### TECHNICAL SUPPORT DOCUMENT AIR QUALITY PERMIT NO. 53399 ARI ZONA PUBLIC SERVICE COMPANY-CHOLLA GENERATING STATION

I. INTRODUCTION

This Class I renewal permit issued to Arizona P ublic Service Company (APS) for continued operation of Cholla Generating Station located near Joseph City in Navajo County, Ariz ona. 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 consis t 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 analys is during their previous permit application after implementation of new control systems. The modeling results documented compliance with the National Ambient Air Quality Standa rds (NAAQS) for criteria pollutants and Arizona Ambient Air Quality Guidelines (AAAQG) for the hazardous air po llutants (HAPs). Since this modeling analysis, the facility has not made cha nges that resulted in in crease 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) Pa ge 1 of 15 Permit Issued: May 31, 2012 APS-Cholla Permit No. 53399

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

### The Cholla generating station consists of four co al-fired steam generating units, associated air pollution control devices and auxiliary equipment necessar y 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 rates 1 

### 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 rate s listed in the table are estimates and should not be used as operat ing 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 (Un its 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 a pplied 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 ne w 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 th e 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 to wer #2 where it can be co nveyed to the silos for Units 2, 3, or 4. The coal collected below the gr izzly at the new track feeders is loaded to a coal conveying belt which travels to coal crusher towe r #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 s ilos 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 stati on combust bituminous/sub-bituminous coal to heat high purity water to create super-heated steam wh ich is used as the thermodynamic medium that drives the turbines/generators to produce electric ity. 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 tim e. Historical operating data indicate this to be approximately 0.7 percent of total heat i nput on Unit 1 and approximately 0.3 percent on

### Technical Support Document (EPA review) Pa ge 3 of 15 Permit Issued: May 31, 2012 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 fiel d 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 bur n 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

SO 2 

### in coal (lb/MMBtu) 2.21

Ash 17.30%

Moisture 15.50%

C. Air Pollution Control Equipment Cholla generating station curren tly 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 m echanical 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 scrubb ers/absorbers with lime reagent. Units 3 and 4 use sulfur dioxide spray tower absorber s with lime reagent for the control of SO 2 

### . APS has proposed to replace the scrubber on Unit 2 with a new flue-gas desulfurization unit. All four units are retrofitted with low-NO x 

### burners and over-fire air system to control NO x 

### emissions.

Table 3: Current Air Pollution Controls

Equipment PM SO x 

### NO x 

### Unit 1 Baghouse 2 tray tower absorbers with lime reagent; 90% SO 2 

### removal Low NO x 

### 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% SO 2 

### removal Low NO x 

### burners

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### Equipment PM SO x 

### NO x 

### 98% particulate removal

Proposed Installation – Fabric Filter Unit 3 Baghouse SO2 Spray Tower Absorber Low NO x 

### burners

Unit 4 Baghouse SO2 Spray Tower Absorber Low NO x 

### 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 crite ria air pollutants which mainly include particulate matter (PM)/particulate matter with an aerodynamic diameter less than or equal to a nominal 10 micrometers (PM 10 

### ), sulfur dioxide (SO 2 

### ), nitrogen oxides (NO x 

### ), carbon monoxide (CO), and volatile organic compound (VOC). Table 4 summarizes poten tial 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 SO 2 

### Control upgrade (tons per year) PM 2.5 

### 666.4 666.4 PM/PM 10 

### 2,507 2507 SO 2 

### 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 SO 2 

### controls with a new FGD. The upgrades will reduce the facility wide P TE as noted in the above table. The upgrades will not result any increases in GHG gases and he nce 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.

### Technical Support Document (EPA review) Pa ge 5 of 15 Permit Issued: May 31, 2012 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 un its are subject to the New Source Performance Standards (NSPS) Subpart D requirements. Howe ver, in the early 1980s, APS modified the SO 2 

### control equipment on Unit 2 without a proper permit modificati on. As a result, ADEQ and APS Cholla entered into a consent order that subject Unit 2 to the SO 2 

### limits and monitoring requirements of Subpart Da. Therefore, Unit 2 is subject to Subpart Da for SO 2 

### only and Subpart D for the other pollutants.

Unit 2 Pollution Control Equipment Operation – When APS Cholla made m odifications 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 bo iler-induced draft fans and forced draft fans were placed in service and before fires were ignited in th e 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 Cho lla, 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.

### Technical Support Document (EPA review) Pa ge 6 of 15 Permit Issued: May 31, 2012 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 th e Arizona Department of Environmental Quality (ADEQ) and APS-Cholla Generating Sta tion on February 18, 2009. Additionally, this permit revision streamlined the compliance assura nce 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

Determination Comments Condition # in

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 SO 2 

### allowance allocations and NOx emission limitations on all boilers.

### Technical Support Document (EPA review) Pa ge 7 of 15 Permit Issued: May 31, 2012 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 monito ring system is required to meet the requirements of A.A.C. R18-2-313.D.1, wh ich references to 40 CFR 60.13 and 40 CFR 60, Appendix B, Performance Specification 1.

SO 2 

### : 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 continuo us 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 s ource is also required to meet 80% SO 2 

### removal efficiency through the use of the control device. SO 2 

### concentrations at inlet and outlet of the control device are monitore d by CEMS to determine compliance with the SO 2 

### removal efficiency.

NO x 

### : There is no standard for NO x 

### emissions from Unit 1 as it was built before May 30, 1972. NO x 

### monitoring is not required, except for 40 CFR 76 NO x 

### standards which requires compliance CEMS. The unit is fitted with low-NO x 

### burners and over-fire air systems to reduce emissions of NO x 

### . 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 re quired. In conjunction with the low-NOx burners and the baghouse, Cholla shall fo llow 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. Cho lla is required under 40 CFR 60.45(a) to maintain and operate a conti nuous 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.

SO 2 

### : The unit is subject to the sulfur dioxide standard of 0.8 lb/MMBtu heat input and 90% removal efficiency. Cholla is re quired to maintain and operate a SO 2 

### 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 SO 2 

### 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.

NO x 

### : The unit is subject to the NO x 

### 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 NO x 

### . 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-NO x 

### 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 majo r source threshold, and pursuant to 40 CFR 64.2(a), CAM is required. The flooded disc pressure drop ( Δ p) and slurry flow are

### Technical Support Document (EPA review) Pa ge 8 of 15 Permit Issued: May 31, 2012 APS-Cholla Permit No. 53399 

### selected to be primary performance indicator of the Unit 2 Venturi scrubbers. Using Δ p and slurry flow data, Cholla is to calcula te 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 Δ p 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 Cho lla needs to (1) record and report the excursion and (2) record the operational status of Unit 2 bo iler (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 appli cable 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 SO 2 

### emissions limit of 0.8 lbs/MMBtu. Cholla is required to maintain and operate a SO 2 

### 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 SO 2 

### CEMS is required to meet the requireme nts of 40 CFR 60.13, 40 CFR 60, Appendix F, and 40 CFR 75, Appendix A through C.

NO x 

### : The unit is subject to the NO x 

### standard of 0.70 lb/MMBtu heat input in 40 CFR 60.44(a)(3) while burning coal. Although Cholla is ex empted from installation of a continuous NO x 

### monitoring system under 40 CFR 60.45(b)(3), periodic monitoring for NO x 

### emissions is required under A.A.C. R18-2-306.A.3.c. The Acid Rain Program NO x 

### 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-NO x 

### burners and over-fire air systems to reduce emissions of NO x 

### . 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 opac ity average exceeds 8%, then Cholla will initiate mandatory investigation within 30 mi nutes, 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 fo r 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 sta ndard 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

### Technical Support Document (EPA review) Pa ge 9 of 15 Permit Issued: May 31, 2012 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 a nd 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 emissi ons 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 da ta, Cholla is to calculate block 1-hour average opacities excluding periods of boiler star tup, 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-servi ce baghouse compartment for signs of dusting. Records pf investigation and corrective ac tion taken are required to be maintained. Cholla is required to follow the m onitoring 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 whic h 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 pr eparation 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 multip le 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 tran sition 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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### 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, th en 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 si x-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 engi nes of capacity over 500hp and manufactured in the 1970s. The NSPS requirements are applicable to those engines manufactured after 2006. NESHAP requirements exempt existing emerge ncy engines over 500 hp at a major source of HAPs. Hence only the Arizona Administrativ e 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 c ontrol strategy without interfering with APS’s ability to comply with the State Mercury Sta ndard beginning on December 31, 2016, and the eventual Maximum Achievable Control Technology (MACT) standard that will address mercury emissions from Existing Utility Steam Ge nerating Units. The plan provided for the voluntary implementation of an early mercury c ontrol strategy expected to achieve total mercury emissions reductions that over time w ill 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 substant ially 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 f ilter 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 indicat ed 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 a bove 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 lis ted 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 BaghousePerformanceindicatorStack opacity at each of Steam Boiler Units 1, 2, 3 and4 stacksInduction draft (ID) fan suction pressure ateach of Steam Boiler Units 1, 3,and 4, and atUnit 2 upon installationof fabric filter.Individual baghouse compartment magnahelicdifferential pressure gage readingsMeasurementApproachOpacity values from the Continuous Opacity Monitor(COM) at each boiler unit are monitored.This is a direct indication of the condition ofthe baghouse filters for each boiler unit.Each baghouse compartment is equipped with amagnahelic differential pressure gauge thatcontinuously measures the differential air pressureacross the compartment.

General CriteriaIndicator range(s)and excursiondefinitionAn excursion is defined as block 1-hour opacityaverage that exceeds 8%, excluding periods of boilerstartup, shutdown, and malfunction. An excursionrequires investigation of the compartment pressuredifferential values for decreases in differentialpressure. Repairs or adjustments are made asnecessary. A log of the corrective action(s) will bemaintained.An excursion is defined as an ID fan suctionpressure reading that exceeds a unit specificpressure level in inches water column or asudden drop of more than 1.0 inch in the IDfan suction pressure, excluding periods ofboiler startup, shutdown, and malfunction.An excursion is defined as a differential pressure valueof more than 1⁄2 inch of water column above the restingor cleaning mode pressures, excluding periods ofboiler startup, shutdown, and malfunction.Investigation is initiated to locate the cause.DatarepresentativenessAn increase in visible emissions (opacity) understeady-state operating conditions is an indirectindication of an increase in particulate matteremissions.A high pressure indicates bags may beclogged and particulatematter may be beingforced through the bag fabric. A suddendecrease in fan suction pressure indicates apossible bag break or seal loss. Particulateremoval rates should remain consistent untila problem is detected.From the standpoint of particulate removal efficiency,only a reading indicating a loss of compartmentintegrity shows a reduction in the overall efficiency ofthe baghouse. Readings indicating a compartment isclogged may not indicate degradation of overallbaghouse particulate removalefficiency, but do signalthe need for investigation.Verification ofmonitoring statusEffective upon commissioning of service of a fabricfilter control device at each affected boiler unit.Effective upon commissioning of service ofa fabric filter control device at each affectedboiler unit.Effective upon commissioning of service of a fabricfilter control device at each affected boiler unit.QA/QC practicesThe COM equipment and data quality assurance is inconformance with 40 CFR Part 60 Appendix B & F.Annual calibration of ID fan suction pressuregauges.Annual calibration of the baghouse magnahelic gages.Operators check magnahelics on routine rounds eachshift. The most frequentproblem identified is pluggedsensing lines which arecleared upon detection.MonitoringfrequencyContinuous recording of opacity.Continuous, with hourly recording ofpressure values.Cell magnahelic values recorded once per shift.Data collectionproceduresThe opacity monitor continuously records the averagefor each one (1) minute interval.Operator records readings on the log sheethourly.Magnahelic readings are recorded once per shift.Once per week the operator records the in-service,reverse air cleaning, and at rest magnahelic readingson each cell, and notes any discrepancies. Plantmanagement reviews this data to identify issues thatneed to be addressed immediately and those that canbe added to the next scheduled maintenance work list.

Performance CriteriaAveraging periodBlock one hour.N/AN/ATechnical Support DocumentPage 11 of 15Permit Issued: May 31, 2012APS-Cholla – Permit l#53399

### X. TESTING REQUIREMENTS

Cholla is required to conduct a nnual 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 em issions standards, except for nitrogen oxides emissions from unit 1 stack where there is no applicable standard for NO x 

### emissions. Compliance with opacity standards is determined using EPA Reference Method 9. Performance tests for all pollutants are conducted using the pr ocedures 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 c oal a small quantity of on- site generated used oil and/or used oil fuel for energy recovery purposes. Total heat input from th is 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 HE DP 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 CL AM-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-T ROL CT-1 yes A.A.C. R18-2-101.54.j 7 Stack Gas Analyzers+ Gas Cylinders SO 2,NO,FLUE GAS yes A. A.C. R18-2-101.54.i 8 Potable Water Head Tanks CHLO RINE yes A.A.C. R18-2-101.54.j 9 Service Water Tanks C ONTAINS WELL WATER yes A.A.C. R18-2-101.54.j 10 De-aerator Tanks TRACE BOILER CH EMICALS 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 OI L 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 ye s 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) FU EL 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, DI ESEL (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) GLYC OL yes A.A.C. R18-2-101.54.j 25 Process Water Tank PM-10 yes A.A.C. R18-2-101.54.j



### Tech nical 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 Ta nk 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 ye s A.A.C. R18-2-101.54.j 29 Absorber Feed Pumps Bearings LUBE OI L VAPORS(VOC'S) yes A.A.C. R18-2-101.54.j 30 Scrubber Feed Pumps LUBE OIL VAPOR S(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 OI L 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 CHEMIC ALS 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 C AO(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, BOIL ER CLEANING yes A.A.C. R18-2-101.54.j 69 Coal Lab Vent PM-10 ye s A.A.C. R18-2-101.54.i 70 Misc. Steam Vents(6 -8) BOILER CH EMICALS 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



### Tech nical 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 Vent s 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 HYDROC ARBONS yes A.A.C. R18-2-101.54.j 101 Electric & Instrument Battery Char ging 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 Vent s 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 HYDR OCARBONS 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 HYDROC ARBONS 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



### Tech nical 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 HYDROCA RBONS, 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 ye s 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 ye s A.A.C. R18-2-101.54.j 147 Planning Bldg. Bathroom Vents N-M HYDR OCARBONS 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 HYDR OCARBONS 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 CL 2 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 C ode AAAQGs ..........................................................................Arizona Ambient Air Quality Guidelines APS ............................................................................................................... Arizona Publi c Service ADEQ ......................................................................Arizona Department of Environmental Quality BACT........................................................................................ Best Availabl e Control Technology CAM .......................................................................................... Compliance Assurance Monitoring CEMS............................................................................... Continuous Emission Monitoring System CO......................................................................................................................... Carb on Monoxide COMS ..................................................................................... Continuous Opacity Monitor System CFR...................................................................................................... Code of Federal Regula tions GHG....................................................................................................................Green Ho use Gases lb ............................................................................................................................. .................Pound LNB ........................................................................................................................Low NO x 

### Burner MMBtu............................................................................................... Million British Thermal Uni ts NAAQS..............................................................................National Ambient Air Quality Standards NO x 

### .......................................................................................................................... Nitr ogen Oxide NSPS.........................................................................................New Source Performance Standards NESHAP...............................................National Emission Standard s for Hazardous Air Pollutants PM..........................................................................................................................Par ticulate Matter PM 10 

### ........................................................... Particulate Matter Nominall y less than 10 Micrometers PM 2.5 

### ......................................................... Particulate Matter Nominall y less than 2.5 Micrometers PTE ......................................................................................................................... Pot ential to Emit PSD ......................................................................................Prevention of Significant Deterioratio n SO 2 

### ............................................................................................................................. Sulfur Dioxide USEPA ................................................................. United States Environmental Protection Agency VOC.................................................................................................... Volatile Organic Compoun ds