## PIMA COUNTY DEPARTMENT OF ENVIRONMENTAL QUALITY Air Program

33 North Stone Avenue, Suite 730, Tu cson, 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 pe rmit 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, 20102 July 13, 2010 Tucson Electric Power Irvington Generating Station

Air Quality Permit # 1052

TABLE OF CONTENTS

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

Part A: Genera l Provisions......................................................................................................................................5

I. Permit Expiration and Renewal .............................................................................................. .............5 II. Compliance with Permit Conditions......................................................................................... ...........5 III. Permit Revision, Reopening, Revocation a nd 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 Fede ral Hazardous Air Pollutant Standard ............................................8 XI. Excess Emissions, Permit Devia tions 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 .......................................................................1 4 XVII. Testing Requirements .................................................................................................... ....................15 XVIII. Prope rty Rights........................................................................................................ ..........................16

XIX. Severa bility 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 ...................................................................................... ................75Tucson 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 Po wer – Irvington Generating Station, (TEP-IGS), the Permittee. The permit was revised in April 2010 to incl ude 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 elect ricity and consists primarily of fo ssil-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 de livery 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.

3 July 13, 2010Tucson 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 Admini strative 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 cond itions 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 gr ounds 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, re opened, revoked and reissued, or te rminated 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 antic ipated 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 th e Act become applicable to a major source. Such reopening shall only occur if there are th ree 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 th e 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 sh all reset the five-year permit term.

2. Additional requirements, including excess emissions requirements, become applicable to an affected source under the acid rain progr am. Upon approval by the Administrator, excess emissions offset plans shall be deemed to be incorporated into the Class I permit.

4 July 13, 20103. 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 appl y 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 r esult 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 co py 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 Contro l Officer pursuant to PCC 17.12.510.

VI. ANNUAL EMISSIONS INVENTORY QUESTIONNAIRE [PCC 17.12.320]

A. When requested by the Control Officer, th e Permittee shall complete and submit an annual emissions inventory questionnaire. The questionnair e is due by March 31 or ninety days after the Control Officer makes the request and provides th e 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 a nd 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 cond ition. Certifications shall be submitted as specified in Part B of this permit.

A. The compliance certificati on shall include the following:

1. Identification of each term or conditi on contained in the permit including emission limitations, standards, or work practices that are the basis of the certification;

5 July 13, 20102. Identification of the method(s) or other m eans 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 sha ll include, at a minimum, the methods and means required under the monitoring, related r ecordkeeping 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 comp liance 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 in formation 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 sour ce 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;

6 July 13, 2010D. Sample or monitor, at reasonable times, s ubstances 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 promulga ted by the Administrator pursuant to section 112(d) of the Act, then the Permittee shall, within twel ve months of the date on which the standard is promulgated, submit an application for a permit re vision 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 occurrenc e 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;

7 July 13, 2010vi. 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 pr ocedures 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 em issions 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 deviati ons 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 me asures 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 arisi ng from sudden and reasonably unforeseeable events beyond the control of the source, in cluding 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 e quipment, lack of preventive maintenance, careless or improper operation, or operator error.

2. An emergency constitutes an affirmative defe nse 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 sha ll be demonstrated through properly signed, contemporaneous operating logs, or other relevant evidence that:

a. An emergency occurred and that the pe rmittee 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 excee ded the emissions standards or other requirements in the permit; and

8 July 13, 2010d. The Permittee submitted notice of the em ergency 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 emer gency 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 schedul e 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 mileston es, 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 fo r 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 Signifi cant 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 malfuncti on 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 fro m a sudden and unavoidable breakdown of process equipment or air pollution co ntrol equipment beyond the reasonable control of the operator;

9 July 13, 2010b. The air pollution control equipment, process equipment, or processes were at all times maintained and operated in a ma nner consistent with good practice for minimizing emissions;

c. If repairs were required, the repairs we re made in an expeditious fashion when the applicable emission limitations we re 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 dem onstrated that the measures were impracticable;

d. The amount and duration of th e excess emissions (including any bypass operation) were minimized to the maximu m 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 sha ll 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

10 July 13, 2010severe 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 emi ssions there were no exceedances of the relevant ambient air quality standard s established in PCC Chapter 17.08 that could be attributed to the emitting source;

vii. All emissions monitoring sy stems 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 Malf unctions 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 pr event the occurrence of the excess emissions.

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

A. Permittee shall keep records of all require d 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 perm it, 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;

11 July 13, 20104. 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 requi red monitoring data and support information for a period of at least 5 years from the date of th e monitoring sample, measurement, report, or application. Support information includes all calibration and maintenance records and all original strip-chart recordings for continuous monitori ng 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 re quirements 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 Offi cer, 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 claime d 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 applica tion, the Permittee shall, upon becoming aware of such failure or incorrect submittal, promptly submit such supplem entary facts or corrected information. In addition, an applicant shall provide add itional 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 revisi on for changes to the facility which do not qualify for a facility change without revision under XVI of Part A, as follows:

12 July 13, 2010A. 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.

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

A A facility with a Class I permit may make ch anges 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 applicab le requirements or trigger any additional applicable requirements;

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

and

5. The changes do not contravene federally en forceable 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 substitu tion 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 implemen tation 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. Notifi cations 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 prac ticable 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;

14 July 13, 20106. If the emissions trading provisions of th e 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 accordi ng 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 uni t is operating at full load under representative operational conditions unless other conditions are requi red 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, sh utdown, and malfunction (as defined in PCC 17.04.340.A.) shall not constitute representativ e 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 Ariz ona 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, 2010E. Interpretation of Final Results

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

run shall be conducted for the time and under the c onditions 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 even t 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 meteorologi cal 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 stoppe d 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 Pe rmittee’s control. Termination of any test without good cause after the first run is commen ced 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. Th e 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 pr ovision 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 complia nce 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 - As bestos for asbestos regulations when conducting any renovation or demolition at this premises, th en the Permittee shall submit proper notification as

16 July 13, 2010described 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 an y 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 chlo rofluorocarbon (CFC) or hydrochlorofluorocarbon (HCFC) compound as a working fluid, unless such flui d 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, 2010Tucson Electric Power Irvington Generating Station

Air Quality Permit # 1052

PART B: SPECIFIC CONDITIONS All standards are Federally En forceable unless otherwise noted

[References are to Title 17 of the Pi ma 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 Stati onary 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, PM 10 & 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 perm it the emission of particulate matter from any fossil fuel-fired steam generator in excess of th e amounts calculated by the following equation:

E = 1.02Q 0.769 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, 2010a. UNITS I1, I2, & I3

The Permittee shall not cause, allow, or pe rmit 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 pe rmit 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 per cent 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 av ailable for use by the source and that it has adequate facilities and contingency plans to in sure 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 sh all 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 mach inery in excess of the amounts calculated by the following equation:

E = 1.02Q 0.769 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 pe rmit 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 require ment (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 e ffluent 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, 2010ii. A violation of an opacity standard shall be determined by measuring and recording a set of consecutive, instantaneous opac ities, and calculating the arithmetic average

of the measurements within the set unless otherwise noted herein. The measurements shall be made at approxima tely 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 av ailable for use by the source and that it has adequate facilities and contingency plans to in sure 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 fu el 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 th e emission of particulate matter, caused by the

combustion of fuel from the stack of

E = 1.02Q 0.769 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 th e 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 av ailable for use by the source and that it has adequate facilities and contingency plans to in sure 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 = 17.31P

P 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 c oncentrations to cause air pollution. [PCC 17.16.430.D] [Locally Enforceable Condition]

3. Where a stack, vent, or other outlet is at su ch 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 ther eof 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 wa ter 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 th e 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 = 3.59P 0.62 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 emissi ons shall be determined by the following equation:

E = 17.31P

P 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 allo wable emission of particulate matter.

[PCC 17.16.310.D]

2. The Permittee shall not cause, suffer, allo w, or permit crushing, screening, handling, transporting, or conveying of materials or ot her operations likely to result in significant amounts of airborne dust without taking reasona ble 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 stor ed 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 st orage 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, dus t 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 or ganic or inorganic dust producing material;

[PCC 17.16.110.A]

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

minimum fall of material and with th e 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 = 3.59P 0.62 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 = 17.31P

P 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 allo wable emission of particulate matter.

[PCC 17.16.430.B]

2. The Permittee shall not cause, suffer, allo w, or permit crushing, screening, handling, transporting, or conveying of materials or ot her operations likely to result in significant amounts of airborne dust without taking reasona ble 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 stor ed 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 st orage 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, 20105. 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, dus t 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 or ganic 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 th e 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 ar ea, or a vacant lot or other open area to be constructed, used, altered, repair ed, 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 usi ng an approved dust suppressant or adhesive soil stabilizer, paving, covering, landscaping, c ontinuous 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, bui lding site, parking area, or other open area in such a state after construction, alteration, cl earing, 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 gr avel 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 othe r 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, allo w 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 ma nual, and EPA Reference Method 9.

[PCC 17.16.050.B] [Locally Enforceable Condition]

25 July 13, 2010b. Except as provided elsewhere in this Part B, the Permittee shall not cause, allow, or permit to be emitted into the atmosphere an y plume or effluent the opacity of which exceeds 20 percent, as measured in accord ance 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 odor ous 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 vi sible emissions across property lines shall be prevented by appropriately controlling the em issions at the point of discharge, or ceasing entirely the activity or operation which is cau sing 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 do es 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, ma intain, and operate a baghouse on U NIT I 4 to capture particulate emissions resulting from combustion of coal fuel . The baghouse shall be operated at all times when

U NIT I 4 is firing coal (exclusively or in combinati on) and when transitioning to or from firing coal fuel (exclusively or in combination). Air pollutio n 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, 2010Table 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 follo wing table is in operation, the Permittee shall maintain and operate the associated air pollu tion 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 hoppe r trucks through a closed gravity feed system and the outer sleeve of the dual sleeve system shall se al 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 re quire 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 polluti on control equipment shall be requested by the Control Officer through a permit reope ning 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 tran sition period, and deactivated only after the opacity readings have stabilized to le vels 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, 2010The Permittee shall record the zero a nd 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 dr ift limits of 2% opacity are

exceeded.

(b) The system shall allow for th e 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 comp lete 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, 2010included in the data averages computed under the previous paragraph. An arithmetic or integrated average of all data may be

used.

2. Particulate Matter – Compliance As surance 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) & Installa tion 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 intern al visual inspection of the entire baghouse including bag compartments fo r 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 th e 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’ c onditions as described in IV.A.2.a.ii.(a) of

Part B shall constitute an excursion.

30 July 13, 2010c. 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 expe rienced personnel perform conduct the inspection and maintenance program.

d. Data Collection Procedure & Monitoring Frequency

i. Visible Emissions Opacity

(A) The Permittee shall conduct all mon itoring in continuous operation with data recorded as 6-minute averages (or shall co llect 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 (i ncluding, as applicable, calibration checks and required zero and span ad justments). Data recorded during monitoring malfunctions, associated repa irs, 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 baghou se 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 inspecti on 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 sha ll submit written notification to the Control Officer. Such notification shall include the pr oposed 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, 2010f. Upon detecting an excursion or exceedance, the owner or operator shall restore operation of the pollutant-specific emissions unit (i ncluding the control device and associated capture system) to its normal or usual manne r 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 th an those caused by excused startup or shutdown conditions). Su ch 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 with in 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, mon itoring results, review of operation and maintenance procedures and records, and in spection of the control device, associated capture system, and the process. [40 CFR 64.7(d)(2)]

h. In addition to the genera l reporting requirements of this pe rmit, all reports of excursions

shall follow the format outlined in 40 CF R 64.9(a)(2) and submitted with the report required in VI.F of Part B. For the pur poses 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 recordk eeping 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 natu ral gas, the Permittee may use the emission

factor of 0.0006 lb/MMBTU to estimate emissions of SO 2 in place of the continuous SO 2 emission monitor. [Installation Permit #1156, Condition #6] [Material Permit Condition]

b. The CEMS for SO 2 , 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, 2010ii. 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 reco rdkeeping 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 (inclu ding 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 unchangeab le 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 Fe deral 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, 20101. A certified Method 9 observer shall conduct a week ly visual survey of visible emissions from the coal preparation plant when it is in operati on. 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 poi nt 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 th an 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 week ly visual survey of visible emissions from the fly-ash handling system when it is in ope ration. This weekly survey shall include observation of all exposed transfer points, enclo sed 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 poi nt 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 th an 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, 2010A. Fossil Fuel Fired Steam Generators

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

With regard to all liquid fuels, the Permittee sh all 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 sha ll 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 comp liance 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 f 

### 000,000,1 %0.2

2 

### ×

= ×

SO 2 = emissions of SO 2 in lb/MMBtu %S = Percent Sulfur by weight (decimal; i.e. 1% = 0.01)

D f = 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, & I3Until 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 previ ous 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 conti nues 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 (inclu ding Stationary Turbines IGT1 & IGT2)

1. Particulate Matter

The Permittee shall keep on record, along with th e 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 cont ractual 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 co mpliance 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, 2010b. 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 th e 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 measu re 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 stab ilization, 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 ai r 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 em issions related maintenance performed on all air pollution control equipment.

E. Fly-Ash Handling Systems

1. Particulate Matter

The Permittee shall maintain and operate all ai r 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 em issions related maintenance performed on all air pollution control equipment.

F. Open Areas, Roadways, & Streets

The Permittee shall maintain records of dates a nd 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, 2010A. Fossil Fuel Fired Steam Generators

1. CAM Reporting – UNIT I4

For the purposes of permit deviation reporting u nder Condition XII of Attachment “A,” the Permittee shall include the following informa tion required by 40 CFR part 64, §64.9(a).

[40 CFR 64.7(d)]

a. Summary information on the number, dur ation 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, dur ation 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 cont ent 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 31 st , April 30 th

, July 31 st , and October 31 st , covering October through December , January through March, April through June, and July through September, re spectively. The reports shall include the following:

a. The magnitude of deviations comput ed in accordance with PCC 17.12.060, any conversion factor(s) used, and the date a nd time of commencement and completion of each time period of deviation.

38 July 13, 2010b. Specific identification of each period of devi ation that occurs during startups, shutdowns,

and malfunctions of the boiler. The nature a nd 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 peri od 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 repa irs 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 & Installati on Permit #1156, Condition # 6]

2. In addition to the requirements of the above Pa ragraph (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 re port of all permit de viations (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 D ecember 31st and January 1st thr ough 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 certifica tion to the Control Officer pursuant to VII of Part A. Annual compliance certification reports shall be due on February 15 th of each year and shall cover the period January 1st through December 31s t. 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 questi onnaire 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 me thods 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, includi ng the exclusive use, of any credible evidence or

information relevant to whether a source would ha ve 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 re ference 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 performan ce test in accordan ce with EPA Reference Method 6 or 6C when liquid fuel is fired gr eater than 1300 hours in a 12 consecutive month period.

2. UNIT I4

The Permittee shall conduct a performance test for vi sible 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 th e 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 c onducted 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 test s 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 performan ce test in accordan ce with EPA Reference Method 6 or 6C when liquid fuel is fired gr eater 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 conducte d after the twelve month rolling total hours of operation exceeds 4500 hours. The performance t est 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 Cont rol Officer for appropriate test methods.

40 July 13, 2010Tucson 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 A ssurance 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 Performan ce for Coal Preparation Plants 17.16.340 Standards of Performance for Stationary Rotating Machinery

17.16.430 Standards of Perfo rmance for Unclassified Sources

Installation Permit #1156 – Octobe r 14, 1981 by Arizona Depart ment of Health Services

41 July 13, 201042 July 13, 2010Tucson 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, 2010IV. 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%

NO

x 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%

NO X 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%

NO

x Chemiluminesence 0-400 ppm

Sulfur Dioxide U.V. Fluorescence 0-700 ppm

Mass Flow Constant temperature an emometer thermal array 3.29 x 10 7 scfh I4

Opacity Electro-optical, double pass 0-100%

44 July 13, 2010Tucson 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 Co llector 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, 201046 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 NA47 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 Transportatio n Steam Cleaner NA NA

WH4 WH4 Warehouse - Latrine Vents NA NA

WW1 Power Production - North Coll ection 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 Tr eatment Clarifier - Wastewater 140,000 gal NA NA

WW11 Power Production - Waste Water Tr eatment Scum Tank-Clarifier Scum for recycle 1170 gal NA NA

WW12 Power Production - Waste Water Treatment pH Adjustment TankPretreated Wastew ater 6768 gal NA NA

WW13 Power Production - Waste Water Treatment pH Adjustment TankTreated Wastewater 5000 gal NA NA

WW14 Power Production - Waste Water Tr eatment Chemical Mix Tank (2) - Alum 730 gal NA NA

WW15 Power Production - Waste Water Tr eatment Chemical Mix Tank (2) - Polymer 148 gal NA NATucson 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 th e 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. SO ALLOWANCE 2 [40 CFR Part 73 Table 2] 1 ALLOCATIONS AND NOX REQUIREMENTS FOR EACH AFFECTED UNIT

A. UNIT I1

Year: 2005 – 2009 2010 –

Annual SO 2 allowances 16 tons 14 tons

NOx Limits: This unit is not subject to a NO

x limit under 40 CFR Part 76.

B. UNIT I2

Year: 2005 – 2009 2010 –

Annual SO 2 allowances 28 tons 40 tons

NOx Limits: This unit is not subject to a NO

x limit under 40 CFR Part 76.

C. UNIT I3

Year: 2005 – 2009 2010 –

Annual SO 2 allowances 0 tons 2 tons

NOx Limits: This unit is not subject to a NO

x limit under 40 CFR Part 76.

D. UNIT I4

Year: 2005 – 2009 2010 –

Annual SO 2 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 U NIT I 4. This unit’s a nnual average NOx emission rate for each year, determined in accordance with 40 CF R 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 dioxid e during or after a sp ecified calendar year.

48 July 13, 2010The 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 nece ssitate a revision to the unit SO 2 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 ra in permit applications. These applications are:

A. Phase II Permit Application (OMB No. 2060-02 58) signed by the Designated Representative on

12/12/95.

B. Phase II NOx Compliance Plan (OMB No. 2060-02 58) signed by the Designated Representative on

12/15/97.

49 July 13, 2010Tucson 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 notificati on shall include all reporting requirements that are

identified in this attachment.



### II. GENERAL PROVISIONS

The following requirements apply to the operation, main tenance, recordkeeping and testing of Unit IGT3 and its associated monitoring systems in accordance w ith 40 CFR Part 60, Subpart A – General Provisions. These requirements are in addition to any applicable re quirements in the General Provisions in Part A of this permit, unless Attachment G is more stringent.

A. Mailing Address

All requests, reports, applications, submittals, a nd 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 Cont rol Officer written notification as follows: [40 CFR 60.7(a)]

a. A notification of the date of constr uction 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 initia l 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 app licable subpart or in 40 CFR 60.14(e). This notice shall be postmarked 60 days or as s oon as practicable before the change is

commenced and shall include information d escribing 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 co mpletion date of the change. The Control Officer may request additional relevant in formation subsequent to this notice.

[40 CFR 60.7(a)(4)]

50 July 13, 2010d. A notification of the date upon which de monstration 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 m onitoring 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 Met hod 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 O fficer semi-annually, except when: more frequent reporting is specifically required by an applicab le 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 30 th 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 comput ed in accordance with 40 CFR 60.13(h), any conversion factor(s) used, and the date a nd time of commencement and completion of each time period of excess emissions and th e 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 pe riod during which the continuous monitoring system was inoperative except fo r 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 occurre d or the continuous monitoring system(s) have not been inoperative, repaired, or adjusted, su ch 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 submitte d 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, 2010period is less than 5 percent of the total ope rating 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 fo r the reporting period is 1 percent or greater of the total operating time for the reporting pe riod or the total CMS downtime for the reporting period is 5 percent or greater of th e 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 a ll measurements, including continuous monitoring system, monitoring device, and performance tes ting 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 fo rm 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, a nd where the calculated data averages do not exclude periods of CEMS breakdown or malf unction. An automated CEMS records and

reduces the measured data to the form of th e 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 peri ods 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 report able form of the standard. [40 CFR 60.7(f)(1)]

b. If the Permittee is required to insta ll a CEMS where the measured data is manually reduced to obtain the reportable form of th e 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 maximu m production rate at which IGT3 will be operated, but not later than 180 days after initial start up 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 SO 2 , and furnish the Control Officer a written report of the results of such performance test(s). [40 CFR 60.8(a)]

52 July 13, 2010D. 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 IG T3 including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptabl e operating and maintenance procedures are being used will be based on information availabl e 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 cer tifications 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 t est or procedure had been performed. [40 CFR 60.11(g)]

E. Circumvention

The Permittee shall not build, erect, install, or u se any article, machine, equipment or process, the use of which conceals an emission, which would othe rwise constitute a violation of an applicable standard. Such concealment includes, but is not lim ited to, the use of gaseous diluents to achieve compliance with opacity standard or with a sta ndard, which is based on the concentration of a pollutant in the gases discha rged to the atmosphere. [40 CFR 60.12]

F. General Notification and Reporting Requirements

The Permittee shall comply with the “General No tification 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 con centration to exceed 25 ppm at 15 percent O 2 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, cal culated as a 12-month rolling total. [PCC 17.12.190.B] [Material Permit Condition]

53 July 13, 20102. Air Pollution Control Equipment

The Permittee must operate and maintain the st ationary 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 da ys 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 comp liance with the NOx emission limitation in

III.B.1.a of Attachment G as follows:

i. Install, calibrate, maintain, and ope rate a continuous monitoring system (CMS) to monitor and record the fuel consumption a nd the ratio of water to fuel being fired in Unit IGT3 when burning a fuel that re quires 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 (CO 2 or O 2 ) 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 st andard, 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 mete rs) 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 a nnual 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 a nnual 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 Me thods 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 ∗ Q std 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 Q std = 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 emissi on 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 SO 2 per million British thermal unit (lb of SO 2 /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 SO 2 from Unit IGT3 to equal or exceed 40 tons per year, cal culated 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 ava ilable for inspection, a paper or electronic record of a current, valid purchase contract, ta riff 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 SO 2 /J (0.060 lb SO 2 /MMBtu) heat input. [40 CFR §60.4365(a)]

55 July 13, 2010b. 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 comb ined 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 (C EMS) 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, mainta in 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 CE MS 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 Att achment G the Permittee shall install, calibrate, maintain, and operate a continuous emission m onitoring 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 a nd recording devices shall be installed and operational prior to conducting initial perfo rmance test. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for insta llation, 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 w ith 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 lim it of the applicable performance

56 July 13, 2010specification in 40 CFR, Part 60, appendix B. The system must allow the amount of the excess zero and span drift to be reco rded and quantified whenever specified.

[40 CFR 60.13 (d)(1)]

iii. Except for system breakdowns, repa irs, calibration checks, and zero and span adjustments required under II.B.5 of A ttachment 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 a ffected 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 O 2 or ng/J of pollutant). All excess emis sions shall be converted into units

of the standard. After conversion into un its of the standard, the data may be rounded to the same number of significant digits as used to sp ecify 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 th e 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 accordan ce with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.2.

iii. Calibration drift test procedure sha ll 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 sha ll 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 acco rdance with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.5.

vi. Analytical procedures shall be in accord ance with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 11.0.

57 July 13, 2010vii. Calculation and data analysis sha ll 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 accordan ce with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 13.0.

ix. Alternative Procedures shall be in acco rdance 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 O 2 and CO 2 CEMS in Stationary Systems

shall be in accordance with the met hods and procedures in 40 CFR Part 60, Appendix B, Specification 3.

xiii. Specifications and Test Procedures fo r 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 op erate each CEMS unit in accordance with the following:

i. As specified in III.E.1.a.iii of A ttachment G, during each full unit operating hour,

both the NOx monitor and the diluent mon itor 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 w ith 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 whic h a valid hourly aver age, 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 equati on from method 19 in appendix A of this part. For any hour in which the hourly average O 2 concentration exceeds 19.0 percent O 2 (or the hourly average CO 2 concentration is less than 1.0 percent CO 2 ), a diluent cap value of 19.0 percent O 2 or 1.0 percent CO 2 (as applicable) may be

used in the emission calculations. [40 CFR 60.4350(b)]

iv. Correction of measured NOx concentrations to 15 percent O 2 is not allowed.

[40 CFR 60.4350(c)]

58 July 13, 2010v. The Permittee shall reduc e 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 hour ly 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 un its complying with the output based standard by using the simple cycle operation equation below: [40 CFR 60.4350(f)]

E = (NO

x ) h * (HI) h where: (Equation 1)

P

E = hourly NO

x emission rate, in lb/MWh. (NO

x ) 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., calcu lated 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, SO 2 , 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 SO 2 concentration will be calcula ted using equation 3 below. The DAHS will calculate emissions of NOx, SO 2 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 SO 2 mass emission rates for Unit IGT3 using Equation 3

and 3A below:

ER = (2.0 / 7000) x 10 6 x (S total / GCV) where: (Equation 3)

ER = Default SO2 emission rate for natural gas combustion, lb/mmBtu

S total = Total sulfur content of the natu ral gas from a valid purchase agreement, tariff agreement, or sampling, gr/100 scf

GCV = Gross calorific value of th e 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

10 6 = Conversion factor (Btu/mmBtu)

SO 2 rate = ER x HI rate where: (Equation 3A)

SO 2 rate = Hourly mass emission rate of SO 2 , lb/hr

ER = SO 2 default emission rate of 0.06 lbs/MMBtu HI rate = Hourly heat input rate, MMBtu/hr

59 July 13, 2010c. 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 O fficer in accordance with XI.A of Part A.

f. Each calendar month during which the combined 12-month rolling total for the SO 2 , emission rate from Unit IGT3, exceeds 40 tons shall constitute an exceedance. Exceedances shall be reported to the Control O fficer 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 O fficer in accordance with XI.A of Part A.

h. Each individual day and 12-month rolling total for NOx, SO 2 , and CO emission rates in the reporting period shall be included in th e semiannual compliance certification required by VII of Part A.

i. Quality Assurance Requirement s for Natural Gas Fuel Flow meters

i. Each transmitter or transducer sha ll be calibrated by equipment that has a current certificate of traceability to NIST standa rds 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 thr ee 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 accura cy 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 Gu idelines, the flow meter accuracy requirement is considered to be met for that level.

iv. If during a transmitter or transdu cer accuracy test the flow meter accuracy specification of 2.0 percent is not met at a ny of the levels tested, the Permittee shall repair or replace the transmitter(s) or transducer(s) as nec essary until the flow meter accuracy specification has been ach ieved at all levels. (Note that only transmitters or transducers which are repa ired or replaced need to be re-tested; however, the re-testing is required at all thr ee measurement levels to ensure that the flow meter accuracy specification is met at each level).

v. For orifice-, nozzles, and venturi t ype flow meters, the Pe rmittee 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 me ter 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, 2010Tucson 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 s ubject 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, main tenance, recordkeeping and testing of Unit IGT3 and its associated monitoring systems in accordance w ith 40 CFR Part 60, Subpart A – General Provisions. These requirements are in addition to any applicable re quirements in the General Provisions in Part A of this permit, unless Attachment H is more stringent.

A. Mailing Address

All requests, reports, applications, submittals, a nd 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 Cont rol Officer written notification as follows: [40 CFR 60.7(a)]

a. A notification of the date of constr uction 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 initia l 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 app licable subpart or in 40 CFR 60.14(e). This notice shall be postmarked 60 days or as s oon as practicable before the change is

commenced and shall include information d escribing 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 co mpletion date of the change. The Control Officer may request additional relevant in formation subsequent to this notice.

[40 CFR 60.7(a)(4)]

62 July 13, 2010d. A notification of the date upon which de monstration 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 m onitoring 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 Met hod 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 O fficer semi-annually, except when: more frequent reporting is specifically required by an applicab le 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 30 th 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 comput ed in accordance with 40 CFR 60.13(h), any conversion factor(s) used, and the date a nd time of commencement and completion of each time period of excess emissions and th e 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 pe riod during which the continuous monitoring system was inoperative except fo r 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 occurre d or the continuous monitoring system(s) have not been inoperative, repaired, or adjusted, su ch 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 submitte d 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, 2010period is less than 5 percent of the total ope rating 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 fo r the reporting period is 1 percent or greater of the total operating time for the reporting pe riod or the total CMS downtime for the reporting period is 5 percent or greater of th e 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 a ll measurements, including continuous monitoring system, monitoring device, and performance tes ting 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 fo rm 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, a nd where the calculated data averages do not exclude periods of CEMS breakdown or malf unction. An automated CEMS records and

reduces the measured data to the form of th e 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 peri ods 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 report able form of the standard. [40 CFR 60.7(f)(1)]

b. If the Permittee is required to insta ll a CEMS where the measured data is manually reduced to obtain the reportable form of th e 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 producti on rate at which IGT3 w ill 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, th e Permittee shall conduct emissions performance test(s) for NOx and SO 2 , and furnish the Control Officer a wr itten report of the results of such performance test(s). [40 CFR 60.8(a)]

64 July 13, 2010D. 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 IG T3 including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptabl e operating and maintenance procedures are being used will be based on information availabl e 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 cer tifications 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 t est or procedure had been performed. [40 CFR 60.11(g)]

E. Circumvention

The Permittee shall not build, erect, install, or u se any article, machine, equipment or process, the use of which conceals an emission, which would othe rwise constitute a violation of an applicable standard. Such concealment includes, but is not lim ited to, the use of gaseous diluents to achieve compliance with opacity standard or with a sta ndard, which is based on the concentration of a pollutant in the gases discha rged to the atmosphere. [40 CFR 60.12]

F. General Notification and Reporting Requirements

The Permittee shall comply with the “General No tification 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 (NO

x ) 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)) NO

x 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 = NO

x 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 comb ined 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 manne r 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 qua lity-assure Continuous Emission Monitoring Systems (CEMS) consisting of NO

x and O 2 (or CO 2 ) monitors for measuring NO

x emissions from Gas Turbine Unit IGT3. [PCC 17.12.180.A.2] [Material Permit Condition]

b. The Permittee shall install, calibrate, ma intain, 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 monitori ng 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 NO

x emission limitation in III.B.1.a.of Attachment H by using one of the following methods:

(A) Install, calibrate, maintain a nd 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 fu el 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 engin eering 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 NO

x 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 op eration, 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 wa ter 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 in jected 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 tu rbine, but the essential parametric

data needed to determine the wate r to fuel ratio are unavailable or

invalid.

(3) Each report shall include the average water to fuel ratio, average fuel consumption, ambient conditions (tem perature, pressure, and humidity) and gas turbine load. The Permittee is not required to report ambient conditions if opting to use the wo rst 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 NO

x 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 NO

x 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 NO

x and diluent, the data acquisition and handling system must calculate and record the hourly NO

x emissions in the units of the applicable NO

x emission standard under III.B.1.a. of Attachment H of this Attachment. For any hour in which the hourly average O 2 concentration exceeds 19.0 percent O 2 , a diluent cap value of 19.0 percent O may be used in the emission calculations. 2 [40 CFR 60.334(b)(3)(i)]

(6) A worst case ISO correcti on 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 30 th day following the end of each calendar quarter. Excess emissions shall be reported for a ll periods of unit operation, including startup, shutdown and malfunction. Pe riods 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 NO

x concentration exceeds the applicable emission limit in Condition III.B.1.a of Attachment H. A 4-hour rolling average NO

x concentration is the arithmetic average of the average

NO

x concentration measured by the CEMS for a given hour (corrected to 15 percent O 2 and, to ISO standard conditions) and the three unit operating hour average NO

x 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

NO

x concentration or diluent (or both).

(3) Each report shall includ e the ambient conditions (temperature, pressure, and humidity) at the time of the excess emission period. The Permittee is not required to report am bient 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 th e 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 NO

x emissions performance test on Unit IGT3, in accordance with 40 CFR 60.8 and the test methods and pro cedures 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, an y 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 SO 2 from Unit IGT3 to equal or exceed 40 tons per year, cal culated 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 demonstrat ed to meet the definition of natural gas in 40 CFR 60.331(u). The Permitt ee 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, 2010b. 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 comb ined 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 (C EMS) 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, mainta in 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 CE MS 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 Att achment H the Permittee shall install, calibrate, maintain, and operate a continuous emission m onitoring 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 a nd recording devices shall be installed and operational prior to conducting initial perfo rmance test. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for insta llation, 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 w ith 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, 2010hour span drift exceeds two times the lim it 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 reco rded 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 su ch that representative measurements of emissions or process parameters from the a ffected 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 point s equally spaced over each 1-hour period. Data recorded during periods of contin uous 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 O 2 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 sp ecify 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 th e 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 accordan ce with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.2.

iii. Calibration drift test procedure sha ll 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 sha ll 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 acco rdance with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 8.5.

vi. Analytical procedures shall be in accord ance 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 sha ll 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 accordan ce with the methods and procedures in 40 CFR Part 60, Appendix B, Specification 2, Sections 2 & 13.0.

ix. Alternative Procedures shall be in acco rdance 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 O 2 and CO 2 CEMS in Stationary Systems

shall be in accordance with the met hods and procedures in 40 CFR Part 60, Appendix B, Specification 3.

xiii. Specifications and Test Procedures fo r 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, SO 2 , 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 SO 2 concentration will be calcula ted using equation 3 below. The DAHS will calculate emissions of NOx, SO 2 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 SO 2 mass emission rates for Unit IGT3 using Equation 3

and 3A below:

ER = (2.0 / 7000) x 10 6 x (S total / GCV) where: (Equation 3)

ER = Default SO2 emission rate for natural gas combustion, lb/mmBtu

S total = Total sulfur content of the natu ral gas from a valid purchase agreement, tariff agreement, or sampling, gr/100 scf

GCV = Gross calorific value of th e 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

10 6 = Conversion factor (Btu/mmBtu)

SO 2 rate = ER x HI rate where: (Equation 3)

SO 2 rate = Hourly mass emission rate of SO 2 , lb/hr

ER = SO 2 default emission rate of 0.06 lbs/MMBtu HI rate = Hourly heat input rate, MMBtu/hr

72 July 13, 2010c. 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 O fficer in accordance with XI.A of Part A.

f. Each calendar month during which the combined 12-month rolling total for the SO 2 , emission rate from Unit IGT3, exceeds 40 tons shall constitute an exceedance. Exceedances shall be reported to the Control O fficer 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 O fficer in accordance with XI.A of Part A.

h. Each individual day and 12-month rolling total for NOx, SO 2 , and CO emission rates in the reporting period shall be included in th e semiannual compliance certification required by VII of Part A.

i. Quality Assurance Requirement s for Natural Gas Fuel Flow meters

i. Each transmitter or transducer sha ll be calibrated by equipment that has a current certificate of traceability to NIST standa rds 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 thr ee 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 accura cy of each transmitter or transducer at each level tested, using the following equation:



### 100 × −

= F S TR ACC where:

ACC = Accuracy of the transmitter or tran sducer as a percentage of full-scale. R = Reading of the NIST traceable re ference 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, cons istent 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 th e NIST traceable reference value).

73 July 13, 2010iii. 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 Gu idelines, the flow meter accuracy requirement is considered to be met for that level.

iv. If during a transmitter or transdu cer accuracy test the flow meter accuracy specification of 2.0 percent is not met at a ny of the levels tested, the Permittee shall repair or replace the transmitter(s) or transducer(s) as nec essary until the flow meter accuracy specification has been ach ieved at all levels. (Note that only transmitters or transducers which are repa ired or replaced need to be re-tested; however, the re-testing is required at all thr ee measurement levels to ensure that the flow meter accuracy specification is met at each level).

v. For orifice-, nozzles, and venturi t ype flow meters, the Pe rmittee 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 me ter 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, 2010Tucson 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 monitori ng, recordkeeping, reporting and testing. Emission standards will be incorporated at a future date wh en 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 th e maintenance, monitoring, recordk eeping and testing of the mercury monitoring systems associated with Unit I4 in acco rdance with the February 17, 2009 ADEQ Consent Order. These requirements are in addition to any appli cable requirements in the Ge neral Provisions in Part A of this permit, unless Attachment I is more stringent.

A. Mailing Address

All requests, reports, applications, submittals, a nd 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 pe r 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 associat ed 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 pollu tion control practices shall mean the practices that conform to those prescr ibed 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, 2010C. Operational & Other Requirements [PCC 17.12.180.A.2]

1. The Permittee shall implement a control stra tegy that is designed to achieve either 0.0087 lbs/GWh or a 50 percent reduction of total merc ury 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 re vision 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 re ductions 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 th e 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 Pe rmittee shall apply the following monitoring, recordkeeping and reporting methods for de termining 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 mercur y reduction year shall not begin until the later of January 1, 2011, or 185 calendar days after th e Control Officer issues the permit revision and shall end on December 31, 2015.

2. The Permittee shall conduct the stack testing dow nstream of Unit I4 fabric filters while coal is being burned as the main fuel, using EPA Refe rence 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 fu el, 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 m onthly 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 th e Permittee decide to utilize analysis of coal samples provided be the coal supplier, an offici al 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 percen t reduction of mercury emissions, using the inlet and outlet mercury da ta (based on coal use) obtained from III.D.2 & III.D.4 of this Section. The calendar year averag e 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 th e 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 15 th and shall contain the results for the

76 July 13, 2010preceding 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 th e 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 Mercur y Standard and any amendments adopted by the Director to ensure that the State Mercury Standa rd 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 en sure 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 excepti on 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