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$: SALT RIVER PROJECT AGRICULTURAL AND POWER IMPROVEMENT DISTRICT …€¦ · · 2017-10-10S:\Word\PERMITS\Issued.v\V20672.ISS.docx PERMIT #V20672.KGW 1 (10/6/17) SRP Copper Crossing$
S:\Word\PERMITS\Issued.v\V20672.ISS.docx PERMIT #V20672.KGW

1 (10/6/17) SRP Copper Crossing Energy Center – Florence

SALT RIVER PROJECT AGRICULTURAL AND POWER IMPROVEMENT DISTRICT – FLORENCE

1. INTRODUCTION .............................................................................................................................................. 4

2. LISTING OF (FEDERALLY ENFORCEABLE) APPLICABLE REQUIREMENTS ........................................................... 4

3. COMPLIANCE CERTIFICATION ......................................................................................................................... 5

A. COMPLIANCE PLAN ......................................................................................................................................... 5 B. COMPLIANCE SCHEDULE ................................................................................................................................... 6

4. AUTHORITY TO CONSTRUCT – MAJOR AND MINOR NSR PERMIT BASED LIMITATIONS .................................. 6

A. GENERALLY .................................................................................................................................................... 6 B. EQUIPMENT AUTHORIZED AND REQUIRED............................................................................................................ 6 C. MAJOR NEW SOURCE REVIEW REQUIREMENTS AND OTHER RESTRICTIONS AND LIMITATIONS ........................................ 7 D. MINOR NEW SOURCE REVIEW REQUIREMENTS..................................................................................................... 9

5. EMISSION LIMITATIONS AND CONTROLS ....................................................................................................... 9

A. APPLICABLE LIMITATIONS ................................................................................................................................. 9 B. ALLOWABLE EMISSIONS ................................................................................................................................... 9 C. BEST AVAILABLE CONTROL TECHNOLOGY (BACT) ................................................................................................. 9

1. Definitions .................................................................................................................................................. 9 2. BACT for Simple Cycle Combustion Turbine Generators (CTGs) ............................................................... 10 3. PM/PM2.5 BACT for Wet Surface Air Coolers (or Similar Technology) and Mechanical Draft Cooling

Tower ....................................................................................................................................................... 12 4. BACT for Emergency Fire Pump ................................................................................................................ 12 5. VOC BACT for Diesel Storage Tank ........................................................................................................... 13 6. GHG BACT for Electric Circuit Breakers .................................................................................................... 13 7. BACT for Equipment Leaks ....................................................................................................................... 13

D. NSPS (SUBPART KKKK) – STATIONARY COMBUSTION TURBINES ........................................................................... 13 E. NSPS (SUBPART TTTT) – GREENHOUSE GAS EMISSIONS FOR ELECTRIC GENERATING UNITS ....................................... 14 F. NSPS (SUBPART IIII) STANDARDS – STATIONARY COMPRESSION IGNITION INTERNAL COMBUSTION ENGINES ................ 14 G. OPACITY LIMITS ............................................................................................................................................ 15

1. SIP Limitation ........................................................................................................................................... 15 2. Rotating Equipment Limitation ................................................................................................................ 15 3. Visibility Limiting Standard ...................................................................................................................... 15

H. FUEL USE LIMITATIONS .................................................................................................................................. 15 I. PARTICULATE AND SO2 EMISSIONS – FUEL BURNING EQUIPMENT .......................................................................... 16 J. FUGITIVE PARTICULATE EMISSION – REASONABLE PRECAUTIONS ............................................................................ 16 K. FUGITIVE PARTICULATE EMISSIONS - SURFACE STABILIZATION ................................................................................ 17 L. GENERALLY APPLICABLE STANDARDS ................................................................................................................ 17

1. Asbestos NESHAP Compliance ................................................................................................................. 18 2. Stratospheric Ozone and Climate Protection ........................................................................................... 18 3. Chemical Accident Prevention .................................................................................................................. 18

M. ADDITIONAL PLANT-WIDE REQUIREMENTS ........................................................................................................ 18 1. Sandblasting............................................................................................................................................. 18 2. Architectural Coatings .............................................................................................................................. 18 3. Spray Painting .......................................................................................................................................... 18 4. Solvent Cleaning ....................................................................................................................................... 18 5. Cutback and Emulsified Asphalt ............................................................................................................... 18

N. ACID RAIN PROGRAM REQUIREMENTS – COMBUSTION TURBINES .......................................................................... 18 O. GENERAL MAINTENANCE OBLIGATION .............................................................................................................. 19



6. COMPLIANCE DEMONSTRATION .................................................................................................................. 20

A. REGULAR EMISSIONS MONITORING AND RECORDKEEPING .................................................................................... 20 1. SO2 parametric monitoring ...................................................................................................................... 20 2. PM10 and PM2.5 parametric monitoring ................................................................................................ 20 3. VOC parametric monitoring ..................................................................................................................... 21 4. HAP parametric monitoring ..................................................................................................................... 21 5. Opacity Screens ........................................................................................................................................ 21 6. Compliance Assurance Monitoring (CAM) for CO from the Combustion Turbines................................... 21 7. Compliance Assurance Monitoring (CAM) for VOCs from the Combustion Turbines ............................... 22

B. BACT COMPLIANCE DEMONSTRATION .............................................................................................................. 22 1. PM/PM2.5, CO, VOC BACT Compliance Demonstration .......................................................................... 22 2. NOx BACT Compliance Demonstration .................................................................................................... 22 3. GHG BACT Compliance Demonstration .................................................................................................... 22 4. Startup and Shutdown BACT Compliance Demonstration ....................................................................... 23 5. BACT Compliance Demonstration for Cooling Tower and Wet Surface Air Coolers ................................. 23 6. BACT Compliance Demonstration for Electric Circuit Breakers ................................................................ 23

C. NSPS (SUBPART KKKK) STATIONARY COMBUSTION TURBINE COMPLIANCE DEMONSTRATION .................................... 24 D. NSPS (SUBPART KKKK) STATIONARY COMBUSTION TURBINE REPORTING AND RECORDKEEPING REQUIREMENTS ........... 25 E. NSPS (SUBPART KKKK) STATIONARY COMBUSTION TURBINE TESTING REQUIREMENTS ............................................. 25 F. NSPS (SUBPART TTTT) GREENHOUSE GAS EMISSIONS FOR ELECTRIC GENERATING UNITS COMPLIANCE DEMONSTRATION

26 G. NSPS (SUBPART TTTT) GREENHOUSE GAS EMISSIONS FOR ELECTRIC GENERATING UNITS TESTING REQUIREMENTS ....... 26 H. NSPS (SUBPART IIII) INTERNAL COMBUSTION ENGINE (ICE) OPERATIONAL COMPLIANCE DEMONSTRATION ................. 26 I. ACID RAIN COMPLIANCE ................................................................................................................................ 27 J. CHEMICAL ACCIDENT PREVENTION REQUIREMENTS ............................................................................................. 27 K. EMISSION TESTING - GENERAL REQUIREMENTS ................................................................................................... 27

1. Test Methods and Protocol ...................................................................................................................... 27 2. Initial Performance Test Requirements .................................................................................................... 28

a. NOx testing ........................................................................................................................................................ 28 b. CO testing. ......................................................................................................................................................... 28 c. PM/PM10/PM2.5 testing. ................................................................................................................................. 28 d. VOC testing. ...................................................................................................................................................... 29 e. HAP (Formaldehyde) testing ............................................................................................................................. 29 f. Opacity .............................................................................................................................................................. 29

3. Subsequent Performance Testing ............................................................................................................ 29 4. Performance Test Notices ........................................................................................................................ 30 5. Test Reports ............................................................................................................................................. 30

L. RECORDKEEPING ........................................................................................................................................... 30 M. SEMI-ANNUAL COMPLIANCE REPORTING ........................................................................................................... 31 N. ANNUAL REGULAR COMPLIANCE/COMPLIANCE PROGRESS CERTIFICATION ............................................................... 31

7. OTHER REPORTING OBLIGATIONS ................................................................................................................ 32

A. DEVIATIONS FROM PERMIT REQUIREMENTS ....................................................................................................... 32 B. NOTIFICATIONS............................................................................................................................................. 32 C. ANNUAL EMISSIONS INVENTORY ...................................................................................................................... 33

8. FEE PAYMENT ............................................................................................................................................... 33

9. GENERAL CONDITIONS ................................................................................................................................. 33

A. TERM ......................................................................................................................................................... 33 B. BASIC OBLIGATION ........................................................................................................................................ 33 C. DUTY TO SUPPLEMENT APPLICATION ................................................................................................................ 34



D. RIGHT TO ENTER ........................................................................................................................................... 34 E. TRANSFER OF OWNERSHIP .............................................................................................................................. 34 F. POSTING OF PERMIT ...................................................................................................................................... 34 G. PERMIT REVOCATION FOR CAUSE ..................................................................................................................... 34 H. CERTIFICATION OF TRUTH, ACCURACY, AND COMPLETENESS ................................................................................. 35 I. PERMIT EXPIRATION AND RENEWAL.................................................................................................................. 35 J. SEVERABILITY ............................................................................................................................................... 35 K. PERMIT SHIELD ............................................................................................................................................. 35 L. PERMIT REVISIONS ........................................................................................................................................ 35 M. PERMIT RE-OPENING ..................................................................................................................................... 36 N. RECORD RETENTION ...................................................................................................................................... 36 O. SCOPE OF LICENSE CONFERRED ........................................................................................................................ 36 P. EXCESS EMISSION REPORTS; EMERGENCY PROVISION .......................................................................................... 36

10. ADDITIONAL PROVISIONS APPLICABLE TO TITLE V SOURCES ........................................................................ 38

A. ENFORCEMENT BY THE ADMINISTRATOR AND CITIZENS ......................................................................................... 38 B. FEDERAL ENFORCEABILITY EXCLUSIONS ............................................................................................................. 38

11. EQUIPMENT ................................................................................................................................................. 38

12. INSIGNIFICANT ACTIVITIES ........................................................................................................................... 39

APPENDIX A: SEMI-ANNUAL REPORT ................................................................................................................... 40



1. Introduction

This permit pertains to a new natural gas power plant, operated by Salt River Project Agricultural

Improvement and Power District (SRP). The SIC Code is 4911. The facility is located on Pinal County

parcel numbers 210-24-001J, 210-24-001M, 210-24-001R, in Florence, Arizona. The source is situated in

an area classified as non-attainment for PM10 and attainment or unclassifiable for all other criteria

pollutants.

The facility has up to a nominal 1684 MW (at ISO conditions) generating capacity, provided by two

aeroderivative simple cycle combustion turbine generators and up to six frame simple cycle combustion

turbines that burn natural gas. The permit allows for construction of one of three potential combinations of

two aeroderivative simple cycle combustion turbine generators and either six GE frame simple cycle

combustion turbines for a total of 1,412 MW generation capacity, or six Siemens frame simple cycle

combustion turbines for a total of 1,382 MW generation capacity, or five Mitsubishi frame simple cycle

combustion turbines for a total of 1,272 MW generation capacity (generation capacity values listed here as

nominal peak summer rating at 102 °F with no evaporative cooling). Ancillary equipment includes three

wet surface coolers (or similar technology), a cooling tower, a nominal 220 hp diesel-fired emergency fire

pump, a 500 gallon diesel storage tank, and project associated valves, pressure relief devices, connectors,

and electric circuit breakers. Section 11 of this permit recites a list of emission-generating equipment

covered under this permit. Emissions consist of typical products-of-combustion and fugitive emissions.

Applicable Federal standards include New Source Performance Standards (NSPS) 40 Code of Federal

Regulations (CFR) Part 60 Subpart KKKK, Subpart TTTT, and Subpart IIII. Provisions of 40 CFR Part 60

Subpart KKKK, Standards of Performance for Stationary Combustion Turbines, apply to each combustion

turbine. 40 CFR Part 60 Subpart TTTT, Standards of Performance for Greenhouse Gas Emissions for

Electric Generating Units, applies to each combustion turbine. 40 CFR Part 60 Subpart IIII, Standards of

Performance for Stationary Compression Ignition Internal Combustion Engines applies to the emergency

fire pump.

This permit is issued under the Pinal County Air Quality Control District (PCAQCD) State Implementation

Plan (SIP) approved authority and under a delegation agreement with the United States Environmental

Protection Agency (EPA). This permit is the initial unitary permit for the facility and includes Prevention

of Significant Deterioration (PSD) construction provisions, Clean Air Act (CAA) Title IV Acid Rain

provisions, CAA Title V operating provisions and CAA Title VI Stratospheric Ozone Protection

provisions. This permit also serves as a Greenhouse Gas (GHG) PSD construction permit pursuant to a 40

CFR 52.21 delegation agreement with (EPA). The project is subject to PSD requirements for carbon

monoxide (CO), particulate matter (PM), particulate matter with aerodynamic diameter less than 2.5

micrometers (PM2.5), volatile organic compounds (VOC), oxides of nitrogen (NOx), and greenhouse gases

(GHGs). The project has accepted synthetic minor limits that have been incorporated into the Title V

operating permit to limit particulate matter with aerodynamic diameter less than 10 micrometers (PM10)

below the applicability threshold for Nonattainment New Source Review (NNSR) construction permitting

requirements. The facility will control emissions using Best Available Control Technology (BACT)

including but not limited to requirements to use a CO oxidation catalyst to control CO and VOC emissions,

and Selective Catalytic Reduction (SCR) to control NOx emissions from the combustion turbines.

2. Listing of (Federally Enforceable) Applicable Requirements

[Mandated by 40 CFR §70.5(c)(4)]

A. The listed specific provisions of the Pinal-Gila Counties Air Quality Control District (PGAQCD)

Regulations, as adopted by the Pinal County Board of Supervisors on the dates listed, and

approved by the Administrator as elements of the Arizona State Implementation Plan (SIP) by the

Federal Register (FR) notice listed:

7-3-1.2 Emission Standards - Particulate Emissions - Fugitive Dust

(3/31/75) 43 FR 50531 (11/15/78)



7-3-1.1 Visible Emissions; General

(6/16/80) 47 FR 15579 (4/12/82)

B. Those specific provisions of the Pinal County Air Quality Control District Code of Regulations

(PCAQCD Code), as adopted by the Pinal County Board of Supervisors on dates listed, and

approved by the Administrator as elements of the Arizona State Implementation Plan (SIP) by the

Federal Register (FR) notice listed:

2-8-300 Visibility Limiting Standard

(5/18/05) 71 FR 15043 (3/27/06)

4-2-040 Fugitive Dust Standards

(6/29/93) 72 FR 41896 (08/01/07)

4-1-030 Nonattainment Area Fugitive Dust

(10/28/15) 82 FR 20267 (5/1/17)

C. The New Source Performance Standards (NSPS), 40 CFR Part 60, Subpart IIII, for Stationary

Compression Ignition Internal Combustion Engines, §§40 CFR 60.4205(c), 60.4206, 60.4207(b),

60.4209, 60.4211(a)(c)(f), 60.4214(d)

D. The New Source Performance Standards (NSPS), 40 CFR Part 60, Subpart KKKK, Standards of

Performance for Stationary Combustion Turbines, §§40 CFR 60.4305, 60.4320, 60.4330(a)(1) or

(2), 60.4333, 60.4335, 60.4340, 60.4345, 60.4350, 60.4350(g), 60.4365, 60.4375, 60.4380,

60.4380(b), 60.4395, 60.4405, 60.4420, Table 1 of 40 CFR Part 60, Subpart KKKK

E. The New Source Performance Standards (NSPS), 40 CFR Part 60, Subpart TTTT, Standards of

Performance for Greenhouse Gas Emissions for Electric Generating Units, §§40 CFR 60.5520, 40

CFR 60.5520(d), 60.5525, 60.5535(a), 40 CFR 60.5580, Table 2 of 40 CFR Part 60, Subpart

TTTT

F. General Provisions, 40 CFR 60, Subpart A, 40 CFR 60.1-60.19

G. Compliance Assurance Monitoring (CAM), 40 CFR Part 64, §§64.1- 64.10

H. Acid Rain Provisions; CAA Title IV, and:

40 CFR Part 72 Permit Regulation - Code §3-6-565

40 CFR Part 73 Sulfur Dioxide Allowance System

40 CFR Part 75 Continuous Emission Monitoring (Acid Rain Program) - Code §3-6-565

I. Protection of Stratospheric Ozone, 40 CFR Part 82, Subpart F - Recycling and Emissions

Reduction

J. National Emission Standards for Hazardous Air Pollutants (NESHAP), 40 CFR Part 61,

Subpart M, Asbestos, §§61.140-61.157 and Appendix A

3. Compliance Certification

A. Compliance Plan

[Mandated by 40 CFR §70. 5(c)(8)] (Code §§3-1-081.C, 3-1-083.A.7)

Insofar as the Permittee is currently in compliance, the compliance plan consists of continued

adherence to the requirements of this permit.



B. Compliance Schedule

[Mandated by 40 CFR §§ 70.5(c)(8), 70.6(c)(3)] (Code §§3-1-060.B.1, 3-1-083.A.7.c)

Insofar as the Permittee is currently in compliance, no compliance schedule to attain compliance is

required.

4. Authority to Construct – Major and Minor NSR Permit Based Limitations

A. Generally

[Federally enforceable pursuant to PCAQCD Code §§3-1-010, 3-1-040 (10/12/95) approved as a

SIP element at 65 FR 79742 (12/20/00) and 40 CFR 52.21 (delegated for GHGs)]

This permit authorizes the construction of the equipment enumerated in the "Equipment Schedule"

below. Emissions from this facility, specifically the emissions from the equipment described in the

Equipment Schedule, and the operating configuration more fully described in the application for

permit, fall subject to the enforceable limitations set forth either below or elsewhere in this permit.

Therefore, based on the regulations in effect upon the date of issuance of this permit and a finding

that allowable emissions from the equipment described in the Equipment Schedule will neither

cause nor contribute to a violation of any ambient air quality standard even without additional

limitations this permit constitutes authority to construct and operate such equipment.

B. Equipment Authorized and Required

[Federally enforceable pursuant to PCAQCD Code §3-3-250.A (2/22/95) approved as a SIP

element at 65 FR 79742 (12/20/00)]

1. This permit authorizes the installation of 2 Simple Cycle Aeroderivative Combustion

Turbine Generators (CTGs) (GE LMS100PA or equivalent technology) along with any

one of the following CTG equipment manufacturer specific combinations:

a. 6 GE 7F.05 (or equivalent technology) Simple Cycle Frame CTGs ; or

b. 6 Siemens SGT6-5000F (or equivalent technology) Simple Cycle Frame CTGs;

or

c. 5 Mitsubishi M501GAC (or equivalent technology) Simple Cycle Frame CTGs;

Equivalent technology as used in this permit shall mean equipment by the same

manufacturer that has equivalent capabilities and the same or less emission profile.

2. Control devices for CTGs:

a. Selective Catalytic Reduction (SCR) Systems;

b. Oxidation Catalyst Systems;

3. Three wet surface air coolers or equivalent cooling technology (for the frame units);

4. Mechanical-induced draft wet cooling tower (for the aeroderivative units);

5. A nominal 220-hp emergency fire pump;

6. 500 gallon diesel storage tank;

7. Associated valves, pressure relief valves, and connectors; and,



8. An electrical switchyard containing circuit breakers.

9. Permittee shall design and operate each CTG to incorporate:

a. A “low-NOx” combustion operation (water injection for Aeroderivative units

and low-NOx design for Frame units);

b. A system for the Selective Catalytic Reduction of NOx (SCR), including

ammonia injection and a catalyst system;

c. A CEMS system for NOx, configured to meet prevailing Acid Rain

requirements as specified under 40 CFR §75.12, Specific Provisions for

monitoring NOx emission rate;

d. A CEMS system for CO2, configured to meet prevailing Acid Rain requirements

as specified under 40 CFR §75.13, Specific Provisions for monitoring CO2

emissions;

e. An oxidation catalyst system for control of CO and VOC emissions;

f. A system for monitoring and recording the inlet temperature for the oxidation

catalyst.

g. Each stack shall be equipped with such platforms and sampling ports as may be

required to fulfill the testing and monitoring requirements set forth below;

h. Separate fuel-flow meters for each respective CTG.

C. Major New Source Review Requirements and Other Restrictions and Limitations

1. Permittee shall limit the facility-wide PM10 emissions to a rolling 12-month total of less

than 100 tons (PM10 emissions cap).

[Federally enforceable pursuant to Arizona Administrative Code (AAC) R18-2-403

approved as a SIP element at 80 FR 67319 (11/2/15)] [Federally enforceable pursuant

to PCAQCD Code 3-1-084 (8/15/94) approved as a SIP element at 61 FR 15717

(4/9/96)]

a. Monitoring Requirements to Avoid PM10 major source status

[Federally enforceable provision, pursuant to Code §3-1-081(9/5/01) approved

as a SIP element at 66 FR 63166 (12/5/01)]

i. In order to ensure that the PM10 emissions cap is not exceeded,

Permittee shall:

On a monthly basis, generate a record of cumulative actual PM10

emissions for the previous month and for the preceding twelve calendar

months.

ii. Exceeding the PM10 emission cap shall constitute a violation of this

permit for each day that emissions of the pollutant were emitted from

any part of the facility during:

The calendar month in which the cap was exceeded and any subsequent

calendar month in which the cap continues to be exceeded.



2. The following limitations on hours of operation of the CTGs combined with the

PM/PM2.5 BACT limitations for the CTGs will limit source-wide PM10 emissions to

less than 100 tons per year so that the facility does not trigger Nonattainment New Source

Review requirements.

[Federally enforceable pursuant to PCAQCD Code §3-1-0-084 (2/22/95) approved as a

SIP element at 65 FR 79742 (12/20/00)]

a. The Permittee shall not exceed the following hours of operation for each CTG.

The hours of operation limitations for each CTG listed here do not include

periods of time during startup and shutdown of the unit.

The two Aeroderivative Units (GE LMS 100 PA or equivalent) shall not operate

cumulatively more than 7,468 hours per calendar year.

The Frame Units (GE 7FA.05 or Siemens SGT6-5000F or Mitsubishi

M501GAC1) shall not operate cumulatively more than 19,200 hours per year (if

GE or Siemens models are used) or more than 16,000 hours per year (if

Mitsubishi model used).

i. In order to ensure that the hourly limit is not exceeded, Permittee shall:

Each month generate a report of operating hours for each CTG during

the preceding calendar month and a report of cumulative operating

hours for each CTG during the preceding twelve calendar months

b. The Permittee shall not exceed the following number of startup and shutdown

cycles per year for each CTG.

The two Aeroderivative Unit (GE LMS 100 PA or equivalent) shall not exceed

cumulatively 1,460 startup and shutdown cycles per calendar year.

The Frame Units (GE 7FA.05 or Siemens SGT6-5000F or Mitsubishi

M501GAC1) shall not exceed cumulatively 1800 startup and shutdown cycles

per year (if GE or Siemens models are used) or 1,500 startup and shutdown

cycles per year (if Mitsubishi model used).

3. Permittee shall limit the facility-wide Hazardous Air Pollutant (HAP) emissions to a

rolling 12-month total of less than 10 tons for each individual HAP and less than 25 tons

for cumulative HAPs.

[Federally enforceable pursuant to PCAQCD Code 3-1-084 (8/15/94) approved as a

SIP element at 61 FR 15717 (4/9/96)]

The oxidation catalyst system required for control of CO and VOCs will also reduce

organic HAPs from the CTGs and will limit HAP emissions to less than the 10/25 tons

per year major source definition for HAPs.

4. Timing and Progress of Construction

[Federally enforceable pursuant to PCAQCD Code §3-3-210.4 (2/22/95) approved as a

SIP element at 65 FR 79742 (12/20/00)] [Federally enforceable pursuant to Arizona

Administrative Code (AAC) R18-2-402.I.4 (8/7/12) approved as a SIP element at 80 FR

67319 (11/2/15)]



This permit shall be subject to termination if the proposed construction on the facility has

not commenced construction within 18 months of permit issuance, or if during the

construction work is suspended for more than 18 months after actual construction has

begun. The Control Officer may extend the 18-month period upon a satisfactory showing

that an extension is justified.

D. Minor New Source Review Requirements

1. Emergency Engine (Fire Pump)

[Federally enforceable pursuant to PCAQCD Code §3-1-040 (10/12/95) approved as a

SIP element at 65 FR 79742 (12/20/00)]

Permittee shall install a non-resettable hour meter prior to the startup of the emergency

fire pump engine and shall not operate the emergency fire pump engine more than 500

hours per year.

2. Ammonia Slip

(PCAQCD Code §5-24-1030.D)

Permittee shall control ammonia emissions from the CTG units to a maximum allowable

concentration of 10 ppmvd corrected to 15 percent oxygen as demonstrated by an annual

performance test.

5. Emission Limitations and Controls

[Mandated by 40 CFR §70.6(a)(1)]

A. Applicable Limitations

[Federally enforceable pursuant to PCAQCD Code § 3-1-082 (11/3/93) approved as SIP

Elements at 65 FR 79742 (12/20/00)]

Where different standards or limitations apply under this permit, the most stringent combination

shall prevail and be enforceable.

B. Allowable Emissions


Elements at 65 FR 79742 (12/20/00)]

The owner/operator (Permittee) is authorized to discharge or cause to discharge into the

atmosphere those emissions of air contaminants as set forth in this permit. Unless exempted under

Code§3-2-180, Permittee shall not use any material, process, or equipment not identified in this

permit which will cause emissions of any regulated air pollutant in excess of the 5.5 pound-per-

day de minimis amount, unless authorized by a permit revision under as allowed under this permit,

or by a separate permit issued by the District or other competent authority.

C. Best Available Control Technology (BACT)


Elements at 65 FR 79742 (12/20/00)]

1. Definitions

In complying with the BACT requirements in this permit, the following definitions apply:



a. Minimum Emissions Compliance Load (MECL) is the minimum turbine load

condition where the unit NOx emissions at the outlet of the control device are in

compliance with the normal operations emission limit.

b. Start-up is defined as length of time from initial firing of fuel in the unit to

achieving MECL. This time generally lasts for a period of 30-33 minutes

(depending on unit type) from the initial time of fuel firing.

c. Shutdown is defined as length of time from MECL to unit flame out. This period

generally lasts for a period of 12-20 minutes depending on source type.

d. Normal is defined as those periods of operations that do not qualify as start-up,

shutdown, or malfunction.

e. Malfunction is defined as any sudden and unavoidable failure of air pollution

control equipment, process equipment or a process to operate in a usual manner,

but does not include failures that are caused by poor maintenance, careless

operation or any other upset condition or equipment breakdown which could have

been prevented by the exercise of reasonable care.

f. Event is defined as either a period of a single start-up or a period of a single

shutdown.

g. Cycle is defined to include both a start-up and shutdown “event.”

2. BACT for Simple Cycle Combustion Turbine Generators (CTGs)

Permittee shall not discharge or cause to be discharged into the atmosphere emissions in

excess of the air pollutant and activity-specific BACT requirement(s) for each specified

emission unit type listed below:

Unit Type: Aeroderivative Simple Cycle (GE LMS100 PA)

Pollutant Mode of

Operation

BACT Emission

Limitation

Time Frame

PM/PM2.5 Normal 5.3 lb/hr 3-test average for the most

recent performance test

NOx Normal 2.5 ppmvd

(corrected to 15% O2)

1-hour average

Start-up 21.9 lbs per event

Shutdown 6.0 lbs per event

CO Normal 4.0 ppmvd (corrected to

15% O2)

3-test average during the

most recent stack test

VOC Normal 2.0 ppmvd



most recent performance

test

CO2e All 1,425lb/MWhgross

12-month rolling average



PM/PM2.5, VOC, CO Start-up

Shutdown

1. Follow

Manufacturer’s

recommended

procedures;

2. Not to exceed

730 cycles

per calendar year

This permit allows for the installation of one of the following alternative frame type

CTGs. Permittee shall comply with BACT limits listed for the type of frame unit

installed.

Unit Type: Frame Simple Cycle GE 7F.05 Frame (Alternative 1)

Pollutant Mode of

Operation

BACT Emission

Limitation

Time Frame

PM/ /PM2.5 Normal 7.1 lb/hr 3-test average for the most




1- hour average




15% O2)





3-test average the during


test

CO2e All 1,313 lb/MWhgross 12-month rolling average


Shutdown

1. Follow

Manufacturer’s

recommended

procedures;

2. Not to exceed

300 cycles

per calendar year

Unit Type Frame Simple Cycle Siemens SGT6-5000F (Alternative 2)

Pollutant Mode of

Operation

BACT Emission

Limitation

Time Frame





1-hour average




15% O2)



VOC Normal 1.2 ppmvd (corrected to

15% O2)



test





Shutdown

1. Follow

Manufacturer’s

recommended

procedures;

2. Not to exceed

300 cycles

per calendar year

Unit Type: Frame Simple Cycle Mitsubishi M501GAC1 (Alternative 3)

Pollutant Mode of

Operation

BACT Emission

Limitation

Time Frame



NOx

Normal 2.5 ppmvd


1-hour average




15% O2)







test



Shutdown

1. Follow

Manufacturer’s

recommended

procedures;

2. Not to exceed

300 cycles

per calendar year

3. PM/PM2.5 BACT for Wet Surface Air Coolers (or Similar Technology) and Mechanical

Draft Cooling Tower

a. The Permittee shall install drift eliminators with a maximum drift loss of 0.0005

percent or less on the mechanical draft cooling tower and each wet surface air

cooler (or similar technology) to control particulate emissions.

b. At all times, including periods of startup, shutdown, and malfunction, the

Permittee shall, to the extent practicable, maintain and operate the high

efficiency drift eliminators in a manner consistent with good air pollution

control practice for minimizing emissions.

4. BACT for Emergency Fire Pump

a. VOC/PM/PM2.5/ NOx/CO BACT

Permittee shall install equipment that is certified by the manufacturer to meet

the emissions standards in 40 CFR Part 60 Subpart IIII and 40 CFR § 89.112 for

emergency fire pumps with a rated power capacity between 130 and 225 HP.

See §5.F for additional details



b. The Permittee shall not operate the emergency fire-pump during non-emergency

situations for greater than 100 hours per calendar year.

c. GHG BACT

The Permittee shall not discharge into the atmosphere from the emergency fire

pump GHG emissions that exceed a 12-month rolling average rate of 163.6 lb

CO2e/MMBtu1.

5. VOC BACT for Diesel Storage Tank

The Permittee shall install a tank with a fixed-roof design to control VOC emissions from

the tank.

6. GHG BACT for Electric Circuit Breakers

a. The Permittee shall install equipment guaranteed by the manufacturer with a

sulfur hexafluoride (SF6) leak rate less than or equal to 0.5% per calendar year.

b. The Permittee shall install a SF6 leak detection system with alarms.

7. BACT for Equipment Leaks

a. VOC/GHG BACT

Permittee shall install good industrial design natural gas supply systems and operate and

maintain the equipment consistent with all applicable safety standards.

D. NSPS (Subpart KKKK) – Stationary Combustion Turbines

[Federally enforceable pursuant to 40 CFR 60.4305, 60.4333]

1. Each CTG and associated SCR and monitoring equipment must be operated and

maintained in a manner consistent with good air pollution control practices for

minimizing emissions at all times including during startup, shutdown, and malfunction.

In addition the Permittee shall comply with the following emission limitations at each

combustion turbine.

2. NOx Emission Limitations

[Federally enforceable pursuant to 40 CFR 60.4320, 60.4350(g), 60.4380(b), 60.4420,

Table 1 of 40 CFR Part 60, Subpart KKKK]

The Permittee shall comply with the following NOx emission limitations for each

combustion turbine.

a. For a combustion turbine firing natural gas with an input greater than 850

MMBtu/hour, no gases shall be discharged to the atmosphere from the

combustion turbine that exceed 15 ppm NOx at 15 percent O2 or 0.43 lb

NOx/MWh based on a 4-hour rolling average.

b. For a combustion turbine firing natural gas with an output greater than 30 MW,

but operating at less than 75% of peak load, no gases shall be discharged to the

1 As long as the Permittee burns fuel approved elsewhere in this permit, this limit will not be exceeded.



atmosphere from the combustion turbine that exceed 96 ppm NOx at 15 percent

O2 or 4.7 lb NOx/MWh based on a 4-hour rolling average.

c. For any operating hour during which conditions in both paragraph §5.D.2.a and

§5.D.2.b exist, the Permittee shall comply with §5.D.2.b. For any operating

period, that exceeds an hour in duration and for which conditions in both

§5.D.2.a and §5.D.2.b exist, the applicable standard is the average of the

applicable standards during each hour.

d. Compliance with the NOx emissions limitations shall be based on a 4-hour

rolling average hourly emissions rate. A 4- hour rolling average is the arithmetic

average of the average NOx emission rate in ppm or ng/J (lb/MWh) measured

by the continuous emission monitoring equipment for a given hour and the three

unit operating hour average NOx emission rates immediately preceding that unit

operating hour, if a valid NOx emission rate is obtained for at least 3 of the 4

hours. “Unit operating hour” means a clock hour during which any fuel is

combusted in the CTG. If the unit combusts fuel for the entire clock hour, it is

considered to be a full unit operating hour. If the unit combusts fuel for only part

of the clock hour, it is considered to be a partial unit operating hour.

3. SO2 Emission Limitations

[Federally enforceable pursuant to 40 CFR 60.4330(a)(2)]

The Permittee shall comply with the following SO2 emission limitations for each

combustion turbine.

a. No fuel shall be burned that contains potential sulfur emissions in excess of 26

ng SO2/J or 0.060 lb SO2/MMbtu heat input (an exempt fuel).

E. NSPS (Subpart TTTT) – Greenhouse Gas Emissions for Electric Generating Units

[Federally enforceable pursuant to 40 CFR 60.5520, Table 2 of 40 CFR Part 60, Subpart

TTTT]

1. The Permittee shall not discharge into the atmosphere CO2 emissions from any simple

cycle combustion turbine in excess of 50 kg per gigajoule (GJ) of heat input or 120 lb

/MMBtu (nominal) on a 12-operating-month rolling average basis.

2. The Permittee shall only use natural gas with a consistent chemical composition that

results in a consistent emission rate of 160 lb CO2/MMBtu or less in the combustion

turbines.

3. The Permittee shall limit the net electric output for each CTG to no more than the design

efficiency or 50%, whichever is less, times the potential electric output, on a 3 calendar

year rolling average. The design efficiency and potential electric output will be

determined during the initial performance test using the methods referenced in 40 CFR

60 Subpart TTTT.

F. NSPS (Subpart IIII) Standards – Stationary Compression Ignition Internal Combustion Engines

[Federally enforceable; 40 CFR 60.4205(c), 60.4206, 60.4209, 60.4211(a)(c)(f), Table 4 of 40

CFR Part 60, Subpart IIII]

1. The Permittee must purchase and install a fire pump engine that meets the emission

standards listed below for engines between 175 HP and 300 HP and maintain the engine

according to the manufacturer’s instructions for the entire life of the engine.



Model

Year(s)

NMHC+NOX

g/KW-hr

(g/HP-hr)

CO

g/KW-hr

(g/HP-hr)

PM

g/KW-hr

(g/HP-hr)

2009+ 4.0 (3.0) 3.5 (2.6) 0.2 (0.15)

2. Permittee must install a non-resettable hour meter.

G. Opacity Limits

1. SIP Limitation

[Federally enforceable pursuant to PGAQCD Reg. 7-3-1.1 (8/7/80) approved as a SIP

element at 47 FR 15580 (4/12/82)]

The opacity of any plume or effluent shall not be greater than 40 percent as determined

by Reference Method 9 in the Arizona Testing Manual (ADEQ, 1992). Nothing in this

limitation shall be interpreted to prevent the discharge or emission of uncontaminated

aqueous steam, or uncombined water vapor, to the open air.

2. Rotating Equipment Limitation

(Code §5-23-1010)

Permittee shall limit the opacity of emissions from any stationary rotating machinery

such that opacity does not exceed 40% for longer than 10 consecutive seconds. Visible

emissions when starting cold equipment shall be exempt from the requirement of this

subparagraph for the first 10 minutes of operation.

3. Visibility Limiting Standard

[Federally enforceable pursuant to Code §2-8-300 (5/18/05) approved as a SIP element

at 71 FR 15043 (3/27/06)]

The opacity of any plume or effluent from any point source not subject to a New Source

Performance Standard adopted under Chapter 6 of the Code, and not subject to an opacity

standard in Chapter 5 of the Code, shall not be greater than 20% as determined in Method

9 in 40 CFR Part 60, Appendix A-4.

H. Fuel Use Limitations

1. CTG Fuels

(Code §3-3-250.A.1)

In the CTG units, Permittee is allowed to burn exclusively pipeline natural gas, provided

Permittee shall not burn natural gas having a total sulfur content in excess of 0.25 grains

per 100 standard cubic feet (scf)2.

2. Emergency Engine (Fire Pump) Fuels

a. Local Limit

(Code §5-23-1010.F)

2 Sulfur concentration of natural gas utilized in the application to build the SO2 emission factor. See Table 3-1 of

September 2016 SRP CCEC application.



Permittee shall only burn diesel fuel having a sulfur content less than 0.90

percent sulfur by weight

b. NSPS Limit – Subpart IIII

[Federally enforceable pursuant to 40 CFR 60.4207.b]

Permittee shall only burn diesel fuel having a sulfur content of 15ppm or less

and a minimum cetane index of 40 or a maximum aromatic content of 35

volume percent.

3. Other Fuels

(Code §§3-1-081.G, 5-23-1010.F)

Permittee shall not use used oil, used oil fuel, hazardous waste, or hazardous waste fuel

(as defined in federal, state, or county codes and rules) in any engine or turbine without

first obtaining a separate permit or an appropriate permit revision.

I. Particulate and SO2 Emissions – Fuel Burning Equipment

(Code §5-23-1010)

1. For each combustion turbine or fire pump with a heat input capacity of 4,200 million Btu

or less per hour, particulate emissions shall not exceed:

E = 1.02Q0.769, where E = maximum emissions in lbs./hr. for each million BTU per hour

heat input, and Q = maximum heat input capacity in million BTU per hour.

2. For each fire pump SO2 emissions shall not exceed 1.0 lb/million BTU heat input.

J. Fugitive Particulate Emission – Reasonable Precautions

[Federally enforceable pursuant to Code §4-2-040 (6/29/93) approved as a SIP element at 72

FR 41896 (8/1/07) and PGAQD Reg. 7-3-1.2 (7/1/75) approved as a SIP element at 43 FR

53034(11/15/78)]

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

subdivision site, driveway, parking area, vacant lot or sales lot, or an urban or suburban

open area to be constructed, used, altered, repaired, demolished, cleared, or leveled, or

the earth to be moved or excavated, or fill dirt to be deposited, without taking reasonable

precautions to effectively prevent fugitive dust from becoming airborne.

2. Permittee shall not cause, suffer, allow, or permit a vacant lot, or an urban or suburban

open area, to be driven over or used by motor vehicles, such as but not limited to all-

terrain vehicles, trucks, cars, cycles, bikes, or buggies, without taking reasonable


3. Permittee shall not disturb or remove soil or natural cover from any area without taking

reasonable precautions to effectively prevent fugitive dust from becoming airborne.

4. Permittee shall not crush, screen, handle or convey materials or cause, suffer, allow or

permit material to be stacked, piled or otherwise stored without taking reasonable


5. Stacking and reclaiming machinery utilized at storage piles shall be operated at all times

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

wetting agents, as to prevent excessive amounts of particulate matter from becoming



airborne. Other reasonable precautions shall be taken, as necessary, to effectively

prevent fugitive dust from becoming airborne.

6. Permittee shall not cause, suffer, allow or permit transportation of materials likely to give

rise to fugitive dust without taking reasonable precautions to prevent fugitive dust from

becoming airborne. Earth and other material that is tracked out or transported by

trucking and earth moving equipment on paved streets shall be removed by the party or

person responsible for such deposits.

K. Fugitive Particulate Emissions - Surface Stabilization

[Federally enforceable pursuant to Code §4-1-030 (10/28/15) approved as a SIP element at 82

FR 20267 (5/1/17)

1. Permittee shall not cause or allow visible fugitive dust emissions from open areas / vacant

lots (areas not currently utilized for an activity) to exceed 20% opacity based on EPA

Method 9 or the continuous plume or intermittent plume methods listed in PCAQCD

Code §4-9-340.

2. Permittee shall erect barriers or no trespassing signs upon evidence of trespass on open

areas / vacant lots.

3. Permittee shall stabilize any open area / vacant lot greater than 1.0 acre that has 0.5 acre

or more of disturbed surface and sign up for the Pinal County Dust Control forecast

within 30 days of discovery. The open area / vacant lot shall be stabilized the day leading

up to and the day that is forecast to be high risk for dust emissions.

4. Permittee shall not remove vegetation from open areas / vacant lots without applying dust

suppressants before or during the weed abatement. Trackout onto paved surfaces must be

prevented or eliminated and dust suppressants must be applied following weed abatement

to stabilize the entire surface.

5. Stabilization of open areas / vacant lots is determined by the drop ball, threshold friction

velocity, flat vegetation or standing vegetation methods listed in PCAQCD Code 4-9-

320.

6. Permittee shall not cause or allow visible fugitive dust emissions from unpaved lots

(areas being utilized for an activity) greater than 5000 square feet to exceed 20% opacity

based on EPA Method 9 or the continuous plume or intermittent plume methods listed in

PCAQCD Code §4-9-340.

7. Permittee shall not allow silt loading equal to or greater than 0.33 oz/ft2 (or if silt loading

is equal to or greater than 0.33 oz/ft2, shall not allow the silt content to exceed 8%) on

unpaved lots greater than 5000 square feet.

8. Permittee shall stabilize unpaved lots greater than 5000 square feet by paving, applying a

dust suppressant or graveling.

9. Permittee shall clean up trackout on a paved public roadway that exceeds 50 feet within

24 hours of discovery and limit opacity to 20% or less while using a rotary brush or

broom.

10. Permittee shall make a record of the control measures applied.

L. Generally Applicable Standards



1. Asbestos NESHAP Compliance

[Federally enforceable pursuant 40 CFR Part 61, Subpart M] (Code §§7-1-030, 7-1-

060)

Permittee shall comply with Code §§7-1-030.A. and 7-1-060 and 40 CFR Part 61,

Subpart M, when conducting any renovation or demolition activities at the facility.

2. Stratospheric Ozone and Climate Protection

[40 CFR Part 82 Subpart F]

The Permittee shall comply with the standards for recycling and emissions reduction

pursuant to 40 CFR Part 82, Subpart F, Recycling and Emissions Reduction.

3. Chemical Accident Prevention

[40 CFR Part 68]

If the facility has more than a threshold quantity of ammonia, the Permittee shall comply

with the planning requirements set forth in 40 CFR Part 68.

M. Additional Plant-Wide Requirements

1. Sandblasting

(PCAQCD Code §5-4-160)

If the Permittee engages in sandblasting operations, the Permittee shall comply with the

provisions listed in PCAQCD Code Chapter 5, Article 4.

2. Architectural Coatings


If the Permittee engages in architectural coating operations, the Permittee shall comply

with the provisions listed in PCAQCD Code Chapter 5, Article 12.

3. Spray Painting


If the Permittee engages in spray painting operations, the Permittee shall comply with the


4. Solvent Cleaning


If the Permittee engages in solvent cleaning operations, the Permittee shall comply with

the provisions listed in PCAQCD Code Chapter 5, Article 15.

5. Cutback and Emulsified Asphalt


If the Permittee engages in asphalt paving operations, the Permittee shall comply with the


N. Acid Rain Program Requirements – Combustion Turbines

[Federally enforceable pursuant to 40 CFR Parts 72, 73, 75] (Code §3-6-565)

1. Affected Units



For purposes of the continuous emission monitoring and reporting requirements under the

Acid Rain program, each CTG constitutes an “affected unit,” and shall be known as CC1

through CC8.

2. The Acid Rain Phase II Permit application and Certificate of Representation signed by the

Designated Representative shall constitute the basis of the Acid Rain Permit element of

this permit.

3. The Permittee shall comply with the Acid Rain requirements listed in 40 CFR Parts 72, 73

and 75, and any additional requirements listed within this permit. At a minimum,

compliance with 40 CFR Part 75 shall include installation and operation of monitoring

equipment and/or maintenance of recordkeeping as required under 40 CFR §§75.10, 75.11,

75.12 and 75.13

4. The Permittee shall hold SO2 allowances as of the allowance transfer deadline in the

facility’s compliance account not less than the total annual actual emissions of SO2 for the

previous calendar year from each Part 75 affected operating unit as required by the Acid

Rain Program. In calculating those allowances, Permittee may utilize SO2 Allowance

Allocations for the respective units, as follows:

Affected Units Pollutant Allowances

CC1-CC8 SO2 NA

5. When provisions or requirements of the regulations incorporated pursuant to Code §3-6-

565 (Acid Rain Program) conflict with any of the other applicable requirements set forth

in this permit, the regulations incorporated under §3-6-565 shall apply and take

precedence.

6. No permit revision shall be required for increases in emissions that are authorized by

allowances acquired pursuant to the Acid Rain Program, provided that such increases do

not require a permit revision under any other applicable requirement. (Code §3-1-

081.A.6.a)

7. No limit shall be placed on the number of allowances held by the source. The source may

not, however, use allowances as a defense to be in non-compliance with any other

applicable requirement. (Code §3-1-081.A.6.b)

8. Any such allowance shall be accounted for according to the procedures established in

regulations promulgated under Part IV of the CAA, commonly known as CAA Title IV.

(Code §3-1-081.A.6.c)

9. All of the following are prohibited: (Code §3-1-081.A.6.d.)

a. Annual emissions of sulfur dioxide in excess of the number of allowances to emit

sulfur dioxide held by the owners or operators of the unit or the designated

representative of the owners or operators.

b. Exceedances of applicable emission rates specified in this permit.

c. The use of any allowance prior to the year for which it was allocated.

d. Contravention of any other provision of this permit.

O. General Maintenance Obligation

[Federally Enforceable Provision pursuant to code §3-1-081.E (9/5/01) approved as a SIP

element at 66 FR 63166 (12/5/01)](Code 8-1-030.A.3)



At all times, including periods of start-up, shutdown, and malfunction, owners and operators

shall, to the extent practicable, maintain and operate the permitted facility including associated

air pollution control equipment in a manner consistent with good air pollution control practice

for minimizing emissions.

6. Compliance Demonstration


A. Regular Emissions Monitoring and Recordkeeping

[Federally Enforceable Provision pursuant to code §3-1-083 (2/22/95) approved as a SIP

element at 65 FR 79742 (12/20/00)]

To demonstrate continuing compliance with the emissions limitations and/or to support emission

inventory requirements established under this permit, Permittee shall:

1. SO2 parametric monitoring

[Federally Enforceable Provision pursuant to code §3-1-083 (2/22/95) approved as a

SIP element at 65 FR 79742 (12/20/00)]

a. As an alternative to monitoring fuel sulfur;

i. Natural Gas

Permittee shall maintain an annual certification from the natural gas

fuel supplier or at least annually, sample and analyze the composition

of the pipeline gas to demonstrate the natural gas utilized does not

contain more than 0.25 grains per 100 standard cubic feet (scf) The

Permitttee shall use one of the approved ASTM reference methods,

ASTM D1072-80, 90, D3246-81, 92, 96 or D6667-01, for the

measurement of sulfur in gaseous fuels as referenced in 40 CFR

§60.335, or an approved alternative method,. ; and

ii. Diesel

Permittee shall maintain an annual certification from the diesel fuel

supplier demonstrating that the diesel fuel utilized does not contain

more than 0.9% by weight and 15ppm sulfur.

b. As a surrogate measurement for monitoring actual emissions of sulfur dioxide,

Permittee shall at least semi-annually utilize the sulfur content of the fuel

determined above, the fuel consumption records required elsewhere in the

permit and the SO2 emission calculation methodology set forth in 40 CFR Part

75, Appendix D, to calculate and report SO2 emissions from natural gas.

2. PM10 and PM2.5 parametric monitoring


SIP element at 65 FR 79742 (12/20/00)]

a. As a surrogate for monitoring actual particulate matter emissions from the CTGs

the Permittee shall calculate the quantity of emissions monthly for PM10 and

semi-annually for PM2.5, by multiplying the aggregate fuel flows/heat input for

same type of CTGs (i.e. aeroderivative or frame type) by the corresponding

PM10 and PM2.5 emission factors established in the most recent representative



performance test or if the initial performance test has yet to be completed

emission factors based on the manufacturer’s specifications.

b. As a surrogate measurement for monitoring actual emissions of particulate

matter from the cooling tower the Permittee shall maintain on-site a log of

cooling tower operation containing the average daily flow rate through the

tower. This information along with referenced AP-42 (or equivalent) emission

factors shall be used at least semi-annually to calculate the quantity of

emissions.

3. VOC parametric monitoring


SIP element at 65 FR 79742 (12/20/00)]

a. As a surrogate for monitoring actual emissions, Permittee shall periodically, at

least semi-annually, calculate the quantity of emissions, by multiplying the

aggregate fuel flows/heat input by the corresponding VOC emission factors

defined in the most recent performance test.

4. HAP parametric monitoring


SIP element at 65 FR 79742 (12/20/00)]

a. As a surrogate for monitoring actual emissions, Permittee shall periodically, at

least semi-annually, calculate the quantity of emissions, by multiplying the

aggregate fuel flows/heat input by the corresponding formaldehyde emission

factor defined in the most recent performance test and by referencedAP-42 (or

equivalent) emission factors for any other identified HAPs.

5. Opacity Screens


SIP element at 65 FR 79742 (12/20/00)]

a. On at least a semi-annual basis, Permittee shall conduct a visual opacity screen

test on the exhaust(s) from all CTGs and/or control devices when in operation. If

visible emissions (other than steam) are observed, Permittee shall have a full

method 9 opacity test performed by a certified opacity observer, and shall provide

a copy of the resulting report to the District within 10 days. Permittee shall

maintain a record of all opacity screens and tests conducted.

6. Compliance Assurance Monitoring (CAM) for CO from the Combustion Turbines

[Federally enforceable pursuant to 40 CFR §64.3 and §64.7]

a. Permittee shall install, calibrate, maintain and operate a temperature monitoring

system according to the manufacturer’s specification and consistent with the

monitoring requirements of 40 CFR Part 64 at the inlet of the oxidation catalyst.

b. Permittee must submit a permit revision application within 30 days of

commencing construction in order to incorporate into this permit a temperature

range that is to be maintained at the oxidation catalyst inlet based on the

equipment selected.



c. The permit revision application must define the precision and accuracy of the

temperature probe necessary to monitor the proposed range and propose an

averaging time for the temperature parameter.

d. The oxidation catalyst inlet temperature shall be monitored and recorded

continuously. The data collection system shall record the temperature parameter

at least once every fifteen minutes.

e. The temperature monitoring system shall be calibrated at least annually. Records

of these calibrations shall be available upon request.

f. Excursions of the defined temperature range shall reported as defined in §7.A

g. The permit revision shall define when a Quality Improvement Plan (QIP) shall be

implemented consistent with 40 CFR §64.8.

7. Compliance Assurance Monitoring (CAM) for VOCs from the Combustion Turbines

[Federally enforceable pursuant to 40 CFR §64.3 and §64.7]

a. If the Permittee elects to install the Mitsubishi M501GAC units the oxidation

catalyst inlet temperature monitoring system required above will satisfy the CAM

requirements found in 40 CFR Part 64 and will serve as a performance indicator

for controlling VOC emissions..

B. BACT Compliance Demonstration


Elements at 65 FR 79742 (12/20/00)]

1. PM/PM2.5, CO, VOC BACT Compliance Demonstration

a. Permittee shall maintain records of fuel used for demonstrating ongoing

compliance with the applicable PM/PM2.5, CO and VOC emission limitations.

b. Compliance will be demonstrated if the last performance test demonstrated

compliance with the applicable PM/PM2.5, CO, and VOC emission limitations

and there is no change to the type of fuel used.

2. NOx BACT Compliance Demonstration

Each month, using data collected from the NOx CEMS, the Permittee shall determine

compliance with the normal operation NOx emission limitation in §5.C.2 by calculating a

1-hour average NOx concentrations for each hour in which the CTG operated during the

previous month.

3. GHG BACT Compliance Demonstration

Each month, Permittee shall determine compliance with the CO2e emission limitations

listed in §5.C.2 by calculating a 12-month rolling average for the previous month as

follows:

a. Calculating the tons of CO2 emitted hourly over the previous month during all

modes of operation using the equations in 40 CFR 75, Appendix G and

summing the hourly emissions for each calendar day of operations; convert CO2



emissions calculated using the equations in 40 CFR 75 from short tons to metric

tons; and

b. Calculate the tons of CH4 and N2O emitted during all modes of operation by

using the default CH4 and N2O emission factors contained in Table C-2 of 40

CFR Part 98, and the measured actual hourly heat input (HHV) for each

calendar day of operation, and then calculate the tons of CO2e (as CH4 and N2O)

based on the procedures contained in the Greenhouse Gas Regulations, 40 CFR

98, Subpart A using the Global Warming Potentials (GWP) listed in Table A-1

of 40 CFR 98, Subpart A (Version July 1, 2016).

c. Sum the emissions calculated in §6.B.4.a and 6.B.4.b;

d. Divide the sum by the measured gross electrical output in terms of gross MWh

for the month to determine an average lb/MWhgross emissions rate for the month.

e. Sum the average emission rate for the month with the average emissions rate for

the immediately preceding 11 months and divide this value by 12 to determine

the 12-month rolling average emissions rate.

4. Startup and Shutdown BACT Compliance Demonstration

a. At all times, including periods of startup, shutdown, tuning, and malfunction, the

Permittee shall, to the extent practicable, maintain and operate each CTG,

including oxidation catalyst systems and SCRs in a manner consistent with good

air pollution control practice for minimizing emissions.

b. Each month Permittee shall determine compliance with startup and shutdown

event emission limitations in §5.C.2 by calculating and recording the total

pounds of NOx emitted during each event using NOx CEMS data during the

previous month.

c. Each month the Permittee shall determine and record compliance with the

startup and shutdown cycle limitations in §4.C.2.b and §5.C.2 by summing the

number of cycles occurring in the last month and adding this value to the sum of

the values for the previous months in the calendar year.

5. BACT Compliance Demonstration for Cooling Tower and Wet Surface Air Coolers

(or Similar Technology)

a. The Permittee shall maintain the drift eliminators for the mechanical draft

cooling tower and the wet surface air coolers (or similar technology) in

accordance with the manufacturer(s) recommendation.

b. On at least a semi-annual basis, Permittee shall conduct a visual inspection of

the drift eliminators for the cooling tower and the Wet Surface Air Coolers (or

similar technology) to ensure proper installation, maintenance and operation.

Permittee shall maintain a record of these visual inspections.

6. BACT Compliance Demonstration for Electric Circuit Breakers

The Permittee shall operate the SF6 leak detection system in accordance with

manufacturer’s instruction for reducing emissions, and shall respond to all alarms as soon

as practicable.



C. NSPS (Subpart KKKK) Stationary Combustion Turbine Compliance Demonstration

[Federally enforceable pursuant to 40 CFR 60.4335, 60.4340, 60.4345, 60.4350, 60.4365]

1. Permittee shall install, calibrate, maintain and operate a NOx diluent continuous emission

monitoring system (CEMS) on each CTG and shall certify and recertify it according to 40

CFR Part 75. The relative accuracy test audit (RATA) of the CEMS shall be performed

on a lb/MMBtu basis.

2. Permittee shall install, calibrate, maintain and operate a CO2 CEMs (diluent CEMS) on

each CTG. The Permittee shall follow the procedures in 40 CFR 75.20 to certify and

recertify the accuracy of the monitoring system.

3. As specified in 40 CFR § 60.13(e)(2), during each full unit operating hour, both the NOx

monitor and the diluent monitor must complete a minimum of one cycle of operation

(sampling, analyzing, and data recording) for each 15-minute quadrant of the hour, to

validate the hour. For partial unit operating hours, at least one valid data point must be

obtained with each monitor 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 for each monitor to validate the NOX emission rate for the hour.

4. A fuel flow meter to monitor unit specific fuel flow to each CTG shall be installed,

calibrated, maintained, and operated in a manner that meets all the applicable

requirements of 40 CFR Part 75. All required fuel flow rate data shall be reduced to

hourly averages.

5. A watt meter to continuously measure and record the gross electric output from each

CTG shall be installed, calibrated, maintained, and operated according to manufacturer's

instructions.

6. The Permittee shall develop and keep on-site a quality assurance (QA) plan for all of the

continuous monitoring equipment described in of this section. For the CEMS and fuel

flow meters, the QA program and plan shall meet the provision of 40 CFR Part 75

Appendix B, Section 1.

7. All CEMS data must be reduced to hourly averages as specified in 40 CFR § 60.13(h).

8. For each unit operating hour in which a valid hourly average, as described in paragraph 2

of this section, is obtained for both NOx and diluent monitors, the data acquisition and

handling system must calculate and record the hourly NOx emission rate in units of ppm

or lb/MMBtu, using the appropriate equation from Method 19 in appendix A-7 of 40

CFR Part 60. For any hour in which the hourly average O2 concentration exceeds 19.0

percent O2 (or the hourly average CO2 concentration is less than 1.0 percent CO2), a

diluent cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be used in the

emission calculations.

9. For the purposes of identifying excess emissions, correction of measured NOx

concentrations to 15 percent O2 is not allowed.

10. Only quality assured data from the CEMS shall be used to identify excess emissions

under this subpart. Periods where the missing data substitution procedures in 40 CFR Part

75 subpart D are applied are to be reported as monitor downtime in the excess emissions

and monitoring performance report required under §60.7(c).



11. All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data

must be reduced to hourly averages.

12. Calculate the hourly average NOx emission rates, in units of the emission standards under

§5.D.2, using either ppm for units complying with the concentration limit or the

following equation for units complying with the output based standard:

Where:

E = hourly NOX emission rate, in lb/MWh,

(NOx)h = hourly NOx emission rate, in lb/MMBtu,

(HI)h = hourly heat input rate to the unit, in MMBtu/h, measured using the fuel

flowmeter(s), e.g., calculated using Equation D-15a in appendix D to 40 CFR Part 75,

and

P = gross energy output of the combustion turbine in MW.

13. Use the calculated hourly average emission rates from paragraph 11 of this section to

assess excess emissions on a 4-hour rolling average basis. An excess emission is any unit

operating period in which the 4-hour rolling average NOx emission rate exceeds the

applicable emission limit in §5.D.2. For the purposes of this subpart, a “4-hour rolling

average NOx emission rate” is the arithmetic average of the average NOx emission rate

in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for

a given hour and the three unit operating hour average NOx emission rates immediately

preceding that unit operating hour. Calculate the rolling average if a valid NOx emission

rate is obtained for at least 3 of the 4 hours. The 4-rolling average NOx emission rate

shall be calculated by the tenth day of each month.

14. The Permittee shall demonstrate compliance with the SO2 Emission Limitations listed in

§5.D.3 by demonstrating the fuel used does not to exceed the potential sulfur emissions

of 26 ng SO2/J (0.060 lb SO2/MMBtu) heat input. If the fuel quality characteristics in a

current, valid purchase contract, tariff sheet or transportation contract for the fuel

specifies that the total sulfur content for the natural gas used is 20 grains of sulfur or less

per 100 standard cubic feet, the fuel has potential sulfur emissions of less than less than

26 ng SO2/J (0.060 lb SO2/MMBtu) heat input.

D. NSPS (Subpart KKKK) Stationary Combustion Turbine Reporting and Recordkeeping

Requirements

[Federally enforceable pursuant to 40 CFR 60.4365, 60.4375, 60.4380, 60.4395]

1. The Permittee must maintain records of a current, valid purchase contract, tariff sheet or

transportation contract for the natural gas used that documents the sulfur content.

2. For each affected unit required to continuously monitor emissions the Permittee must

submit reports of excess emissions and monitor downtime, in accordance with 40 CFR

Part 60.7(c). Excess emissions must be reported for all periods of unit operation,

including start-up, shutdown, and malfunction. A period of monitor downtime is any unit

operating hour in which the data for a required parameter is either missing or invalid.

3. All reports required under 40 CFR Part 60.7(c) must be postmarked by the 30th day

following the end of each 6-month period.

E. NSPS (Subpart KKKK) Stationary Combustion Turbine Testing Requirements

[Federally enforceable pursuant to 40 CFR 60.4405, 40 CFR 75]



The initial NOx and CO2 performance test required under 40 CFR Part 60.8 shall be performed in

the following manner:

1. Perform a minimum of nine Relative Accuracy Test Audit (RATA) reference method

runs, with a minimum time per run of 21 minutes, at a single load level, within plus or

minus 25 percent of 100 percent of peak load. The ambient temperature must be greater

than 0 °F during the RATA runs.

2. For each RATA run, concurrently measure the heat input to the unit using a fuel flow

meter (or flow meters) and measure the electrical and thermal output from the unit.

3. Use the test data both to demonstrate compliance with the applicable NOx emission limit

under §5.D.2 and to provide the required reference method data for the RATA of the

NOx and CO2 CEMS.

4. Compliance with the applicable emission limit in §5.D.2 is achieved if the arithmetic

average of all of the NOx emission rates for the RATA runs, expressed in units of ppm or

lb/MWh, does not exceed the emission limit.

5. Permittee shall conduct CO2 and NOx CEMs evaluations in accord with the RATA

requirements under 40 CFR Part 75, Appendix A. Evaluations shall be conducted at least

annually unless the unit qualifies for an extension under 40 CFR Part 75, Appendix B.

The deadline for the next RATA shall be no more than 8 calendar quarters after the

quarter in which a RATA was last performed. A 720 operating hour grace period is

available if the RATA cannot be completed by the deadline.

F. NSPS (Subpart TTTT) Greenhouse Gas Emissions for Electric Generating Units Compliance

Demonstration

[Federally enforceable pursuant to 40 CFR 60.5525]

1. Permittee shall maintain purchase records for the permitted fuels.

G. NSPS (Subpart TTTT) Greenhouse Gas Emissions for Electric Generating Units Testing

Requirements


1. Design efficiency of the combustion turbines shall be determined using one of the

following methods: ASME PTC 22 Gas Turbines (incorporated by reference, see §60.17),

ASME PTC 46 Overall Plant Performance (incorporated by reference, see §60.17) or ISO

2314 Gas turbines—acceptance tests (incorporated by reference, see §60.17).

H. NSPS (Subpart IIII) Internal Combustion Engine (ICE) Operational Compliance Demonstration

[Federally enforceable pursuant to 40 CFR 60.4211.f, 60.4214.d]

1. Permittee may operate the emergency engine for the purpose of maintenance checks and

readiness testing, provided the tests are recommended by Federal, State, or local

government, the manufacturer, the vendor or the insurance company associated with the

engine. Permittee shall not operate the ICE for the purposes of maintenance checks and

readiness testing for more than 100 hours per year unless the Permittee maintains records

identifying the Federal, State or local standards that require maintenance and testing of

emergency internal combustion engines beyond 100 hours per year. Copies of such

records shall be provided to the District upon request.



a. Non-emergency operation is limited to 50 hours per calendar year. The 50 hours

of operation in non-emergency situations are counted as part of the 100 hours

per calendar year for maintenance, readiness checks, and demand response

operation.

b. The 50 hours per calendar year for non-emergency operation cannot be used to

supply power to another entity without a separate permit or revision issued by

the District.

I. Acid Rain Compliance

[Mandated by 40 CFR Parts 72 and 75]

For each affected unit, Permittee shall monitor SO2, NOx, and CO2 emissions in accordance with

the requirements of 40 CFR Part 75. At a minimum, monitoring and corresponding records

required under this subsection shall conform to the requirements of 40 CFR §§75.10, 75.11, 75.12

and 75.13.

J. Chemical Accident Prevention Requirements

[Federally enforceable pursuant to 40 CFR Part 68]

If the facility is subject to 40 CFR Part 68 by having more than a threshold quantity of ammonia,

the Permittee shall comply with the planning requirements set forth in 40 CFR Part 68 with regard

to the ammonia-handling and ammonia-storage at the facility, as well as any other process or

facility affected under 40 CFR Part 68, including:

1. Submittal of a compliance schedule as required under 40 CFR Part 68, by the date

required under 40 CFR §68.10(a); or

2. As part of the compliance certification submitted under 40 CFR §70.6(c)(5), a

certification statement that the source is in compliance with all requirements of 40 CFR

Part 68, including the registration and submission of a release management plan.

K. Emission Testing - General Requirements


1. Test Methods and Protocol

[Federally enforceable pursuant to 40 CFR 60.8] (Code §§3-1-160 & 3-1-170)

To the extent this permit requires testing, for purposes of preparing emission inventory

data or otherwise, and specific test methods are not defined elsewhere, Permittee shall

conduct performance tests, using standard test methods specified below, or equivalent

methods as approved by the District pursuant to approval of the test plan required below.

The tests shall be conducted using standard test methods approved by the EPA (40 CFR

Part 60). These tests shall be performed at the maximum practical production rate. A test

plan protocol for each test shall be submitted to the District at least thirty (30) days before

the testing, which period the Control Officer may shorten upon a showing of cause. Any

continuous monitoring systems required for purposes of demonstrating compliance with

an emission cap shall be in place and operating prior to conducting the performance tests.

CEMs required for other purposes may be installed in accord with the schedule allowed

by the underlying applicable requirement. Relevant test methods include, but are not

limited to:

a. nitrogen oxides emissions –Reference Method 7e in 40 CFR Part 60, Appendix

A-4



b. carbon monoxide emissions –Reference Method 10 in 40 CFR Part 60,

Appendix A-4

c. particulate matter emissions - filterable fraction of PM2.5/PM10/PM – Reference

Method 5 in 40 CFR Part 60, Appendix A-3, and Method 202 in 40 CFR Part

51, Appendix M

d. particulate matter emissions - condensable fraction of PM2.5/PM10/PM -

Reference Method 5 in 40 CFR Part 60, Appendix A-3 and Method 202 in 40

CFR Part 51, Appendix M

e. volatile organic compound emissions – Reference Method 25a in 40 CFR Part

60, Appendix A-7

f. hazardous air pollutants (formaldehyde)– EPA Method 320 and EPA Method

323

g. opacity - Reference Method 9 in 40 CFR Part 60, Appendix A-4

h. ammonia - EPA Conditional Test Method CTM-027 or Bay Area Air Quality

Management District Source Test Procedure ST-1B or EPA Method 320

2. Initial Performance Test Requirements

(Code §§3-1-160 & 3-1-170)

Within 60 days after each CTG unit subject to these permit requirements achieves the

capability to operate at its maximum production rate on a sustained basis, but no later

than 180 days after initial start-up of such CTG unit, the Permittee shall conduct initial

performance tests for PM/PM10/PM2.5, NOx, CO, VOC, HAP (formaldehyde), opacity,

and, ammonia slip and either test for design efficiency or provide a manufacturer

certificate of compliance (see §6.K.2.h). These tests shall be performed during normal

operations at the maximum practical generation rate. The CEMS required by this permit

shall be in place and operating prior to conducting the performance tests.

a. NOx testing


In lieu of performing a performance test under 40 CFR §60.4400 using

Reference Method 7E or 20 in 40 CFR Part 60, Permittee shall follow the

procedures in 40 CFR §60.4405 in conjunction with a RATA under §60.4345.

The data may be used to demonstrate compliance both with the NOx emission

limitations and to provide the required reference method data to certify the

CEMS.

b. CO testing.

Permittee shall conduct the initial performance tests for carbon monoxide

emissions on each aeroderivative turbine and each frame turbine. Testing shall

be performed using Reference Method 10 in 40 CFR Part 60, Appendix A-4, or

equivalent methods submitted in the test plan and approved by the District.

c. PM/PM10/PM2.5 testing.



Permittee shall conduct the initial performance tests for total particulate matter

emissions on each aeroderivative turbine and each frame turbine. Testing shall

be performed using Reference Method 5 in 40 CFR Part 60, Appendix A-3, and

Method 202 in 40 CFR part 51, Appendix M, or equivalent methods submitted

in the test plan and approved by the District. Results shall be reported as the

sum of the filterable and condensable fractions and shall serve as a surrogate for

PM, PM10, and PM2.5 emissions.

d. VOC testing.

Permittee shall conduct the initial VOC performance tests on each

aeroderivative turbine and each frame turbine. VOC testing shall be performed

using Reference Method 25A in 40 CFR Part 60, Appendix A-7, or equivalent

method submitted in the test plan and approved by the District.

e. HAP (Formaldehyde) testing

Permittee shall conduct the initial formaldehyde test on one aeroderivative

turbine and one frame turbine. Permittee shall follow the procedures in EPA 320

or 323 or an equivalent method submitted in the test plan and approved by the

District.

f. Opacity

Permittee shall conduct the initial opacity test on each aeroderivative turbine and

each frame turbine. Permittee shall follow the procedures in Reference Method 9

in 40 CFR Part 60 Appendix A-4, 40 CFR §60.11.

g. Ammonia Slip

Permittee shall conduct the initial ammonia slip test on each aeroderivative

turbine and each frame turbine. Permittee shall follow the procedures in EPA

Conditional Test Method CTM 027 or Bay Area Air Quality Management

District Source Test Procedure ST 1B or EPA Method 320 or an equivalent

method submitted in the test plan and approved by the District.

h. Design Efficiency

Permittee or the manufacturer shall determine the Design efficiency, as defined

in 40 CFR Part 60 Subpart TTTT, for the aeroderivative turbines and frame

turbines using one of the following methods: ASME PTC 22 Gas Turbines

(incorporated by reference, see §60.17), ASME PTC 46 Overall Plant

Performance (incorporated by reference, see §60.17) or ISO 2314 Gas

turbines—acceptance tests (incorporated by reference, see §60.17). This

requirement may be met by the manufacturer supplying a certificate of

compliance.

3. Subsequent Performance Testing

(Code §3-1-170)

In addition to the monitoring requirements and RATAs pertaining to NOx, and CO2 listed

in elsewhere in this permit the Permittee shall conduct the following reoccurring

performance tests.



a. At least once every five years (60 months) from the previous test, the Permittee

shall conduct recurring performance tests for opacity, VOCs, PM/PM10/PM2.5,

and formaldehyde using the test methods listed above.

At least one aeroderivative CTG and one frame CTG must be selected for VOC,

PM/PM10/PM2.5, and formaldehyde testing and may be used to represent all of

the identical CTGs at the facility for emissions calculations and emissions

inventory. For each five year cycle two different CTGs shall be selected until all

CTGs have been tested.

The Permittee shall conduct the opacity test on each aeroderivative turbine and

each frame turbine.

b. The ammonia slip test shall be conducted on each CTG annually or 12 months

from the previous test

c. The CO test shall be conducted on each CTG annually or 12 months from the

previous test.

4. Performance Test Notices

Notice of the dates of any performance test required by this permit and a test plan

protocol defining the methods and protocols to be utilized shall be submitted to the

District for approval at least 30 days prior to running the test.

5. Test Reports

A copy of each test report shall be submitted to the District for approval within forty-five

days after the test. The test report shall include any relevant information required under

this permit.

L. Recordkeeping

[Mandated by 40 CFR §70.6(a)(3)] [Federally Enforceable Provision pursuant to code §3-1-083

(2/22/95) approved as a SIP element at 65 FR 79742 (12/20/00)]

The Permittee shall maintain all records required by any applicable requirement or requirement of

any Condition of this permit, including but not limited to all:

1. Required monitoring information including, but not limited to, the following:

a. The date, place, and time of sampling or measurements;

b. The date(s) analyses were performed;

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

d. A description of the analytical techniques or methods used;

e. The results of such analyses; and

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

2. Required measurements, including continuous monitoring system data in ppmvd and

lb/hr, monitoring device and performance testing measurements; all continuous



monitoring system performance evaluations; all continuous monitoring system or

monitoring device calibration checks; adjustments and maintenance performed on these

systems or devices; and all other information required by 40 CFR part 60 recorded in a

permanent form suitable for inspection;

3. Daily records of all startup, shutdown, and tuning events for each CTG. Records shall

contain, at a minimum, the type of event and the duration of the event in hours and

minutes;

4. Daily, monthly, and rolling 12-month total records of operation, in hours and minutes, for

each operating mode (startup, shutdown, normal, and malfunction) for each CTG;

5. Records of any periods during which a continuous monitoring system or device is

inoperative;

6. Log of hours of both emergency and non-emergency operation of the emergency fire

pump, along with a record of the amount of fuel used during that operation;

7. Purchase records for all fuels for use in CTGs per 40 CFR §§60.5520(d)(1) and

60.5535(a);

8. Monthly record of the amount of natural gas combusted in each CTG;

9. Records of maintenance performed on each emission unit and control device;

10. Date and time of any alarm sounded by the circuit breaker leak detection monitoring

program, and Permittee response to the alarm.

11. Rolling 12-month total records of the facility wide PM10 emissions and copies of the

associated emission calculations.

12. Copies of any emissions calculations performed to demonstrate compliance with any

Condition of this permit.

M. Semi-annual Compliance Reporting

[Federally enforceable pursuant to 40 CFR 60.7(c)] [Federally Enforceable Provision pursuant

to code §3-1-083 (2/22/95) approved as a SIP element at 65 FR 79742 (12/20/00)]

1. In order to demonstrate compliance with the provisions of this permit, the Permittee shall

submit a semiannual report containing the information required to be recorded pursuant

to this permit. All instances of deviations from permit requirements shall be clearly

identified in such reports. For brevity, such deviation reports may incorporate by

reference any written supplemental upset reports filed by Permittee during the reporting

period. The report shall be submitted to the District within 30 days after the end of each

semiannual period. Appendix A of this permit is a form which may be used for the

report.

2. For each continuous monitoring device the Permittee shall also submit an excess

emissions and monitoring systems performance report (excess emissions are defined in

applicable subparts) and/or a summary report form as described in 40 CFR 60.79d to the

District and Administrator semiannually that is postmarked by the 30th day following the

end of the six-month period

N. Annual Regular Compliance/Compliance Progress Certification



[Federally Enforceable Provision pursuant to code §3-1-083 (2/22/95) approved as a SIP

Element at 65 FR 79742 (12/20/00)]

Permittee shall annually submit a certification of compliance with the provisions of this permit

to the Pinal County Air Quality Control District and EPA. The certification shall:

1. Be signed by a responsible official, namely the proprietor, a general partner, the

president, secretary, treasurer or vice-president of the corporation, or such other person as

may be approved by the Control Officer as an administrative amendment to this permit;

2. Identify each term or condition of the permit that is the basis of the certification;

3. Verify the compliance status with respect to each such term or condition;

4. Verify whether compliance with respect to each such term or condition has

been continuous or intermittent;

5. Identify the permit provision, or other, compliance mechanism upon which the

certification is based; and

6. Be postmarked within thirty (30) days of the start of each calendar year.

7. Other Reporting Obligations

A. Deviations from Permit Requirements

[Federally Enforceable Provision pursuant to code §3-1-081.A.5.b (9/5/01) approved as a SIP

element at 66 FR 63166 (12/5/01)]

Permittee shall report any deviation from the requirements of this permit along with the

probable cause for such deviation, and any corrective actions or preventative measures taken to

the District within ten days of the deviation unless earlier notification is required by the

provisions of this permit.

B. Notifications

[Federally Enforceable, pursuant to 40 CFR 60.7, 60.13, 60.15(d), 40 CFR 60.5550] [Federally

Enforceable Provision pursuant to code §3-1-103 (2/22/95) approved as a SIP element at 65 FR

79742 (12/2/00)]

For new facilities and modification of existing facilities, the Permittee shall notify the District in

writing of:

1. The actual date of commencement of construction; notice shall be sent within thirty (30)

days of such date; and

2. The anticipated date of initial start-up of each facility of the source for which

construction or modification is allowed by this permit; notice shall be sent not more than

sixty (60) days nor less than thirty (30) days prior to such date;

3. The actual date of start-up; notice shall be sent within fifteen (15) days after such date.

4. Verification of operational status of all continuous monitoring systems including

completion of the manufacturer’s written recommendations for installation, operation,

and calibration of the device. This notice shall be sent within 30 days after CEMS

installation.



5. A written report of the results of the performance evaluation of any CEMS required under

40 CFR § 60.8 within 60 days of completion.

6. Permittee shall provide notifications required by 40 CFR Part 60, Subpart A, pertaining

to installation of, modification of, or a change in the method of operation of NSPS-

affected units in a manner that will cause an increase in the emission rate of a regulated

pollutant. This notice shall be postmarked 60 days or as soon as practicable before the

change is commenced.

7. If the Permittee proposes to replace components of any of the CTGs, such that the fixed

capital cost of the new components exceeds 50 percent of the fixed capital cost that

would be required to construct a comparable entirely new unit, the Permittee shall notify

the District of the proposed replacements. The notice shall be postmarked 60 days (or as

soon as practicable) before construction is commenced, and must include the information

required under 40 CFR §60.15(d).

8. The Permittee shall comply with all applicable reporting requirements of 40 CFR Part 60

and 40 CFR Part 75.

C. Annual Emissions Inventory

[Federally Enforceable Provision pursuant to code §3-1-103 (2/22/95) approved as a SIP element

at 65 FR 79742 (12/2/00)]

Permittee shall complete and submit to the District an annual emissions inventory, disclosing

actual emissions for the preceding calendar year.

The submittal shall be made on a form provided by the District. The inventory is due by the

latter of March 31, or ninety (90) days after the form is furnished by the District.

8. Fee Payment

(Code §3-7-600)

As an essential obligation under this permit, a permit fee shall be assessed by the District and paid by

Permittee in accord with the provisions of Code Chapter 3, Article 7, as they may exist at the time the fee is

due. The permit fee shall be due annually on or before the anniversary date of the issuance of an individual

permit, or formal grant of approval to operate under a general permit, or at such other time as may be

designated now or hereafter by rule. The District will notify the Permittee of the amount to be due, as well

as the specific date on which the fee is due.

9. General Conditions

A. Term

(Code §3-1-089)

This permit shall have a term of five (5) years, measured from the date of issuance.

B. Basic Obligation

(Code §3-1-081)

Permittee shall operate in compliance with all conditions of this permit, the Pinal County Air

Quality Control District ("the District") Code of Regulations ("Code"), and all State and Federal

laws, statutes, and codes relating to air quality that apply to these facilities. Any permit

noncompliance is grounds for enforcement action; for a permit termination, revocation and

reissuance, or revision; or for denial of a permit renewal application and may additionally

constitute a violation of the CAA.



C. Duty to Supplement Application

(Code §§3-1-050.H., 3-1-081.A.8.e., 3-1-087.A.1.c., 3-1-110)

Even after the issuance of this permit, a Permittee, who as an applicant failed to include all

relevant facts, or who submitted incorrect information in an application, shall, upon becoming

aware of such failure or incorrect submittal, promptly submit a supplement to the application,

correcting such failure or incorrect submittal. In addition, Permittee shall furnish to the District

within thirty days any information that the Control Officer may request in writing to determine

whether cause exists for modifying, revoking and reissuing, or terminating this permit or to

determine compliance with this permit and/or the Code.

D. Right to Enter

(Code §§3-1-132, 8-1-050)

Authorized representatives of the District shall, upon presentation of proper credentials and a

showing that the District representative is equipped with certain safety equipment, namely a hard

hat, be allowed:

1. To enter upon the premises where the source is located or in which any records are

required to be kept under the terms and conditions of this permit;

2. To inspect any equipment, operation, or method required in this permit; and

3. To sample emissions from the source.

E. Transfer of Ownership

(Code §3-1-090)

This permit may be transferred from one person to another by notifying the District at least 30

days in advance of the transfer. The notice shall contain all the information and items required by

Code §3-1-090. The transfer may take place if not denied by the District within 10 days of the

receipt of the transfer notification.

F. Posting of Permit

(Code §3-1-100)

Permittee shall firmly affix the permit, an approved facsimile of the permit, or other approved

identification bearing the permit number, upon such building, structure, facility or installation for

which the permit was issued. In the event that such building, structure, facility or installation is so

constructed or operated that the permit cannot be so placed, the permit shall be mounted so as to

be clearly visible in an accessible place within a reasonable distance of the equipment or

maintained readily available at all times on the operating premises.

G. Permit Revocation for Cause

(Code §3-1-140)

The Director of the District (“Director") may revoke this permit for cause, which cause shall

include occurrence of any of the following:

1. The Director has reasonable cause to believe that the permit was obtained by fraud or

material misrepresentation;

2. Permittee failed to disclose a material fact required by the permit application form or a

regulation applicable to the permit;



3. The terms and conditions of the permit have been or are being violated.

H. Certification of Truth, Accuracy, and Completeness

(Code §3-1-175)

Any application form, report, or compliance certification submitted pursuant to the Code shall

contain certification by a responsible official of truth, accuracy, and completeness. This

certification and any other certification required under Chapter 3 of the Code shall state that, based

on information and belief formed after reasonable inquiry, the statements and information in the

document are true, accurate, and complete.

I. Permit Expiration and Renewal

(Code §3-1-089)

Expiration of this permit will terminate the facility’s right to operate unless a timely application

for renewal has been submitted in accordance with §§3-1-050, 3-1-055 and 3-1-060, or a substitute

application for general permit under §3-5-490 is submitted. For Class I permit renewals, a timely

application is one that is submitted at least 6 months, but not greater than 18 months prior to the

date of permit expiration. For Class II or Class III permit renewals, a timely application is one that

is submitted at least 3 months, but not greater than 12 months prior to the date of permit

expiration.

J. Severability

(Code §3-1-081.A.7)

The provisions of this permit are severable, and if any provision of this permit is held invalid the

remainder of this permit shall not be affected thereby.

K. Permit Shield

(Code §§3-1-081.A.8.b, 3-1-102)

1. Compliance with the terms of this permit shall be deemed compliance with any

applicable requirement identified in this permit.

2. 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.

L. Permit Revisions

(Code Chapter 3, Article 2)

1. This permit may be revised, reopened, revoked and reissued, or terminated for cause.

Other than as expressly provided in Code Chapter 3, Article 2, the filing of a request by

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

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

condition.

2. The Permittee shall furnish to the Control Officer, within a reasonable time, any

information that the Control officer may request in writing to determine whether cause

exists for revising, revoking and reissuing, or terminating the permit or to determine

compliance with the permit.

3. Permit amendments, permit revisions, and changes made without a permit revision shall

conform to the requirements in Article 2, Chapter 3, of the Code.



4. Should this source become subject to a standard promulgated by the Administrator

pursuant to CAA §112(d), then Permittee shall, within twelve months of the date on

which the standard is promulgated, submit an application for a permit revision

demonstrating how the source will comply with the standard. (Code §3-1-050.C.5)

5. Revision to Permit Provisions Designated as Federally Enforceable Pursuant to Code §3-

1-084 [Federally Enforceable Provision pursuant to code §3-1-084 (8/15/94) approved

as a SIP Element at 61 FR 15717 (4/9/96)]

As an express condition of preserving the federal enforceability of any provision of this

permit designated "federally enforceable" pursuant to Code §3-1-084, Permittee shall not

make any facility allowed change that would contravene such provision, until thirty (30)

days after the Permittee has previously furnished notice of the proposed change to the

District and to the Administrator, to thereby allow the Administrator opportunity to

comment upon the continued "federal enforceability" of the subject provision after the

proposed change.

M. Permit Re-opening

(Code §3-1-087)

1. This permit shall be reopened if either:

a. The Control Officer determines that it contains a material mistake or that

inaccurate statements were made in establishing the emissions standards or other

terms or conditions of it;

b. The Control Officer determines that it needs to be revised or revoked to assure

compliance with the applicable requirements; or

a. The EPA makes a material objection to any of those federally enforceable

designations under Code §3-1-084 after the normal EPA review period is ended.

2. If this permit must be reopened or revised, the District will notify the Permittee in accord

with Code §3-1-087.A.3.

N. Record Retention

(Code §3-1-083.A.2.b)

Permittee shall retain for a period of five (5) years all documents required under this permit,

including reports, monitoring data, support information, calibration and maintenance records, and

all original recordings or physical records of required continuous monitoring instrumentation.

O. Scope of License Conferred

(Code §3-1-081.A.8.d)

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

P. Excess Emission Reports; Emergency Provision

(Code §3-1-081.E, Code §8-1-030)

1. To the extent Permittee may wish to offer a showing in mitigation of any potential

penalty, underlying upset events resulting in excess emissions shall reported as follows:



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

limits established by this permit. Such report shall be in two parts:

i. Notifications by telephone or facsimile within 24 hours or the next

business day, whichever is later, of the time when the owner or operator

first learned of the occurrence of excess emissions, including all available

information required under subparagraph b. below.

ii. Detailed written notification within 3 working days of the initial

occurrence containing the information required under subparagraph b.

below.

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

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

emissions occurred.

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

applicable limitation.

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

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

v. The nature and cause of such emissions.

vi. If the excess emissions were the result of a malfunction, steps taken to

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

recurrence of such malfunctions.

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

the extent this permit defines procedures governing operations during

periods of start-up or malfunction, the report shall contain a list of steps

taken to comply with this permit.

viii. To the extent excess emissions are continuous or recurring, the initial

notification shall include an estimate of the time the excess emissions will

continue. Continued excess emissions beyond the estimated date will

require an additional notification.

2. An "emergency" means any situation arising from sudden and reasonably unforeseeable

events beyond the control of the source, including acts of God, which situation 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 emissions attributable to the emergency. An emergency shall not include

noncompliance to the extent caused by improperly designed equipment, lack of

preventative maintenance, careless or improper operation, or operator error.

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

with such technology-based emission limitations if the conditions of the following

subparagraph are met.

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

contemporaneous operating logs, or other relevant evidence that:



a. An emergency occurred and that the Permittee can identify the cause(s) of the

emergency;

b. The permitted facility was at the time being properly operated;

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

minimize levels of emissions that exceeded the emissions standards or other

requirements in the permit; and

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

certified mail or hand delivery within 2 working days of the time when

emissions limitations were exceeded due to emergency. The notice shall contain

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

corrective action taken.

10. Additional provisions applicable to Title V Sources

A. Enforcement by the Administrator and Citizens

[Mandated by 40 CFR §70.6(b)]

All terms and conditions in this permit not excluded in Section 10.B. are enforceable by the

Administrator and citizens under the Clean Air Act.

B. Federal Enforceability Exclusions

[Mandated by 40 CFR §70.6(b)(2)]

The terms and conditions listed in following sections are not federally enforceable:

§1.0 - Introduction

§5.G.2 - Rotating Equipment Opacity

§5.H.1 - Natural gas sulfur limit in dscf

§5.H.2.a - Diesel sulfur limit by weight

§5.H.3 - Other fuels limit

§5.I - PM and SO2 limits for fuel burning equipment

§5.M Additional Plant-Wide Requirements

11. Equipment

[Mandated by 40 CFR §70.5(c)(3)(ii)] (Code §3-1-050.B)

Equipment for which emissions are allowed by this permit are as follows:

1. CC1, GE LMS 100PA+ or equivalent technology, 117 MW, simple cycle, natural gas, combustion

turbine aeroderivative unit 1

2. CC2, GE LMS 100PA+ or equivalent technology, 117 MW, simple cycle, natural gas, combustion

turbine aeroderivative unit 2

3. CC3, GE 7F.05, 241 MW, or Siemens STG6, 242 MW, or Mitsubishi M501, 276 MW,or

equivalent technology simple cycle, natural gas, combustion turbine frame unit 1

4. CC4, GE 7F.05, 241 MW, or Siemens STG6, 242 MW, or Mitsubishi M501, 276 MW, or










8. CC8, GE 7F.05, 241 MW, or Siemens STG6, 242 MW, or equivalent technology simple cycle,

natural gas, combustion turbine frame unit 6

9. WSAC1, Wet surface air cooler, 16,200 gpm or equivalent technology



12. WCT, Mechanical induced draft wet cooling tower, 14858 gpm

13. FP, Fire pump, 220 hp, diesel engine

14. CB, Twenty-six (26) circuit breakers filled with SF6

15. NG-FUG, Fugitive natural gas equipment leaks from valves, flanges, connectors

12. Insignificant Activities

[Mandated by 40 CFR §70.5(c)] (Code §3-1-050.E)

Permittee has disclosed the following insignificant activities in the application for this permit:

1. Diesel storage tank, 500 gallons



Appendix A: Semi-Annual Report

Permit V20672.000

Abstract

This constitutes an annual report, documenting emissions and use of emission-generating materials during the

subject reporting period.

Facility - SRP Copper Crossing Energy Center

Florence, AZ 85242

Reporting Period - January to June ____ July to December _____ Year ______

Fuel Consumption Report

Natural gas burned during reporting period - __________________ MMBtu

Diesel fuel burned during reporting period - ___________________ gallons

Operations Report

Power generated during reporting period - ______________________ megawatt-hours

Compliance Report

CC1 - normal run time - __________ hours CC2 - normal run time - ____________ hours

CC1 – startup/shutdown - _________ cycles CC2 – startup/shutdown - ___________ cycles







Operational hours of the fire pump engine - _________ hours

Emissions Report

Emissions of nitrogen oxides - __________ tons Emissions of carbon monoxide - __________________ tons

Emissions of PM10 - ___________________ tons Emissions of volatile organic compounds - ___________ tons

Emissions of sulfur dioxide - ____________ tons Emission of hazardous air pollutants - _______________ tons

Compliance Demonstrations

Were open areas / vacant lots stabilized as required by §5.K……………………………………………. Yes ☐ No ☐

On a separate sheet, describe and explain any monitoring activity or recordkeeping that occurred with respect to the

Asbestos NESHAP, Stratospheric Ozone, or Chemical Accident Prevention requirements defined in §5.L.

Is such a supplemental disclosure attached? ……………...…………………………..…………………. Yes ☐ No ☐



Were the fuel sulfur certifications maintained or gas sampling performed as required by §6.A.1?.….…. Yes ☐ No ☐

Were the opacity screens required by §6.A.5 performed? ………………..………….….………...….…. Yes ☐ No ☐

Was the permit revision related to temperature monitoring at the inlet of the oxidation catalyst submitted within 30

days of commencing construction as required by §6.A.6? ………………….………….…………….…. Yes ☐ No ☐

Did the calculations in §6.B.2 demonstrate compliance with the NOx BACT limits in §5.C.2? ….…… Yes ☐ No ☐

Did the calculations in §6.B.3 demonstrate compliance with the CO2e BACT limits in §5.C.2? …….... Yes ☐ No ☐

Did the calculations in §6.B.4 demonstrate compliance with the BACT startup and shutdown limits in §5.C.2?

……………………………………………………………………………………………………………..Yes ☐ No ☐

Was the visual inspection of the drift eliminators conducted as required by §6.B.5? ………..…..……... Yes ☐ No ☐

Did the SF6 leak detection system required by §6.B.6 and §5.C.6 activate the alarm system? ……........ Yes ☐ No ☐

Were there any periods of NOx excess emissions or monitor downtime as described in §6.C and §6.D? Yes ☐ No ☐

If yes attach a supplemental explanation.

Did the calculations in §6.C demonstrate compliance with NOx NSPS limit in §5.D.2? ……....……... Yes ☐ No ☐

Were the natural gas fuel sulfur documents maintained as required in §6.D? ………………………….. Yes ☐ No ☐

Were the CO2 and NOx RATAs performed as required in §6.E? ………………………………...……... Yes ☐ No ☐

Were the initial tests required in §6.K.2 performed within at least 180 days after initial start-up? …...... Yes ☐ No ☐

Have the PM and VOC tests required by §6.K.3 been conducted within the last 60 months? …….......... Yes ☐ No ☐

Did these tests demonstrate compliance with the PM and VOC BACT limits in §5.C.2? ……..….......... Yes ☐ No ☐

Has the ammonia slip test required by §6.K.3 been conducted within the 12 months? ………………..... Yes ☐ No ☐

Did this test demonstrate compliance with the ammonia limit in §4.D.2? ……….................................... Yes ☐ No ☐

Has the CO test required by §6.K.3 been conducted within the 12 months? …………………………..... Yes ☐ No ☐

Did this test demonstrate compliance with the CO limit in §5.C.2? ……………………......................... Yes ☐ No ☐

On a separate sheet, describe and explain any previously un-reported deviations from the terms of this permit as

required by §7.A. Is such a supplemental disclosure attached? ………..................................................... Yes ☐ No ☐

Were any notifications required by §7.B submitted during this reporting period? ………........................ Yes ☐ No ☐

Has the annual emission inventory required by §7.C been submitted? ………......................................... Yes ☐ No ☐

Certification by Responsible Official

I certify that, based on information and belief formed after reasonable inquiry, that the statements and information in

this report are true, accurate and complete.



Signed ____________________________________________

Print Name ________________________________________

Title ______________________________________________

Date_____________ Contact Phone Number _____________________

Mail to - Pinal County Air Quality Control District

PO Box 987

Florence, AZ 85132

salt river project agricultural and power improvement district …€¦ · ·...

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