DAQE-AN125290003-12

October 25, 2012

Bruce Taylor

Sevier Power Company

620 S Main

Bountiful, UT 84010

Dear Mr. Taylor:

Re: Approval Order: Notice of Intent to Construct a 580 MW Combined Cycle, Natural Gas, 

Combustion Turbine Power Plant

Project Number: N012529-0003

The attached document is the Approval Order for the above-referenced project. Future correspondence 

on this Approval Order should include the engineer's name as well as the DAQE number as shown on the 

upper right-hand corner of this letter. The project engineer for this action is John Jenks, who may be 

reached at (801) 536-4459.

Sincerely,

Bryce C. Bird

Director

BCB:JJ:kw

cc: Mike Owens

Central Utah Health Department

195 North 1950 West • Salt Lake City, UT 

Mailing Address: P.O. Box 144820 • Salt Lake City, UT 84114-4820 

Telephone (801) 536-4000 • Fax (801) 536-4099 • T.D.D. (801) 536-4414 

www.deq.utah.gov

Printed on 100% recycled paper

State of Utah 

GARY R. HERBERT

Governor

GREG BELL

Lieutenant Governor

Department of 

Environmental Quality

Amanda Smith

Executive Director

DIVISION OF AIR QUALITY

Bryce C. Bird

Director
STATE OF UTAH

Department of Environmental Quality

Division of Air Quality

APPROVAL ORDER: Notice of Intent to Construct a 580 MW 

Combined Cycle, Natural Gas, Combustion Turbine Power Plant

Prepared By: John Jenks, Engineer

Phone: (801) 536-4459

Email: jjenks@utah.gov

APPROVAL ORDER NUMBER

DAQE-AN125290003-12

Date: October 25, 2012

Sevier Power Company

Power Plant

Source Contact:

Bruce Taylor 

Phone: (801) 916-7341

Bryce C. Bird

Director
Abstract

On September 8, 2011, Sevier Power Company (SPC) submitted a NOI to construct and operate a 580 

MW, combined-cycle, natural gas-fired power plant located near Sigurd, Utah; an attainment area for all 

criteria pollutants. In response to a request for additional information, SPC submitted a revision to its 

NOI on January 19, 2012. As proposed in this revised NOI, the plant will consist of two natural gas-fired, 

combustion turbines (CT); two, natural gas duct-fired, heat recovery steam generators (HRSG); a natural 

gas-fired auxiliary boiler; diesel emergency generator; and other associated equipment. The CT/HRSG 

units are dry low-NOx units controlled with both selective catalytic reduction (SCR) and oxidation 

catalysts (oxy-cat). The auxiliary boiler shall be equipped with ultra-low-NOx burners (ULNB) and flue 

gas recirculation (FGR). The SPC power plant shall be subject to the provisions of 40 CFR 60 Subparts 

A, Dc, IIII and KKKK; and 40 CFR 63 Subparts A and ZZZZ. The proposed source emissions are 

estimated at the following TPY values: PM10 106, PM2.5 (a subset of PM10) 106, NOx 168.3, SO2 25.7, 

CO 577, VOC 91.6, combined HAPs 8.5, and GHG 2,019,226.1 (expressed as CO2e).

This source is a new major source under PSD. The proposed emissions of NOx, PM10 and PM2.5 exceed 

the emission thresholds outlined in R307-406-5 and R307-410-4, and so an air quality impact analysis 

(AQIA) of the proposed project’s impact on federal air quality standards and air quality related values is 

required.

This air quality AO authorizes the project with the following conditions and failure to comply with any of 

the conditions may constitute a violation of this order. This AO is issued to, and applies to the following:

Name of Permittee:

Sevier Power Company

620 S Main

Bountiful, UT 84010

Permitted Location:

Power Plant

414,332 m Easting 4,300,261 Northing

Zone 12

Sigurd, UT 84657

UTM coordinates: 414332 m Easting, 4300261 m Northing, UTM Zone 12

SIC code: 4911 (Electric Services)

Section I: GENERAL PROVISIONS

I.1 The limits set forth in this AO shall not be exceeded without prior approval. [R307-401]

I.2 Modifications to the equipment or processes approved by this AO that could affect the 

emissions covered by this AO must be reviewed and approved. [R307-401-1]

I.3 All records referenced in this AO or in other applicable rules, which are required to be kept by 

the owner/operator, shall be made available to the Director or Director's representative upon 

request, and the records shall include the two-year period prior to the date of the request. Unless 

otherwise specified in this AO or in other applicable state and federal rules, records shall be kept 

for a minimum of five (5) years. [R307-401-8]

I.4 At all times, including periods of startup, shutdown, and malfunction, owners and operators 

shall, to the extent practicable, maintain and operate any equipment approved under this AO, 
DAQE-AN125290003-12

Page 3

including associated air pollution control equipment, in a manner consistent with good air 

pollution control practice for minimizing emissions. Determination of whether acceptable 

operating and maintenance procedures are being used will be based on information available to 

the Director which may include, but is not limited to, monitoring results, opacity observations, 

review of operating and maintenance procedures, and inspection of the source. All maintenance 

performed on equipment authorized by this AO shall be recorded. [R307-401-4]

I.5 The owner/operator shall comply with UAC R307-107. General Requirements: Breakdowns. 

[R307-107]

I.6 The owner/operator shall comply with UAC R307-150 Series. Inventories, Testing and 

Monitoring. [R307-150]

I.7 All definitions, terms, abbreviations, and references used in this AO conform to those used in 

the UAC R307 and 40 CFR. Unless noted otherwise, references cited in these AO conditions 

refer to those rules. [R307-101]

Section II: SPECIAL PROVISIONS

II.A The approved installations shall consist of the following equipment:

II.A.1 Power Plant

Nominal 580 MW natural gas-fired combustion turbine power plant

II.A.2 Turbine 1

F-Class combustion turbine with dry low-NOx

II.A.3 HRSG 1

Heat recovery steam generator with duct burners, SCR and catalytic oxidation

II.A.4 Turbine 2

F-Class combustion turbine with dry low-NOx

II.A.5 HRSG 2

Heat recovery steam generator with duct burners, SCR and catalytic oxidation

II.A.6 Auxiliary Boiler

85 MMBtu/hr auxiliary boiler with ULNB and FGR

II.A.7 Convection Fuel Heaters

Two (2) 22.3 MMBtu/hr fuel heaters

II.A.8 Emergency Generator

1,250 kWe emergency diesel generator 

II.A.9 Emergency Fire Water Pump

300 kWe diesel-fired fire water pump

II.A.10 Water Treatment

Water treatment and storage facilities

II.A.11 Ammonia Storage and Handling

Aqueous ammonia storage and handling equipment
DAQE-AN125290003-12

Page 4

II.B Requirements and Limitations

II.B.1 Conditions on Permitted Source

II.B.1.a SPC shall notify the Director in writing when the installation of the equipment listed in II.A 

has been completed and is operational. To ensure proper credit when notifying the Director, 

send your correspondence to the Director, attn: Compliance Section.

The provisions of R307-405-19. Source Obligation apply to this source. 

II.B.1.b 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 output of 

the system, for measuring the NOx and CO emissions. The monitoring system shall comply 

with all applicable sections of R307-170; 40 CFR 60.13; 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, 

40 CFR 60.13]

II.B.1.c 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.1.d The owner/operator shall use natural gas as fuel in the combustion turbines, duct burners and 

auxiliary boiler. [R307-401-8]

II.B.1.e SPC shall conduct post-construction PM2.5 ambient air monitoring for a period of no less than 

three years or until the Director determines that ambient monitoring for PM2.5 is no longer 

warranted. SPC will submit a post-construction PM2.5 ambient air quality monitoring plan for 

approval by the Director no less than 180 days prior to the start of operations. 

Post-construction PM2.5 monitoring will begin within 30 days of the start of the SPC 

operations. SPC will provide post-construction monitoring reports to the DAQ on a schedule 

outlined in the plan approved by the Director. [R307-401-8]

II.B.2 Conditions on Combustion Turbines and HRSGs

II.B.2.a Emissions to the atmosphere from the indicated emission point(s) shall not exceed the 

following rates and concentrations:

Source: Each Turbine/HRSG Stack

Pollutant Limitations Averaging Period

PM10/PM2.5 14 lb/hour (with duct firing) 30-day rolling average

NOx 2.0 ppmvd at 15% O2* 3-hour 
DAQE-AN125290003-12

Page 5

CO 3.0 ppmvd at 15% O2* 3-hour 

VOC 3.0 ppmvd at 15% O2* 3-hour

* Under steady state operation

[R307-401-8]

II.B.2.b 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 * %

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 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 (CEMS) as outlined in Condition II.B.1.b. The Director may require testing at 

any time.

[R307-165]

II.B.2.c 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 Director. An Occupational Safety and 

Health Administration (OSHA) or Mine Safety and Health Administration (MSHA) approved 

access shall be provided to the test location.
DAQE-AN125290003-12

Page 6

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 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 

Director. All particulate captured shall be considered PM10/PM2.5. The back half condensibles 

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 Director. The back half condensibles 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.

NOx:

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by 

the Director.

CO:

40 CFR 60, Appendix A, Method 10, or other testing methods approved by 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]

II.B.2.d Compliance with the 3-hour NOx and CO emission limitations specified in Condition II.B.2.a 

shall not be required during short-term excursions, limited to a cumulative total of 160 hours 

annually. 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]
DAQE-AN125290003-12

Page 7

II.B.2.e 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.d. Startup is defined as the period beginning with turbine initial firing until 

the unit meets the ppmvd emission limits in Condition II.B.2.a 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. 

1. Emissions of NOx from each CT/HRSG unit shall not exceed 126 lb/hr during startup 

or shutdown operations

2. Emissions of CO from each CT/HRSG unit shall not exceed 959 lb/hr during startup 

or shutdown operations.

[R307-401-8]

II.B.2.f Emissions of GHG from both CT/HRSG units combined shall not exceed 1,958,552.1 metric 

tons of CO2e per rolling 12-month period. Compliance with the rolling 12-month period shall 

be determined through use of the CO2 CEM as outlined in condition II.B.1.b above. Non-CO2

GHGs shall use Emission factors from Table C-2 of 40 CFR Part 98 and global warming 

potentials from Table A-1 of 40 CFR part 98, along with the actual measured heat input to the 

combustion turbines. [R307-401-8, R307-170]

II.B.2.g The height of the CT/HRSG stacks shall be no less than 165 feet, as measured from ground 

level at the base of the stack. [R307-410-6]

II.B.3 Conditions on Auxiliary Boiler

II.B.3.a 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 0.0375 lb/MMBtu 3-hour

[R307-401-8]

II.B.3.b 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

Auxiliary Boiler PM10/PM2.5 * %

NOx * %

CO * %

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.
DAQE-AN125290003-12

Page 8

% Test every five (5) years or testing may be replaced with parametric monitoring if 

approved by the Director

[R307-165]

II.B.3.c 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 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 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 

Director. All particulate captured shall be considered PM10/PM2.5. The back half condensibles 

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 Director. The back half condensibles 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.

NOx:

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by 

the Director.

CO:

40 CFR 60, Appendix A, Method 10, or other testing methods approved by the Director.
DAQE-AN125290003-12

Page 9

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]

II.B.4 Conditions on Emergency Generator

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]

II.B.5 Conditions on Diesel-Fired Equipment

II.B.5.a 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 #1 or #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]

Section III: APPLICABLE FEDERAL REQUIREMENTS

In addition to the requirements of this AO, all applicable provisions of the following federal programs 

have been found to apply to this installation. This AO in no way releases the owner or operator from any 

liability for compliance with all other applicable federal, state, and local regulations including UAC 

R307.

NSPS (Part 60), A: General Provisions

NSPS (Part 60), Dc: Standards of Performance for Small Industrial-Commercial-Institutional Steam 

Generating Units

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), A: General Provisions

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
DAQE-AN125290003-12

Page 10

PERMIT HISTORY

This AO is based on the following documents:

Is Derived From Source submitted NOI dated September 8, 2011

Incorporates Additional information received dated January 19, 2012

ADMINISTRATIVE CODING

The following information is for UDAQ internal classification use only:

Sevier County

CDS A

NSR, PSD, MACT (Part 63), Attainment Area, Title IV (Part 72 / Acid Rain), Compliance Assurance 

Monitoring (CAM), Title V (Part 70) major source, Major criteria source, NSPS (Part 60), 
DAQE-AN125290003-12

Page 11

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 Division of Air Quality (typically interchangeable with UDAQ)

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

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

UDAQ Utah Division of Air Quality (typically interchangeable with DAQ)

VOC Volatile organic compounds
Engineering Review NSR0125290003: Sevier Power Company: Power Plant - NOI to construct a 580 MW combined cycle, 

natural gas, combustion turbine power plant 

March 30, 2012 

Page 1 

UTAH DIVISION OF AIR QUALITY 

SOURCE PLAN REVIEW 

Bruce Taylor 

Sevier Power Company 

620 S Main 

Bountiful, UT 840100 

Project Number: N0125290003 

RE: NOI to construct a 580 MW combined cycle, natural gas, 

combustion turbine power plant 

 Sevier County; CDS A; NSR, PSD, MACT (Part 63), 

Attainment Area, Title IV (Part 72 / Acid Rain), 

Compliance Assurance Monitoring (CAM), Title V (Part 

70) major source, Major criteria source, NSPS (Part 60), 

Review Engineer: John Jenks 

Date: March 30, 2012 

Notice of Intent Submitted: September 8, 2011 

Plant Contact: Bruce Taylor 

Phone Number: (801) 916-7341 

Source Location: 414,332 m Easting 4,300,261 Northing, Zone 12, Sigurd, 

UT 

 Sevier County 

 4300261 m Northing, 414332 m Easting, UTM Zone 12 

 UTM Datum: NAD83 

DAQ requests that a company/corporation official read the attached draft/proposed Plan Review with 

Recommended Approval Order Conditions. If this person does not understand or does not agree with the 

conditions, the review engineer should be contacted within five days after receipt of the Plan Review. If 

this person agrees with the Plan Review and Recommended Approval Order Conditions, this person 

should sign below and return (FAX # 801-536-4099) within 10 days after receipt of the conditions. If the 

review engineer is not contacted within 10 days, the review engineer shall assume that the 

company/corporation official agrees with this Plan Review and will process the Plan Review towards 

final approval. A public comment period will be required before the Approval Order can be issued. 

Applicant Contact ______________________________________________________________ 

(Signature & Date)
Engineering Review NSR0125290003: Sevier Power Company: Power Plant - NOI to construct a 580 MW combined cycle, 

natural gas, combustion turbine power plant 

March 30, 2012 

Page 2 

OPTIONAL: In order for this Source Plan Review and associated Approval Order conditions to be 

administratively included in your Operating Permit (Application), the Responsible Official as defined in 

R307-415-3, must sign the statement below and the signature above is not necessary. THIS IS 

STRICTLY OPTIONAL! 

If you do not desire this Plan Review to be administratively included in your Operating Permit 

(Application), only the Applicant Contact signature above is required. Failure to have the Responsible 

Official sign below will not delay the Approval Order, but will require a separate update to your 

Operating Permit Application or a request for modification of your Operating Permit, signed by the 

Responsible Official, in accordance with R307--415-5a through 5e or R307-415-7a through 7i. 

“Based on reasonable inquiry, I certify that the information provided for this 

Approval Order has been true, accurate and complete and request that this 

Approval Order be administratively amended to the Operating Permit 

(Application).” 

Responsible Official _________________________________________________ 

(Signature & Date) 

 Print Name of Responsible Official _____________________________________ 
Engineering Review NSR0125290003: Sevier Power Company: Power Plant - NOI to construct a 580 MW combined cycle, 

natural gas, combustion turbine power plant 

March 30, 2012 

Page 3 

ABSTRACT 

As the abstract is longer than the available space in this field, please see the attached document SPC - 

Abstract.docx for additional details. 

SOURCE SPECIFIC DESIGNATIONS 

Applicable Programs: 

NSPS (Part 60), Subpart A: General Provisions applies to Power Plant 

NSPS (Part 60), Subpart Dc: Standards of Performance for Small Industrial-Commercial-Institutional 

Steam Generating Units applies to Auxiliary Boiler 

NSPS (Part 60), Subpart Dc: Standards of Performance for Small Industrial-Commercial-Institutional 

Steam Generating Units applies to Convection Fuel Heaters 

NSPS (Part 60), Subpart IIII: Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines applies to Emergency Fire Water Pump 

NSPS (Part 60), Subpart IIII: Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines applies to Emergency Generator 

NSPS (Part 60), Subpart KKKK: Standards of Performance for Stationary Combustion Turbines 

applies to Combustion Turbines 

MACT (Part 63), Subpart A: General Provisions applies to Power Plant 

MACT (Part 63), Subpart ZZZZ: National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines applies to Emergency Fire Water Pump 

MACT (Part 63), Subpart ZZZZ: National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines applies to Emergency Generator 

Attainment Area applies to Power Plant 

Compliance Assurance Monitoring (CAM) applies to Power Plant 

Major criteria source applies to Power Plant 

NSR applies to Power Plant 

PSD applies to Power Plant 

Title IV (Part 72 / Acid Rain) applies to Power Plant 

Title V (Part 70) major source applies to Power Plant 

Permit History: 

When issued, the approval order shall supersede or will be based on the following documents: 

Is Derived From Source submitted NOI dated September 8, 2011 

Incorporates Additional information received dated January 19, 2012 

SUMMARY OF NOTICE OF INTENT INFORMATION 

Description of Proposal: 

Sevier Power Company (SPC) proposes to construct and operate a new natural gas-fired combined-cycle 

power generating plant to be located approximately 8 miles northeast of Richfield Utah in Sevier County, 

Utah. The proposed plant upon completion will include a single power block, fired exclusively on 
Engineering Review NSR0125290003: Sevier Power Company: Power Plant - NOI to construct a 580 MW combined cycle, 

natural gas, combustion turbine power plant 

March 30, 2012 

Page 4 

pipeline-quality natural gas, and will consist of either two General Electric (GE) Frame 7FA or Siemens 

Westinghouse 5000-F(4) gas turbines, two heat recovery steam generators (HRSGs) with supplemental 

firing, and one steam turbine in a combined-cycle configuration, with associated equipment including an 

air-cooled condenser, a natural gas-fired auxiliary boiler, two natural gas-fired fuel heaters, a diesel 

engine-driven fire pump, and a diesel engine emergency generator. The combined cycle plant will have a 

nominal electrical generating capacity output of approximately 580 megawatts (MWe). 

The proposed plant is considered to be a major Prevention of Significant Deterioration 

(PSD) source and is listed as one of the 28 major categories as defined in 40 CFR Part 52.21. The criteria 

pollutants that will be emitted from the facility are nitrogen oxides (NOx), carbon monoxide (CO), 

volatile organic compounds (VOCs), particulate matter (PM10 and PM2.5), and sulfur dioxide (SO2). The 

proposed electric generating facility has the potential to emit (PTE) regulated pollutants in amounts above 

significant levels as 40 CFR Part 52.21 (b) 23 for the following: NOx, PM10 and PM2.5, CO, and VOC. 

Summary of Emission Totals: 

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

rounding of emissions is possible. 

Estimated Criteria Pollutant Potential Emissions 

CO2 Equivalent 2,019,226.1 tons/yr 

Carbon Monoxide 577.40 tons/yr 

Nitrogen Oxides 168.30 tons/yr 

Particulate Matter - PM10 106.00 tons/yr 

Particulate Matter - PM2.5 106.00 tons/yr 

Sulfur Dioxide 25.70 tons/yr 

Volatile Organic Compounds 91.60 tons/yr 

Estimated Hazardous Air Pollutant Potential Emissions 

Total HAPs (CAS #THAPS) 8.50 tons/yr 

Total hazardous air pollutants 8.50 tons/yr 

Review of Best Available Control Technology: 

1. BACT review regarding Criteria Pollutant BACT - Combustion Turbines and HRSGs 

As required under R307-401-8(1)(a) and also under R307-405-11, "the degree of pollution 

control for emissions ... is at least best available control technology." Best available control 

technology or BACT is defined in R307-401-2(d). SPC submitted a BACT analysis following 

EPA's recommended "top-down" approach, which is a five-step methodology outlined as 

follows:

Step 1 - Identify all control technologies

Step 2 - Eliminate technically infeasible options

Step 3 - Rank remaining control technologies by control effectiveness

Step 4 - Evaluate most effective controls

Step 5 - Select BACT

This approach has been well documented and discussed, and is the most commonly accepted 
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natural gas, combustion turbine power plant 

March 30, 2012 

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approach to satisfy the case-by-case requirement for BACT determination. UDAQ will not 

include an in-depth discussion of the top-down methodology here. Rather, UDAQ reviewed 

SPC's BACT submittal and agrees with the reached conclusions. For the CT/HRSG units those 

conclusions are:

NOx - use of dry low-NOx (DLN) combustors, SCR, and ammonia injection to achieve an 

emissions limit of 2.0 ppmdv @ 15% O2 on a 3-hour average

CO - DLN combustors, good combustion practices, oxidation catalyst (oxy-cat) system with a 

limit of 3.0 ppmdv @ 15% O2 on a 3-hour average

VOC - DLN combustors, good combustion practices, oxy-cat with a limit of 3.0 ppmdv @ 15% 

O2 on a 3-hour average

PM10/PM2.5 - good combustion practices, natural gas as fuel, limit of 14 lb/hr on a 30-day rolling 

average

SO2/H2SO4 - good combustion practices, natural gas as fuel, limit of 3.4 lb/hr on a 30-day 

rolling average [Last updated March 29, 2012] 

2. BACT review regarding Criteria Pollutant BACT - Auxiliary Boiler 

For the Auxiliary Boiler those conclusions are:

NOx - use of ultra-low-NOx burners (ULNB) and FGR to achieve an emissions limit of 0.017 

lb/MMBtu, 1.45 lb/hr

CO - good combustion practices with a limit of 0.0375 lb/MMBtu

PM10/PM2.5 - good combustion practices, natural gas as fuel, limit of 0.01 lb/MMBtu

SO2/H2SO4 - natural gas as fuel [Last updated March 9, 2012] 

3. BACT review regarding Criteria Pollutant BACT - Miscellaneous Sources 

For the convection heaters those conclusions are:

NOx - use of low-NOx burners (LNB) utilizing low excess air and FGR to achieve an emissions 

limit of 0.036 lb/MMBtu, 0.81 lb/hr

CO - good combustion practices with a limit of 0.074 lb/MMBtu

PM10/PM2.5 - good combustion practices, natural gas as fuel, limit of 0.01 lb/MMBtu

SO2/H2SO4 - natural gas as fuel

For the diesel fired engines (emergency generator and emergency fire water pump) those 

conclusions are:

NOx - use of Tier II (emergency generator) and Tier III (fire water pump) engines, hours of 

operation for testing and maintenance limited to 100 hrs/yr as per 40 CFR 63 Subpart ZZZZ
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CO - use of Tier II and Tier III engines, hours of operation for testing and maintenance limited 

to 100 hrs/yr

SO2/H2SO4 - ultra low sulfur diesel (15 ppm sulfur) as fuel [Last updated March 9, 2012] 

4. BACT review regarding Startup / Shutdown BACT 

While post-combustion controls work extremely well during normal operations, catalytic 

oxidation and reduction systems (SCR and oxy-cat) are of limited use during startup and 

shutdown periods. While some degree of emission control is possible, catalytic systems are 

designed to operate within specific temperature ranges and care must be taken to avoid thermal 

stresses during heating or cooling. Therefore, during startup and shutdown there will be periods 

when the catalyst beds have reduced or limited control efficiency. For this reason, the optimal 

control technique is to limit the number and duration of startup and shutdown events, as this 

limits the amount of operation under these periods of reduced efficiency.

SPC estimates that a maximum of 12 cold starts (equipment is cold prior to startup), lasting 

approximately 8 hours, 50 warm starts (equipment is warm), lasting approximately 4 hours, and 

230 hot starts (equipment is near normal operating temperature), lasting approximately 1-3 

hours, will occur annually. 

Limits on emissions of 126 lb/hr for NOx and 959 lb/hr for CO shall apply during all startup and 

shutdown periods. [Last updated March 23, 2012] 

5. BACT review regarding GHG BACT 

At this point in time, the only practical way to reduce the amount of CO2 generated is to 

minimize the amount of fuel combustion required to produce the desired amount of electricity. 

This is achieved by operating the equipment efficiently in accordance with manufacturer 

standards and conducting periodic maintenance on the equipment to keep it at its optimum 

performance. In comparison to other fuels, natural gas generates a lower amount of CO2 and will 

be used exclusively by SPC for the CTs/HRSGs. 

To determine an appropriate CO2 emissions limit for the CT/HRSGs, a search of state and EPA's 

RBLC databases for recent issued permits was conducted to proposed a BACT emission limit 

for the CTs/HRSGs, the auxiliary boiler, and convection heaters. Two permits were identified, 

PacifiCorp Lakeside in Utah County, Utah and Russell Energy Center in Alameda County, 

California with a CO2 BACT limit which was 1,100 pounds CO2 per net megawatt-hour. This 

CO2 limit is comparable to the average emissions rate for all natural gas fired power plants of 

1135 lbs/MW-hr that was published by EPA. 

However, in the Response to Comments Document for Russell City Energy Center's project, 

EPA suggested that a proper BACT value should be established based on: 1) output based; 2) 

efficiency-based; 3) and include reasonable assumptions on degradation factors such as a 

compliance design margin and performance degradation from normal wear and tear. UDAQ 

pointed out to the EPA, however, that two factors also need to be accounted in establishing a 

proper BACT value which include: (1) An adjustment of power output for sources located at a 

much higher elevation; and (2) a discussion of relative percentage of duct firing since duct firing 

has a different emissions profile than that of the combustion turbine. 

The Russell City Energy Center established a final efficiency rating of 7730 Btu/kWhr (HHV). 
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This was based on the maximum efficiency of 6,852 Btu/kWhr for each turbine, readjusting to 

7,080 Btu/kWhr for an "as installed" rating, and then readjusting again for normal degradation. 

Russell City is located at an elevation of 16 feet above sea level. The proposed heat input rate 

for the Russell City Energy Center was 2,038.6 MMBtu/hr for each turbine and an additional 

200 MMBtu/hr for duct firing in the HRSG. 

Lake Side II followed a similar approach and established an efficiency rating of 8,095 

Btu/kWhr. Lake Side II is located at an elevation of approximately 4,550 feet above sea level 

with a proposed a heat input rate of 1762 MMBtu/hr for each turbine and an additional 400 

MMBtu/hr for duct firing. 

The Russell City Energy Center is able to supply more fuel to the turbines given its much lower 

elevation. The total expected output of the plant is approximately 612 MW with 8.9% of its total 

heat input coming from duct firing. Lakeside II is a 629 MW plant with 18.5% of its heat input 

from duct firing.

The proposed SPC facility will have an efficiency rating of approximately 7,515 Btu/kWhr and 

occurs at the extreme low ambient conditions of -17°F. The SPC facility will be located at 

approximately 5,303 feet above mean sea-level. The proposed heat input rate of each turbine is a 

maximum of 1916.5 MMBtu/hr. The proposed heat input to the duct burners will be as high as 

540 MMBtu/hr. The proposed SPC facility will be a nominal 580 MW plant with 8.1% of its 

total heat input coming from duct firing.

The NSR section recommends that the use of high efficiency CT/HRSG units be accepted as 

BACT for GHG emissions. As more than 98% of the GHG emissions are the CO2 emissions 

from the CT/HRSG units, a limit of 1,926,426 MT of CO2/yr from both CT/HRSG units 

combined shall be set, with compliance demonstrated by CEM. [Last updated March 27, 2012] 

Modeling Results: 

Please see Modeling Memorandum MN125290003-12.docx for UDAQ's analysis and 

recommendations [Last updated March 8, 2012] 
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RECOMMENDED APPROVAL ORDER CONDITIONS 

The intent is to issue an air quality Approval Order (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. The AO will be issued to and will apply to the following: 

Name of Permittee: 

Sevier Power Company 

620 S Main 

Bountiful, UT 840100 

Permitted Location: 

Sevier Power Company: Power Plant 

414,332 m Easting 4,300,261 Northing 

Zone 12 

Sigurd, UT 84657 

UTM coordinates: 414332 m Easting, 4300261 m Northing, UTM Zone 12 

SIC code: 4911 (Electric Services) 

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] 

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 Executive Secretary or Executive Secretary's 

representative upon request, and the records shall include the two-year period prior to the date of 

the request. Unless otherwise specified in this AO or in other applicable state and federal rules, 

records shall be kept for a minimum of five (5) years. [R307-401-8] 

I.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 Executive 

Secretary 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 R307-107. General Requirements: Unavoidable 

Breakdowns. [R307-107] 

I.7 The owner/operator shall comply with UAC R307-150 Series. Inventories, Testing and 

Monitoring. [R307-150] 
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Section II: SPECIAL PROVISIONS 

II.A The approved installations shall consist of the following equipment: 

II.A.1 Power Plant 

Nominal 580 MW natural gas-fired combustion turbine power plant 

II.A.2 Turbine 1 

F-Class combustion turbine with dry low-NOx

II.A.3 HRSG 1 

Heat recovery steam generator with duct burners, SCR and catalytic oxidation 

II.A.4 Turbine 2 

F-Class combustion turbine with dry low-NOx

II.A.5 HRSG 2 

Heat recovery steam generator with duct burners, SCR and catalytic oxidation 

II.A.6 Auxiliary Boiler 

85 MMBtu/hr auxiliary boiler with ULNB and FGR 

II.A.7 Convection Fuel Heaters 

Two (2) 22.3 MMBtu/hr fuel heaters 

II.A.8 Emergency Generator 

1,250 kWe emergency diesel generator 

II.A.9 Emergency Fire Water Pump 

300 kWe diesel-fired fire water pump 

II.A.10 Water Treatment 

Water treatment and storage facilities 

II.A.11 Ammonia Storage and Handling 

Aqueous ammonia storage and handling equipment 

II.B Requirements and Limitations 

II.B.1 Conditions on Permitted Source

II.B.1.a SPC shall notify the Executive Secretary in writing when the installation of the equipment listed 

in II.A has been completed and is operational, as an initial compliance inspection is required. To 

insure proper credit when notifying the Executive Secretary, send your correspondence to the 

Executive Secretary, attn: Compliance Section.

If construction and/or installation has not been completed within eighteen months from the date 

of this AO, the Executive Secretary shall be notified in writing on the status of the construction 

and/or installation. At that time, the Executive Secretary shall require documentation of the 

continuous construction and/or installation of the operation and may revoke the AO. 

[R307-401-8] 

II.B.1.b 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 output of 

the system, for measuring the NOx and CO emissions. The monitoring system shall comply with 

all applicable sections of R307-170; 40 CFR 60.13; and 40 CFR 60, Appendix B. The NOx

monitor shall comply with 40 CFR 75, Appendix A and B.
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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, 40 CFR 60.13] 

II.B.1.c 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.1.d The owner/operator shall use natural gas as fuel in the combustion turbines, duct burners and 

auxiliary boiler. 

[R307-401-8] 

II.B.2 Conditions on Combustion Turbines and HRSGs

II.B.2.a Emissions to the atmosphere from the indicated emission point(s) shall not exceed the following 

rates and concentrations:

Source: Each Turbine/HRSG Stack

Pollutant Limitations Averaging Period

PM10/PM2.5 14 lb/hour (with duct firing) 30-day rolling average

NOx 2.0 ppmvd at 15% O2* 3-hour 

CO 3.0 ppmvd at 15% O2* 3-hour 

VOC 3.0 ppmvd at 15% O2* 3-hour

* Under steady state operation 

[R307-401-8] 

II.B.2.b 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 * #
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 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 

Executive Secretary

% Test every five (5) years or testing may be replaced with parametric monitoring if approved 

by the Executive Secretary

# Compliance shall be demonstrated through use of a Continuous Emissions Monitoring System 

(CEM) as outlined in Condition II.B.1.b. The Executive Secretary may require testing at any 

time. 

[R307-165] 

II.B.2.c For all emissions testing the following shall apply:

Notification:

The Executive Secretary 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 Executive Secretary. 

The source test protocol shall be approved by the Executive Secretary 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 Executive 

Secretary.

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 Executive Secretary. 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 the 

Executive Secretary.

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 Executive 

Secretary. All particulate captured shall be considered PM10/PM2.5. The back half condensibles 
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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 Executive Secretary. The back half condensibles shall also be tested 

using the method specified by the Executive Secretary. 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 Executive Secretary.

NOx:

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by 

the Executive Secretary.

CO:

40 CFR 60, Appendix A, Method 10, or other testing methods approved by the Executive 

Secretary.

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 Executive Secretary, to give the results in the specified 

units of the emission limitation. 

[R307-165] 

II.B.2.d Compliance with the 3-hour NOx and CO emission limitations specified in Condition II.B.2.a 

shall not be required during short-term excursions, limited to a cumulative total of 160 hours 

annually. 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.e 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 
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Condition II.B.2.d. Startup is defined as the period beginning with turbine initial firing until the 

unit meets the ppmvd emission limits in Condition II.B.2.a 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. 

Emissions of NOx from each CT/HRSG unit shall not exceed 126 lb/hr during startup or 

shutdown operations

Emissions of CO from each CT/HRSG unit shall not exceed 959 lb/hr during startup or 

shutdown operations 

[R307-401-8] 

II.B.2.f Emissions of GHG from both CT/HRSG units combined shall not exceed 1,926,426 metric tons 

of CO2 per rolling 12-month period. Compliance with the rolling 12-month period shall be 

determined through use of the CO2 CEM as outlined in condition II.B.1.b above. 

[R307-170, R307-401-8] 

II.B.2.g The height of the CT/HRSG stacks shall be no less than 165 feet, as measured from ground level 

at the base of the stack. 

[R307-410-6] 

II.B.3 Conditions on Auxiliary Boiler

II.B.3.a 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 0.0375 lb/MMBtu 3-hour 

[R307-401-8] 

II.B.3.b 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

Auxiliary Boiler PM10/PM2.5 * %

 NOx * %

 CO * %

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 
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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 five (5) years or testing may be replaced with parametric monitoring if approved 

by the Executive Secretary

[R307-165] 

II.B.3.c For all emissions testing the following shall apply:

Notification:

The Executive Secretary 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 Executive Secretary. 

The source test protocol shall be approved by the Executive Secretary 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 Executive 

Secretary.

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 Executive Secretary. 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 the 

Executive Secretary.

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 Executive 

Secretary. All particulate captured shall be considered PM10/PM2.5. The back half condensibles 

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 Executive Secretary. The back half condensibles shall also be tested 

using the method specified by the Executive Secretary. 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 Executive Secretary.
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NOx:

40 CFR 60, Appendix A, Method 7, 7A, 7B, 7C, 7D, 7E, or other testing methods approved by 

the Executive Secretary.

CO:

40 CFR 60, Appendix A, Method 10, or other testing methods approved by the Executive 

Secretary.

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 Executive Secretary, to give the results in the specified 

units of the emission limitation. 

[R307-165] 

II.B.4 Conditions on Emergency Generator

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] 

II.B.5 Conditions on Diesel-Fired Equipment

II.B.5.a 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 #1 or #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] 
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 Section III: APPLICABLE FEDERAL REQUIREMENTS 

 

In addition to the requirements of this AO, all applicable provisions of the following federal programs 

have been found to apply to this installation. This AO in no way releases the owner or operator from any 

liability for compliance with all other applicable federal, state, and local regulations including UAC 

R307. 

NSPS (Part 60), A: General Provisions 

NSPS (Part 60), Dc: Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating 

Units 

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), A: General Provisions 

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 
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REVIEWER COMMENTS 

The AO will be based on the following documents: 

Is Derived From Source submitted NOI dated September 8, 2011 

Incorporates Additional information received dated January 19, 2012 

1. Comment regarding PSD Applicability: 

Because the SPC power plant is defined as a fossil fuel-fired steam electric plant of greater than 

250 MMBtu/hr heat input, it falls into one of the 28 listed source categories with a 100 tpy 

emission threshold for determination as a major stationary source under PSD. The SPC power 

plant will be a major source for at least one PSD regulated pollutant as found under 40 CFR 

52.21(b)(1)(i)(a). Therefore, any pollutant with emissions greater than the significance level will 

also be subject to PSD review. An analysis of SPC's emissions reveals that NO2, CO, PM10 and 

PM2.5 are all subject to PSD review (GHG emissions will be covered under a separate review 

comment). 

In addition to the application of BACT (covered elsewhere) and an analysis of air quality impacts, 

a source subject to PSD must also submit an Additional Impacts Analysis which addresses the 

impact to visibility; acid deposition; the impact on soils, vegetation and wildlife; and the general 

commercial, residential, industrial and other growth associated with the source.

For purposes of this review, visibility and acid deposition are both addressed in the associated 

(and attached) modeling memorandum MN125290003-12.docx. 

The soils vegetation and wildlife analysis was submitted under Appendix P of the September 8, 

2012 NOI. After review of the expected emissions from the SPC power plant, modeled impacts 

on Air Quality Related Values (AQRVs) were below, and in most cases far below, the significant 

impact levels established by EPA. Therefore, no adverse impact to soils, vegetation or wildlife is 

expected.

The growth analysis is found in section 8.2 of the NOI. No new commercial construction, 

housing, or industrial construction would be necessary during the construction period. Similarly, 

no new housing, commercial or industrial construction is expected as a result of operating the 

power plant. The full-time permanent positions required are estimated at 20-25, with some of 

these positions filled by local residents. Given these growth expectations, no new significant 

emissions are anticipated from secondary growth during either construction or operation of the 

power plant. [Last updated March 27, 2012] 

2. Comment regarding NSPS Applicability: 

The following New Source Performance Standards were determined to be applicable to the SPC 

power plant:

40 CFR 60 Subpart A - General Provisions. This subpart outlines general provisions applicable to 

a source subject to any other subpart under 40 CFR 60.

40 CFR 60 Subpart Dc - Standards of Performance for Small Industrial-Commercial-Institutional 

Steam Generating Units. This subpart applies to both the auxiliary boiler and the two convection 
Engineering Review NSR0125290003: Sevier Power Company: Power Plant - NOI to construct a 580 MW combined cycle, 

natural gas, combustion turbine power plant 

March 30, 2012 

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heaters. As these units are all natural gas fired, only the recordkeeping and reporting requirements 

of Subpart Dc are applicable. Although the HRSGs are steam generating units, they are not 

subject to the requirements of Subpart Da, Db or Dc, because they are considered to be integral to 

the combined cycle CT/HRSG affected unit under Subpart KKKK (see below) and are therefore 

regulated under that NSPS.

40 CFR 60 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines. This subpart applies to both the diesel-fired emergency generator, and the 

diesel-fired emergency fire water pump. Both units shall comply with the provisions of this 

subpart.

40 CFR 60 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines. As 

the two CT/HRSG units are both greater than 10 MMBtu/hr heat input, this subpart applies. A 

stationary combustion turbine is defined as all equipment associated with the physical turbine; 

including (but not limited to) the turbine, heat recovery systems, ancillary equipment, any 

combined-cycle turbine, and any combined heat and power combustion system. Therefore, the 

HRSGs and duct burners are considered to be part of the stationary combustion turbine, and are 

exempt from the NSPS requirements of Subparts Da, Db or Dc. Subpart KKKK also supersedes 

the older Subpart GG, which, therefore, does not apply. [Last updated March 9, 2012] 

3. Comment regarding NESHAP/MACT Applicability: 

The following NESHAP/MACT requirements were found to be applicable to the SPC power 

plant:

40 CFR 63 Subpart A - General Provisions: This subpart outlines general provisions applicable to 

a source subject to any other subpart under 40 CFR 63.

40 CFR 63 Subpart ZZZZ - National Emissions Standards for Hazardous Air Pollutants for 

Stationary Reciprocating Internal Combustion Engines. This subpart applies to both the 

emergency generator and emergency fire water pump. An affected compression ignition source 

that meets the criteria outlined in 40 CFR 63.6590 paragraphs (c)(1) through (7) must meet the 

requirements of Subpart ZZZZ by meeting the requirements of 40 CFR 60 Subpart IIII. 

Therefore, while Subpart ZZZZ applies to these two units, there are no additional applicable 

requirements.

While the CT/HRSGs are a source of HAP emissions, the total expected HAP emissions from the 

power plant is less than 10 tpy. This categorizes the SPC power plant as an area source for HAP 

emissions. Therefore the requirements of 40 CFR 63 Subpart YYYY do not apply to this plant. 

[Last updated March 29, 2012] 

4. Comment regarding Title IV and Title V: 

The SPC power plant will be subject to both Title IV (Acid Rain Provisions) and Title V 

(Operating Permits) of the CAA. 

Title IV requires, in part, the installation of a CEMS to demonstrate compliance with the acid rain 

requirements of 40 CFR 75. This CEMS requirement is also included in this permitting action.

Title V requires, in part, that the applicant submit a timely and complete Title V application within 

one year of commencing operations. It also requires the application of CAM (compliance 
Engineering Review NSR0125290003: Sevier Power Company: Power Plant - NOI to construct a 580 MW combined cycle, 

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March 30, 2012 

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assurance monitoring) on those emitting units meeting specific requirements. The CT/HRSG 

units will require the application of CAM. SPC has proposed to meet this requirement by 

installing and operating a CEMS for both NOx and CO emissions (the CAM-applicable 

pollutants). [Last updated March 9, 2012] 

5. Comment regarding GHG Emissions: 

As part of its request for additional information, UDAQ asked SPC to recalculate GHG emissions 

using a consistent methodology. In summary, that strategy was to apply the same ambient 

temperature conditions to each source of GHG emissions and then pick the highest emitting 

scenario with all other factors being unchanged. This results in a lower but more accurate and 

realistic estimate of GHG emissions from the plant. Using this revised methodology the GHG 

emissions from the SPC plant are calculated as follows:

SPC operating case #11(GE operating case #14) turbine emissions:

CO2 = 1926425.5 metric tons (MT)/yr, global warming potential (GWP) x1 = 1926425.5 MT/yr 

CO2e

N2O = 101.43 MT/yr, GWP x310 = 31443.3 MT/yr CO2e

CH4 = 32.60 MT/yr, GWP x21 = 684.6 MT/yr CO2e

Turbine CO2e = 1958552.1 MT/yr

Adding in the auxiliary boiler at 39816 MT/yr CO2e and convection heaters at 20858 MT/yr CO2e 

for this same operating case gives a grand total of 2,019,226.1 MT/yr CO2e. 

A discussion of GHG BACT is found in the BACT section of this source plan review document. 

[Last updated March 9, 2012] 
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natural gas, combustion turbine power plant 

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ACRONYMS 

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

40 CFR Title 40 of the Code of Federal Regulations 

AO Approval Order 

BACT Best Available Control Technology 

CAA Clean Air Act 

CAAA Clean Air Act Amendments 

CDS Classification Data System (used by EPA to classify sources by size/type) 

CEM Continuous emissions monitor 

CEMS Continuous emissions monitoring system 

CFR Code of Federal Regulations 

CMS Continuous monitoring system

CO Carbon monoxide 

CO2 Carbon Dioxide 

CO2e Carbon Dioxide Equivalent - 40 CFR Part 98, Subpart A, Table A-1 

COM Continuous opacity monitor 

DAQ Division of Air Quality (typically interchangeable with UDAQ) 

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 

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 

UDAQ Utah Division of Air Quality (typically interchangeable with DAQ) 

VOC Volatile organic compounds