DAQ-2025-001448

DAQE-AN102090014-25

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Erin Dunman
Kinder Morgan Altamont LLC
1001 Louisiana Street, Suite 1000
Houston, TX 77002
[e-mail]

Dear Ms. Dunman:

Re: Approval Order: Administrative Amendment to Approval Order DAQE-AN102090008-15 to
Update Equipment and Emissions
Project Number: N102090014

The attached Approval Order (AO) is issued pursuant to the Notice of Intent (NOI) received on August
26, 2024. Kinder Morgan Altamont LLC must comply with the requirements of this AO, all applicable
state requirements (R307), and Federal Standards.

The project engineer for this action is Tad Anderson, who can be contacted at [phone] or
[e-mail]. Future correspondence on this AO should include the engineer's name as well as
the DAQE number shown on the upper right-hand corner of this letter.

Sincerely,

{{$s }}

Bryce C. Bird
Director

BCB:TA:jg

cc: TriCounty Health Department
EPA Region 8

195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
State of Utah

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Tim Davis
Interim Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

March 6, 2025

STATE OF UTAH
Department of Environmental Quality
Division of Air Quality

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APPROVAL ORDER
DAQE-AN102090014-25
Administrative Amendment to Approval Order
DAQE-AN102090008-15 to Update Equipment
and Emissions

Prepared By
Tad Anderson, Engineer
[phone]
[e-mail]

Issued to
Kinder Morgan Altamont LLC - Altamont East Compressor Station

Issued On
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Issued By

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Bryce C. Bird
Director
Division of Air Quality

March 6, 2025
TABLE OF CONTENTS

TITLE/SIGNATURE PAGE ....................................................................................................... 1
GENERAL INFORMATION ...................................................................................................... 3
CONTACT/LOCATION INFORMATION ............................................................................... 3
SOURCE INFORMATION ........................................................................................................ 3
General Description ................................................................................................................ 3
NSR Classification .................................................................................................................. 3
Source Classification .............................................................................................................. 3
Applicable Federal Standards ................................................................................................. 3
Project Description.................................................................................................................. 4
SUMMARY OF EMISSIONS .................................................................................................... 4
SECTION I: GENERAL PROVISIONS .................................................................................... 5
SECTION II: PERMITTED EQUIPMENT .............................................................................. 6
SECTION II: SPECIAL PROVISIONS ..................................................................................... 7
PERMIT HISTORY ................................................................................................................... 13
ACRONYMS ............................................................................................................................... 14

DAQE-AN102090014-25
Page 3

GENERAL INFORMATION

CONTACT/LOCATION INFORMATION

Owner Name Source Name
Kinder Morgan Altamont LLC Kinder Morgan Altamont LLC - Altamont East Compressor Station

Mailing Address Physical Address
1001 Louisiana Street, Suite 1000 approximately two miles east of Altamont
Houston, TX 77002 Altamont, UT 84001

Source Contact UTM Coordinates
Name: Erin Dunman 564,020 m Easting
Phone: [phone],467,280 m Northing
Email: [e-mail] Datum NAD27 UTM Zone 12

SIC code 1311 (Crude Petroleum & Natural Gas)

SOURCE INFORMATION
General Description
The Kinder Morgan Altamont LLC (Kinder Morgan) East Compressor Station receives and compresses
natural gas from the Altamont field. The station is located approximately two miles east of Altamont. The
equipment at this source consists of five (5) compressor units, dehydration equipment, a flare, line
heaters, and various tanks.

NSR Classification
Administrative Amendment

Source Classification
Located in
Duchesne County
Airs Source Size: A

Applicable Federal Standards
NSPS (Part 60), A: General Provisions
NSPS (Part 60), JJJJ: Standards of Performance for Stationary Spark Ignition Internal
Combustion Engines
NSPS (Part 60), OOOO: Standards of Performance for Crude Oil and Natural Gas Production,
Transmission and Distribution for which Construction, Modification, or Reconstruction
Commenced After August 23, 2011, and on or before September 18, 2015
MACT (Part 63), A: General Provisions
DAQE-AN102090014-25
Page 4

MACT (Part 63), HH: National Emission Standards for Hazardous Air Pollutants From Oil and
Natural Gas Production Facilities
MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines
Title V (Part 70) Major Source

Project Description
Kinder Morgan has voluntarily installed a flare (FL-2) to control the VOC emissions from the two (2)
condensate tanks (T-2 & T-3) and the pit tank (T-1); the tanks were previously uncontrolled. The
installation of the flare (FL-2) will reduce VOC emissions by 45.24 tons per year. The permit change is
being implemented as a Reduction of Air Pollutants UAC R307-401-12 and does not require a public
review.

Process Description
The facility receives low-pressure field (wet) gas produced from the Altamont Field via a gas gathering
system. The field natural gas is delivered to the facility, then treated and compressed up to 25 MMscf/day
of gas.

The field gas is treated to remove water, hydrocarbon condensate, and residual hydrogen sulfide (H2S),
compressed, and delivered to the Altamont Main Gas Plant via pipeline for processing. Fuel gas (residue
gas) from the Altamont Main Gas Plant is delivered to the facility via pipeline and is used to fuel the
natural gas-fired equipment at the facility. The hydrocarbon liquid condensate removed in the inlet slug
catcher vessel and from other sumps at the facility is collected and routed to the pit tank, then is stored in
two (2) above-ground storage tanks. The condensate is sold and loaded onto trucks from the condensate
tanks. The water is removed from the facility via truck and taken to company disposal facilities.

SUMMARY OF EMISSIONS

The emissions listed below are an estimate of the total potential emissions from the source. Some
rounding of emissions is possible.

Criteria Pollutant Change (TPY) Total (TPY)
CO2 Equivalent 0 30647.00
Carbon Monoxide 0 82.17
Nitrogen Oxides 0 550.39
Particulate Matter - PM10 0 8.10
Particulate Matter - PM2.5 0 8.10
Sulfur Dioxide 0 0.15
Volatile Organic Compounds -45.24 0.92

Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
1,3-Butadiene (CAS #106990) 0 280
Acetaldehyde (CAS #75070) 0 2140
Acrolein (CAS #107028) 0 2440
Benzene (Including Benzene From Gasoline) (CAS #71432) 0 1300
Ethyl Benzene (CAS #100414) 0 40
DAQE-AN102090014-25
Page 5

Formaldehyde (CAS #50000) 0 12680
Generic HAPs (CAS #GHAPS) 0 660
Hexane (CAS #110543) 0 4760
Methanol (CAS #67561) 0 1500
Toluene (CAS #108883) 0 600
Xylenes (Isomers And Mixture) (CAS #1330207) 0 120
Change (TPY) Total (TPY)
Total HAPs 0 13.26

SECTION I: GENERAL PROVISIONS

I.1 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]
I.2 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1] I.3 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the five-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five (5) years. [R307-401-8]
I.4 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO, including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4] I.5 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107]
I.6 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150] I.7 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101]
I.8 The owner/operator shall submit documentation of the status of construction or modification to the Director within 18 months from the date of this AO. This AO may become invalid if construction is not commenced within 18 months from the date of this AO or if construction is discontinued for 18 months or more. To ensure proper credit when notifying the Director, send the documentation to the Director, attn.: NSR Section. [R307-401-18]

DAQE-AN102090014-25
Page 6

SECTION II: PERMITTED EQUIPMENT

II.A THE APPROVED EQUIPMENT

II.A.1 Altamont East Compressor Station Source-wide
II.A.2 TEG-1
Triethylene Glycol Dehydration Unit with Flash Tank and Condenser
Hydrocarbon steam vent from dehydration process
Capacity: 25 MMscf/day

II.A.3 TEG-2 Triethylene glycol reboiler burner exhaust vent Reboiler Capacity: 1.0 MMBtu/hr
II.A.4 BCU
Hydrocarbon condenser unit (controls emissions from TEG-1)

II.A.5 FL-1 Flare with knock out and natural gas pilot
II.A.6 FL-2 (NEW)
Control: Condensate Tanks (T-2 and T-3) and Pit Tank (T-1)

II.A.7 T-1 Pit tank Approximate volume: 16,800 gallons non-NSPS (below 19,813-gallon threshold for 40 CFR Part 60, Subpart Kb)
II.A.8 T-2,3
Two (2) 400-barrel Condensate Tanks
Approximate volume: 16,800 gallons (each)
non-NSPS (below 19,813-gallon threshold for 40 CFR Part 60, Subpart Kb)

II.A.9 T-4 Methanol storage tank Approximate volume: 4,200 gallons non-NSPS (below 19,813-gallon threshold for 40 CFR Part 60, Subpart Kb)
II.A.10 CE-1
Natural Gas-Fired Reciprocating Internal Combustion Engine
Powers an inlet gas compressor
approximately 1,350 hp
Construction during a period of exemption for natural gas burning equipment. (Code of Air
Conservation Regulations, 1972, 1.3.7)
non-NSPS (commenced construction before applicability date)
II.A.11 CE-2,3 Two (2) Natural Gas-Fired Reciprocating Internal Combustion Engines Powers inlet gas compressors approximately 1,030 hp (each) Construction during a period of exemption for natural gas burning equipment. (Code of Air Conservation Regulations, 1972, 1.3.7) non-NSPS (commenced construction before applicability date)
DAQE-AN102090014-25
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II.A.12 CE-4 Natural Gas-Fired Reciprocating Internal Combustion Engine Powers an inlet gas compressor approximately 1,800 hp Construction during a period of exemption for natural gas burning equipment. (Code of Air Conservation Regulations, 1972, 1.3.7) non-NSPS (commenced construction before applicability date)
II.A.13 CE-5 Natural Gas-Fired Reciprocating Internal Combustion Engine Capacity: 1,680 bhp
Stack Height: greater than or equal to 30 feet from ground Controls: air-fuel ratio controller Non-selective catalytic reduction unit

II.A.14 LH Natural Gas-Fired Line heater: Approximately 2,000,000 BTU/hr Construction during a period of exemption for natural gas burning equipment. (Code of Air Conservation Regulations, 1972, 1.3.7) non-NSPS (heat input capacity less than applicable thresholds) II.A.15 C-1
Combustor
Controlling the emissions from the condenser BCU on the TEG-1
II.A.16 Fugitive Equipment leaks of VOC and loading racks

SECTION II: SPECIAL PROVISIONS II.B REQUIREMENTS AND LIMITATIONS
II.B.1 Site Wide Requirements II.B.1.a Visible emissions from the following emission points shall not exceed the following values: A. All natural gas operated equipment and tanks - 10% opacity B. All other points - 20% opacity. Opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9. [R307-401]
II.B.1.b The owner/operator shall use only pipeline-quality natural gas as a primary fuel. If any other fuel is to be used, an AO shall be required. [R307-401]
II.B.1.c The flare (F-1) shall be used for emergencies and planned station and pipeline blowdowns for repair and maintenance activities. [R307-401]
II.B.1.d The VOC emissions from condensate tanks (T-2 and T-3) and the Pit Tank (T-1) shall be routed
and combusted by the flare (FL-2). [R307-401-8]
DAQE-AN102090014-25
Page 8

II.B.1.e The following items are recognized to be at the East Compressor Station. A permit is not necessary for their operation due to construction during a period of exemption (Code of Air Conservation Regulations, 1972, 1.3.7) for natural gas burning equipment: A. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,350 hp, natural gas fired B. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,030 hp, natural gas fired C. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,030 hp, natural gas fired D. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,800 hp, natural gas fired E. Line heater: Approximately 2,000,000 BTU/hr, natural gas fired. [R307-401]
II.B.2 TEG Dehydration Unit Requirements
II.B.2.a The TEG Dehydration unit TEG-1 shall be equipped with a flash tank. The flash tank off gas shall be recycled or recompressed. [R307-401]
II.B.2.b An air-cooled condenser unit shall be installed for control of VOC emissions from the TEG Dehydration Unit TEG-1. [R307-401]

II.B.2.c Vapors not condensed in the air-cooled condenser shall be routed to the combustor. The combustor shall operate at all times except for downtime not to exceed 175 hours on a calendar year basis. Records of combustor downtime must be kept on a daily basis. [R307-401]
II.B.3 Tank Requirements
II.B.3.a The owner/operator shall load the tanker trucks on site by the use of submerged loading. [R307-401-8]
II.B.3.b The owner/operator shall keep the storage tank thief hatches closed and latched except during tank unloading or other maintenance activities. [R307-401-8]

II.B.3.c The owner/operator shall inspect the thief hatches at least once every three (3) months to ensure the thief hatches are closed, latched, and the associated gaskets, if any, are in good working condition. Records of the thief hatch inspections shall include the date of the inspection and the status of the thief hatches. [R307-401-8] II.B.4 Requirements on Condensate
II.B.4.a The following production limit shall not be exceeded: 4,250,000 gallons of condensate produced per rolling 12-month total. To determine compliance with a rolling 12-month total, the owner/operator shall calculate a new 12-month total by the twentieth day of each month using data from the previous 12 months. Records of production shall be kept for all periods when the plant is in operation. Production shall be determined by records of tank throughput and hours of operation. The records of processing and production shall be kept on a daily basis. Hours of operation shall be determined by supervisor monitoring and maintaining an operations log. [R307-401]

DAQE-AN102090014-25
Page 9

II.B.5 Engine testing requirements II.B.5.a Emissions to the atmosphere at all times from the indicated emission point(s) shall not exceed the
following rates and concentrations: Source: Compressor Engines (CE-5)
Pollutant: NOx lb/hr: 3.70
Pollutant: CO lb/hr: 7.41
Pollutant: VOC lb/hr: 0.59
[R307-401]

DAQE-AN102090014-25
Page 10

II.B.5.a.1 Stack testing to show compliance with the emission limitations stated in the above condition shall be performed as specified below: A. Testing Emissions Points: Compression Engine Exhaust Stack Testing Pollutants: NOx, CO, and VOC Test Status: Initial compliance testing is required for CE-5. The initial test shall be performed as soon as possible and in no case later than 180 days after the startup of a new emission source. A compliance test is required on the emission point that has an emission rate limit. Frequency: Compliance test every 8,760 hours of operation or three (3) years, whichever comes first, subsequent to the initial compliance test. The Director may require testing at any time. B. Notification The Director shall be notified at least 30 days prior to conducting any required emission testing. A source test protocol shall be submitted to DAQ when the testing notification is submitted to the Director. The source test protocol shall be approved by the Director prior to performing the test(s). The source test protocol shall outline the proposed test methodologies, the stack to be tested, and the procedures to be used. A pretest conference shall be held, if directed by the Director. C. Sample Location The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, or other EPA methods as approved by the Director. An Occupational Safety and Health Administration (OSHA) or Mine Safety and Health Administration (MSHA) approved access shall be provided to the test location. D. Volumetric Flow Rate 40 CFR 60, Appendix A, Method 2, or other EPA testing methods approved by the Director. E. Nitrogen Oxides (NOx) 40 CFR 60, Appendix A, Method 3A, 7, 7A, 7B, 7C, 7D, 7E, 20, or other EPA testing methods approved by the Director. F. Carbon Monoxide (CO) 40 CFR 60, Appendix A, Method 10, or other EPA testing methods approved by the Director. G. Volatile Organic Compounds (VOCs) 40 CFR 60, Appendix A, Method 18, 25, 25A, 40 CFR 63 Appendix A, Method 320, or other EPA testing methods approved by the Director. H. Calculations To determine mass emission rates (lb/hr, etc.), the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Director to give the results in the specified units of the emission limitation. I. Existing Source Operation For an existing source/emission point, the production rate during all compliance testing shall be no less than 90% of the maximum production achieved in the previous five (5) years. [R307-401]
DAQE-AN102090014-25
Page 11

II.B.6 Leak Detection and Repair Requirements II.B.6.a The owner/operator shall conduct a leak detection inspection for each new or modified fugitive
emission component installed or modified as part of the project, except for compressor driven by Engine CE-5. Each individual inspection image must encompass valve(s), flange(s) or other connection, pump(s), compressor(s), pressure relief device(s) or other vent(s), process drain(s),
open-ended valve(s), pump seal(s), compressor seal(s), and access door seal(s) or other seal containing or contacting a process stream with hydrocarbons that is associated with the approved emission unit according to the following schedule:
Existing facility:
A. For an existing facility, no later than 180 days from the date of this AO, and B. At least once every 12 months thereafter.
[R307-401]

II.B.6.b Inspections shall be conducted in one of two ways: 1. An analyzer that meets U.S. EPA Method 21, 40 CFR Part 60, Appendix A, or 2. An optical gas imaging instrument as defined in 40 CFR 60.18(g)(4). The optical gas imaging instrument must meet requirements specified in 40 CFR 60.18 (i)(3). Any emissions detected with an optical gas imaging instrument shall be considered a leak in need of repair unless the owner/operator evaluates the leak with an analyzer meeting U.S. EPA Method 21, 40 CFR Part 60. Emissions detected from tank gauging, load-out operations, venting of pneumatics, operation of pressure relief valves, or other maintenance activities shall not be considered leaks. An analyzer reading of 500 ppmv or greater shall be considered a leak in need of repair, except for pumps in light liquid service for which an analyzer reading of 2000 ppmv shall be considered a leak in need of repair. [R307-401]
II.B.6.c The owner/operator is exempt from inspecting a valve, flange, or other connection, pump or compressor, pressure relief device, process drain, open-ended valve, pump or compressor seal
system degassing vent, accumulator vessel vent, agitator seal, or access door seal under any of
the following circumstances:
A. The contacting process stream only contains glycol, amine, methanol, or produced water,
or
B. Monitoring could not occur without elevating the monitoring personnel more than six (6)
feet above a supported surface or without the assistance of a wheeled scissor lift or
hydraulic-type scaffold, or

C. Monitoring could not occur without exposing monitoring personnel to an immediate
danger as a consequence of completing monitoring, or

D. The item to be inspected is buried, insulated in a manner that prevents access to the
components by a monitor probe, or obstructed by equipment or piping that prevents
access to the components by a monitor probe.

[R307-401]

DAQE-AN102090014-25
Page 12

II.B.6.d If a leak as defined in II.B.6 is detected, the owner/operator shall attempt to repair the leak no later than five (5) calendar days after detection. Repair of the leak shall be completed no later than 15 calendar days after detection, unless parts are unavailable or unless repair is technically infeasible without a shutdown. The owner/operator shall inspect the repaired leak no later than 15 calendar days after the leak was repaired to verify that it is no longer leaking. If replacement parts or specialty tools needed for repairs are unavailable, the replacement parts must be ordered no later than five (5) calendar days after detection, and the leak must be repaired no later than 15 calendar days after receipt of the replacement parts. If repair is technically infeasible without a shutdown, the leak must be repaired by the end of the next planned shutdown. If a shutdown is required to repair a leak, the shutdown must occur no later than six (6) months after the detection of the leak unless the owner/operator demonstrates that emissions generated from the shutdown are greater than the fugitive emissions likely to result from delay of repair. [R307-401]
II.B.6.e Records of inspections and leak detection and repair shall include the following:
A. The date of the inspection

B. The name of the person conducting the inspection
C. Any component not exempt under II.B.6.c that is not inspected and the reason it was not
inspected
D. The identification of any component that was determined to be leaking
E. All records shall be maintained for optical gas imaging instrument as per 40 CFR
60.18(i)(4)(vi)
F. The date of first attempt to repair the leaking component

G. Any component with a delayed repair
H. The reason for a delayed repair:
1. For unavailable parts or specialty tools:
i. The date of ordering a replacement component or specialty tool,
ii. The date the replacement component or specialty tool was received.
2. For leaks that cannot be repaired without a shutdown:
i. The reason the repair is technically infeasible ii. The date of the shutdown
iii. Emission estimates from the shutdown and the repair if the delay is
longer than 6 months.
I. Corrective action taken

J. The date corrective action was completed, and

K. The date the component was verified to no longer be leaking.

[R307-401]

DAQE-AN102090014-25
Page 13

PERMIT HISTORY

This Approval Order shall supersede (if a modification) or will be based on the following documents: Supersedes AO DAQE-AN102090008-15 dated September 22, 2015 Is Derived From NOI dated August 26, 2024

DAQE-AN102090014-25
Page 14

ACRONYMS

The following lists commonly used acronyms and associated translations as they apply to this document:

40 CFR Title 40 of the Code of Federal Regulations
AO Approval Order
BACT Best Available Control Technology
CAA Clean Air Act
CAAA Clean Air Act Amendments
CDS Classification Data System (used by Environmental Protection Agency to classify
sources by size/type)
CEM Continuous emissions monitor
CEMS Continuous emissions monitoring system
CFR Code of Federal Regulations
CMS Continuous monitoring system
CO Carbon monoxide
CO2 Carbon Dioxide
CO2e Carbon Dioxide Equivalent - Title 40 of the Code of Federal Regulations Part 98,
Subpart A, Table A-1
COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality
DAQE This is a document tracking code for internal Division of Air Quality use
EPA Environmental Protection Agency
FDCP Fugitive dust control plan
GHG Greenhouse Gas(es) - Title 40 of the Code of Federal Regulations 52.21 (b)(49)(i)
GWP Global Warming Potential - Title 40 of the Code of Federal Regulations Part 86.1818-
12(a)
HAP or HAPs Hazardous air pollutant(s)
ITA Intent to Approve
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent
NOx Oxides of nitrogen
NSPS New Source Performance Standard
NSR New Source Review
PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size
PSD Prevention of Significant Deterioration
PTE Potential to Emit
R307 Rules Series 307
R307-401 Rules Series 307 - Section 401
SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act
Title V Title V of the Clean Air Act
TPY Tons per year
UAC Utah Administrative Code
VOC Volatile organic compounds

DAQE-

RN102090014 January 27, 2025 Erin Dunman
Kinder Morgan Altamont LLC 1001 Louisiana St. Suite 1000
Houston, TX 77002 [e-mail]
Dear Erin Dunman, Re: Engineer Review: Administrative Amendment to Approval Order to DAQE-AN102090008-15, to Update Equipment and Emissions Project Number: N102090014 Please review and sign this letter and attached Engineer Review (ER) within 10 business days. For this document to be considered as the application for a Title V administrative amendment, a Title V Responsible Official must sign the next page.
Please contact Tad Anderson at [phone] if you have any questions or concerns about the ER. If you accept the contents of this ER, please email this signed cover letter to Tad Anderson at [e-mail]. After receipt of the signed cover letter, the DAQ will prepare an Approval Order (AO) for signature by the DAQ Director. If Kinder Morgan Altamont LLC does not respond to this letter within 10 business days, the project will
move forward without your approval. If you have concerns that we cannot resolve, the DAQ Director may issue an Order prohibiting construction. Approval Signature _____________________________________________________________ (Signature & Date)
195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
State of Utah
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor

Engineer Review N102090014: Kinder Morgan Altamont LLC- Altamont East Compressor Station January 27, 2025 Page 1
OPTIONAL: In order for this Engineer Review and associated Approval Order conditions to be considered as an application to administratively amend your Title V Permit, the Responsible Official, as
defined in R307-415-3, must sign the statement below. THIS IS STRICTLY OPTIONAL. If you do not want the Engineer Review to be considered as an application to administratively amend your Operating Permit only the approval signature above is required. Failure to have the Responsible Official sign below will not delay the Approval Order, but will require submittal of a separate Operating Permit Application to revise the Title V permit in accordance with R307-415-5a through 5e and R307-415-7a through 7i. A guidance document: Title V Operating Permit Application Due Dates clarifies the required due dates for Title V operating permit applications and can be viewed at:
https://deq.utah.gov/air-quality/permitting-guidance-and-guidelines-air-quality “Based on information and belief formed after reasonable inquiry, I certify that the statements and information provided for this Approval Order are true, accurate and complete and request that this Approval Order be considered as an application to administratively amend the Operating Permit.” Responsible Official _________________________________________________ (Signature & Date) Print Name of Responsible Official _____________________________________

Engineer Review N102090014: Kinder Morgan Altamont LLC- Altamont East Compressor Station January 27, 2025 Page 2
UTAH DIVISION OF AIR QUALITY
ENGINEER REVIEW

SOURCE INFORMATION
Project Number N102090014 Owner Name Kinder Morgan Altamont LLC
Mailing Address 1001 Louisiana St. Suite 1000 Houston, TX, 77002
Source Name Kinder Morgan Altamont LLC- Altamont East Compressor Station Source Location: approximately two miles east of Altamont Altamont, UT 84001 UTM Projection 564,020 m Easting, 4,467,280 m Northing UTM Datum NAD27 UTM Zone UTM Zone 12 SIC Code 1311 (Crude Petroleum & Natural Gas) Source Contact Erin Dunman Phone Number [phone]
Email [e-mail] Billing Contact Erin Dunman
Phone Number 303-914-7605 Email [e-mail]
Project Engineer Tad Anderson, Engineer Phone Number [phone] Email [e-mail] Notice of Intent (NOI) Submitted August 26, 2024

Engineer Review N102090014: Kinder Morgan Altamont LLC- Altamont East Compressor Station January 27, 2025 Page 3
SOURCE DESCRIPTION General Description
The Kinder Morgan Altamont LLC (Kinder Morgan), East Compressor Station receives and compresses natural gas from the Altamont field. The station is located approximately two miles east of Altamont. The equipment at this source consists of five compressor units, dehydration
equipment, flare, line heaters and various tanks. NSR Classification: Administrative Amendment Source Classification Located in Duchesne County Airs Source Size: A Applicable Federal Standards NSPS (Part 60), A: General Provisions
NSPS (Part 60), JJJJ: Standards of Performance for Stationary Spark Ignition Internal Combustion Engines NSPS (Part 60), OOOO: Standards of Performance for Crude Oil and Natural Gas Production,
Transmission and Distribution for which Construction, Modification, or Reconstruction Commenced After August 23, 2011, and on or before September 18, 2015 MACT (Part 63), A: General Provisions
MACT (Part 63), HH: National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Facilities MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines Title V (Part 70) Major Source
Project Proposal Administrative Amendment to Approval Order to DAQE-AN102090008-15, to Update Equipment and Emissions Project Description Kinder Morgan has voluntarily installed a flare (FL-2) to control the VOC emissions from the two condensate tanks (T-2 & T-3) and the pit tank (T-1), the tanks were previously uncontrolled. The installation of the flare (FL-2) will reduce VOC emissions by 45.24 tons per year. The
permit change is being implemented as a Reduction of Air Pollutants UAC R307-401-12 and does not require a public review.
Process Description The facility receives low-pressure field (wet) gas produced from the Altamont Field via a gas gathering system. The field natural gas is delivered to the facility then treated and compress up to
25 MMscf/day of gas. The field gas is treated to remove water, hydrocarbon condensate and residual hydrogen sulfide
(H2S), compressed and delivered to the Altamont Main Gas Plant via pipeline for processing. Fuel gas (residue gas) from the Altamont Main Gas Plant is delivered to the facility via pipeline and is used to fuel the natural gas-fired equipment at the facility. The hydrocarbon liquid condensate removed in the inlet slug catcher vessel and from other sumps at the facility is

Engineer Review N102090014: Kinder Morgan Altamont LLC- Altamont East Compressor Station January 27, 2025 Page 4
collected and routed to the pit tank, then is stored in two above ground storage tanks. The condensate is sold and loaded to trucks from the condensate tanks. The water is removed from the
facility via truck and taken to company disposal facilities. EMISSION IMPACT ANALYSIS
Modeling is not required as per R307-410-4 and R307-410-5. [Last updated January 24, 2025]

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SUMMARY OF EMISSIONS
The emissions listed below are an estimate of the total potential emissions from the source. Some rounding of emissions is possible.
Criteria Pollutant Change (TPY) Total (TPY) CO2 Equivalent 0 30647.00 Carbon Monoxide 0 82.17
Nitrogen Oxides 0 550.39
Particulate Matter - PM10 0 8.10
Particulate Matter - PM2.5 0 8.10
Sulfur Dioxide 0 0.15
Volatile Organic Compounds -45.24 0.92 Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
1,3-Butadiene (CAS #106990) 0 280
Acetaldehyde (CAS #75070) 0 2140
Acrolein (CAS #107028) 0 2440
Benzene (Including Benzene From Gasoline) (CAS #71432) 0 1300
Ethyl Benzene (CAS #100414) 0 40 Formaldehyde (CAS #50000) 0 12680 Generic HAPs (CAS #GHAPS) 0 660
Hexane (CAS #110543) 0 4760
Methanol (CAS #67561) 0 1500
Toluene (CAS #108883) 0 600
Xylenes (Isomers And Mixture) (CAS #1330207) 0 120 Change (TPY) Total (TPY) Total HAPs 0 13.26
Note: Change in emissions indicates the difference between previous AO and proposed modification.

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Review of BACT for New/Modified Emission Units . BACT review regarding BACT for project
A BACT is required for Administrative Amendments. The installation of additional controls verses no control is considered BACT. BACT for the control of the Condensate Tanks and Pit Tank is to be maintained and operated in a manner consistent with good air pollution control
practices. [Last updated January 27, 2025]
SECTION I: GENERAL PROVISIONS
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the AO. (New or Modified conditions are indicated as “New” in the Outline Label):
I.1 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401] I.2 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1]

I.3 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the five-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five (5) years. [R307-401-8]
I.4 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO,
including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4]
I.5 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107]
I.6 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]
I.7 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101]

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I.8 The owner/operator shall submit documentation of the status of construction or modification to the Director within 18 months from the date of this AO. This AO may become invalid if construction is not commenced within 18 months from the date of this AO or if construction is
discontinued for 18 months or more. To ensure proper credit when notifying the Director, send the documentation to the Director, attn.: NSR Section. [R307-401-18]

SECTION II: PERMITTED EQUIPMENT
The intent is to issue an air quality AO authorizing the project with the following recommended
conditions and that failure to comply with any of the conditions may constitute a violation of the AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.A THE APPROVED EQUIPMENT II.A.1 Altamont East Compressor Station Source-wide

II.A.2 TEG-1 Triethylene Glycol Dehydration Unit with Flash Tank and Condenser Hydrocarbon steam vent from dehydration process
Capacity: 25 MMscf/day II.A.3 TEG-2 Triethylene glycol reboiler burner exhaust vent Reboiler Capacity: 1.0 MMBtu/hr II.A.4 BCU Hydrocarbon condenser unit (controls emissions from for TEG-1)
II.A.5 FL-1
Flare with knock out and natural gas pilot II.A.6 NEW FL-2 (NEW) Control: Condensate Tanks (T-2 and T-3) and Pit Tank (T-1)
II.A.7 T-1
Pit tank Approximate volume 16,800 gallons non NSPS (below 19,813 gallon threshold for 40 CFR Part 60, Subpart Kb)
II.A.8 T-2,3 Two 400 barrel Condensate Tanks Approximate volume 16,800 gallons (each)
non NSPS (below 19,813 gallon threshold for 40 CFR Part 60, Subpart Kb) II.A.9 T-4 Methanol storage tank
Approximate volume 4,200 gallons non NSPS (below 19,813 gallon threshold for 40 CFR Part 60, Subpart Kb)

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II.A.10 CE-1 Natural Gas Fired Reciprocating Internal Combustion Engine Powers an inlet gas compressor
approximately 1,350 hp Construction during a period of exemption for natural gas burning equipment. (Code of Air Conservation Regulations, 1972, 1.3.7)
non NSPS (commenced construction before applicability date) II.A.11 CE-2,3 Two (2) Natural Gas Fired Reciprocating Internal Combustion Engines Powers inlet gas compressors approximately 1,030 hp (each) Construction during a period of exemption for natural gas burning equipment. (Code of Air
Conservation Regulations, 1972, 1.3.7) non NSPS (commenced construction before applicability date)
II.A.12 CE-4 Natural Gas Fired Reciprocating Internal Combustion Engine Powers an inlet gas compressor approximately 1,800 hp
Construction during a period of exemption for natural gas burning equipment. (Code of Air Conservation Regulations, 1972, 1.3.7) non NSPS (commenced construction before applicability date)

II.A.13 CE-5 Natural Gas Fired Reciprocating Internal Combustion Engine Capacity: 1,680 bhp Stack Height: greater than or equal to 30 feet from ground Controls: air-fuel ratio controller Non-Selective catalytic reduction unit

II.A.14 LH Natural Gas Fired Line heater: Approximately 2,000,000 BTU/hr Construction during a period of exemption for natural gas burning equipment. (Code of Air Conservation Regulations, 1972, 1.3.7) non NSPS (heat input capacity less than applicable thresholds)
II.A.15 C-1
Combustor Controlling the emissions from the condenser BCU on the TEG-1
II.A.16 Fugitive
Equipment leaks of VOC and loading racks

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SECTION II: SPECIAL PROVISIONS The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.B REQUIREMENTS AND LIMITATIONS
II.B.1 Site Wide Requirements
II.B.1.a Visible emissions from the following emission points shall not exceed the following values:
A. All natural gas operated equipment and tanks - 10% opacity B. All other points - 20% opacity Opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9.
. [R307-401] II.B.1.b The owner/operator shall use only pipeline quality natural gas as a primary fuel. If any other fuel is to be used, an AO shall be required.
. [R307-401]
II.B.1.c NEW The flare (F-1) shall be used for emergencies and planned station and pipeline blow downs for repair and maintenance activities. [R307-401]
II.B.1.d
NEW
The VOC emissions from condensate tanks (T-2 and T-3) and the Pit Tank (T-1) shall be
routed and combusted by the flare (FL-2). [R307-401-8] II.B.1.e The following items are recognized to be at the East Compressor Station. A permit is not necessary for their operation due to construction during a period of exemption (Code of Air Conservation Regulations, 1972, 1.3.7) for natural gas burning equipment:
A. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,350 hp, natural gas fired. B. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,030 hp, natural gas fired. C. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,030 hp, natural gas fired. D. Reciprocating internal combustion engine: Powers an inlet gas compressor, approximately 1,800 hp, natural gas fired.
E. Line heater: Approximately 2,000,000 BTU/hr, natural gas fired. [R307-401]

II.B.2 TEG Dehydration Unit Requirements
II.B.2.a The TEG Dehydration unit TEG-1 shall be equipped with a flash tank. The flash tank off gas
shall be recycled or recompressed. [R307-401]

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II.B.2.b An air-cooled condenser unit shall be installed for control of VOC emissions from the TEG Dehydration Unit TEG-1. [R307-401]
II.B.2.c Vapors not condensed in the air-cooled condenser shall be routed to the combustor. The combustor shall operate at all times except for downtime not to exceed 175 hours on a calendar year basis. Records of combustor downtime must be kept on a daily basis. [R307-401]
II.B.3 Tank Requirements
II.B.3.a The owner/operator shall load the tanker trucks on site by the use of submerged loading.
[R307-401-8]
II.B.3.b The owner/operator shall keep the storage tank thief hatches closed and latched except during tank unloading or other maintenance activities. [R307-401-8]
II.B.3.c The owner/operator shall inspect the thief hatches at least once every three months to ensure
the thief hatches are closed, latched, and the associated gaskets, if any, are in good working condition. Records of thief hatch inspections shall include the date of the inspection and the status of the thief hatches. [R307-401-8]

II.B.4 Requirements on Condensate
II.B.4.a The following production limit shall not be exceeded:
4,250,000 gallons of condensate produced per rolling 12-month total
To determine compliance with a rolling 12-month total, the owner/operator shall calculate a new 12-month total by the twentieth day of each month using data from the previous 12 months. Records of production shall be kept for all periods when the plant is in operation. Production shall be determined by records of tank throughput and hours of operation. The records of processing and production shall be kept on a daily basis. Hours of operation shall be determined by supervisor monitoring and maintaining of an operations log. [R307-401] II.B.5 Engine testing requirements II.B.5.a Emissions to the atmosphere at all times from the indicated emission point(s) shall not exceed the following rates and concentrations:
Source: Compressor Engines (CE-5) Pollutant: NOx lb/hr: 3.70
Pollutant: CO
lb/hr: 7.41
Pollutant: VOC
lb/hr: 0.59. [R307-401] II.B.5.a.1 Stack testing to show compliance with the emission limitations stated in the above condition shall be performed as specified below:
A. Testing

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Emissions Points: Compression Engine Exhaust Stack Testing Pollutants: NOx, CO, and VOC Test Status: Initial compliance testing is required for CE-5. The initial test shall be performed as soon as possible and in no case later than 180 days after the start up of a new emission source. A compliance test is required on the emission point that has an emission rate limit.
Frequency: Compliance test every 8,760 hours of operation or three years, whichever comes
first, subsequent to the initial compliance test. The Director may require testing at any time.
B. Notification The Director shall be notified at least 30 days prior to conducting any required emission testing. A source test protocol shall be submitted to DAQ when the testing notification is submitted to the Director.
The source test protocol shall be approved by the Director prior to performing the test(s). The source test protocol shall outline the proposed test methodologies, stack to be tested, and procedures to be used. A pretest conference shall be held, if directed by the Director. C. Sample Location The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix
A, Method 1, or other EPA methods as approved by the Director. An Occupational Safety and Health Administration (OSHA) or Mine Safety and Health Administration (MSHA) approved access shall be provided to the test location.
D. Volumetric Flow Rate 40 CFR 60, Appendix A, Method 2 or other EPA testing methods approved by the Director.
E. Nitrogen Oxides (NOx)
40 CFR 60, Appendix A, Method 3A, 7, 7A, 7B, 7C, 7D, 7E, 20 or other EPA testing methods approved by the Director. F. Carbon Monoxide (CO) 40 CFR 60, Appendix A, Method 10, or other EPA testing methods approved by the Director.
G. Volatile Organic Compounds (VOCs) 40 CFR 60, Appendix A, Method 18, 25, 25A, 40 CFR 63 Appendix A, Method 320,or other EPA testing methods approved by the Director. H. Calculations To determine mass emission rates (lb/hr, etc.) the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Director, to give the results in the specified units of the emission limitation. I. Existing Source Operation For an existing source/emission point, the production rate during all compliance testing shall
be no less than 90% of the maximum production achieved in the previous five (5) years. [R307-401]

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II.B.6 Leak Detection and Repair Requirements
II.B.6.a The owner/operator shall conduct a leak detection inspection for each new or modified fugitive emission component installed or modified as part of the project except for compressor driven by Engine CE-5. Each individual inspection image must encompass valve(s), flange(s) or other connection, pump(s), compressor(s), pressure relief device(s) or other vent(s), process drain(s), open-ended valve(s), pump seal(s), compressor seal(s), and access door seal(s) or other seal containing or contacting a process stream with hydrocarbons that is associated with the approved emission unit according to the following schedule:
Existing facility:
a. For an existing facility, no later than 180 days from the date of this AO, and b. At least once every 12 months thereafter. [R307-401]
II.B.6.b Inspections shall be conducted in one of two ways;
1. An analyzer that meets U.S. EPA Method 21, 40 CFR Part 60, Appendix A, or 2. An optical gas imaging instrument as defined in 40 CFR 60.18(g)(4) The optical gas imaging instrument must meet requirements specified in 40 CFR 60.18 (i)(3). Any emissions detected with an optical gas imaging instrument shall be considered a leak in need of repair unless the owner/operator evaluates the leak with an analyzer meeting U.S. EPA Method 21, 40 CFR Part 60. Emissions detected from tank gauging, load-out operations, venting of pneumatics, operation of pressure relief valves, or other maintenance activities shall not be considered leaks.
An analyzer reading of 500 ppmv or greater shall be considered a leak in need of repair except
for pumps in light liquid service for which analyzer reading of 2000 ppmv shall be considered a leak in need of repair. [R307-401]
II.B.6.c The owner/operator is exempt from inspecting a valve, flange or other connection, pump or
compressor, pressure relief device, process drain, open-ended valve, pump or compressor seal system degassing vent, accumulator vessel vent, agitator seal, or access door seal under any of the following circumstances:
a. the contacting process stream only contains glycol, amine, methanol, or produced water, or
b. monitoring could not occur without elevating the monitoring personnel more than six feet above a supported surface or without the assistance of a wheeled scissor-lift or hydraulic type scaffold, or c. monitoring could not occur without exposing monitoring personnel to an immediate danger as a consequence of completing monitoring, or d. the item to be inspected is buried, insulated in a manner that prevents access to the components by a monitor probe, or obstructed by equipment or piping that prevents access to the components by a monitor probe. [R307-401]

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II.B.6.d NEW If a leak as defined in II.B.6 is detected, the owner/operator shall attempt to repair the leak no later than 5 calendar days after detection. Repair of the leak shall be completed no later than 15 calendar days after detection, unless parts are unavailable or unless repair is technically
infeasible without a shutdown. The owner/operator shall inspect the repaired leak no later than 15 calendar days after the leak was repaired to verify that it is no longer leaking. If replacement parts or specialty tools needed for repairs are unavailable, the replacement parts must be ordered no later than 5 calendar days after detection, and the leak must be repaired no later than 15 calendar days after receipt of the replacement parts.
If repair is technically infeasible without a shutdown, the leak must be repaired by the end of the next planned shutdown. If a shutdown is required to repair a leak, the shutdown must occur no later than 6 months after the detection of the leak unless the owner/operator demonstrates that emissions generated from the shutdown are greater than the fugitive
emissions likely to result from delay of repair. [R307-401] II.B.6.e Records of inspections and leak detection and repair shall include the following: a. The date of the inspection,
b. The name of the person conducting the inspection, c. Any component not exempt under II.B.5.c that is not inspected and the reason it was not
inspected,
d. The identification of any component that was determined to be leaking, e. All records shall be maintained for optical gas imaging instrument as per 40 CFR
60.18(i)(4)(vi) f. The date of first attempt to repair the leaking component, g. Any component with a delayed repair, h. The reason for a delayed repair,
1. For unavailable parts or specialty tools:
i. The date of ordering a replacement component or specialty tool,
ii. The date the replacement component or specialty tool was received,
2. For leaks that cannot be repaired without a shutdown:
i. The reason the repair is technically infeasible,
ii. The date of the shutdown
iii. Emission estimates from the shutdown and the repair if the delay is longer
than 6 months,
i. Corrective action taken, j. The date corrective action was completed, and k. The date the component was verified to no longer be leaking. [R307-401]

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PERMIT HISTORY When issued, the approval order shall supersede (if a modification) or will be based on the
following documents: Supersedes DAQE-AN102090008-15 dated September 22, 2015
Is Derived From NOI dated July 8, 2024
REVIEWER COMMENTS

1. Comment regarding PSD Source: The 1972 IC engines do not have any requirements on them due to the fact that the whole plant was installed in 1972 after the grandfathered date of 1969 but the state of Utah had a rule (Code of Air Conservation Regulations, 1972, 1.3.7) for natural gas burning equipment exemption which allowed the source to construct the entire plant without getting a permit. Since then, the source operated the Altamont East Compressor Station and submitted a Title V Application in early 1990's. [Last updated January 24, 2025] 2. Comment regarding Emission Estimates: Kinder Morgan has submitted a notification to UDAQ to add a flare and control the VOC emissions coming from the condensate tanks (T-1 and T-2) and the pit tank (T-1) per UAC R307-401-12. In
the notification focused on the emissions calculations for the tanks and the control (destruction) efficiency of the flare (98%). The use of the flare reduced the VOC emissions from the tanks from 46.16 TPY to 0.92 TPY of VOC emissions. [Last updated January 27, 2025]
3. Comment regarding Project Type: This project is being conducted as a Reduction of Air Pollutants, UAC R307-401-12. Since all
emissions are decreasing, this action is an Administrative Amendment. [Last updated January 27, 2025] 4. Comment regarding Permit Format Update: The previous permit was permitted in 2015. UDAQ has changed the permit format since 2015 and this permit has been updated to reflect. [Last updated January 24, 2025] 5. Comment regarding Source Classification: The permit action is decreasing the emissions of VOC emissions from 46.16 TPY to 0.92 TPY. This reduction in emissions does not change the source classification. The Kinder Morgan, East Compressor Station will remain a Major PSD source (250 TPY) for NOx emissions (550.39 TPY). [Last updated January 24, 2025] 6. Comment regarding Federal Applicable Regulations:
Kinder Morgan, East Compressor Station is subject to 40 CFR 60 Subpart A (General Provisions), JJJJ (Standards of Performance for Stationary Spark Ignition Internal Combustion Engines) and OOOO (Standards of Performance from Crude Oil and Natural Gas Production, Transmission, and
Distribution); and 40 CFR 63 Subparts A (General Provisions), HH (National Emission Standards for Hazardous Air Pollutants from Oil and Gas Production Facilities), and ZZZZ (National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines.
This permit change does not make this source subject to 40 CFR 60 Subpart OOOOa. [Last updated January 24, 2025]

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7. Comment regarding Additional The updated approval order has an additional condition for the operation of the new flare (FL-2) to control the VOC emissions from the existing condensate tanks (T-2 and T-3) and the Pit Tank (T-1). [Last updated January 27, 2025]

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ACRONYMS The following lists commonly used acronyms and associated translations as they apply to this document:
40 CFR Title 40 of the Code of Federal Regulations AO Approval Order BACT Best Available Control Technology
CAA Clean Air Act CAAA Clean Air Act Amendments CDS Classification Data System (used by EPA to classify sources by size/type) CEM Continuous emissions monitor CEMS Continuous emissions monitoring system CFR Code of Federal Regulations CMS Continuous monitoring system CO Carbon monoxide CO2 Carbon Dioxide CO2e Carbon Dioxide Equivalent - 40 CFR Part 98, Subpart A, Table A-1 COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality DAQE This is a document tracking code for internal UDAQ use EPA Environmental Protection Agency
FDCP Fugitive dust control plan GHG Greenhouse Gas(es) - 40 CFR 52.21 (b)(49)(i) GWP Global Warming Potential - 40 CFR Part 86.1818-12(a)
HAP or HAPs Hazardous air pollutant(s) ITA Intent to Approve LB/HR Pounds per hour
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units
NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent NOx Oxides of nitrogen NSPS New Source Performance Standard NSR New Source Review PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size PSD Prevention of Significant Deterioration PTE Potential to Emit
R307 Rules Series 307 R307-401 Rules Series 307 - Section 401 SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act Title V Title V of the Clean Air Act TPY Tons per year
UAC Utah Administrative Code VOC Volatile organic compounds
DAQE-

RN102090014 January 27, 2025
Erin Dunman
Kinder Morgan Altamont LLC 1001 Louisiana St. Suite 1000
Houston, TX 77002 [e-mail]
Dear Erin Dunman,
Re: Engineer Review: Administrative Amendment to Approval Order to DAQE-AN102090008-15, to Update Equipment and Emissions Project Number: N102090014
Please review and sign this letter and attached Engineer Review (ER) within 10 business days. For this document to be considered as the application for a Title V administrative amendment, a Title V Responsible Official must sign the next page.
Please contact Tad Anderson at [phone] if you have any questions or concerns about the ER. If you accept the contents of this ER, please email this signed cover letter to Tad Anderson at [e-mail]. After receipt of the signed cover letter, the DAQ will prepare an Approval Order (AO) for signature by the DAQ Director.
If Kinder Morgan Altamont LLC does not respond to this letter within 10 business days, the project will move forward without your approval. If you have concerns that we cannot resolve, the DAQ Director may issue an Order prohibiting construction.
Approval Signature _________________________________________February 27, 2025___________ (Signature & Date)
195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
Department of Environmental Quality
Kimberly D. Shelley Executive Director
DIVISION OF AIR QUALITY Bryce C. Bird Director State of Utah
SPENCER J. COX Governor
DEIDRE HENDERSON Lieutenant Governor

FedEx 2780 1272 8502

August 7, 2024

Mr. Harold Burge, Manager Major NSR
Utah Division of Air Quality (UDAQ)
Utah Department of Environmental Quality
195 North 1950 West
Salt Lake City, Utah 84116

Re: Kinder Morgan Altamont LLC – Altamont East Compressor Station
Approval Order DAQE-AN102090008-15 &
Title V Operating Permit # 1300039005
R307-401-12 Notification for Tank Flare

Dear Mr. Burge:

Kinder Morgan Altamont LLC (Kinder Morgan) operates the Altamont East Compressor Station, which is
currently permitted to operate under Approval Order DAQE- AN102090008-15 (dated September 22,
2015) and Title V Operating Permit #1300039005 (dated June 16, 2022). Kinder Morgan has voluntarily
installed a flare (FL-2) to control the emissions from the two condensate tanks (T-2 & T-3) and the pit tank
(Pit Tank), the tanks were previously uncontrolled. As required by R307-407-8 FL-2 is equipped with a
continuous pilot and auto-ignitor. Additionally, FL-1’s opacity will not exceed 20%.

This installation resulted in a significant reduction in VOC emissions. Per guidance from UDAQ this project
qualifies for Utah Rule R307-401-12, which provides an exemption from the requirement to submit a
Notice of Intent (NOI). With this letter, notification of the change is being provided in accordance with
paragraph (b) of R307-401-12. The project is commenced on July 19, 2024.

The project does not trigger applicability with any new regulations.

The project also triggers applicability to Utah Rule R307-501 which applies to all oil and natural gas
exploration, production, and transmission operations, well production facilities, natural gas compressor
stations, and natural gas processing plants in Utah. The facility meets these criteria, and the project is
subject to R307-501. The project is not subject to other requirements within R307-502 through R307-511
generally because the equipment will be regulated by an Approval Order, is not located at a well site, and
the compressor is not impacted by the project.

Under the provisions of R307-401-12, a BACT evaluation is not formally required.

The estimated change in potential emissions from the tanks is summarized in the table below. The “Pre-
Project PTE” includes total potential emissions from the uncontrolled tanks and “Post-Project PTE”
includes total potential emissions from the controlled tanks. The destruction efficiency of the flare is 98%.

Table 1. Estimated Change in Potential Emissions (tpy)
Contaminant Pre-Project PTE Post-Project PTE Difference
VOC 46.16 0.92 -45.24

Kinder Morgan requests concurrence from the Utah Division of Air Quality (UDAQ) that this project meets
the R307-401-12 Reduction in Air Contaminants exemption.

Furthermore, as a follow-up action to make this project enforceable, Kinder Morgan requests UDAQ issues
an update to the facility’s Approval Order. Kinder Morgan is requesting addition of the following permit
changes within the AO:

1. Addition of FL-2.

Kinder Morgan also requests that the facility’s Title V Operating Permit #1300039005 (dated June 16,
2022) incorporate these changes.

Please do not hesitate to contact me at 303-914-7605 or [e-mail] if you have
questions as you process this request.

Sincerely,

Erin Dunman
EHS Engineer

Enclosures: Attachment A: Flare Specifications

Attachment A:
Flare Specifications

11:46 AM, 6/15/2010
VENDOR:
CLIENT:
PROJECT:
QUOTE #:
DESIGN CASE:
SERVICE:
DATE:
[1] - Waste Gas Flow Rate 500,000.00 [SCFD]14,158.42 [SCMD]
[2] - Fuel Gas Flow Rate 0.00 [SCFH]0.00 [SCMH]
[3] - Waste Gas Inlet Temperature 80.00 [°F]26.67 [°C]
[4] - Waste Gas Allowable Pressure Drop 5.00 [psig]34.48 [kPa]
[5] - Ambient Air Temperature 60.00 [°F]15.56 [°C]
[6] - Ambient Air Relative Humidity 80.00 [%]80.00 [%]
[7] - Atmospheric Pressure 14.17 [psi]97.70 [kPa]
[8] - Wind Speed for Radiation 29.33 [ft/s]8.94 [m/s]
[9] - Flare Design Exit Mach Rating (as per API 521)0.20 [-]0.20 [-]
[10] - Flare Gas Molecular Weight 22.70 [lb/lb-mol]22.70 [g/g-mol]
FLARE DESIGN DATA SHEET
Tornado Technologies Inc.
Continuous
Hydrocarbons
June 15, 2010
FLARE DESIGN CRITERIA USED
FLARE GAS CHARACTERISTICS
[10] - Flare Gas Molecular Weight 22.70 [lb/lb-mol]22.70 [g/g-mol]
[11] - Waste Gas Lower Heating Value 1202.20 [BTU/SCF]44.8 [MJ/SCM]
[12] - Net Heat Release 28,745,780.84 [BTU/hr]30,328 [MJ/hr]
[13] - Flare Height 40.00 [ft]12.2 [m]
[14] - Tip Nominal Pipe Size 3.00 [in]0.076 [m]
[15] - Purge Reducer Installed:
[16] - Recommended Purge Flow Rate 90 [SCFH]2.5 [SCMH]
[17] - Flare Tip Velocity 120.66 [ft/s]36.78 [m/s]
[18] - Actual Flare Tip Exit Mach 0.10 [-]0.10 [-]
[19] - Maximum Ground Level Radiation 510 [BTU/hr/ft2]1.61 [kW/m2]
[20] - Radial Distance to Maximum Radiation 9.87 [ft]3.01 [m]
[21] - Customer Specified Radial Distance to Determine Radiation 10.00 [ft]3.05 [m]
[22] - Solar Radiation 300.00 [BTU/hr/ft2]0.95 [kW/m2]
[23] - Radiation at Above Customer Specified Radial Distance 510.00 [BTU/hr/ft2]1.61 [kW/m2]
[24] - Tip Pressure Drop at the Above Waste Gas Flow Rate 3.15 [in WC]0.78 [kPa]
[25] - Purge Reducer Pressure Drop at the Above Waste Gas Flow Rate 0.00 [in WC]0.00 [kPa]
[26] - Flare Riser Pressure Drop at the Above Waste Gas Flow Rate 1.28 [in WC]0.32 [kPa]
[27] - Total Pressure Drop at the Above Waste Gas Flow Rate 4.43 [in. WC]1.10 [kPa]
CALCULATED FLARE VALUES
FLARE GEOMETRY
No Seal
Calgary Office
3236- 50 Ave. SE
Calgary, Alberta
T2B 3A3
Ph: [phone]
Fax: [phone]
Gadsby Office
Box 1799
Settler, Alberta
T0C 2L0
Ph: [phone]
Fax: [phone]
Texas Office
5854IH - 10
Alleyton,Texas
78935 - 2061
Ph: [phone]
Fax: [phone]