DAQE­AN0102370012­08 

March 13, 2008 

Reginald Soepnel, Managing Director

PacifiCorp, Hunter Power Plant 

3 miles South Highway 10 

P.O. Box 569 

Castle Dale, Utah  84513 

Dear Mr. Soepnel:

Re:  Approval Order:  Installation of Pollution Control Equipment, Established Plantwide

Applicability Limitations and Approval Orders Consolidation, Emery County – CDS A; NSPS; 

PSD; Title IV; Title V Major; HAPs Project Code:  N010237­0012 

The attached document is the Approval Order for the above­referenced project.

Future correspondence on this Approval Order should include the engineer's name as well as the DAQE 

number as shown on the upper right­hand corner of this letter. Please direct any technical questions you 

may have on this project to Mr. John Jenks. He may be reached at (801) 536­4459.

Sincerely,

M. Cheryl Heying, Executive Secretary 

Utah Air Quality Board 

MCH:JJ:sa

cc:  Southeastern Utah District Health Department 

Mike Owens, EPA Region VIII

150 North 1950 West • PO Box 144820 • Salt Lake City, UT 84114­4820 • phone (801) 536­4000 • fax (801) 536­4099

T.D.D. (801) 536­4414 • www.deq.utah.gov

State of Utah 

Department of 

Environmental Quality 

Richard W. Sprott

Executive Director

DIVISION OF AIR QUALITY 

Cheryl Heying

Director

JON M. HUNTSMAN, JR. Governor

GARY HERBERT

Lieutenant Governor
STATE OF UTAH

Department of Environmental Quality

Division of Air Quality

APPROVAL ORDER: Installation of Pollution Control 

Equipment, Establishing Plantwide Applicability

Limitations and Approval Orders Consolidation

Prepared By: John Jenks, Engineer

(801) 536­4459 

Email: jjenks@utah.gov 

APPROVAL ORDER NUMBER 

DAQE­AN0102370012­08 

Date: March 13, 2008 

PacifiCorp, Hunter Power Plant 

Source Contact

William Lawson

(801) 220­4581 

M. Cheryl Heying 

Executive Secretary 

Utah Air Quality Board
Abstract 

PacifiCorp is installing new emissions control equipment at the Hunter Power Plant on Units #1, #2 and 

#3 boilers in order to substantially reduce plant emissions, mainly sulfur dioxide (SO2), H2SO4, HCl,

HFl, particulate matter (PM) and nitrogen oxides (NOx). PacifiCorp will install on Units #1, #2 and #3 

a NOx reduction system consisting of two general components: (1) two levels of separated overfire air

and (2) new low­NOx burners. These changes will result in reduction of NOx emissions and possibly 

result in an increase in CO emissions greater than the PSD significance level. PacifiCorp will also 

replace the existing electrostatic precipitators (ESP) on Units #1 and #2 with a new pulse jet fabric filter 

(baghouse) system. This will result in a reduction of H2SO4 and PM emissions. Finally, PacifiCorp will 

upgrade the existing flue gas desulfurization system on Units #1 and #2 to achieve greater sulfur dioxide 

removal, which will significantly reduce the amount of SO2, HCl, and HFl emissions.

In addition, PacifiCorp is requesting existing approval orders (AO) be consolidated; plantwide 

applicability limits (PALs) for SO2 and NOx emissions and for Unit #3 the SO2 emission limit be set at 

0.12 lb/MMBtu. As indicated in the AO DAQE­1189­97, Unit #3 was subject to an emission limit for 

SO2 of 0.12lb/MMBtu prior to implementation of the existing limit of 0.10 lb/MMBtu.

Opacity limit language for the Unit #1, #2, and #3 boiler stacks is expanded to clarify the opacity limit

during startup and shutdown events.

As a result of the proposed changes, the source is subject to carbon monoxide (CO) PSD major

modification review since the rest of the plant emission changes are reductions. Unit #1 and #2 boilers 

are subject to New Source Performance Standards (NSPS), Part 60 Subpart D, and the Unit #3 boiler is

subject to Subpart Da. Title IV and Title V of the 1990 Clean Air Act apply to this source. The Title V

Operating Permit will be updated prior to operating the modified equipment. The source is located in

Emery County, which is an attainment area for the National Ambient Air Quality Standards (NAAQS)

for all pollutants. This AO has gone through the enhanced NSR process.

After the installation and upgrades of the control equipment, the emissions from the plant, in tons per 

year, will change as follows: PM10 = (­) 1,441.02, NOx = (­) 9,298, SO2 = (­) 3,609, CO = (+) 17,278,

H2SO4 = (­) 33.1, HFl = (­) 7.5, and HCl = (­) 27.9.

The change in emissions, after the replacement, addition and upgrades of control equipment, will result

in the following, in tons per year, potential to emit totals for the plant:  PM10 = 1,218.1, NOx = 19,319, SO2 = 7,187, CO = 18,449, VOC = 163, H2SO4 = 3.5, HF = 44.6, HCl = 13.41, Lead = 0.12 and other 

HAPs = 43.15.

PALs are now established for NOx = 19,319 tons/year and SO2 = 7,187 tons/year based on a 12­month

rolling average.
DAQE­AN0102370012­08 

Page 3

General Conditions:

1. This AO applies to the following PacifiCorp: 

Site Office Corporate Office Location 

PacifiCorp Hunter Plant  PacifiCorp 

3 miles South Highway 10  1407 West North Temple 

P.O. Box 569  Salt Lake City, Utah  84140 

Castle Dale, Utah  84513 

Phone Number (435) 748­5114  (801) 220­2235 

Fax Number (435) 748­6579  (801) 220­4307 

The equipment listed in this AO shall be operated at the following location: 

Approximately three (3) miles south of Castle Dale, Utah on State Highway 10,

Emery County 

Universal Transverse Mercator (UTM) Coordinate System: 

4,335.8 kilometers Northing;  497.8 kilometers Easting;  Zone 12 

UTM Datum NAD27 

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

the Utah Administrative Code (UAC) Rule 307 (R307) and Title 40 of the Code of Federal 

Regulations (40 CFR). Unless noted otherwise, references cited in these AO conditions refer

to those rules.

3. The limits set forth in this AO shall not be exceeded without prior approval in accordance

with R307­401.

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

emissions covered by this AO must be reviewed and approved in accordance with R307­401.

5. All records referenced in this AO or in applicable NSPS and/or NESHAP and/or MACT 

standards, 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. Records shall 

be kept for a minimum of five year periods.

6. PacifiCorp shall install and operate the new Low NOx burners, overfire air system, main 

boiler stack baghouse and upgrade of the existing flue gas desulfurization system on Unit #1 

& #2 (each) and new Low NOx burner system with OFA on Unit #3.  PacifiCorp shall

conduct its operations of the Hunter Power Plant in accordance with the terms and conditions 

of this AO, which was written pursuant to PacifCorp’s Notice of Intent submitted to the

Division of Air Quality (DAQ) on May 2, 2007, July 19, 2007, September 17, 2007,

September 21, 2007, October 26, 2007, November 27, 2007, December 5, 2007 and 

December 26, 2007.
DAQE­AN0102370012­08 

Page 4 

7. This AO shall replace the following AOs : 

DAQE­1189­97 dated December 18, 1997 

Unit #1 dated April 3, 1986 

Unit #2 dated July 27, 1987 

Unit #3 dated August 31, 1983 and additional letters dated October 27, 1983 and September

6, 1985 

8. The approved installations shall consist of the following equipment or equivalent*: 

A.  Steam Generating Unit #1 

Unit Description:  Nominal 480 MW gross capacity, dry bottom, tangentially­fired 

boiler fired on subbituminous & bituminous coal using distillate fuel oil during start­ 

up and flame stabilization currently equipped with Low NOx firing system, ESP and 

SO2 FGD scrubber. Boiler will be equipped with a new advanced combustion Low 

NOx burner/overfire air system (OFA), new baghouse and upgraded SO2 WFGD 

scrubber, with no scrubber bypass.

B. Steam Generating Unit #2 

Unit Description:  Nominal 480 MW gross capacity, dry bottom, tangentially­fired 

boiler fired on subbituminous and bituminous coal using distillate fuel oil during 

start­up and flame stabilization currently equipped with Low NOx firing system, ESP

and SO2 FGD scrubber. Boiler will be equipped with a new advanced combustion 

Low NOx burner/overfire air system (OFA), new baghouse and upgraded SO2

WFGD scrubber, with no scrubber bypass.

C. Steam Generating Unit #3 

Unit Description:  Nominal 495 MW gross capacity, dry bottom, wall­fired boiler

fired on subbituminous and bituminous coal using distillate fuel oil during start­up 

and flame stabilization. Unit is equipped with a new Low NOx burner system with 

overfire air, baghouse and SO2 WFGD scrubber, with no scrubber bypass.

D.  Circulating Water Cooling Tower for Unit #1 steam generating boiler

E. Circulating Water Cooling Tower for Unit #2 steam generating boiler

F. Circulating Water Cooling Tower for Unit #3 steam generating boiler

G. Coal Pile and operations and associated fugitive emissions and fugitive dust

H. Coal Conveyors for coal transfer operations 

I. Unpaved Ash Haul Road for ash disposal 

J. Paved Ash Haul Road for disposal of ash
DAQE­AN0102370012­08 

Page 5 

K. Ash Landfill operations and associated fugitive emissions and fugitive dust

L. Unit #1 Emergency Diesel Generator

M. Unit #2 Emergency Diesel Generator

N.  Unit #3 Emergency Diesel Generator

O.  Emergency Diesel Fire Pump #1 

P. Emergency Diesel Fire Pump #2 

Q.  Auxiliary Steam Boiler rated at 211.4 MMBtu/hr fired on fuel oil and constructed in 

1976 

R. Coal Silo System Exhauster with centrifugal dust collector for Unit #1 coal silos

distribution system 

S. Coal Silo System Exhauster with centrifugal dust collector for Unit #2 coal silo 

distribution system 

T. Coal Silo System Exhauster with centrifugal dust collector for Unit #3 coal silo 

distribution system 

U.  Lime Silo Bin Vents (water treatment plant) dust collectors for lime storage silos for

water treatment plant 

V.  Lime Silo Bin Vents (SO2 scrubber) dust collectors for scrubber lime silos for Units 

#1, #2, and #3 

W. Four 70,000 distillate fuel oil tanks for the emergency diesel generators and fire

pumps 

X.  Four 10,000 gallon tanks that store lubricating oil

Y.  Storage area for oil contained in closed 55 gallon drums and totes 

Z. Three 400 gallon electro control hydraulic oil reservoirs 

AA. Paved access road from the plant entrance to the administration building and parking 

area

BB. Bench­top cold degreasing units using Safety­Kleen or other comparable degreasing 

agents

CC. Miscellaneous Electrical Equipment with some fugitive emission units including 

transformer insulating oil
DAQE­AN0102370012­08 

Page 6 

DD. Anhydrous Sulfur Dioxide Tank: 

Unit Description:  10,000 gallon anhydrous sulfur dioxide tank to generate SO3 for

ESP flue gas conditioning. After the baghouse installation, Anhydrous Sulfur

Dioxide Tank will be removed from service after the baghouses installation on Units

#1 and #2.

EE.  Water Treatment storage tanks including chlorine, aluminum sulfate, lime, sodium 

sulfite, soda ash, calcium hypochlorite, sodium hydroxide, anti­scale, aqueous 

ammonia 

FF. Various storage areas for sealed paint containers 

GG. Spray Paint Booth for painting parts to maintain plant 

HH. Gasoline Refueling Station and Storage Tank for fleet vehicles with a 5,500 gallon 

aboveground tank 

II. 5,500 gallon aboveground unleaded gasoline tank for fleet vehicle refueling 

JJ. Boiler feed pump lube oil conditioners 

KK. Lube oil conditioners with vapor extractors 

LL. Lube oil reservoirs with vapor extractors 

MM. Three 5,500 gallon aboveground diesel tanks and dispensing equipment to refuel 

vehicles and mobile equipment 

NN. Mobile truck mounted vacuum to clean up spilled material such as ash 

OO. Unit #1 equipment for unloading ash from silos and into trucks for transport to the

ash landfill 

PP. Unit #2 equipment for unloading ash from silos and into trucks for transport to the

ash landfill 

QQ. Unit #3 equipment for unloading ash from silos and into trucks for transport to the

ash landfill

· Equivalency shall be determined by the Executive Secretary.

9. PacifCorp shall notify the Executive Secretary in writing when the installation of the new 

equipment listed in Condition #8A, B and C has been completed and is operational. To 

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

Executive Secretary, attn: Compliance Section.
DAQE­AN0102370012­08 

Page 7 

If the 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 in accordance with R307­401­18.

Limitations and Tests Procedures

10. Unit #1 and Unit #2 Boilers 

A  Effective upon issuance of the AO: 

1. PM limit

a. Emissions shall not be greater than 0.05 lb/MMBtu heat input from 

each boiler based on 6­hour averaging period.

b. Stack testing for the emission limitation shall be performed each 

year. The source may be tested at any time if directed by the

Executive Secretary.

2. NOx limits 

a. Emissions from each boiler shall be no greater than 0.70 lb/MMBtu 

heat input based on a 3­hour averaging period.

b. Emissions from each boiler shall be no greater than 0.45 lb/MMBtu 

heat input based on a 12­month rolling averaging period.

c. Measuring of the NOx emissions shall be performed by CEMs.

3. SO2 limits 

a. Emissions from each boiler shall be no greater than 1.2 lb/MMBtu 

heat input for any 3­hour period.

b. Emissions from each boiler shall be no greater than 0.21 lb/MMBtu 

heat input based on a 12­month rolling average.

c. Emissions of SO2 shall be no greater than 20 percent of the potential 

combustion concentration based on the average inlet and average

outlet SO2 emissions determined as the arithmetic average of all

hourly emission rates for the 30 successive boiler operating days.

d. Measuring of the SO2 1.2 lb/MMBtu and 0.21 lb/MMBtu emissions 

shall be performed by CEMs.
DAQE­AN0102370012­08 

Page 8 

B. Effective upon installation or upgrade of control equipment:

1. PM limit

a. Emissions shall not be greater than 0.015 lb/MMBtu heat input from 

each boiler based on a 3­test average.

b. After the initial stack test is performed, stack testing for the

emission limitation shall be performed each year. The source may 

be tested at any time if directed by the Executive Secretary.

2. NOx limits 

a. Emissions from each boiler shall be no greater than 0.70 lb/MMBtu 

heat input based on a 3­hour averaging period.

b. Emissions from each boiler shall be no greater than 0.26 lb/MMBtu 

heat input for a 30­day rolling average.

c. After the initial stack test is performed for 0.26 lb/MMBtu 

measuring of all NOx emissions shall be performed by CEMs.

3. SO2 limits 

a. Emissions from each boiler shall be no greater than 1.2 lb/MMBtu 

heat input for any 3­hour period.

b. Emissions from each boiler shall be no greater than 0.12 lb/MMBtu 

heat input based on a 30­day rolling average.

c. Unit #1 and Unit #2 boiler emissions of SO2 shall be no greater than 

20 percent of the potential combustion concentration based on the

average inlet and average outlet SO2 emissions determined as the

arithmetic average of all hourly emission rates for the 30 successive

boiler operating days.

d. After the initial stack test is performed for 0.12 lb/MMBtu limit, measuring of the SO2 emissions for 0.12 lb/MMBtu and 1.2 

lb/MMBtu limits shall be performed by CEMs.

4. CO limit

a. Emission shall be no greater than 0.34 lb/MMBtu heat input for a

30­day rolling average.

b. 3990 lb/hr for an 8­hour block average.

c. After the initial stack test is performed, measuring of the CO 

emissions shall be performed by CEMs.
DAQE­AN0102370012­08 

Page 9 

11. Unit #3 Boiler

A  Effective upon issuance of the AO: 

1. PM limit

a. Emissions shall not be greater than 0.02 lb/MMBtu heat input from 

each boiler based on a 6­hour averaging period.

b. Stack testing for the emission limitation shall be performed each 

year. The source may be tested at any time if directed by the

Executive Secretary.

2. NOx limits 

a. Emissions from the boiler shall be no greater than 0.46 lb/MMBtu 

heat input for a 30­day rolling average.

b. Measuring of the NOx emissions shall be performed by CEMs.

3. SO2 limits 

a. Emissions of SO2 from the Unit #3 boiler shall be no greater than 

0.12 lb/MMBtu heat input based on a 30­day rolling period.

b. Boiler #3 emissions of SO2 shall be no greater than 10 percent of the

potential combustion concentration based on the average inlet and 

average outlet SO2 emissions determined as the arithmetic average

of all hourly emission rates for the 30 successive boiler operating 

days.

c. Measuring of the SO2 0.10 lb/MMBtu emissions limit shall be

performed by CEMs.

B. Effective upon installation or upgrade of control equipment:

1. PM limit

a. Emissions shall not be greater than 0.02 lb/MMBtu heat input from 

each boiler based on a 6­hour averaging period.

b. Stack testing for the emission limitation shall be performed each 

year. The source may be tested at any time if directed by the

Executive Secretary.

2. NOx limits 

a. Emissions from each boiler shall be no greater than 0.34 lb/MMBtu 

heat input for a 30­day rolling average.
DAQE­AN0102370012­08 

Page 10 

b. After the initial stack test is performed, measuring of NOx 

emissions shall be performed by CEMs.

3. SO2 limits 

a. Emissions of SO2 from the Unit #3 boiler shall be no greater than 

0.12 lb/MMBtu heat input based on a 30­day rolling period.

b. Boiler #3 emissions of SO2 shall be no greater than 10 percent of the

potential combustion concentration based on the average inlet and 

average outlet SO2 emissions determined as the arithmetic average

of all hourly emission rates for the 30 successive boiler operating 

days.

c. Measuring of the SO2 0.12 lb/MMBtu emissions limit shall be

performed by CEMs.

4. CO limit

a. Emission shall be no greater than 0.2 lb/MMBtu heat input for a 30­ day rolling average.

b. 2406 lb/hr for 8­hour block average.

c. After the initial stack test is performed, measuring of the CO 

emissions shall be performed by CEMs.

12. Unit #1, #2 and #3 Boilers Compliance and Monitoring: 

A.  The initial test shall be performed as soon as possible and in no case later than 180 

days after the start up of each new baghouse on unit #1 and #2 boilers, each 

advanced combustion Low NOx burner/overfire air system, new generation Low 

NOx burner system and each WFGD upgrade. Initial stack testing for PM, NOx, and SO2 shall be performed as specified below. Initial stack testing for the CO, NOx 

and SO2 emissions in the Conditions 10.B.2.a, 10.B.2.b., 10.B.3.a., 10.B.3.b., 10.B.4.a., 10.B.4.b. ,11.B.2.a. and 11.B.4.a. may be substituted with a RATA test if 

approved by the Executive Secretary.

B. 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.
DAQE­AN0102370012­08 

Page 11 

C. 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.

D.  Volumetric Flow Rate 

40 CFR 60, Appendix A, Method 2 or other testing methods approved by the

Executive Secretary 

E. PM10

Method 5B shall be used for PM emission or other testing methods approved by the

Executive Secretary.

The back half condensibles shall also be tested using the referenced method 202. The back half condensibles shall not be used for compliance demonstration but shall

be used for inventory purposes.

F. Sulfur Dioxide (SO2)

40 CFR 60, Appendix A, Method 6, 6A, 6B, 6C, or other testing methods approved 

by the Executive Secretary 

G. Nitrogen Oxides (NOx)

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

approved by the Executive Secretary 

H. Carbon Monoxide (CO)

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

Executive Secretary 

I. PacifiCorp shall perform annual stack testing to show compliance with the CO 

emission limitation after the initial stack testing.

J. PacifiCorp shall install, calibrate, maintain, and operate a continuous monitoring 

system for measuring carbon monoxide, sulfur dioxide and nitrogen oxides 

emissions.

13. At all times, the plant­wide applicability limitations for the entire Hunter Plant from all point 

sources and fugitive emissions shall not exceeded the following: 

SO2 Limit 7,187 tons/year based on 12­months rolling total 

NOx Limit 19,319 tons/year based on 12­months rolling total
DAQE­AN0102370012­08 

Page 12 

14. SO2 and NOx limits in Condition 13 shall be monitored in accordance with 40 CFR Part 

52.21.21(aa)(12) and as minimum it shall be done by summing up emissions as follows: 

A.  For Units #1, #2 and #3 main boiler stacks, PacifiCorp’s reporting to EPA’s Acid 

Rain Emissions data base for NOx and SO2 in pounds per hour obtained from the

boilers’ CEM data shall be used to calculate NOx and SO2 emission rates. All 

reported SO2 emissions, including emissions associated with startups, shutdowns, and malfunctions, in pounds per hour, shall be summed to get monthly total 

emissions.

B. For Units #1, #2 and #3 emergency diesel­fired generators, emissions shall be

calculated by multiplying the SO2 and NOx emission factor from the latest edition of

EPA’s emission factors compilation AP­42 and hours of operation. Records 

documenting generator usage shall be kept in a log, and they shall show the date the

generator was used and the duration in hours of generator usage.

C. For Units #1, #2 and #3 emergency diesel­fired fire pumps, emissions shall be

calculated by multiplying the SO2 and NOx emission factor from the latest edition of

EPA’s emission factors compilation AP­42 and hours of operation. Records 

documenting generator usage shall be kept in a log, and they shall show the date the

pump was used and the duration in hours of pump usage.

D.  Auxiliary steam boiler emissions, including emissions associated with startups,

shutdowns, and malfunctions, shall be calculated by multiplying the emission factor 

for SO2 and NOx from the latest edition of EPA’s emission factors compilation AP­ 

42 and fuel consumption. Records documenting Auxiliary steam boiler usage shall

be kept in a log, and they shall show the date the Auxiliary steam boiler was used 

and the duration in hours of the Auxiliary steam boiler usage.

E. The PAL limits in Condition 13 shall be effective for ten years from the date of 

issuance of this AO, in accordance with 40 CFR Subpart 52.21(aa).

F If PacifiCorp applies for PAL renewal, the application in accordance with 40 CFR

Subpart 52.21(aa)(10) shall be submitted before the end of the PAL effective date, 

and the PAL established in this AO will remain until a revised approval order is

issued.

G. Once the PAL expires, the source is subject to the requirements of 40 CFR Subpart 

52.21(aa)(9).

H. Monitoring for each PAL shall be in accordance with 40 CFR Subpart 52.21(aa)(12).

I. For the record keeping requirements of each PAL, PacifiCorp shall comply with 40 

CFR Subpart 52.21(aa)(13).

J. For record submittal, PacifiCorp shall comply with 40 CFR Subpart 52.21(aa)(14).
DAQE­AN0102370012­08 

Page 13 

15. To determine compliance with the applicable 12­month rolling NOx and SO2 PAL limits, the

owner/operator shall calculate new 12­month total NOx and SO2 emissions by the twentieth 

day of each month using data from the previous 12 months. Records of emissions shall be

kept for all periods when the plant is in operation.

16. Visible emissions from Hunter Unit #1, Unit #2 and Unit #3 boilers shall be limited as 

follows: 

During boiler operation, no greater than 20 percent opacity, except as provided in 

R307­201­3(7). During startup and shutdown events Condition 18 and Condition 26 

shall apply.

17. PacifiCorp shall develop, maintain, and implement a written Hunter Emissions Minimization 

Plan (Hunter Plan) that describes, in detail, procedures for operating and maintaining the

Units #1, #2 and #3 boilers, including associated air pollution control and monitoring 

equipment, during events of startup and shutdown. The Plan shall be submitted to the

Executive Secretary no later than 180 days after the issuance of this AO.

18. Definition of startup and shutdown events for Unit #1, Unit #2 and Unit #3 boilers and the

Hunter Plan minimum requirements: 

A.  Startup is defined as the period beginning with the introduction of fuel into the boiler

and ending no later than when two coal feeders have been proven in service and the

flue gas temperature at the outlet ducts to both sides of the electrostatic precipitator

(Units #1 and #2) or the baghouse outlet (Units #1, #2 or #3 boilers) have reached a

temperature of 220 oF and less than 20 percent of the boiler heat input is being 

furnished by fuel oil.

B. Bypass of associated control equipment shall only be used to prevent loss of life, personal injury, or severe property damage.

C. Shutdown is defined as the period beginning when the unit load or output is reduced 

with the intent of removing the unit from service, or when the unit trips as the result

of a sudden and unforeseen failure or malfunction and ending when fuel flow to the

boiler ceases.

D.  The Hunter Plan shall contain detailed steps to minimize, to the maximum extent 

practicable, the frequency and duration of operation in startup or shutdown and shall

be followed at all times. The Hunter Plan shall contain steps to minimize, to the

maximum extent practicable, the frequency and duration of operation in startup or

shutdown mode. This shall include, but not necessarily be limited to, careful and 

detailed design, planning, operation, and maintenance so as to avoid unnecessary, preventable, or unreasonably frequent or lengthy startups and shutdowns.

E. The duration of a boiler startup event shall not extend beyond 20 hours per startup 

period or 300 hours per year per boiler and 750 hours per year combined for the Unit 

#1, #2 and #3 boilers.
DAQE­AN0102370012­08 

Page 14 

F. During periods of startup and shutdown, PacifiCorp shall operate and maintain the

boilers, including associated air pollution control and monitoring equipment, in 

accordance with procedures specified in the Hunter Plan based on equipment 

manufacturer/plant operating procedures.

G. PacifiCorp shall maintain records demonstrating that the procedures in the Hunter

Plan were followed. These records shall include the date and time of occurrence and 

duration of each startup and shutdown, include emissions during startup and 

shutdown as well as other pertinent information.

H. PacifiCorp may periodically revise the Hunter Plan for the affected source as 

necessary to satisfy the requirements of this Condition or to reflect changes in 

equipment or procedures at the affected source. Each such revision must be

submitted to the Executive Secretary.

19. Unless otherwise specified in this AO, visible emissions from any stationary point, other

than main stacks, or fugitive emission source associated with the source or with the control 

facilities shall not exceed 20% opacity. Opacity observations of emissions from stationary 

sources shall be conducted in accordance with 40 CFR 60, Appendix A, Method 9.

For those sources that are subject to NSPS, opacity shall be determined by conducting 

observations in accordance with 40 CFR 60.11(b) and 40 CFR 60, Appendix A, Method 9.

20. Visible fugitive dust emissions from haul­road traffic and mobile equipment in operational 

areas shall not exceed 20% opacity. Visible emission determinations for traffic sources shall

use procedures similar to Method 9. The normal requirement for observations to be made at 

15­second intervals over a six­minute period, however, shall not apply.

21. Fugitive dust and emissions shall be minimized by the following techniques:

A.  All conveyors and drop points shall be enclosed in a structure.

B. The live coal handling and storage shall be enclosed in a structure.

Fuels

22. The sulfur content of any fuel oil shall not exceed 0.85 lbs/MMBtu heat input.  The sulfur

content shall be determined by ASTM Methods D2015­77 or D3286­85 or approved 

equivalent.

Federal Limitations and Requirements

23. In addition to the requirements of this AO, all applicable provisions of 40 CFR Part 60, NSPS Subparts A, 40 CFR 60.1 to 60.18, Subpart D, 40 CFR Part 60.40 to 60.46 (Standards 

of Performance for Fossil­Fuel­Fired Steam Generators for Which Construction is

Commenced After August 17, 1971), Subpart Da (Standards of Performance for Electric 

Utility Steam Generating Units for Which Construction Commenced After September 18,

1978) and Subpart HHHH (Emission Guidelines and Compliance Times for Coal­fired 

Electric Steam Generating Units) apply to this installation.
DAQE­AN0102370012­08 

Page 15 

24. In addition to the requirements of this AO, all applicable provisions of 40 CFR Part 72, 73,

75, 76, 77 and 78 ­ Federal regulations for the Acid Rain Program under Clean Air Act Title 

IV apply to this installation.

25. In addition to the requirements of this AO, all applicable provisions of 40 CFR Part 52.21 

(aa)­Actuals Pals (incorporated by reference in the UAC, R307­405­2) apply to this

installation.

Monitoring ­ General Process

26. The owner/operator shall install, calibrate, maintain, and operate a continuous emissions 

monitoring system (CEMs) on the main boilers stacks for CO, SO2, and NOx. The

owner/operator shall record the output of the system, for measuring the opacity, CO, SO2, and NOx emissions. The monitoring system shall comply with all applicable sections of

R307­170, UAC; and 40 CFR 60, Appendix B.

All continuous emissions monitoring devices as required in federal regulations, and state 

rules shall be installed and operational prior to placing the affected source in operation.

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 devices and shall meet minimum 

frequency of operation requirements as outlined in 40 CFR 60.13 and Section UAC R307­ 170.

Records & Miscellaneous

27. 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 the 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 the equipment authorized by this

AO shall be recorded.

28. The owner/operator shall comply with R307­150 Series. Inventories, Testing and 

Monitoring.

29. The owner/operator shall comply with R307­107. General Requirements: Unavoidable 

Breakdowns.

The Executive Secretary shall be notified in writing if PacifiCorp is sold or changes its name.

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 R307.
DAQE­AN0102370012­08 

Page 16 

A copy of the rules, regulations and/or attachments addressed in this AO may be obtained by contacting the

DAQ.  The UAC R307 rules used by DAQ, the Notice of Intent (NOI) guide, and other air quality documents 

and forms may also be obtained on the Internet at the following web site: 

http://www.airquality.utah.gov/ 

The DAQ is authorized to charge a fee for reimbursement of the actual costs incurred in the issuance of an 

AO. An invoice will follow upon issuance of the final AO. 

Approved By: 

M. Cheryl Heying, Executive Secretary 

Utah Air Quality Board