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 1814-04
TABLE 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 4
6.4.2 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 AREA
TABLE 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

111
1.0 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

ofthe 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

1-2
PSD Permit Application Form Page] of4

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~ ~-~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: 1991
PSD 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 day
PSD 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 offlared gas 300-443 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 ofjet streams: NA

Diameter ofjet 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 SCFH
4

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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Figure 2-1: Facility Location Map I I I miles

~ 10 15 20 The McEImo Creek Oil Production Unit,

IMMA PROJECT No.: ‘DATE DRAWN: Gas Compression Facility 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” W
The 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

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

to the Main Flare.

A flow diagram of the facility’s gathering system operations is presented in Figure 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
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Figure 2-2

Block Flow Diagram of Existing

Gathering System Operations

McEImo Creek Oil Production Unit

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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.

2-4
2.4.4 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.

2-5
3.0 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).

3-1
3.1 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.

3-2
4.0 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

4-1
basis 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 ofthe 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

4-2
Hazardous 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

4-3
list 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 ifthose 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, ifthe 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.

4-4
The 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

4-5
operation 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

4-6
zone. 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.

4-7
Of 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

4-8
BACT/LAER Clearinghouse Database Summary

Determinations 1995 —2005

Industrial Flares (RBLC Report 8/4/05)

Table 4-1. BACT Determinations for Flare VOC Emissions

Company Location Emission Throughput Pollutant Emission Limit Control Technology BA

Source (Size) Oth

Exxon Mobil Kent County, 2 Flares Not provided VOC 42.82 lb/br, each None listed — BASalt Creek Gas Plant TX 156.31 tpy, Notes flare as VOC control

combined device,with 98% efficiency

Conoco, Inc. Kay County, I Flare 0.20 lb/MMbtu — VOC 0.14 lb/MMbtu Good combustion practice BA

Ponca City Refinery OK no further detail provided

Valero Refining Co. Nueces County, Main Flare — Not provided VOC 226 lb/br None listed. Notes flare as VOC BACorpus Christi TX 2 groups of 39.6 tpy, and control device, with 98%Refinery equipment 4,013 lb/hr efficiency.

vents to flare Process notes indicate flare will be 1,544 tpy

. designed & operated per 40 CFR § (2 sets of limits) 60.18.

Duke Energy Field Webster Parish, 1 Flare Not provided VOC 2.82 lb/br None listed “othServices - Minden LA 8.73 tpy — th

minonly

Orion Refining Co. St. Charles 2 Flares 60,700,000 Btu/hr, VOC 25.4 lb/br, each None listed. Notes flare as VOC BAC

Parish, LA each 16.7 tpy each control device, with 98% control

efficiency.

Flint Hills Resources Nueces, TX Flares Not provided VOC 4,036.26 lb/hr None listed. “othLP 2,982.09 tpy,

West Refinery Both “initial” capsTrifinery Petroleum Nueces, TX 1 Flare Not provided VOC 12.74 lb/hr None listed. Notes flare as VOC “othService 55.79 tpy control device.Trigeant CorpusChristi

Citgo Refining & Nueces, TX 1 Flare (HP) 80,000 sc6’day VOC None listed “Gas- Assist” smokeless “othChemicals Co LP technologyCorpus Christi

Refinery — West

Plant
BACT/LAER Clearinghouse Database Summary

Determinations 1995 —2005

Industrial Flares (RBLC Report 8/4/05)

Company Location Emission Throughput Pollutant Emission Limit Control Technology BAC

Source (Size) Oth

Citgo Refining & Nueces, TX 1 Flare (LP) 20,000 scffday NG VOC None listed “Gas- Assist” smokeless “othChemicals Co LP technology

430,000 scf/day

Corpus Christi produced gas

Refinery — West

PlantBP Exploration Inc. AK I Flare (HP) 660,000,000 scfd VOC None Gas-assist smokeless flare “oth

Northstar technology

Development Facility

BP Exploration Inc. AK I Flare (LP) 18,022,000 scfd VOC None Gas-assist smokeless flare “oth

Northstar Natural and technology

Development Facility Produced

Gas

Mobil Exploration & Kent County, Process Not provided VOC 0.01 lb/hr None listed “otheProducing US, Inc. TX Emergency 0.01 tpySalt Creek Gas Plant Flare
Table 4-2.

BACT/LAER Clearinghouse Database Summary

Determinations 1995 — 2005

Industrial Flares (RBLC Report 8/4/05)

BACT Determinations for Flare CO Emissions

Company Location Emission Throughput Pollutant Emission Limit Control Technology BAC

Source (Size)

Exxon Mobil Kent County, 2 Flares Not provided CO 37.2 lb/br, each None listed BACSalt Creek Gas Plant TX 1 35.8 tpy, combined

Conoco, Inc. Kay County, 1 Flare 0.20 lb/MMbtu — CO 0.37 lb/MMbtu Good combustion practice BACPonca City Refinery OK no further detail provided

Valero Refining Co. Nueces County, Main Flare Not provided CO 472 lb/br None listed. BAC

Corpus Christi TX 90.5 tpyRefineryDuke Energy Field Webster Parish, 1 Flare Not provided CO 0.26 lb/br None listed “othServices - Minden ~ 1.14 tpy thi

minoonly

Orion Refining Co. St. Charles 2 Flares 60,700,000 Btu/hr, CO 149 lb/br, each None listed. BAC

Parish, LA each 98.3 tpy, each

Flint Hills Resources Nueces, TX Flares Not provided CO 901.5 lb/br None listed. “othe

LP 2,657.98 tpy,

West Refinery Both “initial” capsTrifinery Petroleum Nueces, TX 1 Flare Not provided CO 16.3 lb/br None listed. “otheService 71.36 tpyTrigeant Corpus

ChristiTesoro Alaska Co AK I Flare 1,000,000 Btu!hr CO 0.04 lb/MMBtu None listed. “otheKenai RefineryTesoro Alaska Co AK I Flare (HP) 261,000,000 scfd CO 0.37 lb/MMBtu Proper Operation & Maintenance “otheKenai RefineryTesoro Alaska Co AK 1 Flare (LP) 212,000,000 scfd CO 0.37 lbIMMBtu Proper Operation & Maintenance “otheKenai RefineryCitgo Refining & Nueces, TX 1 Flare (HP) 80,000 scflday CO None listed “Gas- Assist” smokeless “othe

Chemcals Co LP technologyCorpus Christi [
BACT/LAER Clearinghouse Database Summary

Determinations 1995 — 2005

Industrial Flares (RBLC Report 8/4/05)

Company Location Emission Throughput Pollutant Emission Limit Control Technology

Source (Size)

Refinery — West

PlantCitgo Refining & Nueces, TX I Flare (LP) 20,000 scf7day NG CO None listed “Gas- Assist” smokelessChemicals Co LP 430,000 scf/day technologyCorpus Christi produced gas

Refinery WestPlant

BP Exploration Inc. AK I Flare (HP) 660,000,000 scfd CO None Gas-assist smokeless flare

Northstar technology

Development Facility

BP Exploration Inc. AK I Flare (LP) 18,022,000 scfd CO None Gas-assist smokeless flare

Northstar technology

Development Facility

Mobil Exploration & Kent County, I Flare Not provided CO 1.1 lb/hr None listedProducing US, Inc. TX 4.8 tpySalt Creek Gas PlantEquistar Chemicals, Nueces, TX 2 Flares Not provided CO 0.05 lb/hr, each None listed.

LP 0.23 tpy, each
Table 4-3.

BACT/LAER Clearinghouse Database Summary

Determinations 1995 — 2005

Industrial Flares (RBLC Report 8/4/05)

BACT Determinations for Flare NO~ Emissions

Company Location Emission Throughput Pollutant Emission Limit Control Technology BAC

Source (Size)

Exxon Mobil Kent County, 2 Flares Not provided NOx 4.37 lb/br, each None listed BACSalt Creek Gas Plant TX 15.85 tpy, combinedConoco, Inc. Kay County, I Flare 0.20 lb/MMbtu — NOx 0.068 lb/MMbtu Limit fuel to pipeline-grade natural BACPonca City Refinery OK no further detail gas provided

Valero Refining Co. Nueces County, Main Flare Not provided NOx 75.8 lb/hr None listed. BACCorpus Christi TX 18.8 tpyRefinery

Orion Refining Co. St. Charles 2 Flares 60,700,000 Btu/hr, NOx 33.6 lb/br, each None listed. BAC

Parish, LA each 45.3 tpy, each

Flint Hills Resources Nueces, TX Flares Not provided NOx 1,409.8 lb/br None listed. “othLP 5,266.82 tpy,

West Refinery Both “initial” capsTrifinery Petroleum Nueces, TX I Flare Not provided NOx 3.2 lb/hr None listed. “otheService 14.01 tpyTrigeant Corpus

ChristiTesoro Alaska Co AK I Flare 1,000,000 Btu/br NOx 0.14 Ib/MMBtu None listed. N/A 

Kenai Refinery

Tesoro Alaska Co AK I Flare (HP) 261,000,000 scfd NOx 0.068 lb/MMBtu Proper Operation & Maintenance “otheKenai RefineryTesoro Alaska Co AK 1 Flare (LP) 212,000,000 scfd NOx 0.068 lb/MMBtu Proper Operation & Maintenance “otheKenai Refinery

Conoco, Inc. Calcasieu 1 Flare Not provided NOx 1.2 lb/hr Operate in accordance with BAC

Lake Charles Parish, LA 5.0 tpy 40 CFR § 60.18 General ControlRefinery Device Requirements

Mobil Exploration & Kent County, I Flare Not provided NOx 0.08 lb/hr None listed “otheProducing US, Inc. TX 0.4 tpySalt Creek Gas Plant
BACT/LAER Clearinghouse Database Summary

Determinations 1995 —2005

Industrial Flares (RBLC Report 8/4/05)

Company Location Emission Throughput Pollutant Emission Limit Control Technology BAC

Source (Size)

Equistar Chemicals, Nueces, TX 2 Flares Not provided NOx 0.01 lb/hr None listed. “oth

LP

0.04 tpy
Q 

BACT/LAER Clearinghouse Database Summary

Determinations 1995 —2005

Industrial Flares (RBLC Report 8/4/05)

Table 4-4. BACT Determinations for Flare SO2 Emissions

Company — Location Emission Throughput Pollutant Emission Limit Control Technology BAC

Source (Size)

Exxon Mobil Kent County, 2 Flares Not provided SO2 50.48 lb/br, each None listed “othSalt Creek Gas Plant TX 184.24 tpy,

combined

Conoco, Inc. Kay County, 1 Flare 0.20 lb/~tMbtu — SO2 0.0006 lb/MMbtu Limit fuel to pipeline-grade natural BAC

Ponca City Refinery OK no further detail gas provided

Valero Refining Co. Nueces County, Main Flare Not provided SO2 51.1 lb/hr None listed. BACCorpus Christi TX 12 tpyRefinery

Orion Refining Co. St. Charles 2 Flares 60,700,000 Btu/hr, SO2 133 lb/br, each None listed. BAC

Parish, LA each 87.6 tpy, each

BP Exploration AK 1 Flare Max rate SO2 500 ppm, 3-hr Bum fuel oil with no greater than SIP (Alaska) Inc. 83,000,000 scfd average 0.3 wt% sulfur, andMilne Point Nominal rate Bum natural gas with no greaterProduction Facility 340,000 scfd than 100 ppmvd H2S

Flint Hills Resources Nueces, TX Flares Not provided SO2 962.12 lb/br None listed. BAC

LP 118.76tpy,

West Refinery Both “initial” capsTrifinery Petroleum Nueces, TX 1 Flare Not provided SO2 71.48 lb/br Continuous ignition with two BACService 263.31 tpy pilots, UV fire-eye flame monitor,Trigeant Corpus KO pot & seal druml; 98% controlChristi efficiencyTesoro Alaska Co AK 1 Flare 1,000,000 Btu/hr SO2 500 ppm, 3-hr Fuel sulfur content limits: BACKenai Refinery average 0.35% sulfur in diesel,

0.01% sulfur in natural gas,0.01% sulfur in LPG, and

168 ppmv H2S in refinery gas
BACT/LAER Clearinghouse Database Summary

Determinations 1995 — 2005

Industrial Flares (RBLC Report 8/4/05)

Company Location Emission Throughput Pollutant Emission Limit Control Technology BAC

Source (Size)

Tesoro Alaska Co AK I Flare (HP) 261,000,000 scfd SO2 None listed Fuel sulfur content limits: BACKenai Refinery 0.15% sulfur in distillate, and

200 ppm I-12S in fuel gas

Tesoro Alaska Co AK I Flare (LP) 212,000,000 scfd SO2 None listed Fuel sulfur content limits: “oth

Kenai Refinery 0.15% sulfur in distillate, and

200 ppm H2S in fuel gas

Citgo Refining & Nueces, TX I Flare (HP) 80,000 scf7day SO2 500 ppm, 3-hr H2S content limited to 50 ppmv “othChemicals Co LP averageCorpus ChristiRefinery — WestPlant

Citgo Refining & Nueces, TX 1 Flare (LP) 20,000 scf7day NG SO2 500 ppm, 3-hr Fuel sulfur content limits: “othChemicals Co LP 430,000 scf/day average 0.15% sulfur in fuel oil, andCorpus Christi produced gas 50 ppmv H2S in fuel gasRefinery — West

PlantBP Exploration Inc. AK I Flare (HP) 660,000,000 scfd SO2 500 ppm, 3-hr H2S content of the fuel shall not “othe

Northstar average exceed 50 ppmv

Development Facility

BP Exploration Inc. AK 1 Flare (LP) 18,022,000 scfd SO2 500 ppm, 3-hr H2S content of the fuel shall not “othe

Northstar average exceed 50 ppmvm, and

Development Facility Sulfur content of fuel oil shall not

exceed 0.15 wt%

Conoco, Inc. Calcasieu 1 Flare Not provided SO2 0.3 lb/hr None listed “othe

Lake Charles Parish, LA 1.1 tpyRefineryMobil Exploration & Kent County, I Flare Not provided SO2 39.74 lb/hr None listed “otheProducing US, Inc. TX 174.1 tpy Fuel limited to pipeline qualitySalt Creek Gas Plant sweet natural gas with no more

than 5 grains sulfur/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

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

approximately 85 °F. Additionally, the discharge pressure is above the critical pressure of the

gas. Therefore, the process stream actually leaves the compressor and can simultaneously have

the properties of a liquid and a gas. It is when the gas behaves as a liquid that compressor

damage can occur. This mixed gas stream allows for the potential of liquid drop-out throughout

the compression process.

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

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

4-10
Change 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, ifthe 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.

4-11
TABLE 4-5a

McElmo Gas Compression Facility

Change HOS-6 Compressor Process

Capital Cost Analysis

2. Installation Costs:

A) Foundation & Supports

B) Erection and Handling

C) ElectricalD) Piping

E) InsulationF) Painting

St Site Preoaration

Total Installation Costs (TINC):

3% of TEC14% of TECt% of TEC5% of TEC≥% of TEC

1% of TEC

3% of TEC

$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$447,120

Item EPA Cost Control Manuaf~ ExiconMobil Assumptions ExxonMobll ¶~IRECT CAPITAL COSTS1. Purchased Equipment:

A) Process Changes Base Cost $12,000,000 $12,000,000

In the EM estimate, 15% is the fa

B) Instrumentation & Controls 10% of Base Cost $1,200,000 $1,800,000 based on ExxonMobil experienc

basis. The EPA cost cost contrrange from 5% to 30%.

C) Freight & Taxes 4% Taxes; 4’~’~ $1,056,000 $1,104,000 reight on IA & I B

Total Purchased Equipment Costs (TEC): SumoflA, lB and $14,256,000 $14,904,000 1C1. Engineering & Supervision 15% of TEC $2,138,400 $2,235,600

2. Construction and Field Expenses 5% of TEC $712,800 $745,2003. ContractorFees 10%ofTEC $1,425,600 $1,490,400

4. Start-up 2% of TEC $285,120 $447,120 In the EM estimate, 3% is the fac

on ExxonMobil experience inste

5. Performance Testing 2% of TEC $285,120 $447,120 In the EM estimate, 3% is the fac

based on ExxonMobil experienc

6. Government Permitting & Fees 1%ofTEC $149,040 In the EM estimate, 1% is added 

and Fees based on ExxonMobil 

Total Direct Capital Costs (TDCC):

INDIRECT CAPITAL COSTS

Sum of TEC and

TINC

$5,274,720

$19,530,720

$5,514,480

$20,418,480
TABLE 4-5a

McEImo Gas Compression Facility

Change HOS-6 Compressor Process

Capital Cost Analysis

Total Direct & Indirect Capital Costs (TDICC):

Owners Cost

Sum of TDCC andrIcc $24,377,760 $25,932,960

$3,111,955

Item EPA C~St C~ñtiOI Mãi~àI IE onMobll Assumptions Exxo Mobil 

Sum of 1, 2, 3, 4 Total Indirect Capital Costs (TICC): and 5 $4,847,040 $5,514,480

In the EM estimate, 30% is the fbased on ExxonMobil experienc

Contingency 20% of TDICC $4,875,552 $7,779,888 basis. The EPA cost control ma

cost estimate (a “study estimat

In the EM estimate, 12% is addeExxonMobil experience to coverequired to oversee the design, 

commissioning contractors.

TOTAL.CAPITAL COSTS (TCC): S~~T’~C and $29,253,312 $36,824,803 Contingency
0

TABLE 4-5b

McElmo Gas Compression Facility

Change HOS-6 Compressor Process

Operating Cost Analysis

1. Overhead

Total Indirect Operating Costs (TIOC):

Item EPA Cost Control Manual ExxonMobll Assumptions ExxonMDIRECT OPERATING COSTS1. Operating Labor ~ $43,800 $43,800

2. Supervisory Labor 15% of Operating Labor $6,570 $6,570

In the EM estimate, 3% 

3. Maintenance Labor& Materials 2% of TCC $585,066 $1,104,744 Maintenance Labor & 

experience instead of 

Total Direct Operating Costs (TDOC): Sum of 1 -9 $635,436 $1,155,114

INDIRECT OPERATING COSTS

1. Property Tax 1% of TCC $292,533 $368,248

2. Insurance 1% of TCC $292,533 $368,2483. General Administrative 2% of TCC $585,066 $736,4964. Capital Recovery Factor ~Fr~ 0.1061 [10% @ $3,103,776 $3,907,112Total Capital Charges Costs (TCCC): ISum of 1,2,3 and 4 $4,273,909 $5,380,104 I

60% of Total Labor ÷Maintenance

CAPITAL CHARGES COSTS

$381,262$381,262

$693,068

$693,068

TOTAL ANNUALIZED OPERATING COSTS Sum of TDO2 hOC and $5,290,607 ~ $7,228,286

75% control of annual SO2 emissions (.75 x 60.0 tpy) = 45.0 $117,569 per ton of SO2 removal

75% control of annual CO emissions (.75 x 73.0 tpy) = 54.8 $96,632 per ton of CO removal75% control of annual NOx emissions (.75 x 13.4 tpy) = 10.1 $526,429 per ton of NO~ removal75% control of annual VOC emissions (.75 x 95.4 tpy) = 71.6 $73,943 per ton of VOC removal
TABLE 4-6a

McEImo Gas Compression Facility

Replace HOS-6 Compressor

Capital Cost Analysis

2. Installation Costs:

A) Foundation & Supports

B) Erection and Handling

C) ElectricalD) PipingE) InsulationF) Painting

G~ Site Precaration

Total Installation Costs (TINC):

3% of TEC14% of TECt% of TEC5% of TEC2% of TEC1% of TEC3% of TEC

$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

$372,600

Item EPA Cost Co trol Manual ExxonMobll Assumptions ExxonMobll DIRECT CAPITAL COSTS1. Purchased Equipment:

A) Process Changes Base Cost $10,000,000 $10,000,000

In the EM estimate, 15% is the fa

B) Instrumentation & Controls 10% of Base Cost $1,000,000 $1,500,000 based on ExxonMobil experienc

basis. The EPA cost cost contrrange from 5% to 30%.

C) Freight & Taxes 4% Taxes: 4’~~ $880,000 $920,000 r~reiaht on 1A & lB

Total Purchased Equipment Costs (TEC): SumoflA, lB and $11,880,000 $12,420,000 101. Engineering & Supervision 15% of TEC $1,782,000 $1,863,000

2. Construction and Field Expenses 5%ofTEC $594,000 $621,0003. Contractor Fees 10% of TEC $1,188,000 $1,242,000

4. Start-up 2% of TEC $237,600 $372,600 In the EM estimate, 3% is the fac

on ExxonMobil experience inste

5. Performance Testing 2%ofTEC $237,600 $372,600 In the EM estimate, 3% is the fac

based on ExxonMobil experienc

6. Government Permitting & Fees 1%ofTEC $124,200 In the EM estimate, 1% is added 

and Fees based on ExxonMobil 

Total Direct Capital Costs (TDCC):

INDIRECT CAPITAL COSTS

Sum of TEC and

TINC

$4,395,600

$16,275,600

$4,595,400

$17,015,400
TABLE 4-6a

McElmo Gas Compression Facility

Replace HOS-6 Compressor

Capital Cost Analysis

Total Direct & Indirect Capital Costs (TDICC):Owners Cost

Sum of TDCC and

TIflfl $20,314,800 $21,610,800

$2,593,296

Item EPA Cost Control Manual ExxonMobll Assumptions ExxonMobll 

Sum of 1,2,3,4 Total Indirect Capital Costs (TICC): and 5 $4,039,200 $4,595,400

In the EM estimate, 30% is the f

based on ExxonMobil experienc

Contingency 20% of TDICC $4,062,960 $6,483,240 basis. The EPA cost control ma

cost estimate (a “study estimate

In the EM estimate, 12% is addeExxonMobil experience to coverequired to oversee the design, 

commissioning contractors.

Sum of TDICC andContingenôy TO1~AL CAPITAL COSTS (TCC): $24,377,760 $30,687,336
INDIRECT OPERATING COSTS

1. OverheadTotal Indirect Operating Costs (TIOC):CAPITAL (~IJADK~Q COSTS

TOTAL ANNUALIZED OPERATING cosis75% control of annual SO2 emissions (.75 x 60.0 tpy) =75% control of annual CO emissions (.75 x 73.0 tpy) =75% control of annual NOx emissions (.75 x 13.4 tpy) =75% control of annual VOC emissions (.75 x 95.4 tpy) =

TABLE 4-6b

McEImo Gas Compression Facility

Replace HOS-6 Compressor

Operating Cost Analysis

60% of Total Labor +

Maintenance

Item . . ‘ EPA Cost Control Manual . ExxonMobllAssumptlons . ExxonM

DIRECT OPERATING COSTS

2 hr/shift @ $20/hr, ~ $43,800 $43,800 1. Operating Labor shifts/day. 365 days/yr

2. Supervisory Labor 15% of Operating Labor $6,570 $6,570

In the EM estimate, 3% 

3. Maintenance Labor& Materials 2% of TCC $487,555 $920,620 Maintenance Labor & 

experience instead of 

Total Direct Operating Costs (TDOC): Sum of 1 -9 $537,925 $970,990

1. Property Tax 1% of TCC $243,778 $306,873

2. Insurance 1% of TCC $243,778 $306,8733. General Administrative 2% of TCC $487,555 $613,747

CRF = 0.1061 [10% @ $2,586,480 $3,255,926 4. Capital Recovery Factor 30 yr.]

Total Capital Charges Costs (TCCC): Isum of 1,2, 3 and 4 $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 $98,273 per ton of SO2 removal

54.8 $80,772 per ton of CO removal

10.1 $440,027 per ton of NO~ removal

71.6 $61,807 per ton of VOC removal
4.2.3 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.

4-12
4.3 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

4-13
that 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.

4-14
TABLE 4-7a

McElmo Gas Compression Facility

Flare Gas Recovery System

Capital Cost Analysis

$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

$19,227,402

0

2. Installation Costs:

A) Foundation & Supports

B) Erection and Handling

C) ElectricalD) PipingE) Insulation

8% of TEC

F) Painting

14% of TEC

4% of TEC

G~ Site Preoaration

5% of TEC

rotal Installation Costs (TINC):

2% of TEC

1% of TEC

rotal Direct Capital Costs (TDCC):

3% of TEC

Item EPA Cost Control Manual ExxonMo II Assumptions ExxonMobll ‘)IRECT CAPITAL COSTS1. Purchased Equipment:

A) Equipment BaseCost $11,300,000 $11,300,000

In the EM estimate, 15% is the f

B) Instrumentation & Controls 10% of Base Cost $1,130,000 $1,695,000 based on ExxonMobil experienc

basis. The EPA cost cost contrrange from 5% to 30%.

C) Freight & Taxes 4% Taxes: ~ $994,400 $1,039,600 ~reiahton 1A& 15

Total Purchased Equipment Costs (TEC): ~um of 1A, lB and $13,424,400 $14,034,600 1C

1. Engineering & Supervision 15% of TEC $2,013,660 $2,105,190

2. Construction and Field Expenses 5% of TEC $671,220 $701,7303. Contractor Fees 10% of TEC $1,342,440 $1,403,460

4. Start-up 2% of TEC $268,488 $421,038 In the EM estimate, 3% is the fa

on ExxonMobil experience inste

5. Performance Testing 2% of TEC $268,488 $421,038 In the EM estimate, 3% is the fa

based on ExxonMobil experienc

6. Government Permitting & Fees 1%ofTEC $140,346 In the EM estimate, 1% is added 

and Fees based on ExxonMobil 

INDIRECT CAPITAL COSTS

Sum of TEC andTINC
TABLE 4-7a

McEImo Gas Compression Facility

Flare Gas Recovery System

Capital Cost Analysis

$22,955,724 $24,420,204

$2,930,424

Total Direct & Indirect Capital Costs (TDICC):

Owners Cost

Sum of TDCC andTICc

Item EPA Cost Control Manual ExxonMobll Assumptions ExxonMobll 

Sum of 1, 2. 3. 4 Total Indirect Capital Costs (TICC): and5 $4,564,296 $5,192,802

. In the EM estimate, 30% is the fa

based on ExxonMobil experienc

Contingency 20% of TDICC $4,591,145 $7,326,061 basis. The EPA cost control ma

cost estimate (a “study estimate

In the EM estimate, 12% is addeExxonMobil experience to cove

required to oversee the design, commissioning contractors.

TOTAL cApn~AL COStS (TCC): Sum of TDlC~~d $27,546,869 s34;676,69o Cofltflgeflcy
TABLE 4-7b

McElmo Gas Compression Facility

Flare Gas Recovery System

Operating Cost Analysis

$654,402$654,402

$6;81i,337~,

per ton of SO2 removal

per ton of CO removal

per ton of NO~ removal

per ton of VOC removal

1. OverheadTotal Indirect Operating Costs (TIOC):

60% of Total Labor +Maintenance

Item - - -. .• EPA CostControl Manual’ - ExxonMobil Assumptions Exxon

‘DIRECT OPERATING COSTS

2 hr/shift @ $20/hr, ~ $43,800 $43,800 1. Operating Labor shifts/day, 365 days/yr

2. Supervisory Labor 15% of Operating Labor $6,570 $6,570

In the EM estimate, 3% 

3. Maintenance Labor& Materials 2% of TCC $550,937 $1,040,301 Maintenance Labor & 

experience instead of 

Total Direct Operating Costs (TDOC): Sum of 1 -9 $601,307 $1,090,671

INDIRECT OPERATING COSTS1. Property Tax 1% of TCC $275,469 $346,767

2. Insurance 1% of TCC $275,469 $346,7673. General Administrative 2% of TCC $550,937 $693,534

CRF = 0.1061 [10% @ $2,922,723 $3,679,197 4. Capital Recovery Factor 30 yr.]

Total Capital Charges Costs (TCCC): Isum of 1,2,3 and 4 $4,024,598 $5,066,264

CAPITAL ~

$360,784

$360,784

TOTAL ANNUALIZED OPERATING COSTS Sum of TDOC TlOC~ p986 68975% control of annual SO2 emissions (.75 x 60.0 tpy) = 45.0 $110,81575% control of annual CO emissions (.75 x 73.0 tpy) = 54.8 $91,08175% control of annual NOx emissions (.75 x 13.4 tpy) 10.1 $496,188

75% control of annual VOC emissions (.75 x 95.4 tpy) = 71.6 $69,695
5.0 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.

5-1
Table 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

5-2
International 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

5-3
Table 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 => 41
Wind Speed White Mesa Mill - Bianding, Utah Direction (blowing from)

—— I

— — — — — I — — — —

—— I

—— I -..‘

- I 2O%~

- -I- -

16%~

S

/ S S

/ /

/ / 12%~

S S

/ — S S S --1--- S S

/ / S S

/ 5 5 I

/ 5 I I

I I I I I

I -l • .___L . I I WEST I I EAST

I I / I

I I I

/ I

S — / / I I

/ / I

S S / I I

/ / / S S / /

‘ ‘ S / /

‘ ‘ / /

S / / I

‘ ‘ / /

S / /

S /

S /

S I /

S I /

S — — /

WIND SPEED

5’ II (mis)

I — >=11.1

I 8.8-11.1

I — 5.7-8.8

— I SOUTH —— —— 3.6- 5.7

2.1 - 3.6

0.5- 2.1

Calms: 0.15%

COMMENTS DATA PERIOD: COMPANY:

2004 international Uranium Corporation

Jan 1 - Dec 31

00:00 - 23:00 PREPARED BY

McVehil-Monnett

Associates

CALM WINDS TOTAL COUNT FIG U RE 5—1

0.15% 8456 hrs.

AVG. WINDSPEED DATE: PROJECT NO

3.43 mIs 111 9(2005 1721-03

WRPLOT View - Lakes Environmental Software
5.4 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.

5-4
6.0 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 ofthe 4th highest daily maximum concentrations must not exceed this standard.

6-1
6.1 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.

6-2
6.2 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

6-3
for 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.

6-4
6.4.2 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:

6-5
rate = 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

6-6
21St 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

6-7
occur. 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.

6-8
7.0 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 ofproviding 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.

7-2
7.1.2 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.

7-3
7.2.1 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.

7-4
Table 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

7-5
the 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,

7-6
averaging 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.

7-7
Based 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.

7-8
8.0 REFERENCES

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

Consent Decree, United States ofAmerica 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 ofAir Pollution Emissions Factors,

5th Edition, AP 42, Office ofAir 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.

8-1
APPENDIX 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

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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 ofAmerica

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

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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.

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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 ofMain 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

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

1 WHEREAS, concurrent with the Lodging ofthis Consent Decree, Plaintiff United States

2 ofAmerica, 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)ofthe 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 ofthe commencement ofthis action has been given to the

22 Utah Department ofEnvironmental Quality and the Navajo Nation Environmental Protection

23 Agency in accordance with Section 113(b) ofthe 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

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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 ofEPA.

2 3. IfMobil 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) ofthis 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 ofthe obligations ofMobil

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 ofFederal 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 ofoil 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

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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 ofthe Consent Decree by the

12 Clerk of the United States District Court for the District ofUtah.

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 of40 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 ofthe terms and conditions

26 included in Paragraphs 9.a., 10, 11, and 25(i) through (ix) ofthis Consent Decree, with the

27

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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 iffive-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 ofwhich 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 ofthe 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 ofthe

4 Facility’s compressors are not Malfunctions.

5 w. “NO~” shall mean oxides of nitrogen.

6 x. “Paragraph” shall mean a portion ofthis 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 ofthe 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 ofthis 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.

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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 ofAmerica, 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 ofthe 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 ofthe receipt ofthe Electronic

14 Fund Transfer procedures described in Paragraph 7 below, Mobil shall pay to the United States a

15 civil penalty in the amount ofTHREE HUNDRED FIFTY THOUSAND DOLLARS ($350,000),

16 plus interest at 1.29 percent per year from the date ofAugust 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 ofpayment 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 ofthe transferring bank; (iii) the civil

26 action case name and case number; (iv) USAO File Number 2003V00248; (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 ofthe

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 ofthis 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 ofVOC. Field Flares

12 shall not be used to circumvent the emission limits of this Paragraph.

13 b. The provisions of Section VIII ofthis 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 ofMobil, 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 ofthe 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 ofthe 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 ofinadequate design, operation, or maintenance ifthe 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 ofa Malflmction);

23 (11) Ifthe emissions in question are associated with a Flaring Incident, Mobil

24 complied with all ofthe applicable requirements of Paragraphs 12 and 13

25 ofthis 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) ifthe emissions in question are associated with a Flaring Incident,

2 Mobil complied with the notification and reporting requirements of

3 Paragraphs 12 and 25 ofthis Consent Decree;

4 (b) ifthe 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. IfMobil 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 ofthis daily average as substitute data neither relieves nor excuses Mobil from complying

26 with the sampling, data collection, and monitoring requirements ofthis 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 ofthe 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 ofthe 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 ofthis Consent Decree. Mobil’s failure to comply with any requirement ofthe

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 Chiefofthe Air

10 Enforcement Office, Air Division ofEPA 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) ofthis 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, ifany, 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 ofthat 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. IfMobil

13 concludes that corrective action(s) is (are) required under Paragraph 13, the report shall include a

14 description ofthe action(s) and, ifnot already completed, a schedule for its (their)

15 implementation, including proposed commencement and completion dates. IfMobil 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 ofthe causes and/or possible corrective

19 actions still are under way on the due date ofthe report, a statement of the anticipated date by

20 which a follow-up report fully conforming to the requirements ofParagraph 12.d and 12.e will be

21 submitted; provided, however, that ifMobil has not submitted a report or a series ofreports

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) ofthis

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 oftime

4 under this Paragraph 12.f.

5 g. To the extent that completion ofthe implementation of corrective

6 action(s), if any, is not fmalized at the time ofthe 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 ofimplementation.

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. IfEPA does not notify Mobil in writing within sixty (60) days ofreceipt 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 ofthe corrective action plan shall

19 become incorporated into this Consent Decree, and Mobil’s failure to comply with any

20 requirement ofthe EPA-approved corrective action plan shall constitute a violation ofthis

21 Consent Decree subject to stipulated penalties.

22 b. EPA does not, however, by its agreement to the entry ofthis 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. IfEPA 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 ofthat fact within sixty (60) days

4 following receipt of the report(s) required by Paragraph 12 above. IfEPA 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 ofthis Consent Decree.

8 d. Nothing in this Section V (Compliance Measures) shall be construed as a

9 waiver ofEPA’s rights under the Act for future violations ofthe 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 ofthe 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 ofthe 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 ofthe 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 ofthe Act and 40 C.F.R. Part 71.

6 Vi. SUPPLEMENTAL ENVIRONMENTAL PROJECT

7 15. In partial satisfaction ofPlaintiff’s claims, Mobil shall implement a SEP to

8 support public health for the local residents in the vicinity ofAneth, 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 ofthis 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 ofMobil’s knowledge, a reasonable and good faith

24 estimate ofthe cost of the SEP is $99,849;

25 b. That, as ofthe 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 ofthe 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 ofthis Consent Decree; and

18 (5) A description ofthe 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 ifthe SEP has not been satisfactorily completed, stipulated penalties

2 may be assessed under Section VIII (Stipulated Penalties) ofthis Consent Decree. Disputes

3 concerning the satisfactory completion ofthe 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 ofthe

6 SEP shall not be deductible for purposes of calculating federal and state taxes. Mobil, at the time

7 of completion ofthe 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 ofthe 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 behalfofthe 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 ofrolling 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 ofthis 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 ofVOC.

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) ofthis Consent Decree

4 and bearing the certification language set forth in Paragraph 42 ofthis Consent Decree, a

5 quarterly report that includes: (i) a list ofthe 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 ofthis 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 ofthis 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 ofthe

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 ofthe 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 oftotal 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 ofthis 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 ofthis 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 ofthe 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 ofthe emission limits in

Paragraph 9 ofthis 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 ofNoncompliance from Effective Penalty per Day per Violation

Date to Termination ofthe 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 ofthe specific requirements

in Paragraphs 11 through 13 ofthis 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 ofthis 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) IfMobil’s total Eligible SEP Costs are less than $99,849 in connection

with the performance ofthe SEP specified in Appendix D of this Consent Decree, or ifthe SEP

has not been satisfactorily completed, Mobil shall be liable for stipulated penaLties, as set forth

below. IfMobil 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) Ifthe 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 ifMobil 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. IfMobil does not provide

the certification and documentation required by this subparagraph, or ifthe 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 ifMobil complies with the specific

obligations set forth in Paragraphs 15, 17 through 19, and 21 through 23.

(e) IfMobil 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 ofNoncompliance 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 ofSection 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 ofthis 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 ofthe noncompliance or completion ofthe 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 ofwhether

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 2003V00248, and shall be delivered by certified mail with return receipt

15 requested to:

16 United States Attorney, District ofUtah

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 ofpayment to EPA and

20 DOJ, directed to the addresses provided in Section XII (Notification). The notice ofpayment

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 ofEPA’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 ofthis Consent Decree shall not

7 preclude the United States from seeking additional monetary penalties or other relieffor 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 orjudicially, and outside

10 the provisions ofthis Consent Decree. Where a violation ofthis 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 ofthis 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 ofthis 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 ofthe 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 Chiefof the Air Enforcement Office, Air

14 Division ofEPA 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) ofthis Consent Decree, made within seven (7) working days ofMobil’s knowledge

17 ofthe 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 ofMobil; (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 ofthe

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 ofits

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 IfMobil disagrees with EPA’s force majeure determination, then Mobil may initiate

5 the dispute resolution procedures of Section XI (Dispute Resolution) ofthis 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 ofthe Consent Decree under Paragraph 53, Mobil shall send a written notice to EPA

11 and DOJ outlining the nature ofthe 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. Ifthe informal negotiations are unsuccessful, then the determination ofEPA 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) ofthis 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 ofthis 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 ofthe Consent Decree, and shall cite the case name ofUnited 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 ofMobil 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 ofthe Parties to this Consent Decree that neither the terms and conditions ofthis Consent

20 Decree nor any act ofperformance by Defendant shall be (i) admissible in any proceeding for the

21 purpose of imputing, implying, or otherwise raising an inference ofwrongdoing 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 ofthe United States against Defendant for the violations specifically

26 alleged in the Complaint filed in this action, up to the Date of Lodging ofthe 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 ofthe 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 ofthe Plaintiffor

15 Defendant against any third parties (parties not specifically part ofthis 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 ofthe 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 ofthis 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) ofthis 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 ofthis 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 oftermination) 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. IfEPA fails to provide written response within sixty (60) days after receiving written

18 notice from Mobil or ifEPA 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 ofthis 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 29
Case 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 ofdisputes by this Court) for the purposes of implementing and enforcing the terms

4 and conditions ofthis Consent Decree.

5 57. Public Comment. Mobil agrees and acknowledges that fInal approval ofthis

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 ofthe Lodging ofthis 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 ofthe 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 ofFederal 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 SWENT

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 31
Case 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

I

Dated: ~‘(p 0 ~ ~.

THOM~

R~CMM’V

V. SKINNER

~1,—

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 ofRegional 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: v/I ~ /J6-/~s800 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 33
APPENDIX 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 ofAP-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 ofVOCs 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 ofAP-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 ofAP-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 1.3
08/08/00 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.
-EXXON MOOU

S.q,le-MCU !NIPLTOp~e8of- Gay Moukaa -Chit OfOmccTtc6igdaii

S~,çbJib: CQM. Inc. MCI3 INJECTION PLANT. 6-6-03. D~M3ilc,. Low Pii~&

~: ~ ~ t~. Li~,Lb’ %I: 1~ A~

57 6,483 14.452 0.088 160.001 157.217 137.236

4 4.685 8.811 0.063 108.085 306204 106214

6 4.364 6.413 0066 108.788 106.894 106.905

6 0.860 I.031 0.012 18.860 lS.332 18.533

1 2.480 2.839 0.033 54.377 53.627 53.630

3 0.803 0.860 0.011 17.456 17.132 17.153

2 0.932. 1.009 0.013 20.741 20.380 20.381

8 0.359 0.361 0.005 7.762 7.627 7.628

1 0.1.31 0.128 0.002 2.828 2.779 2.779

4 0.051 0.048 0. I 1.091 1.072. 1.012

0 0.017 0.015 0.000 0.354 0348 0.348

8 0.007 0006 0.000 0.140 0.137 0.137

7 0.073 0.051 0.001 1.414 1.389 1289

8 0.065 0.050 0.001 1.245 1.223 1.223

7 0.010 0.008 0.000 0.182 0.189 0.189

2 0.008 0.004 0.000 0.134 0.112 0.112

39 76.692 62.667 1.036 0.000 0.000 0.000

0 0.000 0.000 0.000 0.000 0.000 0.000

0.000 0.000 0.000 0.000 0.000 0.000

6 I. 1.197 0.020 0.000 0.000 0.000

0 0.0(0 0.055 0.000 0.000 0.000 0.000

100.010 100000 1.350 503.649494.883 140.837
07/20/2008 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 MCUJNJECTIONPLANT 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 — 0.9945
07/20/2008 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: 7f26105

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

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

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 i
07/20/2008 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 1008
07/20/2006 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*ITINLET 400

RESULTS: PPM HYDROGEN SULFIDE

ANALYSIS PERPORMEI5 USiNG SENSE)YNFI(3ASTEC I)ETBCTION TUBES.
~~

________ Osla Fb

•~ -‘~!J~..~i*~

~

~.. i’1.~:— - PkI% Wt% UqVol% 8PG~~ GOTUCE

17.0741 7.062 15A90 0.~86 iiaeoi

6.5418 5.071 9505 0.958 116.0304.8207 5.480 7.111 0.073 121.5780.5180 0.027 1.004 9012 20.172

1.7305 2.503 2.921 0.035 00.590

0.4105 0.704 0.694 0.010 16.404

0.0243 1.161 1.2W 0.01 25.0620.1263 0.201 0.278 0.004 6.8200.0346 0.080 0.008 0.001 1 8070.0115 0.034 0.031 0.000 0.7190.0058 0.012 0.011 0.000 0254

0.0018 0.006 0.006 0090 0.1370.6258 0.056 0.043 0.001 1.0750.0192 0.046 0.034 0.091 0550

0.0026 0.007 0.005 0.000 0.134

0.0016 0.005 0.003 0.000 0056

00.4455 75.365 80520 1 010 0000

0.0000

~ 0~P00

0.0000 0.000 0.000 0.. 0000

1.3011

~ 0.81$

0.1126 0.012 0.06? 0.000 0.000

100.0000 100.000 100.006 1.339 530.084

99.494

1.339

s530.503530.615

30.790

0080

0Thi~: ;r..’r~:~j~~

~

P.O. ~b.

81013145.0

GSrUd(CF ~11~CE

169.633 169.856

114.031

110.482 119.475

19.821 19.821

55.003 55.605

16.177 16.178

24.846 24.847

5.915 5.815

1.474 ~S74

0.706 0.706

0.250 0.2500.195 0.135

1.050 1.060

0.844 0.844

0.131 0.131

0.005 0.OBS0.000 0.000

0.000 110000.000 0000

0.000 0.0000.000 0.000

164.092
07/20/2006 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%

~10/10/05
07/20/2006 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... 11/9/05
07/20/2006 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... 12/12/05
07120/2006 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 RESULTS
SCREEN3 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 NO
3000. .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 NO
3000. 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 NO
3000. 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 NO
3000. 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 NO
3000. 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 NO
3000. 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 SUPERVISOR
E-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 not
anticipate 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, UT
APPENDIX 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