DAQ-2025-000454

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

Department of
Environmental Quality
Kimberly D. Shelley
Executive Director
DIVISION OF AIR QUALITY
Bryce C. Bird
Director
Air Quality Board
Kim Frost, Chair
Michelle Bujdoso, Vice-Chair
Kevin R. Cromar
Cassady Kristensen
Randal S. Martin
Sonja Norton
John Rasband
Kimberly D. Shelley
Jeff Silvestrini
Bryce C. Bird,
Executive Secretary
SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor
DAQ-012-25
UTAH AIR QUALITY BOARD MEETING
TENTATIVE AGENDA
Wednesday, February 5, 2025 - 1:30 p.m.
195 North 1950 West, Room 1015
Salt Lake City, Utah 84116
Board members may be participating electronically. Interested persons can participate telephonically by
dialing 1-475-299-8810 using access code: 449-801-632#, or via the Internet at meeting link:
meet.google.com/dpm-oqgm-nzk
I. Call-to-Order
II. Date of the Next Air Quality Board Meeting: March 5, 2025
III.Approval of the Minutes for the November 6, 2024, Board Meeting.
IV.Propose for Final Adoption: Amend Utah State Implementation Plan, Section X, Vehicle
Inspection and Maintenance Program, Part F, Cache County; and R307-110-36. Section X, Vehicle
Inspection and Maintenance Program, Part F, Cache County. Presented by Mat Carlile.
V.Propose for Final Adoption: New Rule R307-209. Portable Aggregate Processing Plants.
Presented by Alan Humpherys.
VI. Propose for Final Adoption: Amend R307-401. Permit: New and Modified Sources.
Presented by Alan Humpherys.
VII. Propose for Public Comment: Amend R307-150. Emission Inventories. Presented by Greg
Mortensen.
VIII. Propose for Public Comment: Amendment to Section R307-110-17. Section IX, Control Measures
for Area and Point Sources, Part H, Emission Limits; and Amendments to Utah State
Implementation Plan, Section IX.H.11 and Section IX.H.12: Emission Limitations and Operating
Practices. Presented by Ana Williams.
DAQ-012-25
Page 2

IX. Informational Items:
A. Air Toxics. Presented by Leonard Wright.
B. Compliance. Presented by Harold Burge, Rik Ombach, and Chad Gilgen.
C. Monitoring. Presented by Bo Call.
D. Other Items to be Brought Before the Board.
E. Board Meeting Follow-up Items.

In compliance with the Americans with Disabilities Act, individuals with special needs (including auxiliary communicative aids
and services) should contact LeAnn Johnson, Office of Human Resources at [phone], TDD [phone] or by email
at [e-mail].

ITEM 4

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

Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor
DAQ-011-25
M E M O R A N D U M TO: Air Quality Board THROUGH: Bryce C. Bird, Executive Secretary FROM: Mat Carlile, Environmental Planning Consultant DATE: January 23, 2025 SUBJECT: PROPOSE FOR FINAL ADOPTION: Amend Utah State Implementation Plan, Section X, Vehicle Inspection and Maintenance Program, Part F, Cache County; and R307-110-36. Section X, Vehicle Inspection and Maintenance Program, Part F, Cache County.
______________________________________________________________________________________ On November 6, 2024, the Utah Air Quality Board approved for public comment amendments to Part F of
Utah SIP Section X. and Section R307-110-36. Amendments to Part F update Cache County’s regulation to reflect the activities of the current programs, provide clarity, and ensure that the programs conform to federal requirements. A public comment period was held from December 1-31, 2024. No public comments were received, and no hearing was requested. Recommendation: Staff recommend the Board approve the amendment to SIP Section X, Parts F, and Section R307-110-36 for final adoption.
State of Utah
Administrative Rule Analysis
Revised May 2024

NOTICE OF SUBSTANTIVE CHANGE
TYPE OF FILING: Amendment
Rule or Section Number: R307-110-36 Filing ID: Office Use Only
Date of Previous Publication (Only for CPRs): Click or tap to enter a date.

Agency Information
1. Title catchline: Environmental Quality, Air Quality
Building: Multi-Agency State Office Building
Street address: 195 N 1950 W
City, state: Salt Lake City
Mailing address: PO Box 144820
City, state and zip: Salt Lake City, UT 84114-4820
Contact persons:
Name: Phone: Email:
Erica Pryor 385-499-3416 [e-mail]
Mat Carlile 385-306-6535 [e-mail]

Please address questions regarding information on this notice to the persons listed above.

General Information
2. Rule or section catchline:
R307-110-36. General Requirements: State Implementation Plan

3. Purpose of the new rule or reason for the change:
The Utah Air Quality Board (Board) has proposed for public comment amended Utah State Implementation Plan (SIP), Section
X, Part F. Section R307-110-36 incorporates SIP Section X, Parts F, into the rule and must be amended to change the Board
adoption date to the anticipated adoption date of the amended plan

4. Summary of the new rule or change:
Section R307-110-36 incorporates Section X Part F of the Utah State Implementation Plan (SIP). Section R307-110-36
incorporates Section X Part F of the Utah SIP. Part F contains the requirements of Cache County’s I/M program. Amendments
to Part F update the plan to incorporate changes to Cache County’s I/M regulation to ensure that the SIP reflects the current
program. Section R307-110-36 is amended by changing the date of the last adoption by the Air Quality Board to February 5,
2025. These changes were already legally enforceable, and the amendment is bringing the rule in line with federal law.

Fiscal Information
5. Provide an estimate and written explanation of the aggregate anticipated cost or savings to:
A) State budget:
This rule change will not have any fiscal impact on the state budget because it does not enact or remove any new
requirements.

B) Local governments:
This rule change will not have any fiscal impact on the local governments because it does not enact or remove any new
requirements

C) Small businesses ("small business" means a business employing 1-49 persons):
This rule change will not have any fiscal impact on small businesses because it does not enact or remove any new
requirements.

D) Non-small businesses ("non-small business" means a business employing 50 or more persons):
This rule change will not have any fiscal impact on non- small businesses because it does not enact or remove any new
requirements.

E) Persons other than small businesses, non-small businesses, state, or local government entities ("person" means
any individual, partnership, corporation, association, governmental entity, or public or private organization of any character
other than an agency):
This rule change will have not any fiscal impact on other persons because it does not enact or remove any new requirements.

F) Compliance costs for affected persons (How much will it cost an impacted entity to adhere to this rule or its changes?):
No additional costs for affected persons are anticipated due to this rule change because it does not enact or remove any new
requirements.

G) Regulatory Impact Summary Table (This table only includes fiscal impacts that could be measured. If there are
inestimable fiscal impacts, they will not be included in this table. Inestimable impacts will be included in narratives above.)
Regulatory Impact Table
Fiscal Cost FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Cost $0 $0 $0
Fiscal Benefits FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Benefits $0 $0 $0
Net Fiscal Benefits $0 $0 $0
H) Department head comments on fiscal impact and approval of regulatory impact analysis:
The Executive Director of the Department of Environmental Quality, Kim D. Shelley, has reviewed and approved this regulatory
impact analysis.

Citation Information
6. Provide citations to the statutory authority for the rule. If there is also a federal requirement for the rule, provide a
citation to that requirement:
Section 19-6a-1642 40 CFR Part 51 Subpart S Inspection and
Maintenance Program Requirements

Incorporations by Reference Information
7. Incorporations by Reference (if this rule incorporates more than two items by reference, please include additional tables):
A) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)
UTAH STATE IMPLEMENTATION PLAN SECTION X VEHICLE INSPECTION
AND MAINTENANCE PROGRAM PART F CACHE COUNTY
Publisher Division of Air Quality, Utah Department of Environmental Quality

Issue Date February 5, 2025
Issue or Version

B) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

Public Notice Information
8. The public may submit written or oral comments to the agency identified in box 1. (The public may also request a
hearing by submitting a written request to the agency. See Section 63G-3-302 and Rule R15-1 for more information.)
A) Comments will be accepted until: 12/31/2024
B) A public hearing (optional) will be held:
Date (mm/dd/yyyy): Time (hh:mm AM/PM): Place (physical address or URL):
12/18/2024 2:30 PM R307-110-36 Public Hearing

Wednesday, December 18, 2024 at 2:30 PM

In Person

Multi-Agency State Office Building (MASOB) 195 N 1950 W, Salt Lake
City, UT 84116, USA
Air Quality Board Room 1015, 1st Floor

Or attend virtually:

Air Quality Public Hearing R307-110-36
Wednesday, December 18 ꞏ 2:30 – 3:30pm

Time zone: America/Denver

Google Meet joining info

Video call link:
https://meet.google.com/pap-hiyu-unw

Or dial: 4082-438-+1 413 (US) PIN: 356 203 677#
More phone numbers: https://tel.meet/pap-hiyu-unw?pin=6631750756387

In accordance with 63G-3-302, please note that if no requests for a public
hearing for R307-110-36 are received by 2:00pm on December 13th, 2024,
then we will cancel this hearing.

To determine if the hearing has been cancelled and/or view the cancellation
notice, you can visit:

https://deq.utah.gov/air-quality/air-quality-rule-plan-changes-open-public-
comment

To the agency: If more than one hearing will take place, continue to add rows.
9. This rule change MAY become effective on: 02/05/2025
NOTE: The date above is the date the agency anticipates making the rule or its changes effective. It is NOT the effective date.
Agency Authorization Information
To the agency: Information requested on this form is required by Sections 63G-3-301, 63G-3-302, 63G-3-303, and 63G-3-
402. Incomplete forms will be returned to the agency for completion, possibly delaying publication in the Utah State Bulletin
and delaying the first possible effective date.
Agency head or
designee and title:
Bryce C. Bird, Director, Division of Air
Quality
Date: 10/23/2024

R307. Environmental Quality, Air Quality. 1
R307-110. General Requirements: State Implementation Plan. 2
3
…. 4
R307-110-36. Section X, Vehicle Inspection and Maintenance Program, Part F, Cache County. 5
The Utah State Implementation Plan, Section X, Vehicle Inspection and Maintenance Program, Part 6
F, Cache County, as most recently adopted by the Utah Air Quality Board on [(September 4, 2019)]February 7
5, 2025, pursuant to Section 19-2-104, is [hereby] incorporated by reference and made a part of [these]this 8
rule[s]. 9
10
11
…. 12
KEY: air pollution, PM10, PM2.5, ozone 13
Date of Last Change: February 7, 2024 14
Notice of Continuation: December 1, 2021 15
Authorizing, and Implemented or Interpreted Law: 19-2-104 16
Page 1 of 1

Section X Part F, Page i
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UTAH STATE IMPLEMENTATION PLAN 4
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SECTION X 6
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VEHICLE INSPECTION AND 8
MAINTENANCE PROGRAM 9
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Part F 11
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Cache County 13
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Adopted by the Utah Air Quality Board 38
[September 4, 2019]February 5, 2025 39
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Section X Part F, Page ii
Table of Contents 1
2
3
1. Applicability ............................................................................................................................................................. 1 4
2. Description of Cache I/M Programs .......................................................................................................................... 1 5
3. I/M SIP Implementation ............................................................................................................................................ 2 6
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Section X Part F, Page iii
SECTION X Part F 1
Cache County Emission Inspection/ Maintenance Program 2
APPENDICES 3
4
5
1. Cache County Emission Inspection/ Maintenance Program Ordinance 2018-15 6
2. Bear River Health Department Regulation 2013-1 Updated July 1, 2024 7
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Section X Part F, Page 1
1
UTAH STATE IMPLEMENTATION PLAN 2
SECTION X, PART F 3
VEHICLE INSPECTION AND MAINTENANCE (I/M) PROGRAM 4
1. Applicability 5
6
Cache County I/M program requirements: Cache County was designated nonattainment for the 7
PM2.5 National Ambient Air Quality Standard (NAAQS) on December 14, 2009 (74 FR 58688, 8
November 13, 2009). Accordingly, Cache County implemented control strategies to attain the 9
PM2.5 NAAQS. A motor vehicle emission inspection and maintenance (I/M) program was 10
identified by the PM2.5 State Implementation Plan (SIP) as a necessary control strategy to attain 11
the PM2.5 NAAQS as expeditiously as practicable. Therefore, pursuant to Utah Code Annotated 12
41-6a-1642, Cache County implemented an I/M program that complies with the minimum 13
requirements of 40 CFR Part 51 Subpart S. Cache County implemented its I/M program county-14
wide. This program was approved by EPA on October 9, 2015 (80 FR 54237 September 9, 15
2019). Parts A and F of Section X demonstrate compliance with 40 CFR Part 51 Subpart S for 16
Cache County. 17
18
2. Description of Cache I/M Programs 19
20
Below is a summary of Cache County’s I/M program. Section X, Part F Appendices 1 and 2 21
contain the essential documents for Cache County’s I/M program. 22
23
Network Type: Cache County’s I/M program will comprise of a decentralized test-and-24
repair network. 25
26
Test Convenience: Cache County will make every effort to ensure that its citizens will 27
have stations conveniently located throughout Cache County. Specific operating hours 28
are not specified by the county; however, its Regulation requires that stations be open and 29
available to perform inspections during a major portion of normal business hours of 8:00 a.m. 30
to 5:00 pm Mondays through Fridays. 31
32
Subject fleet: All model year 1996 and newer vehicles registered or principally-operated 33
in Cache County are subject to the I/M program except for exempt vehicles. 34
35
Station/inspector Audits: Cache County’s I/M program will regularly audit all permitted 36
I/M inspectors and stations to ensure compliance with county I/M ordinances, 37
regulations, and policies. Particular attention will be given to identifying and correcting 38
any fraud or incompetence with respect to vehicle emissions inspections. Compliance 39
with recordkeeping, document security, analyzer maintenance, and program security 40
requirements will be scrutinized. The Cache County I/M program will have an active 41
covert compliance program to minimize potential fraudulent testing. 42

Section X Part F, Page 2

1
Waivers: Cache County’s I/M program allows for the issuance of waivers under limited 2
circumstances. The procedure for issuing waivers is specified in Cache County’s I/M 3
regulation provided in Section 9.5 of Appendix 2 of this part of the SIP and meets the 4
minimum waiver issuance criteria specified in 40 CFR Subparts 51.360. 5
6
Test frequency: Vehicles less than six years old as of January 1 on any given year will be 7
exempt from an emissions inspection. All model year 1996 and newer vehicles are 8
subject to a biennial test. 9
10
Test Equipment: Specifications for the I/M test procedures, standards and analyzers are 11
described in Cache County’s I/M regulation provided in Appendix 2. Specifications for 12
the test procedure and equipment were developed according to good engineering 13
practices to ensure test accuracy. Certified testing equipment and emissions test 14
procedures meet the minimum standards established in Appendix A of the EPA's I/M 15
Guidance Program Requirements, 40 CFR Part 51 Subpart S. 16
17
Test Procedures: 18
19
 The following vehicles are subject to an on-board diagnostic (OBD) II inspection: 20
21
o 1996 and newer light duty vehicles1 and 22
o 2008 and newer medium duty vehicles2 23
24
Test procedures are outlined in Appendix 2 of this part of the SIP 25
26
27
3. I/M SIP Implementation 28
29
The I/M program ordinance, regulations, policies, procedures, and activities specified in 30
this I/M SIP revision shall be implemented by [January 1, 2021] July 1, 2024 and shall 31
continue until a maintenance plan without an I/M program is approved by EPA in 32
accordance with Section 175 of the Clean Air Act. 33
34
35

1 Light duty vehicles have a Gross Vehicle Weight of 8500 lbs or less.
2 Medium duty vehicles have a Gross Vehicle Weight greater than 850[0]1 lbs but less than 14,000 lbs
1
Regulation No. 2013-1 2
VEHICLE EMISSIONS INSPECTION 3
AND MAINTENANCE PROGRAM 4
Adopted by the Bear River Board of Health 5
May 9, 2013 6
Updated May 27, 2015 7
Updated April 10, 2019 8
Updated January 5, 2023 9
Updated July 1, 2024 10
Under Authority of Section 26A-1-121 11
Utah Code Annotated, 1953, as amended 12
1 13
Table of Contents 1
1.0 DEFINITIONS......................................................................................................................3 2
2.0 PURPOSE.............................................................................................................................6 3
3.0 AUTHORITY AND JURISDICTION OF THE DEPARTMENT....................................... 6 4
4.0 POWERS AND DUTIES..................................................................................................... 7 5
5.0 SCOPE..................................................................................................................................9 6
6.0 GENERAL PROVISIONS................................................................................................... 9 7
7.0 PERMIT REQUIREMENTS OF THE VEHICLE EMISSIONS I/M PROGRAM 8
STATION....................................................................................................................................... 9
14 10
8.0 TRAINING AND CERTIFICATION OF INSPECTORS..................................................15 11
9.0 INSPECTION PROCEDURE............................................................................................ 17 12
10.0 ENGINE SWITCHING......................................................................................................20 13
11.0 SPECIFICATIONS FOR CERTIFIED TESTING EQUIPMENT..................................... 21 14
12.0 QUALITY ASSURANCE..................................................................................................21 15
13.0 DISCIPLINARY PENALTIES AND RIGHT TO APPEAL..............................................21 16
14.0 PENALTY...........................................................................................................................23 17
15.0 SEVERABILITY................................................................................................................23 18
16.0 EFFECTIVE DATE............................................................................................................24 19
APPENDIX A – FEE SCHEDULE...............................................................................................25 20
APPENDIX B - RESERVED........................................................................................................ 21
26 22
APPENDIX C – PENALTY SCHEDULE.................................................................................... 23
27 24
APPENDIX D – TEST PROCEDURES....................................................................................... 25
28 26
APPENDIX E – CERTIFIED TESTING EQUIPMENT STANDARDS......................................34 27
APPENDIX F – WAIVERS FOR “NOT READY” VEHICLES..................................................37 28
1.0 DEFINITIONS 29
For the purpose of this Regulation, the following terms, phrases, and words shall have the 30
following meanings, unless otherwise defined: 31
Alternative Fuel: A fuel that is derived from resources other than petroleum. This 32
includes but is not limited to: natural gas, propane, ethanol, and bio-diesel. 33
Bi-fuel Vehicle: A vehicle that has two separate fueling systems that enables the 34
vehicle to run on one or the other (ex. Gasoline and natural gas). These vehicles 35
may be switchable or non-switchable. 36
Board: See Board of Health. 1
Board of Health: The Bear River Board of Health. 2
Cache County Council: The elected Cache County Council representatives. 3
Certificate of Compliance: Proof that a vehicle meets all applicable requirements 4
of the I/M Program. This proof may be sent in an electronic format to the Utah 5
State Tax Commission. 6
Certification: Assurance by an authorized source, whether it be a laboratory, the 7
manufacturer, the State, or the Department, that a specific product or statement is 8
in fact true and meets all required requirements. 9
Certified Emissions Inspector: A person who has successfully completed all 10
certification requirements and has been issued a current, valid Certified Emissions 11
Inspector Certification by the Department. 12
Certified Testing Equipment: An official test instrument that has been approved by 13
the Department to test motor vehicles for compliance with this Regulation. 14
Compliance: Verification that certain submission data and hardware submitted by 15
a manufacturer for accreditation consideration, meets all required accreditation 16
requirements. 17
Compliance Assurance Inspection: A more detailed emissions inspection 18
performed at the I/M Technical Center. Details of this inspection are found in 19
Appendix D, Test Procedures. 20
Compliance Assurance List: A list created and maintained by the Department that 21
identifies vehicles for Compliance Assurance Inspections. Vehicles placed on this 22
list, as required in Section 6.8 and Appendix D, Test Procedures, shall be 23
inspected at the I/M Technical Center. 24
Contractor: The emission inspection system contractor selected by the Department 25
to provide specialized services related to the I/M Program in Cache County. 26
Council: See Cache County Council. 27
County: Cache County, Utah. 28
Department: The Bear River Health Department. 29
Director: The Director of the Bear River Health Department or his authorized 30
representative. 31
DLC: Data Link Connector used in OBD applications is a 16 pin connector used 1
by scan tools and other emission diagnostic equipment to communicate with the 2
vehicle’s computer for the purpose of collecting emissions related data. 3
DTC: Diagnostic Trouble Code is a standardized 5 digit code that is used to 4
identify a specific fault that has occurred or is occurring in a vehicle. 5
Dual Fuel Vehicle: See Flexible Fuel Vehicle. 6
Emissions Control Systems: Parts, assemblies or systems originally installed by 7
the manufacturer in or on a vehicle for the sole or primary purpose of reducing 8
emissions. 9
EPA: The United States Environmental Protection Agency. 10
Flexible Fuel Vehicle: Also called Flex-Fuel Vehicle. A vehicle that is designed to 11
run on more than one fuel, usually gasoline blended with ethanol (0-85%), and 12
both fuels are stored in the same common tank. 13
I/M Program: See Vehicle Emissions Inspection and Maintenance Program. 14
I/M Program Station: A vehicle Emissions Inspection and Maintenance Station 15
that qualifies and has a valid permit, issued by the Department, to operate as an 16
emissions inspection and maintenance station in the I/M Program. 17
I/M Technical Center: A facility operated by the Department for technical or 18
administrative support of the I/M Program. 19
Inspection: An official vehicle emissions test performed for the purpose of 20
issuing a Certificate of Compliance or Waiver. 21
Inspector: A Certified Emissions Inspector. 22
MIL: Malfunction Indicator Light is an indicator located on the instrument panel 23
that notifies the operator of an emissions fault. 24
Motor Vehicle: A self-propelled motorized vehicle with an internal combustion 25
powered engine which is licensed for operation on public roads and/or streets. 26
Motor Vehicles exempted from the inspection requirements of this Regulation are 27
listed in Section 6.4 of this Regulation. 28
Non-certified Inspector: Any person who has not been certified by the Department 29
to perform official emissions tests. 30
OBD: On Board Diagnostic refers to a vehicle’s monitoring and diagnostic 31
capabilities of its emissions systems. 32
Publicly-owned Vehicles: A motor vehicle owned by a government entity, 1
including but not limited to the federal government or any agency thereof, the 2
State of Utah or any agency or political subdivision thereof. 3
Readiness: Readiness is used to identify the state of a vehicle’s emissions 4
monitors as they are tested. Readiness does not indicate whether the monitors 5
passed or failed the test, it only indicates whether or not the test has been run for 6
any particular monitor. 7
Referee Inspection: An emissions inspection performed at the I/M Technical 8
Center for the purpose of resolving disputes or overriding inspection criteria for 9
cause. 10
Regulation: A regulation of the Bear River Health Department for a vehicle 11
emissions inspection and maintenance program. 12
Rejection: A condition where a vehicle subject to an OBD inspection has not met 13
the Readiness requirements as set forth by this Regulation. The vehicle has not 14
failed the inspection but it must be driven additional miles until Readiness 15
monitors are set “ready” or repairs have been made allowing readiness flags to set 16
ready. 17
Station: An I/M Program Station. 18
Training Program: A formal program administered, conducted, or approved by the 19
Department for the education of emission inspectors in basic emission control 20
technology, inspection procedures, I/M Program policies, procedures, and this 21
Regulation. 22
Vehicle Emission Control Information Label (VECI Label): An EPA required 23
label found on a vehicle that contains the manufacturer’s name and trademark, 24
and an unconditional statement of compliance with EPA emission regulations. 25
The label often contains a list of emissions control devices found on the vehicle. 26
Vehicle Emissions Inspection and Maintenance Program: The program established 27
by the Department pursuant to Section 41-6a-1642 Utah Code Annotated, 1953, 28
as amended, and Cache County Code Chapter 10.20. 29
Waiver: Documentation of proof that a vehicle which has not been able to meet 30
applicable test requirements, has met the applicable repair and/or adjustment 31
requirements of Section 9.5 of this Regulation. 32
2.0 PURPOSE 33
It is the purpose of this Regulation to reduce air pollution levels in Cache County by 34
requiring inspections of in-use motor vehicles and by requiring emission related repairs 35
and/or adjustments for those vehicles that fail to meet the prescribed standards so as to: 36
2.1 Protect and promote the public health, safety, and welfare; 1
2.2 Improve air quality; 2
2.3 Comply with the applicable federal requirements for I/M Programs as defined 3
in 40 CFR Part 51, Subpart S; 4
2.4 Comply with the law enacted by the Legislature of the State of Utah, Sections 5
416a-1642 Utah Code Annotated, 1953, as amended; and 6
2.5 Comply with Cache County Code Chapter 10.20, Vehicle Emissions and 7
Maintenance Program, as amended. 8
3.0 AUTHORITY AND JURISDICTION OF THE DEPARTMENT 9
3.1 Under Chapter 10.20.020(C) of Cache County Code, the Cache County Council 10
(hereafter, Council) delegates its authority as an administrative body under Section 41- 11
6a-1642, Utah Code Annotated, 1953, as amended, to the Bear River Board of Health 12
(hereafter Board), to address all issues pertaining to the adoption and administration of 13
the Vehicle Emissions Inspection and Maintenance Program (hereafter I/M Program). 14
3.2 Under Chapter 10.20.020(D) of Cache County Code, the Council directs the 15
Board to adopt and promulgate regulations to ensure compliance with State 16
Implementation Plan requirements with respect to an I/M Program. 17
3.3 The Board is authorized to make standards and regulations pursuant to Section 18
26A-1-121(1) of the Utah Code Annotated, 1953, as amended. 19
3.4 The Board is authorized to establish and collect fees pursuant to Section 26A-20
1114(1)(h)(i) of the Utah Code Annotated, 1953, as amended. 21
3.5 All aspects of the I/M Program within Cache County enumerated in Section 22
2.0 of this Regulation shall be subject to the direction and control of the Bear River 23
Health Department (hereafter Department). 24
4.0 POWERS AND DUTIES 25
4.1 The Department shall be responsible for the enforcement and administration of 26
this Regulation and any other powers vested in it by law and shall: 27
4.1.1 Make policies and procedures necessary to ensure that the provisions of 28
this Regulation are met and that the purposes of this Regulation are accomplished; 29
4.1.2 Require the submission of information, reports, plans, and 30
specifications from I/M Program Stations as necessary to implement the 31
provisions, requirements, and standards of this Regulation; 32
4.1.3 Issue permits, certifications, and charge fees as necessary to implement 1
the provisions, requirements, and standards of this Regulation; and 2
4.1.4 Perform audits of any I/M Program Station, issue orders and/or 3
notices, hold hearings, and levy administrative penalties, as necessary to effect 4
the purposes of this Regulation. 5
4.2 The Department may suspend, revoke, or deny a permit, subject to the 6
Penalty Schedule in Appendix C, of an I/M Program Station and/or require the 7
surrender of the permit of such I/M Program Station upon showing that: 8
4.2.1 A vehicle was inspected and issued a Certificate of Compliance by the 9
station personnel that did not, at the time of inspection, comply with all applicable 10
policies, procedures, and this Regulation; 11
4.2.2 A vehicle was inspected and failed by the I/M Program Station when, 12
in fact, the vehicle was determined by the Department to be in such condition that 13
it did comply with the requirements of this Regulation; 14
4.2.3 The I/M Program Station has violated any provisions of this 15
Regulation, or any rule, regulation, or Department policy properly promulgated 16
for the operation of an I/M Program Station; 17
4.2.4 The I/M Program Station is not operating from a location specified on 18
the permit; 19
4.2.5 An official inspection was done by a Non-certified Inspector or a 20
Noncertified Inspector has gained access to the official testing portion of the 21
Certified Testing Equipment; 22
4.2.6 The Certified Emissions Inspector logged in to the official testing 23
portion of the Certified Testing Equipment did not perform the inspection; 24
4.2.7 The Certified Testing Equipment has been tampered with or altered in 25
any way contrary to the certification and maintenance requirements of the 26
Certified Testing Equipment; 27
4.2.8 The I/M Program Station denies access to a representative of the 28
Department to conduct an audit or other necessary business during regular 29
business hours; 30
4.2.9 The I/M fee has been determined by the Department to be 31
discriminatory in that different fees are assessed dependent upon vehicle 32
ownership, vehicle make or model, owner residence, etc; or 33
4.2.10 The I/M Program Station that also contracts with the State of Utah as an 34
On the Spot Station renewed a vehicle registration without a valid Certificate of 35
Compliance for that vehicle. This is considered an intentional pass. 36
4.3 The Department may suspend, revoke, or deny the certificate of a Certified 1
Emissions Inspector, subject to the Penalty Schedule in Appendix C, and require the 2
surrender of this certificate upon showing that: 3
4.3.1 The Certified Emissions Inspector caused a Certificate of Compliance 4
to be issued without an approved inspection being made; 5
4.3.2 The Certified Emissions Inspector denied the issuance of a Certificate 6
of Compliance to a vehicle that, at the time of inspection, complied with the law 7
for issuance of said certificate; 8
4.3.3 The Certified Emissions Inspector issued a Certificate of Compliance 9
to a vehicle that, at the time of issuance, was in such a condition that it did not 10
comply with this Regulation; 11
4.3.4 Inspections were performed by the Certified Emissions Inspector, but 12
not in accordance with applicable policies, procedures, and this Regulation; 13
4.3.5 The Certified Emissions Inspector allowed a Non-certified Inspector to 14
perform an official Inspection or gain access to the official testing portion of the 15
Certified Testing Equipment; 16
4.3.6 The Certified Emissions Inspector logged in to the official testing 17
portion of the Certified Testing Equipment did not perform the inspection; 18
4.3.7 The Certified Emissions Inspector signed an inspection form or 19
certificate stating that he had performed the emissions test when, in fact, he did 20
not; or 21
4.3.8 The Certified Emissions Inspector employed at an I/M Program Station 22
that also contracts with the State of Utah as an On the Spot Station renewed a 23
vehicle registration without a valid Certificate of Compliance for that vehicle. 24
This is considered an intentional pass. 25
4.4 The Department shall respond, according to the policies and procedures of the 26
Department, to public complaints regarding the fairness and integrity of the inspections 27
they receive and shall provide a method that inspection results may be challenged if there 28
is a reason to believe them to be inaccurate. 29
5.0 SCOPE 30
It shall be unlawful for any person to fail to comply with any policy, procedure, or 31
regulation promulgated by the Department, unless expressly waived by this Regulation. 32
6.0 GENERAL PROVISIONS 1
Subject to the exceptions in Section 6.4 and pursuant to the schedule in Section 6.1, 2
motor vehicles that are registered in Cache County, or principally operated within Cache 3
County shall be subject to an emission inspection. Owners of vehicles that meet the 4
requirements of Section 6.2 or 6.3 shall comply with the inspection requirements 5
regardless of the county of registration. 6
6.1 Motor vehicles are subject to a biennial emissions inspection. Emissions 7
inspections will be required in odd-numbered years for a vehicle with an odd-numbered 8
model year. Emissions inspections will be required in even-numbered years for a vehicle 9
with an even-numbered model year. 10
6.1.1 A Certificate of Compliance, or evidence that the motor vehicle is 11
exempt from the I/M Program requirements (as defined in Section 6.4) shall be 12
presented to the Cache County Assessor or the Utah State Tax Commission as 13
conditions precedent to registration or renewal of registration of a motor vehicle 14
in oddnumbered years for a vehicle with an odd-numbered model year. Persons 15
who register a vehicle without meeting the requirements listed may be subject to 16
the penalties referenced in Section 14 of this Regulation. 17
6.1.2 A Certificate of Compliance, or evidence that the motor vehicle is 18
exempt from the I/M Program requirements (as defined in Section 6.4) shall be 19
presented to the Cache County Assessor or the Utah State Tax Commission as 20
conditions precedent to registration or renewal of registration of a motor vehicle 21
in evennumbered years for a vehicle with an even-numbered model year. Persons 22
who register a vehicle without meeting the requirements listed may be subject to 23
the penalties referenced in Section 14 of this Regulation. 24
6.1.3 The Air Pollution Control Fee shall be paid annually, as per Chapter 25
10.20.040(E) of Cache County Code, (see also Section 6.7 of this Regulation) as 26
conditions precedent to registration or renewal of registration of a motor vehicle. 27
6.1.4 A Certificate of Compliance shall be valid for a period of time in 28
accordance with Section 41-6a-1642(10) Utah Code Annotated, 1953, as 29
amended. 30
6.2 Publicly-Owned Vehicles. Owners of publicly-owned vehicles shall comply 31
with the inspection program requirements. Federally-owned vehicles and vehicles of 32
employees operated on a federal installation that do not require registration in the State of 33
Utah shall comply with the emissions testing requirements. 34
6.3 Vehicles of employees and/or students parked at a college or university that do 35
not require registration in Cache County shall comply with the emissions testing 36
requirements as authorized by 41-6a-1642(5)(a) Utah Code Annotated, 1953, as 37
amended. 38
6.3.1 College or university parking areas that are metered or for which 1
payment is required per use are not subject to the requirements in Section 6.3. 2
6.4 Vehicle Exemption. The following vehicles are exempt from these emissions 3
testing requirements: 4
6.4.1 An implement of husbandry as provided in Section 41-1a-102 Utah 5
Code Annotated, 1953, as amended; 6
6.4.2 A motor vehicle that meets the definition of a farm truck as provided in 7
Section 41-1a-102 Utah Code Annotated, 1953, as amended, and has a gross 8
vehicle weight rating of 12,001 pounds or more; 9
6.4.3 A vintage vehicle as defined in Section 41-21-1 Utah Code Annotated, 10
1953, as amended; 11
6.4.4 A custom vehicle as defined in Section 41-6a-1507 Utah Code 12
Annotated, 1953, as amended; 13
6.4.5 A pickup truck, as defined in Section 41-1a-102 Utah Code Annotated, 14
1953, as amended, with a gross vehicle weight rating of 12,000 pounds or less 15
that meets the requirements provided in Section 41-6a-1642(4)(f) Utah Code 16
Annotated, 1953, as amended; 17
6.4.6 A motorcycle as defined in Section 41-1a-102 Utah Code Annotated, 18
1953, as amended; 19
6.4.7 A motor vehicle powered solely by electric power; 20
6.4.8 Any gasoline or non-diesel based Alternative Fuel powered vehicle of 21
model year 1995 or older; 22
6.4.9 Any gasoline or non-diesel based Alternative Fuel powered vehicle, 23
with a gross vehicle weight rating greater than 8,500 pounds, and of model year 24
2007 or older; 25
6.4.10 Any gasoline or non-diesel based Alternative Fuel powered vehicle, with a 26
gross vehicle weight rating greater than 14,000 pounds, and of model year 2008 27
or newer; 28
6.4.11 Any vehicle that is less than six years old on January 1 based on the age of 29
the vehicle as determined by the model year identified by the manufacturer; 30
6.4.12 Any diesel or diesel based Alternative Fuel powered vehicle 1997 and 31
older; 32
6.4.13 Any diesel or diesel based Alternative Fuel powered vehicle with a gross 33
vehicle weight rating greater than 14,000 pounds; and 34
6.4.14 Any vehicle that qualifies for exemption under Section 41-6a-1642 Utah 1
Code Annotated, 1953, as amended; 2
6.4.15 Any current use “Authorized emergency vehicle” as defined by Section 3
41-6a-102 Utah Code Annotated,1953, as amended 4
6.5 If a vehicle exempted by Section 6.4 of this Regulation is brought to the Certified 5
Emissions Inspector for an official Inspection it shall be the responsibility of the Certified 6
Emissions Inspector to inform the owner/operator of the vehicle that the vehicle is not 7
required to have an official Inspection. 8
6.6 Official Signs. 9
6.6.1 All I/M Program Stations shall display in a conspicuous location on 10
the premises an official sign provided and approved by the Department; The 11
readiness requirements for an OBD test as referenced in Appendix D shall be 12
posted in a conspicuous place on the station’s premises; 13
6.6.2 The station shall post on a clear and legible sign and in a conspicuous 14
place at the station, the fees charged by that station for the performance of the 15
emissions inspection; 16
6.6.3 The free re-inspection policy as referenced in Section 9.4 shall be 17
posted in a conspicuous place on the station’s premises; 18
6.6.4 The signs required by Sections 6.6.1 through 6.6.4 shall be located so 19
as to be easily in the public view. 20
6.7 Fees. 21
6.7.1 The fees assessed upon I/M Program Stations and Certified Emissions 22
Inspectors shall be determined according to a fee schedule adopted by the Board. 23
The fee schedule is referenced in Appendix A to this Regulation and may be 24
amended by the Board as necessary. 25
6.7.2 An Air Pollution Control Fee is hereby assessed upon every motor 26
vehicle registered in Cache County as per Chapter 10.20.040 of Cache County 27
Code. The fee will be assessed annually at the time of registration of the vehicle. 28
6.7.2.1 This fee assessment is included upon all motorized vehicles 29
including those that are exempted from the inspection 30
requirements of this Regulation by Section 6.4. 31
6.7.2.2 A motor vehicle that is exempt from the registration fee, 32
and a commercial vehicle with an apportioned registration 33
shall be exempt from this fee as per Section 41-1a-1223, 34
Utah Code Annotated, 1953, as amended and Chapter 35
10.20.040 of Cache County Code. 36
6.7.3 I/M Program Stations may charge a fee for the required service. The fee 1
may not exceed, for each vehicle inspected, the amount set by the Board and 2
referenced in Appendix A of this Regulation. 3
6.7.3.1 The inspection fee pays for a complete inspection leading 4
to a Certificate of Compliance, a Rejection, or a failure. If 5
a vehicle fails, or is rejected from an inspection, the 6
owner/operator is entitled to one free re-inspection if he 7
returns to the I/M Program Station that performed the 8
original inspection within fifteen (15) calendar days from 9
the date of the initial inspection. The I/M Program Station 10
shall extend the fifteen day free re-inspection to 11
accommodate the vehicle owner/operator if the I/M 12
Program Station is unable to schedule the retest of the 13
vehicle within the fifteen day time period. The inspection 14
fee shall be the same whether the vehicle passes or fails the 15
emission test. 16
6.7.4 If a vehicle fails the inspection and is within the time and mileage 17
requirements of the federal emissions warranty contained in section 207 of the 18
Federal Clean Air Act, the Certified Emissions Inspector shall inform the 19
owner/operator that he may qualify for warranty coverage of emission related 20
repairs as provided by the vehicle manufacturer and mandated by the Federal 21
Environmental Protection Agency (see 40 CFR Part 85, Subpart V). 22
6.8 Compliance Assurance List. 23
6.8.1 The Department reserves the right to recall a vehicle and perform a 24
Compliance Assurance Inspection at the I/M Technical Center for the following 25
reasons: 26
6.8.1.1 Suspected fraudulent registration; 27
6.8.1.2 Suspected fraudulent emissions inspection; 28
6.8.1.3 Suspected tampering of emissions control devices; 29
6.8.1.4 Violations of Section 41-6a-1626, Utah Code Annotated, 1953, as 30
amended, regarding visible emissions; and 31
6.8.1.5 Any item listed in Appendix D, Test Procedures, that cause the 32
vehicle to be flagged during an emissions inspection. 33
6.8.2 The Department shall create and maintain a list of vehicles that are 34
subject to a Compliance Assurance Inspection at the I/M Technical Center. 35
6.8.2.1 The Compliance Assurance Inspection criteria listed in Appendix 1
D, Test Procedures, shall be followed. 2
6.8.2.2 A vehicle that passes the Compliance Assurance Inspection may be 3
removed from the Compliance Assurance List by Department personnel. 4
6.8.2.3 A vehicle that fails the Compliance Assurance Inspection may be 5
subject to penalties as described in Section 14 of this regulation. 6
7.0 PERMIT REQUIREMENTS OF THE VEHICLE EMISSIONS 7
I/M PROGRAM STATION 8
7.1 Permit Required. 9
7.1.1 No person shall in any way represent any place as an official I/M 10
Program Station unless the station is operated under a valid permit issued by the 11
Department. 12
7.1.2 The Department is authorized to issue or deny permits for I/M Program 13
Stations. 14
7.1.3 No permit for any official I/M Program Station may be assigned, 15
transferred, or used by any person other than the original owner identified on the 16
permit application for that specific I/M Program Station. 17
7.1.4 The permit shall be posted in a conspicuous place within public view 18
on the premises. 19
7.1.5 Application for an I/M Program Station permit shall be made to the 20
Department upon a form provided by the Department. No permit shall be issued 21
unless the Department finds that the facilities, and equipment of the applicant 22
comply with the requirements of this Regulation and that competent personnel, 23
certified under the provisions of Section 8.0, are employed and will be available 24
to make inspections, and the operation thereof will be properly conducted in 25
accordance with this Regulation. 26
7.1.5.1 An I/M Program Station shall notify the Department and 27
cease any emission testing if the station does not have a 28
Certified Emissions Inspector employed. 29
7.1.5.2 An I/M Program Station shall notify the Department upon 30
termination and/or resignation of any Certified Emissions 31
Inspector employed by the station. 32
7.1.5.3 An I/M Program Station shall comply with all the terms 33
stated in the permit application and all the requirements of 34
this Regulation. 35
7.1.5.4 An I/M Program Station shall provide a dedicated internet 1
connection for the Certified Testing Equipment. A wireless 2
internet connection may be required by the Contractor. 3
7.2 Permit Duration and Renewal 4
7.2.1 The permit for I/M Program Stations shall be issued annually and shall 5
expire on the last day of the month, one year from the month of issue. The permit 6
shall be renewable sixty days prior to the date of expiration. 7
7.2.2 It is the responsibility of the owner/operator of the I/M Program Station 8
to pursue the permit renewal through appropriate channels. 9
7.3 I/M Program Station to hold Department Harmless 10
7.3.1 In making application for a permit or for its renewal, such action shall 11
constitute a declaration by the applicant that the Department shall be held 12
harmless from liability incurred due to action or inaction of I/M Program Station’s 13
owners or their employees. 14
7.4 An I/M Program Station shall be kept in good repair and in a safe condition for 15
inspection purposes free of obstructions and hazards. 16
8.0 TRAINING AND CERTIFICATION OF INSPECTORS 17
8.1 Certified Emissions Inspector Certification Required. 18
8.1.1 No person shall perform any part of the inspection for the issuance of a 19
Certificate of Compliance unless the person possesses a valid Certified Emissions 20
Inspector Certification issued by the Department. 21
8.1.2 Applications for a Certified Emissions Inspector Certification shall be 22
made upon an application form prescribed by the Department. No certification 23
shall be issued unless: 24
8.1.2.1 The applicant has shown adequate competence by 25
successfully completing all portions of the Certified 26
Emissions Inspector Certification requirements as specified 27
in this Regulation; and 28
8.1.2.2 The applicant has paid the required permit fees as set by 29
the Board and referenced in Appendix A of this Regulation. 30
8.1.3 An applicant shall comply with all of the terms stated in the application 31
and with all the requirements of this Regulation. 32
8.1.4 An applicant shall complete a Department approved training course and 1
shall demonstrate knowledge and skill in the performance of emission testing and 2
use of the Certified Testing Equipment. Such knowledge and skill shall be shown 3
by passing at minimum: 4
8.1.4.1 Operation and purposes of emission control systems; 5
8.1.4.2 Inspection procedures as outlined in this Regulation and 6
prompted by the Certified Testing Equipment ; 7
8.1.4.3 Operation of the Certified Testing Equipment; 8
8.1.4.4 The provisions of Section 207(b) warranty provisions of 9
the Federal Clean Air Act, and other federal warranties; 10
8.1.4.5 The provisions of this Regulation and other applicable 11
Department policies and procedures; and 12
8.1.4.6 A performance qualification test including but not limited 13
to the following: 14
(a) Demonstration of skill in proper use, care, and 15
maintenance, of the Certified Testing Equipment; 16
(b) Demonstration of ability to conduct the inspection; and 17
(c) Demonstration of ability to accurately enter data in the 18
Certified Testing Equipment. 19
8.1.5 The Department shall issue a Certified Emissions Inspector 20
Certificate to an applicant upon successful completion of the requirements of 21
this section. 22
8.1.6 The Certified Emissions Inspector Certificates are and remain the 23
property of the Department, only their use and the license they represent is 24
tendered. 25
8.1.7 Certified Emissions Inspector Certifications shall not be transferred 26
from one person to another person. 27
8.2 Recertification Requirements for Certified Emissions Inspectors 28
8.2.1 The Department may renew certifications for an existing Certified 29
Emissions Inspector after a properly completed renewal form is submitted, 30
reviewed, and approved, the recertification requirements have been completed, 31
the fees are paid and the Certified Emissions Inspector has complied with this 32
Regulation. 33
8.2.2 Certified Emissions Inspectors shall be required to recertify annually. 1
Failure to recertify shall result in suspension or revocation of the Certification as 2
described in this Regulation. 3
8.2.3 Certified Emissions Inspectors shall complete a Department approved 4
refresher course every 2 years. Applicants for recertification shall complete a 5
Department approved refresher course no more than sixty days prior to the date of 6
expiration. 7
8.3 Certification Expiration 8
8.3.1 The Certified Emissions Inspector Certification shall be issued 9
annually and shall expire on the last day of the month one year from the month 10
of issue. The certification shall be renewable sixty days prior to the date of 11
expiration. 12
8.3.2 It is the responsibility of the Certified Emissions Inspector to pursue 13
the renewal of the Certification. 14
8.4 Certified Emissions Inspector Certification Denial, Suspension and Revocation 15
8.4.1 Certified Emissions Inspector Certifications may be suspended or 16
revoked by the Department for violations of this Regulation. 17
8.4.2 Suspension or revocation of Certified Emissions Inspector 18
Certifications shall follow the provisions of Appendix C of this Regulation. 19
8.4.3 The Department may deny issuance of a Certified Emissions Inspector 20
Certification to an individual that works as an emissions inspector in another 21
county in Utah and is currently under suspension or revocation in that program. 22
9.0 INSPECTION PROCEDURE 23
9.1 The official emissions inspection shall be solely performed by a Certified 24
Emissions Inspector at an I/M Program Station, and Department approved inspection 25
procedures, as referenced in this section and Appendix D, Test Procedures, are to be 26
followed. 27
9.2 A complete official test must be performed any time an inspection is requested. 28
The Certified Emissions Inspector shall not perform any part of the inspection without 29
initiating an official test on the Certified Testing Equipment. 30
9.3 The Certified Emissions Inspector shall perform the official vehicle emissions 31
test using the proper testing procedure. 32
9.3.1 All gasoline, and non-diesel based Alternative Fuel powered vehicles, 33
including Bi-Fuel vehicles, model year 1996 and newer, with a gross vehicle 34
weight rating 8,500 pounds or less, shall be tested as specified in Appendix D, 1
OBDII Test Procedures, unless specifically exempted by this Regulation. 2
9.3.2 All gasoline and non-diesel based Alternative Fuel powered vehicles, 3
including Bi-Fuel vehicles, model year 2008 and newer with a gross vehicle 4
weight rating greater than 8,500 pounds and less than 14,001 pounds shall be 5
tested as specified in Appendix D, OBDII Test Procedures, unless specifically 6
exempted by this Regulation. 7
9.3.3 All diesel and diesel based Alternative Fuel powered vehicles model 8
year 1998 and newer with a gross vehicle weight rating less than 14,001 pounds 9
shall be tested as specified in Appendix D, Diesel Test Procedures, unless 10
specifically exempted by this Regulation. 11
9.4 Retesting Procedures 12
9.4.1 If the vehicle fails the initial emissions inspection, the 13
owner/operator shall have fifteen calendar days in which to 14
have repairs or adjustments made and return the vehicle to 15
the I/M Program Station that performed the initial 16
inspection for one (1) free re-inspection. 17
9.4.2 If the vehicle is Rejected from the initial emissions 18
inspection for failure to complete Readiness requirements, 19
the owner/operator shall have fifteen calendar days in 20
which to return the vehicle to the I/M Program Station that 21
performed the initial inspection for one (1) free 22
reinspection. 23
9.4.3 If the vehicle owner/operator does not return to the I/M Program 24
Station that performed the initial inspection within fifteen calendar days the I/M 25
Program Station is under no obligation to offer a free re-inspection. 26
9.5 Waivers 27
9.5.1 A Waiver may be granted and a Certificate of Compliance issued for 28
1996 and newer model year vehicles if all of the following requirements are met: 29
9.5.1.1 Air pollution control devices identified in the VECI Label 30
are in place and apparently operable on the vehicle. If the 31
VECI Label is missing, the Department may use reference 32
material to identify the air pollution control devices 33
required for the vehicle. If the devices have been removed 34
or rendered inoperable, they shall be replaced or repaired 35
before a Waiver is granted; 36
9.5.1.2 The vehicle continues to fail the inspection after $200.00 1
has been spent on acceptable emissions related repair costs 2
for that specific vehicle, and proof of repair costs for that 3
specific vehicle have been provided to the Department in 4
the form of an itemized bill, invoice, work order, manifest, 5
or statement in which emissions related parts are 6
specifically identified. If repairs are made at a repair station 7
that employs individuals with current ASE L1, ASE A8, or 8
another certification approved by the Department, the cost 9
of labor may be included in the $200.00; 10
9.5.1.3 The vehicle is not within the time and mileage 11
requirements of the federal emissions warranties. Any 12
vehicle that is within time and mileage requirements of the 13
federal emissions warranties shall not be eligible for a 14
Waiver, but shall be repaired to pass the testing 15
requirements; and 16
9.5.1.4 A vehicle that is Rejected from the OBD Inspection may qualify 17
for a Waiver if it meets requirements set forth in 18
Appendix F, Waivers for “Not Ready” Vehicles. 19
9.5.2 As used in 9.5.1, acceptable emissions related repairs: 20
9.5.2.1 May include repairs performed up to 60 days prior to the 21
official emissions test, provided appropriate documentation 22
is supplied to the Department; 23
Diagnostic work performed, including Diagnostic Trouble 24
Codes if applicable, must be properly documented to 25
justify any repairs performed; 26
9.5.2.2 Does not include the fee paid for the test; 27
9.5.2.3 Does not include costs associated with the repairs or 28
replacements of air pollution control equipment on the 29
vehicle if the need for such adjustment, maintenance, 30
replacement, or repair is due to disconnection of, tampering 31
with, or abuse of the emissions control systems; 32
9.5.2.4 Refers to repairs, maintenance, and diagnostic evaluations 33
done in accordance with manufacturer’s specifications, to 34
the extent that the purpose is to reduce emissions; 35
9.5.2.5 Repairs performed on OBD compliant vehicles should be 36
directly related to the diagnostic trouble codes identified by 37
the vehicle and by further diagnostic tests on the vehicle; 38
9.5.2.6 Does not include parts replaced on OBD compliant 1
vehicles that cannot be justified through diagnostic trouble 2
codes or further diagnostic tests on the vehicle. 3
9.5.3 A Waiver shall only be issued by the Department. A Waiver shall only 4
be issued after determining that the vehicle complies with the requirements of this 5
Section. 6
9.5.4 A Waiver shall only be issued once to any vehicle that qualifies, 7
throughout the lifetime of the vehicle. 8
9.5.5 A vehicle must meet the requirements of Section 41-6a-1626, Utah 9
Code Annotated 1953, as amended, regarding visible emissions in order to qualify 10
for a Waiver. 11
9.6 The Department shall explore new technologies related to emissions 12
inspections. As part of this exploration the Department may perform studies, run pilot 13
projects, collect and analyze data, and make recommendations to the Board. If a new 14
technology can be shown to be as effective as current technologies in reducing emissions 15
and preventing fraud, the Department shall present these findings to the EPA. The 16
Department shall then work with the EPA, the Board, and the Council to seek approval to 17
incorporate the new technology as a testing method. 18
10.0 ENGINE SWITCHING 19
10.1 Engine switching shall be allowed only in accordance with EPA policy, as 20
detailed in EPA’s Engine Switching Fact Sheet, dated March 13, 1991, and EPA’s 21
Addendum to Mobile Source Enforcement Memorandum 1A, dated September 4, 1997. 22
10.2 Vehicles subject to an emissions inspection, as referenced in Section 6.0 of this 23
Regulation, that do not meet the requirements of Section 10.1 shall be deemed as 24
tampered and are not eligible for a Waiver, unless they are restored to the original engine 25
and emission control configuration. 26
11.0 SPECIFICATIONS FOR CERTIFIED TESTING EQUIPMENT 27
11.1 Approval of Certified Testing Equipment 28
11.1.1 Certified Testing Equipment shall meet the specifications as detailed in 29
Appendix E. 30
11.1.2 It shall be illegal for any person to modify the hardware or software of 31
Certified Testing Equipment without approval by the Department and/or 32
Contractor. 33
11.1.3 It shall be illegal for any person to gain access to any Department or 1
Contractor controlled portions of Certified Testing Equipment without approval 2
by the Department and/or Contractor. 3
12.0 QUALITY ASSURANCE 4
12.1 A quarterly inspection shall be made by a representative of the Department to 5
verify compliance with this Regulation for each I/M Program Station. During the time of 6
the inspection by the Department, the Department’s representative shall have exclusive 7
access to the Certified Testing Equipment. Inspections may be performed utilizing 8
technology integrated into the Certified Testing Equipment. 9
12.2 An annual covert inspection and audit shall be made by a representative of the 10
Department to verify compliance with this Regulation for each I/M Program Station. 11
12.3 The Department may increase the frequency of inspections for I/M Program 12
Stations and/or Certified Emissions Inspectors if the Department receives information of 13
a violation of this Regulation. 14
12.4 The Department shall regularly monitor I/M Program Stations and/or Certified 15
Emissions Inspectors through inspection records and/or technology integrated into the 16
Certified Testing Equipment. 17
13.0 DISCIPLINARY PENALTIES AND RIGHT TO APPEAL 18
13.1 When the Department, or its representative(s), receives information of a 19
violation of any regulation contained herein which may result in a permit denial, 20
revocation, or suspension, the Department shall notify the affected entity, in writing, 21
informing the entity of the violation and penalties to be enforced. The affected entity may 22
request a hearing within ten calendar days of the Department giving notice of the 23
potential permit denial, revocation, or suspension. Only a written request for a hearing 24
shall be honored by the Department. No appeal may be made on a formal warning. 25
13.1.1 In considering the appropriate administrative action to be taken as 26
indicated in Appendix C, the Director shall consider the following: 27
13.1.1.1 whether the violation was unintentional or careless; 28
13.1.1.2 the frequency of the violation or violations; 29
13.1.1.3 the inspection and covert inspection history of the I/M 30
Program Station and the Certified Emissions Inspector; 31
13.1.1.4 whether the fault lies with the I/M Program Station or the 32
Certified Emissions Inspector. 33
13.1.2 After consideration of the factors in Section 13.1.1 the Director may take 1
appropriate administrative action as indicated in Appendix C against either the 2
I/M Program Station, the Certified Emissions Inspector, or both. 3
13.2 Appeals Hearing Procedure: 4
13.2.1 An appeals hearing shall be held at the request of the affected entity in 5
order to determine the accuracy of information obtained by the Department and 6
whether there are mitigating factors which would justify a reduction of the 7
imposed penalties. 8
13.2.2 The requesting party may bring to the hearing any witnesses and any 9
evidence believed to be pertinent to the disciplinary action. 10
13.2.3 The appeal shall be heard by the Vehicle Inspection and Maintenance 11
Appeal Board, hereafter I/M Board, consisting of at least three persons, who are 12
not employees of Bear River Health Department, appointed by the Board. The 13
I/M Board shall have the discretion to determine which witnesses shall be heard 14
and what evidence is relevant. 15
13.2.4 Violations determined to be intentional or flagrant shall result in the 16
maximum enforcement of the penalty schedule pursuant to Appendix C. 17
13.2.5 In considering whether to reduce a penalty indicated by Appendix C, the 18
I/M Board and the Department shall consider the following: 19
13.2.5.1 whether the violation was unintentional or careless; 20
13.2.5.2 the frequency of the violation or violations; 21
13.2.5.3 the inspection and covert inspection history of the I/M 22
Program Station and the Certified Emissions Inspector; 23
13.2.5.4 whether the fault lies with the I/M Program Station, the 24
Certified Emissions Inspector, or both. 25
13.3 Written notice of the final determination of the I/M Board, including the I/M 26
Board’s finding under Section 14.2.5, shall be made within ten calendar days after the 27
conclusion of the appeals hearing. 28
14.0 PENALTY 29
14.1 Any person who is found guilty of violating any of the provisions of this 30
Regulation, either by failing to do those acts required herein or by doing a prohibited act, 31
shall be guilty of a class B misdemeanor pursuant to Section 26A-1-123, Utah Code 32
Annotated, 1953, as amended. If a person is found guilty of a subsequent similar 33
violation within two years, he shall be guilty of a class A misdemeanor pursuant to 1
Section 26A-1-123, Utah Code Annotated, 1953, as amended. 2
14.2 Each day such violation is committed or permitted to continue shall constitute 3
a separate violation. 4
14.3 The Cache County Attorney’s Office may initiate legal action, civil or 5
criminal, requested by the Department to abate any condition that exists in violation of 6
this Regulation. 7
14.4 In addition to other penalties imposed by a court of competent jurisdictions, 8
any person(s) found guilty of violating any of this Regulation shall be liable for all 9
expenses incurred by the Department. 10
14.5 A Penalty Schedule for permit warning, suspension, or revocation is adopted as 11
Appendix C and may be amended by the Board as the Board deems necessary to 12
accomplish the purposes of this Regulation. 13
14.6 The Department shall request that the Utah Division of Motor Vehicles 14
suspend or revoke a registered vehicle’s registration if the vehicle is unable to meet 15
emissions standards or if the vehicle has not complied with the required emission testing 16
requirements pursuant to Section 41-1a-110(6), Utah Code Annotated, 1953, as amended. 17
15.0 SEVERABILITY 18
If any provision, clause, sentence, or paragraph of this Regulation or the application 19
thereof to any person or circumstances shall be held to be invalid, such invalidity shall 20
not affect the other provisions or applications of this Regulation. The valid part of any 21
clause, sentence, or paragraph of this Regulation shall be given independence from the 22
invalid provisions or application and to this end the provisions of this Regulation are 23
hereby declared to be severable. 24
16.0 EFFECTIVE DATE 25
This Regulation shall become effective on July 1, 2024 as adopted by the Bear River Board 26
of Health. 27
28
Executive Director/Health Officer 29
Bear River Health Department 30
APPENDIX A - FEE SCHEDULE 1
Permitting of an official I/M Program Station $250.00
Annual Renewal of I/M Program Station $50.00
Expired I/M Program Station Renewal $75.00
I/M Program Station Re-location $75.00
Permitting of a Certified Emissions Inspector $25.00
Renewal of Certified Emissions Inspector $15.00
Expired Certified Emissions Inspector Renewal $25.00
Official Station Sign Cost
APC Fee for 12 month registration $3.00
APC Fee for 6 month registration $2.25
Emissions Inspection Fee – OBD Test Market
Emissions Inspection Fee –Tampering Market
2
APPENDIX B - RESERVED 1
APPENDIX C - PENALTY SCHEDULE 1
Violation
(resets after 2 years of no
similar violations unless
revoked)
1st Occurrence 2nd Occurrence 3rd Occurrence 4th Occurrence
Failure to inspect
or substituting a
vehicle other than
the vehicle on the
test record –
Registering a
failing vehicle
(intentional pass)
Tech: 180 day
suspension and
mandatory retraining
Tech: Revocation of
permit for up to 5 years

Station: 180 day
suspension Station: 270 day
suspension Station: Revocation of
inspection station permit
for up to 5 years

Passing a failing
vehicle or
recording pass for
Tech: 30 day suspension
and mandatory
retraining Tech: 60 day suspension
and mandatory retraining Tech: Revocation of
permit for up to 5 years

Station: 15 day Station: 30 day Station: 60 day Station: Revocation of
tampering on a
tampered vehicle
(gross negligence)
suspension suspension suspension permit for up to 5 years
Falsifying an
inspection record
or emissions
certificate or
Failing a passing
vehicle
(intentional)
Tech: 180 day
suspension and
mandatory retraining
Tech: Revocation of
permit for up to 5 years

Station: 180 day
suspension Station: 270 day
suspension Station: Revocation of
inspection station permit
for up to 5 years

Non-certified
person performing
test – Using
Tech: 60 day suspension Tech: 180 day
suspension Tech: Revocation of
permit for up to 5 years

Station: 60 day Station: 180 day Station: Revocation of
another inspector’s
access
(gross negligence
table)
suspension suspension inspection station permit
for up to 5 years
Inaccurate or
incomplete data
entry
Tech: Formal warning
and mandatory
retraining Tech: 30 day suspension
and mandatory retraining
Tech: 90 day suspension
and mandatory
retraining Tech: Revocation of
permit for up to 5 years
Station: Formal warning Station: 15 day Station: 45 day Station: Revocation of
(incompetence) suspension suspension inspection station permit
for up to 5 years
Failure to follow
proper test
procedures – Other
Tech: Formal warning
and mandatory
retraining Tech: 30 day suspension
and mandatory retraining
Tech: 90 day suspension
and mandatory
retraining Tech: Revocation of
permit for up to 5 years
Station: Formal warning Station: 15 day Station: 45 day Station: Revocation of
regulation
violations
(incompentence)
suspension suspension inspection station permit
for up to 5 years
2
APPENDIX D - TEST PROCEDURES
OBDII Test Procedures for gasoline and non-diesel based Alternative Fuel powered
vehicles
1 The Certified Emissions Inspector shall verify the following items from the vehicle and
accurately record them in the Certified Testing Equipment:
1.1 Vehicle Identification Number (VIN)
1.2 Gross Vehicle Weight Rating (GVWR)
1.3 Model year
1.4 Make
1.5 Model
1.6 Fuel Type
1.7 Engine size
1.8 Number of cylinders
1.9 Certification standard (EPA or California)
2 The Certified Emissions Inspector shall visually examine the instrument panel to
determine if the Malfunction Indicator Light (MIL) illuminates, at least briefly, when the
ignition key is turned to the “key on, engine off” (KOEO) position. The visual result shall
be accurately recorded in the Certified Testing Equipment.
3 The Certified Emissions Inspector shall locate the Diagnostic Link Connector (DLC) on
the vehicle being tested. The vehicle should be connected to the Certified Testing
Equipment when prompted.
3.1 If the DLC is missing, has been tampered with, or is otherwise inoperable, the vehicle fails
the test and shall be repaired.
3.2 If the DLC is inaccessible, the problem must be remedied before the test can continue.
4 When prompted by the Certified Testing Equipment the Certified Emissions Inspector
should start the engine so the vehicle is in the “key on, engine running” (KOER)
condition and follow the screen prompts until the test is complete.
5 For 1996-2000 model year vehicles two (2) supported readiness monitors are allowed to
be “not ready”. For 2001 and newer vehicles one (1) supported readiness monitor is
allowed to be “not ready”. If the “not ready” status exceeds these numbers the vehicle
must be driven additional miles or have appropriate repairs made.
5.1 A vehicle that fails the initial inspection for a catalyst related fault (i.e., P0420P0439) must
have the catalyst monitor set to “ready” upon re-inspection.
6 If the MIL is commanded on while the engine is running, regardless of the presence of
Diagnostic Trouble Codes (DTC), the vehicle will fail the test and will require repairs.
7 Certain vehicles have been determined to be OBDII deficient. The Certified Testing
Equipment software will maintain a list of these vehicles and perform a modified OBDII
test.
8 A vehicle must meet the requirements of Section 41-6a-1626, Utah Code Annotated
1953, as amended, regarding visible emissions in order to qualify for a Certificate of
Compliance.
9 Certain vehicles will be flagged by the testing software during the inspection and may be
recalled to the I/M Technical Center for a Compliance Assurance Inspection. Vehicles
will be flagged for the following items:
9.1 Mismatch between entered VIN and OBD VIN;
9.2 Any of the following readiness monitors being unsupported: Misfire, fuel system,
component, catalyst, and/or oxygen sensor;
9.3 A change in supported readiness monitors since the last inspection;
9.4 A change in communication protocol since the last inspection;
9.5 A change in OBD VIN since the last inspection;
9.6 The presence of an OBD VIN in a vehicle that does not support OBD VINs;
9.7 The absence of an OBD VIN in a vehicle that supports OBD VINs; or
9.8 A change in PID count since the last inspection.
10 Certain vehicles might not communicate with the Certified Testing Equipment. These
vehicles will be referred to the I/M Technical Center for a Referee Inspection.
11 A vehicle owner/operator that challenges the results of an official emissions inspection
may request a Referee Inspection at the I/M Technical Center.
Diesel and diesel based Alternative Fuel Powered Vehicles Test Procedures
All diesel powered vehicles 2007 and newer, with a gross vehicle weight rating less than 14,001
pounds, shall be tested as follows:
1 The Certified Emissions Inspector shall verify the following items from the vehicle and
accurately record them in the Certified Testing Equipment:
1.1 Vehicle Identification Number (VIN)
1.2 Gross Vehicle Weight Rating (GVWR)
1.3 Model year
1.4 Make
1.5 Model
1.6 Fuel Type
1.7 Engine size
1.8 Number of cylinders
1.9 Certification standard (EPA or California)
2 The Certified Emissions Inspector shall visually examine the instrument panel to
determine if the Malfunction Indicator Light (MIL) illuminates, at least briefly, when the
ignition key is turned to the “key on, engine off” (KOEO) position. The visual result shall
be accurately recorded in the Certified Testing Equipment.
3 The Certified Emissions Inspector shall locate the Diagnostic Link Connector (DLC) on
the vehicle being tested. The vehicle should be connected to the Certified Testing
Equipment when prompted.
3.1 If the DLC is missing, has been tampered with, or is otherwise inoperable, the vehicle fails
the test and shall be repaired.
3.2 If the DLC is inaccessible, the problem must be remedied before the test can continue.
4 When prompted by the Certified Testing Equipment the Certified Emissions Inspector
should start the engine so the vehicle is in the “key on, engine running” (KOER)
condition and follow the screen prompts until the test is complete.
5 Two supported readiness monitors are allowed to be “not ready”. If the “not ready” status
exceeds these numbers the vehicle must be driven additional miles or have appropriate
repairs made.
5.1 A vehicle that fails the initial inspection for a catalyst related fault (i.e., P0420P0439) must
have the catalyst monitor set to “ready” upon re-inspection.
6 If the MIL is commanded on while the engine is running, regardless of the presence of
Diagnostic Trouble Codes (DTC), the vehicle will fail the test and will require repairs.
7 Certain vehicles have been determined to be OBDII deficient. The Certified Testing
Equipment software will maintain a list of these vehicles and perform a modified OBDII
test.
8 A vehicle must meet the requirements of Section 41-6a-1626, Utah Code Annotated
1953, as amended, regarding visible emissions in order to qualify for a Certificate of
Compliance.
9 Certain vehicles will be flagged by the testing software during the inspection and may be
recalled to the I/M Technical Center for a Compliance Assurance Inspection. Vehicles
will be flagged for the following items:
9.1 Mismatch between entered VIN and OBD VIN;
9.2 Any of the following readiness monitors being unsupported: Misfire, fuel system,
component, NMHC, and/or NOx/SCR;
9.3 A change in supported readiness monitors since the last inspection;
9.4 A change in communication protocol since the last inspection;
9.5 A change in OBD VIN since the last inspection;
9.6 The absence of an OBD VIN; or
9.7 A change in PID count since the last inspection.
10 Diesel powered vehicles shall be subject to a visual anti-tampering inspection. The air
pollution control devices identified in the Vehicle Emissions Control Information (VECI)
label shall be in place and apparently operable on the vehicle. If the decal is missing,
reference material may be used to identify the air pollution control devices required for
the vehicle.
11 Certain vehicles might not communicate with the Certified Testing Equipment. These
vehicles will be referred to the I/M Technical Center for a Referee Inspection.
12 A vehicle owner/operator that challenges the results of an official emissions inspection
may request a Referee Inspection at the I/M Technical Center.
All diesel powered vehicles 1998-2006, with a gross vehicle weight rating less than 14,001
pounds, shall be tested as follows:
1 The Certified Emissions Inspector shall verify the following items from the vehicle and
accurately record them in the Certified Testing Equipment:
1.1 Vehicle Identification Number (VIN)
1.2 Gross Vehicle Weight Rating (GVWR)
1.3 Model year
1.4 Make
1.5 Model
1.6 Fuel Type
1.7 Engine size
1.8 Number of cylinders
1.9 Certification standard (EPA or California)
2 Diesel powered vehicles shall be subject to a visual anti-tampering inspection. The air
pollution control devices identified in the Vehicle Emissions Control Information (VECI)
label shall be in place and apparently operable on the vehicle. If the decal is missing,
reference material may be used to identify the air pollution control devices required for the
vehicle.
3 A vehicle must meet the requirements of Section 41-6a-1626, Utah Code Annotated 1953,
as amended, regarding visible emissions in order to qualify for a Certificate of Compliance.
4 If the OBDII System is identified on the VECI label, the procedure in Section 2 through 5
shall be followed.
4.1 An inspection of the OBDII System shall be for informational purposes only and will not
determine whether a vehicle passes or fails the emission inspection.
Compliance Assurance Inspection
1 A vehicle that is referred to the I/M Technical Center for a Compliance Assurance Inspection
shall be subject to an official emissions inspection. A visual anti-tampering inspection shall
also be included in every Compliance Assurance Inspection. The air pollution control devices
listed in the Vehicle Emissions Control Information (VECI) label shall be in place and
apparently operable on the vehicle. If the VECI label is missing, reference material may be
used to identify the air pollution control devices required for the vehicle.
1.1 A vehicle that has missing or tampered air pollution control devices will fail the
Compliance Assurance Inspection and will not be issued a Certificate of
Compliance.
1.2 A vehicle that has missing or tampered air pollution control devices and has
already been issued a Certificate of Compliance will be required to replace or
repair the devices. Owners/operators of vehicles that do not comply will be subject
to the penalties in this Regulation.
2 The Department will use data obtained by the Utah Division of Motor Vehicles and
inspection data to determine if a vehicle should be subject to a Compliance Assurance
Inspection.
3 The owner/operator of a vehicle subject to a Compliance Assurance Inspection will be
notified in writing of the requirement to present the vehicle for inspection.
Referee Inspection
1 Vehicles may be referred to the I/M Technical Center for a Referee Inspection. During a
Referee Inspection the Department may override the normal testing criteria and issue a
Certificate of Compliance for the following reasons:
1.1 The vehicle will not communicate with the Certified Testing Equipment but will
communicate with other scan tools. The vehicle must meet all other testing requirements
including readiness status and MIL status; or
1.2 The vehicle has met the criteria to be issued a Waiver.
2 A Referee Inspection may also be performed when an owner/operator believes the emissions
inspection performed at an I/M Program Station was not done correctly.
APPENDIX E - CERTIFIED TESTING EQUIPMENT STANDARDS
1 General
This appendix contains specifications for Contractors to design Certified Testing
Equipment to be used in the Cache County I/M Program.
1.1 Design Goals
Certified Testing Equipment must be designed and constructed to provide reliable and
accurate service in the automotive service environment. The software must be designed
for maximum operational simplicity. The software must prevent users from clearing
Diagnostic Trouble Codes (DTC), changing readiness status, or performing other actions
that could change the results of an official emissions test. In addition, the Certified
Testing Equipment must include security measures that will prevent unauthorized
modifications to the software or inspection data.
These technical specifications contain the minimum requirements for Certified Testing
Equipment used to perform official emissions inspections in Cache County, UT.
1.2 Manuals
All Certified Testing Equipment sold or leased by the Contractor must be provided with a
current copy of a manual that contains, at a minimum, operating instructions,
maintenance instructions, and initial startup instructions. The manual may be provided in
electronic format and shall be accessible from the Certified Testing Equipment.
1.3 Warranty Coverage and Extended Service Agreements
A written warranty coverage agreement, signed by an authorized representative of the
Contractor and the I/M Program Station, which provides a complete description of
coverage for all systems and components and all Contractor provided services listed
below in Contractor Provided Services, must accompany the sale or lease of each unit of
Certified Testing Equipment.
The Contractor shall provide a minimum of one-year warranty coverage on each unit of
Certified Testing Equipment sold or leased. The one-year warranty coverage shall begin
on the date of purchase and shall be included in the unit pricing for the Certified Testing
Equipment. An extended warranty shall be made available to the I/M Program Stations
that purchase or lease Certified Testing Equipment.
1.4 Contractor Provided Services
The Contractor shall provide the following services to the I/M Program Station as part of
any sale, lease, or loan of Certified Testing Equipment:
- Delivery, set-up, and verification of proper functionality of the Certified
Testing Equipment; and
- Training on the use and maintenance of the Certified Testing Equipment.
The Contractor shall provide the following services to the I/M Program Station during the
initial one-year warranty coverage period and thereafter to any I/M Program Station that
purchases an extended warranty:
- Full system support and repair as detailed in the warranty coverage agreement;
and
- Appropriate service response, either on-site or remote, by a Contractor
authorized repair technician within one business day (Saturday shall be
considered a business day), excluding Sundays, and national/state holidays
(New Year’s Day, Human Rights Day, President’s Day, Memorial Day,
Independence Day, Pioneer Day, Labor Day, Veteran’s Day, Thanksgiving,
and Christmas), of a request from the I/M Program Station. All system repairs,
component replacements, and/or Certified Testing Equipment adjustments
must be accomplished within a minimum average response time of 8 business
hours after a service request has been initiated. If the completion of this work
is not possible within this time period, Certified Testing Equipment of equal
quality and specifications must be provided until the malfunctioning unit is
properly repaired and returned to service.
1.5 Tamper Resistance
The Certified Testing Equipment operators, Department personnel, and Contractor
authorized service technicians shall be prevented from changing any inspection results,
programs, or data contained on the Certified Testing Equipment. The Contractor shall
use appropriate software and/or hardware provisions to protect files and programs.
2 – Hardware/Software Requirements
2.1 Accessing the OBD System
The Certified Testing Equipment must include hardware and software necessary
to access the on-board computer systems of vehicles subject to OBD inspections.
This includes the following:
- 1996 and newer gasoline and non-diesel based alternative fuel vehicles with a
gross vehicle weight rating of 8,500 pounds or less
- 2008 and newer gasoline and non-diesel based alternative fuel vehicles with a
gross vehicle weight rating of 14,000 pounds or less
- 2007 and newer diesel and diesel based alternative fuel vehicles with a gross
vehicle weight rating of 14,000 pounds or less
The Certified Testing Equipment shall be compliant with the recommended
practices regarding OBD inspections contained in J1962, J1978, and J1979 as
published by the Society of Automotive Engineers (SAE). The Certified Testing
Equipment must be able to connect to the vehicle’s data link connector (DLC) and
access, at a minimum, the following OBD data:
- Service modes $01, $03, $06, $07, $09, $0A
The Certified Testing Equipment must be capable of communicating with all
OBD vehicles that use, at a minimum, the following communications protocols:
- International Organization for Standardization (ISO) 9141
- Variable Pulse Width (VPW)
- Pulse Width Modulation (PWM)
- Keyword Protocol 2000 (KWP)
- Controller Area Network (CAN)
2.2 Barcode Scanner
The Certified Testing Equipment must include a bar code scanner capable of
reading both 1D and 2D barcodes. The bar code scanner must be able to read the
barcode through a windshield. The barcode scanner must be able to withstand
multiple 6.5 foot (2 meter) drops to concrete and be environmentally sealed to
withstand the normal operating conditions of an automotive service environment.
The bar code scanner may be a stand alone device or may be integrated into the
Certified Testing Equipment.
2.3 Camera
Certified Testing Equipment shall be equipped with video capturing equipment.
The video capturing equipment must capture video from each official emissions
inspection.
APPENDIX F - WAIVERS FOR "NOT READY" VEHICLES
A vehicle owner may be eligible for a Waiver when their gasoline powered vehicle is “Not
Ready” and the following conditions are met:
1 The vehicle is not subject to a modified OBDII test because of OBD deficiencies;
2 The vehicle has an official test performed showing a “Not Ready” status. The MIL is
functioning properly and is not commanded on. No pending codes are stored in the vehicle’s
computer.
3 A second inspection has been performed showing the following:
3.1 Readiness monitors have not changed from “Not Ready” to “Ready”;
3.2 The test dates are separated by at least 7 days and the vehicle has traveled a
minimum of 200 miles;
3.3 The MIL is functioning properly and is not commanded on. No pending codes are
stored in the vehicle’s computer; and
3.4 A statement is included from a repair station, stating the appropriate diagnostics and
manufacturer recommended drive cycles have been performed and the readiness
monitors have not been set.
4 A third inspection has been performed by a second repair station showing the following:
4.1 Readiness monitors have not changed from “Not Ready” to “Ready”;
4.2 The initial and third test dates are separated by at least 14 days and the vehicle has
traveled a minimum of 400 miles;
4.3 The MIL is functioning properly and is not commanded on. No pending codes are
stored in the vehicle’s computer; and
4.4 A statement is included from a repair station, stating the appropriate diagnostics and
manufacturer recommended drive cycles have been performed and the readiness
monitors have not been set.
5 At least one of the statements must come from the vehicle manufacturer’s dealership repair
station. This statement must indicate that the appropriate drive cycles and diagnostics have
been performed and the vehicle will not reach a “Ready” status. The dealership must also
document that the vehicle’s computer is up to date and functioning properly. The computer
must be updated if required or recommended by the manufacturer. If the computer is updated
the vehicle must complete the appropriate drive cycles following the update.
6 The cost requirements as set forth by this Regulation must be met in order to qualify for a
Waiver. In order to count labor the repair station must employ individuals with current ASE
L1, ASE A8, or other certifications approved by the Department.
APPENDIX G - WAIVERS FOR PART UNAVAILABILITY
A vehicle owner may be eligible for a “Parts” Waiver when their vehicle is unable to pass an
emissions test with a valid error code and the following conditions are met:
1. The vehicle is not subject to a modified OBDII test because of OBD deficiencies;
2. The vehicle has an official test, performed within the prior 30 days, showing a failing status.
3. The MIL is functioning properly. Pending and/or permanent codes are stored in the vehicle’s computer.
4. A written, signed statement is provided from an ASE certified, currently licensed I/M station stating the
part(s) are unavailable for a time exceeding six (6) months
5. A second, separate I/M Station meeting the above criteria issues a written and signed statement detailing the
part is unavailable for a time exceeding six (6) months.
6. At least one of the statements must come from the vehicle manufacturer’s dealership repair station. This
statement must indicate that the part is either backordered or out of production. The dealership must also
document that the vehicle’s computer is up to date and functioning properly.
The computer must be updated if required or recommended by the manufacturer.
Clean Air Act 110(l) Demonstration
Air Quality Impact of Amendment to
Bear River Health Department Inspection and Maintenance Program

UTAH DIVISION OF AIR QUALITY 1

Introduction

Section 110(l) of the Clean Air Act (CAA) states that the Environmental Protection Agency
(EPA) cannot approve a state implementation plan (SIP) revision if the revision would interfere
with any applicable requirement concerning attainment and reasonable further progress, or any
other applicable requirement of the CAA. When revisions to these rules are made, the CAA
requires that an analysis is made to verify that the rule will not be relaxed in a way that would be
impermissible under Section 110(l).

Additionally, EPA has given draft guidance that “For example, for certain pollutants such as CO,
the Agency could determine that an increase in emissions is not interfering with attainment if
ambient levels in an attainment area were well below the National Ambient Air Quality Standard
(NAAQS) and not trending upward. Under these conditions, the Agency could conclude that
ambient levels are so low that a slight emissions increase is not likely to cause a violation of the
NAAQS, hence noninterference has been demonstrated (p.12).” 1 The proposed amendments
impact such a small number of vehicle emissions within Cache County that it is not likely to
cause a violation.

This demonstration is being submitted for public comment because the Utah Division of Air
Quality is proposing amendments to Bear River Health Department’s Inspection and
Maintenance Program (I/M) to align with ordinance changes already approved by Bear River
Health Department’s Board of Health.

Proposed Amendment Summary

1. This change creates the addition of a Part Unavailability Waiver which would be utilized if a
vehicle part was unable to be obtained due to the following described circumstances. The
Bear River Health Department I/M may issue a waiver if it can be verified that the part in
question or one similar to it is no longer available for sale or unobtainable due to
manufacturing circumstances.

Air Quality Impact Analysis: This change might result in an additional 4-10 vehicle waivers
per year. Due to the small number of vehicles impacted, this change will have no noticeable
impact on air quality, air quality modeling for the SIP or attainment of the PM2.5 NAAQS

2. This change creates the addition of a Mobile Inspection Service option. The amendment
includes the deletion of the word “stationary” in the Bear River Health Department’s I/M
regulation. The new language in the I/M regulation states: "I/M Program Station: A vehicle

1 U.S. Environmental Protection Agency. (2005). Demonstrating noninterference under Section 110(l) of the Clean Air Act when revising a State
Implementation Plan (Draft).
Clean Air Act 110(l) Demonstration
Air Quality Impact of Amendment to
Bear River Health Department Inspection and Maintenance Program

UTAH DIVISION OF AIR QUALITY 2

Emissions I/M Station that qualifies and has a valid permit, issued by the Department, to
operate as an emissions inspection and maintenance station in the I/M Program."

Air Quality Impact Analysis: Modifying the I/M regulation to reflect this business innovation
has no impact on air quality. It improves the convenience of the inspection process for the
customer and may have a positive impact on air quality.

3. This change creates the addition of an exemption for emergency vehicles within the I/M
program. The new language in the I/M regulation within the Vehicle Exemption section states:
"Any current use “Authorized emergency vehicle” as defined by Section 41-6a-102 Utah Code
Annotated,1953, as amended". Codifying this exemption within the Bear River Health
Department I/M further allows for the emergency departments to exempt emergency vehicles
from inspection. This change is to address issues surrounding the availability of emergency
response vehicles in Cache County where the vehicle is running into performance issues. The
change is necessary to prevent the decommissioning of critical emergency response vehicles
when a part may not be accessed in a timely fashion.

Air Quality Impact Analysis: This exemption would impact approximately 102 vehicles within
Cache County. To put this number into context the total number of registered vehicles in
Cache County as of 2024 is 124,718. Due to the small number of vehicles impacted, this
change will have no noticeable impact on air quality, air quality modeling for the SIP or
attainment of the 24-hour PM2.5 NAAQS.

Table 1. PM2.5 values compared to the 24-hour PM2.5 NAAQS between 2015-2023.
Cache County Air Quality Monitor Data
24 hour PM2.5 Values
Year
Annual average
of 24-hour
PM2.5 value for
listed year
3 year DV centered on
listed year
2015 28.9 33.9
2016 34.0 32.9
2017 36.0 32.6
2018 27.9 33.0
2019 35.1 30.5
2020 28.6 32.4
2021 33.5 30.6
2022 29.9 33.8
2023 38.0 31.0

Clean Air Act 110(l) Demonstration
Air Quality Impact of Amendment to
Bear River Health Department Inspection and Maintenance Program

UTAH DIVISION OF AIR QUALITY 3

Conclusion: The proposed amendments to the Bear River Health Department I/M will not
impact the area's ability to maintain the PM2.5 NAAQS. Table 1 indicates that the design value in
Cache County has been consistently lower than the NAAQS over the last 8 years. The Cache
County monitor is not likely to be influenced by the minor amendment and is predicted to
continue to maintain the NAAQS. The ambient levels are so low that a slight emissions increase
is not likely to cause a violation of the NAAQS, hence noninterference has been demonstrated.

ITEM 5

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

Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor
DAQ-008-25
M E M O R A N D U M TO: Air Quality Board THROUGH: Bryce C. Bird, Executive Secretary THROUGH: Erica Pryor, Rules Coordinator FROM: Alan Humpherys, Minor New Source Review Section Manager DATE: January 22, 2025 SUBJECT: PROPOSE FOR FINAL ADOPTION: New Rule R307-209. Portable Aggregate
Processing Plants. __________________________________________________________________________________
The Utah Division of Air Quality (DAQ) currently issues approval orders to portable aggregate processing plants. These plants include nonmetallic mineral processing plants, hot mix asphalt plants, and concrete batch plants. These portable aggregate processing plants can temporarily relocate to locations throughout
the state under section R307-401-17. These sources must comply with the issued approval orders and temporary relocation letter. New rule R307-209 codifies the requirements in portable approval orders, and amendments to existing section R307-401-10 will allow these sources to temporarily relocate aggregate equipment without first obtaining an approval order. These rules will not add any new requirements to sources, but save sources the time and money from first obtaining a portable approval order. In addition, the new process will reduce DAQ staff time spent on this work. On November 6, 2024, the Utah Air Quality Board approved a 30-day public comment period for the proposed new rule. This public comment period ran from December 1, 2024, to December 31, 2024. A
public hearing was scheduled for December 18, 2024; however, no request was made to hold the hearing, and it was cancelled in accordance with 63G-3-302. No formal public comments were received during the public comment period; however, we did receive one internal comment from the ATLAS section and as
such, one minor change was made to the rule language.
DAQ-008-25 Page 2
Clarity was added to the rule to indicate that a temporary source would be required to comply with the applicable provisions of R307-801, Utah Asbestos Rule, if that rule applies. A source would be required to comply with R307-801 regardless of whether R307-209 has the applicability language; however, the DAQ wanted to make sure sources are aware of the requirements of R307-801 when operating a portable aggregate processing plant. No other changes were made to the proposed rule. Recommendation: Staff recommend the Board approve new rule R307-209, Portable Aggregate Processing Plants, as amended, for final adoption.
State of Utah
Administrative Rule Analysis
Revised May 2024

NOTICE OF SUBSTANTIVE CHANGE
TYPE OF FILING: CPR (Change in Proposed Rule)
Rule or Section Number: R307-209 Filing ID: Office Use Only
Date of Previous Publication (Only for CPRs): 12/01/2024

Agency Information
1. Title catchline: Environmental Quality, Air Quality
Building: Multi Agency State Office Building
Street address: 195 N 1950 W
City, state: Salt Lake City, UT
Mailing address: PO BOX 144820
City, state and zip: Salt Lake City, UT 84114-4820
Contact persons:
Name: Phone: Email:
Alan Humpherys 801-536-4142 [e-mail]
Erica Pryor 385-499-3416 [e-mail]

Please address questions regarding information on this notice to the persons listed above.

General Information
2. Rule or section catchline:
R307-209. Portable Aggregate Processing Plants.

3. Purpose of the new rule or reason for the change:
Rule R307-209 will allow portable aggregate sources to operate under a temporary relocation notice without first having
obtained an Approval Order. A minor change is being proposed after a 30-day public comment period.

4. Summary of the new rule or change:
Based on feedback received during a 30-day public comment period, one minor change is being proposed. A line indicating that
sources are required to comply with the applicable provisions of Rule R307-801, Utah Asbestos Rule. Sources were required to
comply with the applicable provisions of this rule before the change; however, the rule will specifically mention the rule to
provide clarity that sources are not exempt from Rule R307-801, Utah Asbestos Rule.

Fiscal Information
5. Provide an estimate and written explanation of the aggregate anticipated cost or savings to:
A) State budget:
The changes to this proposed rule will not add or remove any additional requirements and will not impact the state budget
because the changes are clarifying the originally intended meaning.

B) Local governments:
The changes to this proposed rule will not add or remove any additional requirements and will not impact local governments
because the changes are clarifying the originally intended meaning

C) Small businesses ("small business" means a business employing 1-49 persons):
The changes to this proposed rule will not add or remove any additional requirements and will not impact small businesses
because the changes are clarifying the originally intended meaning.

D) Non-small businesses ("non-small business" means a business employing 50 or more persons):
The changes to this proposed rule will not add or remove any additional requirements and will not impact non-small businesses
because the changes are clarifying the originally intended meaning.

E) Persons other than small businesses, non-small businesses, state, or local government entities ("person" means
any individual, partnership, corporation, association, governmental entity, or public or private organization of any character
other than an agency):
The changes to this proposed rule will not add or remove any additional requirements and will not impact persons other than
small businesses, non-small businesses, state, or local government entities because the changes are clarifying the originally
intended meaning.

F) Compliance costs for affected persons (How much will it cost an impacted entity to adhere to this rule or its changes?):
The changes to this proposed rule will not add or remove any additional requirements and will not cause any additional
compliance costs for affected persons because the changes are clarifying the originally intended meaning.

G) Regulatory Impact Summary Table (This table only includes fiscal impacts that could be measured. If there are
inestimable fiscal impacts, they will not be included in this table. Inestimable impacts will be included in narratives above.)
Regulatory Impact Table
Fiscal Cost FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Cost $0 $0 $0
Fiscal Benefits FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Benefits $0 $0 $0
Net Fiscal Benefits $0 $0 $0
H) Department head comments on fiscal impact and approval of regulatory impact analysis:
The Executive Director of the Department of Environmental Quality, Kim D. Shelley, has reviewed and approved this regulatory
impact analysis.

Citation Information
6. Provide citations to the statutory authority for the rule. If there is also a federal requirement for the rule, provide a
citation to that requirement:

U.S.C. Title 42 Chapter 85 Subchapter I
Part A Section 7410 (a)(1)2(A)

Incorporations by Reference Information
7. Incorporations by Reference (if this rule incorporates more than two items by reference, please include additional tables):
A) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

B) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

Public Notice Information
8. The public may submit written or oral comments to the agency identified in box 1. (The public may also request a
hearing by submitting a written request to the agency. See Section 63G-3-302 and Rule R15-1 for more information.)
A) Comments will be accepted until: Click or tap to enter a date.
B) A public hearing (optional) will be held:
Date (mm/dd/yyyy): Time (hh:mm AM/PM): Place (physical address or URL):
N/A CPR
To the agency: If more than one hearing will take place, continue to add rows.

9. This rule change MAY become effective on: 03/31/2025
NOTE: The date above is the date the agency anticipates making the rule or its changes effective. It is NOT the effective date.

Agency Authorization Information
To the agency: Information requested on this form is required by Sections 63G-3-301, 63G-3-302, 63G-3-303, and 63G-3-
402. Incomplete forms will be returned to the agency for completion, possibly delaying publication in the Utah State Bulletin
and delaying the first possible effective date.
Agency head or
designee and title:
Bryce C. Bird, Director, Division of Air
Quality
Date: 01/17/2025

R307. Environmental Quality, Air Quality. 1
R307-209. Portable Aggregate Processing Plants. 2
R307-209-1. Purpose. 3
Rule R307-209 establishes requirements for portable aggregate processing plants including 4
concrete batch plants, asphalt plants, and nonmetallic mineral processing plants. 5
6
R307-209-2. Definitions. 7
“Asphalt Plant” means any equipment used to produce, process, or store hot-mix, warm-mix, or 8
cold-mix asphalt and its ingredients. Equipment in this definition includes dryers, mixers, screens, 9
conveyors, storage bins or silos, storage tanks, and loading stations. 10
“Concrete Batch Plant” means any equipment used to produce, process, or store concrete and its 11
ingredients. Equipment in this definition includes mixers, screens, conveyors, storage bins or silos, and 12
loading stations. 13
“Nonmetallic Mineral Processing Plant” means any equipment used to produce, process, or store 14
nonmetallic minerals. Equipment in this definition includes crushers, grinding mills, screens, conveyors, 15
storage bins or silos, and loading stations. 16
“Portable Aggregate Processing Plant” means any nonmetallic mineral processing plant, asphalt 17
plant, or concrete batch plant that temporarily operates for a period of not more than 180 working days or 18
365 consecutive calendar days at a single source. Engines, boilers, and storage tanks used to support 19
concrete batch plants, asphalt plants, or nonmetallic mineral processing plants are included in this 20
definition. 21
22
R307-209-3. Applicability. 23
(1) Rule R307-209 applies to each portable aggregate processing plant including each concrete24
batch plant, asphalt plant, and nonmetallic mineral processing plant. 25
(2) Rule R307-209 does not apply to concrete batch plants, asphalt plants, or nonmetallic mineral26
processing plants that are subject to an approval order issued under Section R307-401-8. 27
(3) Rule R307-209 does not apply to a concrete batch plant, asphalt plant, or nonmetallic mineral28
processing plant that plans to or will operate at a single source longer than 180 operating days or remains 29
at a source longer than 365 calendar days. These sources shall submit a notice of intent and obtain an 30
approval order under Rule R307-401 before beginning actual construction unless the source qualifies for 31
an exemption under Section R307-401-9. 32
33
R307-209-4. Notice of Temporary Relocation. 34
(1) An owner or operator of a portable aggregate processing plant shall submit a Notice of35
Temporary Relocation to the director and obtain a Temporary Relocation Approval Letter before 36
operating a portable source at any location. 37
(2) A Notice of Temporary Relocation shall include the following:38
(a) the address and driving directions of the proposed location;39
(b) a list of the equipment to be operated at the proposed location, including the:40
(i) type of equipment;41
(ii) rated capacity of the equipment; and42
(iii) date of manufacture of the equipment;43
(c) a site diagram showing the general equipment location on site to scale; and44
(d) the distance to the nearest houses, barns, or commercial operations to scale if the plant45
boundary is located within one mile of these buildings; 46
(e) the expected startup and completion dates for operating at the proposed location;47
(f) the expected hours of operation, including start and stop times;48
(g) the emission control measures that the owner or operator proposes to adopt for each emission49
point at each location, including a fugitive dust control plan specific to the proposed location; and 50
(h) if relocating an asphalt plant, either:51
(i) the results and the date of the most recent stack test for the asphalt plant; or52
(ii) the anticipated stack test date and the stack test protocol for an asphalt plant that has not been53
stack tested. 54
Page 1 of 3
1
R307-209-5. Operations at a Temporary Location. 2
(1) An owner or operator of a portable aggregate processing plant may not exceed 180 working3
days and may not exceed 365 calendar days at a single location. 4
(2) An owner or operator of a portable aggregate processing plant may not operate the portable5
aggregate processing plant before 6 a.m. or after 10 p.m. each day at each temporary location. 6
(3) An owner or operator of a portable aggregate processing plant shall operate in accordance7
with the terms and conditions of the Temporary Relocation Approval Letter issued by the director for 8
each location. 9
(4) An owner or operator of a portable aggregate processing plant shall comply with the10
applicable requirements of Rule R307-801, Utah Asbestos Rule. 11
12
R307-209-6. Recordkeeping & Reporting Requirements. 13
(1) Following the end of operations at each temporary location, an owner or operator of a14
portable aggregate processing plant shall submit the following records to the director at the end of 15
operation at each temporary location, and shall retain the records for at least two years: 16
(a) the initial relocation date at each location;17
(b) number of working days at each location;18
(c) consecutive days at each location;19
(d) the production for each day of operation at each location;20
(e) the total production at each location;21
(f) the time operations started and ended each day at each location; and22
(g) the last day of operation at each location.23
(2) An owner or operator of a portable aggregate processing plant shall keep records and submit24
emissions inventories according to Rule R307-150. 25
26
R307-209-7. Fugitive Dust Requirements. 27
Unless otherwise specified in Rule R307-209, an owner or operator of a portable aggregate 28
processing plant shall comply with the following for fugitive dust: 29
(1) the opacity limits and control measures in Section R307-309-5; and30
(2) the fugitive dust control plan submitted with the Notice of Temporary Relocation for each31
respective location. 32
33
R307-209-8. Concrete Batch Plant Requirements. 34
An owner or operator of a concrete batch plant shall comply with the following: 35
(1) ensure opacity does not exceed the limits in Section R307-312-4; and36
(2) control particulate emissions from each storage silo and each mixer with a fabric filter, a37
baghouse, a bin vent, or a dust collector. 38
39
R307-209-9. Nonmetallic Mineral Processing Plant Requirements. 40
An owner or operator of a nonmetallic mineral processing plant shall comply with the following: 41
(1) ensure opacity does not exceed the limits in Section R307-312-4; and42
(2) use water sprays and water application to control particulate emissions from each crusher,43
screen, and conveyor. 44
45
R307-209-10. Asphalt Plant Requirements. 46
(1) An owner or operator of an asphalt plant shall comply with the following:47
(a) ensure opacity does not exceed 10% opacity and opacity observations shall be conducted in48
accordance with 40 CFR 60, Method 9; 49
(b) use natural gas, propane, fuel oil, on-specification used oil as defined in Rule R315-15, or50
any combination thereof as fuel; 51
(c) maintain records of fuel use;52
(d) control particulate emissions from each storage silo with a fabric filter, a baghouse, a bin53
vent, or a dust collector; 54
Page 2 of 3
(e) control particulate emissions from each asphalt mixer with a baghouse;1
(f) maintain the pressure drop of the asphalt plant baghouse between 3.0 and 7.0 inches of water2
during operation and additionally the owner or operator shall comply with the following: 3
(i) install a pressure gauge on each baghouse;4
(ii) ensure the pressure gauge measures the pressure drop in 1-inch water column increments or5
less; 6
(iii) calibrate the pressure gauge according to the manufacturer's instructions at least once every7
12 months; and 8
(iv) record the reading of the pressure gauge at least once per operating day.9
(2) The owner or operator shall:10
(a) ensure filterable PM2.5 emissions do not exceed 0.024 grains per dry standard cubic foot;11
(b) conduct an initial stack test on each asphalt plant within 180 days after startup;12
(c) conduct a stack test on each asphalt plant within three years after the date of the most recent13
stack test; 14
(d) conduct stack testing according to Rule R307-165; and15
(e) determine PM2.5 emissions by 40 CFR 60, Appendix A, Method 5.16
17
R307-209-11. Diesel-Fired Engine Requirements. 18
An owner or operator of a diesel-fired engine associated with a portable aggregate processing 19
plant shall comply with the following. 20
(1) Maintain opacity at or below 20% opacity. Opacity observations shall be conducted in21
accordance with 40 CFR 60, Method 9. 22
(2) Use Ultra-Low Sulfur Diesel (ULSD) as defined in 40 CFR 1090.305 as fuel.23
(3) Maintain records of ULSD use.24
25
KEY: air pollution, permits, approval orders, greenhouse gases 26
Date of Last Change: 2025 27
Authorizing, and Implemented or Interpreted Law: 19-2-104(3)(b)(iii); 19-2-108 28
Page 3 of 3

ITEM 6

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

Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor
DAQ-009-25
M E M O R A N D U M TO: Air Quality Board THROUGH: Bryce C. Bird, Executive Secretary THROUGH: Erica Pryor, Rules Coordinator FROM: Alan Humpherys, Minor New Source Review Section Manager DATE: January 22, 2025 SUBJECT: PROPOSE FOR FINAL ADOPTION: Amend R307-401. Permit: New and Modified
Sources. _________________________________________________________________________________
In response to the new rule R307-209, Portable Aggregate Processing Plants, an amendment to rule R307-401, Permit: New and Modified Sources, is necessary. A revision to section R307-401-10 will allow these sources to temporarily relocate aggregate equipment without first obtaining an approval order. The
amendment to rule R307-401 will not add any new requirements to sources but save sources the time and money from first obtaining a portable approval order. In addition, the new process will reduce DAQ staff time spent on this work. On November 6, 2024, the Utah Air Quality Board approved a 30-day public comment period for the proposed amendments. This public comment period ran from December 1, 2024, to December 31, 2024. A public hearing was scheduled for December 18, 2024; however, no request was made to hold the hearing, and it was cancelled in accordance with 63G-3-302. No public comments were received on the proposed rule amendment. Recommendation: Staff recommend the Board approve the amendment to rule R307-401, Permit: New and
Modified Sources, for final adoption.
State of Utah
Administrative Rule Analysis
Revised May 2024

NOTICE OF SUBSTANTIVE CHANGE
TYPE OF FILING: Amendment
Rule or Section Number: R307-401 Filing ID: Office Use Only
Date of Previous Publication (Only for CPRs): Click or tap to enter a date.

Agency Information
1. Title catchline: Environmental Quality, Air Quality
Building: Multi-Agency State Office Building
Street address: 195 N 1950 W
City, state: Salt Lake City
Mailing address: PO BOX 144820
City, state and zip: Salt Lake City, UT 84114-4820
Contact persons:
Name: Phone: Email:
Alan Humpherys 801-536-4142 [e-mail]
Erica Pryor 385-499-3416 [e-mail]

Please address questions regarding information on this notice to the persons listed above.

General Information
2. Rule or section catchline:
R307-401. Permit: New and Modified Sources.

3. Purpose of the new rule or reason for the change:
The Division of Air Quality (DAQ) will be proposing a new rule R307-209, Portable Aggregate Processing Plants, which will
impact Rule R307-401 Permit: New and Modified Sources by necessitating an additional exemption under Subsection R307-
401-10(8).

4. Summary of the new rule or change:
This filing adds an additional source listed as a new Subsection, R307-401-10(8) portable aggregate processing plant, to the list of
exemptions under Section R307-401-10 Source Category Exemptions. This change is because of the introduction of new Rule
R307-209, Portable Aggregate Processing Plants.

Fiscal Information
5. Provide an estimate and written explanation of the aggregate anticipated cost or savings to:
A) State budget:
On average, DAQ issues around four portable Approval Orders a year. The average cost of a portable approval order is $3,075.
It is anticipated that the DAQ will not receive around $12,300 a year in permitting fees by implementing this rule.

B) Local governments:
DAQ is not aware of any local governments that have a portable Approval Order, so it is anticipated that this rule change will
not have an impact on local governments.

C) Small businesses ("small business" means a business employing 1-49 persons):
The proposed changes to Rule R307-401 are anticipated to provide a total fiscal savings of $12,300 per year to all impacted
companies, with no negative fiscal impacts anticipated. At this time DAQ is unable to estimate how many of the total companies
impacted by this rulemaking are small businesses, however the anticipated savings would apply to all small businesses
impacted.

D) Non-small businesses ("non-small business" means a business employing 50 or more persons):
The proposed amendments to Rule R307-401 are anticipated to provide a total fiscal savings of $12,300 per year to all
impacted companies, with no negative fiscal impacts anticipated. At this time DAQ is unable to estimate how many of the total
companies impacted by this rulemaking are non-small businesses, however the anticipated savings would apply to all non-
small businesses impacted.

E) Persons other than small businesses, non-small businesses, state, or local government entities ("person" means
any individual, partnership, corporation, association, governmental entity, or public or private organization of any character
other than an agency):
It is anticipated that amendments to Rule R307-401 would not impact other persons.

F) Compliance costs for affected persons (How much will it cost an impacted entity to adhere to this rule or its changes?):
Rule R307-401 will exempt sources from the requirement to obtain Air Quality Approval Orders; therefore, it is anticipated that
these amendments will not impose any new compliance costs to affected persons.

G) Regulatory Impact Summary Table (This table only includes fiscal impacts that could be measured. If there are
inestimable fiscal impacts, they will not be included in this table. Inestimable impacts will be included in narratives above.)
Regulatory Impact Table
Fiscal Cost FY2025 FY2026 FY2027
State Government $6,150 $12,300 $12,300
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Cost $0 $12,300 $12,300
Fiscal Benefits FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $6,150 $12,300 $12,300
Other Persons $0 $0 $0
Total Fiscal Benefits $6,150 $12,300 $12,300
Net Fiscal Benefits $0 $0 $0
H) Department head comments on fiscal impact and approval of regulatory impact analysis:
The Executive Director of the Department of Environmental Quality, Kim D. Shelley, has reviewed and approved this regulatory
impact analysis.

Citation Information
6. Provide citations to the statutory authority for the rule. If there is also a federal requirement for the rule, provide a
citation to that requirement:
Utah Code 19-2-104 U.S.C. Title 42 Chapter 85 Subchapter I
Part A Section 7410 (a)(1)2(A)

Incorporations by Reference Information
7. Incorporations by Reference (if this rule incorporates more than two items by reference, please include additional tables):
A) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

B) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

Public Notice Information
8. The public may submit written or oral comments to the agency identified in box 1. (The public may also request a
hearing by submitting a written request to the agency. See Section 63G-3-302 and Rule R15-1 for more information.)
A) Comments will be accepted until: 12/31/2024
B) A public hearing (optional) will be held:
Date (mm/dd/yyyy): Time (hh:mm AM/PM): Place (physical address or URL):

To the agency: If more than one hearing will take place, continue to add rows.

9. This rule change MAY become effective on: 02/05/2025
NOTE: The date above is the date the agency anticipates making the rule or its changes effective. It is NOT the effective date.

Agency Authorization Information
To the agency: Information requested on this form is required by Sections 63G-3-301, 63G-3-302, 63G-3-303, and 63G-3-
402. Incomplete forms will be returned to the agency for completion, possibly delaying publication in the Utah State Bulletin
and delaying the first possible effective date.
Agency head or
designee and title:
Bryce C. Bird, Director, Division of Air
Quality
Date: 10/23/2024

R307. Environmental Quality, Air Quality. 1
R307-401. Permit: New and Modified Sources. 2
R307-401-1. Purpose. 3
This rule establishes the application and permitting requirements for new installations and 4
modifications to existing installations throughout the State of Utah. Additional permitting requirements apply 5
to larger installations or installations located in nonattainment or maintenance areas. These additional 6
requirements can be found in Rules R307-403, R307-405, R307-406, R307-420, and R307-421. Modeling 7
requirements in Rule R307-410 may also apply. Each of the permitting rules establishes independent 8
requirements, and the owner or operator must comply with all of the requirements that apply to the 9
installation. Exemptions under R307-401 do not affect applicability of the other permitting rules. 10
11
R307-401-2. Definitions. 12
"Actual emissions" (a) means the actual rate of emissions of an air pollutant from an emissions unit, 13
as determined in accordance with Subsections R307-401-2(b) through R307-401-2(d). 14
(b) In general, actual emissions as of a particular date shall equal the average rate, in tons per year, at15
which the unit actually emitted the air pollutant during a consecutive 24-month period which precedes the 16
particular date and which is representative of normal source operation. The director shall allow the use of a 17
different time period upon a determination that it is more representative of normal source operation. Actual 18
emissions shall be calculated using the unit's actual operating hours, production rates, and types of materials 19
processed, stored, or combusted during the selected time period. 20
(c)The director may presume that source-specific allowable emissions for the unit are equivalent to21
the actual emissions of the unit. 22
(d) For any emissions unit that has not begun normal operations on the particular date, actual23
emissions shall equal the potential to emit of the unit on that date. 24
"Best available control technology" means an emissions limitation (including a visible emissions 25
standard) based on the maximum degree of reduction for each air pollutant which would be emitted from any 26
proposed stationary source or modification which the director, on a case-by-case basis, taking into account 27
energy, environmental, and economic impacts and other costs, determines is achievable for such source or 28
modification through application of production processes or available methods, systems, and techniques, 29
including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. 30
In no event shall application of best available control technology result in emissions of any pollutant which 31
would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the 32
director determines that technological or economic limitations on the application of measurement 33
methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a 34
design, equipment, work practice, operational standard or combination thereof, may be prescribed instead to 35
satisfy the requirement for the application of best available control technology. Such standard shall, to the 36
degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, 37
work practice or operation, and shall provide for compliance by means which achieve equivalent results. 38
Air Strippers" are systems designed to pump groundwater to the surface for treatment, usually by 39
aeration. 40
"Building, structure, facility, or installation" means all of the pollutant-emitting activities which 41
belong to the same industrial grouping, are located on one or more contiguous or adjacent properties, and are 42
under the control of the same person (or persons under common control) except the activities of any vessel. 43
Pollutant-emitting activities shall be considered as part of the same industrial grouping if they belong to the 44
same Major Group (i.e., which have the same two-digit code) as described in the Standard Industrial 45
Classification Manual, 1972, as amended by the 1977 Supplement (U.S. Government Printing Office stock 46
numbers 4101-0066 and 003-005-00176-0, respectively). 47
"Construction" means any physical change or change in the method of operation (including 48
fabrication, erection, installation, demolition, or modification of an emissions unit) that would result in a 49
change in emissions. 50
"Emissions unit" means any part of a stationary source that emits or would have the potential to emit 51
any air pollutant. 52
"Fugitive emissions" means those emissions which could not reasonably pass through a stack, 53
chimney, vent, or other functionally equivalent opening. 54
Page 1 of 10
"Indirect source" means a building, structure, facility, or installation which attracts or may attract 1
mobile source activity that results in emissions of a pollutant for which there is a national standard. 2
"Potential to emit" means the maximum capacity of a stationary source to emit an air pollutant under 3
its physical and operational design. Any physical or operational limitation on the capacity of the source to 4
emit a pollutant, including air pollution control equipment and restrictions on hours of operation or on the 5
type or amount of material combusted, stored, or processed, shall be treated as part of its design if the 6
limitation or the effect it would have on emissions is enforceable. Secondary emissions do not count in 7
determining the potential to emit of a stationary source. 8
"Secondary emissions" means emissions which occur as a result of the construction or operation of a 9
major stationary source or major modification, but do not come from the major stationary source or major 10
modification itself. Secondary emissions include emissions from any offsite support facility which would not 11
be constructed or increase its emissions except as a result of the construction or operation of the major 12
stationary source or major modification. Secondary emissions do not include any emissions which come 13
directly from a mobile source, such as emissions from the tailpipe of a motor vehicle, from a train, or from a 14
vessel. 15
"Soil Aeration" is an ex-situ treatment process where excavated soil from a remediation project is 16
spread in a thin layer to encourage biodegradation of soil contamination. Biodegradation may be stimulated 17
through aeration or the addition of minerals, nutrients, and/or moisture. 18
"Soil Vapor Extraction", or SVE, is a system designed to extract vapor phase contaminants from the 19
subsurface. SVE systems are often combined with other technologies, such as air sparging or vacuum-20
enhanced recovery systems. 21
"Stationary source" means any building, structure, facility, or installation which emits or may emit an 22
air pollutant. 23
"Vapor Mitigation System", or VMS, is a sub-slab system whose primary purpose is mitigating 24
vapor intrusion into an occupied, or occupiable, structure and is not intended or designed for the remediation 25
of contaminated soil or groundwater. This definition includes both active and passive systems. Passive 26
systems consist of a vapor barrier either below or above the slab of a structure and a venting system 27
installed under a structure to divert vapor from beneath the structure to the sides or roofline of a structure. 28
Active systems are similar to passive systems but incorporate a blower or fan to actively extract air from 29
beneath the structure. 30
31
R307-401-3. Applicability. 32
(1) Rule R307-401 applies to any person planning to:33
(a) construct a new installation that will or might reasonably be expected to bea source or an indirect34
source of air pollution; 35
(b) make modifications to or relocate an existing installation that will or might reasonably be36
expected to increase the amount of or change the character or effect of air pollutants discharged, so that the 37
installation may be expected to be a source or indirect source of air pollution; or 38
(c)install an air cleaning device or other equipment intended to control emission of air pollutants.39
(2) Rules R307-403, R307-405 and R307-406 may establish additional permitting requirements for40
new or modified sources. 41
(a) Exemptions contained in Rule R307-401 do not affect applicability or other requirements under42
Rules R307-403, R307-405 or R307-406. 43
(b) Exemptions contained in Rules R307-403, R307-405 or R307-406 do not affect applicability or44
other requirements under Rule R307-401, unless specifically authorized in this rule. 45
46
R307-401-4. General Requirements. 47
The general requirements in Subsections R307-401-4(1) through R307-401-4(4) apply to all new and 48
modified installations, including installations that are exempt from the requirement to obtain an approval 49
order. 50
(1)Any control apparatus installed on an installation shall be adequately and properly maintained.51
(2) If the director determines that an exempted installation is not meeting an approval order or State52
Implementation Plan limitation, is creating an adverse impact to the environment, or would be injurious to 53
human health or welfare, the director may require the owner or operator to submit a notice of intent and 54
Page 2 of 10
obtain an approval order in accordance with Sections R307-401-5 through R307-401-8. The director will 1
complete an appropriate analysis and evaluation in consultation with the owner or operator before 2
determining that an approval order is required. 3
(3) Low Oxides of Nitrogen Burner Technology. 4
(a) Except as provided in Subsection R307-401-4(3)(b), whenever existing fuel combustion burners 5
are replaced, the owner or operator shall install low oxides of nitrogen burners or equivalent oxides of 6
nitrogen controls, as determined by the director, unless such equipment is not physically practical or cost 7
effective. The owner or operator shall submit a demonstration that the equipment is not physically practical or 8
cost effective to the director for review and approval prior to beginning construction. 9
(b) The provisions of (a) above do not apply to non-commercial, residential buildings. 10
(4) A person shall not operate a source of air pollution that is required to have a permit under Rule 11
R307-401 unless the person has obtained a permit for the source under the procedures of Rule R307-401. 12
13
R307-401-5. Notice of Intent. 14
(1) Except as provided in Sections R307-401-9 through R307-401-17, any person subject to Rule 15
R307-401 shall submit a notice of intent to the director and receive an approval order precedent to the 16
construction, modification, installation, establishment, or relocation of an air pollutant source or indirect 17
source. The notice of intent shall be in a format specified by the director. 18
(2) The notice of intent shall include the following information: 19
(a) A description of the nature of the processes involved; the nature, procedures for handling and 20
quantities of raw materials; the type and quantity of fuels employed; and the nature and quantity of finished 21
product. 22
(b) The expected composition and physical characteristics of effluent stream both before and after 23
treatment by any control apparatus, including emission rates, volume, temperature, air pollutant types, and 24
concentration of air pollutants. 25
(c) The size, type, and performance characteristics of any control apparatus. 26
(d) An analysis of best available control technology for the proposed source or modification. When 27
determining best available control technology for a new or modified source in an ozone nonattainment or 28
maintenance area that will emit volatile organic compounds or nitrogen oxides, the owner or operator of the 29
source shall consider EPA Control Technique Guidance (CTG) documents and Alternative Control 30
Technique documents that are applicable to the source. Best available control technology shall be at least as 31
stringent as any published CTG that is applicable to the source. 32
(e) The location and elevation of the emission point and other factors relating to dispersion and 33
diffusion of the air pollutant in relation to nearby structures and window openings, and other information 34
necessary to appraise the possible effects of the effluent. 35
(f) The location of planned sampling points and the tests of the completed installation to be made by 36
the owner or operator when necessary to ascertain compliance. 37
(g) The typical operating schedule. 38
(h) A schedule for construction. 39
(i) Any plans, specifications and related information that are in final form at the time of submission 40
of notice of intent. 41
(j) Any additional information required by: 42
(i) Rule R307-403, Permits: New and Modified Sources in Nonattainment Areas and Maintenance 43
Areas; 44
(ii) Rule R307-405, Permits: Major Sources in Attainment or Unclassified Areas (PSD); 45
(iii) Rule R307-406, Visibility; 46
(iv) Rule R307-410, Permits: Emissions Impact Analysis; 47
(v) Rule R307-420, Permits: Ozone Offset Requirements in Davis and Salt Lake Counties; or 48
(vi) Rule R307-421, Permits: PM10 Offset Requirements in Salt Lake County and Utah County. 49
(k) Any other information necessary to determine if the proposed construction, modification, 50
installation, or establishment will be in accord with Title R307. 51
(l) The payment of a new source review fee established under Subsection 19-1-201(6)(i). 52
(3) Notwithstanding the exemptions in Sections R307-401-9 through R307-401-16, any person that 53
is subject to Rules R307-403, R307-405, or R307-406 shall submit a notice of intent to the director and 54
Page 3 of 10
receive an approval order precedent to the construction, modification, installation, establishment, or 1
relocation of an air pollutant source or indirect source. 2
3
R307-401-6. Review Period. 4
(1) Completeness Determination. Within 30 days after receipt of a notice of intent, or any additional 5
information necessary to the review, the director will advise the applicant of any deficiency in the notice of 6
intent or the information submitted. 7
(2) Within 90 days after the receipt of a complete application including all the information described 8
in Section R307-401-5, the director will 9
(a) issue an approval order for the proposed construction, installation, modification, relocation, or 10
establishment pursuant to the requirements of Section R307-401-8, or 11
(b) issue an order prohibiting the proposed construction, installation, modification, relocation or 12
establishment if it is determined that any part of the proposal will not be in the accord with the requirements 13
of Title R307. 14
(3) The review period under Subsection R307-401-6(2) may be extended by up to three 30-day 15
extensions if more time is needed to review the proposal. 16
17
R307-401-7. Public Notice. 18
(1) Issuing the Notice. Prior to issuing an approval or disapproval order of the proposed 19
construction, installation, modification, relocation or establishment, the director shall: 20
(a) publish a legal notice of the intent to approve or disapprove on the public legal notice website 21
under Subsection 45-1-101(2); 22
(b) notify the public of the intent to approve or disapprove on the Division's website; and 23
(c) post the draft permit and administrative record for the draft permit, or information on how to 24
access the administrative record for the draft permit, on the Division's website for the duration of the 25
public comment period. 26
(2) Opportunity for Review and Comment. 27
(a) At least one location will be provided where the information submitted by the owner or 28
operator, the director's analysis of the notice of intent proposal, and the proposed approval order 29
conditions will be available for public inspection. 30
(b) Public Comment. 31
(i) A 30-day public comment period will be established. 32
(ii) A request to extend the length of the comment period, up to 30 days, may be submitted to the 33
director within 15 days of the date the legal notice in Subsection R307-401-7(1)(a) is published. 34
(iii) Public Hearing. A request for a hearing on the proposed approval or disapproval order may 35
be submitted to the director within 15 days of the date the legal notice in Subsection R307-401-7(1)(a) is 36
published. 37
(iv) The hearing will be held in the area of the proposed construction, installation, modification, 38
relocation or establishment. 39
(v) The public comment and hearing procedure shall not be required when an order is issued to 40
extend the time required by the director to review plans and specifications. 41
(3) The director will consider comments received during the public comment period and at the 42
public hearing and, if appropriate, will make changes to the proposal in response to comments before 43
issuing an approval order or disapproval order. 44
45
R307-401-8. Approval Order. 46
(1) The director will issue an approval order if the following conditions have been met: 47
(a) The degree of pollution control for emissions, to include fugitive emissions and fugitive dust, is 48
at least best available control technology. When determining best available control technology for a new or 49
modified source in an ozone nonattainment or maintenance area that will emit volatile organic compounds or 50
nitrogen oxides, best available control technology shall be at least as stringent as any Control Technique 51
Guidance document that has been published by EPA that is applicable to the source. 52
(b) The proposed installation will meet the applicable requirements of: 53
(i) Rule R307-403, Permits: New and Modified Sources in Nonattainment Areas and Maintenance 54
Page 4 of 10
Areas; 1
(ii) Rule R307-405, Permits: Major Sources in Attainment or Unclassified Areas (PSD); 2
(iii) Rule R307-406, Visibility; 3
(iv) Rule R307-410, Permits: Emissions Impact Analysis; 4
(v) Rule R307-420, Permits: Ozone Offset Requirements in Davis and Salt Lake Counties; 5
(vi) Rule R307-210, Standards of Performance for New Stationary Sources; 6
(vii) National Primary and Secondary Ambient Air Quality Standards; 7
(viii) Rule R307-214, National Emission Standards for Hazardous Air Pollutants; 8
(ix) Rule R307-110, General Requirements: State Implementation Plan; and 9
(x) all other provisions of Title R307. 10
(2) The approval order will require that all pollution control equipment be adequately and properly 11
maintained. 12
(3) Receipt of an approval order does not relieve any owner or operator of the responsibility to 13
comply with the provisions of Title R307 or the State Implementation Plan. 14
(4) To accommodate staged construction of a large source, the director may issue an order 15
authorizing construction of an initial stage prior to receipt of detailed plans for the entire proposal provided 16
that, through a review of general plans, engineering reports and other information the proposal is determined 17
feasible by the director under the intent of Title R307. Subsequent detailed plans will then be processed as 18
prescribed in this paragraph. For staged construction projects the previous determination under Subsections 19
R307-401-8(1) and (2) will be reviewed and modified as appropriate at the earliest reasonable time prior to 20
commencement of construction of each independent phase of the proposed source or modification. 21
(5) If the director determines that a proposed stationary source, modification or relocation does not 22
meet the conditions established in (1) above, the director will not issue an approval order. 23
24
R307-401-9. Small Source Exemption. 25
(1) A small stationary source is exempt from the requirement to obtain an approval order in Sections 26
R307-401-5 through R307-401-8 if the following conditions are met. 27
(a) its actual emissions are less than 5 tons per year per air pollutant of any of the following air 28
pollutants: sulfur dioxide, carbon monoxide, nitrogen oxides, PM10, ozone, or volatile organic compounds; 29
(b) its actual emissions are less than 500 pounds per year of any hazardous air pollutant and less than 30
2000 pounds per year of any combination of hazardous air pollutants; 31
(c) its actual emissions are less than 500 pounds per year of any air pollutant not listed in (a) or (b) 32
above and less than 2000 pounds per year of any combination of air pollutants not listed in (a) or (b) above. 33
(d) Air pollutants that are drawn from the environment through equipment in intake air and then are 34
released back to the environment without chemical change, as well as carbon dioxide, nitrogen, oxygen, 35
argon, neon, helium, krypton, xenon should not be included in emission calculations when determining 36
applicability under (a) through (c) above. 37
(2) The owner or operator of a source that is exempted from the requirement to obtain an approval 38
order under (1) above shall no longer be exempt if actual emissions in any subsequent year exceed the 39
emission thresholds in (1) above. The owner or operator shall submit a notice of intent under Section R307-40
401-5 no later than 180 days after the end of the calendar year in which the source exceeded the emission 41
threshold. 42
(3) Small Source Exemption - Registration. The director will maintain a registry of sources that are 43
claiming an exemption under Section R307-401-9. The owner or operator of a stationary source that is 44
claiming an exemption under Section R307-401-9 may submit a written registration notice to the director. 45
The notice shall include the following minimum information: 46
(a) identifying information, including company name and address, location of source, telephone 47
number, and name of plant site manager or point of contact; 48
(b) a description of the nature of the processes involved, equipment, anticipated quantities of 49
materials used, the type and quantity of fuel employed and nature and quantity of the finished product; 50
(c) identification of expected emissions; 51
(d) estimated annual emission rates; 52
(e) any control apparatus used; and 53
(f) typical operating schedule. 54
Page 5 of 10
(4) An exemption under Section R307-401-9 does not affect the requirements of Section R307-401-1
17, Temporary Relocation. 2
(5) A stationary source that is not required to obtain a permit under Rule R307-405 for greenhouse 3
gases, as defined in Subsection R307-405-3(9)(a), is not required to obtain an approval order for greenhouse 4
gases under Rule R307-401. This exemption does not affect the requirement to obtain an approval order for 5
any other air pollutant emitted by the stationary source. 6
7
R307-401-10. Source Category Exemptions. 8
The source categories described in Section R307-401-10 are exempt from the requirement to obtain 9
an approval order found in Sections R307-401-5 through R307-401-8. The general provisions in Section 10
R307-401-4 shall apply to these sources. 11
(1) Fuel-burning equipment in which combustion takes place at no greater pressure than one inch of 12
mercury above ambient pressure with a rated capacity of less than five million BTU per hour using no other 13
fuel than natural gas or LPG or other mixed gas that meets the standards of gas distributed by a utility in 14
accordance with the rules of the Public Service Commission of the State of Utah, unless there are emissions 15
other than combustion products. 16
(2) Comfort heating equipment such as boilers, water heaters, air heaters and steam generators with 17
a rated capacity of less than one million BTU per hour if fueled only by fuel oil numbers 1 - 6, 18
(3) Emergency heating equipment, using coal or wood for fuel, with a rated capacity less than 19
50,000 BTU per hour. 20
(4) Exhaust systems for controlling steam and heat that do not contain combustion products. 21
(5) A well site as defined in 40 CFR 60.5430a, including centralized tank batteries, that is not a 22
major source as defined in Section R307-101-2, and is registered with the Division as required by Rule R307-23
505. 24
(6) A gasoline dispensing facility as defined in 40 CFR 63.11132 that is not a major source as 25
defined in Section R307-101-2. These sources shall comply with the applicable requirements of Rule R307-26
328 and 40 CFR 63 Subpart CCCCCC: National Emission Standards for Hazardous Air Pollutants for 27
Source Category: Gasoline Dispensing Facilities. 28
(7) A Vapor Mitigation System as defined in R307-401-2. 29
(8) A Portable Aggregate Processing Plant as defined in Subsection R307-209-2. 30
31
32
R307-401-11. Replacement-in-Kind Equipment. 33
(1) Applicability. Existing process equipment or pollution control equipment that is covered by an 34
existing approval order or State Implementation Plan requirement may be replaced using the procedures in 35
(2) below if: 36
(a) the potential to emit of the process equipment is the same or lower; 37
(b) the number of emission points or emitting units is the same or lower; 38
(c) no additional types of air pollutants are emitted as a result of the replacement; 39
(d) the process equipment or pollution control equipment is identical to or functionally equivalent to 40
the replaced equipment; 41
(e) the replacement does not change the basic design parameters of the process unit or pollution 42
control equipment; 43
(f) the replaced process equipment or pollution control equipment is permanently removed from the 44
stationary source, otherwise permanently disabled, or permanently barred from operation; 45
(g) the replacement process equipment or pollution control equipment does not trigger New Source 46
Performance Standards or National Emissions Standards for Hazardous Air Pollutants under 42 U.S.C. 7411 47
or 7412; and 48
(h) the replacement of the control apparatus or process equipment does not violate any other 49
provision of Title R307. 50
(2) Replacement-in-Kind Procedures. 51
(a) In lieu of filing a notice of intent under Section R307-401-5, the owner or operator of a stationary 52
source shall submit a written notification to the director before replacing the equipment. The notification shall 53
contain a description of the replacement-in-kind equipment, including the control capability of any control 54
Page 6 of 10
apparatus and a demonstration that the conditions of (1) above are met. 1
(b) If the replacement-in-kind meets the conditions of (1) above, the director will update the source's 2
approval order and notify the owner or operator. Public review under Section R307-401-7 is not required for 3
the update to the approval order. 4
(3) If the replaced process equipment or pollution control equipment is brought back into operation, 5
it shall constitute a new emissions unit. 6
7
R307-401-12. Reduction in Air Pollutants. 8
(1) Applicability. The owner or operator of a stationary source of air pollutants that reduces or 9
eliminates air pollutants is exempt from the requirement to submit a notice of intent and obtain an approval 10
order prior to construction if: 11
(a) the project does not increase the potential to emit of any air pollutant or cause emissions of any 12
new air pollutant, and 13
(b) the director is notified of the change and the reduction of air pollutants is made enforceable 14
through an approval order in accordance with (2) below. 15
(2) Notification. The owner or operator shall submit a written description of the project to the 16
director no later than 60 days after the changes are made. The director will update the source's approval order 17
or issue a new approval order to include the project and to make the emission reductions enforceable. Public 18
review under Section R307-401-7 is not required for the update to the approval order. 19
20
R307-401-13. Plantwide Applicability Limits. 21
A plantwide applicability limit under Section R307-405-21 does not exempt a stationary source from 22
the requirements of R307-401. 23
24
R307-401-14. Used Oil Fuel Burned for Energy Recovery. 25
(1) Definitions. 26
"Used Oil" is defined as any oil that has been refined from crude oil, used, and, as a result of such 27
use contaminated by physical or chemical impurities. 28
(2) An emission unit that burns used oil, as defined in Section R315-15-1, for energy recovery is 29
exempt from the requirement to obtain an approval order in Sections R307-401-5 through R307-401-8 if 30
the owner or operator complies with Section R315-15-6 and the heat input design of the emission unit is 31
not more than 0.5 MMBtu/hr. 32
33
R307-401-15. Air Strippers and Soil Vapor Extraction Systems. 34
R307-401-15 applies to remediation systems with the potential to generate air emissions, such as air 35
strippers and soil vapor extraction (SVE) as defined in R307-401-2. 36
(1) The owner or operator of an air stripper or SVE remediation system is exempt from the notice of 37
intent and approval order requirements of Sections R307-401-5 through R307-401-8 if the following 38
conditions are met: 39
(a) actual emissions of volatile organic compounds from a given project are less than 5 tons per year; 40
and 41
(b) emission rates of hazardous air pollutants are below their respective threshold values contained 42
in R307-410-5(1)(c)(i)(C). 43
(2) The owner or operator shall submit documentation to the director that demonstrates the project 44
meets the exemption criteria in R307-401-15(1). Required documentation includes, but is not limited to: 45
(a) project summary, including location, system description, operational schedule, and schedule for 46
construction; 47
(b) emission calculations and any laboratory sampling data used in calculations; and 48
(c) plans and specifications for the system and equipment. 49
(3) After beginning the soil remediation project, the owner or operator shall conduct testing to 50
demonstrate compliance with the exemption levels in R307-401-15(1)(1) and (b). Monitoring and reporting 51
shall be conducted as follows: 52
(a) Emissions for air strippers shall be based on the following: 53
(i) influent and effluent water samples analyzed for volatile organic compounds and hazardous air 54
Page 7 of 10
pollutants using the most recent version of USEPA Test Method 8260, Method 8021, or other EPA approved 1
testing methods acceptable to the director; and 2
(ii) design water flow rate of the system or the water flow rates measured during the sample period. 3
(b) Emissions for SVE systems shall be based on the following: 4
(i) Air samples collected from a sample port in the exhaust stack of the SVE system and analyzed 5
for volatile organic compounds and hazardous air pollutants using USEPA test method TO-15, or other EPA 6
approved testing methods acceptable to the director. 7
(ii) Design air flow rate of the system or the air flow rates measured at the outlet of the SVE system 8
during the sample period. Flow rates should be measured and reported at actual conditions. 9
(c) Within one month of sampling, the owner or operator shall submit to the director the sample 10
results, estimated emissions of volatile organic compounds, and estimated emission rates of hazardous air 11
pollutants. 12
(d) Samples shall be collected at the following frequencies or more frequently as determined 13
necessary by the director: 14
(i) no less than twenty-eight days and no more than thirty-one days (i.e., monthly) after startup for 15
the first quarter; 16
(ii) quarterly for the remainder of the first year; and 17
(iii) semi-annually thereafter for the life of the project or as allowed in R307-401-15(3)(f). 18
(e) If an SVE or air stripper system is restarted after rehabilitation or an extended period of 19
shutdown, the owner or operator shall recommence the sampling schedule in R307-415(3)(d), unless 20
otherwise approved by the director. 21
(f) The owner or operator may request to discontinue sampling after three years of operation. To 22
discontinue sampling, the owner or operator must submit to the director a request to discontinue monitoring. 23
(i) The request must include documentation demonstrating emissions have remained below the 24
exemption levels in R307-401-15(1)(a) and (b) since startup of the system. 25
(ii) The request is subject to approval from the director upon consultation with other regulatory 26
agencies involved in the project, such as Division of Environmental Response and Remediation or Division 27
of Waste Management and Radiation Control. 28
(4) The following control devices do not require a notice of intent or approval order when used in 29
relation to an air stripper or soil vapor extraction system that is exempted under Section R307-401-15: 30
(a) thermodestruction unit with a rated input capacity of less than five million BTU per hour using 31
no other auxiliary fuel than natural gas or LPG, or 32
(b) carbon adsorption unit. 33
34
R307-401-16. Soil Aeration Projects. 35
R307-401-16 applies to soil aeration projects used to conduct soil remediation. 36
(1) The owner or operator of a soil aeration project is not subject to the notice of intent and approval 37
order requirements of Sections R307-401-5 through R307-401-8, if the following conditions are met: 38
(a) emissions of volatile organic compounds from a given soil aeration project are less than 5 tons 39
per year; and 40
(b) emission rates of hazardous air pollutants are below their respective threshold values contained 41
in R307-410-(1)(c)(i)(C). 42
(2) The owner or operator shall submit documentation to the director demonstrating the project 43
meets the exemption criteria in R307-401-16(1). The owner or operator shall receive approval from the 44
director for the exemption prior to beginning the remediation project. Required documentation includes, but 45
is not limited to: 46
(a) calculated emissions of volatile organic compounds and estimated emission rates of hazardous 47
air pollutants from all soils to be treated from the soil aeration project. 48
(b) Emission calculations shall be based on soil samples of the soils to be remediated. Samples shall 49
be analyzed for volatile organic compounds and hazardous air pollutants using the most recent version of 50
USEPA Test Method 8260, Method 8021, or other EPA approved testing methods acceptable to the director. 51
Emission calculations should be based on the methodology in EPA guidance "Air Emissions from the 52
Treatment of Soils Contaminated with Petroleum Fuels and Other Substances" (EPA-600/R-92-124) or other 53
methodology acceptable to the director. 54
Page 8 of 10
(c) Location where soil aeration will occur and where the remediated material originated. 1
(3) The owner or operator is exempt from the reporting requirements in R307-401-16(2) if 2
excavated soils are disposed of at a disposal or treatment facility, such as a landfill, solid waste management 3
facility, or a landfarm facility, that is owned or operated by a third party and operates under an existing 4
approval order. 5
6
R307-401-17. Temporary Relocation. 7
The owner or operator of a stationary source previously approved under Rule R307-401 may 8
temporarily relocate and operate the stationary source at any site for up to 180 working days in any calendar 9
year not to exceed 365 consecutive days, starting from the initial relocation date. The director will evaluate 10
the expected emissions impact at the site and compliance with applicable Title R307 rules as the basis for 11
determining if approval for temporary relocation may be granted. Records of the working days at each site, 12
consecutive days at each site, and actual production rate shall be submitted to the director at the end of each 13
180 calendar days. These records shall also be kept on site by the owner or operator for the entire project, and 14
be made available for review to the director as requested. Section R307-401-7, Public Notice, does not apply 15
to temporary relocations under Section R307-401-17. 16
17
R307-401-18. Eighteen Month Review. 18
Approval orders issued by the director in accordance with the provisions of Rule R307-401 will be 19
reviewed eighteen months after the date of issuance to determine the status of construction, installation, 20
modification, relocation or establishment. If a continuous program of construction, installation, modification, 21
relocation or establishment is not proceeding, the director may revoke the approval order. 22
23
R307-401-19. General Approval Order. 24
(1) The director may issue a general approval order that would establish conditions for similar 25
new or modified sources of the same type or for specific types of equipment. The general approval order 26
may apply throughout the state or in a specific area. 27
(a) A major source or major modification as defined in Rules R307-403, R307-405, or R307-420 28
for each respective area is not eligible for coverage under a general approval order. 29
(b) A source that is subject to the requirements of Section R307-403-5 is not eligible for 30
coverage under a general approval order. 31
(c) A source that is subject to the requirements of Section R307-410-4 is not eligible for 32
coverage under a general approval order unless a demonstration that meets the requirements of Section 33
R307-410-4 was conducted. 34
(d) A source that is subject to the requirements of Subsection R307-410-5(1)(c)(ii) is not eligible 35
for coverage under a general approval order unless a demonstration that meets the requirements of 36
Subsection R307-410-5(1)(c)(ii) was conducted. 37
(e) A source that is subject to the requirements of Subsection R307-410-5(1)(c)(iii) is not eligible 38
for coverage under a general approval order. 39
(2) A general approval order shall meet applicable requirements of Section R307-401-8. 40
(3) The public notice requirements in Section R307-401-7 shall apply to a general approval 41
order. 42
(4) Application. 43
(a) After a general approval order has been issued, the owner or operator of a proposed new or 44
modified source may apply to be covered under the conditions of the general approval order. 45
(b) The owner or operator shall submit the application on forms provided by the director in lieu 46
of the notice of intent requirements in Section R307-401-5 for equipment covered by the general approval 47
order. 48
(c) The owner or operator may request that an existing, individual approval order for the source 49
be revoked, and that it be covered by the general approval order. 50
(d) The owner or operator that has applied to be covered by a general approval order shall not 51
initiate construction, modification, or relocation until the application has been approved by the director. 52
(5) Approval. 53
(a) The director will review the application and approve or deny the request based on criteria 54
Page 9 of 10
specified in the general approval order for that type of source. If approved, the director will issue an 1
authorization to the applicant to operate under the general approval order. 2
(b) The public notice requirements in Section R307-401-7 do not apply to the approval of an 3
application to be covered under the general approval order. 4
(c) The director will maintain a record of stationary sources that are covered by a specific general 5
approval order and this record will be available for public review. 6
(6) Exclusions and Revocation. 7
(a) The director may require any source that has applied for or is authorized by a general 8
approval order to submit a notice of intent and obtain an individual approval order under Section R307-9
401-8. Cases where the director will require an individual approval order include the following: 10
(i) the director determines that the source does not meet the criteria specified in the general 11
approval order; 12
(ii) the director determines that the application for the general approval order did not contain all 13
necessary information to evaluate applicability under the general approval order; 14
(iii) modifications were made to the source that were not authorized by the general approval 15
order or an individual approval order; 16
(iv) the director determines the source may cause a violation of a national ambient air quality 17
standard; 18
(v) the director determines that an approval order is required based on the compliance history and 19
current compliance status of the source or applicant; or 20
(vi) the director determines that an approval order is required for any other reason. 21
(b)(i) Any source authorized by a general approval order may request to be excluded from the 22
coverage of the general approval order by submitting a notice of intent under Section R307-401-5 and 23
receiving an individual approval order under Section R307-401-8. 24
(ii) When the director issues an individual approval order to a source subject to a general 25
approval order, the applicability of the general approval order to the individual source is revoked on the 26
effective date of the individual approval order. 27
(7) Modification of General Approval Order. The director may modify, replace, or discontinue 28
the general approval order. 29
(a) Administrative corrections may be made to the existing version of the general approval order. 30
These corrections are to correct typographical errors or similar minor administrative changes. 31
(b) All other modifications or the discontinuation of a general approval order shall not apply to 32
any source authorized under previous versions of the general approval order unless the owner or operator 33
submits an application to be covered under the new version of the general approval order. Modifications 34
under Subsection R307-401-19(7)(b) shall meet the public notice requirements in Subsection R307-401-35
19(3). 36
(c) A general approval order shall be reviewed at least every three years. The review of the 37
general approval order shall follow the public notice requirements of Subsection R307-401-19(3). 38
(8) Modifications at a source covered by a general approval order. A source may make 39
modifications only as authorized by the approved general approval order. Modifications outside the scope 40
authorized by the approved general approval order shall require a new application for either an individual 41
approval order under Section R307-401-8 or a general approval order under Section R307-401-19. 42
43
KEY: air pollution, permits, approval orders, greenhouse gases 44
Date of Last Change: September 26, 2022 45
Notice of Continuation: May 4, 2022 46
Authorizing, and Implemented or Interpreted Law: 19-2-104(3)(b)(iii); 19-2-108 47
Page 10 of 10

ITEM 7

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

Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor
DAQ-010-25
M E M O R A N D U M TO: Air Quality Board THROUGH: Bryce C. Bird, Executive Secretary THROUGH: Erica Pryor, Rules Coordinator FROM: Greg Mortensen, Inventory Section Manager DATE: January 23, 2025 SUBJECT: PROPOSE FOR PUBLIC COMMENT: Amend R307-150. Emission Inventories.
______________________________________________________________________________________ During a review prompted by a board member question about rule R307-150 in 2020, Division of Air
Quality (DAQ) staff determined that the point source hazardous air pollutants (HAPs) exemption threshold calculations in section R307-150-7 could not be replicated. Historical documentation of the calculation was also unavailable despite numerous records searches and interviews with current and former DAQ
employees. Emissions inventory staff began to seek alternative means to calculate HAPs reporting exemptions and working with the State and Local Emissions Inventory System (SLEIS) vendor to evaluate the ability of the program to automatically calculate HAPs based on already required material throughputs and established emission factors. The SLEIS vendor subsequently provided a program enhancement which automatically populates HAPs. The enhancement was applied during the 2023-point source emissions inventory collection and proved successful. As part of staff research activities, other states were contacted regarding their point HAPs collection rules. Oklahoma and West Virginia have no minimum reporting threshold (note: both states use SLEIS),
Louisiana and Wyoming have a ten-pound reporting threshold and South Carolina has a 200 pound threshold. It was also reported that Colorado, Illinois, Iowa, Kentucky, North Carolina, and Wisconsin also have point source HAPs reporting requirements, but no details were provided.

DAQ-010-25 Page 2
Additionally, it was noted that states that do have a reporting threshold expect that regulated facilities calculate HAPs emissions estimates to determine whether they exceed the threshold and must report or not. Therefore, it is unlikely that establishing a new reporting threshold calculation would reduce the workload for a source. Furthermore, having an expected HAPs list auto-populate in SLEIS reduces the uncertainty for which HAPs sources may need to report for a given process and should save manual calculation time. This should be particularly helpful for smaller point sources who, at times, rely on administrative staff to complete emissions inventories. Ultimately, striking the HAPs reporting thresholds in section R307-150-7 removes a confusing and intricate calculation sources have struggled with and one which DAQ staff were unable to replicate. More
importantly, this proposed change allows sources and DAQ to leverage SLEIS’s capability and will align the rule with what sources are already reporting in SLEIS.
The aforementioned rule review also revealed that the current section R307-150-3 language implied that sulfur dioxide (SO2) requirements would lapse in 2018. However, that is not the case and SO2 reporting is still necessary to comply with U.S. Environmental Protection Agency regional haze requirements.
Therefore, it is proposed that section R307-150-3 be modified to remove this inaccurate language. This rule R307-150 review also coincided with the ongoing development of the Northern Wasatch Front Serious Ozone State Implementation Plan. As emissions inventories were passed on to technical analysis staff for modeling, it was noted that the majority of point sources (230 of 421 sources) reported mobile emissions, but other facilities did not. Inventory staff noted that the inconsistency was due to a combination of some sources having a specific reporting requirement in their permits and many others voluntarily reported these emissions as there was no explicit requirement in rule R307-150. A meeting with various DAQ sections (including technical analysis, policy, emissions inventory, and compliance) was subsequently held to discuss the issue. Technical analysis and policy staff noted that having a consistent and comprehensive emissions inventory on point sources would allow for more accurate emissions spatial allocation, reduced uncertainty, enhanced model performance, and more accurate policy evaluation, if/when needed. Emissions inventory staff noted that most sources are already
submitting these emissions and SLEIS is capable of automatically calculating the emissions based on fuel use or operation hours once a source populates the mobile process in SLEIS. Staff do not anticipate a large workload increase for reporting these emissions as many sources already track fuel use and operational
hours of equipment. Workload would be further limited as emissions reporting would be restricted to equipment that does not leave the facility’s property in a given year. Staff has consulted with Attorney General representatives related to appropriate rule language changes to incorporate mobile emission reporting and limiting the reporting to mobile sources that do not leave the facility’s property. The proposed definition and language have been added to sections R307-150-2, R307-150-5, and R307-150-6. Finally, additional changes are proposed to bring rule R307-150 into compliance with Executive Order 2021-12.
Recommendation: Staff recommend the Board approve the amendments to rule R307-150, Emission Inventories, for a 30-day public comment period.
State of Utah
Administrative Rule Analysis
Revised May 2024

NOTICE OF SUBSTANTIVE CHANGE
TYPE OF FILING: Amendment
Rule or Section Number: R307-150 Filing ID: Office Use Only
Date of Previous Publication (Only for CPRs): Click or tap to enter a date.

Agency Information
1. Title catchline: Environmental Quality, Air Quality
Building: Multi-Agency State Office Building
Street address: 195 N 1950 W
City, state: Salt Lake City
Mailing address: PO Box 144820
City, state and zip: Salt Lake City, UT 84114-4820
Contact persons:
Name: Phone: Email:
Greg Mortensen 385-226-6171 [e-mail]
Erica Pryor 385-499-3416 [e-mail]

Please address questions regarding information on this notice to the persons listed above.

General Information
2. Rule or section catchline:
R307-150. Emission Inventories.

3. Purpose of the new rule or reason for the change:
Rule R307-150 is being updated to reflect what our State and Local Emissions Inventory System (SLEIS) database is capable
of. Ultimately, the Division of Air Quality (DAQ) needs to catch the rule up on Hazardous Air Pollutants (HAPs) to reflect what
sources are already reporting and what SLEIS is also already able to do. Additionally, DAQ is removing the HAPs exemption
limits as staff were unable to replicate the calculation methodology employed in the existing rule. SLEIS is now able to
automatically populate any HAPs emission factors with standard, well defined methodology, therefore negating the need for
exemption limits. This is a much-simplified means for most facilities to report their HAPs emissions. DAQ staff believe this will
also provide more accurate and consistent HAPs data while also streamlining HAPs reporting with criteria pollutants. DAQ is
also adding the explicit authority to collect mobile emissions from point sources. Over half of the facilities reporting in SLEIS
were already including emissions. This change will allow staff to level the playing field and mandate all facilities to report these
emissions. This will result in a more comprehensive point source inventory which can be leveraged for modeling and policy
purposes. Staff is also taking the opportunity to update the sulfur dioxide (SO2) reporting requirements by removing a conflicting
statement indicating an erroneous end date for SO2 reporting. Additionally, other revisions have been made to bring the rule
into compliance with EO 2021-12.

4. Summary of the new rule or change:
The amendments to Rule R307-150 do the following:
 Remove HAPs threshold calculation and HAPs reporting exemptions
 Update SO2 reporting language
 Remove the outdated timeline for SO2 reporting period.
 Require mobile emissions reporting by point sources
 Include the definition of mobile emissions (by modifying reference to 40 CFR 51 to include “which never leave
the property”).
 Add mobile emissions reporting requirement to Sections R307-150-5 and R307-150-6
 Rule language changes to bring the rule into compliance with EO 2021-12

Fiscal Information
5. Provide an estimate and written explanation of the aggregate anticipated cost or savings to:
A) State budget:
There are no anticipated costs or savings to the state budget associated with the amendments to Rule R307-150. No additional
costs are expected as the automated HAPs enhancement is already included in the current SLEIS maintenance agreement and
mobile emissions are already reportable, and reported by many facilities, in SLEIS. All other changes are administrative
language changes for portions of the rule already in effect.

B) Local governments:
If not already reporting, there is a possible workload increase to track mobile source use on a facility. However, there are no or
negligible costs anticipated for HAPs reporting due to automated processes for local governments associated with the
amendments to Rule R307-150.

C) Small businesses ("small business" means a business employing 1-49 persons):
If not already reporting, there is a possible workload increase to track mobile source use on a facility. However, there are no or
negligible costs anticipated for HAPs reporting due to automated processes for small businesses associated with the
amendments to Rule R307-150.

D) Non-small businesses ("non-small business" means a business employing 50 or more persons):
If not already reporting, there is a possible workload increase to track mobile source use on a facility. However, there are no or
negligible costs anticipated for HAPs reporting due to automated processes for non-small businesses associated with the
amendments to Rule R307-150.

E) Persons other than small businesses, non-small businesses, state, or local government entities ("person" means
any individual, partnership, corporation, association, governmental entity, or public or private organization of any character
other than an agency):
If not already reporting, there is a possible workload increase to track mobile source use on a facility. However, there are no or
negligible costs anticipated for HAPs reporting due to automated processes for non-small businesses associated with the
amendments to Rule R307-150.

F) Compliance costs for affected persons (How much will it cost an impacted entity to adhere to this rule or its changes?):
If not already reporting, there is a possible workload increase to track mobile source use on a facility. However, given that the
majority of facilities already report these emissions, there are a limited number of facilities that do not report and these all vary
in operational size and the possible mobile equipment operating on each facility is unknown at this time. Therefore, predicting
labor cost (current hourly pay rates are unknown) and possible time needed to determine equipment types to load into the
inventory database is unknown due to the potential variability of each operation’s mobile quantity and types.

Conversely, workloads costs should be significantly reduced as SLEIS provides the means to input activity data (e.g. fuel use or
operating hours, both of which are typically tracked by sources as part of their normal business practices) to calculate
emissions. Thus, once the source adds the equipment types and number thereof to SLEIS, they only need to input activity data
going forward as SLEIS will carry their equipment type and number from year-to-year.

Removing the HAPs reporting thresholds should have negligible workload increase as SLEIS will automatically calculate HAPs
based on the already required activity data for their annual emission inventory reports. Additionally, there is a strong potential
that this will reduce workload for sources as they are already expected to determine if their HAP emissions are above or below
the threshold in the current rule which involves a complex calculation for each pollutant. For smaller sources, it is not
uncommon that administrative staff are tasked with submitting the inventory and are confused by these thresholds. This not
only expends their time and agency time supporting them but also exposes sources to potential compliance costs if they fail to
report a HAP as they guessed or erroneously calculated that they were below the threshold. SLEIS’s HAPs auto-calculation
capability alleviates this burden and allows sources to simply populate their processes with already-required activity data.

G) Regulatory Impact Summary Table (This table only includes fiscal impacts that could be measured. If there are
inestimable fiscal impacts, they will not be included in this table. Inestimable impacts will be included in narratives above.)
Regulatory Impact Table
Fiscal Cost FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Cost $0 $0 $0
Fiscal Benefits FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Benefits $0 $0 $0
Net Fiscal Benefits $0 $0 $0
H) Department head comments on fiscal impact and approval of regulatory impact analysis:
The Executive Director of the Department of Environmental Quality, Kim D. Shelley, has reviewed and approved
this regulatory impact analysis.

Citation Information
6. Provide citations to the statutory authority for the rule. If there is also a federal requirement for the rule, provide a
citation to that requirement:
Section 19-6a-1642

Incorporations by Reference Information
7. Incorporations by Reference (if this rule incorporates more than two items by reference, please include additional tables):
A) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

B) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

Public Notice Information
8. The public may submit written or oral comments to the agency identified in box 1. (The public may also request a
hearing by submitting a written request to the agency. See Section 63G-3-302 and Rule R15-1 for more information.)
A) Comments will be accepted until: 03/31/2025
B) A public hearing (optional) will be held:
Date (mm/dd/yyyy): Time (hh:mm AM/PM): Place (physical address or URL):
TBD TBD TBD
To the agency: If more than one hearing will take place, continue to add rows.

9. This rule change MAY become effective on: 04/07/2025
NOTE: The date above is the date the agency anticipates making the rule or its changes effective. It is NOT the effective date.

Agency Authorization Information
To the agency: Information requested on this form is required by Sections 63G-3-301, 63G-3-302, 63G-3-303, and 63G-3-
402. Incomplete forms will be returned to the agency for completion, possibly delaying publication in the Utah State Bulletin
and delaying the first possible effective date.
Agency head or
designee and title:
Bryce C. Bird, Director, Division of Air
Quality
Date: 01/21/2025
R307. Environmental Quality, Air Quality. 1
R307-150. Emission Inventories. 2
R307-150-1. Purpose and General Requirements. 3
(1) The purpose of Rule R307-150 is to establish:4
(a)[to establish ]by rule, the time frame, pollutants, and information that sources [must]shall include5
in inventory submittals; and 6
(b)[to establish ]consistent reporting requirements for stationary sources in Utah to determine7
whether sulfur dioxide emissions remain below the sulfur dioxide milestones established in the State 8
Implementation Plan for Regional Haze, [s]Section XX.E.1.a, incorporated by reference, in Section R307-9
110-28.10
(2) The requirements of Rule R307-150 replace any annual inventory reporting requirements in11
approval orders or operating permits issued [prior to]before December 4, 2003. 12
(3) Emission inventories shall be submitted on or before April 15 of each year following the13
calendar year for which an inventory is required. The inventory shall be submitted in a format specified by 14
the Division of Air Quality following consultation with each source. 15
(4) The [executive secretary]Director may require at any time a full or partial[ ]-year inventory upon16
reasonable notice to affected sources when it is determined that the inventory is necessary to develop a state 17
implementation plan, to assess whether there is a threat to public health or safety or the environment, or to 18
determine whether the source is in compliance with Title R307. 19
(5)Recordkeeping [R]requirements include the following[.]:20
(a) [E]each owner or operator of a stationary source subject to this rule shall maintain a copy of the21
emission inventory submitted to the Division of Air Quality and records indicating how the information 22
submitted in the inventory was determined, including any calculations, data, measurements, and estimates 23
used[.];[ The records under Section R307-150-4 shall be kept for ten years. Other records shall be kept for a 24
period of at least five years from the due date of each inventory.] 25
(i) the records under Section R307-150-4 shall be kept for ten years;26
(ii) other records shall be kept for a period of at least five years from the due date of each inventory;27
(b)[T]the owner or operator of the stationary source shall make these records available for28
inspection by any representative of the Division of Air Quality during normal business hours. 29
30
R307-150-2. Definitions. 31
The following additional definitions apply to Rule R307-150:[, and all references to the "Threshold 32
Limit Values for chemical Substances and Physical Agents and Biological Exposure Indices" adopted by the 33
American Conference of Governmental Industrial Hygienists refers to the 2003 version, which is hereby 34
incorporated by reference. 35
"Acute pollutant" means any noncarcinogenic air pollutant for which a threshold limit value - ceiling 36
(TLV-C) has been adopted by the American Conference of Governmental Industrial Hygienists in its 37
"Threshold Limit Values for Chemical Substances and Physical Agents and Biological Exposure Indices," 38
2003 edition. 39
"Carcinogenic pollutant" means any air pollutant that is classified as a known human carcinogen 40
(A1) or suspected human carcinogen (A2) by the American Conference of Governmental Industrial 41
Hygienists in its "Threshold Limit Values for Chemical Substances and Physical Agents and Biological 42
Exposure Indices," 2003 edition. 43
"Chronic Pollutant" means any noncarcinogenic air pollutant for which a threshold limit value - time 44
weighted average (TLV-TWA) having no threshold limit value - ceiling (TLV-C) has been adopted by the 45
American Conference of Governmental Industrial Hygienists in its "Threshold Limit Values for Chemical 46
Substances and Physical Agents and Biological Exposure Indices," 2003 edition. 47
"Dioxins" and "Furans" mean total tetra- through octachlorinated dibenzo-p-dioxins and 48
dibenzofurans.] 49
"Emissions unit" means emissions unit as defined in Section R307-415-3. 50
"Large Major Source" means a major source that emits or has the potential to emit 2,500 tons or 51
more per year of oxides of sulfur, oxides of nitrogen, or carbon monoxide, or that emits or has the potential to 52
emit 250 tons or more per year of PM10, PM2.5, volatile organic compounds, or ammonia. 53
"Lead" means elemental lead and the portion of its compounds measured as elemental lead. 54
"Major Source" means major source as defined in Section R307-415-3. 55
Page 1 of 4
“Mobile Emissions” means emissions from mobile sources as defined in 40 CFR § 51.491 which 1
never leave the property line. 2
3
R307-150-3. Applicability. 4
(1) Section R307-150-4 applies to stationary sources with actual emissions of 100 tons or more per5
year of sulfur dioxide in calendar year 2000 or any subsequent year unless exempted in Subsection R307-6
150-3(1)([a]b).[ Sources subject to Subsection R307-150-4 may be subject to other sections of Rule R307-7
150.] 8
(a) Stationary sources subject to Subsection R307-150-3(1) that emit less than 100 tons per year of9
sulfur dioxide in any subsequent year shall remain subject to Section R307-150-4. 10
(b)Stationary sources that meet the requirements of Subsection R307-150-3(1) that have11
permanently ceased operation are exempt from the requirements of Section R307-150-4 for the years during 12
which the source did not operate at any time during the year, except for the Carbon Power Plant, which, 13
beginning with 2016 emissions, the Division of Air Quality shall include emissions of 8,005 tons per year of 14
sulfur dioxide in the annual regional sulfur dioxide milestone report required as part of the Regional Haze 15
State Implementation Plan. 16
(c)Sources subject to Section R307-150-4 may be subject to other sections of Rule R307-150.17
[ (a) A stationary source that meets the requirements of Subsection R307-150-3(1) that has18
permanently ceased operation is exempt from the requirements of Section R307-150-4 for the years during 19
which the source did not operate at any time during the year. 20
(b) Notwithstanding Subsection R307-150-3(1)(a), beginning with 2016 emissions, the Division of21
Air Quality will include emissions of 8,005 tons per year of sulfur dioxide for the Carbon Power Plant in the 22
annual regional sulfur dioxide milestone report required as part of the Regional Haze State Implementation 23
Plan. 24
(c)Except as provided in Subsection R307-150-3(1)(a), any source that meets the criteria of25
Subsection R307-150-3(1) and that emits less than 100 tons per year of sulfur dioxide in any subsequent year 26
shall remain subject to the requirements of Section R307-150-4 until 2018 or until the first control period 27
under the Western Backstop Sulfur Dioxide Trading Program as established in Subsection R307-250-28
12(1)(a), whichever is earlier.] 29
(2) Section R307-150-5 applies to large major sources.30
(3) Section R307-150-6 applies to each:31
(a)[each ]major source that is not a large major source;32
(b) [each ]source with the potential to emit [5]five tons or more per year of lead;33
(c)[each ]source not included in Subsection[s] R307-150-3(2), R307-150-3(3)(a), or R307-150-34
3(3)(b) that is located in Davis, Salt Lake, Utah, or Weber Counties and that has the potential to emit 25 tons 35
or more per year of any combination of oxides of nitrogen, oxides of sulfur and PM10, or the potential to emit 36
[10]ten tons or more per year of volatile organic compounds; and37
(d) [each ]Part 70 source not included in Subsection[s] R307-150-3(2), R307-150-3(3)(a), R307-38
150-3(3)(b), or R307-150-3(3)(c).39
(4) Section R307-150-8 applies to sources with Standard Industrial Classification codes in the major40
group 13 that have uncontrolled actual emissions greater than one ton per year for a single pollutant of PM10, 41
PM2.5, oxides of nitrogen, oxides of sulfur, carbon monoxide, or volatile organic compounds. These sources 42
include, [but are not limited to, ]industries involved in oil and natural gas exploration, production, and 43
transmission operations[;], well production facilities[;], natural gas compressor stations[;], [and ]natural gas 44
processing plants, and commercial oil and gas disposal wells, and ponds. 45
(a) Sources that require inventory submittals under Subsections R307-150-3(1) through [R307-150-46
3](3) are excluded from the requirements of Section R307-150-8. 47
(5) Section R307-150-9 applies to stationary sources located in a designated ozone nonattainment48
area that have the potential to emit oxides of nitrogen or volatile organic compounds greater than 25 tons per 49
year. 50
51
R307-150-4. Sulfur Dioxide Milestone Inventory Requirements. 52
(1)Annual Sulfur Dioxide Emission Report requirements are as follows.53
(a)Sources identified in Subsection R307-150-3(1) shall submit an annual inventory of sulfur54
dioxide emissions beginning with calendar year 2003 for emissions units including fugitive emissions. 55
Page 2 of 4
(b) The inventory shall include the rate and period of emissions, excess or breakdown emissions, 1
startup and shut down emissions, the specific emissions unit that is the source of the air pollution, type and 2
efficiency of the air pollution control equipment, percent of sulfur content in fuel and how the percent is 3
calculated, and other information necessary to quantify operation and emissions and to evaluate pollution 4
control efficiency. The emissions of a pollutant shall be calculated using the source's actual operating hours, 5
production rates, and types of materials processed, stored, or combusted during the inventoried [time ]period. 6
(2) Each source subject to Section R307-150-4 that is also subject to 40 CFR Part 75 reporting 7
requirements shall submit a summary report of annual sulfur dioxide emissions that were reported to the 8
Environmental Protection Agency under 40 CFR Part 75 in lieu of the reporting requirements in Subection 9
(1)[ above]. 10
(3) Changes in Emission Measurement Techniques include:[. Each source subject to Section R307-11
150-4 that uses a different emission monitoring or calculation method than was used to report their sulfur 12
dioxide emissions in 2006 under Rule R307-150 or 40 CFR Part 75 shall adjust their reported emissions to be 13
comparable to the emission monitoring or calculation method that was used in 2006. The calculations that 14
are used to make this adjustment shall be included with the annual emission report.] 15
(a) each source subject to Section R307-150-4 that uses a different emission monitoring or 16
calculation method than was used to report their sulfur dioxide emissions in 2006 under Rule R307-150 or 40 17
CFR Part 75 shall adjust their reported emissions to be comparable to the emission monitoring or calculation 18
method that was used in 2006; and 19
(b) the calculations that are used to make this adjustment shall be included with the annual emission 20
report. 21
22
R307-150-5. Sources Identified in Subsection R307-150-3(2), Large Major Source Inventory 23
Requirements. 24
(1) Each large major source shall submit an emission inventory annually beginning with calendar 25
year 2002. The inventory shall include PM10, PM2.5, oxides of sulfur, oxides of nitrogen, carbon monoxide, 26
volatile organic compounds, and ammonia for emissions units including fugitive and mobile emissions. 27
(2) For every third year beginning with 2005, the inventory shall also include [all]any other 28
chargeable pollutants and hazardous air pollutants[ not exempted in Section R307-150-7]. 29
(3) For each pollutant specified in Subsection (1) or (2)[ above], the inventory shall include the rate 30
and period of emissions, excess or breakdown emissions, startup and shut down emissions, the specific 31
emissions unit that is the source of the air pollution, composition of air pollutant, type and efficiency of the 32
air pollution control equipment, and other information necessary to quantify operation and emissions and to 33
evaluate pollution control efficiency. The emissions of a pollutant shall be calculated using the source's 34
actual operating hours, production rates, and types of materials processed, stored, or combusted during the 35
inventoried [time ]period. 36
37
R307-150-6. Sources Identified in Subsection R307-150-3(3). 38
(1) Each source identified in Subsection R307-150-3(3) shall submit an inventory every third year 39
beginning with calendar year 2002 for emissions units including fugitive and mobile emissions. 40
(a) The inventory shall include PM10, PM2.5, oxides of sulfur, oxides of nitrogen, carbon monoxide, 41
volatile organic compounds, ammonia, other chargeable pollutants, and hazardous air pollutants not 42
exempted in Section R307-150-7. 43
(b) For each pollutant, the inventory shall include the rate and period of emissions, excess or 44
breakdown emissions, startup and shut down emissions, the specific emissions unit which is the source of the 45
air pollution, composition of air pollutant, type and efficiency of the air pollution control equipment, and 46
other information necessary to quantify operation and emissions and to evaluate pollution control efficiency. 47
The emissions of a pollutant shall be calculated using the source's actual operating hours, production rates, 48
and types of materials processed, stored, or combusted during the inventoried [time ]period. 49
(2) Sources identified in Subsection R307-150-3(3) shall submit an inventory for each year after 50
2002 in which the total amount of PM10, oxides of sulfur, oxides of nitrogen, carbon monoxide, or volatile 51
organic compounds increases or decreases by 40 tons or more per year from the most recently submitted 52
inventory. For each pollutant, the inventory shall meet the requirements of Subsections R307-150-6(1)(a) 53
and R307-150-6(1)(b). 54
55
Page 3 of 4
[R307-150-7. Exempted Hazardous Air Pollutants. 1
(1) The following air pollutants are exempt from this rule if they are emitted in an amount less than 2
that listed in Table 1. 3
4
TABLE 1 5
6
POLLUTANT Pounds/year 7
Arsenic 0.21 8
Benzene 33.90 9
Beryllium 0.04 10
Ethylene oxide 38.23 11
Formaldehyde 5.83 12
13
(2) Hazardous air pollutants, except for dioxins or furans, are exempt from being reported if they are 14
emitted in an amount less than the smaller of the following: 15
(a) 500 pounds per year; or 16
(b) for acute pollutants, the applicable TLV-C expressed in milligrams per cubic meter and 17
multiplied by 15.81 to obtain the pounds-per-year threshold; or 18
(c) for chronic pollutants, the applicable TLV-TWA expressed in milligrams per cubic meter and 19
multiplied by 21.22 to obtain the pounds-per-year threshold; or 20
(d) for carcinogenic pollutants, the applicable TLV-C or TLV-TWA expressed in milligrams per 21
cubic meter and multiplied by 7.07 to obtain the pounds-per-year threshold.] 22
23
R307-150-[8]7. Crude Oil and Natural Gas Source Category. 24
(1) Sources identified in Subsection R307-150-3(4) shall submit an inventory every third year 25
beginning with the 2017 calendar year for emission units. The inventory shall: 26
(a) [The inventory shall ]include the total emissions for PM10, PM2.5, oxides of sulfur, oxides of 27
nitrogen, carbon monoxide and volatile organic compounds for each emission unit at the source[.]and [T]the 28
emissions of a pollutant shall be calculated using the emission unit's actual operating hours, product rates, and 29
types of materials processed, stored, or combusted during the inventoried [time ]period[.]; 30
(b) [The inventory shall ]include the type and efficiency of air pollution control equipment[.]; and 31
(c) [The inventory shall ]be submitted in an electronic format determined by the Director specific to 32
this source category. 33
34
R307-150-[9]8. Annual Ozone Emission Statement. 35
(1) Beginning in the year 2021, sources identified in Subsection R307-150-3(5) shall submit an 36
ozone emission statement to the Division of Air Quality annually by April 15 of each year for the previous 37
year's emissions. 38
(2) A source required to submit an emission statement shall provide the following minimum 39
information: 40
(a) a certification that the information contained in the statement is accurate to the best knowledge of 41
the individual certifying the statement; 42
(b) the physical location where actual emissions occurred; 43
(c) the name and address of person or entity operating or owning the source; 44
(d) the nature of the source; and 45
(e) the total actual emissions of oxides of nitrogen and volatile organic compounds in tons per year 46
for each emission unit. 47
(3) Emission statements shall be submitted in an electronic format determined by the Director. 48
49
KEY: air pollution, reports, inventories 50
Date of Last Change: September 3, 2020 51
Notice of Continuation: November 1, 2023 52
Authorizing, and Implemented or Interpreted Law: 19-2-104(1)(c) 53
Page 4 of 4

ITEM 8

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

Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor
DAQ-013-25
M E M O R A N D U M TO: Air Quality Board THROUGH: Bryce C. Bird, Executive Secretary THROUGH: Erica Pryor, Rules Coordinator FROM: Ana Williams, Environmental Engineer DATE: January 27, 2025 SUBJECT: PROPOSE FOR PUBLIC COMMENT: Amendment to Section R307-110-17. Section IX,
Control Measures for Area and Point Sources, Part H, Emission Limits; and Amendments to Utah State Implementation Plan, Section IX.H.11 and Section IX.H.12: Emission Limitations and Operating Practices.
______________________________________________________________________________________ On November 6, 2020, the Environmental Protection Agency (EPA) proposed “Approval and
Promulgation of Implementation Plans; State of Utah; Salt Lake City and Provo, Utah PM2.5 Redesignations to Attainment and Utah State Implementation Plan Revisions.” (85 FR 71023). This proposal included approval of Utah’s moderate and serious State Implementation Plans (SIPs) for the 2006 24-hr PM2.5 standard for the Salt Lake City nonattainment area (SLC NAA) and the Provo NAA. EPA received adverse public comments regarding how best available control technology (BACT) was addressed for the four major point source refineries included in the SLC NAA. Over the past four years, the division has worked closely with EPA and the refineries to address the comments, resulting in these “Part H” SIP amendments. The proposed amendments to Part H that are incorporated in the SIP through Section R307-110-17 result in the change of specific emission limitations for five major industrial sources located within the serious PM2.5 NAAs, as well as a clarification in the Recordkeeping and Reporting General Requirements for all major industrial sources located within the serious PM2.5 NAAs. These emission limitations serve to fulfill Utah’s statutory obligations under Section 189(b) of the Clean Air Act.

DAQ-013-25 Page 2
The emission limitations proposed in this rulemaking will replace the existing source-wide PM2.5, nitrogen oxides (NOX), and sulfur dioxide (SO2) limitations originally adopted by the Air Quality Board on January 2, 2019, for four major industrial sources: Big West Oil LLC Refinery, Chevron Products Company – Salt Lake Refinery, Holly Corporation: Holly Frontier Sinclair Refinery, and Tesoro Refining and Marketing Company LLC Marathon Refinery: Salt Lake City Refinery. The existing source-wide PM2.5, NOX, and SO2 limitations are being removed at the direction of the EPA as they determined that the limitations did not meet the definition of BACT. Emissions at the sources will continue to be controlled and meet BACT requirements through the existing “Petroleum Refineries” requirements found in Section IX.H.11. General Requirements in conjunction with the new NOX emission limitations that have been added to Section IX.H.12. Source-Specific Emission Limitations for each of the listed refineries. Details regarding the
additional analysis that identified the proposed emission limitations and supporting information surrounding these proposed changes can be found in the documentation associated with the proposed revisions. Amendments were also made to Hexcel’s Part H requirements and there is an additional memo
in this package that includes details. During the final stages of state rulemaking, EPA will propose rulemaking at the federal level, review
public comments, and finalize. This entire process must be complete by the end of the calendar year in 2025 to align with the projected modeling years included in the maintenance plan attainment demonstration. Recommendation: Staff recommend the Board approve the amendments to Section R307-110-17; and amendments to Utah State Implementation Plan, Section IX.H.11 and Section IX.H.12: Emission Limitations and Operating Practices, for a 30-day public comment period.
State of Utah
Administrative Rule Analysis
Revised May 2024
NOTICE OF SUBSTANTIVE CHANGE
TYPE OF FILING: Amendment
Rule or Section Number: R307-110-17 Filing ID: Office Use Only
Date of Previous Publication (Only for CPRs): Click or tap to enter a date.
Agency Information
1. Title catchline:Air Quality, Environmental Quality
Building: Multi-Agency State Office Building
Street address: 195 N 1950 W
City, state: Salt Lake City
Mailing address: PO Box 144820
City, state and zip: Salt Lake City, UT 84114-4820
Contact persons:
Name: Phone: Email:
Ana Williams 801-536-4153 [e-mail]
Erica Pryor 385-499-3416 [e-mail]
Please address questions regarding information on this notice to the persons listed above.
General Information
2. Rule or section catchline:
R307-110-17. Section IX, Control Measures for Area and Point Sources, Part H, Emission Limits.
3. Purpose of the new rule or reason for the change:
The purpose of the amendment to Section R307-110-17 is to amend the Utah State Implementation Plan, Subsections IX.H.11
and IX.H.12 Emission Limits and Operating Practices to comply with the Clean Air Act requirements for Serious PM2.5
nonattainment areas as listed in Title 40 Code of Federal Regulations, Part 51, Subpart Z (40 CFR 51 Subpart Z). Section
R307-110-17 incorporates amendments to Subsections IX.H.11 and IX.H.12 into the rule and shall be amended to change the
Board adoption date to the anticipated adoption date of the amended plan.
4. Summary of the new rule or change:
This rule amendment is in response to feedback and direction provided by the US Environmental Protection Agency after the
original submittal of the Utah Serious PM2.5 nonattainment area State Implementation Plan as adopted by the Utah Air Quality
Board on January 2, 2019. The following rule amendments are proposed: (1) Additional recordkeeping and reporting
requirements under Subsection IX.H.11 General Requirements. (2) The removal of source-wide PM2.5, NOx, and SO2 caps for
four sources under Subsection IX.H.12 Source-Specific Emission Limitations. (3) The addition of new NOx limitations for the
same four sources under Subsection IX.H.12 Source-Specific Emission Limitations. (4) Minor changes to reflect current process
units at two sources under Subsection IX.H.12 Source-Specific Emission Limitations.
Fiscal Information
5. Provide an estimate and written explanation of the aggregate anticipated cost or savings to:
A) State budget:
This rule amendment is not expected to create additional costs or savings for the state government. These facilities are already
permitted and inspected under existing rules and have existing stack testing requirements in place. Inspectors will be able to
confirm compliance as part of normal stack testing processes.
B) Local governments:
This rule amendment is not expected to impact local governments; therefore, no costs or savings are anticipated.
C) Small businesses ("small business" means a business employing 1-49 persons):
This rule amendment is not expected to impact small businesses; therefore, no costs or savings are anticipated.

D) Non-small businesses ("non-small business" means a business employing 50 or more persons):
The Utah Division of Air Quality anticipates that these changes to the proposed rule will impact four non-small businesses. The
impacts are described below.

These changes will require new stack testing requirements on 12 emission units located across four non-small businesses.
Stack testing costs were calculated based on information submitted to the UDAQ as part of the BACT/BACM process in 2017
for the PM2.5 Serious SIP. Assuming an average of $5,441 for stack testing costs, and accounting for inflation changes from
2017 to 2025, an average stack testing value of $7,071.38 was used. Stack tests will be required every three years. Therefore,
for 12 units stack testing every three years across four non-small businesses, the estimated impact will be $84,856.56 every
three years.

E) Persons other than small businesses, non-small businesses, state, or local government entities ("person" means
any individual, partnership, corporation, association, governmental entity, or public or private organization of any character
other than an agency):
This amendment does not apply to persons other than small business, non-small businesses, state, or local government
entities; therefore, no additional costs are expected because of these changes.

F) Compliance costs for affected persons (How much will it cost an impacted entity to adhere to this rule or its changes?):
Compliance costs will consist of additional stack testing for four non-small businesses. The impacts are described below.

Compliance costs are estimated at $84,856.56 every three years for additional stack testing requirements.

G) Regulatory Impact Summary Table (This table only includes fiscal impacts that could be measured. If there are
inestimable fiscal impacts, they will not be included in this table. Inestimable impacts will be included in narratives above.)
Regulatory Impact Table
Fiscal Cost FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $0 $0 $0
Other Persons $0 $0 $0
Total Fiscal Cost $0 $0 $0
Fiscal Benefits FY2025 FY2026 FY2027
State Government $0 $0 $0
Local Governments $0 $0 $0
Small Businesses $0 $0 $0
Non-Small Businesses $84,856.56 $0 $0
Other Persons $0 $0 $0
Total Fiscal Benefits $0 $0 $0
Net Fiscal Benefits $0 $0 $0
H) Department head comments on fiscal impact and approval of regulatory impact analysis:
The Executive Director of the Department of Environmental Quality, Kim D. Shelley, has reviewed and approved
this regulatory impact analysis.

Citation Information
6. Provide citations to the statutory authority for the rule. If there is also a federal requirement for the rule, provide a
citation to that requirement:
Section 19-6a-1642 Section 19-2-104

Incorporations by Reference Information
7. Incorporations by Reference (if this rule incorporates more than two items by reference, please include additional tables):
A) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)
Section IX, Control Measures for Area and Point Sources, Part H, Emission
Limits.
Publisher
Issue Date 05/05/2025
Issue or Version

B) This rule adds or updates the following title of materials incorporated by references (a copy of materials incorporated
by reference must be submitted to the Office of Administrative Rules; if none, leave blank):
Official Title of Materials Incorporated
(from title page)

Publisher
Issue Date
Issue or Version

Public Notice Information
8. The public may submit written or oral comments to the agency identified in box 1. (The public may also request a
hearing by submitting a written request to the agency. See Section 63G-3-302 and Rule R15-1 for more information.)
A) Comments will be accepted until: 03/31/2025
B) A public hearing (optional) will be held:
Date (mm/dd/yyyy): Time (hh:mm AM/PM): Place (physical address or URL):
TBD TBD
To the agency: If more than one hearing will take place, continue to add rows.

9. This rule change MAY become effective on: 04/07/2025
NOTE: The date above is the date the agency anticipates making the rule or its changes effective. It is NOT the effective date.

Agency Authorization Information
To the agency: Information requested on this form is required by Sections 63G-3-301, 63G-3-302, 63G-3-303, and 63G-3-
402. Incomplete forms will be returned to the agency for completion, possibly delaying publication in the Utah State Bulletin
and delaying the first possible effective date.
Agency head or
designee and title:
Bryce C. Bird, Director, Division of Air
Quality
Date: 01/23/2025

R307. Environmental Quality, Air Quality. 1
R307-110. General Requirements: State Implementation Plan. 2
R307-110-17. Section IX, Control Measures for Area and Point Sources, Part H, Emission Limits. 3
The Utah State Implementation Plan, Section IX, Control Measures for Area and Point Sources, 4
Part H, Emission Limits and Operating Practices, as most recently amended by the Utah Air Quality 5
Board on [September 12, 2023]February 5, 2025, pursuant to Section 19-2-104, is incorporated by 6
reference and made a part of Rule R307-110. 7
8
KEY: air pollution, PM10, PM2.5, ozone 9
Date of Last Change: February 7, 2024 10
Notice of Continuation: December 1, 2021 11
Authorizing, and Implemented or Interpreted Law: 19-2-104 12
Page 1 of 1
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H.11. General Requirements: Control Measures for Area and Point1
Sources, Emission Limits and Operating Practices, PM2.5 2
3 a. Except as otherwise outlined in individual conditions of this Subsection IX.H.11 listed4 below, the terms and conditions of this Subsection IX.H.11 shall apply to all sources5 subsequently addressed in Subsection IX.H.12 and 13. Should any inconsistencies6 exist between these subsections, the source specific conditions listed in IX.H.12 and 137 shall take precedence.8 9 b. Definitions:10 11 i.The definitions contained in R307-101-2, Definitions, apply to Section IX, Part H.12 13 ii.Natural gas curtailment means a period of time during which the supply of natural gas 14 to an affected facility is halted for reasons beyond the control of the facility. The act 15 of entering into a contractual agreement with a supplier of natural gas established 16 for curtailment purposes does not constitute a reason that is under the control of a17 facility for the purposes of this definition. An increase in the cost or unit price of18 natural gas does not constitute a period of natural gas curtailment.19 20 c. Recordkeeping and Reporting:21 22 i.Any information used to determine compliance shall be recorded for all periods when23 the source is in operation, and such records shall be kept for a minimum of five years.24 Any or all of these records shall be made available to the Director upon request. 25 26 ii.Each source shall comply with all applicable sections of R307-150 Emission27 Inventories.28
29 iii.Each source shall submit a report of any deviation from the applicable30 requirements of this Subsection IX.H, including those attributable to upset31 conditions, the probable cause of such deviations, and any corrective actions or32 preventive measures taken. The report shall be submitted to the Director no later33 than 24-months following the deviation or earlier if specified by an underlying34 applicable requirement. Deviations due to breakdowns shall be reported according35 to the breakdown provisions of R307-107.36
37 iv.Each source shall comply with all applicable recordkeeping and reporting38 sections of their most recently issued Title V Operating Permit, including39 all requirements associated with the submission of annual compliance40 certifications and biannual monitoring reports. If more stringent or41 additional requirements are listed in Subsections IX.H.12 and IX.H.13,42 each source shall comply with those requirements.43
44 v.Each source shall comply with all applicable recordkeeping and reporting45 as required in 40 CFR 60 and 40 CFR 63 requirements.46 47 48 d. Emission Limitations:49 50 i.All emission limitations listed in Subsections IX.H.12 and IX.H.13 apply at all times,51 unless otherwise specified in the source specific conditions listed in IX.H.12 and 13. 52 53
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ii.All emission limitations of particulate matter (PM2.5) listed in Subsections1 IX.H.12 and IX.H.13 include both filterable PM 2.5 and condensable PM, unless2 otherwise specified in the source specific conditions listed in IX.H.12 and IX.H.13.3 4 e. Stack Testing:5 6 i.As applicable, stack testing to show compliance with the emission limitations for the7 sources in Subsection IX.H.12 and 13 shall be performed in accordance with the8 following:9 10 A.Sample Location: The emission point shall be designed to conform to the11 requirements of 40 CFR 60, Appendix A, Method 1, or other EPA-approved12 testing methods acceptable to the Director. Occupational Safety and Health13 Administration (OSHA) approvable access shall be provided to the test14 location.15 16 B.Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method17 No. 19 "SO2 Removal & PM, SO2, NOx Rates from Electric Utility18 Steam Generators" or other EPA-approved testing methods acceptable to the19 Director.20 21 C.PM: 40 CFR 60, Appendix A, Methods 5, 5b, 5f, 17 or other 22 EPA approved testing methods acceptable to the Director.23 24 D.PM2.5: 40 CFR 51, Appendix M, 201a and 202, or other EPA approved25 testing methods acceptable to the Director. The back half condensables shall be26 used for compliance demonstration as well as for inventory purposes. If a27 method other than 201a is used, the portion of the front half of the catch28 considered PM2.5 shall be based on information in Appendix B of the fifth29 edition of the EPA document, AP-42, or other data acceptable to the30 Director.31 32 E.SO2: 40 CFR 60 Appendix A, Method 6C, or other EPA-33 approved testing methods acceptable to the Director.34 35 F.NOx: 40 CFR 60 Appendix A, Method 7E, or other EPA-approved36 testing methods acceptable to the Director.37 38 G.VOC: 40 CFR 60 Appendix A, Method 25A or other EPA -approved39 testing methods acceptable to the Director.40 41 H.Calculations: To determine mass emission rates (lb/hr, etc.) the42 pollutant concentration as determined by the appropriate methods above shall be43 multiplied by the volumetric flow rate and any necessary conversion factors to give44 the results in the specified units of the emission limitation.45 46 I.A stack test protocol shall be provided at least 30 days prior to the47 test. A pretest conference shall be held if directed by the48 Director.49 50 J.The production rate during all compliance testing shall be no less than 90% of the 51 maximum production rate achieved in the previous three (3) years. If the desired 52 production rate is not achieved at the time of the test, the maximum production rate53 shall be 110% of the tested achieved rate, but not more than the maximum54 allowable production rate. This new allowable maximum production rate shall 55
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remain in effect until successfully tested at a higher rate. The owner/operator shall 1 request a higher production rate when necessary. Testing at no less than 90% of 2 the higher rate shall be conducted. A new maximum production rate (110% of the 3 new rate) will then be allowed if the test is successful. This process may be 4 repeated until the maximum allowable production rate is achieved. 5 6 f. Continuous Emission and Opacity Monitoring 7 8 i. For all continuous monitoring devices, the following shall apply: 9 10 A. Except for system breakdown, repairs, calibration checks, and zero and span 11 adjustments required under paragraph (d) 40 CFR 60.13, the owner/operator of 12 an affected source shall continuously operate all required continuous 13 monitoring systems and shall meet minimum frequency of operation requirements 14 as outlined in R307-170 and 40 CFR 60.13. Flow measurement shall be in 15 accordance with the requirements of 40 CFR 52, Appendix E; 40 CFR 60 16 Appendix B; or 40 CFR 75, Appendix A. 17 18 B. The monitoring system shall comply with all applicable sections of R307-170; 19 40 CFR 13; and 40 CFR 60, Appendix B –Performance Specifications. 20 21 ii. Opacity observations of emissions from stationary sources shall be conducted in 22 accordance with 40 CFR 60, Appendix A, Method 9. 23 24 g. Petroleum Refineries. 25 26 i. Limits at Fluid Catalytic Cracking Units 27 28 A. FCCU SO2 Emissions 29 30 I. Each owner or operator of an FCCU shall comply with an SO2 31 emission limit of 25 ppmvd @ 0% excess air on a 365-day rolling 32 average basis and 50 ppmvd @ 0% excess air on a 7-day rolling 33 average basis. 34 35 II. Compliance with this limit shall be determined using a CEM in accordance 36 with IX.H.11.f. 37 38 B. FCCU PM Emissions 39 40 I. Each owner or operator of an FCCU shall comply with an emission limit of 41 1.0 pounds PM per 1000 pounds coke burn-off. 42 43 II. Compliance with this limit shall be determined by following the stack test 44 protocol specified in 40 C.F.R. §60.106(b) to measure PM emissions on 45 the FCCU. Each owner operator shall conduct stack tests once every 46 three (3) years at each FCCU. 47 48 III. No later than January 1, 2019, each owner or operator of an FCCU subject to 49 NSPS Ja shall install, operate and maintain a continuous parameter monitor 50 system (CPMS) to measure and record operating parameters from the FCCU 51 and control devices as per the requirements of 40 CFR 60.105a(b)(1). No later 52 than January 1, 2019, each owner or operator of an FCCU not subject to 53 NSPS Ja shall install, operate and maintain a continuous opacity monitoring 54 system to measure and record opacity from the FCCU as per the 55
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requirements of 40 CFR 63.1572(b) and comply with the opacity limitation as 1 per the requirements of Table 7 to Subpart UUU of Part 63. 2 3 ii. Limits on Refinery Fuel Gas 4 5 A. All petroleum refineries in or affecting any PM2.5 nonattainment area or any 6 PM10 nonattainment or maintenance area shall reduce the H2S content of the refinery 7 plant gas to 60 ppm or less as described in 40 CFR 60.102a. Compliance shall be 8 based on a rolling average of 365 days. The owner/operator shall comply with 9 the fuel gas monitoring requirements of 40 CFR 60.107a and the related 10 recordkeeping and reporting requirements of 40CFR60.108a. As used herein, 11 refinery “plant gas” shall have the meaning of “fuel gas” as defined in 40 12 CFR60.101a, and may be used interchangeably. 13 14 B. For natural gas, compliance is assumed while the fuel comes from a public utility. 15 16 iii. Limits on Heat Exchangers 17 18 A. Each owner or operator shall comply with the requirements of 40 CFR 63.654 19 for heat exchange systems in VOC service. The owner or operator may elect 20 to use another EPA-approved method other than the Modified El Paso 21 Method if approved by the Director. 22 23 I. The following applies in lieu of 40 CFR 63.654(b): A heat exchange system 24 is exempt from the requirements in paragraphs 63.654(c) through (g) of 25 this section if it meets any one of the criteria in the following paragraphs 26 (1) through (2) of this section. 27 28 1. All heat exchangers that are in VOC service within the heat exchange 29 system that either: 30 31 a. Operate with the minimum pressure on the cooling water side at 32 least 35 kilopascals greater than the maximum pressure on the 33 process side; or 34 35 b. Employ an intervening cooling fluid, containing less than 10 percent by 36 weight of VOCs, between the process and the cooling water. This 37 intervening fluid must serve to isolate the cooling water from the process 38 fluid and must not be sent through a cooling tower or discharged. 39 For purposes of this section, discharge does not include emptying 40 for maintenance purposes. 41 42 2. The heat exchange system cools process fluids that contain less than 10 43 percent by weight VOCs (i.e., the heat exchange system does not 44 contain any heat exchangers that are in VOC service). 45 46 iv. Leak Detection and Repair Requirements 47 48 A. Each owner or operator shall comply with the requirements of 40 CFR 60.590a to 49 60.593a as soon as practicable. 50 51 B. For units complying with the Sustainable Skip Period, previous process unit 52 monitoring results may be used to determine the initial skip period interval provided 53 that each valve has been monitored using the 500 ppm leak definition. 54 55
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v. Requirements on Hydrocarbon Flares 1 2 A. All hydrocarbon flares at petroleum refineries located in or affecting a 3 PM2.5 nonattainment area or any PM10 nonattainment or maintenance area 4 shall be subject to the flaring requirements of NSPS Subpart Ja (40 CFR 5 60.100a–109a), if not already subject under the flare applicability 6 provisions of Ja. 7 8 B. No later than January 1, 2019, all major source petroleum refineries in or 9 affecting any PM2.5 nonattainment area or any PM10 nonattainment or 10 maintenance area shall either 1) install and operate a flare gas recovery 11 system designed to limit hydrocarbon flaring produced from each affected flare 12 during normal operations to levels below the values listed in 40 CFR 13 60.103a(c), or 2) limit flaring during normal operations to 500,000 scfd for 14 each affected flare. Flare gas recovery is not required for dedicated SRU flare 15 and header systems, or HF flare and header systems. 16 17 vi. Requirements on Tank Degassing 18 19 A. Beginning January 1, 2017, the owner or operator of any stationary tank of 40,000- 20 gallon or greater capacity and containing or last containing any organic liquid, with 21 a true vapor pressure equal or greater than 10.5 kPa (1.52 psia) at storage temperature 22 (see R307-324-4(1)) shall not allow it to be opened to the atmosphere unless the 23 emissions are controlled by exhausting VOCs contained in the tank vapor-space to a 24 vapor control device until the organic vapor concentration is 10 percent or less of the 25 lower explosion limit (LEL). 26 27 B. These degassing provisions shall not apply while connecting or disconnecting 28 degassing equipment. 29 30 C. The Director shall be notified of the intent to degas any tank subject to the rule. 31 Except in an emergency situation, initial notification shall be submitted at least 32 three (3) days prior to degassing operations. The initial notification shall 33 include: 34 35 I. Start date and time; 36 37 II. Tank owner, address, tank location, and applicable tank permit numbers; 38 39 III. Degassing operator’s name, contact person, telephone number; 40 41 IV. Tank capacity, volume of space to be degassed, and materials stored; 42 43 V. Description of vapor control device. 44 45 vii. No Burning of Liquid Fuel Oil in Stationary Sources 46 47 A. No petroleum refineries in or affecting any PM2.5 nonattainment area or 48 PM10 nonattainment or maintenance area shall be allowed to burn liquid 49 fuel oil in stationary sources except during natural gas curtailments or as 50 specified in the individual subsections of Section IX, Part H. 51 52 B. The use of diesel fuel meeting the specifications of 40 CFR [80.510]1090.305 53 in standby or emergency equipment is exempt from the limitation of 54 IX.H.11.g.vii.A above. 55
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1 h. Catalytic Oxidation for VOC Control 2 3 i. Internal Combustion Engines 4 5 A. Emissions from each VOC catalytic-controlled IC engine shall be routed through the 6 oxidation catalyst system prior to being emitted to the atmosphere. The oxidation 7 catalyst system shall be installed and operated as outlined in 40 CFR 63.6625(e). 8 9 iii. Natural Gas Combustion Turbines 10 11 A. Emissions from each VOC catalytic-controlled combustion turbine shall be routed 12 through the oxidation catalyst system prior to being emitted to the atmosphere. The 13 oxidation catalyst system shall be installed and operated according to the 14 manufacturer's emission-related written instructions and in a manner consistent with 15 good air pollution control practice for minimizing emissions. 16 17 i. Good Combustion Practices for Emission Minimization 18 19 A. Each owner or operator shall operate all combustion units in 20 accordance with good combustion practices and maintain all 21 combustion units following the manufacturer’s recommendations. 22 23 j. Recordkeeping and Reporting 24 25 A. In addition to the requirements specified in Section IX.H.11.c, each 26 refinery shall comply with the following recordkeeping and reporting 27 requirements, until such time that a Title V Operating Permit is issued. 28 At that time, each refinery shall comply with the applicable 29 recordkeeping and reporting sections of their most recently issued 30 Title V Operating Permit. 31 32 i. All required monitoring data and support information required 33 by Subsections IX.H.11 and IX.H.12 shall be retained by the 34 source for a period of at least five years from the date of the 35 monitoring sample, measurement, report, or application. 36 Support information includes all calibration and maintenance 37 records, all original strip-charts or appropriate readings for 38 continuous monitoring instrumentation, and copies of all 39 reports required by Subsections IX.H.11 and IX.H.12. 40 41 ii. Monitoring reports, if applicable, shall be submitted to the 42 Director as specified in Subsections IX.H.11.e and IX.H.11.f. 43
44 45
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1
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 2
Nonattainment Area 3
a. ATK Launch Systems Inc. Promontory 4
5
i. During the period November 1 to February 28/29 on days when the 24-hour 6
average PM2.5 levels exceed 35 μg/m3 at the nearest real-time monitoring station, 7
the open burning of reactive wastes with properties identified in 40 CFR 261.23 (a) 8
(6) (7) (8) may be conducted when the 24-hour average PM2.5 levels exceed 35 9
μg/m3 at the nearest real time monitoring station in limited quantities. Limited 10
quantities, as authorized in the facility’s RCRA Subpart X permit, of time sensitive 11
reactive wastes may be open burned when the 24-hour average PM2.5 levels 12
exceed 35 μg/m3 at the nearest real-time monitoring station. 13
14
ii. During the period November 1 to February 28/29, on days when the 24-hour average 15
PM2.5 levels exceed 35 μg/m3 at the nearest real-time monitoring station, the 16
following shall not be tested: 17
18
A. Propellant, energetics, pyrotechnics, flares and other reactive compounds greater 19
than 2,400 lbs. per day; or 20
21
B. Rocket motors less than 1,000,000 lbs. of propellant per motor subject to 22
the following exception: 23
24
I. A single test of rocket motors less than 1,000,000 lbs. of propellant per motor 25
is allowed on a day when the 24-hour average PM2.5 level exceeds 35 μg/m3 26
at the nearest real-time monitoring station provided notice is given to the 27
Director of the Utah Air Quality Division. No additional tests of rocket motors 28
less than 1,000,000 lbs. of propellant may be conducted during the inversion 29
period until the 24-hour average PM2.5 level has returned to a 30
concentration below 35 μg/m3 at the nearest real-time monitoring 31
station. 32
33
C. During this period, records will be maintained identifying the size of the 34
rocket motors tested and the 24-hour average PM2.5 level at the nearest 35
real-time monitoring station on days when motor testing occur. 36
37
iii. Natural Gas-Fired Boilers 38
39
A. Building M-576 40
41
I. One 71 MMBTU/hr boiler shall be upgraded with low NOx burners and flue 42
gas recirculation by January 2016. The boiler shall be rated at a maximum of 9 43
ppm. The remaining boiler shall not consume more than 100,000 MCF of 44
natural gas per rolling 12- month period unless upgraded so the NOx 45
emission rate is no greater than 30 ppm. 46
47
II. Emissions to the atmosphere from the Cleaver Brooks 71 48
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131
MMBTU/hr boiler in building M-576 shall not exceed the following 1
concentration: 2
3
a. Pollutant ppmdv (3% O2 dry) 4
NOX 9 5
6
b. Compliance with the above emission limits shall be determined by 7
stack test as outlined in Section IX Part H.11.e of this SIP. 8
9
c. Subsequent to initial compliance testing, stack testing is required 10
every three years. 11
12
B. Building M-14 13
14
I. The two 25 MMBTU/hr boiler shall be upgraded with low NOx 15
burners and flue gas recirculation by December 31, 2024. The boiler 16
shall be rated at a maximum of 9 ppm. 17
II. Emissions to the atmosphere from the two (2) Cleaver Brooks 25 18
MMBTU/hr boilers in building M-14 shall not exceed the 19
following concentrations: 20
21
a. Pollutant ppmdv (3% O2 dry) 22
23
NOX 9 24
25
b. Compliance with the above emission limits shall be determined 26
by stack test as outlined in Section IX Part H.11.e of this 27
SIP. 28
29
c. Subsequent to initial compliance testing, stack testing is 30
required every three years. 31
32
b. Big West Oil LLC Refinery 33
34
i. [Source-wide PM2.5: 35
Following installation of the Flue Gas Blow Back Filter (FGF), but no later than 36
January 1, 2019, combined emissions of PM2.5 (filterable+condensable) shall 37
not exceed 0.29 tons per day and 72.5 tons per rolling 12-month period. No later 38
than January 1, 2019, Big West Oil shall conduct stack testing to establish the ratio 39
of filterable and condensable PM2.5 from the Catalyst Regeneration System. 40
41
A. Setting of emission factors: 42
43
The emission factors derived from the most current performance test shall be 44
applied to the relevant quantities of fuel combusted. Unless adjusted by 45
performance testing as discussed in IX.H.12.b.i.B below, the default emission 46
factors to be used are as follows: 47
48
Natural gas: 49
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131
Filterable PM2.5: 1.9 1
lb/MMscf Condensable PM2.5: 2
5.7 lb/MMscf 3
4
Plant gas: 5
Filterable PM2.5: 1.9 6
lb/MMscf Condensable PM2.5: 7
5.7 lb/MMscf 8 9
Fuel Oil: The PM2.5 emission factors shall be determined from the latest 10
edition of AP-42 or other EPA-approved methods. 11
12
FCC Stacks: The PM2.5 emission factors shall be established by stack test. 13
14
Where mixtures of fuel are used in a Unit, the above factors shall be 15
weighted according to the use of each fuel. 16
17
B. The default emission factors listed in IX.H.12.b.i.A above apply until 18
such time as stack testing is conducted as provided in IX.H.11.e or as 19
outlined below: 20
21
PM2.5 stack testing on the FCC shall be performed initially no later than 22
January 1, 2019 and at least once every three (3) years thereafter. Stack 23
testing shall be performed as outlined in IX.H.11.e. 24
25
C. Compliance with the source-wide PM2.5 Cap shall be determined for each 26
day as follows: Total 24-hour PM2.5 emissions for the emission points 27
shall be calculated by adding the daily results of the PM2.5 emissions 28
equations listed below for natural gas, plant gas, and fuel oil combustion. 29
These emissions shall be added to the emissions from the FCC to arrive at 30
a combined daily PM2.5 31
emission total. 32
33
For purposes of this subsectiona“day”isdefinedasaperiodof24-hours 34
commencing at midnight and ending at the following midnight. 35
36
Daily gas consumption shall be measured by meters that can delineate the 37
flow of gas to the boilers, furnaces and the SRU incinerator. 38
39
The equation used to determine emissions from these units shall be as 40
follows: Emissions = Emission Factor (lb/MMscf) * Gas Consumption 41
(MMscf/24 hrs)/(2,000 42
lb/ton) 43
44
Daily fuel oil consumption shall be monitored by means of leveling gauges 45
on all tanks that supply combustion sources. 46
47
The daily PM2.5 emissions from the FCC shall be calculated using the following 48
equation: E = FR * EF 49
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131
1
Where: 2
E = Emitted PM2.5 3
FR = Feed Rate to Unit (kbbls/day) 4
EF = emission factor (lbs/kbbl), established by the most recent stack test 5
6
Results shall be tabulated for each day, and records shall be kept which include 7
the meter readings (in the appropriate units) and the calculated emissions. 8
9
ii. Source-wide NOx Cap 10
No later than January 1, 2019, combined emissions of NOx shall not exceed 11
0.80 tons per day (tpd) and 195 tons per rolling 12-month period. 12
13
A. Setting of emission factors: 14
15
The emission factors derived from the most current performance test shall be applied 16
to the relevant quantities of fuel combusted. Unless adjusted by performance testing 17
as discussed in IX.H.12.b.ii.B below, the default emission factors to be used are as 18
follows: 19
20
Natural gas: shall be determined from the latest edition of AP-42 or other 21
EPA- approved methods. 22
Plant gas: assumed equal to natural gas 23
Diesel fuel: shall be determined from the latest edition of AP-42 or other 24
EPA- approved methods. 25
26
Where mixtures of fuel are used in a Unit, the above factors shall be weighted 27
according to the use of each fuel. 28
29
B. The default emission factors listed in IX.H.12.b.ii.A above apply until such time 30
as stack testing is conducted as provided in IX.H.11.e or as outlined below: 31
32
Initial NOx stack testing on natural gas/refinery fuel gas combustion 33
equipment above 40 MMBtu/hr has been performed NOx emissions for the FCC 34
are monitored with a continuous emission monitoring system. Refinery Boilers and 35
heaters over 40 MMBtu/hr, but less than 100 MMBtu/hr, are in compliance with 36
monitoring and work practice standards of Subpart DDDDD of Part 63. 37
38
C. Compliance with the source-wide NOx Cap shall be determined for each day 39
as follows: Total 24-hour NOx emissions shall be calculated by adding the 40
emissions for each emitting unit. The emissions for each emitting unit shall be 41
calculated by multiplying the hours of operation of a unit, feed rate to a unit, or 42
quantity of each fuel combusted at each affected unit by the associated 43
emission factor, and summing the results. 44
45
Daily plant gas consumption at the furnaces, boilers and SRU incinerator shall 46
be measured by flow meters. The equations used to determine emissions shall be 47
as follows: 48
49
Page 10 of 46
131
NOx = Emission Factor (lb/MMscf)*Gas Consumption (MMscf/24 hrs)/(2,000 1
lb/ton) 2
3
Where the emission factor is derived from the fuel used, as listed in IX.H.12.b.ii.A 4
above Daily fuel oil consumption shall be monitored by means of leveling gauges 5
on all tanks that supply combustion sources. 6
7
The daily NOx emissions from the FCC shall be calculated using a CEM as outlined 8
in IX.H.11.f 9
10
Total daily NOx emissions shall be calculated by adding the results of the above 11
NOx equations for natural gas and plant gas combustion to the estimate for the 12
FCC. 13
14
Forpurposesofthissubsectiona“day”isdefinedasaperiodof24-hours 15
commencing at midnight and ending at the following midnight. 16
17
Results shall be tabulated for each day, and records shall be kept which include the 18
meter readings (in the appropriate units) and the calculated emissions. 19
20
iii. Source-wide SO2 Cap 21
No later than January 1, 2019, combined emissions of SO2 shall not exceed 0.60 22
tons per day and 140 tons per rolling 12-month period. 23
A. Setting of emission factors: 24
The emission factors derived from the most current performance test shall be 25
applied to the relevant quantities of fuel combusted. The default emission factors 26
to be used are as follows: 27
28
Natural Gas - 0.60 lb SO2/MMscf gas 29
30
Plant Gas: The emission factor to be used in conjunction with plant gas 31
combustion shall be determined through the use of a CEM as outlined in 32
IX.H.11.f. 33
34
SRUs: The emission rate shall be determined by multiplying the 35
sulfur dioxide concentration in the flue gas by the flow rate of the flue 36
gas. The sulfur dioxide concentration in the flue gas shall be determined 37
by CEM as outlined in IX.H.11.f. 38
39
Fuel oil: The emission factor to be used for combustion shall be calculated based 40
on the weight percent of sulfur, as determined by ASTM Method D-4294-89 or 41
EPA approved equivalent acceptable to the Director, and the density of the fuel oil, 42
as follows: 43
44
EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt. % S/100 * (64 lb 45
SO2/32 lbs) 46
47
Where mixtures of fuel are used in a Unit, the above factors shall be 48
weighted according to the use of each fuel. 49
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131
1
B. Compliance with the source-wide SO2 Cap shall be determined for each 2
day as follows: 3
Total daily SO2 emissions shall be calculated by adding the daily SO2 4
emissions for natural gas and plant fuel gas combustion, to those from the 5
FCC and SRU stacks. 6
7
The daily SOx emissions from the FCC shall be calculated using a CEM as outlined 8
in IX.H.11.f 9
10
Daily natural gas and plant gas consumption shall be determined through the use 11
of flow meters. 12
13
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 14
tanks that supply combustion sources. 15
16
Forpurposesofthissubsectiona“day”isdefinedas a period of 24-hours 17
commencing at midnight and ending at the following midnight. 18
19
Results shall be tabulated for each day, and records shall be kept which include 20
CEM readings for H2S (averaged for each day), all meter readings (in the 21
appropriate units), fuel oil parameters (density and wt% sulfur for each day any 22
fuel oil is burned), and the calculated emissions.] 23
24
i. NOx emissions to the atmosphere from the indicated emission points shall not exceed 25
the following rates and concentrations. The averaging period for the following emission 26
limits is determined on a 30-day rolling average. 27
28
Emission Points Emission Rate (lb/MMBtu) 29
30
1. FCC Heater H-101 0.1 lb/MMBtu 31
32
2. Reformer Heaters H-621, 622, 624 0.05 lb/MMBtu 33
34
3. #1 Boiler 0.035 lb/MMBtu 35
36
4. #6 Boiler 0.035 lb/MMBtu 37
38 ii. Initial NOx stack testing has been performed for the #1 Boiler and #6 Boiler. For these 39 units, stack testing shall be performed no later than December 31st, 2025. Subsequent 40 stack testing shall be conducted at least once every three (3) years from the date of the 41 last stack test. Stack testing shall be performed as outlined in IX.H.11.e. 42 43 iii. Initial compliance testing for FCC Heater H-101, Reformer Heater H-621, Reformer 44 Heater H-622, and Reformer Heater H-624 is required. The initial test shall be 45 performed no later than December 31st, 2025. After the initial compliance test, stack 46 testing shall be performed at least once every three (3) years from the date of the last 47 stack test. Stack testing shall be performed as outlined in IX.H.11.e. 48
49
iv. [Emergency and Standby Equipment 50
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131
1
A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed 2
in standby or emergency equipment at all times.] 3
iv. Alternate Startup and Shutdown Requirements 4
5
A. During any day which includes startup or shutdown of the FCCU, combined 6
emissions of SO2 shall not exceed 1.2 tons per day (tpd). For purposes of 7
this subsection, a "day" is defined as a period of 24-hours commencing at midnight 8
and ending at the following midnight. 9
10
B. The total number of days which include startup or shutdown of the 11
FCCU shall not exceed ten (10) per 12-month rolling period. 12
13
v. No later than January 1, 2019, the owner/operator shall install the following 14
to control emissions from the listed equipment: 15
16
Emission Unit Control Equipment
FCCU Regenerator Flue gas blowback “Pall Filter”, quaternary cyclones
with fabric filter
H-404 #1 Crude Heater Ultra-low NOx burners
Refinery Flares Subpart Ja, and MACT CC flaring standards
SRU Tail gas incinerator and redundant caustic scrubber
Product Loading Racks Vapor recovery and vapor combustors
Wastewater Treatment
System
API separator fixed cover, carbon adsorber canisters to
be installed 2019.
17
c. Chemical Lime Company (LHoist North America) 18
19
Lime Production Kiln 20
21
i. No later than January 1, 2019, or upon source start-up, whichever comes later, 22
SNCR technology shall be installed on the Lime Production Kiln. 23
24
a. Effective January 1, 2019, or upon source start-up, whichever comes later, 25
NOx emissions shall not exceed 56 lb/hr. (3-hr rolling average) 26
27
b. Compliance with the above emissions limit shall be determined by stack 28
testing as outlined in Section IX Part H.11.e of this SIP. 29
30
ii. No later than January 1, 2019, or upon source start-up, whichever comes later, a 31
baghouse control technology shall be installed and operating on the Lime Production 32
Kiln. 33
34
a. Effective January 1, 2019, or upon source start-up, whichever comes later, PM 35
emissions shall not exceed 0.12 pounds per ton (lb/ton) of stone feed. (3-hr 36
rolling average) 37
38
b. Effective January 1, 2019, or upon source start-up, whichever comes later, PM2.5 39
(filterable + condensable) emissions shall not exceed 1.5 lbs/ton of stone feed. (3- 40
Page 13 of 46
131
hr rolling average) 1
2
c. Compliance with the above emission limits shall be determined by stack testing as 3
outlined in Section IX Part H.11.e of this SIP and in accordance with 40 CFR 4
63 Subpart AAAAA. 5
6
iii. An initial compliance test is required no later than January 1, 2019 (if start-up occurs 7
on or before January 1, 2019) or within 180 days of source start-up (if start-up 8
occurs after January 1, 2019) All subsequent compliance testing 9
shall be performed at least once annually based upon the date of 10
the last compliance test. 11
12
iv. Upon plant start-up kiln emissions shall be exhausted through the baghouse during all 13
startup, shutdown, and operations of the kiln. 14
15
v. Start-up/shut-down provisions for SNCR technology be as follows: 16
17
a. No ammonia or urea injection during startup until the combustion gases exiting 18
the kiln reach the temperature when NOx reduction is effective, and 19
20
b. No ammonia or urea injection during shutdown. 21
22
c. Records of ammonia or urea injection shall be documented in an operations log. 23
The operations log shall include all periods of start-up/shut-down and subsequent 24
beginning and ending times of ammonia or urea injection which documents v.a 25
and v.b above. 26
27 d. Chevron Products Company - Salt Lake Refinery 28
29
i. [Source-wide PM2.5 Cap 30
31
No later than January 1, 2019, combined emissions of PM2.5 32
(filterable+condensable) shall not exceed 0.305 tons per day (tpd) and 110 tons per 33
rolling 12-month period. 34
35
A. Setting of emission factors: 36
The emission factors derived from the most current performance test shall be 37
applied to the relevant quantities of fuel combusted. Unless adjusted by 38
performance testing as discussed in IX.H.12.f.i.B below, the default emission 39
factors to be used are as follows: 40
41
Natural gas: 42
Filterable PM2.5: 1.9 lb/MMscf 43
Condensable PM2.5: 5.7 lb/MMscf 44
45
Plant gas: 46
Filterable PM2.5: 1.9 lb/MMscf 47
Condensable PM2.5: 5.7 lb/MMscf 48
49
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131
HF alkylation polymer: shall be determined from the latest edition of AP-42 1
(HF alkylation polymer treated as fuel oil #6) or other EPA-approved 2
methods. 3
Diesel fuel: shall be determined from the latest edition of AP-42 or other 4
EPA- approved methods. 5
6
FCC Stack: 7
The PM2.5 emission factors shall be based on the most recent stack test and 8
verified by parametric monitoring as outlined in IX.H.11.g.i.B.III 9
10
Where mixtures of fuel are used in a Unit, the above factors shall be 11
weighted according to the use of each fuel. 12
13
B. The default emission factors listed in IX.H.12.f.i.A above apply until such time 14
as stack testing is conducted as provided in IX.H.11.e or as outlined below: 15
16
Initial PM2.5 stack testing on the FCC stack has been performed and shall 17
be conducted at least once every three (3) years from the date of the last 18
stack test. Stack testing shall be performed as outlined in IX.H.11.e. 19
20
C. Compliance with the source-wide PM2.5 Cap shall be determined for each day 21
as follows: 22
23
Total 24-hour PM2.5 emissions for the emission points shall be calculated by 24
adding the daily results of the PM2.5 emissions equations listed below for natural 25
gas, plant gas, and fuel oil combustion. These emissions shall be added to the 26
emissions from the FCC to arrive at a combined daily PM2.5 emission total. 27
28
Forpurposesofthissubsectiona“day”isdefinedasaperiod of 24-hours 29
commencing at midnight and ending at the following midnight. 30
31
Daily natural gas and plant gas consumption shall be determined through the use of 32
flow meters. 33
34
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 35
tanks that supply combustion sources. 36
37
The equation used to determine emissions for the boilers and furnaces shall be as 38
follows: Emissions = Emission Factor (lb/MMscf) * Gas Consumption (MMscf/24 39
hrs)/(2,000 lb/ton) 40
41
Results shall be tabulated for each day, and records shall be kept which include the 42
meter readings (in the appropriate units) and the calculated emissions. 43
44
ii. Source-wide NOx Cap 45
46
No later than January 1, 2019, combined emissions of NOx shall not exceed 2.1 tons 47
per day (tpd) and 766.5 tons per rolling 12-month period. 48
49
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131
A. Setting of emission factors: 1
2
The emission factors derived from the most current performance test shall be 3
applied to the relevant quantities of fuel combusted. Unless adjusted by 4
performance testing as discussed in IX.H.12.f.ii.B below, the default emission 5
factors to be used are as follows: 6
7
Natural gas: shall be determined from the latest edition of AP-42 or other 8
EPA- approved methods. 9
10
Plant gas: assumed equal to natural gas 11
12
Alkylation polymer: shall be determined from the latest edition of AP-42 (as 13
fuel oil #6) or other EPA-approved methods. 14
15
Diesel fuel: shall be determined from the latest edition of AP-42 or other 16
EPA- approved methods. 17
18
Where mixtures of fuel are used in a Unit, the above factors shall be weighted 19
according to the use of each fuel. 20
21
B. The default emission factors listed in IX.H.12.f.ii.A above apply until such time 22
as stack testing is conducted as provided in IX.H.11.e or as outlined below: 23
24
Initial NOx stack testing on natural gas/refinery fuel gas combustion equipment 25
above 100 MMBtu/hr has been performed and shall be conducted at least once 26
every three (3) years from the date of the last stack test. At that time a new flow- 27
weighted average emission factor in terms of: lbs/MMbtu shall be derived for 28
each combustion type listed in IX.H.12.f.ii.A above. Stack testing shall be 29
performed as outlined in IX.H.11.e. 30
31
C. Compliance with the source-wide NOx Cap shall be determined for each day 32
as follows: 33
34
Total 24-hour NOx emissions shall be calculated by adding the emissions for 35
each emitting unit. The emissions for each emitting unit shall be calculated 36
by multiplying the hours of operation of a unit, feed rate to a unit, or quantity 37
of each fuel combusted at each affected unit by the associated emission 38
factor, and summing the results. 39
40
A NOx CEM shall be used to calculate daily NOx emissions from the FCC. 41
Emissions shall be determined by multiplying the nitrogen dioxide concentration in 42
the flue gas by the flow rate of the flue gas. The NOx concentration in the flue gas 43
shall be determined by a CEM as outlined in IX.H.11.f. 44
45
Forpurposesofthissubsectiona“day”isdefinedasaperiodof24-hours 46
commencing at midnight and ending at the following midnight. 47
48
Daily natural gas and plant gas consumption shall be determined through the use of 49
Page 16 of 46
131
flow meters. 1
2
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 3
tanks that supply combustion sources. 4
5
Results shall be tabulated for each day, and records shall be kept which include the 6
meter readings (in the appropriate units) and the calculated emissions 7
8
iii. Source-wide SO2 9
10
No later than January 1, 2019, combined emissions of SO2 shall not exceed 1.05 11
tons per day (tpd) and 383.3 tons per rolling 12-month period. 12
13
A. Setting of emission factors: 14
The emission factors derived from the most current performance test shall be applied 15
to the relevant quantities of fuel combusted. The default emission factors to be used 16
are as follows: 17
18
FCC: The emission rate shall be determined by the FCC SO2 CEM as outlined 19
in IX.H.11.f. 20
21
SRUs: The emission rate shall be determined by multiplying the sulfur dioxide 22
concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide 23
concentration in the flue gas shall be determined by CEM as outlined in 24
IX.H.11.f. 25
26
Natural gas: EF = 0.60 lb/MMscf 27
28
Fuel oil & HF Alkylation polymer: The emission factor to be used for combustion 29
shall be calculated based on the weight percent of sulfur, as determined by ASTM 30
Method D-4294-89 or EPA-approved equivalent acceptable to the Director, and the 31
density of the fuel oil, as follows: 32
33
EF (lb SO2/k gal) = density (lb/gal) * (1000 gal/k gal) * wt.% S/100 * (64 lb 34
SO2/32 lb S) 35
36
Plant gas: the emission factor shall be calculated from the H2S measurement 37
obtained from the H2S CEM. 38
39
Where mixtures of fuel are used in a Unit, the above factors shall be 40
weighted according to the use of each fuel. 41
42
B. Compliance with the source-wide SO2 Cap shall be determined for each day 43
as follows: Total daily SO2 emissions shall be calculated by adding the daily 44
SO2 45
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131
emissions for natural gas and plant fuel gas combustion, to those from the FCC 1
and SRU stacks. 2
3
Daily natural gas and plant gas consumption shall be determined through the use of 4
flow meters. 5
6
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 7
tanks that supply combustion sources. 8
9
Results shall be tabulated for each day, and records shall be kept which include 10
CEM readings for H2S (averaged for each one-hour period), all meter reading (in 11
the appropriate units), fuel oil parameters (density and wt% sulfur for each day 12
any fuel oil is burned), and the calculated emissions.] 13
14 i. NOx Emissions to the atmosphere from the indicated emission points shall not exceed the 15 following rates and concentrations. The averaging period for the following emission limits 16 is determined on a 30-day rolling average. 17 18 Emission Points Emission Rate (lb/MMBtu) 19 20 1. F-11005 Boiler #5 0.20 lb/MMBtu 21 22 2. F-11006 Boiler #6 0.20 lb/MMBtu 23 24 3. F-11007 Boiler #7 0.20 lb/MMBtu 25 26 4. F-21001 Crude Furnace #1 0.09 lb/MMBtu 27 28 5. F-21002 Crude Furnace #2 0.09 lb/MMBtu 29 30 6. F-32021 FCC Furnace #1 0.17 lb/MMBtu 31 32 7. F-32023 FCC Furnace #2 0.17 lb/MMBtu 33 34 8. F-35001 Reformer Furnace F-1 0.17 lb/MMBtu 35 36 9. F-35002 Reformer Furnace F-2 0.17 lb/MMBtu 37 38 10. F-36017 Alkylation Furnace 0.12 lb/MMBtu 39 40 11. F-70001 Coker Furnace 0.16 lb/MMBtu 41 42 12. F-66100 VGO Furnace #1 0.05 lb/MMBtu 43 44 13. F-66200 VGO Furnace #2 0.05 lb/MMBtu 45 46 ii. Initial NOx stack testing has been performed for the following units: F-11005 Boiler #5, F-47 11006 Boiler #6, F-21001 Crude Furnace #1, F-21002 Crude Furnace #2, F-36017 48 Alkylation Furnace, and F-70001 Coker Furnace. For these units, stack testing shall be 49 conducted at least once every three (3) years from the date of the last stack test. Stack 50 testing shall be performed as outlined in IX.H.11.e. 51 52 iii. For F-11007 Boiler #7, NOx emissions shall be monitored by CEMs to determine 53
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compliance. The CEM shall operate as outlined in IX.H.11.f. 1 2 iv. Initial compliance testing for F-32021 FCC Furnace #1, F-32023 FCC Furnace #2, F-66100 3 VGO Furnace #1, and F-66200 VGO Furnace #2 is required. The initial test shall be 4 performed no later than December 31st, 2025. After the initial compliance test, stack 5 testing shall be performed at least once every three (3) years from the date of the last 6 stack test. Stack testing shall be performed as outlined in IX.H.11.e. 7
8 v. A stack testing port shall be installed for F-35001 Reformer Furnace F-1 and F-35002 9 Reformer Furnace F-2 and initial compliance testing shall be performed no later than 10 December 31st, 2027. Stack testing shall be performed as outlined in IX.H.11.e. 11
12
vi. Emergency and Standby Equipment and Alternative Fuels 13
14
A. [The use of diesel fuel meeting the specifications of 40 CFR 80.510 is 15
allowed in standby or emergency equipment at all times. 16
17
B. HF alkylation polymer may be burned in the Alky Furnace (F-36017).] 18
19
A. Plant coke may be burned in the FCC Catalyst Regenerator. 20
21
vii. Compressor Engine Requirements 22
23
A. Emissions of NOx from each rich-burn compressor engine shall not exceed 24
the following: 25
26
Engine Number NOx in ppmvd @ 0% O2
K35001 236
K35002 208
K35003 230

B. Initial stack testing to demonstrate compliance with the above emission limitations 27
shall be performed no later than January 1, 2019 and at least once every three years 28
thereafter. Stack testing shall be performed as outlined in IX.H.11.e. 29
30
viii. [Flare Calculation 31
32
A. Chevron’s Flare #3 receives gases from its Isomerization unit, Reformer unit as 33
well as its HF AlkylationUnit.TheHFAlkylationUnit’sflowcontributionto Flare #3 34
will not be included in determining compliance with the flow restrictions set in 35
IX.H.11.g.v.B] 36
Page 19 of 46

ix. No later than January 1, 2019, the owner/operator shall install the following to 1
control emissions from the listed equipment: 2
3
Emission Unit Control Equipment
Boilers: 5, 6, 7 Low NOx burners and flue gas recirculation (FGR)
Cooling Water Towers High efficiency drift eliminators
Crude Furnaces F21001, F21002 Low NOx burners
Crude Oil Loading Vapor Combustion Unit (VCU)
FCC Regenerator Stack Vacuum gas oil hydrotreater, Electrostatic
precipitator (ESP) and cyclones
Flares: Flare 1, 2 Flare gas recovery system
HDS Furnaces F64010, F64011 Low NOx burners
Reformer Compressor Drivers
K35001, K35002, K35003
Selective Catalytic Reduction (SCR)
Sulfur Recovery Unit 1 Tail gas treatment unit and tail gas incineration
Sulfur Recovery Unit 2 Tail gas treatment unit and tail gas incineration
Wastewater Treatment Plant Existing wastewater controls system of induced air
flotation (IAF) and regenerative thermal oxidation
(RTO).
Upon completion of startup and initial
commissioning, the Dissolved Nitrogen Floatation
(DNF) process is allowed instead of the IAF system.
4
e. Compass Minerals Ogden Inc. 5
6
i. NOx emissions to the atmosphere from the indicated emission point shall not 7
exceed the following concentrations: 8
9
Emission Points Concentration (ppm) lb/hr
Boiler #1 9.0 1.3
Boiler #2 9.0 1.3
10
Compliance to the above emission limits shall be determined by stack test as outlined in 11
Section IX Part H.11.e of this SIP. A compliance test shall be performed at least 12
annually subsequent to the initial compliance test. 13
14
ii. PM2.5 emissions (filterable+condensable) to the atmosphere from each of 15
the following emission points shall not exceed the listed concentration and 16
lb/hr emission rates: 17
18
Emission Unit PM2.5 Emission Rate (lb/hr) Concentration Emission Rate (grains/dscf) 19
20
AH-500 1.61 0.01
AH-502 0.74 0.04
AH-513 1.49 0.0114
BH-001 0.37 0.01
BH-002 0.47 0.01
BH-008 4.25 0.01
Page 20 of 46

BH-501 1.15 0.01
BH-502 0.06 0.0053
BH-503 0.23 0.01
BH-505 0.12 0.01
AH-1555 0.39 0.01
BH-1400 2.78 0.02
AH-692 0.12 0.01
BH-1516 0.22 0.01
1
A. Compliance to the above emission limits shall be determined by stack test as outlined 2
in Section IX Part H.11.e of this SIP. Compliance testing shall be performed 3
annually. 4
5
B. Process emissions shall be routed through operating controls prior to being emitted to 6
the atmosphere. 7
8
iii. Emissions of VOC from all Magnesium Chloride Evaporators (four stacks total) 9
shall not exceed 6.18 lb/hr. 10
11
A. Compliance shall be determined by stack test as outlined in Section IX Part H.11.e 12
of this SIP. Compliance testing shall be performed at least once every three years. 13
14
B. Process emissions shall be routed through operating controls prior to being emitted to 15
the atmosphere. 16
17
f. Hexcel Corporation: Salt Lake Operations 18
19
i. The following limits shall not be exceeded for fiber line 20
operations: 21
22
A. 5.50 MMscf of natural gas consumed per day. 23
24
B. 0.061 MM pounds of carbon fiber produced per day. 25
26
C. Compliance with each limit shall be determined by the following methods: 27
28
I. Natural gas consumption shall be determined by examination of natural 29
gas billing records for the plant and onsite pipe-line metering. 30
31
II. Fiber production shall be determined by examination of plant production records. 32
33
III. Records of consumption and production shall be kept on a daily basis for all 34
periods when the plant is in operation. 35
36
ii. After a shutdown and prior to startup of fiber lines 13 to 16, the line’s 37
baghouse(s) and natural gas injection dual chambered regenerative thermal 38
oxidizer shall be started and remain in operation during production. 39
40
A. During fiber line production, the static pressure differential across the filter media 41
Page 21 of 46

shall be within the manufacturer’s recommended range and shall be recorded daily. 1
2
B. The manometer or the differential pressure gauge shall be calibrated according to the 3
manufacturer’s instructions at least once every 12 months. 4
5
iii. Filter boxes will be installed on Fiber lines 13 and 14 to control PM2.5 emissions 6
no later than December 31, 2019. 7
8
iv. [Ultra Low NOx Burners with flue gas recirculation shall be installed on Fiber 9
lines 3, 4, and 7 to control NOx emissions no later than December 31, 10
2024. 11
12
13
A. Emission limitations for NOx shall be as follows: 14
15
Concentration (ppm) 16
17
Fiber Line 3 9.0 18
19
Fiber Line 4 9.0 20
21
Fiber Line 7 9.0 22
23
B. Stack testing shall be performed at least once every (3) years based upon the 24
date of the last compliance test and at a time when PAN is not being introduced 25
into the burners. 26
27
v. De-NOx Water Direct Fired Thermal Oxidizer (DFTO) shall be installed on Fiber 28
lines 13, 14, 15, and 16 to control NOx emissions no later than December 31, 29
2024.] 30
31
iv. After a shutdown and prior to startup of the fiber lines, the residence time and 32
temperature associated with the regenerative thermal-oxidation fume incinerators 33
and solvent-coating fume incinerators shall be started and remain in operation during 34
production. 35
36
A. Unless otherwise indicated, the carbon fiber production thermal-oxidation fume 37
incinerators the minimum temperature shall be 1,400 deg F and the residence time 38
shall be greater than or equal to 0.5 seconds 39
40
Solvent-coating fume incinerators the minimum temperature shall be 1,450 deg 41
F and the residence time shall be greater than or equal to 0.5 seconds 42
43
For fiber lines 6, 7, 8, 10, 11, 12, and the line associated with the Research and 44
Development Facility, the solvent coating fume incinerators temperature shall range 45
from 1,400 to 1,700 deg F and the residence time shall be greater than or equal to 46
1.0 second 47
48
Residence times shall be determined by: 49
Page 22 of 46

1
R = V / Qmax 2
Where 3
R = residence time 4
V = interior volume of the incinerator – ft3 5
Qmax = maximum exhaust gas flow rate – ft3/second 6
7
B. Incinerator temperatures shall be monitored with temperature sensing equipment 8
that is capable of continuous measurement and readout of the combustion 9
temperature. The readout shall be located such that an inspector/operator can at 10
any time safely read the output. The measurement shall be accurate within ± 25°F 11
at operating temperature. The measurement need not be continuously recorded. 12
All instruments shall be calibrated against a primary standard at least once every 13
180 days. The calibration procedure shall be in accordance with 40 CFR 60, 14
Appendix A, Method 2, paragraph 6.3, and 10.31, or use a type "K" 15
thermocouple. 16
17
g. Holly Frontier Sinclair Refinery [Corporation: Holly Refining & Marketing 18
Company (Holly Refinery)] 19
20
i. [Source-wide PM2.5 Cap 21
22
No later than January 1, 2019, PM2.5 emissions (filterable + condensable) from 23
all combustion sources shall not exceed 47.6 tons per rolling 12-month period and 24
0.134 tons per day (tpd). 25
26
A. Setting of emission factors: 27
The emission factors derived from the most current performance test shall be 28
applied to the relevant quantities of fuel combusted. Unless adjusted by 29
performance testing as discussed in IX.H.12. g.i.B below, the default 30
emission factors to be used are as follows: 31
32
Natural gas or Plant gas: 33
non-NSPS combustion equipment: 7.65 lb 34
PM2.5/MMscf NSPS combustion equipment: 0.52 lb 35
PM2.5/MMscf 36
37
Fuel oil: 38
The filterable PM2.5 emission factor for fuel oil combustion shall be determined 39
based on the sulfur content of the oil as follows: 40
41
PM2.5 (lb/1000 gal) = (10 * wt. % S) + 3 42
43
The condensable PM2.5 emission factor for fuel oil combustion shall be determined 44
from the latest edition of AP-42. 45
46
FCC Wet Scrubbers: 47
The PM2.5 emission factors shall be based on the most recent stack test 48
and verified by parametric monitoring as outlined in IX.H.11.g.i.B.III. 49
Page 23 of 46

As an alternative to a continuous parameter monitor system or continuous 1
opacity monitoring system for PM emissions from any FCCU controlled by a 2
wet gas scrubber, as required in Subsection IX.H.11.g.i.B.III, the 3
owner/operator may satisfy the opacity monitoring requirements from its 4
FCC Units with wet gas scrubbers through an alternate monitoring program as 5
approved by the EPA and acceptable to the Director. 6
7
B. The default emission factors listed in IX.H.12. g.i.A above apply until such 8
time as stack testing is conducted as outlined below: 9
10
Initial stack testing on all NSPS combustion equipment shall be conducted no 11
later than January 1, 2019 and at least once every three years thereafter. At that 12
time a new flow-weighted average emission factor in terms of: lb 13
PM2.5/MMBtu shall be derived. Stack testing shall be performed as outlined in 14
IX.H.11.e. 15
C. Compliance with the source-wide PM2.5 Cap shall be determined for each day 16
as follows: Total 24-hour PM2.5 emissions for the emission points shall be 17
calculated by adding the daily results of the PM2.5 emissions equations listed 18
below for natural gas, plant gas, and fuel oil combustion. These emissions shall 19
be added to the emissions from the wet scrubbers to arrive at a combined daily 20
PM2.5 emission total. 21
22
For purposes of this subsectiona“day”isdefinedasaperiodof24-hours 23
commencing at midnight and ending at the following midnight. 24
25
Daily natural gas and plant gas consumption shall be determined through the use of 26
flow meters on all gas-fueled combustion equipment. 27
28
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 29
tanks that supply fuel oil to combustion sources. 30
31
The equations used to determine emissions for the boilers and furnaces shall be as 32
follows: 33
34
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural/Plant 35
Gas Consumption 36
(MMscf/day)/(2,000 lb/ton) 37
38
Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil 39
Consumption (kgal/day)/(2,000 lb/ton) 40
41
Results shall be tabulated for each day, and records shall be kept which include all 42
meter readings (in the appropriate units), and the calculated emissions. 43
44
ii. Source-wide NOx Cap 45
46
No later than January 1, 2019, NOx emissions into the atmosphere from all 47
emission points shall not exceed 347.1 tons per rolling 12-month period and 2.09 tons 48
per day (tpd). 49
Page 24 of 46

1
A. Setting of emission factors: 2
The emission factors derived from the most current performance test shall be 3
applied to the relevant quantities of fuel combusted. 4
5
Unless adjusted by performance testing as discussed in IX.H.12. g.ii.B below, 6
the default emission factors to be used are as follows: 7
8
Natural gas/refinery fuel gas combustion using: 9
Low NOx burners (LNB): 41 lbs/MMscf 10
Ultra-Low NOx (ULNB) burners: 0.04 lbs/MMbtu 11
Next Generation Ultra Low NOx burners (NGULNB): 0.10 lbs/MMbtu 12
Boiler #5: 0.02 lbs/MMbtu 13
All other boilers with selective catalytic reduction (SCR): 0.02 14
lbs/MMbtu All other combustion burners: 100 lb/MMscf 15
16
Where: 17
"Natural gas/refinery fuel gas" shall represent any combustion of natural 18
gas, refinery fuel gas, or combination of the two in the associated 19
burner. 20
21
All fuel oil combustion: 120 lbs/Kgal 22
23
B. The default emission factors listed in IX.H.12. g.ii.A above apply until such time 24
as stack testing is conducted as outlined in IX.H.11.e or by NSPS. 25
26
C. Compliance with the Source-wide NOx Cap shall be determined for each day 27
as follows: Total daily NOx emissions for emission points shall be 28
calculated by adding the results of the NOx equations for plant gas, fuel oil, 29
and natural gas 30
combustionlistedbelow.Forpurposesofthissubsectiona“day”isdefinedasa 31
period of 24- hours commencing at midnight and ending at the following 32
midnight. 33
34
Daily natural gas and plant gas consumption shall be determined through the use of 35
flow meters. 36
37
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 38
tanks that supply combustion sources. 39
40
The equations used to determine emissions for the boilers and furnaces shall 41
be as follows: 42
43
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas 44
Consumption (MMscf/day)/(2,000 lb/ton) 45
46
Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas Consumption 47
(MMscf/day)/(2,000 lb/ton) 48
49
Page 25 of 46

Emissions (tons/day) = Emission Factor (lb/MMBTU) * Burner Heat Rating 1
(BTU/hr)* 2
24 hours per day /(2,000 lb/ton) 3
4
Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil 5
Consumption (kgal/day)/(2,000 lb/ton) 6
7
Results shall be tabulated for each day; and records shall be kept which include the 8
meter readings (in the appropriate units), emission factors, and the calculated 9
emissions. 10
11
iii. Source-wide SO2 Cap 12
No later than January 1, 2019, the emission of SO2 from all emission points 13
(excluding routine SRU turnaround maintenance emissions) shall not exceed 110.3 14
tons per rolling 12- month period and 0.31 tons per day (tpd). 15
16
A. Setting of emission factors: 17
The emission factors listed below shall be applied to the relevant quantities 18
of fuel combusted: 19
20
Natural gas - 0.60 lb SO2/MMscf 21
22
Plant gas - The emission factor to be used in conjunction with plant gas 23
combustion shall be determined through the use of a CEM which will measure the 24
H2S content of the fuel gas. The CEM shall operate as outlined in 25
IX.H.11.f. 26
27
Fuel oil - The emission factor to be used in conjunction with fuel oil combustion 28
shall be calculated based on the weight percent of sulfur, as determined by ASTM 29
Method D-4294-89 or EPA-approved equivalent, and the density of the fuel oil, 30
as follows: 31
32
(lb of SO2/kgal) = (density lb/gal) * (1000 gal/kgal) * (wt. %S)/100 * (64 g 33
SO2/32 g S) 34
35
The weight percent sulfur and the fuel oil density shall be recorded for each day 36
any fuel oil is combusted. 37
38
B. Compliance with the Source-wide SO2 Cap shall be determined for each day as 39
follows: Total daily SO2 emissions shall be calculated by adding daily results 40
of the SO2 emissions 41
equations listed below for natural gas, plant gas, and fuel oil combustion. 42
For purposes 43
ofthissubsectiona“day”isdefinedasaperiodof24-hours commencing 44
at midnight and ending at the following midnight. 45
46
The equations used to determine emissions are: 47
48
Emissions (tons/day) = Emission Factor (lb/MMscf) * Natural Gas 49
Page 26 of 46

Consumption (MMscf/day)/(2,000 lb/ton) 1
2
Emissions (tons/day) = Emission Factor (lb/MMscf) * Plant Gas Consumption 3
(MMscf/day)/(2,000 lb/ton) 4
5
Emissions (tons/day) = Emission Factor (lb/kgal) * Fuel Oil 6
Consumption (kgal/24 hrs)/(2,000 lb/ton) 7
8
For purposes of these equations, fuel consumption shall be measured as outlined 9
below: Daily natural gas and plant gas consumption shall be determined through 10
the use of flow meters. 11
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 12
tanks that supply combustion sources. 13
14
Results shall be tabulated for each day, and records shall be kept which include CEM 15
readings for H2S (averaged for each one-hour period), all meter reading (in the 16
appropriate units), fuel oil parameters (density and wt% sulfur for each day any fuel oil 17
is burned), and the calculated emissions.] 18
19
i. NOx Emissions to the atmosphere from the indicated emission points shall not exceed 20
the following rates and concentrations. The averaging period for the following emission 21
limits is determined on a 30-day rolling average. 22
23
Emission Points Emission Rate (lb/MMBtu) 24
25
1. Reformer Reheat Furnace 6H1 0.15 lb/MMBtu 26
27
2. Crude Furnace #1 8H2 0.04 lb/MMBtu 28
29
3. NHDS Reactor Charge Furnace 12H1 0.10 lb/MMBtu 30
31
4. Fractionator Charge Heater 20H2 0.04 lb/MMBtu 32
33
5. Boiler #5 0.02 lb/MMBtu 34
35
6. Boiler #8 0.02 lb/MMBtu 36
37
7. Boiler #9 0.02 lb/MMBtu 38
39
8. Boiler #10 0.02 lb/MMBtu 40
41
9. Boiler #11 0.02 lb/MMBtu 42
43
ii. A stack testing port shall be installed for Reformer Reheat Furnace 6H1 and initial 44
compliance testing shall be performed no later than December 31st, 2028. Stack testing 45
shall be performed as outlined in IX.H.11.e. 46
47
iii. Initial NOx stack testing has been performed for the following units: Crude Furnace #1 48
8H2, NHDS Reactor Charge Furnace 12H1, Boiler #5, Boiler #8, Boiler #9, Boiler #10, 49
Page 27 of 46

and Boiler #11. For these units, stack testing shall be conducted at least once every 1
three (3) years from the date of the last stack test. Stack testing shall be performed as 2
outlined in IX.H.11.e. 3
4
iv. Initial compliance testing for the Fractionator Charge Heater 20H2 is required. The 5
initial test shall be performed no later than December 31st, 2025. After the initial 6
compliance test, stack testing shall be performed at least once every three (3) years 7
from the date of the last stack test. Stack testing shall be performed as outlined in 8
IX.H.11.e. 9
10
v. [Emergency and Standby Equipment 11
12
A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed in 13
standby or emergency equipment at all times.] 14
15
v. No later than January 1, 2019, the owner/operator shall install the following to 16
control emissions from the listed equipment: 17
18
Emission Unit Control Equipment
Process heaters and Boilers 8&11:
boilers LNB+SCR Boilers 5, 9
& 10: SCR
Process heaters 20H2, 20H3, [23H1], 24H1,
25H1: ULNB

Cooling water towers 10,
11
High efficiency drift eliminators
FCCU regenerator stacks WGS with Lo-TOx
Flares Flare gas recovery system
Sulfur recovery unit Tail gas incineration and WGS with Lo-TOx
Wastewater treatment plant API separators, dissolved gas floatation (DGF),
moving bed bio-film reactors (MBBR)
19
h. Kennecott Utah Copper (KUC): Mine 20
21
i. Bingham Canyon Mine (BCM) 22
23
A. Maximum total mileage per calendar day for diesel-powered ore and waste haul 24
trucks shall not exceed 30,000 miles. 25
26
KUC shall keep records of daily total mileage for all periods when the mine is in 27
operation. KUC shall track haul truck miles with a Global Positioning System or 28
equivalent. The system shall use real time tracking to determine daily mileage. 29
30
B. To minimize fugitive dust on roads at the mine, the owner/operator shall perform 31
the following measures: 32
33
I. Apply water to all active haul roads as weather and operational conditions 34
warrant except during precipitation or freezing weather conditions, and shall 35
Page 28 of 46

apply a chemical dust suppressant to active haul roads located outside of the pit 1
influence boundary no less than twice per year. 2
3
II. Chemical dust suppressant shall be applied as weather and operational 4
conditions warrant except during precipitation or freezing weather conditions on 5
unpaved access roads that receive haul truck traffic and light vehicle traffic. 6
7
III. Records of water and/or chemical dust control treatment shall be kept for 8
all periods when the BCM is in operation. 9
10
IV. KUC is subject to the requirements in the most recent federally approved 11
Fugitive Emissions and Fugitive Dust rules. 12
13
C. The In-pit crusher baghouse shall not exceed a PM2.5 emission limit of 14
0.78 lbs/hr (0.007 gr/dscf) PM2.5 monitoring shall be performed by stack 15
testing every three years. 16
17
ii. Copperton Concentrator (CC) 18
19
A. Control emissions from the Product Molybdenite Dryers with a scrubber 20
during operation of the dryers. 21
22
During operation of the dryers, the static pressure differential between the inlet and 23
outlet of the scrubber shall be within the manufacturer’s recommended range and 24
shall be recorded weekly. 25
26
The manometer or the differential pressure gauge shall be calibrated according to the 27
manufacturer’s instructions at least once per year. 28
29
The remaining heaters shall not operate more than 300 hours per rolling 12- month 30
period unless upgraded so the NOx emission rate is no greater than 30 ppm. 31
32
i. Kennecott Utah Copper (KUC): Power Plant 33
34
i. Utah Power Plant 35
36
A. The following requirements are applicable to Unit #4: 37
38
I. Only natural gas shall only be used as a fuel, unless the supplier or transporter 39
of natural gas imposes a curtailment. Unit #4 may then burn coal, only for the 40
duration of the curtailment plus sufficient time to empty the coal bins following 41
the curtailment. The Director shall be notified of the curtailment within 48 42
hours of when it begins and within 48 hours of when it ends. 43
44
II. Emissions to the atmosphere when burning natural gas shall not exceed the 45
following rates and concentrations: 46
47
Pollutant grains/dscf ppmdv lbs/hr lbs/MMBtu 48
68oF. 29.92 in Hg 3% O2 49
Page 29 of 46

1. PM2.5: 1
Filterable 0.004 2
Filterable + 3
condensable 0.03 4
5
2. NOx: 30 32 0.04 6
7
8
B. Upon commencement of operation of Unit #4, stack testing to demonstrate compliance 9
with each emission limitation in IX.H.12.j.i.A and IX.H.12.j.i.B shall be performed 10
as follows: 11
12
* Initial compliance testing for the Unit 4 boiler is required. Initial testing shall be 13
performed when burning natural gas. The initial test shall be performed within 60 14
days after achieving the maximum heat input capacity production rate at which the 15
affected facility will be operated and in no case later than 180 days after the initial 16
startup of a new emission source. 17
18
The limited use of natural gas during maintenance firings and break-in firings does 19
not constitute operation and does not require stack testing. 20
21
Pollutant Test Frequency 22
23
I. PM2.5 every year 24
25
II. NOx every year 26
27
C. Unit #5 (combined cycle, natural gas-fired combustion turbine) shall not exceed 28
the following emission rates to the atmosphere: 29
30
Pollutant lbs/hr ppmdv 31
(15% O2 32
dry) 33
I. PM2.5 with duct firing: 34
Filterable + condensable 18.8 35
36
II. VOC: 2.0 37
38
39
III. NOx: 2.0 40
41
D: Upon commencement of operation of Unit #5*, stack testing to demonstrate 42
compliance with the emission limitations in IX.H.12.m.i.B shall be performed 43
as follows for the following air contaminants 44
45
* Initial compliance testing for the natural gas turbine and duct burner is required. 46
The initial test shall be performed within 60 days after achieving the maximum heat 47
input capacity production rate at which the affected facility will be operated and in no 48
case later than 180 days after the initial startup of a new emission source. 49
Page 30 of 46

1
The limited use of natural gas during maintenance firings and break-in firings 2
does not constitute operation and does not require stack testing. 3
Pollutant Test Frequency 4
5
I. PM2.5 every year 6
7
II. NOx every year 8
9
III. VOC every year 10
11
j. Kennecott Utah Copper: Smelter and Refinery 12
13
i. Smelter: 14
15
A. Emissions to the atmosphere from the indicated emission points shall not exceed the 16
following rates and concentrations: 17
18
I. Main Stack (Stack No. 11) 19
20 1. PM2.5 21
a. 85 lbs/hr (filterable) 22
b. 434 lbs/hr (filterable + condensable) 23
24
2. SO2 25
a. 552 lbs/hr (3 hr. rolling average) 26
b. 422 lbs/hr (daily average) 27
28
3. NOx 154 lbs/hr (daily average) 29
30
II. Holman Boiler 31
32
1. NOx 33
a. 14 lbs/hr, (calendar-day average) 34
35
B. Stack testing to show compliance with the emissions limitations of Condition 36
(A) above shall be performed as specified below: 37
38
EMISSION POINT POLLUTANT TEST FREQUENCY 39
I. Main Stack (Stack No. 11) PM2.5 Every Year 40
SO2 CEM 41
NOx CEM 42
43
II. Holman Boiler NOx Every three years and 44
CEMS or alternate 45
method according to 46
applicable NSPS 47
Standards 48
49
Page 31 of 46

The Holman boiler shall use an EPA approved test method every three years and 1
in between years use or an approved CEMS or alternate method according to 2
applicable NSPS standards. 3
4
C. During startup/shutdown operations, NOx and SO2 emissions are 5
monitored by CEMS or alternate methods in accordance with applicable 6
NSPS standards. 7
8
D. KUC must operate and maintain the air pollution control equipment and 9
monitoring equipment in a manner consistent with good air pollution control 10
practices for minimizing emissions at all times including during startup, 11
shutdown, and malfunction. 12
13
ii. Refinery: 14
15
A. Emissions to the atmosphere from the indicated emission point shall not exceed the 16
following rate: 17
18
EMISSION POINT POLLUTANT MAXIMUM EMISSION RATE 19
20
The sum of two 21
(Tankhouse) 22
Boilers 23
24
(Upgraded 25
26
NOx 9.5 lbs/hr (before December 2020) 27
Page 32 of 46

Tankhouse Boiler) NOx 1.5 lbs/hr (After December 2020) 1
2
Combined Heat Plant NOx 5.96 lbs/hr 3
4
B. Stack testing to show compliance with the above emission limitations shall be 5
performed as follows: 6
7
EMISSION POINT POLLUTANT TESTING FREQUENCY
Upgraded Tankhouse
Boilers

NOx

every three years*
Combined Heat Plant NOx every year
8
*Stack testing shall be performed on boilers that have operated more than 300 9
hours during a three year period. 10
11
C. One 82 MMBTU/hr Tankhouse boiler shall be upgraded to meet a NOx rating of 12
9 ppm no later than December 31, 2020. The remaining Tankhouse boiler shall 13
not consume more than 100,000 MCF of natural gas per rolling 12- month period 14
unless upgraded so the NOx emission rate is no greater than 30 ppm 15
16
D. KUC must operate and maintain the stationary combustion turbine, air pollution 17
control equipment, and monitoring equipment in a manner consistent with good air 18
pollution control practices for minimizing emissions at all times including during 19
startup, shutdown, and malfunction. Records shall be kept on site which indicate the 20
date and time of startups and shutdowns. 21
22
k. Nucor Steel Mills 23
24
i. Emissions to the atmosphere from the indicated emission points shall not exceed the 25
following rates: 26
27
A. Electric Arc Furnace Baghouse 28
29
I. PM2.5 30
1. 17.4 lbs/hr (24 hr. average filterable) 31
2. 29.53 lbs/hr (24 hr. average condensable) 32
33
II. SO2 34
1. 93.98 lbs/hr (3 hr. rolling average) 35
2. 89.0 lbs/hr (daily average) 36
37
III. NOx 59.5 lbs/hr (calendar-day average) 38
39
IV. VOC 22.20 lbs/hr 40
41
B. Reheat Furnace #1 42
NOx 15.0 lb/hr 43
44
Page 33 of 46

C. Reheat Furnace #2 1
NOx 8.0 lb/hr 2
3
ii. Stack testing to show compliance with the emissions limitations of Condition 4
(i) above shall be performed as outlined in IX.H.11.e and as specified 5
below: 6
7
EMISSION POINT POLLUTANT TEST FREQUENCY 8
9
A. Electric Arc Furnace Baghouse PM2.5 every year 10
SO2 11
NOx 12
VOC 13
14
CEM 15
CEM 16
every year 17
Page 34 of 46

B. Reheat Furnace #1 NOx every year 1
2
C. Reheat Furnace #2 NOx every year 3
4
iii. Testing Status (To be applied to (i) and (ii) above) 5
6
A. To demonstrate compliance with the Electric Arc Furnace stack mass emissions 7
limits for SO2 and NOx of Condition (i)(A) above, Nucor shall calibrate, 8
maintain and operate the measurement systems for continuously monitoring for 9
SO2 and NOx concentrations and stack gas volumetric flow rates in the Electric Arc 10
Furnace stack. Such measurement systems shall meet the requirements of 11
R307-170. 12
13
B. For PM2.5 testing, 40 CFR 60, Appendix A, Method 5D, or another EPA 14
approved method acceptable to the Director, shall be used to determine total TSP 15
emissions. If TSP emissions are below the PM2.5 limit, that will constitute 16
compliance with the PM2.5 limit. If TSP emissions are not below the PM2.5 17
limit, the owner/operator shall retest using EPA approved methods specified for 18
PM2.5 testing, within 120 days. 19
20
C. Startup/shutdown NOx and SO2 emissions are monitored by CEMS. 21
22
l. PacifiCorp Energy: Gadsby Power Plant 23
24
i. Steam Generating Unit #1: 25
26
A. Emissions of NOx shall be no greater than 179 lbs/hr on a three (3) 27
hour block average basis. 28
29
B. Emissions of NOx shall not exceed 336 ppmdv (@ 3% O2, dry) 30
31
C. The owner/operator shall install, certify, maintain, operate, and quality-assure 32
a CEM consisting of NOx and O2 monitors to determine compliance with 33
the NOx limitation. The CEM shall operate as outlined in IX.H.11.f. 34
35
ii. Steam Generating Unit #2: 36
37
A. Emissions of NOx shall be no greater than 204 lbs/hr on a three (3) 38
hour block average basis. 39
40
B. Emissions of NOx shall not exceed 336 ppmdv (@ 3% O2, dry) 41
42
C. The owner/operator shall install, certify, maintain, operate, and quality-assure 43
a continuous emission monitoring system (CEMS) consisting of NOx 44
and O2 monitors to determine compliance with the NOx limitation. 45
46
iii. Steam Generating Unit #3: 47
A. Emissions of NOx shall be no greater than 48
49
Page 35 of 46

I. 142 lbs/hr on a three (3) hour block average basis, applicable 1
between November 1 and February 28/29. 2
3
II. 203 lbs/hr on a three (3) hour block average basis, applicable between 4
March 1 and October 31. 5
6
B. Emissions of NOx shall not exceed 7
8
I. 168 ppmdv (@ 3% O2, dry), applicable between November 1 and 9
February 28/29 10
11
II. 168 ppmdv (@ 3% O2, dry), applicable between applicable between March 12
1 and October 31. 13
14
C. The owner/operator shall install, certify, maintain, operate, and quality-assure 15
a CEM consisting of NOx and O2 monitors to determine compliance with 16
the NOx limitation. The CEM shall operate as outlined in IX.H.11.f. 17
18
iv. Steam Generating Units #1-3: 19
20
A. The owner/operator shall use only natural gas as a primary fuel and No. 2 fuel oil 21
or better as back-up fuel in the boilers. The No. 2 fuel oil may be used only 22
during periods of natural gas curtailment and for maintenance firings. 23
Maintenance firings shall not exceed one-percent of the annual plant Btu 24
requirement. In addition, maintenance firings shall be scheduled between April 25
1 and November 30 of any calendar year. Records of fuel oil use shall be kept and 26
they shall show the date the fuel oil was fired, the duration in hours the fuel oil 27
was fired, the amount of fuel oil consumed during each curtailment, and the 28
reason for each firing. 29
30
v. Natural Gas-fired Simple Cycle, Catalytic-controlled Turbine Units: 31
32
A. Total emissions of NOx from all three turbines shall be no greater than 33
600 lbs/day. For purposes of this subsection a “day” is defined as a 34
period of 24-hours commencing at midnight and ending at the 35
following midnight. 36
37
B. Emissions of NOx from each turbine stack shall not exceed 5 ppmvd (@ 15% 38
O2 dry). Emissions shall be calculated on a 30-day rolling average. This 39
limitation applies to steady state operation, not including startup and 40
shutdown. 41
42
C. The owner/operator shall install, certify, maintain, operate, and quality-assure 43
a CEM consisting of NOx and O2 monitors to determine compliance with 44
the NOx limitation. The CEM shall operate as outlined in IX.H.11.f. 45
46
vi. Combustion Turbine Startup / Shutdown Emission Minimization Plan 47
48
A. Startup begins when the fuel values open and natural gas is supplied to 49
Page 36 of 46

the combustion turbines 1
2
B. Startup ends when either of the following conditions is met: 3
4
I. The NOx water injection pump is operational, the dilution air temperature 5
is greater than 600°F, the stack inlet temperature reaches 570°F, the 6
ammonia block value has opened and ammonia is being injected into the SCR 7
and the unit has reached an output of ten (10) gross MW; or 8
9
II. The unit has been in startup for two (2) hours. 10
11
C. Unit shutdown begins when the unit load or output is reduced below ten (10) 12
gross MW with the intent of removing the unit from service. 13
14
D. Shutdown ends at the cessation of fuel input to the turbine combustor. 15
16
E. Periods of startup or shutdown shall not exceed two (2) hours per combustion 17
turbine per day. 18
19
F. Turbine output (turbine load) shall be monitored and recorded on an hourly 20
basis with an electrical meter. 21
22
m. Tesoro Refining and Marketing Company LLC Marathon Refinery: Salt Lake City 23
Refinery 24
25
i. [Source-wide PM2.5 Cap 26
27
No later than January 1, 2019, combined emissions of PM2.5 28
(filterable+condensable) shall not exceed 2.25 tons per day (tpd) and 179 tons per 29
rolling 12-month period. 30
31
A. Setting of emission factors: 32
33
The emission factors derived from the most current performance test shall be 34
applied to the relevant quantities of fuel combusted. Unless adjusted by 35
performance testing as discussed in IX.H.12.p.i.B below, the default emission 36
factors to be used are as follows: 37
38
Natural gas: 39
Filterable PM2.5: 0.0019 40
lb/MMBtu Condensable PM2.5: 41
0.0056 lb/MMBtu 42
43
Plant gas: 44
Filterable PM2.5: 0.0019 45
lb/MMBtu Condensable PM2.5: 46
0.0056 lb/MMBtu 47
48
Fuel Oil: The PM2.5 emission factor shall be determined from the latest edition 49
Page 37 of 46

of AP-42 or other EPA-approved methods. 1
2
FCC Wet Scrubber: 3
The PM2.5 emission factors shall be based on the most recent stack test and verified 4
by parametric monitoring as outlined in IX.H.11.g.i.B.III 5
6
Where mixtures of fuel are used in a Unit, the above factors shall be 7
weighted according to the use of each fuel. 8
9
B. The default emission factors listed in IX.H.12.m.i.A above apply until such time 10
as stack testing is conducted as provided in IX.H.11.e or as outlined below: 11
12
Initial PM2.5 stack testing on the FCC wet gas scrubber stack shall be 13
conducted no later than January 1, 2019 and at least once every three (3) years 14
thereafter. Stack testing shall be performed as outlined in IX.H.11.e. 15
16
C. Compliance with the Source-wide PM2.5 Cap shall be determined for each day 17
as follows: Total 24-hour PM2.5 emissions for the emission points shall be 18
calculated by adding the daily results of the PM2.5 emissions equations listed 19
below for natural gas, plant gas, and fuel oil combustion. These emissions shall 20
be added to the emissions from the wet scrubber to arrive at a combined daily 21
PM2.5 emission total. 22
Forpurposesofthissubsectiona“day”isdefinedasaperiodof24-hours 23
commencing at midnight and ending at the following midnight. 24
Daily natural gas and plant gas consumption shall be determined through the use of 25
flow meters. 26
27
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 28
tanks that supply combustion sources. 29
30
The emissions for each emitting unit shall be calculated by multiplying the hours of 31
operation of a unit feed rate to a unit, or quantity of each fuel combusted at each 32
affected unity by the associated emission factor, and summing the results. 33
34
Results shall be tabulated for each day, and records shall be kept which include the 35
meter readings (in the appropriate units) and the calculated emissions. 36
37
ii. Source-wide NOx Cap 38
39
No later than January 1, 2019, combined emissions of NOx shall not exceed 2.3 tons 40
per day (tpd) and 475 tons per rolling 12-month period. 41
42
A. Setting of emission factors: 43
44
The emission factors derived from the most current performance test shall be 45
applied to the relevant quantities of fuel combusted. Unless adjusted by 46
performance testing as discussed in IX.H.12.m.ii.B below, the default emission 47
factors to be used are as follows: 48
Page 38 of 46

Natural gas/refinery fuel gas combustion using: 1
Low NOx burners (LNB):0.051 lbs/MMbtu 2
Ultra-Low NOx (ULNB) burners: 0.04 lbs/MMbtu 3
Diesel fuel: shall be determined from the latest edition of AP-42 or other 4
EPA- approved methods. 5
6
B. The default emission factors listed in IX.H.12.m.ii.A above apply unless 7
stack testing results are available or emissions are measured by operation of 8
a NOx CEMS. 9
10
Initial NOx stack testing on natural gas/refinery fuel gas combustion equipment 11
above 100 MMBtu/hr has already been performed and shall be conducted at least 12
once every three (3) years. At that time a new flow-weighted average emission 13
factor in terms of: lbs/MMbtu shall be derived. Stack testing shall be performed 14
as outlined in IX.H.11.e. Stack testing is not required for natural gas/refinery 15
fuel gas combustion equipment with a NOx CEMS. 16
17
C. Compliance with the source-wide NOx Cap shall be determined for each day as 18
follows: Total 24-hour NOx emissions shall be calculated by adding the 19
emissions for each emitting unit. The emissions for each emitting unit shall be 20
calculated by 21
multiplying the hours of operation of a unit, feed rate to a unit, or quantity of 22
each fuel combusted at each affected unit by the associated emission factor, 23
and summing the results. 24
25
A NOx CEM shall be used to calculate daily NOx emissions from the FCCU wet 26
gas scrubber stack. Emissions shall be determined by multiplying the nitrogen 27
dioxide concentration in the flue gas by the flow rate of the flue gas. The NOx 28
concentration in the flue gas shall be determined by a CEM as outlined in 29
IX.H.11.f. 30
31
Daily natural gas and plant gas consumption shall be determined through the use of 32
flow meters. 33
34
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 35
tanks that supply combustion sources. 36
37
Forpurposesofthissubsectiona“day”isdefined as a period of 24-hours 38
commencing at midnight and ending at the following midnight. 39
40
Results shall be tabulated for each day, and records shall be kept which include the 41
meter readings (in the appropriate units) and the calculated emissions. 42
43
iii. Source-wide SO2 Cap 44
45
No later than January 1, 2019, combined emissions of SO2 shall not exceed 3.8 tons 46
per day (tpd) and 300 tons per rolling 12-month period. 47
48
A. Setting of emission factors: 49
Page 39 of 46

1
The emission factors derived from the most current performance test shall be applied 2
to the relevant quantities of fuel combusted. The default emission factors to be used 3
are as follows: 4
5
Natural gas: EF = 0.0006 6
lb/MMBtu Propane: EF = 0.0006 7
lb/MMBtu 8
Diesel fuel: shall be determined from the latest edition of AP-42 or other 9
EPA- approved methods. 10
11
Plant fuel gas: the emission factor shall be calculated from the H2S measurement or 12
from the SO2 measurement obtained by direct testing/monitoring. 13
14
Where mixtures of fuel are used in a unit, the above factors shall be 15
weighted according to the use of each fuel. 16
17
B. Compliance with the source-wide SO2 Cap shall be determined for each 18
day as follows: Total daily SO2 emissions shall be calculated by adding the 19
daily SO2 20
emissions for natural gas, plant fuel gas, and propane combustion to those from the 21
wet gas scrubber stack. 22
23
Daily SO2 emissions from the FCCU wet gas scrubber stack shall be 24
determined by multiplying the SO2 concentration in the flue gas by the flow 25
rate of the flue gas. 26
The SO2 concentration in the flue gas shall be determined by a CEM as outlined 27
in IX.H.11.f. 28
29
SRUs: The emission rate shall be determined by multiplying the sulfur dioxide 30
concentration in the flue gas by the flow rate of the flue gas. The sulfur dioxide 31
concentration in the flue gas shall be determined by CEM as outlined in 32
IX.H.11.f 33
34
Daily SO2 emissions from other affected units shall be determined by 35
multiplying the quantity of each fuel used daily at each affected unit by the 36
appropriate emission factor. 37
38
Daily natural gas and plant gas consumption shall be determined through the use of 39
flow meters. 40
41
Daily fuel oil consumption shall be monitored by means of leveling gauges on all 42
tanks that supply combustion sources. 43
44
Results shall be tabulated for each day, and records shall be kept which include 45
CEM readings for H2S (averaged for each one-hour period), all meter reading (in 46
the appropriate units), fuel oil parameters (density and wt% sulfur for each day any 47
fuel oil is burned), and the calculated emissions. 48
49
Page 40 of 46

C. Instead of complying with Condition IX.H.11.g.ii.A, source may reduce the H 1
2S content of the refinery plant gas to 60 ppm or less or reduce SO2 2
concentration from fuel gas combustion devices to 8 ppmvd at 0% O2 or less as 3
described in 40 CFR 60.102a. Compliance shall be based on a rolling 4
average of 365 days. The owner/operator shall comply with the fuel gas or 5
SO2 emissions monitoring requirements of 40 CFR 60.107a and the related 6
recordkeeping and reporting 7
requirementsof40CFR60.108a.Asusedherein,refinery“plantgas”shallhave 8
themeaningof“fuelgas”asdefinedin40CFR60.101a,andmaybeused 9
interchangeably.] 10
11
i. NOx Emissions to the atmosphere from the indicated emission points shall not exceed 12 the following rates and concentrations. The averaging period for the following emission 13
limits is determined on a 30-day rolling average. 14
15
Emission Points Emission Rate (lb/MMBtu) 16
17
1. Crude Unit Furnace H-101 0.054 lb/MMBtu 18
19
2. UFU Furnace F-1 0.065 lb/MMBtu 20 21
ii. Initial NOx stack testing has been performed for the Crude Unit Furnace H-101 and 22
UFU Furnace F-1 and shall be conducted at least once annually from the date of the 23
last stack test. Stack testing shall be performed as outlined in IX.H.11.e. 24
25
iii. Emissions to the atmosphere from the cogeneration turbines with heat recovery 26
steam generation CG1 and CG2 shall not exceed the following concentration. The 27
averaging period for the following emission limit is determined on a 30-day rolling 28 average. 29
30
1. Pollutant ppmdv (15% O2 dry) 31 NOx 32 32
33
2. Initial NOx stack testing has been performed and shall be conducted at least once 34
every two (2) years from the date of the last stack test. Stack testing shall be 35
performed as outlined in IX.H.11.e. 36
37
3. The above emission limits apply to steady state operations when ambient 38
temperature is between 0 °F and 120 °F, not including startup, shutdown, 39 and minimum power load operations. 40
41
iv. Startup / Shutdown / Minimum Power Load Emission Minimization Plan 42
43
1. Startup and shutdown events shall not exceed 614 hours per 12-month rolling 44
period per turbine. 45
46
2. Cumulative minimum power load operations shall not exceed 421 hours per 12-47
month rolling period per turbine. 48
49
Page 41 of 46

3. Startup begins when the fuel valves open and natural gas or fuel gas is supplied to 1
the combustion turbines. 2
3
4. Startup ends when the following conditions are met: 4
5 a. The gas temperature is at least 575 °F, and the unit has reached an output of 6
50% operating load. 7
8
5. Shutdown begins when the unit load or output is reduced below 50% operating 9
load with the intent of removing the unit from service. 10
11
6. Shutdown ends at the cessation of fuel input to the turbine combustor. 12
13
7. Minimum Power Load begins when the turbine generator is less than 50% 14
operating load and the heat recovery steam generation unit is no longer 15
supplemental fired, with the intent to continue operation of the turbine generator at 16 minimum power make. 17
18
8. Minimum Power Load ends when the turbine generator is greater than 50% 19
operating load. 20
21
9. Turbine output (turbine load) shall be monitored and recorded on an hourly basis 22
with an electrical meter. 23
24 v. SO2 emissions from the SRU/TGTU/TGI shall be limited to: 25
26
A. 1.68 tons per day (tpd) for up to 21 days per rolling 12-month period, and 27
28
B. 0.69 tpd for the remainder of the rolling 12-month period. 29
30
C. Daily sulfur dioxide emissions from the SRU/TGI/TGTU shall be determined by 31
multiplying the SO2 concentration in the flue gas by the mass flow of the flue 32
gas. The sulfur dioxide concentration in the flue gas shall be determined by 33
CEM as outlined in IX.H.11.f 34
35
vi. [Emergency and Standby Equipment 36
37
A. The use of diesel fuel meeting the specifications of 40 CFR 80.510 is allowed 38
in standby or emergency equipment at all times.] 39
40
vi. No later than January 1, 2019, the owner/operator shall install the following to 41
control emissions from the listed equipment: 42
43
Emission Unit Control Equipment
FCCU / CO Boiler Wet Gas Scrubber, LoTOx
Furnace F-1 Ultra Low NOx Burners
Tanks Tank Degassing Controls
North and South Flares Flare Gas Recovery
Page 42 of 46

Furnace H-101 Ultra Low NOx Burners
Truck loading rack Vapor recovery unit
Sulfur recovery unit Tail Gas Treatment Unit
API separator Floating roof (single seal)
1
n. The Procter & Gamble Paper Products Company 2
3
i. Emissions to the atmosphere at all times from the indicated emission points shall not 4
exceed the following rates: 5
6
Source: Paper Making Boilers (Each) 7
8
Pollutant Oxygen Ref. lb/hr 9
NOx 3% 3.3 10
11
PM2.5 12
(Filterable and Condensables) 3% 0.9 13
14 Source: Paper Machine Process Stack 15
16
Pollutant Oxygen Ref. lb/hr 17
NOX 3% 13.50 18
19
PM2.5 20
(Filterable and Condensables) 3% 17.95 21
22 Source: Utility Boilers (Each) 23
24
Pollutant Oxygen Ref. lb/hr 25
NOX 3% 1.8 26
27
PM2.5 28
(Filterable and Condensables) 3% 0.74 29
30
A. Compliance with the above emission limits shall be determined by stack test as 31
outlined in Section IX Part H.11.e of this SIP. 32
33
B. Subsequent to initial compliance testing, stack testing is required at a minimum of 34
once every three years. 35
36
ii. Boiler Startup/Shutdown Emissions Minimization Plan 37
38
A. Startup begins when natural gas is supplied to the Boiler(s) with the intent of 39
combusting the fuel to generate steam. Startup conditions end within thirty (30) 40
minutes of natural gas being supplied to the boilers(s). 41
42
B. Shutdown begins with the initiation of the stop sequence of the boiler until 43
the cessation of natural gas flow to the boiler. 44
Page 43 of 46

iii. Paper Machine Startup/Shutdown Emissions Minimization Plan 1
2
A. Startup begins when natural gas is supplied to the dryer combustion equipment with 3
the intent of combusting the fuel to heat the air to a desired temperature for the 4
paper machine. Startup conditions end within thirty (30) minutes of natural gas 5
being supplied to the dryer combustion equipment. 6
7
B. Shutdown begins with the diversion of the hot air to the dryer startup stack and 8
then the cessation of natural gas flow to the dryer combustion equipment. 9
Shutdown conditions end within thirty (30) minutes of hot air being diverted to 10
the dryer startup stack. 11
12
o. Utah Municipal Power Association: West Valley Power Plant. 13
14
i. Total emissions of NOx from all five (5) catalytic-controlled turbines combined shall 15
be no greater than 1050 lb of NOx on a daily basis. For purposes of this subpart, a 16
"day" is defined as a period of 24-hours commencing at midnight and ending at the 17
following midnight. 18
19
ii. Emissions of NOx shall not exceed 5 ppmdv (@ 15% O2, dry) on a 30-day rolling average. 20
21
iii. Total emissions of NOx from all five (5) catalytic-controlled turbines shall include 22
the sum of all periods in the day including periods of startup, shutdown, and 23
maintenance. 24
25
iv. The NOx emission rate (lb/hr) shall be determined by CEM. The CEM 26
shall operate as outlined in IX.H.11.f. 27
28
p. University of Utah: University of Utah Facilities 29
30
i Emissions to the atmosphere from the listed emission points in Building 303 31
LCHWTP shall not exceed the following concentrations: 32
33
Emissions Point Pollutant ppmdv (3% O2 dry) 34
35
BoilerA#.4*
B
NOx 187
.
Boiler1s)#6 & 7 NOx 9
.C.B
Boiler2)#9* NOx 9
.C
Turbin3e)

NOx

9
.D
Page 44 of 46

Turbin4e) and WHRU Duct burner NOx 15 1
2
*By December 31, 2019, Boiler #4 will be decommissioned and Boiler #9 will be installed and 3
operational. 4
5
ii. Stack testing to show compliance with the emissions limitations of Condition i above shall 6
be performed as outlined in IX.H.11.e and as specified below: 7
8
Emissions Point Pollutant Initial Test Test Frequency 9
10
BoilBer #4* NOx * # 11
. 12
Boilers #6 & 7 NOx * # 13
.C 14
15
5Boiler #9* 16
).C 17
18
TDurbine 19
. 20
ETurbine and WHRU 21
22
NOx 23
24
25
NOx 26
27
2020 # 28
29
30
* # 31
Duc.t Burner 32
33
NOx * # 34
35
Initial test already performed 36
37
* Initial tests have been performed and the next method test using EPA approved test 38
methods shall be performed within 3 years of the last stack test. Initial compliance 39
testing for Boiler #9 is required. The initial test date shall be performed within 60 40
days after achieving the maximum heat input capacity production rate at which the 41
affected facility will be operated and in no case later than 180 days after the initial 42
startup of a new emission source. 43
44
# A compliance test shall be performed at least once every three years from the date of the last 45
compliance test that demonstrated compliance with the emission limit(s). Compliance 46
testing shall be performed using EPA approved test methods acceptable to the Director. The 47
Director shall be notified, in accordance with all applicable rules, of any compliance test that 48
is to be performed. 49
50
iii. Boiler #4 in the LCHWTP shall be decommissioned and replaced by Boiler #9 by 51
December 31, 2019. 52
53
iv. By the end of the third quarter of calendar year 2019, Boilers #1, #3, and #4 in 54
the UCHWTP shall be limited to a natural gas usage of 530 MMscf per calendar 55
year. 56
Page 45 of 46

v. The HSC Transformation Project boilers shall be installed and operational by the end 1
of the third quarter of calendar year 2019. The new HSC Transformation Project 2
boilers shall be equipped with low NOx burners rated at 30 ppmvd at 3% O2 or 3
less. 4
5
vi. Records shall be kept on site which indicate the date, and time of startup and shutdown. 6
7
q. Hill Air Force Base 8
9
i. Painting and Depainting Operations 10
11
A. VOC emissions from painting and depainting operations shall not exceed 0.58 tons per 12
day (tpd). 13
14
I. No later than the 28th of each month, a rolling 30-day VOC emission 15
average shall be calculated for the previous month. 16
17
ii. Boilers 18
19
A. The combined NOx emissions for all boilers (except those less than 5 MMBtu/hr) 20
shall not exceed 95 lb/hr. This limit shall not apply during periods of 21
curtailment. 22
23
I. No later than the 28th of each month, the NOx lb/hr emission total 24
shall be calculated for the previous month. 25
26
B. No later than December 31, 2024, no boiler shall be operating on base with the 27
capacity over 30 MMBtu/hr and with a manufacture date older than January 1, 28
1989. 29
30
Page 46 of 46
M E M O R A N D U M 1
2
To: File: 11386 – Hexcel Corporation 3
4
Through: Jon L. Black, Major New Source Review Section Manager 5
6
From: Tad Anderson, Engineer, Major New Source Review Section 7
8
Date: January 2, 2025 9
10
Subject: PM2.5 SIP Condition Amendment Request 11
12
On June 11, 2024, Hexcel Corporation (Hexcel) met with UDAQ to discuss the feasibility of two of the 13
PM2.5 SIP conditions. The two conditions Hexcel is requesting a feasibility determination on pertain to 14
Ultra Low NOx Burners (condition H.12.f.iv) and De-NOx Water systems (condition H.12.f.v). Hexcel 15
submitted two letters on August 1, 2024 addressing the technical feasibility of Ultra Low NOx Burners 16
with flue gas recirculation on fiber lines 3, 4, and 7 and De-NOx Water Direct Fired Thermal Oxidizer on 17
fiber lines 13, 14, 15 and 16. UDAQ requested additional information for the technical feasibility. 18
Hexcel submitted the “SIP Conditions Amendment Request Additional Information” on December 5, 19
2024. This response addressed both conditions and included an updated BACM analysis. Each SIP 20
requested removal condition will be addressed individually below. 21
22
Condition H.12.f.iv 23
“Ultra Low NOx Burners with flue gas recirculation shall be installed on Fiber Lines 3, 4 and 7 to 24
control NOx emissions no later than December 31, 2024.” 25
26
Hexcel has submitted a “SIP Condition Amendment Request” on August 1, 2024 and additional 27
information submitted “SIP conditions Amendment Request Additional Information” on December 6, 28
2024, which contained a request to remove Condition H.12.f.iv (Ultra Low NOx Burners on fiber lines 3, 29
4 and 7) due to technical infeasibility. 30
31
The submitted documents describe the operational requirements for the thermal oxidizers on fiber lines 3, 32
4 and 7. The thermal oxidizers are used as a control device for hydrogen cyanide, ammonia and VOCs. 33
For the thermal oxidizer to operate correctly for the combustion of the hydrogen cyanide, the temperature 34
must be maintained at approximately 1,400 degrees Fahrenheit. With the addition of the flue gas 35
recirculation on the low NOx burners to lower the NOx emissions to 9 ppm, the flue gas recirculation 36
reduces the combustion temperatures (to approximately 1000 degrees Fahrenheit) to lower thermal NOx 37
creation. For this reason, flue gas recirculation is not technically feasible to be added to a thermal 38
oxidizer. 39
40
The burner size for the existing thermal oxidizers for fiber lines 3 (0.75 MMBtu/hr), 4 (2.0 MMBtu/hr) 41
and 7 (0.30 MMBtu/hr) are all below 5 MMBtu/hr. Hexcel hired an internationally reputed industrial 42
pollution control company to determine if the existing burners can be replaced withUltra Low NOx 43
burners. The company contacted Honeywell, Fives and Access (burner manufacturers) to determine if 44
there were any burners that could operate at 1400 degrees Fahrenheit with a low NOx emissions rate. All 45
three burner companies had no burners at the existing size that could meet the 9 ppm and 1400 degrees 46
Fahrenheit. 47
48
DAQE-MN102370025-18
Page 2
The submitted “SIP conditions Amendment Request Additional Information” on December 6, 2024, 1
contained an updated BACM. The BACM included a top-down analysis of all the control technologies 2
for lowering NOx emissions. The BACM demonstrated that Low NOx burner operation on the thermal 3
oxidizer is technically infeasible. The replacement of the existing burner with a direct fired thermal 4
oxidizer is technically feasible. The lowest cost to replace the thermal oxidizer with a direct fired thermal 5
oxidizer is $94,398 per ton removed for fiber line #7 making the replacement economically infeasible. 6
7
Condition H.12.f.v 8
“De-NOx Water Direct Fired Thermal Oxidizer (DFTO) shall be installed on Fiber Lines 13, 14, 15, and 9
16 to control NOx emissions no later than December 31, 2024.” 10
11
Hexcel has submitted a “SIP Condition Amendment Request” on August 1, 2024 and additional 12
information submitted “SIP conditions Amendment Request Additional Information” on December 6, 13
2024, which contained a request to remove Condition H.12.f.v (De-NOx Water Direct Fired Thermal 14
Oxidizer on fiber lines 13 thru 16) due to technical infeasibility. 15
16
The submitted documents described the operational implications from installing the De-NOx water 17
system to the DFTO. Hexcel has installed the De-NOx water system on Fiber Lines 13, 14, 15 and 16 to 18
meet the SIP requirements. Once installed and operating, Hexcel experienced the following operational 19
complications. Hexcel noticed “caking” in the baghouse located downstream of the system. The caking 20
of the baghouse decreases the removal efficiency and increases maintenance operations which increases 21
down time. Hexcel experienced an increase in natural gas usage on Fiber Lines 13, 14, 15 and 16, since 22
the De-NOx water system decreases the burner temperature. The increase in natural gas increases the 23
combustion emissions of all the associated fiber lines which leads to the formation of more NOx. In 24
March 2024, Hexcel stack tested the fiber lines and the testing indicated that the De-water system lowered 25
the destruction removal efficiency of hydrogen cyanide and ammonia. Hexcel hired an internationally 26
reputed industrial pollution control company to provide a technical analysis of why the De-NOx water 27
system was not working as designed. The industrial pollution control company concluded that, due to the 28
DFTO requiring a multi-stage combustion chamber configuration and the system not operating in a zero-29
oxygen environment, the De-NOx water system is unable to achieve the designed NOx reductions. The 30
industrial pollution control company also concluded that the existing system would require extensive 31
retrofitting to the DFTO. For this reason, the implementation of the De-NOx water system to the DFTO 32
is not technically feasible. 33
34
The use of ultra-low NOx burners with flue gas recirculation and the installation of the De-NOx water 35
system were not included in the original conclusion for Hexcel’s PM2.5 SIP Evaluation Report and were 36
not considered as “PM2.5 SIP Specific Requirements” (Section 5 of the UTAH PM2.5 SIP SERIOUS 37
Evaluation Report dated July 1, 2018). Hexcel submitted a revised BACT analysis on June 19, 2018, 38
after the June Board meeting. The June 19th submittal revised the economic analysis, which resulted in 39
the costs of some of the equipment being considered economically feasible. UDAQ had originally 40
determined the equipment was not economically feasible based on the original economic analysis 41
received prior to the June meeting. Therefore, based on the revised information, UDAQ had incorporated 42
new requirements into the final draft as a consideration for ultra-low NOx burners and De-NOx water 43
system. The PM2.5 SIP modeling analysis had already been completed at this time and there was no need 44
to revisit the model as this was an assumed reduction in potential emissions which would not affect the 45
model. Therefore, the removal of the ultra-low NOx burners and De-NOx water system will not result in 46
an emission increase as these potential reductions in emissions were never considered in the original 47
modeling analysis performed for the PM2.5 Serious SIP demonstration. 48
49
DAQE-MN102370025-18
Page 3
Conclusion 1
The UDAQ has reviewed the submitted documentation and agrees that the Low NOx burner operation on 2
the thermal oxidizer is technically infeasible, the replacement of the existing burner with a direct fired 3
thermal oxidizer is technically feasible and the cost to replace the thermal oxidizers with a direct fired 4
thermal oxidizer is economically infeasible. 5
6
The UDAQ will remove PM2.5 SIP conditions IX.H.12.f.iv and IX.H.12.f.v, amend the Utah PM2.5 SIP 7
Serious Evaluation Report for Hexcel Corporation to incorporate the cost analysis for replacing the 8
thermal oxidizers with direct fired thermal oxidizers, and update the technological feasibility analysis for 9
the implementation of a De-NOx water system to the DFTO. 10
11
12

ITEM 9
Air Toxics

195 North 1950 West • Salt Lake City, Utah
Mailing Address: P.O. Box 144820 • Salt Lake City, Utah 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

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

DAQA-757-24

M E M O R A N D U M

TO: Air Quality Board

FROM: Bryce C. Bird, Executive Secretary

DATE: November 5, 2024

SUBJECT: Air Toxics, Lead-Based Paint, and Asbestos (ATLAS) Section Compliance Activities –
October 2024
______________________________________________________________________________________

Asbestos Demolition/Renovation NESHAP Inspections 9
Asbestos AHERA Inspections 9
Asbestos State Rules Only Inspections 3
Asbestos Notification Forms Accepted 182
Asbestos Telephone Calls 358
Asbestos Individuals Certifications Approved 114
Asbestos Company Certifications 13
Asbestos Alternate Work Practices Approved 5
Lead-Based Paint (LBP) Inspections 2
LBP Notification Forms Approved 0
LBP Telephone Calls 84
LBP Letters Prepared and Mailed 7
LBP Courses Reviewed/Approved 0
LBP Course Audits 0
LBP Individual Certifications Approved 44
DAQA-757-24
Page 2

LBP Firm Certifications 25
Notices of Violation Sent 0
Compliance Advisories Sent 10
Warning Letters Sent 2
Settlement Agreements Finalized 2
Penalties Agreed to:
Squires Construction/Calvin Squires $1,200.00
Asbestos Abatement Services, LLC/Stephen Cisney $150.00
Total: $1,350.00

195 North 1950 West • Salt Lake City, Utah Mailing Address: P.O. Box 144820 • Salt Lake City, Utah 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
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
DAQA-803-24
M E M O R A N D U M TO: Air Quality Board FROM: Bryce C. Bird, Executive Secretary DATE: December 3, 2024 SUBJECT: Air Toxics, Lead-Based Paint, and Asbestos (ATLAS) Section Compliance Activities –November 2024 ______________________________________________________________________________________ Asbestos Demolition/Renovation NESHAP Inspections 6
Asbestos AHERA Inspections 10
Asbestos State Rules Only Inspections 3
Asbestos Notification Forms Accepted 125
Asbestos Telephone Calls 296
Asbestos Individuals Certifications Approved 103
Asbestos Company Certifications 14
Asbestos Alternate Work Practices Approved 2
Lead-Based Paint (LBP) Inspections 0
LBP Notification Forms Approved 0
LBP Telephone Calls 69
LBP Letters Prepared and Mailed 1
LBP Courses Reviewed/Approved 0
LBP Course Audits 0
LBP Individual Certifications Approved 13
DAQA-803-24 Page 2
LBP Firm Certifications 7
Notices of Violation Sent 0
Compliance Advisories Sent 4
Warning Letters Sent 7
Settlement Agreements Finalized 1
Penalties Agreed to:
Impact Demolition/AJ Kim $250.00

195 North 1950 West • Salt Lake City, Utah Mailing Address: P.O. Box 144820 • Salt Lake City, Utah 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
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
DAQA-021-25
M E M O R A N D U M TO: Air Quality Board FROM: Bryce C. Bird, Executive Secretary DATE: January 7, 2025 SUBJECT: Air Toxics, Lead-Based Paint, and Asbestos (ATLAS) Section Compliance Activities –December 2024 ______________________________________________________________________________________ Asbestos Demolition/Renovation NESHAP Inspections 12
Asbestos AHERA Inspections 9
Asbestos State Rules Only Inspections 7
Asbestos Notification Forms Accepted 139
Asbestos Telephone Calls 293
Asbestos Individuals Certifications Approved 87
Asbestos Company Certifications 11
Asbestos Alternate Work Practices Approved 10
Lead-Based Paint (LBP) Inspections 2
LBP Notification Forms Approved 1
LBP Telephone Calls 55
LBP Letters Prepared and Mailed 0
LBP Courses Reviewed/Approved 0
LBP Course Audits 0
LBP Individual Certifications Approved 10
DAQA-021-25 Page 2
LBP Firm Certifications 8
Notices of Violation Sent 0
Compliance Advisories Sent 6
Warning Letters Sent 3
Settlement Agreements Finalized 0

Compliance

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

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

SPENCER J. COX
Governor

DEIDRE HENDERSON
Lieutenant Governor
DAQC-1122-24

M E M O R A N D U M

TO: Air Quality Board

FROM: Bryce C. Bird, Executive Secretary

DATE: November 6, 2024

SUBJECT: Compliance Activities – October 2024
_____________________________________________________________________________________

ACTIVITIES:
Activity Monthly Total 36-Month Average
Inspections 80 61
On-Site Stack Test & CEM Audits 9 5
Stack Test & RATA Report Reviews 72 38
Emission Report Reviews 30 20
Temporary Relocation Request Reviews 7 6
Fugitive Dust Control Plan Reviews 134 124
Soil Remediation Report Reviews 2 2
Open Burn Permits Issued 1,014 634
Miscellaneous Inspections1 13 16
Complaints Received 51 20
Wood Burning Complaints Received 0 3
Breakdown Reports Received 1 1
Compliance Actions Resulting from a Breakdown 0 0
VOC Inspections (Gas station vapor recovery) 0 0
Warning Letters Issued 5 2
Notices of Violation Issued 1 0
Compliance Advisories Issued 5 6
No Further Action Letters Issued 4 2
Settlement Agreements Reached 5 2
Penalties Assessed $3,496 $197,867.21
1Miscellaneous inspections include, e.g., surveillance, complaint, on-site training, dust patrol, smoke patrol, open
burning, etc.
DAQC-1122-24
Page 2

SETTLEMENT AGREEMENTS:
Party Amount
Maverik Trucking $471
Redmond Minerals $471
Mountain Country Foods $471
Intermountain Regional Landfill $1,500
TM Crushing – Talons Cove $583

UNRESOLVED NOTICES OF VIOLATION:
Party Date Issued
Citation Oil and Gas (in administrative litigation) 01/15/2020
Uinta Wax Operating (formerly CH4 Finley) 07/24/2020
Finley Resources 09/15/2022
Holcim 12/19/2023
Holcim 03/27/2024
Big West Oil 07/19/2024
Holcim 08/02/2024
Flowers Bakeries, LLC 09/17/2024
Winds Exploration and Production 09/17/2024
Big West Oil 10/01/2024

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

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

SPENCER J. COX
Governor

DEIDRE HENDERSON
Lieutenant Governor
DAQC-1220-24

M E M O R A N D U M

TO: Air Quality Board

FROM: Bryce C. Bird, Executive Secretary

DATE: December 11, 2024

SUBJECT: Compliance Activities – November 2024
_____________________________________________________________________________________

ACTIVITIES:
Activity Monthly Total 36-Month Average
Inspections 72 62
On-Site Stack Test & CEM Audits 1 5
Stack Test & RATA Report Reviews 52 38
Emission Report Reviews 26 20
Temporary Relocation Request Reviews 4 6
Fugitive Dust Control Plan Reviews 90 123
Soil Remediation Report Reviews 1 2
Open Burn Permits Issued 546 649
Miscellaneous Inspections1 17 16
Complaints Received 32 20
Wood Burning Complaints Received 2 3
Breakdown Reports Received 1 1
Compliance Actions Resulting from a Breakdown 0 0
VOC Inspections (Gas station vapor recovery) 0 0
Warning Letters Issued 4 2
Notices of Violation Issued 0 0
Compliance Advisories Issued 8 6
No Further Action Letters Issued 0 2
Settlement Agreements Reached 0 2
Penalties Assessed $0 $197,867.21
1Miscellaneous inspections include, e.g., surveillance, complaint, on-site training, dust patrol, smoke patrol, open
burning, etc.
DAQC-1220-24
Page 2

SETTLEMENT AGREEMENTS:
Party Amount

UNRESOLVED NOTICES OF VIOLATION:
Party Date Issued
Citation Oil and Gas (in administrative litigation) 01/15/2020
Uinta Wax Operating (formerly CH4 Finley) 07/24/2020
Finley Resources 09/15/2022
Holcim 12/19/2023
Holcim 03/27/2024
Big West Oil 07/19/2024
Holcim 08/02/2024
Flowers Bakeries, LLC 09/17/2024
Big West Oil 10/01/2024

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

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

SPENCER J. COX
Governor

DEIDRE HENDERSON
Lieutenant Governor
DAQC-015-25

M E M O R A N D U M

TO: Air Quality Board

FROM: Bryce C. Bird, Executive Secretary

DATE: January 7, 2025

SUBJECT: Compliance Activities – December 2024
_____________________________________________________________________________________

ACTIVITIES:
Activity Monthly Total 36-Month Average
Inspections 78 62
On-Site Stack Test & CEM Audits 0 5
Stack Test & RATA Report Reviews 48 38
Emission Report Reviews 7 20
Temporary Relocation Request Reviews 3 6
Fugitive Dust Control Plan Reviews 72 123
Soil Remediation Report Reviews 1 2
Open Burn Permits Issued 182 649
Miscellaneous Inspections1 11 16
Complaints Received 26 20
Wood Burning Complaints Received 16 3
Breakdown Reports Received 1 1
Compliance Actions Resulting from a Breakdown 0 0
VOC Inspections (Gas station vapor recovery) 0 0
Warning Letters Issued 7 2
Notices of Violation Issued 0 0
Compliance Advisories Issued 8 6
No Further Action Letters Issued 0 2
Settlement Agreements Reached 1 2
Penalties Assessed $2,827 $197,867.21
1Miscellaneous inspections include, e.g., surveillance, complaint, on-site training, dust patrol, smoke patrol, open
burning, etc.
DAQC-015-25
Page 2

SETTLEMENT AGREEMENTS:
Party Amount
Lisbon Valley Mining $2,827

UNRESOLVED NOTICES OF VIOLATION:
Party Date Issued
Citation Oil and Gas (in administrative litigation) 01/15/2020
Ovintiv Production Inc. 07/14/2020
Uinta Wax Operating (formerly CH4 Finley) 07/24/2020
Finley Resources 09/15/2022
Holcim 12/19/2023
Holcim 03/27/2024
Big West Oil (tolling agreement until 2/25/2025) 07/19/2024
Holcim 08/02/2024
Flowers Bakeries, LLC 09/17/2024
Big West Oil (tolling agreement until 2/25/2025) 10/01/2024

Monitoring
Utah Division of Air Quality
0
10
20
30
40
50
60
70
80
90
100
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 29 30 31
PM
2.
5
(µ
g
/
m
3)
Days
Utah 24-Hr PM2.5 Data November 2024
Brigham City Bountiful Copperview Erda
Harrisville Hawthorne Lindon Near road
Rose Park Roosevelt Spanish Fork Smithfield
Environmental Quality Vernal 24-hr Exceedence Value is 35 µg/m3
Exceedence Value is 35 µg/m3
*EnvironmentalQuality (EQ) previously named Technical Support Center (TSC)
*
BG BV CV ED HV HW LN NR RP RS SF SM EQ V4
Arith Mean 5 5 6 4 5 6 6 8 6 4 4 5 6 4Max 24-hr Avg 10 9 12 9 11 12 12 15 14 10 8 10 13 698th percentile 10 9 12 8 11 11 12 14 13 9 8 10 12 6Days of Data 30 30 30 30 30 30 30 30 30 30 30 30 30 30
Days >35 µg/m3 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Utah Division of Air Quality
0
10
20
30
40
50
60
70
80
90
100
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 29 30 31
PM
2.
5
(µ
g
/
m
3)
Days
Utah 24-Hr PM2.5 Data December 2024
Brigham City Bountiful Copperview Erda
Harrisville Hawthorne Lindon Near road
Rose Park Roosevelt Spanish Fork Smithfield
Environmental Quality Vernal 24-hr Exceedence Value is 35 µg/m3
Exceedence Value is 35 µg/m3
*EnvironmentalQuality (EQ) previously named Technical Support Center (TSC)
*
BG BV CV ED HV HW LN NR RP RS SF SM EQ V4
Arith Mean 8 11 15 9 9 13 11 17 14 6 8 7 13 6Max 24-hr Avg 21 27 44 22 25 33 30 46 36 12 27 20 35 13
98th percentile 20 27 40 22 24 33 30 45 35 12 25 19 34 12Days of Data 31 31 31 31 31 31 31 31 31 31 31 31 31 31
Days >35 µg/m3 0 0 4 0 0 0 0 4 1 0 0 0 0 0
Utah Division of Air Quality
0
10
20
30
40
50
60
70
80
90
100
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 29 30 31
PM
2.
5
(µ
g
/
m
3)
Days
Utah 24-Hr PM2.5 Data January 2025
Brigham City Bountiful Copperview Erda
Harrisville Hawthorne Lindon Near road
Rose Park Roosevelt Spanish Fork Smithfield
Environmental Quality Vernal 24-hr Exceedence Value is 35 µg/m3
Exceedence Value is 35 µg/m3
*Environmental Quality (EQ) previously named Technical Support Center (TSC)
*
BG BV CV ED HV HW LN NR RP RS SF SM EQ V4
Arith Mean 5 6 7 3 5 7 8 9 7 4 5 5 7 4Max 24-hr Avg 17 21 25 14 18 22 18 30 27 8 12 13 24 798th percentile 16 19 22 12 16 19 17 27 24 7 11 13 23 7Days of Data 19 21 21 21 21 21 21 21 21 21 21 21 21 21
Days >35 µg/m3 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Utah Division of Air Quality
0
50
100
150
200
250
300
350
400
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 29 30 31
PM
10
(µ
g
/
m
3)
Days
Utah 24-hr PM10 Data November 2024
Harrisville Hawthorne Herriman #3 Lindon Roosevelt Environmental Quality 24-hr Exceedance Value is 150 ug/m3
Exceedance Value is 150 ug/m3
*
*Environmental Quality (EQ) previously named Technical Support Center (TSC)
HV HW H3 LN RS EQ
Arith Mean 12 19 9 12 9 17Max 24-hr Avg 33 41 23 29 25 37Days of Data 30 30 30 30 30 30Days >150 µg/m3 0 0 0 0 0 0
Utah Division of Air Quality
0
50
100
150
200
250
300
350
400
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 29 30 31
PM
10
(µ
g
/
m
3)
Days
Utah 24-hr PM10 Data December 2024
Harrisville Hawthorne Herriman #3 Lindon Roosevelt Environmental Quality 24-hr Exceedance Value is 150 ug/m3
Exceedance Value is 150 ug/m3
*
*Environmental Quality (EQ) previously named Technical Support Center (TSC)
HV HW H3 LN RS EQ
Arith Mean 17 27 17 21 16 29Max 24-hr Avg 40 57 43 52 28 66Days of Data 31 31 31 31 31 31Days >150 µg/m3 0 0 0 0 0 0
Utah Division of Air Quality
0
50
100
150
200
250
300
350
400
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 29 30 31
PM
10
(µ
g
/
m
3)
Days
Utah 24-hr PM10 Data January 2025
Harrisville Hawthorne Herriman #3 Lindon Roosevelt Environmental Quality 24-hr Exceedance Value is 150 ug/m3
Exceedance Value is 150 ug/m3
*
*Environmental Quality (EQ) previously named Technical Support Center (TSC)
HV HW H3 LN RS EQ
Arith Mean 9 17 12 19 9 24
Max 24-hr Avg 31 43 43 90 23 92
Days of Data 21 21 21 21 21 21
Days >150 µg/m3 0 0 0 0 0 0
14.511.9
6.8
8.4
4.7
6.8
7.4
9.9
14.4
17.9 20.8
13.7
11.2 13.510.9
3.2
8.1 5.76.0
11.1
14.4 15.3 16.2
7.8 7.2 7.5
6.1
6.0 7.2 7.8
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
0.110
0.120
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 29 30 31
Da
i
l
y

M
a
x
i
m
u
m

T
e
m
p
e
r
a
t
u
r
e

(
0C)

(

H
a
w
t
h
o
r
n
e

)
Oz
o
n
e

(
p
p
m
)
Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Bountiful Copperview Erda Herriman #3 HV Hawthorne Near Road Red Butte Rose Park Environmental Quality Exceed.TM*
*Environmental Quality (EQ) previously named Technical Support Center (TSC)
** Controlling Monitor
**
O3 NOV 2024 BV CV ED H3 HV HW NR RB RP EQ
Arith Mean .033 .033 .038 .035 .030 .030 .027 .036 .031 .030
8 -hr. Ozone 4th Max .038 .039 .043 .042 .037 .034 .034 .040 .037 .036
Days of Data 30 30 30 30 30 30 30 30 30 30
Days > 0.070 0 0 0 0 0 0 0 0 0 0
9.311.1
5.4
8.9 6.0
4.35.5
6.9
10.4 11.1
11.9
8.0
6.6
8.4 11.0
6.4
5.4
8.5
3.14.3
6.4 7.2 6.0
3.2 2.8
0.8 3.2
1.7
1.5 2.1
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.020
0.040
0.060
0.080
0.100
0.120
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 29 30 31
Da
i
l
y

M
a
x
i
m
u
m

T
e
m
p
e
r
a
t
u
r
e

(
0C)

(

R
o
o
s
e
v
e
l
t

)
Oz
o
n
e

(
p
p
m
)
Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Price #2 Roosevelt Vernal Exceed.TM
P2 RS V4
Arith Mean .039 .034 .037
8 -hr. Ozone 4th Max .044 .040 .042
Days of Data 30 30 30
Days > 0.070 0 0 0
8.1
9.3
4.1 4.74.3
5.7 6.9
8.5
10.1
12.8
17.6
6.8 6.9 7.1 7.9
3.6 5.0
1.5
2.3
3.7
8.6
9.7 11.5
4.7
2.4
3.4 2.9
3.1 3.2
4.5
-10.0
-5.0
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
0.110
0.120
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 29 30 31
Da
i
l
y

M
a
x
i
m
u
m

T
e
m
p
e
r
a
t
u
r
e

(
0C)

(

S
m
i
t
h
f
i
e
l
d

)
Oz
o
n
e

(
p
p
m
)
Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Smithfield Exceed.TM
SM
Arith Mean .032
8 -hr. Ozone 4th Max .038
Days of Data 30
Days > 0.070 0
13.4
12.6
5.9
7.2
3.7
5.77.5
7.6
10.9
16.7
19.7
11.8
10.1
16.0
11.4
4.6 5.9
5.5
4.3
12.5
17.5 18.0
14.6
6.2 5.4 5.7
3.8 3.1
4.6 6.2
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
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 29 30 31
Da
i
l
y

M
a
x
i
m
u
m

T
e
m
p
e
r
a
t
u
r
e

(
0C)

(

L
i
n
d
o
n
)
Oz
o
n
e

(
p
p
m
)
Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Lindon Spanish Fork Exceed.TM
LN SF
Arith Mean .033 .034
8 -hr. Ozone 4th Max .040 .037
Days of Data 30 30
Days > 0.070 0 0
18.7
12.9
11.7 12.110.6 9.4 11.5
14.8
16.3 19.1 20.3
14.6
17.0
18.8
12.8
10.6
12.4
12.8
10.8
16.9
19.1
19.2 20.3
14.2
9.1 11.5 10.6 10.7 11.1
14.0
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
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 29 30 31
Da
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Enoch Hurricane Moab Exceed.TM
EN HC M7
Arith Mean .038 .038 .036
8 -hr. Ozone 4th Max .045 .042 .044
Days of Data 30 30 28
Days > 0.070 0 0 0
14.5
11.9
6.8
8.4
4.7
6.8 7.4
9.9
14.4 17.9
20.8
13.7
11.2
13.5
10.9
3.2
8.1
5.7 6.0
11.1
14.4
15.3 16.2
7.8 7.2
7.5 6.1 6.0 7.2
7.8
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
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 29 30 31
Da
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Stations Monitoring the Inland Port Development
Prison Lake Park Exceed.TM
*ZZis located at the New Utah State Prison (1480 North 8000 West, SLC).
This site was previously named IP
*
ZZ LP
Arith Mean .033 .035
8 -hr. Ozone 4th Max .039 .041
Days of Data 30 30
Days > 0.070 0 0
8.1 9.3
4.1 4.74.3
5.7 6.9
8.5
10.1 12.8
17.6
6.8 6.9
7.1 7.9
3.6
5.0
1.5 2.3
3.7
8.6 9.7
11.5
4.7
2.4 3.4 2.9 3.1 3.2
4.5
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
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 29 30 31
Da
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature November 2024
Brigham city Exceed.TM
BG
Arith Mean .030
8 -hr. Ozone 4th Max .037
Days of Data 30
Days > 0.070 0
7.6
7.9
8.0 8.6 7.7 5.2 7.0
7.4
3.3
4.6 6.1
10.9
8.1
11.08.6
6.7
10.5
11.311.7
11.2
9.1 8.6
10.7
9.2
6.6 5.6 6.0
8.4
13.0
4.3
3.1
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
0.110
0.120
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Bountiful Copperview Erda Herriman #3 HV Hawthorne Near Road Red Butte Rose Park Environmental Quality Exceed.TM*
*EnvironmentalQuality (EQ) previously named Technical Support Center (TSC)
** Controlling Monitor
**
O3 DEC 2024 BV CV ED H3 HV HW NR RB RP EQ
Arith Mean .021 .024 .028 .029 .022 .020 .019 .032 .022 .021
8 -hr. Ozone 4th Max .036 .036 .038 .038 .035 .033 .031 .040 .034 .032
Days of Data 31 31 31 31 31 31 31 31 31 31
Days > 0.070 0000000000
3.4
3.9
4.7
5.2
5.1 4.7
4.8
4.8
1.5
0.5
0.9
2.0
5.8
0.6
5.4
2.8
7.0
4.7 5.3
4.7 3.7 4.5
5.3
2.8
3.4
2.4
4.3 4.2
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.020
0.040
0.060
0.080
0.100
0.120
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 29 30 31
Da
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Price #2 Roosevelt Vernal Exceed.TM
P2 RS V4
Arith Mean .030 .029 .032
8 -hr. Ozone 4th Max .036 .037 .038
Days of Data 31 31 31
Days > 0.070 000
6.1
6.9 8.6
7.87.0 6.9
4.9
5.7
2.3 1.9 1.6
3.8
2.7
3.3 4.1 1.4
4.7
6.6
7.0
6.8
5.7 5.0
5.4
1.4 2.5
3.2 3.5
4.8 5.3
3.5
0.0
-10.0
-5.0
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
0.110
0.120
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 29 30 31
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Smithfield Exceed.TM
SM
Arith Mean .028
8 -hr. Ozone 4th Max .038
Days of Data 31
Days > 0.070 0
6.9
6.49.3
7.7
7.9
6.57.8
8.0
2.3 3.1
5.3
9.1
6.0
10.0
6.7
6.7
8.8
9.110.2 11.1
11.8
10.5
7.4
10.6
6.8 5.2
3.3
8.0
13.2
3.9
2.0
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Lindon Spanish Fork Exceed.TM
LN SF
Arith Mean .027 .028
8 -hr. Ozone 4th Max .038 .037
Days of Data 31 31
Days > 0.070 00
12.1
16.0
15.3
16.616.1 15.5
14.5 13.5
8.4
7.8
9.7
10.2 11.5
11.9 12.6
12.2
13.616.0 16.5
17.7 14.9
13.9
16.0
17.3
11.2
10.5
12.6 12.7
14.8 14.0
10.3
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Enoch Hurricane Moab Exceed.TM
EN HC M7
Arith Mean .033 .032 .026
8 -hr. Ozone 4th Max .040 .039 .035
Days of Data 31 31 31
Days > 0.070 000
7.6 7.9
8.0 8.67.7
5.2 7.0
7.4
3.3
4.6 6.1
10.9
8.1
11.0
8.6
6.7
10.5
11.3 11.711.2 9.1
8.6
10.7
9.2
6.6
5.6
6.0
8.4
13.0
4.3
3.1
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Stations Monitoring the Inland Port Development
Prison Lake Park Exceed.TM
*ZZ is located at the New Utah State Prison (1480 North 8000 West, SLC).
This site was previously named IP
*
ZZ LP
Arith Mean .028 .024
8 -hr. Ozone 4th Max .039 .038
Days of Data 31 31
Days > 0.070 00
6.1 6.98.6 7.87.0 6.9
4.9
5.7
2.3
1.9 1.6
3.8
2.7
3.3 4.1
1.4
4.7 6.6 7.0 6.8 5.7
5.0 5.4
1.4 2.5
3.2
3.5
4.8 5.3 3.5
0.0 0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature December 2024
Brigham city Exceed.TM
BG
Arith Mean .024
8 -hr. Ozone 4th Max .038
Days of Data 31
Days > 0.070 0
5.7
13.3
13.4
11.4
5.4 4.5
5.7 4.4 3.8
5.4
1.8 1.1 0.6
3.4
6.1 6.5
2.2 0.0 0.5 2.2
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
0.110
0.120
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Bountiful Copperview Erda Herriman #3 HV Hawthorne Near Road Red Butte Rose Park Environmental Quality Exceed.TM*
*Environmental Quality (EQ) previously named Technical Support Center (TSC)
** Controlling Monitor
**
O3 JAN 2024 BV CV ED H3 HV HW NR RB RP EQ
Arith Mean .032 .033 .035 .033 .033 .030 .028 .038 .031 .030
8 -hr. Ozone 4th Max .040 .039 .038 .036 .039 .035 .035 .041 .037 .035
Days of Data 21 21 21 21 21 21 21 21 21 21
Days > 0.070 0 00000000 0
4.8
4.4 6.0 3.7
1.8
2.0 2.8
4.4
0.3
0.3
2.0
5.8
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.020
0.040
0.060
0.080
0.100
0.120
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 29 30 31
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Price #2 Roosevelt Vernal Exceed.TM
P2 RS V4
Arith Mean .033 .033 .036
8 -hr. Ozone 4th Max .037 .039 .041
Days of Data 21 21 21
Days > 0.070 000
0.5
7.6
7.4
3.62.7 3.5
1.9 0.0
1.7
0.1
1.3
0.7
-2.6
0.6 3.2
5.0
1.3
-2.7
-2.4
-6.5
-1.2
-10.0
-5.0
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
0.110
0.120
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 29 30 31
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Smithfield Exceed.TM
SM
Arith Mean .034
8 -hr. Ozone 4th Max .038
Days of Data 21
Days > 0.070 0
6.5
10.5
13.9
9.9
4.3 4.15.3 2.5 3.4 3.4 1.71.9 1.4 3.2
6.9
5.2
1.5 0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Lindon Spanish Fork Exceed.TM
LN SF
Arith Mean .031 .032
8 -hr. Ozone 4th Max .037 .036
Days of Data 21 21
Days > 0.070 00
9.6
13.6
13.2 14.111.4 12.1
8.1
10.1
7.3
8.2 9.16.9 7.0
9.0
11.3 12.4 10.7
6.3 7.1
2.7
5.7
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Enoch Hurricane Moab Exceed.TM
EN HC M7
Arith Mean .036 .037 .036
8 -hr. Ozone 4th Max .041 .043 .042
Days of Data 21 21 21
Days > 0.070 000
5.7
13.3
13.4
11.4
5.4 4.5 5.7 4.4 3.8 5.4
1.81.1 0.6
3.4
6.1 6.5
2.2
0.0 0.5
2.2
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
12345678910111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Stations Monitoring the Inland Port Development
Prison Lake Park Exceed.TM
*ZZ is located at the New Utah State Prison (1480 North 8000 West, SLC).
This site was previously named IP
*
ZZ LP
Arith Mean .035 .034
8 -hr. Ozone 4th Max .041 .039
Days of Data 21 21
Days > 0.070 00
0.5
7.6
7.4
3.62.7 3.5
1.9 0.0
1.7
0.1 1.30.7
0.6
3.2 5.0
1.3
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0
45.0
50.0
55.0
60.0
65.0
0.000
0.010
0.020
0.030
0.040
0.050
0.060
0.070
0.080
0.090
0.100
1 2 3 4 5 6 7 8 9 10111213141516171819202122232425262728293031
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Days
Highest 8-hr Ozone Concentration and Daily Maximum Temperature January 2025
Brigham city Exceed.TM
BG
Arith Mean .034
8 -hr. Ozone 4th Max .040
Days of Data 21
Days > 0.070 0