DAQ-2025-000868

Utah State Implementation Plan

Regional Haze Second
Implementation Period

Section XX.A

[August 1, 2022]

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List of tables .................................................................................................................. 6
List of figures ................................................................................................................ 8
List of acronyms ......................................................................................................... 11
EXECUTIVE SUMMARY .............................................................................................. 13
Chapter 1: Background and Overview of the Federal Regional Haze Rule ............ 16
1.A Regional Haze Planning Periods and Due Dates ..................................................... 16
1.B Class I Areas in Utah .................................................................................................. 17
1.B.1 Arches National Park ................................................................................................................. 18
1.B.2 Bryce Canyon National Park ................................................................................................... 19
1.B.3 Canyonlands National Park .................................................................................................... 20
1.B.4 Capitol Reef National Park ...................................................................................................... 20
1.B.5 Zion National Park ................................................................................................................... 21
1.C Haze Characteristics and Effects .............................................................................. 21
1.D Monitoring Strategy .................................................................................................... 22
1.D.1 Participation in the IMPROVE Network ................................................................................... 24
1.E History of Regional Haze in Utah .................................................................................. 25
1.E.1 Grand Canyon Visibility Transport Commission ....................................................................... 26
1.E.2 Western Regional Air Partnership ............................................................................................ 28
1.E.3 2003 Regional Haze SIP ......................................................................................................... 29
1.E.4 2008 Regional Haze SIP Revision .......................................................................................... 29
1.E.5 2011 Regional Haze SIP Revision .......................................................................................... 30
1.E.6 2015 Regional Haze SIP Revision .......................................................................................... 30
1.E.7 2019 Regional Haze SIP Revision .......................................................................................... 31
1.F General Planning Provisions ..................................................................................... 32
1.F.1 Regional Haze Program Requirements .................................................................................. 32
1.F.2 SIP Submission and Planning Commitments ......................................................................... 32
1.F.3 Utah Statutory Authority .......................................................................................................... 33
Chapter 2: Utah Regional Haze SIP Development Process ..................................... 34
2.A WRAP Engagement .................................................................................................... 34
2.A.1 Technical Information and Data: WRAP TSS2.0 .................................................................... 35
2.B Consultation with Federal Land Managers .............................................................. 35
2.C Collaboration with Tribes .......................................................................................... 36
2.D Consultation with Other States ................................................................................. 36
2.E Public and Stakeholder Consultation ....................................................................... 37
Chapter 3: Progress to Date ....................................................................................... 38
3.A Embedded Progress Report Requirements ............................................................. 38
3.A.1 Implementation status of all measures in first planning period ............................................... 38

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3.A.2 Summary of emission reductions achieved by control measure implementation ................... 39
3.A.3 Assessment of visibility conditions .......................................................................................... 39
3.A.4 Analysis of any changes in emissions from all sources and activities within the state .......... 40
3.A.5 Assessment of any changes in emissions from within or outside the state. ........................... 44
Chapter 4: Utah Visibility Analysis ............................................................................ 49
4.A Baseline, Current Conditions and Natural Visibility Conditions ............................ 52
4.A.1 Baseline (2000-2004) visibility for the most impaired and clearest days ................................ 53
4.A.2 Natural visibility for the most impaired and clearest days ....................................................... 53
4.A.3 Current (2014-2018) visibility for the most impaired and clearest days .................................. 54
4.A.4 Progress to date: most impaired and clearest days ................................................................ 55
4.A.5 Differences between current and natural for the most impaired and clearest days ................ 55
4.B Uniform Rate of Progress .......................................................................................... 56
4.C Adjustments to URP: International impacts and/or prescribed fire ....................... 56
Chapter 5: Utah Sources of Visibility Impairment .................................................... 61
5.A Natural Sources of Impairment ................................................................................. 61
5.B Anthropogenic Sources of Impairment .................................................................... 61
5.C Overview of Emission Inventory System - TSS ....................................................... 62
5.D Wildland Prescribed Fires ......................................................................................... 63
5.E Utah Emissions ........................................................................................................... 64
Chapter 6: Long-Term Strategy for Second Planning Period .................................. 72
6.A LTS Requirements ..................................................................................................... 72
6.A.1 States reasonably anticipated to contribute to visibility impairment in the Utah CIAs ............ 73
6.A.2 Utah sources identified by downwind states that are reasonably anticipated to impact CIAs 77
6.A.3 Technical Basis of Reasonable Progress Goals ..................................................................... 81
6.A.4 Identify Anthropogenic Sources .............................................................................................. 81
6.A.5 Emissions Reductions Due to Ongoing Pollution Control Programs ...................................... 81
6.A.6 Measures to Mitigate the Impacts of Construction Activities .................................................. 86
6.A.7 Basic smoke management practices ...................................................................................... 87
6.A.8 Emissions Limitations and Schedules for Compliance to Achieve the RPG .......................... 88
6.A.9 Source retirement and replacement schedules ...................................................................... 88
6.A.10 Anticipated net effect on visibility from projected changes in emissions during this planning
period 89
6.A.11 Enforceability of Emissions Limitations ............................................................................... 96
Chapter 7: Emission Control Analysis ...................................................................... 97
7.A Source Screening ....................................................................................................... 97
7.A.1 Q/d Analysis ............................................................................................................................ 99
7.A.2 Secondary Screening of Sources .......................................................................................... 102
7.A.3 Weighted Emissions Potential Analysis of Sources in Utah and Neighboring States .......... 108
7.A.4 Other Sources .......................................................................................................................... 120

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7.A.5 Environmental Justice Considerations ................................................................... 122
7.B Four-Factor Analyses for Utah Sources ................................................................. 126
7.B.1 Control Equipment Descriptions ............................................................................................ 127
7.B.2 Existing Controls on Active EGUs ......................................................................................... 130
7.C Source Consultation .............................................................................................................. 131
7.C.1 Ash Grove Cement Company- Leamington Cement Plant Four-Factor Analysis
Summary and Evaluation ................................................................................................... 132
Ash Grove’s Four-Factor Analysis Conclusion ................................................................................. 133
UDAQ Four-Factor Analysis Evaluation ............................................................................................ 133
Ash Grove’s Evaluation Response ................................................................................................... 133
UDAQ Response Conclusion ............................................................................................................ 134
7.C.2 Graymont Western US Incorporated- Cricket Mountain Plant Four-Factor
Analysis Summary and Evaluation .................................................................................... 134
Graymont Four-Factor Analysis Conclusion ..................................................................................... 135
UDAQ Four-Factor Analysis Evaluation ............................................................................................ 135
Graymont’s Evaluation Response ..................................................................................................... 137
UDAQ Response Conclusion ............................................................................................................ 138
7.C.3 PacifiCorp's Hunter and Huntington Power Plants Four-Factor Analysis
Summary and Evaluation ................................................................................................... 138
PacifiCorp Four Factor Analysis Conclusion ..................................................................................... 139
UDAQ Four-Factor Analysis Evaluation ............................................................................................ 140
Huntington Power Plant .................................................................................................................... 140
PacifiCorp Four Factor Analysis Conclusion ..................................................................................... 141
UDAQ’s Four Factor Analysis Conclusion ........................................................................................ 142
PacifiCorp’s Four-Factor Analysis Evaluation Response for Hunter and Huntington ....................... 142
UDAQ Response Conclusion ............................................................................................................ 144
7.C.4 Sunnyside Cogeneration Associates- Sunnyside Cogeneration Facility Four-
Factor Analysis Summary and Evaluation ........................................................................ 164
Sunnyside Four Factor Analysis Conclusion .................................................................................... 166
UDAQ Evaluation Summary and Conclusion .................................................................................... 166
Sunnyside’s Evaluation Response .................................................................................................... 167
UDAQ Response Conclusion ............................................................................................................ 169
7.C.5 US Magnesium LLC- Rowley Plant ...................................................................... 169
US Magnesium Four-Factor Analysis Conclusion ............................................................................ 170
UDAQ Evaluation .............................................................................................................................. 170
US Magnesium’s Evaluation Response ............................................................................................ 171
UDAQ Response Conclusion ............................................................................................................ 171
Chapter 8: Determination of Reasonable Progress Goals ..................................... 172
8.A Reasonable Progress Requirements ...................................................................... 172
8.B. Regional Modeling of the LTS to set RPGs ............................................................ 172
8.C URP Glidepath Checks ............................................................................................. 173
8.C.1 Bryce Canyon National Park ................................................................................................. 174

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8.C.2 Canyonlands and Arches National Park ............................................................................... 175
8.C.3 Capitol Reef National Park .................................................................................................... 176
8.C.4 Zion National Park ................................................................................................................... 177
8.C.5 Summary of URP Glidepaths .................................................................................................. 178
8.D Reasonable Progress Determinations .................................................................... 178
8.D.1 Reasonable Progress Determination for Ash Grove Cement Company – Leamington Cement
Plant 178
8.D.2 Reasonable Progress Determination for Graymont Western US Incorporated – Cricket
Mountain Plant .................................................................................................................................. 179
8.D.3 Reasonable Progress Determination for PacifiCorp: Hunter and Huntington Power Plants 179
8.D.4 Reasonable Progress Determination for Sunnyside Cogeneration Associated – Sunnyside
Cogeneration Facility ........................................................................................................................ 179
8.D.5 Reasonable Progress Determination for US Magnesium LLC – Rowley Plant ....................... 179
8.D.6 Intermountain Power Service Corporation – Intermountain Generation Station ..................... 180
Chapter 9: Consultation, Public Review, Commitment to further Planning ......... 181
9.A Federal requirements ............................................................................................... 181
9.B Interstate Consultation .......................................................................................................... 181
9.C Documentation of Federal Land Manager consultation and commitment to
continuing consultation ...................................................................................................... 186
9.C.1 FLM SIP Review ...................................................................................................................... 187
9.C.2 NPS Feedback Summary and UDAQ Responses .................................................................. 187
9.C.3 USFS Feedback Summary and UDAQ Responses ................................................................ 193
9.D Coordination with Indian tribes ............................................................................... 194
9.E Stakeholder Outreach and Communication ........................................................... 194
9.F Public Comment Period ........................................................................................... 196
9.G Comment Conclusions ............................................................................................ 196
9.H Commitment to Further Planning............................................................................ 197
9.H.1 Process for conducting future emissions inventories and future monitoring strategy ........... 197
9.H.2 Commitment to provide other elements necessary to report on visibility, including reporting,
recordkeeping, and other measures ................................................................................................. 198
9.H.3 Commitment to submit January 31, 2025 progress report .................................................... 198

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List of tables

Table 1: 30-day Rolling Average Emission Limits for the Retrofitted Hunter and Huntington Units
.................................................................................................................................................... 39
Table 2: Western Coal Unit Retirement and Control Summary .................................................. 45
Table 3: Changes in Emissions from 1996 - 2018 for 9 GCVTC States ..................................... 48
Table 4: Representative IMPROVE Monitoring Sites ................................................................. 53
Table 5: IMPROVE site information for CIAs .............................................................................. 53
Table 6: Baseline Visibility for the 20% Most Impaired Days and 20% Clearest Days ............... 53
Table 7: Natural Visibility values for Utah CIAs .......................................................................... 54
Table 8: Current Visibility (2014-2018) conditions in Utah CIAs ................................................. 54
Table 9: Progress to date for the most impaired and clearest days ............................................ 55
Table 10: Current visibility compared to natural visibility ............................................................ 55
Table 11: Uniform Rates of Progress .......................................................................................... 56
Table 12: Calculation of 2028 Uniform Rate of Progress Level .................................................. 56
Table 13: Data sources for WRAP emissions sectors ................................................................ 61
Table 14: Status of Utah EGU Retirements in RepBase2 and 2028OTBa2 Inventories ............ 64
Table 15: Utah SO₂ Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2 ................. 66
Table 16: Utah NOx Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2 ................. 66
Table 17: Utah VOC Emission Inventory – RebBase2 (2014-2018) and 2028OTBa2 ............... 67
Table 18: Utah PM2.5 Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2 ............... 68
Table 19: Utah PM2.5 PM10 Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2 .... 69
Table 20: Utah NH3 Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2 ................. 70
Table 21: Utah Share of U.S. Anthropogenic Nitrate Impacts on Neighboring State CIAs ......... 77
Table 22: Utah Share of U.S. Anthropogenic Sulfate Impacts on Neighboring State CIAs ........ 78
Table 23: Utah Share of Total Nitrate Impacts on Neighboring State CIAs ................................ 79
Table 24: Utah Share of Total Sulfate Impacts on Neighboring State CIAs ............................... 80
Table 25: Status of Utah EGU Retirements in RepBase2 and 2028OTBa2 Inventories ............ 89
Table 26: Net Changes in Emissions from New and Existing Measures Relative to 2028OTBa2
.................................................................................................................................................... 91
Table 27: Statewide Anthropogenic Scenario Totals and LTS Emission Reductions (tpy) ......... 92
Table 28: Comparison of baseline, 2028 URP, 2028 EPA w/o fire projection for worst and
clearest days ............................................................................................................................... 92
Table 29: Sources initially selected to perform a Four-Factor analysis..................................... 100
Table 30: 2017 NEI Q/d Screen ................................................................................................ 101
Table 31: Paradox Lisbon Plant Q/d Analysis for nearest CIAs ................................................ 103
Table 32: 2017 Kennecott Utah Copper LLC – Mine & Concentrator Emissions and Revised Q/d
.................................................................................................................................................. 104
Table 33: Existing Controls in Utah’s SIP for Screened Sources ............................................. 105
Table 34: Nitrate Point Source WEP Rank for Utah CIAs ......................................................... 109
Table 35: Sulfate Point Source WEP Rank for Utah CIAs ........................................................ 113
Table 36: Nitrate Utah Point Source WEP Rank for Non-Utah CIAs ........................................ 117

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Table 37: Sulfate Utah Point Source WEP Rank for Non-Utah CIAs ........................................ 118
Table 38: Ash Grove Leamington Cement Plant EJScreen Findings ....................................... 122
Table 39: Graymont Western Cricket Mountain Plant EJScreen Findings ............................... 123
Table 40: PacifiCorp Hunter Power Plant EJScreen Findings .................................................. 123
Table 41: PacifiCorp Huntington Power Plant EJScreen Findings ........................................... 123
Table 42: Sunnyside Cogeneration Power Plant EJScreen Findings ....................................... 124
Table 43: US Magnesium Rowley Plant EJScreen Findings .................................................... 124
Table 44: Intermountain Generation Station EJScreen Findings .............................................. 124
Table 45: Kennecott Power Plant EJScreen Findings .............................................................. 125
Table 46: Kennecott Mine and Copperton Concentrator EJScreen Findings ........................... 125
Table 47: Paradox Lisbon Plant EJScreen Findings ................................................................. 126
Table 48: Existing controls on active coal units in Utah ............................................................ 130
Table 49: Existing controls on active gas units in Utah ............................................................. 131
Table 50: Ash Grove Leamington Cement Plant Current Potential to Emit .............................. 133
Table 51: Current Potential to Emit - Graymont ........................................................................ 135
Table 52: Estimated Direct Annual Costs (doubled) Graymont ................................................ 136
Table 53: Hunter Current Potential to Emit ............................................................................... 139
Table 54: Current Potential to Emit: Huntington ....................................................................... 141
Table 55: PacifiCorp Updated Hunter SNCR Cost Effectiveness ............................................. 143
Table 56: PacifiCorp Updated Huntington SNCR Cost Effectiveness ...................................... 144
Table 57: Cost-effectiveness of SNCR and SCR and Hunter and Huntington Power Plants ... 147
Table 58: 2028 Mass-based NOx Limit - SNCR Cost-effectiveness ......................................... 156
Table 59: 2028 Mass-based NOx Limit – SCR Cost-effectiveness ........................................... 156
Table 60: Hunter Actuals and Limits ......................................................................................... 158
Table 61: Huntington Actual and Limits .................................................................................... 159
Table 62: Sunnyside: Current Potential to Emit (Tons/Year) .................................................... 165
Table 63: Current Potential to Emit ........................................................................................... 169
Table 64: US Magnesium’s Reevaluation of Riley Boiler Controls ........................................... 171
Table 65: Comparison of baseline, 2028 URP, 2028 EPA w/o fire projection for worst and
clearest days ............................................................................................................................. 178
Table 66: Summary of Interstate Meetings with UDAQ ............................................................ 182
Table 67: Second Implementation Period Status of Non-Utah Sources Identified in NO3 WEP
Analysis ..................................................................................................................................... 184
Table 68: Second Implementation Period Status of Non-Utah Sources Identified in SO4 WEP
Analysis ..................................................................................................................................... 184
Table 69: Summary of FLM Meetings with UDAQ .................................................................... 186
Table 70: Summary of Stakeholder Meetings with UDAQ ........................................................ 194

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List of figures

Figure 1: Regional Haze Timeline option for GCVTC areas ....................................................... 16
Figure 2: Map of Utah CIAs ........................................................................................................ 17
Figure 3: Map of Utah Class I Area Land Ownership ................................................................. 18
Figure 4: Arches National Park ................................................................................................... 18
Figure 5: Bryce Canyon National Park ........................................................................................ 19
Figure 6: Canyonlands National Park ......................................................................................... 20
Figure 7: Capitol Reef National Park .......................................................................................... 20
Figure 8: Zion National Park ....................................................................................................... 21
Figure 9: Monitoring station for Capitol Reef National Park ........................................................ 22
Figure 10: Monitoring station for Bryce Canyon National Park ................................................... 23
Figure 11: Monitoring station for Canyonlands and Arches National Park ................................. 23
Figure 12: Monitoring station layout ............................................................................................ 24
Figure 13: IMPROVE monitoring sites ........................................................................................ 24
Figure 14: United States map of mandatory CIAs ...................................................................... 26
Figure 15: Regional haze glidepath for Bryce Canyon National Park tracking progress towards
natural conditions in 2064 ........................................................................................................... 27
Figure 16:Statewide NOx Emissions Trends by Sector ............................................................... 40
Figure 17: Statewide VOC Emissions Trends by Sector ............................................................ 41
Figure 18: Statewide SO2 Emissions Trends by Sector ............................................................. 41
Figure 19: Statewide PM10 Emissions Trends by Sector ............................................................ 42
Figure 20: Statewide PM2.5 Emissions Trends by Sector ............................................................ 42
Figure 21: Utah Particulate Matter Trends .................................................................................. 43
Figure 22: Utah Gaseous Trends ................................................................................................ 43
Figure 23: SO2 and NOx Emissions Trends for Western Power Plants ...................................... 44
Figure 24: Remaining and Retiring EGU Emissions Apportionment ........................................... 48
Figure 25: Light extinction for Utah Class I Areas: natural and anthropogenic sources ............. 50
Figure 26: URP Glidepath for Clearest Days, Bryce Canyon NP ............................................... 51
Figure 27: URP Glidepath for most impaired days, Bryce Canyon NP ....................................... 52
Figure 28: Projected Source Contributions to Light Extinction in Bryce Canyon NP .................. 57
Figure 29: Projected Source Contributions to Light Extinction in Canyonlands and Arches NP . 58
Figure 30: Projected Source Contributions to Light Extinction in Capitol Reef NP ..................... 58
Figure 31: Projected Source Contributions to Light Extinction in Zion NP .................................. 59
Figure 32: Example URP Glidepath for Bryce Canyon National Park Showing Adjustment
Options ........................................................................................................................................ 59
Figure 33: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at
Bryce Canyon National Park ....................................................................................................... 73
Figure 34: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at
Bryce Canyon National Park ....................................................................................................... 73
Figure 35: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at
Canyonlands and Arches National Park ..................................................................................... 74

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Figure 36: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at
Canyonlands and Arches National Park ..................................................................................... 74
Figure 37: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at
Capitol Reef National Park .......................................................................................................... 75
Figure 38: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at
Capitol Reef National Park .......................................................................................................... 75
Figure 39: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at
Zion National Park ...................................................................................................................... 76
Figure 40: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at
Zion National Park ...................................................................................................................... 76
Figure 41: Modeled Visibility Progress for MID at Bryce Canyon National Park ......................... 93
Figure 42: Modeled Visibility Progress for MID at Canyonlands and Arches National Park ....... 93
Figure 43: Modeled Visibility Progress for MID at Capitol Reef National Park............................ 94
Figure 44: Modeled Visibility Progress for MID at Zion National ................................................. 94
Figure 45: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Bryce
Canyon National Park ................................................................................................................. 95
Figure 46: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at
Canyonlands and Arches National Park ..................................................................................... 95
Figure 47: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Capitol
Reef National Park ...................................................................................................................... 96
Figure 48: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Zion
National Park .............................................................................................................................. 96
Figure 49: Average Light Extinction by Sources in Bryce Canyon National Park ....................... 97
Figure 50: Source Contributions on Average Most Impaired Days in Bryce Canyon National
Park ............................................................................................................................................. 98
Figure 51: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at
Bryce Canyon National Park ....................................................................................................... 98
Figure 52: Map of Utah Regulated Sources with Emissions >100 TPY ...................................... 99
Figure 53: Hunter and Huntington SO2 Rate ............................................................................. 145
Figure 54: SCR Cost-effectiveness by utilization level at Hunter and Huntington Power Plants
.................................................................................................................................................. 149
Figure 55: Hunter and Huntington Capacity Factors ................................................................. 150
Figure 56: Hunter and Huntington Utilization (based on Net Summer Capability) .................... 151
Figure 57: Hunter and Huntington NOx Emissions by Unit........................................................ 151
Figure 58: PacifiCorp 2021 IRP Cumulative Resource Additions ............................................. 152
Figure 59: PacifiCorp 2021 IRP Cumulative Coal Retirements/Gas Conversions .................... 153
Figure 60: PacifiCorp 2021 IRP Coal Capacity (MW) vs. Coal % of Total Energy and % of Total
Capacity .................................................................................................................................... 153
Figure 61: State Control Cost-effectiveness Ranges ................................................................ 161
Figure 62: Daily Nitrate Light Extinction MIDs at Utah CIA IMPROVE Sites, 2014-2019 ......... 162
Figure 63: Combined Hunter and Huntington Monthly NOx Emissions vs. Monthly Gross Load,
2014-2021 ................................................................................................................................. 163
Figure 64: Example of projected RPGs for Canyonlands and Arches CIAs ............................. 164

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Figure 65: Projected 2028 RPG Bryce Canyon National Park .................................................. 174
Figure 66: Projected 2028 RPG Canyonlands and Arches National Parks .............................. 175
Figure 67: Projected 2028 RPG Capitol Reef National Park .................................................... 176
Figure 68: Projected 2028 RPG Zion National Park ................................................................. 177
Figure 69: USFS Fire Glidepath Adjustment for Bryce Canyon ................................................ 194

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List of acronyms

BACT BACM Best Available Control Technology Best Available Control Measures CIA CAA CAMx
Class 1 Area Clean Air Act Comprehensive Air Quality Model with Extensions CCR CF
CIRA
Consumer Confidence Report Code of Federal Regulations
Cooperative Institute for Research in the Atmosphere CO CSU Carbon Monoxide Colorado State University
DAQ Division of Air Quality DEQ Department of Environmental Quality EPA Environmental Protection Agency FLM FWS GCVTC IMPROVE LTS NAAQS
Federal Land Manager US Fish and Wildlife Service Grand Canyon Visibility Transportation Commission
Interagency Monitoring of Protected Visibility Elements Long Term Strategy National Ambient Air Quality Standards NOI Notice of Intent NO2 Nitrogen Dioxide NOx NPS Nitrogen Oxides National Parks Service O3 Ozone PAL PB Plantwide Applicability Limit Lead PM Particulate Matter
PM10 Particulate Matter Smaller Than 10 Microns in Diameter PM2.5 RH Particulate Matter Smaller Than 2.5 Microns in Diameter Regional Haze RHR RHPWG RPEL RPG SCR SIP
Regional Haze Rule Regional Haze Planning Work Group (WRAP) Reasonable Progress Emissions Limit
Reasonable Progress Goals Selective Catalytic Reduction State Implementation Plan SNCR SO2 Selective Non-Catalytic Reduction Sulfur Dioxide SOx TSS UDOGM
Sulfur Oxides Technical Support System Utah Division of Oil, Gas, and Mining URP UAC USFS
Uniform Rate of Progress Utah Administrative Code US Forest Service VOCs WESTAR Volatile Organic Compounds Western States Air Resources

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WRAP Western Regional Air Partnership

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EXECUTIVE SUMMARY

This document comprises the State of Utah's State Implementation Plan (SIP) submittal to the
U.S. Environmental Protection Agency (EPA) under the Regional Haze Rule.1 The purpose of
this SIP revision is to comply with the requirements of the Regional Haze Rule (RHR).2
Specifically, this SIP addresses requirements for periodic comprehensive revisions of
implementation plans for regional haze.3 The RHR requires Utah to address regional haze in
each mandatory Class I Area (CIA) located within Utah and in each mandatory CIA located
outside Utah that may be affected by primary pollutants emitted from sources within Utah. Utah
is required to submit a SIP addressing the specific elements required by the rule.
The objectives of the RHR are to improve existing visibility in 156 national parks, wilderness
areas, and monuments (termed Mandatory Class I Areas or CIAs), prevent future impairment of
visibility by manmade sources, and meet the national goal of natural visibility conditions in all
mandatory CIAs by 2064. Utah’s CIAs consist of: Arches National Park, Bryce Canyon National
Park, Canyonlands National Park, Capitol Reef National Park, and Zion National Park.4
The RHR establishes several planning periods extending from 2005 to 2064. The State of Utah
is required to develop a Regional Haze (RH) SIP for each period. The first implementation
period spanned from 2008 to 2018. This SIP revision consists of the second implementation
period spanning from 2018 to 2028. This SIP was originally due for submittal to the EPA on July
31st, 2018. However, the deadline was extended to July 31st, 2021. In this revision, UDAQ
demonstrates the visibility progress to date5 in each of Utah’s CIAs and analyzes Utah’s
emissions trends and sources of visibility impairment6. Utah is required to set reasonable
progress goals which 1) must provide for an improvement in visibility for the most impaired days
over the period of the implementation plan and 2) ensure no degradation in visibility for the least
impaired days over the same period.7 For this purpose, Utah has outlined its Long-Term
Strategy (LTS) in this document8 as well as determination of reasonable progress goals (RPGs)
for CIAs in Utah.
The RH SIP must also address mandatory CIAs outside of the state that are reasonably
anticipated to be affected by emissions from Utah as well as out-of-state sources impacting
Utah CIAs. For this requirement, UDAQ analyzed Western Regional Air Partnership (WRAP)
photochemical modeling and found that Utah does not significantly impact visibility at out-of-
1 40 CFR 51.308(f) and (g)
2 40 CFR 51 3 40 CFR 51.308(f)
4 See chapter 1 for more information on the RHR and Utah’s regional haze history 5 See chapter 3 to view Utah’s visibility and emissions reduction progress to date
6 See chapter 5 to review Utah’s sources of visibility impairment 7 See chapter 8 for more information on Utah’s reasonable progress goals
8 See chapter 6 for Utah’s Long-Term Strategy

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state CIAs.9 Utah has also determined that Utah’s CIAs are not significantly impacted by out-of-
state sources. Upon consultation with Utah’s surrounding states, Utah will not require any
actions from other states for impacts on Utah’s CIAs and Utah has received no requests for
actions regarding Utah sources’ impacts on out-of-state CIAs.10
Throughout this second implementation period, UDAQ has participated in the WRAP, which has
conducted modeling and technical analysis for the purposes of supporting state RH planning.
UDAQ has also consulted with Federal Land Managers (FLMs), Tribes, Utah’s surrounding
states, as well as environmental advocates, industry stakeholders, and the public.11
This SIP revision also determines what control measures are necessary for reasonable
progress in the second implementation period. The examination required to determine new
control measures for this period is known as a four-factor analysis12 and consists of four criteria:
1) cost of compliance, 2) time necessary for compliance, 3) energy and non-air quality
environmental impacts, and 4) remaining useful life. In order to determine which sources must
submit a four-factor analysis to the State, UDAQ performed a Q/d (emissions/distance) analysis
to determine which of Utah’s sources have the highest potential visibility impact on Utah’s CIAs.
These facilities include the Ash Grove Cement Company Leamington Cement Plant, the
Graymont Western US Inc. Cricket Mountain Plant, the PacifiCorp Hunter and Huntington
Plants, the Sunnyside Cogeneration Associated Sunnyside Cogeneration Facility, and the US
Magnesium LLC Rowley Plant. UDAQ requested each facility to submit a four-factor analysis for
the purpose of this second implementation period. UDAQ has received each facility’s four-factor
analysis, provided each with an evaluation of their analysis, received evaluation responses from
each, and subsequent information submittals13. After consideration of the information provided,
as well as the modeling results provided by the WRAP, UDAQ has made the following
reasonable progress determinations14 for Utah’s second implementation period of regional haze
planning.
UDAQ identified several existing measures necessary for reasonable progress, including federal
on-road and non-road vehicle and equipment standards, BACM measures and BACT controls
included in the recently completed Serious Area PM2.5 SIP for the Salt Lake Nonattainment
Area, as well as the following first implementation period regional haze controls:
• Existing NOx control rate-based limits and Hunter power plant
• Existing NOx control rate-based limits and Huntington power plant
9 See sections 6.A.1 and 6.A.2 for Utah’s impacts on out of state CIAs and other state’s impacts on Utah’s CIAs 10 See Appendix B for interstate consultation agreement documentation
11 See chapter 9 for details on Utah’s consultation efforts 12 See chapter 7 for Utah’s source selection and the four-factor analyses, evaluations, responses, and conclusions for each source 13 See Appendix D.2 to view additional information submittals by sources
14 See sections 6.A.10 to view Utah’s Long-Term Strategy, 8.D to view UDAQ’s reasonable progress determinations, and IX.H in appendix A to view the enforceable language for these determinations.

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• Existing SO2 limits for Hunter power plant (Section 309 control added to SIP in round
2)
• Existing SO2 limits for Huntington power plant (Section 309 control added to SIP in
round 2)
• Closure of the Carbon power plant
UDAQ also identified and included the following existing control measures to ensure ongoing
enforceability in the second implementation period:
• Ash Grove
• Graymont
• Sunnyside
• US Magnesium
• Intermountain Generation Station
Finally, UDAQ identified and included the following new control measures as necessary for
reasonable progress:
• A plantwide enforceable mass-based NOx limit on Hunter power plant
• A plantwide enforceable mass-based NOx limit on Huntington power plant
• Installation of FGR on the US Magnesium Rowley Plant Riley Boiler
• An enforceable closure date for Units 1 and 2 of the Intermountain Generation Station

16
Chapter 1: Background and Overview of the Federal Regional
Haze Rule
1.A Regional Haze Planning Periods and Due Dates
Utah took part in early regional haze planning through participation in the Grand Canyon
Visibility Transport Commission (GCVTC), which originally consisted of nine states and 211
tribal lands. In 1996, the GCVTC submitted a report containing recommendations for improving
western vistas.15 In 2000, Utah established Sulfur Dioxide (SO₂) milestones with an Annex16 to
the original GCVTC report through the Western Regional Air Partnership. Based on the
recommendations of the GCVTC and the Annex, in 2003 Utah’s Air Quality Board adopted
section XX17 of the State Implementation Plan (SIP) to address regional haze and the many
source categories and pollutants contributing to the regional haze in Utah. The first state plans
were due in 2007 and the last date for states to submit initial regional haze control plans for all
Mandatory Federal CIAs was in 2008. Utah submitted its evaluation of the Best Available
Retrofit Technology (BART) in 201518 along with a revision in 201919. Progress reports are due
every five years and full plan revisions are required every 10 years. The first revision was
originally due in 2018, but in 2017 EPA extended the deadline to July 31, 2021 with the latest
revision of the Regional Haze Rule (RHR)20. As part of the RH SIP process, Utah must work
towards the overarching goal of achieving natural visibility in its CIAs by 2064. This timeline is
summarized in the figure below.

15 The original 1996 report of The Grand Canyon Visibility Transport Commission can be found at
https://www.phoenixvis.net/PDF/GCVTCFinal.pdf 16 The EPA Notice of Availability of the Annex to the Report of The Grand Canyon Visibility Transport Commission can be found at https://www.federalregister.gov/documents/2000/11/15/00-29226/notice-of-availability-of-annex-to-the-report-of-the-grand-canyon-visibility-transport-commission
17 Section XX of Utah’s Regional Haze SIP can be found at https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2020-008934.pdf
18 Utah’s 2015 RH SIP can be found at https://documents.deq.utah.gov/legacy/laws-and-rules/air-quality/sip/docs/2015/07Jul/SecXXRegHaze201Final.pdf
19 Utah’s 2019 RH SIP revision can be found at https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/DAQ-2019-012208.pdf
20 40 C.F.R. § 51.308(f). For the purposes of this SIP submittal, the RHR acronym refers to the most current 2017 Regional Haze Rule revisions.
Figure 1: Regional Haze Timeline option for GCVTC areas

17

1.B Class I Areas in Utah
In the 1977 Clean Air Act, Congress established requirements for the prevention of significant
deterioration of air quality in areas within the United States and for the review of pollution
controls on new sources. Coupled with this, Congress established a visibility protection program
for those larger national parks and wilderness areas designated as mandatory Federal CIAs.
This program establishes a national goal of “the prevention of any future, and remedying of any
existing, impairment of visibility in mandatory CIAs which impairment results from manmade air
pollution”21 and requires states to develop long-term strategies to assure reasonable progress
toward this national goal. 40 CFR 81.400 Scope: Subpart D, §§ 81.401 through 81.437, lists
Mandatory Federal CIAs, where the Administrator, in consultation with the Secretary of the
Interior, has determined
visibility to be an important
value.
As shown in Figure 2, there are
five Mandatory Federal CIAs in
Utah, all of which are National
Parks: Arches National Park,
Bryce National Park,
Canyonlands National Park,
Capitol Reef National Park and
Zion National Park. The
following sections include data
from the National Parks
Service (NPS) Stats website.22

21 42 U.S.C.A. § 7491(a)(1) (West). 22 Statistics for all the National Parks discussed in this section come from the NPS Stats website at:
https://irma.nps.gov/STATS/
Figure 2: Map of Utah CIAs

18

1.B.1 Arches National Park
Arches National Park
was originally
designated as a
National Monument in
1929 and became a
national park in 1978.
Congress established
the park “to protect
extraordinary
examples of geologic
features including
arches, natural
bridges, windows,
spires, balanced
rocks, as well as other
features of geologic,
historic, and scientific interest, and to provide opportunities to experience these resources and
Figure 3: Map of Utah Class I Area Land Ownership
Figure 4: Arches National Park

19
their associated values in their majestic natural settings.”23 Located in southwest Utah, Arches
National Park is home to over 2,000 cataloged, naturally formed, sandstone arches. These
76,679 acres of red sandstone are surrounded by thousands of acres of additional natural
lands, administered mainly by the Bureau of Land Management and Utah’s School and
Institutional Trust Lands Administration (See Figure 3). Over 1.6 million people visited Arches in
2019.24 Over the past 10 years, park visitation has increased, on average, five percent each
year.25 The largest population center near Arches National Park is Moab. This town of over
5,300 residents26 is about five miles south of the Park. It is the major hub for recreation in
Arches, Canyonlands National Park, and the surrounding areas.
1.B.2 Bryce Canyon National Park
Bryce Canyon was originally established as a National Monument in June 1923. One year later
it was designated a
national park.
According to its
foundation document,
the purpose of the park
was to “protect and
conserve resources
integral to a landscape
of unusual scenic
beauty exemplified by
highly colored and
fantastically eroded
geological features,
including rock fins and
spires, for the benefit
and enjoyment of the
people.”27 Bryce
Canyon contains the
highest concentration of irregular rock columns (Hoodoos) on Earth. Located in southern Utah
near the city of Bryce, the national park sits along the edge of a high plateau on top of the
Grand Staircase. At 35,835 acres, Bryce Canyon is Utah’s smallest National Park. However,
nearly 2.6 million people visited Bryce Canyon in 2019.28
23 Arches National Park Foundation Document, website: https://www.nps.gov/arch/learn/management/foundation-document.htm#CP_JUMP_5740028 24 Data source: Stats Report Viewer (nps.gov).
25 See id. 26 United States Census Bureau, website: https://www.census.gov/quickfacts/moabcityutah (data for July 1, 2019). 27 Bryce Canyon National Park Foundation Document, website: https://www.nps.gov/brca/learn/management/upload/BRCA_FD_SP.pdf 28 Data source: Stats Report Viewer (nps.gov).
Figure 5: Bryce Canyon National Park

20
1.B.3 Canyonlands National Park
Canyonlands National Park was originally established on September 12, 1964 with the help of
Bates Wilson, the superintendent of Arches National Park. Located near Moab, Utah with
337,598 acres
of land and
water,
Canyonlands is
Utah’s largest
national park.
The Green and
Colorado rivers
split this section
of the Colorado
Plateau into
three main
districts: “Island
in the Sky,” “The
Needles,” and
“The Maze.”
Since 2007,
over 400,000
people visit Canyonlands each year with a record of 776,218 in 2016 alone.29 Canyonlands
features deep canyons, mesas, pinnacles, cliffs, and spires and contains one of the most
photographed landforms in the west—the Mesa Arch.
1.B.4 Capitol Reef National Park
Capitol Reef National
Park was originally
designated a national
monument in August
1937 but then turned
into a national park in
1971. Spanning
241,904 acres, Capitol
Reef is made of a
geologic monocline
almost 100 miles long.
This monocline is called
the Waterpocket Fold
and is considered a
geologic warp in the
29 Data source: Stats Report Viewer (nps.gov).
Figure 7: Capitol Reef National Park
Figure 6: Canyonlands National Park

21
Earth’s crust spanning from Thousand Lake Mountain to Lake Powell. The tall, seemingly
impassible ridges made by the Waterpocket Fold were called “reefs” by early settlers. The white
Navajo sandstone dome formations appear like those placed on capitol buildings, giving the
park its name. Capitol Reef had 1,226,519 visitors in 201930 and offers many hiking and
backpacking opportunities, including 71 campsites.
1.B.5 Zion National Park
Established on July 31, 1909, Zion
National Park was the first national
park in Utah. It is also the fourth
most visited National Park in the
United States with 4.48 million
visitors in 2019.31 The park’s
147,243 acres contain the Zion
Canyon which is 15 miles long and
2,640 feet tall.32 The purpose of
Zion National Park is to “preserve
the dramatic geology including
Zion Canyon and a labyrinth of
deep and brilliantly colored Navajo
sandstone canyons formed by
extraordinary processes of erosion
at the margin of the Colorado
Plateau.”33 Located in southwestern Utah near St. George, Zion is home to famous hikes
including Angel’s Landing, The narrows, Observation Point, and the Emerald Pools.
1.C Haze Characteristics and Effects
Unimpaired visibility is important to fully enjoy the experience of visiting Utah’s national parks
and wilderness areas. Visibility is defined as the greatest distance at which an observer can see
a black object viewed against the horizon sky. Visibility is impaired by light scattering and
absorption caused by PM and gases in the atmosphere that occur from both natural and
anthropogenic activities. This diminished clarity is called haze. Haze obscures the color, texture,
and form of objects that can be seen at a distance.
Visibility can be impaired by natural sources such as rain, wildland fires, volcanic activity, sea
mists, and wind-blown dust from undisturbed desert areas. Visibility also can be impaired by
anthropogenic sources of air pollution such as industrial processes, (utilities, smelters,
30 Data source: Stats Report Viewer (nps.gov). 31 Data source: Stats Report Viewer (nps.gov).
32 Data Source: https://www.nps.gov/subjects/lwcf/upload/NPS-Acreage-12-31-2012.pdf
33 Zion National Park Foundation Document, website: https://www.nps.gov/zion/learn/management/upload/ZION_Foundation_Document_SP-2.pdf
Figure 8: Zion National Park

22
refineries, etc.), mobile sources (cars, trucks, trains, etc.), and area sources (residential wood
burning, prescribed burning on wild and agricultural lands, wind-blown dust from disturbed soils,
etc.). These sources emit pollutants that, in higher concentrations, can also affect public health.
Regional haze is the cumulative impact of emissions from varied sources, often located over a
broad geographic area. The haze-causing particles can be transported great distances in the
air, sometimes hundreds or thousands of miles. Therefore, one single source of emissions may
not have a visible impact on haze, but emissions from many sources in a region can add up and
cause haziness.
There are different metrics to measure impact on visibility. Visual range is the most intuitive and
is defined as the distance at which a given standard object can be seen with the unaided eye. It
is measured in miles or kilometers. A deciview is a unit of visibility proportional to the logarithm
of the atmospheric light extinction. This unit will be used in many figures and tables within this
report. Deciviews measure visibility derived from light extinction so that incremental changes in
the haze index correspond to uniform incremental changes in visual perception ranging from
pristine to highly impaired conditions.

1.D Monitoring Strategy34
Interagency Monitoring of Protected
Visual Environments (IMPROVE)
was designated as the visibility
monitoring network representative
of the 156 visibility-protected federal
CIAs. IMPROVE was developed in
1985 to establish current visibility
conditions, track changes in
visibility, and help determine the
causes and sources of visibility
impairment in CIAs. The network is
comprised of 110 monitoring sites
across the nation35, four of which
are in Utah. IMPROVE monitoring
sites in Utah’s CIAs include those at
Canyonlands National Park
(monitoring site for both Arches and
Canyonlands national parks), Capitol Reef National Park, Bryce Canyon National Park, and
Zion National Park. Figure 10 through Figure 12 show three of Utah’s monitoring stations.

34 40 CFR 51.308(f)(6) (IMPROVE PROGRAM) 35 Shown in Figure 13
Figure 9: Monitoring station for Capitol Reef National Park

23
The IMPROVE monitoring sites contain equipment programmed to automatically collect
samples of haze-forming particles
from the air continually. Local
operators at each field site—in
many cases a park ranger,
firefighter, or rancher—inspect the
samples and exchange filters
weekly, shipping all exposed filters
back to the Air Quality Research
Center (AQRC) at the University of
California (UC) Davis every three
weeks. Each month, the program’s
110 field sites generate about 7,000
filters, which are processed in
AQRC’s laboratories by staff
members and UC Davis students
working part-time.36 The analyses
conducted at the AQRC test
samples for various
pollutants and trace metals
and estimate the light
scattering effect of each
species This estimation
results in a light extinction
value. For purposes of the
RHR, light extinction is
estimated for sulfate, nitrate,
organic mass by carbon
(OMC), light absorbing
carbon (LAC), fine soil (FS),
sea salt, and coarse material
(CM)—all components of
particulate emissions. Figure
12 shows the four separate
modules used for sampling
the different species.

36 For more information see: https://aqrc.ucdavis.edu/improve
Figure 10: Monitoring station for Canyonlands and Arches National Park
Figure 11: Monitoring station for Bryce Canyon National Park

24

1.D.1 Participation in the IMPROVE Network
In 1985, the IMPROVE program was established to coordinate the monitoring of air quality in
national parks and wilderness areas and to ensure sound and consistent scientific methods
were being used. The IMPROVE Steering Committee established monitoring protocols for
visibility measurement, PM measurement, and scientific photography of the CIAs. IMPROVE
monitoring is designed to establish reference information on visibility conditions and trends to
aid in the development of visibility protection programs. Monitoring from the IMPROVE network,
shown in Figure 13, demonstrated that visibility in all the CIAs is impaired to some degree by
regional haze.
Figure 12: Monitoring station layout
Figure 13: IMPROVE monitoring sites

25

1.E History of Regional Haze in Utah
Utah has been at the forefront of haze improvement and prevention since 1991 when the
GCVTC was formed. The GCVTC recognized haze as a regional issue prior to the creation of
the RHR in 1999 and was the first multi-state collaborative effort to address visual air quality
issues. In recognition of the GCVTC, Section 309 of the RHR provided an early regional haze
planning opportunity for states within the Colorado Plateau region. Utah is one of the five states
to submit a complete Section 309 regional haze plan in 2003.
In amendments to the Clean Air Act (CAA) in 1977, Congress added Section 169A setting the
national visibility goal of restoring pristine conditions in national parks and wilderness areas:
“Congress hereby declares as a national goal the prevention of any future, and the remedying of
any existing, impairment of visibility in mandatory CIAs which impairment results from man-
made air pollution.”37
When the CAA was amended in 1990, Congress added Section 169B,38 authorizing further
research and regular assessments of the progress to improve visibility in the mandatory CIAs.39

37 42 U.S.C.A. § 7491. 38 See id. § 7492.
39 Figure 14: Map of 156 Mandatory Federal CIAs shows the location of the CIAs of concern and the Federal Land Managers (FLMs) responsible for each area around the nation.

26
The RHR specifies that these CIAs should attain “natural conditions” by 2064 and that states
should make progress in controlling air pollution to meet this goal. The timeline is broken into
10-year planning periods, and in each period, states must show reductions in emissions of
haze-causing pollutants along a linear path, or glidepath, toward the 2064 end goal.

To meet the RHR planning requirements, states conduct analyses of visibility in each Class I
area, identify the available reasonable measures to reduce haze, and implement those
measures. The implemented measures establish the required Reasonable Progress Goals
(RPG) for each Class I area. The RPGs are the visibility improvement benchmarks on the
glidepath toward the long-term goal of natural visibility conditions by 2064.40 The analysis,
measures, and RPGs are the basis of the long-term strategy for the states, and this strategy
must be included in the states’ SIPs. States are also required to assess progress halfway
through the 10-year implementation period - a process that is intended to keep the states on
target to meet the 10-year goals established for each Class I area.
1.E.1 Grand Canyon Visibility Transport Commission
The GCVTC was established by EPA in November of 1991, consisting of seven western
governors (or their designees), five tribes, and five ex-officio members representing federal land
management agencies and EPA. When establishing the GCVTC, EPA designated a transport
region including seven western states: California, Oregon, Nevada, Idaho, Utah, Arizona,

40 See Figure 15 for an RPG glidepath example of Bryce Canyon National Park, provided by the Western Regional Air Partnership (WRAP) Technical Support System.
Figure 14: United States map of mandatory CIAs Figure 14: United States map of mandatory CIAs

27
Colorado, and New Mexico. Although a part of the Transport Region, the State of Idaho declined
the invitation to participate in the GCVTC.
Although Congress required a commission to be established for Grand Canyon National Park,
the member states agreed to expand the scope of the GCVTC to address all 16 of the CIAs on
the Colorado Plateau. The GCVTC elected to use a stakeholder-driven process to accomplish
its objectives. Ultimately, the organization included 200+ political, policy and technical
stakeholders who staffed a variety of committees and subcommittees to perform policy analysis
and technical studies, and to participate in the public debate. The GCVTC was funded by EPA
grants and contributions from stakeholders, including substantial in-kind labor. During its four-
and-one-half year development, the GCVTC was expanded to include the State of Wyoming and
tribal leaders as members. The GCVTC appointed a Public Advisory Committee (PAC)
representing broad stakeholder interests to provide input and feedback to the GCVTC. Many
Utahns were members of the PAC, with two serving on the PAC Steering Committee, and one
serving on the Executive Committee as Vice-Chair of the PAC. The 80+ member Public
Advisory Committee developed a consensus report of recommendations for the GCVTC that
was ultimately adopted by the GCVTC and submitted to EPA in June 1996.41
Recommendations of the GCVTC included the following:
• Policies based on energy conservation, increased energy efficiency, and promotion of
the use of renewable resources for energy production;
• Careful tracking of emissions growth that may affect air quality in clean air corridors;

41 The Grand Canyon Visibility Transport Commission. Recommendations for Improving Western Vistas (June 10, 1996) available at https://www.phoenixvis.net/PDF/GCVTCFinal.pdf
Figure 15: Regional haze glidepath for Bryce Canyon National Park tracking progress towards natural conditions in 2064

28
• Regional targets for SO₂ emissions with a backstop program, probably including a
regional cap and possibly a market-based trading program;
• Cooperatively developed strategies, expanded data collection and improved modeling for
reducing or preventing visibility impairment in areas within and adjacent to CIAs, pending
further studies of sources adjacent to CIAs;
• Emissions cap for mobile sources at the lowest level (expected to occur in 2005) and
establishment of a regional emissions budget, as well as the implementation of national
strategies aimed at reducing tailpipe emissions;
• Further study to resolve issues regarding the modeled contribution to visibility impairment
of dust from paved and unpaved roads;
• Continued bi-national cooperation to resolve data gaps and jurisdictional issues around
emissions from Mexico;
• Programs to minimize emissions and visibility impacts and to educate the public about
impacts from prescribed fire and wildfire, because emissions are projected to increase
significantly through 2040; and
• Creation of an entity like the GCVTC to promote, support, and oversee the
implementation of many of the recommendations in this report.
EPA initially proposed regional haze regulations in 1997.42 The proposed regulations described
a generic program to apply nationally and did not include provisions to address the
recommendations of the GCVTC. The Western Governors’ Association (WGA) engaged key
stakeholders to develop a recommendation on how to transform the GCVTC recommendations
into the regional haze regulations. WGA approved the stakeholders’ recommendation and
transmitted it to EPA in June 1998.43 Based on this and other public input, EPA issued the final
Regional Haze Rule in July 1999 with a national program (Section 308) that could apply to any
state or tribe and an optional program (Section 309) relying on the work of the GCVTC that is
available to the states and tribes in the nine-state GCVTC transport region.44
1.E.2 Western Regional Air Partnership
The GCVTC recognized the need for a long-term organization to address the policy and
technical studies needed to address regional haze. The Western Regional Air Partnership
(WRAP) was formed in September 1997 to fulfill this need. The WRAP’s charter allows it to
address any air quality issue of interest to WRAP members, though most current work is
focused on developing the policy and technical work products needed by states and tribes in
writing their regional haze SIPs and tribal implementation plans (TIPs). The WRAP has been co-
chaired by the governor of Utah and the governor of the Acoma Pueblo. The WRAP Board is
currently composed of representatives from 13 states, 13 tribes, the U.S. Department of
Agriculture, the U.S. Department of the Interior, and the EPA. The WRAP operates on a
consensus basis and receives financial support from EPA. The WRAP established stakeholder-

42 Regional Haze Regulations, 62 Fed. Reg. 41138 (July 31, 1997) (proposed rule). 43 Leavitt, M. O., Governor of Utah, Letter to EPA Administrator Browner on behalf of the Western Governors’ Association, June 29, 1998. 44 Regional Haze Regulations, 64 Fed. Reg. 35714 (July 1, 1999), codified at 40 C.F.R. pt. 51.

29
based technical and policy oversight committees to assist in managing the development process
of regional haze work products. Stakeholder-based working groups and forums were
established to focus on the policy and technical work products the states and tribes need to
develop their implementation plans.
The WRAP developed and submitted an Annex to the GCVTC recommendations to define a
voluntary program of SO₂ emission reduction milestones coupled with a backstop market-trading
program to assure emission reductions. EPA proposed changes to the Regional Haze Rule to
incorporate the GCVTC Annex, and the final revised rule was published on June 5, 2003.45 The
WRAP has completed a suite of products to support states and tribes developing GCVTC-based
regional haze implementation plans.46
1.E.3 2003 Regional Haze SIP
On June 5, 2003, EPA approved the Annex and incorporated the stationary source provisions
into the RHR In December 2003 the Utah Air Quality Board adopted Section XX of the SIP to
address regional haze. This plan was based on the GCVTC recommendations and the Annex
and contained a broad-based strategy to address the many source categories and pollutants
that contributed to regional haze in Utah, including clean air corridors, fire, mobile sources,
paved and unpaved road dust, pollution prevention and renewable energy programs, and
stationary sources.
EPA’s approval of the Annex was challenged in court, and on February 18, 2005, the DC Circuit
Court of Appeals vacated EPA’s 2003 rules.47 The Court determined that EPA had required a
BART demonstration in the Annex that was based on a methodology that had been vacated by
the Court in 2002 in American Corn Growers Association v. E.P.A., 291 F.3d 1 (D.C. Cir. 2002),
decision. On October 13, 2006, EPA revised the RHR to establish the methodology for states to
develop an alternative to BART that was consistent with the DC Circuit’s 2005 decision.48
1.E.4 2008 Regional Haze SIP Revision
While most of the 2003 SIP remained unchanged, in 2008 the Utah Air Quality Board adopted
revisions to the stationary source provisions of the SIP to meet the requirements of the revised
RHR and to reflect changes in the number of states participating in the program. In addition to
these changes, the rule required an update to the SIP in 2008 to address the BART requirement
for NOx and PM as well as an analysis of the impact of sources in Utah on CIAs outside of the
Colorado Plateau.

45 Revisions to Regional Haze Rule to Incorporate SO₂ Milestones and Backstop Emissions Trading Program for Nine Western States and Eligible Indian Tribes Within That Geographic Area, 68 Fed. Reg. 33764 (June 5, 2003), codified at 40 C.F.R. pt. 51.
46 Additional information about the WRAP can be found on the WRAP website at https://www.wrapair2.org/ 47 See Ctr. for Energy & Econ. Dev. v. E.P.A., 398 F.3d 653 (D.C. Cir. 2005)
48 See Regional Haze Regulations, 71 Fed. Reg. 60,612, 60,631 (Oct. 13, 2006), codified at 40 C.F.R. pt. 51.

30
1.E.5 2011 Regional Haze SIP Revision
The SO₂ milestones were updated in 2011 to reflect a reduced number of states participating in
the program (Arizona elected to pursue a SIP under Section 308 of the RHR). In addition, the
growth estimates for coal-fired utilities and the estimates for emission reductions due to BART
were revised.
1.E.6 2015 Regional Haze SIP Revision
On June 4, 2015, Utah resubmitted its SIP for PM BART and submitted an alternative to BART
for NOx for PacifiCorp’s Electrical Generating Units (EGUs). On January 14, 2016, EPA issued a
proposed rule containing a proposal to approve the PM BART and a co-proposal to either
approve or disapprove the BART Alternative for NOx and to impose a Federal Implementation
Plan (FIP) requiring BART for NOx in the event of the disapproval.49 On July 5, 2016, EPA
issued the final rule disapproving the BART alternative for NOx and approving the BART for the
PM portion of the June 4, 2015 SIP.50 To replace the disapproved BART alternative, EPA
promulgated a FIP, requiring installation of Selective Catalytic Reduction (SCR) controls on the
subject EGUs by August of 2021.51
Utah filed a lawsuit against EPA challenging the July 5, 2016 disapproval of BART Alternative
for NOx in the Tenth Circuit on September 1, 2016.52 The parties engaged in settlement
discussions to resolve the case administratively. As a result of the settlement negotiations, Utah
conducted an additional technical analysis using the state-of-the-science model and
methodologies to perform air quality model simulations.53 Utah used the photochemical grid
model Comprehensive Air Quality Model with Extensions (CAMx) to estimate and compare the
potential visibility impacts at selected CIAs for different emissions scenarios considered for
PacifiCorp’s EGUs. The CAMx was used because it accounts for complex processes such as
the chemistry, transport, and deposition of pollutants responsible for regional haze.
Utah came to the same conclusion employing the CAMx modeling: that its NOx BART
Alternative would provide greater reasonable progress toward natural visibility conditions than
BART.54 Utah revised the disapproved SIP to include this additional technical analysis and, after
49 See Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Partial Approval and Partial Disapproval of Air Quality Implementation Plans and Federal Implementation Plan; Utah; Revisions to Regional Haze State Implementation Plan; Federal Implementation Plan for Regional Haze, 81 Fed. Reg. 2004 (Jan. 14, 2016) (proposed rule). 50 See Approval, Disapproval and Promulgation of Air Quality Implementation Plans; Partial Approval and Partial Disapproval of Air Quality Implementation Plans and Federal Implementation Plan; Utah; Revisions to Regional Haze State Implementation Plan; Federal Implementation Plan for Regional Haze, 81 Fed. Reg. 43894 (July 5, 2016), codified at 40 C.F.R. pt. 52. 51 See id., 81 Fed. Reg. at 43907.
52 See Utah v. E.P.A. et al., No. 16-9541 (10th Cir. Sept. 1, 2016). 53 See Section 1.E.7 below for additional details.
54 Staff Review Recommended Alternative to BART for NOx at 5-2 (Jan. 14, 2019) ("The model results... indicate that the emissions modeled under the Utah SIP will not degrade visibility conditions relative to the Baseline scenario at any of the analyzed CIAs during either the 20% best or 20% worst visibility days.

31
public notice and comment, submitted the revised NOx BART Alternative to EPA on July 3,
2019. Utah submitted a supplement to the July 2019 submission on December 3, 2019 on the
issue unrelated to the initial disapproval—the requirement to report all deviations from
compliance with the applicable requirements under BART and BART Alternative, including
emission limits for PacifiCorp’s EGUs. On January 22, 2020, EPA published a proposed rule to
approve the July 2019 SIP submittal with December 2019 supplement.55
After EPA’s public notice and comment, on November 27, 2020, EPA issued a final rule
approving Utah’s July 2019 SIP submittal and December 2019 supplement.56 This concluded
and resolved the litigation that Utah initiated on September 1, 2016. The Tenth Circuit dismissed
the case and issued a mandate on January 11, 2021.57 EPA’s November 27, 2020 final rule is
currently challenged in the Tenth Circuit by the conservation organizations (HEAL Utah,
National Parks Conservation Association, Sierra Club, and Utah Physicians for a Healthy
Environment).58 The lawsuit was filed on January 19, 2021.59
1.E.7 2019 Regional Haze SIP Revision
In the 2019 SIP revision, Utah used dispersion modeling and the two-prong test prescribed by
the RHR60 to demonstrate that the proposed alternative to BART does show greater progress
than the most stringent NOx controls (installation of SCR). The two prongs that Utah had to
satisfy are (1) that visibility does not decline in any Class I area; and (2) that there is an overall
improvement in visibility determined by comparing the average differences between BART and
the BART Alternative over all affected CIAs.
The two-prong test was an objective pass-fail test which Utah’s BART Alternative met. EPA
proposed approval of this latest SIP on January 22, 2020.61EPA issued final approval of the
2019 SIP revision on November 27, 2020 with effective date of December 28, 2020.62 In the
final rule EPA concluded “that Utah’s NOX BART Alternative achieves greater reasonable
progress under 40 CFR 51.308(e)(2) and (3).”63 With the final approval, EPA also found that
“Utah’s SIP fully satisfies the requirements of section 309 of the Regional Haze Rule and
The modeling results also show that, on average, visibility improvement at the analyzed CIAs is greater under the Utah SIP than the USEPA FIP scenarios during both the 20% best and 20% worst visibility days.”).
55 See Approval and Promulgation of Air Quality Implementation Plans; Utah; Regional Haze State and Federal Implementation Plans, 85 Fed. Reg. 3558 (Jan. 22, 2020) (proposed rule).
56 Approval and Promulgation of Air Quality Implementation Plans; Utah; Regional Haze State and Federal Implementation Plans, 85 Fed. Reg. 75860 (Nov. 27, 2020), codified at 40 C.F.R. pt. 52.
57 See Order, Utah v. E.P.A. et al., No. 16-9541 (10th Cir. Jan. 11, 2021). 58 See HEAL Utah et al. v. E.P.A. et al., No. 21-9509 (10th Cir. Jan 19, 2021).
59 See Petition for Review, HEAL Utah et al., No. 21-9509 (10th Cir. Jan. 19, 2021). 60 40 CFR 51.308€ (3)
61 See 85 Fed. Reg. 3558. 62 See 85 Fed. Reg. 75860.
63 Id., 85 Fed. Reg. at 75861.

32
therefore the State has fully complied with the requirements for reasonable progress, including
BART, for the first implementation period.”64
1.F General Planning Provisions
1.F.1 Regional Haze Program Requirements
The program requirements of the RHR65 are identified in Subsection 51.308(f) which lists the
requirements for haze SIP updates, including a reference to the requirements in Subsection
51.308(d). In addition to re‐evaluating all elements required in subsection (d), the states must
also do the following:
• Assess current visibility conditions for the most impaired and least impaired days.
• Address actual progress made towards natural conditions during the previous
implementation period.
• Determine the effectiveness of the long‐term strategy for achieving reasonable progress
goals over the prior implementation period.
• Affirm or revise reasonable progress goals according to procedures in paragraph (d).
As noted above, the section addressing the requirements for the SIP revisions references the
requirements of subsection (d). The subsection (d) requirements are as follows: requirements:
• Establishing reasonable progress goals for the implementation period, including the four‐
factor analysis.
• Determining current visibility conditions and comparing to natural conditions.
• Developing long‐term strategies to reduce emissions that contribute to visibility
impairment.
• Submitting a monitoring strategy.
40 CFR 51.308(f)(5) requires states to address the requirements of Subsections 51.308(g)(1)-
(5) in the 2021 plan revision. According to the requirements of 40 CFR 51.308(g), states shall
submit periodic reports that describe progress toward the natural visibility goals. Therefore, this
RH SIP submittal also serves as a progress report addressing the period since Utah’s
September 18, 2017 progress report. The RHR requires that subsequent progress reports are
due by January 31, 2025, July 31, 2033, and every 10 years thereafter.
1.F.2 SIP Submission and Planning Commitments
This SIP revision meets the requirements of the EPA’s RHR and the CAA. Elements of this SIP
address the core elements required by 40 CFR Section 51.308(f)(3)—the establishment of
RPGs and measures that Utah will take to meet the RPGs. This SIP revision also addresses 40
CFR 51.308(f)(2) (long-term strategy for regional haze) and 40 CFR 51.308(i)(2) (state

64 Id. 65 40 CFR 51.308

33
coordination with the FLMs) and commits to develop future plan revisions and adequacy
determinations as necessary.
The State of Utah commits to participate in a regional planning process, as a member state
through the Western States Air Resource Council (WESTAR) and as a partner in WRAP.
WESTAR is a partnership of 15 western states formed to promote the exchange of information,
serve as a forum to discuss western regional air quality issues, and share resources for the
common benefit of the member states. WRAP is a voluntary partnership of state, tribes, FLMs,
local air agencies, and the EPA whose purpose is to understand current and evolving regional
air quality issues in the West. The regional planning process describes the process, goals,
objectives, management and decision-making structure, and deadlines for completing significant
technical analyses of the regional group. To assist in making sound planning decisions, Utah
has assisted the regional planning organization to complete regional analyses that include
certain methods, inputs, and resources. Utah commits to continue regional participation through
future SIPs.
Pursuant to the Tribal Authority Rule66, any Tribe whose lands are within the boundaries of the
State of Utah have the option to develop a regional haze Tribal Implementation Plan (TIP) for
their lands to assure reasonable progress in the twelve CIAs in Utah. As such, no provisions of
this Implementation Plan shall be construed as being applicable to tribal lands.
1.F.3 Utah Statutory Authority
The Utah Air Conservation Act67 gives the Utah Air Quality Board authority to make rules
pertaining to air quality activities.68
An administrative rule serves two purposes:
• A properly enacted administrative rule has the binding effect of law. Therefore, a rule
affects the regulated entities and citizens as much as a statute passed by the
Legislature.
• An administrative rule informs citizens of actions a state government agency will take or
how a state agency will conduct its business.
This SIP is a compilation of analyses under Utah’s statutory authority that satisfies the
requirements of Sections 110 and 169 of the CAA.

Indian Tribes: Air Quality Planning and Management, 63 Fed. Reg. 7254 (Feb. 12, 1998).
67 Utah Code Ann. §§ 19-2-101 through 19-2-304 (West 2021). 68 See id. § 19-2-104.

34
Chapter 2: Utah Regional Haze SIP Development Process
This SIP addresses regulatory requirements of the second planning period by screening
facilities with the most impact on Utah’s CIAs, conducting and evaluating the four-factor
analysis,69 and making controls determinations based on this analysis. The current visibility
conditions in relation to our Uniform Rate of Progress (URP) goals were also analyzed with the
modeled data analysis tools provided by the WRAP Technical Support System (TSS).

Utah’s SIP development process included consultation with industry stakeholders,
environmental advocate stakeholders, regional states, WESTAR, WRAP, FLMs from the
National Parks Service and the US Forest Service, and EPA’s Region 8 office. Utah also
consulted members of other state agencies including the Department of Energy Development
and Office of Public Utilities. This chapter outlines Utah’s consultation and communications with
these entities. For additional details regarding individual consultation, see Chapter 9
Consultation, Public Review, Commitment to further Planning.

After initial consultation, Utah submitted the second planning period RH SIP to the FLMs, EPA,
and Tribes of Utah on December, 8, 2021 for their mandatory 60-day comment period. After the
comment period, the SIP was submitted to Utah Air Quality Board for the April 6th, 2022 Utah Air
Quality Board meeting. The Board then proposed the SIP for public comment on May 1st, 2022
for the required 30 days. Utah then submitted the final SIP to the EPA on August 1, 2022.
2.A WRAP Engagement
During this second planning period, the WRAP Regional Haze Planning Work Group
(RHPWG)70 has helped create a framework for regional haze planning for all 15 participating
states as well as the City of Albuquerque within the WESTAR and WRAP region. This initiative
included regular meetings to discuss regional haze planning, encourage coordination among
states, and offer training opportunities. WRAP has also been responsible for the WRAP TSS
which is an online portal to the technical and analytical results created from technology
development from Colorado State University (CSU) and the Cooperative Institute for Research
in the Atmosphere (CIRA). TSS is the source of the key summary analytical results and
methods for the required technical elements of the RHR contained within this SIP including:
• Inventories: current and future (growth projections methodologies by source categories)
• Development of a transparent and complete monitoring data metric for planning and
model projection purposes
• Database management (including the TSS database)

69 For purposes of this document, the Four-Factor Analysis is defined as the analysis required by 40 C.F.R. § 51.308(d)(1)(i)(A).
70 More information on the Regional Haze Planning Work Group can be found at https://www.wrapair2.org/RHPWG.aspx

35
• Four-Factor Analysis for control measures
• Regional photochemical modeling
• Assessment of “unknowns” and uncertain categories (natural conditions, international
emissions, fire, and dust emission, etc.)
• Development of RH SIP package content and progress report template
• Development of control strategies menu for major western state sources
For additional information on the origins of WRAP, see Section 1.E.2.
2.A.1 Technical Information and Data: WRAP TSS2.0
The WRAP TSS 2.0 is the data warehouse and online portal used by air quality planners to
evaluate the technical data and analytical results to support regional haze implementation plans.
The TSS 2.0 is a “system of systems” that integrates capabilities from many systems, including
systems focused on: monitoring data analysis efforts, emissions data management systems, fire
emissions tracking systems, photochemical aerosol regional modeling analyses, and
visualization and summary data analyses.71 These diverse data sets can be analyzed through
the TSS and the resultant outputs can be downloaded for use in SIP reports. This SIP submittal
relies on the data stored in and retrieved from the TSS 2.0 system.
2.B Consultation with Federal Land Managers
The federal land management agencies with jurisdiction over mandatory CIAs in the West
include the National Park Service (NPS), U.S. Forest Service (U.S. Department of Agriculture)
(USFS), and the Fish and Wildlife Service (FWS). FLMs have a critical role in protecting air
quality in national parks, wilderness, and other federally protected areas. They have an
affirmative responsibility to protect air quality related values, including visibility, in all CIAs.72
Utah primarily meets with the NPS and USFS for RH planning.
States must provide the FLMs with an opportunity for an early in-person consultation about the
state’s long-term strategy to reduce emissions.73 This consultation should happen early enough
in the process so that the information and recommendations provided by the FLMs can
meaningfully inform the State’s decisions.74 The opportunity for consultation is sufficient if the
consultation happened at least 120 days prior to any public hearing or other public comment
opportunity on SIP or SIP revision.75 The opportunity for consultation must also be provided no
less than 60 days prior to said public hearing or public comment opportunity.76

71 https://views.cira.colostate.edu/tssv2/About/Default.aspx
72 See 40 C.F.R. § 51.166(p)(2). 73 See 40 C.F.R. § 51.308(i)(2).
74 See id. 75 See id.
76 See id.

36
This consultation must include the opportunity for the affected FLMs to discuss their:
• Assessment of impairment of visibility in any mandatory CIA; and
• Recommendations on the development of the reasonable progress goal and on the
development and implementation of strategies to address visibility impairment.77
FLM of any mandatory Class I area can submit any recommendations on the implementation of
this subpart (40 C.F.R. Part 51, Subpart P: Protection of Visibility) including, but not limited to:
i. Identification of impairment of visibility in any mandatory CIA(s); and
ii. Identification of elements for inclusion in the visibility monitoring strategy required by
§ 51.305.78
Utah has engaged with the FLMs and shared the RH SIP with them on December 8, 2021. See
Chapter 9 Consultation, Public Review, Commitment to Further Planning for full documentation
of Utah’s consultation with the FLMs during this implementation period.
Numerous opportunities were provided through the WRAP for states and FLMs to participate
fully in the development of technical documents included in this SIP. This included the ability to
review and comment on these analyses, reports, and policies. A summary of the WRAP-
sponsored meetings and conference calls is provided on the WRAP website79.
2.C Collaboration with Tribes
Tribal governments are responsible for coordinating with federal and state governments to
protect air quality on their sovereign lands and to ensure emission sources on tribal lands meet
federal requirements. The federally recognized tribes in Utah include the Paiute Indian Tribe,
the Skull Valley Band of Goshute Indiana, and the Ute Indian Tribe of the Uintah and Ouray
Reservation. The sources located on tribal lands are considered federal jurisdiction. For
example, The Bonanza power plant, located on “Indian Country” in the Uinta Basin, has a Q/d
value large enough to require a Four-Factor Analysis, but is not under the jurisdiction of the
Utah Department of Environmental Quality. In order to further the environmental justice initiative
in Utah, UDAQ shared its RH SIP draft with the tribes of Utah at the same time it was shared
with the FLMs and EPA for a 60-day review on December 8, 2021.
2.D Consultation with Other States
States are required to share information with other states that have CIAs that are reasonably
anticipated to be impacted by each other’s emissions. States are also required to evaluate,
though not necessarily implement, control measures requested by other states and document
actions taken to resolve disagreements. The TSS 2.0 analyses tools, including emissions tools
and source apportionment modeling results, aid states to determine if an in-state source could
be impacting an out-of-state Class I area. Utah consulted with neighboring states, both through

77 See id., § 51.308(i)(2)(i) and (ii). 78 See id., § 51.308(i)(1)(i) and (ii).
79 More information on WRAP-sponsored meetings and conference calls is available at https://www.wrapair2.org/RHPWG.aspx.

37
webinars and calls organized through the WRAP, and via state-to-state communication, to
address the requirements of the RHR for coordinated emissions control strategies between
states. Specifically, 40 CFR § 51.308(f)(2)(ii) requires that Utah consult with other states that
have emissions that are reasonably anticipated to contribute to visibility impairment in Utah
CIAs to develop coordinated emission management strategies containing the emission
reductions necessary to make reasonable progress.
WRAP conducted technical analyses to evaluate interstate emissions impacts. These analyses
include source apportionment modeling and area of influence/weighted emissions potential
(AOI/WEP) analyses. Source apportionment modeling is used to identify states and sectors that
are contributing haze. AOI/WEP analyses can identify what significant emission sources are
upwind from a Class I area. Utah discussed the results of these analyses with surrounding
states. Due to all of Utah’s CIAs visibility being at or below their projected glidepath goals
towards natural conditions in 2064, UDAQ will not ask for any additional controls from other
states that may impact Utah’s visibility in CIAs. Refer to sections 6.A.1 and 6.A.2 for a detailed
analysis on out of state impacts on Utah’s CIA’s and Utah’s impacts on out of state CIAs.
Utah has met with Colorado, New Mexico, Arizona, and Wyoming directly as well as attended
Region 8, WRAP, WESTAR, and Four Corners States meetings as part of the second planning
period SIP development. For additional details regarding individual consultation, see Chapter 9
as well as Appendix B or Utah’s interstate consultation agreements with surrounding states.
2.E Public and Stakeholder Consultation
Many different agencies and interests come together to develop a RH SIP. Prior to formal public
review and EPA action, states should communicate regularly with industry and the public. Utah
communicated regularly with the regulated industry, including the sources that may be impacted
by the Four-Factor Analysis, environmental advocates, as well as members of the public. Utah
holds six meetings each for the industry stakeholders and environmental advocates. For
additional details regarding stakeholder consultation, see Chapter 9.

38
Chapter 3: Progress to Date
3.A Embedded Progress Report Requirements
Section 51.308(f)(5) of the RHR requires a state to address the requirements of subsections
51.308 (g)(1) through (5) in the plan revision. By fulfilling this requirement, the plan revision due
in 2021 will also serve as a progress report for the period since submission of the progress
report for the first implementation period. The progress report for the first implementation period
included visibility levels, emissions, and implementation status up to a date prior to submittal.80

This chapter is meant to inform the public and EPA about implementation activities since the
last regional haze SIP submission.
3.A.1 Implementation status of all measures in first planning period81
The RHR82 requires certain major stationary sources to evaluate, install, operate and maintain
BART technology or an approved BART alternative for NOx and PM emissions. The State of
Utah chose to evaluate BART for PM under the case-by-case provisions of 40 CFR 51.308(e)(1)
and BART for NOx through alternative measures83. BART for SO₂ is addressed through an
alternative program84 that is described in Part E of the 2019 Regional Haze SIP.
40 CFR 51.308(e)(1)(ii) requires states to determine which BART-eligible sources are also
“subject to BART.” BART-eligible sources are subject to BART if they emit any air pollutant that
may reasonably be anticipated to cause or contribute to any impairment of visibility in any
mandatory CIA.
Four BART-eligible electric generating units were identified in the State of Utah: PacifiCorp’s
Hunter Units 1 and 2 and Huntington Units 1 and 2. The units are located at fossil fuel-fired
steam electric plants of more than 250 million Btu per hour heat input, one of the 26 specific
BART source categories. The units had potential emissions greater than 250 tons per year of
visibility impairing pollutants. The units had commenced construction within the BART time
frame of August 7, 1962 to August 7, 1977. PacifiCorp Hunter Units 1 and 2 and Huntington
Units 1 and 2 replaced first generation low-NOx burners with Alstom TSF 2000TM low-NOx firing
system and installation of two elevations of separated overfire air with an emission limit of 0.26
lb./MMBtu on a 30-day rolling average.
In addition, PacifiCorp Hunter Unit 3 (not subject-to-BART) replaced first generation low-NOx
burners with improved low-NOx burners with overfire air with an emission limit of 0.34 lb./MMBtu
80 The 2017 Regional Haze Guidance document can be found at https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf
81 (40 CFR 51.308(g)(1)) 82 40 CFR 51.308(e) and 40 CFR 51.309(d)(4)(vii)
83 40 CFR 51.308(e)(2) and (3) 84 40 CFR 51.309

39
on a 30-day rolling average and PacifiCorp Carbon Units 1 and 2 (not subject-to-BART) were
permanently retired by August 15, 2015.
Table 1: 30-day Rolling Average Emission Limits for the Retrofitted Hunter and Huntington Units
Units Utah Permitted Limits
SO₂ (lb./MMBtu) NOx (lb./MMBtu) PM (lb./MMBtu)
Hunter 1 0.12 0.26 0.015
Hunter 2 0.12 0.26 0.015 Hunter 3 0.34 Huntington 1 0.12 0.26 0.015 Huntington 2 0.12 0.26 0.015

3.A.2 Summary of emission reductions achieved by control measure implementation85
The enforceable retirement of Carbon Units 1 and 2 resulted in SO₂ reductions of 3,388
tons/year from Unit 1 and 4,617 tons per year from Unit 2, resulting in a total of 8,005 tons per
year. Utah’s emissions reductions are further detailed in Chapter 5.
3.A.3 Assessment of visibility conditions86
Please refer to Chapter 4 for information regarding Utah’s visibility analyses.

85 (40 CFR 51.308(g)(2)(5)) 86 (40 CFR 51.308(g)(3))

40
3.A.4 Analysis of any changes in emissions from all sources and activities within the
state87 88
The following figures show Utah’s statewide total emissions trends by sector from 2002 to 2017.
This data comes from Utah’s statewide emissions inventories. In 2011, there are certain spikes
in emissions for area source emissions due to inventory method changes and an increase in the
amount of Source Classification Codes (SCCs) defining area sources. UDAQ notes that
inventory methodologies have changed over time and the emissions inventories based on
WRAP modeling data in section 5.E may be more useful for comparing historical and recent
emissions to future projections for the purposes of satisfying the requirements of 40 CFR
51.308(g)(4).

87 (40 CFR 51.308(g)(4))
2002 2005 2008 2011 2014 2017
Area Source 6,294 5,536 8,664 41,987 13,848 4,134
Area Source - Oil & Gas 15,340 13,130
Non-Road Mobile 36,257 22,212 23,296 19,507 17,288 16,388
On-Road Mobile 77,437 82,449 61,634 68,109 60,952 57,387
Point Source 82,421 75,102 86,857 69,913 63,370 41,903
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
to
n
s
/
y
e
a
r
Statewide NOx Emissions Trends by Sector
Figure 16:Statewide NOx Emissions Trends by Sector

41

Figure 17: Statewide VOC Emissions Trends by Sector
2002 2005 2008 2011 2014 2017
Area Source 50,152 56,416 59,587 184,099 31,574 33,935
Area Source - Oil & Gas 111,880 70,217
Non-Road Mobile 27,584 22,479 24,677 22,629 20,066 10,671
On-Road Mobile 53,582 36,278 31,673 25,282 20,487 19,619
Point Source 6,555 6,963 8,872 5,707 5,899 6,104
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
200,000
to
n
s
/
y
e
a
r
Statewide VOC Emissions Trends by Sector
Figure 18: Statewide SO2 Emissions Trends by Sector
2002 2005 2008 2011 2014 2017
Area Source 3,416 1,660 1,284 2,156 89 117
Area Source - Oil & Gas 92 74
Non-Road Mobile 1,536 1,627 1,132 759 214 220
On-Road Mobile 2,458 1,667 247 333 295 327
Point Source 41,704 43,019 28,621 25,170 25,600 11,786
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
to
n
s
/
y
e
a
r
Statewide SO2 Emissions Trends by Sector

42

2002 2005 2008 2011 2014 2017
Area Source 29,181 31,416 47,552 164,142 150,865 128,303
Area Source - Oil & Gas 675 483
Non-Road Mobile 2,243 1,892 1,841 1,627 1,528 1,230
On-Road Mobile 24,246 29,077 37,137 16,856 12,426 14,212
Point Source 11,080 11,739 11,877 9,443 10,397 9,303
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
180,000
to
n
s
/
y
e
a
r
Statewide PM10 Emissions Trends by Sector
Figure 19: Statewide PM10 Emissions Trends by Sector
2002 2005 2008 2011 2014 2017
Area Source 8,613 9,806 13,878 23,254 21,254 17,460
Area Source - Oil & Gas 656 483
Non-Road Mobile 1,840 1,473 1,727 1,533 1,449 1,117
On-Road Mobile 4,101 5,404 3,111 6,074 4,278 4,532
Point Source 3,587 4,518 4,089 4,809 5,653 4,998
0
5,000
10,000
15,000
20,000
25,000
to
n
s
/
y
e
a
r
Statewide PM2.5 Emissions Trends by Sector
Figure 20: Statewide PM2.5 Emissions Trends by Sector

43

2002 2005 2008 2011 2014 2017
PM10 66,751 74,125 98,407 192,067 175,891 153,531
PM2.5 18,142 21,201 22,806 35,670 33,290 28,589
0
50,000
100,000
150,000
200,000
250,000
to
n
s
/
y
e
a
r
Utah Particulate Matter Trends
Figure 21: Utah Particulate Matter Trends
2002 2005 2008 2011 2014 2017
NOx 202,409 185,300 180,451 199,517 170,798 132,942
SO2 49,113 47,975 31,283 28,418 26,290 12,524
VOC 137,873 122,136 124,809 237,717 189,907 140,545
0
50,000
100,000
150,000
200,000
250,000
to
n
s
/
y
e
a
r
Utah Gaseous Trends
Figure 22: Utah Gaseous Trends

44
3.A.5 Assessment of any changes in emissions from within or outside the state.89
The Center for the New Energy Economy (CNEE) at Colorado State University conducted an
analysis of current and future emissions of NOx and SO2 from fossil-fueled EGUs in 13-Western
states1 for WESTAR and WRAP.90 WRAP state air quality staff and representatives of Western
electric utilities actively participated in the project and helped develop the study parameters,
including information needed for Western regional air quality analyses and planning under the
federal Clean Air Act.
SO2 and NOx emissions from the Western power sector have decreased dramatically over the
last 20 years. As shown in Figure 23, 2018 EGU emissions of SO2 were 84% below 1998 levels
and NOx emissions were 71% below 1998.

Table 2 below shows that 29 of the 84 coal units operating in the West in 2018 have plans (not
all federally enforceable) to retire by 2028. Emissions from these units were omitted from the
2028 projections produced by the CNEE, though some states opted to include emissions for
some of the listed EGUs in the final WRAP 2028OTBa2 projections due to uncertainties about
firm closures (e.g., North Valmy, San Juan Generating Station, etc.).
89 (40 CFR 51.308(g)(5))
90 The Analysis of EGU Emissions for Regional Haze Planning by the CNEE can be found at http://www.wrapair2.org/%5C/pdf/Final%20EGU%20Emissions%20Analysis%20Report.pdf
100
200
300
400
500
600
700
800
199819992000200120022003200420052006200720082009201020112012201320142015201620172018
SO2 & NOx Emissions from Western Power Plants
13-State Region -EPA CAMD (thousand tons)
SO2 NOx
Figure 23: SO2 and NOx Emissions Trends for Western Power Plants1

45
Table 2: Western Coal Unit Retirement and Control Summary
State Facility Name Unit ID Operating Year Retirement Year Notes
PLANNED RETIREMENTS - NO POST-COMBUSTION CONTROL FOR NO=x
AZ Cholla 1 1962 2025 APS IRP
AZ Cholla 3 1980 2025 APS IRP
AZ Cholla 4 1981 2025 PAC IRP
AZ Navajo Generating Station 1 1974 2019 SRP IRP
AZ Navajo Generating Station 2 1975 2019 SRP IRP
AZ Navajo Generating Station 3 1976 2019 SRP IRP
CO Comanche (470) 1 1973 2022 Xcel Colorado Energy Plan CO Comanche (470) 2 1975 2025 Xcel Colorado Energy Plan
CO Craig C1 1980 2025 Legal/Regulatory
CO Nucla 1 1991 2022 Legal/Regulatory
CO Valmont 5 1964 2017 Retired
MT Colstrip 1 1975 2022 Legal/Regulatory
MT Colstrip 2 1976 2022 Legal/Regulatory
NM San Juan 1 1976 2022 PNM IRP (SNCR)
NM San Juan 2 1973 2017 Retired
NM San Juan 3 1979 2017 Retired
NM San Juan 4 1982 2022 PNM IRP
NV North Valmy 1 1981 2025 NV IRP (2019 per ID Power?)
NV North Valmy 2 1985 2025 NV IRP
NV Reid Gardner 4 1983 2017 Retired
OR Boardman 1SG 1980 2021 Legal/Regulatory
UT Intermountain 1SGA 1986 2025 Planned (new gas?)
UT Intermountain 2SGA 1987 2025 Planned (new gas?)
WA Centralia BW21 1972 2021 Legal/Regulatory (12/31/2020)
WA Centralia BW22 1973 2026 Legal/Regulatory (12/31/2025)
WY Naughton 3 1971 2018 PAC IRP - gas in 2019?
MT Hardin 2017
POTENTIAL RETIREMENTS - NO POST-COMBUSTION CONTROL FOR NOx
AZ Coronado Generating
Station
U1B 1979 Retire or install SCR in 2025
UT Bonanza 1-Jan 1986 2030 Coal consumption cap
WY Dave Johnston BW41 1959 2027 PAC IRP
WY Dave Johnston BW42 1961 2027 PAC IRP
WY Dave Johnston BW43 1964 2027 PAC IRP

46
State Facility Name Unit ID Operating Year Retirement Year Notes
WY Dave Johnston BW44 1972 2027 PAC IRP
WY Jim Bridger BW71 1974 2028 PAC IRP (SCR req'd
2022)
WY Naughton 1 1963 2029 PAC IRP
WY Naughton 2 1968 2029 PAC IRP
POST 2028 RETIREMENT DATE - SCR INSTALLED
AZ Coronado Generating
Station
U2B 1980 SCR 2014
AZ Springerville Generating
Station
4 2009 SCR
AZ Springerville Generating
Station
TS3 2006 SCR
CO Comanche (470) 3 2010 SCR
CO Craig C2 1979 SCR 2017
CO Hayden H1 1965 2030 Xcel IRP - SCR in 2015
CO Hayden H2 1976 2036 Xcel IRP - SCR 2016
CO Pawnee 1 1981 2034 Xcel IRP - SCR 2014
NM Four Corners Steam Elec
Station
4 1969 2031 per TEP&PNM - SCR 2017
NM Four Corners Steam Elec
Station
5 1970 2031 per TEP&PNM - SCR 2017
NV TS Power Plant 1 2008 SCR
WY Dry Fork Station 1 2011 SCR
WY Jim Bridger BW73 1976 2037 PAC IRP - SCR 2015
WY Jim Bridger BW74 1979 2037 PAC IRP - SCR 2016
WY Laramie River 1 1981 SCR 2019
WY Wygen I 1 2003 SCR
WY Wygen II 1 2008 SCR
WY Wygen III 1 2010 SCR
AZ Apache Station 3 1979 SNCR 2017
CO Craig C3 1984 SNCR 2017
WY Laramie River 2 1981 SNCR 2018
WY Laramie River 3 1982 SNCR 2018
POST 2028 RETIREMENT DATE - NO POST COMBUSTION CONTROLS FOR NOx
AZ Springerville Generating
Station
1 1985
AZ Springerville Generating
Station
2 1990
CO Martin Drake 6 1968
CO Martin Drake 7 1974
CO Rawhide Energy Station 101 1984

47
State Facility Name Unit ID Operating Year Retirement Year Notes
CO Ray D Nixon 1 1980
MT Colstrip 3 1984
MT Colstrip 4 1986
MT Lewis & Clark B1 1958
NM Escalante 1 1984
UT Hunter 1 1978 2042 PAC IRP - Haze
Lawsuit
UT Hunter 2 1980 2042 PAC IRP - Haze Lawsuit
UT Hunter 3 1983 2042 PAC IRP
UT Huntington 1 1977 2036 PAC IRP - Haze Lawsuit
UT Huntington 2 1974 2036 PAC IRP - Haze
Lawsuit
WY Jim Bridger BW72 1975 2032 PAC IRP (SCR Req'd 2021)
WY Neil Simpson II 1 1995
WY Wyodak BW91 1978 2039 PAC IRP - Haze Lawsuit

Emissions from coal units that will retire by 2028 comprised 27% of the SO2 and 34% of the NOx
emitted in 2018 by all EGUs (coal and gas) in the 13-state Western region.91 Figure 24 below
shows the portion of EGU emissions represented by remaining fossil units and retiring coal
units. Table 3 below contains data compiled by WESTAR-WRAP showing the changes in
emissions from 1996-2018 and percent change throughout the GCVTC states.

91 The Analysis of EGU Emissions for Regional Haze Planning by the CNEE can be found at http://www.wrapair2.org/%5C/pdf/Final%20EGU%20Emissions%20Analysis%20Report.pdf

48

Table 3: Changes in Emissions from 1996 - 2018 for 9 GCVTC States
Year VOC NOx SO₂ PM2.5* CM
1996 3325 3952 1063 1197 1171
2002 2449 2241 675 832 1886
2018 2760 1683 503 832 2104
% Change -17 -57 -53 -30 80
0
50,000
100,000
150,000
200,000
250,000
SO2 NOx
2018 EGU Emissions -13 Western States
28 Coal Units Retiring by 2028
Remaining Fossil Units Retiring Coal Units
Figure 24: Remaining and Retiring EGU Emissions Apportionment

49

Chapter 4: Utah Visibility Analysis92

The rule adopted in 1999 defined “visibility impairment” as “any humanly perceptible change”
(i.e., difference) “in visibility (light extinction, visual range, contract, or coloration) from that which
would have existed under natural conditions.”93 The 1999 rule directed states to track visibility
impairment on the 20% “most impaired days” and 20% “least impaired days” in order to
determine progress towards natural visibility conditions.94 This iteration of the rule did not define
“most impaired days” or “least impaired days” or clearly indicate whether they were the days
with the highest and lowest values for both natural and anthropogenic impairment or for
anthropogenic impairment only. However, the preamble to the 1999 final rule stated that the
least and most impaired days were to be selected as the monitored days with the lowest and
highest actual deciview levels, respectively, which encompass both natural and anthropogenic
contributions to reduced visibility.95 In 2003, the EPA issued a guidance detailing the steps for
selecting and calculating light extinction on the “worst” and “best” visibility days, which also
indicated that it is preferable for states to determine the least and most impaired days based on
monitoring data rather than determining and selecting the days with the highest and lowest
anthropogenic impacts.96 For the assessment purposes in the first planning period, the GCVTC
considered the average of the days representing the 20% best visibility conditions to be the
least impaired days.
The “worst” visibility days for some CIAs are impacted by natural emissions (e.g., wildfires and
dust storms). These natural contributions to haze vary in magnitude and duration. WRAP used
regional photochemical grid models to project visibility improvement between the 2002 baseline
and the 2018 future year and to set RPGs for the RHR state implementation plans. Despite
western states projecting large emission reductions from EGUs, mobile sources and smoke
management programs, the results of the 2018 visibility RPGs indicated many western CIAs
were projected to achieve less progress than the glidepath.
As a result, EPA modified the way in which certain days during each year are to be selected for
purposes of tracking progress towards natural visibility conditions in order to focus attention on
days when anthropogenic emissions impair visibility and away from days when wildfires and
natural dust storms are the greatest contributors to visibility impairment.97 These changes will

92 40 CFR 51.308(F)(1) 93 “64 Fed. Reg. 35714, 35764.”
94 “40 CFR 51.308(d)(2)(i)-(iv).” 95 The 2019 EPA Guidance can be found at: https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf 96 The EPA Guidance for Tracking Progress Under the Regional Haze Rule can be found at https://www.epa.gov/visibility/guidance-tracking-progress-under-regional-haze-rule 97 The 2019 EPA Guidance can be found at: https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf

50
provide the public and public officials with more meaningful information on how emission
reduction contribute to a decline in anthropogenic visibility impairment by reasonably reducing
the distorting effects of wildfires and natural dust storms on estimates of reasonable progress.
The EPA method defined a threshold for the episodic portion of natural haze for the
carbonaceous species (organic mass carbon (OMC), elemental carbon (EC)) and crustal
material (fine soil plus coarse mass), components that are indicators of wildfires and dust
storms, respectively.98 EPA recommended nominal thresholds for each episodic species’
combinations as the minimums of the yearly 95th percentile for the 15-year period from 2000 to
2014. The daily fraction of species extinction values greater than the 95th percentile threshold
are assigned to the natural episodic bin. Smaller, routine natural contributions from biogenic or
geogenic emissions are assumed to be a constant fraction of the measured IMPROVE species
concentrations on each day, with the fraction calculated as the ratio of a previously estimated
annual average natural concentration99 (Natural Conditions II, NC-II) divided by the non-
episodic annual average IMPROVE concentrations measured for each species. The metric
calculates the
natural routine portion, such that its annual average (excluding episodic events) is equal to the
site and species-specific NC-II concentrations.
Daily anthropogenic impairment is calculated as:
∆ dvanthropogenic visibility impairment = dvtotal – dvnatural
Daily anthropogenic impairment values are ranked from high to low impairment in order to select
the 20% most impaired days (MIDs) each year. States must now determine the baseline (2000-
2004) visibility condition for the 20% most anthropogenically impaired days. This approach
differs from the previous round in which the 20% most impaired days were selected from days
with the highest total impairment, not separating anthropogenic versus natural impairment.
Once the most impaired days are selected, states must calculate the rate of visibility
improvement over time that is required to reach natural conditions by 2064 for the 20% most
impaired days. Using the metric described above for separating natural (episodic and routine)

98 Figure 25 shows how haze is separated into natural and anthropogenic causes 99 IMPROVE. 2007. Natural Haze Levels II: Application of the New IMPROVE Algorithm to Natural Species Concentrations Estimates. Interagency Monitoring of Protected Visual Environments. http://vista.cira.colostate.edu/Improve/gray-literature/ (accessed October 2021)
Figure 25: Light extinction for Utah Class I Areas: natural and anthropogenic sources
Haze
Anthropogenic
Natural
Episodic
Routine

51
and anthropogenic, natural conditions are calculated as the average of the daily natural
contributions on the 20% most impaired days, in the period 2000-2014. The figures below
display the clearest and most impaired days calculated as described in EPA guidance. The line
drawn from the baseline to the endpoint is termed the glidepath, or the “uniform rate of progress
(URP),” and is calculated for each Class I area, and is used as a tracking metric for the path to
natural conditions. The URP is calculated with the following formula: 𝑼𝑼𝑼𝑼𝑼𝑼=[(𝟐𝟐𝟐𝟐𝟐𝟐𝟐𝟐−𝟐𝟐𝟐𝟐𝟐𝟐𝟐𝟐 𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗)𝟐𝟐𝟐𝟐% 𝒎𝒎𝒎𝒎𝒗𝒗𝒗𝒗 𝒗𝒗𝒎𝒎𝒊𝒊𝒊𝒊𝒗𝒗𝒊𝒊𝒊𝒊𝒊𝒊−(𝒏𝒏𝒊𝒊𝒗𝒗𝒏𝒏𝒊𝒊𝒊𝒊𝒗𝒗 𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗𝒗)𝟐𝟐𝟐𝟐% 𝒎𝒎𝒎𝒎𝒗𝒗𝒗𝒗 𝒗𝒗𝒎𝒎𝒊𝒊𝒊𝒊𝒗𝒗𝒊𝒊𝒊𝒊𝒊𝒊]𝟔𝟔𝟐𝟐
The most impaired days are the 20% of days with the highest anthropogenic fraction of total
haze. Tracking visibility progress on those days with highest impairment is intended to limit the
influence of episodic wildfires and dust storms on the visibility trends.
No changes were made from the previous implementation period in how the 20% clearest days
are calculated. The 20% clearest days are calculated from the days with the lowest total
impairment. As stated previously, the RHR requires states to demonstrate that there is no
degradation in the 20% clearest days from the baseline period.100
100 “64 Fed. Reg. 35714, 35764.”
Figure 26: URP Glidepath for Clearest Days, Bryce Canyon NP

52

4.A Baseline, Current Conditions and Natural Visibility Conditions
Section 51.308(f)(1) of the RHR requires Utah to calculate the baseline, current, and natural
visibility conditions as well as to determine the visibility progress to date and the uniform rate of
progress (URP) for each of its five CIAs. According to the RHR, baseline period visibility
conditions, current visibility conditions, natural conditions, and the URP should be expressed in
deciviews and calculated based on total light extinction.101 Baseline visibility conditions are
based on available monitoring data of the most impaired and clearest days during the period of
2000 to 2004. Current visibility conditions are to be calculated based upon the most recent five
years of data by calculating the average of the annual deciview index values for the most
impaired days and clearest days in this period, and averaging these respective annual values.
Natural visibility conditions are to be calculated by estimating the average deciview index on
most impaired and clearest days under natural conditions. Calculations were made in
accordance with 40 CFR 51.308(d)(2) and EPA’s Technical Guidance on Tracking Visibility
Progress for the Second Implementation Period of the Regional Haze Program.102
101 The 2019 EPA Guidance can be found at: https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf 102 Table 4 and Table 5 describe the IMPROVE site information for Utah’s CIAs
Figure 27: URP Glidepath for most impaired days, Bryce Canyon NP

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Table 4: Representative IMPROVE Monitoring Sites
Class I Area Name Representative IMPROVE Site Site ID
Arches National Park Canyonlands NP CANY1
Bryce Canyon National Park Bryce Canyon NP BRCA1
Canyonlands National Park Canyonlands NP CANY1
Capitol Reef National Park Capitol Reef NP CAPI1
Zion National Park Zion NP ZICA1

Table 5: IMPROVE site information for CIAs
Site ID Class I Area Name(s) Latitude Longitude State AQS Code
BRCA1 Bryce Canyon National Park 37.6184 -112.1736 UT 49-017-0101
CANY1 Arches National Park, Canyonlands National Park 38.4587 -109.821 UT 49-037-0101
CAPI1 Capitol Reef National Park 38.3022 -111.2926 UT 49-055-9000
ZICA1 Zion National Park 37.1983 -113.1507 UT 49-053-0130

4.A.1 Baseline (2000-2004) visibility for the most impaired and clearest days103
Baseline visibility conditions are based on the available IMPROVE monitoring data of the 20%
most impaired and clearest days during the period of 2000 to 2004. Table 6 shows the baseline
visibility calculated for clearest days and most impaired days for each of Utah’s CIAs.
Table 6: Baseline Visibility for the 20% Most Impaired Days and 20% Clearest Days
Site ID Class I Area Name(s) Clearest Days
(dv)
Most Impaired Days
(dv)
BRCA1 Bryce Canyon National Park 2.77 8.42
CANY1 Arches National Park, Canyonlands National Park 3.75 8.79
CAPI1 Capitol Reef National Park 4.10 8.78
ZICA1 Zion National Park 4.48 10.40

4.A.2 Natural visibility for the most impaired and clearest days104
Natural visibility conditions are to be calculated by estimating the average deciview index on
most impaired and clearest days under natural conditions. Table 7 summarizes the natural
visibility values calculated for the clearest and most impaired days in each of Utah’s CIAs.

103 (40 CFR 51.308(f)(1)(i))
104 (40 CFR 51.308(f)(1)(ii))

54
Table 7: Natural Visibility values for Utah CIAs
Site ID Class I Area Name(s) Clearest Days (dv) Most Impaired Days (dv)
BRCA1 Bryce Canyon National Park 0.57 4.08 CANY1 Arches National Park, Canyonlands National Park 1.05 4.13
CAPI1 Capitol Reef National Park 1.28 4.00
ZICA1 Zion National Park 1.83 5.26
4.A.3 Current (2014-2018) visibility for the most impaired and clearest days105
Current visibility conditions are to be calculated based upon the most recent five years of data
by calculating the average of the annual deciview index values for the most impaired days and
clearest days in this period, and averaging these respective annual values. Table 8 below
shows the current visibility values calculated for the clearest and most impaired days in each of
Utah’s CIAs.
Table 8: Current Visibility (2014-2018) conditions in Utah CIAs
Site ID Class I Area Name(s) Clearest Days (dv) Most Impaired Days (dv)
BRCA1 Bryce Canyon National Park 1.46 6.60
CANY1 Arches National Park, Canyonlands National Park 2.20 6.76
CAPI1 Capitol Reef National Park 2.38 7.18
ZICA1 Zion National Park 3.86 8.75

105 (40 CFR 51.308(f)(1)(iii))

55
4.A.4 Progress to date: most impaired and clearest days106
Actual progress towards the natural visibility conditions goal has been calculated in relation to
the baseline period for each of Utah’s CIAs. This is exhibited by the difference between the
average visibility condition during the 5-year baseline, previous implementation period, and
each subsequent 5-year period up to and including the current period. Table 9 displays the
progress in Utah’s CIAs comparing the baseline values for clearest and most impaired days with
the first implementation period and 2014-2018 values.
Table 9: Progress to date for the most impaired and clearest days
Site ID 2000-2004 Baseline (dv) 2008-2012 Previous implementation period (dv) 2014-2018 Current (dv) 20% Clearest 20% Most Impaired 20% Clearest 20% Most Impaired 20% Clearest 20% Most Impaired
BRCA1 2.77 8.42 1.82 7.69 1.46 6.60
CANY1 3.75 8.79 2.93 8.12 2.20 6.76
CAPI1 4.10 8.78 2.53 8.16 2.38 7.18
ZICA1 4.48 10.40 4.22 9.17 3.86 8.75

4.A.5 Differences between current and natural for the most impaired and clearest
days107
Table 10 compares the difference between the current deciview values for each CIA to the
estimated natural visibility for the 20% most impaired days and clearest days.
Table 10: Current visibility compared to natural visibility

106 (40 CFR 51.308(f)(1)(iv)) 107 (40 CFR 51.308(f)(1)(v))
Site ID 2014-2018 Current (dv) Natural Visibility (dv) Difference (dv)
20% Clearest 20% Most Impaired 20% Clearest 20% Most Impaired 20% Clearest 20% Most Impaired
BRCA1 1.46 6.60 0.57 4.08 0.89 2.52
CANY1 2.20 6.76 1.05 4.13 1.15 2.63
CAPI1 2.38 7.18 1.28 4.00 1.1 3.18
ZICA1 3.86 8.75 1.83 5.26 2.03 3.49

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4.B Uniform Rate of Progress108
Utah analyzed and determined the uniform rate of progress (URP) over time for each of its five
CIAs, starting at the baseline period of 2000-2004, that would be needed to attain the natural
visibility condition on the 20% most anthropogenically impaired days by the year 2064. Table 11
shows the URP for each IMPROVE site.
Table 11: Uniform Rates of Progress
CIA IMPROVE
Site
Baseline Conditions
(Most Impaired Days)
(dv)
2064 Natural Conditions
(Most Impaired Days)
(dv)
Years to
Reach Natural
Conditions
Uniform Rate of
Progress (URP)
(dv/year)
BRCA1 8.42 4.08 60 -0.072
CANY1 8.79 4.13 60 -0.078
CAPI1 8.78 4.00 60 -0.080
ZICA1 10.40 5.26 60 -0.086

Utah then used the URP to establish the level of visibility change needed from baseline
conditions by 2028 as shown in Table 12. The 2028 URP level is used for comparison to WRAP
photochemical modeling projections for 2028 shown in sections 6.A.10 and 8.C.
Table 12: Calculation of 2028 Uniform Rate of Progress Level
CIA IMPROVE
Site
Baseline Conditions (Most Impaired
Days) (dv)
Visibility Change by 2028
(URPX24 years) (dv)
2028 URP Level
(dv)
BRCA1 8.42 -1.74 6.68
CANY1 8.79 -1.87 6.92
CAPI1 8.78 -1.91 6.87
ZICA1 10.40 -2.06 8.35

4.C Adjustments to URP: International impacts and/or prescribed fire109
EPA added a provision in the 2019 guidance that allows EPA to approve adjustments to the
URP to reflect the impacts of international and wildland prescribed fire sources of visibility
impairment if an adjustment has been developed through scientifically valid data and methods.
These adjustments would be developed and applied separately, although they would both be
accomplished by adding an estimate of the impact of the relevant source type or types to the
value of the natural visibility condition for the 20% most anthropogenically impaired days, for the
purposes of calculating the URP.110 The wildland prescribed fires that are eligible under the
108 (40 CFR 51.308(f)(1)(vi))
109 (40 CFR 51.308(f)(1)(vi)(B)(1) and (2)) 110 The 2019 EPA Guidance can be found at: https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf

57
RHR to be included in this adjustment are those conducted with the objective to establish,
restore, and/or maintain sustainable and resilient wildland ecosystems, to reduce the risk of
catastrophic wildfires, and/or to preserve endangered or threatened species during which
appropriate basic smoke management practices were applied.111
Consistent with the methods evaluated in the EPA Technical Support Document112, WRAP
calculated the international and wildland prescribed fire glidepath adjustments for Utah using
2028OTBa2 source apportionment modeling results normalized to the IMPROVE monitoring
data and added to EPA estimated natural conditions.113
Modeling done by both EPA and WRAP shows that Utah is significantly impacted by
international and wildland prescribed fire emissions (as shown by Figures 28-31). Further detail
on emission source apportionment can be found in Chapter 5: Utah Sources of Visibility
Impairment.

111 “64 Fed. Reg. 35714, 35764.” 112 Technical Support Document (TSD) Revised Recommendations for Visibility Progress Tracking
Metrics for the Regional Haze Program https://www.epa.gov/sites/default/files/2016-
07/documents/technical_support_document_for_draft_guidance_on_regional_haze.pdf
113 WRAP Technical Support System for Regional Haze Planning: Modeling Methods, Results, and
References
https://views.cira.colostate.edu/tssv2/Docs/WRAP_TSS_modeling_reference_final_20210930.pdf
Figure 28: Projected Source Contributions to Light Extinction in Bryce Canyon NP

58

Figure 29: Projected Source Contributions to Light Extinction in Canyonlands and Arches NP
Figure 30: Projected Source Contributions to Light Extinction in Capitol Reef NP

59

Figure 32 shows an example of Bryce Canyon’s URP glidepath with the international and wildland prescribed fire adjustments. It should be noted that the prescribed fire adjustments for Utah’s CIAs are small relative to those in other states. The international source adjustments, on
the other hand, can be sizable. While the international and wildland prescribed fire adjustments are available for Utah’s CIA glidepaths, UDAQ is choosing to remain conservative for the purposes of this implementation period by not using them. However, this choice does not
preclude the use of glidepath adjustments in future planning periods, since international and
Figure 32: Example URP Glidepath for Bryce Canyon National Park Showing Adjustment Options
Figure 31: Projected Source Contributions to Light Extinction in Zion NP

60
wildland prescribed fire emissions do impact Utah CIAs and are largely beyond the control of individual states and since prescribed fires are seen to be an increasingly important tool for land managers in the future.

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Chapter 5: Utah Sources of Visibility Impairment
5.A Natural Sources of Impairment
Natural impairment sources include any non-anthropogenically caused visibility-reducing
emissions and are often seasonally attributed to natural events such as rain, sea mists,
windblown dust, wildfire, volcanic activity, and biogenic emissions. Natural sources of
impairment are often caused by seasonal conditions and lead to high concentrations of visibility-
impairing emissions that are short-term. Natural contributions to impairment are categorized into
the “episodic” and “routine” types. Episodic contributions, such as large wildfires or dust storms,
occur infrequently and vary yearly in number and size. Routine contributions include biogenic
sources, sea salt, and incorporate the site-specific value for Rayleigh scattering, a term which
refers to the scattering of light off of particles in the air. These contributions occur often and are
more consistent on a yearly basis.
5.B Anthropogenic Sources of Impairment
Anthropogenic impairment sources include any visibility-decreasing emissions directly related to
human-caused activities. These activities include industrial processes (utilities, smelters,
refineries, etc.), mobile sources (cars, trucks, trains, etc.) and area sources (residential wood
burning, prescribed burning on wild and agricultural lands, wind-blown dust from disturbed soils,
etc.). Anthropogenic sources of emissions include those originating within Utah as well as
neighboring states, Mexico, Canada, and maritime shipping emissions from across the Pacific
Ocean. While Utah can consult with regional states about their anthropogenic emission
contributions to impairment in Utah’s CIAs, those international contributions cannot be
controlled at the state level. Table 13 details the data sources used by WRAP for determining
anthropogenic source emissions contributions.
Table 13: Data sources for WRAP emissions sectors114

114 This table’s data comes from the 2021 WRAP Technical Support System Emissions and Modeling Report and References document.
Source Sector 2014v2 RepBase2 2028OTBa2
California All Sectors 12WUS2 CARB-2014v2 CARB-2014v2 CARB-2028
WRAP Fossil EGU w/ CEM WRAP-2014v2 WRAP-RB-EGU 1 WRAP-2028-EGU 1
WRAP Fossil EGU w/o CEM EPA-2014v2 WRAP-RB-EGU 1 WRAP-2028-EGU 1
WRAP Non-Fossil EGU EPA-2014v2 EPA-2016v1 EPA-2028v1
Non-WRAP EGU EPA-2014v2 EPA-2016v1 EPA-2028v1
O&G WRAP O&G States WRAP-2014v2 WRAP-RB-O&G 2 WRAP-2028-O&G 2
O&G WRAP Other States EPA-2014v2 EPA-2016v1 EPA-2016v1 3
O&G non-WRAP States EPA-2014v2 EPA-2016v1 EPA-2016v1 3
WRAP Non-EGU Point WRAP-2014v2 WRAP-2014v2 4 WRAP-2014v2 4
Non-WRAP non-EGU Point EPA-2014v2 EPA-2016v1 EPA-2016v1
On-Road Mobile 12WUS2 WRAP-2014v2 WRAP-2014v2 WRAP-2028-Mobile 5
On-Road Mobile 36US EPA-2014v2 EPA-2016v1 EPA-2028v1
Non-Road 12WUS2 EPA-2014v2 EPA-2016v1 WRAP-2028-Mobile 5
Non-Road non-WRAP 36US EPA-2014v2 EPA-2016v1 6 EPA-2028v1 6

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5.C Overview of Emission Inventory System - TSS
The WRAP 2014v2 inventory was based on the National Emissions Inventory (NEI) and
updates provided by states through their Emissions and Modeling Protocol subcommittee.
Specific data sources for each emissions sector are detailed below:
The CAMx Particle Source Apportionment tool (PSAT) is a photochemical model that tracks
gaseous and particle air emissions from sources through atmospheric dispersion,
photochemical reactions, and transport to receptors where IMPROVE monitors are located.
These PSAT runs include aerosol concentrations of:
• AmmNO3
• AmmSO4
• Primary Organic Mass from Carbon (OMC)
• Primary Elemental Carbon (EC)
• Primary Fine Soil
• Primary Coarse Mass
• Sea salt
• Secondary Organic Aerosols
o Anthropogenic (SOAA)
o Biogenic (SOAB)
These particles are direct products of primary gaseous and particle emissions and secondary
aerosol formation. Secondary organic aerosols (SOA) tracers are not used in these PSAT runs,
rather SOAs at the receptor are assigned to anthropogenic (SOAA) or biogenic (SOAB)
contributions based on the chemical signatures (e.g., isoprene is assigned as biogenic in origin;
benzene is assigned as anthropogenic in origin).
Other (Non-Point) 12WUS2 EPA-2014v2 EPA-2014v2 7 EPA-2014v2 7
Other (Non-Point) 36US EPA-2014v2 EPA-2016v1 EPA-2016v1
Can/Mex/Offshore 12WUS2 EPA-2014v2 EPA-2016v1 EPA-2016v1
Fires (WF, Rx, Ag) WRAP-2014-Fires WRAP-RB-Fires 8 WRAP-RB-Fires 8
Natural (Bio, etc.) WRAP-2014v2 WRAP-2014v2 WRAP-2014v2
Boundary Conditions (BCs) WRAP-2014-GEOS WRAP-2014-GEOS WRAP-2014-GEOS
1. WRAP-RepBase2-EGU and WRAP-2028OTBa2-EGU include changes/corrections/updates from WESTAR-WRAP
states.
2. WRAP-RepBase2-O&G and WRAP-2028OTBa2-O&G both include corrections for WESTAR-WRAP states.
3. O&G for other WRAP states and Non-WRAP states use EPA-2016v1 assumptions for 2028OTBa2 and unit-
level changes provided by WESTAR-WRAP states.
4. WRAP-2014v2 Non-EGU Point is used for RepBase2 and 2028OTBa2, with source specific updates provided by WESTAR-WRAP states.
5. WRAP-2028-MOBILE is used for On-Road and Non-Road sources for the 12WUS2 domain.
6. EPA-2016v1 and EPA-2028v1 are used for On-Road and Non-Road Mobile for the 36km US domain.
7. Non-Point emissions use 2014v2 emissions for RepBase2 and 2028OTBa2 scenarios, including state-
provided corrections. 8. RepBase fires are used for both RepBase2 and 2028OTBa2

63
WRAP modeled values for six source categories and 15 component source groups115:
• U.S. Anthropogenic (USAnthro)
o U.S. anthropogenic (AntUS)
o U.S. agricultural fire (AgfireUS)
o Secondary Organic Aerosol-Anthropogenic (SOAA)
o Commercial Marine Vessels (CMVUS)
o U.S. anthropogenic contributions from outside the CAMx 36-km domain
boundary as defined by the GEOS-Chem global model. (BC-US)
• U.S. Wildfire (WFUS)
• U.S. Wildland Prescribed fire (RxUS)
• Canadian and Mexican fires (OthFr)
• Natural
o Natural (Nat)
o Secondary Organic Aerosol -Biogenic (SOAB)
o Natural contributions from outside the CAMx 36-km domain boundary as defined
by the GEOS-Chem global model. (BC-Nat)
• International Anthropogenic (IntlAnthro)
o International Anthropogenic contributions from outside the CAMx 36-km domain
boundary as defined by the GEOS-Chem global model. (BC-Int)
o Canadian Anthropogenic (AntCAN)
o Mexican Anthropogenic (AntMEX)
o Commercial Marine vessels – International (beyond 200km from U.S. coast)
(CMV_nonUS)
Summaries of Utah’s emissions data are located in Table 15 to Table 20.
5.D Wildland Prescribed Fires
Most forest ecosystems in the West have a general pattern in which fires naturally occur,
otherwise called a fire regime. These regimes serve the purpose of helping a forest get rid of
excess wood fuel and cause opportunities for regrowth and regeneration. Many forest
ecosystems in the West depend on fire to create their optimal conditions. As human populations
increase in the West, the Wildland-Urban Interface (WUI) has led to fire suppression which
impedes natural fire regimes for the safety of residential areas. This causes an increase in fuel
(burnable wood) in the forests of Utah that increases their chances of unintentionally catching
fire. Further contributing to the dangers of uncontrolled fire is the increase in climate change
every year. To better control the location and degree at which forest fires occur, fire can be
prescribed for an area under certain weather conditions and with the appropriate permits.
Utilizing prescribed fires and returning fire to an ecosystem in a controlled manner helps restore
its health and reduce potentially catastrophic wildfires. Healthy ecosystems with restored natural
fire regimes are more resistant to severe fire, disease, and insect infestations. The United
States Forest Service (USFS) and other land management agencies in Utah closely monitor

115 Information on the TSS source apportionment data is located at http://views.cira.colostate.edu/tssv2/Reports2/Modeling/Src-App-DB-Avg-Bext-By-Source.aspx

64
local precipitation, wind, fuel, moisture, and other elements to determine the best conditions to
carry out prescribed burning.
The State of Utah and the USFS have developed mutual commitments to advance the strategy
of “Shared Stewardship” in Utah. In August 2018, the Forest Service released a document
outlining a new strategy for land management called “Toward Shared Stewardship Across
Landscapes: An Outcome-Based Investment Strategy.” This strategy responds to the growing
challenges faced by land managers including catastrophic wildfires. Of particular concern are
longer fire seasons and the increasing size and severity of wildfires, along with the expanding
risk to communities, water sources, wildlife habitat, air quality, and the safety of firefighters.
Through Shared Stewardship, the State and Forest Service can work together and set
landscape-scale priorities, implement projects at the appropriate scale, co-manage risks, share
resources, and learn from each other while building long-term capacity to live with wildfire. Due
to these initiatives, more frequent wildfires in the West, and thus increasing importance of
prescribed fires, Utah does not consider reducing prescribed fires as a reasonable method to
reduce visibility impairment.
5.E Utah Emissions
Federal visibility regulations116 require a statewide emissions inventory of pollutants anticipated
to contribute to visibility impairment in Utah’s CIAs. WRAP inventoried pollutants in Utah
including SO₂, NOx, VOCs, PM2.5, PM10, and NH3. The WRAP 2014v2 inventory was based on
the 2014v2 National Emissions Inventory (NEI) as well as updates provided by western states
(including Utah). RepBase2, the representative baseline emissions scenario, updated the
2014v2 inventory originally used to account for changes and variations in emissions from 2014
to 2018.117 This version also accounted for duplicate records found and revised some EGU,
non-EGU point, oil, and gas emissions. The 2028 On the Books Inventory (2028OTBa2)
projection follows the methods presented by the EPA in their 2019 Technical Support
Document. WRAP states updated projections for all anthropogenic source sectors. Oil and gas
area emissions were also updated by Ramboll, Inc. and the WRAP Oil and Gas Workgroup and
separated into Tribal and non-Tribal mineral ownership. Table 14 contains data compiled by
WRAP with information on the status of EGU retirements in Utah that were used in the
RepBase2 and 2028OTBa2 inventories.
Table 14: Status of Utah EGU Retirements in RepBase2 and 2028OTBa2 Inventories
Facility Name Unit
ID
In-
Service
Year
Retirement
Year
Notes Operator Unit Type
Intermountain 1SGA 1986 2025 Announced
retirement
Intermountain
Power Service
Corporation
Dry bottom wall-fired
boiler
Intermountain 2SGA 1987 2025 Announced
retirement
Intermountain
Power Service
Corporation
Dry bottom wall-fired
boiler

116 40 C.F.R. § 51.308(d)(4)(v). 117 UDAQ notes that these projections include emission not under state jurisdiction (i.e. Tribal)

65
Facility Name Unit
ID
In-
Service
Year
Retirement
Year
Notes Operator Unit Type
Bonanza 1-Jan 1986 2030 Coal
consumption
cap
Deseret Generation
& Transmission
Dry bottom wall-fired
boiler
Hunter 1 1978 2042 PAC IRP; Round
1 RH FIP in
Litigation
PacifiCorp Energy
Generation
Tangentially-fired
Hunter 2 1980 2042 PAC IRP; Round 1 RH FIP in Litigation
PacifiCorp Energy Generation Tangentially-fired
Hunter 3 1983 2042 PAC IRP PacifiCorp Energy
Generation
Dry bottom wall-fired
boiler
Huntington 1 1977 2036 PAC IRP; Round 1 RH FIP in Litigation
PacifiCorp Energy Generation Tangentially-fired
Huntington 2 1974 2036 PAC IRP; Round
1 RH FIP in
Litigation
PacifiCorp Energy
Generation
Tangentially-fired

The resulting inventories were then used by WRAP to model future visibility in Utah’s CIAs.118
State and federal law require Utah to conduct a statewide emissions inventory program every
three years. This inventory accounts for point, area, and mobile sources and accounts for the
following criteria pollutants:
• Ammonia (NH3)
• Carbon Monoxide (CO)
• Lead and Lead Compounds
• Nitrogen Oxides (NO)
• Particulate Matter (PM10 and PM2.5)
• Sulfur Oxides (SO₂)
• Volatile Organic Compounds (VOCs)
The following tables contain Utah’s projected emissions inventories by species resulting from
the RepBase2 and 2018OTBa2 modeling projections.
118 The complete methodology used to develop the WRAP emissions inventory can be found in “WRAP Technical Support System for Regional Haze Planning: Emissions and Modeling Methods, Results, and References” released on August 19, 2021.

66

Table 15: Utah SO₂ Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2
Utah – Statewide SO₂ Emissions (TPY)
Type Source
Category
2014v2
Actual
Representative
Baseline 2
2028 OTB a2
Anthropogenic Electric Generating Units (EGU) 24,011 11,357 9,866
Anthropogenic Oil and Gas – Point 664 545 570
Anthropogenic Industrial and Non-EGU
Point
2,400 2,402 2,402
Anthropogenic Oil and Gas – Non-point 41 41 31
Anthropogenic Residential Wood
Combustion
24 24 24
Anthropogenic Fugitive dust 0 0 0
Anthropogenic Agriculture 0 0 0
Anthropogenic Remaining Non-point 61 61 61
Anthropogenic On-Road Mobile [phone]
Anthropogenic Non-road Mobile 25 16 13
Anthropogenic Rail 3 3 3
Anthropogenic Commercial Marine 0 0 0
Anthropogenic Agricultural Fire 5 5 5
Anthropogenic Wildland Prescribed Fire 320 524 524
Total Anthropogenic 27,829 15,253 13,684
Natural Wildfire 375 1,295 1,295
Natural Biogenic 0 0 0
Total Natural 375 1,295 1,295
Grand Total 28,204 16,548 14,979

The largest source of SO₂ emissions is fossil fuel combustion (mainly coal) at power plants and
other industrial facilities. In Utah, the largest source of SO₂ emissions are EGUs. Smaller
sources include metal extraction, mobile vehicles, and wood burning. Wildfires are the second
largest source of SO₂ emissions in both the RepBase and 2028 scenarios. SO₂ emissions that
lead to high concentrations of SO₂ in the air generally also lead to the formation of other sulfur
oxides (SOx). SOx can react with other compounds in the atmosphere to form small particles.
These particles contribute to PM pollution. Ammonium sulfate particles can have a great impact
on visibility due to their greater light scattering effects. According to the 2028OTBa2 modeling,
SO2 emissions are projected to decline to 14,979 tons per year in 2028.
Table 16: Utah NOx Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2
Utah – Statewide NOx Emissions (TPY)
Type Source 2014v2 Representative 2028 OTB a2

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Utah – Statewide NOx Emissions (TPY)
Category Actual Baseline 2
Anthropogenic Electric Generating Units (EGU) 54,497 31,882 23,848
Anthropogenic Oil and Gas – Point 14,636 14,589 9,140
Anthropogenic Industrial and Non-EGU Point 13,086 13,107 13,107
Anthropogenic Oil and Gas – Non-point 1,811 1,806 1,428
Anthropogenic Residential Wood Combustion 189 189 189
Anthropogenic Fugitive dust 0 0 0
Anthropogenic Agriculture 0 0 0
Anthropogenic Remaining Non-point 4,846 4,846 4,846
Anthropogenic On-Road Mobile 74,643 74,643 25,539
Anthropogenic Non-road Mobile 9,669 7,029 4,741
Anthropogenic Rail 5,646 5,646 4,164
Anthropogenic Commercial Marine 1 0 0
Anthropogenic Agricultural Fire 19 19 19
Anthropogenic Wildland Prescribed Fire 596 572 572
Total Anthropogenic 179,639 154,328 87,593
Natural Wildfire 704 2,063 2,063
Natural Biogenic 12,602 12,602 12,602
Total Natural 13,306 14,665 14,665
Grand Total 192,945 168,993 102,258

NOx is a group of highly reactive gases formed in high-temperature combustion processes. This
group includes NO2, nitrous acid, and nitric acid. NO2 emissions are primarily caused by fuel
combustion from cars, trucks, buses, power plants, and off-road equipment. These substances
are toxic by themselves and can react to form ozone or PM10 in the form of nitrates. Large
nitrate particles have a greater light-scattering effect than large sulfate particles or dust
particles. Most NOx emissions in Utah are from EGUs. NOx emissions are projected to decline to
102,258 tons per year, according to the 2028OTBa2 modeling.
Table 17: Utah VOC Emission Inventory – RebBase2 (2014-2018) and 2028OTBa2
Utah - Statewide VOC Emissions (TPY)
Type Source
Category
2014v2
Actual
Representative
Baseline 2
2028 OTB a2
Anthropogenic Electric Generating Units (EGU) 391 285 276
Anthropogenic Oil and Gas - Point 111,225 110,906 71,207
Anthropogenic Industrial and Non-EGU Point 3,146 3,152 3,152
Anthropogenic Oil and Gas - Non-point 37,069 35,252 21,513
Anthropogenic Residential Wood Combustion 1,589 1,589 1,589
Anthropogenic Fugitive dust 0 0 0
Anthropogenic Agriculture 2,120 2,120 2,120

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Utah - Statewide VOC Emissions (TPY)
Anthropogenic Remaining Non-point 29,913 29,913 29,913
Anthropogenic On-Road Mobile 28,356 28,356 11,589
Anthropogenic Non-road Mobile 17,694 8,966 6,314
Anthropogenic Rail 287 287 179
Anthropogenic Commercial Marine 0 0 0
Anthropogenic Agricultural Fire 31 31 31
Anthropogenic Wildland Prescribed Fire 8,675 23,415 23,415
Total Anthropogenic 240,496 244,272 171,298
Natural Wildfire 10,062 54,614 54,614
Natural Biogenic 717,742 717,742 717,742
Total Natural 727,804 772,356 772,356
Grand Total 968,300 1,016,628 943,654

VOCs are volatile organic compounds that have high vapor pressure at room temperature.
Many VOCs are human-made compounds that are used and produced in the manufacturing of
paints, pharmaceuticals, and refrigerants. Companies in Utah must report all reactive VOC
emissions (including fugitive emissions). Different VOCs have differing levels of reactivity that
convert them to ozone. Therefore, changes in their emissions have limited effects on local or
regional ozone pollution. VOCs also play a role in the formation of secondary particulates that
can impact regional haze. The largest source of VOC emissions in Utah is oil and gas point
sources. VOC emissions are expected to decline to 943,654 tons per year according to the
2028OTBa2 projections.
Table 18: Utah PM2.5 Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2
Utah - Statewide PM2.5 Emissions (TPY)
Type Source
Category
2014v2
Actual
Representative
Baseline 2
2028 OTB a2
Anthropogenic Electric Generating Units (EGU) 2,799 2,195 1,310
Anthropogenic Oil and Gas - Point 631 621 476
Anthropogenic Industrial and Non-EGU Point 2,618 2,620 2,620
Anthropogenic Oil and Gas - Non-point 81 81 61
Anthropogenic Residential Wood Combustion 1,403 1,403 1,403
Anthropogenic Fugitive dust 12,177 12,177 12,177
Anthropogenic Agriculture 0 0 0
Anthropogenic Remaining Non-point 1,181 1,181 1,181
Anthropogenic On-Road Mobile 2,726 2,726 1,081
Anthropogenic Non-road Mobile 1,103 706 447
Anthropogenic Rail 165 165 108
Anthropogenic Commercial Marine 0 0 0
Anthropogenic Agricultural Fire 83 83 83

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Anthropogenic Wildland Prescribed Fire 3,580 7,092 7,092
Total Anthropogenic 28,547 31,050 28,039
Natural Wildfire 4,161 17,381 17,381
Natural Biogenic 0 0 0
Total Natural 4,161 17,381 17,381
Grand Total 32,708 48,431 45,420

PM2.5 particulates are fine, inhalable particles or droplets with a diameter of 2.5 microns or
smaller. Within two years after the EPA revises NAAQS for criteria pollutants, it must designate
areas according to their attainment status. These designations are based on the most recent
three years of monitoring data, state recommendations, and other technical information. If an
area is not meeting the standard, Utah must write a PM2.5 SIP that includes necessary control
measures to ensure future attainment. The sector with the largest contribution of PM2.5
emissions in Utah is fugitive dust. PM2.5 emissions are expected to decline somewhat according
to the 2028OTBa2 modeling.
Table 19: Utah PM10 Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2
Utah - Statewide PM10 Emissions (TPY)
Type Source
Category
2014v2
Actual
Representative
Baseline 2
2028 OTB a2
Anthropogenic Electric Generating Units (EGU) 3,671 2,534 1,607
Anthropogenic Oil and Gas - Point 632 621 476
Anthropogenic Industrial and Non-EGU Point 5,385 5,387 5,387
Anthropogenic Oil and Gas - Non-point 81 81 61
Anthropogenic Residential Wood Combustion 1,410 1,410 1,410
Anthropogenic Fugitive dust 95,505 95,505 95,505
Anthropogenic Agriculture 0 0 0
Anthropogenic Remaining Non-point 1,317 1,317 1,317
Anthropogenic On-Road Mobile 4,547 4,547 3,550
Anthropogenic Non-road Mobile 1,165 745 477
Anthropogenic Rail 179 179 111
Anthropogenic Commercial Marine 0 0 0
Anthropogenic Agricultural Fire 119 119 119
Anthropogenic Wildland Prescribed Fire 4,224 8,097 8,097
Total Anthropogenic 118,235 120,542 118,117
Natural Wildfire 4,910 20,318 20,318
Natural Biogenic 0 0 0
Total Natural 4,910 20,318 20,318
Grand Total 123,145 140,860 138,435

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PM10 is inhalable particulate matter that is 10 microns or smaller in diameter. Sources of PM10
include:
• Vehicles
• Wood-burning
• Wildfires or open burns
• Industry
• Dust from construction sites, landfills, gravels pits, agriculture, and open lands
The NAAQS for PM specifies the maximum amount of PM present in outdoor air. PM
concentration is measured in micrograms per cubic meter, or µg/m3. For PM10, most high values
tend to occur during wintertime inversions. In the summertime, high wind events can also lead
to unusually high PM10 values. According to the 2028OTBa2 projections, PM10 emissions are
expected to decrease to 138,435 tons per year in 2028. This is lower than the representative
baseline from 2014 to 2017, but higher than the recalculated 2014 emissions.
Table 20: Utah NH3 Emission Inventory – RepBase2 (2014-2018) and 2028OTBa2
Utah - Statewide NH3 Emissions
Type Source
Category
2014v2
Actual
Representative
Baseline 2 2028 OTB a2
Anthropogenic Electric Generating Units (EGU) 273 262 261
Anthropogenic Oil and Gas - Point 0 0 0
Anthropogenic Industrial and Non-EGU Point 400 400 400
Anthropogenic Oil and Gas - Non-point 0 0 0
Anthropogenic Residential Wood Combustion 63 63 63
Anthropogenic Fugitive dust 0 0 0
Anthropogenic Agriculture 12,982 12,982 12,982
Anthropogenic Remaining Non-point 5,012 5,012 5,012
Anthropogenic On-Road Mobile 1,025 1,025 1,039
Anthropogenic Non-road Mobile 17 14 17
Anthropogenic Rail 3 3 3
Anthropogenic Commercial Marine 0 0 0
Anthropogenic Agricultural Fire 70 70 70
Anthropogenic Wildland Prescribed Fire 678 1,164 1,164
Total Anthropogenic 20,523 20,995 21,011
Natural Wildfire 787 2,702 2,702
Natural Biogenic 0 0 0
Total Natural 787 2,702 2,702
Grand Total 21,310 23,697 23,713

NH3 plays a role in light extinction since it is involved in the formation of ammonium nitrate and
ammonium sulfate. The various industries that emit NH3 include:

71
• Fertilizer manufacturing
• Fossil fuel combustion
• Livestock management
• Refrigeration methods
Currently, there is limited federal regulation of NH3 emissions, although the CAA provides
federal authority to regulate this pollutant. NH3 emissions levels are consistent in each of the
three WRAP projections for 2014, 2014-2017, and 2028.

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Chapter 6: Long-Term Strategy for Second Planning Period119
6.A LTS Requirements 120
The Long-Term Strategy requirements under Subsections 51.308(d)(3) and (f)(2) include the
following:
• Submit an initial LTS and 5-year progress review per 40 CFR 51.308(g) that addresses
regional haze visibility impairment.
• Consult with other states to develop coordinated emission management strategies for
CIAs outside Utah where Utah emissions cause or contribute to visibility impairment, or
for CIAs in Utah where emissions from other states cause or contribute to visibility
impairment.
• Enforceable emissions limitations, compliance schedules, and other measures
necessary to achieve the reasonable progress goals established by Utah for its CIAs.
• Document the technical basis on which the state is relying to determine its
apportionment of emission reduction obligations necessary for achieving reasonable
progress in each CIA it affects.
• Identify all anthropogenic sources of visibility impairing emissions (major and minor
stationary sources, mobile sources, and area sources).
• Consider the following factors when developing the LTS:
o Emission reductions due to ongoing air pollution control programs, including
measures to address Reasonably Attributable Visibility Impairment (RAVI);
o Measures to mitigate the impacts of construction activities;
o Emission limitations and schedules for compliance to achieve the reasonable
progress goal;
o Source retirement and replacement schedules;
o Smoke management techniques for agricultural and forestry management
purposes including plans as currently exist within the state for this purpose;
o Enforceability of emission limitations and control measures; and
o The anticipated net effect on visibility due to projected changes in point, area,
and mobile source emissions over the period addressed by the long-term
strategy.
Sections 6.A.1 through 6.A.8 detail how Utah addressed the above LTS factors.
119 40 CFR 51.308(f)(2)
120 40 CFR 51.308(d)(3) and (f)(2)

73
6.A.1 States reasonably anticipated to contribute to visibility impairment in the Utah
CIAs121
Bryce Canyon National Park
In Bryce Canyon National Park, California contributes the highest portion of U.S. anthropogenic
ammonium nitrate-caused light extinction on most impaired days at 35%, followed by Utah at
23%. California also contributes the highest amount of U.S. anthropogenic ammonium sulfate
light extinction in Bryce Canyon at 19% followed by non-WRAP states at 14%, Utah at 14%,
Arizona at 12%, Wyoming at 12%, and New Mexico at 11%.
121 40 CFR 51.308 (f)(2)(ii)
Figure 34: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at Bryce Canyon National Park
Figure 33: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at Bryce Canyon National Park

74
Canyonlands and Arches National Park
In Canyonlands and Arches National Park, Utah contributes the largest portion of U.S.
ammonium nitrate light extinction (60%) followed by Colorado (14%). Utah also contributes the
most U.S. ammonium sulfate light extinction (40%) on the park’s most impaired days followed
by New Mexico (13%) and non-WRAP US states (12%).
Figure 36: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at Canyonlands and Arches National Park
Figure 35: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at Canyonlands and Arches National Park

75

Capitol Reef National Park
Utah contributes the highest portion of U.S. anthropogenic ammonium nitrate light extinction on
Capitol Reef’s most impaired days at 35%. California contributes the second-highest amount at
21%. Utah also contributes the highest portion of U.S. anthropogenic ammonium sulfate light
extinction at 20%, closely followed by non-WRAP states (15%), California (13%), and Wyoming
(13%).

Figure 37: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at Capitol Reef National Park
Figure 38: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at Capitol Reef National Park

76

Zion National Park
For Zion National Park’s most impaired days, California contributes the highest portion of U.S.
anthropogenic ammonium nitrate light extinction (49%) with mobile emissions comprising the
majority of their impact (27%). California also contributes to the majority of U.S. anthropogenic
ammonium sulfate light extinction (37%), most of which are from non-EGU sources (23%).

Figure 40: WRAP States Ammonium Nitrate Source Apportionment for Most Impaired Days at Zion National Park
Figure 39: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at Zion National Park

77
6.A.2 Utah sources identified by downwind states that are reasonably anticipated to
impact CIAs122
Utah has analyzed the WRAP photochemical modeling for OTB 2028 and found that emissions
from Utah can impact visibility at CIAs in other states. Table 21 and Table 22 below summarize
Utah’s percent contribution to total U.S. anthropogenic nitrate and sulfate light extinction at CIAs
in neighboring states. As can be seen, Utah’s highest nitrate impacts occur in Colorado, Idaho,
and Wyoming CIAs and mostly stem from mobile source emissions. Utah’s highest sulfate
impacts also occur in Colorado, Idaho, and Wyoming (namely at MOZI1, WHRI1, CRMO1, and
BRID1) and predominantly stem from EGU emissions and some non-EGU emissions in the
case of CRMO1. It should be noted that the WRAP source apportionment results for Utah EGUs
include impacts from the Bonanza power plant, which is located in Indian Country and which is
not, therefore, a source regulated by UDAQ. A review of the weighted emissions potential
(WEP) values for sulfate at the latter CIAs identified one Utah EGU, Kennecott Power Plant,
with a top-ten sulfate WEP value for BRID1 (rank 2, 7.4% of total WEP). However, this facility
was officially closed in 2020. The facilities with the two highest ranking non-EGU WEP sulfate
values at CRMO1 were the Tesoro (now Marathon) refinery (rank 6, 6.8% of total WEP) and the
Kennecott Smelter and Refinery (rank 10, 2.2% of total WEP), both of which recently underwent
BACT analysis for the Salt Lake PM2.5 serious area SIP and are well-controlled for SO2.
As one might expect, when Utah anthropogenic impacts are compared to total nitrate and
sulfate light extinction at the same CIAs, Utah’s shares drop markedly, as shown in Table 23
and Table 24, respectively. And nitrate and sulfate are only two of several contributors to total
visibility impairment. As such, Utah’s shares of nitrate and sulfate impacts should be considered
in this broader context. That said, the aforementioned source apportionment results were not
used to screen out any sources from a requirement to conduct a four-factor analysis. Rather,
UDAQ relied upon a preliminary Q/d analysis to identify sources with a Q/d of >=6. UDAQ then
conducted a secondary screening to review the initial pool of Q/d-qualifying sources to account
for factors such as recent emissions controls required by other air quality programs, facility
closures, federal preemptions on state controls, etc. Finally, UDAQ reviewed WEP results for
nitrate and sulfate to ensure that the remaining Q/d pool reasonably captured sources with
impacts at Utah and non-Utah CIAs. This screening analysis is detailed in section 7.A.
Table 21: Utah Share of U.S. Anthropogenic Nitrate Impacts on Neighboring State CIAs
State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
AZ BALD1 0.19% 0.22% 0.10% 0.02% 0.03% 0.55%
AZ CHIR1 0.76% 0.68% 0.29% 0.19% 0.13% 2.05%
AZ GRCA2 0.64% 0.63% 0.13% 0.22% 0.09% 1.71%
AZ IKBA1 0.21% 0.29% 0.10% 0.05% 0.07% 0.73%
AZ PEFO1 2.89% 1.95% 0.75% 0.57% 0.56% 6.73%
AZ SAGU1 0.35% 0.32% 0.10% 0.08% 0.07% 0.93%
AZ SIAN1 0.19% 0.19% 0.11% 0.02% 0.03% 0.53%
122 40 CFR 51.308 (f)(2)(ii)(A)

78
State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
AZ SYCA_RHTS 1.12% 1.45% 0.57% 0.23% 0.26% 3.62%
AZ TONT1 0.22% 0.30% 0.09% 0.05% 0.07% 0.74%
CO GRSA1 2.39% 1.35% 0.44% 0.59% 0.32% 5.08%
CO MEVE1 4.33% 2.76% 0.81% 0.91% 0.68% 9.49%
CO MOZI1 4.14% 7.23% 3.00% 3.00% 1.44% 18.81%
CO ROMO1 1.95% 3.53% 1.47% 1.27% 0.72% 8.94%
CO WEMI1 2.43% 2.20% 0.72% 0.99% 0.25% 6.59%
CO WHRI1 5.14% 6.75% 2.23% 2.64% 0.98% 17.74%
ID CRMO1 0.62% 6.88% 3.42% 0.03% 2.02% 12.97%
ID SAWT1 0.05% 0.38% 0.22% 0.01% 0.09% 0.74%
ID SULA1 0.09% 0.96% 0.45% 0.01% 0.13% 1.63%
NM BAND1 0.58% 0.43% 0.14% 0.14% 0.08% 1.37%
NM BOAP1 0.50% 0.47% 0.19% 0.12% 0.12% 1.41%
NM GICL1 0.27% 0.38% 0.15% 0.07% 0.06% 0.93%
NM GUMO1 0.17% 0.27% 0.09% 0.06% 0.02% 0.60%
NM SACR1 0.06% 0.06% 0.02% 0.02% 0.01% 0.17%
NM SAPE1 0.84% 0.60% 0.24% 0.24% 0.14% 2.05%
NM WHIT1 0.12% 0.14% 0.05% 0.04% 0.03% 0.38%
NM WHPE1 0.96% 0.84% 0.29% 0.23% 0.16% 2.48%
NV JARB1 0.43% 1.32% 0.54% 0.10% 0.23% 2.63%
WY BRID1 2.98% 12.91% 6.56% 1.53% 2.41% 26.39%
WY NOAB1 0.49% 3.11% 1.60% 0.07% 0.72% 5.98%
WY YELL2 0.63% 5.90% 2.94% 0.07% 1.43% 10.97%

Table 22: Utah Share of U.S. Anthropogenic Sulfate Impacts on Neighboring State CIAs
State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
AZ BALD1 0.60% 0.03% 0.23% 0.02% 0.02% 0.91%
AZ CHIR1 1.26% 0.04% 0.33% 0.08% 0.03% 1.74%
AZ GRCA2 2.18% 0.08% 0.19% 0.28% 0.08% 2.81%
AZ IKBA1 1.29% 0.07% 0.29% 0.10% 0.06% 1.81%
AZ PEFO1 2.30% 0.11% 0.51% 0.14% 0.07% 3.12%
AZ SAGU1 1.36% 0.06% 0.34% 0.06% 0.04% 1.86%
AZ SIAN1 0.62% 0.03% 0.18% 0.03% 0.03% 0.89%
AZ SYCA_RHTS 4.21% 0.22% 1.45% 0.09% 0.15% 6.13%
AZ TONT1 1.31% 0.06% 0.33% 0.09% 0.04% 1.84%
CO GRSA1 4.85% 0.09% 0.38% 0.52% 0.07% 5.91%
CO MEVE1 7.97% 0.17% 0.84% 1.57% 0.14% 10.69%
CO MOZI1 10.25% 0.27% 1.48% 0.67% 0.18% 12.85%
CO ROMO1 5.89% 0.28% 2.12% 0.49% 0.17% 8.96%
CO WEMI1 6.79% 0.19% 0.96% 1.41% 0.14% 9.49%
CO WHRI1 22.85% 0.45% 1.91% 2.12% 0.30% 27.62%

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State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
ID CRMO1 4.17% 0.48% 4.08% 0.01% 0.35% 9.10%
ID SAWT1 1.23% 0.06% 0.82% 0.01% 0.04% 2.15%
ID SULA1 0.79% 0.11% 0.70% 0.01% 0.08% 1.70%
NM BAND1 1.25% 0.04% 0.18% 0.22% 0.02% 1.70%
NM BOAP1 0.68% 0.03% 0.14% 0.04% 0.02% 0.91%
NM GICL1 0.89% 0.04% 0.26% 0.04% 0.03% 1.25%
NM GUMO1 0.49% 0.02% 0.12% 0.03% 0.01% 0.66%
NM SACR1 0.21% 0.01% 0.04% 0.01% 0.00% 0.27%
NM SAPE1 2.07% 0.06% 0.31% 0.25% 0.05% 2.74%
NM WHIT1 0.29% 0.01% 0.06% 0.02% 0.01% 0.38%
NM WHPE1 1.55% 0.05% 0.28% 0.13% 0.03% 2.04%
NV JARB1 2.05% 0.12% 0.85% 0.03% 0.07% 3.13%
WY BRID1 12.26% 0.63% 5.98% 0.30% 0.42% 19.59%
WY NOAB1 4.01% 0.15% 1.12% 0.17% 0.12% 5.57%
WY YELL2 5.29% 0.35% 3.22% 0.05% 0.24% 9.15%

Table 23: Utah Share of Total Nitrate Impacts on Neighboring State CIAs
State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
AZ BALD1 0.06% 0.07% 0.03% 0.01% 0.01% 0.17%
AZ CHIR1 0.17% 0.15% 0.06% 0.04% 0.03% 0.45%
AZ GRCA2 0.07% 0.07% 0.01% 0.03% 0.01% 0.20%
AZ IKBA1 0.12% 0.16% 0.06% 0.03% 0.04% 0.41%
AZ PEFO1 1.34% 0.90% 0.35% 0.26% 0.26% 3.11%
AZ SAGU1 0.18% 0.17% 0.05% 0.04% 0.04% 0.48%
AZ SIAN1 0.10% 0.09% 0.06% 0.01% 0.01% 0.27%
AZ SYCA_RHTS 0.38% 0.50% 0.19% 0.08% 0.09% 1.24%
AZ TONT1 0.13% 0.18% 0.06% 0.03% 0.04% 0.44%
CO GRSA1 1.19% 0.68% 0.22% 0.29% 0.16% 2.54%
CO MEVE1 2.38% 1.52% 0.45% 0.50% 0.37% 5.21%
CO MOZI1 1.77% 3.09% 1.28% 1.28% 0.61% 8.03%
CO ROMO1 1.19% 2.16% 0.90% 0.77% 0.44% 5.45%
CO WEMI1 0.94% 0.85% 0.28% 0.38% 0.10% 2.54%
CO WHRI1 1.81% 2.39% 0.79% 0.93% 0.35% 6.27%
ID CRMO1 0.26% 2.94% 1.46% 0.01% 0.86% 5.54%
ID SAWT1 0.01% 0.08% 0.05% 0.00% 0.02% 0.16%
ID SULA1 0.02% 0.18% 0.08% 0.00% 0.02% 0.31%
NM BAND1 0.32% 0.24% 0.08% 0.08% 0.05% 0.75%
NM BOAP1 0.24% 0.22% 0.09% 0.06% 0.06% 0.67%
NM GICL1 0.01% 0.01% 0.00% 0.00% 0.00% 0.03%
NM GUMO1 0.06% 0.09% 0.03% 0.02% 0.01% 0.20%

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State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
NM SACR1 0.04% 0.04% 0.01% 0.01% 0.01% 0.12%
NM SAPE1 0.44% 0.31% 0.13% 0.12% 0.07% 1.07%
NM WHIT1 0.05% 0.06% 0.02% 0.02% 0.01% 0.17%
NM WHPE1 0.42% 0.37% 0.13% 0.10% 0.07% 1.09%
NV JARB1 0.11% 0.33% 0.13% 0.03% 0.06% 0.65%
WY BRID1 0.97% 4.20% 2.13% 0.50% 0.78% 8.57%
WY NOAB1 0.08% 0.49% 0.25% 0.01% 0.11% 0.95%
WY YELL2 0.18% 1.69% 0.84% 0.02% 0.41% 3.14%

Table 24: Utah Share of Total Sulfate Impacts on Neighboring State CIAs
State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
AZ BALD1 0.06% 0.00% 0.02% 0.00% 0.00% 0.10%
AZ CHIR1 0.13% 0.00% 0.03% 0.01% 0.00% 0.17%
AZ GRCA2 0.93% 0.03% 0.08% 0.12% 0.03% 1.19%
AZ IKBA1 0.14% 0.01% 0.03% 0.01% 0.01% 0.20%
AZ PEFO1 0.46% 0.02% 0.10% 0.03% 0.01% 0.63%
AZ SAGU1 0.20% 0.01% 0.05% 0.01% 0.01% 0.27%
AZ SIAN1 0.06% 0.00% 0.02% 0.00% 0.00% 0.09%
AZ SYCA_RHTS 0.50% 0.03% 0.17% 0.01% 0.02% 0.72%
AZ TONT1 0.15% 0.01% 0.04% 0.01% 0.00% 0.21%
CO GRSA1 1.31% 0.02% 0.10% 0.14% 0.02% 1.60%
CO MEVE1 1.98% 0.04% 0.21% 0.39% 0.03% 2.66%
CO MOZI1 2.68% 0.07% 0.39% 0.18% 0.05% 3.36%
CO ROMO1 1.64% 0.08% 0.59% 0.14% 0.05% 2.50%
CO WEMI1 1.45% 0.04% 0.20% 0.30% 0.03% 2.02%
CO WHRI1 4.16% 0.08% 0.35% 0.39% 0.05% 5.02%
ID CRMO1 0.46% 0.05% 0.45% 0.00% 0.04% 1.01%
ID SAWT1 0.08% 0.00% 0.05% 0.00% 0.00% 0.13%
ID SULA1 0.05% 0.01% 0.05% 0.00% 0.01% 0.11%
NM BAND1 0.41% 0.01% 0.06% 0.07% 0.01% 0.55%
NM BOAP1 0.19% 0.01% 0.04% 0.01% 0.00% 0.25%
NM GICL1 0.12% 0.01% 0.03% 0.00% 0.00% 0.17%
NM GUMO1 0.11% 0.00% 0.03% 0.01% 0.00% 0.15%
NM SACR1 0.06% 0.00% 0.01% 0.00% 0.00% 0.08%
NM SAPE1 0.54% 0.01% 0.08% 0.07% 0.01% 0.71%
NM WHIT1 0.07% 0.00% 0.01% 0.00% 0.00% 0.10%
NM WHPE1 0.44% 0.01% 0.08% 0.04% 0.01% 0.58%
NV JARB1 0.13% 0.01% 0.05% 0.00% 0.00% 0.20%
WY BRID1 2.01% 0.10% 0.98% 0.05% 0.07% 3.21%
WY NOAB1 0.35% 0.01% 0.10% 0.02% 0.01% 0.49%

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State Site EGU Mobile Non-EGU Oil & Gas Remaining Anthro Utah Total
WY YELL2 0.68% 0.05% 0.41% 0.01% 0.03% 1.17%

6.A.3 Technical Basis of Reasonable Progress Goals
Please refer to sections 4.A.4 and 4.A.5 to view visibility progress to date and natural baseline
comparisons for Utah’s CIAs as well as section 6.A.10 to review UDAQ’s Long-Term Strategy
along with its technical basis.
6.A.4 Identify Anthropogenic Sources
Please refer to sections 5.C and 5.E for Utah’s detailed emissions inventory by sector. Please
refer to sections 7.A and 7.A.1 for Utah’s source screening processes and Q/d analysis for
determining which sources have the highest potential impact on Utah’s CIAs.
6.A.5 Emissions Reductions Due to Ongoing Pollution Control Programs123
RAVI
RAVI refers to a process to identify and control visibility impairment that is caused by the
emissions of air pollutants from one, or a small number of sources directly impacting a CIA. The
three primary steps in this process are:124
• FLM certification of impairment
• State identification of existing sources causing or contributing to the impairment
• BART analysis to determine what controls, if any, are required on any existing source
that meets BART criteria and has been identified as contributing to impairment
In the case that a FLM certifies impairment for any of Utah’s CIAs, RAVI125 will be addressed by
the state through the following actions:
• Submittal of an initial RAVI LTS along with periodic revisions every three years
• Submittal of an LTS revision within three years of an FLM certification of impairment
• Consultation with FLMs
• Submittal of a report to the EPA and public on Utah’s progress towards the national goal
UDAQ consulted with NPS who confirmed that none of Utah’s CIAs have been certified as
impaired by any FLMs.
National Ambient Air Quality Standards
The CAA requires the EPA to set NAAQS for pollutants considered harmful to public health and
the environment. The CAA establishes two types of air quality standards: primary and
123 51.308(d)(3) and (f)(2)
124 The Recommendations for Making Attribution Determinations in the Context of Reasonably Attributable BART can be found at: http://www.westar.org/RA%20BART/final%20RA%20BART%20Report.pdf 125 40 CFR 51.302

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secondary. Primary standards are set to protect public health, including the health of sensitive
populations such as asthmatics, children, and the elderly. Secondary standards are set to
protect public welfare, including protection from decreased visibility and damage to animals,
crops, vegetation, and buildings.
The EPA has established health-based NAAQS for the six criteria pollutants including CO, NO2,
O3, PM, SO2, and lead. The EPA establishes the primary health standards after considering
both the concentration level and the duration of exposure that can cause adverse health effects.
Pollutant concentrations that exceed the NAAQS are considered unhealthy for some portion of
the population. At concentrations between 1.0 and 1.5 times the standard, while the general
public is not expected to be adversely affected by the pollutant, the most sensitive portion of the
population may be. However, at levels above 1.5 times the standard, even healthy people may
see adverse effects. The UDAQ monitors these criteria pollutants, as well as meteorological
conditions and several non-criteria pollutants for special studies at various monitoring sites
throughout the state.
The CAA has three different designations for areas based on whether they meet the NAAQS for
each pollutant. Areas in compliance with the NAAQS are designated as attainment areas. Areas
where there is no monitoring data showing compliance or noncompliance with the NAAQS are
designated as unclassifiable areas. Areas that are not in compliance with the NAAQS are
designated as nonattainment areas. A maintenance area is an attainment area that was once
designated as nonattainment for one of the NAAQS and has since been demonstrated as
attaining and continuing to attain that standard for a period of a minimum of 10 years. Most of
the State of Utah has been designated as either Attainment or Unclassifiable for all the NAAQS.
Utah has never been out of compliance with any NO2 standard, and has not exceeded the lead
standard since the 1970s. Three cities in Utah (Salt Lake City, Ogden, and Provo) were at one
time designated as nonattainment areas for carbon monoxide. Due primarily to improvements in
motor vehicle technology, Utah has complied with the carbon monoxide standards since 1994.
Salt Lake City, Ogden, and Provo were successfully redesignated to attainment status in 1999,
2001, and 2006, respectively.
Ozone (O3)
In October of 2015, the EPA strengthened the ozone NAAQS from 75 ppb to 70 ppb, based on
a three-year average of the annual 4th highest daily eight-hour average concentration. The
standard was reviewed again in 2020 and the EPA chose to retain the standard at 70 ppb.
Ozone monitors operated by the UDAQ along the Wasatch Front show exceedances of the
current standard in Weber, Davis, and Salt Lake counties. There were also exceedances in
Uinta County and Duchesne County during the winter. In 2016, the Governor recommended that
portions of the Wasatch Front and Uinta Basin be designated non-attainment and that the rest
of the State be designated attainment/unclassifiable. The current status of attainment for ozone
in the Uintah basin is marginal non-attainment.

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The unique wintertime ozone issue in the Uinta Basin is caused by oil and gas extraction.
UDAQ is working on rule amendments and potentially new rules for the oil and gas industry to
stay in compliance with the ozone NAAQS.
PM10
The EPA established the 24-hour NAAQS for PM10 in July 1987 as 150 μg/m3. The standard is
met when the probability of exceeding the standard is no greater than once per year for a three-
year averaging period. Salt Lake County and Utah County had been designated nonattainment
for PM10 shortly after the standard was promulgated. Ogden City was also designated as a
nonattainment area due to one year of high concentrations (1992) but was determined to be
attaining the standard in January 2013. State Implementation Plans (SIP) were written and
promulgated in 1991 and included control strategies that resulted in the marked decrease in
PM10 concentrations observed in the early 1990s. Ogden City, and Salt Lake and Utah Counties
were officially designated as attainment for PM10 effective March 27, 2020. These three former
nonattainment areas are now subject to the maintenance plans that were approved by EPA and
the areas must continue to attain the standard for the first maintenance period of ten years. High
values of monitored PM10 sometimes result from exceptional events, such as dust storms and
wildfires.
PM2.5
The EPA first established standards for PM2.5 in 1997. In 2006, the EPA lowered the 24-hour
PM2.5 standard from 65µg/m3 to 35 µg/m3. The PM2.5 NAAQS underwent a review in 2020 and
the standards were retained. In 2009, three areas in Utah were designated nonattainment for
PM2.5. UDAQ wrote a moderate SIP for the Logan, UT-ID nonattainment area, including a
vehicle emissions inspection program. Logan attained the standard, and has since been
redesignated to attainment status. The Provo and Salt Lake PM2.5 nonattainment areas were
unable to attain by the moderate attainment date and were reclassified to serious
nonattainment. A serious SIP was submitted to EPA for the Salt Lake nonattainment area, and
the Provo nonattainment area attained the standard prior to a serious SIP due date. Best
Available Control Measures and Technologies were still required in both nonattainment areas,
significantly reducing VOCs, NOx, and both primary and secondary PM2.5 in the airsheds. Both
areas have now attained the standard, and EPA is reviewing SIP elements and maintenance
plans for official redesignation to attainment/maintenance.
Sulfur Dioxide (SO2)
In 1971, EPA established a 24-hour average SO2 standard of 0.14 ppm, and an annual
arithmetic average standard of 0.030 ppm. In 2010, EPA revised the primary standard for SO2,
setting it at 75 ppb for a three-year average of the 99thpercentile of the annual distribution of
daily maximum one-hour average concentrations for SO2. Throughout the 1970s, the Magna
monitor routinely measured violations of the 1971 24-hour standard. Consequently, all of Salt
Lake County and parts of eastern Tooele County above 5,600 feet were designated as
nonattainment for that standard. Two significant technological upgrades at the Kennecott
smelter costing the company nearly one billion dollars resulted in continued compliance with the
SO2 standard since 1981. In the mid-1990s, Kennecott, Geneva Steel, the five refineries in Salt

84
Lake City, and several other large sources of SO2 made dramatic reductions in emissions as
part of an effort to curb concentrations of secondary particulates (sulfates) that were contributing
to PM10 violations. More recently, Kennecott closed Units 1, 2, and 3 of its coal-fired power
plants in 2016 and Unit 4 in 2019, resulting in further SO2 emissions reductions.
Utah submitted an SO2 Maintenance Plan and redesignation request for Salt Lake and Tooele
Counties to the EPA in April of 2005, but EPA never took formal action on the request. Because
of changes in the emissions in subsequent years, and changes in the modeling used to
demonstrate attainment of the standard, in November 2019, the State of Utah withdrew its 2005
Maintenance Plan and redesignation request. UDAQ is currently working very closely with EPA
to develop a new maintenance plan and redesignation request to address the 1971 standard.
UDAQ will conduct modeling and other analyses in 2021 with the goal of submitting an
approvable maintenance plan and redesignation request to EPA by the end of that year. On
November 1, 2016, Governor Herbert submitted a recommendation to EPA that all areas of the
state be designated as attainment for the 2010 SO2 NAAQS based on monitoring and air quality
modeling data. On January 9, 2018, EPA formally concurred with this recommendation and
designated all areas of the state as attainment/unclassifiable.
The NAAQS program and Utah’s work to stay in compliance with all NAAQS has significantly
decreased VOC, NOx, PM2.5, PM10, and SO2 emissions over time, benefiting the regional haze
program.
Air Quality Incentive Programs
In addition to the NAAQS program, UDAQ administers multiple incentive programs created to
encourage individuals and businesses to voluntarily reduce emissions. Funding for these
programs comes from various sources, including settlement agreements, legislative
appropriations, and federal grant programs. The emissions reductions from incentive programs
are not included as part of any SIP, but the reductions do make an impact on monitored ambient
values.
Targeted Airshed Grants
UDAQ has been a recipient of EPA targeted airshed grants in the past for PM2.5 and ozone in
Logan, Salt Lake, Provo, and the Uinta Basin nonattainment areas. Programs include
woodstove/fireplace conversions, school bus replacements, vehicle repair and replacement
assistance programs, and an oil and gas engine replacement program. UDAQ applied for the
competitive grants and was awarded a total of $14.5 million for these projects that are still in
process.
Utah Clean Diesel Program
The Utah Clean Diesel Program aims to cut emissions from heavy- duty diesel vehicles and
equipment that operate in the State’s nonattainment areas. Fleet owners receive a 25%
incentive toward the purchase of new vehicles and equipment that meet the cleanest emissions
standards. Retiring engine model years 2006 and older diesel trucks that are currently
operational and have a minimum of three years remaining in their useful life and replacing them
with current model years can achieve approximately 71 to 90% reductions in NOx, 97 to 98%

85
reductions in PM2.5, and 89 to 91% reductions in VOCs, according to the EPA Emissions
Standards for Heavy-Duty Highway Engines and Vehicles. Nearly $24 million in federal grants
have been awarded through the Utah Clean Diesel Program since 2008, resulting in thousands
of tons reduced from diesel emissions.
Legislative Appropriations for Incentive Programs
The woodstove and fireplace conversion funded by the targeted airshed grant was wildly
successful, and the Utah State Legislature appropriated UDAQ an additional $9 million to
convert wood burning appliance to gas or electric along Utah’s Wasatch Front. This program is
currently being administered. During the 2019 General Legislative Session, the State
Legislature appropriated $4.9 million to be used as an incentive for the installation of electric
vehicle supply equipment (EVSE) throughout the State. The EVSE Incentive Program allows
businesses, non-profit organizations, and other governmental entities (excluding State
Executive Branch agencies) to apply for a grant for reimbursement of up to 50% of the purchase
and installation costs for a pre-approved EVSE project. Funds can be used for the purchase and
installation of both Level 2 or DC fast charging EVSE. This program continues to be
administered. During the 2019 Legislative Session, the Legislature appropriated $500,000 to the
UDAQ to administer a Trip Reduction Program. A primary component of the Trip Reduction
Program is a Free-Fare Day Pilot Project. The UDAQ has worked closely with the Utah Transit
Authority (UTA) to provide free fares during inversion periods when air quality levels are
increasing and projected to reach levels that are harmful to human health.
Clean Air Violation Settlement Dollars for Emissions Reduction Incentives
The State of Utah is a beneficiary of over $35 million from the Volkswagen (VW) Environmental
Mitigation Trust, part of a settlement with VW for violations of the CAA. UDAQ has developed an
environmental mitigation plan to offset the NOx emissions from the vehicles in the State affected
by the automaker’s violations. The plan directs the $35 million settlement funds towards
upgrades to government-owned diesel truck and bus fleets as well as the expansion of electric-
vehicle (EV) charging equipment. Funding allocations are as follows:
• Class 4-8 Local Freight Trucks and School Bus, Shuttle Bus, and Transit Bus: 73.5%
• Light-Duty, Zero Emissions Vehicle Supply Equipment: 11%
• Administrative Costs: 8.5%
• Diesel Emission Reduction Act (DERA) options: 7%
Projects were prioritized and selected based on their reduction of NOx, cost-per-ton of NOx
reduced, value to the nonattainment areas, and community benefits. Awardees will have three
years to complete their projects.
Using settlement money from General Motors, UDAQ runs an electric lawn equipment
exchange each year. Participants receive a higher incentive dollar amount if they scrap an old
gas-powered piece of equipment.

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6.A.6 Measures to Mitigate the Impacts of Construction Activities
Fugitive dust is particles of soil, ash, coal, minerals, etc., which become airborne because of
wind or mechanical disturbance. Fugitive dust can be generated from natural causes such as
wind or from manmade causes such as unpaved haul roads and operational areas, storage,
hauling and handling of aggregate materials, construction activities and demolition activities.
Fugitive dust contributes particulate matter (PM) emissions to the atmosphere. PM emissions
must be minimized to meet NAAQS. Fugitive dust is limited to an opacity of 20% or less on site,
and 10% or less at the property boundary. Opacity is a measurement of how much visibility is
obscured by a plume of dust. For example, if a plume of dust obscures 20% of the view in the
background, the visible emissions from the dust plume is 20% opacity. The regulations
described in this Subsection apply to the following areas of the state:
• all regions of Salt Lake and Davis counties
• all portions of the Cache Valley
• all regions in Weber and Utah counties west of the Wasatch Mountain range
• in Box Elder County, from the Wasatch Mountain range west to the Promontory
Mountain range and south of Portage
• in Tooele County, from the northernmost part of the Oquirrh mountain range to the
northern most part of the Stansbury Mountain range and north of Route 199.
In addition to opacity limits, any source 0.25 acre or greater in size is required to submit a
Fugitive Dust Control Plan (FDCP) to the UDAQ. The FDCP is required to help sources
minimize the amount of fugitive dust generated onsite. A source is required to submit a FDCP
prior to initial construction or operation and prior to any modifications made on site that effect
fugitive dust emissions. Sources are required to maintain records indicating compliance with the
conditions of a FDCP. For high wind events (winds over 25 miles per hour) additional records
are required. The sources must make these records available for review by the UDAQ upon
request.
There are also regulations regarding possible fugitive dust from roadways:
• Any person whose activities result in fugitive dust from a road shall minimize fugitive
dust to the maximum extent possible.
• Any person who deposits materials that may create fugitive dust on a public or private
paved road shall clean the road promptly.
• Any person responsible for construction or maintenance of any existing road or having a
right-of-way easement or possessing the right to use a road shall minimize fugitive dust
to the maximum extent possible.
• Any person responsible for construction or maintenance of any new or existing unpaved
road shall prevent, to the maximum extent possible, the deposit of material from the
unpaved road onto any intersecting paved road during construction or maintenance. This
includes site entrances and exits for vehicles.
• Demolition activities including razing homes, buildings, or other structures.

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6.A.7 Basic smoke management practices
Subsection 51.309(d)(6) of Title 40 Code of Federal Regulations includes the following
requirements for state implementation plans regarding programs related to fire: (1)
documentation that all federal, state and private prescribed fire programs in the state evaluate
and address the degree of visibility impairment from smoke in their planning and application; (2)
a statewide inventory and emissions tracking system for VOCs, NOx, elemental and organic
carbon, and fine particle emissions from fire; (3) identification and removal of any administrative
barriers to the use of alternatives to burning where possible; (4) inclusion of enhanced smoke
management programs considering visibility as well as health and nuisance objectives based on
specific criteria; (5) and establishment of annual emission goals for fire in cooperation with
states, tribes, federal land managers and private entities to minimize emissions increases from
fire to the maximum extent feasible.
Utah implements an EPA-approved Smoke Management Plan (SMP) to regulate open burning
and prescribed fire activities. Utah has developed a smoke management regulation (found in
Utah Administrative Code r. R307-204) that implements the Western Regional Air Partnership
(WRAP) Enhanced Smoke Management Programs for Visibility Policy. The SMP considers
smoke management techniques and the visibility impacts of smoke when developing, issuing or
conditioning permits, and when making dispersion forecast recommendations. Pursuant to 40
CFR § 51.309(d)(6)(i), the State of Utah has evaluated all federal, state, and private prescribed
fire programs in the state, based on the potential to contribute to visibility impairment in the 16
CIAs of the Colorado Plateau, and how visibility protection from smoke is addressed in planning
and operation. The State of Utah relied upon the WRAP report Assessing Status of
Incorporating Smoke Effects into fire Planning and Operation as a guide for making this
evaluation. The State of Utah has also evaluated whether these prescribed fire programs
contain the following elements: actions to minimize emissions; evaluation of smoke dispersion;
alternatives to fire; public notification; air quality monitoring; surveillance and enforcement; and
program evaluation.
The Utah Smoke Management Plan (SMP), revised March 23, 2000, provides operating
procedures for federal and state agencies that use prescribed fire, wildfire, and wildland fire on
federal, state, and private wildlands in Utah. The SMP includes the program elements listed in
40 CFR § 51.309(d)(6)(i), except for alternatives to fire. In a letter dated November 8, 1999, the
EPA certified the Utah SMP under EPA’s April 1998 Interim Air Quality Policy on Wildland and
Prescribed Fires (Policy). EPA’s Policy also includes the elements that are listed in 40 CFR §
51.309(d)(6)(i).
In 2001, the Utah SMP requirements were codified through rulemaking and comprise R307-204
of the Utah Administrative Code. R307-204 applies to all persons using prescribed fire or
wildland fire on land they own or manage, including federal, state, and private wildlands. The
Utah TSD Supplement includes copies of the Utah SMP.
Under R307-204, Land Managers are required to submit pre-burn information including the
location of any CIAs within 15 miles of the burn, a map depicting the potential impact of the

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smoke from the burn on any CIAs, a description of fuels and acres to be burned, emission
reduction techniques to be applied, and monitoring of smoke effects to be conducted. In
addition, Land Managers are required to submit a more detailed burn plan that includes, at a
minimum, information on the fire prescription or conditions under which a prescribed fire may be
ignited.
Under R307-204, prescribed fires requiring a burn plan cannot be ignited and wildland fire used
for resource benefits cannot be managed before the UDAQ Director approves the burn request.
The burn approval requirement provides for the scheduling of burns to reduce impacts on
visibility in CIAs.
After the burn is completed, the Land Manager is required to submit post-burn information (daily
emission report) to evaluate the effectiveness of the burn and provide a record of acres treated
by the burn, emissions information, public interest, daytime and nighttime smoke behavior, any
emission reduction techniques applied, and evaluation of those techniques. The procedures
listed above serve as an evaluation of the degree of visibility impairment from smoke from
prescribed fires that are conducted on federal, state, and private wildlands.
Information on the types of management alternatives to fire considered by Land Managers are
included in programmatic or long-term management plans. These programmatic plans are
developed in accordance with the National Environmental Policy Act (NEPA) and are reviewed
by the UDAQ on an individual basis. Typically, the Land Manager does not evaluate alternatives
to fire once the decision has been made to use fire and the subsequent burn plan developed.
6.A.8 Emissions Limitations and Schedules for Compliance to Achieve the RPG
The 2028OTBa2 modeled visibility projections from WRAP for Utah are based on recent actual
emissions and activities of in-state sources. These projections are compared to the URP
glidepaths in section 8.C. As shown in Table 26 (section 6.A.10), Utah is making reasonable
progress in each of its parks and is projected to continue that progress through 2028 on the
assumption that Utah sources continue operating within the confines of these “on-the-books”
emissions trends. Section 8.D contains Utah’s reasonable progress determinations detailing
emissions limits and controls UDAQ has deemed necessary for Utah to achieve reasonable
progress in its CIAs. Emissions limitations and schedules for compliance for the second
planning period may be found in SIP Subsection IX.H.23.126
6.A.9 Source retirement and replacement schedules
Table 25 details the planned EGU retirement and replacement schedules for Utah sources used
in WRAP’s RepBase2 and 2028OTBa2 modeling projections. Of all of the planned retirements,
only the announced retirement of the Intermountain Generation Station in 2025 occurs within
the second planning period. Though the IGS coal-fired units are expected to cease operation by
mid-2025, Utah is establishing a firm closure date of no later than December 31, 2027, to
126 See Appendix A

89
ensure that these units will not continue to operate beyond the end of the second planning
period. This date allows flexibility for closing the plant and the rescinding of the permit and
approval order.
Table 25: Status of Utah EGU Retirements in RepBase2 and 2028OTBa2 Inventories
Facility Name Unit ID In-Service Year Retirement Year Notes Operator Unit Type
Intermountain 1SGA 1986 2025 Announced retirement Intermountain
Power Service
Corporation
Dry bottom
wall-fired
boiler
Intermountain 2SGA 1987 2025 Announced retirement Intermountain
Power Service
Corporation
Dry bottom
wall-fired
boiler
Bonanza 1-Jan 1986 2030 Coal consumption cap from settlement agreement
Deseret
Generation &
Transmission
Dry bottom
wall-fired
boiler
Hunter 1 1978 2042 PAC IRP; Round 1 RH FIP in Litigation
PacifiCorp Energy
Generation
Tangentially-
fired
Hunter 2 1980 2042 PAC IRP; Round 1 RH FIP in Litigation
PacifiCorp Energy
Generation
Tangentially-
fired
Hunter 3 1983 2042 PAC IRP PacifiCorp Energy
Generation
Dry bottom
wall-fired
boiler
Huntington 1 1977 2036 PAC IRP; Round 1 RH FIP in Litigation
PacifiCorp Energy
Generation
Tangentially-
fired
Huntington 2 1974 2036 PAC IRP; Round 1 RH FIP in Litigation
PacifiCorp Energy
Generation
Tangentially-
fired

6.A.10 Anticipated net effect on visibility from projected changes in emissions during
this planning period
According to the RHR, the 2028 RPG for the 20 percent most anthropogenically impaired days
is to be compared to the 2000-2004 baseline period visibility condition for the same set of days
and must provide for visibility improvement since the baseline period.127 UDAQ has used
modeling data from WRAP’s TSS to project the anticipated net effect on visibility progress that
will occur in the second planning period based on already adopted controls and “on-the-books"
activities and emissions rates. UDAQ has chosen the “2028OTBa2 w/o fire” projection that
excludes wildfire to more accurately represent future emissions from sources UDAQ is better
able to control. This projection reduces the impact of elemental carbon and organic carbon from

127 40 CFR 51.308(f)(3)(i)

90
fires from the original 2028 EPA projection to remove additional fire impacts that were not fully
eliminated by the move from haziest days metric (used during the first planning period) to most
impaired days metric (used during the second planning period). These projections result from in-
state emission reductions due to ongoing air pollution control programs, including source
measures the state has already adopted to meet RHR requirements and CAA requirements
other than for visibility protection.
Long Term Strategy Summary
UDAQ’s long term strategy (LTS) includes an array of existing and new measures as detailed
below.
Existing Measures
UDAQ relied upon several existing measures in the development of its LTS, including federal
on-road and non-road vehicle and equipment standards and BACM measures and BACT
controls included in the recently completed Serious Area PM2.5 SIP for the Salt Lake
Nonattainment Area. Utah also relied upon the following existing round 1 regional haze controls:
• Existing NOx control rate-based limits and Hunter power plant
• Existing NOx control rate-based limits and Huntington power plant
• Existing SO2 limits for Hunter power plant (Section 309 control added to SIP in round 2)
• Existing SO2 limits for Huntington power plant (Section 309 control added to SIP in round
2)
• Closure of the Carbon power plant
UDAQ also added existing controls/limits on haze-forming pollutants at screened-in facilities to
the round 2 SIP to ensure ongoing enforceability in the regional haze context:
• Graymont
• Ash Grove
• Sunnyside
• US Magnesium
• Intermountain Generation Station
Most of the above measures are already accounted for in the WRAP 2028OTBa2 scenario,
which was based on the emission inventories and data sources listed in Section 5.B of this SIP
revision. However, two existing measures led to additional emissions reductions that were not
accounted for in the WRAP 2028OTBa2 projections:
• PM2.5 SIP BACT SCR level NOx rate-based limit and subsequent closure of the
Kennecott Utah Copper power plant
• PM2.5 SIP BACT annual mass-based SO2 limit at the Tesoro Refinery
New Measures
As stated previously UDAQ required four-factor analyses on six sources with Q/d values >=6
that met additional screening criteria. These analyses informed the reasonable progress

91
determinations for these sources and led to the inclusion of the following new measures in the
LTS:
• A plantwide enforceable mass-based NOx limit on Hunter power plant
• A plantwide enforceable mass-based NOx limit on Huntington power plant
• Installation of FGR on the US Magnesium Rowley Plant Riley Boiler
• An enforceable closure date for Units 1 and 2 of the Intermountain Generation Station
Emissions reductions for one of these new measures, the closure of IGS Units 1 and 2, were
already accounted for in the WRAP 2028OTBa2 projections based upon closure plans that had
been announced at the time the scenario was developed.
Table 26 below summarizes estimated net changes to the 2028 projection based upon the
inclusion of both new and existing measures in the LTS. The emission reductions from the KUC
power plant were estimated based on the elimination of the EGU emissions from that facility
from the 2028OTBa2 scenario. The SO2 emission reductions for the Tesoro Refinery were
estimated by reducing the 2028OTBa2 SO2 emissions for that facility (708 tons) to the SIP
Section IX.H source-wide SO2 annual limit of 300 tons per year, resulting in a reduction of 408
tons. The remaining emission reductions stem from the four-factor analyses and reasonable
progress determinations for the sources listed.
Table 26: Net Changes in Emissions from New and Existing Measures Relative to 2028OTBa2
Source/Facility New or Existing
Measure
Reduction Included
in 2028OTBa2
NOX SO2 PM10-PRI PM2.5-
PRI
VOC NH3
PacifiCorp- Hunter Power Plant New No -158 0 0 0 0 0
PacifiCorp- Huntington
Power Plant
New No 149 0 0 0 0 0
US Magnesium Riley Boiler New No -23 0 0 0 0 0
Tesoro Refining &
Marketing Company
LLC
Existing No 0 -408 0 0 0 0
Kennecott Utah Copper LLC- Power Plant Existing No -1,152 -2,152 -135 -99 -6 0
Total -1,184 -2,560 -135 -99 -6 0

Based upon these changes, UDAQ revised the original 2028OTBa2 projection as summarized
in Table 27. The resulting 2028LTS scenario results in emissions reductions of 44% (NOx), 27%
(SO2), 2% (PM10), 10% (PM2.5) and 30% (VOC) relative to RepBase2.

92

Table 27: Statewide Anthropogenic Scenario Totals and LTS Emission Reductions (tpy)
Source
Category
2014v2 RepBase2 2028OTBa2 Change Due
to New and Existing
Measures
2028LTS 2028LTS-
RepBase2
2028LTS-
RepBase2 (% Change)
NOX 179,639 154,328 87,593 -1,184 86,409 -67,919 -44%
SO2 27,829 15,253 13,684 -2,560 11,124 -4,129 -27%
PM10 118,235 120,542 118,117 -135 117,982 -2,560 -2%
PM2.5 28,547 31,050 28,039 -99 27,940 -3,110 -10%
VOC 240,496 244,272 171,298 -6 171,292 -72,980 -30%
NH3 20,523 20,995 21,011 0 21,011 16 0%

Because the LTS was developed after the completion of the WRAP photochemical modeling,
the additional reductions from the LTS relative to 2028OTBa2 are not expressly accounted for in
the modeled reasonable progress goal. The omission of these emissions reductions in the
2028OTBa2 projection make our glidepath comparisons conservative, as actual 2028 visibility
can be expected to improve due to additional emission reductions associated with the LTS.
Visibility Comparison
Table 28 compares the baseline visibility data for each of Utah’s CIAs with the 2028 point along
the URP glidepath and the 2028 modeled projections and calculates the resulting percentage of
progress towards the 2028 URP made in each.
Table 28: Comparison of baseline, 2028 URP, 2028 EPA w/o fire projection for worst and clearest days
CIA
IMPROVE
Site
WORST DAYS CLEAREST DAYS
Baseline (dv) 2028 URP (dv)
2028 EPA w/o Fire Projection (dv)
% Progress to 2028 URP 2028 Below URP Glidepath? (Y/N)
Baseline (dv) 2028 EPA Projection (dv)
2028 EPA w/o Fire Projection (dv)
2028 Below No Degradation Line? (Y/N)
BRCA1 8.42 6.68 6.03 137.60% YES 2.77 1.22 1.20 YES
CANY1 8.79 6.92 6.19 139.10% YES 3.75 1.94 1.92 YES
CAPI1 8.78 6.87 6.63 112.28% YES 4.10 2.17 2.10 YES
ZICA1 10.40 8.35 8.27 103.73% YES 4.48 3.65 3.54 YES

The following figures compare the modeled 2002, representative baseline, and 2028 projections
with source apportionment for most impaired days to show the visibility progress made in Utah’s
CIAs.

93

Figure 42: Modeled Visibility Progress for MID at Canyonlands and Arches National Park
Figure 41: Modeled Visibility Progress for MID at Bryce Canyon National Park

94

Figure 43: Modeled Visibility Progress for MID at Capitol Reef National Park
Figure 44: Modeled Visibility Progress for MID at Zion National

95

The following figures represent the visibility progress made in each CIA based on only US
anthropogenic contribution with the same modeling projections for most impaired days.

Figure 46: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Canyonlands and Arches National Park
Figure 45: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Bryce Canyon National Park

96

6.A.11 Enforceability of Emissions Limitations
Any emissions limits and operating procedures identified for the implementation of the RHR are
listed in SIP Subsection IX.H.21, 22, and 23, which are made enforceable through EPA
approval and incorporation into the Utah Air Quality Rules. The proposed IX.H language can be
found in Appendix A. Existing control measures from UDAQ’s PM2.5 and PM10 SIP revisions
deemed necessary for reasonable progress can be found in IX.H.2, 4, and 12.
Figure 47: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Capitol Reef National Park
Figure 48: Modeled Visibility Progress for US Anthropogenic Contributions to MIDs at Zion National Park

97

Chapter 7: Emission Control Analysis128
7.A Source Screening
Through modeling done by WRAP with data collected at the IMPROVE sites in Utah’s CIAs,
UDAQ was able to assess the source apportionment for the most impaired days in Utah’s
National Parks. Figure 49 shows that, on most impaired days, US anthropogenic, international,
and biogenic pollution are the most significant sources of light extinction. Figure 50 and Figure
51 further apportion species contributing to each pollution source. US anthropogenic impairment
consists primarily of organic mass carbon, coarse mass, ammonium nitrate, and ammonium
sulfate. For this implementation period, Utah has focused on visibility impairing pollutants
attributed to anthropogenic sources which can be controlled including ammonium nitrate and
ammonium sulfate.

128 40 CFR 51.308(f)(2)(i)
Figure 49: Average Light Extinction by Sources in Bryce Canyon National Park

98

The regulated sources included in the map below consist of point sources and oil and gas wells
within Utah. There are 37 sources emitting pollutants greater than 100 TPY (major sources) and
Figure 50: Source Contributions on Average Most Impaired Days in Bryce Canyon National Park
Figure 51: WRAP States Ammonium Sulfate Source Apportionment for Most Impaired Days at Bryce Canyon National Park

99
511 other point sources emitting less than 100 TPY. There are 13,853 oil and gas wells in Utah,
including all “shut-in” wells which are not currently in use, but could resume production at any
time, which would be documented by reports from the Utah Division of Oil, Gas, and Mining
(UDOGM).

7.A.1 Q/d Analysis
The RHR129 requires states to consider anthropogenic sources of visibility impairment and
should consider evaluating major and minor stationary sources or groups of sources, mobile
sources, and area sources. Sources in Utah were selected based on a Q/d analysis. The
analysis is a ratio of a source’s emissions in tons per year (Q) in 2014 divided by the distance
(d) in kilometers to any Class I area. Emissions in tons per year of SO₂, NOx, and PM were

129 40 C.F.R. § 51.308(f)(2).
Figure 52: Map of Utah Regulated Sources with Emissions >100 TPY

100
included in the analysis. WRAP’s analysis suggested using a Q/d value of 10 as the threshold
for sources with the most potential to impact CIAs. However, UDAQ used a more conservative
threshold of six.130
Table 29: Sources initially selected to perform a Four-Factor analysis
Facility Name Combined Q/d Total Q tpy* Distance to Nearest Class I
area in km (D)
Class I Area Q/d NOx Q/D SO₂ Q/D PM10 NOx tons per year (Q) SO₂ tons per year (Q) PM10 tons per year (Q)
Ash Grove Cement Company- Leamington Cement Plant
6.9 930.5 134.0 Capitol Reef

6.3 0.04 0.6 845.5 5.9 79.1
CCI Paradox Midstream,
LLC: Lisbon Natural Gas
Processing Plant†
20.9 747.1 35.8 Canyonlands 5.3 14.0 1.6 188.6 499.6 59.0
Graymont Western Us Incorporated- Cricket Mountain Plant
9.0 1,180.7 130.8 Capitol Reef 7.0 0.3 1.7 916.5 40.8 223.4
Intermountain Power
Service Corporation-
Intermountain Generation
Station†
193.6 28,945.7 149.5 Capitol Reef 153.3 29.2 11.1 22,909.2 4,371.5 1,665.0
Kennecott Utah Copper LLC- Mine & Copperton Concentrator†
22.1 5,234.5 237.2 Capitol Reef 17.7 0.01 4.4 4,199.6 2.0 1,032.9
Kennecott Utah Copper
LLC- Power Plant, Lab, and
Tailings Impoundment†
11.8 2,949.7 250.4 Capitol Reef 5.3 6.0 0.5 1,322.5 1,500.3 126.8
PacifiCorp- Hunter Power Plant 216.1 16,177.9 74.9 Capitol Reef 153.5 52.6 10.0 11,491.2 3,939.3 747.4
PacifiCorp- Huntington
Power Plant
105.5 10,106.2 95.8 Capitol Reef 71.7 25.9 7.9 6,871.6 2,479.2 755.4
Sunnyside Cogeneration
Associates- Sunnyside
Cogeneration Facility
15.2 1,477.1 97.0 Arches 3.6 10.9 0.8 348.9 1,054.8 73.4
US Magnesium LLC-
Rowley Plant
7.4 2,124.2 288.7 Capitol Reef 3.6 0.1 3.7 1,052.1 17.9 1,054.2
*Tons per year: Data is from version 2 of the 2014 National Emissions Inventory
† Additional data from these sources, including recent emissions, projected 2028 emissions, and planned closure, allowed
them to be exempt from a 4-factor analysis

Because the original Q/d analysis used 2014 NEI data, UDAQ also conducted a follow-up Q/d
screen using more recently available 2017 NEI data to ensure that the source selection results
130 See Table 27

101
remained consistent and that no sources with potential impacts were missed. No additional
sources were identified with Q/d >=6. One source, CCI Paradox Lisbon Natural Gas Plant, was
not selected as the plant was not in operation that year and had no emissions. Also, the 2017
NEI does not include haul truck emissions from the KUC Mine & Copperton Concentrator,
resulting in a Q/d of 3.9 for that source. UDAQ elaborates on this source in Section 7.A.2 below.
Table 30: 2017 NEI Q/d Screen
Facility Name Combined Q/d Total Q tpy* Distance to Nearest
Class I area
in km (D)
Class I Area Q/d NOx Q/D SO₂ Q/D PM10 NOx tons per year
(Q)
SO₂ tons per year
(Q)
PM10 tons per
year (Q)
Ash Grove Cement
Company-
Leamington Cement
Plant
9.8 1,319.3 134.0 Capitol Reef

8.8 0.14 0.9 1,183.8 19.0 116.5
CCI Paradox Midstream, LLC:
Lisbon Natural Gas
Processing Plant†
NA NA 35.8 Canyonlands NA NA NA NA NA NA
Graymont Western
Us Incorporated-
Cricket Mountain
Plant
6.3 823.8 130.8 Capitol Reef 4.07 0.13 2.1 532.7 17.5 273.6
Intermountain Power
Service Corporation-
Intermountain
Generation Station†
85.5 12,785.0 149.5 Capitol Reef 62.3 16.6 6.6 9,318.8 2,483.6 982.6
Kennecott Utah Copper LLC- Mine &
Copperton Concentrator††
3.9 931.6 237.2
Capitol Reef
0.02 0.00 3.9 5.2 0.0 926.4
Kennecott Utah
Copper LLC- Power
Plant, Lab, and
Tailings
Impoundment†
6.3 1,570.1 250.4 Capitol Reef 1.8 4.1 0.3 460.8 1,036.4 73.0
PacifiCorp- Hunter Power Plant 184.2 13,789.1 74.9 Capitol Reef 130.6 46.9 6.7 9,773.8 3,511.6 503.8
PacifiCorp-
Huntington Power
Plant
90.7 8,686.0 95.8 Capitol Reef 61.9 23.8 5.0 5,931.2 2,281.0 473.8
Sunnyside
Cogeneration
Associates-
Sunnyside
Cogeneration Facility
10.0 965.4 97.0 Arches 4.4 4.9 0.6 428.0 477.0 60.3
US Magnesium LLC- Rowley Plant 6.4 1,832.5 288.7 Capitol Reef 3.5 0.02 2.8 1,004.9 6.7 820.9

102
*Tons per year: Data is from the 2017 National Emissions Inventory † Additional data from these sources, including recent emissions, projected 2028 emissions, and planned closure, allowed them to be exempt from a 4-factor analysis ††The 2017 NEI does not include the KUC Mine haul truck emissions. UDAQ elaborates on this in section 7.A.2 below

7.A.2 Secondary Screening of Sources
After performing Q/d analysis, UDAQ further narrowed down the list of sources required to
undergo the four-factor analysis based on current emissions, projected emissions in 2028,
closure and controls put in place after the 2014 base year inventory. As a result of this
secondary screening, the following sources were not required to provide a four-factor analysis:
The CCI Paradox Midstream, LLC - Lisbon Natural Gas Processing Plant
The CCI Paradox Midstream, LLC: Lisbon Natural Gas Processing Plant has a complicated
regulatory and ownership history which has impacted its emissions performance over the recent
past.131 The combined Q/d (for NOx, SO2, and PM10) for the facility was 13.68 for Arches and
20.87 for Canyonlands, both of which are above the Q/d threshold of 6 used to select significant
sources of haze impairing pollutants to Utah's CIAs. These high Q/d values largely stemmed
from anomalously high SO2 emissions in 2014 (and 2015) due to issues with the disposal well at
the plant. DAQ reviewed Lisbon’s most recent five years of data (2017-2021) and re-calculated
the Q/d values shown in Table 31 below, all of which fall below UDAQ’s Q/d threshold of 6. Of
note, recent actual SO2 emissions have dropped dramatically to between 0.01 and 0.13 percent
of the 2014 levels used in the original screening. For this reason, this source was ultimately not
required to provide a four-factor analysis. However, UDAQ is continuing to work with this source
to evaluate whether reductions in permitted emission limits may be appropriate, particularly for
SO2, given recent actual emissions levels.

131 In 2009 the plant received a permit modification to lower the SO2 emissions from 1,593 tons down to
111 tons. The plant requested a reduction in emissions as it had installed both primary and secondary
control systems to limit emissions of SO2. Unfortunately, in 2010 the plant requested a new modification
and mistakenly restored the original 1,593 tons of SO2 emissions without explanation. While that PTE
value has been carried forward in more recent permitting actions, actual emissions have never reached
the 1,593-ton value. The plant changed ownership in early-2017, which resulted in changes in the
operation of the facility and addition of a helium plant in early-2020.

103
Table 31: Paradox Lisbon Plant Q/d Analysis for nearest CIAs
Year PM10-PRI SO2 NOx CIA Distance (km) PM10-PRI SO2 NOx Total Q/d
2017 Plant was not in operation
2018 45.1 0.1 111.6 Canyonlands 35.8 1.3 0.0 3.1 4.4
2018 45.1 0.1 111.6 Arches 54.6 0.8 0.0 2.0 2.9
2019 Plant was not in operation
2020 61.9 0.6 126.0 Canyonlands 35.8 1.7 0.0 3.5 5.3
2020 61.9 0.6 126.0 Arches 54.6 1.1 0.0 2.3 3.5
2021 27.8 0.1 181.4 Canyonlands 35.8 0.8 0.0 5.1 5.8
2021 27.8 0.1 181.4 Arches 54.6 0.5 0.0 3.3 3.8

Intermountain Power Service Corporation- Intermountain Generation Station
On September 29, 2006, the Governor of California approved California Senate Bill (SB) 1368,
which directed the California Energy Commission to establish a greenhouse gas (GHG)
emission performance standard (EPS) for electricity generation and which disallowed load-
serving entities in California from entering into long-term financial commitments with electrical
corporations unless the generation supplied under the financial commitment complies with that
standard. Because approximately 98% of the power generated at the Intermountain Generation
Station (IGS) is consumed by customers of California utilities and because the power generated
by the IGS’s two coal-fired units exceeds California’s GHG EPS, the current contract for coal-
fired generation, which expires in 2025, will not be renewed for power from those units. Instead,
the permittee, Intermountain Power Service Corporation (IPSC), plans to replace the coal-fired
units with an EPS-compliant combined-cycle natural gas plant, which will be highly thermally
efficient and which will include state-of-the-art emissions controls such as SCR. As a result,
regional haze-related pollutants (PM, SO2, and NOx) from the IGS are expected to decrease
dramatically. Though the coal-fired units are expected to cease operation by mid-2025, Utah is
establishing a firm closure date of no later than December 31, 2027, to ensure that the coal-fired
units at IGS will not continue to operate beyond the end of the second planning period. This
date allows flexibility for closing the plant and the rescinding of the permit and approval order.
UDAQ did approach IPSC about the feasibility of improving the efficiency of existing controls,
particularly SO2 scrubbing, at the facility in the three years between mid-2022 and mid-2025, but
the company indicated that such improvements are logistically and economically infeasible over
such a short time period. Furthermore, the operator’s engineering and environmental staff and
resources are fully engaged in the process of bringing the replacement gas-fired units online,
the successful completion of which will bring about dramatic emissions reductions.
Kennecott Utah Copper LLC- Mine & Copperton Concentrator
The predominant visibility impairing pollutant from the Kennecott Mine and Copperton
Concentrator is NOx, the vast majority of which comes from mine haul trucks and other non-road
equipment as shown in Table 32 below. Specifically, this equipment was responsible for 4,376.7

104
tons (82.5%) of the 5,308.3 tons of combined PM10, SO2, and NOx emissions from this facility.
Section 209 of the Clean Air Act preempts the State from setting standards for non-road
vehicles or engines, leaving UDAQ with few options to control NOx emissions from haul
trucks.132 When non-road emissions are removed from the 2017 inventory for this source, the
Q/d drops to 3.9 – i.e., below UDAQ’s threshold value of 6. That said, as identified by EPA,133
the anticipated NOx+NMHC emissions reduction from replacing a Tier 1 haul truck with a Tier 4
truck is 65.9%, and the NOx+NMHC emissions reduction from replacing a Tier 2 haul truck with
a Tier 4 truck is 42.3%. This gives UDAQ a degree of comfort that emissions from this source
will continue to improve over time as older vehicles are replaced.
Additionally, this source recently underwent a thorough BACT analysis as part of the Salt Lake
Serious Nonattainment Area PM 2.5 SIP. As a result, there are no additional controls that can be
applied at this time beyond those already included in the SIP as identified in Table 33 in Section
7.A.2 below.
Table 32: 2017 Kennecott Utah Copper LLC – Mine & Concentrator Emissions and Revised Q/d
Source/Distance/Q/d PM10 SO2 NOX PM10+SO2+N
OX
Non-Truck Emissions 926.4 0.0 5.2 931.6
Haul Truck (non-road) Emissions 170.0 2.7 4,204.0 4,376.7
Total Emissions 1,096.4 2.7 4,209.2 5,308.3
Distance to nearest CIA (km) 237.2 237.2 237.2 237.2
Revised Q/d without haul truck
emissions
3.9 0.0 0.0 3.9

Kennecott Utah Copper LLC- Power Plant Lab Tailings Impoundment
The coal-fired boilers at the Power Plant Lab Tailings impoundment were decommissioned, and
the Approval Order (AO) reflecting this change was updated on February 4, 2020.134 The
February 2020 AO removed any ability for Kennecott to operate coal fired boilers as all the coal-
fired boilers were removed from the approved equipment list. The AO summarizes the updates
in the project description. Units 1-3 were prohibited to operate under the recently approved
PM2.5 SIP, and a specific SIP condition set their closure date. Thus, due to that applicable
condition, Units 1 – 3 were removed from the permit. Kennecott proposed the removal of Unit 4
from the permit because they planned to decommission the unit. The AO project summarizes
that Kennecott made that decision voluntarily, and – based on that decision – Unit 4 was
removed from the permit. The AO only lists remaining ancillary equipment. It does not list Units
1-3 or Unit 4 as equipment for the facility and – for this reason – Kennecott does not have
132 See 42 U.S.C. § 7543(e). 133 Source: https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P100OA05.pdf
134 This Approval Order can be found at: https://daqpermitting.utah.gov/DocViewer?IntDocID=117327&contentType=application/pdf

105
approval to operate any coal-fired boilers. Based on this equipment change, UDAQ also
rescinded the Title V permit for the facility on February 12, 2020.135 The vast majority of
emissions from this facility were associated with the boilers, and emissions from the remaining
equipment (a diesel emergency generator engine, cooling tower, degreasers and two natural
gas-fired emergency generators to support the KUC electricity distribution control room) are low
enough that this source is below the Q/d threshold for the four-factor analysis. Finally, even if
had not been decommissioned, this source recently underwent a thorough BACT analysis for
the PM2.5 SIP, which resulted in the inclusion of fuel-switching to natural gas and an SCR-
derived NOx rate-based emission limit for Unit 4 in SIP Section IX.H as summarized in Table 33
below. For these reasons, this source was not required to provide a four-factor analysis for the
round 2 regional haze SIP.
Table 33: Existing Controls in Utah’s SIP for Screened Sources
Company Facility Applicable Units Control Type Limits Implementation Date SIP Reference Last Revision EPA Approval Part H reference
PacifiCorp Hunter 1 and 2 PM
Emissions of particulate (PM) shall not exceed 0.015 lb/MMBtu heat input from each boiler based on a 3-run test average.
No later than January 1, 2019
Regional Haze June 24, 2019 Pending
H.22 Source Specific Emission Limitations: Regional Haze Requirements, Best Available Retrofit Technology
PacifiCorp Hunter 1 and 2 NOx
Emissions of NOx from each boiler shall not exceed 0.26 lb/MMBtu heat input for a 30-day rolling average.
No later than January 1, 2019
Regional Haze June 24, 2019 Pending
H.22 Source Specific Emission Limitations: Regional Haze Requirements, Best Available Retrofit Technology
PacifiCorp Hunter 3 NOx
Emissions of NOx shall not exceed 0.34 lb/MMBtu heat input for a 30- day rolling average.
No later than January 1, 2019
Regional Haze June 24, 2019 Pending
H.22 Source Specific Emission Limitations: Regional Haze Requirements, Best Available Retrofit Technology
PacifiCorp Huntington 1 and 2 PM
Emissions of particulate (PM) shall not exceed 0.015 lb/MMBtu heat input from each boiler based on a 3-run test average.
No later than January 1, 2019
Regional Haze June 24, 2019 Pending
H.22 Source Specific Emission Limitations: Regional Haze Requirements, Best Available Retrofit Technology
PacifiCorp Huntington 1 and 2 NOx
Emissions of NOx from each boiler shall not exceed 0.26 lb/MMBtu heat input for a 30-day rolling average.
No later than January 1, 2019
Regional Haze June 24, 2019 Pending
H.22 Source Specific Emission Limitations: Regional Haze Requirements, Best Available Retrofit Technology
Kennecott Utah Copper LLC
Bingham Canyon Mine
Diesel-powered ore and waste haul trucks
Mileage
Maximum total mileage per calendar day for diesel-powered ore and waste haul trucks shall not exceed 30,000 miles.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
135 See Appendix G for UDAQ’s letter rescinding the Title V permit.

106
Kennecott Utah Copper LLC
Bingham Canyon Mine
In-pit crusher baghouse PM2.5
The In-pit crusher baghouse shall not exceed a PM2.5 emission limit of 0.78 lbs/hr(0.007 gr/dscf) PM2.5 monitoring shall be performed by stack testing every three years.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Kennecott Utah Copper LLC
Copperton Concentrator Dryers
Control emissions from the Product Molybdenite Dryers with a scrubber during operation of the dryers.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Kennecott Utah Copper LLC
Copperton Concentrator Heaters NOx
The remaining heaters shall not operate more than 300 hours per rolling 12- month period unless upgraded so the NOx emission rate is no greater than 30 ppm.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Kennecott Utah Copper LLC
Utah Power Plant 4 Fuel
Only natural gas shall only be used as a fuel, unless the supplier or transporter of natural gas imposes a curtailment. Unit #4 may then burn coal, only for the duration of the curtailment plus sufficient time to empty the coal bins following the curtailment.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Kennecott Utah Copper LLC
Utah Power Plant 4 PM2.5
Filterable PM2.5 emissions to the atmosphere when burning natural gas shall not exceed 0.004 grains/dscf. Filterable+condensible PM2.5 emissions to the atmosphere when burning natural gas shall not exceed 0.03 grains/dscf.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Kennecott Utah Copper LLC
Utah Power Plant 4 NOx
NOx emissions to the atmosphere when burning natural gas shall not exceed 32 lbs/hr or 0.04 lbs/MMBtu
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Kennecott Utah Copper LLC
Utah Power Plant 5 PM2.5
PM2.5 with duct burning emissions to the atmosphere when burning natural gas shall not exceed 18.8 lbs/hr (filterable + condensible)
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area

107
Kennecott Utah Copper LLC
Utah Power Plant 5 VOC
VOC emissions to the atmosphere shall not exceed 2.0 ppmdv
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Chevron Products Co.
Salt Lake Refinery Source-wide PM10
Combined emissions of PM10 shall not exceed 0.715 tons per day (tpd).
No later than January 1, 2019 PM10 December 2, 2020 Pending
H.2 Source Specific Emission Limitations in Salt Lake County PM10 Nonattainment/Maintenance Area
Chevron Products Co.
Salt Lake Refinery Source-wide NOx
Combined emissions of NOx shall not exceed 2.1 tons per day (tpd) and 766.5 tons per rolling 12-month period.
No later than January 1, 2019 PM10 December 2, 2020 Pending
H.2 Source Specific Emission Limitations in Salt Lake County PM10 Nonattainment/Maintenance Area
Chevron Products Co.
Salt Lake Refinery Source-wide SO2
Combined emissions of SO2 shall not exceed 1.05 tons per day (tpd) and 383.3 tons per rolling 12-month period.
No later than January 1, 2019 PM10 December 2, 2020 Pending
H.2 Source Specific Emission Limitations in Salt Lake County PM10 Nonattainment/Maintenance Area
Chevron Products Co.
Salt Lake Refinery Source-wide PM2.5
Combined emissions of PM2.5 (filterable+condensable) shall not exceed 0.305 tons per day (tpd) and 110 tons per rolling 12-month period.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Chevron Products Co.
Salt Lake Refinery Source-wide NOx
Combined emissions of NOx shall not exceed 2.1 tons per day (tpd) and 766.5 tons per rolling 12-month period.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Chevron Products Co.
Salt Lake Refinery Source-wide SO2
Combined emissions of SO2 shall not exceed 1.05 tons per day (tpd) and 383.3 tons per rolling 12-month period.
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Chevron Products Co.
Salt Lake Refinery Engine K35001 NOx
Emissions of NOx from each rich-burn compressor engine shall not exceed 236 NOx in ppmvd @ 0% O2
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Chevron Products Co.
Salt Lake Refinery Engine K35002 NOx
Emissions of NOx from each rich-burn compressor engine shall not exceed 208 NOx in ppmvd @ 0% O2
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area
Chevron Products Co.
Salt Lake Refinery Engine K35003 NOx
Emissions of NOx from each rich-burn compressor engine shall not exceed 230 NOx in ppmvd @ 0% O2
No later than January 1, 2019 PM2.5 December 2, 2020 Pending
H.12. Source-Specific Emission Limitations in Salt Lake City – UT PM2.5 Nonattainment Area

108
Chevron Products Co.
Salt Lake Refinery
External combustion process equipment
PM10
Combined emissions of filterable PM10 from all external combustion process equipment shall be no greater than 0.234 tons per day.
No later than January 1, 2019 PM10 December 2, 2020 Pending
H.4 Interim Emission Limits and Operating Practices

7.A.3 Weighted Emissions Potential Analysis of Sources in Utah and Neighboring
States
WRAP released a Weighted Emissions Potential (WEP) analysis after UDAQ chose sources to
submit a four-factor analysis. The WEP is obtained by overlaying extinction weighted residence
time (EWRT) results with 2028OTBa2 emissions of light extinction precursors and shows which
sources have the highest potential to impact visibility in CIAs. Table 34 and Table 35 list the
point sources with the top ten WEP values for Utah CIAs for nitrate and sulfate, respectively,
and summarize whether those sources were captured by Utah’s initial Q/d screen and whether
they were ultimately required to submit a four-factor analysis. As can be seen, UDAQ’s initial
Q/d screen captured most of the point sources with the highest-ranking WEP values at Utah
CIAs. For those sources that were ultimately excluded from submitting a four-factor analysis, the
tables provide notes as to the rationale for the exclusion, including plant closures, recent BACT
analysis/controls, revised emission inventories, and the predominance of emissions from
sources that states are largely preempted from controlling (e.g., non-road). The tables also
include information regarding the status of non-Utah point sources with high-ranking WEP
values, where available.
Tables 36 and 37 list Utah point sources that were among the top ten WEP values in the CIAs
of neighboring states for nitrate and sulfate, respectively. Again, the tables show that UDAQ’s
initial and secondary screening largely succeeded in identifying the sources with the potential to
impact CIAs, while excluding some sources that were already well-controlled, closed/closing, or
that have few options for state-level controls.
Tesoro and Chevron Refineries
UDAQ's original Q/d screening using 2014 NEI data yielded values below 6 for the Chevron and
Tesoro facilities. At EPA’s request, UDAQ re-calculated the Q/d thresholds of its major sources
using 2017 NEI data to ensure that additional sources did not exceed a Q/d of 6 and confirmed
that no additional sources would be screened-in using the newer data. Specifically, neither the
Chevron or Tesoro refineries had a revised Q/d of 6 or greater. Here it should be noted that
UDAQ chose a more stringent Q/d threshold of 6 rather than the Q/d value of 10 recommended
by WRAP.
However, both sources had high-ranking weighted emissions potential values for sulfate or
nitrate and various in-state and out-of-state CIAs, Specifically, Chevron ranked 9th for nitrate at
BRCA1 with a % of total point WEP of 1.4%. Chevron had no high-ranking sulfate impacts.
Tesoro ranked 10th at BRCA1 for nitrate at BRCA1 (0.9%) and had the following rankings and
% values for sulfate:

109
• BRCA1: Rank 8 (2.6%)
• CAPI1: Rank 8 (1.6%)
• BRID1: Rank 8 (3.9%)
• YELL2: Rank 8 (3.4%)
• CRMO1: Rank 6 (2.7%)
• SAWT1: Rank 8 (2.7%)
Though “Top 10” ranked, these WEP values represented a relatively small percentage of total
point WEP at each CIA, as indicated above.
In addition, the 2019 Guidance states that it "may be reasonable for a state not to select an
effectively controlled source" (page 22) and that "the statutory considerations for selection of
BACT and LAER are also similar to, if not more stringent than, the four statutory factors for
reasonable progress" (See 2019 EPA Guidance at 23). Both Chevron and Tesoro recently
underwent a thorough BACT analysis for the Serious Area PM2.5 Salt Lake Nonattainment Area
SIP that resulted in additional controls and limits being added to SIP Section IX.H. Specifically,
Tesoro installed a wet gas scrubber unit to control SO2 emissions and is now subject to a
source-wide annual SO2 limit of 300 tons per year. For comparison, WRAP’s WEP analyses
used a 2028OTBa2 projection of 708.3 tons. Tesoro’s actual SO2 emissions for 2019-2021
since the installation of new controls ranged between 22 and 23 tons per year. As a result, the
sulfate WEP values for this source – which were already a tiny fraction of total point source
sulfate WEP – are not representative of either the enforceable limits or the recent actuals for
this facility. Please refer to section 7.A.2 to review the existing controls resulting from the recent
PM2.5 and PM10 SIP revisions for Chevron and Tesoro which include both source-wide and
equipment limits for NOx, SO2, PM10, and PM2.5. Please refer to section 6.A.10 to review the
projected emissions reductions resulting from Tesoro's existing controls.

Table 34: Nitrate Point Source WEP Rank for Utah CIAs
Utah CIA Rank Facility Name Source State
2028 OTB NOX (tons)
Distance (meters) NOx Q/d
WEP_NO3 (% of total)
Selected
in Utah Q/d Screen? (Y/N)
UT Four-
Factor Analysis? (Y/N)
Notes
BRCA1 1 PacifiCorp- Hunter Power
Plant
UT 10,001.2 198,466.7 50.4 109,484.1 (18.6%) YES YES
BRCA1 2 PacifiCorp- Huntington Power Plant UT 6,091.4 216,464.4 28.1 61,138.6 (10.4%) YES YES
BRCA1 3
Kennecott
Utah Copper LLC- Mine & Copperton
Concentrator
UT 4,199.6 329,072.0 12.8 52,048.8 (8.8%) YES NO
BACT for
PM2.5 Serious
SIP; majority of NOX emissions
from non-
road sources

110
Utah
CIA Rank Facility Name Source
State
2028 OTB NOX
(tons)
Distance
(meters)
NOx
Q/d
WEP_NO3 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
BRCA1 4
Graymont
Western US
Incorporated- Cricket Mountain
Plant
UT 916.5 155,620.0 5.9 34,304.4 (5.8%) YES YES
BRCA1 5
Ash Grove
Cement
Company- Leamington Cement Plant
UT 845.5 214,929.5 3.9 30,091.0
(5.1%) YES YES
BRCA1 6
Kennecott Utah Copper
LLC- Power
Plant Lab Tailings Impoundment
UT 1,157.5 342,148.6 3.4 20,954.3
(3.6%) YES NO Power plant
closed in 2020
BRCA1 7 Salt Lake City
Intl UT 784.0 350,666.3 2.2 17,677.6
(3.0%) NO NO
Q/d <6; majority of
NOX emissions
from non-
road sources (aircraft take-offs and
landings)
BRCA1 8
US Magnesium
LLC- Rowley
Plant
UT 1,052.1 367,453.2 2.9 10,062.0
(1.7%) YES YES
BRCA1 9
Chevron
Products Co - Salt Lake Refinery
UT 375.6 355,251.0 1.1 8,359.5 (1.4%) NO NO
Q/d <6; BACT
for PM2.5 Serious SIP
BRCA1 10
Tesoro Refining &
Marketing
Company LLC
UT 358.1 351,572.8 1.0 8,053.0
(0.9%) NO NO Q/d <6; BACT for PM2.5
Serious SIP
CANY1 1
PacifiCorp-
Hunter Power
Plant
UT 10,001.2 130,681.1 76.5 128,112.8
(13.9%) YES YES
CANY1 2
PacifiCorp-
Huntington
Power Plant
UT 6,091.4 148,607.2 41.0 68,616.5
(7.4%) YES YES
CANY1 3 Bonanza TR 5,721.7 185,722.9 30.8 59,301.8 (6.4%) NA NA
Likely closure
in 2030 due to settlement
CANY1 4
PNM - San Juan
Generating
Station
NM 7,390.8 219,591.9 33.7 47,113.4
(5.1%) NA NA
Subject to
four-factor analysis in NM’s draft
SIP. PNM has
announced plant closure in 2022

111
Utah
CIA Rank Facility Name Source
State
2028 OTB NOX
(tons)
Distance
(meters)
NOx
Q/d
WEP_NO3 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
CANY1 5
Kennecott
Utah Copper
LLC- Mine & Copperton Concentrator
UT 4,199.6 307,168.4 13.7 45,956.2 (5.0%) YES NO
BACT for PM2.5 Serious
SIP; majority
of NOX emissions from non-
road sources
CANY1 6 Four Corners
Power Plant TR 4,060.4 228,638.6 17.8 24,859.3
(2.7%) NA NA
APS has announced
plant closure
in 2031
CANY1 7
Sunnyside
Cogeneration
Associates- Sunnyside Cogeneration
Facility
UT 442.2 129,762.3 3.4 22,940.9 (2.5%) YES YES
CANY1 8 Chaco Gas
Plant NM 2,053.4 264,690.7 7.8 14,056.2
(1.5%) NA NA
Not subject to
four-factor
analysis in NM’s proposed SIP
CANY1 9
CCI Paradox Midstream,
LLC: Lisbon
Natural Gas
Processing Plant
UT 201.9 57,532.7 3.5 12,076.0
(1.3%) YES NO
2018
emissions Q/d
<6
CANY1 10
RED ROCK GATHERING-
PREMIER BAR
X C.S.
CO 73.3 118,289.1 0.6 11,567.0
(1.3%) NA NA
Not subject to four-factor analysis in
CO’s proposed
SIP due to low NOX Q/d
CAPI1 1 PacifiCorp- Hunter Power Plant UT 10,001.2 98,938.2 101.1 334,329.1 (37.2%) YES YES
CAPI1 2
PacifiCorp-
Huntington Power Plant UT 6,091.4 120,459.7 50.6 167,247.5 (18.6%) YES YES
CAPI1 3
Kennecott
Utah Copper
LLC- Mine & Copperton Concentrator
UT 4,199.6 263,195.8 16.0 42,259.0 (4.7%) YES NO
BACT for
PM2.5 Serious
SIP; majority
of NOX emissions from non-
road sources
CAPI1 4
Graymont Western US
Incorporated-
Cricket
Mountain Plant
UT 916.5 148,543.7 6.2 26,049.6
(2.9%) YES YES

112
Utah
CIA Rank Facility Name Source
State
2028 OTB NOX
(tons)
Distance
(meters)
NOx
Q/d
WEP_NO3 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
CAPI1 5
Ash Grove
Cement
Company- Leamington Cement Plant
UT 845.5 159,501.2 5.3 24,633.4 (2.7%) YES YES
CAPI1 6
Kennecott
Utah Copper
LLC- Power
Plant Lab Tailings Impoundment
UT 1,157.5 275,718.8 4.2 13,860.1
(1.5%) YES NO Power plant
closed in 2020
CAPI1 7 US Magnesium LLC- Rowley
Plant
UT 1,052.1 313,659.3 3.4 10,218.3 (1.1%) YES YES
CAPI1 8 Bonanza TR 5,721.7 261,713.3 21.9 9,450.1 (1.1%) NA NA Likely closure in 2030 due to settlement
CAPI1 9
Sunnyside Cogeneration Associates-
Sunnyside
Cogeneration
Facility
UT 442.2 158,414.3 2.8 8,764.7
(1.0%) YES YES
CAPI1 10 Salt Lake City
Intl UT 784.0 280,646.7 2.8 7,264.8
(0.8%) NO NO
Q/d <6;
majority of NOX emissions from non-
road sources
(aircraft take-offs and landings)
ZICA1 1
St. George City Power- Red
Rock Power
Generation
Station
UT 34.3 38,429.0 0.9 13,108.2
(5.3%) NO NO Q/d <6
ZICA1 2
PacifiCorp-
Hunter Power Plant UT 10,001.2 285,805.3 35.0 12,364.2 (5.0%) YES YES
ZICA1 3 McCarran Intl NV 2,430.2 218,239.9 11.1 9,235.4 (3.7%) NA NA
Majority of
NOX emissions from non-road sources
(aircraft take-
offs and landings)
ZICA1 4
Kern River Gas
Transmission
Company- Veyo Compressor
Station
UT 72.7 56,439.3 1.3 9,185.2 (3.7%) NO NO Q/d <6

113
Utah
CIA Rank Facility Name Source
State
2028 OTB NOX
(tons)
Distance
(meters)
NOx
Q/d
WEP_NO3 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
ZICA1 5
Kennecott
Utah Copper
LLC- Mine & Copperton Concentrator
UT 4,199.6 385,739.6 10.9 7,998.7 (3.2%) YES NO
BACT for PM2.5 Serious
SIP; majority
of NOX emissions from non-
road sources
ZICA1 6
Pg&E Topock
Compressor
Station
CA 968.8 300,092.2 3.2 7,620.0
(3.1%) NA NA
Not subject to four-factor
analysis in
CA’s proposed
SIP due to low NOx Q/d
ZICA1 7 Millcreek Power UT 19.4 38,438.7 0.5 7,402.2 (3.0%) NO NO Q/d <6
ZICA1 8
PacifiCorp-
Huntington
Power Plant
UT 6,091.4 300,744.4 20.3 7,156.5
(2.9%) YES YES
ZICA1 9
Lhoist North America and
Granite Const.
(Apex)
NV 1,361.8 181,728.8 7.5 7,041.9
(2.8%) NA NA
NV’s
proposed SIP
requires SNCR on Kilns 1, 3, & 4 as well as
LNB on Kiln 1.
Kilns 3 & 4 have existing LNBs.
ZICA1 10
Kennecott Utah Copper
LLC- Power
Plant Lab
Tailings Impoundment
UT 1,157.5 398,524.3 2.9 6,609.7
(2.7%) YES NO Power plant
closed in 2020

Table 35: Sulfate Point Source WEP Rank for Utah CIAs
Utah CIA Rank Facility Name Source State
2028
OTB SO2 (tons)
Distance (meters) SO2 Q/d
WEP_SO4
(% of Total)
Selected
in Utah
Q/d Screen? (Y/N)
UT Four-
Factor Analysis? (Y/N)
Notes
BRCA1 1 CHEMICAL LIME
NELSON PLANT AZ 2,040.6 253,654.7 8.0 43,684.7
(21.8%) NA NA
Not subject to four-factor
analysis in AZ’s
proposed SIP
due to Round 1 BART FIP controls
BRCA1 2 PacifiCorp- Hunter Power
Plant
UT 3,498.2 198,466.7 17.6 22,430.8
(11.2%) YES YES

114
Utah
CIA Rank Facility Name Source
State
2028 OTB
SO2
(tons)
Distance
(meters)
SO2
Q/d
WEP_SO4 (% of
Total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
BRCA1 3
Kennecott Utah
Copper LLC-
Power Plant Lab Tailings Impoundment
UT 2,151.9 342,148.6 6.3 17,191.7 (8.6%) YES NO Power plant closed in 2020
BRCA1 4 PacifiCorp- Huntington Power Plant UT 2,449.0 216,464.4 11.3 14,397.6 (7.2%) YES YES
BRCA1 5 ASARCO LLC - HAYDEN
SMELTER
AZ 3,062.1 527,077.3 5.8 14,391.7
(7.2%) NA NA
Not subject to
four-factor analysis in AZ’s proposed SIP
due to Round 1
BART FIP controls
BRCA1 6
Kennecott Utah Copper LLC- Smelter &
Refinery
UT 704.4 342,656.1 2.1 5,618.9 (2.8%) NO NO Q/d <6; BACT for PM2.5 Serious SIP
BRCA1 7 Four Corners
Power Plant TR 2,537.7 341,751.7 7.4 5,413.2
(2.7%) NA NA
APS has
announced
plant closure in
2031
BRCA1 8
Tesoro Refining
& Marketing
Company LLC
UT 708.3 351,572.8 2.0 5,158.3
(2.6%) NO NO
Q/d <6; BACT
for PM2.5
Serious SIP
BRCA1 9
TUCSON
ELECTRIC
POWER CO - SPRINGERVILLE
AZ 6,991.9 455,128.8 15.4 3,654.7
(1.8%) NA NA
New SO2 limits
for units 1 & 2
included in
AZ’s proposed SIP
BRCA1 10 Phoenix Sky Harbor Intl AZ 275.1 463,195.4 0.6 3,615.9 (1.8%) NA NA
Majority of
NOX emissions from non-road sources
(aircraft take-
offs and
landings)
CANY1 1
PacifiCorp-
Hunter Power
Plant
UT 3,498.2 130,681.1 26.8 78,098.2
(19.1%) YES YES
CANY1 2
PacifiCorp-
Huntington
Power Plant
UT 2,449.0 148,607.2 16.5 48,079.5
(11.8%) YES YES
CANY1 3
CCI Paradox Midstream, LLC:
Lisbon Natural
Gas Processing Plant
UT 534.9 57,532.7 9.3 39,468.2
(9.7%) YES NO 2018 emissions
Q/d <6
CANY1 4 Four Corners Power Plant TR 2,537.7 228,638.6 11.1 32,557.0 (8.0%) NA NA
APS has announced plant closure in
2031

115
Utah
CIA Rank Facility Name Source
State
2028 OTB
SO2
(tons)
Distance
(meters)
SO2
Q/d
WEP_SO4 (% of
Total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
CANY1 5
Sunnyside
Cogeneration
Associates- Sunnyside Cogeneration
Facility
UT 460.8 129,762.3 3.6 25,602.8 (6.3%) YES YES
CANY1 6
Kennecott Utah
Copper LLC-
Power Plant Lab Tailings Impoundment
UT 2,151.9 317,050.4 6.8 21,266.8
(5.2%) YES NO Power plant
closed in 2020
CANY1 7
TUCSON ELECTRIC
POWER CO -
SPRINGERVILLE
AZ 6,991.9 463,072.9 15.1 13,923.7
(3.4%) NA NA
New SO2 limits for units 1 & 2
included in
AZ’s proposed SIP
CANY1 8 CHEMICAL LIME
NELSON PLANT AZ 2,040.6 448,519.3 4.6 13,409.0
(3.3%) NA NA
Not subject to
four-factor analysis in AZ’s
proposed SIP
due to Round 1
BART FIP controls
CANY1 9 Bonanza TR 1,281.3 185,722.9 6.9 11,908.4 (2.9%) NA NA Likely closure in 2030 due to
settlement
CANY1 10 PNM - San Juan Generating
Station
NM 823.1 219,591.9 3.7 10,995.1 (2.7%) NA NA
Subject to
four-factor
analysis in NM’s draft SIP. PNM has
announced
plant closure in 2022
CAPI1 1
PacifiCorp-
Hunter Power Plant UT 3,498.2 98,938.2 35.4 138,922.3 (34.7%) YES YES
CAPI1 2
PacifiCorp-
Huntington Power Plant UT 2,449.0 120,459.7 20.3 79,880.4
(20.0%) YES YES
CAPI1 3
Kennecott Utah
Copper LLC-
Power Plant Lab Tailings Impoundment
UT 2,151.9 275,718.8 7.8 31,599.4 (7.9%) YES NO Power plant closed in 2020
CAPI1 4 CHEMICAL LIME
NELSON PLANT AZ 2,040.6 356,269.4 5.7 25,448.1
(6.4%) NA NA
Not subject to four-factor
analysis in AZ’s
proposed SIP due to Round 1 BART FIP
controls

116
Utah
CIA Rank Facility Name Source
State
2028 OTB
SO2
(tons)
Distance
(meters)
SO2
Q/d
WEP_SO4 (% of
Total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
CAPI1 5
Sunnyside
Cogeneration
Associates- Sunnyside Cogeneration
Facility
UT 460.8 158,414.3 2.9 10,823.1 (2.7%) YES YES
CAPI1 6 ASARCO LLC - HAYDEN SMELTER AZ 3,062.1 589,323.9 5.2 10,351.8 (2.6%) NA NA
Not subject to
four-factor
analysis in AZ’s proposed SIP due to Round 1
BART FIP
controls
CAPI1 7
Kennecott Utah
Copper LLC- Smelter & Refinery
UT 704.4 277,921.4 2.5 10,261.2 (2.6%) NO NO
Q/d <6; BACT
for PM2.5 Serious SIP
CAPI1 8
Tesoro Refining
& Marketing Company LLC UT 708.3 280,166.8 2.5 6,278.1
(1.6%) NO NO
Q/d <6; BACT
for PM2.5 Serious SIP
CAPI1 9
NORTH VALMY
GENERATING STATION NV 2,277.3 574,890.7 4.0 5,620.2
(1.4%) NA NA
NV’s proposed
SIP includes a
federally
enforceable closure date of
12/31/28
CAPI1 10 Bonanza TR 1,281.3 261,713.3 4.9 4,809.0
(1.2%) NA NA Likely closure in 2030 due to
settlement
ZICA1 1 CHEMICAL LIME NELSON PLANT AZ 2,040.6 186,619.3 10.9 38,687.4 (24.8%) NA NA
Not subject to
four-factor
analysis in AZ’s proposed SIP due to Round 1
BART FIP
controls
ZICA1 2
Kennecott Utah
Copper LLC- Power Plant Lab Tailings
Impoundment
UT 2,151.9 398,524.3 5.4 9,186.4 (5.9%) YES NO Power plant closed in 2020
ZICA1 3 ASARCO LLC - HAYDEN SMELTER AZ 3,062.1 512,466.4 6.0 6,672.2 (4.3%) NA NA
Not subject to
four-factor
analysis in AZ’s proposed SIP due to Round 1
BART FIP
controls

117
Utah
CIA Rank Facility Name Source
State
2028 OTB
SO2
(tons)
Distance
(meters)
SO2
Q/d
WEP_SO4 (% of
Total)
Selected in Utah Q/d
Screen?
(Y/N)
UT Four-Factor
Analysis?
(Y/N)
Notes
ZICA1 4 McCarran Intl NV 265.3 218,239.9 1.2 4,713.6 (3.0%) NA NA
Majority of NOX emissions
from non-road
sources (aircraft take-offs and
landings)
ZICA1 5 PacifiCorp- Hunter Power
Plant
UT 3,498.2 285,805.3 12.2 4,557.8 (2.9%) YES YES
ZICA1 6 Phoenix Sky
Harbor Intl AZ 275.1 428,694.4 0.6 4,554.6
(2.9%) NA NA
Majority of NOX emissions from non-road
sources
(aircraft take-offs and landings)
ZICA1 7 California Portland Cement Co. CA 1,445.5 520,498.4 2.8 4,038.8 (2.6%) NA NA
Not subject to
four-factor analysis in CA’s proposed SIP
due to AB 617
ZICA1 8 Republic
Services Sunrise NV 209.5 201,737.4 1.0 4,025.8
(2.6%) NA NA
Not subject to
four-factor
analysis in NV’s proposed SIP due to low Q/d
ZICA1 9
TUCSON ELECTRIC
POWER CO -
SPRINGERVILLE
AZ 6,991.9 480,561.1 14.5 3,447.7
(2.2%) NA NA
New SO2 limits for units 1 & 2
included in
AZ’s proposed
SIP
ZICA1 10
PacifiCorp-
Huntington
Power Plant
UT 2,449.0 300,744.4 8.1 3,032.3
(1.9%) YES YES

Table 36: Nitrate Utah Point Source WEP Rank for Non-Utah CIAs
CIA State CIA Rank Facility Name Source State
2028 OTB NOx
(tons)
Distance (meters) NOx Q/d
WEP_NO3 (% of total)
Selected in Utah Q/d Screen?
(Y/N)
Included in Four-Factor Analysis?
(Y/N)
Notes
WY BRID1 5
Kennecott
Utah Copper LLC- Mine & Copperton
Concentrator
UT 4,199.6 328,062.1 12.8 23,190.1 (3.9%) YES NO
BACT for
PM2.5
Serious SIP;
majority of NOX
emissions
from non-
road sources

118
CIA
State CIA Rank Facility
Name
Source
State
2028 OTB
NOx
(tons)
Distance
(meters)
NOx
Q/d
WEP_NO3 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
Included in Four-Factor
Analysis?
(Y/N)
Notes
WY YELL2 9
Kennecott Utah Copper LLC- Mine &
Copperton
Concentrator
UT 4,199.6 461,954.1 9.1 4,042.4 (1.8%) YES NO
BACT for
PM2.5
Serious SIP; majority of NOX
emissions
from non-road sources
WY YELL2 10 Salt Lake City Intl UT 784.0 437,939.4 1.8 3,887.0 (1.7%) NO NO
Q/d <6; majority of NOX
emissions
from non-road sources (aircraft
take-offs
and
landings)
ID CRMO1 10
Kennecott Utah Copper
LLC- Mine &
Copperton
Concentrator
UT 4,199.6 338,486.4 12.4 22,912.5
(2.5%) YES NO
BACT for
PM2.5 Serious SIP; majority of
NOX
emissions from non-road sources

Table 37: Sulfate Utah Point Source WEP Rank for Non-Utah CIAs
CIA State CIA Rank Facility Name Source State
2028 OTB SO2 (tons)
Distance (meters) SO2 Q/d
WEP_SO4 (% of total)
Selected
in Utah Q/d Screen?
(Y/N)
Included
in Four-Factor Analysis?
(Y/N)
Notes
CO MEVE1 6
CCI Paradox
Midstream,
LLC: Lisbon
Natural Gas Processing Plant
UT 534.9 126,687.8 4.2 22,144.4
(1.3%) YES NO
2018
emissions
Q/d <6
CO MEVE1 9 PacifiCorp- Hunter Power
Plant
UT 3,498.2 310,434.6 11.3 11,845.4
(0.7%) YES YES
CO WEMI1 3
CCI Paradox
Midstream,
LLC: Lisbon
Natural Gas Processing
Plant
UT 534.9 140,388.0 3.8 24,308.8
(3.8%) YES NO
2018
emissions Q/d <6
CO WEMI1 6
PacifiCorp-
Hunter Power
Plant
UT 3,498.2 326,019.1 10.7 12,361.1
(1.9%) YES YES

119
CIA
State CIA Rank Facility Name Source
State
2028 OTB
SO2
(tons)
Distance
(meters)
SO2
Q/d
WEP_SO4 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
Included in Four-Factor
Analysis?
(Y/N)
Notes
WY BRID1 5
Kennecott
Utah Copper
LLC- Power Plant Lab Tailings
Impoundment
UT 2,151.9 317,383.8 6.8 53,003.7 (6.3%) YES NO
Power
plant closed in 2020
WY BRID1 8
Tesoro
Refining &
Marketing Company LLC
UT 708.3 299,746.7 2.4 32,334.3
(3.9%) NO NO
Q/d <6;
BACT for
PM2.5 Serious SIP
WY NOAB1 8
Kennecott Utah Copper
LLC- Power
Plant Lab Tailings Impoundment
UT 2,151.9 499,395.1 4.3 15,792.1
(2.2%) YES NO
Power
plant
closed in 2020
WY YELL2 2
Kennecott Utah Copper
LLC- Power
Plant Lab
Tailings Impoundment
UT 2,151.9 449,396.5 4.8 23,791.3
(7.4%) YES NO
Power
plant
closed in
2020
WY YELL2 8
Tesoro Refining &
Marketing
Company LLC
UT 708.3 435,882.7 1.6 10,963.7
(3.4%) NO NO
Q/d <6; BACT for PM2.5
Serious
SIP
ID CRMO1 4
Kennecott
Utah Copper LLC- Power Plant Lab
Tailings
Impoundment
UT 2,151.9 326,319.5 6.6 18,525.9 (6.8%) YES NO
Power plant closed in
2020
ID CRMO1 6
Tesoro
Refining & Marketing Company LLC
UT 708.3 325,079.4 2.2 7,431.8 (2.7%) NO NO
Q/d <6;
BACT for
PM2.5 Serious
SIP
ID CRMO1 10
Kennecott
Utah Copper
LLC- Smelter
& Refinery
UT 704.4 323,667.2 2.2 6,113.6
(2.2%) NO NO
Q/d <6; BACT for
PM2.5
Serious SIP
ID SAWT1 4
Kennecott Utah Copper LLC- Power
Plant Lab
Tailings
Impoundment
UT 2,151.9 446,448.0 4.8 6,827.9
(5.4%) YES NO
Power plant
closed in
2020
ID SAWT1 8
Tesoro Refining & Marketing
Company LLC
UT 708.3 448,276.9 1.6 3,373.8 (2.7%) NO NO
Q/d <6;
BACT for +PM2.5 Serious
SIP

120
CIA
State CIA Rank Facility Name Source
State
2028 OTB
SO2
(tons)
Distance
(meters)
SO2
Q/d
WEP_SO4 (% of
total)
Selected in Utah Q/d
Screen?
(Y/N)
Included in Four-Factor
Analysis?
(Y/N)
Notes
ID SAWT1 10
Kennecott
Utah Copper LLC- Smelter & Refinery
UT 704.4 442,899.3 1.6 2,252.8 (1.8%) NO NO
Q/d <6;
BACT for
PM2.5 Serious SIP
NV JARB1 10
Kennecott
Utah Copper
LLC- Power
Plant Lab Tailings Impoundment
UT 2,151.9 304,126.8 7.1 5,105.3
(1.4%) YES NO
Power
plant
closed in 2020
AZ GRCA2 10 PacifiCorp- Hunter Power
Plant
UT 3,498.2 363,743.3 9.6 2,321.3 (0.6%) YES YES

7.A.4 Other Sources
The foregoing Q/d analysis, secondary screening, and WEP analysis sections were used to help
identify point sources with potential impacts at Utah and non-Utah CIAs. However, the emissions
inventories detailed in section 5.A and the WRAP photochemical source apportionment results
provided in section 6.A suggest that non-point sources in Utah may also impact visibility in CIAs.
This section discusses the potential impacts of and state of emissions controls for non-point sources
in Utah.
Oil and Gas
Utah oil and gas sources are spread over a very large area making a traditional Q/d analysis
problematic. Furthermore, in light of updated inventory findings discussed below, UDAQ does
not consider the WRAP oil and gas inventories to be adequate for any type of Q/d emissions
analysis, derived or otherwise. That said, UDAQ acknowledges that oil and gas sector
emissions may affect visibility in CIAs.
Most of Utah’s oil and gas sector emissions occur in the Uinta Basin (UB), where considerable
work has already been done to address this sector’s contribution to wintertime ozone pollution.
The UB, located in northeast Utah, contains the majority of oil and gas extraction in Utah. The
UB has been found to have high levels of ozone during the winter months. This phenomenon is
associated with the geological basin, cold temperature inversion, and snow cover albedo in the
presence of VOCs and NOx. The majority of emissions for the ozone precursors of VOC and
NOx come primarily from the oil and gas exploration and production in the area, not other urban
or mobile sources. Since the discovery of these high ozone emissions, Utah has acted to control
the oil and gas sources in the UB and the rest of the state. However, the jurisdictional
complexity of the UB has led to inconsistency between state-controlled sources and EPA-
controlled sources on Indian Country. Emission inventories show that about 80% of the
emissions are under EPA regulatory control. The 2017 oil and gas emission inventory compared

121
to the total emission inventory for the UB accounts for about 97% of the total VOC emissions
and 68% of the total NOx emissions. The 2017 oil and gas emission inventory showed that 80%
of emissions in the UB result from areas under EPA control. Therefore, the state of Utah can
only address about 20% of the ozone-forming precursors VOC and NOx and cannot address air
quality issues on their own in the UB. Over the past several years, UDAQ has proposed and
adopted a series of statewide rules specific to oil and gas operations found in Utah’s state
administrative rules R301-500 to 511. Though these rules have been focused on controlling
VOC emissions, there is also a state-specific rule for natural gas-powered engines associated
with oil and gas production. Since the rule was put in place in 2018, several sources have
provided engine stack test data that have led UDAQ, EPA, and the Tribes to initiate further
research and compliance studies on engines in the Basin, with a focus on two-stroke smaller
horsepower engines that power pump jacks associated with oil-producing wells. The data
collected have indicated lower values for NOx emissions than what was reported in the 2017 oil
and gas emission inventory for these engines, yet much higher emissions of VOCs. UDAQ will
be evaluating this data and will be evaluating future rulemaking for engines associated with oil
and gas operations that would be statewide. EPA did follow UDAQ’s lead and has proposed the
Uintah and Ouray Federal Implementation Plan that is similar to Utah’s oil and gas rules, and
will bring some regulatory consistency to the area. The UDAQ will continue to coordinate with
EPA and the Tribe to encourage that rules are consistent across all regulatory jurisdictions, but
ultimately any controls under EPA regulatory jurisdiction will be determined by EPA and the
Tribe136.
Mobile
As identified in section 6.A above, mobile source emissions are a leading Utah source for nitrate
impacts at all Utah CIAs and in some neighboring states, namely Colorado, Idaho, and
Wyoming. Under Section 209 of the Clean Air Act, states are largely preempted from setting
standards for on-road and non-road mobile sources. Fortunately, federal emission standards for
on-road vehicles and engines as well as non-road equipment are projected to result in dramatic
reductions in NOx and PM emissions in Utah over the second planning period for regional haze.
To help guarantee these emissions reductions, the State of Utah has worked with the petroleum
refiners that supply the Utah market to ensure that suppliers produce gasoline that meets the
Tier 3 sulfur requirement of 30 ppm and not just comply using credits. In addition, Utah has
taken measures as part of other air quality programs to ensure that mobile source emissions are
well-controlled. For example, Utah has vehicle inspection and maintenance programs in place in
Utah, Salt Lake, Davis, Weber, and Cache counties, which accounted for 79.3% of the state’s
population in 2021i and 60.1% of total statewide on-road mobile source OTB2028a2 emissions.
These programs also include diesel vehicle inspections which, while not creditable in Utah's
various SIP revisions, help reduce NOx emissions that contribute to nitrate formation and CIA
impacts.

136 Please refer to sections 5.B and 9.C.2, response 24 for additional information concerning Utah’s area sources.

122
Remaining Anthropogenic
The remaining anthropogenic category of the WRAP photochemical analysis represents non-oil
and gas area source emissions, and specifically includes fugitive dust, agriculture, agricultural
fire, residential wood combustion, and all remaining nonpoint sources (e.g., residential and
commercial stationary source fuel combustion). As shown in section 6.A, the remaining
anthropogenic impacts are relatively small for Utah and non-Utah CIAs. That said, these
sources are relatively well-controlled as a result of rulemaking associated with other air quality
programs in Utah (e.g., the PM2.5 SIP BACM review and resulting controls). For example, Utah
restricts residential wood burning on so-called mandatory action days when conditions are ripe
for secondary formation of particulates. Utah has also adopted an ultra-low NOx water heater
rule that applies statewide and, when fully implemented, will result in a 75% reduction in NOx
emissions from residential and commercial water heating-related natural gas stationary source
fuel combustion. Additional Utah area source rules to reduce NOx and/or PM emissions include
those governing hydronic heaters, fugitive dust, and pilot lights.
7.A.5 Environmental Justice Considerations
Environmental Justice (EJ) is the fair treatment and meaningful involvement of all people
regardless of race, color, national origin, or income, with respect to the development,
implementation, and enforcement of environmental laws, regulations, and policies137. Absent
further guidance from EPA, UDAQ believes the consideration of EJ is best used in the
screening process to ensure sources within disproportionately affected areas are included in the
four-factor analysis process. UDAQ has used the EJScreen (version 2.0) tool developed by EPA
to analyze the environmental justice indices surrounding the sources selected to conduct four-
factor analyses. EJScreen138. For the 10 sources originally screened in this implementation
period, UDAQ reviewed all pollution and sources as well as socioeconomic indicators (a total of
19 indices) as percentiles calculated by comparing data from census blocks within the state of
Utah. UDAQ notes that the RH program does not have the authority to control the following
indexes included in this analysis: lead paint, superfund sites, wastewater discharge, RMP
facilities, hazardous waste, or underground storage tanks. Percentiles for all indexes were
generated for each source’s location centered within a 20-mile buffer radius. UDAQ recorded all
indexes in the 80th percentiles and above at the state level for the screened sources and offers
the following information used to consider the co-benefits of the reasonable progress
determinations included in this implementation period. UDAQ was not able to draw significant
conclusions from this analysis affecting the reasonable progress determinations made in this
SIP revision.
Table 38: Ash Grove Leamington Cement Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
137 More information on EJ can be found at: https://www.epa.gov/environmentaljustice
138 Technical information on EJScreen can be found at: https://www.epa.gov/sites/default/files/2021-04/documents/ejscreen_technical_document.pdf

123
Pollution and Sources
No percentiles above 80.
Socioeconomic Indicators
Under Age 5 12% 8% 85

Table 39: Graymont Western Cricket Mountain Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
Lead Paint (% Pre-1960 Housing) 0.3 0.17 81
Socioeconomic Indicators
No percentiles above 80.

Table 40: PacifiCorp Hunter Power Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
No percentiles above 80.
Socioeconomic Indicators
Over Age 64 16% 11% 81

Table 41: PacifiCorp Huntington Power Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
No percentiles above 80.
Socioeconomic Indicators
Unemployment Rate 6% 4% 84
Over Age 64 16% 11% 80

124

Table 42: Sunnyside Cogeneration Power Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
Lead Paint (% Pre-1960 Housing) 0.48 0.17 89
Socioeconomic Indicators
Low Income 41% 27% 80
Unemployment Rate 8% 4% 89
Over Age 64 17% 11% 83

Table 43: US Magnesium Rowley Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
2017 Air Toxics Respiratory HI 0.62 0.3 98
Wastewater Discharge (toxicity-weighted concentration/m distance)
11 13 88
Socioeconomic Indicators
No percentiles above 80.

Table 44: Intermountain Generation Station EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
Lead Paint (% Pre-1960 Housing) 0.29 0.17 81
Socioeconomic Indicators
No percentiles above 80.

125
Table 45: Kennecott Power Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
2017 Air Toxics Cancer Risk* (lifetime risk per million) 24 21 89
2017 Air Toxics Respiratory HI* 0.37 0.3 89
Superfund Proximity (site count/km distance) 0.34 0.18 88
Hazardous Waste Proximity (facility count/km distance) 1.5 0.89 80
Socioeconomic Indicators
No percentiles above 80.

Table 46: Kennecott Mine and Copperton Concentrator EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
2017 Air Toxics Cancer Risk* (lifetime risk per million) 24 21 88
2017 Air Toxics Respiratory HI* 0.36 0.3 89
Superfund Proximity (site count/km distance) 0.24 0.18 83
Socioeconomic Indicators
No percentiles above 80.

126
Table 47: Paradox Lisbon Plant EJScreen Findings
Selected Variables Value State
Avg. %tile
Pollution and Sources
Superfund Proximity (site count/km distance) 0.36 0.18 88
Socioeconomic Indicators
Over Age 64 18% 11% 86

7.B Four-Factor Analyses for Utah Sources139
Each source subject to submitting a four-factor analysis in this second planning period
submitted a report on the available control technologies for SO2 and NOx emission reductions
and the application of each technology to that facility. UDAQ notes that none of the sources
selected to complete a four-factor analysis are within any nonattainment areas under the
NAAQS. The information on available controls should include the analysis of the following four
factors when determining the possible emission reductions:
1. Factor 1 – The Costs of Compliance
2. Factor 2 – Time Necessary for Compliance
3. Factor 3 – Energy and Non-Air Quality Environmental Impacts of Compliance
4. Factor 4 – Remaining Useful Life of the Source140

Although not specifically required, the recommended approach was to follow a step-by-step
review of possible emission reduction options in a “top-down” fashion similar to EPA’s
guidelines for reviewing BART or Best Available Retrofit Technology (as found in 70 Fed. Reg.
39,104, 39,108-09 (July 6, 2005)). The steps involved are as follows:

1. Identify all available retrofit control technologies
2. Eliminate technically infeasible control technologies
3. Evaluate the control effectiveness of remaining control technologies
4. Evaluate impacts and document results

The process is inherently similar to that used in selecting BACT (Best Available Control
Technology) under the NSR/PSD (Title I) permitting program. UDAQ evaluated the submissions
from each source following the methodology outlined above. Where a particular submission may

139 40 CFR 51.308(f)(2)(i) 140 See 40 C.F.R. § 51.308(f)(2)(i).

127
have differed from the recommended process, UDAQ makes a note, and provides additional
explanation as necessary.
7.B.1 Control Equipment Descriptions
Available NOx Reduction Strategies and Technologies141
The sources selected to provide additional analyses consistent with the four factors listed
above-evaluated controls primarily for NOx emissions reductions. The following represents
proven, available NOx reduction strategies and technologies for four-factor sources. The
sources selected to provide additional analyses consistent with the four factors listed above
evaluated controls primarily for NOx emissions reductions.
Fuel switching. Fuel switching is the simplest and potentially the most economical way to reduce
NOx emissions. Fuel-bound NOx formation is most effectively reduced by switching to a fuel with
reduced nitrogen content. No. 6 fuel oil or another residual fuel, having relatively high nitrogen
content, can be replaced with No. 2 fuel oil, another distillate oil, or natural gas (which is
essentially nitrogen-free) to reduce NOx emissions.
Flue-gas recirculation (FGR). Flue gas recirculation involves extracting some of the flue gas
from the stack and recirculating it with the combustion air supplied to the burners. The process
reduces both the oxygen concentration at the burners and the temperature by diluting the
combustion air with flue gas. Reductions in NOx emissions ranging from 30 to 60% have been
achieved with this control technology.
Low NOx burners. Installation of burners especially designed to limit NOx formation can reduce
NOx emissions by up to 50%. Greater reduction efficiencies can be achieved by combining a
low-NOx burner with FGR—though not additive of each of the reduction efficiencies. Low-NOx
burners are designed to reduce the peak flame temperature by inducing recirculation zones,
staging combustion zones, and reducing local oxygen concentrations.
Derating. Some industrial boilers can be derated to produce a reduced quantity of steam or hot
water. Derating can be accomplished by reducing the firing rate or by installing a permanent
restriction, such as an orifice plate, in the fuel line.
Steam or water injection. Injecting a small amount of water or steam into the immediate vicinity
of the flame will lower the flame temperature and reduce the local oxygen concentration. The
result is to decrease the formation of thermal and fuel-bound NOx. Be advised that this process
generally lowers the combustion efficiency of the unit by 1 to 2%.
Staged combustion. Either air or fuel injection can be staged, creating either a fuel-rich zone
followed by an air-rich zone or an air-rich zone followed by a fuel-rich zone. Staged combustion
can be achieved by installing a low-NOx staged combustion burner, or the furnace can be

141 More information on emission control strategies can be found at: https://www.epa.gov/sites/default/files/2015-07/documents/chapter_5_emission_control_technologies.pdf

128
retrofitted for staged combustion. NOx reductions of more than 40% have been demonstrated
with staged combustion.
Fuel reburning. Staged combustion can be achieved through the process of fuel reburning by
creating a gas-reburning zone above the primary combustion zone. In the gas-reburning zone,
additional natural gas is injected, creating a fuel-rich region where hydrocarbon radicals react
with NOx to form molecular nitrogen. Field evaluations of natural gas reburning (NGR) on
several full-scale utility boilers have yielded NOx reductions ranging from 40 to 75%.
Reduced-oxygen concentration. Decreasing the excess air reduces the oxygen available in the
combustion zone and lengthens the flame, resulting in a reduced heat-release rate per unit
flame volume. NOx emissions diminish in an approximately linear fashion with decreasing
excess air. However, as excess air falls below a threshold value, combustion efficiency will
decrease due to incomplete mixing, and CO emissions will increase. The optimum excess-air
value must be determined experimentally and will depend on the fuel and the combustion-
system design. A feedback control system can be installed to monitor oxygen or combustibles
levels in the flue gas and to adjust the combustion-air flow rate until the desired target is
reached. Such a system can reduce NOx emissions by up to 50%.
Selective catalytic reduction (SCR). SCR is a post-formation NOx control technology that uses a
catalyst to facilitate a chemical reaction between NOx and ammonia to produce nitrogen and
water. An ammonia/air or ammonia/steam mixture is injected into the exhaust gas, which then
passes through the catalyst where NOx is reduced. To optimize the reaction, the temperature of
the exhaust gas must be in a certain range when it passes through the catalyst bed. Typically,
removal efficiencies greater than 80% can be achieved, regardless of the combustion process
or fuel type used. Among its disadvantages, SCR requires additional space for the catalyst and
reactor vessel, as well as an ammonia storage, distribution, and injection system. Also, a Risk
Management Plan (RMP) in compliance with Federal Accidental Release Prevention rules may
have to be prepared and submitted for ammonia storage. Precise control of ammonia injection
is critical. An inadequate amount of ammonia can result in unacceptable high NOx emission
rates, whereas excess ammonia can lead to ammonia "slip," or the venting of undesirable
ammonia to the atmosphere. As NH3 is both a visibility impairing air pollutant and a wastewater
regulated pollutant, air emissions and water discharges can be impacted. Excess ammonia in
the presence of other pollutants still remaining in the flue gas can also form species such as
ammonium-sulfate which can create visible plumes downwind of the stack discharge.
Selective non-catalytic reduction (SNCR). Selective non-catalytic NOx reduction involves
injection of a reducing agent—ammonia or urea—into the flue gas. The optimum injection
temperature when using ammonia is 1850ºF, at which temperature 60% NOx removal can be
approached. The optimum temperature range is wider when using urea. Below the optimum
temperature range, ammonia forms, and above, NOx emissions actually increase. The success
of NOx removal depends not only on the injection temperature but also on the ability of the agent
to mix sufficiently with flue gas.

129
Available SO₂ Reduction Strategies and Technologies142
The following represents proven, available SO₂ reduction strategies and technologies for four-
factor sources.
Choice of Fuel. Since sulfur emissions are proportional to the sulfur content of the fuel, an
effective means of reducing SO₂ emissions is to burn low-sulfur fuel such as natural gas, low-
sulfur oil, or low-sulfur coal. Natural gas has the added advantage of emitting no PM when
burned.
Sorbent Injection. Sorbent injection involves adding an alkali compound to the combustion
gases for reaction with the SO₂. Typical calcium sorbents include lime and variants of lime.
Sodium-based compounds are also used. Dry sorbent injection systems are simple systems,
and generally require a sorbent storage tank, feeding mechanism, transfer line and blower, and
injection device. Sorbent injection processes remove 30–60% of sulfur oxide emissions;
however, if the sorbent is hydrated lime, then 80% or greater removal can be achieved. These
systems are commonly called lime spray dryers.
Flue Gas Desulfurization (FGD). FGD may be carried out using either of the two basic systems:
regenerable or throwaway. Both methods may include wet or dry processes. Currently, more
than 90% of utility FGD systems use a wet throwaway system process. Throwaway systems
use inexpensive scrubbing mediums that are cheaper to replace than to regenerate.
Regenerable systems use expensive sorbents that are recovered by stripping sulfur oxides from
the scrubbing medium. These produce useful by-products, including sulfur, sulfuric acid, and
gypsum. Regenerable FGDs generally have higher capital costs than throwaway systems but
lower waste disposal requirements and costs.
FGD processes can be wet or dry. In wet FGD processes, flue gases are scrubbed in a liquid or
liquid/solid slurry of lime or limestone. Wet processes are highly efficient and can achieve SO₂
removal of 90% or more. With dry scrubbing, solid sorbents capture the sulfur oxides. Dry
systems have 70–90% sulfur oxide removal efficiencies and often have lower capital and
operating costs, lower energy and water requirements, and lower maintenance requirements, in
addition to which there is no need to handle sludge. Examples of FGD include:
Dual Alkali Wet Scrubber. Dual-alkali scrubbers use a sodium-based alkali solution to remove
SO₂ from the combustion exhaust gas. The process uses both sodium-based and calcium-
based compounds. The sodium-based reagents absorb SO₂ from the exhaust gas, and the
calcium-based solution (lime or limestone) regenerates the spent liquor. Calcium sulfites and
sulfates are precipitated and discarded as sludge, and the regenerated sodium solution is
returned to the absorber loop.
Spray Dry Absorber. The typical spray dry absorber (SDA) uses lime slurry and water injected
into a tower to remove SO₂ from the combustion gases. The towers must be designed to
provide adequate contact and residence time between the exhaust gas and the slurry to

142 More information on emission control strategies can be found at: https://www.epa.gov/sites/default/files/2015-07/documents/chapter_5_emission_control_technologies.pdf

130
produce a relatively dry by-product. The process equipment associated with an SDA typically
includes an alkaline storage tank, mixing and feed tanks, atomizer, spray chamber, particulate
control device, and recycle system. The recycle system collects solid reaction products and
recycles them back to the spray dryer feed system to reduce alkaline sorbent use. SDAs are the
commonly used dry scrubbing method in large industrial and utility boiler applications. SDAs
have demonstrated the ability to achieve greater than 95% SO₂ reduction.
Circulating Dry Scrubber. The circulating dry scrubber (CDS) uses a circulating fluidized bed of
dry hydrated lime reagent to remove SO₂. Flue gas passes through a venturi at the base of a
vertical reactor tower and is humidified by a water mist. The humidified flue gas then enters a
fluidized bed of powdered hydrated lime where SO₂ is removed. The dry by-product produced
by this system is routed with the flue gas to the particulate removal system.
Hydrated Ash Reinjection. The hydrated ash reinjection (HAR) process is a modified dry FGD
process developed to increase utilization of unreacted lime (CaO) in the CFB ash and any free
lime left from the furnace burning process. The hydrated ash reinjection process will further
reduce the SO₂ concentration in the flue gas. The actual design of a hydrated ash reinjection
system is vendor specific. In a hydrated ash reinjection system, a portion of the collected ash
and lime is hydrated and re-introduced into a reaction vessel located ahead of the fabric filter
inlet. In conventional boiler applications, additional lime may be added to the ash to increase the
mixture’s alkalinity. For CFB boiler applications, sufficient residual CaO is available in the ash
and additional lime is not required.

7.B.2 Existing Controls on Active EGUs
The following tables summarize existing controls on all active coal and gas facilities in Utah. For
more detailed information on control compliance schedules from the first implementation period
and retirement dates, refer to section 3.A.1.
Table 48: Existing controls on active coal units in Utah
Facility Unit Operator SO2 Control(s) NOx Control(s)
Bonanza 43101 Deseret Generation &
Transmission
Wet
Limestone
Low NOx Burner Technology (Dry
Bottom only)
Hunter 1 PacifiCorp Energy
Generation
Wet Lime
FGD
Low NOx Burner Technology w/
Closed-coupled OFA
Hunter 2 PacifiCorp Energy
Generation
Wet Lime
FGD
Low NOx Burner Technology w/
Separated OFA
Hunter 3 PacifiCorp Energy
Generation
Wet Lime
FGD
Low NOx Burner Technology w/
Overfire Air
Huntington 1 PacifiCorp Energy
Generation
Wet Lime
FGD
Low NOx Burner Technology w/
Closed-coupled OFA
Huntington 2 PacifiCorp Energy
Generation
Wet Lime
FGD
Low NOx Burner Technology w/
Separated OFA

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Table 49: Existing controls on active gas units in Utah
Facility Name Unit
ID
Owner NOx Control(s)
Lake Side Power
Plant CT03 PacifiCorp Energy Generation Selective Catalytic Reduction
Lake Side Power
Plant
CT04 PacifiCorp Energy Generation Selective Catalytic Reduction
Lake Side Power
Plant
CT02 PacifiCorp Energy Generation Selective Catalytic Reduction
Currant Creek Power
Project CTG1B PacifiCorp Energy Generation Selective Catalytic Reduction
Currant Creek Power
Project
CTG1A PacifiCorp Energy Generation Selective Catalytic Reduction
Nebo Power Station U1 Utah Associated Municipal
Power Systems
Dry Low NOx Burners
Selective Catalytic Reduction
Millcreek Power MC-1 City of St. George Dry Low NOx Burners
Millcreek Power MC-2 City of St. George Dry Low NOx Burners
Selective Catalytic Reduction
Gadsby 4 PacifiCorp Energy Generation Water Injection
Selective Catalytic Reduction
West Valley Power
Plant
U4 Utah Municipal Power Agency Water Injection
Selective Catalytic Reduction
West Valley Power
Plant
U2 Utah Municipal Power Agency Water Injection
Selective Catalytic Reduction
West Valley Power
Plant U3 Utah Municipal Power Agency Water Injection
Selective Catalytic Reduction
Gadsby 5 PacifiCorp Energy Generation Water Injection
Selective Catalytic Reduction
West Valley Power
Plant
U5 Utah Municipal Power Agency Water Injection
Selective Catalytic Reduction
Gadsby 6 PacifiCorp Energy Generation Water Injection
Selective Catalytic Reduction
West Valley Power
Plant
U1 Utah Municipal Power Agency Water Injection
Selective Catalytic Reduction
Gadsby 2 PacifiCorp Energy Generation Low NOx Burner Technology (Dry
Bottom only)
Gadsby 1 PacifiCorp Energy Generation Low NOx Burner Technology (Dry
Bottom only)

7.C Source Consultation
UDAQ has kept regular contact with the sources selected to perform four-factor analyses on
their units and offered guidance on developing control cost estimates using EPA’s Air Pollution

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Control Cost Manual143 and facility-specific data representing current emissions, projected future
emissions, and potential control scenarios. UDAQ received and reviewed each source’s initial
four-factor analysis and sent an evaluation to each source with recommendations, requests for
additional information, and explanations of any issues with calculations or assumptions made by
sources in calculations. Refer to Chapter 9 to review detailed information on UDAQ’s meetings
with the sources. The following sections contain each source’s four-factor analysis, UDAQ’s
evaluation of their initial submittal, and the sources resulting responses and corrections.144
7.C.1 Ash Grove Cement Company- Leamington Cement Plant Four-Factor
Analysis Summary and Evaluation145
Facility Identification
Name: Ash Grove Cement Company
Address: Hwy. 132, Leamington, Utah 84638
Owner/Operator: Ash Grove Cement Company
UTM coordinates: 4,379,850 m Northing, 397,000 m Easting, Zone 12
Facility Process Summary
Ash Grove Cement Company (Ash Grove) operates the Leamington Cement Plant. This plant
has been in operation since 1981. At the Leamington cement plant, cement is produced when
inorganic raw materials, primarily limestone (quarried on site), are correctly proportioned,
ground and mixed, and then fed into a rotating kiln. The kiln alters the materials and recombines
them into small stones called cement clinker. The clinker is cooled and ground with gypsum and
additional limestone into a fine powdered cement. The final product is stored on site for later
shipping. The major sources of air emissions are from the combustion of fuels for the kiln
operation, from the kiln, and from the clinker cooling process.
Facility Criteria Air Pollutant Emissions Sources
This source consists of the following emission unit:
• Unit Designation: Kiln 1
Kiln 1 has the following emission controls installed:
SNCR for NOx control; NOx, CO, Total Hydrocarbons (VOC), and Oxygen (O2) CEMS on
main stack; Mercury (Hg) CEMS or integrated sorbent trap monitoring system on main
stack; TSP (PM) Continuous Parametric Monitoring System (CPMS) on main kiln and
clinker cooler stack.

143 The EPA Air Pollution Control Cost Manual can be found in at: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-reports-and-guidance-air-pollution#cost%20manual
144 Each source’s full four-factor analysis submittals, UDAQ’s four-factor analysis evaluations, and evaluation responses sent by sources can be found at https://deq.utah.gov/air-quality/regional-haze-in-utah in the ”Current Regional Haze Planning” section. 145 Ash Grove’s full four-factor analysis submittal can be found in appendix C.1.A or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2020-008930.pdf

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Facility Current Potential to Emit
The current PTE values for Ash Grove, as established by the most recent NSR permit issued to
the source (DAQE-AN103030029-19) are as follows:
Table 50: Ash Grove Leamington Cement Plant Current Potential to Emit
Pollutant Potential to Emit (tons/year)
SO2 192.50 NOx 1347.20
Ash Grove’s Four-Factor Analysis Conclusion
Ash Grove believes that reasonable progress compliant controls are already in place. Ash
Grove’s actual NOx emission level of 1198 tpy is adequate and the Leamington facility does not
propose any change to their current limit of 2.8 lbs./ton clinker on a 30-day rolling average
basis.
UDAQ Four-Factor Analysis Evaluation146
Although some additional information should be supplied by the source regarding SNCR
efficiency, the Leamington Cement Plant appears to be adequately controlled at this time for
purposes of Second Planning Period.
Ash Grove’s Evaluation Response147
AGC provided the actual SO2 emissions rates for the Leamington Plant’s main kiln which are
lower than their PTE. Lowering SO2 emissions further would require the addition of aluminum
and iron which are not readily available to Ash Grove. The efficiency of the Leamington Plant’s
SNCR system was designed to be able to achieve 2.8 lb. NOx/ton clinker on a 30-day rolling
average basis, and the plant typically operates in the 2.5-2.6 lb. NOx/ton clinker range. The
system uses an Aqua NH3 solution as a chemical reagent. Adding additional solution is not
feasible as the plant already requires reagent delivery by truck every two days and additional
reagent would require the installation of larger nozzles and/or larger storage tanks. The system
is also near solution saturation as it currently runs, and additional solution may not increase
control efficiency, but rather cause NH3 to slip from the system and be emitted from the stack.
Thus, Ash Grove believes that the current and NOx limits reflect a reasonable level of safety
margin relative to actual emission rates.

146 UDAQs full evaluation of Ash Grove’s four-factor analysis submittal can be found in appendix C.1.A or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/DAQ-2021-009636.pdf
147 Ash Grove’s full evaluation response can be found in appendix C.1.B or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2021-011724.pdf

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UDAQ Response Conclusion
UDAQ accepts the additional information provided by Ash Grove on their emission rate
efficiency and agrees that their units are well controlled. Refer to section 8.D.1. for UDAQ’s
reasonable progress determination for Ash Grove.
7.C.2 Graymont Western US Incorporated- Cricket Mountain Plant Four-Factor
Analysis Summary and Evaluation148
Facility Identification
Name: Cricket Mountain Plant
Address: 32 Miles Southwest of Delta, Utah; Highway 257
Owner/Operator: Graymont Western US Incorporated
UTM coordinates: 4,311,010 m Northing, 343,100 m Easting, Zone 12
Facility Process Summary
Graymont Western US Inc. (Graymont) operates the Cricket Mountain Lime Plant in Millard
County. The Cricket Mountain Lime Plant consists of quarries and a lime processing plant,
which includes five (5) rotary lime kilns (Kilns 1 through 5). The rotary kilns are used to convert
crushed limestone ore into quicklime. The products produced for resale are lime, limestone, and
kiln dust. The kilns operate on pet coke and coal. Sources of emissions at this source include
mining, limestone processing, rotary lime kilns, post-kiln lime handling, and truck & loadout
facilities.
Facility Criteria Air Pollutant Emissions Sources
The source consists of the following emission units:
• Rotary Lime Kiln #1 rated at 600 tons of lime per 24-hour period with a preheater and
baghouse emissions control system (D-85) rated at an exhaust gas flow rate 54,000
scfm and an Air to Cloth (A/C) ratio of 3.26:1. NESHAP Applicability: 40 CFR 63 Subpart
AAAAA
• Rotary Lime Kiln #2 rated at 600 tons of lime per 24-hour period with a preheater,
cyclone and baghouse emissions control system (D-275) rated at an exhaust gas flow
rate of 48,000 scfm and an A/C ratio of 2.9:1. NESHAP Applicability: 40 CFR 63 Subpart
AAAAA
• Rotary Lime Kiln #3 rated at 840 tons of lime per 24-hour period with a preheater,
cyclone and baghouse emissions control system (D-375) rated at an exhaust gas flow
rate of 55,000 scfm and a A/C ratio of 2.49:1. NESHAP Applicability: 40 CFR 63 Subpart
AAAAA
• Rotary Lime Kiln #4 rated at 1266 tons of lime per 24-hour period with a preheater,
cyclone and baghouse emissions control system (D-485) rated at an exhaust gas flow
148 Graymont’s full four-factor analysis submittal for the Cricket Mountain Plant can be found in appendix C.2.A or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2020-008924.pdf

135
rate of 100,000 scfm and an A/C ratio of 5:1. NESHAP Applicability: 40 CFR 63 Subpart
AAAAA
• Rotary Lime Kiln #5 rated at 1400 tons of lime per 24-hour period with a preheater and
baghouse emissions control system (D-585) rated at an exhaust gas flow rate of
103,000 scfm and an A/C ratio of 3.5:1. NESHAP Applicability: 40 CFR 63 Subpart
AAAAA
Facility Current Potential to Emit
The current PTE values for Source, as established by the most recent NSR permit issued to the
source (DAQE-AN103130044-21) are as follows:
Table 51: Current Potential to Emit - Graymont
Pollutant Potential to Emit (tons/year)
SO2 760.29 NOx 3,883.85
Graymont Four-Factor Analysis Conclusion
The facility currently uses low NOx burners in its five kilns to minimize NOx emissions. The use of
low NOx burners is a commonly applied technology in current BACT determinations for new
rotary preheater lime kilns today. The application of SCR has never been attempted on a lime
kiln. SNCR has only one RBLC entry documenting implementation on a lime kiln. The use of
these controls does not represent a cost-effective control technology given the limited expected
improvements to NOx emission rates, high uncertainty of successful implementation, high capital
investment, and high cost per ton NOx removed. Therefore, the emissions for the 2028 on-the-
books modeling scenario are expected to be the same as those used in the “control scenario”
for the Graymont Cricket Mountain facility.
UDAQ Four-Factor Analysis Evaluation149
UDAQ disagrees with several points of Graymont’s analysis. Aside from the lack of SO2
analysis, UDAQ found several errors in the Graymont NOx analysis which must be corrected.
1. Two additional control technologies were identified by DAQ as potential ways of
reducing NOx emissions: fuel switching and alternative production techniques. The
Graymont Cricket Mountain Plant is fueled by coal – alternative fuels should be
investigated. Secondly, the kilns at this facility are long horizontal rotary
preheater/precalciner style kilns. Other types of kiln such as vertical lime kilns should
also be investigated.
2. Graymont has claimed that SNCR is not technically feasible for installation on rotary
preheater kilns. However, that is not accurate as there have been other SNCR retrofits
149 UDAQ’s full evaluation of Graymont’s four-factor analysis submittal can be found in appendix C.2.A or
at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/DAQ-2021-009634.pdf

136
done at preheater rotary lime kilns. Those lime kilns include the Lhoist North America
O’Neal Plant in Alabama, the Unimin Corporation lime plant in Calera, Alabama, and the
rotary lime kilns of the Lhoist North America Nelson Lime Plant in Arizona, as well as the
Mississippi Lime Company plant in Illinois (specifically mentioned by Graymont as the
only source listed on the RBLC).
3. A NOx reduction of 20% for SNCR is too low for use in the analysis, given that Graymont
itself quoted the average NOx removal at cement kilns with SNCR was 40%, with the
range of NOx removal efficiency between 35%-58%. At a minimum, Graymont should
have evaluated the use of SNCR at 35% removal efficiency rather than merely 20%.
4. The current bank prime rate is 3.25% and not 4.75% as stated by Graymont. The
economic analysis must be recalculated using the correct interest rate.
5. The cost of an air preheater was included – which appears to be a mistake based on an
error (a typographical misprint) found in EPA’s SNCR control cost spreadsheets. In one
place the spreadsheet uses a value of 3.0 lb. SO2/ton coal while in another the value is
erroneously listed as 0.3 lb. SO2/ton coal. Graymont apparently included the cost of the
air preheater when burning coal which does not require such equipment as part of an
SNCR installation.
Although DAQ has not fully evaluated these deficiencies, it has analyzed how Graymont’s cost
evaluation would change if the correct bank prime interest rate were used, if the cost of the air
preheater were not included, and if the removal efficiency of the SNCR were increased to a
minimum of 35%. To reflect the increased cost of a more efficient SNCR than that proposed by
Graymont, the direct annual costs (energy, cost of ammonia, etc.) were doubled as a
conservative estimate. The results of these changes are as follows:
Table 52: Estimated Direct Annual Costs (doubled) Graymont
Kiln Capital Costs ($)
Direct Annual Costs ($)
Total Annual Costs ($)
NOx Removed (tons)
cost-effectiveness ($/ton) 1 $3,616,821 $180,574 $328,281 30 $10,943 2 $3,878,230 $186,204 $343,367 22 $15,608 3 $4,321,811 $208,776 $377,952 18 $20,997
4 $5,285,030 $258,458 $461,703 38 $12,150
5 $5,031,753 $289,720 $485,174 122 $ 3,977

Based on these revised results, the application of SNCR may appear to be feasible, at least for
Kiln #5. Additional analysis should be provided by the source to further detail these deficiencies.

137
Graymont’s Evaluation Response150
In order to obtain a more accurate capital and operating cost estimate, Graymont commissioned
a Class 4 engineering cost estimate to ascertain capital and operating costs associated with
installing and operating Selective Non-Catalytic Reduction (SNCR) Nitrogen Oxides (NOx)
abatement systems on Cricket Mountain kilns. The cost estimations performed by a third-party
engineer indicate that the total capital cost for installation of SNCR systems at Cricket Mountain
exceeds $6.9 MMUSD and operating costs exceed $1.4 MMUSD annually, resulting in a cost of
$17,561 per ton of NOx removed based upon a 20% removal efficiency. A factor of 20% was
utilized based on the temperature and residence time limitations of the SNCR reaction zone for
each Cricket Mountain kiln combined with the Low NOx baseline concentration already achieved
through the use of Low NOx Burners (LNB)151.
Graymont also compared the current NOx emissions from Cricket Mountain to publicly available
information for the Lhoist North America (LNA) rotary preheater kilns which utilize SCNR.
Graymont offered the following observations:
• The existing LNBs at Cricket Mountain have effectively reduced the NOx emission
intensity to a level more than three times less than the pre-control NOx intensity of LNA’s
Nelson Plant which utilizes SNCR.
• Any additive efficiency that might be gained from Cricket Mountain’s use of SNCR would
be marginal, at best, as SNCR NOx removal efficiency is highly dependent upon the inlet
NOx concentration, reaction zone temperature and residence time, all of these factors
reduce the anticipated efficiency that can reasonably be assumed for the Cricket
Mountain Kilns.
• The LNA SNCR technology for rotary lime kilns is proprietary and not unconditionally
commercially available to Graymont. The technology appears to be patented, adding to
its cost and the uncertainty as to its technical feasibility.
• SNCR addition at Cricket Mountain would have unintended negative environmental
impacts and visibility disbenefits, including the generation of condensable particulate, an
identified regional haze primary pollutant.
• The Cricket Mountain facility operates 5 rotary preheat lime kilns, each of which are
substantially different technology than mid-fired cement kilns (more conducive reaction
zone temperatures, higher NOx concentrations, and longer residence times). As such, it
is not appropriate to draw direct comparisons with application of SNCR between cement
kilns and lime kilns as referenced in your letter.
Based on Graymont’s findings, requiring the installation of SNCR at Cricket Mountain would be
unreasonable because it would be infeasible, unnecessary and counterproductive to making

150 Graymont’s full evaluation response can be found in appendix C.2.C or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2021-
011722.pdf 151 Lhoist North America indicated in a November 2020 4-factor analysis that Kilns 1, 2 & 3 would be
capable of a maximum NOx control of 20%.

138
reasonable progress towards the goal of preventing future, and remedying any existing,
anthropogenic impairment of visibility in mandatory Class I Federal areas in the context of
Utah’s pending Round 2 Regional Haze State Implementation Plan (RH SIP). Cricket
Mountain’s successful implementation of LNBs effectively controls NOx at the point of generation
in kilns.
These NOx rates are sufficient for inclusion in the UDAQ RH SIP since they are already some of
the lowest achieved in the industry and far exceed what has been deemed BART at other kilns
(such as the SNCR controlled kilns at the LNA Nelson Facility).
UDAQ Response Conclusion
UDAQ accepts Graymont’s four-factor analysis amendments and additional justification on the
unfeasibility of additional controls on the Cricket Mountain Facility’s kilns. Refer to section 8.D.2
for UDAQ’s controls for reasonable progress determination.
7.C.3 PacifiCorp's Hunter and Huntington Power Plants Four-Factor Analysis
Summary and Evaluation152
Facility Identification
Name: Hunter Power Plant
Address: P.O. Box 569, Castle Dale, UT 84513
Owner/Operator: PacifiCorp
UTM coordinates: 497,800 m Easting, 4,335,800 m Northing, UTM Zone 12
Facility Process Summary
The Hunter Power Plant is located near Castle Dale in Emery County. The plant is classified as
a PSD source and is a Phase II Acid Rain source. The source is PSD major for SO₂, NOx, PM10,
and CO and also major for VOC and HAPs. The source is subject to the provisions of 40 CFR
52.21(aa); 40 CFR 60 Subparts A, D, Da, Y, and HHHH; and 40 CFR 63 Subparts A, ZZZZ, and
UUUUU.
Facility Criteria Air Pollutant Emissions Sources
The source consists of the following emission units:
• Steam Generating Unit #1 - Nominal 480 MW gross capacity dry bottom, tangentially-
fired boiler fired on subbituminous and bituminous coal using distillate fuel oil during
start-up and flame stabilization. System is equipped with a low-NOx burner/overfire air
system (OFA), baghouse, and SO₂ Wet FGD (WFGD) scrubber with no scrubber
bypass.
• Steam Generating Unit #2 - Nominal 480 MW gross capacity dry bottom, tangentially-
fired boiler fired on subbituminous and bituminous coal using distillate fuel oil during
152 PacifiCorp’s full four-factor analysis submittal for the Hunter and Huntington power plants can be found in appendix C.3.A or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2020-008926.pdf

139
start-up and flame stabilization. System is equipped with a low-NOx burner/OFA,
baghouse, and SO₂ WFGD scrubber with no scrubber bypass.
• Steam Generating Unit #3 - Nominal 495 MW gross capacity dry bottom, wall-fired boiler
fired on subbituminous and bituminous coal using distillate fuel oil during start-up and
flame stabilization. System is equipped with baghouse, a low NOx burner/OFA, and SO₂
FGD scrubber.
Facility Current Potential to Emit
The current PTE values for the Hunter Power Plant, as established by the most recent NSR
permit issued to the source (DAQE-AN102370028-18) are as follows:
Table 53: Hunter Current Potential to Emit
Pollutant Potential to Emit (Tons/Year)
SO₂ 5,537.5
NOx 15,095

PacifiCorp Four Factor Analysis Conclusion
When balanced for Hunter Units 1, 2, and 3 the four factors demonstrate that the RPEL is the
best option for making reasonable progress during the second planning period. First, installation
of SNCR or SCR are not cost effective (even with the skewed depreciable life assumptions) and
would result in hundreds of millions of dollars in costs for PacifiCorp customers, and tens of
millions in additional operating costs for PacifiCorp. Implementation of the Hunter RPEL would
not result in any significant additional costs for customers and would result in minimal additional
operating costs. Second, installation of SNCR or SCR would involve long-lead times for
permitting, design, procurement, and installation before reductions and compliance can be
achieved. The Hunter RPEL requires negligible time for compliance, and could be implemented
as soon as the State’s implementation plan is finalized and achieves federal approval. Third,
SCR requires more energy to implement, and SNCR and SCR result in additional non-air
environmental impacts over the Hunter RPEL. As documented, the Hunter RPEL has less
potential consumption of natural resources, less GHG emissions, and less generation of CCR.
Fourth and finally, a requirement to install SCR or SNCR on Hunter Units 1, 2, and 3 would
create uncertainty about the facility’s remaining useful life. Many coal-fired power plants across
the country have been forced to shut down due to the increased costs associated with SNCR
and SCR. Implementing the Hunter RPEL would not be expected to either increase or decrease
the remaining useful life of the facility. Based on this analysis, Utah should determine that the
Hunter RPEL is the best option for achieving reasonable progress during the second planning
period.
The Utah Division of Air Quality has indicated that photochemical grid modeling and analysis of
visibility impacts will be performed by WRAP as part of the state’s second planning period
analysis. PacifiCorp anticipates that visibility modeling which incorporates the Hunter RPEL
(and is compared to modeling of Hunter’s current, permitted potential to emit) would assist the

140
state in demonstrating reasonable progress at the CIAs impacted by emissions from the Hunter
plant, supporting a conclusion that no additional installation of retrofit pollution control
equipment is required at Hunter. However, if the State were to determine that the Hunter RPEL,
as proposed, would not contribute to reasonable progress, PacifiCorp respectfully requests that
the State propose an alternative RPEL (NOx +SO₂ limit) for Hunter (allowing time for PacifiCorp
to analyze the feasibility of the alternative RPEL proposal) as opposed to pursuing a
requirement to install SNCR or SCR retrofits. This reasonable progress analysis demonstrates
that implementing a RPEL is a better option than installing SNCR or SCR retrofits under each of
the four statutory factors.
UDAQ Four-Factor Analysis Evaluation153
At this time, UDAQ is unable to proceed with its review and requests additional information as follows:
1. The source needs to resubmit the Four-factor analysis correcting the errors mentioned
above. 2. Additional information must be provided regarding the infeasibility of SCR. a. This information can include additional details on economics as well as technical limitations. 3. Additional information must be provided regarding the infeasibility of SNCR. a. As with SCR, this information can include additional details on economics as well as technical limitations. 4. Supplemental details regarding the RPEL approach, including the selection of allowable
limits should be provided. The methodology used for setting the allowable limits should be discussed in detail. 5. Any other pertinent information PacifiCorp feels is warranted should also be provided in
order to assist UDAQ in the review process.
Huntington Power Plant
Facility Identification
Name: Huntington Power Plant
Address: P.O. Box 680, Huntington, UT 84528
Owner/Operator: PacifiCorp
UTM coordinates: 493,130 Easting 4,358,840 Northing, UTM Zone 12
Facility Process Summary
The PacifiCorp Huntington Power Plant is a coal-fired steam electric generating facility
consisting of two (2) boilers. Unit #1 is a 480 MW unit constructed in October 1973; Unit #2 is a
480 MW unit that commenced construction in April 1970. Bituminous and sub-bituminous coal is
the primary fuel source for the dry bottom, tangentially-fired boilers. Fuel oil is used to start up
the boilers from a cold start and for boiler flame stabilization. The Huntington Power Plant uses

153 UDAQ’s full four-factor analysis evaluation for the Hunter and Huntington power plants can be found in
appendix C.3.B or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-
haze/DAQ-2020-008926.pdf

141
low-NOx burners, separated overfire air system, SO₂ FGD scrubber system, and pulse jet fabric
filters for both units.
Facility Criteria Air Pollutant Emissions Sources
The source consists of the following emission units:
• Boiler Unit #1 – Nominal 480 MW gross capacity dry bottom, tangentially-fired utility
boiler fired on subbituminous and bituminous coal using fuel oil during startup and flame
stabilization. Equipped with a fabric filter baghouse, low NOx burners with overfire air
system, and a SO₂ FGD scrubber. NSPS Subpart D.
• Boiler Unit #2 – Nominal 480 MW gross capacity dry bottom tangentially-fired utility
boiler fired on subbituminous and bituminous coal using fuel oil during startup and flame
stabilization. Equipped with a fabric filter baghouse, low-NOx burners with overfire air
system, and a SO₂ FGD scrubber.
Facility Current Potential to Emit
The current PTE values for the Huntington Power Plant, as established by the most recent NSR
permit issued to the source (DAQE-AN102370028-18) are as follows:
Table 54: Current Potential to Emit: Huntington
Pollutant Potential to Emit (Tons/Year)
SO₂ 3,105 NOx 7,971

PacifiCorp Four Factor Analysis Conclusion
When balanced for Huntington Units 1 and 2, the four factors demonstrate that the RPEL is the
best option for making reasonable progress during the second planning period. First, installation
of SNCR or SCR are not cost effective (even with the skewed depreciable life assumptions) and
would result in hundreds of millions of dollars in costs for PacifiCorp customers, and tens of
millions in additional operating costs for PacifiCorp. Implementation of the Huntington RPEL
would not result in any significant additional costs for customers and would result in minimal
additional operating costs. Second, installation of SNCR or SCR would involve long-lead times
for permitting, design, procurement, and installation before reductions and compliance can be
achieved. The Huntington RPEL requires negligible time for compliance, and could be
implemented as soon as the State’s implementation plan is finalized and achieves federal
approval. Third, SCR requires more energy to implement, and SNCR and SCR result in
additional non-air environmental impacts over the Huntington RPEL. As documented, the
Huntington RPEL has less potential consumption of natural resources, less GHG emissions,
and less generation of CCR. Fourth and finally, a requirement to install SCR or SNCR on
Huntington Units 1 and 2 would create uncertainty about the facility’s remaining useful life. Many
coal-fired power plants across the country have been forced to shut down due to the increased
costs associated with SNCR and SCR. Implementing the Huntington RPEL would not be
expected to either increase or decrease the remaining useful life of the facility. Based on this

142
analysis, Utah should determine that the Huntington RPEL is the best option for achieving
reasonable progress during the second planning period.
The Utah Division of Air Quality has indicated that photochemical grid modeling and analysis of
visibility impacts will be performed by the Western Regional Air Partnership (“WRAP”) as part of
the state’s second planning period analysis. PacifiCorp anticipates that visibility modeling which
incorporates the Huntington RPEL (and is compared to modeling of Huntington’s current,
permitted potential to emit) would assist the state in demonstrating reasonable progress at the
CIAs impacted by emissions from the Huntington plant, supporting a conclusion that no
additional installation of retrofit pollution control equipment is required at Huntington. However, if
the State were to determine that the Huntington RPEL, as proposed, would not contribute to
reasonable progress, PacifiCorp respectfully requests that the State propose an alternative
RPEL (NOx +SO₂ limit) for Huntington (allowing time for PacifiCorp to analyze the feasibility of
the alternative RPEL proposal) as opposed to pursuing a requirement to install SNCR or SCR
retrofits. This reasonable progress analysis demonstrates that implementing a RPEL is a better
option than installing SNCR or SCR retrofits under each of the four statutory factors.
UDAQ’s Four Factor Analysis Conclusion
At this time, UDAQ is unable to proceed with its review and requests additional information as
follows:
1. The source needs to resubmit the Four-factor analysis correcting the errors mentioned above. 2. Additional information must be provided regarding the infeasibility of SCR. a. This information can include additional details on economics as well as technical limitations. 3. Additional information must be provided regarding the infeasibility of SNCR. a. As with SCR, this information can include additional details on economics as well
as technical limitations. 4. Supplemental details regarding the RPEL approach, including the selection of allowable limits should be provided. The methodology used for setting the allowable limits should
be discussed in detail. 5. Any other pertinent information PacifiCorp feels is warranted should also be provided in order to assist UDAQ in the review process.
PacifiCorp’s Four-Factor Analysis Evaluation Response for Hunter and Huntington154
PacifiCorp proposed that UDAQ make the following adjustments to obtain a more representative
cost effectiveness value for the installation of SNCR at the Hunter and Huntington plants:
• Utilize an SNCR NOx control efficiency of 20% for the Hunter and Huntington boilers, which is
expected to be achievable based on unit size and firing configuration;
154 PacifiCorp’s full evaluation response for the Hunter and Huntington Power Plants can be found in appendix C.3.C or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2021-011726.pdf

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• Utilize capital and O&M costs provided by S&L which are site specific and more accurate than
the generalized costs provided by the CCM model;
• Utilize PacifiCorp’s actual weighted average cost of capital of 7.303% as the interest rate in the
model instead of the 3.25% rate originally used by UDAQ;
• Utilize the current and accurate net MW generation rates and net unit heat rate provided in
Table 1155 to calculate boiler heat input; and lastly;
• Utilize the actual 2015-2019 average annual capacity factors in Table 3156 instead of the rates
included in Table 2, which are inaccurate.
PacifiCorp believed that use of the S&L capital and O&M cost data when combined with an
SNCR 20% control efficiency and 7.303% interest rate will provide an accurate representation of
unit-specific cost effectiveness. This is demonstrated by UDAQ’s and PacifiCorp’s SCR cost
effectiveness determinations which provide essentially equivalent dollar-per-ton values. The
following tables provide a summary of PacifiCorp’s revised SNCR cost effectiveness values for
the Hunter and Huntington plants applying these adjustments. The estimates are based on a
systemwide SNCR control efficiency of 20% and an interest rate of 7.303%. Note that the
provided values do not incorporate minor changes in annualized capital and O&M costs which
will occur when the April 9, 2020, S&L studies are updated to incorporate the current 7.303%
interest rate and use of the 20% SNCR NOx control efficiency versus the studies’ original use of
a 7% interest rate and anticipated SNCR-controlled permit limit emission rates.
Table 55: PacifiCorp Updated Hunter SNCR Cost Effectiveness
Cost Effectiveness Hunter 1 Hunter 2 Hunter 3
Baseline Heat Input (MMBtu/year) NOx Emissions Rate (lb/MMBtu) NOx Emissions (tons/year)

28,482,643 0.200 2,842

30,101,030 0.193 2,902

31,182,279 0.280 4,359
NOx Emissions w/ SNCR (20% efficiency) Controlled NOx Emissions Rate (lb/MMBtu) Controlled NOx Emissions (tons/year)
0.160
2,273
0.154
2,322
0.224
3,487
SNCR Annual NOx Removal (tons/year) 568 580 872
SNCR Cost Effectiveness (7.303% interest rate) Annualized Capitalized Costs (20-yr life) Total Annualized O&M Costs

$1,546,424 $2,168,400

$1,546,424 $2,208,800

$1,546,424 $3,176,600
Total Annual Cost ($/year) $3,714,824 $3,755,224 $4,723,024
Cost effectiveness ($/ton) $6,536 $6,469 $5,417

155 Located on page 4 of appendix C in PacifiCorp’s Four Factor Analysis Evaluation Response 156 Located on page 5 of appendix C in PacifiCorp’s Four Factor Analysis Evaluation Response

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Table 56: PacifiCorp Updated Huntington SNCR Cost Effectiveness
Cost Effectiveness Huntington 1 Huntington 2
Baseline Heat Input (MMBtu/year) NOx Emissions Rate (lb/MMBtu) NOx Emissions (tons/year)
28,063,728 0.212 2,968
27,150,145 0.208 2,825
NOx Emissions w/ SNCR (20% efficiency) Controlled NOx Emissions Rate (lb/MMBtu) Controlled NOx Emissions (tons/year)
0.169
2,374
0.166
2,260
SNCR Annual NOx Removal (tons/year) 594 565
SNCR Cost Effectiveness (7.303% interest rate) Annualized Capitalized Costs (20-yr life) Total Annualized O&M Costs

$1,560,724 $2,256,200

$1,560,724 $2,156,000
Total Annual Cost ($/year) $3,816,924 $3,716,724
Cost effectiveness ($/ton) $6,431 $6,579

In conclusion, PacifiCorp submitted that the above table’s use of accurate annualized capital
and O&M costs when combined with an appropriate SNCR NOx control efficiency of 20%
provide reasonable SNCR cost effectiveness determinations for the Hunter and Huntington
units. PacifiCorp has requested that S&L update their April 9, 2020, studies to utilize the current
interest rate of 7.303% and the more conservative SNCR NOx control efficiency of 20% for all
Hunter and Huntington units. These updates are currently being finalized and are not
anticipated to materially impact the data provided here. PacifiCorp will notify UDAQ if any
material changes occur.
UDAQ Response Conclusion
Interest Rate
Upon consulting with the Control Cost Manual and EPA staff,157 UDAQ has found that it is
preferable for a source’s four-factor analysis to use a source-specific interest rate. After further
discussion with the Utah Department of Public Utilities, UDAQ has confirmed that 7.34% is
PacifiCorp’s most recently approved interest rate in Utah.158 However, as noted in the
company’s Four-Factor Analysis Evaluation Response for Hunter and Huntington above, “The
actual weighted average cost of capital is calculated using the rates approved by the six state
regulatory authorities where PacifiCorp conducts business and the percentage of energy
delivered by PacifiCorp to each of those states.” UDAQ accepts the resulting 7.303% interest
rate as an appropriate source-specific rate across the company's service territory and notes that
this rate is more conservative than the Utah Public Service Commission approved 7.34% with
regard to control-cost assessment.

157 See email correspondence with Larry Sorrels (EPA) in Appendix D.2.H. 158 Source: https://pscdocs.utah.gov/electric/20docs/2003504/3168662003504ro12-30-2020.pdf

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SO2
As noted above, all five units at both plants have FGD in place to control SO2 emissions, and all
units have SO2 emission limits (generally 0.12 lb/MMBtu 30-day rolling average) that correspond
to these controls as included in the approval orders for both plants. Since controls were
installed/upgraded, all five units at both plants have operated at levels below the 0.12 lb/MMBtu
SO2 emission limits, ranging between approximately 0.6 and 0.10 lb/MMBtu as shown in Figure
53 below. UDAQ does not believe it is possible for the Hunter and Huntington units to scrub to
the SO2 emissions level of 0.03 lb/MMBtu specified in the original four-factor submittal RPEL
proposal with the existing FGD controls. As PacifiCorp states in their comments159:
The Utah Units’ SO2 pollution control equipment (scrubbers) have design rates from 0.08
to 0.10 lb/MMBtu, and the costs indicated in the 2020 RP Analysis are to optimize these
rates. The design parameters were necessary to ensure compliance with the Units’ 0.12
lb/MMBtu emission limits. The existing Utah Units’ scrubbers cannot control to lower SO2
emission rates. To achieve a 0.03 lb/MMBtu SO2 rate, new scrubbers would have to be
constructed at an estimated capital cost of $180 million for each unit.
UDAQ views the 0.03 lb/MMBtu rate as an artifact of the way the RPELs were calculated, and –
as discussed in the NOx section below – UDAQ does not concur with this methodology or the
RPELs that result from it.
159 See appendix C.3.D to view PacifiCorp’s response to comments regarding SO2 scrubbing
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Hunter Huntington
1 0.13 0.12 0.14 0.15 0.09 0.08 0.06 0.07 0.07 0.08 0.07 0.08 0.15 0.11 0.07 0.07 0.09 0.09 0.09 0.09 0.10 0.09 0.07 0.09
2 0.11 0.11 0.09 0.09 0.09 0.09 0.09 0.08 0.08 0.08 0.07 0.08 0.06 0.06 0.07 0.07 0.07 0.08 0.08 0.08 0.07 0.07 0.06 0.07
3 0.06 0.07 0.06 0.07 0.07 0.08 0.07 0.08 0.07 0.08 0.07 0.08
0.00
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Figure 53: Hunter and Huntington SO2 Rate

146
The 2019 Guidance states that it “may be reasonable for a state not to select an effectively
controlled source. A source may already have effective controls in place as a result of a
previous regional haze SIP or to meet another CAA requirement.” The guidance goes on to
provide “scenarios in which EPA believes it may be reasonable for a state not to select a
particular source for further analysis,” including the following example:
For the purpose of SO2 control measures, an EGU that has add-on flue gas
desulfurization (FGD) and that meets the applicable alternative SO2 emission limit of the
2012 Mercury Air Toxics Standards (MATS) rule47 for power plants. The two limits in the
rule (0.2 lb/MMBtu for coal-fired EGUs or 0.3 lb/MMBtu for EGUs fired with oil-derived
solid fuel) are low enough that it is unlikely that an analysis of control measures for a
source already equipped with a scrubber and meeting one of these limits would
conclude that even more stringent control of SO2 is necessary to make reasonable
progress.
As previously stated, all of PacifiCorp’s Utah units have permitted SO2 limits of 0.12 lb/MMBtu,
which is well below the 0.2 lb/MMBtu limit provided in the 2019 Guidance.
For the foregoing reasons, UDAQ concludes that SO2 emissions are well-controlled at all five
Hunter and Huntington units. These units have operated at rates between 0.06 and 0.10
lb/MMBtu in recent years, and this range is consistent with the design parameters of the existing
scrubbers. UDAQ also acknowledges that potential variations in the sulfur content of coal
impact the ability of the existing controls to consistently scrub to lower levels in rejecting lower
limits for these units.
Because Utah participated in the Section 309 compliance pathway for SO2 in its round one SIP,
the existing SO2 emission limits were not included among the Section IX.H controls for regional
haze. Since the continued operation of these controls is essential to making reasonable
progress as demonstrated by the WRAP photochemical modeling and helps eliminate the
possibility of backsliding on past emissions reductions, UDAQ is adding the existing SO2
emission limits for all five units to SIP Section IX.H.23 to ensure federal enforceability in the
regional haze context. However, UDAQ is eliminating the startup, shutdown,
maintenance/planned outage or malfunction exemptions found in the approval order for
Huntington Units 1 and 2 to ensure that the limits are applicable to these sources continuously
to be consistent with CAA requirements.
NOx
Four-factor Analyses
For NOx controls, specifically SNCR and SCR, UDAQ concurs with PacifiCorp’s calculations
supporting their four-factor analyses (as amended or further justified in the company’s follow-up
submittals). However, UDAQ does not concur with the company's four-factor analysis
calculations for the proposed RPELs. First, the emissions reductions ascribed to the RPELs
were based upon the application of SNCR controls – a technology the company claimed not to
be cost-effective – to each plant's plantwide applicability limit (PAL). Furthermore, the control
costs associated with the RPELs were estimated based solely on the cost of additional

147
scrubbing of SO2, while the estimated emissions reductions included both NOx and SO2, and the
RPEL cost-effectiveness analysis used an unrealistic baseline emissions scenario (i.e., 100% of
the PAL). As a result, the RPEL cost-effectiveness estimates cannot be meaningfully compared
to those for physical controls. For these reasons, UDAQ rejects the proposed RPELs.
Regarding SNCR and SCR cost-effectiveness, the company’s analysis was based upon
applying recent (2015-2019 average) heat inputs (in MMBtu/year) and emissions rates (in
lb/MMBtu) to calculate emissions (MMBtu/year X lb/MMBtu = lb/year) compared to using the
same heat inputs at the control emissions rates for SNCR and SCR. The delta between the
recent actual emissions versus emissions with new controls represented the emissions
reductions associated with each control. The total annual cost of each control was then divided
by tons reduced per year to establish a cost-effectiveness metric of dollars per ton ($/ton) of
emissions reduced.
PacifiCorp’s analysis yielded cost-effectiveness values ranging from $5,417/ton to $6,579/ton
for SNCR and $4,401/ton to $6,533/ton for SCR, as summarized in Table 57 below.
Table 57: Cost-effectiveness of SNCR and SCR and Hunter and Huntington Power Plants
Unit SNCR $/ton SCR $/ton
Hunter 1 $6,536 $6,533 Hunter 2 $6,469 $6,488 Hunter 3 $5,417 $4,401 Huntington 1 $6,431 $5,979
Huntington 2 $6,579 $6,294

As noted above, PacifiCorp’s cost-effectiveness estimates were calculated using a baseline of
recent actual emission levels. However, as EPA notes in its 2019 Guidance:
A state may choose a different emission control scenario as the analytical baseline
scenario. Generally, the estimate of a source’s 2028 emissions is based at least in part
on information on the source’s operation and emissions during a representative historical
period. However, there may be circumstances under which it is reasonable to project
that 2028 operations will differ significantly from historical emissions. Enforceable
requirements are one reasonable basis for projecting a change in operating parameters
and thus emissions; energy efficiency, renewable energy, or other such programs where
there is a documented commitment to participate and a verifiable basis for quantifying
any change in future emissions due to operational changes may be another.160
160 See Guidance on Regional Haze Implementation Plans for the Second Implementation Period (Aug. 20, 2019) (2019 Regional Haze Guidance) at 29, available at https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf.

148
In its July 2021 clarifications memo, EPA adds that there may be instances in which state
projections of changes in future utilization are unenforceable, leading to the need to establish
utilization or production limits to ensure reasonable progress at existing emission rates:
. . . in some cases, states may have projected significantly lower total emissions due to
unenforceable utilization or production assumptions and those projections are dispositive
of the four-factor analysis. For example, a state that rejected new controls solely based
on cost effectiveness values that were higher due to low utilization assumptions. In this
circumstance, an emission limit that requires compliance with only an emission rate may
not be able to reasonably ensure that the source’s future emissions will be consistent
with the assumptions relied upon for the reasonable progress determination. EPA
anticipates these circumstances will be rare. One option a state may consider in this
case is to incorporate a utilization or production limit corresponding to the assumption in
the four-factor analysis into the SIP. Although not required, this approach is one way for
states to address circumstances in which a specific emission rate does not, by itself,
represent the reasonable progress determination.161
Furthermore, EPA recognized that in instances in which control costs are dominated by a
relatively high proportion of fixed capital costs, actual cost-effectiveness will be highly
dependent on the future utilization levels of the facility. In instances where utilization is lower
than initially projected, controls will be less cost-effective, while higher future utilization will result
in improved cost-effectiveness, since there will be more tons reduced by a given control but for
the same fixed costs when utilization increases. In such instances, EPA notes that a mass-
based emission limit may be appropriate to demonstrate reasonable progress:
. . . if the annualized cost for a measure is dominated by fixed capital costs, the state
may have determined that the measure is necessary to make reasonable progress if the
operating level is high (making cost/ton and cost/Mm-1 relatively low) but not if the
operating level is low (making cost/ton and cost/Mm-1 relatively high). In this case, a
mass-based emission limit may be reasonable because it could relieve the source of the
requirement to install the control if it manages its operating level strategically.
. . . in addition to considering technology-based emission control measures, a state may
consider restrictions on hours of operation, fuel input, or product output. Such
restrictions could be implemented directly or by a time-based limit on mass emissions.162
To further assess the appropriateness of installing physical controls at these facilities, UDAQ
developed a plant utilization sensitivity analysis for installing SCR at all five units at both plants.
In this analysis, UDAQ assumed a baseline emission scenario using historical utilization levels

161 See Clarifications Regarding Regional Haze State Implementation Plans for the Second Implementation Period (July 8, 2021) (2021 Regional Haze Clarifications) at 12, available at https://www.epa.gov/system/files/documents/2021-07/clarifications-regarding-regional-haze-state-implementation-plans-for-the-second-implementation-period.pdf.
162 See 2019 Regional Haze Guidance at 45, available at https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf.

149
(based on 2015-2019 actual emissions), and then varied potential future utilization relative to
that baseline to create four alternative emissions scenarios:
• 125% of baseline utilization
• 75% of baseline utilization
• 50% of baseline utilization
UDAQ also scaled O&M costs by the same factors in an attempt to account for changes in
variable costs but kept fixed capital costs constant. Figure 54 below summarizes this sensitivity
analysis.

As can be seen, higher unit and plant utilization yields lower $/ton estimates (more cost-
effective), while lower utilization yields higher $/ton estimates (less cost-effective).
This sensitivity analysis raises the question of how the units at both plants are likely to be
utilized throughout the second regional haze planning period. In its attempt to address this
question, WRAP relied on the Center for the New Energy Economy (CNEE) at Colorado State
University to project 2028 emissions for coal- and gas-fired EGUs throughout the West for use
in modeling to support WRAP states in their SIP development.163 For coal-fired units, these
estimates were based on 2016-2018 utilization (i.e., gross load), heat rates, and emissions
rates, but were adjusted for certain known or “on-the-books” (OTB) changes in emissions
163 See http://www.wrapair2.org/pdf/Final%20EGU%20Emissions%20Analysis%20Report.pdf.
Figure 54: SCR Cost-effectiveness by utilization level at Hunter and Huntington Power Plants

150
controls, fuel switching, and unit closures. For example, in Utah, CNEE accounted for the
previously announced closure of Intermountain Power Plant (IPP) Units 1 and 2 in 2025 by
reducing emissions accordingly.
Using this OTB methodology, WRAP projected 2028 NOx emissions of 10,001 tons/year for
Hunter and 6,091 tons/year for Huntington.164 These emissions estimates are similar though not
identical to PacifiCorp’s recent actual emissions used in its four-factor analyses, with the
differences stemming from the use of different averaging periods and methodologies.
Anticipated Changes in Utilization
The electricity generation industry is experiencing significant change with the introduction of
cheap natural gas and renewable sources such as wind and solar altering previous operating
practices. Other factors affecting change include increased grid coordination (e.g., the Energy
Imbalance Market (EIM), the potential establishment of a new Western regional transmission
organization (RTO), new transmission capacity, etc.), dramatic improvements in lighting and
other equipment efficiency, uncertainty regarding the future of climate regulation, and increased
customer preference for cleaner energy resources. Low-cost renewable electricity in particular
has forced operators to switch “baseload” EGUs, such as Utah’s coal-fired plants, to “follow”
load between periods when renewables are available and unavailable. This trend is reflected in
the utilization165 of the Hunter and Huntington power plants as shown in Figure 55 and Figure 56
below.

164 CNEE originally estimated 9,992 tons/year for Hunter and 6,083 for Huntington, but the final WRAP projections included additional non-EGU sources at each plant to arrive at the values above. 165 From Utah Geological Survey Energy Utah Energy and Mineral Statistics, Table 5.1 (https://geology.utah.gov/docs/statistics/electricity5.0/pdf/T5.1.pdf) and Table 5.15a (https://geology.utah.gov/docs/statistics/electricity5.0/pdf/T5.15.pdf).
74%68%63%63%66%69%66%70%
59%62%60%63%58%
79%74%67%65%
74%74%69%66%61%59%56%54%50%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Hunter and Huntington Capacity Factors(based on Nameplate Capacity)
Hunter Huntington
Figure 55: Hunter and Huntington Capacity Factors

151
These changes in utilization, coupled with existing emission reduction controls, have led to
decreases in NOx emissions from Utah’s coal-fueled EGUs, as shown in Figure 57.

86%79%74%73%76%80%76%81%
68%72%69%73%67%
90%85%77%75%
85%85%79%75%69%68%64%61%57%
0%
10%
20%
30%
40%
50%
60%
70%
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2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020*
Hunter and Huntington Utilization(based on Net Summer Capability)
Hunter Huntington
Figure 56: Hunter and Huntington Utilization (based on Net Summer Capability)
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Figure 57: Hunter and Huntington NOx Emissions by Unit

152
While there is always uncertainty regarding the future utilization of a facility, PacifiCorp’s 2021
Integrated Resource Plan (IRP)166 helps shed light on the likely future operation of Hunter and
Huntington Power Plants. Indeed, it provides the company’s most recent and robust
assessment of the projected future resource utilization.
As shown in Figure 58 (2021 IRP Figures 1.4-1.7), the 2021 IRP preferred portfolio includes
approximately 6,000 MW of new solar capacity, over 3,500 MW of new wind capacity, over
6,000 MW of new storage capacity, and over 2,500 MW of new non-emitting resources (e.g.,
hydrogen, nuclear, etc.) through 2040. Over the same period, it anticipates over 4,000 MW of
coal retirements or conversion of coal units to natural gas, as shown in Figure 59 (2021 IRP
Figure 1.12) below.

166 https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-irp/Volume%20I%20-%209.15.2021%20Final.pdf
Figure 58: PacifiCorp 2021 IRP Cumulative Resource Additions

153

Figure 60 compares PacifiCorp’s remaining coal capacity (MW) to both the coal share of total
energy (% of total MWh) and total capacity (% of total MW) over the 2021 IRP planning window.
In 2021, coal-fired units are responsible for 49% of total energy, but only 31% of total capacity.
Over time the coal energy share declines at a steeper rate than the coal capacity share as
renewables and non-emitting resources enter PacifiCorp’s system, with the metrics crossing
each other in 2031 at 11%. By the end of the IRP planning window in 2040 when the Hunter
power plant is the only coal-fired unit remaining in PacifiCorp’s system, the coal capacity share
is only 3% and the coal energy share is only 1% of the total system. Importantly, it is energy
generation, not capacity, that correlates with emissions levels for a given emission rate. Of
particular interest is the period from 2029 through 2036 during which both in- and out-of-state
coal capacity remains flat. Yet over the same period, the coal-fired share of total energy
declines from 18% to just 6%. This chart helps illustrate that PacifiCorp’s coal-fired units switch
Figure 60: PacifiCorp 2021 IRP Coal Capacity (MW) vs. Coal % of Total Energy and % of Total Capacity
0%
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20%
30%
40%
50%
60%
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Hunter Capacity Huntington Capacity Remaining Coal Capacity
Coal % of Total Energy Coal % of Total Capacity
Figure 59: PacifiCorp 2021 IRP Cumulative Coal Retirements/Gas Conversions

154
from being energy resource to capacity resources over time, as they transition to their new role
of supporting zero-emission resources.
While the 2021 IRP projected plant-level and unit-level capacity factors for Hunter and
Huntington are confidential and, therefore, not available to include in the SIP, the redacted
comments of interveners before the Utah Public Service Commission (PSC) who have been
granted access to these projections provide an additional degree of confidence that the
utilization of these plants is likely to change. For example, excerpts from the redacted
comments by Western Resource Advocates (WRA)167 shed light on the projected future
utilization of PacifiCorp’s coal-fired plants:
With the planned new resources in PacifiCorp’s Preferred Portfolio, the transformation of
PacifiCorp’s coal fleet is projected to accelerate significantly over the coming decade
from the provision of round-the-clock energy to seasonal dispatch with limited annual
hours of operation. (page 10)
Confidential Exhibit 4 is comprised of six pages, and displays monthly capacity factors
for PacifiCorp’s long-lived coal plants: Jim Bridger, Wyodak, Hunter, and Huntington. A
review of the exhibit makes clear that once take-or-pay contracts expire, the units at
Hunter and Huntington operate only seasonally… (pages 15-16)
Affordability
In addition to concerns that reduced future plant utilization will erode the cost-effectiveness of
physical controls at Hunter and Huntington, it is important to note that PacifiCorp believes that
these controls are unaffordable under the current constraints the company faces as a regulated
public utility and in the face of post-pandemic supply chain issues and rising inflation. As
PacifiCorp states168:
…the dollar-per-ton cost-effectiveness value for SCR does not represent all of the
considerations necessary to determine whether SCR is a reasonable control that should
be required at the Utah Units. As the Affordability Analysis shows, a demonstration that
SCR is the least-cost, least-risk option for PacifiCorp’s customers faces likely
insurmountable obstacles. In addition, over the past decade, the requirement to install
SCR has led to early retirement or refueling of numerous other coal-fueled generating
plants in the region and across the country. External factors including increased
regulatory scrutiny of investments in coal-fueled resources, state laws limiting the market
for coal-fueled power and increasing competition from renewable and storage resources
add to the pressures making SCR unaffordable, especially for a regulated utility. The
decision to retire a coal-fueled unit rather than install SCR is not merely “a voluntary
business decision[ ] that the benefits of continuing to generate electricity at the affected
units were outweighed” by other factors. Instead, an early retirement decision is a

167 See https://pscdocs.utah.gov/electric/21docs/2103509/322689RdctdWRACmnts3-4-2022.pdf.
168 PacifiCorp’s public comment period submission can be found at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2022-007454.pdf

155
regulatory necessity as continued plant operation becomes unfeasible because “the
costs of [SCR] . . . [are] so onerous that the source[ ] simply could not afford them”
making “the sources’ decisions to cease operations . . . in essence involuntary.”
In the Wyodak Facility SCR Affordability Analysis (August 25, 2020) supplied with their public
comments on the proposed SIP, PacifiCorp identifies several coal units across the country that
have either been retired or repowered rather than installing SCR to meet regulatory
requirements, including:
- Cholla Plant, Arizona
- Craig Unit 1, Colorado
- San Juan Generating Station (retirement of two of four units), New Mexico
- Progress Energy and Duke have shut down 22 units subject to BART instead of
installing controls, North Carolina
- Boardman Plant elected to cease burning coal instead of installing SCR, Oregon
- Dave Johnson Plan will retire Unit 3 by 2027 rather than installing SCR, Wyoming
More recently, PacifiCorp has announced that it will convert Jim Bridger 1 and 2 to natural gas
rather than installing SCR.
Affordability concerns have led some 2021 IRP commenters to opine that SCR might be
considered an imprudent investment relative to unit closures in the economic regulatory arena,
including parties who in their round two proposed SIP comments to UDAQ claim SCR to be a
cost-effective control. For example, in redacted comments before the Utah PSC, the Sierra Club
states, “SCR requirements will at some point be required under the Clean Air Act. At that time,
the early retirement case becomes roughly equivalent from an economic standpoint to the
current preferred case, depending on the price-policy scenario.”169 Here it is important to note
that EPA has historically held that it does not have the authority to force the retirement of a unit
under the regional haze rule: “Generally, EPA does not interpret the regional haze rule to
provide us with authority to make a BART determination that requires the shutdown of a
source.”170
Additional affordability concerns were raised in public comments from Deseret Power, which
owns an undivided 25.108% of Hunter Unit 2. Deseret states171:
For over 20 years, Deseret has operated as a financially distressed company under the
terms of a troubled debt forbearance (the “Debt Forbearance”) with its principal creditor.
Under the terms of the Debt Forbearance, Deseret essentially pledged all of its available
net cashflow toward partial payment of long-term indebtedness which Deseret has been
unable to pay in full. A key provision of the Debt Forbearance is that Deseret cannot
169 See https://pscdocs.utah.gov/electric/21docs/2103509/322718RdctdSierraClubCmnts3-4-2022.pdf
170 79 FR 5032, 5045 (Jan. 30, 2014). 171 The public comments submitted by Deseret Power can be found at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2022-007475.pdf

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incur any added indebtedness without prior express consent of the existing creditor. The
creditor understandably does not allow Deseret to take on new debt without first
scrutinizing whether and to what extent the new debt would result in increased net
cashflows to help repay the outstanding arrearage on existing debt held by the creditor.
In its present condition, Deseret is not certain it would be able to raise capital necessary
to finance its portion of costs to install any additional and costly post-combustion controls
at Hunter II. It would be left to the decision of Deseret’s creditor to refuse to allow
Deseret to solicit or draw on any new source of financing for such controls.
These affordability concerns and the potential for forced unit closures weigh in favor of
considering reasonable alternatives to requiring the installation of physical controls.
Balancing the Four Statutory Factors
Given the likely reduction in utilization of Hunter and Huntington in future years and the erosion
of the cost-effectiveness of physical controls that would accompany such a reduction, UDAQ is
establishing enforceable mass-based limits on future emissions from these facilities to reduce
uncertainty and ensure that the plants operate at or below emissions levels at which physical
controls are not cost-effective. To identify these limits, UDAQ calculated the utilization and
resulting emissions levels that would result in a $5,750/ton level for SNCR and SCR for all units
at both plants, as shown in Table 58 and Table 59 below. UDAQ then used the more stringent
of the two scenarios (based on SCR) to set limits at which both SNCR and SCR are not cost-
effective.
Table 58: 2028 Mass-based NOx Limit - SNCR Cost-effectiveness
Item (unit) Hunter 1 Hunter 2 Hunter 3 Huntington 1 Huntington 2 Total 2028 Utilization (% of 2015-2019 Average) 144.6% 134.2% 85.6% 133.0% 138.3% 2015-2019 Average Heat Input (MMBTU) 28,482,643 30,101,030 31,182,279 28,063,728 27,150,145 2028 Limit Heat Input (MMBTU) 41,183,800 40,400,840 26,683,091 37,329,312 37,542,964 Existing Control Rate (lb/MMBTU) 0.200 0.193 0.280 0.212 0.208
Proposed Control Rate (lb/MMBTU) 0.160 0.154 0.224 0.169 0.166
Emissions w/ Existing Controls (tons/year) 4,109 3,895 3,730 3,948 3,906
Emissions w/ Control (tons/year) 3,295 3,111 2,989 3,154 3,116 Emissions Reduction (tons/year) 814 785 742 793 790 Annualized Capital Costs $1,546,424 $1,546,424 $1,546,424 $ 1,560,724 $ 1,560,724 Total Annual O&M Costs $ 3,135,346 $ 2,964,595 $ 2,718,259 $ 3,001,112 $ 2,981,296
Total Annual Cost $4,681,770 $4,511,019 $4,264,683 $4,561,836 $4,542,020 $/ton $ 5,750 $ 5,750 $ 5,750 $ 5,750 $ 5,750 2028 Emission Limit (tons)
Hunter Plantwide: 11,735 Huntington Plantwide: 7,854 19,588
Table 59: 2028 Mass-based NOx Limit – SCR Cost-effectiveness
Item (unit) Hunter 1 Hunter 2 Hunter 3 Huntington 1 Huntington 2 Total

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2028 Utilization (% of 2015-2019 Average) 115.9% 115.0% 73.6% 104.6% 111.0% 2015-2019 Average Heat Input (MMBTU) 28,482,643 30,101,030 31,182,279 28,063,728 27,150,145 2028 Limit Heat Input (MMBTU) 33,016,004 34,628,669 22,963,607 29,357,153 30,136,124 Existing Control Rate (lb/MMBTU) 0.1995 0.1928 0.2796 0.2115 0.2081
Proposed Control Rate (lb/MMBTU) 0.0500 0.0500 0.0500 0.0500 0.0500
Emissions w/ Existing Controls (tons/year) 3,294 3,339 3,210 3,105 3,135
Emissions w/ Control (tons/year) 825 866 574 734 753 Emissions Reduction (tons/year) 2,469 2,473 2,636 2,371 2,382
Annualized Capital Costs $12,141,691 $12,141,691 $13,490,472 $11,787,158 $11,787,158
Total Annual O&M Costs $ 2,052,876 $ 2,078,799 $ 1,667,280 $ 1,844,255 $ 1,909,166
Total Annual Cost $14,194,567 $14,220,490 $15,157,752 $13,631,413 $13,696,324
$/ton $ 5,750 $ 5,750 $ 5,750 $ 5,750 $ 5,750 2028 Emission Limit (tons)
Hunter Plantwide: 9,843 Huntington Plantwide: 6,240 16,083
While UDAQ is not establishing a cost-effectiveness threshold per se, the agency believes that
a level of $5,750/ton for physical controls, when balanced against the remaining three statutory
factors, is not cost-effective. As a result, UDAQ concludes that physical controls are not
necessary to demonstrate reasonable progress. What follows is a brief summary of the
remaining factors, beyond cost-effectiveness, that help in leading UDAQ to this conclusion:
Time Necessary for Compliance
Due to the delayed nature of the round 2 regional haze SIPs, there is only a short
window available for control installation of approximately five years, depending the final
approval date. This is likely not enough time for the potential installation of SNCR or
SCR at up to five units. In contrast, enforceable annual mass-based limits can begin to
be implemented immediately upon approval of the round 2 regional haze SIP.
Energy and non-air quality environmental impacts
According to PacifiCorp’s four-factor analysis, the installation of SCR on Hunter and
Huntington would result in a large parasitic load of 12.5 MW at Hunter and 8.6 MW at
Huntington, which equates to 115,687 and 79,743 more tons of CO2, respectively. In
addition, the installation of SNCR or SCR could potentially lead to increases in water
use, coal consumption, coal combustion residuals, and other consumables and waste
products associated with coal combustion (e.g., water treatment chemicals, anhydrous
ammonia reagent, urea reagent, mercury control system reagent, and diesel fuel), since
physical controls would enable the plants to operate more under the existing PALs
relative to mass-based limits. In addition, these plants are currently projected to assist in
the transition towards intermittent renewable resources. Should the cost of physical
controls lead to early plant closures, alternative resources will be required to provide
such support.

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Remaining Useful Life
The currently anticipated economic life of Huntington is approximately 14 years (16
years fewer than EPA’s 30-year control life of SCR). The economic life of Hunter is
approximately 20 years (10 years fewer than EPA’s 30-year control life of SCR). While
the respective closure years of 2036 and 2042 are not currently enforceable, closure of
these facilities at or before the end of their economic life would further erode the cost-
effectiveness of physical controls by shortening the amortization period for control costs.
Ongoing scrutiny of expenditures associated with coal-fired power plants by state public
service commissions and the establishment of clean energy requirements in California,
Oregon, and Washington increase the risk that these facilities may face early closure.
Mass-based Limits and Flexible Compliance
While Table 59 above shows the emissions levels that would result from constraining cost-
effectiveness at $5,750/ton for SCR at the unit level, UDAQ is summing these estimated unit-
level emissions at each plant to develop plantwide emission limits to provide compliance
flexibility. In particular, UDAQ is establishing a 2028 plantwide NOx limit of 9,843 tons per year
for Hunter and a 2028 plantwide NOx limit of 6,240 tons per year for Huntington. In addition,
UDAQ is establishing an initial plantwide NOx limit for Hunter of 11,041 tons per year and an
initial plantwide NOx limit for Huntington of 6,604 tons per year, both effective upon SIP
approval. These initial levels are based on each plant’s highest emission value over the past
five years (2017-2021). Finally, UDAQ is establishing an interim 2025 plantwide limit of 10,442
tons per year for Hunter and an interim 2025 plantwide limit of 6,422 tons per year for
Huntington, to create a compliance glidepath to aid in the transition from recent actual utilization
levels to the final 2028 limits. The interim limits for each plant were calculated as the average of
(i.e., the midpoint between) the initial and 2028 plantwide limits for each plant. The limits are
compared to recent actual emissions and the outgoing PAL in Table 60 and Table 61 below.
UDAQ notes that flexible compliance mechanisms such as plantwide limits and glidepaths are
commonly used in environmental regulation (e.g., plantwide applicability limits; Tier 3 fuel
averaging, banking, and trading; the Tier 3 vehicle fleet averaging glidepath from 2017-2025;
cap and trade programs, etc.) and are appropriate in this application.

Table 60: Hunter Actuals and Limits
Year or Limit Unit 1 Unit 2 Unit 3 Total
2015 3,274 3,210 5,107 11,591
2016 2,806 2,556 3,506 8,869
2017 2,518 2,789 4,466 9,773
2018 2,422 2,975 4,372 9,770
2019 3,188 2,981 4,344 10,514
2020 2,996 2,955 3,336 9,287
2021 3,032 2,905 5,103 11,041
2022 Initial Limit 11,041
2025 Interim Limit 10,442
2028 Final Limit 9,843
Outgoing PAL 15,095

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Table 61: Huntington Actuals and Limits
Year or Limit Unit 1 Unit 2 Total
2015 3,563 2,899 6,462
2016 2,810 3,400 6,210
2017 2,990 2,940 5,931
2018 2,462 2,692 5,153
2019 3,013 2,193 5,206
2020 2,476 2,337 4,814
2021 3,111 3,493 6,604
2022 Initial Limit 6,604
2025 Interim Limit 6,422
2028 Final Limit 6,240
Outgoing PAL 7,971

As discussed previously, UDAQ has historically used plantwide limits (i.e., PALs) to limit
emissions from Hunter and Huntington power plants while providing PacifiCorp operational
flexibility. According to EPA’s 2020 “Guidance on Plantwide Applicability Limitation Provisions
Under the New Source Review Regulations”:172

A PAL is an optional flexible permitting mechanism available to major stationary sources
that involves the establishment of a plantwide emissions limit, in tons per year, for a
regulated NSR pollutant. A PAL represents a simplified NSR applicability approach that
provides a source with the ability to manage physical and operational changes, and the
impacts of those changes on facility-wide emissions, without triggering major NSR or the
need to conduct project-by-project major NSR applicability analyses. The added
flexibility of a PAL allows a source to respond rapidly to market changes with reduced
permitting burden and greater regulatory certainty.

While sources may favor such regulatory flexibility, the ability for emissions to vary from unit to
unit under a plantwide limit raises the question of how such variations might impact visibility at
CIAs. On this point, UDAQ notes that the distance between the outermost stacks at Hunter is
approximately 596 feet, and the distance between the stacks for units 1 and 2 at Huntington is
265 feet. In contrast, the distance between each plant and the CANYI IMPROVE monitor for
Arches and Canyonlands is 431,589 feet (Hunter) and 490,433 feet (Huntington). While
distances from these facilities to each IMPROVE site vary, the CANY1 example illustrates that
differences in visibility impairment that stem from the proximity effects associated with plantwide
limits are likely to be negligible. Visibility impacts related to using plantwide limits are more likely
to stem from other factors that might favor or constrain the utilization of one unit relative to other
units than from differences in proximity to CIAs among units.

172 https://www.epa.gov/sites/default/files/2020-08/documents/pal_guidance_final_-_signed.pdf

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Cost-effectiveness Thresholds
On the subject of decision thresholds, the 2019 Guidance notes that states “may” use
thresholds, but the use of such thresholds must be justified with respect to consideration for
other relevant factors:

A state may find it useful to develop thresholds for single metrics to organize and guide
its decision-making. As the Ninth Circuit explained in NPCA v. EPA, 788 F.3d at 1142,
the Regional Haze Rule does not prevent states from implementing “bright line” rules,
such as thresholds, when considering costs and visibility benefits. However, the state
must explain the basis for any thresholds or other rules (see 40 CFR 51.308(f)(2)). If a
state applies a threshold for any particular metric to remove control measures from
further consideration before all other relevant factors are considered, it should explain
why its selected threshold is appropriate for that purpose, i.e., why its application is
consistent with the requirement to make reasonable progress.

In general, UDAQ believes that such “bright line” thresholds are neither required nor appropriate
for determining reasonable progress. As discussed in Section 7.A.1 regarding the selection of
sources for controls determination, UDAQ’s Q/d threshold value of 6 is only the starting point for
screening sources for further evaluation. UDAQ augments this threshold with both a secondary
screening and a WEP analysis to ensure that it has accurately captured sources in need of
evaluation. Similarly, a bright line cost-effectiveness threshold (i.e., cost/ton) is not required and
may be of limited utility. In fact, the 2019 Guidance states that such cost/ton thresholds must be
justified, and comparisons among various cost/ton estimates may or may not be useful for
assessing compliance costs:

If a state applies a threshold for cost/ton to evaluate control measures, we recommend
that the SIP explain why the selected threshold is appropriate for that purpose and
consistent with the requirement to make reasonable progress.

… a cost/ton metric and comparisons to the cost/ton values for measures that have been
previously implemented may or may not be useful in determining the reasonableness of
compliance costs.

Historically, UDAQ has not utilized cost-effectiveness thresholds for compliance cost
assessment, whether for RACT, BACT, or other air quality program control measures. Selecting
a cost-effectiveness threshold provides a “target” that sources could potentially exploit to adjust
their compliance cost analyses to avoid control requirements. In the round 2 regional haze
context, the selection of a bright line $/ton threshold would inappropriately limit UDAQ’s ability to
consider the remaining three statutory factors and related considerations. That said, a review of
cost-effectiveness thresholds and ranges in various states – either incorporated directly into
regional haze SIPs, used internally by staff and shared via the interstate coordination process,
or shared by commenters on the proposed SIP – reveals that UDAQ’s determination that

161
physical controls are not cost-effective at a $5,750/ton level is in line with the range considered
by other states as shown in Figure 61 below.
Annual Limits vs. Short-term Limits or Emission Rates
Given concerns that the use of an annual limit might not be sufficiently short to limit visibility
impairment on Most Impaired Days (MIDs), UDAQ evaluated the seasonality of nitrate
impairment on MIDs at Utah’s CIAs using the last five available years of visibility data.173 As
shown in Figure 62, nitrate impairment is largely seasonal with the MIDs with the highest light
extinction happening during the winter months. This result is consistent with the secondary
formation of particulates that UDAQ sees along the Wasatch Front and is not unexpected.
173 Source: "TSS Ambient Species Composition of Daily Light Extinction by Percentile Days - Product #XATP_ECSB_GDYR." WRAP Technical Support System (TSS); The Western Regional Air Partnership (WRAP) and the Cooperative Institute for Research in the Atmosphere (CIRA), 20 Jun 2022
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Figure 61: State Control Cost-effectiveness Ranges

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While nitrate light extinction has a single annual peak in the wintertime, the Hunter and
Huntington power plants have two gross load (and associated NOx emissions) peaks each year,
one in the summer and one in the winter, as shown in Figure 63 below. As a result, UDAQ
believes that the company is unlikely to utilize the majority of its annual mass-based NOx limit
for each plant during the wintertime gross load and MID nitrate impairment peaks, since it must
retain enough headroom to accommodate the summer gross load peak. Thus, UDAQ concludes
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Figure 62: Daily Nitrate Light Extinction MIDs at Utah CIA IMPROVE Sites, 2014-2019

163
that an annual mass-based limit is a sufficient to reduce the likelihood of excess emissions
impact CIAs during periods of high electricity demand.

Other Considerations
UDAQ finds it additionally compelling to incorporate these enforceable mass-based emission
limits to ensure that the EGU nitrate contribution to light extinction at Utah (and other states)
CIAs does not exceed the emissions levels utilized in WRAP’s photochemical modeling.174 Such
mass-based emission limits would help ensure that Utah is making reasonable progress as
demonstrated by the WRAP modeling, while eliminating the possibility of backsliding on past
emissions reductions. Importantly, the mass-based emissions limits outlined above result in
combined emissions that are generally consistent with WRAP’s 2028 OTB projections that are
explicitly accounted for in Utah’s projected 2028 RPGs, such as the example shown for
Canyonlands in Figure 64.
174 See Appendix A for UDAQ’s proposed Part H language for emission limits and controls enforcement
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Figure 63: Combined Hunter and Huntington Monthly NOx Emissions vs. Monthly Gross Load, 2014-2021

164
Finally, this approach provides regulatory flexibility for PacifiCorp, which can meet the mass-
based emission limits either by limiting or otherwise modifying operation, installing controls,
switching fuels, closing units, or some combination of these options. Refer to section 8.D.3 for
UDAQ’s reasonable progress determinations for the Hunter and Huntington power plants.
7.C.4 Sunnyside Cogeneration Associates- Sunnyside Cogeneration Facility
Four-Factor Analysis Summary and Evaluation175
Facility Identification
Name: Sunnyside Cogeneration Facility
Address: State Road 123, #1 Power Plant Road, Sunnyside, Utah
Owner/Operator: Sunnyside Cogeneration Associates
UTM coordinates: 552,984 m Easting, 4,377,786 m Northing, UTM Zone 12
Facility Process Summary
The Sunnyside Cogeneration Facility (Sunnyside) is in Sunnyside, Carbon County, Utah
(approximately 25 miles southeast of Price). The nearest Class I areas and their respective
distance from the facility are Canyonlands National Park, (91 miles), Capitol Reef National Park
(95 miles), Bryce Canyon National Park (171 miles) and Zion National Park (217 miles). The
Sunnyside power plant began operations in May of 1993. The electricity it produces is sold to
PacifiCorp, operating as Utah Power and Light [UPLC). The plant qualifies as a small power
production facility and qualifying cogeneration facility (“QF”) under the Public Utility Regulatory
175 Sunnyside’s full four-factor analysis can be found in appendix C.4.A or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2020-008928.pdf
Figure 64: Example of projected RPGs for Canyonlands and Arches CIAs

165
Policy Act of 1997 (‘PURPA”). The facility operates a coal-fired combustion boiler that features
circulating fluidized bed (CFB), a baghouse and a limestone injection system. The facility also
operates an emergency diesel engine and emergency generator. All process units are currently
permitted in its UDAQ Title V air operating permit (Permit # 700030004) which was renewed on
April 30, 2018. The CFB boiler is subject to the NESHAPS Part 63, Subpart UUUUU Mercury
and Air Toxics Standards [MATSI Rule. As a result, Sunnyside is required to meet a standard of
0.2 lb./MMBtu of SO2.
This standard requires continuous monitoring with a continuous emission monitor system
(CEMS). The plant’s CFB boiler, designed by Tampella Power, produces steam that drives a
Dresser Rand turbine generator. The CFB boiler and baghouse uses limestone injection.
Historically, CFB boilers have been one of the primary low emission combustion technologies
for commercial and small utility installations using low grade fuels. This trend continues with
CFB technology being considered for smaller coal fired units as a means to effectively utilize
lower quality fuels and meet environmental requirements. The current boiler produces
emissions from one stack at Sunnyside’s cogeneration facility. For the purposes of a control
technology review, only the emissions from the boiler stack itself are considered as well as the
operations from the emergency diesel engine and emergency generator.
Facility Criteria Air Pollutant Emissions Sources
The source consists of the following emission units:
• Circulating Fluidized Bed Combustion Boiler – Rated at 700 MMBtu/hr and fueled by
coal, coal refuse or alternative fuels, and fueled by diesel fuel during startup,
shutdown, upset condition and flame stabilization. This boiler is equipped with a
limestone injection system to the fluidized bed and a baghouse. This boiler is subject
to 40 CFR 60, Subpart Da and CAM.
• One diesel engine, approximately 201 HP, used to power the emergency backup fire
pump, and various portable I/C engines to power air compressors, generators,
welders and pumps.
• A 500-kW emergency standby diesel generator, used in the event of disruption of
normal electrical power and testing/maintenance. 1.4 Facility Current Potential to
Emit The current PTE values for Sunnyside, as established by the most recent NSR
permit issued to the source (DAQE-AN100960029-13) are as follows (in tons/year):
SO2 1,289.26 NOx 771.2.

Facility Current Potential to Emit
The current PTE values for Sunnyside, as established by the most recent NSR permit issued to
the source (DAQE-AN100960029-13) are as follows:
Table 62: Sunnyside: Current Potential to Emit (Tons/Year)
Pollutant Potential to Emit (tons/yr) SO2 1,289.26 NOx 771.2

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Sunnyside Four Factor Analysis Conclusion
The facility currently uses CFB technology to lower NOx emissions and achieves Title V
permitting NOx limits as currently operated. SCR is a technically feasible control option for this
boiler but is not cost effective with a control cost greater than $10,000 per ton of NOx removed.
While SNCR may represent a cost-effective option for NOx emissions reduction, the introduction
of substantial ammonia slip has the potential to cause adverse environmental impacts. The
ammonia and PM2.5 emissions have the potential to cause direct health impacts for those in the
area, and present additional safety concerns for the storage and transportation of ammonia.
Despite not having SNCR or SCR installed, the Sunnyside boiler is achieving a NOx emission
rate on a lb./MMBtu basis that is comparable to PSD BACT levels set on CFB boilers.
Therefore, additional add-on controls for NOx emissions reductions are not necessary on the
Sunnyside CFB boiler.
UDAQ Evaluation Summary and Conclusion176
UDAQ noted several potential errors in Sunnyside’s analysis:
1. The Sunnyside four-factor analysis for SO2 eliminated both wet scrubbers and spray dry
scrubbers from consideration as an SO2 control because it does not have the water
rights that would be needed for operation of the wet scrubber or a spray dry absorber.
2. Sunnyside Cogen did not provide justification for including the cost for a new
replacement baghouse with a dry scrubbing option.
3. Sunnyside’s analysis was inconsistent regarding the amount of sorbent required and the
possible resulting efficiency.
4. The Sunnyside dry sorbent injection analysis assumed too high of a cost for auxiliary
power.
5. The Sunnyside dry scrubbing cost analysis improperly included annual costs for taxes
and insurance and assumed unreasonably high annual costs for administrative charges.
6. The Sunnyside dry scrubbing cost analysis improperly assumed a 30% increase in cost
as a retrofit factor.
7. The Sunnyside dry sorbent injection cost analysis used too high of an interest rate and
too short expected life when amortizing costs.
8. Sunnyside assumed too high of an interest rate and too short of a life of controls in
determining the annualized capital costs of SNCR and SCR The Sunnyside SCR and
SNCR cost effectiveness analyses assumed a 4.75% interest rate and a 20- year life of
both SCR and SNCR.
9. Sunnyside assumed a very high cost for aqueous ammonia that was not justified. In its
SNCR and SCR cost analyses, Sunnyside Cogen assumed a cost for 29.4% aqueous
ammonia of $2.50 per gallon.
176 UDAQ’s full evaluation of Sunnyside’s four-factor analysis submittal can be found in appendix C.4.B or
at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/DAQ-2021-009630.pdf

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10. Sunnyside assumed a higher cost for electricity than it assumed in its dry sorbent
injection analysis in its SCR and SNCR cost analysis.
At this time, UDAQ is unable to proceed with its review and requests additional information as
follows:
1. The source needs to resubmit the Four Factor analysis correcting the errors mentioned
above.
2. Additional information must be provided regarding the infeasibility of SCR. A. This
information can include additional details on economics as well as technical limitations.
3. Additional information must be provided regarding the infeasibility of SNCR. A. As with
SCR, this information can include additional details on economics as well as technical
limitations.
4. Any other pertinent information Sunnyside feels is warranted should also be provided in
order to assist UDAQ in the review process.
Sunnyside’s Evaluation Response177
1. HAR technology is not feasible as flue gas exiting the CFB boiler at Sunnyside typically
contains approximately 10% unreacted calcium oxide in the in the fly ash and even less
in the bottom ash.178 Additionally, there is a significant amount of ash already entrained
in the CFB boiler which would make additional ash infeasible. SDA technology requires
significant amounts of water that Sunnyside is unable to adequately source, thus they
find it infeasible. Given the configuration of existing units, there is not enough space
between the CFB boiler and existing baghouse for the addition of a further CDS/CFBS
unit without significant reconfiguration of existing equipment. Of all the add on control
technologies considered, CDS/CFBS is the only potentially feasible option. Existing
controls for SO2 as defined in Sunnyside’s Title V air operation permit (#700030004)
Condition II.A.2 currently provide SO2 controls to the circulating fluidized bed (CFB)
boiler, which involves limestone injection.
2. Sunnyside included a cost analysis for a CDS/CFBS as per UDAQ request as it is the
only technically feasible add-on unit. However, the average estimated cost for a
CDS/CFBS able to achieve 90% SO2 control ranges from $81 to $400 million plus
another $1.7 million for a new baghouse required with this technology. Ash Grove does
not consider this device economically feasible.
3. Sunnyside has updated this formula in the revised cost analysis to utilize the Sargent &
Lundy formula for estimating the amount of lime needed for the Sunnyside CFB boiler.
This formula now assumes that use of lime could achieve 74% SO2 reduction resulting in
a lime injection rate of 0.0921 tons per hour or 184 lb/hour.
4. Sunnyside has revised the cost for auxiliary power to be consistent with the UDAQ
comments. Specifically, the busbar cost for electricity has now been calculated based on
177 Sunnyside’s full evaluation response can be found in appendix C.4.C or at: https://documents.deq.utah.gov/air-quality/pm25-serious-sip/DAQ-2021-017202.pdf 178 Based on fly ash characterization results conducted at Sunnyside Cogeneration Associates.

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2018 operating data. The resulting rate is $49.45 per MW. Additionally, the electrical
usage rate has been updated to match the UDAQ comments and as displayed below:
0.028% x 58.33 MW x 8031 hours/yr x $49.45/MW-hr = $6,486 per year.
The analysis provided under Question 2, 3, and 4 along with the attached cost analysis
should replace information found in Sections 5.4 and 5.5 of the Four Factor Analysis.
5. The UDAQ suggested that there are tax exemptions in Utah for control equipment. UAC
R307-120 exempts the purchase of control equipment from sales/use tax. As a result,
sales tax is no longer included in CDS/CFBS cost analysis provided. Sales tax rates and
property taxes are not used in either the SCR or SNCR cost analyses due to the
equation format provided by EPA. Insurance rate was based on a 1% of the Total capital
investment (TCI) which is documented in the EPA Cost Control Manual, Section 1,
Chapter 2 Cost Estimation: Concepts and Methodology, Subsection 2.6.5.8 Property
Taxes, Insurance, Administrative Charges and Permitting Costs. The administrative cost
calculation has been updated to be consistent with SCR as suggested by the UDAQ.
6. The UDAQ questioned the retrofit factor (RF) of 1.3 used all cost analyses, as a result
Sunnyside reevaluated the use of this factor on a technology specific basis. Referencing
the EPA Control Cost Manual, Sunnyside believes the 1.3 retrofit factor is justified for
use in their cost calculations for CDS/CFBS and SCR. They reconsidered their SNCR
calculations and instead used a 1.0 retrofit factor.
7. A 20-year life span and 7% interest rate has been applied to the cost control analyses
provided by Sunnyside.
8. The equipment life and interest rate explanations provided in Question 7 are not control
technology specific. Thus, the same conclusions are applicable, namely, a 20-year life
span and 7% interest rate are appropriate for the cost analyses provided.
9. In response to the UDAQ’s request, Sunnyside obtained a cost estimate for 19% aqua
ammonia from Thatcher Group, Inc (Thatcher). Thatcher quoted $0.18 per lb. of solution.
Based on this value, if we assume a density of 19% ammonia is estimated to be 7.46
lbs/gal to 7.99 lbs/gal. This results in a cost per gallon ranges from 1.34 $/gal to 1.438
$/gal. This cost is significantly higher than the EPA estimate of $0.293, which is
acceptable as it states, “User should enter actual value if known”. Furthermore, it should
be noted that the cost for ammonia based on the most recent U.S. Geological Survey,
Minerals Commodity Summaries, which was quoted in the original Four Factor Analysis
is also significantly higher and based on a density of 29% ammonia. Since the $1.438 is
still less than the originally used $2.5 per gallon, these calculations have been updated
to include the vendor quote.
10. As discussed in Question 4, Sunnyside has revised the cost for auxiliary power to be
consistent with the UDAQ’s comments. Please see section 4 for additional information. A
revised cost analysis for SCR and SNCR have been provided in Attachment A to replace
the cost analysis in the original Four Factor Analysis.

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UDAQ Response Conclusion
UDAQ agrees with the amendments included in Sunnyside’s evaluation response and finds the
answer’s provided in the facility’s response satisfactory. Refer to section 8.D.5 for UDAQ’s
reasonable progress determinations for the Sunnyside Cogeneration Facility.
7.C.5 US Magnesium LLC- Rowley Plant179
Facility Identification
Name: Rowley Plant Address: 12819 North Skull Valley Road 15 Miles North Exit 77, I-
80, Rowley, Utah
Owner/Operator: US Magnesium LLC
UTM coordinates: 4,530,490 m Northing, 354,141 m Easting, Zone 12
Facility Process Summary
US Magnesium LLC (USM) operates a primary magnesium production facility at its Rowley
Plant, located in Tooele County, Utah. USM produces magnesium metal from the waters of the
Great Salt Lake. Some of the water is evaporated in a system of solar evaporation ponds and
the resulting brine solution is purified and dried to a powder in spray dryers. The powder is then
melted and further purified in the melt reactor before going through an electrolytic process to
separate magnesium metal from chlorine. The metal is then refined and/or alloyed and cast into
molds. The chlorine from the melt reactor is combusted with natural gas in the chlorine
reduction burner (CRB) and converted into hydrochloric acid (HCl). The HCl is removed from
the gas stream through a scrubber train. The chlorine that is generated at the electrolytic cells is
collected and piped to the chlorine plant where it is liquefied for reuse or sale. USM Rowley
Plant is a PSD source for CO, NOx, PM10, PM2.5, and VOCs.
Facility Criteria Air Pollutant Emissions Sources
The source consists of the following emission units:
• Three (3) gas turbines/generators and duct/process burners (natural gas/fuel oil)
• Chlorine reduction burner (CRB), and associated equipment
• Riley Boiler, 60 MMBtu/hr (natural gas)
• Solar pond diesel engines, 30 engines rated between 90 and 420 hp
• Fire pump engine, one additional diesel engine rated at 292 hp
Facility Current Potential to Emit
The current PTE values for the Rowley Plant, as established by the most recent NSR permit
issued to the source (DAQE-AN107160050-20) are as follows:
Table 63: Current Potential to Emit
Pollutant Potential to Emit SO2 24.10
NOx 1,260.99

179 US Magnesium’s full four-factor analysis submittal for the Rowley Plant can be found in appendix C.5.A or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/DAQ-2020-014024.pdf

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US Magnesium Four-Factor Analysis Conclusion
This outlines USM’s evaluation of possible retrofit options for all NOx emitting units onsite at their
Rowley Plant located in Tooele County, Utah, in an attempt at reducing their NOx emissions
facility wide and reducing their impact on visibility impairment issues. The results of this report
found that it is potentially technologically and economically feasible to install a flue gas
recirculation unit on the Riley boiler, reducing their NOx emissions by an estimated 22.6 tons
annually. Aside from this change, there were currently no other technically or economically
feasible options available for USM’s Rowley Plant. Pending further technological and cost
refinement, the implementation schedule for the installation of the FGR unit may be installed
prior to the end of 2028. Therefore, the emissions for the 2028 modeling scenario could be an
estimated 22.6 tons less than the 2018 baseline year NOx emissions.
UDAQ Evaluation180
Several errors were made during the analysis of the various control options outlined in this
document. While the errors ultimately do not change the outcome or results of the analysis, they
should be corrected prior to final acceptance by DAQ. The following lists the errors noticed by
DAQ and the resulting effect each error leads to in the final result:
Incorrect interest rate used for control cost calculation – rather than using the current bank
prime rate of 3.25%, the source calculated all control costs with either an interest rate of 7%
(used as the default in the control cost manual) or 5.5% (used as the default in the SCR control
cost spreadsheet). Both calculations result in a higher control cost in $/ton. Second, the source
used only a 20-year expected life for application of an SCR, which is lower than the standard
30-year lifespan. Again, this would artificially inflate the control cost by increasing the
annualized cost. However, the overall cost of the SCR system as estimated by the source was
lower than expected, with an initial cost of just $87,000. The low initial cost serves to lower the
resulting control cost. DAQ reanalyzed the use of SCR on the Riley Boiler under two different
scenarios. Under PTE, assuming full load, the application of SCR might be expected to remove
as much as 188 tons of NOx at a control cost of $4,073/ton of NOx removed – assuming the
same 90% removal efficiency as did the source. However, the Riley Boiler did not operate at
that high an output level – reporting just 45.25 tons of actual emissions in 2018. Adjusting the
emission reduction for 90% of the actual emissions gives a removal of 40.7 tons of NOx (as
opposed to the 38 tons suggested by the source), at a control cost of $18,800/ton of NOx
removed. Similar errors were made with respect to the FGR calculations on the Riley Boiler.
The incorrect interest rate was used – 7% vs 3.25%. FGR systems typically have a potential
lifespan of 15 years rather than the 20 years suggested by the source. DAQ recalculated the
control costs correcting for these errors and obtained a modified value of 22.5 tons of NOx
removed at a control cost of $1,880/ton of NOx removed. None of the other equipment requires
additional evaluation, as each is currently well controlled. While the same types of errors were

180 UDAQ’s full evaluation of US Magnesium’s four-factor analysis submittal can be found in appendix C.5.B or at: https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/DAQ-2021-009628.pdf

171
made in the source’s analysis, the resulting outcomes and conclusions remain unchanged. DAQ
recommends that FGR be considered for retrofit control application on the Riley boiler. Should
the source increase utilization of the Riley boiler, then the application of SCR should be
considered.
US Magnesium’s Evaluation Response181
US Magnesium re-evaluated the status of the Riley boiler and the Riley boiler NOx emission
factor utilized in US Magnesium’s 2018 air emission inventory (AEI) that was the basis for the 4-
factor analysis of that unit. In summary, the US Magnesium 2018 AEI grossly overstated the
NOx emissions associated with the Riley boiler in two ways: 1) the Riley boiler is a 60 MMBTU
boiler but the AP42 emission factor in the 2018 AEI is for a >100 MMBTU boiler, and 2) the
Riley boiler, from the time of its installation, is outfitted with a low NOx burner, but the AP42
emission factor in the 2018 AEI is for an “uncontrolled burner.” The implications are summarized
in the table below:
Table 64: US Magnesium’s Reevaluation of Riley Boiler Controls
Riley Boiler 2018 NOx emission factor
AP 42 Table1.4-1. Emission Factors for NOx and CO from Natural Gas Combustion
Estimated NOx emissions (TPY)
AEI as submitted 190 lbs./MMscf >100MMBTU (Large) Uncontrolled 45.2499
AEI corrected for actual status of Riley boiler
50 lbs./MMscf <100MMBTU (Small) Controlled - Low NOx burner 11.9074

Corrected 2018 NOx emissions for the Riley boiler, implications on the 4-factor analysis:
• Using the same reductions assumed for FGR (up to 50% NOx), the estimated reduction
would be about 6 tons/year.
• Using the same reductions assumed for SCR (up to 90% NOx), the estimated reduction
would be about 10.7 tons/year.
• Using DAQ’s modified calculation for FGR: $1,880/ton * 22.5 tons = $42,000/yr.
Correcting to 6 ton/yr reduction = $7,050/ton.
• Using DAQ’s modified calculation for SCR: $18,800/ton * 40.7 tons = $765,160/yr.
Correcting to 11.9 ton/yr reduction = $64,300/ton.
UDAQ Response Conclusion
UDAQ does not agree with US Magnesium’s evaluation response. We do not possess any
records of an LNB control on the Riley boiler. Using the original four-factor analysis submittal,

181 US Magnesium’s full evaluation response can be found in appendix C.5.C or at:
https://documents.deq.utah.gov/air-quality/planning/air-quality-policy/regional-haze/DAQ-2021-
011902.pdf

172
FGR on the Riley boiler remains a cost-effective and viable control option. UDAQ would require
proof of the existence of the LNB and its NOx removal efficacy before agreeing it is a
satisfactory justification for altering the control cost calculations. Refer to section 8.D.6 to review
UDAQ’s reasonable progress and controls determination for the Rowley Plant.
Chapter 8: Determination of Reasonable Progress Goals
8.A Reasonable Progress Requirements
The RHR requires Utah to submit a long-term strategy (LTS) that includes measures necessary
to achieve the Reasonable Progress Goals (RPGs) in each CIA. This strategy must consider
major and minor stationary sources, mobile sources, and area sources. Section 169A (a)(4) and
other subsections of the Clean Air Act call for reasonable progress "toward meeting the national
goal" of eliminating anthropogenic (manmade) impairment of visibility. Utah is required under
the RHR to establish visibility deciview goals for each of its five CIAs that allow them to meet the
RPGs towards natural visibility by 2064. RPGs are interim goals that represent incremental
visibility improvement over time toward the goal of natural background conditions and are
developed in consultation with FLMs and nearby affected states. In determining the criteria for
reasonable progress, Utah was required under Section 169A(g) of the CAA to consider four
factors: cost of compliance, the time necessary for compliance, energy and non-air
environmental impacts of compliance, and the remaining useful life of existing sources that
contribute to visibility impairment.182
8.B. Regional Modeling of the LTS to set RPGs
The RHR requires states to demonstrate progress every ten years toward the CAA goal of no
manmade visibility impairment. WRAP conducted the modeling necessary to track this progress
for Utah. EPA guidance for tracking visibility progress183 defines a visibility impairment tracking
metric (measured in deciviews) using observations from the IMPROVE monitoring network sites
that represent CIAs. EPA defined in the RHR and guidance a Uniform Rate of Progress (URP)
glidepath for the 20% most impaired days as the straight line from the 2000-2004 IMPROVE 5-
year average baseline to EPA estimates of future natural visibility conditions, plotted for 2064. In
the first regional haze planning period, 2000-2018, EPA guidance184 defined most impaired days
as those days with highest total haze. States were required to demonstrate visibility progress by
2018 compared to the URP glidepath for the haziest days and no degradation of visibility on the
clearest days from the 2000-2004 IMPROVE 5-year average baseline. Visibility on the clearest
days improved between 2000 and 2018 across the Class I areas in the western U.S. However,

182 See 42 USC § 7492(g)(1). 183 The EPA Technical Guidance on Tracking Visibility Progress for the Second Implementation Period of the Regional Haze Program can be found at: https://www.epa.gov/sites/default/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf
184 The EPA Technical Guidance on Tracking Visibility Progress for the Second Implementation Period of the Regional Haze Program can be found at: https://www.epa.gov/sites/default/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf

173
smoke from wildfire and wildland prescribed fire events and dust events on the haziest days
made tracking the visibility benefits due to reducing U.S. anthropogenic emissions more difficult.
For the second regional haze implementation period, 2018-2028, states are required to
demonstrate visibility progress by 2028 for the most impaired days and no visibility degradation
for the clearest days. EPA guidance185 defined most impaired days as those days with the
highest fractional contribution to aerosol light extinction from anthropogenic sources. EPA
statistical methods use IMPROVE measurements of carbon and crustal materials to separate
contributions from episodic extreme natural events (e.g., wildfire or dust) from routine natural
and anthropogenic contributions. Ammonium sulfate and ammonium nitrate are assigned
primarily to anthropogenic emissions with smaller contributions from routine natural sources.
This statistical approach does not separate contributions due to U.S. anthropogenic emissions
from those of international anthropogenic emissions. Since states do not have authority to
reduce international emissions, WRAP conducted source apportionment modeling analyses to
evaluate U.S. anthropogenic contributions to haze and progress in reducing U.S. anthropogenic
contributions to haze over time.
8.C URP Glidepath Checks186
These charts illustrate the Uniform Rate of Progress (URP) Glidepath, as defined by EPA
guidance,187 compared to IMPROVE measurements for the period 2000-2018. The URP
glidepath is constructed (in deciviews) for the 20% most impaired days (MID) or clearest days
using observations from the IMPROVE monitoring site representing a Class I area. The URP
glidepath starts with the IMPROVE MID for the 2000-2004 5-year baseline and draws a straight
line to estimated natural conditions in 2064. For clearest days, the goal is no degradation of
visibility from the 2000-2004 5-year baseline, therefore glidepath for clearest days is a straight
line from the 2000-2004 baseline to 2064. In the second regional haze planning period, 2064
natural conditions estimates are the same as the 15-year average of natural conditions on most
impaired days or clearest days in each year 2000-2014. IMPROVE annual average values are
presented as points. IMPROVE 5-year average values are presented as solid lines covering the
periods 2000-2004 and 2014-2018.
The 2028 On the Books (2028OTBa2) visibility projection in deciviews is illustrated as a point
that can be compared to the Uniform Rate of Progress glidepath. UDAQ has chosen the
“2028OTBa2 w/o fire” projection that excludes wildfire from MID to more accurately represent
future emissions from sources UDAQ is better able to control. This projection reduces the
impact of elemental carbon and organic carbon from fires from the original 2028 EPA projection
to remove additional fire impacts that were not fully eliminated by the move from haziest days
metric (used during the first planning period) to most impaired days metric (used during the

185 The EPA Technical Guidance on Tracking Visibility Progress for the Second Implementation Period of the Regional Haze Program can be found at: https://www.epa.gov/sites/default/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf 186 40 C.F.R. § 51.308(f)(3)(i)
187 The EPA Guidance for Tracking Progress Under the Regional Haze Rule can be found at https://www.epa.gov/sites/default/files/2021-03/documents/tracking.pdf

174
second planning period). The 2028OTBa2 visibility projection reflects Utah’s LTS, including the
results of the reasonable progress determinations found in 8.D, with the exception of the
anticipated 22.5 tons of NOx emissions reductions associated with the installation of FGR
controls on the Riley Boiler at U.S. Magnesium’s Rowley Plant. However, the resulting reduction
in NOx emissions is a small percentage of Utah’s total 2028 NOx emissions. The 2028OTBa2
visibility projection includes emissions from the now-closed Kennecott Power Plant, which was
projected to have 1,152 tons of NOx, 2,152 tons of SO2, and 135 tons of PM2.5 emissions in
2028. The 2028 projections also include emissions from the Tesoro Refinery not accounting for
the refinery’s recent PM2.5 SIP BACT analysis which resulted in an annual mass-based SO2
limit and an estimated 408-ton SO2 reduction. The omission of these emissions reductions in the
2028OTBa2 projection make our glidepath comparisons conservative, as actual 2028 visibility
can be expected to improve due to lower emissions levels. Refer to section 6.A.10 to review
Utah’s Long-Term Strategy and additional details on the emissions reductions UDAQ is relying
on to make reasonable progress in the second implementation period.
8.C.1 Bryce Canyon National Park
The 2000-2004 URP baseline in Bryce Canyon for MID is 8.4 dv. The 2014-2018 average
observations for MID is 6.6, meaning visual range on the most impaired days has increased
from 104.62 miles to 125.26 miles, an improvement of 20.64 miles. The projected visibility in
2028 without fire impacts is 6 dv, which, represented by the orange triangle on the graph, is
below the URP glidepath. For clearest days, the 2000-2004 baseline for Bryce Canyon is 2.8 dv.
The 2014-2018 average observations for clearest days are 1.5 dv meaning that visual range on
the clearest days has increased from 183.16 miles to 208.59 miles, an increase of 25.43 miles.
Figure 65: Projected 2028 RPG Bryce Canyon National Park

175
The projected 2028 visibility on clearest days is 1.2 dv, which, represented by the blue triangle,
is below the no degradation limit for clearest days.

8.C.2 Canyonlands and Arches National Park
The 2000-2004 URP baseline in Canyonlands and Arches National Park for MID is 8.8 dv. The
2014-2018 average observations for MID is 6.8, meaning visual range on the most impaired
days has increased from 100.52 miles to 122.78 miles, an improvement of 22.26 miles. The
projected visibility for MID in 2028 without fire impacts is 6.2 dv, which is below the URP
glidepath. For clearest days, the 2000-2004 baseline for Canyonlands and Arches is 3.7 dv. The
2014-2018 average observations for clearest days are 2.2 dv meaning that visual range on the
clearest days has increased from 167.40 miles to 194.49 miles, an increase of 27.09 miles. The
projected 2028 visibility on clearest days is 1.9 dv, which is also below the no degradation limit
for clearest days.
Figure 66: Projected 2028 RPG Canyonlands and Arches National Parks

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8.C.3 Capitol Reef National Park
The 2000-2004 URP baseline in Capitol Reef for MID is 8.8 dv. The 2014-2018 average
observations for MID is 7.2, meaning visual range on the most impaired days has increased
from 100.52 miles to 117.96 miles, an improvement of 17.44 miles. The projected visibility for
MID in 2028 without fire impacts is 6.6 dv, which is below the URP glidepath. For clearest days,
the 2000-2004 baseline for Capitol Reef is 4.1 dv. The 2014-2018 average observations for
clearest days are 2.4 dv meaning that visual range on the clearest days has increased from
160.83 miles to 190.64 miles, an increase of 29.81 miles. The projected 2028 visibility on
clearest days is 2.1 dv, which is below Capitol Reef’s no degradation limit for clearest days.
Figure 67: Projected 2028 RPG Capitol Reef National Park

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8.C.4 Zion National Park
The 2000-2004 URP baseline in Zion National Park for MID is 10.4 dv. The 2014-2018 average
observations for MID is 8.7, meaning visual range on the most impaired days has increased
from 85.66 miles to 101.53 miles, an improvement of 15.87 miles. The projected visibility for
MID in 2028 without fire impacts is 8.3 dv, which is below the URP glidepath. For Zion’s clearest
days, the 2000-2004 baseline for is 4.5 dv. The 2014-2018 average observations for clearest
days are 3.9 dv meaning that visual range on the clearest days has increased from 154.53 miles
to 164.08 miles, an increase of 9.55 miles. The projected 2028 visibility on clearest days is 3.5
dv, which is below the no degradation limit for clearest days in Zion.

Figure 68: Projected 2028 RPG Zion National Park

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8.C.5 Summary of URP Glidepaths
The table below summarizes the information from Figures 65-68 above, comparing visibility on
the most impaired and clearest days for the baseline, 2028 URP, and 2028 EPA w/o fire
projection values for each of Utah’s CIAs in addition to stating whether the CIA is below the
URP glidepath and no degradation line.
Table 65: Comparison of baseline, 2028 URP, 2028 EPA w/o fire projection for worst and clearest days
CIA
IMPROVE
Site
WORST DAYS CLEAREST DAYS
Baseline
(dv) 2028
URP (dv)
2028 EPA
w/o Fire Projection (dv)
% Progress
to 2028 URP
2028
Below URP Glidepath? (Y/N)
Baseline
(dv) 2028 EPA
Projection (dv)
2028 EPA
w/o Fire Projection (dv)
2028 Below No
Degradation Line? (Y/N)
BRCA1 8.42 6.68 6.03 137.60% YES 2.77 1.22 1.20 YES
CANY1 8.79 6.92 6.19 139.10% YES 3.75 1.94 1.92 YES
CAPI1 8.78 6.87 6.63 112.28% YES 4.10 2.17 2.10 YES
ZICA1 10.40 8.35 8.27 103.73% YES 4.48 3.65 3.54 YES

8.D Reasonable Progress Determinations
The following sections contain UDAQ’s determinations on what controls are necessary for
Utah’s CIAs to make reasonable progress in this implementation period. UDAQ believes these
determinations will help protect reasonable further progress demonstration and visibility in Utah.
All emissions limits, operating procedures, and compliance strategies for the following
reasonable progress determinations which limit NOx, SO2, and PM are identified in SIP
Subsection IX.H.21 and 23, which are made enforceable through EPA approval and
incorporation into the Utah Air Quality Rules.
8.D.1 Reasonable Progress Determination for Ash Grove Cement Company –
Leamington Cement Plant
Upon reviewing Ash Grove’s four-factor analysis for the Leamington Cement Plant and their
evaluation response, UDAQ finds that it is adequately controlled for the purposes of the Second
Implementation Period. UDAQ has determined that the existing SCNR control and emissions
limits for the Leamington Cement Plant are effective measures necessary for reasonable
progress in Utah’s Second Implementation Period of regional haze planning. The Leamington
Cement Plant’s existing controls and emissions limits will be implemented and enforced through
SIP Subsection IX.H.23 to ensure the plant will continue to implement existing measures and
will not increase its emission rate. Refer to section 7.B.3 to review the four-factor analysis and
evaluation response results for the Leamington Cement Plant.

179
8.D.2 Reasonable Progress Determination for Graymont Western US Incorporated –
Cricket Mountain Plant
Upon reviewing the Graymont Western US Inc. four-factor analysis for their Cricket Mountain
Plant and their evaluation response, UDAQ finds that additional controls are not required for
reasonable progress in this implementation period based on their cost/ton and the potential
proprietary costs of SNCR technology for the kilns. UDAQ has determined that the existing
controls and emissions limits for the Cricket Mountain Plant are effective measures necessary
for reasonable progress in Utah’s Second Implementation Period of regional haze planning. The
Cricket Mountain Plant’s controls and emissions limits will be implemented and enforced
through SIP Subsection IX.H.23 to ensure the plant will continue to implement existing
measures and will not increase its emission rate. Refer to section 7.B.4 to review the four-factor
analysis and evaluation response results for the Cricket Mountain Plant.
8.D.3 Reasonable Progress Determination for PacifiCorp: Hunter and Huntington
Power Plants
Upon reviewing PacifiCorp’s four-factor analysis and evaluation response, UDAQ is establishing
plantwide annual mass-based NOx emission limits. At the resulting utilization and emissions
levels, UDAQ finds SNCR and SCR not to be cost-effective. UDAQ is also adding PacifiCorp’s
existing SO2 emission limits from their Title V permit for all five units to ensure federal
enforceability in the regional haze context. These emission limits are to be implemented and
enforced through SIP Subsection IX.H.23. Please refer to section 7.C.3 to view PacifiCorp’s and
UDAQ’s complete analysis and conclusions.
8.D.4 Reasonable Progress Determination for Sunnyside Cogeneration Associated –
Sunnyside Cogeneration Facility
Upon reviewing the Sunnyside Cogeneration Associated four-factor analysis and evaluation
response containing corrections to their analysis of the Sunnyside Cogeneration Facility, UDAQ
has found no cost-efficient control options for the facility for the purposes of the Second
Implementation Period. UDAQ has determined that the existing controls and emissions limits for
the Sunnyside Cogeneration Facility are effective measures necessary for reasonable progress
in Utah’s Second Implementation Period of regional haze planning. The Sunnyside
Cogeneration Facility’s controls and emissions limits will be implemented and enforced through
SIP Subsection IX.H.23 to ensure the facility will continue to implement existing measures and
will not increase its emission rate. Refer to section 7.B.6 to review the four-factor analysis and
evaluation response results for the Sunnyside Power Plant.
8.D.5 Reasonable Progress Determination for US Magnesium LLC – Rowley Plant
Upon reviewing US Magnesium LLC’s four factor analysis for their Rowley Plant, UDAQ does
not agree with its assessment of an LNB on the Riley Boiler. UDAQ has no record of the
existence of an LNB on this unit or it’s NOx reducing efficacy. UDAQ therefore refers to US
Magnesium’s original four-factor analysis submittal information suggesting that FGR is a cost-
effective and viable control option for the Riley Boiler. UDAQ recommends the installation of

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FGR on the Riley Boiler to ensure that Utah makes reasonable progress in this implementation
period. UDAQ has also determined that the existing controls and emissions limits for the Rowley
Plant are measures necessary for reasonable progress in Utah’s Second Implementation Period
of regional haze planning to ensure the plant will continue to implement existing measures and
will not increase its emission rate. Implementation of these control determinations are to be
enforced through SIP Subsection IX.H.23. Refer to section 7.B.7 to review the four-factor
analysis and evaluation response results for the Rowley Plant.
8.D.6 Intermountain Power Service Corporation – Intermountain Generation Station
As discussed in section 7.A.2, the planned replacement of the IGS coal-fired units with an EPS-
compliant combined-cycle natural gas plant is expected to dramatically decrease regional haze-
causing pollutants (PM, SO2, and NOx). Though the coal-fire units are expected to cease
operation by mid-2025, UDAQ has established a firm closure date of no later than December
31, 2027 to ensure that the coal-fired units at IGS will not continue operation beyond the
conclusion of the second implementation period while allowing flexibility for closing the plant in
addition to rescinding its permit and approval order. UDAQ has also determined that the existing
controls and emissions limits for IGS are measures necessary for reasonable progress in Utah’s
Second Implementation Period of regional haze planning to ensure the plant will continue to
implement existing measures and will not increase its emission rate. The implementation of the
IGS closure and its existing control measures are to be enforced through SIP Subsection
IX.H.23.

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Chapter 9: Consultation, Public Review, Commitment to further
Planning
9.A Federal requirements
In developing each reasonable progress goal, Utah must consult with those States which may
reasonably be anticipated to cause or contribute to visibility impairment in CIAs within Utah.188
Where the State has emissions that are reasonably anticipated to contribute to visibility
impairment in any mandatory Class I Federal area located in another State, Utah must consult
with the other State(s) in order to develop coordinated emission management strategies.189 Utah
must demonstrate that it has included in its implementation plan all measures agreed to during
state-to-state consultations or a regional planning process, or measures that will provide
equivalent visibility improvement and document all substantive interstate consultations.190 Utah
must also provide the FLMs with an opportunity for consultation no less than 60 days prior to the
SIP public hearing or public commenting opportunity.191 This consultation must include the
opportunity for FLMs to discuss their assessment of the visibility impairment at CIAs and their
recommendations on the development and implementation of strategies to address visibility
impairment.192 Utah must include a description in their implementation period of how it
addressed any comment provided by FLMs.193
9.B Interstate Consultation
Throughout the second implementation period, Utah has met regularly with its surrounding
states. Utah also participates in WESTAR Planning Committee and Four Corners meetings for
state RH planning coordination. Table 66 includes a summary of interstate meetings UDAQ took
part of. See Appendix B for further documentation of interstate consultation and agreements.
UDAQ conducted further consultation and SIP review of the second implementation period
status of the non-Utah sources identified in UDAQ's WEP analysis and included this information
in Table 67 to Table 68. As shown, all out-of-state sources identified by UDAQ’s WEP analysis
of Utah’s CIAs are either:
• outside state jurisdiction,
• have Q/d values too low to be screened in by the state,
• were screened out due to effective Round 1 BACT controls, or
• are subject to controls or closure in this implementation period.

188 See 40 CFR § 51.308 (d)(1)(iv) 189 See id., § 51.308 (d)(3)(i)
190 See id., § 51.308 (f)(2)(ii)(C) 191 See id., § 51.308 (i)(ii)(2)
192 See id., § 51.308 (i)(ii)(2) 193 See id., § 51.308 (i)(4)

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Table 66: Summary of Interstate Meetings with UDAQ
Date Time Entity Topic Result
4/28/2021 10-11a Wyoming Wyoming and Utah Regional Haze Second Planning Period Update
Debrief after PacifiCorp meeting. Shared draft Montana SIP with Wyoming. They shared their draft SIP with us. We offered ours as soon as it is more complete. 4/30/2021 1-2:30p Four Corners States Regional Haze Consultations Four corners states do not expect to require other states to enforce controls for emissions affecting their Class I Areas. NM discussed in length where they are in their SIP writing process.
5/5/2021 9-9:30a Wyoming WY-UT RH Coordination Call Discussion emissions affecting the other state.
5/5/2021 2-4p WESTAR Regional Haze Results Meeting #9 Discussion of different modeling resources available and uses. 5/6/2021 2-3p WESTAR WESTAR Planning Committee Call RH updates and deadline considerations.
5/12/2021 2:30-3:30p New Mexico NM-UT DEQ Regional Haze Consultation
NM described their SIP writing process and showed us the modeling tools they plan to use for the out of state emissions section. We offered to exchange draft SIPs.
6/1/2021 1:30-2p Colorado CO-UT Regional Haze Consultation Discussed controls implementation.
9/9/2021 12-12:30p Arizona UT-AZ RH Consultation Neither state is looking for additional controls in the other. Consulted about interest rates and control cost thresholds.
9/9/2021 2-3:30p WESTAR State-Only RH Call
10/15/2021 10-11a New Mexico (Mark Jones) Control Cost Consultation Discussed control cost thresholds and justification.
11/04/2021 2-3p WESTAR Planning Committee Meeting Discussed RH updates and interstate consultation documentation emails.
11/08/2021 1-2p Wyoming RH Controls Implementation Consultation
Discussed sources and controls implementation.
11/15-16,2021 10a-4p 4 Corners Annual AQ Meeting Participated in giving RH updates with other 4 corners states.
1/7/22 10-11a New Mexico WEP Analysis Consultation Discussed WEP analysis methodologies and CAMx photochemical low-level source apportionment.
1/13/22 1:30-3p WVPPI Western Visibility Protection and Planning Initiative
Discussion of the key components of Section 169a of the CAA.
2/10/22 1:30-3p WVPPI Western Visibility Protection and Planning Initiative
Discussed, RH history, the relationship between reasonable progress and long-term strategies. Utah volunteered to help plan an in-person meeting between states, FLMs, and EPA. 2/24/22 1-2p RHPWG Regional Haze Planning Work Group
Discussed the NGO actions letter submitted to EPA and 60-day notice to file suit.
3/3/22 2-3p WESTAR Planning Committee Discussed RH updates.
3/10/22 1:30-3p WVPPI Western Visibility Protection and Planning Initiative
States discussed reasonable progress and long-term strategies.
4/5-4/7/22 8a-5p WESTAR/WRAP Spring Meeting States presented on air quality, visibility, and wildfire modeling and updates. 4/13/22 1:30-3p WVPPI Western Visibility Protection and Planning Initiative
States discussed how reasonable progress can be determined and challenges faced by states whose largest sources of impairment are not anthropogenic sources.
4/14/22 2-3p WESTAR Planning Committee States gave RH updates.
5/5/22 2-3p WESTAR Planning Committee States discussed visibility modeling strategies

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5/12/22 1:30-3p WVPPI Western Visibility Protection and Planning Initiative
States discussed how to incorporate EJ into RH planning.
6/9/22 2-3p WESTAR Planning Committee States were updated by the WRAP work groups.
6/16/22 2-3:30p WVPPI Western Visibility Protection and Planning Initiative
States discussed challenges with incorporating EJ into RH planning due to a lack of guidance on how to address or make decisions considering EJ in visibility standards for CIAs. 6/21/22 Various CA, CO, NM, and NV RH SIP Controls UDAQ corresponded with neighbor states inquiring the controls status of non-UT sources ranking in WEP analysis for UT CIAs.

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Table 67: Second Implementation Period Status of Non-Utah Sources Identified in NO3 WEP Analysis
Facility Name Source
State
Utah
CIA
WEP NOx
Rank
NOx
Q/d
WEP_NO3
(% of total)
Four-Factor
Analysis? (Y/N) Proposed Controls Notes
Bonanza TR CANY1 3 30.8 59,301.8
(6.4%) N Likely closure in 2030 due
to settlement
McCarran Intl NV ZICA1 3 11.1 9,235.4
(3.7%) N
Majority of NOX emissions
from non-road sources
(aircraft take-offs and
landings)
PNM - San Juan Generating Station NM CANY1 4 33.7 47,113.4 (5.1%) Y
TBD, NM has not
finalized their second implementation period draft
Subject to four-factor
analysis in NM’s draft SIP. PNM has announced plant closure in 2022
Four Corners Power Plant TR CANY1 6 17.8 24,859.3 (2.7%) N APS has announced plant closure in 2031
Pg&E Topock Compressor
Station
CA ZICA1 6 3.2 7,620.0
(3.1%) N Not subject to four-factor analysis in CA’s proposed
SIP due to low NOx Q/d
Chaco Gas Plant NM CANY1 8 7.8 14,056.2
(1.5%) N Not subject to four-factor
analysis in NM’s proposed
SIP
Bonanza TR CAPI1 8 21.9 9,450.1
(1.1%) N Likely closure in 2030 due
to settlement
Lhoist North America and Granite Const. (Apex)
NV ZICA1 9 7.5 7,041.9 (2.8%) Y
NV proposed SIP
requires SNCR on
Kilns 1, 3, & 4 as well as LNB on Kiln 1. Kilns 3 & 4 have
existing LNBs.
NV's proposed SIP requires
SNCR on Kilns 1, 3, & 4 as well as LNB on Kiln 1. Kilns 3 & 4 have existing LNBs.
RED ROCK
GATHERING-
PREMIER BAR X C.S.
CO CANY1 10 0.6 11,567.0
(1.3%) N Not subject to four-factor
analysis in CO’s proposed
SIP due to low NOX Q/d

Table 68: Second Implementation Period Status of Non-Utah Sources Identified in SO4 WEP Analysis
Facility Name Source
State
Utah
CIA Rank SO2
Q/d
WEP_SO4
(% of Total)
Four-Factor
Analysis Y/N
Proposed New
Controls Notes
CHEMICAL LIME
NELSON PLANT AZ BRCA1 1 8 43,684.7
(21.8%) N
Not subject to four-factor
analysis in AZ’s proposed
SIP due to Round 1 BART FIP controls
CHEMICAL LIME NELSON PLANT AZ ZICA1 1 10.9 38,687.4 (24.8%) N
Not subject to four-factor analysis in AZ’s proposed SIP due to Round 1 BART
FIP controls
ASARCO LLC -
HAYDEN
SMELTER
AZ ZICA1 3 6 6,672.2
(4.3%) N
Not subject to four-factor
analysis in AZ’s proposed
SIP due to Round 1 BART
FIP controls
Four Corners Power Plant TR CANY1 4 11.1 32,557.0
(8.0%) N APS has announced plant
closure in 2031
CHEMICAL LIME NELSON PLANT AZ CAPI1 4 5.7 25,448.1 (6.4%) N
Not subject to four-factor
analysis in AZ’s proposed SIP due to Round 1 BART FIP controls
McCarran Intl NV ZICA1 4 1.2 4,713.6 (3.0%) N Majority of NOX emissions from non-road sources

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(aircraft take-offs and landings)
ASARCO LLC - HAYDEN
SMELTER
AZ BRCA1 5 5.8 14,391.7 (7.2%) N
Not subject to four-factor analysis in AZ’s proposed SIP due to Round 1 BART
FIP controls
ASARCO LLC -
HAYDEN SMELTER AZ CAPI1 6 5.2 10,351.8
(2.6%) N
Not subject to four-factor
analysis in AZ’s proposed
SIP due to Round 1 BART FIP controls
Phoenix Sky Harbor Intl AZ ZICA1 6 0.6 4,554.6 (2.9%) N
Majority of NOX emissions from non-road sources (aircraft take-offs and
landings)
Four Corners
Power Plant TR BRCA1 7 7.4 5,413.2
(2.7%) N APS has announced plant
closure in 2031
TUCSON ELECTRIC POWER CO -
SPRINGERVILLE
AZ CANY1 7 15.1 13,923.7 (3.4%) Y
SO2 Limits for Units 1
& 2:
a) 16.1 tons SO2/day
based on a daily rolling 20-calendar day average.
b) 3,729 tons
SO2/12-month rolling total
New SO2 limits for units 1 & 2 included in AZ’s proposed SIP
California
Portland Cement Co. CA ZICA1 7 2.8 4,038.8
(2.6%) N
Not subject to four-factor analysis in CA’s proposed SIP not required because it
is subject to AB 617 which
requires local air districts
to evaluate large stationary sources to
ensure reasonable
controls are installed.
CHEMICAL LIME NELSON PLANT AZ CANY1 8 4.6 13,409.0
(3.3%) N
Not subject to four-factor
analysis in AZ’s proposed
SIP due to Round 1 BART FIP controls
Republic Services Sunrise NV ZICA1 8 1 4,025.8 (2.6%) N Not subject to four-factor analysis in NV’s proposed SIP due to low Q/d
TUCSON ELECTRIC POWER CO - SPRINGERVILLE
AZ BRCA1 9 15.4 3,654.7 (1.8%) Y
SO2 Limits for Units 1 & 2:
a) 16.1 tons SO2/day
based on a daily rolling 20-calendar day average.
b) 3,729 tons
SO2/12-month
rolling total
New SO2 limits for units 1 & 2 included in AZ’s proposed SIP
Bonanza TR CANY1 9 6.9 11,908.4
(2.9%) N Likely closure in 2030 due
to settlement
NORTH VALMY GENERATING STATION NV CAPI1 9 4 5,620.2 (1.4%) Y
Permanent closure of
units 1 and 2 by 12/31/28
NV’s proposed SIP includes
a federally enforceable closure date of 12/31/28
TUCSON
ELECTRIC POWER CO - SPRINGERVILLE
AZ ZICA1 9 14.5 3,447.7
(2.2%) Y
SO2 Limits for Units 1 & 2: a) 16.1 tons SO2/day
based on a daily
rolling 20-calendar day average. b) 3,729 tons
SO2/12-month
rolling total
New SO2 limits for units 1
& 2 included in AZ’s proposed SIP

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Phoenix Sky
Harbor Intl AZ BRCA1 10 0.6 3,615.9
(1.8%)
Majority of NOX emissions from non-road sources
(aircraft take-offs and
landings)
PNM - San Juan
Generating Station NM CANY1 10 3.7 10,995.1
(2.7%) Y
Subject to four-factor
analysis in NM’s draft SIP.
PNM has announced plant closure in 2022
Bonanza TR CAPI1 10 4.9 4,809.0 (1.2%) Likely closure in 2030 due to settlement
9.C Documentation of Federal Land Manager consultation and commitment to
continuing consultation
UDAQ continuously met with the FLMs throughout the second implementation period planning
process. A summary of the meetings UDAQ held with the FLMs is outlined in the table below.
UDAQ will continue to consult and collaborate with the FLMs in its future regional haze planning
efforts.
Table 69: Summary of FLM Meetings with UDAQ
Date Time Entity Topic Result
5/5/21 8-9a Utah DEQ/US Forest Service
Prescribed Fire and Regional Haze Brief history of Utah’s smoke management program and policy regarding it.
5/6/21 1-1:30p FLM FLM/UT – Regional Haze Check-In Updated FLMs on timeline and current RH SIP progress. They informed us on their view that visibility should not be main focus of 2nd planning period and to follow the rule more than the guidance document. They are primarily concerned about 4-factor analyses. 6/22/21 12-12:30p US Forestry Service - Ples Mcneel
RH update, introductions Introduction to Ples Mcneel. Wants to be included in updates to FLMs and Paul Corrigan.
10/12/21 12-11a NPS Regional Haze Update/Timeline change
Discussed RH SIP draft submittal.
2/9/22 11:30a-1p NPS NPS UT Regional Haze Consultation NPS presented UDAQ with the results of their 60-day review period 2/23/22 11a-12p USFS – Ples Mcneel and Paul Corrigan
Rx Fire Endpoint Adjustments Discussed the Rx fire endpoint adjustments available to Utah.
3/13/22 1:04p NPS RH Public Comment Schedule Corresponded via email on the public comment process for UT’s RH SIP.
5/2/22 9:56a NPS Appendix D.2.C Provided PDF version of appendix D.2.C via email.
5/3/22 4:20p NPS Additional Source Information Corresponded via email about additional information submittal by Sunnyside and Paradox. 4/21-5/18/22 Various NPS Additional Source Information UDAQ provided additional information provided by Sunnyside, PacifiCorp, and USM via email.
5/16-5/17/22 Various NPS Public Comment Hearing Corresponded via email on the logistics of the RH SIP public hearing.
5/31/22 3:20p NPS Public Comment Submittal NPS provided UDAQ with their comments on the RH SIP.
6/7/22 7:13p NPS Additional Source Information UDAQ provided NPS with comment submittals from Sunnyside and PacifiCorp as well as the link to all public comments.
6/26/22 1:25p NPS Additional Source Information UDAQ provided NPS with an additional information submittals by Sunnyside.

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9.C.1 FLM SIP Review194
UDAQ submitted its draft RH SIP for the second implementation period to the NPS on
December 7th, 2021 and the USFS on December 15th, 2021. On February 14th, NPS and USFS
provided UDAQ with their respective SIP reviews which can be found in Appendix D.
Documentation of the public notice published by UDAQ on its website from April 25th to June
2nd, 2022 can be found in Appendix F.
9.C.2 NPS Feedback Summary and UDAQ Responses195
1. In general, NPS agrees that Utah’s source selection process resulted in a reasonable
subset of sources to evaluate in the draft SIP. Utah’s recommendation to use a lower
emission over distance threshold of six versus ten—as recommended by the WRAP—is
more rigorous and resulted in a reasonable selection of facilities for evaluation.

2. UDAQ has not identified a cost threshold under which the evaluated controls would be
considered reasonable. Many of the controls identified in the four-factor analyses for
Utah sources are cost-effective based on cost criteria/thresholds identified by other
states. NPS also feels that PacifiCorp should be subject to a higher cost threshold due to
their plant’s proximity to Utah’s CIAs. The SIP should document the full rationale upon
which the reasonable progress decisions are based.

UDAQ Response: UDAQ will not be establishing a control cost threshold at this time.
Please refer to chapter 8 for Utah’s reasonable progress determinations for the second
implementation period and the accompanying justifications, which UDAQ believes are
sufficient.

3. NPS recommends that UDAQ require all technically feasible, cost-effective controls
identified through four-factor analysis in this planning period.

UDAQ Response: UDAQ has required all controls it has deemed technically feasible and
cost effective. Please refer to the updated part H language in Appendix A to view the
enforceable actions resulting from UDAQ’s reasonable progress determinations for the
purposes of the second implementation period.

4. In the draft SIP UDAQ writes that “Utah has analyzed the WRAP photochemical
modeling for OTB 2028 and found that emissions from Utah do not significantly impact
visibility at CIAs in other states.” While it does not appear that this conclusion impacted
the source selection process, it is not clear how Utah used this conclusion or whether it
influenced their control technology determinations. NPS believes UDAQ’s conclusion is

194 See Appendix D for all FLM RH SIP review documents 195 See Appendix D.1 and D.2 to view the full NPS review of Utah’s RH SIP and supporting cost analyses

188
not compatible with their findings regarding the impact of Utah sources in Class I areas
of neighboring states, and NPS recommends that UDAQ revise this section of the draft
SIP by using a 1% threshold for determining significant impacts.

UDAQ Response: Section 6.A.2 has been revised in response to this comment.

5. Utah requested more information regarding where Utah stands in terms of RAVI for
Class I areas. RAVI is a separate process from periodic SIP revisions. This avenue is
rarely used by the FLMs to address specific sources causing visibility impairment at
Class I areas. The NPS will not likely pursue RAVI certification unless the approaches
identified in the periodic SIP revisions do not adequately address documented
impairment.

6. UDAQ asked for feedback on using prescribed fire data from USFS to adjust projections.
NPS does not take a position on the adjustment of glidepath end points for prescribed
fire. We support UDAQ’s determination to not use glidepath adjustments for estimated
contributions from international emissions.

7. In Table 27: Sources initially selected to perform a Four-Factor analysis in draft SIP,
section 7.A.1, NPS recommends identifying the nearest Class I area referenced in the
“distance to nearest Class I area” column.

UDAQ Response: A column identifying the nearest CIA has been added to Table 27 in
section 7.A.1.

8. In section 8.D.6 there appears to be a typographical error listing Intermountain
Generation Station closing in 2017.

UDAQ Response: The typographical error in section 8.D.6 has been fixed and the
closing year for IGS now reads as 2027.

9. NPS recommends UDAQ revise the permit limits for the Paradox Resources Lisbon
Natural Gas Processing Plant to reflect the assumptions used to exclude this facility from
four-factor analysis. NPS also recommends including the plant’s recent actual emissions
data in the SIP.

UDAQ Response: UDAQ has received 2021 inventory data for the Lisbon Plant and
created an emissions summary with resulting Q/d values in section 7.A.2.

10. NPS recommends that UDAQ conducts or requires a four-factor analysis for the
Intermountain Power Intermountain Generation Station exploring opportunities to

189
improve the efficiency of the existing SO2 scrubbers considering NOx emissions for the
remaining useful life of the facility.

UDAQ Response: UDAQ has been in contact with IGS concerning this matter. UDAQ
believes the station’s existing SO2 scrubbers are sufficient and that the plant is well
controlled. UDAQ has also included IGS’s 2028 closure in the proposed part H language
for this SIP located in Appendix A, which would make the closure federally enforceable.

11. NPS requests that UDAQ provide a breakdown of emissions from the Kennecott units
the state can regulate versus those it cannot regulate. UDAQ should explain how its
PM2.5 SIP includes in-use requirements for this equipment.

UDAQ Response: Section 7.A.2 was revised and a breakdown of Kennecott’s emissions
was included in response to this comment.

12. NPS recommends that UDAQ reduce haze causing SO2 emissions from Hunter and
Huntington facilities by requiring an evaluation of SO2 scrubber optimization and
potential efficiency improvements and implement any technically feasible and cost-
effective options identified.

UDAQ Response: PacifiCorp has provided additional information concerning their
existing SO2 scrubbing196. The existing FGD SO2 controls at the Hunter and Huntington
power plants all have control efficiencies of at least 90% and each unit at these plants
are subject to an SO2 emissions limit of 0.12 lb/mmBtu through their respective Title V
permits. It is PacifiCorp’s stance that these controls are running as efficiently as possible
and there are no cost-efficient upgrades available. The “RPELs” proposed in
PacifiCorp’s original four-factor analysis “combined operational adjustments (such as
reduced until utilization) with incremental capital and O&M costs”. Additionally,
PacifiCorp cited EPA’s 2019 “Guidance on Regional Haze State Implementation Plans
for the Second Implementation Period” (“2019 Guidance”) which recognizes that it “may
be reasonable for a state not to select an effectively controlled source. A source may
already have effective controls in place as a result of a previous regional haze SIP or to
meet another CAA requirement.”197 UDAQ is adding the existing SO2 emission limits for
all five units to SIP Section IX.H23, Source Specific Emission Limitations: Regional Haze
Requirements, Reasonable Progress Controls, to ensure federal enforceability of
PacifiCorp’s SO2 limits in the regional haze context. Section 7.C.3 has been revised to
include this information and additional discussion in response to this NPS comment.

196 Please refer to Appendix D.2.C to view PacifiCorp’s document on Regional Haze Second Planning Period Issues Regarding SO2 Controls for PacifiCorp’s Power Plants
197 See page 22 of https://www.epa.gov/sites/default/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf?VersionId=QC2nPZHuAH1VYmm3EuhV9ABIGm5rQynb.

190
13. NPS generally agrees with UDAQ’s revisions to PacifiCorp’s NOx control technology cost
analyses and used similar adjustments in their cost assessments. NPS also agrees with
UDAQ that PacifiCorp’s demonstration that the interest rate of 7.303% is their site-
specific value and appropriate for use in their four-factor analyses.

14. NPS shares UDAQ’s concerns with PacifiCorp’s RPEL recommendation and support
UDAQ’s rejection of this proposal. RPEL would essentially be a “paper” reduction in
emissions that would not reduce haze-causing emissions affecting visibility in Utah’s
CIAs.

15. NPS suggest that UDAQ could consider environmental co-benefits of NOx emission
reduction as part of this factor. NOx is an ozone pre-cursor emission and ozone is known
to affect both human and ecosystem health.

UDAQ Response: UDAQ recognizes the co-benefits associated with pollutant emissions
reductions and may highlight these benefits in the final draft of this SIP. However, UDAQ
also recognizes the four-factor analysis198 being the primary decision-making tool in this
second implementation period and other benefits do not necessarily impact UDAQ’s
reasonable progress determinations.

16. NPS believes the cost of controls for the Sunnyside Cogeneration Facility are more
economical than the company’s estimates based on their calculations derived from the
EPA Control Cost Manual. NPS disagrees with Sunnyside’s use of a 7% interest rate
and recommends UDAQ consider their control costs using the bank prime interest rate
of 3.25%.

UDAQ Response: Sunnyside Cogeneration provided additional justification found in
Appendix D.2.A for the 7% interest rate they used in their control cost analysis. This rate
was supported by a variety of institutions and most closely matched the financial
indicators known by Sunnyside. UDAQ agrees with the final iterations of Sunnyside’s
estimated control costs.

17. NPS does not believe that Sunnyside has provided sufficient justification to exclude dry
sorbent injection technology as technically feasible.

UDAQ Response: UDAQ has received additional information regarding the feasibility
and cost-effectiveness of dry sorbent injection technology from Sunnyside which has
been included in Appendix D.2.G.

198 Please refer to section 7.B to view the four factors used to determine control feasibility in this implementation period.

191
18. NPS’s review of the Ash Grove Leamington Cement Plant suggests potential
improvements may be available for their existing SNCR system. NPS recommends
UDAQ request further evaluation of this opportunity to reduce NOx emissions from the
facility.

UDAQ’s Response: In response to UDAQ’s four-factor analysis evaluation, Ash Grove
provided additional information on the efficiency of their SNCR system199. Based on this
information, UDAQ believes this facility is well controlled for the purposes of this
implementation period.

19. NPS’s review of the Graymont Cricket Mountain Plant finds that their permitted
emissions levels are significantly higher than their recent emissions levels. NPS believes
the costs of controls would be more cost effective if emissions increased to permitted
levels. NPS recommends UDAQ consider tightening permitted emissions limits for NOx
and SO2 to reflect future potential emissions and prevent backsliding.

UDAQ Response: UDAQ contacted Graymont concerning their permitted emissions
levels. The Cricket Mountain facility has seen a decrease in production over the past few
years with special emphasis on the impacts of the COVID-19 pandemic. Graymont views
this as a temporary decrease as the market is currently in the midst of recovery while
they anticipate growth in their market. As this decrease is temporary, Graymont does not
foresee the need to reduce its limits at this facility as it could reduce their flexibility to
meet the market recovery and growth.

20. NPS recommends that numerical NOx and SO2 emissions limits be incorporated into US
Magnesium’s current permit for the turbines/duct burners, chlorine reduction burner,
melt/reactor, riley boiler, and the diesel engines would ensure that reasonable progress
assumptions and determinations for the facility are adhered to.

UDAQ Response: UDAQ issued an order to US Magnesium to obtain the information
required to respond to these comments. USM provided responses on April 26th and May
11th, 2022 which can be found in Appendix D.2.E and F.

21. NPS recommends UDAQ re-evaluate the feasibility and costs of US Magnesium
installing SCR on their turbines.

UDAQ Response: See response to comment 20.

22. NPS recommends UDAQ reconsider requiring implementation of SCR on US
Magnesium’s riley boiler as part of this implementation period. Additionally, actual
emission assumptions relied on to eliminate SCR from consideration be reflected in
permit limitations for this unit.
199 Located in section 7.C.1 in Ash Grove’s Evaluation Response

192

UDAQ Response: See response to comment 20.

23. NPS requests additional information and emissions verification on US Magnesium’s
diesel engines and engine replacement and/or electrification be included as additional
emission control options in their four-factor analysis.

UDAQ Response: See response to comment 20.

24. NPS recognizes the jurisdictional complexity of the Uintah and Paradox basins with 80%
of the land being under tribal and EPA control. However, NPS recommends that air
quality improvement will require cooperative and commensurate efforts from all agencies
involved in air quality management in the basin and suggests UDAQ implement
statewide rules to address oil and gas emission sources throughout Utah.

UDAQ Response: Over the past several years, UDAQ has proposed and adopted a
series of statewide rules specific to oil and gas operations found in Utah’s state
administrative rules R307-500 to 511. Though these rules have been focused on
controlling VOC emissions, there is also a state-specific rule for natural gas-powered
engines associated with oil and gas production. Since the rule was put in place in 2018,
several sources have provided engine stack test data that have led UDAQ, EPA, and the
Tribes to initiate further research and compliance studies on engines in the Basin, with a
focus on two-stroke smaller horsepower engines that power pump jacks associated with
oil-producing wells. The data collected have indicated lower values for NOx emissions
than what was reported in the 2017 oil and gas emission inventory for these engines, yet
much higher emissions of VOCs. UDAQ will be evaluating this data and will be
evaluating future rulemaking for engines associated with oil and gas operations that
would be statewide. UDAQ will coordinate with EPA and the Tribe to encourage that
rules are consistent across all regulatory jurisdictions, but ultimately any controls under
EPA jurisdiction on sources in Indian Country will be determined by EPA and the Tribe.

The main pollutant of concern in the Uinta Basin is ozone, with VOCs and NOx being the
actual precursor emissions that create ozone. Photochemical modeling has been a
challenge in this area due to the complexity of the chemical reactions and unique
geography and wintertime conditions. Therefore, it has not yet been determined what
emission reductions will be the most effective to lower ozone values. However, initial
thoughts are that the area is NOx limited. If this is shown to be the case, then NOx
reductions will have a greater impact and as about 80% of NOx emissions in the Basin
are associated with engines, UDAQ will definitely evaluate the reduction in NOx limits. As
part of this evaluation, UDAQ will also keep in mind the NPS comments regarding the
potential positive impacts on regional haze management. In summary, the evaluation of
potentially lower VOC and NOx limits for engines associated with oil and gas production
is actively in progress and Utah is working on further controlling NOx from engines for

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separate health standards.

9.C.3 USFS Feedback Summary and UDAQ Responses200
The USFS recognizes the emission reductions made in Utah over the past decade that have
resulted in improvements in visibility at the Forest Service Class I Wilderness Areas and
appreciates the working relationship among our respective staff. Overall, the USDA Forest
Service found that the draft RH SIP is well organized and comprehensive. The Long-Term
Strategies for this planning period appear to indicate that Forest Service Class I Wilderness
Areas will continue to show visibility improvements better than the Uniform Rate of Progress
(URP) through 2028, and USFS appreciates the commitment by UDEQ to evaluate progress in
meeting the visibility goals during the 5-year progress reports.

40 CFR 51.308(f)(1)(vi)(B) allows states to adjust the glidepath to account for prescribed fire.
The draft SIP states that no glidepath adjustment was made to account for prescribed fire
emissions. The USFS encourages Utah DEQ to use the adjustment of glidepaths for the
increased prescribed fire projections reflected in the “Future Fire Scenario 2” available in
Product 18 of Modeling Express Tools of the WRAP TSS.

When considering the Rx fire end-point adjustment, the USFS is concerned that industry or
other groups could improperly argue that additional controls are not necessary to make further
progress if modeling demonstrates that the Class I Area in Utah is below adjusted glidepaths,
essentially arguing that the glidepath provides safe harbor from additional control requirements.
The USFS believes this “safe harbor” argument is erroneous and is not supported by the
Regional Haze Rule.

UDAQ Response: UDAQ appreciates the feedback from USFS as well as their work on the
wildland prescribed fire adjustment. UDAQ acknowledges the visibility impacts expected future
increases in wildland prescribed fire may have on Utah as well as the importance of prescribed
fire for conservation. However, the impact of USFS’s glidepath adjustment is less significant for
Utah’s CIAs than for those in other states. While the international and wildland prescribed fire
adjustments are available for Utah’s CIA glidepaths, UDAQ is choosing to remain conservative
for the purposes of this implementation period by not using them. However, this choice does not
preclude the use of glidepath adjustments in future planning periods, since international and
wildland prescribed fire emissions do impact Utah CIAs and are largely beyond the control of
individual states and since prescribed fires are seen to be an increasingly important tool for land
managers in the future.
200 See Appendix D.3 to view the full USFS RH SIP review document

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9.D Coordination with Indian tribes
Utah has five major tribes: the Ute, Dine’ (Navajo), Paiute, Goshute, and Shoshone. There is
one source in Northeast Utah where the Bonanza Power Plant is situated, but it resides in EPA
jurisdiction. UDAQ sent the regional haze SIP draft to the tribes in Utah on December 9th, 2021,
concurrently with submission to EPA and FLMs for a 60-day review. UDAQ has received no
feedback from the tribes as of the submittal of this SIP. Documentation of this outreach can be
found in Appendix E.
9.E Stakeholder Outreach and Communication
In the process of developing this SIP, Utah has been in contact with the five major sources
subject to a four-factor analysis for controls feasibility. Upon evaluation of the five source’s
original four-factor analysis submittals, Utah evaluated and requested responses from each of
the sources. This correspondence is summarized in Chapter 7. Utah has had several meetings
with PacifiCorp concerning the implementation of controls in its Hunter and Huntington facilities.
Utah also holds regular industry stakeholder meetings and environmental advocate meetings to
update these groups on Utah’s regional haze planning progress and address any questions or
concerns they have regarding regional haze. Throughout the second implementation period,
Utah also met with other state departments for coordination including the Department of Public
Utilities and the Office of Energy Development.
Table 70: Summary of Stakeholder Meetings with UDAQ
Date Time Entity Topic Result
Figure 69: USFS Fire Glidepath Adjustment for Bryce Canyon

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4/27/21 4-5p PacifiCorp and Wyoming Regional Haze Pre-Meeting Discussed possible controls and power plant planning. 5/19/21 2-3p Air Quality Advocates DAQ-Utah Advocates Regional Haze Catch Up
Introduction to members of HEAL Utah, Sierra Club, and NPCA. They expect requirements for additional controls at power plants, especially Hunter and Huntington. 6/23/21 12-1:05p PacifiCorp Presentation on legal risks and 4-factor evaluation
Discussed possible controls and issues with 4-factor analysis.
7/7/21 10:30a-12p RH Advocates Meeting RH Update Gave RH updates and discussed guidance vs rule issue. 7/15/21 3:30-4:30p DAQ, OED, DPU RH and Power Plant Planning Gave RH overview/update, informed them of PacifiCorp 4-factor eval, control options, and rule vs. guidance. 7/19/21 9a PacifiCorp RH primer scheduling Kirsten Merrit called about times for RH backgrounder. 7/20/21 9:15a PacifiCorp RH primer scheduling Kirsten Merrit called about invitees for RH backgrounder. 10/27/21 8-9a PacifiCorp RH Follow-Up/Update We discussed implementing new PALs for Hunter based on the emissions reductions installing SCR on Hunter 3 would have and Huntington based on their recent actuals in the 2028OTB modeling.
11/3/21 10:30-11:30a Air Quality Advocates RH Update Gave presentation with RH overview, Utah’s RH history, current planning, and updated timeline for Utah’s round two SIP.
11/10/21 11a-12p NPCA, Western Resources, & Sierra Club
RH Presentation Follow-Up UDAQ addressed additional question resulting from the presentation given at the Air Quality Advocates Meeting.
12/3/21 11a-12p PacifiCorp RH Update Discussed control options for Hunter and Huntington.
1/5/22 10:30- 11:30a Air Quality Advocates RH Update Offered to send the draft UT RH SIP to those who requested it via email.
1/26/22 11:49a Sunnyside Information Submittal Sunnyside provided control cost spreadsheets via email by NPS request 3/2/22 10-11:30a Air Quality Advocates RH Update Offered to send the FLM comment documents to those who requested it via email. 3/4/22 10-10:15a PacifiCorp – Kirsten Merrit RH Information Offered technical responses to FLM comments concerning the Hunter and Huntington power plants 3/14/22 2-3p Paradox Resources RH Planning Met with Paradox Resources to discuss FLM comments regarding their source, updating their permit for the Lisbon Plant, and obtaining 2021 inventory data.
3/17/22 3-4p PacifiCorp RH Planning Discussed PacifiCorp’s SO2 scrubbing equipment and efficiency as well as the possibility of optimization. 3/14/22 2-3p Paradox Information Request Discussed emissions inventory data.
3/14/22 1:12p Sunnyside Interest Rates Sunnyside provided interest rate justification via email.
3/17/22 4:12p PacifiCorp SO2 Scrubbing PacifiCorp provided additional justification for SO2 scrubbing
3/21/22 1-2p Sunnyside Information Request Discussed DSI feasibility.
4/18/22 1-2p PacifiCorp RH Discussion Discussed future utilization.
4/20/22 4:42p PacifiCorp EPA Comments UDAQ provided EPA public comments.
5/4/22 10-11:30a Air Quality Advocates RH Update UDAQ provided the advocates with a RH update.
5/24/22 1:30-2:30p Sunnyside NPS Comment Questions Sunnyside requested clarification on NPS comments. 5/24/22 2p PacifiCorp Public Hearing Discussed public hearing logistics.
5/27/22 11:58a Sunnyside Public Comment Submittal Sunnyside submitted public comments.
5/31/22 4:25p PacifiCorp Public Comment Submittal PacifiCorp provided public comments on the RH SIP.

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6/10/22 1-2p PacifiCorp RH Information Discussed SO2 scrubbing.
6/22/22 10-11a Sunnyside Water Rights/CDS Discussed water rights and CDS feasibility. Sunnyside provided additional documentation via email.
6/22/22 10:05a PacifiCorp Air Preheaters PacifiCorp provided information on air preheater costs.

9.F Public Comment Period
Utah’s RH SIP for the second implementation period was presented to the Air Quality Board at
their April 6th, 2022 meeting. The Board approved a 30-day public comment period beginning
on May 1st, 2022 and ending on May 31st, 2022. Notices regarding the public comment period
and availability of the SIP draft were published in the State Bulletin, posted on the UDAQ
webpage, published in the Salt Lake Tribune (04/26/2022), Deseret News (04/27/2022) and the
Spectrum (05/01/2022), and the AQ board actions update. UDAQ held a public hearing on May
26th, 2022 for the submission of verbal comments. UDAQ’s public notice was published on
UDAQ’s webpage from April 30th to June 2nd, 2022. Documentation of this notice can be found
in Appendix F.
9.G Comment Conclusions
During the public comment period, UDAQ received written and verbal comments from the
following:
• EPA • Sunnyside Cogeneration
• NPS • Intermountain Power Service Corporation
• The Conservation Organizations201 • Utah Associated Municipal Power Systems
• Utah Petroleum Association • City of Moab
• Utah Mining Association • Grand County Commission
• PacifiCorp • 657 individuals
• US Magnesium

201 Comments submitted jointly by the National Parks Conservation Association, Sierra Club, Utah Physicians for a Healthy Environment, The Coalition to Protect America’s National Parks, the Healthy Environmental Alliance of Utah, and O2 Utah

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UDAQ reviewed all comments202 which are summarized by topic and responded to in Appendix
H. Some comments resulted in SIP revisions which include:
• Updated inventory graphs in Section 3.A.4 upon request from the Air Quality Board.
• Section 6.A.10 was updated with a table detailing emission reduction quantification for
the long-term strategy. Strategies were not changed; the table was added for
clarification.
• A new table in Section 7.A.2 to show existing controls in Utah’s SIP for screened
sources that have resulted from other SIP revisions, including PM2.5.
• Part of section 7.A.3 was struck out and rewritten for clarity and improved justification for
emission limits at Hunter and Huntington power plants.
• An environmental justice analysis and writeup was added to section 7.A.5.
• Additions to appendices to include additional information that sources have submitted.
• Multiple minor additions or deletions due to oversights, or for clarifications.
• SIP Subsection IX.H.23 changes include:
o emission limits for screened-in sources’ existing limits that were not already in
IX.H,
o annual stack testing at US Magnesium,
o SO2 limit exemptions were removed for startup, shutdown, and malfunction for
Huntington, and
o minor adjustments to Hunter and Huntington limits based on the improved
justification.
9.H Commitment to Further Planning
Utah will continue its regional haze planning efforts through consultation efforts, participation in
regional haze work groups, and SIP development.
9.H.1 Process for conducting future emissions inventories and future monitoring
strategy
Utah will continue to triennially update its statewide emissions inventory as dictated by the Air
Emissions Reporting Requirements (AERR)203 and Utah’s Continuous Emissions Monitoring
Program204 to track regional haze progress, participate in regional haze modeling efforts, and
track emissions trends.

202 All public comments received by UDAQ on this SIP revision can be found on UDAQ’s Current
Regional Haze Planning web page here: https://deq.utah.gov/air-quality/regional-haze-in-utah#planning
203 73 Fed. Reg. 76539, 76552 (Dec. 17 2008). The AERR rule can be found at https://www.epa.gov/air-emissions-inventories/air-emissions-reporting-requirements-aerr 204 Utah Admin. Code r. R307-170.

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9.H.2 Commitment to provide other elements necessary to report on visibility, including
reporting, recordkeeping, and other measures
Utah will provide any additional reporting, recordkeeping, and other measures necessary to
continue its regional haze progress deemed necessary by the EPA or the regional haze work
groups Utah participates in. At this time, no such additional efforts have been identified.
9.H.3 Commitment to submit January 31, 2025 progress report
Under the RHR, states must submit periodic progress reports to EPA evaluating their progress
towards their RPGs. The 2017 RHR amendments adjusted the next progress report due date to
be submitted by January 31, 2025. Utah commits to submitting this progress report and
confirms that it will contain the following elements pursuant to the RHR:205
• Status of implementation of SIP measures for RPGs in Utah’s CIAs and those outside
the State identified as being impacted by emissions from within the state.
• Summary of emissions reductions in Utah adopted or identified as part of the RPG
strategy.
• A five-year annual average assessment of the most and least impaired days for each
CIA in Utah including the current visibility conditions, difference between current
conditions and baseline, and change in visibility impairment over the five-year period.

205 See page 6 of https://gardner.utah.edu/wp-content/uploads/ERG2022-Full.pdf?x71849.