DAQ-2025-001016

DAQE-AN130310014-25

{{$d1 }}

Brett Shakespear
PacifiCorp
1407 West North Temple, Suite 310
Salt Lake City, UT 84116
[e-mail]

Dear Mr. Shakespear:

Re: Approval Order: Administrative Amendment to Approval Order DAQE-AN130310012-15 to
Update Description of Equipment
Project Number: N130310014

The attached Approval Order (AO) is issued pursuant to the Notice of Intent (NOI) received on August
28, 2024. PacifiCorp must comply with the requirements of this AO, all applicable state requirements
(R307), and Federal Standards.

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

Sincerely,

{{$s }}

Bryce C. Bird
Director

BCB:JJ:jg

cc: Utah County Health Department
EPA Region 8

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

SPENCER J. COX
Governor
DEIDRE HENDERSON
Lieutenant Governor

Department of
Environmental Quality

Kimberly D. Shelley
Executive Director

DIVISION OF AIR QUALITY
Bryce C. Bird
Director

February 13, 2025

STATE OF UTAH
Department of Environmental Quality
Division of Air Quality

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APPROVAL ORDER
DAQE-AN130310014-25
Administrative Amendment to Approval Order
DAQE-AN130310012-15 to Update
Description of Equipment

Prepared By
John Jenks, Engineer
[phone]
[e-mail]

Issued to
PacifiCorp - Lake Side Power Plant

Issued On
{{$d2 }}

Issued By

{{$s }}

Bryce C. Bird
Director
Division of Air Quality

February 13, 2025
TABLE OF CONTENTS

TITLE/SIGNATURE PAGE ....................................................................................................... 1
GENERAL INFORMATION ...................................................................................................... 3
CONTACT/LOCATION INFORMATION ............................................................................... 3
SOURCE INFORMATION ........................................................................................................ 3
General Description ................................................................................................................ 3
NSR Classification .................................................................................................................. 3
Source Classification .............................................................................................................. 3
Applicable Federal Standards ................................................................................................. 3
Project Description.................................................................................................................. 4
SUMMARY OF EMISSIONS .................................................................................................... 4
SECTION I: GENERAL PROVISIONS .................................................................................... 4
SECTION II: PERMITTED EQUIPMENT .............................................................................. 5
SECTION II: SPECIAL PROVISIONS ..................................................................................... 7
PERMIT HISTORY ................................................................................................................... 15
ACRONYMS ............................................................................................................................... 16

DAQE-AN130310014-25
Page 3

GENERAL INFORMATION

CONTACT/LOCATION INFORMATION

Owner Name Source Name
PacifiCorp PacifiCorp - Lake Side Power Plant

Mailing Address Physical Address
1407 West North Temple, Suite 310 1825 North Pioneer Lane
Salt Lake City, UT 84116 Vineyard, UT 84058

Source Contact UTM Coordinates
Name: Joshua Sewell 436,000 m Easting
Phone: [phone],464,500 m Northing
Email: [e-mail] Datum NAD27
UTM Zone 12
SIC code 4911 (Electric Services)

SOURCE INFORMATION
General Description
The PacifiCorp Lake Side Power Plant is a natural gas-fired electric generating facility consisting of two
(2) electricity-generating blocks. Lake Side Block #1 consists of two (2) natural gas combustion turbines
(CTs) (each with a projected average output rating of 165 MW) with heat recovery steam generators
(HRSGs) and one (1) steam turbine with a projected average output rating of 240 MW. Lake Side Block
#2 consists of two (2) natural gas-fired CT’s (each with a projected average output rating of 200 MW)
with HRSGs and one (1) steam turbine with a projected average output rating of 229 MW. Each
CT/HRSG unit is equipped with a selective catalytic reduction (SCR) system and a CO oxidation catalyst.

NSR Classification
Administrative Amendment

Source Classification
Located in Provo UT PM2.5 NAA
Utah County
Airs Source Size: A

Applicable Federal Standards
NSPS (Part 60), A: General Provisions
NSPS (Part 60), Db: Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units
NSPS (Part 60), Dc: Standards of Performance for Small Industrial-Commercial-Institutional
Steam Generating Units
NSPS (Part 60), GG: Standards of Performance for Stationary Gas Turbines
DAQE-AN130310014-25
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NSPS (Part 60), IIII: Standards of Performance for Stationary Compression Ignition Internal
Combustion Engines
NSPS (Part 60), KKKK: Standards of Performance for Stationary Combustion Turbines
MACT (Part 63), YYYY: National Emission Standards for Hazardous Air Pollutants for
Stationary Combustion Turbines
MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for
Stationary Reciprocating Internal Combustion Engines
Title IV (Part 72 / Acid Rain)
Title V (Part 70) Major Source

Project Description
PacifiCorp intends to upgrade the existing CT’s and install ultra-low NOx burners on Block 1 of its Lake
Side Power Plant. These upgrades will increase fuel burn efficiency, decrease minimum operating levels,
and provide the capability to incorporate 30% hydrogen co-firing. The plant will continue to operate
Block 1 within the current emission limitations in the Title V Operating Permit, AO
DAQE-AN1303100012-15, and relevant State Implementation Plans.

SUMMARY OF EMISSIONS

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

Criteria Pollutant Change (TPY) Total (TPY)
CO2 Equivalent 0 3.62
Carbon Monoxide 0 1139.60
Nitrogen Oxides 0 280.90
Particulate Matter - PM10 0 215.40
Particulate Matter - PM2.5 0 215.40
Sulfur Dioxide 0 55.60
Volatile Organic Compounds 0 169.70

Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Formaldehyde (CAS #50000) 0 12400
Total HAPs (CAS #THAPS) 0 54800
Change (TPY) Total (TPY)
Total HAPs 0 33.60

SECTION I: GENERAL PROVISIONS

I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions refer to those rules. [R307-101]
I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]
DAQE-AN130310014-25
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I.3 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1] I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon
request, and the records shall include the five-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five (5) years. [R307-415-6b]

I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO, including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4]
I.6 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]

I.7 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. [R307-107]

SECTION II: PERMITTED EQUIPMENT
II.A THE APPROVED EQUIPMENT II.A.1 Lake Side Power Plant Permitted Source
II.A.2 CT #1 and #2 Two (2) natural gas-fired ultra-low-NOx, combined cycle turbines, each with 150-foot stack (as measured from the base of the stack) II.A.3 HRSG #1 and #2 Two (2) HRSGs, each equipped with low NOx duct burner - 184 MMBtu/hr
II.A.4 Block #1 SCR Two (2) SCR systems with ammonia injection, one for each turbine/HRSG set II.A.5 Block #1 CO Catalysts Two (2) CO catalysts, one for each turbine/HRSG set
II.A.6 Block #1 Steam Turbine One (1) steam turbine II.A.7 Auxiliary Boiler #1 One (1) natural gas-fired 62.765 MMBtu/hr (nameplate rating) auxiliary boiler with 50 ft. boiler stack (as measured from the base of the stack)
DAQE-AN130310014-25
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II.A.8 Cooling Tower #1 One (1) 10 Cell mechanical draft evaporative cooling tower with drift elimination II.A.9 CT #3 and #4 Two (2) natural gas-fired dry low-NOx, combined cycle turbines, each with 150-foot stack (as
measured from the base of the stack)
II.A.10 HRSG #3 and #4 Two (2) HRSGs, each equipped with low NOx duct burner approximately 400 MMBtu/hr II.A.11 Block #2 SCR Two (2) SCR systems with ammonia injection, one for each turbine/HRSG set

II.A.12 Block #2 CO Catalysts Two (2) CO catalysts, one for each turbine/HRSG set
II.A.13 Block #2 Steam Turbine One (1) steam turbine

II.A.14 Auxiliary Boiler #2 One (1) natural gas-fired 57.6 MMBtu/hr (nameplate rating) auxiliary boiler with 60 ft. boiler stack (as measured from the base of the stack)
II.A.15 Cooling Tower #2 One (1) 16 Cell mechanical draft evaporative cooling tower with drift elimination

II.A.16 Fuel Dew Point Heater One (1) 4.76 MMBtu/hr (nameplate rating) fuel dew point heater
II.A.17 Emergency Generator
Two (2) approximately 1,500 hp diesel-fired emergency generators
II.A.18 Fire Pump One (1) 290 hp diesel-fired fire pump II.A.19 Water Treatment
Water treatment and storage facilities

II.A.20 Ammonia Storage and Handling Aqueous ammonia storage and handling equipment
II.A.21 Miscellaneous Equipment CT lube oil vent system, maintenance shop vent system, machining and welding operations, etc.

II.A.22 Lake Side Block #1 Lake Side Block #1 consists of CT #1 and #2, associated HRSGs, control equipment, an auxiliary boiler, and a cooling tower
II.A.23 Lake Side Block #2
Lake Side Block #2 consists of CT #3 and #4, associated HRSGs, control equipment, an auxiliary
boiler, and cooling tower

II.A.24 Additional Equipment Fuel treatment, fire suppression, water treatment, ammonia storage, and other misc. equipment

DAQE-AN130310014-25
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SECTION II: SPECIAL PROVISIONS
II.B REQUIREMENTS AND LIMITATIONS

II.B.1 Conditions on Permitted Source
II.B.1.a The owner/operator shall install, calibrate, maintain, and operate a continuous emissions
monitoring system (CEMS) on each of the HRSG stacks. The owner/operator shall record the
NOx and CO emissions. The monitoring system shall comply with all applicable sections of
R307-170, 40 CFR 13, and 40 CFR 60, Appendix B. The NOx monitor shall comply with 40
CFR 75, Appendix A and B.

All CEM devices as required in federal regulations and state rules shall be installed prior to
placing the affected source in operation. These devices shall be certified within 90 days of
achieving full load, not to exceed 180 days after startup.

Except for system breakdown, repairs, calibration checks, and zero and span adjustments
required under paragraph (d) 40 CFR 60.13, the owner/operator of an affected source shall
continuously operate all required continuous monitoring systems and shall meet minimum
frequency of operation requirements as outlined in R307-170 and 40 CFR 60.13. [R307-170]

II.B.1.b Visible emissions shall not exceed the following values: All natural gas combustion exhaust stacks - 10% opacity All other emission points - 20% opacity. Opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9. [R307-401-8]
II.B.2 Conditions on Lake Side Block #1
II.B.2.a The owner/operator shall use natural gas as fuel in the CT’s, duct burners, and auxiliary boiler. [R307-401-8]
II.B.2.b Emissions to the atmosphere from the indicated emission point(s) shall not exceed the following
rates and concentrations:

Source: Auxiliary Boiler #1

Pollutant Limitations Averaging Period
PM10 0.01 lb/MMBtu 3-hour
NOx 0.017 lb/MMBtu 3-hour
CO 0.037 lb/MMBtu 3-hour

Source: Each Turbine/HRSG Stack (at Block #1)

Pollutant Limitations Averaging Period PM10 10.8 lb/hour (0.01 lb/MMBtu) 30-day rolling average
NOx 2.0 ppmvd at 15% O2 (14.9 lb/hr)* 3-hour
CO 3.0 ppmvd at 15% O2 (14.1 lb/hr)* 3-hour
* Under steady-state operation.
[R307-401-8]

DAQE-AN130310014-25
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II.B.2.c Stack testing to show compliance with the emission limitations stated in the above condition shall be performed as specified below: Emissions Point Pollutant Status Frequency HRSG Stacks PM10/PM2.5 * $ NOx * # CO * # Auxiliary Boilers PM10 * % NOx * % CO * % Testing Status (To be applied to the sources listed above) * Initial compliance testing has been completed. If an existing source is modified, a compliance test is required on the modified emission point that has an emission rate limit. $ Test every year, or testing may be replaced with parametric monitoring if approved by the Director. % Test every five (5) years, or testing may be replaced with parametric monitoring if approved by the Director. # Compliance shall be demonstrated through use of a CEMS as outlined in Condition II.B.1.c. The Director may require testing at any time. [R307-165]
DAQE-AN130310014-25
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II.B.2.d For all emissions testing, the following shall apply: Notification: The Director shall be notified at least 30 days prior to conducting any required emission testing. A source test protocol shall be submitted to DAQ when the testing notification is submitted to the Director. The source test protocol shall be approved by the Director prior to performing the test(s). The source test protocol shall outline the proposed test methodologies, stack to be tested, and procedures to be used. A pretest conference shall be held if directed by the Director. Sample Location: The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, or other methods as approved by the EPA and acceptable to the Director. An Occupational Safety and Health Administration (OSHA) or Mine Safety and Health Administration (MSHA) approved access shall be provided to the test location. Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2, or the EPA Test Method No. 19 "SO2 Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing methods approved by the EPA and acceptable to the Director. PM10: For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a, and 202, or other testing methods approved by the EPA and acceptable to the Director. All particulates captured shall be considered PM10. The back half condensable shall be used for compliance demonstration as well as for inventory purposes. For stacks in which liquid drops are present, methods to eliminate the liquid drops should be explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing methods approved by the EPA and acceptable to the Director. The back half condensable shall also be tested using the method specified by the Director. The portion of the front half of the catch considered PM10 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director. PM2.5: For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a, and 202, or other testing methods approved by the EPA and acceptable to the Director. All particulates captured shall be considered PM2.5. For stacks in which liquid drops are present, methods to eliminate the liquid drops should be explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing methods approved by the EPA and acceptable to the Director. The back half condensable shall also be tested using the method specified by the Director. The portion of the front half of the catch considered PM2.5 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director. NOx: 40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by the EPA and acceptable to the Director. CO: 40 CFR 60, Appendix A, Method 10, or other testing methods approved by the EPA and acceptable to the Director. Calculations: To determine mass emission rates (lb/hr, etc.), the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Director to give the results in the specified units of the emission limitation. [R307-165]
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II.B.2.e Compliance with the 3-hour NOx and CO emission limitations specified in Condition II.B.2.b shall not be required during short-term excursions, limited to a cumulative total of 160 hours per rolling 12-month period. Short-term excursions are defined as 15-minute periods designated by the owner/operator that are the direct result of transient load conditions, not to exceed four consecutive 15-minute periods, when the 15-minute average NOx and CO concentrations exceed 2.0 ppmv and 3.0 ppmv, dry @ 15% O2, respectively. Transient load conditions include the following: 1. Initiation/shutdown of combustion turbine inlet air-cooling 2. Rapid combustion turbine load changes 3. Initiation/shutdown of HRSG duct burners 4. Provision of ancillary services and automatic generation control. During periods of transient load conditions, the NOx concentration shall not exceed 25 ppmv, and the CO concentration shall not exceed 50 ppmv, dry @ 15% O2. All NOx and CO emissions during these events shall be included in all calculations of annual mass emissions as required by this permit. [R307-401-8]
II.B.2.f Steady-state operation means all periods of combustion turbine operation, except for periods of startup and shutdown as defined below, and periods of transient load conditions as defined in
Condition II.B.2.e. Startup is defined as the period beginning with turbine initial firing until the
unit meets the ppmvd emission limits in the first table of Condition II.B.2.b for steady-state operation. Shutdown is defined as the period beginning with the initiation of turbine shutdown
sequence and ending with the cessation of firing of the gas turbine engine. Startup and shutdown
events shall not exceed 613.5 hours per turbine per rolling 12-month period and are counted toward the applicable annual emission limitations. Total startup and shutdown events shall not
exceed 14-hours per turbine in any one calendar day, commencing at midnight. Emissions during
startup and shutdown periods shall be counted toward the applicable annual emission limitations. [R307-401-8]

II.B.3 Conditions on Lake Side Block #2
II.B.3.a The owner/operator shall use natural gas as fuel in the CT’s, duct burners, and auxiliary boiler. [R307-401-8]

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II.B.3.b Emissions to the atmosphere from the indicated emission point(s) shall not exceed the following rates and concentrations: Source: Auxiliary Boiler #2 Pollutant Limitations Averaging Period PM10/PM2.5 0.01 lb/MMBtu 3-hour NOx 0.017 lb/MMBtu 3-hour CO 0.037 lb/MMBtu 3-hour VOC 0.006 lb/MMBtu 3-hour Source: Each Turbine/HRSG Stack (at Block #2) Pollutant Limitations Averaging Period PM10/PM2.5 14 lb/hour (with duct firing) 30-day rolling average NOx 2.0 ppmvd at 15% O2 (18.1 lb/hr)* 3-hour CO 3.0 ppmvd at 15% O2 (16.6 lb/hr)* 3-hour VOC 2.8 ppmvd at 15% O2* 3-hour * Under steady-state operation. [R307-401-8]
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II.B.3.c Stack testing to show compliance with the emission limitations stated in the above condition shall be performed as specified below: Emissions Point Pollutant Status Frequency HRSG Stacks PM10/PM2.5 * $ NOx * # CO * # VOC * & Auxiliary Boilers PM10/PM2.5 * % NOx * % CO * % VOC * % Testing Status (To be applied to the sources listed above) * Initial compliance testing is required. The initial test date shall be performed as soon as possible and in no case later than 180 days after the startup of a new emission source, an existing source without an AO, or the granting of an AO to an existing emission source that has not had an initial compliance test performed. If an existing source is modified, a compliance test is required on the modified emission point that has an emission rate limit. $ Test every year, or testing may be replaced with parametric monitoring if approved by the Director. & Test every two (2) years, or testing may be replaced with parametric monitoring if approved by the Director. % Test every five (5) years, or testing may be replaced with parametric monitoring if approved by the Director. # Compliance shall be demonstrated through use of a CEMS as outlined in Condition II.B.1.c. The Director may require testing at any time. [R307-165]
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II.B.3.d For all emissions testing, the following shall apply: Notification: The Director shall be notified at least 30 days prior to conducting any required emission testing. A source test protocol shall be submitted to DAQ when the testing notification is submitted to the Director. The source test protocol shall be approved by the Director prior to performing the test(s). The source test protocol shall outline the proposed test methodologies, the stack to be tested, and procedures to be used. A pretest conference shall be held if directed by the Director. Sample Location: The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, or other methods as approved by the EPA and acceptable to the Director. An OSHA or MSHA approved access shall be provided to the test location. Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2, or the EPA Test Method No. 19 "SO2 Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing methods approved by the EPA and acceptable to the Director. PM10/PM2.5: For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a, and 202, or other testing methods approved by the EPA and acceptable to the Director. All particulates captured shall be considered PM10/PM2.5. The back half condensable shall be used for compliance demonstration as well as for inventory purposes. For stacks in which liquid drops are present, methods to eliminate the liquid drops should be explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing methods approved by the EPA and acceptable to the Director. The back half condensable shall also be tested using the method specified by the Director. The portion of the front half of the catch considered PM10/PM2.5 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director. NOx: 40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by the EPA and acceptable to the Director. CO: 40 CFR 60, Appendix A, Method 10, or other testing methods approved by the EPA and acceptable to the Director. Calculations: To determine mass emission rates (lb/hr, etc.), the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Director, to give the results in the specified units of the emission limitation. [R307-165]
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II.B.3.e Compliance with the 3-hour NOx and CO emission limitations specified in Condition II.B.3.b shall not be required during short-term excursions, limited to a cumulative total of 160 hours per rolling 12-month period. Short-term excursions are defined as 15-minute periods designated by the owner/operator that are the direct result of transient load conditions, not to exceed four consecutive 15-minute periods, when the 15-minute average NOx and CO concentrations exceed 2.0 ppmv and 3.0 ppmv, dry @ 15% O2, respectively. Transient load conditions include the following: 1. Initiation/shutdown of combustion turbine inlet air-cooling 2. Rapid combustion turbine load changes 3. Initiation/shutdown of HRSG duct burners 4. Provision of Ancillary Services and Automatic Generation Control. During periods of transient load conditions, the NOx concentration shall not exceed 25 ppmv, and the CO concentration shall not exceed 50 ppmv, dry @ 15% O2. All NOx and CO emissions during these events shall be included in all calculations of annual mass emissions as required by this permit. [R307-401-8] II.B.3.f Steady-state operation means all periods of combustion turbine’s operation, except for periods of
startup and shutdown as defined below, and periods of transient load conditions as defined in
Condition II.B.3.e. Startup is defined as the period beginning with turbine initial firing until the unit meets the ppmvd emission limits in the first table of Condition II.B.3.b for steady-state
operation. Shutdown is defined as the period beginning with the initiation of turbine shutdown
sequence and ending with the cessation of firing of the gas turbine engine. Startup and shutdown events shall not exceed 553.6 hours per turbine per rolling 12-month period. Total startup and
shutdown events shall not exceed 8 hours per turbine in any one calendar day, commencing at
midnight.
Emissions of NOx from either Block #2 CT/HRSG unit (CT #3 or #4) shall not exceed 130 lb/hr
during startup or shutdown operations.
Emissions of CO from either Block #2 CT/HRSG unit (CT #3 or #4) shall not exceed 3,000 lb/hr
during startup or shutdown operations.
[R307-401-8]

II.B.3.g Total CO2e emissions from Lake Side Block 2 shall not exceed 950 lb/MWh(g) on a 12-month rolling average basis. Hourly heat input for each turbine and the HSRG will be obtained from the data submitted to the Acid Rain database and summed over the appropriate 12-month period. This total heat input will then be multiplied by an emission factor of 121.723 lb CO2e/MMBtu to obtain the total CO2e emissions during the 12-month period. The 12-month gross generation for each turbine and HSRG will be obtained from the data reported to the Acid Rain database. This hourly generation will be summed over the twelve-month period to obtain the total gross generation. The CO2e per MWH(g) value is calculated by dividing the 12-month total CO2e emissions by the 12-month total gross generation. [R307-401-8]
II.B.4 Conditions on Additional Equipment
II.B.4.a Emergency generators shall be used for electricity-producing operations only during the periods when electric power from the public utilities is interrupted and for regular maintenance and testing. Records documenting generator usage shall be kept in a log, and they shall show the date the generator was used, the duration in hours of the generator usage, and the reason for each generator usage. [R307-401-8]
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II.B.4.b The owner/operator shall use a combination of #1 or #2 fuel oil or diesel fuel in the emergency generators and fire pump. The sulfur content of any #2 fuel oil or diesel fuel burned shall not exceed 0.0015 percent by weight. Sulfur content shall be determined by ASTM Method D-4294-89 or approved equivalent. Certification of fuels shall be either by the owner/operator's own testing or test reports from the fuel marketer or supplier. For purposes of demonstrating compliance with this limitation, the owner/operator may obtain the above specifications by testing each purchase of fuel in accordance with the required methods, by inspection of the specifications provided by the vendor for each purchase of fuel, or by inspection of summary documentation of the fuel sulfur content from the vendor, provided that the above specifications are available from the vendor for each purchase if requested. [R307-401-8]
PERMIT HISTORY

This Approval Order shall supersede (if a modification) or will be based on the following documents: Supersedes AO DAQE-AN130310012-15 dated March 13, 2015 Is Derived From NOI dated August 28, 2024

DAQE-AN130310014-25
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ACRONYMS

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

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

DAQE-

RN130310014 February 4, 2025 Brett Shakespear
PacifiCorp 1407 W. North Temple Suite 310
Salt Lake City, UT 84116 [e-mail]
Dear Brett Shakespear, Re: Engineer Review: Administrative Amendment to Approval Order DAQE-AN130310012-15 to Update Description of Equipment Project Number: N130310014 Please review and sign this letter and attached Engineer Review (ER) within 10 business days. For this document to be considered as the application for a Title V administrative amendment, a Title V Responsible Official must sign the next page.
Please contact John Jenks at [phone] if you have any questions or concerns about the ER. If you accept the contents of this ER, please email this signed cover letter to John Jenks at [e-mail]. After receipt of the signed cover letter, the DAQ will prepare an Approval Order (AO) for signature by the DAQ Director. If PacifiCorp does not respond to this letter within 10 business days, the project will move forward
without your approval. If you have concerns that we cannot resolve, the DAQ Director may issue an Order prohibiting construction. Approval Signature _____________________________________________________________ (Signature & Date)
195 North 1950 West • Salt Lake City, UT
Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820
Telephone [phone] • Fax [phone] • T.D.D. [phone]
www.deq.utah.gov
Printed on 100% recycled paper
Department of Environmental Quality
Kimberly D. Shelley Executive Director DIVISION OF AIR QUALITY Bryce C. Bird Director
State of Utah
SPENCER J. COX Governor DEIDRE HENDERSON Lieutenant Governor

Engineer Review N130310014: PacifiCorp Energy- Lake Side Power Plant February 4, 2025 Page 1
OPTIONAL: In order for this Engineer Review and associated Approval Order conditions to be considered as an application to administratively amend your Title V Permit, the Responsible Official, as
defined in R307-415-3, must sign the statement below. THIS IS STRICTLY OPTIONAL. If you do not want the Engineer Review to be considered as an application to administratively amend your Operating Permit only the approval signature above is required. Failure to have the Responsible Official sign below will not delay the Approval Order, but will require submittal of a separate Operating Permit Application to revise the Title V permit in accordance with R307-415-5a through 5e and R307-415-7a through 7i. A guidance document: Title V Operating Permit Application Due Dates clarifies the required due dates for Title V operating permit applications and can be viewed at:
https://deq.utah.gov/air-quality/permitting-guidance-and-guidelines-air-quality “Based on information and belief formed after reasonable inquiry, I certify that the statements and information provided for this Approval Order are true, accurate and complete and request that this Approval Order be considered as an application to administratively amend the Operating Permit.” Responsible Official _________________________________________________ (Signature & Date) Print Name of Responsible Official _____________________________________

Engineer Review N130310014: PacifiCorp Energy- Lake Side Power Plant February 4, 2025 Page 2
UTAH DIVISION OF AIR QUALITY
ENGINEER REVIEW

SOURCE INFORMATION
Project Number N130310014 Owner Name PacifiCorp
Mailing Address 1407 W. North Temple Suite 310 Salt Lake City, UT, 84116
Source Name PacifiCorp Energy- Lake Side Power Plant Source Location:
1825 N Pioneer Lane Vineyard, UT 84058 UTM Projection 436,000 m Easting, 4,464,500 m Northing UTM Datum NAD27 UTM Zone UTM Zone 12 SIC Code 4911 (Electric Services) Source Contact Joshua Sewell Phone Number [phone] Email [e-mail]
Billing Contact Veronica Reyes Phone Number 8017961916
Email [e-mail] Project Engineer John Jenks, Engineer
Phone Number [phone] Email [e-mail] Notice of Intent (NOI) Submitted August 28, 2024 Date of Accepted Application January 20, 2025

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SOURCE DESCRIPTION General Description
The PacifiCorp Energy Lake Side Power Plant is a natural gas-fired electric generating facility consisting of two electricity generating blocks. Lake Side Block #1 consists of two natural gas combustion turbines (CTs) (each with a projected average output rating of 165 MW) with heat
recovery steam generators (HRSGs) and one steam turbine with a projected average output rating of 240 MW. Lake Side Block #2 consists of two natural gas fired combustion turbines (each with a projected average output rating of 200 MW) with HRSGs and one steam turbine with a projected average output rating of 229 MW. Each CT/HRSG unit is equipped with a selective catalytic reduction (SCR) system and a CO oxidation catalyst. NSR Classification: Administrative Amendment Source Classification Located in , Provo UT PM2.5 NAA,
Utah County Airs Source Size: A
Applicable Federal Standards NSPS (Part 60), A: General Provisions NSPS (Part 60), Db: Standards of Performance for Industrial-Commercial-Institutional Steam
Generating Units NSPS (Part 60), Dc: Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units NSPS (Part 60), GG: Standards of Performance for Stationary Gas Turbines NSPS (Part 60), IIII: Standards of Performance for Stationary Compression Ignition Internal Combustion Engines
NSPS (Part 60), KKKK: Standards of Performance for Stationary Combustion Turbines MACT (Part 63), YYYY: National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines MACT (Part 63), ZZZZ: National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines Title IV (Part 72 / Acid Rain) Title V (Part 70) Major Source
Project Proposal Administrative Amendment to Approval Order DAQE-AN130310012-15 to Update Description of Equipment
Project Description PacifiCorp intends to upgrade the existing combustion turbines and install ultra-low NOx burners
on Block 1 of its Lake Side Power Plant. These upgrades will increase fuel burn efficiency, decrease minimum operating levels, and provide the capability to incorporate 30% hydrogen co-firing. The plant will continue to operate Block 1 within the current emission limitations in the
Title V Operating Permit, Approval Order DAQE-AN0 1303100012-15, and relevant State Implementation Plans.

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EMISSION IMPACT ANALYSIS This is an administrative change to update the description of the equipment in Block 1. There is no change in
emissions from this project. No modeling is required [Last updated January 28, 2025]

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SUMMARY OF EMISSIONS
The emissions listed below are an estimate of the total potential emissions from the source. Some rounding of emissions is possible.
Criteria Pollutant Change (TPY) Total (TPY) CO2 Equivalent 0 3.62 Carbon Monoxide 0 1139.60
Nitrogen Oxides 0 280.90
Particulate Matter - PM10 0 215.40
Particulate Matter - PM2.5 0 215.40
Sulfur Dioxide 0 55.60
Volatile Organic Compounds 0 169.70 Hazardous Air Pollutant Change (lbs/yr) Total (lbs/yr)
Formaldehyde (CAS #50000) 0 12400
Total HAPs (CAS #THAPS) 0 54800
Change (TPY) Total (TPY)
Total HAPs 0 33.60
Note: Change in emissions indicates the difference between previous AO and proposed modification.

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Review of BACT for New/Modified Emission Units 1. BACT review regarding for Block 1 combustion turbines
PacifiCorp is proposing to install new Siemens Energy ultra-low NOx combustion hardware and perform other turbine upgrades on the Lake Side Block 1 combustion turbines. The technology upgrades will increase combustion fuel flows through a different aerodynamic profile than that of
the current turbine section. The ultra-low NOx upgrade will add an additional fuel stage with a change in all combustor hardware. The upgrade in technology will allow for improved power and efficiency benefits, reduced fuel consumption per generated power, and capability to operate the combustion turbines on up to 30 percent hydrogen in the future. In addition to combustion controls, emissions from Block 1 combustion turbines/heat recovery steam generators (CT/HRSGs) will continue to be controlled with selective catalytic reduction and catalytic oxidation systems. PacifiCorp is not proposing changes to these control systems.
Although there is no change in emissions, the installation of the new combustion design could represent a change in the method of operation of the Block 1 turbines. PacifiCorp is subject to both lowest achievable emission rate (LAER) controls under nonattainment area major NSR as well as SIP source BACT under the requirements of the Provo, Utah PM2.5 Nonattainment Area SIP. Therefore, a BACT review is required to determine if the changes are equivalent to the existing control systems. The discussion of BACT in the technical support documents for the SIP describe the Block 1 turbines as follows: ". . . the turbines installed at the LSPP are all based around a dry-low-NOx combustor. This particular system is a lean pre-mix burner design, which uses a combination of staged combustion and differing fuel-air mixing for each combustion stage to both lower the combustion temperature and still allow for complete combustion."
The original LAER determination included similar language to describe the Block 1 turbines.
There is no change in post combustion controls being proposed. UDAQ has reviewed the
documentation submitted by PacifiCorp and agrees that the new combustion configuration and burner design continues to represent LAER and BACT. PacifiCorp will meet the same emission limits established as LAER and BACT. [Last updated January 29, 2025]

SECTION I: GENERAL PROVISIONS
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as “New” in the Outline Label): I.1 All definitions, terms, abbreviations, and references used in this AO conform to those used in the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions
refer to those rules. [R307-101] I.2 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]

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I.3 Modifications to the equipment or processes approved by this AO that could affect the emissions covered by this AO must be reviewed and approved. [R307-401-1]
I.4 All records referenced in this AO or in other applicable rules, which are required to be kept by the owner/operator, shall be made available to the Director or Director's representative upon request, and the records shall include the five-year period prior to the date of the request. Unless otherwise specified in this AO or in other applicable state and federal rules, records shall be kept for a minimum of five (5) years. [R307-415-6b]
I.5 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall, to the extent practicable, maintain and operate any equipment approved under this AO, including associated air pollution control equipment, in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Director which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. All maintenance performed on equipment authorized by this AO shall be recorded. [R307-401-4] I.6 The owner/operator shall comply with UAC R307-150 Series. Emission Inventories. [R307-150]
I.7 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns.
[R307-107]
SECTION II: PERMITTED EQUIPMENT
The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.A THE APPROVED EQUIPMENT
II.A.1 Lake Side Power Plant Permitted Source II.A.2 CT #1 and #2 Two (2) natural gas-fired ultra-low-NOx, combined cycle turbines, each with 150-foot stack (as measured from the base of the stack)
II.A.3 HRSG #1 and #2 Two (2) Heat Recovery Steam Generators, each equipped with low NOx duct burner - 184 MMBtu/hr II.A.4 Block #1 SCR Two (2) Selective Catalytic Reduction (SCR) systems with ammonia injection, one for each
turbine/HRSG set
II.A.5 Block #1 CO Catalysts Two (2) CO catalysts, one for each turbine/HRSG set
II.A.6 Block #1 Steam Turbine One (1) steam turbine

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II.A.7 Auxiliary Boiler #1 One (1) natural gas-fired 62.765 MMBtu/hr (nameplate rating) auxiliary boiler with 50 ft. boiler stack (as measured from the base of the stack)
II.A.8 Cooling Tower #1 One (1) 10 Cell mechanical draft evaporative cooling tower with drift elimination
II.A.9 CT #3 and #4
Two (2) natural gas-fired dry low-NOx, combined cycle turbines, each with 150-foot stack (as measured from the base of the stack) II.A.10 HRSG #3 and #4 Two (2) Heat Recovery Steam Generators, each equipped with low NOx duct burner
approximately 400 MMBtu/hr
II.A.11 Block #2 SCR
Two (2) Selective Catalytic Reduction (SCR) systems with ammonia injection, one for each turbine/HRSG set II.A.12 Block #2 CO Catalysts Two (2) CO catalysts, one for each turbine/HRSG set
II.A.13 Block #2 Steam Turbine One (1) steam turbine
II.A.14 Auxiliary Boiler #2
One (1) natural gas-fired 57.6 MMBtu/hr (nameplate rating) auxiliary boiler with 60 ft. boiler stack (as measured from the base of the stack) II.A.15 Cooling Tower #2 One (1) 16 Cell mechanical draft evaporative cooling tower with drift elimination
II.A.16 Fuel Dew Point Heater One (1) 4.76 MMBtu/hr (nameplate rating) fuel dew point heater
II.A.17 Emergency Generator
Two (2) approximately 1,500 hp diesel-fired emergency generators
II.A.18 Fire Pump One (1) 290 hp diesel-fired fire pump
II.A.19 Water Treatment Water treatment and storage facilities II.A.20 Ammonia Storage and Handling Aqueous ammonia storage and handling equipment
II.A.21 Miscellaneous Equipment CT lube oil vent system, maintenance shop vent system, machining and welding operations, etc.
II.A.22 Lake Side Block #1 Lake Side Block #1 consists of CT #1 and #2, associated HRSGs, control equipment, auxiliary boiler and cooling tower
II.A.23 Lake Side Block #2 Lake Side Block #2 consists of CT #3 and #4, associated HRSGs, control equipment, auxiliary boiler and cooling tower II.A.24 Additional Equipment Fuel treatment, fire suppression, water treatment, ammonia storage and other misc. equipment

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SECTION II: SPECIAL PROVISIONS The intent is to issue an air quality AO authorizing the project with the following recommended conditions and that failure to comply with any of the conditions may constitute a violation of the
AO. (New or Modified conditions are indicated as “New” in the Outline Label): II.B REQUIREMENTS AND LIMITATIONS
II.B.1 Conditions on Permitted Source
II.B.1.a The owner/operator shall install, calibrate, maintain, and operate a continuous emissions
monitoring system on each of the HRSG stacks. The owner/operator shall record the NOx and CO emissions. The monitoring system shall comply with all applicable sections of R307-170; 40 CFR 13; and 40 CFR 60, Appendix B. The NOx monitor shall comply with 40 CFR 75, Appendix A and B. All continuous emissions monitoring devices as required in federal regulations and state rules shall be installed prior to placing the affected source in operation. These devices shall be certified within 90 days of achieving full load, not to exceed 180 days after startup.
Except for system breakdown, repairs, calibration checks, and zero and span adjustments
required under paragraph (d) 40 CFR 60.13, the owner/operator of an affected source shall continuously operate all required continuous monitoring systems and shall meet minimum frequency of operation requirements as outlined in R307-170 and 40 CFR 60.13. [R307-170]

II.B.1.b Visible emissions shall not exceed the following values:
All natural gas combustion exhaust stacks - 10% opacity
All other emission points - 20% opacity Opacity observations of emissions from stationary sources shall be conducted according to 40 CFR 60, Appendix A, Method 9. [R307-401-8]
II.B.2 Conditions on Lake Side Block #1 II.B.2.a The owner/operator shall use natural gas as fuel in the combustion turbines, duct burners and auxiliary boiler. [R307-401-8]

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II.B.2.b Emissions to the atmosphere from the indicated emission point(s) shall not exceed the following rates and concentrations: Source: Auxiliary Boiler #1 Pollutant Limitations Averaging Period PM10 0.01 lb/MMBtu 3-hour NOx 0.017 lb/MMBtu 3-hour
CO 0.037 lb/MMBtu 3-hour Source: Each Turbine/HRSG Stack (at Block #1)
Pollutant Limitations Averaging Period
PM10 10.8 lb/hour (0.01 lb/MMBtu) 30-day rolling average NOx 2.0 ppmvd at 15% O2 (14.9 lb/hr)* 3-hour CO 3.0 ppmvd at 15% O2 (14.1 lb/hr)* 3-hour
* Under steady state operation.
. [R307-401-8]
II.B.2.c Stack testing to show compliance with the emission limitations stated in the above condition
shall be performed as specified below:
Emissions Point Pollutant Status Frequency
HRSG Stacks PM10/PM2.5 * $
NOx * # CO * # Auxiliary Boilers PM10 * % NOx * %
CO * %
Testing Status (To be applied to the sources listed above)
* Initial compliance testing has been completed. If an existing source is modified, a
compliance test is required on the modified emission point that has an emission rate limit. $ Test every year or testing may be replaced with parametric monitoring if approved by the Director % Test every five (5) years or testing may be replaced with parametric monitoring if
approved by the Director # Compliance shall be demonstrated through use of a Continuous Emissions Monitoring System (CEM) as outlined in Condition II.B.1.c. The Director may require testing at any
time. [R307-165]

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II.B.2.d For all emissions testing the following shall apply:
Notification:
The Director shall be notified at least 30 days prior to conducting any required emission testing. A source test protocol shall be submitted to DAQ when the testing notification is submitted to the Director. The source test protocol shall be approved by the Director prior to performing the test(s). The source test protocol shall outline the proposed test methodologies, stack to be tested, and procedures to be used. A pretest conference shall be held, if directed by the Director.
Sample Location:
The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, or other methods as approved by EPA and acceptable to the Director. An Occupational Safety and Health Administration (OSHA) or Mine Safety and Health Administration (MSHA) approved access shall be provided to the test location.
Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2 Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing methods approved by EPA
and acceptable to the Director.
PM10:
For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and acceptable to the Director. All particulate captured shall be considered PM10. The back half condensables shall be used for compliance demonstration as well as for inventory purposes.
For stacks in which liquid drops are present, methods to eliminate the liquid drops should be
explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing methods approved by EPA and acceptable to the Director. The back half condensables
shall also be tested using the method specified by the Director. The portion of the front half of the catch considered PM10 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director.
PM2.5:
For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and acceptable to the Director. All particulate captured shall be considered PM2.5. For stacks in which liquid drops are present, methods to eliminate the liquid drops should be explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other testing
methods approved by EPA and acceptable to the Director. The back half condensables shall also be tested using the method specified by the Director. The portion of the front half of the catch considered PM2.5 shall be based on information in Appendix B of the fifth edition of the
EPA document, AP-42, or other data acceptable to the Director. NOx:
40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by EPA and acceptable to the Director.

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II.B.2.e Compliance with the 3-hour NOx and CO emission limitations specified in Condition II.B.2.b shall not be required during short-term excursions, limited to a cumulative total of 160 hours per rolling 12-month period. Short-term excursions are defined as 15-minute periods
designated by the Owner/Operator that are the direct result of transient load conditions, not to exceed four consecutive 15-minute periods, when the 15-minute average NOx and CO concentrations exceed 2.0 ppmv and 3.0 ppmv, dry @ 15% O2, respectively. Transient load
conditions include the following:
1. Initiation/shutdown of combustion turbine inlet air-cooling 2. Rapid combustion turbine load changes 3. Initiation/shutdown of HRSG duct burners 4. Provision of Ancillary Services and Automatic Generation Control
During periods of transient load conditions, the NOx concentration shall not exceed 25 ppmv
and the CO concentration shall not exceed 50 ppmv, dry @ 15% O2. All NOx and CO emissions during these events shall be included in all calculations of annual mass emissions as required by this permit. [R307-401-8]
II.B.2.f Steady state operation means all periods of combustion turbine operation, except for periods of startup and shutdown as defined below, and periods of transient load conditions as defined in Condition II.B.2.e. Startup is defined as the period beginning with turbine initial firing
until the unit meets the ppmvd emission limits in the first table of Condition II.B.2.b for steady state operation. Shutdown is defined as the period beginning with the initiation of turbine shutdown sequence and ending with the cessation of firing of the gas turbine engine. Startup and shutdown events shall not exceed 613.5 hours per turbine per rolling 12-month period and are counted toward the applicable annual emission limitations. Total startup and shutdown events shall not exceed 14-hours per turbine in any one calendar day, commencing at midnight. Emissions during startup and shutdown periods shall be counted toward the applicable annual emission limitations. [R307-401-8]
II.B.3 Conditions on Lake Side Block #2
II.B.3.a The owner/operator shall use natural gas as fuel in the combustion turbines, duct burners and
auxiliary boiler. [R307-401-8]

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II.B.3.b Emissions to the atmosphere from the indicated emission point(s) shall not exceed the following rates and concentrations: Source: Auxiliary Boiler #2 Pollutant Limitations Averaging Period PM10/PM2.5 0.01 lb/MMBtu 3-hour NOx 0.017 lb/MMBtu 3-hour
CO 0.037 lb/MMBtu 3-hour VOC 0.006 lb/MMBtu 3-hour Source: Each Turbine/HRSG Stack (at Block #2) Pollutant Limitations Averaging Period PM10/PM2.5 14 lb/hour (with duct firing) 30-day rolling average NOx 2.0 ppmvd at 15% O2 (18.1 lb/hr)* 3-hour CO 3.0 ppmvd at 15% O2 (16.6 lb/hr)* 3-hour VOC 2.8 ppmvd at 15% O2* 3-hour * Under steady state operation. . [R307-401-8]

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II.B.3.c Stack testing to show compliance with the emission limitations stated in the above condition shall be performed as specified below: Emissions Point Pollutant Status Frequency HRSG Stacks PM10/PM2.5 * $ NOx * # CO * #
VOC * & Auxiliary Boilers PM10/PM2.5 * % NOx * % CO * %
VOC * %
Testing Status (To be applied to the sources listed above)
* Initial compliance testing is required. The initial test date shall be performed as soon as
possible and in no case later than 180 days after the start up of a new emission source, an existing source without an AO, or the granting of an AO to an existing emission source that has not had an initial compliance test performed. If an existing source is modified, a
compliance test is required on the modified emission point that has an emission rate limit.
$ Test every year or testing may be replaced with parametric monitoring if approved by the Director & Test every two (2) years or testing may be replaced with parametric monitoring if approved by the Director % Test every five (5) years or testing may be replaced with parametric monitoring if approved by the Director
# Compliance shall be demonstrated through use of a Continuous Emissions Monitoring System (CEM) as outlined in Condition II.B.1.c. The Director may require testing at any time. [R307-165]

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II.B.3.d For all emissions testing the following shall apply:
Notification:
The Director shall be notified at least 30 days prior to conducting any required emission testing. A source test protocol shall be submitted to DAQ when the testing notification is submitted to the Director. The source test protocol shall be approved by the Director prior to performing the test(s). The source test protocol shall outline the proposed test methodologies, stack to be tested, and procedures to be used. A pretest conference shall be held, if directed by the Director.
Sample Location:
The emission point shall be designed to conform to the requirements of 40 CFR 60, Appendix A, Method 1, or other methods as approved by EPA and acceptable to the Director. An Occupational Safety and Health Administration (OSHA) or Mine Safety and Health Administration (MSHA) approved access shall be provided to the test location.
Volumetric Flow Rate: 40 CFR 60, Appendix A, Method 2 or EPA Test Method No. 19 "SO2 Removal & PM, SO2, NOx Rates from Electric Utility Steam Generators" or other testing methods approved by EPA
and acceptable to the Director.
PM10/PM2.5:
For stacks in which no liquid drops are present, the following methods shall be used: 40 CFR 51, Appendix M, Methods 201, 201a and 202, or other testing methods approved by EPA and acceptable to the Director. All particulate captured shall be considered PM10/PM2.5. The back half condensables shall be used for compliance demonstration as well as for inventory
purposes. For stacks in which liquid drops are present, methods to eliminate the liquid drops should be explored. If no reasonable method to eliminate the drops exists, then the following methods shall be used: 40 CFR 60, Appendix A, Method 5, 5a, 5d, or 5e as appropriate, or other
testing methods approved by EPA and acceptable to the Director. The back half condensables shall also be tested using the method specified by the Director. The portion of the front half of the catch considered PM10/PM2.5 shall be based on information in Appendix B of the fifth edition of the EPA document, AP-42, or other data acceptable to the Director. NOx:
40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by EPA and acceptable to the Director. CO:
40 CFR 60, Appendix A, Method 10, or other testing methods approved by EPA and acceptable to the Director. Calculations: To determine mass emission rates (lb/hr, etc.) the pollutant concentration as determined by the appropriate methods above shall be multiplied by the volumetric flow rate and any necessary conversion factors determined by the Director, to give the results in the specified units of the
emission limitation. [R307-165]

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II.B.3.e Compliance with the 3-hour NOx and CO emission limitations specified in Condition II.B.3.b shall not be required during short-term excursions, limited to a cumulative total of 160 hours per rolling 12-month period. Short-term excursions are defined as 15-minute periods
designated by the Owner/Operator that are the direct result of transient load conditions, not to exceed four consecutive 15-minute periods, when the 15-minute average NOx and CO concentrations exceed 2.0 ppmv and 3.0 ppmv, dry @ 15% O2, respectively. Transient load
conditions include the following:
1. Initiation/shutdown of combustion turbine inlet air-cooling 2. Rapid combustion turbine load changes 3. Initiation/shutdown of HRSG duct burners 4. Provision of Ancillary Services and Automatic Generation Control
During periods of transient load conditions, the NOx concentration shall not exceed 25 ppmv
and the CO concentration shall not exceed 50 ppmv, dry @ 15% O2. All NOx and CO emissions during these events shall be included in all calculations of annual mass emissions as required by this permit. [R307-401-8]
II.B.3.f Steady state operation means all periods of combustion turbine operation, except for periods of startup and shutdown as defined below, and periods of transient load conditions as defined in Condition II.B.3.e. Startup is defined as the period beginning with turbine initial firing
until the unit meets the ppmvd emission limits in the first table of Condition II.B.3.b for steady state operation. Shutdown is defined as the period beginning with the initiation of turbine shutdown sequence and ending with the cessation of firing of the gas turbine engine. Startup and shutdown events shall not exceed 553.6 hours per turbine per rolling 12-month period. Total startup and shutdown events shall not exceed 8 hours per turbine in any one calendar day, commencing at midnight.
Emissions of NOx from either Block #2 CT/HRSG unit (CT #3 or #4) shall not exceed 130
lb/hr during startup or shutdown operations.
Emissions of CO from either Block #2 CT/HRSG unit (CT #3 or #4) shall not exceed 3,000 lb/hr during startup or shutdown operations. [R307-401-8]
II.B.3.g Total CO2e emissions from Lake Side Block 2 shall not exceed 950 lb/MWh(g) on a 12-month rolling average basis. Hourly heat input for each turbine and the HSRG will be obtained from the data submitted to the Acid Rain database and summed over the appropriate 12-month period. This total heat input will then be multiplied by an emission factor of 121.723 lb CO2e/MMBtu to obtain the total CO2e emissions during the 12-month period. The 12-month gross generation for each turbine and HSRG will be obtained from the data reported to the Acid Rain database. This hourly generation will be summed over the twelve-month period to
obtain the total gross generation. The CO2e per MWH(g) value is calculated by dividing the 12-month total CO2e emissions by the 12-month total gross generation. [R307-401-8] II.B.4 Conditions on Additional Equipment II.B.4.a Emergency generators shall be used for electricity producing operation only during the periods when electric power from the public utilities is interrupted, and for regular maintenance and
testing. Records documenting generator usage shall be kept in a log and they shall show the date the generator was used, the duration in hours of the generator usage, and the reason for each generator usage. [R307-401-8]

Engineer Review N130310014: PacifiCorp Energy- Lake Side Power Plant February 4, 2025 Page 17
II.B.4.b The owner/operator shall use a combination of #1 or #2 fuel oil or diesel fuel in the emergency generators and fire pump. The sulfur content of any #2 fuel oil or diesel fuel burned shall not exceed 0.0015 percent by weight. Sulfur content shall be determined by ASTM Method D-4294-89, or approved equivalent. Certification of fuels shall be either by the owner/operator's own testing or test reports from the fuel marketer or supplier. For purposes of demonstrating compliance with this limitation, the owner/operator may obtain the above specifications by testing each purchase of fuel in accordance with the required methods; by inspection of the specifications provided by the vendor for each purchase of fuel; or by inspection of summary documentation of the fuel sulfur content from the vendor; provided that the above specifications are available from the vendor for each purchase if requested. [R307-401-8]

Engineer Review N130310014: PacifiCorp Energy- Lake Side Power Plant February 4, 2025 Page 18
PERMIT HISTORY When issued, the approval order shall supersede (if a modification) or will be based on the
following documents: Supersedes DAQE-AN130310012-15 dated March 13, 2015
Is Derived From Source submitted NOI dated August 28, 2024
REVIEWER COMMENTS

1. Comment regarding changes in the AO: The only change necessary for this permitting project is updating the description of II.A.2 - CT #1 and #2. rather than reading: Two (2) natural gas-fired dry low-NOx, combined cycle turbines, each with 150 foot stack (as measured from the base of the stack) It will now read: Two (2) natural gas-fired ultra low-NOx, combined cycle turbines, each with 150 foot stack (as measured from the base of the stack) The description of the post combustion control systems are listed in II.A.4 and II.A.5 which are not being changed. The only other change is to update the contact information for the source. [Last
updated January 28, 2025] 2. Comment regarding no change in emissions: The project results in a change in description of the Block 1 turbines. This is no anticipated change in emissions from this project. PacifiCorp will continue to meet the existing emission limits previously established. [Last updated January 28, 2025]

Engineer Review N130310014: PacifiCorp Energy- Lake Side Power Plant February 4, 2025 Page 19
ACRONYMS The following lists commonly used acronyms and associated translations as they apply to this document:
40 CFR Title 40 of the Code of Federal Regulations AO Approval Order BACT Best Available Control Technology
CAA Clean Air Act CAAA Clean Air Act Amendments CDS Classification Data System (used by EPA to classify sources by size/type) CEM Continuous emissions monitor CEMS Continuous emissions monitoring system CFR Code of Federal Regulations CMS Continuous monitoring system CO Carbon monoxide CO2 Carbon Dioxide CO2e Carbon Dioxide Equivalent - 40 CFR Part 98, Subpart A, Table A-1 COM Continuous opacity monitor
DAQ/UDAQ Division of Air Quality DAQE This is a document tracking code for internal UDAQ use EPA Environmental Protection Agency
FDCP Fugitive dust control plan GHG Greenhouse Gas(es) - 40 CFR 52.21 (b)(49)(i) GWP Global Warming Potential - 40 CFR Part 86.1818-12(a)
HAP or HAPs Hazardous air pollutant(s) ITA Intent to Approve LB/HR Pounds per hour
LB/YR Pounds per year MACT Maximum Achievable Control Technology MMBTU Million British Thermal Units
NAA Nonattainment Area NAAQS National Ambient Air Quality Standards NESHAP National Emission Standards for Hazardous Air Pollutants NOI Notice of Intent NOx Oxides of nitrogen NSPS New Source Performance Standard NSR New Source Review PM10 Particulate matter less than 10 microns in size
PM2.5 Particulate matter less than 2.5 microns in size PSD Prevention of Significant Deterioration PTE Potential to Emit
R307 Rules Series 307 R307-401 Rules Series 307 - Section 401 SO2 Sulfur dioxide
Title IV Title IV of the Clean Air Act Title V Title V of the Clean Air Act TPY Tons per year
UAC Utah Administrative Code VOC Volatile organic compounds
Notice of Intent Application for Lake
Side Block 1 Combustion Turbines
PacifiCorp
PacifiCorp Lake Side Power Plant
August 2024
Notice of Intent Application for Block 1 Combustion Turbines
1
Contents
Introduction........................................................................................................................................................... 2
Process Description ............................................................................................................................................... 2
Emissions Information ........................................................................................................................................... 2
Regulatory Review ................................................................................................................................................. 3
Control Technology Discussion .............................................................................................................................. 4
Tables
Table 1. Maximum Steady-State Emissions for Each CT/HRSG in Block 1 ............................................................... 2
Table 2. Maximum Steady-State Emissions for Each CT/HRSG in Block 1 ............................................................... 3
Table 3. 2004 BACT/LAER Determinations for Block 1 ............................................................................................ 4
Table 4. Block 1 PM2.5 SIP Limitations for NOX ........................................................................................................ 4
Notice of Intent Application for Block 1 Combustion Turbines
2
Introduction
On behalf of PacifiCorp, Jacobs Project Management Co. has prepared this Notice of Intent (NOI)
application to modify the Lake Side Power Plant Approval Order (AO) DAQE-AN01303100012-15. As part
of improvements to the plant, PacifiCorp is proposing to install new Siemens Energy ultra-low nitrogen
oxide (NOx) combustion hardware and perform other turbine upgrades on the Lake Side Block 1
combustion turbines in early 2025. The Lake Side Power Plant is a prevention of significant deterioration
(PSD) major source located in Vineyard, Utah County, Utah.
Process Description
PacifiCorp is proposing to install new Siemens Energy ultra-low NOx combustion hardware and perform
other turbine upgrades on the Lake Side Block 1 combustion turbines. The technology upgrades will
increase combustion fuel flows through a different aerodynamic profile than that of the current turbine
section. The ultra-low NOx upgrade will add an additional fuel stage with a change in all combustor
hardware. The upgrade in technology will allow for improved power and efficiency benefits, reduction in
carbon footprint through reduced fuel consumption per generated power, and capability to operate the
combustion turbines on up to 30 percent hydrogen in the future.
In addition to combustion controls, emissions from Block 1 combustion turbines/heat recovery steam
generators (CT/HRSGs) will continue to be controlled with selective catalytic reduction and catalytic
oxidation systems. PacifiCorp is not proposing changes to these state-of-the-art control systems.
Emissions Information
The installation of new Siemens Energy ultra-low NOx combustion hardware is expected to reduce
emissions. Post combustion emissions from the Block 1 turbines and HRSGs are controlled with a selective
catalytic reduction system for NOx and a catalytic oxidation system for carbon monoxide (CO) and volatile
organic compounds (VOCs). Both of these state-of-the-art control systems will continue to operate and
minimize emissions from Block 1.
After the above-mentioned upgrades, PacifiCorp will continue to operate the Block 1 turbines and HRSGs
within the emissions limitations listed in the Title V Operating Permit, AO, and relevant State
Implementation Plans. Table 1 summarizes emissions as permitted in the current AO and those expected
after the proposed modification. The permitted emissions outlined in Table 1 are included in AO
Condition II.B.2.b.
Table 1. Maximum Steady-State Emissions for Each CT/HRSG in Block 1
Pollutant Permitted Emissions Emissions after Proposed Modification
NOx 2.0 ppmvd @ 15%
O2 3-hour average
14.9 lb/hr 2.0 ppmvd @ 15%
O2 3-hour average
14.9 lb/hr
CO 3.0 ppmvd @ 15%
O2 3-hour average
14.1 lb/hr 3.0 ppmvd @ 15%
O2 3-hour average
14.1 lb/hr
PM10 -10.8 lb/hr
(0.01 lb/mm Btu)
30-day rolling average
-10.8 lb/hr
(0.01 lb/mm Btu)
30-day rolling average
Notes:
- = not applicable
Notice of Intent Application for Block 1 Combustion Turbines
3
lb/hr = pound(s) per hour
lb/mm Btu = pound(s) per million British thermal unit(s)
O2 = oxygen
PM10 = particulate matter less than 10 micrometers in aerodynamic diameter
ppmvd = parts per million by volume, dry
Emissions of VOCs, SO2 and PM2.5 will continue to remain at permitted levels. Emissions from the
May 20, 2004, Block 1 NOI application (Table 3-5) and those after the proposed modification are
presented in Table 2.
Table 2. Maximum Steady-State Emissions for Each CT/HRSG in Block 1
Pollutant Permitted Emissions Emissions after Proposed Modification
VOC 1.7 ppmvd @ 15% O2 4.1 lb/hr 1.7 ppmvd @ 15% O2 4.1 lb/hr
SO2 -3.1 lb/hr -3.1 lb/hr
PM2.5 ---10.8 lb/hr
(0.01 lb/mmBtu)
Notes:
PM2.5 = particulate matter less than 2.5 micrometers in aerodynamic diameter
SO2 = sulfur dioxide
Emissions associated with startup and shutdown as well as annual operating scenarios are not expected to
change with this proposed modification.
Because no change is expected, the proposed project will be permitted as a modification to the AO without
an increase in emissions.
Regulatory Review
The proposed project involves a modification to an existing installation. The air quality regulation, codified
in Title R307 of the Utah Administrative Code (UAC), applicable to this NOI is R307-401 – Permit: Notice
of Intent and Approval Order.
According to R307-401, any person planning to make modifications to or relocate an existing installation
that will or might reasonably be expected to increase the amount of or change the character or effect of
air pollutants discharged shall submit a NOI to the director and receive an AO prior to the construction,
modification, installation, establishment, or relocation of an air pollutant source or indirect source. The
NOI shall include all information listed under R307-401-5(2) to determine whether the proposed
modification will be in accordance with applicable requirements of these rules. Within 30 days after receipt
of a NOI, or any additional information necessary to the review, the director will advise the applicant of any
deficiency in the NOI or the information submitted. Within 90 days after the receipt of a complete
application, including all information described in R307-401-5, the director will either issue an AO from
the proposed modification or issue an order prohibiting the proposed modification if it is determined that
any part of the proposal will not be in accord with requirements of Title R307.
This NOI application has been prepared in accordance with the requirements of UAC R307-401.
Notice of Intent Application for Block 1 Combustion Turbines
4
Control Technology Discussion
The Lake Side Power Plant is a major PSD source as outlined in the AO. Block 1 was permitted in 2004 at
which time Utah County was designated as a nonattainment area for the 24-hour PM10 standard. The
County was designated as attainment or unclassified for all other pollutants in 2004. The permit
application submitted in 2004 demonstrated that CT/HRGs in Block 1 will meet the lowest achievable
emission rate (LAER) for NOx and PM10 and BACT for CO, VOC, and SO2. LAER and BACT determinations for
Block 1 are outlined in Table 3.
Table 3. 2004 BACT/LAER Determinations for Block 1
Control Technology 2004 BACT/LAER
Determination
Reference
PM10 Emissions Combustion turbine design,
combustion control, low
sulfur fuel
LAER: 10.8 lb/hour; 0.01
lb/mmBtu
AO and Table 5-2 of
2004 NOI application
NOx Emissions Dry Low NOx burners with
selective catalytic reduction
LAER: 2 ppmvd @ 15% O2
(3-hour average)
AO and Table 5-2 of
2004 NOI application
CO Emissions Combustion turbine design,
proper combustion,
oxidation catalyst
BACT: 3 ppmvd @ 15% O2
(3-hour average)
AO and Table 5-2 of
2004 NOI application
VOC Emissions Combustion turbine design,
proper combustion,
oxidation catalyst
BACT: 1.7 ppmvd @ 15% O2
(3-hour average)
AO and Table 5-2 of
2004 NOI application
SO2 Emissions Low sulfur fuel BACT: 3.1 lb/hr; 0.0015
lb/mmBtu
Table 5-2 of 2004 NOI
application
The Lakeside Power plant is a listed source in the PM2.5 State Implementation Plan. Section IX.H.13 (d)
limits NOx emissions from Block 1 as shown below.
Table 4. Block 1 PM2.5 SIP Limitations for NOX
Control Technology NOX BACT Determination Reference
2020 BACT
Determination
Dry Low NOx burners with
selective catalytic reduction
14.9 lb/hr (3-hour
average)
Section IX.H.13 (d) of
PM2.5 SIP
Proposed BACT Ultra Low NOx burners with
selective catalytic reduction
14.9 lb/hr (3-hour
average)
-
Currently, Utah County is designated as a maintenance area for the 24-hour PM10 standard and a
nonattainment area for the 24-hour PM2.5 standard. Because previous LAER and BACT determinations
were relied upon by the Division of Air Quality during the development of applicable State Implementation
Plans, Lake Side Block 1 will continue to meet these previously established BACT and LAER
determinations.