintenance and 

operation None listed TX-0574 

Air Products Hydrogen, 

Steam, and Electricity 

Production 

TX 8/18/2006 Flares (2) 

98% VOC control with flare; 

proper maintenance and 

operation 

98% control TX-0526 

Fountain Avenue Landfill NY 6/29/2006 LFG flare 98% VOC control 98% control NY-0096 

BASF Ethylene/Propylene 

Cracker TX 2/3/2006 Ground flare Flare used to control VOC None listed TX-0511 

Enterprise Mont Belvieu 

Complex TX 1/24/2006 Flares (2) None listed None listed TX-0514 

Formosa Point Comfort Plant TX 5/9/2005 Flares (5) None listed None listed TX-0475 

Citgo Corpus Christi Refinery 

– West Plant TX 4/20/2005 Flares (3) 

98% VOC control with flare; 

proper maintenance and 

operation 

98% control TX-0478 

Rohm and Haas Chemicals 

LLC Lone Star Plant TX 3/24/2005 Flares (6) 98% VOC control with flare 98% control TX-0487 

Continental Carbon Sunray 

Plant TX 3/18/2005 Flares (3) 98% VOC control with flare 98% control TX-0464 

Source: RBLC 

7.4.4 Step 4 –Economic, Energy and Environmental Impacts for VOC 

Resolute provided a cost analysis for the top two VOC control options, compressor engine 

modifications and flare gas recovery systems. The third control option (i.e., Proper operation 

and maintenance with steam, air, or gas-assist technology) does not additional controls beyond 

the Main Flare and an economic analysis is not needed since this is the baseline case. A 

summary of the cost analysis is provided in Table 7-6. This analysis is based on the EPA 

Control Cost Manual and the VOC requirements of the Consent Decree. With cost effectiveness 

values ranging between $58,395 and $69,646 per ton VOC removed, the top control options are 

considered cost-prohibitive for the Main Flare. Therefore, we are eliminating compressor 

modifications and flare recovery systems. 

No significant energy or environmental impacts are expected from proper operation and 

maintenance of the Main Flare. 
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Table 7-6: VOC Economic Analysis 

Cost Parameters 

Compressor 

Modifications - 

Change HOS-6 

Compressor Process 

Compressor 

Modifications - 

Replace HOS-6 

Compressor 

Flare Recovery 

Systems 

Cost Recovery Factor 0.1061 0.1061 0.1061 

Total Capital Costs $29,253,312 $24,377,760 $27,546,869 

Total Annualized Costs $5,290,607/year $4,422,271/year $4,986,689 

Control Range 75%-95% 75%-95% 75% 

Control Level Used in 

Cost Analysis 95% 95% 75% 

Tons of VOC Removed 90.6 tpy 

(0.95 x 95.4 tpy) 

90.6 tpy 

(0.95 x 95.4 tpy) 

71.6 tpy 

(0.75 x 95.4 tpy) 

Cost Effectiveness $58,395/ton VOC 

removed 

$48,811/ton VOC 

removed 

69,646/ton VOC 

removed 

7.4.5 Step 5 – Select BACT for VOC 

Based on the above analysis, BACT for VOC emissions from the Main Flare are the following 

requirements. 

 VOC emissions not to exceed an emission limit of 95.4 tpy based on a cumulative 365-

day rolling total. 

 Proper operation and maintenance which include: 

(1) operating the Main Flare using air-assist technology; 

(2) complying with a net heating value air assist dilution parameter of greater than or 

equal to 24.4 BTU/ft2 to ensure complete combustion in the flare; 

(3) following the manufacturer’s specifications for the flare to ensure complete 

combustion in the flare; 

(4) operating and maintaining the flare in accordance with the flare requirements in 

40 CFR § 60.18; and 

(5) following the operations and maintenance, root cause, and corrective action 

requirements (incorporated from the Consent Decree into the PSD permit). 

 
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8. AIR QUALITY IMPACTS ANALYSIS 

The Consent Decree requires the owner or operator of the MCU Facility, Resolute, to submit a 

PSD application that includes an air quality analysis for SO2, CO, NOx, and VOC in accordance 

with 40 CFR § 52.21. Under Clean Air Act section 165 and EPA’s PSD regulations at 40 CFR § 

52.21, Resolute must demonstrate, using air quality models, that the Facility’s emissions of SO2, 

CO, NOx, and VOC will not cause or contribute to a violation of (1) the applicable NAAQS, or 

(2) the applicable PSD increments (explained below in Sections 8.4 and 8.5 of this document). 

The following sections provide a discussion of the relevant background data and air quality 

modeling, and EPA’s conclusion that the Facility’s emission increases will not cause or 

contribute to an exceedance of the applicable NAAQS or applicable PSD increments, and is 

otherwise consistent with PSD requirements governing air quality.

8.1 INTRODUCTION

8.1.1 Overview of PSD Air Impact Requirements 

Under the PSD regulations, permit applications for sources subject to review under the PSD 

regulations at 40 CFR § 52.21 must include an air quality analysis demonstrating that the 

facility’s emissions of the PSD-regulated air pollutants will not cause or contribute to a violation 

of the applicable NAAQS or applicable PSD increments. (A PSD increment for a pollutant 

applies only to areas that that are in attainment with the corresponding NAAQS for that 

pollutant.) The Applicant provides separate modeling analyses for each criteria pollutant emitted 

above the applicable significant emission rate. If a preliminary analysis shows that the ambient 

concentration impact of the Main Flare by itself is greater than the Significant Impact Level 

(SIL), then a full or cumulative impact analysis is required for that pollutant. The cumulative 

impact analysis includes nearby pollution sources in the modeling, and adds a monitored 

background concentration to account for sources not explicitly included in the model. The 

cumulative impact analysis must demonstrate that the Main Flare will not cause or contribute to 

a NAAQS or increment violation. If a preliminary analysis shows that the ambient concentration 

impact of the Main Flare by itself is less than the Significant Impact Level (SIL), then further 

analysis is generally not required. Required model inputs characterize the various emitting units, 

meteorology, and the land surface, and define a set of receptors (i.e., spatial locations at which to 

estimate concentrations, typically out to 50 km from the facility). Modeling should be performed 

in accordance with EPA’s Guideline on Air Quality Modeling, in Appendix W to 40 CFR Part 

51 (GAQM or Appendix W). AERMOD with its default settings is the standard model choice, 

with CALPUFF available for complex wind situations. 

A PSD permit application typically includes a Good Engineering Practice (GEP) stack height 

analysis, to ensure that (1) downwash is properly considered in the modeling, and (2) stack 

heights used as inputs to the modeling are no greater than GEP height, so as to disallow artificial 

dispersion from the use of overly tall stacks. The application may also include initial “load 

screening,” in which a variety of source operating loads and ambient temperatures are modeled, 

to determine the worst-case scenario for use in the rest of the modeling. 
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The PSD regulations also require an analysis of the impact on nearby Class I areas, generally 

those within 100 km, though the relevant Federal Land Manager (FLM) may specify additional 

or fewer areas. This analysis includes the NAAQS, PSD increments, and Air Quality Related 

Values (AQRVs). AQRVs are defined by the FLM, and typically limit visibility degradation and 

the deposition of sulfur and nitrogen. Generally, CALPUFF is the standard model choice for 

Class I analyses, since it can handle visibility chemistry as well as the typically large distances 

(over 50 km) to Class I areas. 

Finally, the PSD regulations require an additional impact analysis, showing the Main Flare’s 

effect on visibility, soils, vegetation, and growth. This visibility analysis is independent of the 

Class I visibility AQRV analysis. The additional impact analysis for the Main Flare at the MCU 

Facility is discussed in Section 9 below. 

8.1.2 Identification of MCU Facility Main Flare Modeling Documentation 

The modeling analysis for the MCU Facility comprises the documents listed in Table 8-1 below. 

The original PSD Permit application dated March 22, 2007 contained the results of the original 

modeling. The revised PSD Application addresses higher BTU content and increased emissions 

and was submitted in April 2008. Resolute submitted a revised 1-hour SO2 Modeling analysis 

with AERMOD and accompanying DVD in April 2011. 

Table 8-1: Modeling Documentation for MCU Facility Main Flare PSD Application 

Short name Citation 

December 2005 PSD 

Application for Main Flare 

PSD Permit Application for Main Flare submitted by ExxonMobil, 

dated December 5, 2005 

March 2007 PSD 

Application for Main Flare 

Revised PSD Permit Application for Main Flare submitted by 

ExxonMobil, dated March 22, 2007 

(received by EPA on March 29, 2007) 

April 2008 Revised PSD 

Application 

Revised PSD Permit Application submitted by Resolute to address 

higher BTU content and increased emissions, dated April 2008 

(received by EPA on June 2, 2008) 

April 2011 MCU 1-Hour 

SO2 Modeling 

McElmo Creek Unit Oil Production Facility-Main Flare, Gas 

Compression Facility 1-Hour SO2 Modeling with AERMOD and 

accompanying DVD, dated April 2011 

(received by EPA on June 3, 2011) 

8.2 BACKGROUND AMBIENT AIR QUALITY

The PSD regulations require the air quality analysis to contain air quality monitoring data as 

needed to assess ambient air quality in the area for the PSD-regulated pollutants for which there 

are NAAQS that may be affected by the source. In addition, for demonstrating compliance with 

the NAAQS, a background concentration is added to represent those sources not explicitly 

included in the modeling, so that the total accounts for all contributions to current air quality. 
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No site or area-specific data was available for southeastern Utah for NO2, CO, SO2 and ozone21; 

therefore, air quality data gathered from monitoring stations located in north central Utah, 

primarily within the Salt Lake City metropolitan area, are used as conservative indicators of air 

quality for this rural area of Utah. Background PM10 concentrations are not addressed since 

PM10 emissions are insignificant from a flare, and the Consent Decree does not cite emission 

limits for PM10. 

Table 8-2 below describes the maximum background concentrations of the PSD-regulated 

pollutants for which there are NAAQS that may be affected by the Facility’s emissions, and the 

corresponding NAAQS. 

Background air quality monitoring data shown in the table are from 2009-2011 for NO2, CO, and 

ozone. No site or area-specific data was available for southeastern Utah for NO2, CO and ozone; 

therefore, except for SO2, air quality data gathered from monitoring stations located in north 

central Utah, primarily within the Salt Lake City metropolitan area, are used as conservative 

indicators of air quality for this rural area of Utah. Available SO2 data from Shiprock 

(Farmington, New Mexico) are more representative of rural areas around the MCU Facility. 

Ozone concentrations are cited as surrogate for VOC impacts because VOCs do not have an 

ambient air quality standard; rather, VOC is considered a contributor to the formation of ozone. 

Table 8-2: Maximum Background Concentrations and NAAQS 

NAAQS pollutant 

& averaging time 

Background 

Concentration, μg/m3 NAAQS, μg/m3

NO2, 1-hour 103.4 (55 ppb) 188 (100 ppb) 

NO2, annual 34 (18 ppb) 100 (53 ppb) 

SO2, 1-hour 79 (30 ppb) 196 (75 ppb) 

CO, 1-hour 5,726 (5 ppm) 40,000 (35 ppm) 

Ozone, 8-hour 0.065 (ppm) 0.07 (ppm) 

Note: The NO2 1-hr value is 98th percentile averaged over three years rather than maximum; 

The SO2 1-hr value is 99th percentile averaged over three years rather than maximum 

8.3 MODELING METHODOLOGY FOR CLASS II AREAS

The Applicant modeled the impact of the Main Flare on the NAAQS and PSD Class II 

increments using AERMOD and SCREEN in accordance with EPA’s GAQM (Appendix W of 

40 CFR Part 51). The modeling analyses included the maximum air quality impacts from a 

variety of conditions to determine worst-case short-term air impacts. 

8.3.1 Model selection 

As discussed in the latest PSD Application (April 2011 MCU 1-Hour SO2 Modeling, p.5-2), the 

model that Resolute selected for analyzing air quality impacts in Class II areas is AERMOD, 

along with AERMAP for terrain processing and AERMET for meteorological data processing. 

This is in accordance with the default recommendations in EPA’s GAQM, Section 4.2.2 on 

 

21 NOx and VOC are precursors to ozone formation. 
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Refined Analytical Techniques. SCREEN was also used in earlier the earlier modeling 

submittals. 

8.3.2 Meteorology model inputs 

AERMOD requires representative meteorological data in order to accurately simulate air quality 

impacts. Resolute used surface meteorological data collected for a five consecutive-year period 

(2005-2009) at the Canyonlands Airport meteorological station near Moab, Utah, northwest of 

the Main Flare site. This station is located approximately 105 miles (170 km) from the t site. 

Utah processed the data using EPA’s AERMET data processor, and provided the data to the 

Applicant. EPA concurs that the chosen Canyonlands Airport data is the most representative for 

the Main Flare analysis. 

For upper air data, the Applicant obtained concurrent data from the Grand Junction, Colorado 

upper air site located approximately 134 miles (215 km) north of the Main Flare site as being the 

most representative site available that had data complete enough to use. No other upper air 

meteorological monitoring stations are located closer to the Main Flare site. (MCU 1-hour SO2

Modeling, April 2011, p.5-3pdf17). EPA agrees that it is appropriate to use Grand Junction, 

Colorado upper air data for the Main Flare analysis. 

For screening model application, the full array of 44 discrete meteorological conditions 

internally generated by SCREEN3 was used to estimate potential worst-case short-term (i.e., 

one-hour averaged) impacts for each modeled pollutant. The maximum impact cited by 

SCREEN3 from a specific discrete meteorological condition (wind speed, stability class and 

mixing height combination) and receptor distance was used as the basis for estimating maximum 

pollutant impacts. The maximum one-hour impact for each pollutant was extrapolated to values 

for each averaging period for which a pollutant has an applicable NAAQS and PSD increment, 

using the adjustment factors referenced below: 

Averaging Time Multiplying Factor 

3 hours 0.9 

8 hours 0.7 

24 hours 0.4 

Annual 0.08 

8.3.3 Land characteristics model inputs 

Land characteristics are used in the AERMOD modeling system in three ways: 1) via elevation 

within AERMOD to assess plume interaction with the ground; 2) via a choice of rural versus 

urban algorithm within AERMOD; and 3) via specific values of AERMET parameters that affect 

turbulence and dispersion, namely surface roughness length, Bowen ratio, and albedo. The 

surface roughness length is related to the height of obstacles to the wind flow and is an important 

factor in determining the magnitude of mechanical turbulence. The Bowen ratio is an indicator 

of surface moisture. The albedo is the fraction of total incident solar radiation reflected by the 

surface back to space without absorption. 
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AERMAP is a terrain preprocessor that uses Digital Elevation Model (DEM) or National 

Elevation Dataset (NED) electronic files, which are readily available online, for use with usergenerated receptor grids. The output file consists of the x, y locations of each receptor, mean sea 

level (MSL) elevation and hill profile parameter. The hill profile parameter is used in 

determining plume flow around elevated terrain. Source elevation and receptor elevations and 

hill heights were determined through AERMAP using NED files. 

Reolute determined surface parameters including the surface roughness length, albedo, and 

Bowen ratio for the area surrounding the Canyonlands Airport meteorological tower using the 

AERMET preprocessor, AERSURFACE (Version 08009), and the USGS 1992 National Land 

Cover (NLCD92) land-use data set. The NLCD92 data set used in the analysis has 30 m data 

point spacing and 21 land-use categories. Seasonal surface parameters were determined using 

AERSURFACE according to EPA’s guidance. 

8.3.4 Model receptors 

Receptors in the model are geographic locations at which the model estimates concentrations. 

The Applicant places the receptors such that they have good area coverage and are closely 

spaced enough so that the maximum model concentrations can be found. At larger distances, 

spacing between receptors may be greater than it is close to the source, since concentrations vary 

less with increasing distance. The spatial extent of the receptors is limited by the applicable 

range of the model (roughly 50 km for AERMOD), and possibly by knowledge of the distance at 

which impacts fall to negligible levels. Receptors need be placed only in ambient air, that is, 

locations to which the public has access, and that are not inside the project fence line. 

Discrete receptors in UTM Zone 12 NAD83 coordinates were processed by AERMAP using 10-

meter NED data with the following grid resolutions: 

 A single ring of receptors 200 meters from the center point of the flare 

 100 meter spaced grid out to 2,200 meters from the flare 

 250 meter spaced grid from 2.2 to 10 kilometers from the flare 

 500 meter spaced grid from 10 to 20 kilometers from the flare 

Additional blocks of 100-meter spaced grids were also used to determine maximum 

concentrations within the coarse grids. 

AERMOD was run in both the FLAT and ELEV modes to assess the effects of terrain on 

modeled impacts. 

8.3.5 Stack parameter model inputs 

Short-term pollutant emission rates were estimated by assuming that the maximum volume of 

process gas that could be generated from the well field would be sent to the flare at four different 

heat content values (in BTU/scf). These four heat content values represent a range of estimates 
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including the lowest allowable LHV, the lowest LHV from 2004 gas analyses, the lowest LHV 

from 2005-2008 gas analyses and the highest LHV from 2005-2008 gas analyses data. The 

lowest value input was 300 BTU/scf, which is the lowest allowable LHV as stated in 

40 CFR § 60.18(c)(3)(ii). The next lowest value utilized was 443 BTU/scf, which is the lowest 

of four 2004 actual plant gas samples from the MCU Facility. The LHV of 443 BTU/scf was 

utilized due to the assumption that it would provide the least amount of heat rise, thus producing 

the lowest effective release height. The lowest and highest LHVs from 2005-2008 gas analyses 

data of 538.8 and 682.4 BTU/scf, respectively, were also used for emission estimation. The 

resultant range of BTU contents and effective release heights were modeled to evaluate the 

sensitivity of impacts to each emission rate/effective release height and diameter combination. 

The modeling done by the Applicant used the corresponding stack parameters in Table 8-3 

below. 

Table 8-3: Stack Parameters for Main Flare 

Operating Mode Stack Height 

(m) 

Stack Diameter 

(m) 

Stack Velocity 

(m/s) 

Stack Temp 

(Degrees K) 

300 BTU/scf 59.45 3.56 20.0 1273 

443 BTU/scf 59.45 4.33 20.0 1273 

538.8 BTU/scf 59.45 4.77 20.0 1273 

682.4 BTU/scf 59.45 5.37 20.0 1273 

Source: April 2011 MCU 1-hour SO2 modeling, Table 5-3 

Table 8-4: Load Screening for Main Flare 

Operating Mode NOx 

(g/s) 

SO2 

(g/s) 

CO 

(g/s) 

300 BTU/scf 1.50 9.18 12.84 

443 BTU/scf 2.21 9.18 18.96 

538.8 BTU/scf 2.21 9.18 23.06 

682.4 BTU/scf 2.21 9.18 29.21 

Source: April 2011 MCU 1-hour SO2 modeling, Table 5-3 

8.3.6 Good Engineering Practice (GEP) Analysis 

For modeling purposes, particularly for comparison to short-term standards and PSD increments, 

the worst-case impacts from the Main Flare would be during an upset episode when all process 

gas is sent to the flare, rather than re-injected into the ground. Thus, modeled flare stack 

parameters were adjusted to reflect the instantaneous nature of heat release characteristics of a 

flare when combusting all process gas rather than re-injecting for input to AERMOD. The 

algorithm for this characterization is based on the Texas Commission on Environmental 

Quality’s “Technical Basis for Flare Parameters” (September 10, 2004). An effective stack 

diameter at an assumed stack velocity of 20 m/s at the estimated heat release (in calories per 

second) of the flare is estimated. An effective stack height is estimated based on heat release and 

the physical stack height of the flare. The actual flare stack height of 195 feet was field verified 

to ensure proper stack height. 
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8.4 NATIONAL AMBIENT AIR QUALITY STANDARDS (NAAQS) AND PSD CLASS II

INCREMENT CONSUMPTION ANALYSIS

8.4.1 Pollutants with Significant Emissions 

The PSD regulations require an air quality impact analysis for each PSD-regulated pollutant (for 

which there is a NAAQS) that a major source has the potential to emit in a significant amount, 

i.e., an amount greater than the Significant Emission Rate for the pollutant. Applicable MCU 

Facility emissions and the Significant Emission Rates are shown in Table 8-4. As shown in 

Table 8-4, EPA does not expect the MCU Facility to emit CO and NOx in significant amounts. 

However, based on the estimates submitted by the applicant, EPA expects the MCU Facility to 

emit SO2 and VOC in significant amounts. Therefore, this permit action triggers air impact 

analyses for CO, NO2 and SO2. 

Table 8-5: PSD Applicability to the MCU Facility 

Criteria 

Pollutant 

McElmo Creek Emissions 

(tpy) 

Significant Emission Rate

(tpy) PSD applicable? 

CO 73 100 No 

NOx 13.4 40 No 

SO2 60 40 Yes 

VOC 95.4 40 Yes 

Source: April 2008 Revised PSD Application, Table 3-2 

However, the worst-case conditions based on the modeled maximum flare rate of 14.83 MCFD 

and LHV of 682.4 BTU/scf result in emissions of 319.1 tpy of SO2, 1,015.4 tpy of CO, and 118.5 

tpy of NOx. These very conservative worst-case conditions result in emission rates in the 

analysis that are at least five times greater than current air permit limits. Even with these worstcase emission estimates that far exceed the current air permit limits and actual flow rate 

conditions, the modeling results show no exceedances of the NAAQS or the PSD Class II 

Increments. 

8.4.2 Preliminary Analysis: Project-Only Impacts 

EPA has established Significant Impact Levels (SILs) to characterize air quality impacts. A SIL 

is the ambient concentration resulting from the Facility’s emissions, for a given pollutant and 

averaging period, below which the source is considered to have an insignificant impact. For 

maximum modeled concentrations below the SIL, further air quality analysis for the pollutant 

may not be necessary. For maximum concentrations that exceed the SIL, EPA requires a 

cumulative modeling analysis, which incorporates the combined impact of nearby sources of air 

pollution to determine compliance with the NAAQS and PSD increments. 

Table 8-5 shows the results of the preliminary or project-only analysis based on maximum 

operations for the Main Flare. The worst case short-term impacts from the flare would be during 

an upset episode when all process gas is sent to the flare, rather than injected in the ground. The 

updated modeling includes the worst-case impacts from four flare gas heat content scenarios 

defined in a revise permit application submitted in April 2008. Resolute used SCREEN results 
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to predict annual, 24-hour and 3-hour SO2 impacts. Resolute performed 1-hour SO2 modeling 

with AERMOD. EPA determined 1-hour NO2 and 1-hour and 8-hour CO impacts from the SO2

AERMOD results by taking the ratio of the NO2 and SO2 emissions for various cases, including 

the worst case. EPA compared the ratio with the predicted SO2 cumulative impacts from Tables 

6-1 and 6-2 provided in Resolute’s April 2008 PSD application submittal for 1-hour SO2

Modeling. The only significant impacts predicted by the modeling results was for 1-hour SO2. 

Table 8-6: Main Flare Significant Impacts 

NAAQS Pollutant & 

Averaging Time 

Project-Only Modeled 

Impact, μg/m3

Significant Impact 

Level (SIL), μg/m3

Project impact 

significant? 

NO2, 1-hour 5.0 7.5 (4 ppb) No 

NO2, Annual 0.15 1 No 

SO2, 1-hour 11.6 7.9 (3 ppb) Yes 

SO2, 3-hour 11.6 25 No 

SO2, 24-hour 4.65 5 No 

SO2, Annual 0.93 1 No 

CO, 1-hour 30 2000 No 

CO, 8-hour 30 500 No 

Sources: April 2008 Revised PSD Application, Sections 6 and 7; April 2011 MCU 1-Hour SO2 Modeling, Sections 5 and 6

8.4.3 Cumulative Impact Analysis 

A cumulative NAAQS or PSD increment impact analysis considers impacts from nearby sources 

in addition to impacts from the project itself. In addition, for demonstrating compliance with the 

NAAQS, the applicant adds a background concentration to represent those sources not explicitly 

included in the modeling, so that the total accounts for all contributions to current air quality. In 

this case, Resolute submitted cumulative impact analyses demonstrating compliance with the 

1-hour SO2 NAAQS. 

PSD increments are limits on cumulative air quality degradation. They are set to prevent air with 

pollutant concentrations lower than the NAAQS from being degraded to the level of the 

NAAQS. PSD increments apply in addition to the NAAQS. Increments have been established 

for NO2 and SO2. However, there have been no increments established for 1-hour NO2 and SO2. 

For demonstrating compliance with the PSD increment, only increment-consuming sources need 

to be included, because the increment concerns only changes occurring since the applicable 

baseline date. For this analysis, no pollutants with Class II increments were predicted to have 

impacts above the SIL. 

8.4.3.1 Nearby Source Emission Inventory 

For both the PSD increment and NAAQS analyses, there may be a large number of sources that 

could potentially be included, so judgment must be applied to exclude small and/or distant 

sources that have only a negligible contribution to total concentrations. Only sources with a 

significant concentration gradient in the vicinity of the source need be included; the number of 

such sources is expected to be small except in unusual situations. (GAQM, Section 8.2.3) 
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The Utah Department of Air Quality (UDAQ) and the Colorado Air Pollution Control Division 

(CAPCD) provided a list of all stationary sources within 50 km of the MCU Facility’s Main 

Flare (approximate distance to the farthest significant impact plus 50 km) for SO2. A 

comprehensive procedure was used to determine which sources were included in the emissions 

inventory. 

It should be noted that short-term maximum emission rates rather than annual emission rates 

determine the distance over which a facility might have a significant impact for short-term 

standards (e.g., hourly NO2). Peak rates that occur with flare heat content of 300 BTU/scf 

determine the MCU Facility’s Main Flare significant impact area for hourly SO2. The applicant 

identified eight facilities nearby for inclusion in the emission inventory for the 1-hour SO2

cumulative analysis, based on data from Utah and Colorado. 

Current EPA SO2 guidance suggests that emphasis on determining which nearby sources to 

include in the nearby source inventory should focus on the area within about 10 km of the MCU 

Facility’s Main Flare location in most cases, which indicates that the MCU Facility inventory is 

adequate for performing these cumulative analyses.22 

Therefore, taking into consideration the current EPA guidance suggesting a focus on sources 

within 10 km, EPA concludes that the combination of a representative background monitored 

concentration, and the additional consideration of sources out to 50 km provide sufficient 

justifications for the inventories used in the cumulative analysis. 

8.4.3.2 NO2-Specific Considerations 

While the new 1-hour NO2 NAAQS is defined relative to ambient concentrations of NO2, the 

majority of NOx emissions from stationary sources are in the form of nitric oxide (NO) rather 

than NO2. Appendix W notes that the impact of an individual source on ambient NO2 depends in 

part “on the chemical environment into which the source’s plume is to be emitted” (see Section 

5.1.j). Because of the role NOx chemistry plays in determining ambient impact levels of NO2 

based on modeled NOx emissions, Section 5.2.4 of Appendix W recommends a three-tiered 

screening approach for NO2 modeling. Later guidance documents issued by EPA expand on this 

approach. Tier 1 assumes full conversion of NO to NO2. Tiers 2 and 3 are refinements of the 

amount of conversion of NO to NO2. The applicant and EPA used the Tier 1 approach, in which 

the 1-hour NO2 and annual impacts are based on the assumption that all of the NO is converted 

to NO2. 

8.4.3.3 Results of the Cumulative Impacts Analysis 

The results of the PSD cumulative impacts analysis for the MCU Facility’s worst case operations 

for SO2 emissions are shown in Table 8-6. The analysis demonstrates that emissions from the 

MCU Facility’s Main Flare will not cause or contribute to exceedances of the NAAQS or for any 

 

22 See “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2

National Ambient Air Quality Standard”, Memorandum from Tyler Fox, EPA Air Quality Modeling Group to EPA 

Regional Air Division Directors, March 1, 2011, page 16 
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applicable PSD increments. The background concentrations were taken from Table 8-2 above. 

As discussed above, the MCU Facility’s Main Flare maximum modeled concentrations are 

below the SILs for annual and 1-hour NO2, and for annual, 24-hour and 3-hour SO2; therefore, a 

cumulative impacts analysis was not required to demonstrate compliance for these pollutants and 

averaging times. 

EPA also considered additional information to ensure that the project would not be responsible 

for causing a new NAAQS exceedance outside this modeling area. EPA considered sources in 

Utah and Colorado (no sources of interest were located outside of these states) that were not 

included, but which had been evaluated for inclusion/exclusion, in the cumulative impacts 

modeling above. EPA concluded that these sources are either small enough or distant enough 

that the Main Flare’s expected emissions along with emissions from these sources would not 

create any new NAAQS exceedance in the modeling area outside of the significant impact area. 

Table 8-7: MCU Facility Main Flare Compliance with Class II PSD Increments and NAAQS 

NAAQS 

pollutant & 

averaging 

time 

All Sources 

Modeled 

Impact 

(ug/m3) 

PSD 

Increment 

Consumption 

(ug/m3) 

Background 

Concentration 

(ug/m3) 

Cumulative 

impact w/ 

background 

(ug/m3) 

NAAQS 

(ug/m3) 

PSD 

Increment 

(ug/m3) 

SO2, 1-hour 26.76 N/A 79 105.76 196 None 

Source: April 2011 MCU 1-Hour SO2 Modeling, Tables 6-1 and 6-2 

Note: There are currently no PSD increments defined for 1-hour SO2

8.5 CLASS I AREA ANALYSIS

8.5.1 Air Quality Related Values 

The two nearest Class I areas are within 100 km of the MCU Facility site and are listed below: 

 Mesa Verde National Park 60 km (38 miles) 

 Canyonlands National Park 96 km (60 miles) 

There are an additional six areas within 200 km: Marble Mountain Wilderness Area (116 km), 

Redwood National Park (147 km), Lava Beds National Monument (148 km) Arches National 

Park is located 160 km and South Warner Wilderness Area (192 km). 

Based on the most recent Federal Land Managers’ Air Quality Related Values (AQRV) Work 

Group (FLAG) (2010) published guidance the following screening approach is used to determine 

whether a more refined Class I Air Quality Analysis is required. This approach, which only 

applies to projects located more than 50 km from a Class I area, requires adding all of the 

visibility-related emissions (SO2, NOx, PM10 and sulfuric acid mist) from a project (based on 24-

hour maximum allowable emissions expressed in units of tons per year) and dividing the sum by 

the distance between the project and the nearest Class I area, which is Mesa Verde 60 km away. 

The values input into the table are the maximum. If the result is less than 10, the project is 

presumed to have negligible impacts to Class I AQRVs. The table below shows that the 
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project’s emissions are well below the FLAG screening criteria. Therefore, no further Class I 

AQRV analysis is required. 

Table 8-8: Summary of Q/D Analysis

Parameter Value 

NOx Emission Increase 13.4 tpy 

SO2 Emission Increase 60 tpy 

PM10 Emission Increase -- 

H2SO4 Emission Increase -- 

Distance to Closest Class I Area 73.4 km 

Q/D 1.22 tpy/km 

Q/D Threshold of Concern 10 tpy/km 

8.5.2 Class I Increment Consumption Analysis 

EPA requires an analysis addressing Class I increment impacts for the applicable pollutants 

regardless of the results of the Class I AQRV analysis. The analysis for annual NO2 and annual, 

24-hour and 3-hour SO2 was included in the original application submitted in 2008. Based on 

the results, EPA did not require updated modeling to be submitted with the 2011 PSD application 

because of the very low predicted impacts by SCREEN. The results are presented in Table 8-9 

below. 

NO2 and SO2 impacts are well below their respective significant impact levels; therefore, the 

Applicant has demonstrated the emission levels for the Main Flare will not cause or contribute to 

any Class I violation for PM10 or NO2. 

Table 8-9: MCU Facility Main Flare Class I Increment Impacts at Class I Area

Class I Area Pollutant Averaging Time Main Flare 

Impact, μg/m3 

Class I PSD 

Increment, μg/m3 

Mesa Verde 

NO2 Annual 0.0102 2.5 

SO2

Annual 0.03 2 

24-hour 0.90 5 

3-hour 2.01 25 

Source: April 2008 Revised PSD Application, Table 7-6 

 
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9. ADDITIONAL IMPACT ANALYSIS 

In addition to assessing the ambient air quality impacts expected from a source subject to PSD 

review, the PSD regulations require that EPA evaluate other potential impacts on 1) soils and 

vegetation; 2) growth; and 3) visibility impairment. 40 CFR § 52.21(o). The depth of the 

analysis generally depends on existing air quality, the quantity of emissions, and the sensitivity 

of local soils, vegetation, and visibility in the source's impact area. 

9.1 SOILS AND VEGETATION 

The additional impact analysis includes consideration of potential impacts to soils and vegetation 

associated with the MCU’s emissions. This component generally includes: 

 A screening analysis to determine if maximum modeled ground-level concentrations of 

pollutants from the Main Flare could have an impact on plants; and 

 A discussion of soils and vegetation that may be affected by proposed emissions from the 

Main Flare and the potential impacts on such soils and vegetation associated with such 

emissions. 

The Main Flare at the MCU Facility is located on Navajo Nation land in southeastern Utah near 

the town of Aneth in San Juan County, Utah. The MCU Facility is an oilfield operation, which 

is primarily involved in crude petroleum and natural gas extraction. The Applicant presented its 

discussion of the potential impacts on soils and vegetation in its supplemental PSD permit 

application submitted to EPA Region 9 in February 2013. Ground cover is relatively sparse 

because of the semiarid climatic conditions surrounding the site. Vegetation in San Juan County 

includes woodlands, dominated by Pinyon Pine and Utah Juniper, desert and semi-desert shrubs 

classified as saltbush because of the because of the prevailing saline soils, sagebrush, blackbush 

and scattered grassland areas. Resolute provided specific vegetation designated as sensitive for 

San Juan County. This information is provided in Table 9-1. 
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Table 9-1: Sensitive Plant Species Potentially Occurring in San Juan County, Utah 

Common Name Habitat

Navajo Sedge Seasonally wet, seeps, springs, hanging gardens in Navajo sandstone: 

3,770 -5,908 ft. elevation 

Chatterly's Onion Moist pinyon-juniper and sagebrush sites 

Culter Milkwood Sand dunes 

Cronquist Milkvetch Cutler formation (Comb Wash), Morrison formation (Aneth) 

Copper Canyon Milkvetch Warm desert shrub, 3,085 ft. elevation, Copper Canyon 

Skull Valley Spring Parsley Deposits of wind-blown sand 

Beck's Spring Parsley Sandy soil of Navajo sandstone origin, crevices and ledges of 

slickrock, higher elevations in Abajo Mountains 

Hole-in-the Rock Prairie 

Clover 

Sandstone bedrock and sand in blackbrush and mixed desert shrub: 

4,690 -5,000 ft. elevation 

Spineless Hedgehog Cactus Blackbrush, ephedra, sagebrush, pinyon-juniper mountain brush, 

aspen communities: 3,200 - 8,400 ft. elevation 

Nevada Willowherb Talus slopes, crevices 

Kachina Daisy Seasonally wet seeps, hanging gardens on sandstone outcrops 

Redroot Buckwheat Sagebrush and pinyon-juniper: 5,000 ft. elevation 

Cataract Canyon Gilia Mixed warm and cool desert shrub communities: 3,280 - 5,215 ft. 

elevation 

Alcove Bog Orchid Moist streambanks, seeps, hanging gardens in mixed desert shrub, 

pinyon-juniper and oakbrush: 4,360 - 8,690 ft. elevation 

Canyonlands Lomatium Slot canyons between Entrada sandstone, sandy soil or crevices in 

sandstone, sheltered cool areas of slopes 

Western Hophornbeam Small tree at bases of monoliths, hanging gardens of sandstone: 

4,000 - 5,600 ft. elevation

Paradox Breadroot Pinyon-juniper and mixed desert shrub: 5,020 ft. elevation 

Alcove Rock Daisy Drier crevices in seasonally wet hanging gardens, alcoves at 

4,000 ft. elevation, Navajo & Windgate sandstone, Rico 

Formation 

Howell Scorpionweed Salt and warm desert shrub, pinyon-juniper: 3,690 - 5,000 ft. elevation 

Bluff Phacelia Salt desert shrub: 4,500 ft. elevation 

Mancos Shadscale Salt desert shrub in Morrison Formation 

Jane's Globemallow Sandy soils of weathered white rim and Organ Rock areas of 

Cutler Formation, warm/salt desert shrub: 4,000 - 4,600 ft. elev.

Source: Table 7-8 of the supplemental PSD permit application submitted to EPA Region 9 on February 20, 2013 

The values in Table 9-2 below and Table 8-5 of this document provide the concentration impacts 

used below in EPA’s “Screening Procedure for the Impacts of Air Pollution Sources on Plants, 

Soils and Animals” (1980)23 to determine if maximum modeled ground-level concentrations of 

SO2, NO2 and CO from the main flare could have an impact on plants, soils, and animals. 

 

23 “Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals,” EPA 450/2-81-078, 

December 1980. 
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Table 9-2: Screening Ambient Air Concentrations for Sensitive Vegetation Exposure

Pollutant 1-hour 

(μg/m3) 

3-hour 

(μg/m3) 

4-hour 

(μg/m3) 

8-hour 

(μg/m3) 

1-week 

(μg/m3) 

1-month 

(μg/m3) 

Annual 

(μg/m3) 

SO2 9 7 -- -- -- -- 18 

NO2 -- -- 3760 3760 -- 564 94 

CO -- -- -- -- 1,800,000 -- -- 

Source: Table 7-9 of the supplemental PSD permit application submitted to EPA Region 9 on February 20, 2013 

The modeled impacts of SO2, NO2, and CO emissions from the Main Flare range from below one 

percent to five percent of the minimum impact levels/screening concentrations identified in this 

Screening Procedure. 

Table 9-3: Maximum Concentrations & Screening Concentrations for Ambient Exposures

Criteria Pollutant and Guidance 

Averaging Time 

EPA Screening 

Concentration 

(μg/m3) 

Modeled Maximum 

Concentrations 

(μg/m3) 

Modeling 

Averaging time 

SO2 1-Hour 917 11.6 1 hour 

SO2 3-Hours 786 (0.30 ppm) 11.6 (0.0045 ppm) 3 hour 

SO2 Annual 18 0.93 Annual 

NO2 4-Hours 3,760 5.0 1 hour 

NO2 8-Hours 3,760 5.0 1 hour 

NO2 1-Month 564 5.0 1 hour 

NO2 Annual 94 (0.05 ppm) 0.15 (0.00008 ppm) Annual 

CO Weekly 1,800,000 30 8 hour 

In summary, based on our consideration of the information and analysis provided by the 

Applicant, and other relevant information, we do not believe that emissions associated with the 

MCU Facility will generally result in adverse impacts to soils or vegetation. 

9.2 VISIBILITY IMPAIRMENT

The additional impact analysis also evaluates the potential for visibility impairment (e.g., plume 

blight) associated with the Main Flare. Using procedures from EPA’s Workbook for Plume 

Visual Impact Screening and Analysis,24 the potential for visibility impairment is characterized 

for: 

 Class I areas located within 50 km of the proposed MCU; and 

 Class II areas identified as potentially sensitive state or federal parks, forests, 

monuments, or recreation areas. 

 

24 “Workbook for Plume Visual Impact Screening and Analysis (Revised)”, EPA, EPA–454/R–92–023, 1992. 
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There are no Federal Class I areas located within 50 km of the MCU Facility’s Main Flare site; 

the nearest Class I area is Mesa Verde National Park 61 km (38 miles), as presented in Section 

8.5.1. For Class II areas, the Applicant evaluated both Level I and Level II VISCREEN 

screening analyses for visibility impairment for five different Hovenweep units in the 

Hovenweep federal Class II areas within 50 km of the site: 

 Cajon Unit (4.8 km away) 

 Square Tower (18 km away) 

 Holly (21 km away) 

 Horseshoe and Hackberry (22 km away) 

 Cuthroat Castle (28 km away) 

Even though, the closest three units had predicted values over the quantitative visibility 

impairment threshold for Class I areas, EPA has not yet established a similar quantitative 

visibility impairment threshold for Class II areas. For the MCU Facility’s Main Flare, these 

predicted values are used for informational purposes only. There is a Level 3 analysis using the 

model PLUVUE that can be requested, but has been limited to being requested only for projects 

which have predicted impacts over the Class I threshold levels in a Class I area. A Level-3 

analysis is no longer considered a screening analysis because it a comprehensive analysis of the 

magnitude and frequency of occurrence of plume visual impacts as observed at a sensitive Class 

I area vista. Even if a PLUVUE analysis were done and the predicted impacts were greater than 

the Level 3 threshold, this would not likely result in a change in the emission rates for the flare. 

9.3 GROWTH

The growth component of the additional impact analysis involves a discussion of general 

commercial, residential, industrial, and other growth associated with the MCU Facility. This 

analysis considers emissions generated by growth that will occur in the area due to the source. 

In conducting this review, we focus on residential, commercial and industrial growth that is 

likely to occur to support the source under review including, for example, employment expected 

during construction and operations and potential growth impacts associated with such 

employment, such as impacts to local population and housing needs. 

No additional temporary employees have been used. Although there has been an increase in the 

number of full-time employees, no significant growth is expected for this Facility. 

 
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10. ENDANGERED SPECIES ACT 

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. 1536, and its 

implementing regulations at 50 CFR Part 402, EPA is required to ensure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued existence of 

any endangered or threatened species or result in the destruction or adverse modification of such 

species’ designated critical habitat. EPA has determined that this PSD permitting action is 

subject to ESA Section 7 requirements. However, the MCU Facility is an existing operation, 

other than the replacement of a fixed speed fan with a variable speed fan to provide better 

pollution control at the Main Flare, EPA Region 9’s action does not authorize any new 

construction or modification of existing equipment at the MCU Facility. Therefore, EPA has 

determined that this permit action will have no effect on any endangered or threatened species or 

any designated critical habitat in the area. The United States Fish and Wildlife Service (FWS) in 

a January 25, 2013 e-mail to EPA Region 9. 

11. NATIONAL HISTORIC PRESERVATION ACT 

Pursuant to Section 106 of the National Historic Preservation Act (NHPA), 6 U.S.C. § 470f, and 

its implementing regulations at 36 CFR Part 800, prior to the approval of the expenditure of any 

funds on or prior to the issuance of any license for an undertaking, EPA is required to take into 

account the effects of its undertakings on historic properties and afford the Advisory Council on 

Historic Preservation (Council) a reasonable opportunity to comment with regard to such 

undertakings. Consultation is required for all undertakings that have the potential to affect 

historic properties. Section 106 consultations assess whether historic properties exist within an 

undertaking’s area of potential effect and, if so, whether the undertaking will adversely affect 

such properties. The term “historic properties” means prehistoric or historic districts, sites, 

buildings, structures, or objects included in, or eligible for inclusion in, the National Register of 

Historic Places maintained by the Department of the Interior. Historic properties include 

properties of traditional religious and cultural importance to an Indian Tribe or Native Hawaiian 

organization. Consultation is generally with relevant state and tribal historic preservation 

authorities in the first instance, with opportunities for direct Council involvement in certain 

circumstances. 

EPA’s action, which is for the issuance of a federal PSD permit, is an undertaking as defined in 

36 CFR 800.16(y). The MCU Facility has been in operation since the 1950s. This permit action 

is for the Main Flare which has been in operation since the 1990s. The EPA’s permit action is to 

incorporate the federal Consent Decree requirements for the Main Flare into the PSD permit. 

Other than the replacement of a fixed speed fan with a variable speed fan to provide better 

pollution control at the Main Flare, this permit action does not authorize any new construction or 

modification of existing equipment at the MCU Facility. EPA is currently consulting with the 

Tribal Historic Preservation Officers for the Navajo Nation and Ute Mountain Indian tribes. 
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12. MAGNUSON-STEVENS FISHERY CONSERVATION AND 

MANAGEMENT ACT 

The Magnuson-Stevens Fishery Conservation and Management Act (MSFCMA) was enacted to 

promote the U.S. fishing industry’s optimal exploitation of coastal fisheries by consolidating control 

over territorial waters to manage fish stocks. Implementation of the MSFCMA is by the U.S. 

Department of Commerce, National Marine Fisheries Service (NMFS), and its appointed regional 

fishery management councils. Because the MCU Facility is located on the Navajo Nation Indian 

Reservation in Utah, which is not located near any coastal or territorial waters and will not 

directly affect any fisheries or fishery resources. Therefore, this PSD permit action will not 

affect marine fisheries management. 

13. COASTAL ZONE MANAGEMENT ACT 

The Coastal Zone Management Act (CZMA) of 1972 provides for management of the nation’s 

coastal resources, including the Great Lakes. It encourages states to preserve, protect, develop, 

and where possible, restore or enhance valuable natural coastal resources such as wetlands, 

floodplains, estuaries, beaches, dunes, barrier islands, and coral reefs, as well as the fish and 

wildlife using those habitats. The CZMA is administered by the National Oceanic and 

Atmospheric Administration’s Office of Ocean and Coastal Resource Management. Under this 

act, two national programs were created, the National Coastal Zone Management Program 

(CZMP) and the National Estuarine Research Reserve System, covering areas bordering the 

Atlantic, Pacific, and Arctic Oceans, the Gulf of Mexico, Long Island Sound, and the Great 

Lakes. Because the MCU Facility is located in on the Navajo Nation Indian Reservation in Utah, 

which is not a coastal State, this PSD permit action will not affect any coastal resources. 

14. ENVIRONMENTAL JUSTICE ANALYSIS 

Executive Order 12898, entitled “Federal Actions To Address Environmental Justice in Minority 

Populations and Low-Income Populations,” states in relevant part that “each Federal agency 

shall make achieving environmental justice part of its mission by identifying and addressing, as 

appropriate, disproportionately high and adverse human health or environmental effects of its 

programs, policies, and activities on minority populations and low-income populations.” Section 

1-101 of Exec. Order 12898, 59 Fed. Reg. 7629 (Feb. 16, 1994). 

EPA determined that there may be minority or low-income populations potentially affected by its 

proposed action on the MCU Facility PSD permit application, and determined that it would be 

appropriate to prepare an Environmental Justice Analysis for this action. EPA prepared an 

Environmental Justice Analysis, which is included in the administrative record for EPA’s 

proposed PSD permit for the MCU Facility. EPA’s analysis concludes that the MCU Facility’s 

Main Flare will not cause or contribute to air quality levels in excess of health standards for the 

pollutants regulated under the proposed PSD permit amendment; therefore, the Main Flare will 

not result in disproportionately high and adverse human health or environmental effects with 

respect to these air pollutants on minority or low-income populations residing near the MCU 

Facility site, or on the community as a whole. 
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15. CLEAN AIR ACT TITLE V OPERATING PERMIT 

The Applicant must apply for and obtain a Title V operating permit from the Navajo Nation 

Environmental Protection Agency (NNEPA). The NNEPA has been delegated authority to 

administer the federal Title V operating program by EPA for stationary sources on the Navajo 

Nation Indian Reservation, and has jurisdiction to issue the Title V Operating Permit for the 

MCU Facility. 

16. PUBLIC PARTICIPATION 

16.1 PUBLIC COMMENTS

The comment period for EPA’s proposed PSD permit amendment for the MCU Facility begins 

on November 15, 2014. Any interested person may submit written comments. All written 

comments on EPA’s proposed action must be received by EPA via email or postmarked by 

November 20, 2014. An extension of the comment period may be granted if the written request 

for an extension adequately explains why more time is required to prepare comments. 

Comments must be sent or delivered in writing to one of the following addresses: 

E-mail: R9airpermits@epa.gov 

U.S. Mail: Shaheerah Kelly (AIR-3) 

 U.S. EPA Region 9 

 75 Hawthorne Street 

 San Francisco, CA 94105-3901 

Alternatively, written comments may be submitted at the Public Hearing for this matter that 

will be held on November 20, 2014 as described below. Comments should address the PSD 

permit action and Facility, including such matters as: 

 BACT determinations for the Main Flare; 

 The effects, if any, on Class I areas; 

 The effect of the proposed facility on ambient air quality; and 

 The attainment and maintenance of the NAAQS. 

16.2 PUBLIC INFORMATION MEETING & PUBLIC HEARING

EPA will hold a Public Information Meeting for the purpose of providing interested parties with 

additional information and an opportunity for informal discussion of the proposed PSD permit. 

Immediately following the Public Information Meeting, EPA will hold a Public Hearing, 

pursuant to 40 CFR 124.12, to provide the public with further opportunity to comment on the 

proposed PSD permit. At the Public Hearing, any interested person may provide written 
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comments or oral comments, in English or Diné, and relevant data pertaining to the proposed 

permit amendment. The date, time, and location of the Public Hearings are as follows: 

Date: November 20, 2014 

Time: 5:00 PM – 6:00 PM (PUBLIC INFORMATION MEETING)

6:00 PM – 8:00 PM (PUBLIC HEARING)

Location: Aneth Chapter House 

East Highway 162, Mile Post 30 

Aneth, Utah 84510 

(435) 651-3525 

English-Diné translation services will be provided at each Public Information Meeting and 

Public Hearing. If you require a reasonable accommodation, please contact Philip Kum, EPA 

Region 9 Reasonable Accommodations Coordinator, by October 31, 2014 at (415) 947-3566, or 

kum.philip@epa.gov. 

16.3 AVAILABILITY OF PERMIT DOCUMENTS

 

All information submitted by the Applicant is available as part of the administrative record. The 

proposed air permit, Ambient Air Quality Impact Report/Fact Sheet (AAQIR/Fact Sheet), permit 

application and other supporting information are available on the EPA Region 9 website at 

http://www.epa.gov/region09/air/permit/r9-permits-issued.html#pubcomment. The 

administrative record may also be viewed in person, Monday through Friday (excluding federal 

holidays) from 9:00 AM to 4:00 PM, at the EPA Region 9 address above. Due to building 

security procedures, please contact Shaheerah Kelly at (415) 947-4156 at least 72 hours in 

advance to arrange a visit. Hard copies of the administrative record can be mailed to individuals 

upon request in accordance with Freedom of Information Act requirements as described on the 

EPA Region 9 website at http://www.epa.gov/region9/foia/. 

The proposed PSD permit and the accompanying AAQIR/Fact Sheet are available for review and 

inspection at the Navajo Nation Environmental Protection Agency, Fort Defiance, AZ, 

(928) 871-7692 and the following Navajo Nation chapter house locations: 

 Aneth Chapter House, Aneth, UT, (435) 651-3525 

 Red Mesa Chapter House near Montezuma Creek, UT, (928) 656-3679 

 Teec Nos Pos Chapter House, Teec Nos Pos, AZ, (928) 656-3662 

 Mexican Water Chapter House, Bluff, AZ, (928) 429-0986 

 Sweetwater Chapter House, Sweetwater, AZ, (928) 429-0977 

 Dennehotso Chapter, Dennehotso, AZ, (928) 658-3300 
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The proposed PSD permit amendment and AAQIR/Fact Sheet are also available for review and 

inspection at Receptionist Desk of the following libraries: 

 Monticello Library, Monticello, UT, (435) 587-2281 

 Blanding Library, Blanding, UT, (435) 678-2335 

 Montezuma Creek Library, Montezuma Creek, UT, (435) 651-3309 

 Bluff Library, Bluff, UT, (435) 672-9996 

 La Sal Library, La Sal, UT, (435) 686-9936 

All comments that are received will be included in the public docket without change and will be 

available to the public, including any personal information provided, unless the comment 

includes Confidential Business Information (CBI) or other information whose disclosure is 

restricted by statute. Information that you consider CBI or otherwise protected should be clearly 

identified as such and should not be submitted through e-mail. If you send e-mail directly to the 

EPA, your e-mail address will be automatically captured and included as part of the public 

comment. Please note that an e-mail or postal address must be provided with your comments if 

you wish to receive direct notification of EPA’s final decision regarding the permit. 

EPA will consider all written comments submitted during the public comment period before 

taking final action on the PSD permit amendment and will send notice of the final decision to 

each person who submitted comments and contact information during the public comment period 

or requested notice of the final permit decision. EPA will respond to all substantive comments in 

a document accompanying EPA’s final permit decision. 

16.4 FINAL PERMIT DECISION

Before taking final action, EPA Region 9 will consider all written and oral comments submitted 

during the public comment period, including those provided at the public hearing, before taking 

final action on the PSD permit amendment. 

EPA will send notice of the final decision to each person who provides contact information and 

who: (i) submits comments during the public comment period, including oral comments 

provided at the public hearing; or (ii) requests notice of the final permit decision. EPA will 

summarize the contents of all substantive comments and provide written responses in a 

document accompanying EPA’s final permit decision. EPA will also make a transcript of the 

Public Hearing proceedings available to the public. 

EPA’s final permit decision will become effective 30 days after the service of notice of the 

decision unless: 

1. A later effective date is specified in the decision; or 

2. The decision is appealed to EPA’s Environmental Appeals Board pursuant to 40 CFR 

124.19; or 

3. There are no comments requesting a change to the proposed permit decision, in which case 

the final decision shall become effective immediately upon issuance. 
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16.5 CONTACT INFORMATION

If you have questions, would like to be added to our mailing list to receive future information 

about this proposed permit decision, or other PSD permit decisions issued by EPA Region 9, 

please contact Shaheerah Kelly at (415) 947-4156 or e-mail at R9airpermits@epa.gov, or visit 

EPA Region 9’s website at http://www.epa.gov/region09/air/permit/psd-public-guidelines.html. 

Shaheerah Kelly can also be reached through EPA Region 9’s toll-free general information line 

at (866) 372-9378. 

17. CONCLUSION AND PROPOSED ACTION 

EPA is proposing to amend the PSD permit for the MCU Facility owned and operated by 

Resolute. We believe that the proposed PSD permit amendment complies with PSD 

requirements, including the installation and operation of BACT and protection of the any 

NAAQS and PSD increment. We have made this determination based on the information 

supplied by the Applicant and our review of the analyses contained in the permit application. 

EPA will provide the proposed PSD permit amendment and this AAQIR/Fact Sheet to the public 

for review, and make a final decision after considering any public comments on our proposal.