TECHNICAL SUPPORT DOCUMENT 

AIR QUALITY PERMIT NO. 53399 

ARIZONA PUBLIC SERVICE COMPANY-CHOLLA GENERATING STATION 

 

I. INTRODUCTION 

 This Class I renewal permit issued to Arizona Public Service Company (APS) for continued operation 

of Cholla Generating Station located near Joseph City in Navajo County, Arizona. This permit renews 

and supersedes Operating Permit No. 33500. 

A. Company Information

Facility Name: Cholla Generating Station 

Mailing Address: P.O. Box 188 

Mail Station 4451 

Joseph City, Navajo County, AZ 86032 

 

 Facility Address: 4801 Cholla Lake Road 

Joseph City, Navajo County, AZ 86032 

 

B. Attainment Classification

 The facility is located in an area that is classified as an attainment area for all criteria pollutants. 

 C. Learning Sites Evaluation 

In accordance with ADEQ’s “Environmental Permits and Approvals Near Learning Sites” 

Policy, the Department is required to evaluate if any nearby learning sites would be adversely 

impacted by the facility. Learning sites consist of all existing public schools, charter schools 

and private schools at the K-12 level, and all planned sites for schools approved by the Arizona 

School Facilities Board. The learning sites policy was established to ensure that the protection 

of children at learning sites is considered before a permit approval is issued by ADEQ. 

The Department identified two learning site within two miles of the facility. 

APS Cholla conducted dispersion modeling analysis during their previous permit application 

after implementation of new control systems. The modeling results documented compliance 

with the National Ambient Air Quality Standards (NAAQS) for criteria pollutants and Arizona 

Ambient Air Quality Guidelines (AAAQG) for the hazardous air pollutants (HAPs). Since this 

modeling analysis, the facility has not made changes that resulted in increase in the potential 

emissions. Therefore the learning sites should not have any adverse impacts from the continued 

operation of the facility. 

II. PROCESS DESCRIPTION 

Technical Support Document (EPA review) Page 1 of 15 Permit Issued: May 31, 2012 

APS-Cholla Permit No. 53399 
Technical Support Document (EPA review) Page 2 of 15 Permit Issued: May 31, 2012 

APS-Cholla Permit No. 53399 

The Cholla generating station consists of four coal-fired steam generating units, associated air pollution 

control devices and auxiliary equipment necessary to produce approximately 1160 megawatts of 

electricity. Units 1, 2 and 3 are owned by APS and Unit 4 is owned by Pacificorp. All four units are 

operated by APS. Unit 1 was completed in 1962, Units 2 and 3 were completed in 1978 and 1980, and 

Unit 4 was placed in commercial operation in 1981. The maximum process rates and operating hours of 

the steam units at the Cholla generating station are summarized in Table 1. 

Table 1: Maximum process rates1

 and operating hours 

Emission Unit Hours/yr Gross MW Gross MW-hr/yr 

Steam Boiler Unit 1 8,760 125 1,095,000 

Steam Boiler Unit 2 8,760 305 2,671,800 

Steam Boiler Unit 3 8,760 305 2,671,800 

Steam Boiler Unit 4 8,760 425 3,723,000 

 1 The maximum process rates listed in the table are estimates and should not be used as operating limits of any kind. 

A. Process Description 

Cholla generating station is a Steam Electric Station, Standard Industrial Code (SIC) 4911 

Electric Generation, consisting of four units (Units 1, 2, 3 and 4) which are coal-fired steam 

boilers with Source Classification Code (SCC) #1-01-002-26. Pulverized coal is tangentially 

fired into the dry bottom furnace of each unit. Separated over-fire air is applied to Unit 1. 

Separated closed coupled over-fired air (OFA) is applied to Units 2, 3 and 4. Historically, coal 

had been obtained from the McKinely Mine near Gallup, New Mexico. Due to planned closure 

of McKinley Mine, APS has transitioned to a new supplier of coal. Since 2010, the Lee Ranch 

and El Segundo mines near Grants, New Mexico, are the principle coal suppliers to the Cholla 

generating station. The coal is transported to the Cholla generating station via trains and 

unloaded at a “coal handling” facility which includes a Coal Preparation Plant that directs coal 

to the four units and a main coal pile. Two track feeders systems, “old” and “new”, are used to 

unload coal directly to any of the four units, the main coal pile or any combination thereof. The 

main coal pile contains approximately a 45 day supply of coal. Coal unloaded at the coal 

handling facility is released through the bottom of the train rail cars to one of two large grates 

known as grizzlies. The coal collected below the grizzly at the old track feeders is loaded to a 

coal conveying belt which travels to coal crusher tower #1 where, the coal can be crushed and 

directed to the Unit 1 silos or to coal crusher tower #2 where it can be conveyed to the silos for 

Units 2, 3, or 4. The coal collected below the grizzly at the new track feeders is loaded to a coal 

conveying belt which travels to coal crusher tower #2. The crusher tower reduces the size of the 

coal before transporting the coal to Unit 1 (via crusher tower #1) or to the transfer tower #2 

which sends it to the main pile or sends the coal to Units 2, 3, and 4 via the transition tower. 

Reclaim off of the bottom of the main pile goes to transfer tower #2 (via crusher tower #2) and 

is transported to Units 1-4. The crusher/transfer towers coal conveyor belts feed the top of coal 

silos of each steam boiler unit silos. All unit silos feed coal gravitationally to feeders which 

supply each pulverizer where the coal is ground to the consistency of talcum-powder before 

firing in the furnace. Emergency diesel generators are located at Units 2, 3, and 4 for purposes 

of safely shutting a Unit down in a loss of off-site power situation. 

All four units at the Cholla generating station combust bituminous/sub-bituminous coal to heat 

high purity water to create super-heated steam which is used as the thermodynamic medium that 

drives the turbines/generators to produce electricity. Unit 1 uses natural gas as the warm-up/ 

stabilization fuel and Units 2, 3 and 4 use diesel fuel #2. All warm-up/ stabilization fuels are 

fired less than one percent of total unit operating time. Historical operating data indicate this to 

be approximately 0.7 percent of total heat input on Unit 1 and approximately 0.3 percent on 
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APS-Cholla Permit No. 53399 

Units 2, 3 and 4. Condenser cooling for Units 1 and 2 are provided by Cholla Reservoir, while 

Unit 3 and 4 have mechanical draft cooling towers with Unit 3 receiving make-up water from 

the reservoir and Unit 4 mainly from the well field and from the reservoir as an alternate source. 

Unit 4 has a used oil burning system which injects on-spec used oil and/or used oil fuel into the 

furnace for energy recovery purposes, and is co-fired with coal and performed on a periodic 

basis. The total heat input from this activity is typically less than 0.1 percent of total heat input 

to Unit 4 on an annual basis. Diesel fuel is used in the emergency generators located at Units 2 

through 4. 

B. Coal Supply 

The four Units at the Cholla generating station typically burn 3.5 to 4.0 million tons of coal 

annually or about 70% of the total potential burn rate of approximately 5.6 million tons. 

 Table 2 presents the typical characteristics of the coal. 

 Table-2: Coal Characteristics 

Coal Data Lee Ranch/ 

El Segundo 

Sulfur 1.01% 

Btu/lb 9,154 

SO2 in coal (lb/MMBtu) 2.21 

Ash 17.30% 

Moisture 15.50% 

C. Air Pollution Control Equipment 

 Cholla generating station currently utilizes fabric filters at Units 1, 3 and 4, and a mechanical 

dust collector and Venturi flooded disc scrubbers Unit 2 for control of particulate matter 

emissions. Cholla has proposed to replace the mechanical dust collector with a fabric filter on 

Unit 2. For sulfur dioxide emissions removal, Unit 1 utilizes a tray tower absorber with lime 

reagent. Unit 2 utilizes Venturi flooded disc scrubbers/absorbers with lime reagent. Units 3 

and 4 use sulfur dioxide spray tower absorbers with lime reagent for the control of SO2. APS 

has proposed to replace the scrubber on Unit 2 with a new flue-gas desulfurization unit. All 

four units are retrofitted with low-NOx burners and over-fire air system to control NOx

emissions. 

 Table 3: Current Air Pollution Controls 

Equipment PM SOx NOx

Unit 1 Baghouse 2 tray tower absorbers with 

lime reagent; 90% SO2

removal 

Low NOx burners 

Primary - Mechanical 

dust collector, estimated 

70% efficiency 

Unit 2 

Secondary - Venturi 

flooded disc scrubber, 

Four-module venturi 

flooded-disc scrubbers/ 

absorber with Lime 

reagent; 90% SO2 removal 

Low NOx burners 
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APS-Cholla Permit No. 53399 

Equipment PM SOx NOx

98% particulate removal 

Proposed Installation – 

Fabric Filter 

Unit 3 Baghouse SO2 Spray Tower Absorber Low NOx burners 

Unit 4 Baghouse SO2 Spray Tower Absorber Low NOx burners 

Fly ash Silo Baghouse N/A N/A 

Lime Silo Baghouse N/A N/A 

Lime Slaker 

Vent 

Wet scrubber N/A N/A 

Coal Handling 

Facility 

Baghouse or wetting 

systems with chemical 

suppressant 

N/A N/A 

IV. EMISSIONS 

As described in Section I, the Cholla operation burns fossil fuel to produce electricity. The fossil fuel 

combustion results in emissions of a number of criteria air pollutants which mainly include particulate 

matter (PM)/particulate matter with an aerodynamic diameter less than or equal to a nominal 10 

micrometers (PM10), sulfur dioxide (SO2), nitrogen oxides (NOx), carbon monoxide (CO), and volatile 

organic compound (VOC). Table 4 summarizes potential to emit (PTE) of criteria air pollutants and 

hazardous air pollutants. For detailed emissions calculations refer to the permit application. 

Table 4: Potential To Emit Summary 

Pollutant PTE (tons per year) PTE after Unit 2 SO2 Control 

upgrade (tons per year) 

PM2.5 666.4 666.4 

PM/PM10 2,507 2507 

SO2 7,817 6659 

NOx 9,770 9770 

VOCs 2 2 

CO 1,262 1262 

HAPs 35 35 

GHG 58279550 58279550 

Proposed Unit 2 Upgrades – APS Cholla has proposed to upgrade the Unit 2 SO2 controls with a new 

FGD. The upgrades will reduce the facility wide PTE as noted in the above table. The upgrades will 

not result any increases in GHG gases and hence does not trigger PSD applicability. 

V. APPLICBLE REQUIREMENTS

APS-Cholla has identified all applicable regulations that apply to its facility in Attachment A of the 

permit application. The permit is a renewal of the Title V Permit No. 33500 and incorporates all 

regulations that were determined applicable in that permit. 
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APS-Cholla Permit No. 53399 

NSPS Applicability – All 4 units at the Cholla Generating Station were built after August 17, 1971 and 

before September 18, 1978, and therefore all 4 units are subject to the New Source Performance 

Standards (NSPS) Subpart D requirements. However, in the early 1980s, APS modified the SO2 control 

equipment on Unit 2 without a proper permit modification. As a result, ADEQ and APS Cholla entered 

into a consent order that subject Unit 2 to the SO2 limits and monitoring requirements of Subpart Da. 

Therefore, Unit 2 is subject to Subpart Da for SO2 only and Subpart D for the other pollutants. 

Unit 2 Pollution Control Equipment Operation – When APS Cholla made modifications to their control 

equipment, EPA also negotiated a Consent Decree (CD) on September 5, 1991, where APS Cholla was 

required to obtain a permit for the changes. In the CD, EPA established operational practices for the 

control equipment associated with Unit 2. The CD specified APS Cholla to place the Venturi scrubbers 

and absorbers in service within one hour of the boiler-induced draft fans and forced draft fans were 

placed in service and before fires were ignited in the boiler. And the venturi scrubbers and absorbers to 

remain in service after the fired in the boiler were put off and not take the boiler out of service until just 

before the draft fans and induced draft fans were turned off. These definitions are being carried forward 

from the previous permit. 

Part 68 Applicability – APS Cholla does not store any listed chemicals on-site in any process in excess 

of threshold amounts to trigger the requirements of Part 68 - Chemical Accidental Prevention Programs. 

Electric Steam Generating Utility (EGU) MACT – EPA finalized the EGU MACT on April 16, 2012. 

This renewal permit will be reopened to incorporate the new requirements. 

 

VI. PREVIOUS PERMIT AND PERMIT REVISIONS 

A. PREVIOUS PERMITS 

 Table 5: PREVIOUS PERMITS 

Permit No. Issue Date Application Basis 

33500 May 3, 2006 Class I Operating Permit 

41787 April 6, 2007 Class I Significant Permit Revision 

46353 April 11, 2008 Class I Significant Permit Revision 

50379 July 14, 2010 Class I Significant Permit Revision 

49962 October 14, 2010 Class I Significant Permit Revision 

B. PERMIT REVISIONS 

1. In April 2007, APS was issued Significant Permit Revision No. 41787 to implement 

voluntary emissions reduction projects at Cholla, including retrofitting all four boilers 

with low NOx burners (LNBs) and over-fire air systems. 

2. Significant Permit Revision No. 46353 issued on April 11, 2008, included physical 

changes to APS Cholla's coal preparation plant for optimization of the coal handling 

operations. 
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APS-Cholla Permit No. 53399 

3. Significant Permit Revision No. 50379 issued on July 14, 2010, incorporated the 

company’s early mercury control strategy, as required by the Consent Order (Docket 

#A-19-09) entered between the Arizona Department of Environmental Quality (ADEQ) 

and APS-Cholla Generating Station on February 18, 2009. Additionally, this permit 

revision streamlined the compliance assurance monitoring (CAM) requirements for 

particulate matter for Units 1, 3 and 4. 

4. Significant Permit Revision No. 49962 issued on October 14, 2010, removed bubbled 

emission limits for Unit 2 and Unit 3, and provided separate emission limitations for 

these units. In addition, the pounds per hour limits for CO during periods of startup, 

shutdown and malfunction were incorporated. The permit revision also consolidated 

and streamlined all the requirements in Permit #33500, and subsequent revision #s 

41787, 46353 and 50379. 

C. CHANGES TO PREVIOUS PERMIT CONDITIONS

 

Table 6: Previous Permit Conditions 

Condition # in Determination Comments

permit no. 

33500

Deleted Kept Revised Streamlined

Attachment “A” x Added applicability of NSPS and NESHAP for 

internal combustion engines 

Attachment “B” 

Condition I & II x 

Section III.B x Added requirement to replace mechanical dust 

collectors with fabric filters and lime slurry 

Flue Gas Desulfurization on Unit 2. 

Section III.C. x Clarified requirement for COMS at fabric filter 

outlet. 

Section IV through 

XIV 

x 

Section XV x Added applicability of mercury reduction 

requirements to Unit 2 upon installation of the 

fabric filter. 

Added use of mercury sorbent trap as an option 

to show compliance with mercury emissions 

reduction. 

Attachment "C" x The equipment list is updated to reflect all the 

changes in Permit Revision No. 46353, and 

removal of redundant equipment. 

Attachment "D" x This Section for acid rain provisions is revised 

to reflect current SO2 allowance allocations and 

NOx emission limitations on all boilers. 
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APS-Cholla Permit No. 53399 

VII. PERIODIC MONITORING REQUIREMENTS 

A. Steam Unit 1

Opacity: Unit 1 is subject to 20% opacity limit in accordance with A.A.C. R18-2-702.B.3. 

Cholla is required under A.A.C. R18-2-313.C.1.a to maintain and operate a continuous 

monitoring system for opacity. The monitoring system is required to meet the 

requirements of A.A.C. R18-2-313.D.1, which references to 40 CFR 60.13 and 40 CFR 

60, Appendix B, Performance Specification 1. 

SO2: The unit is subject to the sulfur dioxide standard of 1.0 lb/MMBtu heat input under 

A.A.C. R18-2-703.G.1 while burning coal. Cholla is required under A.A.C. R18-2-

313.C.1.b to maintain and operate a continuous monitoring system (CEMS) for sulfur 

dioxide. The monitoring system is required to meet the requirements of 40 CFR 60.13 

and 40 CFR 75, Appendix A through C. The source is also required to meet 80% SO2

removal efficiency through the use of the control device. SO2 concentrations at inlet 

and outlet of the control device are monitored by CEMS to determine compliance with 

the SO2 removal efficiency. 

NOx: There is no standard for NOx emissions from Unit 1 as it was built before May 30, 

1972. NOx monitoring is not required, except for 40 CFR 76 NOx standards which 

requires compliance CEMS. The unit is fitted with low-NOx burners and over-fire air 

systems to reduce emissions of NOx. 

PM: The unit is subject to the particulate matter emissions standard set forth in A.A.C. R18-

2-703.C.1. The unit also has potential pre-control device PM emissions that are greater 

than 100 tons per year, the major source threshold, and pursuant to 40 CFR 64.2(a), the 

compliance assurance monitoring (CAM) is required. In conjunction with the low-NOx 

burners and the baghouse, Cholla shall follow the monitoring approach presented in 

Table 7. 

B. Steam Unit 2 

Opacity: Unit 2 is subject to an opacity standard of < 20% except for one six-minute period per 

hour of not more than 27% opacity. Cholla is required under 40 CFR 60.45(a) to 

maintain and operate a continuous monitoring system for opacity. The monitoring system 

is required to meet the requirements of 40 CFR 60.13 and 40 CFR 60, Appendix B, 

Performance Specification 1. 

SO2: The unit is subject to the sulfur dioxide standard of 0.8 lb/MMBtu heat input and 90% 

removal efficiency. Cholla is required to maintain and operate a SO2 continuous 

monitoring system consistent with Subpart Da requirements at inlet and outlet of the 

sulfur dioxide control device that will be utilized to determine compliance with the sulfur 

dioxide emission and removal efficiency limit. The SO2 CEMS is required to meet the 

requirements of 40 CFR 60.13, 40 CFR 60, Appendix F, and 40 CFR 75, Appendix A 

through C. 

NOx: The unit is subject to the NOx standard of 0.70 lb/MMBtu heat input in 40 CFR 

60.44(a)(3) while burning coal. Cholla is required under 40 CFR 60.45(a) to maintain 

and operate a continuous monitoring system for NOx. The monitoring system is required 

to meet the requirements of 40 CFR 60.13 and 40 CFR 75, Appendix A through C. The 

unit is fitted with low-NOx burners and over-fire air systems to reduce emissions of NOx. 

PM: The unit is subject to the particulate matter emissions standard of 0.10 lb/MMBtu set forth 

in 40 CFR 60.42(a)(1). The unit also has potential pre-control device PM emissions that 

are greater than 100 tons per year, the major source threshold, and pursuant to 40 CFR 

64.2(a), CAM is required. The flooded disc pressure drop (Δp) and slurry flow are 
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APS-Cholla Permit No. 53399 

selected to be primary performance indicator of the Unit 2 Venturi scrubbers. Using Δp 

and slurry flow data, Cholla is to calculate block 1-hour average excluding periods of 

boiler startup and shutdown. If at any point, excluding periods of startup and shutdown, 

the block 1-hour average Δp is less than 15 inches of water column or the block 1-hour 

average slurry flow is equal to or less than 4,000 gallons per minute per pump, then an 

excursion has occurred and Cholla needs to (1) record and report the excursion and (2) 

record the operational status of Unit 2 boiler (i.e. load change increase or decrease). 

 APS Cholla has proposed to replace the existing controls with a fabric filter equipment to 

control PM emissions. The CAM indicators applicable to Unit 1,3 &4 will apply to Unit 2 

as well. 

C. Steam Unit 3 

Opacity:Unit 3 is subject to an opacity standard of < 20% except for one six-minute period per 

hour of not more than 27% opacity. Cholla is required under 40 CFR 60.45(a) to maintain 

and operate a continuous monitoring system for opacity. The monitoring system is 

required to meet the requirements of 40 CFR 60.13 and 40 CFR 60, Appendix B, 

Performance Specification 1. 

SO2: Unit 3 is subject to an SO2 emissions limit of 0.8 lbs/MMBtu. Cholla is required to 

maintain and operate a SO2 continuous monitoring system consistent with Subpart Da 

requirements at inlet and outlet of the sulfur dioxide control device that will be utilized to 

determine compliance with the sulfur dioxide emission and removal efficiency limit. The 

SO2 CEMS is required to meet the requirements of 40 CFR 60.13, 40 CFR 60, Appendix 

F, and 40 CFR 75, Appendix A through C. 

NOx: The unit is subject to the NOx standard of 0.70 lb/MMBtu heat input in 40 CFR 60.44(a)(3) 

while burning coal. Although Cholla is exempted from installation of a continuous NOx

monitoring system under 40 CFR 60.45(b)(3), periodic monitoring for NOx emissions is 

required under A.A.C. R18-2-306.A.3.c. The Acid Rain Program NOx CEMS will be used 

to meet the periodic monitoring requirement. For QA/QC purpose, the monitoring system 

is required to meet the requirements of 40 CFR 60.13 and 40 CFR 75, Appendix A through 

C. The unit is fitted with low-NOx burners and over-fire air systems to reduce emissions of 

NOx. 

PM: The unit is subject to a standard of 0.10 lb/MMBtu set forth in 40 CFR 60.42(a)(1). The 

unit also has potential pre-control device PM emissions that are greater than 100 tons per 

year, the major source threshold, and pursuant to 40 CFR 64.2(a), CAM is required. Using 

COMS data, Cholla is to calculate block 1-hour average opacities excluding periods of 

boiler startup, shutdown, and malfunction. If at any point, excluding periods of boiler 

startup, shutdown, and malfunction, the opacity average exceeds 8%, then Cholla will 

initiate mandatory investigation within 30 minutes, including inspection of the clean side 

of each in-service baghouse compartment for signs of dusting. Records pf investigation 

and corrective action taken are required to be maintained. 

D. Steam Unit 4 

Opacity: Unit 4 is subject to an opacity standard of < 20% except for one six-minute period per 

hour of not more than 27% opacity. Cholla is required under 40 CFR 60.45(a) to maintain 

and operate a continuous monitoring system for opacity. The monitoring system is required 

to meet the requirements of 40 CFR 60.13 and 40 CFR 60, Appendix B, Performance 

Specification 1. 

SO2: The unit is subject to the sulfur dioxide standard of 0.8 lb/MMBtu heat input in A.A.C. 

R18-2-903.1 while burning coal. Cholla is required under 40 CFR 60.45(a) to maintain and 
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APS-Cholla Permit No. 53399 

operate a continuous monitoring system for sulfur dioxide emissions. The monitoring 

system is required to meet the requirements of 40 CFR 60.13 and 40 CFR 75, Appendix A 

through C. 

NOx: The unit is subject to the NOx standard of 0.70 lb/MMBtu heat input in 40 CFR 60.44(a)(3) 

while burning coal. Although Cholla is exempted from installation of a continuous NOx 

monitoring system under 40 CFR 60.45(b)(3), periodic monitoring for NOx emissions is 

required under A.A.C. R18-2-306.A.3.c. The Acid Rain Program NOx CEMS will be used 

to meet the periodic monitoring requirement. For QA/QC purpose, the monitoring system 

is required to meet the requirements of 40 CFR 60.13 and 40 CFR 75, Appendix A through 

C. The unit is fitted with low-NOx burners and over-fire air systems to reduce emissions of 

NOx. 

PM: Unit 4 is subject to a standard of 0.10 lb/MMBtu set forth in 40 CFR 60.42(a)(1). The unit 

also has potential pre-control device PM emissions that are greater than 100 tons per year, 

the major source threshold, and pursuant to 40 CFR 64.2(a), the compliance assurance 

monitoring (CAM) is required. Using COMS data, Cholla is to calculate block 1-hour 

average opacities excluding periods of boiler startup, shutdown, and malfunction. If at any 

point, excluding periods of boiler startup, shutdown, and malfunction, the opacity average 

exceeds 8%, then Cholla will initiate mandatory investigation within 30 minutes, including 

inspection of the clean side of each in-service baghouse compartment for signs of dusting. 

Records pf investigation and corrective action taken are required to be maintained. 

 Cholla is required to follow the monitoring approach presented in Table 7. 

E. Other Point, Non-Point and/or Fugitive PM Emission Sources 

Pursuant to A.A.C. R18-2-306.A.3.c, Cholla is required to conduct periodic monitoring at those 

other particulate matter emission sources for which the applicable requirement does not require 

periodic testing or instrumental or non-instrumental monitoring. These include all point, non-point 

and/or fugitive PM emission sources at the cooling towers 3 and 4, coal preparation plant, fly ash 

handling facility, lime handling and slaking facility, fugitive dust sources, and internal combustion 

engines. The periodic monitoring is carried out through a visual observation plan that identifies a 

central lookout station or multiple observation points as follows: 

Point #1: Personnel overpass located at coal handling (North East area of plant) 

Sources observed include coal unloading, coal crushers, coal stacking, coal reclaiming, 

Unit 1 coal handling/silo baghouse exhaust, coal transfer tower #1, all coal drop points 

from coal unloading to Unit 1 silos, to transition tower, and to coal stacker, Unit 1 

flyash handling system, flyash silo baghouse exhaust, lime silo baghouse exhaust, lime 

slaking wet scrubber exhaust, coal storage pile, main entrance roadway and main 

south/north plant road. 

Point #2: North of Unit 3 weld shop and south of Unit 2/3 diesel generators 

Sources observed include Unit 2/3 diesel generators, Unit 2 and 3 flyash handling. 

Point #3: South east corner of Unit 4 auxiliary bay 

Sources observed include Unit 2, 3, and 4 coal handling system baghouse exhausts, 

Unit 4 diesel generator, Unit 4 Eastern flyash handling, main East/West plant roadway. 

Point #4: South West corner of Unit 4 Auxiliary Bay 

Sources observed include Unit 3 and 4 cooling tower, laydown areas, Unit 4 Western 

flyash handling. 
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APS-Cholla Permit No. 53399 

The plan requires Cholla to make a weekly survey of the visible emissions at the above described 

vintage points. If there are no visible emissions, then Cholla is required to record the date, time, 

and results of the survey. If Cholla finds that on an instantaneous basis the visible emissions are in 

excess of the applicable opacity limit, then a six-minute Method 9 observation is required to be 

made. If this observation indicates opacity in excess of the applicable opacity limit, then Cholla is 

required to report it as excess emissions. If Cholla finds that the visible emissions are less than the 

applicable opacity limit, then Cholla is required to record the source of emission, date, time, and 

result of the observation. 

F. Internal Combustion Engines 

 APS Cholla operates 3 diesel-fired emergency engines of capacity over 500hp and manufactured in 

the 1970s. The NSPS requirements are applicable to those engines manufactured after 2006. 

NESHAP requirements exempt existing emergency engines over 500 hp at a major source of 

HAPs. Hence only the Arizona Administrative Code (AAC) requirements, R18-2-719 are 

applicable. The engines are limited to 40% opacity requirement and sulfur content of less than 

0.9% by weight. APS-Cholla is required to conduct weekly visible emissions observation when 

the engine is operating. 

VIII. MERCURY REQUIREMENTS 

A. Background

On February 18, 2009, ADEQ and APS entered into a Consent Order (Docket A-19-09) which 

required APS to implement an interim mercury control strategy without interfering with APS’s 

ability to comply with the State Mercury Standard beginning on December 31, 2016, and the 

eventual Maximum Achievable Control Technology (MACT) standard that will address 

mercury emissions from Existing Utility Steam Generating Units. The plan provided for the 

voluntary implementation of an early mercury control strategy expected to achieve total 

mercury emissions reductions that over time will be substantially similar to the emissions 

reductions that would be realized by complying with the State Mercury Standard. The 

alternative plan called for one of the two options in Section II.A.17 of the consent order. As 

these alternative strategies provide for the early implementation of a control strategy, they 

would be designed to result in total reductions in mercury emissions over the period January 1, 

2011 through December 31, 2015, that are substantially similar to the reductions that would 

result from enforcement of the State Mercury Standard. 

B. Control of Mercury Emissions 

Units 1, 3 and 4 are equipped with fabric filter bag houses and wet absorbers, and Unit 2 is 

equipped with mechanical dust collector, venturi scrubbers and absorbers. Operation of fabric 

filter baghouses and absorbers provide significant mercury removal. Native mercury removal is 

a function of fly ash build up on the surface of fabric filter bag and gas flow rate. Also, mercury 

in oxidized state is highly water soluble, and is captured in wet flue gas desulfurization (FGD) 

systems. The sample testing for mercury indicated 89% mercury removal in Units 1, 3 and 4, 

and 30% removal in Unit 2. The facility-wide mercury removal, with assumed 0% removal 

from Unit 2, is expected to be significantly above the 50% target reduction level identified in 

the Consent Order. 

IX. COMPLIANCE ASSURANCE MONITORING (CAM) REQUIREMENTS 

 The CAM requirements for Unit 1, 3, and 4 are listed in Table 7. The CAM requirements for Unit 2 

will apply upon the installation of the fabric filter. 
Table 7: CAM Plan for Fabric Filter Baghouse 

Performance indicator 

Stack opacity at each of Steam Boiler Units 1, 2, 3 and 4 stacks 

Induction draft (ID) fan suction pressure at each of Steam Boiler Units 1, 3,and 4, and at Unit 2 upon installation of fabric filter. 

Individual baghousdifferential pressur

Measurement Approach 

Opacity values from the Continuous Opacity Monitor (COM) at each boiler unit are monitored. 

This is a direct indication of the condition of the baghouse filters for each boiler unit. 

Each baghouse commagnahelic differencontinuously measuacross the compartm

General Criteria Indicator range(s) and excursion 

definition 

An excursion is defined as block 1-hour opacity average that exceeds 8%, excluding periods of boiler startup, shutdown, and malfunction. An excursion requires investigation of the compartment pressure differential values for decreases in differential pressure. Repairs or adjustments are made as necessary. A log of the corrective action(s) will be maintained. 

An excursion is defined as an ID fan suction pressure reading that exceeds a unit specific pressure level in inches water column or a sudden drop of more than 1.0 inch in the ID fan suction pressure, excluding periods of boiler startup, shutdown, and malfunction. 

An excursion is defof more than 1⁄2 inch or cleaning mode pboiler startup, shutdInvestigation is init

Data representativeness 

An increase in visible emissions (opacity) under steady-state operating conditions is an indirect indication of an increase in particulate matter emissions. 

A high pressure indicates bags may be clogged and particulate matter may be being forced through the bag fabric. A sudden decrease in fan suction pressure indicates a possible bag break or seal loss. Particulate removal rates should remain consistent until a problem is detected. 

From the standpoinonly a reading indicintegrity shows a rethe baghouse. Readclogged may not inbaghouse particulat

the need for investi

Verification of monitoring status 

Effective upon commissioning of service of a fabric filter control device at each affected boiler unit. 

Effective upon commissioning of service of a fabric filter control device at each affected boiler unit. 

Effective upon comfilter control device 

QA/QC practices The COM equipment and data quality assurance is in conformance with 40 CFR Part 60 Appendix B & F. Annual calibration of ID fan suction pressure gauges. 

Annual calibration 

Operators check mashift. The most fresensing lines which 

Monitoring frequency Continuous recording of opacity. Continuous, with hourly recording of pressure values. Cell magnahelic vaData collection procedures 

The opacity monitor continuously records the average for each one (1) minute interval. 

Operator records readings on the log sheet hourly. 

Magnahelic readingOnce per week the reverse air cleaningon each cell, and nomanagement reviewneed to be addressebe added to the nex

Performance Criteria 

Averaging period Block one hour. N/A N/A 

Technical Support Document Page 11 of 15 Permit Issued: May 31, 2012 

APS-Cholla – Permit l#53399 
X. TESTING REQUIREMENTS 

Cholla is required to conduct annual performance tests for stack emissions of opacity, particulate 

matter, sulfur dioxide, and nitrogen oxides from all steam boiler units to demonstrate, on an 

annual basis, compliance with the respective emissions standards, except for nitrogen oxides 

emissions from unit 1 stack where there is no applicable standard for NOx emissions. 

Compliance with opacity standards is determined using EPA Reference Method 9. Performance 

tests for all pollutants are conducted using the procedures and methods contained in the Arizona 

Testing Manual or 40 CFR 60, Appendices A through F. 

XI. USED OIL OR USED OIL FUEL BURNING 

Unit 4 also co-fires with coal a small quantity of on-site generated used oil and/or used oil fuel for 

energy recovery purposes. Total heat input from this activity is typically less than 0.1 percent of 

total heat input to Unit 4 on an annual basis. The oil burned is required to be on specification as 

follows. To assure the standard to be met, Cholla is required to run sample testing semiannually 

for the used oil prior to burning. The flash point of the oil may not fall below 100 oF and the oil 

may not have following constituents in excess of the following allowable levels: 

Arsenic 5 ppm 

Cadmium 2 ppm 

Chromium 10 ppm 

Lead 100 ppm 

PCBs 2 ppm 

Total Halogens 1000 ppm 

XII. INSIGNIFICANT ACTIVITIES 

 Following is a list of insignificant activities identified by APS Cholla: 

No. Insignificant Activities Pollutants Verification Comments 

1 Scale Inhibitor Storage Tank HEDP yes A.A.C. R18-2-101.54.j 

2 Scale Inhibitor Storage Tank HEDP,ZN&PHOSPHONATE yes A.A.C. R18-2-101.54.j 

3 Condensate Storage Tanks PM-10 yes A.A.C. R18-2-101.54.j 

4 Aux. Cooling System Clam Treatment CLAM-TROL CT-1 yes A.A.C. R18-2-101.54.j 

5 Chemical Day Tanks (3 Tanks/unit) NH3, PO4, N2H4 yes A.A.C. R18-2-101.54.j 

6 Lake Intake Clam Treatment CLAM-TROL CT-1 yes A.A.C. R18-2-101.54.j 

7 Stack Gas Analyzers+ Gas Cylinders SO2,NO,FLUE GAS yes A.A.C. R18-2-101.54.i 

8 Potable Water Head Tanks CHLORINE yes A.A.C. R18-2-101.54.j 

9 Service Water Tanks CONTAINS WELL WATER yes A.A.C. R18-2-101.54.j 

10 De-aerator Tanks TRACE BOILER CHEMICALS yes A.A.C. R18-2-101.54.j 

11 Turbine Lube Oil Tanks OIL VAPORS (VOC'S) yes A.A.C. R18-2-101.54.j 

12 Turbine Lube Oil Vapor Extractors OIL VAPORS (VOC'S) no A.A.C. R18-2-730.G 

13 Generator Seal Oil Vapor Extractors OIL VAPORS (VOC'S) no A.A.C. R18-2-730.G 

14 Equip. Lube Oil Storage Tanks OIL VAPORS (VOC'S) yes A.A.C. R18-2-101.54.c 

15 Sedi. Pond Transfer Pump Vents VOC'S yes A.A.C. R18-2-101.54.j 

16 Sludge Tanks(1) PM-10 yes A.A.C. R18-2-101.54.j 

17 Demister Water Tank PM-10 yes A.A.C. R18-2-101.54.j 

18 Diesel Fuel Storage Tank (Small) FUEL OIL (VOC'S) yes A.A.C. R18-2-101.54.j 

19 Fuel Oil Storage Tank (Large) FUEL OIL (VOC'S) yes A.A.C. R18-2-101.54.j 

20 Gasoline, Diesel Storage Tank(ast) GAS, DIESEL (VOC'S) yes A.A.C. R18-2-101.54.b, c 

21 Acid and Caustic Tanks (Empty) H2SO4, NAOH yes A.A.C. R18-2-101.54.j 

22 Acid Tank H2SO4 no A.A.C. R18-2-730.G 

23 Glycol Storage Tank GLYCOL yes A.A.C. R18-2-101.54.j 

24 Glycol Expansion Tank(2) GLYCOL yes A.A.C. R18-2-101.54.j 

25 Process Water Tank PM-10 yes A.A.C. R18-2-101.54.j 

Technical Support Document Page 12 of 15 Permit Issued: May 31, 2012 

APS-Cholla – Permit l#53399 
No. Insignificant Activities Pollutants Verification Comments 

26 Boiler Feed Pump Seal Water Tank PM-10 yes A.A.C. R18-2-101.54.j 

27 Vacuum Pumps PM-10 yes A.A.C. R18-2-101.54.j 

28 Air Ejectors PM-10 yes A.A.C. R18-2-101.54.j 

29 Absorber Feed Pumps Bearings LUBE OIL VAPORS(VOC'S) yes A.A.C. R18-2-101.54.j 

30 Scrubber Feed Pumps LUBE OIL VAPORS(VOC'S) yes A.A.C. R18-2-101.54.j 

31 Fire Water Diesel Pumps(2) DIESEL FUMES(VOC'S) yes A.A.C. R18-2-101.54.j 

32 Fire Water Tanks (2) WATER yes A.A.C. R18-2-101.54.j 

33 Fly Ash Blowers Oil Reservoirs LUBE OIL VAPORS(VOC'S) yes A.A.C. R18-2-101.54.j 

35 Locomotives(2) DIESEL FUEL VAPORS (VOC'S) no A.A.C. R18-2-802 

36 Street Cleaner PM-10, VOC'S no A.A.C. R18-2-802 

37 Road Grader from Childs/Irving Plant PM-10, VOC'S no A.A.C. R18-2-802 

38 Boiler Blowdowns BOILER CHEMICALS yes A.A.C. R18-2-101.54.j 

39 Gland Steam Condenser Exhausters STEAM yes A.A.C. R18-2-101.54.j 

40 Coal Silo Vent Exhaust Fan COAL DUST(PM-10) no A.A.C. R18-2-716.B.1 

41 Reagent Feed Tanks Pumps(4) VOC'S yes A.A.C. R18-2-101.54.j 

42 Reagent Storage Tank Pumps (2) VOC'S yes A.A.C. R18-2-101.54.j 

43 Elemental Sulfur Tank PM-10 yes A.A.C. R18-2-101.54.j 

44 Elemental Sulfur Tank Pump VOC'S yes A.A.C. R18-2-101.54.j 

45 Bottom Ash Trans., Makeup Tank PM-10,VOC'S yes A.A.C. R18-2-101.54.j 

46 Pyrite Transfer Tank PM-10 yes A.A.C. R18-2-101.54.j 

47 EHC Reservoir EHC FLUID VAPORS(VOC'S) yes A.A.C. R18-2-101.54.j 

48 Chlorine Gas Tanks CL2 GAS no 112(r) 

49 Lime Slaking Vent Wet Scrubber CAO(PM-10) no A.A.C. R18-2-730.A.1 

50 Cooling Towers PM-10,CL2,H2SO4,DEFOAM no A.A.C. R18-2-730.A.1 

51 Painting Hood PM-10, VOC'S no A.A.C. R18-2-730.F 

52 Bathroom Vents NON-METHANE HYDROCR. yes A.A.C. R18-2-101.54.j 

53 Aerosol Paints/brushes VOC'S no A.A.C. R18-2-730.F 

54 Woodworking PM-10 yes A.A.C. R18-2-101.54.j 

55 Maintenance Shop Activities PM-10, VOC'S yes A.A.C. R18-2-101.54.j 

56 Electric Water Heaters yes A.A.C. R18-2-101.54.j 

57 Electric Space Heaters yes A.A.C. R18-2-101.54.j 

58 Battery Charging Areas H2SO4 yes A.A.C. R18-2-101.54.j 

59 Breakers yes A.A.C. R18-2-101.54.j 

60 Lab Chemicals HOOD VENTS yes A.A.C. R18-2-101.54.i 

61 Kitchen Hoods VOC'S yes A.A.C. R18-2-101.54.j 

62 Charcoal Grills PM-10,VOC'S yes A.A.C. R18-2-101.54.j 

63 Welding Hood Exhaust PM-10 yes A.A.C. R18-2-101.54.j 

64 Mercury Recovery Hood HG yes A.A.C. R18-2-101.54.j 

65 Pulveriser Pyrite Chutes(5) PM-10 yes A.A.C. R18-2-101.54.j 

66 Insulation Shop Vent PM-10 yes A.A.C. R18-2-101.54.j 

67 Boiler Casing Leaks PM-10, SO2, NOX yes A.A.C. R18-2-101.54.j 

68 Bottom Ash Transfer Sump PM-10, BOILER CLEANING yes A.A.C. R18-2-101.54.j 

69 Coal Lab Vent PM-10 yes A.A.C. R18-2-101.54.i 

70 Misc. Steam Vents(6 -8) BOILER CHEMICALS yes A.A.C. R18-2-101.54.j 

71 Natural Gas Line Vents VOC'S yes A.A.C. R18-2-101.54.j 

72 Parts Cleaners EPA 2000 (VOC'S) yes A.A.C. R18-2-101.54.j 

73 Welding Rod Fumes PM-10 yes A.A.C. R18-2-101.54.j 

74 Acetylene Cylinders ACETYLENE no 112(r) 

75 Boiler Drains and Vents PM-10 yes A.A.C. R18-2-101.54.j 

76 Lake Intake Closed Sump VOC'S yes A.A.C. R18-2-101.54.j 

77 Lake Intake Trash Rakes VOC'S yes A.A.C. R18-2-101.54.j 

78 Paint Shop Hood PM-10, VOC'S no A.A.C. R18-2-730.F 

79 Locomotive Building Vent VOC'S yes A.A.C. R18-2-101.54.j 

80 Satellite Oil/haz Waste Areas VOC'S yes A.A.C. R18-2-101.54.j 

81 Lube Rack(s), Lube Building Vent VOC'S yes A.A.C. R18-2-101.54.j 

82 Oil Drip Racks VOC'S yes A.A.C. R18-2-101.54.j 

83 Portable Heaters, Propane Tanks VOC'S yes A.A.C. R18-2-101.54.j 

84 Track Straightener Machine VOC'S yes A.A.C. R18-2-101.54.j 

85 Coal Crusher Tower Lube System VOC'S yes A.A.C. R18-2-101.54.j 

86 Cooling Towers Fan Motors Vents-18 VOC'S yes A.A.C. R18-2-101.54.j 

Technical Support Document Page 13 of 15 Permit Issued: May 31, 2012 

APS-Cholla – Permit l#53399 
No. Insignificant Activities Pollutants Verification Comments 

87 Unit Condensate Pump Vents(2) VOC'S yes A.A.C. R18-2-101.54.j 

88 Electrical Hydraulic Control System 

Vent VOC'S yes A.A.C. R18-2-101.54.j 

89 Boiler Feed Pump(s) Oil Cooling 

Vents(2) VOC'S yes A.A.C. R18-2-101.54.j 

90 Instrument Air Compressor Vents VOC'S yes A.A.C. R18-2-101.54.i 

91 Station Air Compressors VOC'S yes A.A.C. R18-2-101.54.j 

92 Turbine Oil Cooling Vent(2) VOC'S yes A.A.C. R18-2-101.54.j 

93 Closed Cooling Water Tank Vent PM-10 yes A.A.C. R18-2-101.54.j 

94 ID/FD Fans Oil Cooling Vents VOC'S yes A.A.C. R18-2-101.54.j 

95 Air Preheater Vents VOC'S yes A.A.C. R18-2-101.54.j 

96 Air Preheater Guide Bearing Vents VOC'S yes A.A.C. R18-2-101.54.j 

97 O/W Separators (2) VOC'S yes A.A.C. R18-2-101.54.j 

98 Control Room Bathroom Vents NON-METHANE 

HYDROCARBONS yes A.A.C. R18-2-101.54.j 

99 Laboratory Hoods PM-10, VOC'S yes A.A.C. R18-2-101.54.j 

100 Bathroom Vents by Labs N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

101 Electric & Instrument Battery Charging H2SO4 yes A.A.C. R18-2-101.54.j 

102 Main Transformers(Plus the Two 

Following Items) VOC'S yes A.A.C. R18-2-101.54.j 

103 Stand -By/Auxiliary Transformers VOC'S yes A.A.C. R18-2-101.54.j 

104 Switchyard Transformers/gear VOC'S yes A.A.C. R18-2-101.54.j 

105 Sewage Treatment Plant (No 

incinerator) CL2, H2S, VOC'S yes A.A.C. R18-2-101.54.j 

106 PWS Hypochlorinators CL2 yes A.A.C. R18-2-101.54.j 

107 Rotary Blower Pump Vent VOC'S yes A.A.C. R18-2-101.54.j 

108 Degasifier Transfer Pump Vent(2) VOC'S yes A.A.C. R18-2-101.54.j 

109 Cooling Water Sump Pump Vents(2) VOC'S yes A.A.C. R18-2-101.54.j 

110 PWS Booster Pump Vent VOC'S yes A.A.C. R18-2-101.54.j 

111 Electro-dryer Pump Vent VOC'S yes A.A.C. R18-2-101.54.j 

112 Flammable Storage Cabinets VOC'S no 112(r) 

113 Glycol Feed Pumps Vents VOC'S yes A.A.C. R18-2-101.54.j 

114 Glycol Circ. Pumps Vents(2) VOC'S yes A.A.C. R18-2-101.54.j 

115 Clear Well Sump Pump VOC'S yes A.A.C. R18-2-101.54.j 

116 Seal Oil Pumps(3) VOC'S yes A.A.C. R18-2-101.54.j 

117 Turbine Lube Oil Pumps(3) VOC'S yes A.A.C. R18-2-101.54.j 

118 AC Equipment CFC'S /HCFC'S yes A.A.C. R18-2-101.54.j 

119 Misc. Lube Oil Vents VOC'S yes A.A.C. R18-2-101.54.j 

120 Feedwater Heater Shell Side Vents PM-10 yes A.A.C. R18-2-101.54.j 

121 Ash Sluice Vents (3) PM-10 yes A.A.C. R18-2-101.54.j 

122 Mech. Dust Collectors PM-10 no Permitted activity 

123 Filter Cleaning Bldg. PM-10 yes A.A.C. R18-2-101.54.j 

124 Scrubber Control Room Vent PM-10 yes A.A.C. R18-2-101.54.j 

125 Absorber Tank PM-10 (LIME) no A.A.C. R18-2-730.A.1 

126 Absorber Feed Pump (3) VOC'S yes A.A.C. R18-2-101.54.j 

127 Absorber Feed Pump(4), Scrubber Feed 

Pump(4) VOC'S yes A.A.C. R18-2-101.54.j 

128 Quencher Feed Pump(2) VOC'S yes A.A.C. R18-2-101.54.j 

129 Portable Welders PM-10 yes A.A.C. R18-2-101.54.j 

130 Absorber Area Sump Pump Vent (2) VOC'S yes A.A.C. R18-2-101.54.j 

131 Sludge Disposal Pumps (4) VOC'S yes A.A.C. R18-2-101.54.j 

132 Flyash Hopper Diffuser Blowers (2) VOC'S yes A.A.C. R18-2-101.54.j 

133 Warehouses (2) Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

134 WAREHOUSES (2) BLDG VENTS PM-10 yes A.A.C. R18-2-101.54.j 

135 Bechtel Construction Bldg. Br Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

136 Auto Shop Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

137 General Water Bldg. Vent PM-10, VOC'S yes A.A.C. R18-2-101.54.j 

138 Slurry Disposal Bldg. Vents PM-10, VOC'S yes A.A.C. R18-2-101.54.j 

139 Slurry Disposal Pumps Vents VOC'S yes A.A.C. R18-2-101.54.j 

140 Bottom Ash Disposal Vents VOC'S yes A.A.C. R18-2-101.54.j 

Technical Support Document Page 14 of 15 Permit Issued: May 31, 2012 

APS-Cholla – Permit l#53399 
Technical Support Document Page 15 of 15 Permit Issued: May 31, 2012 

APS-Cholla – Permit l#53399 

No. Insignificant Activities Pollutants Verification Comments 

141 Coal Handling Bldg. Vents N-M HYDROCARBONS, PM-10 yes A.A.C. R18-2-101.54.j 

142 Paint Shop Bldg. Vent PM-10, VOC'S no A.A.C. R18-2-730.F 

143 E&I Room Vents H2SO4 yes A.A.C. R18-2-101.54.j 

144 Machine Shop Vent PM-10,VOC'S yes A.A.C. R18-2-101.54.j 

145 Maintenance Bldg. Vents PM-10, VOC'S yes A.A.C. R18-2-101.54.j 

146 Maintenance Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

147 Planning Bldg. Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.i 

148 Admin. Bldg. (Old) Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

149 Admin. Bldg. (New) Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

150 Admin. Bldg (Old) Water Heater Vents yes A.A.C. R18-2-101.54.j 

151 Admin. Bldg (New) Water Heater 

Vents yes A.A.C. R18-2-101.54.j 

152 Nonroad generators/pumps VOC'S yes A.A.C. R18-2-101.54.j 

153 Stack Test Sampling Trailer SO2, NOX, PART. yes A.A.C. R18-2-101.54.i 

154 Guard Houses (2) N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

155 Security Building Bathroom Vents N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

156 Microwave Building Vent VOC'S yes A.A.C. R18-2-101.54.j 

157 Unit 1 Sedi Pump Vent VOC'S yes A.A.C. R18-2-101.54.j 

158 Unit 2,3, &4 Batch Oil Tank VOC'S yes A.A.C. R18-2-101.54.j 

159 Soot Blowing Air Compressors PM-10, VOC'S yes A.A.C. R18-2-101.54.j 

160 Building and Yard Maintenance Fac. PM-10,VOC'S yes A.A.C. R18-2-101.54.a 

161 500 Kv Control Building Vent N-M HYDROCARBONS yes A.A.C. R18-2-101.54.j 

162 Bulldozer Maintenance Shed VOC'S yes A.A.C. R18-2-101.54.j 

163 Cathodic Protection System CL2 yes A.A.C. R18-2-101.54.j 

164 Freon Recovery Equipment CFC's/HCFC'S no A.A.C. R18-2-602 (a) & 

(b) 

165 Accidental Releases VARIOUS no CAA 112(r) 

166 Spray Painting - Architectural Appl. PM-10,VOC'S no A.A.C. R18-2-727 

167 Sand Blasting PM-10 no A.A.C. R18-2-726

XIII. LIST OF ABBREVIATIONS

A.A.C.................................................................................................. Arizona Administrative Code 

AAAQGs ..........................................................................Arizona Ambient Air Quality Guidelines 

APS ............................................................................................................... Arizona Public Service 

ADEQ ......................................................................Arizona Department of Environmental Quality 

BACT........................................................................................ Best Available Control Technology 

CAM .......................................................................................... Compliance Assurance Monitoring 

CEMS............................................................................... Continuous Emission Monitoring System 

CO......................................................................................................................... Carbon Monoxide 

COMS ..................................................................................... Continuous Opacity Monitor System 

CFR...................................................................................................... Code of Federal Regulations 

GHG....................................................................................................................Green House Gases 

lb ..............................................................................................................................................Pound 

LNB ........................................................................................................................Low NOx Burner 

MMBtu............................................................................................... Million British Thermal Units 

NAAQS..............................................................................National Ambient Air Quality Standards 

NOx .......................................................................................................................... Nitrogen Oxide 

NSPS.........................................................................................New Source Performance Standards 

NESHAP...............................................National Emission Standards for Hazardous Air Pollutants 

PM..........................................................................................................................Particulate Matter 

PM10 ........................................................... Particulate Matter Nominally less than 10 Micrometers 

PM2.5 ......................................................... Particulate Matter Nominally less than 2.5 Micrometers 

PTE ......................................................................................................................... Potential to Emit 

PSD ......................................................................................Prevention of Significant Deterioration 

SO2 ............................................................................................................................. Sulfur Dioxide 

USEPA ................................................................. United States Environmental Protection Agency 

VOC.................................................................................................... Volatile Organic Compounds