# RECEIVED
OCT 0 ~ 2OO~ Permits 

### OftJ~e Air-3 

### U.S. EPA Region 9 

## PREVENTION OF SIGNIFICANT DETERIORATION PERMIT APPLICATION

EXXONMOBIL CORPORATION
McELMO CREEK UNIT OIL PRODUCTION FACILITY

- 

## MAIN FLARE, GAS COMPRESSION FACILITY

Revised August, 2006

Prepared for:
ExxonMobil Corporation 14950 Heathrow Forest Parkway Houston, TX 77032

Prepared by:
McVehil-Monnett Associates, Inc. 44 Inverness Drive East Building C Englewood, Colorado 80112

MMA Project Number 1814-04TABLE OF CONTENTS

Page No. in Section 1.0 INTRODUCTION 1 1.1 GENERAL INFORMATION 1 1.2 PERMIT APPLICATION FORM 2 2.0 PROJECT DESCRIPTION 1 2.1 FACILITY AIR QUALITY PERMIT HISTORY 1 2.2 EXISTING FACILITY OPERATIONS 2 2.3 MODIFICATION 3 2.4 MAIN FLARE REGULATORY REQUIREMENTS 3 2.4.1 New Source Review 3 2.4.2 Consent Decree Requirements 4 2.4.3 New Source Performance Standards (NSPS) and National Emission

Standards for Hazardous Air Pollutants (NESHAP) 4 2.4.4 Other Air Quality Requirements 5 2.4.5 Title V Requirements 5 3.0 MAIN FLARE EMISSIONS 1 3.1 CRITERIA POLLUTANTS 2 4.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS 1 4.1 ALTERNATIVE CONTROLS FOR FLARE 2 4.1.1 Volatile Organic Compounds (VOCs) 2 4.1.2 Carbon Monoxide (CO) 5 4.1.3 Nitrogen Oxides (NO~) 6 4.1.4 Sulfur Dioxide (SO2) 8 4.2 COMPRESSOR ENGINE MODIFICATIONS 9 4.2.1 Past Flaring Due to Compressor Downtime 9 4.2.2 Options to Improve Reliability of HOS-6 Compressor Engine Operations 10 4.2.3 Other Compression Changes 12 4.3 FLARE GAS RECOVERY SYSTEMS 13 4.4 OPERATION & MAINTENANCE (O&M) PLAN 14 5.0 EXISTING ENVIRONMENT 1 5.1 TOPOGRAPHY 1 5.2 AIR QUALITY 1 5.3 AREA CLIMATE AND METEOROLOGY 2 5.4 SOILS AND VEGETATION 4 6.0 IMPACT ASSESSMENT APPROACH 1 6.1 AIR QUALITY MODEL DESCRIPTION 2 6.2 MODEL INPUT 3 6.3 METEOROLOGICAL DATA 3 6.4 SOURCE CHARACTERISTICS AND EMISSION RATES 4 6.4.1 Flare Rate and Heat Release 46.4.2 Flare Height 5

6.4.3 Modeled Emission Rates 5 6.5 RECEPTOR SELECTION 6 6.6 CLASS I AREA IMPACTS 6 6.7 ADDITIONAL IMPACT ANALYSIS 7 6.8 ENDANGERED SPECIES 7 7.0 AIR QUALITY IMPACTS 1 7.1 NITROGEN DIOXIDE (NO2) 2 7.1.1 Increment Consumption 2 7.1.2 National Ambient Air Quality Standards (NAAQS) 3 7.2 SULFUR DIOXIDE (SO2) 3 7.2.1 Increment Consumption 4 7.2.2 National Ambient Air Quality Standards (NAAQS) 4 7.3 CARBON MONOXIDE (CO) 5 7.3.1 National Ambient Air Quality Standards (NAAQS) 5 7.4 CLASS I AREA IMPACTS 6 7.4.1 Class I Increments 7 7.4.2 Visibility 7 7.4.3 Deposition 8 8.0 REFERENCES 1

LIST OF TABLES
TABLE 3-1 PRE-PROJECT & POST-PROJECT ACTUAL & PTE EMISSIONS TABLE 3-2 MAIN FLARE CRITERIA POLLUTANT EMISSION LIMITS TABLE 4-1 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY -VOC TABLE 4-2 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY -CO TABLE 4-3 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY -NOx TABLE 4-4 BACT/LAER CLEARINGHOUSE DATABASE SUMMARY

- SO2 TABLE 4-5a McELMO GAS COMPRESSION FACILITY

- CHANGE HOS-6

COMPRESSOR PROCESS CAPITAL COST SUMMARY TABLE 4-5b McELMO GAS COMPRESSION FACILITY

- CHANGE HOS-6

COMPRESSOR PROCESS OPERATING COST SUMMARY TABLE 4-6a McELMO GAS COMPRESSION FACILITY

- REPLACE HOS-6

COMPRESSOR CAPITAL COST SUMMARY TABLE 4-6b McELMO GAS COMPRESSION FACILITY

- REPLACE HOS-6

COMPRESSOR OPERATING COST SUMMARY TABLE 4-7a McELMO GAS COMPRESSION FACILITY

- FLARE GAS

RECOVERY SYSTEM CAPITAL COST SUMMARY TABLE 4-7b McELMO GAS COMPRESSION FACILITY

- FLARE GAS

RECOVERY SYSTEM OPERATING COST SUMMARY TABLE 5-1 AIR QUALITY IN THE MCELMO CREEK AREATABLE 5-2 JOINT FREQUENCY DISTRIBUTION OF BLANDING, UTAH

TABLE 5-3 ANNUAL STABILITY CLASS DISTRIBUTION AT BLANDING,UT TABLE 5-4 MONTHLY AVERAGE TEMPERATURE & TOTAL PRECIPITATION TABLE 6-1 SUMMARY OF NATIONAL AMBIENT AIR QUALITY STANDARDS

& PSD INCREMENTS TABLE 6-2 SCREEN3 MODELED STACK PARAMETERS & EMISSIONS FOR

THE MAIN FLARE TABLE 7-1 COMPARISON OF MODELED MAIN FLARE NO2 IMPACTS TO THE

PSD INCREMENTS TABLE 7-2 COMPARISON OF MODELED CUMULATIVE NO2 IMPACTS TO

THE NAAQS TABLE 7-3 COMPARISON OF MODELED MAIN FLARE SO2 IMPACTS TO THE

PSD INCREMENTS TABLE 7-4 COMPARISON OF MODELED CUMULATIVE SO2 IMPACTS TO

THE NAAQS TABLE 7-5 COMPARISON OF MODELED CUMULATIVE CO IMPACTS TO

THE NAAQS TABLE 7-6 CLASS I AREA AMBIENT AIR IMPACTS TABLE 7-7 CLASS I AREA DEPOSITION IMPACTS

LIST OF FIGURES
FIGURE 2-1 LOCATION MAP OF McELMO CREEK OIL PRODUCTION FACILITY FIGURE 2-2 FLOW DIAGRAM OF EXISTING GATHERING SYSTEM OPERATIONS FIGURE 2-3 BLOCK FLOW DIAGRAM OF GAS COMPRESSION PLANT FIGURE 5-1 WIND ROSE OF 2004 BLANDING, UTAH METEOROLOGICAL DATA

LIST OF APPENDICES
APPENDIX A EXXONMOBIL MCELMO CREEK OIL PRODUCTION UNIT

CONSENT DECREE APPENDIX B DERIVATION OF ESTIMATED PRE-PROJECT AND POST-PROJECT

ACTUAL AND POTENTIAL TO EMIT EMISSIONS APPENDIX C SCREEN3 MODELING INPUT AND OUTPUT RESULTS APPENDIX D E-MAILS FROM MR. JOHN NOTAR of the NATIONAL PARK

SERVICE and MR. HENRY MADDUX, UTAH ENDANGERED SPECIES SUPERVISOR APPENDIX B SCREEN3 AND VISCREEN PRINT-OUTS FOR CLASS I AREA

IMPACTS

1111.0 INTRODUCTION

1.1 GENERAL INFORMATION

ExxonMobil Corporation (ExxoriMobil) is submitting this revised Prevention of Significant Deterioration (PSD) permit application for the Main Flare at the McElmo Creek Oil Production Facility, located on the Navajo Nation near Aneth, Utah, in order to meet the terms of its Consent Decree (DOJ Case No. 90-5-2-1-2237, filed June 8, 2005) with the U.S. Environmental Protection Agency (US EPA). No modification is proposed with this permit application. ExxonMobil installed an automatic air-assisted system on the Main Flare on May 8 12, 2006, pursuant to the provisions of 40 CFR 

## § 60.18 (c)(5) and (0(6), as required in Paragraph 11 .b of its Consent Decree.

This PSD permit application document presents a facility process description for existing operations, criteria pollutant permit emission limits for the Main Flare, a Best Available Control Technology (BACT) analysis for the Main Flare, air modeling methodology, and air modeling results. Impacts are evaluated in both Class I and II areas.

This permit application contains information submitted on December 5, 2005 with revisions intended to respond to EPA Region IX comments in their letter of May 22, 2006. Specific additions/revisions to the application document submitted on December 5, 2005 in response to EPA Region IX comments include:

1. Emissions Data: Pre- and post-project actual and potential to emit emissions have been estimated and summarized in Section 3.0. Appendix B contains detailed emission calculations and fuel gas compositions used to provide these estimates.

2. BACT Analysis: The Top-Down BACT analysis presented in Section 4.0 has been expanded to consider technologies, work practices or operational standards limiting gas flow to the flare. Reductions in flaring occurrence (Section 4.3) as well as changes to compressor operation (Section 4.2) intended to increase its efficiency are also addressed. Selection or non-selection of these options as BACT has been further supported by a cost effectiveness analysis (Tables 4-5 thru 4-7) consistent with Top-Down BACT.3. Class I Analysis: The approach to analyzing Class I area impacts are presented in

Sections 6.6 and an assessment of Class I impacts are presented in Section 7.4. As directed by EPA, Mr. John Notar of the National Park Service was contacted for his input
on the nature of the Class I area evaluation.

4. Additional Impacts Analysis: Consideration of additional impacts associated with operation of the flare from potential growth, on soils and vegetation and on visibility is provided in Section 6.7.

5. Endangered Species Analysis: The approach and assessment of potential effects from the flare on listed endangered species and on critical habitat within the region surrounding the project site are presented in Section 6.8. As directed by EPA, Mr. Henry Maddux, Utah Endangered Species Supervisor, was contacted for his input on the nature of the evaluation needed for the project area.

1.2 PERMIT APPLICATION FORM

A completed permit application form providing information on the existing facility, including the Main Flare, is attached at the end of this section. Flare specification sheets are attached after the permit application form to provide information on flare manufacturer and model.

Effective April 14, 2006, ExxonMobil sold the McElmo Creek Unit Oil Production Facility to Resolute Natural Resources Company (Resolute) and the Navajo Nation Oil and Gas Company. Resolute assumed operation of the McElmo Creek Unit Oil Production Facility, as well as responsibility for complying with the terms of the PSD permit and the above referenced Consent Decree on June 1, 2006. The current owner’s name and address for the McElmo Creek Oil Production Facility is:

Resolute Natural Resources Company 1675 Broadway, Suite 1950 Denver, CO 80202 Phone 303-534-4600

1-2PSD Permit Application Form Page] of 4

i’’~’~b ~ ~ ~i4~

~ V

~ ~ ~-~General,~Information~

~. ~ 4 .L Company Name and Address: Company Contact for Environmental Matters: Mobil Exploration and Producing U.S. Inc. Neil J. Ryan, OIMS Supervisor CORP-WGR- 1260 CORP-MI-4024 396 West Greens Road 14950 Heathrow Forest Pkwy Houston, TX 77067 Houston, TX 77032 Phone No.: 713-431-1444 Phone No.: 281-654-1042 FaxNo.: 713-431-1050 FaxNo.: 281-654-1183 Facility Name and Address: Owners Name and Address: McElmo Creek Unit Oil Production Facility (Sold to Resolute Natural Resources Co. on 4/14/06) 23429 County Road G Mobil Exploration and Producing U.S. Inc. Cortez, CO 81321 CORP-WGR-1260 396 West Greens Road Phone No.: 970-564-5210 Houston, TX 77067 Fax No.: 970-564-5234 Phone No.: 713-431-1444 Fax No.: 713-431-1050 County where facility is located: Latitude and Longitude or UTM coordinates: San Juan 370 15’ 37.58” N 109° 12’ 12.07” W

Directions to facility (street address and/or directions to site): From Cortez Airport, take Hwy 160 South for 30 miles. Turn right (heading Northwest) on CO 41 to Utah. CO 41 turns into UT 262 at the state line. Continue on UT 262 for 14 miles, through the town of Aneth. Turn Right at the ExxonMobil sign and follow the road 3.1 miles to the office. The office is on the left and the gas compression plant is on the right. List current air quality permits for facility: U.S. EPA Region VIII PSD Permit 8AT-AP (last amended April 18, 1991)

If request for a modification, identify permit # to be modified: Permit No.: 8AT-AP Dated: April 18, 1991 Type of business at this facility: Oil & Gas Production Are the total number of company employees greater Standard Industrial Code Classification: 1311 than 100? Yes Application for:

— New construction _Modification XExisting equipment operating without permit

— Permanent site for portable equipment

— Change of permit condition

— Change of location

For new construction or modification, enter estimated start date: Flare upgrade completed on May 8-12, 2006 estimated completion date: For change of permittee, location, or condition, enter For existing equipment in operation without prior date of occurrence: N/A permit, enter initial operation date: 1991PSD Permit Application Form Page 2of4

Process Information Name of process: Oil & Gas Production; Gas End product of this process: Oil Dehydration and Compression; C02 and Water Injection Primary process equipment: Dehydration System, Compressors, and Flare

Maximum Operating Schedule: Percent annual production by quarter: ~hours/day Winter 25% Spring ~ 7days/week Summer Z~2~ Fall ~ ~2..weeks/year Daily production rates: Maximum annual production: Average: 3,700 bopd 1,825,000 bbls of oil Maximum: 5,000 bopd Projected percent annual increase in production: N/A Type of operation: ~Continuous If batch, indicate minutes per cycle: 

### ~

_Batch Minutes between cycles: WA _Intermittent Materials used in process: (1) raw material, (2) principal use, and (3) amounts: 3,700 bbls of oil produced (hop) and sold each day on average from the tank batteries 26,000 bbls of water produced (bwp) and injected each day on average 10-18 million cubic feet of gas produced each day on average 6-14 million cubic feet of CO2 is purchased each day to supplement injection to 24 million total cubic feet per dayPSD Permit Application Form Page 3of4

Flare System Information Manufacturer: Zeeco, Inc. completed flare upgrade on May 8-12, 2006; Originally by American Steel and Iron Works Model No: UP 24/26 (See Attached Specification Sheets for More Information) Fuel Minimum Expected Flowrate Design Max Temp °F Pressure (psig)

Waste gas stream: Dehydrated Produced Gas (approx. 70% C02 and 0.05% H2S)

- Up to 14 million cubic feet per day Fuel added to gas stream: N/A

Heat Content of flared gas 3 00-443 BTU/scf Number of pilots: Currently 1 Pilot fuel type: Natural Gas Pilot fuel flow rate, per pilot (scfm 70°F & 14.7 psia): 1.0 Flare height: Currently 195 feet Flare tip inside diameter: 24 inches

Steam Injection NA Steam pressure (psig): NA Minimum expected: NA Design maximum: NA Total steam flowrate (lb/hr): NA Temperature (°F): NA Velocity (ft/sec): NA Number of jet streams: NA Diameter of jet streams (in.): NA

Water Injection: Water pressure (psig): NA Minimum expected: NA Design maximum: NA Total water flowrate (gpm): NA Minimum expected: NA Design maximum: NA Number of water jets: NA Diameter of water jets (in.): NA

Air Assist: Air pressure (psig): Minimum expected: Design maximum: Total air flowrate: See Attached Specification Sheets Velocity (ft/sec): Number of air jets: Diameter of air jets (in.):PSD Permit Application Form Page 4of4

Certification Statement
I certify under penalty of law that I have examined and am familiar with the information submitted in this document and all attachments and that this document and its attachments were prepared either by me personally or under my direction or supervision in a manner designed to ensure that qualified and knowledgeable personnel properly gathered and presented the information contained therein. I further certify, based on my personal knowledge or on my inquiry of those individuals immediately responsible for obtaining the information, that the information is true, accurate, and complete. I am aware that there are significant penalties for submitting false information, including the possibility of fines and im sonment for knowing and willful submission of a materially false state i-~ signatur~~g_L~ Date: 

## 9 ~ cL~

Name (type): Randy J. Cleveland
Title: U.S. Production Manager
Phone: 713-431-1444

### Flare Tip Specification Sheet

Client: ExxonMobil Zeeco Ref.: T4P2OF Date: 18-Aug-05
Location: McElmo Creek, Utah Client Ref.:

-- Rev.
General Information: Tag No.: F-i Model: UF 24/26 Type: Utility Length: 10’- 0” 

# ~ Weight: 926 lbs 

# I

~. No.ofpilots: 2 

# I ~ Design Case: Governing Case: Case I Molecular weight: 38.3 L. H. V.: 401 BTU/SCF Temperature: 120 deg. F Available pressure: 16 psig Design flow rate: 75,711 lbs/hr Approximate exit velocity: 63.7 ft/s Approx. tip press. drop: 0.06 psig

~ (Typical drawing only) Construction: Upper Section: 310 ss Windshield: No Lower Section: Carbon Steel Flame retention Ring: 310 ss Refractory: None Refractory Thk: n/a Surface Finish (Carbon Steel Surfaces): Surface Preparation: SSPC-SP6 Primer: Inorganic Zinc Paint: High Heat Aluminum

Connections: Qty. Size Type Material Ni

- Flare Gas Inlet: 1 24” 150# RFSO Carbon Steel N2

- Pilot Gas Manifold: 1 1 “ FNPT Carbon Steel N3

- Ignition Line: 2 1 “ MNPT Carbon Steel

Miscellaneous Notes: 1. Includes Purge Reducing Integral Velocity Seal. 2. Required Purge Rate 515 SCFH4



### Pre-Mix Flare Pilot Assembly Specification Sheet
Client: ExxonMobil Zeeco Ref.: T4P2OF Date: 18-Aug-05 Location: McElmo Creek, Utah Client Ref.:

-- 

### Rev.

General Information: Tag No.: FP-1 Model: HSLF Length: 9.135 feet Weight: 68 lbs. Pilot Type: Pre-Mix High Stability Ignition Type: FFG Process Design Data: Design Heat Release 65000.00 btu/hr Fuel Gas MW 18.00 Fuel Gas LHV 1.000 btu/scf Fuel Gas Temperature 90.0 F Fuel Gas Inlet Pressure 15.00 psig Fuel Gas Flowrate 65.0 scth Design Wind Velocit: 150 mph Design Rainfall: 10.00 inches/hr Mounting Position: Vertical Thermocouple Type None Construction: Pilot Firing Tip HK Windshield Assembly HK Integral Thermowell HK FFG Ignition Line 310 SS Mounting Brackets: HK Premix Fuel Line 310 SS Thermocouple Sheath N/A Thermocouple Head N/A Fuel Mixer Assembly CF-8 / 18-8 Fuel Strainer Assembly CF-aM HEI Probe and Support: N/A HEI Junction Head N/A Connections: Qty. Size Type Material Cl

- Fuel Gas Inlet 1 1/2” FNPT CF8M C2

- FFG Ignition Inlet 1 1” SW 310 SS C3

- Thermocouple N/A N/A N/A N/A C4—HEI Ignition N/A N/A N/A N/A

Misc. Notes: (see ignition system datasheet for type applicable to this quote) 1. Upper mounting bracket is reinforced hook type for pilot removal from platform 2. Pilot mounting brackets and thermocouple mounting brackets are investment cast assemblies. 3. Pilot mixer assembly is investment cast, high efficiency computer modeled venturi section.2.0 PROJECT DESCRIPTION

This section presents an overview of the McElmo Creek Oil Production Facility, including a summary of the facility’s air permit history, overview of operations including the gas compression plant and the Main Flare, and a review of applicable air quality requirements.

2.1 FACILITY AIR QUALITY PERMIT HISTORY

The McElmo Creek Oil Production Facility is located in San Juan County, Utah near Aneth, Utah in Section 23 of T4OS, R24E on Navajo Nation land. A location map of the facility is presented in Figure 2-1.

The original oil well production facility, owned by Superior Oil, started operations in the 1950s. Mobil Exploration and Producing U.S., Inc. (Mobil) purchased the facility from Superior Oil in 1984. Tn 1986, Mobil constructed a gas processing plant at the facility, including an upright flare, dehydrator, amine treater, refrigeration separation unit, a natural gas liquids recovery unit and compressors to transport the produced liquid natural gas. In 1991, the equipment was switched out with an emergency flare added as a control device for the dehydrators. Petroleum liquid storage tanks and heater treaters were also installed in the early 1 990s. At that time, the emergency flare was not permitted because it was viewed as a control device. All other operations were permitted as required by regulation and have been administered by EPA Region TX. EPA has delegated oversight authority of this facility since it is on tribal land and is assisting the tribe in administering its recently approved regulatory program.

In 1997, following a fire, all processing equipment except for one dehydrator was removed, the compressors were converted to run on electricity, and the flare was kept for emergency flaring, flaring closed drain system fumes, and control of dehydrator emissions. The former gas processing plant is now referred to as the gas compression plant.

Tn 1997 and 1999, EPA issued NOVs (Notice of Violations), asserting the flare should have been permitted. The NOVs also cited the lack of fugitive VOC (volatile organic compounds) monitoring per the New Source Performance Standards (NSPS) of 40 CFR 60, Subpart KKK.

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### The McEImo Creek Oil Production Unit, Gas Compression Facility IMMA PROJECT No.: ‘DATE DRAWN: 

### I McVI4u~MoNNmli 

### I San Juan County, Utah I 

### 0d1~~~~lI 1814-04 11/17/2005 ‘— ~‘ 

### 37°15’37.58” N and 109°12’l 2.07” WThe following is a summary of the PSD permit history associated with the McElmo facility:

• March 14, 1985

- U.S. EPA Region VIII determined Stage I of McElmo Creek Unit does not require a PSD permit;

• May 8, 1986

- Mobil Exploration and Producing North America submitted PSD Permit Application for CO2 Project Stage 2;

• February 2, 1987

- U.S. EPA Region VIII issued PSD permit to Mobil;

• September 1, 1987

- Mobil submitted letter requesting to replace three reciprocating internal combustion engines with two natural gas fueled turbines;

• October 27, 1987

- U.S. EPA Region VIII issued amended PSD permit for the change;

• February 21, 1991

- Mobil requested amendment of PSD permit to allow construction of waste heat recovery unit at turbine, replacing two existing pieces of fuel-burning equipment;

• February 22, 1991

- Mobil requested EPA approval for temporary replacement of turbine with an identical unit, during turbine overhauls;

• April 18, 1991

- U.S. EPA Region VIII issues amended PSD permit for requested changes and also, rescinded approval of the second turbine since Mobil had no plans to install it.

2.2 EXISTING FACILITY OPERATIONS
Currently, produced fluids at the oil production facility are processed, sold, and re-injected through a series of satellite facilities, main tank batteries, and injection plants. Produced fluids
are gathered and separated at one of eleven satellite facilities located throughout the field. Gases from the satellite facilities are directed to the gas compression plant, and liquids are pumped to
one of four central tank batteries. Gases sent to the gas compression plant are compressed, dried through a glycol dehydrator, blended with carbon dioxide (C02), and re-injected into the field. Liquids are further separated at the central tank batteries, with oil being sold and transported through a pipeline system. Water from the central tank batteries is pumped to the water flood injection plant.

The Main Flare at the gas compression plant combusts gases that have been bypassed around the plant’s electric-driven compressors or that come through various emergency relief valves in the

2-2compression plant. Additionally, the vent stream from the plant’s glycol dehydrator is directed

to the Main Flare.

A flow diagram of the facility’s gathering system operations is presented in Figure 2-2, illustrating the flow through the satellite facilities, central tanic batteries, water flood injection plant, and gas compression plant. Figure 2-3 presents a simple block flow diagram for the gas compression plant, including the streams directed to the Main Flare.

2.3 MODIFICATION

As noted in Section 1, no modification of existing operations is proposed with this PSD permit application. This application is submitted in order to meet the requirements of ExxonMobil’s Consent Decree (DOJ Case No. 90-5-2-1-2237, filed June 8, 2005). Paragraph 14.a requires ExxonMobil to submit an application for a PSD permit for the Main Flare, including “(i) an analysis of the best available control technology for the Main Flare for [sulfur dioxide] SO2, [carbon monoxide] CO, [nitrogen oxides] NOx, and [volatile organic compounds] 

### VOC; and (ii)
an air quality analysis” no later than 180 days after the Consent Decree’s effective date of June 8, 2005.



### 2.4 MAIN FLARE REGULATORY REQUIREMENTS

2.4.1 New Source Review

No modifications are being proposed to necessitate a PSD permit application. However, ExxonMobil’s Consent Decree requires a PSD permit application submittal for the Main Flare, including a BACT analysis for SO2, CO, NOx, and 

### VOC, and an air quality analysis to assess the impacts of the Main Flare’s criteria emissions to ambient air quality standards. Based on EPA Region TX’s comments in their May 22, 2006 letter, assessment of the Main Flare’s emissions consider BACT criteria and impacts on Class II areas are modeled. Class I area impacts, additional impacts and effects on endangered species are not formally assessed per telephone and e-mail correspondence with Mr. Notar of the National Park Service and Mr. Henry Maddux, Utah Endangered Species Field Supervisor.

2-3•—WATER—EOF—EMERGENCYOvERFlOWtACT—LEASEAUTOMAOCCUSTODYITWISFERFigure2-2BlockFlowDiagramofExistingGatheringSystemOperationsMcEImoCreekOilProductionUnitL.~-—--(TYPICAl.orn)__ad002PORCRADES•FROMMoELASDOMECODPIPEUNEIL-~G±:ICOMPRENSC--—--CE1LKBYCS--—--(TYPICALOF4)C-)00~0•0~r)ZOZ~r,EXXONMOBIIMETERGASFROM:UCUBAIT.IMCUBATT.2MCUBAli.4MCUBATT.6TOTEXACOA=[XXONVOBILCORIOLISMCT[R3=TEXACOCORIOLISMETERIUSP~1IRRAR~--V.—~u(~TODFUY/FLAR~TOUCUINJECTIONWELlSREVISION•=~onMobII‘/o~/o.ORIGINALD1AWINGVMCELMOCREEKCOMPRESSORPLANTU.S..WESTF~(~~~2/04macorc_______ANITH~IF1O‘.s.)SANJUANCOUNTY.UTAH?~f07UPDATEMETER~V~..~~~.~-..~.ss‘v.ascooc..ct~—3/~3O3Ati~ow___c~~—~-~2.4.2 Consent Decree Requirements

The Consent Decree further requires in Paragraph 14.a that the PSD application include “among other things, terms and conditions that are at least as stringent as the terms and conditions included in Paragraphs 9.a, 10, 11, and 25(i)-(ix) of this Consent Decree, with the exception that the quarterly report required by Paragraph 25 may be changed, at the discretion of the permitting authority, to a semiannual report.” Paragraph 9.a of the Consent Decree refers to the rolling 365- day cumulative emission limits for 

### SO2, CO, NOx, and VOC, which will be discussed in Section 3 of this application document. Paragraph 10 of the Consent Decree addressing monitoring requirements for the Main Flare, and Paragraph 11 presents operation and maintenance requirements for the Main Flare and compressors at the gas compression plant. Paragraph 25 of the Consent Decree details a quarterly reporting system, the frequency of which may be changed by the permitting authority, as noted earlier. A copy of the Consent Decree has been attached as an appendix to this application. The air permit for the Main Flare will contain the terms and conditions found in Paragraphs 9.a, 10, 11, and 25(i)-(ix) of the Consent Decree either by reference or by direct inclusion in the permit.

2.4.3 New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP)

The Consent Decree specifies recordkeeping, maintenance, and operational procedures to demonstrate a 98 percent destruction efficiency on VOCs consistent with 40 CFR 

## § 60.18 (NSPS) and 40 CFR 

## § 63.11 (NESHAP). These procedures and limitations are applicable to a flare used as a control device for affected facilities subject to individual NSPS and/or NESHAP subparts. Such is not the case here. Rather, the Main Flare at the McElmo Creek Gas Plant has been typically used as an emergency flare to control process gas and waste gas release emissions when the injection system (the primary control “device”) is malfunctioning and/or undergoing maintenance. As such, it is the Consent Decree alone that compels the flare destruction efficiency requirement.

2-42.4.4 Other Air Quality Requirements

Since the facility is located on the Navajo Nation, it is the Navajo Nation, and not the state of Utah that has the authority (aside from EPA) to implement air quality programs relevant to the facility. Although the Navajo Nation has been granted delegated authority as of October 15, 2004, EPA is acting as an oversight reviewing agency assisting the Navajo Nation in administering their approved program.

2.4.5 Title V Requirements

A Title V operating permit application must be submitted, as required by Paragraph 14.b of the Consent Decree, no later than 180 days after the Consent Decree’s effective date of June 8, 2005. Similar to the requirements for the PSD permit application, the Title V operating permit application must include terms and conditions at least as stringent as those in Paragraphs 9.a, 10, 11, and 25(i)-(ix) of the Consent Decree, with the exception that the quarterly report described at Paragraph 25 may become a semiannual report.

2-53.0 MAIN FLARE EMISSIONS

As requested in the EPA Region IX comment letter of May 22, 2006, this section presents pre and post-project actual emissions, as well as pre-project estimates of the potential to emit (PTE) for all criteria pollutants, including particulate matter (PM10 and PM2.5) and lead. Pre- and postproject gas flow rates to the flare are also included. Per EPA’s comment letter, pre-project is defined as prior to the gas compression facility being dismantled in 1997, and post-project is defined as subsequent to the gas plant being dismantled. Thus, pre-project emission estimates
are based on 1996 gas flare rates and a conservative gas analysis from that year and post-project emission estimates are based on the 2005 emission inventory. Applicable calculation methodology with input data used to estimate emissions and gas analyses for 1996 and 2005 are presented in Appendix B.

The gas flow rates to the flare used for the emission estimates are 1,145.96 MMscf in 1996 and 727.704 MMscf in 2005. Because the flare is only used for emergency relief and to control dehydrator still vent emissions, the daily rates vary.

Table 3-1 Pre-Project and Post-Project Actual and PTE Emissions
Criteria Pre-Project Pre-Pro~ect Post-Project Post-Project Pollutant Actual Emissions PTE Actual Emissions PTE2

(tpy) (tpy) (tpy) (tpy) CO 

### 159.2 159.2 66.0 73.0 NO~ 29.3 29.3 12.1 13.4 

### VOC 183.6 183.6 90.6 95.4 SO2 138.1 138.1 29.2 60.0 Lead 0.00021 0.00021 0.000087 0.00011 

### PM10 3.2 3.2 1.3 1.6 PM2.5 3.2 3.2 1.3 1.6 ‘Pre-project PTE is equivalent to 1996 actual emission estimates. 2 Post-project PTE is equal to the limits prescribed in Consent Decree Paragraph 9a for CU, NUN, VOC, and SO2. Post-project PTE for Lead and PM is equal to 1.25 * (2005 Actual Emissions).



### 3-13.1 CRITERIA POLLUTANTS

Table 3-2 presents a summary of criteria pollutant emission limits for the Main Flare as listed in Paragraph 9.a of Exxon Mobil’s Consent Decree. No changes to these emission limits are proposed.

Table 3-2

Main Flare Criteria Pollutant Emission Limits’

Pollutant tons/year2 SO2 60 CO 73 NOx 13.4 VOC 95.4 1. As listed in Paragraph 9.a of Consent Decree (DOJ Case No. 90-5- 2-1-2237) 2. Cumulative 365-day rolling average.

3-24.0 BEST AVAILABLE CONTROL TECHNOLOGY ANALYSIS

The 1977 Clean Air Act Amendments established revised conditions for the approval of preconstruction permit applications under the PSD Program. One of these requirements is that Best Available Control Technology (BACT) be installed for all pollutants regulated under the Act emitted in significant amounts from new major sources or modifications. BACT is defined
as an emission limitation based on the maximum degree of pollutant reduction determined on a case-by-case basis considering technical, economic, energy, and environmental factors. Additionally, a BACT limitation cannot be less stringent than emissions limits established by an applicable New Source Performance Standard (NSPS). For this specific case, a BACT analysis will be performed for VOC, CO, NOR, and SO2 from the Main Flare as required by ExxonMobil’s Consent Decree (DOJ Case No. 90-5-2-1-2237). Current and future operation of the Main Flare will not otherwise trigger PSD review. The Main Flare is used to incinerate the residual hydrocarbons and sulfur in the injection gas stream during times when injection is not possible, thus, controlling VOC and H2S emissions.

EPA has specified use of a “top-down” approach to BACT determinations, in order to bring consistency to the BACT process. The steps of a Top-Down BACT determination are:

1. Identify all available control options; 2. Evaluate and eliminate those options that are technically infeasible; 3. Rank remaining control alternatives by control effectiveness; 4. Evaluate feasibility of each control option and combinations of control options on the basis of energy, environmental and economic factors; 5. The most stringent control option or combination of options found to be feasible on the basis of technical, energy, environmental and economic factors is selected as BACT.

The first step, to determine all control options for the pollutant in question and emission unit(s) under review, requires research to determine what available control options exist. The EPA maintains a “RACT/BACT/LAER” clearinghouse of historical BACT determinations, known as the “RBLC” database, which can be very useful in gathering an initial list of control options. Other resources may be used as available to complete the list. Following a technical feasibility assessment for all options, those found to be technically feasible are evaluated and ranked on the

4-1basis of control effectiveness (encompassing percent removal, amount of emission reduction,

energy impacts, environmental impacts, and economic factors). When investigating each control option in order of effectiveness, it is important to identify individual controls that can be combined on the basis of technical feasibility. These combinations may result in control alternatives that are more effective than the separate individual control options. As the final step, the most effective control option or combination of options that has not been eliminated is selected as BACT.

EPA Region IX has also requested the Top-Down BACT analysis to consider operating options that would reduce the need to flare. Specific options to be analyzed include improving the efficiency, reliability andJor capacity of the gas compressors and measures designed to reduce flaring frequency and the quantity of gas flared. Thus, the options evaluated in this Top-Down analysis are:

1. Increasing the reliability and efficiency of the existing Dresser HOS-6 compressor 2. Installation of a flare gas recovery unit (FGRU) that would capture most of the gas potentially flared for further processing

The Top-Down BACT analysis presented below considers control alternatives for the flare itself and alternative operating options designed to minimize the need for flaring consisting of modifications to the HOS-6 compressor or installation of a FGRU.

4.1 ALTERNATIVE CONTROLS FOR FLARE

4.1.1 Volatile Organic Compounds (VOCs)

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 VOCs, since combustion through a flaring system prevents the release of hydrocarbons to the atmosphere. When combustion is not complete, flares will emit VOCs in the form of unburned hydrocarbons. The EPA addressed this issue through regulations in the New Source Performance Standard’s (NSPS) General Control Device Requirements at 40 CFR 

## § 60.18 and in the Control Device Requirements for the National Emission Standards for

4-2Hazardous Air Pollutants (NESHAP) regulations at 40 CFR 

## § 63.11. These requirements

establish specifications on visible emissions, continuous presence of a flame, exit velocities, fuel heating value, and monitoring for flare systems applicable to any NSPS, 40 CFR Part 61 NESHAP, or 40 CFR Part 63 NESHAP, with the intent to ensure 98 percent control (hydrocarbon destruction) efficiency for applicable flares. This objective was based on tests confirming 98 percent control efficiencies for flares combusting organic emissions. Additionally, flare manufacturers such as the John Zink Company LLC established that a “properly designed and operated” flare burner will have a combustion efficiency of more than 98 percent. Flares not subject to an NSPS or NESHAPs are not required to meet these specifications.

In order to achieve the visible emission requirements of 40 CFR 

## § 60.18 and 40 CFR 

## § 63.11, “smokeless” flare systems are designed with some type of external momentum force, such as steam, air, water spray, natural gas, or a specialized high velocity vortex design. An external momentum force provides for more complete combustion by improving the fuel flow momentum, which allows a sufficient amount of combustion air to be educted into the combustion zone just outside the flare burner. High-pressure flares (5 to 10 psig or more) might not require a supplemental external momentum design in order to achieve smokeless combustion. However, many flare systems require some type of supplemental assist in order to achieve smokeless operation and 98 percent control efficiency. Steam injection is common, as it
can add sufficient momentum and aid the chemistry of the combustion process. Low-pressure air can be used as an assist medium in locations where steam, water, or gas is not readily available or where cold temperatures present freezing issues. In this case, a blower is utilized to inject approximately 15 to 50 percent of the stoichiometric air requirement into the flame, providing adequate momentum to achieve smokeless and complete combustion. Air-assist design is often used in remote locations. Gas-assist with natural gas can provide an additional benefit by increasing the heating value to the fuel stream, in situations where the waste gas to be combusted does not have a sufficient heating value for safe combustion. Available literature suggests that each technology option for supplemental external momentum provides similar additional control to VOC emissions from flare systems.

Table 4-1 presents a summary of recent BACT determinations from the EPA’s RBLC database for flare VOC emissions. The table shows that seven of the twelve RBLC determinations did not

4-3list any control technology for VOCs, although four of those seven determinations noted flares as

the control device for VOC emissions. Three of the entries which noted flares as a VOC control device went on to state the flare would have 98% control efficiency, and one entry also stated the flare would be designed and operated to meet 40 CFR 

## § 60.18 specifications. Four of the twelve entries noted the use of “gas-assisted” smokeless flare systems as the VOC control technology. (Note that it is not clear in the RBLC if “gas-assisted” refers to the use of air or natural gas as the
source of external momentum.) One of the twelve determinations noted “good combustion practices” as the control technology. For those seven determinations where no control technology was specified, including those noting the flare system as the control device for VOCs, it cannot be determined if those flare systems are designed and operated with any type of supplemental external momentum technology such as steam, air, or gas-assist. It is logical to conclude that some of these systems might have an “assisted” design, particularly in the case of the refinery flares, if the compliance with the provisions of 40 CFR 

## § 60.18 or 40 CFR 

## § 63.11 is required.

Based on review of Table 4-1 and knowledge of controls used to reduce VOC emissions from flare systems, the possible VOC control options for the Main Flare are:

• No control/good combustion practices;

• Meet requirements of 40 CFR 

## § 60.18 and/or 40 CFR 

## § 63.11 for flare systems; and

• Supplemental external momentum design

- steam, air, or gas-assist technology.

Some overlap exists between the second and third options, because as explained previously, the visible emission requirements of 40 CFR 

## § 60.18 and 40 CFR 

## § 63.11 are frequently met by the
use of a supplemental external momentum design, such as steam, air, or gas technology. Therefore, in some cases, compliance with the requirements of the NSPS or NESHAP control device regulations can only occur by utilizing a supplemental external momentum design such as steam, air, or gas-assist technology.

Of the options listed above, steam-assisted technology is immediately determined to be infeasible. The McElmo Creek Gas Compression 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.

4-4The MeElmo Creek Gas Compression Facility’s Main Flare has not been previously viewed as

subject to the requirements at 40 CFR 

## § 60.18 or 40 CFR 

## § 63.11, because its use was not specifically for compliance with a provision of a NSPS or NESHAP. However, Paragraph 11(b) of the Consent Decree with the EPA (DOJ Case No. 90-5-2-1-2237) states that “.

. .[t]hereafter, Mobil shall operate and maintain the Main Flare in compliance with 40 CFR 

## § 60.18(c)(1), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (0(1) through (0(4), and (0(6). Additionally, Paragraph 11(b) of the Consent Decree states that “Within three hundred sixty-five (365) days from the Effective Date, Mobil shall install an automatic air-assisted flare system on the Main Flare, pursuant to the provisions of 40 CFR §60.1 8(c)(5) and (0(6). Therefore, Consent Decree conditions requiring compliance with NSPS requirements (typical starting point for BACT), supplemented by one of the three supplemental external momentum technologies, represents the most stringent BACT currently implemented. On this basis, further analysis of employing a gas-assist technology rather than air-assist is unnecessary, since there would be no additional environmental benefit from using gas-assist. VOC BACT is proposed to be the combination of air-assist technology and complying with the flare specifications of the General Control Device Requirements at 40 CFR 

## § 60.18 as specified in the Consent Decree.

4.1.2 Carbon Monoxide (CO)

Carbon monoxide (CO) from flare systems is formed in the same manner as any combustion process

— through incomplete combustion. VOC emissions from flare systems also originate from incomplete combustion. Therefore, control options to address CO emissions from flares will be the same as those for VOC emissions.

Table 4-2 presents a summary of recent BACT determinations from the EPA’s RBLC database for flare CO emissions. Nine of the sixteen determinations do not cite a specific CO control technology. It is uncertain how many of the flares represented by these determinations are designed and operated with any type of supplemental external momentum technology such as steam, air, or gas-assist technology; however, it is reasonable to conclude that some of the listed flares, particularly those located at petroleum refineries, utilize an assist technology in order to meet NSPS and NESHAP requirements. Four of the sixteen determinations note the use of “gas assist” smokeless technology (note that it is not clear in the RBLC if “gas-assisted” refers to the
use of air or natural gas as the source of external momentum). Two entries cite “proper

4-5operation and maintenance,” and one entry cites “good combustion practices” as the CO control

technology, with no further detail provided.

Based on review of Table 4-2, and typical flare system operations, BACT options for CO are considered to be identical as those for VOC. Therefore, CO BACT is proposed to be the combination of air-assist technology and the requirement to meet the flare specifications under the General Control Device Requirements at 40 CFR 

## § 60.18.

4.1.3 Nitrogen Oxides (NOr)

There are three principal forms of NOR, designated as “thermal” NON, “prompt NON,” and “fuel” NOR. Thermal NO~ 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~ formation are temperature, concentrations of nitrogen and oxygen in the inlet air, and residence time within the combustion zone. Prompt NO~ is formed through relatively fast reaction between nitrogen, oxygen, and hydrocarbon radicals and is an important mechanism in lower temperature combustion processes. Fuel NO~ 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~ is a concern when burning oil, coal, or waste fuels.
Generally, several options exist to reduce NO~ emissions from combustion processes, such as pre-treating the fuel or switching fuels and/or oxidizers to prevent NO~ formation, modifying the combustion process or equipment to lower NO~ formation, and post-treatment end-of-pipe technologies to remove NOR. These options are listed below:

Pre-Treatment Combustion Modification Post-Treatment

• Fuel switching • Air Preheat Reduction • SCR

• Fuel additives • Burners Out-of-Service • SNCR

• Oxidizer switching • Low NOx burner

Post-treatment, end-of-pipe options are not technically feasible for flare systems, due to the inherent design of flaring and the fact that literally, no end-of-pipe exists after the combustion

4-6zone. Combustion modification options have limited technical feasibility for flare systems, as

well. Reducing the amount of air preheat and taking burners out of service are options intended for process heaters and boilers, where the combustion air is heated for more efficiency and where multiple burners exist. Low NO~ burners incorporate concepts such as lowering excess air, fuel staging, and gas recirculation, which can be successfully implemented with process heaters and boilers. However, flare burner design differs substantially from process heater and boiler burner design, because the primary objective of flare burner design is to achieve safe and complete combustion of unwanted hydrocarbons, sometimes in emergency situations, and often in unpredictable volumes, flowrates, and temperatures. Essentially, the best low-NO~ burner for a flare is a well-designed one, properly sized and constructed for a specific flare’s conditions. Thus, the only technically feasible options for NO~ control from the Main Flare fall within the pre-treatment category; however, few options in this category are technically feasible.

Fuel additives, intended to change the chemistry of the combustion process, operate under specific temperature conditions and stable operations, neither of which are possible with flare systems. Oxidizer switching, where pure oxygen is used for combustion rather than air, is not widely used in the hydrocarbon, petrochemical, and power generation industries due to the cost and energy requirements of producing pure oxygen. Fuel switching from fuels with higher fuel-bound nitrogen contents to those with lower fuel-bound nitrogen contents is a possible option for reducing NO~ from flare systems, but only in specific cases where the fuel to the flare
can be controlled and predicted.

Table 4-3 presents a summary of recent BACT determinations from the EPA’s RBLC database for flare NO~ emissions. Eight of the twelve determinations do not cite a specific NO~ control technology. Two of the twelve determinations note “proper operation and maintenance” as the control technology, one notes a limitation on fuel type (use of natural gas only) and one notes the flare will be operated in accordance with 40 CFR 

## § 60.18 General Control Device requirements. Based on review of Table 4-3, and the previous discussion of possible NO~ control technologies for combustion processes, the list of possible NO~ control options for the Main Flare are:

• No controL/good combustion practices;

• Meet requirements of 40 CFR 

## § 60.18 and/or 40 CFR 

## § 63.11 for flare systems; and

• Fuel switching.

4-7Of these options, fuel switching has been determined to be technically infeasible for the Main

Flare. Fuel is sent to the Main Flare through various pressure-relief piping or compressor bypass piping, as a result of emergency or maintenance situations, and also continuously from the dehydration reboiler. This fuel stream to the Main Flare cannot be switched without inherently changing the compressor plant’s purpose and design. Furthermore, the fuel to the Main Flare consists of light hydrocarbons (methane, ethane, propane) and carbon dioxide, with very little fuel-bound nitrogen content.

Given the fact that Exxon Mobil is required by its Consent Decree to “operate and maintain the Main Flare in compliance with 40 CFR 

## § 60.18(c)(1), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (0(1) through (f)(4), and (0(6)” following installation of an air-assist technology, BACT for NOx is proposed as meeting the General Control Device requirements of 40 CFR 

## § 60.18 for flare systems. Compliance with these requirements also guarantees that good combustion practices
are being followed.

4.1.4 Sulfur Dioxide (SO2)

Sulfur dioxide emissions from flare systems depend on the amount of sulfur in the fuel stream. Typically, sulfur dioxide from combustion processes can be controlled through limiting the fuel type or sulfur content, or through end-of-pipe control technology. As discussed in section 4.3, end-of-pipe control technologies are not feasible for flare systems. Therefore, the primary means of controlling SO2 emissions from flare systems is to limit the fuel type or sulfur content, where possible.

Table 4-4 presents a summary of recent BACT determinations from the EPA’s RBLC database for flare SO2 emissions. Ten of the sixteen determinations note some type of fuel sulfur limitation as the control technology. Five entries do not list any type of SO2 control technology, and one entry contains a reference to continuous pilot ignition, flame monitors, and other specifications that can be found in the 40 CFR 

## § 60.18 flare requirements. Following this review, the SO2 control options for the Main Flare are determined to be:

• No controllgood combustion practices;

• Limit fuel type; and

4-8Pa~i8BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)Table4-1.BACTDeterminationsforFlareVOCEmissionsCompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACT,LAER,orPermitDateSource(Size)OtherExxonMobilKentCounty,2FlaresNotprovidedVOC42.82lb/br,eachNonelisted—BACT1/31/2003SaltCreekGasPlantTX156.31tpy,NotesflareasVOCcontrolcombineddevice,with98%efficiencyConoco,Inc.KayCounty,IFlare0.20lb/MMbtu—VOC0.14lb/MMbtuGoodcombustionpracticeBACT7/1/2002PoncaCityRefineryOKnofurtherdetailprovidedValeroRefiningCo.NuecesCounty,MainFlare—NotprovidedVOC226lb/brNonelisted.NotesflareasVOCBACT6/11/2002CorpusChristiTX2groupsof39.6tpy,andcontroldevice,with98%Refineryequipment4,013lb/hrefficiency.ventstoflareProcessnotesindicateflarewillbe1,544tpy.designed&operatedper40CFR§(2setsoflimits)60.18.DukeEnergyFieldWebsterParish,1FlareNotprovidedVOC2.82lb/brNonelisted“othercasebycase”1/24/2002Services-MindenLA8.73tpy—thisactionwasaminormodificationonlyOrionRefiningCo.St.Charles2Flares60,700,000Btu/hr,VOC25.4lb/br,eachNonelisted.NotesflareasVOCBACT1/10/2002Parish,LAeach16.7tpyeachcontroldevice,with98%controlefficiency.FlintHillsResourcesNueces,TXFlaresNotprovidedVOC4,036.26lb/hrNonelisted.“othercase-by-case”10/5/2001LP2,982.09tpy,WestRefineryBoth“initial”capsTrifineryPetroleumNueces,TX1FlareNotprovidedVOC12.74lb/hrNonelisted.NotesflareasVOC“othercase-by-case”8/7/2000Service55.79tpycontroldevice.TrigeantCorpusChristiCitgoRefining&Nueces,TX1Flare(HP)80,000sc6’dayVOCNonelisted“Gas-Assist”smokeless“othercase-by-case”10/15/1999ChemicalsCoLPtechnologyCorpusChristiRefinery—WestPlantPa~x8BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)CompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACT,LAER,orPermitDateSource(Size)OtherCitgoRefining&Nueces,TX1Flare(LP)20,000scffdayNGVOCNonelisted“Gas-Assist”smokeless“othercase-by-case”10/15/1999ChemicalsCoLPtechnology430,000scf/dayCorpusChristiproducedgasRefinery—WestPlantBPExplorationInc.AKIFlare(HP)660,000,000scfdVOCNoneGas-assistsmokelessflare“othercasebycase”2/5/1999NorthstartechnologyDevelopmentFacilityBPExplorationInc.AKIFlare(LP)18,022,000scfdVOCNoneGas-assistsmokelessflare“othercasebycase”2/5/1999NorthstarNaturalandtechnologyDevelopmentFacilityProducedGasMobilExploration&KentCounty,ProcessNotprovidedVOC0.01lb/hrNonelisted“othercasebycase”10/13/1998ProducingUS,Inc.TXEmergency0.01tpySaltCreekGasPlantFlareTable4-2.BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)BACTDeterminationsforFlareCOEmissionsPaLi~8CompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACTorLAERPermitDateSource(Size)ExxonMobilKentCounty,2FlaresNotprovidedCO37.2lb/br,eachNonelistedBACT1/31/2003SaltCreekGasPlantTX135.8tpy,combinedConoco,Inc.KayCounty,1Flare0.20lb/MMbtu—CO0.37lb/MMbtuGoodcombustionpracticeBACT7/1/2002PoncaCityRefineryOKnofurtherdetailprovidedValeroRefiningCo.NuecesCounty,MainFlareNotprovidedCO472lb/brNonelisted.BACT6/11/2002CorpusChristiTX90.5tpyRefineryDukeEnergyFieldWebsterParish,1FlareNotprovidedCO0.26lb/brNonelisted“othercasebycase”1/24/2002Services-Minden~1.14tpythisactionwasaminormodificationonlyOrionRefiningCo.St.Charles2Flares60,700,000Btu/hr,CO149lb/br,eachNonelisted.BACT1/10/2002Parish,LAeach98.3tpy,eachFlintHillsResourcesNueces,TXFlaresNotprovidedCO901.5lb/brNonelisted.“othercase-by-case”10/5/2001LP2,657.98tpy,WestRefineryBoth“initial”capsTrifineryPetroleumNueces,TX1FlareNotprovidedCO16.3lb/brNonelisted.“othercase-by-case”8/7/2000Service71.36tpyTrigeantCorpusChristiTesoroAlaskaCoAKIFlare1,000,000Btu!hrCO0.04lb/MMBtuNonelisted.“othercase-by-case”3/21/2000KenaiRefineryTesoroAlaskaCoAKIFlare(HP)261,000,000scfdCO0.37lb/MMBtuProperOperation&Maintenance“othercase-by-case”3/21/2000KenaiRefineryTesoroAlaskaCoAK1Flare(LP)212,000,000scfdCO0.37lbIMMBtuProperOperation&Maintenance“othercase-by-case”3/21/2000KenaiRefineryCitgoRefining&Nueces,TX1Flare(HP)80,000scfldayCONonelisted“Gas-Assist”smokeless“othercase-by-case”10/15/1999ChemcalsCoLPtechnologyCorpusChristi[Pa~/8BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)CompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologySource(Size)Refinery—WestPlantCitgoRefining&Nueces,TXIFlare(LP)20,000scf7dayNGCONonelisted“Gas-Assist”smokelessChemicalsCoLP430,000scf/daytechnologyCorpusChristiproducedgasRefineryWestPlantBPExplorationInc.AKIFlare(HP)660,000,000scfdCONoneGas-assistsmokelessflareNorthstartechnologyDevelopmentFacilityBPExplorationInc.AKIFlare(LP)18,022,000scfdCONoneGas-assistsmokelessflareNorthstartechnologyDevelopmentFacilityMobilExploration&KentCounty,IFlareNotprovidedCO1.1lb/hrNonelistedProducingUS,Inc.TX4.8tpySaltCreekGasPlantEquistarChemicals,Nueces,TX2FlaresNotprovidedCO0.05lb/hr,eachNonelisted.LP0.23tpy,eachPaLf8Table4-3.BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)BACTDeterminationsforFlareNO~EmissionsCompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACTorLAERPermitDateSource(Size)ExxonMobilKentCounty,2FlaresNotprovidedNOx4.37lb/br,eachNonelistedBACT1/31/2003SaltCreekGasPlantTX15.85tpy,combinedConoco,Inc.KayCounty,IFlare0.20lb/MMbtu—NOx0.068lb/MMbtuLimitfueltopipeline-gradenaturalBACT7/1/2002PoncaCityRefineryOKnofurtherdetailgasprovidedValeroRefiningCo.NuecesCounty,MainFlareNotprovidedNOx75.8lb/hrNonelisted.BACT6/11/2002CorpusChristiTX18.8tpyRefineryOrionRefiningCo.St.Charles2Flares60,700,000Btu/hr,NOx33.6lb/br,eachNonelisted.BACT1/10/2002Parish,LAeach45.3tpy,eachFlintHillsResourcesNueces,TXFlaresNotprovidedNOx1,409.8lb/brNonelisted.“othercase-by-case”10/5/2001LP5,266.82tpy,WestRefineryBoth“initial”capsTrifineryPetroleumNueces,TXIFlareNotprovidedNOx3.2lb/hrNonelisted.“othercase-by-case”8/7/2000Service14.01tpyTrigeantCorpusChristiTesoroAlaskaCoAKIFlare1,000,000Btu/brNOx0.14Ib/MMBtuNonelisted.N/A3/21/2000KenaiRefineryTesoroAlaskaCoAKIFlare(HP)261,000,000scfdNOx0.068lb/MMBtuProperOperation&Maintenance“othercase-by-case”3/21/2000KenaiRefineryTesoroAlaskaCoAK1Flare(LP)212,000,000scfdNOx0.068lb/MMBtuProperOperation&Maintenance“othercase-by-case”3/21/2000KenaiRefineryConoco,Inc.Calcasieu1FlareNotprovidedNOx1.2lb/hrOperateinaccordancewithBACT12/22/1998LakeCharlesParish,LA5.0tpy40CFR§60.18GeneralControlRefineryDeviceRequirementsMobilExploration&KentCounty,IFlareNotprovidedNOx0.08lb/hrNonelisted“othercasebycase”10/13/1998ProducingUS,Inc.TX0.4tpySaltCreekGasPlantBACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)Pa~£8CompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACTorLAERPermitDateSource(Size)EquistarChemicals,Nueces,TX2FlaresNotprovidedNOx0.01lb/hrNonelisted.“othercase-by-case”10/8/1998LP0.04tpyQPa,f8BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)Table4-4.BACTDeterminationsforFlareSO2EmissionsCompany—LocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACTorLAERPermitDateSource(Size)ExxonMobilKentCounty,2FlaresNotprovidedSO250.48lb/br,eachNonelisted“othercasebycase”1/31/2003SaltCreekGasPlantTX184.24tpy,combinedConoco,Inc.KayCounty,1Flare0.20lb/~tMbtu—SO20.0006lb/MMbtuLimitfueltopipeline-gradenaturalBACT7/1/2002PoncaCityRefineryOKnofurtherdetailgasprovidedValeroRefiningCo.NuecesCounty,MainFlareNotprovidedSO251.1lb/hrNonelisted.BACT6/11/2002CorpusChristiTX12tpyRefineryOrionRefiningCo.St.Charles2Flares60,700,000Btu/hr,SO2133lb/br,eachNonelisted.BACT1/10/2002Parish,LAeach87.6tpy,eachBPExplorationAK1FlareMaxrateSO2500ppm,3-hrBumfueloilwithnogreaterthanSIP7/13/2001(Alaska)Inc.83,000,000scfdaverage0.3wt%sulfur,andMilnePointNominalrateBumnaturalgaswithnogreaterProductionFacility340,000scfdthan100ppmvdH2SFlintHillsResourcesNueces,TXFlaresNotprovidedSO2962.12lb/brNonelisted.BACT10/5/2001LP118.76tpy,WestRefineryBoth“initial”capsTrifineryPetroleumNueces,TX1FlareNotprovidedSO271.48lb/brContinuousignitionwithtwoBACT8/7/2000Service263.31tpypilots,UVfire-eyeflamemonitor,TrigeantCorpusKOpot&sealdruml;98%controlChristiefficiencyTesoroAlaskaCoAK1Flare1,000,000Btu/hrSO2500ppm,3-hrFuelsulfurcontentlimits:BACT3/21/2000KenaiRefineryaverage0.35%sulfurindiesel,0.01%sulfurinnaturalgas,0.01%sulfurinLPG,and168ppmvH2SinrefinerygasPa,“8BACT/LAERClearinghouseDatabaseSummaryDeterminations1995—2005IndustrialFlares(RBLCReport8/4/05)CompanyLocationEmissionThroughputPollutantEmissionLimitControlTechnologyBACTorLAERPermitDateSource(Size)TesoroAlaskaCoAKIFlare(HP)261,000,000scfdSO2NonelistedFuelsulfurcontentlimits:BACT3/21/2000KenaiRefinery0.15%sulfurindistillate,and200ppmI-12SinfuelgasTesoroAlaskaCoAKIFlare(LP)212,000,000scfdSO2NonelistedFuelsulfurcontentlimits:“othercase-by-case”3/21/2000KenaiRefinery0.15%sulfurindistillate,and200ppmH2SinfuelgasCitgoRefining&Nueces,TXIFlare(HP)80,000scf7daySO2500ppm,3-hrH2Scontentlimitedto50ppmv“othercase-by-case”10/15/1999ChemicalsCoLPaverageCorpusChristiRefinery—WestPlantCitgoRefining&Nueces,TX1Flare(LP)20,000scf7dayNGSO2500ppm,3-hrFuelsulfurcontentlimits:“othercase-by-case”10/15/1999ChemicalsCoLP430,000scf/dayaverage0.15%sulfurinfueloil,andCorpusChristiproducedgas50ppmvH2SinfuelgasRefinery—WestPlantBPExplorationInc.AKIFlare(HP)660,000,000scfdSO2500ppm,3-hrH2Scontentofthefuelshallnot“othercasebycase”2/5/1999Northstaraverageexceed50ppmvDevelopmentFacilityBPExplorationInc.AK1Flare(LP)18,022,000scfdSO2500ppm,3-hrH2Scontentofthefuelshallnot“othercasebycase”2/5/1999Northstaraverageexceed50ppmvm,andDevelopmentFacilitySulfurcontentoffueloilshallnotexceed0.15wt%Conoco,Inc.Calcasieu1FlareNotprovidedSO20.3lb/hrNonelisted“othercase-by-case”12/22/1998LakeCharlesParish,LA1.1tpyRefineryMobilExploration&KentCounty,IFlareNotprovidedSO239.74lb/hrNonelisted“othercasebycase”10/13/1998ProducingUS,Inc.TX174.1tpyFuellimitedtopipelinequalitySaltCreekGasPlantsweetnaturalgaswithnomorethan5grainssulfur/dscf. Limit sulfur content.

Limiting the fuel type has been determined to be a technically infeasible option for the Main Flare. As discussed in Section 4.3 for NOx, the fuel sent to the Main Flare is a combination of the process gas which is compressed for re-injection and the vent stream from the dehydration reboiler. This fuel stream cannot be switched to a different type without inherently changing the compressor plant’s purpose and design.
Additionally, limiting the fuel’s sulfur content has been determined to be technically infeasible. The compressor plant is designed and operated to compress gas and re-inject it into the field. The gas directed to the compressor plant is not processed for sale or sold to outside customers. Its average hydrogen sulfide (H2S) content is 400-500 ppm, with the maximum H2S content potentially higher, depending on the quality of product from the field. Limiting the sulfur or hydrogen sulfide content in the gas directed to the Main Flare could result in an inherent change to the compressor plant’s purpose and design, because the gas to the Main Flare is a combination of process gas and dehydrator vent gas, and because the plant’s design does not call for any sweetening process due to the fact that it is re-injected, and not sold.

The only remaining technically feasible option is no control/good combustion practices. Therefore, BACT for SO2 is proposed as good combustion practices, which will be achieved through compliance with 40 CFR 

## § 60.18 flare operational requirements.

4.2 COMPRESSOR ENGINE MODIFICATIONS

4.2.1 Past Flaring Due to Compressor Downtime

The majority of the flaring at McElmo Creek Gas Compression Facility is a result of downtime associated with the HOS-6 compressor. This unit is a 4-stage, 6-cylinder Dresser HOS model compressor, which is driven by an electric motor.

HOS-6 compressor reliability is influenced by the interaction of the gas composition and process requirements at McElmo Creek. The gas is primarily composed of carbon dioxide and has a tendency to liquefy at relatively low temperatures. The gas pressure between the 3rd and 4th

4-9stages of compression is approximately 1000 psi. The gas at this pressure liquefies at

approximately 85 °F. Additionally, the discharge pressure is above the critical pressure of the gas. Therefore, the process stream actually leaves the compressor and can simultaneously have the properties of a liquid and a gas. It is when the gas behaves as a liquid that compressor damage can occur. This mixed gas stream allows for the potential of liquid drop-out throughout the compression process.

In an effort to reduce the potential for damage on the 4th stage of the compressor, the field operations group attempts to maintain the suction temperature of the 4th stage near 1000 F. However, the large temperature swings that can occur in the McElmo Gas Compression Facility area, especially in the winter months, make this difficult. Some of the issues are:

• No automatic controls on the coolers

• Gas separation between stages located remotely from the compressor

• Piping between the separation equipment and the compressor having multiple elevation changes, which increase the potential for liquid accumulation in the lines.

The compressor has had downtime associated with 2nd stage failures due to liquids entering the cylinder. The implemented solution was to remove the liquid traps between the separation and compression equipment. This eliminated liquid collection and slugging, thereby reducing downtime events significantly.

4.2.2 Options to Improve Reliability of HOS-6 Compressor Engine Operations

A Top-Down analysis of options to increase reliability of compressor engine operation is presented below. Cost effectiveness based on annual emissions reduction of each pollutant is estimated for each option to evaluate economic feasibility. Cost estimation methodology is based on the EPA Cost Control Manual. ExxonMobil experience with capital costs and maintenance labor is cited, but actual cost effectiveness estimates are based on the EPA costing factors. Implementing these options is assumed to achieve a minimum decrease of 75% of base emissions of each pollutant. Options for increasing the reliability of compressor engine operation are changing the compression process and replacing the compressor engines. These options are discussed below.

4-10Change Compression Process

Reducing the discharge pressure of the reciprocating compression, cooling the gas stream to liquefy it, and utilizing pumps to reach the required pipeline pressure could provide increased reliability and minimize potential compression failures at the McElmo Gas Compression Facility. However, this would require new refrigeration equipment, new pumps, and, at a minimum, restaging of the existing compression. Further corrective actions would also be necessary, as described below, if the existing HOS-6 compressor was used.

The estimated equipment cost for this corrective action would be $12,000,000, at a minimum, if the HOS-6 compressor was reconfigured for this process. Based on the cost-effectiveness analyses in Tables 4-5a and b, this method is considered economically infeasible. To achieve a 75% reduction in the annual emissions of each pollutant allowed by the Consent Decree, the cost effectiveness is a minimum of $73,943 per ton of VOC removal.
Replace the HOS-6 Compressor

This option would replace the HOS-6 unit with one or more reciprocating compressors. The basic process would not change. Replacing the existing compressor may reduce the potential for liquid retention by utilizing different piping configurations. However, problems inherent with the process would still remain.

The equipment cost for this corrective action would be approximately $10,000,000, at a minimum. Based on the cost-effectiveness analyses in Tables 4-6a and b, this method is considered economically infeasible. To achieve the 75% reduction in the annual emissions of each pollutant allowed by the Consent Decree, the cost effectiveness is a minimum of $61,807 per ton of VOC removal. In addition, compression process issues contributing to potential flaring would still exist.

4-11TABLE4-5aMcElmoGasCompressionFacilityChangeHOS-6CompressorProcessCapitalCostAnalysis2.InstallationCosts:A)Foundation&SupportsB)ErectionandHandlingC)ElectricalD)PipingE)InsulationF)PaintingStSitePreoarationTotalInstallationCosts(TINC):3%ofTEC14%ofTECt%ofTEC5%ofTEC≥%ofTEC1%ofTEC3%ofTEC$1,140,480$1,995,840$570,240$712,800$285,120$142,560$427680$1,192,320$2,086,560$596,160$745,200$298,080$149,040$447,120ItemEPACostControlManuaf~ExiconMobilAssumptionsExxonMobllComments¶~IRECTCAPITALCOSTS1.PurchasedEquipment:A)ProcessChangesBaseCost$12,000,000$12,000,000IntheEMestimate,15%isthefactorusedforInstrumentationB)Instrumentation&Controls10%ofBaseCost$1,200,000$1,800,000basedonExxonMobilexperienceinsteadoftheEPA10%basis.TheEPAcostcostcontrolmanualstatesthatfactorsrangefrom5%to30%.C)Freight&Taxes4%Taxes;4’~’~$1,056,000$1,104,000reightonIA&IBTotalPurchasedEquipmentCosts(TEC):SumoflA,lBand$14,256,000$14,904,0001C1.Engineering&Supervision15%ofTEC$2,138,400$2,235,6002.ConstructionandFieldExpenses5%ofTEC$712,800$745,2003.ContractorFees10%ofTEC$1,425,600$1,490,4004.Start-up2%ofTEC$285,120$447,120IntheEMestimate,3%isthefactorusedforStart-upbasedonExxonMobilexperienceinsteadoftheEPA2%basis.5.PerformanceTesting2%ofTEC$285,120$447,120IntheEMestimate,3%isthefactorusedforPerformanceTesibasedonExxonMobilexperienceinsteadoftheEPA2%basis.6.GovernmentPermitting&Fees1%ofTEC$149,040IntheEMestimate,1%isaddedforGovernmentPermittingandFeesbasedonExxonMobilexperience.TotalDirectCapitalCosts(TDCC):INDIRECTCAPITALCOSTSSumofTECandTINC$5,274,720$19,530,720$5,514,480$20,418,480TABLE4-5aMcEImoGasCompressionFacilityChangeHOS-6CompressorProcessCapitalCostAnalysisTotalDirect&IndirectCapitalCosts(TDICC):OwnersCostSumofTDCCandrIcc$24,377,760$25,932,960$3,111,955ItemEPAC~StC~ñtiOIMãi~àIIEonMobllAssumptionsExxoMobilCommentsSumof1,2,3,4TotalIndirectCapitalCosts(TICC):and5$4,847,040$5,514,480IntheEMestimate,30%isthefactorusedforContingencybasedonExxonMobilexperienceinstead.oftheEPA20%Contingency20%ofTDICC$4,875,552$7,779,888basis.TheEPAcostcontrolmanualstatesthatthistypeofcostestimate(a“studyestimate”)hasa+1-30%accuracy.IntheEMestimate,12%isaddedforOwnerCostsbasedonExxonMobilexperiencetocovertheprojectmanagementteamrequiredtooverseethedesign,constructionandcommissioningcontractors.TOTAL.CAPITALCOSTS(TCC):S~~T’~Cand$29,253,312$36,824,803Contingency0TABLE4-5bMcElmoGasCompressionFacilityChangeHOS-6CompressorProcessOperatingCostAnalysis1.OverheadTotalIndirectOperatingCosts(TIOC):ItemEPACostControlManualExxonMobllAssumptionsExxonMobllCommentsDIRECTOPERATINGCOSTS1.OperatingLabor~$43,800$43,8002.SupervisoryLabor15%ofOperatingLabor$6,570$6,570IntheEMestimate,3%isthefactorusedfor3.MaintenanceLabor&Materials2%ofTCC$585,066$1,104,744MaintenanceLabor&MaterialsbasedonExxonMobilexperienceinsteadoftheEPA2%basis.TotalDirectOperatingCosts(TDOC):Sumof1-9$635,436$1,155,114INDIRECTOPERATINGCOSTS1.PropertyTax1%ofTCC$292,533$368,2482.Insurance1%ofTCC$292,533$368,2483.GeneralAdministrative2%ofTCC$585,066$736,4964.CapitalRecoveryFactor~Fr~0.1061[10%@$3,103,776$3,907,112TotalCapitalChargesCosts(TCCC):ISumof1,2,3and4$4,273,909$5,380,104I60%ofTotalLabor÷MaintenanceCAPITALCHARGESCOSTS$381,262$381,262$693,068$693,068TOTALANNUALIZEDOPERATINGCOSTSSumofTDO2hOCand$5,290,607~$7,228,28675%controlofannualSO2emissions(.75x60.0tpy)=45.0$117,569pertonofSO2removal75%controlofannualCOemissions(.75x73.0tpy)=54.8$96,632pertonofCOremoval75%controlofannualNOxemissions(.75x13.4tpy)=10.1$526,429pertonofNO~removal75%controlofannualVOCemissions(.75x95.4tpy)=71.6$73,943pertonofVOCremovalTABLE4-6aMcEImoGasCompressionFacilityReplaceHOS-6CompressorCapitalCostAnalysis2.InstallationCosts:A)Foundation&SupportsB)ErectionandHandlingC)ElectricalD)PipingE)InsulationF)PaintingG~SitePrecarationTotalInstallationCosts(TINC):3%ofTEC14%ofTECt%ofTEC5%ofTEC2%ofTEC1%ofTEC3%ofTEC$950,400$1,663,200$475,200$594,000$237,600$118,800$356,400$993,600$1,738,800$496,800$621,000$248,400$124,200$372,600ItemEPACostCotrolManualExxonMobllAssumptionsExxonMobllCommentsDIRECTCAPITALCOSTS1.PurchasedEquipment:A)ProcessChangesBaseCost$10,000,000$10,000,000IntheEMestimate,15%isthefactorusedforInstrumentationB)Instrumentation&Controls10%ofBaseCost$1,000,000$1,500,000basedonExxonMobilexperienceinsteadoftheEPA10%basis.TheEPAcostcostcontrolmanualstatesthatfactorsrangefrom5%to30%.C)Freight&Taxes4%Taxes:4’~~$880,000$920,000r~reiahton1A&lBTotalPurchasedEquipmentCosts(TEC):SumoflA,lBand$11,880,000$12,420,000101.Engineering&Supervision15%ofTEC$1,782,000$1,863,0002.ConstructionandFieldExpenses5%ofTEC$594,000$621,0003.ContractorFees10%ofTEC$1,188,000$1,242,0004.Start-up2%ofTEC$237,600$372,600IntheEMestimate,3%isthefactorusedforStart-upbasedonExxonMobilexperienceinsteadoftheEPA2%basis.5.PerformanceTesting2%ofTEC$237,600$372,600IntheEMestimate,3%isthefactorusedforPerformanceTesbasedonExxonMobilexperienceinsteadoftheEPA2%basis.6.GovernmentPermitting&Fees1%ofTEC$124,200IntheEMestimate,1%isaddedforGovernmentPermittingandFeesbasedonExxonMobilexperience.TotalDirectCapitalCosts(TDCC):INDIRECTCAPITALCOSTSSumofTECandTINC$4,395,600$16,275,600$4,595,400$17,015,400TABLE4-6aMcElmoGasCompressionFacilityReplaceHOS-6CompressorCapitalCostAnalysisTotalDirect&IndirectCapitalCosts(TDICC):OwnersCostSumofTDCCandTIflfl$20,314,800$21,610,800$2,593,296ItemEPACostControlManualExxonMobllAssumptionsExxonMobllCommentsSumof1,2,3,4TotalIndirectCapitalCosts(TICC):and5$4,039,200$4,595,400IntheEMestimate,30%isthefactorusedforContingencybasedonExxonMobilexperienceinsteadoftheEPA20%Contingency20%ofTDICC$4,062,960$6,483,240basis.TheEPAcostcontrolmanualstatesthatthistypeofcostestimate(a“studyestimate”)hasa+1-30%accuracy.IntheEMestimate,12%isaddedforOwnerCostsbasedonExxonMobilexperiencetocovertheprojectmanagementteamrequiredtooverseethedesign,constructionandcommissioningcontractors.SumofTDICCandContingenôy$30,687,336TO1~ALCAPITALCOSTS(TCC):$24,377,760INDIRECTOPERATINGCOSTS1.OverheadTotalIndirectOperatingCosts(TIOC):CAPITAL(~IJADK~QCOSTSTOTALANNUALIZEDOPERATINGcosis75%controlofannualSO2emissions(.75x60.0tpy)=75%controlofannualCOemissions(.75x73.0tpy)=75%controlofannualNOxemissions(.75x13.4tpy)=75%controlofannualVOCemissions(.75x95.4tpy)=TABLE4-6bMcEImoGasCompressionFacilityReplaceHOS-6CompressorOperatingCostAnalysis60%ofTotalLabor+MaintenanceItem..‘EPACostControlManual.ExxonMobllAssumptlons.ExxonMobllComments.‘.DIRECTOPERATINGCOSTS2hr/shift@$20/hr,~$43,800$43,8001.OperatingLaborshifts/day.365days/yr2.SupervisoryLabor15%ofOperatingLabor$6,570$6,570IntheEMestimate,3%isthefactorusedfor3.MaintenanceLabor&Materials2%ofTCC$487,555$920,620MaintenanceLabor&MaterialsbasedonExxonMobilexperienceinsteadoftheEPA2%basis.TotalDirectOperatingCosts(TDOC):Sumof1-9$537,925$970,9901.PropertyTax1%ofTCC$243,778$306,8732.Insurance1%ofTCC$243,778$306,8733.GeneralAdministrative2%ofTCC$487,555$613,747CRF=0.1061[10%@$2,586,480$3,255,9264.CapitalRecoveryFactor30yr.]TotalCapitalChargesCosts(TCCC):Isumof1,2,3and4$3,561,591[$4,483,420$322,755$322,755$582,594$582,594.~Ei~ofTDOC.TIGC~~$4422,2•71~‘..~.$6,Q37,oO4’~45.0$98,273pertonofSO2removal54.8$80,772pertonofCOremoval10.1$440,027pertonofNO~removal71.6$61,807pertonofVOCremoval4.2.3 Other Compression Changes

The following potential changes to compression operations were also considered, but their effect
on reducing the frequency or duration of flaring is uncertain and may be minimal since documented studies of the results from implementing these changes are not available.

Relocate the HOS-6 separation equipment
By moving the HOS-6 separation equipment closer to the compression equipment, the potential for liquid forming in the intermediate piping and entering the compressor would be reduced. A potential for liquid entering the compressor equipment would still remain because of the size of the separation equipment required on the HOS-6 compressor. Additionally, relocation of the separation equipment would not remove the inherent process issues and there would be no assurance of flaring frequency and duration reductions.
Reconfigure piping
Reconfiguring the piping between the separation and compression equipment, similar to replacing the compressor or relocating the separation equipment, would reduce the potential for liquids to enter the compression equipment by removing liquid traps. The potential for downtime occurrences would still remain, however, and there would be no assurance of flaring frequency and duration reductions.

Insulate and heat-trace the piping
By insulating and heat-tracing the piping between the separation and compression equipment, the probability of the gas cooling and liquids forming would be reduced. The potential for liquids entering the compression equipment would still remain and there would be no assurance of flaring frequency and duration reductions.

4-124.3 FLARE GAS RECOVERY SYSTEMS

Another method of reducing flaring emissions is to recover gas that would otherwise be flared and redirect for further processing in the existing gas compression facility. Description of a commercially available flare gas recovery unit (FGRU) is provided below to illustrate its operation.

• The Flare Gas Recovery Unit (FGRU) initially withdraws gas from the flare header upstream of the liquid seal drum and recovers gas normally combusted by the flare;

• To prevent ambient air from being drawn into the flare system or FGRU, the FGRU operates with a slight positive pressure upstream of the liquid seal drum;

• As the volume of gas increases within the FGRU, the pressure exerted in the flare header will increase until equaling the back-pressure created by the liquid seal drum. Any gas in excess of the back-pressure will be flared;

• As long as the pressure of the collected gas remains below the liquid seal drum backpressure, gas is diverted back to the suction header by staging compressors;

• The staging compressors typically use liquid ring compressor technology; rotary screw, reciprocating sliding vane or rotary-lobed compressors can also be used;

• The recovered gases and some of the sealing liquid combine inside the compressor and flow into a separator vessel to separate liquids and gases;

• The compressor sealing liquid from the separator goes through a heat exchanger and returns to the compressor;

• Compressed gas from the separator is then sent by pipeline to its sales destination.
Various vendors of FGRUs use different methods for achieving the sealed system necessary to prevent recovered gas from simply flowing past the flare header and being flared into the atmosphere. However, the degree of difficulty in installing and operating the variety of available FGRU systems is similar both in terms of costs and technical considerations.

Cost effective use of FGRUs are typically achieved by large oil and gas production facilities where the volume of recovered gas becomes additional sales gas and its revenue from this can largely offset initial FGRU costs and future operating costs within a few years. Thus, facilities

4-13that have successfully used FGRUs and have found them to be both technically and financially

feasible are large production facilities. The amount of recovered flared gas at these facilities represents a significant revenue stream. The Main Flare at the McElmo Gas Compression Facility is used intermittently and the additional volume of gas that would be recovered as sales gas would minimally offset the substantial economic costs associated with installing and operating the FGRU system.

The equipment cost associated with a typical FGRU is approximately $1,300,000. Since additional compressors are required and the cost associated with their installation are similar to those cited for the replacement of existing compressors in Section 4.2.2 (i.e., $10,000,000), the total equipment cost is estimated as $11,300,000. Based on the cost-effectiveness analyses in Tables 4-7a and b, this method is considered economically infeasible. To achieve the 75% reduction in the annual emissions of each pollutant allowed by the Consent Decree, the cost effectiveness is a minimum of $69,695 per ton of VOC removal. In addition, efficient use of a FGRU for an application of this small size is uncertain.

4.4 OPERATION & MAINTENANCE (O&M) PLAN

Since the above options are considered impractical because of cost-ineffectiveness or uncertainty, the existing facility and equipment must be operated and maintained in such a
manner to reduce compressor downtime and thereby, keep flaring to a minimum. This prudent operation and maintenance is conducted in accordance with Paragraphs 9.a, 10, and 11 and in accordance with Appendix B (the “O&M Plan”) of the Consent Decree. This includes constant monitoring, inspecting and performing maintenance on the compressors and associated equipment in accordance with the Life Cycle Maintenance Plan in Appendix B of the Consent Decree, maintaining a supply of designated spare parts for the compressors and associated equipment, and training all operators on the Decree requirements and the “O&M Plan.” This practice, therefore, constitutes BACT for reducing the occurrence of flaring at the Facility.

4-14TABLE4-7aMcElmoGasCompressionFacilityFlareGasRecoverySystemCapitalCostAnalysis$1,073,952$1,879,416$536,976$671,220$268,488$134,244$402732$4,967,028$18,391,428$1,122,768$1,964,844$561,384$701,730$280,692$140,346$421038$5,192,802$19,227,40202.InstallationCosts:A)Foundation&SupportsB)ErectionandHandlingC)ElectricalD)PipingE)Insulation8%ofTECF)Painting14%ofTEC4%ofTECG~SitePreoaration5%ofTECrotalInstallationCosts(TINC):2%ofTEC1%ofTECrotalDirectCapitalCosts(TDCC):3%ofTECItemEPACostControlManualExxonMoIIAssumptionsExxonMobllComments‘)IRECTCAPITALCOSTS1.PurchasedEquipment:A)EquipmentBaseCost$11,300,000$11,300,000IntheEMestimate,15%isthefactorusedforInstrumentationB)Instrumentation&Controls10%ofBaseCost$1,130,000$1,695,000basedonExxonMobilexperienceinsteadoftheEPA10%basis.TheEPAcostcostcontrolmanualstatesthatfactorsrangefrom5%to30%.C)Freight&Taxes4%Taxes:~$994,400$1,039,600~reiahton1A&15TotalPurchasedEquipmentCosts(TEC):~umof1A,lBand$13,424,400$14,034,6001C1.Engineering&Supervision15%ofTEC$2,013,660$2,105,1902.ConstructionandFieldExpenses5%ofTEC$671,220$701,7303.ContractorFees10%ofTEC$1,342,440$1,403,4604.Start-up2%ofTEC$268,488$421,038IntheEMestimate,3%isthefactorusedforStart-upbasedonExxonMobilexperienceinsteadoftheEPA2%basis.5.PerformanceTesting2%ofTEC$268,488$421,038IntheEMestimate,3%isthefactorusedforPerformanceTesbasedonExxonMobilexperienceinsteadoftheEPA2%basis.6.GovernmentPermitting&Fees1%ofTEC$140,346IntheEMestimate,1%isaddedforGovernmentPermittingandFeesbasedonExxonMobilexperience.INDIRECTCAPITALCOSTSSumofTECandTINCTABLE4-7aMcEImoGasCompressionFacilityFlareGasRecoverySystemCapitalCostAnalysis$22,955,724$24,420,204$2,930,424TotalDirect&IndirectCapitalCosts(TDICC):OwnersCostSumofTDCCandTICcItemEPACostControlManualExxonMobllAssumptionsExxonMobllCommntsSumof1,2.3.4TotalIndirectCapitalCosts(TICC):and5$4,564,296$5,192,802.IntheEMestimate,30%isthefactorusedforContingencybasedonExxonMobilexperienceinsteadoftheEPA20%Contingency20%ofTDICC$4,591,145$7,326,061basis.TheEPAcostcontrolmanualstatesthatthistypeofcostestimate(a“studyestimate”)hasa+1-30%accuracy.IntheEMestimate,12%isaddedforOwnerCostsbasedonExxonMobilexperiencetocovertheprojectmanagementtean~requiredtooverseethedesign,constructionandcommissioningcontractors.TOTALcApn~ALCOStS(TCC):SumofTDlC~~d$27,546,869s34;676,69oCofltflgeflcyTABLE4-7bMcElmoGasCompressionFacilityFlareGasRecoverySystemOperatingCostAnalysis$654,402$654,402$6;81i,337~,pertonofSO2removalpertonofCOremovalpertonofNO~removalpertonofVOCremoval1.OverheadTotalIndirectOperatingCosts(TIOC):60%ofTotalLabor+MaintenanceItem---..•EPACostControlManual’-ExxonMobilAssumptionsExxonMobll~mi~tiif~‘DIRECTOPERATINGCOSTS2hr/shift@$20/hr,~$43,800$43,8001.OperatingLaborshifts/day,365days/yr2.SupervisoryLabor15%ofOperatingLabor$6,570$6,570IntheEMestimate,3%isthefactorusedfor3.MaintenanceLabor&Materials2%ofTCC$550,937$1,040,301MaintenanceLabor&MaterialsbasedonExxonMobilexperienceinsteadoftheEPA2%basis.TotalDirectOperatingCosts(TDOC):Sumof1-9$601,307$1,090,671INDIRECTOPERATINGCOSTS1.PropertyTax1%ofTCC$275,469$346,7672.Insurance1%ofTCC$275,469$346,7673.GeneralAdministrative2%ofTCC$550,937$693,534CRF=0.1061[10%@$2,922,723$3,679,1974.CapitalRecoveryFactor30yr.]TotalCapitalChargesCosts(TCCC):Isumof1,2,3and4$4,024,598$5,066,264CAPITAL~$360,784$360,784TOTALANNUALIZEDOPERATINGCOSTSSumofTDOCTlOC~p98668975%controlofannualSO2emissions(.75x60.0tpy)=45.0$110,81575%controlofannualCOemissions(.75x73.0tpy)=54.8$91,08175%controlofannualNOxemissions(.75x13.4tpy)10.1$496,18875%controlofannualVOCemissions(.75x95.4tpy)=71.6$69,6955.0 EXISTING ENVIRONMENT

5.1 TOPOGRAPHY

The McElmo Creek Oil Production Facility is located on Navajo Nation land in southeastern Utah, in San Juan County, near the town of Aneth. The gas compression facility is located approximately 23 km (14 miles) northwest of the Utah / Colorado border and 4.8 km (3 miles) north of State Highway 262. Arches National Park and Canyonlands National Park are located to the northwest, approximately 160 km (100 miles) and 96 km (60 miles), respectively. Mesa Verde National Park is located approximately 60 km (38 miles) east of the gas compression facility site. The western boundary of the Canyon of the Ancients National Monument is approximately 16 km (10 miles) northwest of the plant site.

Elevations around the gas compression plant range from 5,500 feet to 5,900 feet. Terrain generally increases in both the north and south directions from the east-west valley formed by the San Juan River. Ground cover is relatively sparse because of the semiarid climatic conditions surrounding the gas compression facility site.

5.2 AIR QUALITY
Background air quality monitoring data for 1999-2003 are presented in Table 5-1 for ozone (03), nitrogen dioxide (NO2), carbon monoxide (CO), and sulfur dioxide (SO2). Ozone concentrations
are cited as surrogate for VOC impacts because VOCs do not have an ambient air quality standard; rather, VOC is considered a contributor to the formation of 03.

No site or area-specific data was available for southeastern Utah for NO2, CO, SO2 and 03; therefore, air quality data gathered from monitoring stations located in north central Utah, primarily within the Salt Lake City metropolitan area, are used as conservative indicators of air quality for this rural area of Utah. Background PM10 concentrations are not addressed since PM10 emissions are insignificant from a flare, and the Consent Decree does not cite emission limits for PM10.

5-1Table 5-1. Air Quality in the McElmo Creek Area. Pollutant NAAQS Monitor Maximum Annual Mean Location/County’ Year Averaging Period pp~~ig/m3 ppm! ~ig/m3 ppm j~g/m3 Spanish Fork/Utah 1999 8 hour 0.102 / 200 Spanish Fork/Utah 2000 8 hour 0.100 / 196 0.08 2 Ozone (03) Spanish Fork/Utah 2001 8 hour 0.081 / 159 157 Spanish Fork/Utah 2002 8 hour 0.08 1 / 159 Spanish Fork/Utah 2003 8 hour 0.080 / 157 North ProvofUtah 1999 Annual 0.024/45 North Provo/Utah 2000 Annual 0.024/45 Nitrogen Dioxide North Provo/Utah 2001 Annual 0.024/45 0.053 (NO2) North ProvofUtah 2002 Annual 0.025 / 47 100 North Provo/Utah 2003 Annual 0.022 / 41 North Provo/Utah 1999 8 hours 5 / 5, 726 North Provo/Utah 2000 8 hours 4 / 4,581 Carbon Monoxide 35 North Provo/Utah 2001 8 hours 4 / 4,581 (CO) North Provo/Utah 2002 8 hours 4 / 4,581 40,000 North Provo/Utah 2003 8 hours 3 / 3,436 North Salt Lake/Salt Lake 1999 3 hours 0.033 / 86 No data North Salt Lake/Salt Lake 2000 3 hours 0.042 / 110 No data Sulfur Dioxide 0.50

North Salt Lake/Salt Lake 2001 3 hours 0.041 / 107 No data (SO2) North Salt Lake/Salt Lake 2002 3 hours 0.052 / 136 No data 1,300

North Salt Lake/Salt Lake 2003 3 hours 0.03 6 / 94 No data North Salt Lake/Salt Lake 1999 24 hours 0.0 12 / 31 No data North Salt Lake/Salt Lake 2000 24 hours 0.014 / 37 No data 0.14 North Salt Lake/Salt Lake 2001 24 hours 0.013 / 34 No data 365 North Salt Lake/Salt Lake 2002 24 hours 0.010 / 26 No data North Salt Lake/Salt Lake 2003 24 hours 0.015 / 39 No data 1. No site-specific data is available. These monitoring locations provide the closest available data. 2. To attain this standard, the 3-year average of the fourth-highest daily maximum 8-hour average ozone concentrations measured at each monitor within an area over each year must not exceed 0.08 ppm. This table shows that with the exception of ozone, all pollutants are well below the National Ambient Air Quality Standards (NAAQS). Note that compliance with the 8-hour ozone NAAQS is based on the 3-year average of the ~ highest daily maximum value; Table 5-1 presents only the 15t highest ozone value for each year and cannot directly be compared to the 8-hour ozone standard. However, these concentrations represent maximum worst-case background conditions
as an indicator of potential compliance with the ozone NAAQS.

5.3 AREA CLIMATE AND METEOROLOGY

The southeastern area of the state, where the McElmo Creek facility is located, can be characterized as an area of low precipitation, high summer temperatures, and moderate winter temperatures. Meteorological monitoring has not been conducted onsite at the McElmo Creek facility. The nearest meteorological monitoring station with available data is located by

5-2International Uranium Corporation’s White Mesa Mill near Blanding, Utah. This data can be

considered as representative of the southeastern Utah area. The annual 2004 wind frequency distribution is presented in Table 5-2, and graphically as a wind rose in Figure 5-1. The average wind speed for 2004 was 3.4 meters/second (mis), or 7.6 miles per hour (mph). The predominant wind directions were from the north-northeast (15.5%), from the north (11%), and from the south-southwest (10.8%). Annual atmospheric stability distribution for 2004 is in Table 5-3.

Table 5-3. Annual Stability Class Distribution at Blanding, Utah.

Stability Class Percent of Occurrence (%) A 15.2 B 10.1 C 12.2 D 36.0 E 13.2 F 13.3
Temperature and precipitation conditions in vicinity of the McElmo Gas Compression Facility
are depicted by a long-term climatic monthly summary (12/8/1904

— 3/31/2005) of data from Blanding, Utah in Table 5-4.

Table 5-4. Monthly Average Temperature and Total Precipitation at Blanding, Utah.

Month Avg. Temp. Avg. Temp. Avg. Temp. Precipitation Total Max. (°F) Mi (°F) Mean (°F) (inches) January 39.1 17.1 28.1 1.39 February 44.8 22.3 33.6 1.23 March 52.7 27.8 40.3 1.04 April 62.2 34.3 49.3 0.87 May 72.2 42.0 57.1 0.71 June 83.3 50.7 67.0 0.45 July 88.6 57.8 72.2 1.15 August 86.2 56.1 71.1 1.39 September 78.2 48.3 63.3 1.28 October 66.0 37.9 51.9 1.45 November 51.4 26.6 41.0 1.06 December 41.1 19.1 30.1 1.35 Annual Avg. Temp./Annual Total Precip. 63.8 36.7 50.3 13.35

5-3Table 5-2

10 METER WIND DATA ANALYSIS
FROM 1/ 1/2004 THROUGH 12/31/2004
INTERNATIONAL URANIUM METEOROLOGICAL STATION

FREQUENCY OF OCCURRENCE OF WIND SPEED BY DIRECTION

+ WIND SPEED CLASSES (MIS) + AVERAGE 0.0— 1.8— 3.3— 5.4 8.4 > WIND DIR 1.8 3.3 5.4 8.4 11.0 11.0 TOTAL SPEED
N .0141 .0514 .0388 .0052 .0004 .0000 0.110 3.2
NNE .0216 .0895 .0360 .0028 .0012 .0001 0.151 2.9
NE .0231 .0370 .0098 .0018 .0005 .0000 0.072 2.5
ENE .0124 .0121 .0043 .0013 .0000 .0000 0.030 2.4
E .0082 .0072 .0031 .0008 .0000 .0000 0.019 2.5
ESE .0085 .0091 .0024 .0012 .0000 .0000 0.021 2.4
SE .0097 .0186 .0095 .0028 .0002 .0000 0.041 3.4
SSE .0108 .0242 .0112 .0018 .0006 .0000 0.049 2.9
S .0100 .0375 .0254 .0079 .0014 .0000 0.082 3.5
SSW .0073 .0352 .0376 .0199 .0057 .0020 0.108 4.4
SW .0073 .0227 .0197 .0170 .0026 .0011 0.070 4.3
wSw .0054 .0134 .0109 .0105 .0020 .0001 0.042 4.3

w .0064 .0109 .0098 .0082 .0004 .0004 0.036 3.9
WNW .0071 .0117 .0078 .0033 .0000 .0000 0.030 3.2
NW .0087 .0179 .0162 .0095 .0017 .0000 0.054 3.9
NTh~JW .0110 .0218 .0322 .0164 .0026 .0002 0.084 4.1
TOT: 0.172 0.420 0.275 0.110 0.019 0.004 1.000 AVG: 1.4 2.6 4.2 6.7 9.4 12.0 3.4
TOTAL NUMBER OF VALID READINGS FOR THIS TABLE => 8456

OUT OF 8456 TOTAL VALID HOURS TOTAL NUMBER OF MISSING HOURS => 328 TOTAL NUMBER OF CALM HOURS => 41Wind Speed White Mesa Mill

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COMMENTS DATA PERIOD: COMPANY: 2004 international Uranium Corporation Jan 1

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CALM WINDS TOTAL COUNT 

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AVG. WINDSPEED DATE: PROJECT NO 3.43 mIs 111 9(2005 1721-03

WRPLOT View

- Lakes Environmental Software5.4 SOILS AND VEGETATION

Soils within this area of Utah have textural, depth, and drainage characteristics that limit the amount of water the soils can hold and make available for plant growth. Vegetation in the vicinity of the project area is sparse, predominantly sagebrush with scattered grasses and forbs. No listed threatened or endangered plant species are known to occur within the project area.

5-46.0 IMPACT ASSESSMENT APPROACH

This section presents the methodology used to evaluate the potential ambient air quality impacts resulting from the operation of the Main Flare. These analyses are compared against the National Ambient Air Quality Standards (NAAQS) and PSD increments presented in Table 6-1.

TABLE 6-1 SUMMARY OF NATIONAL AMBIENT AIR QUALITY STANDARDS AND PSD INCREMENTS

NAAQS Class II PSD Averaging Primary Increment Pollutant Time ~tgIm3 (ppm) ~Ig/m3 (ppm) Carbon Monoxide 1~houra 40,000 (35)

-- 8-hou? 10,000 (9)

-- Nitrogen Dioxide Annual (arith. mean) 100 (0.05) 25 (0.013)
Ozone 8-Hour” (0.08)

-- Particulates (PM10) 24~houra 150 (--) 30 (--)
Annual (arith. mean) 50 (--) 17 (--)
Sulfur Dioxide 3~houra 1,300 (0.50) 512 (0.20)
24-hou? 365 (0.14) 91 (0.035)
Annual (arith. mean) 80 (0.03) 20 (0.008)
Lead Calendar Quarter (arith. mean) 1.5 (--)

--

a. Not to be exceeded more than once per year. b. The 3-year average of the 4th highest daily maximum concentrations must not exceed this standard.

6-16.1 AIR QUALITY MODEL DESCRIPTION

SCREEN3 is an EPA-approved screening model for estimating near-field impacts from a single emission source or group of emission sources that can be characterized from one location. SCREEN3 utilizes Gaussian dispersion to estimate concentrations within a plume, with maximum impacts estimated at the plume centerline. Version 96043 of SCREEN3 was used for this application.

SCREEN3 transport is assumed to instantaneously occur at specified receptor distances from the
source with specific dispersion dependent upon the atmospheric stability class, using Pasquill stability categories and wind speed. The intended use of SCREEN3 is for short-term averaging periods on the order of one hour or less. However, estimated maximum short-term impacts can be extrapolated to longer averaging periods by adjustment factors referenced from the “Screening Procedures for Estimating the Air Quality Impact of Stationary Sources” (EPA, 1992). These factors are intended to account for long-term wind direction meander as summarized below:

Averaging Time Multiplying Factor 3 hours 0.9 8 hours 0.7 24 hours 0.4 Annual 0.08

The SCREEN3 model is most suitable for estimating concentrations for distances greater than 100 meters from the source and for source plume heights less than 300 meters. In addition, SCREEN3 internally examines a full range of meteorological conditions, representative of possibly occurring stability class and wind speed combinations to find maximum impacts.

The SCREEN3 model also simulates the effects of buoyancy-induced dispersion (BID). The inclusion of BID in SCREEN3 can affect estimated concentrations, depending on the source and distance. For sources with plume heights below 300 meters, the effect of BID on estimated maximum concentrations will usually be less than about ± 10 percent. For elevated sources with relatively large buoyancy, the inclusion of BID may be expected to decrease the estimated maximum concentration by as much as 25 percent.

6-26.2 MODEL INPUT

The Main Flare is a point (stack) source that routinely operates in the stand-by mode as reflected in the annual emissions presented as limits in Section 3. For modeling purposes, particularly for comparison to short-term standards and PSD increments, the worst-case impacts from the Main Flare would be during an upset episode when all process gas is sent to the flare, rather than re injected into the ground. Thus, modeled flare stack parameters were based on using the buoyancy flux algorithm in SCREEN3. This algorithm estimates an effective stack diameter at
an assumed stack velocity of 20 mIs at the estimated heat release (in calories per second) of the flare when combusting all process gas that would otherwise be re-injected.
Modeling was performed to estimate impacts of NO2, CO and SO2 only, since PM10 emissions
are insignificant and VOCs are not modeled directly except as a precursor to ozone. The annual emission limit for VOCs (95.4 tons per year) is below the 100 ton per year criterion typically cited as that level requiring ozone modeling.

Refer to Section 6.4 for additional information about source characteristics and emission rates used in the model input.

6.3 METEOROLOGICAL DATA

The selection of an appropriate meteorological data set for air quality modeling is based on proximity to the project site, similarity of topography and conformity of the data collection and reporting procedures to PSD monitoring requirements. Another consideration is that the meteorological data can be readily processed into a format compatible for use in air dispersion modeling.

For this screening model application, the full array of 44 discrete meteorological conditions internally generated by SCREEN3 was used to estimate potential worst-case short-term (i.e., one-hour averaged) impacts for each modeled pollutant. The maximum impact cited by SCREEN3 from a specific discrete meteorological condition (wind speed, stability class and mixing height combination) and receptor distance was used as the basis for estimating maximum pollutant impacts. The maximum one-hour impact for each pollutant was extrapolated to values

6-3for each averaging period for which a pollutant has an applicable NAAQS and PSD increment,

using the adjustment factors referenced in Section 6.1.

6.4 SOURCE CHARACTERISTICS AND EMISSION RATES

6.4.1 Flare Rate and Heat Release

Short-term pollutant emission rates were estimated by assuming that the maximum volume of process gas that could be generated from the well field would be sent to the flare at two different heat content values (in BTU/SCF). These two heat content values represent lower and upper range estimates. The lowest value input was 300 BTU/scf, which is the lowest allowable LHV
as stated in 40 CFR 60.1 8(c)(3)(ii). The higher value utilized was 443 BTU/scf, which is the lowest of four recent actual plant gas samples from McElmo. (The four analyses are dated 4/28/04, 5/27/04, 8/29/04, and 9/29/04; and their LHV values were 443, 505, 512, and 453 BTU/scf, respectively.) The LHV of 443 BTU/scf was utilized due to the assumption that it would provide the least amount of heat rise, thus producing the lowest effective release height.

The maximum flare rate utilized was 689,423 acfThr (618,104 scf/hr), which assumes that the flare is operating at 14.83 MMCFD for the entire year. The flare rate value of 618,104 scf/hr
was based on the assumption that the new flare tip will be 24 inches in diameter and will have a flare tip exit velocity of 64.74 fl/s. This exit velocity is below the maximum exit velocity as specified by 40 CFR 60.18, which is 66.98 fl/s.

The heat released from the flare tip was then calculated and converted to a rate of calories per second based on the conversion of 1 BTU

= 252.1644 calories. The equation used for this calculation is as follows:
(LHV)(V)(252. 1 644ca1) heat(cal/s)

= 3600s

Where: LHV

= lower heating value of gas burned (BTU/scf)

V

= 618,104 scf/hr.

6-46.4.2 Flare Height

The actual flare stack height of 195 feet was taken from drawing D-SA-107 as provided by Zeeco, Inc. from 1991. This measurement was field verified to ensure proper stack height.

6.4.3 Modeled Emission Rates

The emission factors for N0~ and CO were derived by the Chemical Section of the Texas Commission on Environmental Quality NSR Division based on data published in the 1983 Chemical Manufacturer’s Association document entitled “A Report On A Flare Efficiency Study.” The factors used were as follows:

NO~

= 0.064 1 1b/MMBTU CO

= 0.5496 lb/MMBTU.

Therefore, the equation used to calculate the emission rate for NO~ and CO contaminants at the specified LHV is as follows:

rate(g/s)

= V~L*LHV BTU * MMBTU *EF lb * 453.59g * hr

hr scf 106 BTU MMBTU lb 3600s

‘Where: V

= 618,104 scfYhr LHV

= lower heating value of gas burned (BTU/scf) EF

= emission factor (1bIMMBTU).

Regarding the SO2 emission calculation, recent tests at the McElmo site indicate the plant inlet gas contains approximately 500 ppm H2S. However, it was assumed that the flared gas contains 700 ppm H2S on the SCREEN3 SO2 dispersion model. This H2S value was used in order to provide a conservative estimate of SO2 emissions from the flare. The emission rate was calculated as follows:

6-5rate

= 618,lO4scf/hr * 700ppm * 641b/molSO2

= 73O6lbSO2/h 379scf / mol * lMMparts

In summary, the stack parameters and estimated emission rates for the Main Flare at the two representative heat content values during upset conditions are summarized below in Table 6-2.

Table 6-2 SCREEN3 Modeled Stack Parameters and Emissions for the Main Flare (Maximum Volumetric Process Gas Flow of 618.104 SCF/hr) Heat Total Heat Stack Effective Stack Short-Term Short-Term Short-Term Content Release Height Release Velocity NO~ Emission SO2 Emission CO Emission (BTUISCF) (cal/see) (m.) Height (m.) (mis) Rate (gm/see) Rate (gmlsec) Rate (gm/see) 300 12,988,700 59.45 70.9117 20.0 1.50 9.21 12.84 443 19,179,900 59.45 73.2591 20.0 2.21 9.21 18.96

6.5 RECEPTOR SELECTION
Receptor points were generated using the automated grid option of SCREEN3, starting at 200 meter from the Main Flare and extending out to 4,000 meters. Since the flare is a highly buoyant
source with a stack height of nearly 60 meters, in-close impacts would be minimal and maximum ground-level impacts would likely be located at least one or more kilometers away from the stack. Receptors were placed at 100 meter intervals from 200 to 3,000 meters and at 500 meter intervals from 3,000 to 4,000 meters.

Since terrain within 5 kilometers of the Main Flare is relatively flat, SCREEN3 was run in the simple terrain mode and all receptor elevations were assumed to be at the elevation of the Main Flare stack base.

6.6 CLASS I AREA IMPACTS

A telephone conversation with Mr. John Notar of the National Park Service on June 15, 2006, followed up by an e-mail message from Mr. Notar dated June 21, 2006, provided guidance on the level of detail required for the Class I area impact analysis. Mr. Notar indicated in his June

6-621St e-mail that estimated emissions from the flare are sufficiently small to not require a detailed

quantitative analysis of ambient air quality and air quality related value impacts on nearby Class I and sensitive Class II areas. Appendix D contains documentation of Mr. Notar’s guidance in his June 21st e-mail.

A general discussion of ambient air quality impacts is presented based on the SCREEN3 modeling results at a receptor distance of 50 km. away from the modeled flare emissions. The selection of a receptor distance of 50 km. is based on regulatory guidance stating that 50 km. is the furthest distance at which application of a near-field model is deemed appropriate. VISCREEN was used to estimate visibility impacts at the nearest Class I area, Mesa Verde National Park (approximately 60 km. from the McElmo Gas Compression Facility). Annual averaged ambient air quality impacts of NO~ and SO2 based on SCREEN3 modeling were used to estimate deposition impacts.

6.7 ADDITIONAL IMPACTS ANALYSIS

EPA Region IX’s comment letter of May 22, 2006 stated that additional impacts from secondary growth, soils and vegetation and visibility impairment must be performed even for a source with small emissions. These additional impacts are addressed by:

1. No secondary growth is associated with Main Flare operations as existing manpower used for operation of the McElmo Gas Compression Facility is sufficient.

2. Soils and vegetation impacts are addressed by deposition considerations presented in Section 7.4.3.

3. Visibility impairment is addressed in Section 7.4.2 and VISCREEN has been used to estimate visibility impacts.

6.8 ENDANGERED SPECIES

The effect on threatened and endangered species and critical habitat within the region surrounding Aneth, Utah would be assessed if discernible effects are deemed to potentially

6-7occur. Mr. Henry Maddux, Utah Endangered Species Field Supervisor, was contacted to

determine if such an effects analysis is necessary. Mr. Maddux responded via an e-mail dated June 29, 2006 that the Main Flare emissions addressed in the Consent Decree have no effect on listed species and their critical habitat in the region surrounding Aneth, Utah. Therefore, no further analyses of effects on endangered species and critical habitat were performed.
Appendix D contains documentation of Mr. Maddux’s guidance in his June 29th e-mail.

6-87.0 AIR QUALITY IMPACTS

This section presents modeled air quality impacts of the Main Flare facility to demonstrate compliance with the National Ambient Air Quality Standards (NAAQS) and Prevention of Significant Deterioration Increments for Class II Areas. Air quality impacts are presented from the Main Flare alone and combined with representative ambient air background concentrations for an assessment of cumulative impacts.

As discussed in the previous section, in order to conservatively calculate emission rates from the Main Flare for use in this modeling analysis, several assumptions were made. Many of these assumptions were made with the intent of providing conservative estimates including:

1. The lowest heat value rating for the gas at McElmo to lower the effective release height of the emissions produced by the McElmo Main Flare; 2. The maximum design flare rate of 14.83 MMCFD; and 3. The H2S concentration of 700 ppm instead of the actual measured value of approximately 450 ppm.

Emission limitations established by the Consent Decree for the Main Flare are 60 tons per year of SO2, 73 tons per year of CO, 13.4 tons per year of NON, and 94.5 tons per year of VOC. However, the worst-case conditions based on the modeled maximum flare rate of 14.83 MMCFD and LHV of 443 BTU/scf result in emissions of 320.00 tons per year of SO2, 659.1 tons per year of CO, and 76.8 tons per year of NON. These very conservative worst-case conditions result in emission rates in the analysis that are over five times greater than current air permit limits. In addition, the actual field conditions are not capable of sustaining a flow rate of 14.83 MMCFD. The remainder of this section will show that even with these worst-case emission estimates that far exceed the current air permit limits and actual flow rate conditions, the modeling results show
no exceedances of the NAAQS or the PSD Class II Increments.

Hard copies of the SCREEN3 model run input and output are contained in Appendix B. Model
runs for estimated NO2, CO and SO2 impacts for process gas with a heat content of either 300 or 443 BTU/SCF were generated.7.1 NITROGEN DIOXIDE (NO2)

The Main Flare was modeled at the heat content scenarios of 300 and 443 BTU/SCF. The modeled impact concentrations from SCREEN3 were multiplied by a factor 0.75, the default
ozone limiting factor, and the annual averaging period adjustment factor of 0.08. The ozone limiting factor takes into account the conversion of NO (the majority of a NOx release) to NO2 by reacting with ozone, assuming that approximately 75% is converted as a long-tenn average. A maximum background annual averaged NO2 concentration from Table 5-1 of 47 ~g/m3 is cited
as the value to add to the maximum modeled annual NO2 impact to obtain an estimate of cumulative impacts for comparison to the NO2 NAAQS.

7.1.1 Increment Consumption

Table 7-1 summarizes estimation of the maximum annual averaged NO2 impact from the Main Flare, with a heat content of either 300 or 443 BTU/SCF. The resultant values from the Main Flare are compared to the annual NO2 PSD Class II Increment.

Table 7-1 Comparison of Modeled Main Flare NO2 Impacts to the PSD Increment

Max. Modeled Max. Adjusted Heat One-Hour Modeled PSD Class II Percent of Content Concentration Averaging Adjustment Concentration Increment Increment (BTU/SCF) (uglm3) Period Factora (uglm3) (ug/m3) (%)

300 1.893 Annual 0.06 0.11 25 0.44% 443 2.148 Annual 0.06 0.13 25 0.52%

a. Combination of ozone limiting adjustment factor of 0.75 and the annual averaging period adjustment factor of 0.08. (0.75 x 0.08
= 0.06)

The predicted maximum annual averaged concentration from the Main Flare is 0.13 ~.tg/m3 located 1,075 meters from the flare stack. This maximum concentration is approximately only 0.52% of the PSD Class II increment of 25 ~g/m3. In addition, the maximum annual concentration is only 13% of the Class II significant impact level (SIL) of 1 ~tg/m3.

7-27.1.2 National Ambient Air Quality Standards (NAAQS)

Table 7-2 provides a comparison of the estimated cumulative maximum annual averaged NO2 impact from the Main Flare, with a heat content of either 300 or 443 BTU/SCF, to the annual NO2 NAAQS. The modeled results are added to the cited background concentration to arrive at the estimated cumulative concentration, and the total value is compared to the annual NO2 NAAQS.

Table 7-2.

Comparison of Modeled Cumulative NO2 Impacts to the NAAQS

Max. Modeled Max. Adjusted Monitored Maximum National Heat One-Hour Modeled Background Cumulative Ambient Air Percent of Content Concentration Averaging Adjustment Concentration Concentration Concentration Quality Std. NAAQS (BTU/SCF) (uglm3) Period Factor (uglm3) (uglm3) (uglm3) (uglm3) (%)

300 1.893 Annual 0.06 0.11 47.00 47.11 100 47.11% 443 2.148 Annual 0.06 0.13 47.00 47.13 100 47.13%

The predicted maximum annual averaged concentration from the Main Flare is 0.13 ~g/m3 located 1,075 meters from the flare stack. This maximum concentration, added to the background concentration of 47 ~g/m3, results in a cumulative concentration which is approximately 47.13% of the NAAQS.

7.2 SULFUR DIOXIDE (SO2)

The Main Flare was modeled at the heat content scenarios of 300 and 443 BTU/SCF. The modeled impact concentrations from SCREEN3 were multiplied by the 3-hour, 24-hour and annual averaging period adjustment factors of 0.90, 0.40 and 0.08, respectively. Maximum background 3-hour, 24-hour and annual averaged SO2 concentration from Table 5-1 of 136, 39 and 39 ~g/m3 are cited as the values to add to the maximum modeled SO2 impacts from the Main Flare to obtain an estimate of cumulative impacts for comparison to the SO2 NAAQS. Note that the cited 24-hour background concentration has been assumed to also represent the annual background concentration since no specific annual averaged monitoring data were available.

7-37.2.1 Increment Consumption

Table 7-3 summarizes estimation of the maximum 3-hour, 24-hour and annual averaged SO2 impacts from the Main Flare, with a heat content of either 300 or 443 BTU/SCF. The resultant maximum values from the Main Flare are compared to the SO2 PSD Class II Increments.

Table 7-3 Comparison of Modeled Main Flare SO2 Impacts to the PSD Increment
Max. Modeled Max. Adjusted Heat One-Hour Modeled PSD Class II Percent of Content Concentration Averaging Adjustment Concentration Increment Increment (BTU/SCF) (uglm3) Period Factor (uglm3) (uglm3) (%)

300 11.63 3-hour 0.90 10.47 512 2.04% 443 8.951 3-hour 0.90 8.06 512 1.57% 300 24-hour 0.40 4.65 91 5.11% 443 24-hour 0.40 3.58 91 3.93% 300 Annual 0.08 0.93 20 4.65% 443 Annual 0.08 0.72 20 3.60%

The predicted maximum 3-hour, 24-hour and annual averaged concentrations from the Main Flare are 10.47, 4.65 and 0.93 ~g/m3, respectively, located 1,097 meters from the flare stack. These maximum concentrations are approximately only 2.04%, 5.11% and 4.65% of the PSD Class II increments of 512, 91 and 20 ~iWm3.for the 3-hour, 24-hour and annual averaging periods, respectively. In addition, the maximum 3-hour, 24-hour and annual concentrations are less than the Class II SILs of 25, 5 and 1 ~tg/m3, respectively.

7.2.2 National Ambient Air Quality Standards (NAAQS)

Table 7-4 provides a comparison of the estimated cumulative maximum 3-hour, 24-hour and annual averaged SO2 impacts from the Main Flare, with a heat content of either 300 or 443 BTU/SCF, to the corresponding SO2 NAAQS. The modeled results are added to the cited background concentrations to arrive at the estimated cumulative concentration for each averaging time, and the total value is compared to the 3-hour, 24-hour and annual SO2 NAAQS.

7-4Table 7-4. Comparison of Modeled Cumulative SO2 Impacts to the NAAQS
Max. Modeled Max. Adjusted Monitored Maximum National Heat One-Hour Modeled Background Cumulative Ambient Air Percent of Content Concentration Averaging Adjustment Concentration Concentration Concentration Quality Std. NAAQS (BTU/SCF) (ug/m3) Period Factor (uglm3) (uglm3) (uglm3) (uglm3) (%)

300 11.63 3-hour 0.90 10.47 136 146.47 1300 11.27% 443 8.951 3-hour 0.90 8.06 136 144.06 1300 11.08% 300 24-hour 0.40 4.65 39 43.65 365 11.96% 443 24-hour 0.40 3.58 39 42.58 365 11.67% 300 Annual 0.08 0.93 39 39.93 80 49.91% 443 Annual 0.08 0.72 39 39.72 80 49.65%

The predicted maximum 3-hour, 24-hour and annual averaged concentrations from the Main Flare are 10.47, 4.65 and 0.93 ~gIm3, respectively, located 1,097 meters from the flare stack. These maximum concentrations added to the background concentrations of 136, 39 and 39 ~~g/m3 result in cumulative concentrations of 11% to 12% of the 3-hour and 24-hour averaged NAAQS of 1300 and 365 ~Wm3, respectively, and less than 50% of the annual averaged NAAQS of 80 ~LgIm3.

7.3 CARBON MONOXIDE (CO)

The Main Flare was modeled at the heat content scenarios of 300 and 443 BTU/SCF. The modeled impact concentrations from SCREEN3 were multiplied by the 1-hour and 8-hour averaging period adjustment factors of 1.00 and 0.70, respectively. The maximum background 1-hour and 8-hour averaged CO concentration from Table 5-1 of 5,726 ~g/m3 is cited as the value to add to the maximum modeled CO impacts from the Main Flare to obtain an estimate of cumulative impacts for comparison to the CO NAAQS. Note that the cited 8-hour background concentration has been assumed to also represent the 1-hour background concentration since no specific 1-hour averaged monitoring data was available.

7.3.1 National Ambient Air Quality Standards (NAAQS)

Table 7-5 provides a comparison of the estimated cumulative maximum 1-hour and 8-hour averaged CO impacts from the Main Flare, with a heat content of either 300 or 443 BTU/SCF, to

7-5the corresponding CO NAAQS. The modeled results are added to the cited background

concentrations to arrive at the estimated cumulative concentration for each averaging time, and the total value is compared to the 1-hour and 8-hour CO NAAQS.

Table 7-5. Comparison of Modeled Cumulative CO Impacts to the NAAQS
Max. Modeled Max. Adjusted Monitored Maximum National Heat One-Hour Modeled Background Cumulative Ambient Air Percent of Content Concentration Averaging Adjustment Concentration Concentration Concentration Quality Std. NAAQS (BTU/SCF) (uglm3) Period Factor (uglm3) (uglm3) (ug/m3) (uglm3) (%)

300 16.21 1-hour 1.00 16.21 5,726 5742.21 40,000 14.36% 443 18.43 1-hour 1.00 18.43 5,726 5744.43 40,000 14.36% 300 8-hour 0.70 11.35 5,726 5737.35 10,000 57.37% 443 8-hour 0.70 12.90 5,726 5738.90 10,000 57.39%

The predicted maximum 1-hour and 8-hour averaged concentrations from the Main Flare are 18.43 and 12.90 ~g/m3, respectively, located 1,075 meters from the flare stack. These maximum concentrations added to the background concentrations of 5,726 p~g/m3 results in cumulative concentrations of 14.36% of the 1-hour and 57.39% of the 8-hour averaged NAAQS of 40,000 and 10,000 ~tg/m3, respectively.

In addition, the maximum 1-hour and 8-hour averaged concentrations of 18.43 and 12.90 ~g/m3
are less than the Class II SILs of 2,000 and 500 ~tg/m3, respectively.

7.4 CLASS I AREA IMPACTS

Modeled SCREEN3 impacts at receptors located 50 km. from the flare are used to provide the qualitative discussion of impacts on ambient air quality and air quality related values presented below. The selection of a receptor distance of 50 km. is based on regulatory guidance stating that 50 km. is the furthest distance at which application of a near-field model is deemed appropriate.

SCREEN3 was used to estimate impacts at 50 km. from the flare with a unit emission rate of 1.0 gm/sec. Since the resultant impact is for a short-term averaging period of one hour or less,

7-6averaging period adjustment factors described for Class II area impacts are applied to

qualitatively estimate impacts at Class I and sensitive Class II areas located 50 km. or more from the McElmo Gas Compression Facility. The estimated maximum impact at 50 km. from the flare for a one-hour averaging period with a unit emission rate is 0.243 ~g/m3. The nearest Class I areas are Mesa Verde National Park, Canyonlands National Park and Arches National Park. The distances to these three Class I areas from the main flare are 60, 96 and 160 km., respectively.

7.4.1 Class I Increments

The maximum modeled one-hour impact at 50 km. from the flare with a unit emission rate, adjusted for averaging period and using pollutant-specific short-term and annualized emission rates, provides conservative estimates of Class I and sensitive Class II area impacts. Table 7-6 shows that maximum NO2 and SO2 impacts are well below applicable PSD Class I area increments even with assuming flare upset emissions and assessing impacts at 50 km. away. A print-out of the SCREEN3 model run is included in Appendix E.

TABLE 7-6. CLASS I AREA AMBIENT AIR IMPACTS

Max. 1-hr. 3-Hour 24-Hour Annual ChiIQ Class I Class I Class I Impact 3-Hour Increment 24-Hour Increment Annual Increment Pollutant (~ig/m3) (~g/m3) (~g/m3) (~g/m3) (~g/m3) (~gIm3) (~gIm3)

NO2 0.243

-- -- -- -- 0.0056 2.5 SO2 0.243 2.0142 25.0 0.8952 5.0 0.0336 2.0

7.4.2 Visibility

Since Mesa Verde National Park is the closest Class I area to the McElmo Gas Compression Facility, VISCREEN was used to estimate visibility impacts from the Main Flare. Since the nearest distance of Mesa Verde to the Main Flare is approximately 60 km., use of VISCREEN is appropriate given the closeness of this distance to the 50 km. range cited for near-field models. A print-out of the VISCREEN run is presented in Appendix B.

7-7Based on the results of the VISCREEN run, visibility impacts at Mesa Verde National Park from

the Main Flare are less than the Level I screening thresholds. These thresholds state that plumes resulting from the proposed action will not cause an hourly change in extinction (AE) greater than or equal to 2.0, or cause an absolute plume contrast (Cr) greater than or equal to 0.05. Impacts at the more distant Class I areas would even be lower.

7.4.3 Deposition

Sulfur (S) and nitrogen (N) deposition were conservatively assessed by using the Level I screening methodology presented in the IWAQM Phase 1 document, which assumes that concentrations of NO2 and SO2 are deposited as HNO3 and SO2. This methodology assumes that all NO~ is converted to HNO3. Maximum annual impacts of NOx and 502 were predicted by SCREEN3 at 50 km. from the Main Flare by using the SCREEN3 model results, and the resulting NO~ impacts were then converted to HNO3. This approach provides a conservative estimate of deposition, as SCREEN3 does not account for any removal of mass from the plume (i.e., depositional settling) during transport to the Class I areas.
Resulting HNO3 and SO2 impacts were then multiplied by conservative depositional velocity rates for each pollutant to assess nitrate and sulfate deposition in Class I areas at least 50 km. away. Assumed depositional velocity rates are 0.05 m/s and 0.005 m/s for nitrogen and sulfur deposition, respectively. Initial estimates were then multiplied by two to account for both wet and dry deposition. Estimated nitrate and sulfate deposition are presented in Table 7-7.

TABLE 7-7. CLASS I AREA DEPOSITION IMPACTS

NO2 Cone. Nitrate Deposition SO2 Conc. Sulfate Deposition Class I Area (pg/rn3) (kgfha-yr) (pg/rn3) (kg/ha-yr)
Any Class I Area ~ 50 km. away 0.00749 0.32368 0.03355 0.1058 1

These conservative estimates of deposition impacts are well below any threshold effects levels for soils and vegetation which typically start at approximately 3.0

- 5.0 kg/ha-yr.

7-88.0 REFERENCES

Baukal, Jr., C. (Ed.). (2001). The John Zink Combustion Handbook. CRC Press: New York.

Consent Decree, United States of America v. Mobil Exploration & Producing, U.S., Inc., DOJ Case No. 90-5-2-1-223 7, filed June 8, 2005 in United States District Court, District of Utah.

U.S. Environmental Protection Agency, 2000. Compilation of Air Pollution Emissions Factors,

5th Edition, AP 42, Office of Air and Radiation, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina.

U.S. Environmental Protection Agency (EPA) Electronic Bulletin Board, RACT/BACT/LAER Clearinghouse.

8-1APPENDIX A EXXONMOBIL MCELMO CREEK OIL PRODUCTION UNIT

CONSENT DECREE

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 1 of 35

10
11



### 23 24
25
26 

### 27 THOMAS L. SANSONETTI Assistant Attorney General ROBERT 1). MULLANEY Trial Attorney Environment and Natural Resources Division United States Department of Justice 301 Howard Street, Suite 1050 San Francisco, California 94105 Telephone: (415) 744-6491 PAUL M. WARNER (Utah Bar No. 3389) United States Attorney JEANNETTE SWENT (Utah Bar No. 6043) Assistant United States Attorney District of Utah 185 South State Street, Suite 400 Salt Lake City, Utah 84111 Telephone: (801) 524-5682 Attorneys for Plaintiff United States of America LARRY W. LINDEEN Exxon Mobil Corporation 800 Bell Street Houston, Texas 77002-7426 Telephone: (713) 656-3429 MI~R1cUS 

### B SY.ZIMMERCL

Judge Paul G. Cassell DECK TYPE: C~yi1 DATE STAKP: 04/08/2005 @ 11:35:40 CASE NU1~8ER: 2:05CV00319 PGC 1
2 

### 3
4
5 6
7 8
9 :;. FILE ~

• I.. 

## JUN 082005 ,,..~ •1’

12 13
14
15 16
17 18 

### 19
20
21 22 Attorney for Defendant Mobil Exploration & Producing U.S. Inc.

IN THE UNITED STATES DISTRICT COURT DISTRICT OF UTAH, CENTRAL DIVISION UNITED STATES OF AMERICA, CIVIL ACTION NO.

CONSENT DECREE Plaintiff,

V. MOBIL EXPLORATION & PRODUCING U.S. INC.,

Defendant. 

## )

) ) ) ) ) ) ) ) )

28

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 2 of 35

1 TABLE OF CONTENTS
2 I. JURISDICTION AND PARTIES BOUND 1 3 II. DEFINiTIONS 2 4 III. OBJECTIVES 6 5 IV. CIVIL PENALTY 6 6 V. COMPLIANCE MEASURES 7 7 9. Emission Limits 7

10. Monitoring 9 8 11. Operation and Maintenance of Main Flare and Compressors 10

12. Root Cause Analysis 11 9 13. Corrective Action 13

14. Permitting 14 10 VI. SUPPLEMENTAL ENVIRONMENTAL PROJECT 15 11 18. SEP Completion Report 16
12 VII. COMPLIANCE REPORTING AND RECORDKEEPING 17 13 Vifi. STIPULATED PENALTIES 19

27. Stipulated Penalties 19 14 29. Interest 22 15 IX. RIGHT OF ENTRY 23 16 X. FORCE MAJEURE 23
17 XI. DISPUTE RESOLUTION 25 18 XII. NOTIFICATION 26 19 XIII. EFFECT OF SETTLEMENT/NON-WAIVER PROVISIONS 27 20 XIV. EFFECTIVE DATE AND TERMINATION 28
21 XV. MISCELLANEOUS 29

54. Fees 29 22 55. Integration and Modifications 29

56. Retention of Jurisdiction 29 23 57. Public Comment 30

58. Final Judgment 30 24 25 

### 26
27
28 i

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 3 of 35

1 WHEREAS, concurrent with the Lodging of this Consent Decree, Plaintiff United States
2 of America, on behalf of the United States Environmental Protection Agency (“EPA”), is filing a 3 Complaint against Defendant Mobil Exploration & Producing U.S. Inc. (hereinafter referred to as 4 “Mobil” or “Defendant”), alleging violations of the federal Clean Air Act, 42 U.S.C. 

## §~ 7401-
5 7671q (the “Act”), at Mobil’s McElmo Creek Unit oil production facility and associated oil 6 fields (the “Facility”), located near Aneth, Utah, on the Navajo Nation;
7 WHEREAS, Mobil, without filing any answer in this action, neither admits nor denies the
8 violations alleged in the Complaint;
9 WHEREAS, the Parties recognize, and the Court by entering this Consent Decree finds, 10 that this Consent Decree has been negotiated by the Parties in good faith and that this Consent
11 Decree is fair, reasonable, and in the public interest;
12 NOW, THEREFORE, before taking any testimony, without the adjudication of any issue
13 of fact or law, and upon the consent and agreement of the Parties to this Consent Decree, it is
14 hereby ORDERED, ADJUDGED, AND DECREED as follows:
15 I. JURISDICTION AND PARTIES BOUND
16 1. This Court has jurisdiction over the subject matter of this action under Section
17 113(b)of the Act, 42 U.S.C. 

## § 7413(b), and 28 U.S.C. 

## §~ 1331, 1345, and 1355. This Court also
18 has personal jurisdiction over Defendant. Venue is proper in this judicial district under Section
19 113(b)oftbeAct,42U.S.C. 

## § 7413(b), and28 U.S.C. 

## §~ 1391 and 1395,becauseitisthe 20 judicial district in which Mobil resides and in which the violations alleged in the Complaint have
21 occurred and are occurring. Notice of the commencement of this action has been given to the
22 Utah Department of Environmental Quality and the Navajo Nation Environmental Protection
23 Agency in accordance with Section 113(b) of the Act, 42 U.S.C. 

## § 7413(b). Mobil consents to 24 and shall not challenge entry of this Consent Decree or this Court’s jurisdiction to enter, enforce,
25 modify, or terminate this Consent Decree.
26 2. This Consent Decree shall apply to and be binding upon Mobil and its successors 27 28 1

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 4 of 35

1 and assigns, and upon the United States on behalf of EPA.
2 3. If Mobil transfers any ownership interest or right to operate the Facility, including,
3 but not limited to, the sale, lease, or licensing of others to operate all or part of the Facility, Mobil
4 shall give notice of this Consent Decree to any successor-in-interest prior to such transfer. Mobil
5 shall send a copy of such written notification to EPA, at the address listed in Section XII 6 (Notification) of this Consent Decree, concurrently with such sale or transfer. Upon sale or 7 transfer of such Facility, Mobil shall attach a copy of this Consent Decree to the agreement by 8 which such Facility is sold or transferred and shall make performance of the obligations of Mobil
9 under this Consent Decree an obligation of any purchaser or transferee. For 180 days after sale 10 or transfer of such Facility, Mobil and its successor in interest shall be jointly and severally liable
11 for obligations under this Consent Decree. Thereafter, Mobil shall either retain or be relieved of
12 its obligations under the Consent Decree as provided in Appendix A.
13 IL DEFINITIONS
14 4. Unless otherwise expressly provided herein, terms used in this Consent Decree
15 shall have the meanings assigned to those terms in the Act, 42 U.S.C. 

### §~ 7401-7671q, and the
16 federal rules and regulations promulgated thereunder. Whenever terms listed below are used in
17 this Consent Decree or any appendices or documents incorporated by reference hereto, the
18 following definitions shall apply: 19 a. “Act” shall mean the Clean Air Act, as amended, 42 U.S.C. 

### §~ 740 1-
20 7671q.
21 b. “C.F.R.” shall mean the Code of Federal Regulations.
22 c. “CO” shall mean carbon monoxide. 

### 23 d. “CO2 Breakthrough” shall mean an event where a gas or fluid injected in
24 the Facility’s oil field for the purpose of promoting the production of oil contacts a producing
25 well and results in an increase in gas volume to compressor station equipment.
26 e. “Consent Decree” or “Decree” shall mean this written agreement and all
27 

### 28 2

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 5 of 35

I appendices hereto and any modifications of the agreement or appendices. 2 f. “Day” shall mean a calendar day, unless expressly stated to be a working
3 day. In computing any period of time under this Consent Decree, where the last day of such
4 period would fall on a Saturday, Sunday, or federal holiday, the period shall run until the close of
5 business on the next day that is not a Saturday, Sunday, or federal holiday. 6 g. “Defendant” or “Mobil” shall mean Mobil Exploration and Producing U.S.
7 Inc. 8 h. “Dispute Resolution” shall mean the dispute resolution procedures set 9 forth in Section XI of this Consent Decree. 10 i. “DOJ” shall mean the United States Department of Justice.
11 

## j. “Effective Date” shall mean the date of entry of the Consent Decree by the
12 Clerk of the United States District Court for the District of Utah. 13 k. “Eligible SEP Costs” shall mean money that Mobil spends to purchase
14 equipment specified in Appendix D to this Consent Decree, or substantially similar equipment.
15 1. “EPA” shall mean the United States Environmental Protection Agency.
16 m. “Facility” shall mean Mobil’s McElmo Creek Unit oil production facility
17 and associated oil fields, located near Aneth, Utah, on the Navajo Nation. 18 n. “Field Flares” shall mean the following flares at the Facility: (i) Tank 19 Battery Flares at MCU Area 1 Battery, MCU Area 2 Battery, MCU Area 4 Battery, and MCU
20 Area 6 Battery; arid (ii) Satellite Flares at MCU Section 2, MCU Section 3, MCU Section 5,
21 MCU Section 6, MCU Section 9, MCU Section 11, MCU Section 17, MCU Section 19, MCU
22 Section 32, and MCU Section 33. 23 o. “Final PSD Permit” shall mean a permit (i) that is issued in accordance
24 with the provisions of 40 C.F.R. 

## § 52.21; (ii) that includes, but is not limited to, federally25 enforceable terms and conditions that are at least as stringent as all of the terms and conditions 26 included in Paragraphs 9.a., 10, 11, and 25(i) through (ix) of this Consent Decree, with the
27 28 3

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 6 of 35

1 exception that the quarterly report required by Paragraph 25 may be changed, at the discretion of
2 the permitting authority, to a semiannual report; and (iii) that is no longer subject to any judicial 3 review procedures.
4 p. “Final Title V Permit” shall mean a permit (i) that is issued in accordance
5 with the provisions of 40 C.F.R. Parts 70 and 71, whichever is applicable; (ii) that includes, but
6 is not limited to, federally-enforceable terms and conditions that are at least as stringent as all of
7 the terms and conditions included in the Final PSD Permit; and (iii) that is no longer subject to 8 any judicial review procedures. 9 q. “Flaring Incident” shall mean continuous or intermittent flaring at the 10 Main Flare that occurs after the Effective Date of this Consent Decree and results in the
11 emissions of SO2 equal to, or greater than, five-hundred (500) pounds in any twenty-four (24)
12 hour period; provided, however, that if five-hundred (500) pounds or more of SO2 have been 13 emitted in a twenty-four (24) hour period and the flaring continues into subsequent, contiguous,
14 non-overlapping twenty-four (24) hour period(s), each period of which results in emissions equal
15 to, or greater than, five-hundred (500) pounds of SO2, then only one Flaring Incident shall have
16 occurred. Subsequent, contiguous, non-overlapping periods are measured from the initial
17 commencement of flaring within the Flaring Incident. 18 r. “H2S” shall mean hydrogen sulfide.
19 s. “Lodging” or “Date of Lodging” shall mean the date on which Plaintiff 20 lodges this Consent Decree with the United States District Court for the purpose of seeking
21 public comment on the Consent Decree.
22 t. “Main Flare” shall mean the flare installed as part of the Facility’s former
23 gas processing plant.
24 u. “Main Flare Emissions” shall mean the emissions from the Main Flare at 25 the Facility as well as all emissions that result from: (1) combustion of fuel gas in the Main 26 Flare’s pilot, (2) the closed drain and filter backwash operations, (3) CO2 Breakthroughs, (4) any 27
28 4

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 7 of 35

1 Scheduled Maintenance, and (5) unscheduled maintenance of the Facility’s compressors. 2 v. “Malfunction” shall mean any sudden and unavoidable breakdown of
3 process or pollution control equipment. CO2 Breakthroughs or Scheduled Maintenance of the
4 Facility’s compressors are not Malfunctions.
5 w. “NO~” shall mean oxides of nitrogen. 6 x. “Paragraph” shall mean a portion of this Consent Decree identified by an 7 Arabic numeral or an upper or lower case letter. Any reference to a Paragraph designated by an 8 Arabic numeral includes all subsequent Paragraphs designated by consecutive lower case letters.
9 y. “Parties” shall mean the United States and Mobil. 

## to z. “Plaintiff’ shall mean the United States.
11 aa. “PSD Permit” shall mean a construction permit issued in accordance with
12 the provisions of 40 C.F.R. 

## § 52.21.
13 bb. “Root Cause” shall mean the primary cause of a Flaring Incident as 14 determined through a process of investigation; provided, however, that if a Flaring Incident 15 encompasses multiple releases of SO2, the “Root Cause” may encompass multiple primary
16 causes. 17 cc. “Scheduled Maintenance” shall mean work that is part of the routine work
18 plan for the compressors located at the Facility’s former gas processing plant. This work is
19 typically planned and arranged on a set frequency, usually based on periods of time (e.g., daily, 20 weekly or monthly) or on the operating hours of the equipment. Scheduled Maintenance shall
21 not include work necessitated by the failure of a part of a compressor. 22 dd. Section” shall mean a portion of this Consent Decree identified by an 23 upper-case Roman numeral.
24 ce. “SEP” shall mean the supplemental environmental project required by this 25 Consent Decree.
26 ff. “SO2” shall mean sulfur dioxide.
27 28 5

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 8 of 35

I gg. “United States” shall mean the United States of America, acting on behalf 

### 2 of EPA. 3 hh. “VOC” shall mean volatile organic compounds as defined in 40 C.F.R.
4 

## § 51.100(s).
5 III. OBJECTIVES 6 5. It is the express purpose of the Parties entering into this Consent Decree to further
7 the objectives of the Act and to resolve the violations that the United States specifically alleged
8 in the Complaint filed in this action. To further these objectives, Mobil agrees, i~cr ~ija, to pay 9 the civil penalty as set forth in Section IV (Civil Penalty), to comply with the measures as set 10 forth in Section V (Compliance Measures), and to perform the SEP as set forth in Section VI
11 (Supplemental Environmental Project).
12 N. CIVIL PENALTY
13 6. After the Effective Date and within ten (10) days of the receipt of the Electronic
14 Fund Transfer procedures described in Paragraph 7 below, Mobil shall pay to the United States a 15 civil penalty in the amount of THREE HUNDRED FIFTY THOUSAND DOLLARS ($350,000),
16 plus interest at 1.29 percent per year from the date of August 21, 2003, through the date of
17 payment. 18 7. Payments under this Consent Decree shall be made by Electronic Funds Transfer 19 (“EFT”) to the United States Treasury according to current United States EFT procedures. The 20 United States shall provide a copy of current EFT procedures to Mobil at the address listed in
21 Section XII (Notification) of this Consent Decree. Concurrently with the electronic funds
22 transfer, Mobil shall send, by facsimile, notice of payment to the person designated as “Point of
23 Contact” on the EFT instructions, and shall send notice of payment to both EPA and DOJ at the
24 addresses listed in Section XII (Notification). The notice of payment shall identif~’ (i) the date
25 and amount of money transferred; (ii) the name and address of the transferring bank; (iii) the civil
26 action case name and case number; (iv) USAO File Number 2003 V00248; (v) DOJ Case Number
27 28 6

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 9 of 35

1 90-5-2-1-2237; (vi) this Consent Decree (including Effective Date); and (vii) a description of the
2 reason for payment (including the Paragraph number(s) of this Consent Decree that are most 3 relevant to the payment).
4 8. The payment of the civil penalty specified in this Section shall not be deductible
5 by Mobil or any other person or entity for federal taxation purposes. 6 V. COMPLIANCE MEASURES
7 9. Emission Limits.
8 a. From the Effective Date of this Consent Decree through the effective date 9 of the Final Title V Permit, Mobil’s Main Flare Emissions shall not exceed the following rolling 10 365-day cumulative amounts (to be calculated each day): (i) 60 tons per year of 

### SO2, (ii) 73 tons
11 per year of CO, (iii) 13.4 tons per year of NON, and (iv) 95.4 tons per year of VOC. Field Flares
12 shall not be used to circumvent the emission limits of this Paragraph. 13 b. The provisions of Section VIII of this Consent Decree (Stipulated 

# C) 14 Penalties) shall apply for Mobil’s failure to comply with any of the emission limits in Paragraph 15 9.a above. However, Mobil may assert, as an affirmative defense to a demand by the United
16 States for stipulated penalties, that the alleged violation was due to a Malfunction. To qualify as 17 a Malfunction, Mobil has the burden of proof of demonstrating that:
18 (1) The emissions in question were not the result of any CO2 Breakthroughs or 19 any Scheduled Maintenance of the Facility’s compressors; 20 (2) The emissions in question were caused by a sudden, unavoidable
21 breakdown of process or pollution control equipment, beyond the control
22 of Mobil, its contractors, or any entity controlled by Mobil; 23 (3) The emissions in question (i) did not stem from any activity or event that
24 could have been foreseen and avoided, or planned for, and (ii) could not 25 have been avoided by better operation and maintenance practices; 26 (4) To the maximum extent practicable, the air pollution control equipment or 

### 27
28 7

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 10 of 35

1 processes were maintained and 

### operated in a mariner consistent with good
2 engineering practice for minimizing emissions;
3 (5) Repairs were made in an expeditious fashion when Defendant knew or 4 should have known that SO2 emissions resulting from the event would be
5 equal to, or greater than, 500 pounds in a 24-hour period; (off-shift labor 6 and overtime must have been utilized, to the extent practicable, to ensure 7 that such repairs were made as expeditiously as practicable);
8 (6) The amount and duration of the emissions in question were minimized to 9 the maximum extent practicable during periods of such emissions;
10 (7) All possible steps were taken to minimize the impact of the emissions in
11 question on ambient air quality;
12 (8) All emission monitoring systems were kept in operation if at all possible;
13 (9) The actions of Mobil, its contractors, or any entity controlled by Mobil in
14 response to the emissions in question were documented by properly 15 signed, contemporaneous operating logs, or other relevant evidence; 16 (10) The emissions in question were not part of a recurring pattern indicative of
17 inadequate design, operation, or maintenance. (Emissions associated with
18 a Flaring Incident are presumed to be part of a recurring pattern indicative
19 of inadequate design, operation, or maintenance if the Root Cause of the 20 Flaring Incident is a recurrence of the same Root Cause that caused a 21 previous Flaring Incident, unless EPA agrees that such previous Flaring
22 Incident was the result of a Malflmction);
23 (11) If the emissions in question are associated with a Flaring Incident, Mobil
24 complied with all of the applicable requirements of Paragraphs 12 and 13 25 of this Consent Decree; and 26 (12) Mobil properly and promptly notified EPA as follows:
27 28 8

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 11 of 35

1 (a) if the emissions in question are 

### associated with a Flaring Incident,
2 Mobil complied with the notification and reporting requirements of
3 Paragraphs 12 and 25 of this Consent Decree;
4 (b) if the emissions in question are not associated with a Flaring
5 Incident, Mobil listed such emissions as attributable to a 6 Malfunction in the quarterly report required by Paragraph 25 of this
7 Consent Decree.
8 c. If SO2 emissions exceed 1,000 pounds per day, Mobil may submit a 9 written notification to EPA, claiming that the emissions resulted from a major Malfunction. In 10 the written notification, Mobil shall submit information to show that the incident qualifies as a 11 Malfunction pursuant to Paragraph 9.b.(1)

- (10). EPA agrees to review promptly such written
12 notification regarding a major Malfunction and to respond to the notification within 30 days after
13 EPA receives the written notification.
14 10. Monitoring. In determining compliance with the emission limits referred to in 15 Paragraph 9 above, from the Effective Date of this Consent Decree through the effective date of
16 the Final Title V Permit, Mobil shall measure and record the H2S concentration in the field gas at
17 the Facility in each calendar month at the inlet to the Facility’s former gas processing plant where 18 the Main Flare is located, and shall continuously measure and record the volume of gas 19 combusted in the Main Flare. Each and every calendar day, Mobil shall calculate and record the 20 daily emissions from the Main Flare based on the last recorded measurement of H2S
21 concentration in the field gas at the Facility and that day’s recorded volume of gas combusted in
22 the Main Flare. If Mobil is unable to measure the volume of gas combusted in the Main Flare on 23 any day, the volume of gas for that day shall be deemed to be equal to the daily average volume
24 of gas combusted in the Main Flare based on the previous 12 months’ emissions data. However,
25 the use of this daily average as substitute data neither relieves nor excuses Mobil from complying
26 with the sampling, data collection, and monitoring requirements of this Paragraph.
27 28 9

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 12 of 35

1 1 1. Operation and Maintenance of Main Flare and Compressors. From the Effective
2 Date, Mobil shall at all times and to the extent practicable, including during periods of startup, 3 shutdown, Malfunction, CO2 Breakthrough, Scheduled Maintenance, or unscheduled
4 maintenance of the Facility’s compressors, operate and maintain the compressor station
5 equipment and Main Flare in a manner consistent with good air pollution control practices for
6 minimizing emissions.
7 a. As of the Effective Date, Mobil shall comply with the provisions of the 8 Operations and Maintenance Plan (“O&M Plan”) contained in Appendix B, which is hereby 9 incorporated by reference into this Consent Decree. Mobil shall follow the procedures for the 10 inspection of the Facility’s compressors and associated equipment as set forth in the Life Cycle
11 Maintenance Plan in Appendix B, and shall maintain inspection logs at the Facility documenting
12 that these inspections have been conducted. Mobil shall maintain daily records at the Facility 13 regarding operation of the Facility’s compressors on a Daily Plant Reading Form. (An exemplar
14 of such a Form is contained in Appendix B.) Mobil shall also maintain a supply of designated 

### is spare parts for the Facility’s compressors and associated equipment that includes all of the
16 equipment on the Spare Parts List contained in Appendix B. After using equipment on its Spare
17 Parts List, Mobil shall replace such equipment as expeditiously as possible. Mobil shall place a 18 purchase order for such equipment within 45 days after it is used. Mobil shall conduct training 19 of Facility operators in accordance with the Training Program for Plant Operators contained in
20 Appendix B, and shall maintain records documenting that the training has been conducted.
21 Mobil shall retain copies of inspection logs and other records required by this Paragraph 1 l.a.
22 until termination of this Consent Decree. Mobil’s failure to comply with any requirement of the 23 O&M Plan shall constitute a violation of this Consent Decree subject to stipulated penalties.
24 b. Within three hundred sixty-five (365) days from the Effective Date, Mobil
25 shall install an automatic air-assisted flare system on the Main Flare, pursuant to the provisions 26 of 40 C.F.R. 

## § 60.18(c)(5) and (0(6). Thereafter, Mobil shall operate and maintain the Main
27 28 10

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 13 of 35

1 Flare in compliance with 40 C.F.R. 

### § 60.18(c)(1), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (f)(1) through
2 (f)(4), and (f)(6). 3 c. Within three hundred ninety-five (395) days from the Effective Date,
4 Mobil shall submit to EPA, at the address listed in Section XII (Notification), a certification that
5 the Main Flare is equipped with an automatic air-assisted flare system and is in compliance with
6 all applicable provisions of 40 C.F.R. 

### § 60.18(c)(1), (c)(2), (c)(3)(ii), (c)(5), (d), (e), (f)(1)
7 through (f)(4), and (f)(6). 8 12. Root Cause Analysis. No later than 72 hours after an event first qualifies as a 9 Flaring Incident, Mobil shall noti& by telephone, at (415) 947-8715, the Chief of the Air 10 Enforcement Office, Air Division of EPA Region IX, of such Flaring Incident. Telephone
11 notification shall be followed by a detailed written notification to EPA, at the address listed in
12 Section XII (Notification) of this Consent Decree, made within seven (7) working days after the 13 event first qualifies as a Flaring Incident. For a Flaring Incident caused by Scheduled
14 Maintenance or a CO2 Breakthrough, Mobil shall submit a report to EPA, at the address listed in
15 Section XII (Notification), no later than sixty (60) days following the end of such a Flaring 16 Incident, that sets forth the information required by Paragraph 12.a. through d. below. Except for
17 those Flaring Incidents caused by Scheduled Maintenance or a CO2 Breakthrough, Mobil shall
18 conduct a Root Cause Analysis in accordance with the program described in Appendix C to
19 evaluate the cause of each Flaring Incident and shall submit a report to EPA, at the address listed 20 in Section XII (Notification), no later than sixty (60) days following the end of a Flaring Incident,
21 that sets forth all of the following:
22 a. The date and time that the Flaring Incident started and ended. To the
23 extent that the Flaring Incident involved multiple releases either within a twenty-four (24) hour
24 period or within subsequent, contiguous, non-overlapping twenty-four (24) hour periods, Mobil 25 shall set forth the starting and ending dates and times of each release; 26 b. An estimate of the quantity of SO2 that was emitted and the calculations
27 that were used to determine that quantity;
28 11

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 14 of 35

1 c. The steps, if any, that Mobil took to limit the duration and/or quantity of 2 SO2 emissions associated with the Flaring Incident;
3 d. Except for those Flaring Incidents caused by Scheduled Maintenance or a 4 CO2 Breakthrough, a detailed analysis that sets forth the Root Cause and all contributing causes 5 of that Flaring Incident, to the extent determinable; however, if a Flaring Incident is caused by 6 Scheduled Maintenance or CO2 Breakthrough, then Mobil need only identify the Root Cause as 7 Scheduled Maintenance or CO2 Breakthrough (whichever is applicable), and either (i) describe
8 the nature of the work done for Scheduled Maintenance or (ii) identify the specific wells that 9 most likely experienced the CO2 Breakthrough; 10 e. An analysis of the measures, including possible design, operational, and
11 maintenance changes, that are available to reduce the likelihood of a recurrence of a Flaring
12 Incident resulting from the same Root Cause or contributing causes in the future. If Mobil 13 concludes that corrective action(s) is (are) required under Paragraph 13, the report shall include a 14 description of the action(s) and, if not already completed, a schedule for its (their)
15 implementation, including proposed commencement and completion dates. If Mobil concludes
16 that corrective action is not required under Paragraph 13, the report shall explain the basis for
17 that conclusion; 18 f. To the extent that investigations of the causes and/or possible corrective
19 actions still are under way on the due date of the report, a statement of the anticipated date by
20 which a follow-up report fully conforming to the requirements of Paragraph 12.d and 12.e will be
21 submitted; provided, however, that if Mobil has not submitted a report or a series of reports 22 containing the information required to be submitted under this Paragraph within forty-five (45)
23 days (or such additional time as EPA may allow) after the due date for the initial report for the
24 Flaring Incident, the stipulated penalty provisions of Section Vifi of this Consent Decree shall
25 apply, but Mobil shall retain the right to dispute, under Section XI (Dispute Resolution) of this
26 Consent Decree, any demand for stipulated penalties that was issued as a result of Mobil’s failure
27 to submit the report required under this Paragraph within the time frame set forth. Nothing in 28 12

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 15 of 35

I this Paragraph shall be deemed to excuse Mobil from its investigation, notification, reporting,
2 and corrective action obligations under this Section V (Compliance Measures) for any Flaring
3 Incident that occurs after the Flaring Incident for which Mobil has requested an extension of time
4 under this Paragraph 12.f.
5 g. To the extent that completion of the implementation of corrective 6 action(s), if any, is not fmalized at the time of the submission of the report required under this
7 Paragraph, then, by no later than thirty (30) days after completion of the implementation of 8 corrective action(s), Mobil shall submit a report identifying the corrective action(s) taken and the 9 dates of commencement and completion of implementation. 10 13. Corrective Action. In response to any Flaring Incident, Mobil shall take, as 11 expeditiously as practicable, such interim andlor long-term corrective actions, if any, as are 12 consistent with good engineering practice to minimize the likelihood of a recurrence of the Root 13 Cause and all contributing causes of that Flaring Incident.
14 a. If EPA does not notify Mobil in writing within sixty (60) days of receipt of
15 the report(s) required by Paragraph 12 that it objects to one or more aspects of Mobil’s proposed
16 corrective action(s), if any, and schedule(s) of implementation, if any, then that (those) action(s)
17 and schedule(s) shall be deemed approved for purposes of Mobil’s compliance with Paragraph 13 18 of this Consent Decree. Upon approval by EPA, the provisions of the corrective action plan shall
19 become incorporated into this Consent Decree, and Mobil’s failure to comply with any 20 requirement of the EPA-approved corrective action plan shall constitute a violation of this
21 Consent Decree subject to stipulated penalties.
22 b. EPA does not, however, by its agreement to the entry of this Consent
23 Decree or by its failure to object to any corrective action that Mobil may take in the future,
24 warrant or aver in any manner that any of Mobil’s corrective actions in the future will result in 25 compliance with the provisions of the Act. Notwithstanding EPA’s review of any plans, reports, 26 corrective measures, or procedures under this Section V (Compliance Measures) of this Consent
27 Decree, Mobil shall remain solely responsible for compliance with the Act. 28 13

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 16 of 35

1 c. If EPA does object, in whole or in part, to Mobil’s proposed corrective
2 action(s) and/or its schedule(s) of implementation, or, where applicable, to the absence of such 3 proposal(s) and/or schedule(s), EPA shall notifS’ Mobil of that fact within sixty (60) days
4 following receipt of the report(s) required by Paragraph 12 above. If EPA and Mobil cannot
5 agree within sixty (60) days on the appropriate corrective action(s), if any, to be taken in response 6 to a particular Flaring Incident, disputes may be resolved under Section XI (Dispute Resolution)
7 of this Consent Decree. 8 d. Nothing in this Section V (Compliance Measures) shall be construed as a 9 waiver of EPA’s rights under the Act for future violations of the Act or its regulations nor to 10 limit Mobil’s right to take such corrective actions as it deems necessary and appropriate
11 immediately following a Flaring Incident or in the period during preparation and review of any 12 reports required under this Section.
13 14. Permitting. Not later than one hundred eighty (180) days after the Effective
14 Date, Mobil shall submit to EPA’s permitting office, the following applications: 15 a. An application for a PSD permit for the Main Flare, which shall include,
16 among other things, the following requirements: (1) an analysis of the best available control
17 technology for the Main Flare for 

### SO2, CO. NON, and VOC; and (ii) an air quality analysis. Such
18 application shall be submitted in accordance with the requirements of the Act and 40 C,F.R.
19 

### § 52.21, and shall include, among other things, terms and conditions that are at least as stringent 20 as the terms and conditions included in Paragraphs 9.a, 10, 11, and 25(i)

- (ix) of this Consent
21 Decree, with the exception that the quarterly report required by Paragraph 25 may be changed, at
22 the discretion of the permitting authority, to a semiannual report. Nothing in this Consent Decree
23 is intended to nor shall be construed to operate in any way to prohibit the applicable permitting
24 authority from issuing a PSD permit that includes requirements that differ from or are more 25 stringent than the requirements of this Consent Decree (e.g., emissions limits on a monthly, daily,
26 or hourly basis).
27 b. An application for a Title V Permit, which includes, among other things, 28 14

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 17 of 35

1 

### terms and conditions that are at least as stringent as the terms and conditions in Paragraphs 9.a, 

### 2 10, 11, and 25(i)

- (ix) 

### of this Consent Decree, with the exception that the quarterly report 3 required by Paragraph 25 may be changed, at the discretion 

### of the permitting authority, to a 4 semiannual report. Such application shall be submitted in accordance with the requirements 

### of
5 Title V 

### of the Act and 40 C.F.R. Part 71. 6 Vi. SUPPLEMENTAL ENVIRONMENTAL PROJECT
7 15. In partial satisfaction of Plaintiff’s claims, Mobil shall implement a SEP to 8 support public health for the local residents in the vicinity of Aneth, Utah, on the Navajo Nation. 9 Mobil shall spend at least $99,849 to purchase the x-ray equipment, x-ray processor, and 10 pulmonary function testing machine specified in Appendix D of this Consent Decree, or 11 substantially similar equipment. Mobil shall order the equipment specified in Appendix D
12 within ninety (90) days after the Effective Date and have it delivered to: 13 Nettie Prack Utah Navajo Health Systems, Inc. 14 Montezuma Creek Community Health Center Highway 262 East 15 Montezuma Creek, Utah 84534-0130 Telephone: (435)651-3291 16
17 16. Mobil is responsible for the satisfactory completion of the SEP in accordance with
18 the requirements of this Consent Decree. Mobil may use contractors and/or consultants in 19 planning and implementing the SEP. but costs incurred for contractors or consulting services do
20 not constitute Eligible SEP Costs.
21 17. With regard to the SEP, Mobil certifies the truth and accuracy of each of the
22 following: 23 a. That to the best of Mobil’s knowledge, a reasonable and good faith
24 estimate of the cost of the SEP is $99,849;
25 b. That, as of the Effective Date, Mobil is not required to perform or develop 26 the SEP by any federal, state, or local law or regulation, nor is Mobil required to perform or 27 develop the SEP by agreement, grant, or as injunctive relief awarded in any other action in any 28 15

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 18 of 35

1 forum;
2 c. That Mobil has not received, and is not negotiating to receive, credit for
3 the SEP in any other enforcement action; and,
4 d. That Mobil will not receive reimbursement for any portion of the SEP
5 from any other person. 6 18. SEP Completion Report.
7 a. Within thirty (30) days after Mobil concludes that the SEP has been fully 8 implemented in accordance with the requirements of this Consent Decree, Mobil shall submit a 9 SEP Completion Report to EPA and DOJ at the addresses listed in Section XII (Notification) of
10 this Consent Decree. The SEP Completion Report shall contain the following information:
11 (1) A detailed description of the SEP as implemented;
12 (2) A description of any problems encountered in completing the SEP and the 13 solutions thereto;
14 (3) An itemized list of all Eligible SEP Costs and acceptable evidence of such
15 costs; 16 (4) Certification that the SEP has been fully implemented pursuant to the
17 provisions of this Consent Decree; and
18 (5) A description of the environmental and public health benefits anticipated
19 to result from implementation of the SEP.
20 19. For purposes of Paragraph 1 8.a.(3), “acceptable evidence” includes invoices,
21 purchase orders, or other documentation that specifically identifies and itemizes the individual
22 costs of the goods or services for which payment is made. Canceled drafts do not constitute
23 acceptable evidence unless such drafts specifically identify and itemize the individual costs of the
24 goods or services for which payment is made. 25 20. Within sixty (60) days after receipt of a SEP Completion Report (unless the
26 United States notifies Mobil that additional time is required), the United States shall notify Mobil
27 whether or not Mobil has satisfactorily completed the SEP. If Mobil’s total Eligible SEP Costs
28 16

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 19 of 35

I are less than $99,849, or if the SEP has not been satisfactorily completed, stipulated penalties
2 may be assessed under Section VIII (Stipulated Penalties) of this Consent Decree. Disputes 3 concerning the satisfactory completion of the SEP may be resolved under Section XI (Dispute
4 Resolution) of this Consent Decree.
5 21. Mobil hereby agrees that any funds expended by Mobil in the performance of the 6 SEP shall not be deductible for purposes of calculating federal and state taxes. Mobil, at the time
7 of completion of the SEP, shall submit to the United States certification that any funds expended 8 in the performance of the SEP pursuant to this Consent Decree have not been and will not be
9 deducted for purposes of such taxes. 10 22. Each submission required under this Section shall be signed by an official with
11 knowledge of the SEP and shall bear the certification language set forth in Paragraph 42 of this
12 Consent Decree.
13 23. Any public statement, oral or written, in print, film, or other media, made by
14 Mobil making reference to the SEP under this Consent Decree shall include the following
15 language: “This project was undertaken in connection with the settlement of an enforcement 16 action, United States v. Mobil Exploration and Producing U.S. Inc., taken on behalf of the United
17 States Environmental Protection Agency under the Clean Air Act.”
18 VII. COMPLIANCE REPORTING AND RECORDKEEPING
19 24. Calculation of the daily emissions from the Main Flare shall be based on that 20 day’s recorded volume of gas combusted in the Main Flare and the most recent recorded
21 measurement of H2S concentration in the field gas at the Facility. The emission limits in
22 Paragraph 9 require the use of rolling 365-day cumulative amounts. In calculating the rolling
23 365-day cumulative amounts for the first year after the Effective Date, the daily emissions from
24 the Main Flare for each and every calendar day from 364 days prior to the Effective Date of this 25 Consent Decree through the Effective Date of this Consent Decree shall be deemed to be the
26 following: (1) 101.9 pounds per day (lbs/day) of SO2, (ii) 262.2 lbs/day of CO, (iii) 51.9 lbs/day
27 of NON, and (iv) 371.3 lbs/day of VOC.
28 17

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 20 of 35

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

### (i.e., January to 2 March, April to June, July to September, October to December) after the Effective Date, Mobil
3 shall submit to EPA, at the address listed in Section XII (Notification) of this Consent Decree
4 and bearing the certification language set forth in Paragraph 42 of this Consent Decree, a 5 quarterly report that includes: (i) a list of the rolling 365-day cumulative Main Flare Emissions 6 for each day in that quarter; (ii) a list of each day in the quarter when the emissions limits in
7 Paragraph 9 of this Consent Decree were exceeded and, for each such day, the limit(s) exceeded
8 and the amount(s) of excess emissions; (iii) a list of all emissions for the quarter that Mobil 9 claims are attributable to Malfunctions and, for each such item on the list, a detailed 10 demonstration that all of the qualif~’ing criteria for Malfunctions that are listed in Paragraph 9.b
11 of this Consent Decree have been satisfied; (iv) a list of all emissions for the quarter that may be
12 attributable to CO2 Breakthroughs, Scheduled Maintenance, or unscheduled maintenance of the
13 Facility’s compressors; (v) the date(s) and time(s) during the quarter when the thermocouple or 14 flow meter associated with the Main Flare was inoperative; (vi) the date(s) and time(s) during the 15 quarter when Mobil failed to measure or record the H2S concentration in the field gas at the
16 Facility or failed to continuously measure or record the volume of gas combusted in the Main
17 Flare; (vii) a certification that during the calendar quarter Mobil operated and maintained the
18 compressor station equipment and Main Flare in a manner consistent with good air pollution 19 control practices for minimizing emissions, and performed all of the obligations (including, but
20 not limited to, inspection and training obligations) contained in the O&M Plan in Appendix B;
21 (viii) a certification that the Field Flares have not been used to circumvent the emission limits in
22 Paragraph 9; (ix) a list of total emissions from the Field Flares and the reason for the flaring; and 23 (x) any and all reports generated from the root cause analysis and corrective action program of
24 Paragraphs 12 and 13 above.
25 26. Mobil shall maintain at the Facility copies of all notices, reports, information,
26 submissions, and records required by this Consent Decree until the termination of this Consent
27 Decree or as required by applicable law, whichever is later. Mobil shall provide any of these 28 18

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 21 of 35

documents to EPA upon request. Vifi. STIPULATED PENALTIES
27. Stipulated Penalties.

a. Subject to the force majeure provisions of Section X (Force Majeure), Mobil shall be liable for stipulated penalties in the amounts set forth in this Paragraph 27 to the United States for failure to comply with the terms and conditions of this Consent Decree as follows: (1) for Mobil’s failure to pay the full amount of the civil penalty set forth in Section IV (Civil Penalty): $5,000 for each day that payment of the civil penalty is delayed beyond the date due;

(2) for Mobil’s failure to comply with any requirement of Section V (Compliance Measures):

(a) for Mobil’s failure to comply with any of the emission limits in Paragraph 9 of this Consent Decree (for the purpose of determining stipulated penalties for the emission limits only, days of noncompliance are cumulative from the Effective Date and need
not be continuous):

Days of Noncompliance from Effective Penalty per Day per Violation Date to Termination of the Decree 1” through 5th day $1,000

6th through 10th clay $2,500
1 1th through 20th day $5,000 21 day and beyond $7,500 (b) for Mobil’s failure to comply with any of the specific requirements
in Paragraphs 11 through 13 of this Consent Decree identified in the following table: I
2
3
4 

### 5 6
7 8 9 10
11
12 13
14
15 16
17 18
19
20
21
22
23
24 25 26
27 28 19

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 22 of 35

I Penalty
2 3 $250 per day for each day after the third day of noncompliance 4 within each calendar quarter
5 $250 per task 6 $Soopertask
7 $500 per day 8 $1,000 per day
9 10

___________________________________________ ________________________ 

### H
12 13
14
15 16
17 18

________________________________ ________________________________ 19 20
21
22 23
24 25 26
27 28 Requirement

Failure to implement O&M Plan requirements (~1 l.a.) Failure to maintain inspection logs or records (excluding the first full calendar quarter after the Effective Date) Levels 2, 3, and 4 tasks Levels 5 and 6 tasks Failure to conduct training Failure to maintain spare parts Root Cause Analysis (1112) $5,000 per event Corrective Action (1113) $7,500 per event

(c) for Mobil’s failure to comply with any other requirement of Section V of this Consent Decree not specifically referenced in this Paragraph 27.a (2)(a) or 27.a (2)(b) above:

Period of Noncompliance Penalty per Day per Violation

1st through 10th day $1,000

~ 1~h through 20th day $2,500 21~ day and beyond $5,000

(3) If Mobil’s total Eligible SEP Costs are less than $99,849 in connection with the performance of the SEP specified in Appendix D of this Consent Decree, or if the SEP has not been satisfactorily completed, Mobil shall be liable for stipulated penaLties, as set forth below. If Mobil has halted or abandoned completion of the SEP, such penalties shall accrue from the date of abandonment or the date set for completion of the SEP. whichever is earlier.

(a) If the SEP has been satisfactorily completed but Mobil’s total Eligible SEP Costs for the SEP are less than $99,849, Mobil shall pay stipulated penalties at the
rate of one dollar for every one dollar that Mobil’s total Eligible SEP Costs for that SEP are less
20

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 23 of 35

than $99,849. (b) If a SEP has not been satisfactorily completed, Mobil shall pay stipulated penalties at the rate of $1.50 for every one dollar that Mobil’s total Eligible SEP Costs for that SEP are less than $99,849. However, to the extent that Mobil has made good faith and timely efforts to complete the project, Mobil shall pay stipulated penalties at the rate of one dollar for every one dollar that Mobil’s total Eligible SEP Costs for that SEP are less than $99,849. If a SEP is not satisfactorily completed but Mobil’s total Eligible SEP Costs for that SEP are equal to or exceed $99,849, Mobil shall not be liable for any stipulated penalties for that SEP if Mobil has made good faith and timely efforts to complete the project and certifies with supporting documentation, no later than the date that Mobil is required to submit a SEP Completion Report for that project, that it has spent at least $99,849. If Mobil does not provide the certification and documentation required by this subparagraph, or if the documentation provided does not support Mobil’s certification, Mobil shall be deemed to be in violation of this Consent Decree and shall pay a stipulated penalty of $7,500. Mobil shall be deemed to have made good faith and timely efforts to complete the project if Mobil complies with the specific obligations set forth in Paragraphs 15, 17 through 19, and 21 through 23.

(e) If Mobil fails to: (i) order the equipment within 90 days after the Effective Date as required by Paragraph 15; or (ii) timely submit a SEP Completion Report under Paragraph 18, Mobil shall pay stipulated penalties as follows:

Period of Noncompliance Penalty per Day per Violation 1st through 14th day $100 15th through 30th day $250 31st day and beyond $500

(4) for Mobil’s failure to comply with any requirement of Section IX (Right of Entry): $5,000 per day for each failure to comply; and

(5) for Mobil’s failure to comply with any other requirement of this Consent 1 

### 2 3
4
5 6
7 8 9 10
11
12 13
14 15 16
17
18 19 20
21
22 23
24 25 26
27 28 21

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 24 of 35

I Decree not specifically referenced in this Paragraph 27.a (1) through (4) above: $1,000 per day
2 for each failure to comply.
3 b. All stipulated penalties shall automatically begin to accrue on the day after
4 the complete performance is due or the first day a violation occurs, and shall continue to accrue 5 through the final day of the correction of the noncompliance or completion of the activity. 6 Nothing herein shall prevent the simultaneous accrual of separate stipulated penalties for separate
7 violations of this Consent Decree. Stipulated penalties shall accrue regardless of whether
8 Plaintiff has notified Mobil of a violation of the Consent Decree. 9 c. Any stipulated penalty accruing pursuant to this Consent Decree shall be 10 payable upon demand and due not later than thirty (30) calendar days from EPA’s written
11 demand.
12 28. Stipulated penalties shall be paid by certified or cashier’s check in the amount 13 due, shall be made payable to the “U.S. Department of Justice,” referencing DOJ #90-5-2-1-2237
14 and USAO File Number 2003 V00248, and shall be delivered by certified mail with return receipt 15 requested to: 16 United States Attorney, District of Utah

Attention: Financial Litigation Unit 17 185 South State Street, Suite 400

SaltLake City, Utah 84111 18 19 Concurrently with making the payment, Defendant shall send notice of payment to EPA and
20 DOJ, directed to the addresses provided in Section XII (Notification). The notice of payment
21 shall also identify: (i) the specific provision of this Section VIII (Stipulated Penalties) related to
22 such payment, and (ii) a description of the violation(s) of this Consent Decree for which the
23 stipulated penalties or interest are being tendered.
24 29. Interest. If Mobil fails to pay the full amount of the civil penalty specified in
25 Section 1V (Civil Penalty) when due, or the full amount of any stipulated penalty specified in this
26 Section Vifi (Stipulated Penalties) within 30 days of EPA’s written demand, then Mobil shall pay 27 to the United States (in addition to the unpaid balance of each penalty) interest on the late 28 22

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 25 of 35

1 payment for each day of late payment after the initial 30-day time period. The rate of interest
2 shall be the most recent interest rate determined pursuant to 28 U.S .C. 

## § 1961. If Mobil disputes 3 its obligation to pay part or all of a stipulated penalty, it shall initiate the dispute resolution
4 procedures under Section XI (Dispute Resolution). If Mobil invokes dispute resolution, Mobil
5 shall pay to the United States any amount that it does not dispute. 6 30. Payment of stipulated penalties for a violation of this Consent Decree shall not
7 preclude the United States from seeking additional monetary penalties or other relief for the 8 violations giving rise to the stipulated penalties. The United States reserves its right to pursue 9 any or all relief for any or all violations directly, either administratively or judicially, and outside 10 the provisions of this Consent Decree. Where a violation of this Consent Decree is also a 11 violation of the Clean Air Act, Defendant shall be allowed a credit, for any stipulated penalties
12 paid, against any statutory penalties imposed for such violation.
13 IX. RIGHT OF ENTRY
14 31. EPA and its contractors, consultants, and agents shall have authority to enter the 15 Facility at all reasonable times, upon presentation of credentials. This provision in no way limits 16 or otherwise affects any right of entry held by EPA pursuant to applicable federal, state, or local
17 laws, regulations, or permits.
18 X. FORCE MAJEURE 19 32. Mobil shall satisfy the requirements of Paragraphs 9 through 26 of this Consent
20 Decree except to the extent, and for the period of time, that such performance is prevented or 21 delayed by events that constitute a force majeure.
22 33. For purposes of this Consent Decree, a “force majeure” is defined as an event 23 arising from causes beyond the control of Mobil, its contractors, or any entity controlled by
24 Mobil that prevents or delays the performance of any obligation under this Consent Decree 25 despite Mobil’s best efforts to fulfill the obligation. “Best efforts” include anticipating any 26 potential force majeure event and addressing the effects of any such event (i) as it is occurring
27 and (ii) after it has occurred, such that delay is minimized to the extent possible. “Force 28 23

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 26 of 35

1 majeure” does not include Mobil’s financial inability to perform any obligation under this
2 Consent Decree. 3 34. In the event of a force maj cure, the time for performance of the activity delayed by
4 the force majeure shall be extended for the time period of the delay attributable to the force
5 majeure. The time for performance of any activity dependent on the delayed activity shall be 6 similarly extended, except to the extent that the dependent activity can be reasonably
7 implemented in a shorter time. EPA shall determine whether the dependent activities will be 8 delayed by the force majeure and whether the time period should be extended for performance of
9 such activities. Mobil shall adopt all reasonable measures to avoid or minimize any delay caused 10 by a force majeure.
11 35. When an event occurs or has occurred that may delay or prevent the performance
12 of any obligation under this Consent Decree and that Mobil believes is a force majeure, Mobil 13 shall notify by telephone, at (415) 947-8715, the Chief of the Air Enforcement Office, Air
14 Division of EPA Region IX, within 72 hours of Mobil’s knowledge of such event. Telephone 15 notification shall be followed by written notification to EPA, at the address in Section XII 16 (Notification) of this Consent Decree, made within seven (7) working days of Mobil’s knowledge
17 of the event. The written notification shall fully describe (i) the event that may delay or prevent 18 performance; (ii) the reason that such event may delay or prevent performance; (iii) whether 19 Mobil claims that such event constitutes a force majeure under this Consent Decree; (iv) the 20 reasons any such delay is beyond the reasonable control of Mobil; (v) the anticipated duration of
21 the delay; (vi) actions taken or to be taken to prevent or minimize the delay; (vii) a schedule for
22 implementation of any measures to be taken to prevent or minimize the delay or the effect of the
23 delay; and (viii) the time needed to implement any dependent activities. 24 36. Mobil’s failure to comply with the force majeure notice requirements provided in 25 Paragraph 35 above for any delay in performance will be deemed an automatic forfeiture of its
26 right to assert that the delay was caused by a force majeure unless such failure to provide notice
27 was caused by a force majeure. 28 24

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 27 of 35

1 37. Within seven (7) working days after receiving notice from Mobil of a force
2 majeure, EPA shall provide written notification to Mobil stating whether Mobil’s request for a 3 delay is justified. EPA’s failure to respond to a request for a delay shall be deemed a denial of
4 that request If Mobil disagrees with EPA’s force majeure determination, then Mobil may initiate
5 the dispute resolution procedures of Section XI (Dispute Resolution) of this Consent Decree. 6 XI. DISPUTE RESOLUTION
7 38. If Mobil disputes any determination made by EPA under this Consent Decree 8 related to (i) a request by EPA for stipulated penalties, (ii) EPA’s determination pursuant to 9 Paragraphs 11, 13, or 20, (iii) EPA’s determination related to force majeure, or (iv) the 10 termination of the Consent Decree under Paragraph 53, Mobil shall send a written notice to EPA
11 and DOJ outlining the nature of the dispute and requesting informal negotiations to resolve the
12 dispute. Such period of 

### informal negotiations shall not extend beyond ten (10) working days
13 from the date when the notice was sent unless the Parties agree otherwise.
14 39. If the informal negotiations are unsuccessful, then the determination of EPA shall
15 control, unless Mobil ifies a motion with this Court for dispute resolution. Any such motion
16 must be filed within thirty (30) days after Mobil’s receipt of a notice in writing 

### terminating
17 informal negotiations, and such motion must be concurrently sent to EPA and DOJ in accordance 18 with the Section XII (Notification) of this Consent Decree. The United States shall then have 19 thirty (30) days to respond to Mobil’s motion. The Court’s decision in any such dispute 20 resolution proceeding shall be based on the administrative record. Mobil shall bear the burden of
21 proving that (i) in disputes regarding EPA’s request for stipulated penalties under Section Vifi
22 (Stipulated Penalties) of this Consent Decree or EPA’s determination under Paragraphs 11 or 13, 23 Mobil did not violate the terms and conditions of this Consent Decree; (ii) in disputes regarding
24 EPA’s determination under Paragraph 20, Mobil has satisfied all of its obligations under Section
25 VI (Supplemental Environmental Project); (iii) in disputes regarding Section X (Force Majeure), 26 the delay was caused by circumstances beyond the control of Mobil, its contractors, and agents, 27 all reasonable measures were taken to minimize delay, and the duration of the delay was 28 25

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 28 of 35

1 reasonable under the circumstances; and (iv) in disputes regarding termination of this Consent
2 Decree under Paragraph 53, Mobil has satisfied all of its obligations under this Consent Decree.
3 The Court shall uphold EPA’s determination unless Mobil proves that the determination is
4 arbitrary and capricious, or otherwise not in accordance with law.
5 40. A timely motion by Mobil will not toll the accrual of stipulated penalties under 6 this Consent Decree for any ongoing noncompliance with respect to the disputed matter.
7 XII. NOTIFICATION
8 41. Except as otherwise specifically stated, all notices and submissions from Mobil to 9 EPA required by this Consent Decree shall be sent by certified mail, express mail, or similar 10 overnight mail delivery with return receipt requested and addressed to: 11 Director, Air Division (AIR-i) U.S. Environmental Protection Agency, Region LX 12 75 Hawthorne Street San Francisco, California 94105 13 Attention: John Kim
14 All notices and submissions sent to EPA or DOJ shall refer to this Consent Decree and the
15 Effective Date of the Consent Decree, and shall cite the case name of United States v. Mobil
16 Exploration and Producing U.S. Inc., the civil action case number, and the DOJ Case Number
17 90-5-2-1-2237. 18 42. All notices and submissions made pursuant to this Consent Decree shall be signed 19 and affinned by a responsible official of Mobil using the following certification statement: 20 I certify under penalty of law that I have examined and am familiar

with the information submitted in this document and all 21 attachments and that this document and its attachments were

prepared either by me personally or under my direction or 22 supervision in a manner designed to ensure that qualified and

knowledgeable personnel properly gathered and presented the 23 information contained therein. I further certify, based on my

personal knowledge or on my inquiry of those individuals 24 immediately responsible for obtaining the information, that the

information is true, accurate, and complete. I am aware that there 25 are significant penalties for submitting false information, including

the possibility of fmes and imprisonment for knowing and willful 26 submission of a materially false statement. 27 43. As to DOJ, notices and submissions required to be sent by this Consent Decree 28 26

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 

### Page 29 of 35

1 shall be submitted to: 2 Chief, Environmental Enforcement Section Ann: DOJ # 90-5-2-1-2237 (Mullaney) 3 United States Department of Justice 301 Howard Street, Suite 1050 4 San Francisco, California 94105
5 44. As to Mobil, notices and submissions required to be sent by this Consent Decree 6 shall be submitted to:
7 Vice President Mobil Exploration and Producing U.S. Inc. 8 CORP-WGR-1260 396 West Greens Road 9 Houston, Texas 77067 10 45. All submissions made pursuant to this Consent Decree shall be deemed submitted
11 on the date postmarked.
12 Xffl. EFFECT OF SETTLEMENT/NON-WAIVER PROVISIONS
13 46. Neither by entering into this Consent Decree nor by taking any action in
14 accordance with it (including paying the civil penalty required by this Consent Decree) shall 15 Defendant be deemed to have admitted any liability for any purpose or any responsibility for, or 16 wrongdoing relating to, the mailers specifically alleged in the Complaint, or to have admitted any 17 issues of law or fact related to or arising from the matters specifically alleged in the Complaint, 18 except as set forth in Section I (Jurisdiction and Parties Bound) of this Consent Decree. It is the
19 intent of the Parties to this Consent Decree that neither the terms and conditions of this Consent
20 Decree nor any act of performance by Defendant shall be (i) admissible in any proceeding for the
21 purpose of imputing, implying, or otherwise raising an inference of wrongdoing by Defendant, or 22 (ii) used against Defendant as collateral estoppel in any other proceeding with any third party not 23 a signatory to this Consent Decree.
24 47. Entry of this Consent Decree and compliance with the requirements herein 25 resolves the civil claims of the United States against Defendant for the violations specifically
26 alleged in the Complaint filed in this action, up to the Date of Lodging of the Consent Decree.
27 48. Except as specifically provided herein) the United States does not waive any rights 28 27

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 30 of 35

I or remedies available to it for violation by Defendant of federal or state laws or regulations. This
2 Consent Decree shall in no way affect the United States’ ability to bring future actions for any 3 matters not specifically alleged in the Complaint filed in this action, up to the Date of Lodging of
4 the Consent Decree. Nothing in this Consent Decree is intended to nor shall be construed to
5 operate in any way to resolve any criminal liability of Defendant. 6 49. This Consent Decree in no way affects Defendant’s responsibilities to comply
7 with all federal, state, or local laws, regulations or permits, including, but not limited to, the 8 reporting requirements of Section 103(a) of the Comprehensive Environmental Response,
9 Compensation, and Liability Act, 42 U.S.C. 

## § 9603(a), and Section 304 of the Emergency 10 Planning and Community Right-to-Know Act, 42 U.S.C. 

## § 11004, and the regulations
11 promulgated thereunder. This Consent Decree is not, and shall not be construed as, a permit or a 12 modification of a permit. Nothing in this Consent Decree shall diminish EPA’s ability to request 13 information from Defendant under applicable laws or regulations.
14 50. This Consent Decree does not limit or affect the rights of the Plaintiff or 15 Defendant against any third parties (parties not specifically part of this Decree), nor does it limit 16 the rights of such third parties against Defendant. This Consent Decree shall not be construed to
17 create any rights in, or grant any cause of action to, any person not a party to this Consent Decree.
18 XIV. EFFECTIVE DATE AND TERMiNATION
19 51. This Consent Decree shall take effect on the date of entry by this Court. 20 52. This Consent Decree shall terminate when all of the following conditions have
21 been met:
22 a. Mobil has complied with all of the requirements set forth in Sections V
23 (Compliance Measures) and VI (Supplemental Environmental Project) of this Consent Decree;
24 b. Mobil has paid the civil penalty and interest as set forth in Section IV 25 (Civil Penalty), all stipulated penalties and interest as set forth in Section VIII (Stipulated
26 Penalties), and no penalties or other monetary obligations due under this Consent Decree are 27 outstanding or owed to the United States; 28 28

### Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 31 of 35

I c. all disputes arising under the Consent Decree have been resolved;
2 d. Mobil has received a Final Title V Permit (i) for which Mobil submitted 3 an application in accordance with Paragraph 14 of this Consent Decree; and (ii) that includes, but
4 is not limited to, federally-enforceable terms and conditions that are at least as stringent as all of
5 the terms and conditions included in Paragraphs 9.a, 10, 11, and 25(i)

- (ix) of this Consent 6 Decree, with the exception that the quarterly report required by Paragraph 25 may be changed, at
7 the discretion of the permitting authority, to a semiannual report; and 8 e. this Court approves termination of this Consent Decree. 9 53. Mobil shall initiate termination of this Consent Decree by submitting a written 10 certification concurrently to EPA and DOJ at the addresses listed in Section XII (Notification),
11 that (i) all conditions for termination pursuant to Paragraph 52 above (except for the condition in
12 52.e referring to this Court’s approval of termination) have been satisfied; and (ii) Mobil believes
13 that the Consent Decree should be terminated. After receiving notice from Mobil, EPA shall
14 provide Mobil with a written response, either stating that EPA agrees that the Consent Decree 15 should be terminated, and submitting a motion to this Court requesting that the Consent Decree
16 be terminated, or stating that EPA has determined that the Consent Decree should not be
17 terminated. If EPA fails to provide written response within sixty (60) days after receiving written 18 notice from Mobil or if EPA determines that the Consent Decree should not be terminated, Mobil 19 may initiate dispute resolution procedures pursuant to Section XI (Dispute Resolution).
20 XV. MISCELLANEOUS
21 54.

~ Each Party shall bear its own costs and attorneys’ fees in this action.
22 55. Integration and Modifications. This Consent Decree (including its appendices)
23 contains the entire agreement between the Parties. The notification requirements of this Consent
24 Decree may be modified only if such modifications are made in writing and approved by all
25 Parties. In all other respects, this Consent Decree may not be enlarged~ modified, or altered
26 unless such modifications are made in writing and approved by all Parties and this Court.
27 56. Retention of Jurisdiction. Until the termination of this Consent Decree pursuant 28 29Case 2:05-cv-0031 9-PGC Document 7 FHed 06/08/2005 Page 32 of 35

I to Section XIV (Effective Date and Termination), this Court shall retain jurisdiction over this
2 action and all disputes arising hereunder (to the extent that this Consent Decree provides for
3 resolution of disputes by this Court) for the purposes of implementing and enforcing the terms 4 and conditions of this Consent Decree.
5 57. Public Comment. Mobil agrees and acknowledges that fInal approval of this 6 Consent Decree by the United States and entry of this Consent Decree by this Court is subject to
7 the requirements of 28 C.F.R. 

### § 50.7, which provides for notice of the Lodging of this Consent
8 Decree in the Federal Register, opportunity for public comment for at least thirty (30) days, and 9 consideration by the United States of any comments prior to entry of the Consent Decree by this 10 Court. The United States reserves the right to withdraw its consent to this Consent Decree based
11 on comments received during the public notice period. Mobil consents to entry of this Consent
12 Decree without further notice and shall not oppose or appeal its entry by the Court. 13 58. Final Judgment. Upon entry by this Court, this Consent Decree shall constitute a 14 final judgment for purposes of Federal Rules of Civil Procedure 54 and 58.
15 16 ORDER
17 IT IS SO ORDERED, this

_________ day of

, 2005.

19 ~ JUDGE



### 281 30

### Case 2:05-cv-00319-PGC Document 7 Filed 06/08/2005 Page 33 of 35

1 FOR PLAINTWF UNITED STATES OF AMERICA:

3 Dated:_______ By: 

# Y~ THOMAS L. SANSONETTI 4 Assistant Attorney General Environment and Natural Resources Division 5 United States Department of Justice

7 Dated:__-

- ROBERT D. MULLANEY 8 Trial Attorney Environmental Enforcement Section 9 Environment and Natural Resources Division United States Department of Justice 10 301 Howard Street, Suite 1050 San Francisco, California 94105 11 Telephone: (415) 744-6491
12 13 PAUL M. WARNER 14 United States Attorney JEANNETTE S WENT 15 Assistant United States Attorney District of Utah 16 185 South State Street, Suite 400 Salt Lake City, Utah 84111 17 18
19 20
21
22 23
24 25 26
27
28 31Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 34 of 35

I FOR PLAINTIFF UNITED STATES OF AMERICA (continued):
2~ 3~ 

# z~f

4 Dated: ~‘ 

## (p 

# 0

~ ~. 

# R~CMM’V ~1,—

I THOM~ V. SKINNER Actmg Assistant Administrator for Enforcement and Compliance Assurance 6 United States Environmental Protection Agency
7 8

10 Dated:____________

______________________ WAYNE ~/ASTRI 11 Regional ~dministrator United States Environmental Protection Agency, Region IX 12 13
14
15 OF COUNSEL:
16 THOMAS P. MINTZ Assistant Regional Counsel 17 Office of Regional Counsel United States Environmental 18 Protection Agency, Region IX 75 Hawthorne Street 19 San Francisco, California 94105 20
21
22
23
24 25 26
27
28 32

### 2 Case 2:05-cv-0031 9-PGC Document 7 Filed 06/08/2005 Page 35 of 35

FOR DEFENDANT MOBIL EXPLORATION & PRODUCING U.S. INC.:

Dated:

__________________ SARA N. ORTWEIN Vice President Mobil Exploration and Producing U.S., Inc. 396 West Greens Road Houston, Texas 77067

Attorney for Defendant 

### 1

I,

Dated: ~ 

# /J6-/~s

# v/I

800 Bell Street Houston, Texas 77002-7426 Telephone: (713) 656-3429 

### 3
4
5 6
7 8 

### 9
10 11
12 13
14 15
16
17 18 19 20
21
22 23
24
25 26
27 28 33APPENDIX B

DERIVATION OF ESTIMATED PRE-PROJECT AND POST-PROJECT

ACTUAL AND POTENTIAL TO EMIT EMISSIONS

### Appendix B

Flare Emission Calculation Methodology

- 

### McElmo Gas Compression Facility
Carbon Monoxide CO

= V * (1000 scf/ kscf) * GHV * (MMBTU / (106 BTU)) * EF~o * (ton / 2000 lbs)
CO

= Carbon Monoxide Emissions, tons per year (tpy) V

= Volume of Gas Flared per Year, kscflyr GHV

= Gross Heating Value of Gas Flared, BTU/scf EFc0

= Emission Factor for CO from Table 13.5-1 of AP-42 Chapter 13.5

(September 1991, Reformatted January 1995), lbs/MMBTU

= 0.37 1bfMMBTU Nitrogen Oxides NO~

= 

### v * (1000 scf/ kscf) * GHV * (MMBTU / (106 BTU)) * EFNOX * (ton / 2000 lbs)
NO~

= Nitrogen Oxide Emissions, tpy V

= Volume of Gas Flared per Year, kscflyr GHV Gross Heating Value of Gas Flared, BTU/scf EFNOX = Emission Factor for NO~ from Table 13.5-1 of AP-42 Chapter 13.5

(September 1991, Reformatted January 1995), lbs/MMBTU

= 0.068 lb/MMBTU
Volatile Organic Compounds VOC

= V * (1000 scf/ kscf) * (lbmole / 380 scf) * MW * WFvoc * (1

- (DEFF 

### / 100)) * (ton / 2000 lbs)
VOC

= Volatile Organic Compounds (non-methane, non-ethane) Emissions, tpy V

= Volume of Gas Flared per Year, kscflyr MW Molecular Weight of Gas Flared, lbs/lbmole WF~0~= Weight Fraction of VOCs in Gas Flared DEFF = Percent Destruction Efficiency of Flare (98%)
Sulfur Dioxide SO2

= V * (1000 scf/ kscf) * (lbmole / 380 scf) * MFH2S * (DEFF 

### / 100) * (64 lbs SO2 / lbmole SO2) * (ton / 2000 ibs)
SO2

= Sulfur Dioxide Emissions, tpy V

= Volume of Gas Flared per Year, kscf’yr MFH2S
= Molar Fraction of H2S in Gas Flared DEFF = Percent Destruction Efficiency of Flare (98%)Lead

Pb

= V * (1000 scf/ kscf) * GHV * (MMBTU / (106 BTU)) * EFpb * (ton / 2000 ibs)
Pb

= Lead Emissions, tpy V

= Volume of Gas Flared per Year, kscf/yr GHV Gross Heating Value of Gas Flared, BTU/scf EFPb

= Emission Factor for Lead from Table 1.4-2 of AP-42 Chapter 1.4

(July 1998), lbs/MMBTU 4.9 x 1071b/MMBTU= 0.0005 lb/106 scf* (scf/ 1020 BTU)
Particulate Matter (PM10 and PM25~ PM V * (1000 scf/ kscf) * GHV * (MMBTU / (106 BTU)) * EFPb * (ton / 2000 lbs)
PM

= Particulate Matter Emissions, tpy V

= Volume of Gas Flared per Year, kscflyr GHV

= Gross Heating Value of Gas Flared, BTU/scf EFPb

= Emission Factor for PM (Total)c from Table 1.4-2 of AP-42 Chapter 1.4

(July 1998), lbs/MMBTU

= 0.00745 1b/MMBTU

= 7.6 lb/b6 scf* (scf/ 1020 BTU) All PM (total, condensable, and filterable) is assumed to be less than 1.0 micrometer in diameter. Therefore, the PM emission factor presented here may be used to estimate PM10, PM2.5 or PM1 emissions. Total PM is the sum of the filterable PM and condensable PM.

Value of Input Factors
Factor (units) Pre-Project (1996) Post-Project (2005) V (kscflyr) 1,145,960 727,704 GHV (BTU/scf) 751.1 490.0 Avg. (Varies by Month) MW (lb/lbmole) 36.9 39.1 Avg. (Varies by Month) WFv0c 0.165 0.116 Avg. (Varies by Month) MFH2S 0.00 146 0.00049 Avg. (Varies by Month)
Actual Emission Estimates
Criteria Pollutant Pre-Project (1996) Post-Project (2005) CO (tpy) 159.2 66.0 NO~(tpy) 29.3 12.1 VOC (tpy) 183.6 90.6 SO2 (tpy) 138.1 29.2 Pb(tpy) 0.00021 0.000087 PM10 (tpy) 3.2 1.3 PM2.5 (tpy) 3.2 1.308/08/00 14:87 FAX 3148218494 DEE IcALINEY Id 04
CQM, INC. PG BOX 581 DURANGO, CO. 81302

(970) 247—4891
Source: Station ~: Station Name:

Field: METER RUN

15400—1999 PLANT INLET MOBIL E & P Report Date: Sample Date: Flowing Pressure: Flowing Temp.: 04/13/1996

4/8/96 44 psig 66 F

(~ 60 Dry Sat. Propane GPM Butane GPM Gasoline GPM 26~ Gasoline GPM

Total OPM
Real Specific Gravity Calculated = 1.2736

On—Site Specific Gravity = 0.0000
Gas Compressabllity 0.9938 = 1.808 1.003

= 0.654

= 1.392

= 3.465 Method: c;\ezchrom\wethods\cqmwet .met File: c:\ezchrom\chrom\1999.2
Gas Analysis by Chromatograph
Name Nitrogen Methane C02 Ethanc H2S propane i-Butane n-Butane i—Pentane n—Pent any Hexaucs Hept anes Octanes

Ideal Total
Gross BTU/ReaI Cu. Ft. Mole % BTU SO GPM

1.581 0.000 0.015 24.440 247.415 0.135 53.541 0.000 0.814 8.834 156.688 0.092 2.363 0.146 0.932 0.002 6.562 165.488 0.100 1.808 0.812 26.467 0.016 0.266 2.339 76.482 0.04? 0.737 0.736 29.515 0.018 0.269 0.716 28.770 0.018 0.259 0.227 10.821 0.007 0.093 0.050 2.758 0.002 0.023 0.016 1.122 0.001 0.009 0.000 0.000 0.000

100.000 746.458 1.266

deg F, 14.730)

= 751.097

= 739.238 5.8 28

Actual = 751.097 0.000 lbs. water/M!4CF) Gasoline Content

Remarks:07/24/2008 15:31 FAX 9705651379 bXXUNMU~J.I.—MthIH • u~r I.ompilance i~juu~,uv.~

Cu roMIR ~AJU CaM. INC. IOURCO ~t1A WI ~ MCI) PLANt I~JLET p~9u URE CO WFfI51k1E SA~PL9T*$P 1.0 ITION ANETH, lIT WEI.L F1.DWNO NIA PIE 9 DATI e*MPLEO 121’2/04 Pg 9Afl~w SAWPLEO OY DAN MILLER CU ~.ITN.NG. FORE IIWIIE 102L

~ Aqxg 0TEX~ BENZE;NE4.0252% (282 PPM); TOLUENE—L 01 19% (119 PPF.1)

ETNVLBENZENE~D.O021% (21 PPMfl XYLENE-C.0070% (70 PP?~ ANALYSIS Ot~YON~NT 1~E %

— — KT.U.’ ~~iEN 1.4~ o~o

- o~ 32 ~958 0.0000 0~ E1NANE 17.105 9.0000 173.16 0.0946 T)4.e~NE 8.346 1.7101 113.49 0.0004 ,~OPANE 4.901 121 CI 0.0731 OIJTANE 0791 0.2391 2393 0.0147 ~1~J4~ 2.469 0.8346 95.40 0.0401 PEP4TANE 0.487 0.1819 19.90 00124 ~PENTANE 05.97 0.2095 22.78 0.0141 EXANE aiM 02237 2539 0.0190 EPTAN6

. a o.oiio 8.48 0.0090 CTANE 0.093 0.0202 3.96 0.0025 OPLANERUO

- a.a~ 0.0146 0.0910 DTM. ic0.~ 4.0577 57HZ 1.3546

- 14.730 PSL#. DRY & UNCORRECTED FOR COMPRESSIBILITY

• ~ 14.7SOPSL~~&6UOEG.F. OMPRESSIBUTY FACTOR (l/Z) 1.0064 FTWCU.PT (DRY) CORRECTED FOR (l/Z) 5838 TIJ/CU,FT (WET) CORRECTED FOR (l/Z) 673.4 tEAL. SPEC~IC GRAVITY 1.3614 AALYSI~ RUN AT 14.730 PSIA 8.60 DEGREES F
RY STU~ 14.950 580.4 C~1.ND~# E1214 RYBTUGI4696 682.2 C’,LIIDERPRESSIJRE 25 P510 RYBTU~14,730 5830 E1~-JtRUN 12/16104 RYBTU~ 15.025 585.3 N.~I~UNBY JANACARANTA

~SS2-9~
~ 3DZ~3s Sl~’4l~ 5U~1.b~Li fl Tt

~- ,v’lt’O~



### ~ ~r~g- ~ ~ IJ~S k~jj+~



### ~ C~4se~4

~ of

5 W6.s- 

# 4~_ 

# ~2J~~IoLf

~ 

### wa~ ~
L41.4fl 

### ‘J~c~ 

## ic1 ‘2cos.07/24/2006 15:31 FAX 8705051379 EXXONMOBIL—ANETH • USP Co~p1ianCe I~003/003

CQM, INC. 0N-SrrE GAS ANALYSIS 1523 W. AZTEC BLVD. AZTEC, NM 87410 505-333-2003 ITVDROGEN SULFIDE ANALYSIS ANALYSIS DAm: 12-09-04 CUSTOMER: Exxo~iMobj1
WELL I.D.: PPM 1. 2087 25
.> 2. MCD Plant lnlt~t 500 3. Battt~ry #1 3000 4. Battery #2 4000 RESULTS: PPM HYDROGEN SULFTDE

ANALYSIS PERFORMED USING SENSIDYNE/GASTEC DETECTION TUBES.CQM~T~c.-EXXONMOOU1523W~I•~~4S.q,le-MCU!NIPLTAztic,M1687410Op~e8of-GayMoukaa-ChitOfOmccTtc6igdaiiS~,çbJib:CQM.Inc.MCI3INJECTIONPLANT.6-6-03.D~M3ilc,.LowPii~&~:~~t~.Li~,Lb’%I:1~A~Metbma.1510576,48314.4520.088160.001157.217137.236Etbene6.09344.6858.8110.063108.085306204106214Propin.4.31364.3646.4130066108.788106.894106.905Isob~aae0i1160.860I.0310.01218.860lS.33218.5331.66912.4802.8390.03354.37753.62753.6300.43530.8030.8600.01117.45617.13217.1530.51620.932.1.0090.01320.74120.38020.3810.16280.3590.3610.0057.7627.6277.628n-hcptaac0.05110.1.310.1280.0022.8282.7792.779001740.0510.0480.I1.0911.072.1.012a-~a.wc0.00500.0170.0150.0000.35403480.3480.00180.00700060.0000.1400.1370.137beaxinc0.03770.0730.0510.0011.4141.3891289totucan0.02780.0650.0500.0011.2451.2231.223cibytbcazcaa0.00370.0100.0080.0000.1820.1890.189c-xylem0.00220.0080.0040.0000.1340.1120.112cboa~bord6.68.153976.69262.6671.0360.0000.0000.000b0~ca,1~A1O0.00000.0000.0000.0000.0000.0000.000oxygen00000.0000.0000.0000.0000.0000.000202.36I.1.1970.0200.0000.0000.000bc~wo0.10100.0(00.0550.0000.0000.0000.000100.0101000001.350503.649494.883140.837~9P.363LISOl4ak~rW~.59.1*0C~Iitfl~iIy033107/20/2008 17:11 FAX 3705651379 EXXOHMOBIL-ANETH • USP Coipliance F~008/018

CQM, U~C ON-Sfl’E GAS ANALYSIS 1523W. AZTEC BLVD. AZTEC, NM 87410 505-333-2003 BYDROGEN SI1L~IDE ANALYSTS ANALYSIS DATE: 6/7/OS CUSTOMER: EXXONMOB]L
WELL La.; PPM I MCUJNJECTION PLANT 400

RESULTS: PPM HYDROGEN SULFIDE

ANALYSIS PERFORMED USU~1G SENSIDYNEIGASTEC DETECTION TUBES.07/20/2006 17:16 FAX 8705651379 EXX0N~0BIL—ANETH • USP Coipliance I~018/01O 67/28/2605 26:15 58533328~4 PAGE 63 C~(, I..

.. O~1-SITE GAS ~NALYSIS U

1523 H. A.~T!C BX.VD. AZTEC, NM 67410 505—333—2003 Source: EXXONMOBIL Report Dat.: 07/29/2005 08:O3~00 Station *: Sample Date: 07/26/2005 Station Name; MCU PLANT INLET Flowing Pressuze; 0 psig

Field: ANBTh, UT?~1f Flowing Tenp.; 0 F Method: C: \mti\ezc~rozn\200\mathods\btu9 .iuet File: C: \inti\ezchrom\200\chroznVncuinlet .2 Gas ~x~alysis by Chrotnatogtaph
Nan~e Mole % BTU RD GPM Nitrogen 1.444 0.000 0.014 Methane 17.347 175.610 0.096 C02 69.345 0.000 1.054 Ethane 5.883 104.352 0.061 1.572 Propnne 5.403 136.265 0.002 1.468 i’Butane 0.061 1.988 0.001 fl.fl2.O n—Butane 0.171 5.592 0.003 0.054 i—Pentane 0.045 1.605 0.001 0.016 n-Pentane 0.057 2.290 0.001 0.021 Hexanes 0.129 6.149 0.004 0.053 Octanee 0.051 3.194 0.002 i.026 Hepi.sflea 0.064 3.330 0.002 0.030 Nonanes 0.000 0.000 0.000

Ideal Total 100.000 440.775 1.323 3.280 Unnormalized Total 91.751 Gross BTU/Real Cu. Ft. Gasoline Content (@ 60 deg F, 14.730) Propane G~4

= 0.020 L)ry 443.201 Butane G~(

= 0.070 Sat.

— 436.559 Gasoline GPM

— 0.129 Actual

— 443.201 26* Gasoline GPM 0.146 0.000 ibs. water/W4CF) Total GPM

— 3.260
Real Relative Density Calculated 1.3293

On—Site Relative Density

— 0.0000 Gas CompressiSility

— 0.994507/20/2008 17:11 FAX 9705651378 EXX0N~OBIL—AHETH • USP Compliance ~007/01B 87/2e/2ee5 28:15 5€5333~884 PAGE 04

CQM~I INC. ON-S111 GAS ANALYSIS 1ZZJ W. AZTEC BLVD. AZTEC, NM 87410 505-333-2003 UYDROGEN SULFD)I ANALYSIS ANALYSIS DATE: 7f2 6105 CUSTOMER: E~QCONMOBJL W~L ID.: PPM i. MCUPL41J7’mLET 400

RESULTS: PPM HYDROGEN SULFIDE

ANALYSES PERFORMED USING SENSIDYNE/GASTEC DETECTION TUBES.07/20/2006 17:16 FAX 8705651379 EXXON$OBIL-AHETH e USP Compliance ~013/016 60/23/2865 28:67 5053332084 PAGE 62

C.O.H Inc 1523 C. Main Aztec, NM 505—333—2003 G~A 217Z—96 ~na1y$iS Sariple: EXXOm409U. Injection Date:9/16/2005 4:04:18 PM Method: dali Report Date: 6/16/2005 4:09:50 PM Flowing Pr.esure~O PSTG Flowing Tewç.rature:0 F Source; EXXONNOBIL Station Nane;HCEIMO CREEK flThET Field: 5M 3U~iN CO, tIT Name I RT (minI Normalized Mole 4 Heating Velue Gasoline Content (gal /1000 cubic ft gas)

I I I (Stu/cubic foot) I
I 1 1 I I

Citrogen I 0.657 1.4246 0.000 o.ooo
Methane j 0.697 I 16.0726 I 162.247 I 0.000 C02 I 0.949 68,3006 I 0.000 I 0.000 .Ethane I 1.166 I 5.7921 I 102.454 I 1-545 Propane 0.797 4.6071 I 115.872 I 1.266 i—Butane 0.954 I 0.6343 20.620 I 0.207 n—Butane I 1.072 I 1.8366 I 59.900 0.579 L—rentasIe I 1.482 I 0.452~ I 13.701 I 0.180 ~..p tana I 1.679 L 0.6390 25.596 I 0.231
Hexane I 3.026 0.2005 9.532 I 0.082 Totals I 0.000 I 100,0000 I 515.921 I 4.0e9

Unnornali~od Potal ~our~t~ 97.56 Calorific Values I Dry Saturated I I I I I

I I

Gross Rusting (Otu /pound) I 4969.982) 4949.639 I Gross Reating (Btu/Ideal cubic foot) 515.921 I 506.923 I Gross ieatinq (Stu/Real cubic LOOt) I 516.598 I 509.708 Molar Mass Ratio And Relative Density I Dry I Saturated I I I I I I
No1e~ )4ase I ~.23 I 6. I Molar Mass Ratio I 1.355 I 1.342 I Relativo Density i 1.362 I 1.349 I Holu F~Ctjen Wotor I 0.000 I 0,017 i07/20/2008 17:18 FAX 8705651379 EXX0N~0BIL—ANETH • USP Compliance ~014/018 06/23/2005 26;87 585333260d ~QM PAGE 03

Co~pre~5ibility I Dry I Saturated I I I I Compc~zsibi1jty Facto: I 0.995 I 0.995 I Liquid volwne e~ivalont 4.089 gal /1000 cubic ft Hole rractio~ flC4 for 2~ p~li cyaae1i~o 0.006449 ToLal 26 pai. Reid V~ ~aso1inm 0.6960 gil /3.000 cu1,i~ ft gae Warninqe: Uxuiormalized total amount varies aiore thin 11 from 100807/20/2006 17:11 FAX 3705651379 EXXONMOBIL—AHETM • USP Coapliance ~008/018 ee/2312665 26:67 5633332064 CQM PAGE 64

CQM, JNC. ONSUl GAS ANALYSIS 1523W. AZTEC BLVD. AZTEC, NM 87410 505-333-2003 HYDROGEN SULFIDE ANALYSIS ANALYSIS DATE: 8(23/OS CUSTOMER: EXXONMOBIL
WELL LD.: PPM I. MCUFL4I*IT INLET 400

RESULTS: PPM HYDROGEN SULFIDE

ANALYSIS PERPORMEI5 USiNG SENSE)YNFI(3ASTEC I)ETBCTION TUBES.-I.o.-Ic~Ici~009~i~b:I.Ei~~LabNo;Op.ror~_________________OslaFb8.T~P~Lo~~•~-‘~!J~..~i*~~~..i’1.~:—-PkI%Wt%UqVol%8PG~~GOTUCE17.07417.06215A900.~86iiaeoi6.54185.07195050.958116.030P~ipane4.82075.4807.1110.073121.5780.51800.0271.004901220.172n.~Je.n.1.73052.5032.9210.03500.5900.41050.7040.6940.01016.404ii.P.nlw0.02431.1611.2W0.0125.062i~-ffixs.0.12630.2010.2780.0046.820a4lep(atw0.03460.0800.0080.00118070.01150.0340.0310.0000.7190.00580.0120.0110.0000254-0.00180.0060.00600900.137Bem~ni0.62580.0560.0430.0011.0750.01920.0460.0340.0910550Eftqtm~ame0.00260.0070.0050.0000.1340.00160.0050.0030.0000056C~bo~~D~4de00.445575.36580520101000000.0000~0~P000.00000.0000.0000..0000~0bog.n1.3011~0.81$H.eim0.11260.0120.06?0.0000.000100.0000100.000100.0061.339530.08499.494SPG04i1.339oeiu~sGSTUiaVCF530.503N5TLJ~530.61546ecuIaWI.30.790Comp~onibd8y00800Thi~:;r..’r~:~j~~~P.O.~b.81013145.0GSrUd(CF~11~CE169.633169.856114.031110.482119.47519.82119.82155.00355.60516.17716.17824.84624.8475.9155.8151.474~S740.7060.7060.2500.2500.1950.1351.0501.0600.8440.8440.1310.1310.0050.OBS0.0000.0000.000110000.00000000.0000.0000.0000.000164.09207/20/2006 17:11 FAX 9705651379 EXXONMOBIL—ANETH
~ USP Compliance ~005/018 10/03/2085 22:01 5853332004 P~ 02

CQM, INC ON-SFI~ GAS ANALYSIS 1523W. C BL~ AZTEC, NM 87410 505.3334003 flVDROGEN STJIJIDE ANALYSTS ANALYSTS DATE; 9126105 FPJ~: 09130i2005, 10/03,2005
CUSTO~R: E~OCONMOBIL
WELL I.D.: PPM I. MCurI4IJTTPJ1ET 500

RESULTS: PPM HYDROGEN SULFIDE

ANALYSIS PERJ’ORMED USING SENSJDYNI~1GASTEC DEThCTION TUBES.07/20/2008 17:11 FAX 9705651379 EXXDN$OBIL—AHETH • USP Coipliance ~011/018 Page lofI 

### c.Q.u Inc 1523W. Main Aztec, NM 505-333-2003
GPA 217245 Analysis

[EXXONMO6X. 1h94c594 Date: 1011120059:15 

### l~hod: ~ IR~~~1m [Flowira Preisuie 

### 10 P810 ~FIcwlng Twa~i9Ke: p F 34w~ I~0NM051L 

### I

Suitor Main.: ~ ~tefd: SAiti JUAN GO. Lit

Mini. Naniia~d N.. GinoUn. N 0.65 1.4177 hi 0.069 10.8224 109.825 C02 0.944 07.11 0 Eei.,i. 1.138 5.0076 99.104
coos 5049 126.909 0. 1 0. 1 20.685 1.062 2.0302 59.434 1.502 0.456 19.438 I1.P941150 1.704 23103 Maxine 7 0.1442 8.958 Total 100 556.307

5210 5168.565 tolidial wblc 001.307 000.062 lume.I ted 539.097 529.856 Nolli Noes Rid. Ralhive Da

MoIerM~. 39. 7 38.69 him RoIl. 1.349 1.230 1.355 .343 Mel. F,adior WaW

— 0.017 C hIll) 0 SaMaated

Faotor 0.905 0.995
Liquid volume equivalent. : 4.214 gal /1000 cubic ft Mole Fraction nC4 for 26 psi gasoline : 0.005697 Total 26 psi Reid VP gasoline : 0.6316 gal /1000 cubic ft Qes

Warnings: Unnorinalized total omount varies mor, than 1% from 100%

~ 10/10/0507/20/2006 17:11 FAX 8705651379 EXXONMOB!L—ANETH • USP Co~p1jance ~004/018

CQM~ INC. ON-SITE GAS ANALYSIS 1523 W. AZTEC BLVD. AZTEC, NM 87410 505-333-2003 HYDROGEN SULFIDE ANALYSIS ANALYSIS DATE: 10/07/05
CUSTOMER EXXONMOBIL
WELL LD.: PPM I. MCUPLANT INLET 50(1

RESULTS: PPM HYDROGEN SULFIDE

ANALYSIS PERFORMED USING SENSIDYNEIGASTEC DETECTION TUEES.07/20/2006 17:11 FAX 9705651379 EXXONMOBIL—AHETH • USP Coopliance ~010/018 Page 1 of 1

C.Q.M Inc 1523 W. Main Aztec, NM 505-333-2003
GPA 2172-96 Analysis

~mpla Kep,a..eiiud~ EXXOOIMOBIL h,juctiou Due I 113(1005 105I56 AM Ictbud~ din Rcpue Dute 1119(2005152.35 AM Iuw.’3 Preciuru: 0 PSIG FIo~umg Tenpeu~wc: 0 )~ OXXONMOUU. Iaac.l Nutuc: MCELMO cREEK 1341.51 F,cI& SAN JUAN CO UT

Of 1925 Stun tubc putIud-SOCppm

Nornhllied Ueud.~V.iui (Btuk.bk GpuIMuCo69unt Him, Wr (ruin)
~ (~uI/1OOo cubic ti us)

0655 1.4471 0.000 0.000

— Mclhunc 0.695 17.1504 160.610 0.000 C02 0.944 67.2504 0000 0.000 EIbN,e 1.141 6.0900 116.993 1.764 Prepsuc 0.709 4.9002 125447 1.311 i-8ulnnc 0.957 0.6191 22.453 0225

1,401 0.4624 11.537

- 0.169
n.Pn15n4 1.692 0.5745 23.067 0.200 Hcun. 3.057 0.1472 7.016 0.061 100.0000 494.220 3.790 Calmirue Viii,, u~1, 5a~.rut4 OmuHmIIng(Dl~cund) 4992.736 ‘442.421

— (hneHüngdcuie*ic0.ot) 404220 45419 Gnu H~c6ug (01n19uuI cIIbI~ (ccc) 496.624 469,129 Motur Miii Padu And Rduti.c Puuuity Dry Saturu.t.d

MoIsrMiu 10222 37.961 MalirM,isRutio 1221 1.311 Rii’dvcDcnui1y 1329 1.316

— Mali Fziciica Wi~

— 0.017

C.u.pruiualliiy Dry Sulurarud QmprcnIbiIiiy F,rtae 0395 0.995 Liquid volume equivalent 3.796 gel /1000 cubic ft Mole traction nC4 for 26 ps.~ gasoline 0.005547 Total 26 psi Keid VP gasoline 0.6128 gal /1000 cubic ft gas

Warnings: Unnormalized total amount varies more th~~ 1% from 100$

fi1c:llC:\Documerns%20and%2OSeuings\dswhite~LocaI%20scttings~Temp’~notesDD34o3\cu... 11/9/0507/20/2006 17:11 FAX 8705651379 EXXOHMOBIL—AHETH • LISP Coripliance t~OO3/018

CQM, INC. ON-SITE GAS ANALYSIS 1523 W. AZTEC BLVD. AZTEC, NM 874W 505-333-2003 HYDROGEN SULFIDE ANALYSIS ANALYSIS DATE: 11/3/05 CUSTOMER: EXXONMOBTL
WELL TD.: PPM I. MCUPLANTINLET 500

RESULTS: PPM hYDROGEN SULFIDE

ANALYSIS PERFORMED USING SENSTDYNE/GASTEC DETECTION TUBES.07/20/2006 17:11 FAX 9705851378 EXXOHMOBIL—ANETH + USP Coepliance F~009/018 Page 1 oft

C.Q.M Inc 1523 W. Main Aztec, NM 505-333-2003 GPA 2172-96 Aoi lysis

lomptc: ECCONMOBEL Injcctiai r2~tr 131812005 2~30I0 PM 4othod: daU RapanDota: 1V012005 2:32 50 PM 1owi+~ Pronuro: 0 PSIG Flawiii~ tsTç.owrt. 0 P £XXONMOBII. iou,, MCELMO CREEK INLET P1,14: SAN JUAN CO. 171’ 1OTI6S; 12S STAIN TUIIR 414.450 PPM

Nar~ai1zed Hoat14~ Vol.. (Irolcobdc O~so1Ioi Cootoal N.m. RT (mis) Mat. % ii 11008 eiibtc ft u

0.650 1.4210 0.000 0.000 Mcthmic 0.680 15.882S 160.690 0,000 C02 6.941 66.6648 0.000 0.000

1.156 &S401 9L356 1.402 Propane 0.799 4.8264 121.610 1.328 ~.Fatan. 0.956 0.6676 21.751 0.211

1.075 1.8574 60.704 0.584 I-PcnEne 1.489 0.4060 16.276 0.149 *.Pciuaiie 1.601 0.4602 11.403 0.167 Hems, 3.048 0.2630 12.531 0.108 Total, .—— 100.0000 510.391 4.039

ColartOc V.l.a GronHwtag(Ia~oid) 4919.344 4179.711 OromHeng(D14lldcIicubIcfo.t) 510.391 501.516 Oem. Hnumg (EouVjaI cable (ole) 513.045 504.272 Molar Miii Ratio And JIdadvi Duulty Dry hunted

Molar t4aao 39.161 38912 MoI.rMwha0a 1.356 1.344 RelodveDc,talIy 1363 1.151 MalcFlcIj99Wau,

— 0.011 C.mpremtbili~ Dip Cot pr otbiI6y Faciar 0395 0.995 Liquid volume equivalent : 4.039 gal /1000 cubic ft Hole Fraction nC4 for 26 psi gasoline 0.005697 Total 26 psi Reid VP gasoline : 0.6095 gal /1000 cubic ft gas

Warnings: Unnormaljzed total amount varies more than 1% from 100%

file:l/C:\Documents%2oand%2oSengs\dswhit\Local%2oSettings\Temp\notesDD34O3\C... 12/12/0507120/2006 17:11 FAX 9705651379 EXXOHHOBIL—AHETH
‘ (iSP Corpliance ~002/018 12/12/2065 22:~9 5653332964 PASE 63

CQM, INC. ON-SITE GAS ANALYSIS 1523W. AZTEC BLVD. AZTEC, NM 81410 505-333-2003
IIVDROGEN SULFIDE ANALYSIS
ANALYSIS DATE: 12/10/OS CUSTOMER: E)OCONMOBIL
WELL LD: PPM I. MCUPL4AITJYLEr 450

RESULTS; PPM HYDROGEN SULFIDE

ANALYSIS PERFORMED USING SFNSIDYNE/OASThC DETECTION TUBES.APPENDIX C SCREEN3 MODELING INPUT AND OUTPUT RESULTSSCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ~
McELMO MAIN FLARE

-- NOx DISPERSION, 618,104 SCF/.HR, 300 BTU/SCF
SIMPLE TERRAIN INPUTS: SOURCE TYPE = EMISSION RATE (G/S) = FLARE STACK HEIGHT (M) = TOT HEAT RLS (CALlS) = RECEPTOR HEIGHT (M) = URBAN/RURAL OPTION = EFF RELEASE HEIGHT (M) = BUILDING HEIGHT (M) = MIN HORIZ BLDG DIM (M) = MAX HORIZ BLDG DIM (M) = FLARE 1.50000 59.4500

• 129887E+08 0000 RURAL 70.9117 .0000 .0000 .0000
THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 215.356 M**4/S**3; MOM. FLUX 131.320 M**4/S**2.

~ FULL METEOROLOGY ***

************************* *********

‘~~‘ SCREEN AUTOMATED DISTANCES ***

* *** * * * ** ** *** ***** ****** *** *** 02/22/05 11 : 00 :38

TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** DIST CONC U1OM USTK MIX HT PLUME SIGMA SIGMA (N) (UG/M**3) STAB (MIS) (MIS) (M) HT (N) Y (M) Z (M) DWASH
200. .1976E-03 5 1.0 2.0 10000.0 212.67 42.14 40.98 NO 300. .2504E—03 5 1.0 2.0 10000.0 212.67 43.89 41.43 NO 400. .1994E—02 1 3.0 3.4 960.0 353.43 102.30 83.27 NO 500. .9364E-01 1 3.0 3.4 960.0 353.43 123.67 116.05 NO 600. .5748 1 3.0 3.4 960.0 353.43 144.45 164.03 NO 700. 1.0/1 1 3.0 3.4 960.0 353.43 164.74 222.37 NO 800. 1.236 1 3.0 3.4 960.0 353.43 184.62 291.21 NO 900. 1.570 1 1.5 1.7 636.9 635.95 241.27 392.31 NO 1000. 1.831 1 1.5 1.7 636.9 635.95 262.53 480.98 NO 1100. 1.893 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 1200. 1.849 1 1.5 1.7 636.9 635.95 293.46 686.83 NO 1300. 1.769 1 1.5 1.7 636.9 635.95 308.54 807.14 NO 1400. 1.687 1 1.5 1.7 636.9 635.95 323.75 939.12 NO 1500. 1.611 1 1.5 1.7 636.9 635.95 339.05 1082.70 NO 1600. 1.541 1 1.5 1.7 636.9 635.95 354.42 1237.88 NO 1700. 1.477 1 1.5 1.7 636.9 635.95 369.84 1404.65 NO 1800. 1.417 1 1.5 1.7 636.9 635.95 385.28 1583.04 NO 1900. 1.363 1 1.5 1.7 636.9 635.95 400.74 1773.09 NO 2000. 1.312 1 1.5 1.7 636.9 635.95 416.20 1974.82 NO 2100. 1.265 1 1.5 1.7 636.9 635.95 431.66 2188.30 NO 2200. 1.221 1 1.5 1.7 636.9 635.95 447.11 2413.56 NO 2300. 1.181 1 1.5 1.7 636.9 635.95 462.53 2650.65 NO 2400. 1.143 1 1.5 1.7 636.9 635.~95 477.94 2899.62 NO 2500. 1.107 1 1.5 1.7 636.9 635.95 493.32 3160.53 NO 2600. 1.074 1 1.5 1.7 636.9 635.95 508.66 3433.41 NO 2700. 1.042 1 1.5 1.7 636.9 635.95 523.98 3718.32 NO 2800. 1.013 1 1.5 1.7 636.9 635.95 539.26 4015.30 NO 2900. .9848 1 1.5 1.7 636.9 635.95 554.51 4324.41 NO3000. .9585 1 1.5 1.7 636.9 635.95 569.72 4645.68 NO

3500. .9357 2 1.5 1.7 636.9 635.95 495.84 461.21 NO 4000. .9215 2 1.5 1.7 636.9 635.95 551.47 525.60 NO
MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 1097. 1.893 1 1.5 1.7 636.9 635.95 277.95 574.19 NO
DWASH= MEANS NO CALC MADE (CONC = 0.0) DWASH=NO MEANS NO BUILDING DOWNWASH USED DWASH~HS MEANS HUBER-SNYDER DOWNWASH USED DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

~ SUMMARY OF SCREEN MODEL RESULTS ***

******* ************ ********************
CALCULATION MAX CONC DIST TO TERRAIN PROCEDURE (UG/M**3) MAX (M) HT (M)
SIMPLE TERRAIN 1.893 1097. 0.

******

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

********** **   ** ****** ***************************SCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ***
McELMO MAIN FLARE

-- NOx DISPERSION, 618,104 SCF/HR, 443 BTU/SCF
SIMPLE TERRAIN INPUTS: SOURCE TYPE = EMISSION RATE (G/S) = FLARE STACK HEIGHT CM) = TOT HEAT RLS (CAL/S) = RECEPTOR HEIGHT CM) = URBAN/RURAL OPTION = EFF RELEASE HEIGHT (N) = BUILDING HEIGHT (M) = MIN HORIZ BLDG DIM (M) = MAX HORIZ BLDG DIM (M) = FLARE 2 .21000 59.4500

• 191799E÷08 .0000 RURAL 73.2591 .0000 .0000 .0000 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2.

~ FULL METEOROLOGY ***

*******   ** *********************

~ SCREEN AUTOMATED DISTANCES

~

******* ************ *************** 02/18/05 09 :42 :13

TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** DIST CONC U1OM USTK MIX HT PLUME SIGMA SIGMA (N) (UG/M**3) STAB (MIS) (MIS) (M) HT (M) Y (M) Z CM) DWASH
200. .4666E—03 5 1.0 2.0 10000.0 234.08 47.40 46.37 NO 300. .5548E-03 5 1.0 2.0 10000.0 234.08 48.96 46.76 NO 400. .6661E-03 5 1.0 2.0 10000.0 234.08 50.95 47.20 NO 500. •2049E-01 1 3.0 3.4 960.0 429.40 126.59 119.17 NO 600. .3019 1 3.0 3.4 960.0 429.40 147.64 166.85 NO 700. .8718 1 3.U i.4 950.0 429.40 1~8.18 22494 NO 800. 1.266 1 3.0 3.4 960.0 429.40 188.30 293.55 NO 900. 1.755 1 2.0 2.3 640.0 607.47 228.42 384.54 NO 1000. 2.089 1 2.0 2.3 640.0 607.47 248.95 473.71 NO 1100. 2.143 1 2.0 2.3 640.0 607.47 269.15 573.82 NO 1200. 2.061 1 2.0 2.3 640.0 607.47 288.71 684.81 NO 1300. 1.969 1 2.0 2.3 640.0 607.47 304.03 805.43 NO 1400. 1.876 1 2.0 2.3 640.0 607.47 319.45 937.65 NO 1500. 1.800 1 1.5 1.7 786.5 785.55 360.99 1089.77 NO 1600. 1.731 1 1.5 1.7 786.5 785.55 375.46 1244.06 NO 1700. 1.667 1 1.5 1.7 786.5 785.55 390.04 1410.10 NO 1800. 1.606 1 1.5 1.7 786.5 785.55 404.72 1587.88 NO 1900. 1.550 1 1.5 1.7 786.5 785.55 419.46 1777.41 NO 2000. 1.497 1 1.5 1.7 786.5 785.55 434.26 1978.71 NO 2100. 1.447 1 1.5 1.7 786.5 785.55 449.09 2191.81 NO 2200. 1.401 1 1.5 1.7 786.5 785.55 463.96 2416.74 NO 2300. 1.358 1 1.5 1.7 786.5 785.55 478.84 2653.55 NO 2400. 1.317 1 1.5 1.7 786.5 785.55 493.74 2902.27 NO 2500. 1.278 1 1.5 1.7 786.5 785.55 508.64 3162.96 NO 2600. 1.242 1 1.5 1.7 786.5 785.55 523.54 3435.64 NO 2700. 1.207 1 1.5 1.7 786.5 785.55 538.43 3720.38 NO 2800. 1.175 1 1.5 1.7 786.5 785.55 553.32 4017.22 NO 2900. 1.144 1 1.5 1.7 786.5 785.55 568.19 4326.19 NO3000. 1.115 1 1.5 1.7 786.5 785.55 583.04 4647.34 NO

3500. 1.024 2 2.0 2.3 640.0 607.47 493.05 458.20 NO 4000. 1.012 2 2.0 2.3 640.0 607.47 548.96 522.97 NO
MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 1075. 2.148 1 2.0 2.3 640.0 607.47 263.93 546.73 NO
DWASH= MEANS NO CALC MADE (CONC = 0.0) DWASH=NQ MEANS .NO BUILDING DOWNWASH USED DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

* **************************************

~ SUMMARY OF SCREEN MODEL RESULTS ***

*
CALCULATION MAX CONC DIST TO TERRAIN PROCEDURE (UG/M**3) MAX (M) HT (M)
SIMPLE TERRAIN 2.148 1075. 0.

*********** ************* ************************.***

** REMEMBER TO INCLUDE BACKGROU~JD CONCENTRATIONS **

****** ***** *** ************* ************************SCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ~
MCELMO MAIN FLARE

-- SO2 DISPERSION, 618,104 SCF/HR, 300 BTU/SCF, H2S 700 PPM
SIMPLE TERRAIN INPUTS: SOURCE TYPE EMISSION RATE (G/S) FLARE STACK HEIGHT (M) TOT HEAT RLS (CAL/S) RECEPTOR HEIGHT (M) URBAN/RURAL OPTION EFF RELEASE HEIGHT BUILDING HEIGHT (M) MIN HORIZ BLDG DIM MAX HORIZ BLDG DIM = FLARE

= 9.21000

= 59.4500

= .129887E+08

= .0000

= RURAL

= 70.9117

= .0000

THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 215.356 M**415**3; MOM. FLUX = 131.320 M**4/5**2.

~kk FULL METEOROLOGY ***

* **   ** 

~“ SCREEN AUTOMATED DISTANCES ***

* ****** ** ** * 03/24/05 14:30:42

(M) (M) = (M) = • 0000

0000

TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES
~ DIST CONC U1OM USTK MIX HT PLUME SIGMA SIGMA (M) (UG/M**3) STAB (MIS) (MIS) (M) HT (N) Y (N) Z (N) DWASH
200. .1213E-02 5 1.0 2.0 10000.0 212.67 42.14 40.98 NO 300. •1537E-02 5 1.0 2.0 10000.0 212.67 43.89 41.43 NO 400. .1224E-01 1 3.0 3.4 960.0 353.43 102.30 83.27 NO 500. .5749 1 3.0 3.4 960.0 353.43 123.67 116.05 NO 600. 3.529 1 3.0 3.4 960.0 353.43 144.45 164.03 NO 700. 6.577 1 3.U .3.4 96U.tJ i53.4~ 164.74 222.~7 NO 800. 7.587 1 3.U .3.4 960.0 353.43 184.62 291.21 NO 900. 9.638 1 1.5 1.7 636.9 635.95 241.27 392.31 NO 1000. 11.24 1 1.5 1.7 636.9 635.95 262.53 480.98 NO 1100. 11.63 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 1200. 11.35 1 1.5 1.7 636.9 635.95 293.46 686.83 NO 1300. 10.86 1 1.5 1.7 636.9 635.95 308.54 807.14 NO 1400. 10.36 1 1.5 1.7 636.9 635.95 323.75 939.12 NO 1500. 9.889 1 1.5 1.7 636.9 635.95 339.05 1082.70 NO 1600. 9.460 1 1.5 1.7 636.9 635.95 354.42 1237.88 NO 1700. 9.066 1 1.5 1.7 636.9 635.95 369.84 1404.65 NO 1800. 8.703 1 1.5 1.7 636.9 635.95 385.28 1583.04 NO 1900. 8.367 1 1.5 1.7 636.9 635.95 400.74 1773.09 NO 2000. 8.056 1 1.5 1.7 636.9 635.95 416.20 1974.82 NO 2100. 7.768 1 1.5 1.7 636.9 635.95 431.66 2188.30 NO 2200. 7.499 1 1.5 1.7 636.9 635.95 447.11 2413.56 NO 2300. 7.249 1 1.5 1.7 636.9 635.95 462.53 2650.65 NO 2400. 7.015 1 1.5 1.7 636.9 635.95 477.94 2899.62 NO 2500. 6.797 1 1.5 1.7 636.9 635.95 493.32 3160.53 NO 2600. 6.592 1 1.5 1.7 636.9 635.95 508.66 3433.41 NO 2700. 6.399 1 1.5 1.7 636.9 635.95 523.98 3718.32 NO 2800. 6.218 1 1.5 1.7 636.9 635.95 539.26 4015.30 NO 2900. 6.047 1 1.5 1.7 636.9 635.95 554.51 4324.41 NO3000. 5.885 1 1.5 1.7 636.9 635.95 569.72 4645.68 NO

3500. 5.745 2 1.5 1.7 636.9 635.95 495.84 461.21 NO 4000. 5.658 2 1.5 1.7 636.9 635.95 551.47 525.60 NO
MAXIMUN 1-HR CONCENTRATION AT OR BEYOND 200. M: 1097. 11.63 1 1.5 1.7 636.9 635.95 277.95 574.19 NO
DWASH= MEANS NO CALC MADE (CONC = 0.0) DWASH=NO MEANS NO BUILDING DOWNWASH USED DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED DWASH=SS MEANS SCHULMAN-5CIRE DOWNWASH USED DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

******

~ SUNNARY OF SCREEN MODEL RESULTS ***

***********
CALCULATION MAX CONC DIST TO TERRAIN PROCEDURE (UG/M**3) MAX (M) HT (M)
SIMPLE TERRAIN 11.63 1097. 0.

*******

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

*******   ** *** *** *****SCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ~ 03/28/05 06 : 03 :09

McELMO MAIN FLARE

-- SO2 DISPERSION, 618,104 SCF/HR, 443 BTU/SCF, H2S 700 PPM
SIMPLE TERRAIN INPUTS: SOURCE TYPE EMISSION RATE (G/S) FLARE STACK HEIGHT (M) TOT HEAT RLS (CAL/S) RECEPTOR HEIGHT (M) URBAN/RURAL OPTION EFF RELEASE HEIGHT (M) BUILDING HEIGHT (M) MIN HORIZ BLDG DIM (M) MAX HORIZ BLDG DIM (M) = FLARE

= 9.21000

= 59.4500

= .191799E+08

= .0000

= RURAL

= 73.2591

= .0000

= .0000

= .0000
THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2.

~ FULL METEOROLOGY ***

******* ***************************

*** SCREEN AUTOMATED DISTANCES ***

****** * ** ** ***********************
TERRAIN HEIGHT OF 0. N ABOVE STACK BASE USED FOR FOLLOWING DISTANCES *** DIST CONC U1OM USTK MIX HT PLUME SIGMA SIGMA (M) (UG/M**3) STAB (MIS) (MIS) (N) HT (M) Y (M) Z (N) DWASH
200. .1945E-02 5 1.0 2.0 10000.0 234.08 47.40 46.37 NO 300. .2312E—02 5 1.0 2.0 10000.0 234.08 48.96 46.76 NO 400. .2776E—02 5 1.0 2.0 10000.0 234.08 50.95 47.20 NO 500. .8538E—01 1 3.0 3.4 960.0 429.40 126.59 119.17 NO 600. 1.258 1 3.0 3.4 960.0 429.40 147.64 166.85 NO /UO. 3.633 1 3.0 3.4 960.0 429.40 168.18 224.94 NO 600. 5.276 1 3.0 3.4 960.0 429.40 188.30 293.55 No 900. 7.314 1 2.0 2.3 640.0 607.47 228.42 384.54 NO 1000. 8.704 1 2.0 2.3 640.0 607.47 248.95 473.71 NO 1100. 8.931 1 2.0 2.3 640.0 607.47 269.15 573.82 NO 1200. 8.589 1 2.0 2.3 640.0 607.47 288.71 684.81 NO 1300. 8.207 1 2.0 2.3 640.0 607.47 304.03 805.43 NO 1400. 7.816 1 2.0 2.3 640.0 607.47 319.45 937.65 NO 1500. 7.503 1 1.5 1.7 786.5 785.55 360.99 1089.77 NO 1600. 7.215 1 1.5 1.7 786.5 785.55 375.46 1244.06 NO 1700. 6.945 1 1.5 1.7 786.5 785.55 390.04 1410.10 NO 1800. 6.694 1 1.5 1.7 786.5 785.55 404.72 1587.88 NO 1900. 6.458 1 1.5 1.7 786.5 785.55 419.46 1777.41 NO 2000. 6.238 1 1.5 1.7 786.5 785.55 434.26 1978.71 NO 2100. 6.032 1 1.5 1.7 786.5 785.55 449.09 2191.81 NO 2200. 5.839 1 1.5 1.7 786.5 785.55 463.96 2416.74 NO 2300. 5.657 1 1.5 1.7 786.5 785.55 478.84 2653.55 NO 2400. 5.487 1 1.5 1.7 786.5 785.55 493.74 2902.27 NO 2500. 5.326 1 1.5 1.7 786.5 785.55 508.64 3162.96 NO 2600. 5.174 1 1.5 1.7 786.5 785.55 523.54 3435.64 NO 2700. 5.031 1 1.5 1.7 786.5 785.55 538.43 3720.38 NO 2800. 4.896 1 1.5 1.7 786.5 785.55 553.32 4017.22 NO 2900. 4.768 1 1.5 1~7 786.5 785.55 568.19 4326.19 NO3000. 4.646 1 1.5 1.7 786.5 785.55 583.04 4647.34 NO

3500. 4.268 2 2.0 2.3 640.0 607.47 493.05 458.20 NO 4000. 4.216 2 2.0 2.3 640.0 607.47 548.96 522.97 NO
MAXIMUN 1-HR CONCENTRATION AT OR BEYOND 200. M: 1075. 8.951 1 2.0 2.3 640.0 607.47 263.93 546.73 NO
DWASH= MEANS NO CALC MADE (CONC = 0.0) DWASH=NO MEANS NO BUILDING DOWNWASH USED DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

************* **************************

*** SUMMARY OF SCREEN MODEL RESULTS ***

*********** ** CALCULATION MAX CONC DIST TO TERRAIN PROCEDURE (UG/M**3) MAX (M) HT (M)
SIMPLE TERRAIN 8.951 1075. 0.

************ ***************************** **********

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

********************SCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ***
McELMO MAIN FLARE

-- CO DISPERSION, 618,104 SCF/HR, 300 BTU/CF
SIMPLE TERRAIN INPUTS: SOURCE TYPE EMISSION RATE (G/S) FLARE STACK HEIGHT (M) TOT HEAT RLS (CALlS) RECEPTOR HEIGHT (M) URBAN/RURAL OPTION EFF RELEASE HEIGHT (M) BUILDING HEIGHT (M) MIN HORIZ BLDG DIM CM) MAX HORIZ BLDG DIM (M) = FLARE

= 12.8400

= 59.4500

= .129887E÷08

= .0000

= RURAL

= 70.9117

= .0000

= .0000

= .0000 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 215.356 M**4/S**3; MOM. FLUX = 131.320 M**4/S**2.

~ FULL METEOROLOGY ***

******* ***************************

~ SCREEN AUTOMATED DISTANCES ***

~  **  ** 02/22/05 11 : 05:15

TERRAIN HEIGHT OF 0. N ABOVE STACK BASE USED FOR FOLLOWING DISTANCES
~ DIST CONC U1OM USTK MIX HT PLUME SIGMA SIGMA CM) (UG/M**3) STAB (MIS) (MIS) (N) HT CM) Y (M) Z (M) DWASH
200. .1691E—02 5 1.0 2.0 10000.0 212.67 42.14 40.98 NO 300. .2143E—02 5 1.0 2.0 10000.0 212.67 43.89 41.43 NO 400. .1707E—01 1 3.0 3.4 960.0 353.43 102.30 83.27 NO 500. .8015 1 3.0 3.4 960.0 353.43 123.67 116.05 NO 600. 4.920 1 3.0 3.4 960.0 353.43 144.45 164.03 NO 70U. 9.169 1 3.0 3.4 9~OC) 3S3.43 164.74 222.37 NO 800. 10.58 1 3.0 3.4 960.0 353.43 184.62 291.21 NO 900. 13.44 1 1.5 1.7 636.9 635.95 241.27 392.31 NO 1000. 15.67 1 1.5 1.7 636.9 635.95 262.53 480.98 NO 1100. 16.21 1 1.5 1.7 636.9 635.95 278.55 578.29 NO 1200. 15.83 1 1.5 1.7 636.9 635.95 293.46 686.83 NO 1300. 15.14 1 1.5 1.7 636.9 635.95 308.54 807.14 NO 1400. 14.44 1 1.5 1.7 636.9 635.95 323.75 939.12 NO 1500. 13.79 1 1.5 1.7 636.9 635.95 339.05 1082.70 NO 1600. 13.19 1 1.5 1.7 636.9 635.95 354.42 1237.88 NO 1700. 12.64 1 1.5 1.7 636.9 635.95 369.84 1404.65 NO 1800. 12.13 1 1.5 1.7 636.9 635.95 385.28 1583.04 NO 1900. 11.66 1 1.5 1.7 636.9 635.95 400.74 1773.09 NO 2000. 11.23 1 1.5 1.7 636.9 635.95 416.20 1974.82 NO 2100. 10.83 1 1.5 1.7 636.9 635.95 431.66 2188.30 NO 2200. 10.45 1 1.5 1.7 636.9 635.95 447.11 2413.56 NO 2300. 10.11 1 1.5 1.7 636.9 635.95 462.53 2650.65 NO 2400. 9.780 1 1.5 1.7 636.9 635.95 477.94 2899.62 NO 2500. 9.476 1 1.5 1.7 636.9 635.95 493.32 3160.53 NO 2600. 9.190 1 1.5 1.7 636.9 635.95 508.66 3433.41 NO 2700. 8.921 1 1.5 1.7 636.9 635.95 523.98 3718.32 NO 2800. 8.668 1 1.5 1.7 636.9 635.95 539.26 4015.30 NO 2900. 8.430 1 1.5 1.7 636.9 635.95 554.51 4324.41 NO3000. 8.205 1 1.5 1.7 636.9 635.95 569.72 4645.68 NO

3500. 8.010 2 1.5 1.7 636.9 635.95 495.84 461.21 NO 4000. 7.888 2 1.5 1.7 636.9 635.95 551.47 525.60 NO
MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 1097. 16.21 1 1.5 1.7 636.9 635.95 277.95 574.19 NO
DWASH= MEANS NO CALC MADE (CONC = 0.0) DWASH=NO MEANS NO BUILDING DOWNWASH USED DWASH=HS MEANS HUBER-5NYDER DOWNWASH USED DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

*** ****** ** *** ***** *** ***** ** ******** **

*** SUMMARY OF SCREEN MODEL RESULTS

~

*************************************** CALCULATION MAX CONC DIST TO TERRAIN PROCEDURE (UG/M**3) MAX (M) HT (M)
SIMPLE TERRAIN 16.21 1097. 0.

*********************

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

** ************************************************ *SCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ~ McELMQ MAIN FLARE

-- CO DISPERSION, 618,104 SCF/HR, 443 BTU/SCF
SIMPLE TERRAIN INPUTS: SOURCE TYPE EMISSION RATE (G/S) FLARE STACK HEIGHT (M) TOT HEAT RLS (CALlS) RECEPTOR HEIGHT (M) URBAN/RURAL OPTION EFF RELEASE HEIGHT (M) BUILDING HEIGHT CM) MIN HORIZ BLDG DIM (M) MAX HORIZ BLDG DIM CM) = FLARE

= 18.9600

= 59.4500

= .191799E+08

= .0000

= RURAL

= 73.2591

= .0000

= .0000

= .0000 THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGtJj~ATORy (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 318.009 M**4/S**3; MOM. FLUX = 193.915 M**4/S**2.

~ FULL METEOROLOGY ***

********* *************************

~ SCREEN AUTOMATED DISTANCES ***

*** *** *** 02/18/05 09 :49:45

TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES
~ DIST CONC U1OM USTK MIX MT PLUME SIGMA SIGMA (M) (UG/M**3) STAB (MIS) (MIS) CM) HT (N) Y (N) Z CM) DWASH
200. .4003E-02 5 1.0 2.0 10000.0 234.08 47.40 46.37 NO 300. .4760E-02 5 1.0 2.0 10000.0 234.08 48.96 46.76 NO 400. .5715E—02 5 1.0 2.0 10000.0 234.08 50.95 47.20 NO 500. .1758 1 3.0 3.4 960.0 429.40 126.59 119.17 NO 600. 2.590 1 3.0 3.4 960.0 429.40 147.64 166.85 NO 700. 7.479 1 3.0 3.4 960.0 429.40 16R.l8 224.94 NO 800, 10.86 1 3.0 3.4 960.0 429.40 188.30 293.55 NO 900. 15.06 1 2.0 2.3 640.0 607.47 228.42 384.54 NO 1000. 17.92 1 2.0 2.3 640.0 607.47 248.95 473.71 NO 1100. 18.39 1 2.0 2.3 640.0 607.47 269.15 573.82 NO 1200. 17.68 1 2.0 2.3 640.0 607.47 288.71 684.81 NO 1300. 16.89 1 2.0 2.3 640.0 607.47 304.03 805.43 NO 1400. 16.09 1 2.0 2.3 640.0 607.47 319.45 937.65 NO 1500. 15.45 1 1.5 1.7 786.5 785.55 360.99 1089.77 NO 1600. 14.85 1 1.5 1.7 786.5 785.55 375.46 1244.06 NO 1700. 14.30 1 1.5 1.7 786.5 785.55 390.04 1410.10 NO 1800. 13.78 1 1.5 1.7 786.5 785.55 404.72 1587.88 NO 1900. 13.30 1 1.5 1.7 786.5 785.55 419.46 1777.41 NO 2000. 12.84 1 1.5 1.7 786.5 785.55 434.26 1978.71 NO 2100. 12.42 1 1.5 1.7 786.5 785.55 449.09 2191.81 NO 2200. 12.02 1 1.5 1.7 786.5 785.55 463.96 2416.74 NO 2300. 11.65 1 1.5 1.7 786.5 785.55 478.84 2653.55 NO 2400. 11.30 1 1.5 1.7 786.5 785.55 493.74 2902.27 NO 2500. 10.96 1 1.5 1.7 786.5 785.55 508.64 3162.96 NO 2600. 10.65 1 1.5 1.7 786.5 785.55 523.54 3435.64 NO 2700. 10.36 1 1.5 1.7 786.5 785.55 538.43 3720.38 NO 2800. 10.08 1 1.5 1.7 786.5 785.55 553.32 4017.22 NO 2900. 9.815 1 1.5 1.7 786.5 785.55 568.19 4326.19 NO3000. 9.565 1 1.5 1.7 786.5 785.55 583.04 4647.34 NO

3500. 8.786 2 2.0 2.3 640.0 607.47 493.05 458.20 NO 4000. 8.679 2 2.0 2.3 640.0 607.47 548.96 522.97 NO
MAXIMUM 1-HR CONCENTRATION AT OR BEYOND 200. M: 1075. 18.43 1 2.0 2.3 640.0 607.47 263.93 546.73 NO
DWASH= MEANS NO CALC MADE (CONC = 0.0) DWASH=NO MEANS NO BUILDING DOWNWASH USED DWASH=HS MEANS HUBER-SNYDER DOWNWASH USED DWASH=SS MEANS SCHULMAN-SCIRE DOWNWASH USED DWASH=NA MEANS DOWNWASH NOT APPLICABLE, X<3*LB

*** SUMMARY OF SCREEN MODEL RESULTS ***

CALCULATION MAX CONC 01ST TO TERRAIN PROCEDURE (UG/M**3) MAX (M) HT (M)
SIMPLE TERRAIN 18.43 1075. 0.

*******

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

*******APPENDIX D

E-MAILS FROM MR. JOHN NOTAR of the NATIONAL PARK SERVICE and MR. HENRY MADDUX, UTAH ENDANGERED SPECIES SUPERVISORE-MAIL FROM MR. JOHN NOTAR CONCERNING CLASS I AREA IMPACTS

Forwarded by Justin J Harrison/U-Houston/Exxon Mobil on 06/22/06 10:24 AM

— John_Notar@nps .gov To

justin.j.harrison@exxonmobil.com 06/21/06 04:59 cc PM Liana_Reilly@nps.gov,

John_Bunyak@nps.gov, John_Vimont@nps.gov

Subject Re: Class I Analysis for McElmo Creek PSD Permit Application
Justin: Thank you for the information on the McElmo Creek upset flare project at the Mc Elmo Creek compressor station. Based on the information provided below and on the call; given the distance to the nearest National Park Service Class I area of 61 kilometers to Mesa Verde National Park, and the total emissions of 60 TPY of S02, 13 TPY of NOx from the project, the National Park Service does not request that a Class I air quality analysis be performed due to the small amount of emissions and the distance to the nearest NPS Class I area. Please share this information with EPA Region 9, the permitting authority for this project in Utah. If you have further questions on this issue please contact Liana Reilly of the NPS Air Resources Division at (303)-987-6895. thanks you John Notar
John Notar National Park Service Air Resources Division 12795W. Alameda Pkwy. Lakewood, CO 80228 Phone: 303-969-2079 Fax: 303-9e9-2822 E-Mail: john_notar@nps.gov

justin.j.harrison~exx
onmobil.com To: John_Notar@nps.gov cc:

06/15/2006 04:55 PM Subject: Class I Analysis for McElmo Creek PSD Permit Application

EST

John,
As we discussed today, ExxonMobil submitted a PSD permit application to EPA Region IX on December 5, 2005 for the Emergency Flare located at McElmo Creek Gas Compression Facility. In their response letter dated May 22, 2006, EPA asked us to contact you to determine if additional Class I screening is necessary. The facility is located on the Navajo Nation approximately 4-5 miles northwest of Aneth, Utah, 3 miles from Utah State Road 262. It is comprised of four compressors, a dehydration unit, and an emergency flare, which is used during compressor downtime and to control dehydration still vent emissions. The current emission limits for the flare are as follows: 60 TPY S02, 73 TPY CO, 13.4 TPY NOx, and 95.4 TPY VOCs. We do notanticipate any changes to these limits.

Total emissions for 2005 were: 29.2 tons S02, 66 tons CO, 12.1 tons NOx, and 90.6 tons VOC5. During normal operations when all compressors are running, daily flare volumes are typically less than 500 kcf. Average daily flare volumes for 2005 were 2 MMCF.
Arches National Park and Canyonlands National Park are located to the northwest, approximately 160 km (100 miles) and 96 km (60 miles), respectively. Mesa Verde National Park is located approximately 60 km (38 miles) east of the gas plant site. The western boundary of the Canyon of the Ancients National Monument is approximately 16km (10 miles) northwest of the plant site.
A conservative SCREEN 3 model was submitted in the PSD application to estimate near-field impacts from the flare operating at 14.83 MMCFD for the entire year, which is 7 times greater than the average emissions in 2005. With respect to NOx and S02, this model estimated the following concentrations:
The predicted maximum annual averaged N02 concentration from the flare is 0.13 micrograms/cubic meter located 1,075 meters from the stack. The predicted maximum 3-hour, 24-hour, and annual averaged S02 concentrations from the flare are 10.47, 4.65, and 0.93 micrograms/cubic meter, respectively, located 1,097 meters from the stack.
As you indicated today, you did not feel that any additional Class I screening would be necessary based on this information. We appreciate you confirming this via e-mail as we discussed. If you need any additional information, please let me know.
Thanks.
Justin J. Harrison Exxon Mobil U.S. Production Safety & Air Compliance CORP-Ml-3038 P.O. Box 4697 Houston, TX 77210-4697 Office: 281-654-1127 Fax: 281-654-1147

### E-MAIL FROM Mr. HENRY MADDUX CONCERNING ENDANGERED SPECIES

Forwarded by Justin J Harrison/U-Houston/ExxonMobil on 06/29/06 08:48 AM Henry_Maddux©f ws.gov To

<justin.j.harrison©exxonmobil.com> 06/29/06 08:39 cc AM Subject

Flare-up Near Aneth

Dear Mr. Harrison,
I have reviewed our list of Threatened and Endangered species and critical habitat within your project area near Aneth, Utah. I have determined that the reported flare-up has no effect on listed species and their critical habitat. If you have any questions or if additional environmental impacts occur beyond those we have discussed, please contact me at (801)975-3330 xl 24. Henry R. Maddux Utah ES Field Supervisor West Valley City, UTAPPENDIX E

SCREEN3 AND VISCREEN PRINT-OUTS FOR CLASS I AREA IMPACTS~** SCREEN3 MODEL RUN ***

~ VERSION DATED 96043 ~ 08/03/06 08: 51: 00

MCELMO MAIN FLARE

- CHI/Q DISPERSION AT 50 KM., 618.104 SCF/HR, 300 BTU/SCF

SIMPLE TERRAIN INPUTS: SOURCE TYPE EMISSION RATE (G/S) FLARE STACK HEIGHT (M) TOT HEAT RLS (CAL/S) = FLARE

= 1.00000

= 59.4500

= .129887E÷08
RECEPTOR HEIGHT (M) = URBAN/RURAL OPTION = EFF RELEASE HEIGHT (M) = BUILDING HEIGHT (M) = MIN HORIZ BLDG DIM CM) = MAX HORIZ BLDG DIM CM) =
THE REGULATORY (DEFAULT) MIXING HEIGHT OPTION WAS SELECTED. THE REGULATORY (DEFAULT) ANEMOMETER HEIGHT OF 10.0 METERS WAS ENTERED.

BUOY. FLUX = 215.357 M**4/S**3; MOM. FLUX = 131.320 M**4/S**2.

FULL METEOROLOGY ***

~ SCREEN DISCRETE DISTANCES

~

TERRAIN HEIGHT OF 0. M ABOVE STACK BASE USED FOR FOLLOWING DISTANCES ***
DIST (M)

1100. 50000. 1 1.5 1.7 636.9 5 1.0 2.0 10000.0 635.95 278.55 578.29 212.67 1678.21 156.86 NO NO

* SUMEARY OF TERRAIN HEIGHTS ENTERED FOR *

* SIMPLE ELEVATED TERRAIN PROCEDURE *

********************************************

***************************************

~ SUMEARY OF SCREEN MODEL RESULTS
~

***************************************

MAX CONC DIST TO TERRAIN (UG/M**3) MAX CM) HT CM)

1100. .0000 RURAL 70. 9117 .0000 .0000 .0000

CONC (UG/M**3) STAB UXOM USTK MIX HT PLUME SIGMA SIGMA (M/S) (M/S) (M) HT (M) Y CM) Z (M) DWASH

1.2 62 .243 0
MEANS MEANS MEANS MEANS MEANS DWASH= DWASH=NO DWASH=HS DWASH=SS DWASH=NA NO CALC MADE (CONC = 0.0) NO BUILDING DOWNWASH USED HUBER-SNYDER DOWNWASH USED SCHULMAN-SC IRE DOWNWASH USED DOWNWASH NOT APPLICABLE, X<3*LB

TERRAIN HT (M)

0. 0. DISTANCE RANGE (M)

MINIMUM MAXIMUM

1100. 50000.

CALCULATION PROCEDURE

SIMPLE TERRAIN 1.262 0.

** REMEMBER TO INCLUDE BACKGROUND CONCENTRATIONS **

***************************************************Visual Effects Screening Analysis for Source: McElino Main Flare Class I Area: Mesa Verde National Park

*** User-selected Screening Scenario Results *** nput ~nissions for

Particulates NOx (as N02) Primary N02 Soot Primary S04

Primary Part. Soot Sulfate .05 G IS 1.50 G /5 .00 G IS .00 G IS .00 G IS

CHARACTERISTICS Diameter

Background Ozone: Background Visual Range: Source-Observer Distance: Mm. Source-Class I Distance: Max. Source-Class I Distance: Plume-Source-Observer Angle: Stability: 5 Wind Speed: 1.00 rn/s

Maximum Visual Impacts INSIDE Class I Area Screening Criteria ARE NOT Exceeded Delta E

Theta Azi Distance Alpha Crit Plume

10. 84. 60.0 84. 2.00 .063 140. 84. 60.0 84. 2.00 .048 10. 84. 60.0 84. 2.00 .029 140. 84. 60.0 84. 2.00 .015

Maximum Visual Impacts OUTSIDE Class I Area Screening Criteria ARE NOT Exceeded Delta E

Theta Azi Distance Alpha Crit Plume

10. 0. 1.0 169. 2.00 .692 140. 0. 1.0 169. 2.00 .419 10. 0. 1.0 169. 2.00 .597 140. 0. 1.0 169. 2.00 .396 PARTICLE Density

2.5 6 2.0 1 1.5 4 Transport Scenario Specifications:

.04 250.00 60.00 60.00 80.00 11.25 ppm kin Jan kin kin degrees

RESULTS

Asterisks (*) indicate plume impacts that exceed screening criteria

Contrast

Crit Plume

.05 .000 .05 -.000 .05 .000 .05 .000 Backgrnd
SKY SKY TERRAIN TERRAIN

Backgrnd
SKY SKY TERRAIN TERRAIN Contrast

Crit Plume

.05 —.002 .05 —.009 .05 .009 .05 .006