PIMA COUNTY DEPARTMENT OF ENVIRONMENTAL QUALITY 

Air Program 

 33 North Stone Avenue, Suite 730, Tucson, AZ 85701, Phone: (520) 740-3340

AIR QUALITY OPERATING PERMIT 

(As required by Title 17.12, Article II, Pima County Code)

ISSUED TO 

TUCSON ELECTRIC POWER 

IRVINGTON GENERATING STATION 

3950 EAST IRVINGTON ROAD 

TUCSON, AZ 85714 

This air quality operating permit does not relieve applicant of responsibility for meeting all air pollution regulations 

THIS PERMIT ISSUED SUBJECT TO THE FOLLOWING: Conditions contained in Parts A, B 

AND Attachments C, D, E, F, G & H.

PDEQ PERMIT NUMBER 1052 PERMIT CLASS I 

ISSUED: SEPTEMBER 24, 2007 REVISED: JULY 13, 2010

EXPIRES: SEPTEMBER 23, 2012

Mukonde Chama, P.E., Air Permits Supervisor, PDEQ

SIGNATURE TITLE 

1 

July 13, 2010 
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July 13, 2010 

Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

TABLE OF CONTENTS 

Permit Summary ......................................................................................................................................................4 

Part A: General Provisions......................................................................................................................................5

 I. Permit Expiration and Renewal ...........................................................................................................5 

 II. Compliance with Permit Conditions....................................................................................................5 

 III. Permit Revision, Reopening, Revocation and Reissuance, or Termination for Cause........................5 

 IV. Posting of Permit .................................................................................................................................6 

 V. Fee Payment ........................................................................................................................................6 

 VI. Annual Emissions Inventory Questionnaire ........................................................................................6 

 VII. Compliance Certification.....................................................................................................................6 

 VIII. Certification of Truth, Accuracy and Completeness ...........................................................................7 

 IX. Inspection and Entry............................................................................................................................7 

 X. Permit Revision Pursuant to Federal Hazardous Air Pollutant Standard ............................................8 

 XI. Excess Emissions, Permit Deviations and Emergency Reporting.......................................................8 

 XII. Recordkeeping Requirements............................................................................................................11 

 XIII. Reporting Requirements ....................................................................................................................13 

 XIV. Duty to Provide Information..............................................................................................................13 

 XV. Permit Amendment or Revision ........................................................................................................13 

 XVI. Facility Changes Allowed Without Permit Revisions .......................................................................14 

 XVII. Testing Requirements ........................................................................................................................15 

 XVIII. Property Rights..................................................................................................................................16 

 XIX. Severability Clause ............................................................................................................................16 

 XX. Accident Prevention Requirements Under the Clean Air Act (CAA Section 112(r)) .......................16 

 XXI. Asbestos Requirements......................................................................................................................16 

 XXII. Stratospheric Ozone Depleting Substances .......................................................................................16 

Part B: Specific Conditions....................................................................................................................................17

 I. Applicability ......................................................................................................................................17 

 II. Emission Limits and Standards .........................................................................................................17 

 III. Air Pollution Controls .......................................................................................................................25 

 IV. Monitoring Requirements..................................................................................................................27 

 V. Recordkeeping Requirements............................................................................................................33 

 VI. Reporting Requirements ....................................................................................................................36 

 VII. Testing Requirements ........................................................................................................................38 

Attachment C: Applicable Regulations ................................................................................................................40 

Attachment D: Equipment List ............................................................................................................................41 

Attachment E: Insignificant Equipment .............................................................................................................43 

Attachment F: Phase II Acid Rain Permit ..........................................................................................................46 

Attachment G: Alternate Operating Scenario (AOS) #1 ....................................................................................48 

Attachment H: Alternate Operating Scenario (AOS) #2 ....................................................................................60 

Attachment I: Mercury Provision Standards ......................................................................................................75 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

SUMMARY 

This operating permit is the first 5-year air quality permit issued by the Pima County Department of 

Environmental Quality (PDEQ) to Tucson Electric Power – Irvington Generating Station, (TEP-IGS), the 

Permittee. The permit was revised in April 2010 to include the mercury emission monitoring standards. The 

facility is a major source of all criteria pollutants as well as individual and combined HAPs. The facility is a 

stationary source which generates electricity and consists primarily of fossil-fuel fired steam generating units 

(boilers) and stationary combustion turbines as well as engines, cooling towers, and other processes and 

equipment associated with power production and delivery as well as fuel preparation and transfer. 

The Permittee previously operated under an air quality permit issued by the Arizona Department of 

Environmental Quality, (ADEQ). In 2001 permitting authority for TEP-IGS was transferred from ADEQ to 

PDEQ. 

TEP-IGS is subject to Title V permitting requirements, Standards of Performance for Stationary Combustion 

Turbines (40 CFR 60 Subpart GG or Subpart KKKK for Unit IGT3), Compliance Assurance Monitoring (40 CFR 

64), ADEQ-TEP Consent Order dated February 17, 2009 and the Acid Rain Program of the Clean Air Act (40 

CFR 72-80). 

All terms and conditions of this permit are federally enforceable by the Administrator of the United States 

Environmental Protection Agency (U.S.EPA) under the Clean Air Act, except as otherwise noted. 

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July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

PART A: GENERAL PROVISIONS 

(References to A.R.S. are references to the Arizona Revised Statutes, references to A.A.C. are references to the Arizona Administrative 

Code, and references to PCC are references to Title 17 of the Pima County Code) 

I. PERMIT EXPIRATION AND RENEWAL [PCC 17.12.180.A.1 & PCC 17.12.160.C.2]

 A. This permit is valid for a period of five years from the date of issuance of the permit. 

 B. The Permittee shall submit an application for renewal of this permit at least 6 months, but not 

greater than 18 months prior to the date of permit expiration. 

II. COMPLIANCE WITH PERMIT CONDITIONS [PCC 17.12.180.A.8.a & b]

 A. The Permittee shall comply with all conditions of this permit including all applicable 

requirements of Arizona air quality statutes A.R.S. Title 49, Chapter 3, and Pima County air 

quality rules. Any permit noncompliance is grounds for enforcement action; for permit 

termination, revocation and reissuance, or revision; or for denial of a permit renewal application. 

In addition, noncompliance with any federally enforceable requirement constitutes a violation of 

the Clean Air Act.. 

 B. It shall not be a defense for a Permittee in an enforcement action that it would have been 

necessary to halt or reduce the permitted activity in order to maintain compliance with the 

conditions of this permit. 

III. PERMIT REVISION, REOPENING, REVOCATION AND REISSUANCE, OR TERMINATION 

FOR CAUSE [PCC 17.12.180.A.8.c & PCC 17.12.270]

 A. The permit may be revised, reopened, revoked and reissued, or terminated for cause. The filing 

of a request by the Permittee for a permit revision, revocation and reissuance, or termination; or 

of a notification of planned changes or anticipated noncompliance does not stay any permit 

condition. 

 B. The permit shall be reopened and revised under any of the following circumstances: 

 1. Additional applicable requirements under the Act become applicable to a major source. 

Such reopening shall only occur if there are three or more years remaining in the permit 

term. The reopening shall be completed not later than 18 months after promulgation of 

the applicable requirement. No such reopening is required if the effective date of the 

requirement is later than the date on which the permit is due to expire, unless the original 

permit or any of its terms and conditions has been extended pursuant to PCC 17.12.280. 

Any permit reopening required pursuant to this paragraph shall comply with provisions in 

PCC 17.12.280 for permit renewal and shall reset the five-year permit term. 

 2. Additional requirements, including excess emissions requirements, become applicable to 

an affected source under the acid rain program. Upon approval by the Administrator, 

excess emissions offset plans shall be deemed to be incorporated into the Class I permit. 

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July 13, 2010 
 3. The Control Officer or the Administrator determines that the permit contains a material 

mistake or that inaccurate statements were made in establishing the emissions standards 

or other terms or conditions of the permit. 

 4. The Control Officer or the Administrator determines that the permit needs to be revised 

or revoked to assure compliance with the applicable requirements. 

 C. Proceedings to reopen and issue a permit, including appeal of any final action relating to a permit 

reopening, shall follow the same procedures as apply to initial permit issuance. Such reopenings 

shall be made as expeditiously as practicable. Permit reopenings for reasons other than those 

stated in paragraph III.B.1 of Part A shall not result in the resetting of the five-year permit term. 

IV. POSTING OF PERMIT [PCC 17.12.080]

The Permittee who has been granted an individual permit by PDEQ or a general permit by ADEQ shall 

maintain a complete copy of the permit onsite. If it is not feasible to maintain a copy of the permit onsite, 

the permittee may request, in writing, to maintain a copy of the permit at an alternate location. Upon 

written approval by the Control Officer, the permittee must maintain a complete copy of the permit at the 

approved alternative location. 

V. FEE PAYMENT [PCC 17.12.180.A.9 & PCC 17.12.510]

 Permittee shall pay fees to the Control Officer pursuant to PCC 17.12.510. 

VI. ANNUAL EMISSIONS INVENTORY QUESTIONNAIRE [PCC 17.12.320]

 A. When requested by the Control Officer, the Permittee shall complete and submit an annual 

emissions inventory questionnaire. The questionnaire is due by March 31 or ninety days after the 

Control Officer makes the request and provides the inventory form each year, whichever occurs 

later, and shall include emission information for the previous calendar year These requirements 

apply whether or not a permit has been issued and whether or not a permit application has been 

filed. 

 B. The questionnaire shall be on a form provided by or approved by the Control Officer and shall 

include the information required by PCC 17.12.320. 

VII. COMPLIANCE CERTIFICATION [PCC 17.12.180.A.5 & PCC 17.12.220.A.2]

The Permittee shall submit to the Control Officer a compliance certification that describes the compliance 

status of the source with respect to each permit condition. Certifications shall be submitted as specified in 

Part B of this permit. 

 A. The compliance certification shall include the following: 

 1. Identification of each term or condition contained in the permit including emission 

limitations, standards, or work practices that are the basis of the certification; 

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July 13, 2010 
2. Identification of the method(s) or other means used by the Permittee for determining the 

compliance status of the source with each term and condition during the certification 

period. Such methods and other means shall include, at a minimum, the methods and 

means required under the monitoring, related recordkeeping and reporting sections of this 

permit. If necessary, the owner or operator also shall identify any other material 

information that must be included in the certification to comply with Section 113(c)(2) of 

the Clean Air Act, which prohibits knowingly making a false certification or omitting 

material information.; 

3. The status of compliance with the terms and conditions of the permit for the period 

covered by the certification, including whether compliance during the period was 

continuous or intermittent. The certification shall identify each deviation and take it into 

account in the compliance certification; 

4. For emission units subject to 40 CFR 64, the certification shall also identify as possible 

exceptions to compliance any period during which compliance is required and in which 

an excursion or exceedance defined under 40 CFR 64 occurred; 

5. A progress report on all outstanding compliance schedules submitted pursuant to PCC 

17.12.220; and 

6. Other facts the Control Officer may require to determine the compliance status of the 

facility. 

 B. A copy of all compliance certifications for Class I permits shall also be submitted to the EPA 

Administrator. The address for the EPA administrator is: 

EPA Region 9 Enforcement Office, 75 Hawthorne St (Air-5), San Francisco, CA 

94105

VIII. CERTIFICATION OF TRUTH, ACCURACY AND COMPLETENESS [PCC 17.12.220.A.3]

Any document required to be submitted by this permit, including reports, shall contain a certification by a 

responsible official of truth, accuracy, and completeness. This certification and any other certification 

required by this permit shall state that, based on information and belief formed after reasonable inquiry, 

the statements and information in the document are true, accurate, and complete. 

IX. INSPECTION AND ENTRY [PCC 17.12.220.A.4]

The Permittee shall allow the Control Officer or the authorized representative of the Control Officer upon 

presentation of proper credentials to: 

 A. Enter upon the Permittee’s premises where a source is located or emissions-related activity is 

conducted, or where records are required to be kept under the conditions of the permit; 

 B. Have access to and copy, at reasonable times, any records that are required to be kept under the 

conditions of the permit; 

 C. Inspect, at reasonable times, any facilities, equipment (including monitoring and air pollution 

control equipment), practices, or operations regulated or required under the permit; 

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July 13, 2010 
 D. Sample or monitor, at reasonable times, substances or parameters for the purpose of assuring 

compliance with the permit or other applicable requirements; and 

 E. Record any inspection by use of written, electronic, magnetic and photographic media. 

X. PERMIT REVISION PURSUANT TO FEDERAL HAZARDOUS AIR POLLUTANT 

STANDARD [PCC 17.12.160.D.3]

If this source becomes subject to a standard promulgated by the Administrator pursuant to section 112(d) 

of the Act, then the Permittee shall, within twelve months of the date on which the standard is 

promulgated, submit an application for a permit revision demonstrating how the source will comply with 

the standard. 

XI EXCESS EMISSIONS, PERMIT DEVIATIONS, AND EMERGENCY REPORTING [PCC 17.12.040]

A. Excess Emissions Reporting [PCC 17.12.040]

1. Excess emissions shall be reported as follows: 

a. The permittee shall report to the Control Officer any emissions in excess of the 

limits established by this permit. The report shall be in 2 parts as specified below: 

i. Notification by telephone or facsimile within 24 hours of the time the 

permittee first learned of the occurrence of excess emission that includes 

all available information from 17.12.040.B. The number to call to report 

excess emissions is 520-243-7400. The facsimile number to report excess 

emissions is 520-243-7370. 

 ii. Detailed written notification by submission of an excess emissions report 

within 72 hours of the notification under XI.A.1.a.i of Part A above. 

Notifications should be sent to: 

 PDEQ Air Program 33 N. Stone Avenue, Suite 700 Tucson, Arizona 

85701. 

b. The excess emission report shall contain the following information: 

i. The identity of each stack or other emission point where the excess 

emission occurred; 

ii. The magnitude of the excess emissions expressed in the units of the 

applicable emission limitation and the operating data and calculations 

used in determining the magnitude of the excess emissions; 

iii. The time and duration or expected duration of the excess emissions; 

iv. The identity of the equipment from which the excess emissions 

emanated; 

v. The nature and cause of the emissions; 

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vi. The steps taken, if the excess emissions were the result of a malfunction, 

to remedy the malfunction and the steps taken or planned to prevent the 

recurrence of the malfunctions; 

vii. The steps that were or are being taken to limit the excess emissions; If 

the source’s permit contains procedures governing source operation 

during periods of startup or malfunction and the excess emissions 

resulted from startup or malfunction, a list of the steps taken to comply 

with the permit procedures. 

2. In the case of continuous or recurring excess emissions, the notification requirements of 

this Section shall be satisfied if the source provides the required notification after excess 

emissions are first detected and includes in the notification an estimate of the time the 

excess emissions will continue. Excess emissions occurring after the estimated time 

period or changes in the nature of the emissions as originally reported shall require 

additional notification pursuant to XI.A.1.a & b of Part A above. 

B. Permit Deviations Reporting [PCC 17.12.180.A.5.b]

The Permittee shall promptly report deviations from permit requirements, including those 

attributable to upset conditions as defined in the permit, the probable cause of such deviations, 

and any corrective actions or preventive measures taken. Notice in accordance with 

17.12.180.E.3.d shall be considered prompt for purposes of this permit. 

C. Emergency Provision [PCC 17.12.180.E]

1. An "Emergency" means any situation arising from sudden and reasonably unforeseeable 

events beyond the control of the source, including acts of God, that requires immediate 

corrective action to restore normal operation and that causes the source to exceed a 

technology-based emission limitation under the permit, due to unavoidable increases in 

emission attributable to the emergency. An emergency shall not include noncompliance 

to the extent caused by improperly designed equipment, lack of preventive maintenance, 

careless or improper operation, or operator error. 

2. An emergency constitutes an affirmative defense to an action brought for noncompliance 

with the technology-based emission limitations if the conditions of PCC 17.12.180.E.3 

are met. 

3. The affirmative defense of emergency shall be demonstrated through properly signed, 

contemporaneous operating logs, or other relevant evidence that: 

a. An emergency occurred and that the permittee can identify the cause or causes of 

the emergency; 

 b. At the time of the emergency, the permitted facility was being properly operated; 

 c. During the period of the emergency the permittee took all reasonable steps to 

minimize levels of emissions that exceeded the emissions standards or other 

requirements in the permit; and 

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 d. The Permittee submitted notice of the emergency to the Control Officer by certified 

mail, hand delivery or facsimile transmission within two working days of the time 

when emission limitations were exceeded due to the emergency. This notice shall 

contain a description of the emergency, any steps taken to mitigate emissions, and 

corrective action taken. 

4. In any enforcement proceeding, the permittee seeking to establish the occurrence of an 

emergency has the burden of proof. 

5. This provision is in addition to any emergency or upset provision contained in any 

applicable requirement. 

 D. Compliance Schedule [ARS § 49-480.F.3 & 5]

 For any excess emission or permit deviation that cannot be corrected within 72 hours, the 

permittee is required to submit a compliance schedule to the Director within 21 days of such 

occurrence. The compliance schedule shall include a schedule of remedial measures, including 

an enforceable sequence of actions with milestones, leading to compliance with the permit terms 

or conditions that have been violated. 

E. Affirmative Defenses for Excess Emissions Due to Malfunctions, Startup, and Shutdown. [PCC 17.12.035]

 1. Applicability 

This rule establishes affirmative defenses for certain emissions in excess of an emission 

standard or limitation and applies to all emission standards or limitations except for 

standards or limitations: 

a. Promulgated pursuant to Sections 111 or 112 of the Act, 

b. Promulgated pursuant to Titles IV or VI of the Clean Air Act, 

c. Contained in any Prevention of Significant Deterioration (PSD) or New Source 

Review (NSR) permit issued by the U.S. E.P.A., or 

d. Included in a permit to meet the requirements of PCC 17.16.590.A.5. 

 2. Affirmative Defense for Malfunctions 

Emissions in excess of an applicable emission limitation due to malfunction shall 

constitute a violation. The owner or operator of a source with emissions in excess of an 

applicable emission limitation due to malfunction has an affirmative defense to a civil or 

administrative enforcement proceeding based on that violation, other than a judicial 

action seeking injunctive relief, if the owner or operator of the source has complied with 

the reporting requirements of XIII.B of this Part and has demonstrated all of the 

following: 

 a. The excess emissions resulted from a sudden and unavoidable breakdown of 

process equipment or air pollution control equipment beyond the reasonable 

control of the operator; 

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July 13, 2010 
b. The air pollution control equipment, process equipment, or processes were at all 

times maintained and operated in a manner consistent with good practice for 

minimizing emissions; 

c. If repairs were required, the repairs were made in an expeditious fashion when 

the applicable emission limitations were being exceeded. Off-shift labor and 

overtime were utilized where practicable to ensure that the repairs were made as 

expeditiously as possible. If off-shift labor and overtime were not utilized, the 

owner or operator satisfactorily demonstrated that the measures were 

impracticable; 

 d. The amount and duration of the excess emissions (including any bypass 

operation) were minimized to the maximum extent practicable during periods of 

such emissions; 

 e. All reasonable steps were taken to minimize the impact of the excess emissions 

on ambient air quality; 

 f. The excess emissions were not part of a recurring pattern indicative of inadequate 

design, operation, or maintenance; 

 g. During the period of excess emissions there were no exceedances of the relevant 

ambient air quality standards established in PCC Chapter 17.08 that could be 

attributed to the emitting source; 

 h. The excess emissions did not stem from any activity or event that could have 

been foreseen and avoided, or planned, and could not have been avoided by 

better operations and maintenance practices; 

 i. All emissions monitoring systems were kept in operation if at all practicable; and 

 j. The owner or operator’s actions in response to the excess emissions were 

documented by contemporaneous records. 

 3. Affirmative Defense for Startup and Shutdown 

 a. Except as provided in XI.E.3.b of Part A, and unless otherwise provided for in 

the applicable requirement, emissions in excess of an applicable emission 

limitation due to startup and shutdown shall constitute a violation. The owner or 

operator of a source with emissions in excess of an applicable emission limitation 

due to startup and shutdown has an affirmative defense to a civil or 

administrative enforcement proceeding based on that violation, other than a 

judicial action seeking injunctive relief, if the owner or operator of the source has 

complied with the reporting requirements of XIII.B of Part A and has 

demonstrated all of the following: 

 i. The excess emissions could not have been prevented through careful and 

prudent planning and design; 

 ii. If the excess emissions were the result of a bypass of control equipment, 

the bypass was unavoidable to prevent loss of life, personal injury, or 

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July 13, 2010 
severe damage to air pollution control equipment, production equipment, 

or other property; 

 iii. The source’s air pollution control equipment, process equipment, or 

processes were at all times maintained and operated in a manner 

consistent with good practice for minimizing emissions; 

 iv. The amount and duration of the excess emissions (including any bypass 

operation) were minimized to the maximum extent practicable during 

periods of such emissions; 

 v. All reasonable steps were taken to minimize the impact of the excess 

emissions on ambient air quality; 

 vi. During the period of excess emissions there were no exceedances of the 

relevant ambient air quality standards established in PCC Chapter 17.08 

that could be attributed to the emitting source; 

 vii. All emissions monitoring systems were kept in operation if at all 

practicable; and 

 viii. The Permittee’s actions in response to the excess emissions were 

documented by contemporaneous records. 

 b. If excess emissions occur due to a malfunction during routine startup and 

shutdown, then those instances shall be treated as other malfunctions subject to 

XI.E.2 of this Part A. 

 4. Affirmative Defense for Malfunctions during Scheduled Maintenance 

If excess emissions occur due to a malfunction during scheduled maintenance, then those 

instances will be treated as other malfunctions subject to XI.E.2 of Part A. 

 5. Demonstration of Reasonable and Practicable Measures 

For an affirmative defense under XI.E.2 or 3 of Part A, the Permittee of the source shall 

demonstrate, through submission of the data and information required by XI.E.1 – 5 and 

XII.B of Part A, that all reasonable and practicable measures within the owner or 

operator’s control were implemented to prevent the occurrence of the excess emissions. 

XII. RECORD KEEPING REQUIREMENTS [PCC 17.12.180.A.4]

 A. Permittee shall keep records of all required monitoring information including, recordkeeping 

requirements established pursuant to PCC 17.12.190, where applicable, for the following: 

 1. The date, place as defined in the permit, and time of sampling or measurements; 

 2. The date(s) analyses were performed; 

 3. The name of the company or entity that performed the analyses; 

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July 13, 2010 
 4. A description of the analytical techniques or methods used; 

 5. The results of such analyses; and 

 6. The operating conditions as existing at the time of sampling or measurement. 

B. The Permittee shall retain records of all required monitoring data and support information for a 

period of at least 5 years from the date of the monitoring sample, measurement, report, or 

application. Support information includes all calibration and maintenance records and all original 

strip-chart recordings for continuous monitoring instrumentation, and copies of all reports 

required by the permit. 

C. All required records shall be maintained either in an unchangeable electronic format or in a 

handwritten log utilizing indelible ink. 

XIII. REPORTING REQUIREMENTS [PCC 17.12.180.A.5]

The Permittee shall comply with all of the reporting requirements of this permit. These include all of the 

following: 

A. Compliance certifications pursuant to VII of this Part. 

 B. Excess emission; permit deviation, and emergency reports in accordance with XI of this Part. 

 C. Performance test results in accordance with XVII.F of this Part. 

 D. Reporting requirements listed in Part B of this permit. 

XIV. DUTY TO PROVIDE INFORMATION [PCC 17.12.180.A.8.e, PCC 17.12.160.G, & PCC 17.12.160.H]

 A. The Permittee shall furnish to the Control Officer, within a reasonable time, any information that 

the Control Officer may request in writing to determine whether cause exists for revising, 

revoking and reissuing, or terminating the permit or to determine compliance with the permit. 

Upon request, the Permittee shall also furnish to the Control Officer copies of records required to 

be kept by the permit. For information claimed to be confidential, the Permittee, for Class I 

sources, shall furnish an additional copy of such records directly to the Administrator along with 

a claim of confidentiality. 

 B. If the Permittee has failed to submit any relevant facts or if the Permittee has submitted incorrect 

information in the permit application, the Permittee shall, upon becoming aware of such failure or 

incorrect submittal, promptly submit such supplementary facts or corrected information. In 

addition, an applicant shall provide additional information as necessary to address any 

requirements that become applicable to the source after the date it filed a complete application but 

prior to release of a proposed permit. 

XV. PERMIT AMENDMENT OR REVISION [PCC 17.12.245, PCC 17.12.255 & PCC 17.12.260]

Permittee shall apply for a permit amendment or revision for changes to the facility which do not qualify 

for a facility change without revision under XVI of Part A, as follows: 

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July 13, 2010 
 A. Administrative Permit Amendment (PCC 17.12.245); 

 B. Minor Permit Revision (PCC 17.12.255); 

 C. Significant Permit Revision (PCC 17.12.260). 

 The applicability and requirements for such action are defined in the above referenced regulations. 

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July 13, 2010 
XVI. FACILITY CHANGES ALLOWED WITHOUT PERMIT REVISIONS [PCC 17.12.230]

A A facility with a Class I permit may make changes without a permit revision if all of the 

following apply: 

1. The changes are not modifications under any provision of Title I of the ACT (Air 

Pollution Prevention and Control) or under A.R.S. 49-401.01(17); 

2. The changes do not exceed the emissions allowable under the permit whether expressed 

therein as a rate of emissions or in terms of total emissions; 

3. The changes do not violate any applicable requirements or trigger any additional 

applicable requirements; 

4. The changes satisfy all requirements for a minor permit revision under PCC 17.12.255; 

and 

5. The changes do not contravene federally enforceable permit terms and conditions that are 

monitoring (including test methods), record keeping, reporting, or compliance 

certification requirements. 

B. The substitution of an item of process or pollution control equipment for an identical or 

substantially similar item of process or pollution control equipment shall qualify as a change that 

does not require a permit revision, if the substitution meets all of the requirements of XVI.A, D 

and E of Part A. 

C. Except for sources with authority to operate under general permits, permitted sources may trade 

increases and decreases in emissions within the permitted facility, as established in the permit 

under 17.12.180.A.12 if an applicable implementation plan provides for the emissions trades, 

without applying for a permit revision and based on the seven working days notice prescribed in 

XVI.D of Part A. This provision is available if the permit does not provide for the emissions 

trading as a minor permit revision. 

D. For each change under XVI.A through C of this Part, a written notice, by certified mail or hand 

delivery, shall be received by the Control Officer and the Administrator a minimum of seven (7) 

working days in advance of the change. Notifications of changes associated with emergency 

conditions, such as malfunctions necessitating the replacement of equipment, may be provided 

less than 7 working days in advance of the change but must be provided as far in advance of the 

change, or if advance notification is not practicable as soon after the change as possible. 

E. Each notification shall include: 

1. When the proposed change will occur; 

2. A description of the change; 

3. Any change in emissions of regulated air pollutants; 

4. The pollutants emitted subject to the emissions trade, if any; 

5. The provisions in the implementation plan that provide for the emissions trade with 

which the source will comply and any other information as may be required by the 

provisions in the implementation plan authorizing the trade; 

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July 13, 2010 
6. If the emissions trading provisions of the implementation plan are invoked, then the 

permit requirements with which the source will comply; and 

7. Any permit term or condition that is no longer applicable as a result of the change. 

F. The permit shield described in PCC 17.12.310 shall not apply to any change made under XVI.A 

through C of Part A. Compliance with the permit requirements that the source will meet using the 

emissions trade shall be determined according to requirements of the implementation plan 

authorizing the emissions trade. 

G. Except as otherwise provided for in the permit, making a change from one alternative operating 

scenario to another as proved under PCC 17.12.180.A.11 shall not require any prior notice under 

XVI of Part A. 

H. Notwithstanding any other part of this Section, the Control Officer may require a permit to be 

revised for any change that when considered together with any other changes submitted by the 

same source under this section over the term of the permit, do not satisfy XVI.A of this Part. 

XVII. TESTING REQUIREMENTS [PCC 17.12.050]

 A. Operational Conditions During Testing 

Performance Tests shall be conducted while the unit is operating at full load under representative 

operational conditions unless other conditions are required by the applicable test method or in this 

permit. With prior written approval from the Control Officer, testing may be performed at a 

lower rate. Operations during start-up, shutdown, and malfunction (as defined in PCC 

17.04.340.A.) shall not constitute representative operational conditions unless otherwise specified 

in the applicable requirement. 

 B. Tests shall be conducted and data reduced in accordance with the test methods and procedures 

contained in the Arizona Testing Manual, 40 CFR 52; Appendices D and E, 40 CFR 60; 

Appendices A through F; and 40 CFR 61, Appendices B and C unless modified by the Control 

Officer pursuant to PCC 17.12.050.B or by the Director pursuant to A.A.C. R18-2-312.B. 

 C. Test Plan 

At least 14 calendar days prior to performing a test, the Permittee shall submit a test plan to the 

Control Officer, in accordance with PCC 17.12.050.B. and the Arizona Testing Manual. 

 D. Stack Sampling Facilities 

 The Permittee shall provide or cause to be provided, performance testing facilities as follows: 

 1. Sampling ports adequate for test methods applicable to the facility; 

 2. Safe sampling platforms; 

 3. Safe access to sampling platforms; and 

 4. Utilities for sampling and testing equipment. 

15 

July 13, 2010 
 E. Interpretation of Final Results 

Each performance test shall consist of three separate runs using the applicable test method. Each 

run shall be conducted for the time and under the conditions specified in the applicable standard. 

For the purpose of determining compliance with an applicable standard, the arithmetic means of 

results of the three runs shall apply. In the event that a sample is accidentally lost or conditions 

occur in which one of the three runs is required to be discontinued because of forced shutdown, 

failure of an irreplaceable portion of the sample train, extreme meteorological conditions, or other 

circumstances beyond the Permittee’s control, compliance may, upon the Control Officer’s 

approval, be determined using the arithmetic mean of the results of the other two runs. If the 

Control Officer or the Control Officer’s designee is present, tests may only be stopped with the 

Control Officer’s or such designee’s approval. If the Control Officer or the Control Officer’s 

designee is not present, tests may only be stopped for good cause. Good cause includes: forced 

shutdown, failure of an irreplaceable portion of the sample train, extreme meteorological 

conditions, or other circumstances beyond the Permittee’s control. Termination of any test 

without good cause after the first run is commenced shall constitute a failure of the test. 

Supporting documentation, which demonstrates good cause, must be submitted. 

 F. Report of Final Test Results 

A written report of the results of all performance tests shall be submitted to the Control Officer 

within 45 days after the test is performed. The report shall be submitted in accordance with the 

Arizona Testing Manual. 

XVIII. PROPERTY RIGHTS [PCC 17.12.180.A.8.d]

 This permit does not convey any property rights of any sort, or any exclusive privilege. 

XIX. SEVERABILITY CLAUSE [PCC 17.12.180.A.7]

The provisions of this permit are severable. If any provision of this permit is held invalid, the remainder 

of this permit shall not be affected thereby. 

XX. ACCIDENT PREVENTION REQUIREMENTS UNDER THE CLEAN AIR ACT (CAA Section 

 112(r)) 

Should this stationary source, as defined in 40 CFR Part 68.3, become subject to the accidental release 

prevention regulations in Part 68, then the Permittee shall submit a risk management plan (RMP) by the 

date specified in Section 68.10 and shall certify compliance with the requirements of Part 68 as part of the 

semiannual compliance certification as required by 40 CFR Part 70 and Part B of this permit. 

XXI. ASBESTOS REQUIREMENTS (Demolition/ Renovation)

 Should this stationary source, pursuant to 40 CFR 61, Subpart M become subject to the National 

Emission Standards for Hazardous Air Pollutants - Asbestos for asbestos regulations when conducting 

any renovation or demolition at this premises, then the Permittee shall submit proper notification as 

16 

July 13, 2010 
described in 40 CFR Subpart M and shall comply with all other applicable requirements of subpart M. 

The Permittee shall keep a record of all relevant paperwork on file. [40 CFR 61, Subpart M] 

XXII. STRATOSPHERIC OZONE DEPLETING SUBSTANCES

 The Permittee shall not use, sell, or offer for sale any fluid as a substitute material for use in any motor 

vehicle, residential, commercial, or industrial air conditioning system, refrigerator or freezer unit, or other 

cooling or heating device designed to use a chlorofluorocarbon (CFC) or hydrochlorofluorocarbon 

(HCFC) compound as a working fluid, unless such fluid has been approved for sale and such use by the 

Administrator. The Permittee shall keep a record of all paperwork relevant to the applicable requirements 

of 40 CFR 82, Subpart F onsite. [40 CFR 82 & PCC 17.16.710]

17 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

PART B: SPECIFIC CONDITIONS 

All standards are Federally Enforceable unless otherwise noted 

[References are to Title 17 of the Pima County Code unless otherwise noted] 

I. APPLICABILITY 

Equipment covered by this permit constitutes a Major Source based on 8760 hours of operation per year 

and considering emissions from other emission units of the same SIC Code at this facility. Equipment 

specifically addressed by the permit is listed in Attachment D, “Equipment List” and falls under the 

following Categories: 

A. Fossil Fuel Fired Steam Generators 

B. Stationary Rotating Machinery (including Stationary Turbines IGT1, IGT2 & future AOS for IGT3) 

C. Auxiliary Boiler 

D. Cooling Towers 

E. Coal Preparation Plant 

F Fly-Ash Handling Systems 

G. Open Areas, Roadways, & Streets 

 H All Operations 

 Affected Emission Source Classification: Class I; Major Stationary Source (SOx, NOx, CO, VOC, PM10

& HAPs).

II. EMISSION LIMITS & STANDARDS [PCC 17.12.180.A.2]

A. Fossil Fuel Fired Steam Generators 

 1. Particulate Matter Standard [PCC 17.16.160.C.1]

 [Locally Enforceable Condition]

The Permittee shall not cause, allow, or permit the emission of particulate matter from any 

fossil fuel-fired steam generator in excess of the amounts calculated by the following equation: 

E = 1.02Q0.769 where: 

 E = the maximum allowable particulate emissions rate in pounds-mass per hour. 

 Q = the heat input in million Btu per hour. 

 2. Sulfur Dioxide Standard [PCC 17.16.160.D.1]

 [Locally Enforceable Condition]

18 

July 13, 2010 
a. UNITS I1, I2, & I3 

The Permittee shall not cause, allow, or permit the emission of more than 1.0 pound of 

sulfur dioxide as a three hour average per million Btu heat input when firing liquid fuel. 

 b. UNIT I4 

The Permittee shall not cause, allow, or permit the emission of more than 1.0 pound of 

sulfur dioxide as a three-hour average, per million Btu heat input. 

 [Installation Permit #1156, Condition 5] 

 3. Nitrogen Oxides Standard - UNIT I4 

 The Permittee shall not cause, allow, or permit the emission of more than 0.7 pounds of 

nitrogen oxides as a three hour average (calculated as nitrogen dioxide) per million BTU heat 

input. [Installation Permit #1156, Condition 5]

 4. Opacity Standard - UNIT I4 

 The Permittee shall not cause, allow, or permit to be emitted into the atmosphere any plume or 

effluent from the boiler which exceeds 20 percent opacity, as measured in accordance with 

EPA Reference Method 9. [Installation Permit #1156, Condition 5]

 5. Fuel Limitations 

 a. The Permittee shall not use high sulfur oil (fuel sulfur content > 0.90% by weight) as a 

fuel unless the Permittee demonstrates to the satisfaction of the Control Officer that 

sufficient quantities of low sulfur oil are not available for use by the source and that it has 

adequate facilities and contingency plans to insure that the sulfur dioxide ambient air 

quality standards set forth in 17.08.020 will not be violated. [PCC 17.16.160.G] 

 [Locally Enforceable Condition]

 b. UNITS I1, I2, & I3 

 The Permittee shall only burn the following as fuel: [PCC 17.12.190] 

 i. Natural gas; 

 ii. Fuel Oils #2 through #6 or equivalent; 

 iii. Co-firing Natural gas with Fuel Oils #2 through #6 or equivalent; 

 iv. Co-firing any of the fuels listed above (II.A.5.b.i through ii of this Part) with 

Landfill Gas. 

 c. UNIT I4 

 i. The Permittee shall only burn the following as fuel: [PCC 17.12.190] 

 (A) Coal; 

 (B) Natural Gas; 

19 

July 13, 2010 
 (C) Fuel Oil #2 through #6; 

 (D) Co-Firing Natural Gas with coal or fuel oils #2 through #6; 

 (E) Co-firing Landfill Gas with fuels listed above (II.A.5.c.i.(A) through (C) of 

this Part). 

 (F) Except for short-term fuel switching (three hours or less), fuels shall not be 

fired simultaneously unless the continuous monitoring systems are operating. 

 [Installation Permit #1156, Condition 12]

 ii. The maximum sulfur content of coal shall be less than or equal to 0.50 percent by 

weight at 10,000 BTU/lb on a three hour average basis. [Installation Permit #1156, Condition 4] 

B. Stationary Rotating Machinery (including Stationary Turbines IGT1 and IGT2) 

 1. Particulate Matter Standard [PCC 17.16.340.C]

The Permittee shall not cause, allow, or permit the emission of particulate matter, caused by 

combustion of fuel, from any of the stacks of stationary rotating machinery in excess of the 

amounts calculated by the following equation: 

E = 1.02Q0.769 where: 

 E = the maximum allowable particulate emissions rate in pounds-mass per hour. 

 Q = the heat input in million Btu per hour. 

 2. Sulfur Dioxide Standard 

The Permittee shall not emit more than 1.0 pounds of sulfur per million Btu heat input when 

firing low sulfur oil. [PCC 17.16.340.F] 

 3. Opacity Standard 

 a. The Permittee shall not cause, allow or permit to be emitted into the atmosphere from any 

stationary rotating machinery, smoke for any period of time greater than ten consecutive 

seconds which exceeds 40 percent opacity. Visible emissions when starting cold 

equipment shall be exempt from this requirement (40 percent opacity) for the first ten 

minutes. [PCC 17.16.340.E]

 [Locally Enforceable Condition]

 b. The Permittee shall not cause or permit the effluent from a single emission point, 

multiple emissions point, or fugitive emissions source to have an average optical density 

equal to or greater than opacity limiting standards specified in Table 321 of the Pima 

County Standard Implementation Plan (SIP): subject to the following provisions: [SIP Rule 321] 

 i. Opacities (optical densities) of an effluent shall be measured by a certified visible 

emissions evaluator with his natural eyes, approximately following the procedures 

which were used during his certification, or by an approved and precisely 

calibrated in-stack monitoring instrument. 

20 

July 13, 2010 
 ii. A violation of an opacity standard shall be determined by measuring and recording 

a set of consecutive, instantaneous opacities, and calculating the arithmetic average 

of the measurements within the set unless otherwise noted herein. The 

measurements shall be made at approximately fifteen-second intervals for a period 

of at least six minutes, and the number of required measurements shall be as 

specified in Table 321. Sets need not be consecutive in time, and in no case shall 

two sets overlap. If the average opacity of the set of instantaneous measurements 

exceeds the maximum allowed by any rule, this shall constitute a violation. 

 iii. The use of air or other gaseous diluents solely for the purpose of achieving 

compliance with an opacity standard on prohibited. 

 iv. When the presence of uncombined water is the only reason for failure of a source 

to otherwise meet the requirements of II.B.3.b of Part B, II.B.3.b shall not apply. 

 4. Fuel Limitations 

 a. The Permittee shall not use high sulfur oil (fuel sulfur content > 0.90% by weight) as a 

fuel unless the Permittee demonstrates to the satisfaction of the Control Officer that 

sufficient quantities of low sulfur oil are not available for use by the source and that it has 

adequate facilities and contingency plans to insure that the sulfur dioxide ambient air 

quality standards set forth in 17.08.020 will not be violated. [PCC 17.16.340.H] 

 [Locally Enforceable Condition]

 b. The Permittee shall only burn the following as fuel in UNITS IGT1 and IGT2: 

 [PCC 17.12.190] 

 i. Natural gas; 

 ii. Fuel oil: #2 Distillate; or 

 iii. Co-firing natural gas with Fuel oil #2 Distillate. 

 c. The Permittee shall only burn diesel as fuel in UNITS IGT1A and IGT2A (stationary 

turbine starter engines). [PCC 17.12.190] 

C. Auxiliary Boiler 

 1. Particulate Matter Standard [PCC 17.16.165.C] 

 [Locally Enforceable Condition]

The Permittee shall not cause, allow or permit the emission of particulate matter, caused by the 

combustion of fuel from the stack of 

E = 1.02Q0.769 where: 

 E = the maximum allowable particulate emissions rate in pounds-mass per hour. 

 Q = the heat input in million Btu per hour. 

 2. Sulfur Dioxide Standard [PCC 17.16.165.E]

21 

July 13, 2010 

 [Locally Enforceable Condition]
The Permittee shall not cause, allow, or permit the emission of more than 1.0 pounds of sulfur 

dioxide per million Btu heat input when firing liquid fuel.

 3. Fuel Limitations 

 a. The Permittee shall not use high sulfur oil (fuel sulfur content > 0.90% by weight) as a 

fuel unless the Permittee demonstrates to the satisfaction of the Control Officer that 

sufficient quantities of low sulfur oil are not available for use by the source and that it has 

adequate facilities and contingency plans to insure that the sulfur dioxide ambient air 

quality standards set forth in 17.08.020 will not be violated. [PCC 17.16.165.G] 

 [Locally Enforceable Condition]

 b. Permittee shall only burn the following as fuel in the auxiliary boiler: [PCC 17.12.190] 

 i. Natural gas; 

 ii. Fuel oil #2 Distillate; or 

 iii. Co-firing Natural gas with Fuel oil #2 Distillate. 

D. Cooling Towers 

 1. Particulate Matter Standard [PCC 17.16.430.A.1.b] 

 [Locally Enforceable Condition]

The Permittee shall not cause or allow particulate emissions from the cooling towers to exceed: 

E = 17.31PP

0.16 where: 

 E = the maximum allowable particulate emissions rate in pounds-mass per hour. 

 P = the process rate in tons-mass per hour. 

 2. Odor Limiting Standard 

 The Permittee shall not emit gaseous or odorous materials from equipment, operations, or 

premises in such quantities or concentrations to cause air pollution. [PCC 17.16.430.D] 

 [Locally Enforceable Condition]

 3. Where a stack, vent, or other outlet is at such a level that fumes, gas mist, odor, smoke, vapor 

or any combination thereof constituting air pollution is discharged to adjoining property, the 

Control Officer may require the installation of abatement equipment or the alteration of such 

stack, vent, or other outlet by the Permittee thereof to a degree that will adequately dilute, 

reduce, or eliminate the discharge of air pollution to adjoining property. [PCC 17.16.430.G] 

 [Locally Enforceable Condition]

 4. The Permittee shall not used chromium-based water treatment chemicals in the cooling towers. 

 [PCC 17.12.190][Material Permit Condition] 

E. Coal Preparation Plant (CPP) [Locally Enforceable Conditions]

22 

July 13, 2010 

 1. Particulate Matter Standards [PCC 17.16.310.B] 
The Permittee shall not cause, allow or permit the discharge of particulate matter into the 

atmosphere in any one hour from any existing coal preparation plant in total quantities in 

excess of the amounts calculated by one of the following equations set forth: 

a. For process sources having a process weight rate of 60,000 pounds per hour (30 tons per 

hour) or less, the maximum allowable emissions shall be determined by the following 

equation: 

 E = 3.59P0.62 where: 

 E = the maximum allowable particulate emissions rate in pounds-mass per hour. 

 P = the process weight in tons-mass per hour. 

 b. For process sources having a process weight rate greater than 60,000 pounds per hour (30 

tons per hour), the maximum allowable emissions shall be determined by the following 

equation: 

 E = 17.31PP

0.16 where: 

 "E" and "P" are defined as indicated in II.E.1.a. of Part B. 

c. The total process weight from all similar units employing a similar type process shall be 

used in determining the maximum allowable emission of particulate matter. [PCC 17.16.310.D] 

 2. The Permittee shall not cause, suffer, allow, or permit crushing, screening, handling, 

transporting, or conveying of materials or other operations likely to result in significant 

amounts of airborne dust without taking reasonable precautions, such as the use of spray bars, 

wetting agents, dust suppressants, covering the load, and hoods to prevent excessive amounts of 

particulate matter from becoming airborne. [PCC 17.16.100.A & PCC 17.16.310.E] 

 3. The Permittee shall not cause, suffer, allow, or permit organic or inorganic dust producing 

material to be stacked, piled or otherwise stored without taking reasonable precautions such as 

chemical stabilization, wetting, or covering to prevent excessive amounts of particulate matter 

from becoming airborne. [PCC 17.16.110.A & PCC 17.16.310.E]

 4. Stacking and reclaiming machinery utilized at storage piles shall be operated at all times with a 

minimum fall of material and in such manner, or with the use of spray bars and wetting agents, 

as to minimize and control to ensure compliance with PCC 17.16.050. [PCC 17.16.110.B & PCC 17.16.310.E] 

 5. The Permittee shall employ one or more of the following reasonable precautions to prevent 

excessive amounts of particulate matter from becoming airborne: 

a. Use spray bars, hoods, wetting agents, dust suppressants, or cover when crushing, 

handling, or conveying material that is likely to give rise to airborne dust; [PCC 17.16.100] 

b. Adequately cover, or use wetting agents, chemical stabilization, or dust suppressants 

when stacking, piling, or otherwise storing organic or inorganic dust producing material; [PCC 17.16.110.A]

23 

July 13, 2010 
c. Operate stacking and reclaiming machinery utilized at storage piles at all times with a 

minimum fall of material and with the use of spray bars and wetting agents; [PCC 17.16.110.B] 

 d. The emergency coal storage pile is exempt from the requirements listed above (Part 

B.II.E.5.a through c of this Part). 

 F. Fly-Ash Handling Systems (FAHS) [Locally Enforceable Conditions]

 1. Particulate Matter Standards [PCC 17.16.430.A.1] 

The Permittee shall not cause or permit the discharge of particulate matter into the atmosphere 

in any one hour from FAHS in total quantities in excess of the amounts calculated by one of the 

following equations set forth: 

a. For process sources having a process weight rate of 60,000 pounds per hour (30 tons per 

hour) or less, the maximum allowable emissions shall be determined by the following 

equation: 

 E = 3.59P0.62 where: 

 E = the maximum allowable particulate emissions rate in pounds-mass per hour. 

 P = the process weight in tons-mass per hour. 

 b. For process weight rates greater than 60,000 pounds per hour (30 tons per hour), the 

maximum allowable emissions shall be determined by the following equation: 

 E = 17.31PP

0.16 where: 

 "E" and "P" are defined as indicated in II.F.1.a of Part B. 

 c. The total process weight from all similar units employing a similar type process shall be 

used in determining the maximum allowable emission of particulate matter. [PCC 17.16.430.B]

 2. The Permittee shall not cause, suffer, allow, or permit crushing, screening, handling, 

transporting, or conveying of materials or other operations likely to result in significant 

amounts of airborne dust without taking reasonable precautions, such as the use of spray bars, 

wetting agents, dust suppressants, covering the load, and hoods to prevent excessive amounts of 

particulate matter from becoming airborne. [PCC 17.16.100.A & PCC 17.16.310.E] 

 3. The Permittee shall not cause, suffer, allow, or permit organic or inorganic dust producing 

material to be stacked, piled or otherwise stored without taking reasonable precautions such as 

chemical stabilization, wetting, or covering to prevent excessive amounts of particulate matter 

from becoming airborne. [PCC 17.16.110.A & PCC 17.16.310.E]

 4. Stacking and reclaiming machinery utilized at storage piles shall be operated at all times with a 

minimum fall of material and in such manner, or with the use of spray bars and wetting agents, 

as to minimize and control to ensure compliance with PCC 17.16.050. [PCC 17.16.110.B & PCC 17.16.310.E] 

24 

July 13, 2010 
 5. The Permittee shall employ one or more of the following reasonable precautions to prevent 

excessive amounts of particulate matter from becoming airborne: 

a. Use spray bars, hoods, wetting agents, dust suppressants, or cover when crushing, 

handling, or conveying material that is likely to give rise to airborne dust; [PCC 17.16.100] 

b. Adequately cover, or use wetting agents, chemical stabilization, or dust suppressants 

when stacking, piling, or otherwise storing organic or inorganic dust producing material; [PCC 17.16.110.A]

c. Operate stacking and reclaiming machinery utilized at storage piles at all times with a 

minimum fall of material and with the use of spray bars and wetting agents; 

G. Open Areas, Roadways, & Streets 

 1. The Permittee shall not cause, suffer, allow, or permit a building or its appurtenances, or a 

building site, or a driveway, or a parking area, or a vacant lot or other open area to be 

constructed, used, altered, repaired, demolished, cleared, or leveled, or the earth to be moved or 

excavated, without taking reasonable precautions to limit excessive amounts of particulate 

matter from becoming airborne. Dust and other types of air contaminants shall be kept to a 

minimum by good modern practices such as using an approved dust suppressant or adhesive 

soil stabilizer, paving, covering, landscaping, continuous wetting, detouring, barring access, or 

other acceptable means. [PCC 17.16.080.A & SIP 318.A] 

2. The Permittee shall not leave any vacant lot, building site, parking area, or other open area in 

such a state after construction, alteration, clearing, leveling, or excavation that naturally 

induced wind blowing over the area causes a violation the opacity standards in II.H.1 of this 

Part. Dust and other types of air contaminants shall be kept to a minimum by good modern 

practices such as landscaping, covering with gravel or vegetation, paving, or applying 

equivalently effective controls. [PCC 17.16.080.B & SIP 318.B] 

 3. No vacant lot, parking area, sales lot, or other open urban area shall be used by motor vehicles 

in such a manner that visible dust emissions induced by vehicular traffic on the area cause a 

violation of the opacity standards in II.H.1 of Part B. [PCC 17.16.080.C & SIP 318.C] 

 4. The Permittee shall not cause, suffer, allow or permit the use, repair, construction or 

reconstruction of a roadway or alley without taking reasonable precautions to prevent excessive 

amounts of particulate matter from becoming airborne. Dust and other particulates shall be kept 

to a minimum by employing temporary paving, dust suppressants, wetting down, detouring or 

by other reasonable means. [PCC 17.16.090.A]

 5. The surfacing of roadways with asbestos tailings is prohibited. [PCC 17.16.090.F & SIP 315]

H. All Operations 

 1. Opacity Standards 

 a. Opacity emissions from non-point sources shall not exceed 20 percent as measured in 

accordance with the Arizona Testing manual, and EPA Reference Method 9. 

 [PCC 17.16.050.B][Locally Enforceable Condition]

25 

July 13, 2010 
 b. Except as provided elsewhere in this Part B, the Permittee shall not cause, allow, or 

permit to be emitted into the atmosphere any plume or effluent the opacity of which 

exceeds 20 percent, as measured in accordance with EPA Reference Method 9 in 40 

CFR, Appendix A. [PCC 17.16.130.B.3][Locally Enforceable Condition]

 2. Definition of Heat Input 

 For the purposes of this section (II.A through II. C of this Part) the heat input shall be the 

aggregate heat content of all fuels whose products of combustion pass through a stack or other 

outlet. The heat content of solid fuel shall be determined in accordance with PCC 17.12.045.C. 

 [PCC 17.16.160.B, 17.16.165.B & PCC 17.16.340.B] [Locally Enforceable Condition]

 3. Odor Limiting Standard 

 The Permittee shall not emit gaseous or odorous materials from equipment, operations or 

premises under his control in such quantities or concentrations as to cause air pollution. 

 [PCC 17.16.030] [Locally Enforceable Condition]

 4. Visible Emissions 

 The Permittee shall not cause or permit the airborne diffusion of visible emissions, including 

fugitive dust, beyond the property boundary line within which the emissions become airborne. 

In actual practice, the airborne diffusion of visible emissions across property lines shall be 

prevented by appropriately controlling the emissions at the point of discharge, or ceasing 

entirely the activity or operation which is causing or contributing to the emissions. This 

condition shall not apply when wind speeds exceed twenty-five miles per hour (as estimated by 

an enforcement officer using the Beaufort Scale of Wind-Speed Equivalents, or as recorded by 

the National Weather Service). This exception does not apply if control measures have not been 

taken or were not commensurate with the size or scope of the emission source. [PCC 17.16.050.D & SIP 343]

III. AIR POLLUTION CONTROLS 

A. Fossil Fuel Fired Steam Generators – UNIT I4 

The Permittee shall install, maintain, and operate a baghouse on UNIT I4 to capture particulate 

emissions resulting from combustion of coal fuel. The baghouse shall be operated at all times when 

UNIT I4 is firing coal (exclusively or in combination) and when transitioning to or from firing coal 

fuel (exclusively or in combination). Air pollution control equipment shall be operated in a manner 

consistent with good modern practices for minimizing emissions. [Installation Permit #1156, Condition 8] 

 [Material Permit Condition] 

B. Coal Preparation Plant 

 1. Spray bars shall be used in conjunction with other air pollution control equipment in the coal 

handling/storage systems to prevent fugitive dust. [Installation Permit #1156, Condition 7] 

2. At all times when the equipment in the Table 1 is in operation, the Permittee shall maintain and 

operate the associated air pollution control equipment in accordance with good modern 

practices for minimizing emissions: [PCC 17.12.180.A.3][Material Permit Condition]

26 

July 13, 2010 
 Table 1

 

27 

July 13, 2010 

Equipment Description Pollution Control Equipment 

Rotary Car Dumper Enclosure, Spray Bars & Dust Collector

Live Coal Storage Facility Enclosure & Dust Collector

Crusher Facility Enclosure & Dust Collector

Tower 4 Enclosure & Dust Collector

As Received Sampler Enclosure

Emergency Storage Pile Telescopic Chute

Conveyors C2, C4, C5, C6, C7A, C7B Weather Covers

 C. Fly-Ash Handling Systems 

 1. Spray bars shall be used in conjunction with other air pollution control equipment in the flyash 

handling/storage systems to prevent fugitive dust. [Installation Permit #1156, Condition 7] 

2. At all times when the equipment in the following table is in operation, the Permittee shall 

maintain and operate the associated air pollution control equipment in accordance with good 

modern practices for minimizing emissions: [Material Permit Condition]

 Table B

Equipment Description Pollution Control Equipment 

Flyash Silo A Dust Collector

Flyash Silo A Vent Dust Collector

Flyash Silo B Dust Collector

Flyash Silo B Vent Dust Collector

Flyash Storage Tank #4 Dust Collector

3. The loading sleeve on the flyash hopper shall incorporate a cut-off valve. Flyash shall be wetted 

prior to any handling in an open area. The fly ash handling area and haul road shall be paved. 

 [Installation Permit #1156, Condition 10][Material Permit Condition]

4. The flyash shall be loaded into enclosed hopper trucks through a closed gravity feed system and 

the outer sleeve of the dual sleeve system shall seal with the loading port of the truck and it 

shall be vented back to the hopper baghouse. [Installation Permit #1156, Condition 11] 

 [Material Permit Condition]

D. Additional Pollution Control Equipment 

 1. The Control Officer reserves the right to require any additional air pollution control equipment 

as deemed necessary for UNIT I4, the Coal Preparation Plant and Fly-Ash Handling Systems. [Installation Permit #1156, Condition 13] 
2. The requirement for any additional air pollution control equipment shall be requested by the 

Control Officer through a permit reopening pursuant to III of Part A. [PCC 17.12.180.A.15]

IV. MONITORING REQUIREMENTS [PCC 17.12.180.A.3]

A. Fossil Fuel Fired Steam Generators

 1. Visible Emissions 

 a. UNITS I1, I2, & I3 

 i. If liquid fuel is combusted in the unit continuously for a time period greater than 48 

hours but less than 168 hours, (equal to one week), at least one opacity reading will 

be observed at the exit of the unit’s stack. 

 ii. When continuously firing liquid fuel for a time period greater than 168 hours, the 

Permittee shall conduct at least one opacity reading during each 168-hour period at 

the exit of the unit’s stack by an employee certified in Method 9. 

 iii. All opacity readings shall be observed in accordance with EPA Reference Method 

9. The Permittee shall log in ink or in an unchangeable electronic format and 

maintain a record of the opacity readings from above and the number of hours fuel 

oil is burned continuously. 

 b. UNIT I4 

 i. The Permittee shall install, maintain, calibrate, and operate a continuous opacity 

monitoring system (COMS). When the Permittee is changing fuel to natural gas, 

the COMS shall be operated during the transition period, and deactivated only after 

the opacity readings have stabilized to levels associated with normal natural gas 

combustion. [Installation Permit #1156, Condition #6][Material Permit Condition] 

 ii. The COMS shall meet the following requirements: 

 (A) 40 CFR 60, Appendix B, Performance Specification 1, Specification and Test 

Procedures for Opacity Continuous Emission Monitoring Systems in 

Stationary Sources. 

 (1) Apparatus 

 (2) Installation Specifications 

 (3) Design and Performance Specifications 

 (4) Design Specifications Verification Procedure 

 (5) Performance Specifications Verification Procedure 

 (6) Equations 

 (B) Calibration Checks 

28 

July 13, 2010 
 The Permittee shall record the zero and span drift in accordance with the 

method prescribed by the manufacturer's recommended zero and span check 

at least once daily unless the manufacturer has recommended adjustments at 

shorter intervals, in which case such recommendations shall be followed. [PCC 17.12.060.D.6] 

 (1) Zero and Span Drift Adjustments [PCC 17.12.060.D] 

 [40 CFR 60 Appendix B Spec 1, 13.3 (6)]

 (a) Permittee shall adjust the zero or span whenever the 24-hour 

zero drift or 24-hour calibration drift limits of 2% opacity are 

exceeded. 

 (b) The system shall allow for the amount of excess zero and span 

drift measured at the 24-hour interval checks to be recorded and 

quantified. 

 (c) The optical surfaces exposed to the effluent gases shall be 

cleaned prior to performing the zero and span drift adjustments 

except that for systems using automatic zero adjustments. 

 (d) The optical surfaces shall be cleaned when the cumulative 

automatic zero compensation exceeds 4% opacity. 

 (2) System Checks 

 Each analyzer shall include a calibration system for simulating a zero 

opacity (or no greater than 10%) condition and an upscale opacity 

condition for the purposes of performing periodic checks of the 

transmissometer calibration while on an operating stack or duct. This 

calibration will provide, as a minimum, a system check of the analyzer 

internal optics and all electronic circuitry including the lamp and 

photodetector assembly. 

 (3) Minimum Frequency of Operation 

 Except during periods of system breakdowns, repairs, calibration 

checks, and zero and span adjustments, the COMS shall be in 

continuous operation and shall complete a minimum of one cycle of 

sampling and analyzing for each successive 15-second period and one 

cycle of data recording for each successive 6-minute period. [PCC 17.12.060.E.2] 

 (4) Data Reduction and Missing Data 

 (a) Permittee shall reduce all data from the COMS to 6-minute 

averages. Six-minute opacity averages shall be calculated from 

24 or more data points equally spaced over each 6-minute 

period. 

 (b) Data recorded during periods of system breakdowns, repairs, 

calibration checks, and zero and span adjustments shall not be 

29 

July 13, 2010 
included in the data averages computed under the previous 

paragraph. An arithmetic or integrated average of all data may be 

used. 

 2. Particulate Matter – Compliance Assurance Monitoring for UNIT I4 (CAM) 

a. Indicator, Measurement Approach and Data Representativeness 

 i. Visible Emissions Opacity 

When firing coal and/or liquid fuel the Permittee shall maintain and continuously 

operate a Continuous Opacity Monitoring Systems (COMS) to measure visible 

emissions on the stack (Opacity) which is indicative of operation of the UNIT I4 

fabric filter in a manner necessary to comply with particulate matter emission 

standards. [40 CFR 64.6(c)(1) & Installation Permit #1156, Condition #6] 

 [Material Permit Condition]

 ii. Baghouse Condition 

 The Permittee shall conduct: [40 CFR 64.6(c)(1)] 

 [Material Permit Condition]

 (A) Sampling and analysis of representative bag samples once per year before the 

anniversary date of the issuance of the permit. The analyses of representative 

bag samples will be used as a factor in determining when bag replacement is 

to be scheduled. 

 (B) An inspection and maintenance program, to be performed during a scheduled 

major outage that includes an internal visual inspection of the entire 

baghouse including bag compartments for signs of bag failure. Any known/ 

discovered broken bags will be either replaced or capped off until ready to be 

replaced. Compartments identified during the inspection with one or more 

broken bags, that have not been capped off or replaced, will be isolated and 

only placed back into service when the broken bags have been replaced. 

 b. Indicator range 

i. Visible Emissions Opacity 

 (A) An average opacity measurement of 10 percent or greater in any 3-hour 

rolling average period, except during startup, shutdown and malfunction shall 

constitute an excursion. [40 CFR 64.3(a)(2)] 

 (B) Each three-hour rolling average opacity, except during startup, shutdown and 

malfunction during which a fabric filter parameter alarm is activated shall 

also constitute an excursion for the purposes of responding to and reporting 

excursions under 40 CFR 64.7. [40 CFR 64.6(c)(2)]

ii. Baghouse Condition 

Failure to sample and analyze the bags’ conditions as described in IV.A.2.a.ii.(a) of 

Part B shall constitute an excursion. 

30 

July 13, 2010 
c. Quality Assurance/ Quality Control (QA/QC) Practices [40 CFR 64.6(c)(1)]

 i. Visible Emissions Opacity 

The Permittee shall meet the QA/ QC requirements of 40 CFR Part 60, Appendix 

B, Performance Specification 1, “Specification and Test Procedures for Opacity 

Continuous Emission Monitoring Systems in Stationary Sources.” 

 ii. Baghouse Condition 

The Permittee shall ensure that experienced personnel perform conduct the 

inspection and maintenance program. 

d. Data Collection Procedure & Monitoring Frequency 

 i. Visible Emissions Opacity 

 (A) The Permittee shall conduct all monitoring in continuous operation with data 

recorded as 6-minute averages (or shall collect data at all required intervals) 

at all times that the pollutant specific emission unit is operating. Except for, 

as applicable, monitoring malfunctions, associated repairs, and required 

quality assurance or control activities (including, as applicable, calibration 

checks and required zero and span adjustments). Data recorded during 

monitoring malfunctions, associated repairs, and required quality assurance 

or control activities shall not be used, including data averages and 

calculations, or fulfilling a minimum data availability requirement, if 

applicable. [40 CFR 64.7(c)]

 (B) Averaging Period 

 The Permittee shall have a three-hour rolling average period of visible 

emissions. The three-hour average opacity block parameter shall be equipped 

with an alarm. [40 CFR 64.6(c)(1)]

 ii. Baghouse Condition 

The monitoring frequency of the baghouse may vary. In addition the Permittee 

shall: 

 (A) Keep the results of the annual representative bag analyses on site. 

 (B) Record the results of all inspection and maintenance activities and keep them 

on site. 

e. Prior to making any changes to the alarm set point or alarm delay time described in 

IV.A.2.d.i.(B) of Part B, the Permittee shall submit written notification to the Control 

Officer. Such notification shall include the proposed new alarm set point or alarm delay 

time and the reason for the proposed change. The proposed change may be made without 

the prior approval of the Control Officer. [40 CFR 64.6(c)(2)] 

31 

July 13, 2010 
f. Upon detecting an excursion or exceedance, the owner or operator shall restore operation 

of the pollutant-specific emissions unit (including the control device and associated 

capture system) to its normal or usual manner of operation as expeditiously as practicable 

in accordance with good air pollution control practices for minimizing emissions. The 

response shall include minimizing the period of any startup, shutdown or malfunction and 

taking any necessary corrective actions to restore normal operation and prevent the likely 

recurrence of the cause of an excursion or exceedance (other than those caused by 

excused startup or shutdown conditions). Such actions may include initial inspection and 

evaluation, recording that operations returned to normal without operator action (such as 

through response by a computerized distribution control system), or any necessary 

follow-up actions to return operation to within the indicator range, designated condition, 

or below the applicable emission limitation or standard, as applicable. [40 CFR 64.7(d)(1)] 

g. Determination of whether the owner or operator has used acceptable procedures in 

response to an excursion or exceedance will be based on information available, which 

may include but is not limited to, monitoring results, review of operation and 

maintenance procedures and records, and inspection of the control device, associated 

capture system, and the process. [40 CFR 64.7(d)(2)]

 h. In addition to the general reporting requirements of this permit, all reports of excursions 

shall follow the format outlined in 40 CFR 64.9(a)(2) and submitted with the report 

required in VI.F of Part B. For the purposes of defining “prompt” for excursions, 

reporting of excursions in this report shall be considered prompt reporting. [40 CFR 64.9(a)]

 i. In addition to the general recordkeeping requirements of this permit, all CAM 

recordkeeping shall follow the format outlined in 40 CFR 64.9(b). [40 CFR 64.9(b)]

 3. Sulfur Dioxide and Nitrogen Oxides – UNIT I4 

a. The Permittee shall maintain, calibrate, and operate a continuous emissions monitoring 

system (CEMS) for measuring the sulfur dioxide emissions, nitrogen oxides emissions, 

and diluents. When exclusively firing natural gas, the Permittee may use the emission 

factor of 0.0006 lb/MMBTU to estimate emissions of SO2 in place of the continuous SO2

emission monitor. [Installation Permit #1156, Condition #6] 

 [Material Permit Condition]

b. The CEMS for SO2, NOx and diluents shall meet the following requirements: 

 i. 40 CFR Part 75, Appendix A, “Specification and Test Procedures” 

 (A) Installation and measurement location 

 (B) Equipment specifications 

 (C) Performance specifications 

 (D) Data Acquisition and handling systems 

 (E) Calibration gas 

 (F) Certifications tests and procedures 

 (G) Calculations 

32 

July 13, 2010 
 ii. 40 CFR Part 75, Appendix B, “Quality Assurance and Quality Control Procedures” 

 (A) Quality Assurance/ Quality Control program 

 (B) Frequency of testing 

c. Permittee shall comply with all the recordkeeping and reporting requirements of 40 CFR 

Part 75 Subparts F and G respectively. 

 4. Fuel Limitations - UNIT I4 

 Coal consumed shall be sampled for moisture, ash, sulfur content, and gross calorific value. A 

coal analysis shall be performed on each train load and the results of these analyses shall be 

retained for at least five years following the date of measurement. All sample collection, sample 

preparation, and analyses performed or caused to be performed shall be conducted according to 

the most recent ASTM methods. [Installation Permit 1156, Condition #3] 

B. Stationary Rotating Machinery (including Stationary Turbines IGT1 & IGT2) 

 1. Visible Emissions 

a. If liquid fuel is burned in a unit continuously for a time period greater than 48 hours but 

less than 168 hours, at least one six minute opacity reading will be observed at the exit of 

the unit’s stack. 

b. If liquid fuel is burned in a unit continuously for a time period greater than 168 hours, at 

least one six-minute opacity reading will be observed during each 168-hour period, at the 

exit of the unit’s stack. 

c. All opacity readings will be observed in accordance with EPA Reference Method 9. The 

Permittee shall log in ink or in an unchangeable electronic format and maintain a record 

of the opacity readings from above and the number of hours fuel oil is continuously 

burned. 

 2. Sulfur Dioxide 

For units firing gaseous fuels, the Permittee shall monitor daily, the sulfur content of the fuel 

being combusted in these machines. This requirement may be complied with by maintaining a 

vendor-provided copy of that part of the Federal Energy Regulatory Commission (FERC)-

approved Tariff agreement that limits transmission of pipeline quality natural gas of sulfur 

content to less than 0.9 percent by weight. [PCC 17.16.340.I]

 3. Hours of Operation 

The Permittee shall keep track of the hours of operation, computed as a twelve-month rolling 

total, until the performance tests specified in VII.A.1 & 3 of this Part are completed. 

C. Coal Preparation Plant [PCC 17.12.180.A.3]

33 

July 13, 2010 
1. A certified Method 9 observer shall conduct a weekly visual survey of visible emissions from 

the coal preparation plant when it is in operation. This weekly survey shall include observation 

of all exposed transfer points, enclosed transfer points, the coal storage pile, and the baghouses 

in the coal handling system. The Permittee shall record the location observed, the name of the 

observer, date on which the observation was made, and the results of the observation. 

2. If the observer sees a plume from an emission point that appears to exceed 20% opacity on an 

instantaneous basis, the observer shall take a six-minute Method 9 observation of the plume if 

possible. 

 3. If the six-minute opacity of the plume exceeds 20%, the Permittee shall do the following: 

 a. Adjust or repair the controls or equipment to reduce opacity to below 20%; and 

 b. Report it as an excess emission in accordance with XII.A of Part A of this permit. 

4. If the six-minute opacity of the plume is less than 20%, the observer shall make a record of the 

following: 

 a. Date and time of the observation; and 

 b. The results of the Method 9 observation. 

 D. Fly-Ash Handling System [PCC 17.12.180.A.3]

1. A certified Method 9 observer shall conduct a weekly visual survey of visible emissions from 

the fly-ash handling system when it is in operation. This weekly survey shall include 

observation of all exposed transfer points, enclosed transfer points and the baghouses in the flyash handling system. The Permittee shall record the location observed, the name of the 

observer, date on which the observation was made, and the results of the observation. 

2. If the observer sees a plume from an emission point that appears to exceed 20% opacity on an 

instantaneous basis, the observer shall take a six-minute Method 9 observation of the plume if 

possible. 

 3. If the six-minute opacity of the plume exceeds 20%, the Permittee shall do the following: 

 a. Adjust or repair the controls or equipment to reduce opacity to below 20%; and 

 b. Report it as an excess emission in accordance with XII.A of Part A of this permit. 

4. If the six-minute opacity of the plume is less than 20%, the observer shall make a record of the 

following: 

 a. Date and time of the observation; and 

 b. The results of the Method 9 observation. 

V. RECORDKEEPING [PCC 17.12.180.A.4]

34 

July 13, 2010 
 A. Fossil Fuel Fired Steam Generators 

 1. Particulate Matter - UNITS I1, I2, & I3 

With regard to all liquid fuels, the Permittee shall keep on record, along with the fuel firing 

rate, the contractual agreement with the liquid fuel vendor indicating the following information 

concerning the liquid fuel being fired: 

 a. The heating value; and 

 b. The ash content. 

 2. Sulfur Dioxide - UNITS I1, I2, & I3 

With regard to liquid fuel, the Permittee shall keep records of fuel supplier certifications 

including the following information: 

 a. The name of the fuel oil supplier; 

 b. The sulfur content of the oil from which the shipment came; 

 c. The heating content of the oil from which the shipment came; 

 d. The density of the fuel oil from which the shipment came; and 

 e. The method used to determine the sulfur content of the oil. 

f. Engineering calculations demonstrating compliance with the standard shall be performed 

each time there is a change in V.A.2.b, c, or d of Part B above. These calculations shall 

be performed according to the following equation and maintained in a record: 

35 

July 13, 2010 

 where: MMBtu

Btu

HV

SO

1

×

DS %0.2 f 000,000,1

2

× = ×

SO2 = emissions of SO2 in lb/MMBtu 

%S = Percent Sulfur by weight (decimal; i.e. 1% = 0.01) 

Df = Density of fuel in lb/gal 

HV = Heating value of fuel in Btu/gal 

 3. Fuel Limitation 

Except for fuels fired during startup and/or flame stabilization, the Permittee shall log in ink or 

in an electronic format a record of any change in fuel type including the following information: 

 a. Type of fuel change; and 

 b. Date and time of fuel change. 

 4. Hours of Operation - UNITS I1, I2, & I3 
Until the performance tests specified in VII.A.1 of Part B are completed, the Permittee shall 

compute and record the following information in an individual log for each unit within 5 

working days of the end of each month: 

a. Date and time in which the unit began firing liquid fuel (exclusively or in combination); 

if liquid fuel combustion began in the previous month, the record shall state the fact; 

b. The date and time in which the unit ceased to fire liquid fuel (exclusively or in 

combination); if liquid fuel combustion continues into the next month the record shall 

state that fact; 

c. The hours of operation during which liquid fuel was fired (exclusively or in combination) 

in the previous month, including consecutive hours and total hours; 

d. The hours of operation during which liquid fuel was fired (exclusively or in combination) 

in the previous 12-consecutive month period. 

 B. Stationary Rotating Machinery (including Stationary Turbines IGT1 & IGT2) 

 1. Particulate Matter 

The Permittee shall keep on record, along with the fuel firing rate, the contractual agreement 

with the liquid fuel vendor indicating the following information concerning the liquid fuel fired 

in any stationary rotating machinery: 

 a. The heating value; and 

 b. The ash content. 

The Permittee shall calculate the particulate matter emissions based on the above values for 

each applicable unit. The Permittee shall perform this calculation each time there is a change 

related to V.B.1.a or b of Part B in the contractual agreement. These calculations shall be 

maintained in a record. 

 2. Sulfur Dioxide 

 a. For units firing liquid fuels, the Permittee shall keep records of fuel supplier certifications 

including the following information: 

 i. The name of the oil supplier; 

 ii. The sulfur content and the heating content of the oil from which the shipment 

came; and 

 iii. The method used to determine the sulfur content of the oil. 

iv. Engineering calculations demonstrating compliance with II.B.2 of Part B shall be 

performed each time there is a change in (ii) above (V.B.2.a.ii of Part B). These 

calculations shall be maintained in a record. 

36 

July 13, 2010 
b. Fuel analysis shall be used to determine the sulfur content of fuel used. The Permittee 

may also use fuel sulfur content certifications that employ the following test methods: 

ASTM D 129-91 shall be used to determine the sulfur content of liquid fuels and ASTM 

D-1702-90, D 1072-80, D 3031-81, D 4084-82, or D 3246-81 shall be used for the sulfur 

content of gaseous fuels. The applicable ranges of some ASTM methods mentioned 

above are not adequate to measure the levels of sulfur in some fuel gases. Dilution of 

samples before analysis (with verification of the dilution ratio) may be used, subject to 

the approval of the Control Officer. 

 C. Auxiliary Boiler 

Except for fuels fired during startup and/or flame stabilization, the Permittee shall log in ink or in an 

electronic format a record of any change in fuel type including: 

 1. Types of fuels changed; and 

 2. Date and time of fuel change. 

D. Coal Preparation Plant 

 1. Particulate Matter 

The Permittee shall maintain and operate all air pollution control equipment in accordance with 

best modern practices. These practices shall be on file and shall be readily available for 

inspection by the Control Officer. 

 2. The Permittee shall maintain records of emissions related maintenance performed on all air 

pollution control equipment. 

E. Fly-Ash Handling Systems 

 1. Particulate Matter 

The Permittee shall maintain and operate all air pollution control equipment in accordance with 

best modern practices. These practices shall be on file and shall be readily available for 

inspection by the Control Officer. 

 2. The Permittee shall maintain records of emissions related maintenance performed on all air 

pollution control equipment. 

F. Open Areas, Roadways, & Streets 

The Permittee shall maintain records of dates and types of control measures adopted pursuant to 

II.F.1, 2, & 4 of Part B. 

VI. REPORTING REQUIREMENTS [PCC 17.12.180.A.5]

37 

July 13, 2010 
 A. Fossil Fuel Fired Steam Generators 

 1. CAM Reporting – UNIT I4 

For the purposes of permit deviation reporting under Condition XII of Attachment “A,” the 

Permittee shall include the following information required by 40 CFR part 64, §64.9(a). [40 CFR 64.7(d)] 

a. Summary information on the number, duration and cause (including unknown causes, if 

applicable) of excursions or exceedences, as applicable, and the corrective action taken. [40 CFR 64.9(a)(2)(i)]

b. Summary information on the number, duration and cause (including unknown causes, if 

applicable) for monitoring downtime incidents (other than downtime associated with zero 

and span or other daily calibration checks). [40 CFR 64.9(a)(2)(i)(ii)]

 2. Fuel Limitation – UNIT I4 

The results of the coal analyses required by IV.A.4 shall be compiled in a report to be 

submitted to the Control Officer within 30 days of the end of each quarter. Samples and/or 

analysis provided by the coal supplier may be used to satisfy this condition. [Installation Permit #1156, Condition #3] 

 B. Stationary Gas Turbines (Including Stationary Turbines IGT1 & IGT2) 

 The Permittee shall report any daily period during which the sulfur content of fuels fired in any piece 

of stationary rotating machinery exceeds 0.8 percent by weight. [PCC 17.16.340.J] 

 C. Auxiliary Boiler - Visible Emissions 

The Permittee shall report all 6-minute periods during which the visible emissions exceed 15% 

opacity. [PCC 17.16.165.I] 

 D. Special Reporting for the Affected Source or Process 

The Permittee shall promptly notify and submit written reports to the Control Officer of any instances 

of excess emissions or deviation from permit requirements. (Refer to XI.A & B of Part A). 

 E. Quarterly Reports for CEMS/COMS [PCC 17.12.180.A.5]

1. Permittee shall submit a written report of all deviations to PDEQ on January 31st, April 30th, 

July 31st, and October 31st, covering October through December, January through March, April 

through June, and July through September, respectively. The reports shall include the 

following: 

a. The magnitude of deviations computed in accordance with PCC 17.12.060, any 

conversion factor(s) used, and the date and time of commencement and completion of 

each time period of deviation. 

38 

July 13, 2010 
b. Specific identification of each period of deviation that occurs during startups, shutdowns, 

and malfunctions of the boiler. The nature and cause of any malfunction (if known) and 

the corrective action taken or preventative measures adopted shall also be reported. 

c. The date and time identifying each period during which the continuous monitoring 

system(s) were inoperative except for zero and span checks and the nature of the system 

repairs or adjustments. The Control Officer may require proof of continuous monitoring 

system performance whenever system repairs of adjustments have been made. [PCC 17.12.060.E.4]

d. When no excess emissions have occurred or the continuous monitoring systems have not 

been inoperative, repaired, or adjusted, such information shall be clearly stated in the 

report. [PCC 17.16.060.E.5 & Installation Permit #1156, Condition # 6] 

2. In addition to the requirements of the above Paragraph (VI.E.1 of this Part), the Permittee shall 

report all deviations in accordance with XI.B of Part A. 

 F. Semiannual Summary Reports of Required Monitoring [PCC 17.12.180.A.5.a] 

The Permittee shall submit a semiannual summary report of all permit deviations (including 

excursions defined in IV.A.2 (CAM) of Part B and exceedances that have occurred during the 

reporting period. Semiannual reports shall be due on January 31st and July 31st of each year and shall 

cover the period July 1st through December 31st and January 1st through June 30th, respectively. The 

first semiannual report may not cover a six-month period. 

 G. Compliance Certification Reporting [PCC 17.12.220.A.2]

Permittee shall submit an annual compliance certification to the Control Officer pursuant to VII of 

Part A. Annual compliance certification reports shall be due on February 15th of each year and shall 

cover the period January 1st through December 31st. The first annual report may not cover a 12-

month period. 

 H. Emissions Inventory Reporting [PCC 17.12.320]

Every source subject to a permit requirement shall complete and submit to the Control Officer, when 

requested, an annual emissions inventory questionnaire pursuant to 17.12.320 of the Pima County 

Code. (See VI of Part A of this permit). 

VII. TESTING REQUIREMENTS [PCC 17.12.180.A.3.a & PCC 17.20.010] 

For purposes of demonstrating compliance, these test methods shall be used, provided that for the purpose 

of establishing whether or not the facility has violated or is in violation of any provision of this permit, 

nothing in this permit shall preclude the use, including the exclusive use, of any credible evidence or 

information relevant to whether a source would have been in compliance with applicable federal 

requirements if the appropriate performance or compliance procedures or methods had been performed. 

39 

July 13, 2010 

The Permittee shall use the following EPA approved reference test methods to conduct performance tests 

for the specified pollutants when required: 
 A. Fossil Fuel Fired Steam Generators 

 1. Sulfur Dioxide – UNITS I1, I2, & I3 

The Permittee shall perform an annual performance test in accordance with EPA Reference 

Method 6 or 6C when liquid fuel is fired greater than 1300 hours in a 12 consecutive month 

period. 

 2. UNIT I4 

The Permittee shall conduct a performance test for visible emissions, particulate matter, sulfur 

dioxide, and nitrogen oxides each year within 90 days of the anniversary date of the permit, or a 

date other than the anniversary date of the permit as submitted by the Permittee and approved 

by the Control Officer or the Control Officer’s designee. The compliance test shall be 

conducted while firing coal and at the maximum normal operating load of the unit or other load 

as approved by the Control Officer. If the unit is not burning coal during the 90 days prior to 

the applicable date of the compliance test, the test shall be conducted at a later date as soon as 

practicable after the unit commences the firing of coal, but not later than 30 days after the unit 

commences the firing of coal. Performance tests shall be conducted in accordance with EPA 

Reference Method 9 for visible emissions, EPA Reference Method 5 for particulate matter, 

EPA Reference Method 6 for sulfur dioxide, and EPA Reference Method 7 for nitrogen oxides. 

 B. Stationary Rotating Machinery (Including Stationary Turbines (IGT1 & IGT2) 

 1. Sulfur Dioxide 

The Permittee shall perform an annual performance test in accordance with EPA Reference 

Method 6 or 6C when liquid fuel is fired greater than 1300 hours in a 12 consecutive month 

period. 

 2. Carbon Monoxide [A.R.S. 49-422.A.3]

The Permittee shall perform a performance test to measure the emission rate of carbon 

monoxide. This performance test shall be conducted after the twelve month rolling total hours 

of operation exceeds 4500 hours. The performance test shall be performed in accordance with 

EPA Reference Method 10. 

 C. All Operations 

Should the Permittee desire to test or be required to test to determine compliance with any applicable 

standard, the Permittee shall contact the Control Officer for appropriate test methods. 

40 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT C: APPLICABLE REGULATIONS

Requirements Specifically Identified as Applicable:

Pima County State Implementation Plan (SIP): 

 Rule 315 Roads and Streets 

 Rule 318 Vacant Lots and Open Spaces 

 Rule 321 Standards and Applicability 

 Rule 343 Visibility Limiting Standard 

Code of Federal Regulations Title 40: 

 Part 60 Subpart KKKK New Source Performance Standards for Stationary combustion Turbines 

 Part 60 Subpart GG New Source Performance Standards for Stationary combustion Turbines 

 Part 60 Appendix B Performance Specifications 

 Part 64 Compliance Assurance Monitoring 

 Part 75 Subpart F Conversion Procedures 

 Part 75 Subpart G Determination of CO Emissions 

 Part 75 Appendix A Specifications and Test Procedures 

 Part 75 Appendix B Quality Assurance and Quality Control 

ADEQ Consent Order signed February 17, 2009 

Pima County Code (PCC) Title 17, Chapter 17.16: 

 17.16.020 Noncompliance with Applicable Standards 

 17.16.030 Odor Limiting Standards 

 17.16.040 Standards and Applicability (Includes NESHAP) 

 17.16.050 Visibility Limiting Standards 

 17.16.060 Fugitive Dust Producing Activities 

 17.16.080 Vacant Lots and Open Spaces 

 17.16.090 Roads and Streets 

 17.16.100 Particulate Materials 

 17.16.110 Storage Piles 

 17.16.130 Applicability 

 17.16.160 Standards of Performance for Fossil-Fuel Fired Steam Generators and General Fuel 

Burning Equipment 

 17.16.165 Standards of Performance for Fossil-Fuel Fired Industrial and Commercial Equipment 

 17.16.310 Standards of Performance for Coal Preparation Plants 

 17.16.340 Standards of Performance for Stationary Rotating Machinery 

 17.16.430 Standards of Performance for Unclassified Sources 

Installation Permit #1156 – October 14, 1981 by Arizona Department of Health Services 

41 

July 13, 2010 
42 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT D: EQUIPMENT LIST

I. Fossil Fuel Fired Steam Generators

Equipment ID Description Capacity Serial 

Number Make 

Date of 

Manufacture, 

Installation, or 

Reconstruction 

I1 Steam Electric 

Generating Unit 81 MW Net 18589 Combustion 

Engineering 1957 

I2 Steam Electric 

Generating Unit 80 MW Net 19065 Combustion 

Engineering 1959 

I3 Steam Electric 

Generating Unit 104 MW Net 19485 Combustion 

Engineering 1961 

I4 Steam Electric 

Generating Unit 

Coal: 110 MW Net 

Gas/Oil: 156 MW 

Net 

75-19487 Foster Wheeler 1964 

II. Stationary Rotating Machinery (including Stationary Turbines) 

Equipment ID Description Capacity Serial Number Make 

Date of 

Manufacture, 

Installation, or 

Reconstruction 

IGT1 

Simple cycle gas 

turbine generating 

unit 

24 MW Net 17A2088-1 Westinghouse 1972 

IGT2 

Simple cycle gas 

turbine generating 

unit 

24.5 MW Net 17A2086-1 Westinghouse 1972 

IGT3 

Simple cycle gas 

turbine generating 

unit 

<25 MW Net To be submitted 

upon purchase 

To be submitted 

upon purchase 

To be submitted 

upon purchase 

IGT1A Gas turbine diesel 

starter engine 635 hp 772267-3 Cummings 1972 

IGT2A Gas turbine diesel 

starter engine 635 hp 769853-3 Cummings 1972 

III. Auxiliary Boiler 

Equipment ID Description Capacity Serial 

Number Make 

Date of 

Manufacture, 

Installation, or 

Reconstruction 

IAUX Auxiliary Boiler 57,000 lb/hr (steam) 23583 Babcock-Wilcox 1972 

43 

July 13, 2010 
IV. Cooling Towers 

Equipment 

ID Description Serial Number Make 

Date of Manufacture, 

Installation, or 

Reconstruction 

I1E Steam Unit Cooling Tower FD90980 Fluor Products 1957 

I2D Steam Unit Cooling Tower FD92580 Fluor Products 1959 

I3D Steam Unit Cooling Tower 663-3-10 Marley Co. 1961 

I4E Steam Unit Cooling Tower 6645-12-36-3 Marley Co. 1964 

V. Air Pollution Controls 

Equipment ID Description Serial/ Model Number Make 

I4BH Baghouse to Unit I4 Project No. 83-1364, 65, 66 American Air Filter 

A1 Flyash Silo A & B Collector 13-61-18999 Flex-Clean 100 

CTBC 98 111G 

A1A Flyash Silo A & B Vent Collector 13-94-19000 Flex-Clean 100 

WRBC-9611 

A3 Flyash Storage Tank #4 Dust 

Collector 86410H1 Mikropul Corp. 

VI. Continuous Emissions/Opacity Monitoring Systems 

Unit Pollutant/ Parameter Method Range 

Oxygen Paramagnetic 0-21% 

NOx Chemiluminesence 0-400 ppm 

Fuel Flow - Gas Differential Pressure (DP) 0-9000 hscfh 

I1 

Fuel Flow - Oil Positive Displacement (PDP) 0-50000 lb/hr 

Oxygen Paramagnetic 0-21% 

NOx Chemiluminesence 0-400 ppm 

Fuel Flow - Gas Differential Pressure (DP) 0-9000 hscfh 

I2 

Fuel Flow - Oil Positive Displacement (PDP) 0-50000 lb/hr 

Oxygen Paramagnetic 0-21% 

NOX Chemiluminesence 0-400 ppm 

Fuel Flow - Gas Differential Pressure (DP) 0-12000 hscfh 

Fuel Flow - Oil Positive Displacement (PDP) 0-75000 lb/hr 

I3 

Oxygen Paramagnetic 0-21% 

NOx Chemiluminesence 0-400 ppm 

Sulfur Dioxide U.V. Fluorescence 0-700 ppm 

Mass Flow Constant temperature anemometer thermal array 3.29 x 107 scfh 

I4 

Opacity Electro-optical, double pass 0-100% 

44 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT E: INSIGNIFICANT ACTIVITIES 

45 

Equipment 

ID Description Capacity 

Date of 

Manufacture, 

Installation, or 

Reconstruction 

A6 Power Production - Flyash Latrine Vents NA NA 

C2 Rotary Car Dumper Dust Collector RFC-1178 Carter Day 

C3 Live Coal Storage Dust Collector RFC-1179 Carter Day 

C5 Crusher Facility Dust Collector RFC-1180 Carter Day 

C6 Tower 4 Dust Collector RFC-1181 Carter Day 

C21 Power Production - Rotary Car Dumper Latrine Vent/Septic System NA NA 

C22 Power Production - Crusher Tower Latrine Vent/Septic System NA NA 

CHEM1 Power Production - North 12,000 gal 93% Sulfuric Acid Storage Tank NA NA 

CHEM2 Power Production - North 12,000 gal 50% Liquid NaOH Storage Tank NA NA 

CHEM3 Power Production - North Water Treatment Chemical Storage 

Bins/Barrels NA NA 

CHEM4 Power Production - North Cooling Tower Treatment Room NA NA 

CHEM5 Power Production - North Boiler Water Treatment Area NA NA 

CHEM6 Power Production - South 12,000 gal 93% Sulfuric Acid Storage Tank NA NA 

CHEM7 Power Production - South Water Treatment Chemical Storage 

Bins/Barrels NA NA 

CHEM8 Power Production - South Cooling Tower Treatment Room NA NA 

CHEM9 Power Production - South Boiler Water Treatment Area NA NA 

CHEM11 Power Production -Environmental Laboratory Latrine Vent/Septic 

System NA NA 

CHEM12 Power Production - Environmental Laboratory Fume Hood NA NA 

CHEM13 Power Production - Water Laboratory Fume Hood (2) NA NA 

CHEM14 Power Production –Environmental Laboratory Heater NA NA 

CHEM15 Power Production - Boiler Feedwater Storage Tanks (6) NA NA 

FH1 Fuel Oil Storage Tank #1 – Vertical Fixed Roof AST 524,072 gal 1957 

FH2 Fuel Oil Storage Tank #2 – Vertical Fixed Roof AST 524,072 gal 1958 

FH3 Fuel Oil Storage Tank #3 – Vertical Fixed Cone Roof AST 756,084 gal 1961 

FH5 Water Storage Tank #5 – Vertical Fixed Roof AST 3,034,858 gal 1971 

FH6 Fuel Oil Storage Tank #6 – Vertical Fixed Roof AST 3,034,858 gal 1971 

FH7 Fuel Oil Storage Tank #7 – Vertical Fixed Roof AST 3,034,858 gal 1971 

FH8 Fuel Oil Storage Tank #8 – Vertical Fixed Roof AST 10,612,951 gal 1972 

FH9 Fuel Oil Storage Tank #9 – Vertical Fixed Roof AST 10,612,951 gal 1972 

FH9 Power Production - Condensate Return Collection Sump Vents NA NA 

FH10 Fuel Oil Storage Tank #10 –Vertical Fixed Roof AST 10,612,951 gal 1972 

FH11 Fuel Oil Storage Tank #11 – Vertical Fixed Roof AST 3,034,858 gal 1972 

FH12 Fuel Oil Storage Tank #12 – Vertical Fixed Roof AST 3,034,858 gal 1972 

FH13 Fuel Oil Storage Tank #13 – Vertical Fixed Roof AST 3,034,858 gal 1972 

FH14 Power Production - Condensate Return Collection Sump Vents NA NA 

FH15 Power Production - Fuel Oil Unloading/Transfer/Pumping and Piping 

Facilities NA NA 

FH16 Power Production - Waste Oil Drums NA NA 

GS9 General Shop - Furnace 75 kBTU NA NA 

GS10 General Shop - Latrine Vents NA NA 

GS11 General Shop Paint Booth NA NA 

I5 Power Production - Power Block Latrine Vents NA NA 

I6 Power Production - Engineering Building Latrine Vents NA NA 

July 13, 2010 
46 

July 13, 2010 

Equipment 

ID Description 

Date of 

Manufacture, Capacity Installation, or 

Reconstruction 

I7 Power Production - Power Block Used Oil Storage Drums NA NA 

I8 Power Production - Power Block Battery Rooms NA NA 

I9 Power Production - Common Facilitites Battery Room NA NA 

I11 Power Production - Mechanical Maintenance Flammable Storage 

cabinets NA NA 

I12 Power Production - Switchyard Circuit Breakers/Transformers NA NA 

I13 Lube Oil/Paint Storage Room NA NA 

I14 Power Production - Maintenance Shop Welding Activities/Vents/ 

Solvent Tanks NA NA 

I15 Electrical Shop Solvent Tank NA NA 

I72 Power Production - #5 Fire/Dust Control Water Storage Tank 

3,000,000 gal NA NA 

I73 Power Production - Service Water Pressure/Storage Tank 150,000 

gallons NA NA 

I16-21, 

WH1-2, 

GS1-8, 

TRAN4-12 

Miscellaneous hot water and space heaters Misc. Misc. 

I1A Power Production - Unit #1 Boiler Blowdown Flashtank NA NA 

I1B Turbine lube oil vapor extractor NA NA 

I1C Generator bearing drain vapor extractor NA NA 

I1D Generator bearing drain vacuum pump NA NA 

I1F Power Production - North Turbine Lube Oil Storage Tank NA NA 

I1G Power Production - Unit #1 Fuel Gas Piping NA NA 

I1H Power Production - Unit #1 Fuel Gas Vents NA NA 

I1I Power Production - Unit #1 Boiler Safety Relief Valve Vents NA NA 

I1J Power Production - Unit #1 Steam/Drain Vents NA NA 

I1K Power Production - Unit #1 Main Transformer NA NA 

I1L Power Production - Unit #1 Auxiliary Transformer NA NA 

I2A Power Production - Unit #2 Boiler Blowdown Flashtank NA NA 

I2B Turbine lube oil vapor extractor NA NA 

I2C Generator bearing drain vapor extractor NA NA 

I2E Power Production - Unit #2 Fuel Gas Piping NA NA 

I2F Power Production - Unit #2 Fuel Gas Vents NA NA 

I2G Power Production - Unit #2 Boiler Safety Relief Valve Vents NA NA 

I2H Power Production - Unit #2 Steam/Drain Vents NA NA 

I2I Power Production - Unit #2 Main Transformer NA NA 

I2J Power Production - Unit #2 Auxiliary Transformer NA NA 

I3A Power Production - Unit #3 Boiler Blowdown Flashtank NA NA 

I3B Turbine lube oil vapor extractor NA NA 

I3C Generator bearing drain vapor extractor NA NA 

I3E Power Production - South Turbine Lube Oil Storage Tank NA NA 

I3F Power Production - Unit #3 Fuel Gas Piping NA NA 

I3G Power Production - Unit #3 Fuel Gas Vents NA NA 

I3H Power Production - Unit #3 Boiler Safety Relief Valve Vents NA NA 

I3I Power Production - Unit #3 Steam/Drain Vents NA NA 

I3J Power Production - Unit #3 Main Transformer NA NA 

I3K Power Production - Unit #3 Auxiliary Transformer NA NA 

I4A Power Production - Unit #4 Boiler Blowdown Flashtank NA NA 

I4B Turbine lube oil vapor extractor NA NA 

I4C Generator bearing drain vapor extractor – 6508-G-13 NA NA 
47 

July 13, 2010 

Equipment 

ID Description 

Date of 

Manufacture, Capacity Installation, or 

Reconstruction 

I4D Generator bearing drain vacuum pump NA NA 

I4F Power Production - Unit #4 Fuel Gas Piping NA NA 

I4G Power Production - Unit #4 Fuel Gas Vents NA NA 

I4H Power Production - Unit #4 Boiler Safety Relief Valve Vents NA NA 

I4I Power Production - Unit #4 Steam/Drain Vents NA NA 

I4J Power Production - Unit #4 Main Transformer NA NA 

I4K Power Production - Unit #4 Auxiliary Transformer NA NA 

IGT1B Turbine lube oil vapor extractor 0.5 hp/1A/230V NA 

IGT2B Turbine lube oil vapor extractor 0.5 hp/1A/230V NA 

OH1 Operating Headquarters - HVAC Cooling Tower NA NA 

OH1 ERTF Paint Booth NA NA 

OH4 Operating Headquarters - Latrine Vents NA NA 

OH5 Operating Headquarters - Training Center Latrine Vents NA NA 

OH6 Operating Headquarters - Trailer Latrine Vents NA NA 

OH73 Operating Headquarters Tool Room Solvent Tank NA NA 

SS1 Servicenter - HVAC Cooling Tower NA NA 

SS2 Servicenter - Reproduction Equipment NA NA 

SS4 Servicenter - Latrine Vents NA NA 

TRAN1 Transportation - New/Used Lubricating Oil Storage NA NA 

TRAN13 Transportation - Latrine Vents NA NA 

TRAN2 Transportation - Underground Diesel Storage 15,000 gal NA NA 

TRAN16 Transportation Steam Cleaner NA NA 

WH4 WH4 Warehouse - Latrine Vents NA NA 

WW1 Power Production - North Collection Sump-Boiler Blowdown. NA NA 

WW2 Power Production - South Collection Sump (2) - Rain Runoff, 

Ash/Coal Area Washdown NA NA 

WW3 Power Production - Bottom Ash Runoff Collection Sump NA NA 

WW4 Power Production - Plant Waste Basin-Boiler 

BlowdownDemineralizer Regenerant NA NA 

WW5 Power Production - Coal Pile Runof Basin- Rain Runoff, Ash/Coal 

Area Washdown NA NA 

WW6 Power Production - Evaporation Basin (3) - Treated Wastewater from 

Plant Waste/Coal Pile Runoff Basin NA NA 

WW7 Power Production - Waste Water Treatment Latrine Vent/Septic 

System NA NA 

WW8 WW8 Power Production - Waste Water Treatment 5,000 gal 93% 

Sulfuric Acid Tank NA NA 

WW9 Power Production - Waste Water Treatment 5,000 gal 50% Liquid 

NaOH Tank NA NA 

WW10 Power Production - Waste Water Treatment Clarifier - Wastewater 

140,000 gal NA NA 

WW11 Power Production - Waste Water Treatment Scum Tank-Clarifier 

Scum for recycle 1170 gal NA NA 

WW12 Power Production - Waste Water Treatment pH Adjustment TankPretreated Wastewater 6768 gal NA NA 

WW13 Power Production - Waste Water Treatment pH Adjustment TankTreated Wastewater 5000 gal NA NA 

WW14 Power Production - Waste Water Treatment Chemical Mix Tank (2) - 

Alum 730 gal NA NA 

WW15 Power Production - Waste Water Treatment Chemical Mix Tank (2) - 

Polymer 148 gal NA NA 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT F: PHASE II ACID RAIN PERMIT

I. STATEMENT OF BASIS 

Statutory and Regulatory Authorities: In accordance with Arizona Revised Statutes, Title 49, Chapter 3, 

Article 2, Section 426.N, and Titles IV and V of the Clean Air Act, the Pima County Department of 

Environmental Quality issues this Phase II Acid Rain Permit pursuant to Section 17.12.365 of Title 17 of 

the Pima County Code. 

II. SO2 ALLOWANCE [40 CFR Part 73 Table 2] 

1

 ALLOCATIONS AND NOX REQUIREMENTS FOR EACH AFFECTED UNIT 

 A. UNIT I1 

Year: 2005 – 2009 2010 – 

Annual SO2

allowances 16 tons 14 tons 

NOx Limits: This unit is not subject to a NOx limit under 40 CFR Part 76. 

 B. UNIT I2 

Year: 2005 – 2009 2010 – 

Annual SO2

allowances 28 tons 40 tons 

NOx Limits: This unit is not subject to a NOx limit under 40 CFR Part 76. 

 C. UNIT I3 

Year: 2005 – 2009 2010 – 

Annual SO2

allowances 0 tons 2 tons 

NOx Limits: This unit is not subject to a NOx limit under 40 CFR Part 76. 

D. UNIT I4 

Year: 2005 – 2009 2010 – 

Annual SO2

allowances 2853 tons 2805 tons 

NOx Limits: 

Pursuant to 40 CFR Part 76, the Pima County Department of Environmental Quality 

approves a NOx emission limitation for UNIT I4. This unit’s annual average NOx 

emission rate for each year, determined in accordance with 40 CFR Part 75, shall not 

exceed the applicable emission limitation, under 40 CFR Part 76.7(a)(2), of 0.46 

lb/MMBTU for wall-fired boilers. 

In addition, this unit shall comply with all other applicable requirements of 40 CFR 

Part 76, including the duty to reapply for a NOx compliance plan and requirements 

covering excess emissions. 

1. As defined under 40 CFR §72.2, “Allowance” means an authorization by the Administrator under the Acid Rain 

Program to emit up to one ton of sulfur dioxide during or after a specified calendar year. 

 

48 

July 13, 2010 
 The number of allowances actually held by an affected source in a unit account may differ from the number 

allocated by U.S. EPA. Neither of the aforementioned conditions necessitate a revision to the unit SO2

allowance allocations identified in this permit (See 40 CFR 72.84). 

III. ACID RAIN PERMIT APPLICATION 

The Permittee, and any other owners or operators of the units at this facility, shall comply with the 

requirements contained in the two attached acid rain permit applications. These applications are: 

A. Phase II Permit Application (OMB No. 2060-0258) signed by the Designated Representative on 

12/12/95. 

B. Phase II NOx Compliance Plan (OMB No. 2060-0258) signed by the Designated Representative on 

12/15/97. 

49 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT G: ALTERNATE OPERATING SCENARIO #1 

I. APPLICABILITY – 40 CFR 60 Subpart KKKK 

This alternate operating scenario #1 shall only apply to the turbine that will be identified as IGT3 upon 

purchase should the applicability date of IGT3 be subject to 40 CFR 60 Subpart KKKK. TEP-IGS shall 

notify PDEQ upon purchasing the turbine. The notification shall include all reporting requirements that are 

identified in this attachment. 

II. GENERAL PROVISIONS 

The following requirements apply to the operation, maintenance, recordkeeping and testing of Unit IGT3 

and its associated monitoring systems in accordance with 40 CFR Part 60, Subpart A – General Provisions. 

These requirements are in addition to any applicable requirements in the General Provisions in Part A of 

this permit, unless Attachment G is more stringent. 

 A. Mailing Address 

 All requests, reports, applications, submittals, and other communications to the Administrator and 

Control Officer pursuant to 40 CFR Part 60 shall be submitted in duplicate to the Administrator and 

Control Officer at the following addresses: [40 CFR §60.4(a)]

Director, Air Division Director 

U.S. Environmental Protection Agency Pima County Department of Environmental Quality 

 75 Hawthorne Street 33 North Stone Avenue, Suite 730 

 San Francisco, CA 94105 Tucson, AZ 85701 

 B. Notification and Recordkeeping 

 1. The Permittee shall furnish the Control Officer written notification as follows: [40 CFR 60.7(a)]

 a. A notification of the date of construction of Unit IGT3 is commenced postmarked no 

later than 30 days after such date (date of construction). [40 CFR 60.7(a)(1)]

 b. A notification of the actual date of initial startup of Unit IGT3 postmarked within 15 days 

of after such date (date of initial startup). [40 CFR 60.7(a)(3)]

 c. A notification of any physical or operational change to an existing facility which may 

increase the emission rate of any air pollutant to which a standard applies, unless that 

change is specifically exempted under an applicable subpart or in 40 CFR 60.14(e). This 

notice shall be postmarked 60 days or as soon as practicable before the change is 

commenced and shall include information describing the precise nature of the change, 

present and proposed emission control systems, productive capacity of the facility before 

and after the change, and the expected completion date of the change. The Control 

Officer may request additional relevant information subsequent to this notice. [40 CFR 60.7(a)(4)]

50 

July 13, 2010 
 d. A notification of the date upon which demonstration of the continuous monitoring system 

performance commences in accordance with 40 CFR 60.13(c) postmarked not less than 

30 days prior to such date. [40 CFR 60.7(a)(5)]

 e. A notification of the anticipated date for conducting the opacity observations required by 

40 CFR 60.11(e)(1). The notification shall also include, if appropriate, a request for the 

Administrator to provide a visible emissions reader during a performance test. The 

notification shall be postmarked not less than 30 days prior to such date. [40 CFR 60.7(a)(6)]

 f. A notification that continuous opacity monitoring system data results will be used to 

determine compliance with the applicable opacity standard during a performance test 

required by 40 CFR 60.8 in lieu of Method 9 observation data as allowed by 40 CFR 

60.11(e)(5). This notification shall be postmarked not less than 30 days prior to the date 

of the performance test. [40 CFR 60.7(a)(7)]

 2. The Permittee shall maintain records of the occurrence and duration of any startup, shutdown, 

or malfunction in the operation of an affected facility; any malfunction of the air pollution 

control equipment; or any periods during which a continuous monitoring system or monitoring 

device is inoperative. [40 CFR 60.7(b)]

 3. The Permittee shall submit excess emissions and monitoring systems performance reports 

and/or summary report form to the Control Officer semi-annually, except when: more frequent 

reporting is specifically required by an applicable subpart; or the Control Officer, on a case-bycase basis, determines that more frequent reporting is necessary to accurately assess the 

compliance status of the source. All reports shall be postmarked by the 30th day following the 

end of each six-month period. Written reports of excess emissions shall include the following 

information: [40 CFR 60.7(c), 40 CFR 60.4375(a), 40 CFR 60.4395 & PCC 17.12.040.B]

 a. The magnitude of excess emissions computed in accordance with 40 CFR 60.13(h), any 

conversion factor(s) used, and the date and time of commencement and completion of 

each time period of excess emissions and the process operating time during the reporting 

period. [40 CFR 60.7(c)(1)]

 b. Specific identification of each period of excess emissions that occurs during startups, 

shutdowns, and malfunctions of the affected facility. The nature and cause of any 

malfunction (if known), the corrective action taken or preventative measures adopted. [40 CFR 60.7(c)(2)]

 c. The date and time identifying each period during which the continuous monitoring 

system was inoperative except for zero and span checks and the nature of the system 

repairs or adjustments. [40 CFR 60.7(c)(3)]

 d. When no excess emissions have occurred or the continuous monitoring system(s) have 

not been inoperative, repaired, or adjusted, such information shall be stated in the report. [40 CFR 60.7(c)(4)]

 4. The summary report form submitted by the Permittee shall contain the information and be in 

the format shown in 40 CFR 60.7(d) figure 1 unless otherwise specified by the Administrator. 

One summary report form shall be submitted for each pollutant monitored at IGT3. [40 CFR 60.7(d)]

 a. If the total duration of excess emissions for the reporting period is less than 1 percent of 

the total operating time for the reporting period and CMS downtime for the reporting 

51 

July 13, 2010 
period is less than 5 percent of the total operating time for the reporting period, only the 

summary report form shall be submitted and the excess emission report described in 

II.B.3 of Attachment G need not be submitted unless requested by the Administrator. [40 CFR 60.7(d)(1)]

 b. If the total duration of excess emissions for the reporting period is 1 percent or greater of 

the total operating time for the reporting period or the total CMS downtime for the 

reporting period is 5 percent or greater of the total operating time for the reporting period, 

the summary report form and the excess emission report described in II.B.3 of 

Attachment G shall both be submitted. [40 CFR 60.7(d)(2)]

 5. The Permittee shall maintain a file of all measurements, including continuous monitoring 

system, monitoring device, and performance testing measurements; all continuous monitoring 

system performance evaluations; all continuous monitoring system or monitoring device 

calibration checks; adjustments and maintenance performed on these systems or devices; and 

all other information required in a permanent form suitable for inspection. The file shall be 

retained for at least two years following the date of such measurements, maintenance, reports, 

and records, except as follows: [40 CFR 60.7(f)]

 a. If the Permittee is required to install a continuous emissions monitoring system (CEMS) 

where the CEMS installed is automated, and where the calculated data averages do not 

exclude periods of CEMS breakdown or malfunction. An automated CEMS records and 

reduces the measured data to the form of the pollutant emission standard through the use 

of a computerized data acquisition system. In lieu of maintaining a file of all CEMS 

subhourly measurements as required in II.B.5 of Attachment G, the Permittee shall retain 

the most recent consecutive three averaging periods of subhourly measurements and a file 

that contains a hard copy of the data acquisition system algorithm used to reduce the 

measured data into the reportable form of the standard. [40 CFR 60.7(f)(1)]

 b. If the Permittee is required to install a CEMS where the measured data is manually 

reduced to obtain the reportable form of the standard, and where the calculated data 

averages do not exclude periods of CEMS breakdown or malfunction. In lieu of 

maintaining a file of all CEMS subhourly measurements as required under II.B.5 of 

Attachment G the Permittee shall retain all subhourly measurements for the most recent 

reporting period. The subhourly measurements shall be retained for 120 days from the 

date of the most recent summary or excess emission report submitted to the 

Administrator. [40 CFR 60.7(f)(2)]

 c. The Administrator or Control Officer, upon notification to the source, may require the 

Permittee to maintain all measurements as required by II.B.5 of Attachment G, if the 

Administrator or Control Officer determines these records are required to more 

accurately assess the compliance status of the affected source. [40 CFR 60.7(f)(3)]

 C. Performance Tests 

 1. Within 60 days after achieving the maximum production rate at which IGT3 will be operated, 

but not later than 180 days after initial startup of IGT3 and at such other times as may be 

required by the Control Officer under section 114 of the Act, the Permittee shall conduct 

emissions performance test(s) for NOx and SO2, and furnish the Control Officer a written report 

of the results of such performance test(s). [40 CFR 60.8(a)]

52 

July 13, 2010 
 D. Compliance with Standards and Maintenance Requirements 

 1. At all times, including periods of startup, shutdown, and malfunction, the Permittee shall, to the 

extent practicable, maintain and operate IGT3 including associated air pollution control 

equipment in a manner consistent with good air pollution control practice for minimizing 

emissions. Determination of whether acceptable operating and maintenance procedures are 

being used will be based on information available to the Control Officer which may include, 

but is not limited to, monitoring results, opacity observations, review of operating and 

maintenance procedures, and inspection of the source. [40 CFR 60.11(d)]

 2. For the purpose of submitting compliance certifications or establishing whether or not the 

Permittee has violated or is in violation of any standard in 40 CFR Part 60, nothing shall 

preclude the use, including the exclusive use, of any credible evidence or information, relevant 

to whether a source would have been in compliance with applicable requirements if the 

appropriate performance or compliance test or procedure had been performed. [40 CFR 60.11(g)] 

 E. Circumvention 

 The Permittee shall not build, erect, install, or use any article, machine, equipment or process, the use 

of which conceals an emission, which would otherwise constitute a violation of an applicable 

standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve 

compliance with opacity standard or with a standard, which is based on the concentration of a 

pollutant in the gases discharged to the atmosphere. [40 CFR 60.12]

 F. General Notification and Reporting Requirements 

The Permittee shall comply with the “General Notification and Reporting Requirements” found in 40 

CFR 60.19. [40 CFR 60.19]

III SPECIFIC CONDITIONS 

 A. Operational Limitations 

The Permittee shall not cause or allow the combustion of any fuel in Unit IGT3 other than pipeline 

quality natural gas. [PCC 17.12.190.B]

 B. Nitrogen Oxide 

 1. Emission Limitations/Standards [PCC 17.12.180.A.2] 

 a. The Permittee shall not allow the NOx concentration to exceed 25 ppm at 15 percent O2

or 1.2 pound per megawatt-hour as determined by the NOx and diluent CEMS based on a 

4-hour rolling average. [40 CFR 60.4320 Table 1, 60.4325 & 60.4380(b)(1)]

 b. The Permittee shall not allow the total combined emissions of NOx from Unit IGT3 to 

equal or exceed 40 tons per year, calculated as a 12-month rolling total. [PCC 17.12.190.B]

[Material Permit Condition]

53 

July 13, 2010 
 2. Air Pollution Control Equipment 

The Permittee must operate and maintain the stationary combustion turbine, air pollution 

control equipment, and monitoring equipment in a manner consistent with good air pollution 

control practices for minimizing NOx emissions at all times including during startup, 

shutdown, and malfunction. [40 CFR 60.4333(a)][Material Permit Condition]

 3. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180A.3, A.4 & A5] 

 a. The Permittee must install and certify each NOx diluent CEMS according to 40 CFR 60 

Appendix B, Performance Specification 2 (PS 2), except the 7-day calibration drift is 

based on unit operating days, not calendar days and the relative accuracy test audit 

(RATA) shall be performed in lb/ MMBtu basis. [40 CFR 60.4345(a)] 

[Material Permit Condition]

 b. The Permittee shall demonstrate compliance with the NOx emission limitation in 

III.B.1.a of Attachment G as follows: 

 i. Install, calibrate, maintain, and operate a continuous monitoring system (CMS) to 

monitor and record the fuel consumption and the ratio of water to fuel being fired 

in Unit IGT3 when burning a fuel that requires water injection for compliance; or [40 CFR 60.4335(a)]

 ii. Alternatively, the Permittee shall in accordance with III.E.1 of Attachment G. 

install, certify, maintain and operate a continuous emission monitoring system 

(CEMS) consisting of a NOx monitor, and a diluent gas (CO2 or O2) monitor; to 

determine the hourly NOx emission rate in parts per million (ppm) or pounds per 

million British thermal units (lb/MMBtu); and [40 CFR 60.4335(b)(1)]

 iii. If complying with the output-based standard, the Permittee shall install, calibrate, 

maintain, and operate a fuel flow meter (or flow meters) to continuously measure 

the heat input to IGT3; and [40 CFR 60.4335(b)(2)]

 iv. If complying with the output-based standard, the Permittee shall install, calibrate, 

maintain, and operate a watt meter (or meters) to continuously measure the gross 

electrical output of IGT3 in megawatt hours. [40 CFR 60.4335(b)(3)]

 c. The Permittee shall install, calibrate, maintain and operate each watt meter, steam flow 

meter and each pressure or temperature measurement device according to manufacturer’s 

instructions. [40 CFR 60.4345(d)]

 d. Annual NOx Emission Limit 

To demonstrate compliance with the annual NOx emission limit in III.B.1.b of 

Attachment G, the Permittee shall comply with the continuous emission system 

monitoring, recordkeeping and reporting provisions in III.E.2 of Attachment G. 

 4. Performance Testing [PCC 17.12.180.A.3] 

 a. The Permittee shall perform the initial performance test as required by 40 CFR 60.8: 

54 

July 13, 2010 
 [40 CFR 60.4405]

 b. The Permittee shall conduct annual performance tests (no more than 14 calendar months 

following the previous performance test). [40 CFR 60.4400(a)] 

 c. The Permittee shall use EPA Method 7E or EPA Method 20 for III.B.1.a of Attachment 

G. For units complying with the output based standard, the Permittee shall concurrently 

measure the stack gas flow rate using EPA Methods 1 and 2, and measure and record the 

electrical and thermal output from IGT3. Then, use the following equation to calculate 

the NOx emission rate: 

 E = 1.194 × 10−7 ∗ (NOx )c ∗ Qstd where: (Eq. 5) 

 P 

E = NOx emission rate, in lb/MWh 

1.194 x 10-7 = conversion constant, in lb/ dscf-ppm 

(NOx)c = average NOx concentration for the run, in ppm 

Qstd = stack gas volumetric flow rate, in dscf/ hr 

P = gross electrical and mechanical energy output of the combustion 

turbine, in MW (for simple-cycle operation), for combined-cycle 

operation, the sum of all electrical and mechanical output from the 

combustion and steam turbines, or, for combined heat and power 

operation, the sum of all electrical and mechanical output from the 

combustion and steam turbines plus all useful recovered thermal 

output not used for additional electric or mechanical generation, in 

MW, calculated according to 40 CFR 60.4350(f)(2). 

 d. The Permittee shall conduct NOx emission performance test in accordance with 40 CFR 

60.4400 or 40 CFR 60.4405. 

 C. Sulfur Dioxide 

 1. Emission Limitations/Standards 

 a. The Permittee shall not burn in Unit IGT3, any fuel that contains sulfur in excess of 0.060 

pounds SO2 per million British thermal unit (lb of SO2/MMBtu) heat input. [40 CFR 60.4365][PCC 17.12.190.B] 

[Material Permit Condition] 

 b. The Permittee shall not allow the total combined emissions of SO2 from Unit IGT3 to 

equal or exceed 40 tons per year, calculated as a 12-month rolling total. [PCC 17.12.190.B]

[Material Permit Condition]

 2. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180A.3, A.4 & A5] 

 a. The Permittee shall be exempted from monitoring the total sulfur content of fuel 

combusted in IGT3, by keeping readily available for inspection, a paper or electronic 

record of a current, valid purchase contract, tariff sheet or transportation contract for the 

fuel, specifying that the maximum total sulfur content for natural gas use is 20 grains of 

sulfur or less per 100 standard cubic feet and has potential sulfur emissions of less than 

less than 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. [40 CFR §60.4365(a)]

55 

July 13, 2010 
 b. To demonstrate compliance with III.C.1.b of Attachment G, the Permittee shall comply 

with the continuous emission monitoring, recordkeeping, and reporting requirements in 

III.E.2 of Attachment G. 

 D. Carbon Monoxide 

 1. Emission Limitations/Standards 

The Permittee shall not allow the total combined emissions of carbon monoxide (CO) from 

IGT3 to equal or exceed 100 tons per year, calculated as a 12-month rolling total. [PCC 17.12.190.B]

[Material Permit Condition]

 2. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180.A.3, A.4 & A.5] 

 a. The Permittee shall install, calibrate, maintain and operate and quality-assure a 

Continuous Emission Monitoring System (CEMS) consisting of CO and O2 or CO2 

monitors for measuring CO emissions and diluent from IGT3. 

 [Material Permit Condition]

 b. The Permittee shall install, calibrate, maintain and operate the in-line fuel flowmeter 

monitoring systems for determining the natural gas input rate to IGT3 for each operating 

hour according to the manufacturer’s instructions. [40 CFR 60.4345(c)] 

 [Material Permit Condition]

 c. To demonstrate compliance with the annual CO emission limit in III.D.1 of Attachment 

G, the Permittee shall comply with the CEMS monitoring, recordkeeping, and reporting 

requirements in Condition III.E.2 of Attachment G.

 E. Continuous Emissions Monitoring Systems (CEMS) [40 CFR §60.13, PCC 17.12.050.H.3]

 1. New Source Performance Standards for Continuous Emission Monitoring Systems 

To demonstrate compliance with III.B.1.a of Attachment G the Permittee shall install, calibrate, 

maintain, and operate a continuous emission monitoring system (CEMS) and data acquisition 

handling system (DAHS) to calculate a four hour rolling average NOx emission rate. 

 a. The Permittee shall comply with the following requirements in the General Provisions of 

40 CFR 60 for each CEMS unit installed: 

 i. The CEMS and DAHS monitoring and recording devices shall be installed and 

operational prior to conducting initial performance test. Verification of operational 

status shall, as a minimum, include completion of the manufacturer's written 

requirements or recommendations for installation, operation, and calibration of the 

device. [40 CFR 60.13 (b)]

ii. The Permittee shall automatically check the zero (or low level value between 0 and 

20 percent of span value) and span (50 to 100 percent of span value) calibration 

drifts at least once daily in accordance with a written procedure. The zero and span 

must, as a minimum, be adjusted whenever either the 24-hour zero drift or the 24-

hour span drift exceeds two times the limit of the applicable performance 

56 

July 13, 2010 
specification in 40 CFR, Part 60, appendix B. The system must allow the amount of 

the excess zero and span drift to be recorded and quantified whenever specified. [40 CFR 60.13 (d)(1)]

 iii. Except for system breakdowns, repairs, calibration checks, and zero and span 

adjustments required under II.B.5 of Attachment G, the CEMS shall be in 

continuous operation and shall complete a minimum of one cycle of operation 

(sampling, analyzing, and data recording) for each successive 15-minute period. [40 CFR 60.13 (e) & (e)(2)] 

 iv. The CEMS devices shall be installed such that representative measurements of 

emissions or process parameters from the affected facility are obtained. Additional 

procedures for location of continuous monitoring systems contained in the 

applicable Performance Specifications of appendix B of 40 CFR 60 (III.E.1.b of 

Attachment G) shall be used. [40 CFR 60.13 (f)]

 v. The Permittee shall reduce all data to 1-hour averages as defined in 40 CFR 60.2. 

1-hour averages shall be computed from four or more data points equally spaced 

over each 1-hour period. Data recorded during periods of continuous system 

breakdown, repair, calibration checks, and zero and span adjustments shall not be 

included in the data averages computed under III.E.1.a.v of Attachment G. The 

data may be recorded in reduced or non-reduced form (e.g., ppm pollutant and 

percent O2 or ng/J of pollutant). All excess emissions shall be converted into units 

of the standard. After conversion into units of the standard, the data may be 

rounded to the same number of significant digits as used to specify the emission 

limit. [40 CFR 60.13 (h)]

 vi. The Permittee shall meet the notification and recordkeeping requirements in 

II.B.1.d and II.B.5 of Attachment G. 

 b. The Permittee shall comply with the following requirements in the Performance 

Specifications of 40 CFR 60 Appendix B, for each CEMS unit installed: 

i. The CEMS installation and measurement location specification shall be in 

accordance with the methods and procedures in 40 CFR Part 60, Appendix B, 

Specification 2, Sections 2 & 8.1. 

ii. Pretest preparation shall be in accordance with the methods and procedures in 40 

CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.2. 

iii. Calibration drift test procedure shall be in accordance with the methods and 

procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.3. 

iv. Relative accuracy test procedure shall be in accordance with the methods and 

procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.4. 

v. Reporting requirements shall be in accordance with the methods and procedures in 

40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.5. 

vi. Analytical procedures shall be in accordance with the methods and procedures in 

40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 11.0. 

57 

July 13, 2010 
vii. Calculation and data analysis shall be in accordance with the methods and 

procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 12.0. 

viii. Method performance shall be in accordance with the methods and procedures in 40 

CFR Part 60, Appendix B, Specification 2, Sections 2 & 13.0. 

ix. Alternative Procedures shall be in accordance with the methods and procedures in 

40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 16.0. 

 x. References are located in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 

& 17.0. 

xi. Tables, Diagrams, Flowcharts, and Validation data necessary for NOx CEMS 

testing are located in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 

18.0. 

xii. Specifications and test procedures for O2 and CO2 CEMS in Stationary Systems 

shall be in accordance with the methods and procedures in 40 CFR Part 60, 

Appendix B, Specification 3. 

 xiii. Specifications and Test Procedures for CO CEMS in Stationary Sources shall be in 

accordance with the methods and procedures in 40 CFR Part 60, Appendix B, 

Specification 4. 

 c. The Permittee shall maintain and operate each CEMS unit in accordance with the 

following: 

 i. As specified in III.E.1.a.iii of Attachment G, during each full unit operating hour, 

both the NOx monitor and the diluent monitor must complete a minimum of one 

cycle of operation (sampling, analyzing, and data recording) for each 15-minute 

quadrant of the hour, to validate the hour. For partial unit operating hours, at least 

one valid data point shall be obtained with each monitor for each quadrant of the 

hour in which a unit operates. For unit operating hours in which required quality 

assurance and maintenance activities are performed on the CEMS, a minimum of 

two valid data points (one in each of two quadrants) are required for each monitor 

to validate the NOx emission rate for the hour. [40 CFR 60.4345(b)]

 ii. All CEMS data must be reduced to hourly averages as specified III.E.1.a.v of 

Attachment G. [40 CFR 60.4350(a)]

 iii. For each unit operating hour in which a valid hourly average, as described in 

III.E.1.c.i of Attachment G, is obtained for both NOx and diluent monitors, the 

DAHS must calculate and record the hourly NOx emission rate in units of ppm or 

lb/ MMBtu, using the appropriate equation from method 19 in appendix A of this 

part. For any hour in which the hourly average O2 concentration exceeds 19.0 

percent O2 (or the hourly average CO2 concentration is less than 1.0 percent CO2), 

a diluent cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be 

used in the emission calculations. [40 CFR 60.4350(b)]

 iv. Correction of measured NOx concentrations to 15 percent O2 is not allowed. [40 CFR 60.4350(c)]

58 

July 13, 2010 
 v. The Permittee shall reduce all required fuel flow rate, steam flow rate, temperature, 

pressure, and megawatt data to hourly averages. [40 CFR 60.4350(e)]

 vi. The Permittee shall calculate the hourly average NOx emission rates, in units of 

either ppm (parts per million) for units complying with the concentration limit or in 

pounds per megawatt hour (lb/MWh) for units complying with the output based 

standard by using the simple cycle operation equation below: [40 CFR 60.4350(f)] 

E = (NOx)h * (HI)h where: (Equation 1) 

 P 

E = hourly NOx emission rate, in lb/MWh. 

(NOx)h = hourly NOx emission rate, in lb/MMBtu. 

(HI)h = hourly heat input rate to the unit, in MMBtu/h, measured using the 

fuel flow meter(s), e.g., calculated using Equation D-15a in 

appendix D to 40 CFR Part 75. 

P = gross energy output of the combustion turbine in MW. 

 vii. The Permittee shall develop and keep on-site a quality assurance (QA) plan for all 

of the continuous monitoring equipment described in III.B.3.a, III.D.2.b and 

III.B.3.c. [40 CFR 60.4345(e)]

 2. Monitoring, Recordkeeping, and Reporting Requirements for Annual NOx, SO2, and CO 

Emission Limits [PCC 17.12.180.A.3, A.4 & A.5]

 a. For the purpose of compliance demonstration with annual NOx, and CO emission limits, 

the Permittee shall utilize the NOx, CO, diluent CEMS on Unit IGT3 in conjunction with 

the Data Acquisition and Handling System (DAHS) and fuel flow rate monitoring 

systems. A default value for SO2 concentration will be calculated using equation 3 below. 

The DAHS will calculate emissions of NOx, SO2 and CO in pounds per hour (lb/hr), tons 

per month, and tons per year, calculated monthly as a 12-month rolling total. The 

Permittee shall use the procedures in Method 19 of 40 CFR 60 Appendix A as applicable 

to calculate NOx, and CO mass emission rates. 

 b. The Permittee shall calculate SO2 mass emission rates for Unit IGT3 using Equation 3 

and 3A below: 

 ER = (2.0 / 7000) x 106

 x (Stotal / GCV) where: (Equation 3) 

 ER = Default SO2 emission rate for natural gas combustion, lb/mmBtu 

 Stotal = Total sulfur content of the natural gas from a valid purchase agreement, 

 tariff agreement, or sampling, gr/100 scf 

 GCV = Gross calorific value of the natural gas from a valid purchase agreement, 

 tariff agreement, or sampling, Btu/100 scf 

 7,000 = Conversion of grains/100 scf to lb/100 scf 

 106 = Conversion factor (Btu/mmBtu) 

SO2 rate = ER x HI rate where: (Equation 3A) 

SO2 rate = Hourly mass emission rate of SO2, lb/hr 

ER = SO2 default emission rate of 0.06 lbs/MMBtu 

HI rate = Hourly heat input rate, MMBtu/hr

59 

July 13, 2010 
 c. A period of monitor downtime shall be any unit operating hour in which sufficient data 

are not obtained to validate the hour, for NOx, CO, and diluent concentration or heat 

input rate. 

 d. During CEMS system downtime, the Permittee shall implement the missing data 

procedures for NOx and CO shown in 40 CFR Part 75 Subpart D – Missing Data 

Substitution Procedures 

 e. Each calendar month during which the combined 12-month rolling total for the NOx, 

emission rate from Unit IGT3 exceeds 40 tons shall constitute an exceedance. 

Exceedances shall be reported to the Control Officer in accordance with XI.A of Part A. 

 f. Each calendar month during which the combined 12-month rolling total for the SO2, 

emission rate from Unit IGT3, exceeds 40 tons shall constitute an exceedance. 

Exceedances shall be reported to the Control Officer in accordance with XI.A of Part A. 

 g. Each calendar month during which the combined 12-month rolling total for the CO 

emission rate from Unit IGT3, exceeds 100 tons shall constitute an exceedance. 

Exceedances shall be reported to the Control Officer in accordance with XI.A of Part A. 

 h. Each individual day and 12-month rolling total for NOx, SO2, and CO emission rates in 

the reporting period shall be included in the semiannual compliance certification required 

by VII of Part A. 

 i. Quality Assurance Requirements for Natural Gas Fuel Flow meters 

 i. Each transmitter or transducer shall be calibrated by equipment that has a current 

certificate of traceability to NIST standards at least once every four calendar 

quarters in which a unit operated on natural gas for 168 hours or more during each 

quarter but not less than once every three years. The Permittee shall check the 

calibration of each transmitter or transducer by comparing its readings to that of the 

NIST traceable equipment at least once at the following levels: the zero-level, and 

at least two other upscale levels (e.g., “mid” and “high”), such that the full range of 

transmitter or transducer readings corresponding to normal unit operation is 

represented. 

 ii. The Permittee shall calculate the accuracy of each transmitter or transducer at each 

level tested, using the following equation: 

×100 − = FS

TR

ACC where: 

ACC = Accuracy of the transmitter or transducer as a percentage of fullscale. 

R = Reading of the NIST traceable reference value (in milliamperes, 

inches of 

 water, psi, or degrees). 

T = Reading of the transmitter or transducer being tested (in 

 milliamperes, inches of water, psi, or degrees, consistent with the 

 units of measure of the NIST traceable reference value). 

FS = Full-scale range of the transmitter or transducer being tested 

60 

July 13, 2010 
 (in milliamperes, inches of water, psi, or degrees, consistent with 

 the units of measure of the NIST traceable reference value).

 iii. If each transmitter or transducer meets an accuracy of ± 1.0 percent of its full-scale 

range at each level tested, the fuel flow meter accuracy of 2.0 percent is considered 

to be met at all levels. If however, one or more of the transmitters or transducers 

does not meet an accuracy of ± 1.0 percent of full-scale at a particular level, then 

the Permittee may demonstrate that the fuel flow meter meets the total accuracy 

specification of 2.0 percent at that level by using one of the following alternative 

methods. If, at a particular level, the sum of the individual accuracies of the three 

transducers is less than or equal to 4.0 percent, the fuel flow meter accuracy 

specification of 2.0 percent is considered to be met for that level. Or, if at a 

particular level, the total fuel flow meter accuracy is 2.0 percent or less, when 

calculated in accordance with Part 1 of American Gas Association Report No. 3, 

General Equations and Uncertainty Guidelines, the flow meter accuracy 

requirement is considered to be met for that level. 

 iv. If during a transmitter or transducer accuracy test the flow meter accuracy 

specification of 2.0 percent is not met at any of the levels tested, the Permittee shall 

repair or replace the transmitter(s) or transducer(s) as necessary until the flow 

meter accuracy specification has been achieved at all levels. (Note that only 

transmitters or transducers which are repaired or replaced need to be re-tested; 

however, the re-testing is required at all three measurement levels to ensure that the 

flow meter accuracy specification is met at each level). 

 v. For orifice-, nozzles, and venturi type flow meters, the Permittee shall perform a 

primary element inspection for damage and corrosion at least once every 12 

calendar quarters in which a unit operated on natural gas for 168 hours or more 

during each quarter but not less than once during the term of this permit. If damage 

and/or corrosion are found, the Permittee shall replace the flow meter or restore the 

damaged or corroded flow meter to “as new” condition. 

 vi. The Permittee shall log in ink, or in an electronic format the date that the 

calibration and inspection was conducted, the results of the calibration or 

inspection, and corrective action taken if needed. 

61 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT H: ALTERNATE OPERATING SCENARIO #2 

I. APPLICABILITY – 40 CFR 60 Subpart GG 

This alternate operating scenario #2 shall only apply to the turbine that will be identified as IGT3 upon 

purchase should the applicability date of IGT3 be subject to 40 CFR 60 Subpart GG. TEP-IGS shall notify 

PDEQ upon purchasing the turbine. The notification shall include all reporting requirements that are 

identified in this attachment. 

II. GENERAL PROVISIONS 

The following requirements apply to the operation, maintenance, recordkeeping and testing of Unit IGT3 

and its associated monitoring systems in accordance with 40 CFR Part 60, Subpart A – General Provisions. 

These requirements are in addition to any applicable requirements in the General Provisions in Part A of 

this permit, unless Attachment H is more stringent. 

 A. Mailing Address 

 All requests, reports, applications, submittals, and other communications to the Administrator and 

Control Officer pursuant to 40 CFR Part 60 shall be submitted in duplicate to the Administrator and 

Control Officer at the following addresses: [40 CFR §60.4(a)]

Director, Air Division Director 

U.S. Environmental Protection Agency Pima County Department of Environmental Quality 

 75 Hawthorne Street 33 North Stone Avenue, Suite 700 

 San Francisco, CA 94105 Tucson, AZ 85701 

 B. Notification and Recordkeeping 

 1. The Permittee shall furnish the Control Officer written notification as follows: [40 CFR 60.7(a)]

 a. A notification of the date of construction of Unit IGT3 is commenced postmarked no 

later than 30 days after such date (date of construction). [40 CFR 60.7(a)(1)]

 b. A notification of the actual date of initial startup of Unit IGT3 postmarked within 15 days 

of after such date (date of initial startup). [40 CFR 60.7(a)(3)]

 c. A notification of any physical or operational change to an existing facility which may 

increase the emission rate of any air pollutant to which a standard applies, unless that 

change is specifically exempted under an applicable subpart or in 40 CFR 60.14(e). This 

notice shall be postmarked 60 days or as soon as practicable before the change is 

commenced and shall include information describing the precise nature of the change, 

present and proposed emission control systems, productive capacity of the facility before 

and after the change, and the expected completion date of the change. The Control 

Officer may request additional relevant information subsequent to this notice. [40 CFR 60.7(a)(4)]

62 

July 13, 2010 
 d. A notification of the date upon which demonstration of the continuous monitoring system 

performance commences in accordance with 40 CFR 60.13(c) postmarked not less than 

30 days prior to such date. [40 CFR 60.7(a)(5)]

 e. A notification of the anticipated date for conducting the opacity observations required by 

40 CFR 60.11(e)(1). The notification shall also include, if appropriate, a request for the 

Administrator to provide a visible emissions reader during a performance test. The 

notification shall be postmarked not less than 30 days prior to such date. [40 CFR 60.7(a)(6)]

 f. A notification that continuous opacity monitoring system data results will be used to 

determine compliance with the applicable opacity standard during a performance test 

required by 40 CFR 60.8 in lieu of Method 9 observation data as allowed by 40 CFR 

60.11(e)(5). This notification shall be postmarked not less than 30 days prior to the date 

of the performance test. [40 CFR 60.7(a)(7)]

 2. The Permittee shall maintain records of the occurrence and duration of any startup, shutdown, 

or malfunction in the operation of an affected facility; any malfunction of the air pollution 

control equipment; or any periods during which a continuous monitoring system or monitoring 

device is inoperative. [40 CFR 60.7(b)]

 3. The Permittee shall submit excess emissions and monitoring systems performance reports 

and/or summary report form to the Control Officer semi-annually, except when: more frequent 

reporting is specifically required by an applicable subpart; or the Control Officer, on a case-bycase basis, determines that more frequent reporting is necessary to accurately assess the 

compliance status of the source. All reports shall be postmarked by the 30th day following the 

end of each six-month period. Written reports of excess emissions shall include the following 

information: [40 CFR 60.7(c) & PCC 17.12.040.B]

 a. The magnitude of excess emissions computed in accordance with 40 CFR 60.13(h), any 

conversion factor(s) used, and the date and time of commencement and completion of 

each time period of excess emissions and the process operating time during the reporting 

period. [40 CFR 60.7(c)(1)]

 b. Specific identification of each period of excess emissions that occurs during startups, 

shutdowns, and malfunctions of the affected facility. The nature and cause of any 

malfunction (if known), the corrective action taken or preventative measures adopted. [40 CFR 60.7(c)(2)]

 c. The date and time identifying each period during which the continuous monitoring 

system was inoperative except for zero and span checks and the nature of the system 

repairs or adjustments. [40 CFR 60.7(c)(3)]

 d. When no excess emissions have occurred or the continuous monitoring system(s) have 

not been inoperative, repaired, or adjusted, such information shall be stated in the report. [40 CFR 60.7(c)(4)]

 4. The summary report form submitted by the Permittee shall contain the information and be in 

the format shown in 40 CFR 60.7(d) figure 1 unless otherwise specified by the Administrator. 

One summary report form shall be submitted for each pollutant monitored at IGT3. [40 CFR 60.7(d)]

 a. If the total duration of excess emissions for the reporting period is less than 1 percent of 

the total operating time for the reporting period and CMS downtime for the reporting 

63 

July 13, 2010 
period is less than 5 percent of the total operating time for the reporting period, only the 

summary report form shall be submitted and the excess emission report described in 

II.B.3 of Attachment H need not be submitted unless requested by the Administrator. [40 CFR 60.7(d)(1)]

 b. If the total duration of excess emissions for the reporting period is 1 percent or greater of 

the total operating time for the reporting period or the total CMS downtime for the 

reporting period is 5 percent or greater of the total operating time for the reporting period, 

the summary report form and the excess emission report described in II.B.3 of 

Attachment H shall both be submitted. [40 CFR 60.7(d)(2)]

 5. The Permittee shall maintain a file of all measurements, including continuous monitoring 

system, monitoring device, and performance testing measurements; all continuous monitoring 

system performance evaluations; all continuous monitoring system or monitoring device 

calibration checks; adjustments and maintenance performed on these systems or devices; and 

all other information required in a permanent form suitable for inspection. The file shall be 

retained for at least two years following the date of such measurements, maintenance, reports, 

and records, except as follows: [40 CFR 60.7(f)]

 a. If the Permittee is required to install a continuous emissions monitoring system (CEMS) 

where the CEMS installed is automated, and where the calculated data averages do not 

exclude periods of CEMS breakdown or malfunction. An automated CEMS records and 

reduces the measured data to the form of the pollutant emission standard through the use 

of a computerized data acquisition system. In lieu of maintaining a file of all CEMS 

subhourly measurements as required in II.B.5 of Attachment H, the Permittee shall retain 

the most recent consecutive three averaging periods of subhourly measurements and a file 

that contains a hard copy of the data acquisition system algorithm used to reduce the 

measured data into the reportable form of the standard. [40 CFR 60.7(f)(1)]

 b. If the Permittee is required to install a CEMS where the measured data is manually 

reduced to obtain the reportable form of the standard, and where the calculated data 

averages do not exclude periods of CEMS breakdown or malfunction. In lieu of 

maintaining a file of all CEMS subhourly measurements as required under II.B.5 of 

Attachment H the Permittee shall retain all subhourly measurements for the most recent 

reporting period. The subhourly measurements shall be retained for 120 days from the 

date of the most recent summary or excess emission report submitted to the 

Administrator. [40 CFR 60.7(f)(2)]

 c. The Administrator or Control Officer, upon notification to the source, may require the 

Permittee to maintain all measurements as required by II.B.5 of Attachment H, if the 

Administrator or Control Officer determines these records are required to more 

accurately assess the compliance status of the affected source. [40 CFR 60.7(f)(3)]

 C. Performance Tests 

 Within 60 days after achieving the maximum production rate at which IGT3 will be operated, but not 

later than 180 days after initial startup of IGT3 and at such other times as may be required by the 

Control Officer under section 114 of the Act, the Permittee shall conduct emissions performance 

test(s) for NOx and SO2, and furnish the Control Officer a written report of the results of such 

performance test(s). [40 CFR 60.8(a)]

64 

July 13, 2010 
 D. Compliance with Standards and Maintenance Requirements 

 1. At all times, including periods of startup, shutdown, and malfunction, the Permittee shall, to the 

extent practicable, maintain and operate IGT3 including associated air pollution control 

equipment in a manner consistent with good air pollution control practice for minimizing 

emissions. Determination of whether acceptable operating and maintenance procedures are 

being used will be based on information available to the Control Officer which may include, 

but is not limited to, monitoring results, opacity observations, review of operating and 

maintenance procedures, and inspection of the source. [40 CFR 60.11(d)]

 2. For the purpose of submitting compliance certifications or establishing whether or not the 

Permittee has violated or is in violation of any standard in 40 CFR Part 60, nothing shall 

preclude the use, including the exclusive use, of any credible evidence or information, relevant 

to whether a source would have been in compliance with applicable requirements if the 

appropriate performance or compliance test or procedure had been performed. [40 CFR 60.11(g)] 

 E. Circumvention 

 The Permittee shall not build, erect, install, or use any article, machine, equipment or process, the use 

of which conceals an emission, which would otherwise constitute a violation of an applicable 

standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve 

compliance with opacity standard or with a standard, which is based on the concentration of a 

pollutant in the gases discharged to the atmosphere. [40 CFR 60.12]

 F. General Notification and Reporting Requirements 

The Permittee shall comply with the “General Notification and Reporting Requirements” found in 40 

CFR 60.19. [40 CFR 60.19]

III SPECIFIC CONDITIONS 

 A. Operational Limitations 

The Permittee shall not cause or allow the combustion of any fuel in Unit IGT3 other than pipeline 

quality natural gas. [PCC 17.12.190.B]

 B. Nitrogen Oxide 

 1. Emission Limitations/Standards [PCC 17.12.180.A.2] 

a. On and after the date of the performance test required by II.C of Attachment H is 

completed, the Permittee shall not cause to be discharged into the atmosphere from Unit 

IGT3) any gases which contain nitrogen oxides (NOx) in excess of: [40 CFR 60.332(a)(1) & 60.332(b)] 

 [Material Permit Condition]

65 

July 13, 2010 
F

Y

STD = +

)4.14( 0075.0

 where: 

STD = allowable ISO corrected (if required as given in 40 CFR 60.335(b)(1)) NOx

emission concentration (percent by volume at 15 percent oxygen and on a 

dry basis), 

 Y = manufacturer's rated heat rate at manufacturer's rated load (kilojoules per 

watt hour) or, actual measured heat rate based on lower heating value of fuel 

as measured at actual peak load for the facility. The value of Y shall not 

exceed 14.4 kilojoules per watt hour, and 

 F = NOx emission allowance for fuel-bound nitrogen = 0. 

 For Gas Turbine Units IGT3, STD = 75 ppmv at 15% oxygen 

 b. The Permittee shall not allow the total combined emissions of nitrogen oxides from Unit 

IGT3 to equal or exceed 40 tons per year, calculated as a 12-month rolling total. [PCC 17.12.190.B]

 [Material Permit Condition]

 2. Air Pollution Control Equipment 

At all times, including during startup, shutdown, and malfunction, the Permittee shall, to the 

extent practicable, maintain and operate Unit IGT3 including associated air pollution control 

equipment and monitoring equipment in a manner consistent with good air pollution control 

practices for minimizing NOx emissions. [40 CFR 60.11(d)][PCC 17.12.180.A.2] 

 [Material Permit Condition]

 3. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180A.3, A.4 & A5]

 a. The Permittee shall install, certify, maintain, operate and quality-assure Continuous 

Emission Monitoring Systems (CEMS) consisting of NOx and O2 (or CO2) monitors for 

measuring NOx emissions from Gas Turbine Unit IGT3. [PCC 17.12.180.A.2]

 [Material Permit Condition] 

 b. The Permittee shall install, calibrate, maintain, and operate fuel flow rate monitoring 

systems for determining the natural gas input rate to gas turbine unit IGT3 for each 

operating hour. The fuel flow rate monitoring system shall be calibrated and qualityassured in accordance with III.E.2.i of Attachment H. [PCC 17.12.180.A.2]

 [Material Permit Condition]

 c. New Source Performance Standards (NSPS) Provisions 

 The Permittee shall comply with the following requirements contained in 40 CFR Part 60 

Subpart GG as amended on July 8, 2004. 

 i. The Permittee shall comply with the NOx emission limitation in III.B.1.a.of 

Attachment H by using one of the following methods: 

 (A) Install, calibrate, maintain and operate a continuous monitoring system to 

monitor and record the fuel consumption and the ratio of water to fuel being 

fired in Unit IGT3. [40 CFR 60.334(a)]

66 

July 13, 2010 
 (B) Utilize the CEMS required by III.B.3.a of Attachment H and demonstrate 

compliance in accordance with III.B.3.c.iii of Attachment H. [40 CFR 60.334(d)] 

 ii. If the Permittee elects to demonstrate compliance with III.B.1.a. of Attachment H 

by continuously monitoring the water to fuel ratio as provided by III.B.3.c.i.(A) of 

Attachment H, the following requirements shall apply: 

 (A) The water to fuel ratio in III.B.3.c.i.(A) of Attachment H shall be monitored 

during the performance test required under 40 CFR 60.8 to establish 

acceptable values and ranges. The Permittee may supplement the 

performance test data with engineering analyses, design specifications, 

manufacturer's recommendations and other relevant information to define the 

acceptable parametric ranges more precisely. The Permittee shall develop 

and keep on-site a parameter monitoring plan which explains the procedures 

used to document proper operation of the NOx emission controls. The plan 

shall include the parameter(s) monitored and the acceptable range(s). Any 

supplemental data such as engineering analyses, design specifications, 

manufacturer’s recommendations and other relevant information shall be 

included in the monitoring plan. [40 CFR 60.334(g)]

 (B) The Permittee shall submit reports of excess emissions and monitor 

downtime, in accordance with 40 CFR 60.7(c). Excess emissions shall be 

reported for all periods of Unit IGT3 operation, including startup, shutdown 

and malfunction. Excess emissions and monitor downtime that shall be 

reported are defined as follows: [40 CFR 60.334(j) & (j)(1)(i)] 

 (1) An excess emission shall be any unit operating hour for which the 

average water to fuel ratio, as measured by the continuous monitoring 

system, falls below the acceptable water to fuel ratio needed to 

demonstrate compliance with III.B.1.a. of Attachment H, as established 

during the performance test required in 40 CFR 60.8. Any unit 

operating hour in which no water is injected into the turbine shall also 

be considered an excess emission. 

 (2) A period of monitor downtime shall be any unit operating hour in 

which water is injected into the turbine, but the essential parametric 

data needed to determine the water to fuel ratio are unavailable or 

invalid. 

 (3) Each report shall include the average water to fuel ratio, average fuel 

consumption, ambient conditions (temperature, pressure, and humidity) 

and gas turbine load. The Permittee is not required to report ambient 

conditions if opting to use the worst case ISO correction factor as 

specified in 40 CFR 60.334(b)(3)(ii). 

 iii. If the Permittee elects to demonstrate compliance with III.B.1.a. of Attachment H 

using CEMS as provided by III.B.3.c.(i)(B) of Attachment H, the following 

requirements shall apply:

 (A) The NOx and diluent CEMS shall be installed, certified, maintained and 

operated as follows: 

67 

July 13, 2010 
 (1) Each CEMS must be installed and certified according to Performance 

Specification 2 and 3 (for diluent) of 40 CFR Part 60, Appendix B, 

except the 7-day calibration drift is based on unit operating days, not 

calendar days. [40 CFR 60.334(b)(1)]

 (2) The NOx and diluent CEMS on Unit IGT3 shall be installed and 

operational prior to conducting performance tests as required by III.B.4 

of Attachment H. [40 CFR 60.13(b)]

 (3) During each full unit operating hour, each monitor must complete a 

minimum of one cycle of operation (sampling, analyzing, and data 

recording) for each 15-minute quadrant of the hour, to validate the 

hour. For partial unit operating hours, at least one valid data point 

must be obtained for each quadrant of the hour in which the unit 

operates. For unit operating hours in which required quality assurance 

and maintenance activities are performed on the CEMS, a minimum of 

two valid data points (one in each of two quadrants) are required to 

validate the hour. [40 CFR 60.334(b)(2)]

 (4) For the purpose of identifying excess emissions, CEMS data must be 

reduced to hourly averages as specified in 40 CFR 60.13(h). [40 CFR 60.334(b)(3)]

 (5) For each unit operating hour in which a valid hourly average is 

obtained for both NOx and diluent, the data acquisition and handling 

system must calculate and record the hourly NOx emissions in the units 

of the applicable NOx emission standard under III.B.1.a. of Attachment 

H of this Attachment. For any hour in which the hourly average O2

concentration exceeds 19.0 percent O2, a diluent cap value of 19.0 

percent O2 may be used in the emission calculations. [40 CFR 60.334(b)(3)(i)]

 (6) A worst case ISO correction factor may be calculated and applied 

using historical ambient data in accordance with the procedures in 40 

CFR 60.334(b)(3)(ii). [40 CFR 60.334(b)(3)(ii)]

 (B) The Permittee shall submit reports of excess emissions and monitor 

downtime in accordance with 40 CFR 60.7(c). The reports shall be 

postmarked by the 30th day following the end of each calendar quarter. 

Excess emissions shall be reported for all periods of unit operation, including 

startup, shutdown and malfunction. Periods of excess emissions and monitor 

downtime that shall be reported are defined as follows: [40 CFR 60.334(j)(1)(iii)]

 (1) An hour of excess emissions shall be any unit operating hour in which 

the 4-hour rolling average NOx concentration exceeds the applicable 

emission limit in Condition III.B.1.a of Attachment H. A 4-hour rolling 

average NOx concentration is the arithmetic average of the average 

NOx concentration measured by the CEMS for a given hour (corrected 

to 15 percent O2 and, to ISO standard conditions) and the three unit 

operating hour average NOx concentrations immediately preceding that 

unit operating hour. 

68 

July 13, 2010 
 (2) A period of monitor downtime shall be any unit operating hour in 

which sufficient data are not obtained to validate the hour, for either 

NOx concentration or diluent (or both). 

 (3) Each report shall include the ambient conditions (temperature, 

pressure, and humidity) at the time of the excess emission period. The 

Permittee is not required to report ambient conditions if opting to use 

the worst case ISO correction factor as specified in 40 CFR 

60.334(b)(3)(ii). 

 d. Annual NOx Emission Limit 

 To demonstrate compliance with the annual NOx emission limit in III.B.1.b of 

Attachment H, the Permittee shall comply with the continuous emission system 

monitoring, recordkeeping and reporting provisions in III.E.2 of Attachment H. 

 4. Performance Testing 

The Permittee shall conduct a NOx emissions performance test on Unit IGT3, in accordance 

with 40 CFR 60.8 and the test methods and procedures in 40 CFR 60.335. The performance test 

shall be used to demonstrate compliance with the emission limit contained in III.B.1.a of 

Attachment H. [40 CFR 60.335]

 C. Sulfur Dioxide 

 1. Emission Limitations/ Standards 

 a. The Permittee shall not burn in Unit IGT3, any fuel that contains total sulfur in excess of 

0.8 percent by weight (8000 ppmw). [40 CFR 60.333(b)][PCC 17.12.190.B]

 [Material Permit Condition]

 b. The Permittee shall not allow the total combined emissions of SO2 from Unit IGT3 to 

equal or exceed 40 tons per year, calculated as a 12-month rolling total. [PCC 17.12.190.B]

 2. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180A.3, A.4 & A5] 

 a. The Permittee may elect not to monitor the total sulfur content of the gaseous fuel 

combusted in the turbine, if the gaseous fuel is demonstrated to meet the definition of 

natural gas in 40 CFR 60.331(u). The Permittee shall use one of the following sources of 

information to make the required demonstration: [40 CFR 60.334(h)(3)]

 i. The gas quality characteristics in a current, valid purchase contract, tariff sheet or 

transportation contract for the gaseous fuel, specifying that the maximum total 

sulfur content of the fuel is 20 grains / 100 scf or less; or 

 ii. Representative fuel sampling data which shows that the sulfur content of the 

gaseous fuel does not exceed 20 grains / 100 scf. At a minimum, the amount of fuel 

sampling data specified in section 2.3.1.1 or 2.3.2.4 of appendix D to 40 CFR Part 

75 is required. 

69 

July 13, 2010 
 b. To demonstrate compliance with III.C.1.b of Attachment H, the Permittee shall comply 

with the continuous emission monitoring, recordkeeping, and reporting requirements in 

III.E.2 of Attachment H. 

 D. Carbon Monoxide 

 1. Emission Limitations/Standards 

The Permittee shall not allow the total combined emissions of carbon monoxide (CO) from 

IGT3 to equal or exceed 100 tons per year, calculated as a 12-month rolling total. [PCC 17.12.190.B]

[Material Permit Condition]

 2. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180.A.3, A.4 & A.5] 

 a. The Permittee shall install, calibrate, maintain and operate and quality-assure a 

Continuous Emission Monitoring System (CEMS) consisting of CO and O2 or CO2 

monitors for measuring CO emissions and diluent from IGT3. [PCC 17.12.180.A.2]

 [Material Permit Condition]

 b. The Permittee shall install, calibrate, maintain and operate the in-line fuel flowmeter 

monitoring systems for determining the natural gas input rate to IGT3 for each operating 

hour according to the manufacturer’s instructions. [PCC 17.12.180.A.2] 

 [Material Permit Condition]

 c. To demonstrate compliance with the annual CO emission limit in III.D.1 of Attachment 

H, the Permittee shall comply with the CEMS monitoring, recordkeeping, and reporting 

requirements in Condition III.E.2 of Attachment H. 

 E. Continuous Emissions Monitoring Systems (CEMS) [40 CFR §60.13, PCC 17.12.050.H.3]

 1. New Source Performance Standards for Continuous Emission Monitoring Systems 

To demonstrate compliance with III.B.1.a of Attachment H the Permittee shall install, calibrate, 

maintain, and operate a continuous emission monitoring system (CEMS) and data acquisition 

handling system (DAHS) to calculate a four hour rolling average NOx emission rate. 

 a. The Permittee shall comply with the following requirements in the General Provisions of 

40 CFR 60 for each CEMS unit installed: 

 i. The CEMS and DAHS monitoring and recording devices shall be installed and 

operational prior to conducting initial performance test. Verification of operational 

status shall, as a minimum, include completion of the manufacturer's written 

requirements or recommendations for installation, operation, and calibration of the 

device. [40 CFR 60.13 (b)]

ii. The Permittee shall automatically check the zero (or low level value between 0 and 

20 percent of span value) and span (50 to 100 percent of span value) calibration 

drifts at least once daily in accordance with a written procedure. The zero and span 

must, as a minimum, be adjusted whenever either the 24-hour zero drift or the 24-

70 

July 13, 2010 
hour span drift exceeds two times the limit of the applicable performance 

specification in 40 CFR, Part 60, appendix B. The system must allow the amount of 

the excess zero and span drift to be recorded and quantified whenever specified. [40 CFR 60.13 (d)(1)]

iii. Except for system breakdowns, repairs, calibration checks, and zero and span 

adjustments required under V.B.4.a (ii), the CEMS shall be in continuous operation 

and shall complete a minimum of one cycle of operation (sampling, analyzing, and 

data recording) for each successive 15-minute period. [40 CFR 60.13 (e) & (e)(2)]

iv. The CEMS devices shall be installed such that representative measurements of 

emissions or process parameters from the affected facility are obtained. Additional 

procedures for location of continuous monitoring systems contained in the 

applicable Performance Specifications of appendix B of 40 CFR 60 (III.E.1.b of 

Attachment H) shall be used. [40 CFR 60.13 (f)]

v. The Permittee shall reduce all data to 1-hour averages. 1-hour averages shall be 

computed from four or more data points equally spaced over each 1-hour period. 

Data recorded during periods of continuous system breakdown, repair, calibration 

checks, and zero and span adjustments shall not be included in the data averages. 

The data may be recorded in reduced or nonreduced form (e.g., ppm pollutant and 

percent O2 or ng/J of pollutant). All excess emissions shall be converted into units 

of the standard. After conversion into units of the standard, the data may be 

rounded to the same number of significant digits as used to specify the emission 

limit. [40 CFR 60.13 (h)] 

vi. The Permittee shall meet the notification and recordkeeping requirements in 

II.B.1.d and II.B.5 of Attachment H. 

 b. The Permittee shall comply with the following requirements in the Performance 

Specifications of 40 CFR 60 Appendix B, for each CEMS unit installed: 

i. The CEMS installation and measurement location specification shall be in 

accordance with the methods and procedures in 40 CFR Part 60, Appendix B, 

Specification 2, Sections 2 & 8.1. 

ii. Pretest preparation shall be in accordance with the methods and procedures in 40 

CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.2. 

iii. Calibration drift test procedure shall be in accordance with the methods and 

procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.3. 

iv. Relative accuracy test procedure shall be in accordance with the methods and 

procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.4. 

v. Reporting requirements shall be in accordance with the methods and procedures in 

40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.5. 

vi. Analytical procedures shall be in accordance with the methods and procedures in 

40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 11.0. 

71 

July 13, 2010 

vii. Calculation and data analysis shall be in accordance with the methods and 

procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 12.0. 
viii. Method performance shall be in accordance with the methods and procedures in 40 

CFR Part 60, Appendix B, Specification 2, Sections 2 & 13.0. 

ix. Alternative Procedures shall be in accordance with the methods and procedures in 

40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 16.0. 

 x. References are located in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 

& 17.0. 

xi. Tables, Diagrams, Flowcharts, and Validation data necessary for NOx CEMS 

testing are located in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 

18.0. 

xii. Specifications and test procedures for O2 and CO2 CEMS in Stationary Systems 

shall be in accordance with the methods and procedures in 40 CFR Part 60, 

Appendix B, Specification 3. 

 xiii. Specifications and Test Procedures for CO CEMS in Stationary Sources shall be in 

accordance with the methods and procedures in 40 CFR Part 60, Appendix B, 

Specification 4. 

 2. Monitoring, Recordkeeping, and Reporting Requirements for Annual NOx, SO2, and CO 

Emission Limits [PCC 17.12.180.A.3, A.4 & A.5]

 a. For the purpose of compliance demonstration with annual NOx, and CO emission limits, 

the Permittee shall utilize the NOx, CO, diluent CEMS on Unit IGT3 in conjunction with 

the Data Acquisition and Handling System (DAHS) and fuel flow rate monitoring 

systems. A default value for SO2 concentration will be calculated using equation 3 below. 

The DAHS will calculate emissions of NOx, SO2 and CO in pounds per hour (lb/hr), tons 

per month, and tons per year, calculated monthly as a 12-month rolling total. The 

Permittee shall use the procedures in Method 19 of 40 CFR 60 Appendix A as applicable 

to calculate NOx, and CO mass emission rates. 

 b. The Permittee shall calculate SO2 mass emission rates for Unit IGT3 using Equation 3 

and 3A below: 

 ER = (2.0 / 7000) x 106

 x (Stotal / GCV) where: (Equation 3) 

 ER = Default SO2 emission rate for natural gas combustion, lb/mmBtu 

 Stotal = Total sulfur content of the natural gas from a valid purchase agreement, 

 tariff agreement, or sampling, gr/100 scf 

 GCV = Gross calorific value of the natural gas from a valid purchase agreement, 

 tariff agreement, or sampling, Btu/100 scf 

 7,000 = Conversion of grains/100 scf to lb/100 scf 

 106 = Conversion factor (Btu/mmBtu) 

SO2 rate = ER x HI rate where: (Equation 3) 

SO2 rate = Hourly mass emission rate of SO2, lb/hr 

ER = SO2 default emission rate of 0.06 lbs/MMBtu 

HI rate = Hourly heat input rate, MMBtu/hr

72 

July 13, 2010 
 c. A period of monitor downtime shall be any unit operating hour in which sufficient data 

are not obtained to validate the hour, for NOx, CO, and diluent concentration or heat 

input rate. 

 d. During CEMS system downtime, the Permittee shall implement the missing data 

procedures for NOx and CO shown in 40 CFR Part 75 Subpart D – Missing Data 

Substitution Procedures. 

 e. Each calendar month during which the combined 12-month rolling total for the NOx, 

emission rate from Unit IGT3 exceeds 40 tons shall constitute an exceedance. 

Exceedances shall be reported to the Control Officer in accordance with XI.A of Part A. 

 f. Each calendar month during which the combined 12-month rolling total for the SO2, 

emission rate from Unit IGT3, exceeds 40 tons shall constitute an exceedance. 

Exceedances shall be reported to the Control Officer in accordance with XI.A of Part A. 

 g. Each calendar month during which the combined 12-month rolling total for the CO 

emission rate from Unit IGT3, exceeds 100 tons shall constitute an exceedance. 

Exceedances shall be reported to the Control Officer in accordance with XI.A of Part A. 

 h. Each individual day and 12-month rolling total for NOx, SO2, and CO emission rates in 

the reporting period shall be included in the semiannual compliance certification required 

by VII of Part A. 

 i. Quality Assurance Requirements for Natural Gas Fuel Flow meters 

 i. Each transmitter or transducer shall be calibrated by equipment that has a current 

certificate of traceability to NIST standards at least once every four calendar 

quarters in which a unit operated on natural gas for 168 hours or more during each 

quarter but not less than once every three years. The Permittee shall check the 

calibration of each transmitter or transducer by comparing its readings to that of the 

NIST traceable equipment at least once at the following levels: the zero-level, and 

at least two other upscale levels (e.g., “mid” and “high”), such that the full range of 

transmitter or transducer readings corresponding to normal unit operation is 

represented. 

 ii. The Permittee shall calculate the accuracy of each transmitter or transducer at each 

level tested, using the following equation: 

×100 − = FS

TR

ACC where: 

ACC = Accuracy of the transmitter or transducer as a percentage of full-scale. 

R = Reading of the NIST traceable reference value (in milliamperes, inches of 

 water, psi, or degrees). 

T = Reading of the transmitter or transducer being tested (in 

 milliamperes, inches of water, psi, or degrees, consistent with the 

 units of measure of the NIST traceable reference value). 

FS = Full-scale range of the transmitter or transducer being tested 

 (in milliamperes, inches of water, psi, or degrees, consistent with 

 the units of measure of the NIST traceable reference value).

73 

July 13, 2010 
 iii. If each transmitter or transducer meets an accuracy of ± 1.0 percent of its full-scale 

range at each level tested, the fuel flow meter accuracy of 2.0 percent is considered 

to be met at all levels. If however, one or more of the transmitters or transducers 

does not meet an accuracy of ± 1.0 percent of full-scale at a particular level, then 

the Permittee may demonstrate that the fuel flow meter meets the total accuracy 

specification of 2.0 percent at that level by using one of the following alternative 

methods. If, at a particular level, the sum of the individual accuracies of the three 

transducers is less than or equal to 4.0 percent, the fuel flow meter accuracy 

specification of 2.0 percent is considered to be met for that level. Or, if at a 

particular level, the total fuel flow meter accuracy is 2.0 percent or less, when 

calculated in accordance with Part 1 of American Gas Association Report No. 3, 

General Equations and Uncertainty Guidelines, the flow meter accuracy 

requirement is considered to be met for that level. 

 iv. If during a transmitter or transducer accuracy test the flow meter accuracy 

specification of 2.0 percent is not met at any of the levels tested, the Permittee shall 

repair or replace the transmitter(s) or transducer(s) as necessary until the flow 

meter accuracy specification has been achieved at all levels. (Note that only 

transmitters or transducers which are repaired or replaced need to be re-tested; 

however, the re-testing is required at all three measurement levels to ensure that the 

flow meter accuracy specification is met at each level). 

 v. For orifice-, nozzles, and venturi type flow meters, the Permittee shall perform a 

primary element inspection for damage and corrosion at least once every 12 

calendar quarters in which a unit operated on natural gas for 168 hours or more 

during each quarter but not less than once during the term of this permit. If damage 

and/or corrosion are found, the Permittee shall replace the flow meter or restore the 

damaged or corroded flow meter to “as new” condition. 

 vi. The Permittee shall log in ink, or in an electronic format the date that the 

calibration and inspection was conducted, the results of the calibration or 

inspection, and corrective action taken if needed. 

74 

July 13, 2010 
Tucson Electric Power 

Irvington Generating Station 

Air Quality Permit # 1052 

ATTACHMENT I: MERCURY STANDARD PROVISIONS 

I. APPLICABILITY 

This attachment shall only apply to the coal fired boiler identified as Unit I4 to which the ADEQ Consent 

Order (Docket #A-15-09) signed by ADEQ on February 17, 2009 applies. There are no mercury emission 

standards included in this attachment, only monitoring, recordkeeping, reporting and testing. Emission 

standards will be incorporated at a future date when EPA promulgates a Mercury standard or the mercury 

standard in A.A.C. R18-2-734 becomes applicable. A significant revision submittal will be required to 

incorporate the EPA or ADEQ mercury standards. The mercury standard in R18-2-734 shall not apply until 

December 31, 2016. All the conditions in this Attachment are Locally Enforceable Conditions only.

II. GENERAL PROVISIONS 

The following standards apply to the maintenance, monitoring, recordkeeping and testing of the mercury 

monitoring systems associated with Unit I4 in accordance with the February 17, 2009 ADEQ Consent 

Order. These requirements are in addition to any applicable requirements in the General Provisions in Part 

A of this permit, unless Attachment I is more stringent. 

 A. Mailing Address 

 All requests, reports, applications, submittals, and other communications to the Administrator and 

Control Officer pursuant to 40 CFR Part 60 shall be submitted to the Control Officer at the following 

addresses: [PCC 17.12.180.A.5]

Air Program Manager 

Pima County Department of Environmental Quality 

 33 North Stone Avenue, Suite 700. 

 Tucson, AZ 85701 

III SPECIFIC CONDITIONS 

 A. Emission Limits & Standards 

 None applicable with this revision per ADEQ Consent Order #A-15-09, Section III.F. 

 B. Air Pollution Control Requirements [PCC 17.12.180.A.2] 

 1. The Permittee shall operate and maintain Unit I4, including associated air pollution control 

equipment and monitoring system, in a manner consistent with safety and good air pollution 

control practices for reduction of mercury emissions. 

 Associated air pollution control equipment shall refer to the existing fabric filters 

(FF) for Unit I4, and good air pollution control practices shall mean the 

practices that conform to those prescribed in the Operations & Maintenance 

(O&M) Plan herein referred to as the CAM Plan described in IV.A.2 of Part B 

75 

July 13, 2010 
 C. Operational & Other Requirements [PCC 17.12.180.A.2] 

 1. The Permittee shall implement a control strategy that is designed to achieve either 0.0087 

lbs/GWh or a 50 percent reduction of total mercury emissions (based on inlet mercury in the 

coal) from Unit I4 for the time period beginning on January 1, 2011, or 185 calendar days after 

the Control Officer issues the permit revision and will end on December 31, 2015. The 

emission rate or percent reduction stated above shall be based on Unit I4’s annual coal use 

average. [ADEQ Consent Order #A-15-09, Section III.A.1.a]

 2. The O&M Plan designed to achieve the reductions in III.C.1 above shall be implemented 

beginning January 1, 2011 or 185 calendar days after the Control Officer issues the permit 

revision and will end on December 31, 2015. [ADEQ Consent Order #A-15-09, Section III.A.3] 

 D. Monitoring, Recordkeeping and Reporting Requirements [PCC 17.12.180.A.3, A.4 & A.5]

 Until such time as the Department amends the mercury monitoring, recordkeeping and reporting 

requirements of R18-2-734.D, or USEPA finalizes a federal mercury monitoring, recordkeeping, and 

reporting rule, whichever occurs first, the Permittee shall apply the following monitoring, 

recordkeeping and reporting methods for determining mercury emissions from Unit I4. 

 1. The Permittee shall perform stack testing for Unit I4 during the calendar year in each of the 

early mercury reduction years. The early mercury reduction year shall not begin until the later 

of January 1, 2011, or 185 calendar days after the Control Officer issues the permit revision and 

shall end on December 31, 2015. 

 2. The Permittee shall conduct the stack testing downstream of Unit I4 fabric filters while coal is 

being burned as the main fuel, using EPA Reference Method 29 or other equivalent testing 

methods approved by the Control Officer. Results of the tests shall be reduced as outlet 

mercury rate in lbs/mmBtu. 

 3. If Unit I4 is not operating coal as its main fuel, the stack test shall not be performed until such 

time as the unit is back operating with coal as its main fuel. 

 4. If necessary, the Permittee shall conduct coal mercury and heating value analysis at least once 

each month for each coal type to determine monthly inlet mercury in lbs/mmBtu. For purposes 

of this Attachment, “inlet mercury” means the average concentration of mercury in the coal 

burned in Unit I4, as determined by ASTM methods, EPA-approved methods or an alternative 

method approved by the Control Officer. Should the Permittee decide to utilize analysis of coal 

samples provided be the coal supplier, an official copy of the analysis from the coal supplier 

shall be maintained. 

 5. If necessary to report percent reduction of total mercury emissions, the Permittee shall 

determine and record for each calendar year Unit I4’s annual percent reduction of mercury 

emissions, using the inlet and outlet mercury data (based on coal use) obtained from III.D.2 & 

III.D.4 of this Section. The calendar year average inlet and outlet mercury rate shall be derived 

based on Unit I4 total calendar year heat input in lbs/mmBtu. 

 6. The Permittee shall submit annual reports to the Control Officer that contain either the calendar 

year average outlet mercury rate as determined by III.D.2 of Attachment I, or the calendar year 

based annual percent reduction of mercury emissions as determined by III.D.5 of Attachment I 

above. The report shall be submitted by February 15th and shall contain the results for the 

76 

July 13, 2010 
preceding year. The first such report shall be submitted by February 15, 2012 for the emitting 

year of 2011. 

 E. Application to Incorporate Post-2015 Applicable Standards [ADEQ Consent Order #A-15-09, Section III.A.5]

The Permittee shall submit to the Control Officer the application for a significant permit revision 

required by A.A.C. R18-2-734(F) by no later than January 1, 2014, and shall include the following 

elements in the application: 

a. The State Mercury Standard and any amendments adopted by the Director to ensure that the 

State Mercury Standard is not incompatible with a MACT standard promulgated by EPA. 

b. A control strategy for meeting the State Mercury Standard and any amendments adopted by the 

Director to ensure that the State Mercury Standard is not incompatible with a MACT standard 

promulgated by EPA. 

c. A demonstration that the control strategy is designed to meet the State Mercury Standard and 

any amendments adopted by the Director to ensure that the State Mercury Standard is not 

incompatible with a MACT standard promulgated by EPA. 

d. A proposal to comply with the State Mercury Standard by December 31, 2016, except as 

provided in A.A.C. R18-2-734(H), under the following conditions; 

 (1) For the purposes of applying the exception established in A.A.C. R18-2-734(H), each 

date specified in that provision shall be increased by three calendar years. 

 (2) The exception in A.A.C. R18-2-734(G) shall not apply. 

77 

July 13, 2010