## 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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### PROPOSED CLEA N AIR ACT
PREVENTION OF SIGN IFICANT DETERIORATIO N PERMIT AMENDMENT

RESOLUTE NATURAL RE SOURCES COMPANY
MCELMO CREEK UNIT OIL PRODUCTION FACILITY
PSD Permit NU 05-01

Ambient Air Quality Impact Report & Fact Sheet

Table of Contents

A CRONYMS A CRONYMS & A BBREVIATIONS

................................................................................. IV

E XECUTIVE S UMMARY ................................................................................................................... 1

1. P URPOSE OF THIS D OCUMENT ................................................................................................. 2

2. A PPLICANT

.............................................................................................................................. . 2

3. F ACILITY L OCATION ................................................................................................................ 2

4. P ROJECT D ESCRIPTION ............................................................................................................ 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. P ROJECT E MISSIONS .............................................................................................................. 10

6. A PPLICABILITY OF THE P REVENTION OF S IGNIFICANT D ETERIORATION R EGULATIONS ... 11

7. B EST A VAILABLE C ONTROL T ECHNOLOGY A NALYSIS ........................................................ 12
7.1 BACT for Sulfur Dioxides .......................................................................................... 13
7.1.1 Step 1 - Identify All C ontrol Technologies for SO 2 ................................... 13
7.1.2 Step 2 - Eliminate Technicall y Infeasible Options for SO 2 ....................... 14
7.1.3 Step 3 - Rank Control Technologies ......................................................... 15
7.1.4 Step 4 – Economic, Energy and Environmental Impacts for SO 2 ............. 16
7.1.5 Step 5 – Select BACT for SO 2 ................................................................... 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 ............................................. 18ii 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 C ontrol Technologies for NO X

.................................. 21
7.3.2 Step 2 - Eliminate Technically Infeasible Options for NO X

...................... 22
7.3.3 Step 3 - Rank Control Technologies for NO X

........................................... 23
7.3.4 Step 4 – Economic, Energy and Environmental Impacts for NO X

............ 25
7.3.5 Step 5 – Select BACT for NO X .................................................................. 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. A IR Q UALITY I MPACTS A NALYSIS ......................................................................................... 34
8.1 Introduction ................................................................................................................. 34
8.1.1 Overview of PSD Air Impact Requirements .............................................. 34
8.1.2 Identification of MCU Fa cility Main Flare Mode ling 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 Standard s (NAAQS) and PSD Class II Increment Consumption Analysis ................................................................................................ 40
8.4.1 Pollutants with Significant Emissions ....................................................... 40
8.4.2 Preliminary Analysis: Pr oject-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. A DDITIONAL I MPACT A NALYSIS ............................................................................................ 45
9.1 Soils and Vegetation ................................................................................................... 45
9.2 Visibility Impairment .................................................................................................. 47
9.3 Growth ........................................................................................................................ 48

10. E NDANGERED S PECIES A CT ................................................................................................... 49

11. N ATIONAL H ISTORIC P RESERVATION A CT ........................................................................... 49iii 12. M AGNUSON

- STEVENS F ISHERY C ONSERVATION AND M ANAGEMENT ACT .......................... 50

13. C OASTAL Z ONE M ANAGEMENT ACT ..................................................................................... 50

14. E NVIRONMENTAL J USTICE A NALYSIS ................................................................................... 50

15. C LEAN A IR A CT T ITLE V O PERATING P ERMIT .................................................................... 51

16. P UBLIC P ARTICIPATION ......................................................................................................... 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. C ONCLUSION AND P ROPOSED A CTION .................................................................................. 54iv 

### ACRONYMS & AB BREVIATIONS

AAQIR Ambient Air Quality Imp act Report and Fact Sheet Act Clean Air Act [42 U.S.C. Section 7401 et seq.] Applicant Resolute Natural Resources Company
b ext Light extinction coefficient BA Biological Assessment
BACT Best Availabl e 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
CO 2 Carbon Dioxide Consent Decree United States v. Mobil Explor ation 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 Un it 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/m 3 microgram per cubic meter
MMBTU million British thermal unitsv MSFCMA Magnuson-Stevens Fishery C onservation and Management Act MW Megawatts of electrical power NAAQS National Ambient Air Quality Standards
NESHAP National Emission Standard s 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
NO 2 Nitrogen Dioxide
NO x Nitrogen Oxides or Oxid es of Nitrogen (NO + NO 2 )
NP National Park
NPS National Park Service NSPS New Source Performance Standards, 40 CFR Part 60
NSR New Source Review
O 2 Oxygen Permittee Resolute Natural Resources Compan y; or the owner and/or operator of the McElmo Creek Unit Oil Production Facility
PM Total Particulate Matter

PM 2.5 Particulate Matter less than 2.5 micrometers ( μ m) in diameter

PM 10 Particulate Matter less than 10 micrometers ( μ m) 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
SO 2 Sulfur Dioxide
SO x Sulfur Oxides tpy tons per year USFS United States Forest Service VOC Volatile Organic Compounds
WA Wilderness AreaMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 1 

### Proposed Prevention of Significa nt 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 Ag ency (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 incorporat e pollution limits, terms, and conditions of a federal Consent Decree that applie s to the Main Flare at the Facility. The MCU Facility is an existing oil and gas production op eration located within the Four Corners Area on the Navajo Nation Indian Reservation near th e city of Aneth, San Juan County, Utah. The Facility is on the McElmo Creek Unit oilfie ld, which includes fiel d operations and a gas compression plant. It is owned and operate d 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 th e PSD program for the following reasons:

 The proposed amended PSD permit requires the Best Available Cont rol Technology (BACT) to limit emissions of volatile organi c compounds (VOC), nitrogen oxides (NO x ), sulfur dioxide (SO 2 ), and carbon monoxide (CO).

 The proposed emission limits will protect th e National Ambient Air Quality Standards (NAAQS) for ozone, nitrogen dioxide (NO 2 ), SO 2 , 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 cont ribute to violations of any applicable PSD increments for the pollutants regulated under th e 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 Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 2 

### 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 le gal 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 al so 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, Town ship 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 locat ion of the Facility.

Figure 3-1: Location of McElmo Creek Unit Oil Production FacilityMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 3 The Four Corners Interstate Air Quality Control Re gion is currently designated as attainment or unclassifiable for all criteria po llutants: nitrogen dioxide (NO 2 ), sulfur dioxide (SO 2 ), carbon monoxide (CO), particulate matter less than 10 microns in aerodynamic diameter (PM 10 ), fine particulate matter less than 2.5 microns (PM 2.5 ), lead, and ozone (regula ted as volatile organic compounds (VOC) and oxides of nitrogen (NO x ), 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 Rese rvation because Navajo Nation Environmental Protection Agency (NNEPA) currently does not have a delegated or federally-approved PSD permitting program.



### 4. PROJECT DESCRIPTION

4.1 F ACILITY H ISTORY

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 natu ral gas processing plant at th e Facility, which included dehydrator, amine treater, refriger ation separation unit, a natural gas liquids recovery unit and compressors to transport the produced liquid natura l gas. Mobil installed an upright flare (Main Flare) as part of the emergenc y relief system for the gas proce ssing 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 st orage tanks and heater treaters we re 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 c ontinued to operate the Main Flar e at the gas processing plant.

In 1997, following a fire, most all processing equipm ent was removed. The Main Flare was kept for emergency flaring, flaring clos ed drain system fumes, and c ontrol of dehydrator emissions. The former gas processing plant is now refe rred to as the gas compression plant. The compressors were later convert ed to run on electricity.

In 1997 and 1999, EPA issued Notice of Violations fo r, among other things, permitting violations relating to the Main Flare. The Facility is curr ently 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 Faci lity 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 4 4.2 F ACILITY O PERATIONS

The MCU Facility is on McElmo Creek Unit oilfield, wh ich 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 r ecovered from producing strata, brought to the
surface to be stored at either a satellite or a ta nk battery. There are eleven satellites that function as testing facilities for producing wells and four tank batteries.

Crude oil is recovered using wate r alternating gas (WAG) injection, which is a tertiary recovery method. WAG injection is where water is inje cted into the producing strata, followed by carbon dioxide (CO 2 ) gas, and again by water to enhance cr ude oil recovery to the surface. CO 2 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 wa ter is re-injected back into the produc ing strata via the water injection station. Separated gas is sent to the gas compression plant at the MCU Facility and processed as descri bed in Section 4.2.2 below. Cr ude oil is sold at the lease automatic custody transfer (LACT) unit at each cen tral tank battery and transported to Western Refining’s Ciniza Refinery in Gallup, New Mexico, via the R unning 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 (CO
2 ), 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 pumpe d 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 natura l gas is injected with produced water into the producing strata using a dual inj ection system. Due to varying water injection demands in the field, and to the number of wells being serviced at any time, the gas vo lume entering the plant can vary between 10 and 18 million standard cubic feet per day (MSCFD).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 5 The gas is processed in three main steps: in let 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 incomi ng solids. During the compression stage, 4 highspeed electrically-driven reci procating compressors, which utilize 6300 brake horsepower (BHP), are used to compress the gas. Each comp ressor 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 comp ressor, inter stage dehydration takes place to remove water for corrosion mitigation. During re-i njection, the gases from the four compressors discharge into a single header, where purchased CO 2 is co-mingled to achieve a daily injection goal of 24 MSCFD. The gas is then distributed to the field. During plant upsets, additional CO 2 is purchased to meet the daily injection goal.

The Main Flare at the gas compression plant co mbusts gases that have been bypassed around the facility’s electric-driven compre ssors or that come through various emergency relief valves in the compression plant. Additionally, th e vent stream from the plant’s glycol dehydrator is directed
to the Main Flare.

A flow diagram of the Facility’s gathering sy stem operations is presented in Figure 4-1, illustrating the flow through the sa tellite facilities, central tank batteries, water flood injection plant, and gas compression plant. Figure 4-1 pres ents a simple block flow diagram for the gas compression plant, including the stre ams directed to the Main Flare.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 6 Figure 4-1: McElmo Creek Unit Oil Production Facility Operations

Source: April 2008 PSD Application, Figure 2-2

4.3 PSD P ERMIT H ISTORY

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

February 2, 1987 – EPA issued the initial PSD pe rmit to Mobil for the modification of the MCU Facility for the MCU Stage 2 CO 2 Project. The permit authorized the construction and operation of three 1730 horsepower (HP) recipro cating 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 is sued 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 reservati on, this authority was transferred to EPA Region 9. The Navajo Nation Indian Reservation covers portions of northeastern Arizona, southeastern Utah, and northwestern
New Mexico.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 7 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 hei ght 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 hea ting equipment at the Facility with a waste heat reco very unit; (2) temporarily replace the existing gas turbine with an identical unit during maintenance overhaul of th e turbine, (3) change th e rating of the existing gas turbine one gas turbine wh ich was installed from 3216 HP to 4390 HP and add requirements
for the New Source Performance Standard for Ga s 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 tu rbines at the gas compression plan t 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 CO 2 line heater, which was used during severe cold weather, was removed from th e MCU Facility in March 2004.

4.4 PSD P ERMIT C HANGES

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 eff ective on June 8, 2005. Paragraph 14.a of the Consent Decree requires th e owner and operator of the MCU Faci lity to submit, to EPA, a PSD permit application in accordance with the C AA and the PSD regulations at 40 CFR § 52.21 for the MCU Facility’s Main Flare no t later than the 180 days after th e effective date of the Consent
Decree. The Consent Decree re quires that the PSD application include, among other things, BACT and air quality analyses for SO 2 , CO, NO x , and VOC for the Main Flare. It also requires that the PSD application include terms and condi tions that are at leas t as stringent as the following Consent Decree requirements. 5

 Paragraph 9.a (Emission Limits)

 Paragraph 10 (Monitoring)

 Paragraph 11 (Operation and Maintena nce 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 8 Mobil submitted a PSD application dated Dece mber 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 supplem ental information thereafter.

This permit action also consists of updating the equipment cove red 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 Tabl e 4-2 shows other operations at the Facility that are not explicitly listed in the perm it. 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 Permit 6 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 9 Table 4-2: Other Equipment and Operations at the MCU Facility 7 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
CO 2 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 em ission units remaining at the site: Main Flare, gasoline tank, triethylene glycol (TEG) dehydration unit reboiler, a nd 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 au thorize any new construc tion 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 10 

### 5. PROJECT EMISSIONS

This section describes the emission levels of SO 2 , CO, NO x , and VOC from the Main Flare, and the emission requirements in the Consent Decree.

Table 5-1 shows the actual emissions for the F acility, and Table 5-2 shows the greenhouse gas
emission estimates. Table 5-1: Actual Emissions (2011) for MCU Facility

Operation Size / Throughput SO 2 (tpy) NO
x (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 regardi ng additional information, dated December 4, 2012

Table 5-2: CO 2 e Emission Estimates for MCU Facility Operation Emissions (Metric Tons CO 2 e)

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 regard ing additional information, dated April 18, 2012

Paragraphs 14.a and 9.a of the C onsent Decree requires that BACT fo r 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
SO 2 NO
x CO VOC 60 tpy 13.4 tpy 73 tpy 95.4 tpy Source: Consent Decree, Paragraph 9.aMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 11 

### 6. APPLICABILITY OF THE PREV ENTION 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/unclassifie d areas”, which are areas that meet the National Ambient Air Quality Standards (NAAQS) or where th e 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

SO 2 Attainment or Unclassifiable

CO Attainment or Unclassifiable

Nitrogen Dioxide (NO 2 ) Attainment or Unclassifiable

Ozone 8 Attainment or Unclassifiable

Particulate Matter (PM 2.5 ) 9 Attainment or Unclassifiable

Particulate Matter (PM 10 ) 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: SO 2 , CO, NO x , and VOC. EPA issued a PSD permit to the MCU Facility on February 2, 1987, and the permit was last am ended on April 19, 1991. EPA received a PSD application for the Main Flare in 2005 from Mobil, and has recei ved revised applications in 2007 and 2008 and other supplemental information for th e PSD application from Mobil and Resolute.

8 Troposheric, or ground level ozone, is no t emitted directly into the air, but is created by chemical reactions between NOx and VOC. Thus, both NO
x and VOC precursors in the formation of ozone and are regulated under the
CAA.

9 Fine particulate matter, or PM 2.5 , is particulate matter with diameters that are 2.5 mi crometers and smaller. Some
PM 2.5 is emitted directly from a stationary source, such as construction sites, unpaved roads, fields, or smokestacks.
SO 2 and NO
x are precursors in the formation of PM 2.5 since these pollutants form in complicated reactions in the atmosphere after being emitted from smokestacks.

10 Coarse particulate matter, or PM 10 , includes “inhalable coarse particles, ” with diameters larger than 2.5
micrometers and smaller than 10 micrometers.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 12 

### 7. BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS

This section describes EPA’s BACT analysis for the control of SO 2 , CO, NO x 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 und er 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 en ergy, environmental, and economic impacts and other costs, determines is achievable through ap plication of production processes and available methods, systems, and technique s, including fuel cleaning or treatment or innovative fuel combustion techniques for control of each such po llutant. In no event sha ll application of ‘best available control technology’ result in emissi ons of any pollutants which will exceed the emissions allowed by any applicable standard es tablished 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 re gulated 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 Environm ental Appeals Board (EAB) has consistently followed in adjudicating PSD permit appeals. Se e, 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 pr ocess, all available control tech nologies 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 te chnical 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 st ringent 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 exerci se for the particular source under evaluation. In summary, the five steps involved in a t op-down BACT evaluation are:

1. Identify all available control options with practical potential for application to the specific emission unit for the regul ated pollutant under evaluation;

2. Eliminate technically inf easible technol ogy options;

3. Rank remaining control technologie s by control effectiveness;

4. Evaluate the most effective control alte rnative and document re sults, considering energy, environmental, and economic impact s as appropriate; if top option is notMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 13 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 SO 2 , CO, NO x , and VOC emissions. EPA evaluated the information that Resolute and Mobil submitted. The analys es and our evaluation for each pollutant are presented below.

Table 7-1: Summary of BACT Limits and Requirements for the Main Flare 11

SO 2 CO NO
x VOC

 60.0 tpy, based on a

cumulative 365-day rolling total

 Monitor sulfur content

(in terms of H 2 S) of the gas stream to the flare for calculating SO 2 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/scf 2

 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 S ULFUR D IOXIDES

SO 2 emissions are formed as a result of the co mbustion of gasses containing reduced sulfur compounds. Typically, sulfur dioxide from comb ustion processes can be controlled by limiting
the sulfur content in the fuel or by end-of-pipe cont rol technology.

7.1.1 Step 1 - Identify All Control Technologies for SO 2

The available add-on control technologies for reducing SO 2 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 re port excess emissions to EPA semi-annually, except when: more frequent reporting is specifically required by an app licable subpart; or the Admini strator, on a case-by-case basis, determines that more frequent reporting is necessary to accurately assess the complian ce status of the source.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 14  Spray dryer (e.g., slu rry 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 c ontrol options for reducing SO 2 emissions are as follows.

 Limiting the fuel type

 Limiting the sulfur content

Other control options for reducing SO 2 emissions are as follows.

 Natural gas combustion in flare

 Proper operation and maintenance

7.1.2 Step 2 - Eliminate Technically Infeasible Options for SO 2

Add-On Control Technologies
The add-on control technol ogy options are not techni cally feasible for flare systems, due to the inherent design of flaring and the fact that l iterally, no end-of-pipe exis ts after the combustion zone. Additionally, we found no known demonstrat ions 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 no r applicable to them, all of the add-on control technology options listed above ar e eliminated as technically in feasible for the Main Flare.

Pre-Treatment Control Options Limiting the fuel type is not technically feasib le because the gasses can not be switched with other process or vent streams without cha nging the inherent purpos e and design of the compressor plant. Likewise, limiting the sulfur content or flue gas desulfurization is not technically feasible because th ey 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) re gulations at 40 CFR part 60 define natural gas as the following: “a naturally oc curring 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 temperat ure 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 we ight 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 l east 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 furn ace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might resu lt in highly variable sulfurMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 15 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 CO 2 and 0.05 percent H 2 S, and does not include natural gas as defined above. Thus, requiring combustion of natural gas in the Main Flare to control SO 2 emissions is not technically
feasible.

Proper operation and maintenance is typically sp ecific to a facility and could entail work practices to ensure that the flare is being main tained and operated properly. For the Main Flare, proper operation and maintenance include (1) follo wing 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 ma intenance, root cause, and corrective action requirements of the Consent Decr ee. 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 c ontrol option. Table 7-1 shows a summary of recent SO 2 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 prope r operation and maintenance. As described in Step 2, natural and refinery gases are part of th e 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 flar e gas stream are converted to SO 2 when burned. The
amount of SO 2 emitted depends directly on the quantity of sulfur in the flared gases. The SO 2 BACT emission levels in Table 7-1 vary for each f acility listed. This indicates that the sulfur
content also varies for each of these facilities and that the SO 2 BACT emission levels are facilityspecific. Thus, the SO 2 BACT emission level for the MCU Faci lity’s Main Flare will be based on the expected sulfur cont ent in it flare gas stream.

The SO 2 emission rate specified in the Consent D ecree is 60 tpy based on a cumulative 365-day rolling total. The sulfur cont ent of the dehydrated produced gas that is burned in the MCU’s Main Flare is approximately 0.05 percent H 2 S, but may also result in highly variable sulfur content or heating value.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 16 Table 7-1: SO 2 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 c ontrol 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 SO 2

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 SO 2

Based on the above analysis, BACT for SO 2 emissions from the Main Flare are the following requirements.

 SO 2 emissions not to exceed an emission lim it of 60 tpy based on a cumulative 365-day rolling total.

 Proper operation and maintenance which include: (1) following the manufacturer’s spec ifications for the flare;McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 17 (2) operating and maintaining the flare in acco rdance with the flare requirements in 40 CFR § 60.18; (3) following the operations and maintenance, root cause, and corrective action requirements (incorporated from the Cons ent Decree into the PSD permit); and (4) monitoring of the sulfur content (in terms of H 2 S) of the gas stream to the flare for calculating SO 2 emissions.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 18 7.2 BACT FOR C ARBON M ONOXIDE

Flaring is a high-temperature ox idation process used to burn combustible components, mostly hydrocarbons (i.e., VOC), of waste gases from indus trial operations. In so me waste gas streams sent to a flare, CO is the major combustible co mponent. 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 contro l option for the Main Flare, is technically feasible. Proper operation and maintenan ce include (1) followi ng the manufacturer’s specifications for the flare, (2) operating and main taining the flare in accordance with the flare requirements in 40 CFR § 60.18, and (3) following th e operations and maintenance, root cause, and corrective action requirement s of the Consent Decree.

7.2.3 Step 3 - Rank Control Technologies for CO

Proper operation and maintenance is the only contro l option for the Main Fl are. Table 7-2 shows a summary of recent CO BACT determinati ons for flares at ot her facilities.

These control determinations in clude proper operation and mainte nance, 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 main taining 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 sp ecifications 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 fact or of 0.37 lb/MMBtu. This level is within the range of BACT determinati ons listed in Table 7-2.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 19 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: RBLCMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 20 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 emis sions 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 specificatio ns for the flare to ensure complete combustion in the flare; (2) operating and maintaining the flare in acco rdance 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 C onsent Decree into the PSD permit).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 21 7.3 BACT FOR N ITROGEN O XIDES

NO x is formed as a result of the combustion of hydrocarbons (which are entr ained in the vent gas streams) at the flare (through igni tion with natural gas at the fl are pilot) in the presence of ambient air. There are three principal forms of NO x , designated as “thermal” NO x , “prompt
NO x ,” and “fuel” NO x . Thermal NO x formation is the result of oxidation of atmospheric nitrogen contained in the inlet gas in the high -temperature, post-flame region of the combustion zone. The major factors influencing thermal NO x formation are temperatur e, concentrations of nitrogen and oxygen in the inlet air, and reside nce time within the combustion zone. Prompt
NO x is formed through relatively fast re action between nitrogen, oxygen, and hydrocarbon radicals and is an important mechanism in lo wer temperature combustion processes. Fuel NO x 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 NO x is a concern when burning oil, coal, or waste fuels. NO x emissions from the flare can be best reduced by minimizing the freq uency and amount of vent gases flared and by promoting optimal conditions upon combustion.

7.3.1 Step 1 - Identify All Control Technologies for NO X

Generally, several options exist to reduce NO x emissions from combustion processes, such as pre-treating the fuel or switching fu els and/or oxidizers to prevent NO x formation, modifying the combustion process or equipment to lower NO x formation, and add-on control technologies to
remove NO x . 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 NO x burners (LNB)

The following pre-treatment control options for NO x emissions are listed as follows.

 Fuel Switching

 Fuel Additives

 Oxidizer Switching

Other control options for NO x emissions are listed as follows.

 Proper operation and maintenanceMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 22 7.3.2 Step 2 - Eliminate Technically Infeasible Options for NO X

Add-On Control Technologies
The add-on control technol ogy options are not techni cally feasible for flare systems, due to the inherent design of flaring and the fact that l iterally, no end-of-pipe exis ts after the combustion zone. Additionally, we found no known demonstrat ions of add-on control options such as absorbers or other scrubbing techniques for open, elevated flares. Because these controls are neither available in the marketpl ace for flares nor applicable to them, all of the add-on control technology options listed above ar e eliminated as technically in feasible for the Main Flare.

Inherently Lower-Emitting Control Options Reducing the amount of air prehea t and taking burners out of serv ice are options intended for process heaters and boilers, wher e 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 im plemented with process heaters and boilers. However, flare burner design differs substantiall y from process heater and boiler burner design, because the primary objective of flare burner desi gn is to achieve safe and complete combustion of unwanted hydrocarbons during un predictable 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 th e chemistry of the combustion process, operate under specific temperature conditions and stable operations, neither of which is possible with flare systems. Oxidizer switchi ng, where pure oxygen is used for co mbustion rather than air, is not widely used in the hydrocarbon, petrochemi cal, and power generation industries due to the cost and energy requirements of producing pure oxygen. Fuel switch ing from fuels with higher fuel-bound nitrogen contents to those with lo wer fuel-bound nitrogen contents is a possible option for reducing NO x 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 techni cally infeasible for the Main
Flare as the fuel stream to the flare cannot be switched w ithout inherently changing the compressor plant’s purpose and design. Primarily, fu el is sent to the Main Flare through various pressure-relief piping or compre ssor bypass piping, as a result of emergency or maintenance situations, and also continuously from the dehydrat ion reboiler. Secondly, the fuel to the Main Flare consists of light hydro carbons (methane, ethane, propane) and carbon dioxide, with very little (fuel-bound) nitrogen c ontent. Therefore, these NO x control options are eliminated for technical infeasibility.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 23 Other NO x Control Options Proper operation and maintenance is typically sp ecific to a facility and could entail work practices to ensure that the flare is being main tained and operated properly. For the Main Flare, proper operation and maintenance include (1) follo wing 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 ma intenance, root cause, and corrective action requirements of the Consent Decr ee. Proper operation and maintena nce is technically feasible
for the Main Flare.

7.3.3 Step 3 - Rank Control Technologies for NO X

Proper operation and maintenance is the only contro l option for the Main Fl are. Table 7-3 shows a summary of recent NO x BACT determinations for flares at other facilities.

These control determinations in clude proper operation and mainte nance, comply with the flare requirements in 40 CFR § 60.18, and good comb ustion 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. Prope r operation and maintenan ce for the Main Flare include good combustion practices.

The NO x 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 determina tions listed in Table 7-3.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 24 Table 7-3: NO
x 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% O 2 , 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: RBLCMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 25 7.3.4 Step 4 – Economic, Energy an d Environmental Impacts for NO X

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 NO X

Based on the above analysis, BACT for NO x emissions from the Main Flare are the following requirements.

 NO x 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 spec ifications for the flare; (2) operating and maintaining the flare in acco rdance 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 C onsent Decree into the PSD permit).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 26 7.4 BACT FOR V OLATILE O RGANIC C OMPOUNDS

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 flari ng 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 Cont rol 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 in clude supplemental ex ternal 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 th e reliability of the HOS-6 co mpression engine operations, and considered other compressor changes.

Flaring Due to Compressor Downtime : The majority of the flari ng at the MCU Facility is a
result of downtime associated with the HOS-6 co mpressor. 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 di oxide and has a tendency to liquefy at relative low temperatures. The gas pressure between the 3 rd and 4 th stages of compression is approximately 1000 psi. The gas at this pressure liquefies at approximate ly 85°F. Additionally, the discharge pressure is above the critical pressu re 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 comp ressor 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 4 th stage of the compressor, the field operations group attempts to maintain the suction temperature of the 4 th 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 th is 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 27 The compressor has had downtime associated with 2 nd stage failures due to liquids entering the cylinder. The implemented solution was to rem ove the liquid traps between the separation and compression equipment. This eliminated liquid collection and sl ugging, thereby reducing downtime events significantly.

Reliability of HOS-6 Compressor Engine Operations: The Applicant evaluated two options to increase reliability of compressor engine opera tion: (1) changing the co mpressor process and (2) replacing the HOS-6 compressor. The option to change the compressor process would consist of reducing the discharge pressure of the recipr ocating compression, cooling the gas stream to liquefy it, and utilizing pumps to reach the requ ired pipeline pressure. This could provide increased reliability and minimize potential co mpression failures at the MCU Gas Compression Plant. This option would require new refriger ation equipment, new pumps, and, at a minimum, restaging of the existing compression. Further co rrective actions would also be necessary, as described below, if the existing HOS-6 compressor was used.

The option to replacing the HOS-6 compressor w ould entail replacing the HOS-6 unit with one or more reciprocating compressors. The basic pr ocess would not change. Replacing the existing compressor may reduce the potential for liqui d retention by utilizi ng different piping configurations. However, problems inhere nt with the process would still remain.

Other Compression Changes: The Applicant considered three options for potential changes to compression operations. These options are (1) re locating 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. Ho wever, 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 assu rance of flaring frequency and
duration reductions.

Reconfiguring the piping between the separa tion and compression equipment, similar to replacing the compressor or relo cating the separation equipment, would reduce the potential for liquids to enter the compressi on 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 betwee n the separation and compression equipment, the probability of the gas cooling and liquids formin g would be reduced. The potential for liquids entering the compression equipment would still remain and there would be no assurance of flaring frequency a nd duration reductions.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 28 Flare Gas Recovery System Another method of reducing flaring emissions is to recover gas th at would otherwise be flared and redirect for further processing in the existi ng 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, separa tor, 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 recove r 100 percent of these fuel gases. However, flare gas recovery systems cannot recover large quantities of fuel ga s 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 inte grity of the process un its and the safety of the plant personnel.

Flare gas recovery systems have been used at re fineries and has been re quired in EPA’s final standards for petroleum refineries. 13 These systems have been considered at facilities, such as petroleum refineries, that have fl ares receiving high gas flows.

Proper Operation and Maintenance (Use of Steam, Air, or Gas-Assist Technology) The flare requirements in 40 CFR § 60.18 esta blish specifications on visible emissions, continuous presence of a flame, exit velocities, fuel heating value, and monitoring for flare systems with the intent to ensu re 98 percent control (hydrocarbon destruction) efficiency for applicable flares. In order to achieve th e visible emission require ments of 40 CFR § 60.18, smokeless flare systems are designed with some t ype of external momentum force, such as steam, air, water spray, natural gas, or a specia lized 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 flar e 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 appr oximately 15 to 50 percent of the stoichiometric air requirement into the flame, providing adequate momentum to achieve smokeless and complete combustion. Air-assist desi gn is often used in remote locations. Gasassist with natural gas can provide an additiona l benefit by increasing the heating value to the fuel stream, in situations wher e 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 ai r-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).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 29 Proper operation and maintenance is typically sp ecific to a facility and could entail work practices to ensure that the flare is being main tained 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 CF R § 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 opt ions 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 Effectiven ess 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 dete rminations for flares at other facilities.
These control determinations in clude proper operation and mainte nance, comply with the flare requirements in 40 CFR §§ 60.18 and 63.11, good combus tion practices, and 98% VOC control. The VOC emission rate specified in the Consen t Decree is 95.4 tpy ba sed on a cumulative 365- day rolling total.

Proper operation and maintenance for the Main Fl are 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. Thes e federal requirements for flares include the following minimum requirements:

 Designed and operated with no visible em issions 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 st eam- 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 pe r second (ft/sec). An exit velocity of greater than 60 ft/sec but less than 400 f t/sec may be used if the net heating value of the gas being combusted is sufficiently high.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 30 Proper operation and maintenance include other m easures that ensure complete combustion and proper flare performance. EPA supported a study to better unde rstand flare performance and to identify key operating/monitoring parameters that would ensure adequate performance of flares at all times. Based on this study EPA establis hed 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 wher e 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 th e waste gas and continuously measure, and then control, the air being added as assist gas. Follow the manufacturer’s recommendations and publicly available docum ents in setting proper assist gas rates.

 Utilize automatic damper actuators or vari able 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 contai n 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 supp lemental 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 preven t low heat value in the vent gas stream: 16

 Ensure that the flare waste gas meets the cu rrent regulatory heating value limits of 300 BTU/scf for assisted flares, and 200 BTU/scf for unassisted fl ares, 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 ve nt gas as a whole, not only the hydrocarbons in the vent gas, just before it leaves the flare tip (flare vent ga s to includes all flare waste gas, sweep gas, purge gas and supplemental gas, but not include pilot gas or assist media). The heating value eval uation includes nitrogen and any other compounds that make up the gas mixture that is present just insi de 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 Flar ing Efficiency Violations , EPA 325-F-012-002, August
2012

15 Ibid.

16 Ibid.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 31 flares. 17 EPA has also included such requirements fo r flares in the propos ed 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 ai r-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 th at is greater than or equal to 22 BTU/ft 2

. 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 Flar e must comply with the h eating 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/ft 2 (i.e., 22
BTU/ ft 2 x [(300 BTU/scf)/(270 BTU/scf)]).

A properly operated flare can achieve a destru ction efficiency of 98% or greater when controlling emission streams with heat contents gr eater than 300 BTU/scf. 20 Resolute’s Main
Flare will achieve this 98% dest ruction efficiency through comp liance with the heat content requirements of 40 CFR § 60.18 and the combusti on efficiency provision s discussed above.

17 See Consent Decrees for Marathon Petroleum Compan y, LP and Catlettsburg Refining, LLC Settlement dated April 5, 2012; and Consent Decree for BP Products Nort h America, Inc., case 2:12-c v-00207, filed 09/18/12

18 See Petroleum Refinery Sector Risk and Technology Review and New Source Perf ormance 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)McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 32 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% O 2 , 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 opti ons, compressor engine modifications and flare gas recovery systems. The third control opti on (i.e., Proper operation and maintenance with steam, air, or gas-assist technology) does not ad ditional controls beyond the Main Flare and an economic analysis is no t 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 Flar e. Therefore, we are eliminating compressor modifications and flare recovery systems.

No significant energy or environmental imp acts are expected from proper operation and
maintenance of the Main Flare.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 33 Table 7-6: VOC Ec onomic 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 emi ssions 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 us ing air-assist technology; (2) complying with a net heating value air assi st dilution parameter of greater than or equal to 24.4 BTU/ft 2 to ensure complete combustion in the flare; (3) following the manufacturer’s specificatio ns for the flare to ensure complete combustion in the flare; (4) operating and maintaining the flare in acco rdance 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 C onsent Decree into the PSD permit).McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 34 

### 8. AIR QUALITY IMPACTS ANALYSIS

The Consent Decree requires the owner or operator of the MCU F acility, Resolute, to submit a PSD application that includes an air quality analysis for SO 2 , CO, NO x , and VOC in accordance with 40 CFR § 52.21. Under Clean Air Act secti on 165 and EPA’s PSD regul ations at 40 CFR § 52.21, Resolute must demonstrate, using air quality models, that the Facility’s emissions of SO 2 , CO, NO x , and VOC will not cause or c ontribute to a violation of (1) the applicable NAAQS, or (2) the applicable PSD increments (explained be low 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 Facil ity’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 I NTRODUCTION

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 anal ysis demonstrating that the facility’s emissions of the PSD-re gulated air pollutants will not cause or contribute to a violation of the applicable NAAQS or applicable PSD in crements. (A PSD incr ement for a pollutant applies only to areas that that are in at tainment with the corresponding NAAQS for that pollutant.) The Applicant provides separate modeling analyses for each criteria pollutant emitted above the applicable sign ificant emission rate. If a prelimin ary 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 po llutant. The cumulative impact analysis includes nearby pollution sour ces 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 th e 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 Qual ity 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 typica lly 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 mode ling are no greater than GEP height , so as to disallow artificial dispersion from the use of overly tall stacks. Th e application may also include initial “load screening,” in which a variety of source operatin g loads and ambient temperatures are modeled, to determine the worst-case scenario for use in the rest of the modeling.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 35 The PSD regulations also require an analysis of the impact on nearby Class I areas, generally those within 100 km, though the re levant Federal Land Manager (FLM) may specify additional or fewer areas. This analysis includes th e 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. Generall y, CALPUFF is the standard model choice for Class I analyses, since it can handle visibility ch emistry as well as the typically large distances (over 50 km) to Class I areas.

Finally, the PSD regulations requ ire an additional impact analys is, showing the Main Flare’s effect on visibility, soils, vegeta tion, 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 compri ses the documents listed in Table 8-1 below. The original PSD Permit applica tion dated March 22, 2007 contained the results of the original modeling. The revised PSD App lication addresses higher BTU c ontent and increased emissions and was submitted in April 2008. Resolute submitted a revised 1-hour SO 2 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 s ubmitted 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
SO 2 Modeling McElmo Creek Unit Oil Production Facility-Main Flare, Gas Compression Facility 1-Hour SO 2 Modeling with AERMOD and accompanying DVD, dated April 2011 (received by EPA on June 3, 2011)

8.2 B ACKGROUND A MBIENT A IR Q UALITY

The PSD regulations require the ai r 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 36 No site or area-specific data was available for southeastern Utah for NO 2 , CO, SO 2 and ozone 21 ; therefore, air quality data gathered from mon itoring stations located in north central Utah, primarily within the Salt Lake City metropolitan ar ea, are used as conservative indicators of air quality for this rural area of Utah. Background PM 10 concentrations are not addressed since

PM 10 emissions are insignificant from a flare, and the Consent Decree does not cite emission
limits for PM 10

.

Table 8-2 below describes the maximum bac kground 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 show n in the table are from 2009-2011 for NO 2 , CO, and ozone. No site or area-specific data wa s available for southeastern Utah for NO 2 , CO and ozone; therefore, except for SO 2 , air quality data gathered from m onitoring stations located in north central Utah, primarily within the Salt Lake City metropolitan ar ea, are used as conservative indicators of air quality for this rural area of Ut ah. Available SO 2 data from Shiprock (Farmington, New Mexico) are more representati ve 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 consid ered a contributor to th e formation of ozone.

Table 8-2: Maximum Background Concentrations and NAAQS NAAQS pollutant & averaging time Background Concentration, μg/m 3 NAAQS, μg/m 3

NO 2 , 1-hour 103.4 (55 ppb) 188 (100 ppb)

NO 2 , annual 34 (18 ppb) 100 (53 ppb)

SO 2 , 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 NO 2 1-hr value is 98 th percentile averaged over three years rather than maximum;
The SO 2 1-hr value is 99 th percentile averaged over three years rather than maximum

8.3 M ODELING M ETHODOLOGY FOR C LASS II AREAS

The Applicant modeled the impact of th e 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 incl uded 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 A pplication (April 2011 MCU 1-Hour SO 2 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 meteorologica l data processing.
This is in accordance with the default r ecommendations in EPA’ s GAQM, Section 4.2.2 on

21 NO
x and VOC are precursors to ozone formation.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 37 Refined Analytical Techniques. SCREEN was also used in earlier the earlier modeling
submittals.

8.3.2 Meteorology model inputs

AERMOD requires representative mete orological data in order to a ccurately simulate air quality impacts. Resolute used surface meteorological data collected for a five consecutive-year period (2005-2009) at the Canyonlands Airport meteorologi cal station near Moab, Utah, northwest of
the Main Flare site. This stat ion is located approximately 105 m iles (170 km) from the t site. Utah processed the data using EPA’s AERMET da ta processor, and provi ded the data to the Applicant. EPA concurs that the chosen Canyonla nds Airport data is the most representative for the Main Flare analysis.

For upper air data, the Applicant obtained conc urrent 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 da ta complete enough to use. No other upper air meteorological monitoring stations are located cl oser to the Main Flar e site. (MCU 1-hour SO 2 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 arra y of 44 discrete meteorological conditions internally generated by SCREEN3 was used to estimate potential worst-ca se short-term (i.e., one-hour averaged) impacts fo r 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 fact ors 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 ch oice of rural versus urban algorithm within AERMOD; and 3) via speci fic values of AERMET parameters that affect turbulence and dispersion, namely surface roughn ess 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 magnit ude of mechanical turbulence. The Bowen ratio is an indicator
of surface moisture. The albedo is the fraction of total incident solar ra diation reflected by the surface back to space without absorption.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 38 AERMAP is a terrain preprocessor that uses Digital Elevation Mode l (DEM) or National Elevation Dataset (NED) electronic files, which are readily available onlin e, 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 paramete r. The hill profile parameter is used in determining plume flow around elev ated terrain. Source elevati on and receptor elevations and hill heights were determined th rough AERMAP using NED files.

Reolute determined surface parameters in cluding the surface roughness length, albedo, and Bowen ratio for the area surrounding the Canyonla nds Airport meteorological tower using the AERMET preprocessor, AERSURFACE (Ver sion 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 geogr aphic locations at which the m odel estimates concentrations. The Applicant places the receptors such that they have good area cove rage and are closely spaced enough so that the maximum model concen trations 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 kno wledge 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 ha s access, and that are not insi de the project fence line.

Discrete receptors in UTM Zone 12 NAD83 coor dinates 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 esti mated by assuming that the maximum volume of process gas that could be generate d from the well field woul d be sent to the flar e at four different heat content values (in BTU/scf). These four h eat content values represent a range of estimatesMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 39 including the lowest allowable LHV, the lowest LHV from 2004 gas analyses, the lowest LHV from 2005-2008 gas analyses and the highest LH V 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 th at it would provide the least am ount of heat rise , thus producing the lowest effective release height. The lowe st 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 em ission rate/effective release hei ght 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 SO 2 modeling, Table 5-3

Table 8-4: Load Screening for Main Flare

Operating Mode NO
x (g/s) SO 2 (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 SO 2 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 woul d be during an upset episode when all process gas is sent to the flare, rath er than re-injected into the gr ound. Thus, modeled flare stack parameters were adjusted to reflect the instanta neous nature of heat release characteristics of a flare when combusting all process gas rather than re-injecting for i nput to AERMOD. The algorithm for this characterization is base d on the Texas Commission on Environmental Quality’s “Technical Basis for Flare Parameters” (September 10, 2004). An effective stack
diameter at an assumed stack ve locity of 20 m/s at the estimate d heat release (in calories per second) of the flare is estimated. An effective st ack height is estimated based on heat release and the physical stack height of the fl are. The actual flare stack height of 195 feet was field verified to ensure proper stack height.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 40 8.4 N ATIONAL A MBIENT A IR Q UALITY S TANDARDS (NAAQS) AND PSD C LASS II
I NCREMENT C ONSUMPTION A NALYSIS

8.4.1 Pollutants with Significant Emissions

The PSD regulations require an ai r quality impact analysis for each PSD-regulated pollutant (for which there is a NAAQS) that a major source ha s the potential to emit in a significant amount,

i.e. , an amount greater than the Si gnificant Emission Rate for th e pollutant. Applicable MCU Facility emissions and the Signi ficant 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 NO x in significant amounts. However, based on the estimates submitted by the applicant, EPA expects the MCU Facility to
emit SO 2 and VOC in significant amounts. Therefor e, this permit action triggers air impact analyses for CO, NO 2 and SO 2

.

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
NO
x 13.4 40 No
SO 2 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 SO 2 , 1,015.4 tpy of CO, and 118.5 tpy of NO x . These very conservative worst-case c onditions result in emission rates in theanalysis that are at least five times greater than current air permit limits. Even with these worstcase emission estimates that far exceed the cu rrent air permit limits and actual flow rate conditions, the modeling results show no exceed ances of the NAAQS or the PSD Class II
Increments.

8.4.2 Preliminary Analysis: Project-Only Impacts

EPA has established Significant Impact Levels (SIL s) 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 consid ered 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-on ly analysis based on maximum operations for the Main Flare. The worst case s hort-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 resultsMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 41 to predict annual, 24-hour and 3-hour SO 2 impacts. Resolute performed 1-hour SO 2 modeling
with AERMOD. EPA determined 1-hour NO 2 and 1-hour and 8-hour CO impacts from the SO 2 AERMOD results by taking the ratio of the NO 2 and SO 2 emissions for various cases, including the worst case. EPA compared the ratio with the predicted SO 2 cumulative impacts from Tables 6-1 and 6-2 provided in Resolute’s April 2008 PSD application submittal for 1-hour SO 2 Modeling. The only significant impacts predic ted by the modeling results was for 1-hour SO 2

.

Table 8-6: Main Flare Significant Impacts NAAQS Pollutant & Averaging Time Project-Only Modeled Impact, μ g/m 3 Significant Impact Level (SIL), μ g/m 3 Project impact significant?
NO 2 , 1-hour 5.0 7.5 (4 ppb) No
NO 2 , Annual 0.15 1 No
SO 2 , 1-hour 11.6 7.9 (3 ppb) Yes
SO 2 , 3-hour 11.6 25 No
SO 2 , 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 SO 2 Modeling, Sections 5 and 6

8.4.3 Cumulative Impact Analysis

A cumulative NAAQS or PSD increment impact anal ysis 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 bac kground concentration to represent those sour ces 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 SO 2 NAAQS.

PSD increments are limits on cumulative air quality degradation. They are se t 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 NO 2 and SO 2 . However, there have been no increments established for 1-hour NO 2 and SO 2

. For demonstrating compliance with the PSD incr ement, 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 w ith 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, th ere may be a large numb er of sources that could potentially be included, so judgment must be applied to exclude small and/or distant sources that have only a negligib le contribution to total concentr ations. 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)McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 42 The Utah Department of Air Quality (UDAQ) and the Colorado Air Pollution Control Division (CAPCD) provided a list of all stationary sour ces within 50 km of the MCU Facility’s Main Flare (approximate distance to the farthest significant impact plus 50 km) for SO 2 . A comprehensive procedure was used to determine which sources were included in the emissions inventory.

It should be noted that short-term maximum emi ssion rates rather than annual emission rates determine the distance over which a facility mi ght have a significant impact for short-term standards ( e.g. , hourly NO 2 ). Peak rates that occur with flare heat content of 300 BTU/scf determine the MCU Facility’s Main Flare significant impact area for hourly SO 2 . The applicant identified eight facilities nearby for inclus ion in the emission inve ntory for the 1-hour SO 2 cumulative analysis, based on data from Utah and Colorado.

Current EPA SO 2 guidance suggests that emphasis on de termining which nearby sources to include in the nearby source inventory should focu s on the area within about 10 km of the MCU Facility’s Main Flare location in most cases, whic h 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 NO 2 -Specific Considerations

While the new 1-hour NO 2 NAAQS is defined relative to ambient concentrations of NO 2 , the majority of NO x emissions from stationary sources are in the form of nitric oxide (NO) rather
than NO 2 . Appendix W notes that the impact of an individual source on ambient NO 2 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 NO x chemistry plays in determining ambient impact levels of NO 2 based on modeled NO x emissions, Section 5.2.4 of Appendix W recommends a three-tiered screening approach for NO 2 modeling. Later guidance documents issued by EPA expand on this approach. Tier 1 assumes full conversion of NO to NO 2 . Tiers 2 and 3 are refinements of the
amount of conversion of NO to NO 2 . The applicant and EPA used the Tier 1 approach, in which
the 1-hour NO 2 and annual impacts are based on the assumption that all of the NO is converted
to NO 2

.

8.4.3.3 Results of the Cumulative Impacts Analysis

The results of the PSD cumulative impacts analys is for the MCU Facility’s worst case operations
for SO 2 emissions are shown in Table 8-6. The anal ysis demonstrates that emissions from the MCU Facility’s Main Flare will not cause or co ntribute to exceedances of the NAAQS or for any

22 See “Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO 2 National Ambient Air Quality Standard”, Memorandum fro m Tyler Fox, EPA Air Quality Modeling Group to EPA Regional Air Division Directors, March 1, 2011, page 16McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 43 applicable PSD increments. The background concen trations 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 NO 2 , and for annual, 24-hour and 3-hour SO 2 ; therefore, a cumulative impacts analysis was not required to demonstrate compliance for these pollutants and averaging times.

EPA also considered additional information to en sure 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 in clusion/exclusion, in the cumulative impacts modeling above. EPA concluded that these s ources 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 Complian ce with Class II PSD Increments and NAAQS NAAQS pollutant &

averaging
time All Sources
Modeled Impact (ug/m 3 ) PSD
Increment Consumption (ug/m 3 ) Background
Concentration (ug/m 3 ) Cumulative impact w/ background (ug/m 3 ) NAAQS (ug/m 3 ) PSD
Increment

(ug/m 3 )

SO 2 , 1-hour 26.76 N/A 79 105.76 196 None

Source: April 2011 MCU 1-Hour SO 2 Modeling, Tables 6-1 and 6-2 Note: There are currently no PSD increments defined for 1-hour SO 2

8.5 C LASS I A REA A NALYSIS

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 Wa rner 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 Anal ysis is required. This approach, which only applies to projects located more than 50 km from a Class I ar ea, requires adding all of the visibility-related emissions (SO 2 , NOx, PM 10 and sulfuric acid mist) from a project (based on 24- hour maximum allowable emissions expressed in un its of tons per year) and dividing the sum by the distance between the project and the nearest Cl ass I area, which is Mesa Verde 60 km away. The values input into the table ar e the maximum. If th e result is less than 10, the project is presumed to have negligible impacts to Cla ss I AQRVs. The table below shows that theMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 44 project’s emissions are well belo w the FLAG screening cr iteria. Therefore, no further Class I AQRV analysis is required.

Table 8-8 : Summary of Q/D Analysis

Parameter Value
NO
x Emission Increase 13.4 tpy
SO 2 Emission Increase 60 tpy

PM 10 Emission Increase --

H 2 SO 4 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 NO 2 and annual,
24-hour and 3-hour SO 2 was included in the original ap plication submitted in 2008. Based on the results, EPA did not require updated modeli ng to be submitted with the 2011 PSD application because of the very low predicted impacts by S CREEN. The results are presented in Table 8-9
below.

NO 2 and SO 2 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 PM 10 or NO 2

.

Table 8-9: MCU Facility Main Flare Cla ss 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 NO 2 Annual 0.0102 2.5

SO 2 Annual 0.03 2
24-hour 0.90 5
3-hour 2.01 25 Source: April 2008 Revised PSD Application, Table 7-6McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 45 

### 9. ADDITIONAL IMPACT ANALYSIS

In addition to assessing the ambient air quality impacts expected from a source subject to PSD review, the PSD regulations requ ire that EPA evaluate other pot ential impacts on 1) soils and vegetation; 2) growth; and 3) visibility impairment. 40 CF R § 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 visibi lity in the source's impact area.

9.1 S OILS AND V EGETATION

The additional impact analysis includes consideration of potentia l impacts to soils and vegetation
associated with the MCU’s emissions. This component generally includes:

 A screening analysis to determine if maxi mum modeled ground-leve l concentrations of pollutants from the Main Flare coul d have an impact on plants; and

 A discussion of soils and vegetation that ma y be affected by proposed emissions from the Main Flare and the potential impacts on such soils and vegetation a ssociated 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. Th e MCU Facility is an oilfield operation, which is primarily involved in crude pe troleum and natural gas extracti on. The Applicant presented its discussion of the potential impacts on soils a nd vegetation in its supplemental PSD permit application submitted to EPA Region 9 in Fe bruary 2013. Ground cover is relatively sparse
because of the semiarid climatic conditions su rrounding the site. Vegetation in San Juan County includes woodlands, dominated by Pinyon Pine and Ut ah 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 informa tion is provided in Table 9-1.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 46 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 slick r ock, hi g her elevations in Aba j o 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 mi xed 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 Cutle r Formation, warm/sal t deser t shrub: 4,000 - 4,600 ft. elev. Source: Table 7-8 of the supplemental PSD permit app lication submitted to EPA Region 9 on February 20, 2013

The values in Table 9-2 below a nd Table 8-5 of this document provide the concentration impacts used below in EPA’s “Screening Procedure for th e Impacts of Air Pollution Sources on Plants, Soils and Animals” (1980) 23 to determine if maximum modele d ground-level concentrations of
SO 2 , NO 2 and CO from the main flare could have an impact on plants, soils, and animals.

23 “ Screening Procedure for the Impacts of Air Pollution Sour ces on Plants, Soils, and An imals,” EPA 450/2-81-078,
December 1980.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 47 Table 9-2: Screening Ambient Air Concentrat ions for Sensitive Vegetation Exposure

Pollutant 1-hour (μg/m 3 ) 3-hour (μg/m 3 ) 4-hour (μg/m 3 ) 8-hour (μg/m 3 ) 1-week (μg/m 3 ) 1-month (μg/m 3 ) Annual (μg/m 3 )

SO 2 9 7

-- -- -- -- 18

NO 2

-- -- 3760 3760

-- 564 94

CO

-- -- -- -- 1,800,000

-- -- Source: Table 7-9 of the supplemental PSD permit app lication submitted to EPA Region 9 on February 20, 2013

The modeled impacts of SO 2 , NO 2 , and CO emissions from the Main Flare range from below one percent to five percent of the minimum impact le vels/screening concentrations identified in this Screening Procedure.

Table 9-3: Maximum Concentrations & Scr eening Concentrations for Ambient Exposures

Criteria Pollutant and Guidance Averaging Time EPA Screening
Concentration (μg/m 3 ) Modeled Maximum
Concentrations (μg/m 3 ) Modeling Averaging time

SO 2 1-Hour 917 11.6 1 hour

SO 2 3-Hours 786 (0.30 ppm) 11.6 (0.0045 ppm) 3 hour

SO 2 Annual 18 0.93 Annual

NO 2 4-Hours 3,760 5.0 1 hour

NO 2 8-Hours 3,760 5.0 1 hour

NO 2 1-Month 564 5.0 1 hour

NO 2 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 in formation, we do not believe that emissions associated with the MCU Facility will generally result in adve rse impacts to soils or vegetation.

9.2 V ISIBILITY I MPAIRMENT

The additional impact analysis also evaluate s 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 sens itive 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 48 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 m iles), as presented in Section 8.5.1. For Class II areas, the Applicant eval uated both Level I and Level II VISCREEN screening analyses for visibil ity impairment for five diffe rent 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 pred icted 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 purpo ses 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 ove r the Class I threshold levels in a Class I area. A Level-3 analysis is no longer considered a screening anal ysis 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 th e emission rates for the flare.

9.3 G ROWTH

The growth component of the additional impact analysis involves a discussion of general commercial, residential, industrial, and other gr owth associated with the MCU Facility. This analysis considers emissions generated by growth th at will occur in the area due to the source. In conducting this review, we fo cus 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 use d. Although there has been an increase in the number of full-time employees, no significant growth is expected for this Facility.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 49 

### 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, EP A is required to ensure that any action authorized, funded, or carried out by EPA is not likely to jeopardi ze the continued existence of any endangered or threatened spec ies 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. Howeve r, 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 Re gion 9’s action does not authorize any new construction or modification of existing equipmen t 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 Fi sh 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, pr ior 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 undertak ings on historic properties and afford the Advisory Council on Historic Preservation (Council) a reasonable opportunity to co mment with regard to such undertakings. Consultation is required for all unde rtakings that have th e potential to affect historic properties. Section 106 consultations assess whether histor ic properties exist within an undertaking’s area of potential eff ect and, if so, whether the unde rtaking will adversely affect such properties. The term “historic properties” means prehistoric or historic districts, sites, buildings, structures, or objects incl uded in, or eligible for inclus ion in, the National Register of Historic Places maintained by the Department of the Interior. Histor ic properties include properties of traditional religious and cultural importance to an Indian Tribe or Native Hawaiian organization. Consultation is generally with re levant state and tribal historic preservation
authorities in the first instan ce, with opportunities for direct Council involvement in certain
circumstances.

EPA’s action, which is for the issu ance 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 operatio n since the 1990s. The EPA’s permit action is to incorporate the federal Consent Decree requiremen ts 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 Faci lity. EPA is currently consulting with the
Tribal Historic Preservation O fficers for the Navajo Nation and Ute Mountain Indian tribes.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 50 

### 12. MAGNUSON-STEVENS FISH ERY CONSERVATION AND
MANAGEMENT ACT

The Magnuson-Stevens Fishery Conservati on 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 Fisher ies Service (NMFS), and its appointed regional fishery management councils. Because the MCU Facility is locat ed on the Navajo Nation Indian Reservation in Utah, which is not located near any coastal or te rritorial 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 MA NAGEMENT ACT

The Coastal Zone Management Act (CZMA) of 1972 provides for management of the nation’s coastal resources, incl uding the Great Lakes. It encourages states to preserve , protect, develop, and where possible, restore or enhance valuable natural coastal resour ces such as wetlands, floodplains, estuaries, beaches, dunes, barrier isla nds, 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 a nd 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, coveri ng areas bordering the Atlantic, Pacific, and Arctic Oceans, the Gu lf of Mexico, Long Is land 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 JUST ICE 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 environmenta l justice part of its mission by identifying and addressing, as appropriate, disproportionately hi gh and adverse human health or environmental effects of its programs, policies, and activitie s 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 lo w-income populations pote ntially affected by its proposed action on the MCU Facility PSD permit app lication, and determined that it would be appropriate to prepare an Envi ronmental Justice Analysis for this action. EPA prepared an Environmental Justice Analysis, which is incl uded in the administra tive 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 qual ity levels in excess of health standards for the pollutants regulated under the proposed PSD permit amendment; th erefore, 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.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 51 

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

The Applicant must apply for and obtain a T itle 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 P UBLIC C OMMENTS

The comment period for EPA’s proposed PSD permit amendment for the MCU Facility begins on November 15, 2014. Any interested person ma y submit written comments. All written comments on EPA’s proposed action must be re ceived by EPA via email or postmarked by November 20, 2014. An extension of the comment period ma y 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, in cluding such matters as:

 BACT determinations for the Main Flare;

 The effects, if any, on Class I areas;

 The effect of the proposed facili ty on ambient air quality; and

 The attainment and maintenance of the NAAQS.

16.2 P UBLIC I NFORMATION M EETING & P UBLIC H EARING

EPA will hold a Public Information Meeting for th e purpose of providing interested parties with additional information and an opportunity for info rmal discussion of the proposed PSD permit.

Immediately following the Public Informati on 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 Heari ng, any interested person may provide writtenMcElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 52 comments or oral comments, in English or Diné, and relevant data pertaining to the proposed permit amendment. The date, time, and locati on 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 pr ovided at each Public Information Meeting and Public Hearing. If you require a reasonable accommodation, pleas e contact Philip Kum, EPA Region 9 Reasonable Accommodations Coordinato r, by October 31, 2014 at (415) 947-3566, or kum.philip@epa.gov

.

16.3 A VAILABILITY OF P ERMIT D OCUMENTS

All information submitted by the Applicant is availa ble 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 ar e available on the EPA Region 9 website at http://www.epa.gov/region09/air/perm it/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 reco rd 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 AAQI R/Fact Sheet are available for review and inspection at the Navajo Nation Environmen tal 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, Sw eetwater, AZ, (928) 429-0977

 Dennehotso Chapter, Dennehotso, AZ, (928) 658-3300McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 53 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, Montic ello, UT, (435) 587-2281

 Blanding Library, Blanding, UT, (435) 678-2335

 Montezuma Creek Library, Mont ezuma 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 persona l information provided, unless the comment includes Confidential Business Information (CBI) or other information whose disclosure is restricted by statute. Information that you consid er CBI or otherwise prot ected should be clearly
identified as such and should not be submitted th rough e-mail. If you send e-mail directly to the EPA, your e-mail address will be automatically ca ptured and included as part of the public comment. Please note that an e-mail or postal address must be provide d with your comments if you wish to receive direct not ification of EPA’s final deci sion regarding the permit.

EPA will consider all written comments subm itted during the public comment period before taking final action on the PSD pe rmit 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 F INAL P ERMIT D ECISION

Before taking final action, EPA Region 9 will cons ider all written and oral comments submitted during the public comment peri od, including those provided at th e 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) request s notice of the final permit decision. EPA will
summarize the contents of all substantive co mments 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 sp ecified in the decision; or
2. The decision is appealed to EPA’s Envi ronmental 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 ef fective immediat ely upon issuance.McElmo Creek Unit Oil Production Faci lity (PSD Permit No. NU 05-01) Ambient Air Quality Impact Report & Fact Sheet
October 2014 Page 54 16.5 C ONTACT I NFORMATION

If you have questions, would like to be added to our mailing list to receive future information about this proposed permit decision, or othe r 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/pe rmit/psd-public-guidelines.html

. Shaheerah Kelly can also be reached through EP A 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 th is 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 amendm ent and this AAQIR/Fact Sheet to the public for review, and make a final decision after c onsidering any public comments on our proposal.