AMENDED

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

ISSUED PURSUANT TO THE 

REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION IX

PSD PERMIT NUMBER: SJ 08-01 

PERMITTEE: Avenal Power Center, LLC 

500 Dallas Street, Level 31 

Houston, TX 77002 

FACILITY NAME: Avenal Energy Project 

FACILITY LOCATION: 33119 Avenal Cutoff Road 

Avenal, California 93204 

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C (42 U.S.C. Section 

7470, et. seq.), and the Code of Federal Regulations (CFR) Title 40, Section 52.21, the United 

States Environmental Protection Agency Region 9 (EPA) is issuing an amended Prevention of 

Significant Deterioration (PSD) permit to the Avenal Power Center, LLC (APC). The Permit 

applies to the construction and operation of a new 600 megawatt (MW, nominal) natural gasfired combined-cycle power plant known as the Avenal Energy Project (AEP) in Avenal, 

California. This Amended PSD Permit revises the PSD permit issued to APC on May 27, 2011, 

with the revisions applicable immediately.

APC is authorized to construct and operate the AEP power plant as described herein, in 

accordance with the permit application (and plans submitted with the permit application), the 

federal PSD regulations at 40 CFR § 52.21, and other terms and conditions set forth in this PSD 

Permit. Failure to comply with any condition or term set forth in this PSD Permit may result in 

enforcement action pursuant to Section 113 of the Clean Air Act. This PSD Permit does not 

relieve APC from the responsibility to comply with any other applicable provisions of the Clean 

Air Act (including applicable implementing regulations in 40 CFR Parts 51, 52, 60, 61, 63, and 

72 through 75), or other federal, state, and San Joaquin Valley Air Pollution Control District 

(District) requirements. 

Per 40 CFR § 124.15(b), this PSD Permit becomes effective 30 days after the service of notice of 

theis final permit decision on May 27, 2011 unless review is requested on the permit pursuant to 

40 CFR § 124.19. 

 

 

Gina McCarthy Date 

Assistant Administrator 
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AVENAL ENERGY PROJECT (SJ 08-01)

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

AMENDED FINAL PERMIT CONDITIONS 

PROJECT DESCRIPTION 

The Facility is a combined-cycle power plant capable of generating up to 600 megawatts (MW, 

nominal) of net power. Electrical power will be generated from the combustion of natural gas in 

two 180 MW (nominal) combustion turbine generators (CTG). Exhaust from each gas turbine 

will flow through a dedicated Heat Recovery Steam Generator (HRSG) to produce steam to 

power a shared 300 MW (nominal) Steam Turbine Generator (STG). Each HRSG will be 

equipped with natural gas-fired duct burners to augment steam production during peaking 

operation. Each of the CTGs will be equipped with dry low-NOx (DLN) combustors. The 

Facility will install selective catalytic reduction (SCR) and oxidation catalyst (Ox-Cat) systems. 

Additional equipment includes a natural gas-fired auxiliary boiler, which is used to provide 

steam for auxiliary purposes such as when the plant is off-line or during startup, equipped with 

an ultra low-NOx burner, a natural gas-fired emergency generator equipped with a postcombustion integrated SCR/oxidation catalyst system, and a diesel-fired emergency firewater 

pump engine with a turbocharger and an intercooler/aftercooler. 

The Facility is subject to the Prevention of Significant Deterioration (PSD) Program for 

emissions of Carbon Monoxide (CO), Nitrogen Dioxide (NO2), Particulate Matter (PM), and 

Particulate Matter of less than or equal to 10 micrometers (μm) in diameter (PM10). 

EQUIPMENT LIST 

The following devices are subject to this PSD permit: 

Unit ID Description 

GEN1 

• 180 MW Combustion Turbine Generator (CTG), with a maximum heat input 

rate of 1,856.3 MMBtu/hr, high heating value (HHV) 

• Natural gas-fired General Electric Model Frame 7FA 

• Vented to a dedicated Heat Recovery Steam Generator (HRSG) and a 300 MW 

Steam Turbine Generator (STG) shared with GEN2 

• Emissions of NOx and CO controlled by Dry Low-NOx (DLN) Combustors, 

Selective Catalytic Reduction (SCR), and an Oxidation Catalyst (Ox-Cat) 

GEN2 

• 180 MW CTG, with a maximum heat input rate of 1,856.3 MMBtu/hr (HHV) 

• Natural gas-fired General Electric Model Frame 7FA 

• Vented to a dedicated HRSG and a 300 MW STG shared with GEN1 

• Emissions of NOx and CO controlled by DLN combustors, SCR and an Ox-Cat 
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Unit ID Description 

DB1 • 562.26 MMBtu/hr (HHV) Duct Burner for GEN1, fired on natural gas 

DB2 • 562.26 MMBtu/hr (HHV) Duct Burner for GEN2, fired on natural gas 

D1 • 37.4 MMBtu/hr (HHV) Auxiliary Boiler with ultra low-NOx burner, fired on 

natural gas 

D2 

• 550 kW (860 hp) Emergency Internal Combustion (IC) Engine, fired on natural 

gas 

• Emissions of NOx and CO controlled by post-combustion integrated 

SCR/oxidation catalyst system 

D3 • 288 hp Emergency Diesel-fired IC Engine Firewater Pump Engine 

• Equipped with a turbocharger and an intercooler/aftercooler 

PERMIT CONDITIONS 

I. PERMIT EXPIRATION

As provided in 40 CFR § 52.21(r), this PSD Permit shall become invalid if construction: 

A. is not commenced (as defined in 40 CFR § 52.21(b)(9)) within 18 months after 

the approval takes effect; or 

B. is discontinued for a period of 18 months or more; or 

C. is not completed within a reasonable time. 

II. PERMIT NOTIFICATION REQUIREMENTS

Permittee shall notify EPA Region IX by letter or by electronic mail of the: 

A. date construction is commenced, postmarked within 30 days of such date; 

B. actual date of initial startup, as defined in 40 CFR § 60.2, postmarked within 15 

days of such date; 

C. date upon which initial performance tests will commence, in accordance with the 

provisions of Condition X.G, postmarked not less than 30 days prior to such date. 

Notification may be provided with the submittal of the performance test protocol 

required pursuant to Condition X.G; and 

D. date upon which initial performance evaluation of the continuous emissions 

monitoring system (CEMS) will commence in accordance with 40 CFR § 
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60.13(c), postmarked not less than 30 days prior to such date. Notification may 

be provided with the submittal of the CEMS performance test protocol required 

pursuant to Condition X.F. 

III. FACILITY OPERATION

At all times, including periods of startup, shutdown, shakedown, and malfunction, 

Permittee shall, to the extent practicable, maintain and operate the Facility including 

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

control practice for minimizing emissions. Determination of whether acceptable 

operating and maintenance procedures are being used will be based on information 

available to the EPA, which may include, but is not limited to, monitoring results, opacity 

observations, review of operating maintenance procedures and inspection of the Facility. 

IV. MALFUNCTION REPORTING

A. Permittee shall notify EPA at R9.AEO@epa.gov within two (2) working days 

following the discovery of any failure of air pollution control equipment, process 

equipment, or of a process to operate in a normal manner, which results in an 

increase in emissions above the allowable emission limits stated in Section X of 

this permit. 

B. In addition, Permittee shall provide an additional notification to EPA in writing or 

electronic mail within fifteen (15) days of any such failure described under 

Condition IV.A. This notification shall include a description of the 

malfunctioning equipment or abnormal operation, the date of the initial 

malfunction, the period of time over which emissions were increased due to the 

failure, the cause of the failure, the estimated resultant emissions in excess of 

those allowed in Section X, and the methods utilized to mitigate emissions and 

restore normal operations. 

C. Compliance with this malfunction notification provision shall not excuse or 

otherwise constitute a defense to any violation of this permit or any law or 

regulation such malfunction may cause. 

V. RIGHT OF ENTRY

The EPA Regional Administrator, and/or an authorized representative, upon the 

presentation of credentials, shall be permitted: 

A. to enter the premises where the Facility is located or where any records are 
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required to be kept under the terms and conditions of this PSD Permit; 

B. during normal business hours, to have access to and to copy any records required 

to be kept under the terms and conditions of this PSD Permit; 

C. to inspect any equipment, operation, or method subject to requirements in this 

PSD Permit; and 

D. to sample materials and emissions from the source(s). 

VI. TRANSFER OF OWNERSHIP

In the event of any changes in control or ownership of the Facility to be constructed, this 

PSD Permit shall be binding on all subsequent owners and operators. Permittee shall 

notify the succeeding owner and operator of the existence of this PSD Permit and its 

conditions by letter, a copy of that shall be forwarded to EPA Region IX within thirty 

(30) days. 

VII. SEVERABILITY

The provisions of this PSD Permit are severable, and, if any provision of the PSD Permit 

is held invalid, the remainder of this PSD Permit shall not be affected. 

VIII. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LAWS

Permittee shall construct this project in compliance with this PSD permit, the application 

on which this permit is based and all other applicable federal, state, and local air quality 

regulations. This PSD permit does not release the Permittee from any liability for 

compliance with other applicable federal, state and local environmental laws and 

regulations, including the Clean Air Act. 

IX. RESERVED 

 
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X. SPECIAL CONDITIONS 

 A. Annual Facility Emission Limits 

1. Annual emissions, in tons per year (tpy) on a 12-month rolling average basis, 

shall not exceed the following: 

NOx CO PM PM10

Total Facility 144.3 tpy 602.7 tpy 80.7 tpy 80.7 tpy 

2. Only Public Utilities Commission (PUC)-quality pipeline natural gas shall be 

fired at this Facility. PUC-quality pipeline natural gas shall not exceed a 

sulfur content of 0.36 grains per 100 dry standard cubic feet on a 12-month 

rolling average basis and shall not exceed a sulfur content of 1.0 grains per 

100 dry standard cubic feet, at any time. 

B. Air Pollution Control Equipment and Operation 

As soon as practicable following initial startup of the power plant (startup as 

defined in 40 CFR § 60.2) but prior to commencement of commercial operation 

(as defined in 40 CFR § 72.2), and thereafter, except as noted below in Condition 

X.D, the Permittee shall install, continuously operate, and maintain: (1) the SCR 

systems for control of NOx and the Ox-Cat systems for control of CO for Units 

GEN1 and GEN2, and (2) the post-combustion integrated SCR/oxidation catalyst 

system for control of NOx and CO for D2. Permittee shall also perform any 

necessary operations to minimize emissions so that emissions are at or below the 

emission limits specified in this permit. 

C. Combustion Turbine Generator (CTG) Emission Limits 

1. Except as noted below under Condition X.D, on and after the date of initial 

startup, Permittee shall not discharge or cause the discharge of emissions from 

each CTG Unit (of GEN1 and GEN2) into the atmosphere in excess of the 

following: 

 
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Emission Limit (per CTG) 

(no duct burning) 

Emission Limit (per CTG) 

(with duct burning) 

NOx

• 13.55 lb/hr 

• 1-hr average 

• 2.0 ppmvd @ 15% O2

• 17.20 lb/hr 

• 1-hr average 

• 2.0 ppmvd @ 15% O2

CO 

3-Year Demonstration Period 

• 8.35 lb/hr 

• 1-hr average 

• 2.0 ppmvd @ 15% O2

Post-Demonstration Period 

• 6.27 lb/hr 

• 1-hr average 

• 1.5 ppmvd @ 15% O2

Conditions in X.C.3 may affect 

the timing and applicability of 

post-demonstration period 

emission limits. 

• 10.60 lb/hr 

• 1-hr average 

• 2.0 ppmvd @ 15% O2

PM / PM10 

• 8.91 lb/hr 

• 12-month rolling average 

• PUC-quality pipeline 

natural gas 

• 11.78 lb/hr 

• 12-month rolling average 

• PUC-quality pipeline 

natural gas 

2. Annual heat input to each duct burner (DB1 and DB2) shall not exceed 

449,800 MMBtu per 12-month rolling period. The Permittee shall ensure that 

the duct burners are not operated unless the associated turbine units are in 

operation. 

3. CO Emissions Limit Demonstration Period – The Demonstration Period is 

defined as the first 3 years immediately following the commencement of 

commercial operations. 

a. The Permittee shall design the gas turbines to achieve a CO emission rate 

of 1.5 ppmvd @ 15% O2 and 6.27 lb/hr over a 1-hour period without duct 

firing. Prior to construction, the Permittee shall submit design 

specifications to EPA as proof that the gas turbines were designed to 

achieve such a rate. The Permittee shall also submit a plan to EPA that sets 
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forth the measures that will be taken to maintain the system and optimize 

its performance. 

b. During the Demonstration Period, the Permittee shall operate the gas 

turbines according to the design specifications, within the design 

parameters, and consistent with the maintenance and performance 

optimization plan described above in Condition X.C.3.a. During the 

Demonstration Period the Permittee shall not discharge or cause the 

discharge of CO emissions from each CTG Unit (GEN1 and GEN2) into 

the atmosphere in excess of the following amounts over a 1-hour 

averaging period: 2.0 ppmvd CO @ 15% O2 and (1) 10.60 lb/hr with duct 

firing or (2) 8.35 lb/hr with or without duct firing over a 1-hour averaging 

period. 

c. Following the Demonstration Period, the Permittee shall not discharge or 

cause the discharge of CO emissions from each CTG Unit (GEN1 and 

GEN2) into the atmosphere in excess of the following amounts over a 1-

hour averaging period except as specified in Condition X.C.3.d: 

i. 1.5 ppmvd @ 15% O2 without duct firing; 

ii. 2.0 ppmvd @ 15% O2 with duct firing; 

iii. 6.27 lb/hr without duct firing; and 

iv. 10.60 8.35 lb/hr with duct firing. 

d. If, during the Demonstration Period, the Permittee determines that the CO 

limits in Conditions X.C.3.i or X.C.3.iii are not feasible, the Permittee 

shall submit an application to EPA prior to the end of the Demonstration 

Period requesting a revision of those limits. Such an application must 

contain data and information that demonstrates that the Facility was 

operated according to the design specifications and parameters, and the 

maintenance and performance optimization plan, identified above in 

Condition X.C.3.a, as well as a technical justification explaining why the 

lower limits are not feasible. If, after the applicable review process 

following such a submission (which will include an opportunity for public 

review and comment), it is determined through data and information 

gathered during the Demonstration Period that different CO limits are 

necessary, the limits in Condition X.C.3.i and X.C.3.iii will be revised 

accordingly. Provided that the application specified in this condition is 

postmarked prior to the end of the Demonstration Period, the emission 

limits in Condition X.C.3.b shall remain in effect until EPA evaluates the 

application and makes a final decision regarding the revision of the limits 
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in Conditions X.C.3.i or X.C.3.iii. 

D. Requirements during Gas Turbine (GEN1 and GEN2) Startup and 

Shutdown 

1. Startup is defined as the period of time during which a unit is brought from a 

shutdown status to its operating temperature and pressure, including the time 

required by the unit’s emission control system to reach full operations and 

demonstrate compliance with Conditions X.C. 

2. Shutdown is defined as the period beginning with the lowering of equipment 

from normal operating load to minimum operating load and lasting until fuel 

flow is completely off and combustion has ceased. 

3. During startup and shutdown periods emissions from each CTG and 

associated HRSG unit, verified by the CEMS, shall not exceed the following: 

NOx CO 

Each CTG and HRSG 

Startup / Shutdown 160 lb/hr 1,000 lb/hr 

Both CTG and HRSG 

Combined 

Startup / Shutdown 

240 lb/hr 1,902 lb/hr 

Event 

Duration 

Annual Limit for 

Both CTG 

Combined 

Each CTG and HRSG 

Startup 4.50 hours 

1,248 hours/yr 

Each CTG and HSRG 

Shutdown 0.50 hour 

4. The Permittee must operate the CEMS during startups and shutdowns. 

5. The Permittee must record the time, date, and duration of each startup and 

shutdown event. The records must include calculations of NOx and CO 

emissions during each event based on the CEMS data. These records must be 

kept for five years following the date of such event. 
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6. During startup, the CTG and HRSG emissions shall comply with Condition 

X.D.3, and the SCR system, including ammonia injection, shall be operated in 

a manner to minimize emissions, as technologically feasible, and not later than 

when the load reaches 60% of plant net output. 

E. Auxiliary Combustion Equipment Emission Limits 

1. At all times, including equipment startup and shutdown, Permittee shall not 

discharge, or cause the discharge of emissions from each unit into the 

atmosphere, in excess of the following: 

Unit ID NOx CO PM and PM10

Restrictions on 

Usage 

Unit D1 

37.4 MMBtu/hr 

(HHV) Boiler 

• 9 ppmvd @ 

3% O2

• 3-hr average 

• 50 ppmvd @ 

3% O2

• 3-hr average 

• 0.0034 gr/dscf 

• PUC-quality 

pipeline natural gas 

• 46,675 

MMBtu/yr 

Unit D2 

550 kW (860 hp) 

engine 

• 1.0 g/hp-hr • 0.21 g/hp-hr • PUC-quality 

pipeline natural 

gas 

• 0.34 g/hp-hr 

• 50 hrs/yr 

Unit D3

288 hp firewater 

pump 

• 3.4 g/hp-hr • 0.447 g/hphr • Use of ultra-low 

sulfur fuel, not to 

exceed 15 ppmvd 

fuel sulfur 

• 50 hrs/yr 

2. Unit D1 shall not operate during normal operations of GEN1 or GEN2, except 

during periods of, or immediately following, startup. Unit D1 shall be shut 

down as soon as practicable after the completion of any startup process as 

defined in Condition X.D.1. 

3. Unit D2 restrictions on usage shall be limited to operation of the engine for all 

maintenance and testing. 

4. Unit D3 restrictions on usage shall be limited to the total hours of operations 

for all maintenance and testing. 

5. Units D2 or D3 shall not operate during startup of GEN1 or GEN2, except 

when Units D2 or D3 are required for emergency operations. 

 
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 F. Continuous Emissions Monitoring System (CEMS) for GEN1 and GEN2 

1. At the earliest feasible opportunity after first fire of GEN1 and GEN2 and 

before GEN1 and GEN2 commence commercial operation (as defined in 40 

CFR § 72.2), in accordance with the recommendations of the equipment 

manufacturer and the construction contractor, Permittee shall install, calibrate, 

and operate a CEMS each for GEN1 and GEN2 that measures stack gas NOx, 

CO, and O2 or CO2 concentrations in ppmv. The concentrations shall be 

corrected to 15% O2 on a dry basis. No later than the end of the shakedown 

period as defined in Condition X.J. or upon commencing commercial 

operations, whichever comes first, Permittee shall also maintain, certify, and 

quality-assure a CEMS for each CTG that measures stack gas NOx, CO, and 

O2 concentrations in ppmv, and shall is required to conduct initial certification 

of the CEMS in accordance with Condition X.F.6. The concentrations shall be 

corrected to 15% O2 on a dry basis. 

2. The NOx and O2 CEMS shall meet the applicable requirements of 40 CFR 

Part 75. 

3. The CO CEMS shall meet the applicable requirements of 40 CFR Part 60 

Appendix B, Performance Specification 4, and 40 CFR Part 60 Appendix F, 

Procedure 1, except the relative accuracy specified in section 13.2 of 40 CFR 

Part 60 Appendix B, Performance Specification 4 shall not exceed 20 percent. 

4. Each CEMS shall complete a minimum of one cycle of operation (sampling, 

analyzing, and data recording) for each successive 15-minute clock-hour 

period. 

5. The CEMS shall be tested in accordance with Conditions X.F.2 and X.F.3. 

6. The initial certification of the CEMS may either be conducted separately, as 

specified in 40 CFR § 60.334(b)(1) or as part of the initial performance test of 

each emission unit. CEMS must undergo and pass initial performance 

specification testing on or before the date of the initial performance test. 

7. CEMS shall meet the requirements of 40 CFR § 60.13. Data sampling, 

analyzing, and recording shall also be adequate to demonstrate compliance 

with emission limits during startup and shutdown. 

8. Not less than 90 days prior to the date of initial startup of the Facility, the 

Permittee shall submit to the EPA a quality assurance project plan for the 

certification and operation of the continuous emission monitors. Such a plan 
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shall conform to EPA requirements contained in 40 CFR Part 60 Appendix F 

for CO, 40 CFR Part 75 for NOx and O2 or CO2, and 40 CFR Part 75 

Appendix B for stack flow. The plan shall be updated and resubmitted upon 

request by EPA. The protocol shall specify how emissions during startups and 

shutdowns will be determined and calculated, including quantifying flow 

accurately if calculations are used. 

9. The gas turbine CEMS shall be audited quarterly and tested annually in 

accordance with 40 CFR Part 60 Appendix F, Procedure 1. Permittee shall 

perform a full stack traverse during initial run of annual RATA testing of the 

CEMS, with testing points selected according to 40 CFR Part 60 Appendix A, 

Method 1. 

10. Permittee shall submit a CEMS performance test protocol to the EPA no later 

than 30 days prior to the test date to allow review of the test plan and to 

arrange for an observer to be present at the test. The performance test shall be 

conducted in accordance with the submitted protocol and any changes 

required by EPA. 

11. Permittee shall furnish the EPA a written report of the results of performance 

tests within 60 days of completion. 

12. The stack gas volumetric flow rates shall be calculated in accordance with the 

fuel flowmeter requirements of 40 CFR Part 75 Appendix D in combination 

with the appropriate parts of EPA Method 19. 

13. Prior to the date of initial startup of GEN1 and GEN2, Permittee shall install, 

and thereafter maintain and operate, continuous monitoring and recording 

systems to measure and record the following operational parameters: 

a. The ammonia injection rate of the ammonia injection system of the 

SCR system. 

b. The plant output as noted in Condition X.D.6. 

 G. Performance Tests

1. Stack Tests 

a. Within 60 days after achieving normal operation, but not later than 180 

days after the initial start-up of equipment, and, unless otherwise specified, 

annually thereafter (within 30 days of the initial performance test 
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anniversary), Permittee shall conduct performance tests (as described in 40 

CFR § 60.8) as follows: 

i. NOx, CO, PM, and PM10 emissions from each gas turbine (Units 

GEN1/DB1 and GEN2/DB2), 

ii. NOx, and CO emissions from the 37.4 MMBtu/hr boiler (D1); PM and 

PM10 emissions from the 37.4 MMBtu/hr boiler (D1) shall be tested 

initially and at least every five years (within 30 days of the initial 

performance test anniversary) 

iii. NOx, CO, PM, and PM10 emissions from the 550 kW (860 hp) internal 

combustion engine (D2), only upon notification by EPA 

iv. NOx, CO, PM, and PM10 emissions from the 288 hp firewater pump 

(D3), only upon notification by EPA 

b. Permittee shall submit a performance test protocol to EPA no later than 30 

days prior to the test to allow review of the test plan and to arrange for an 

observer to be present at the test. The performance test shall be conducted 

in accordance with the submitted protocol, and any changes required by 

EPA. 

c. Performance tests shall be conducted in accordance with the test methods 

set forth in 40 CFR § 60.8 and 40 CFR Part 60 Appendix A, as modified 

below. In lieu of the specified test methods, equivalent methods may be 

used with prior written approval from EPA: 

i. EPA Methods 1-4 and 7E for NOx emissions measured in ppmvd 

ii. EPA Methods 1-4, 7E, and 19 for NOx emissions measured on a heat 

input basis 

iii. EPA Methods 1-4 and 10 for CO emissions 

iv. EPA Methods 5 and 202, or Methods 201A and 202, for both PM and 

PM10, in accordance with the test methods set forth in 40 CFR § 60.8, 

40 CFR Part 60 Appendix A, and 40 CFR Part 51 Appendix M. In lieu 

of Method 202, the Permittee may use EPA Conditional Test Methods 

for particulate matter: CTM-039. 

v. the provisions of 40 CFR § 60.8 (f). 

d. The initial performance test conducted after initial startup shall use the test 

procedures for a “high NO2 emission site,” as specified in San Diego Test 

Method 100, to measure NOx emissions. The source shall be classified as 

either a “low” or “high” NO2 emission site based on these test results. If 

the emission source is classified as a: 

i. “high NO2 emission site,“ then each subsequent performance test shall 
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use the test procedures for a “high NO2 emission site,” as specified in 

San Diego Test Method 100. 

ii. “low NO2 emission site,” then the test procedures for a “high NO2

emission site,” as specified in San Diego Test Method 100, shall be 

performed once every five years to verify the source's classification as 

a “low NO2 emission site.” 

e. The performance test methods for NOx emissions specified in Condition 

X.G.1.c.i and ii., may be modified as follows: 

i. Perform a minimum of 9 reference method runs, with a minimum time 

per run of 21 minutes, at a single load level, between 90 and 100 

percent of peak (or the highest physically achievable) load. 

ii. Use the test data both to demonstrate compliance with the applicable 

NOx emission limit and to provide the required reference method data 

for the RATA of the CEMS. 

f. Upon written request and adequate justification from the Permittee, EPA 

may waive a specific annual test and/or allow for testing to be done at less 

than maximum operating capacity. 

g. For performance test purposes, sampling ports, platforms, and access shall 

be provided on the emission unit exhaust system in accordance with the 

requirements of 40 CFR § 60.8(e). 

h. Permittee shall furnish the EPA a written report of the results of 

performance tests within 60 days of completion. 

2. Fuel Testing 

a. Permittee shall take monthly samples of the natural gas combusted. The 

samples shall be analyzed for sulfur content using an ASTM method. The 

sulfur content test results shall be retained on site and taken to ensure 

compliance with Special Conditions X.C and X.E for Units GEN1/DB1, 

GEN2/DB2, D1, and D2. 

H. Monitoring for Auxiliary Combustion Equipment 

1. Permittee shall install and maintain an operational non-resettable totalizing 

mass or volumetric flow meter in each fuel line for the 37.4 MMBtu /hr boiler 

(Unit D1). 

2. Permittee shall install and maintain an operational non-resettable elapsed time 

meter for the 550 kW emergency use engine (Unit D2) and the 288 hp 
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emergency-use firewater pump (Unit D3). 

 I. Recordkeeping and Reporting 

1. Permittee shall maintain a file of all records, data, measurements, reports, and 

documents related to the operation of the Facility, including, but not limited 

to, the following: all records or reports pertaining to adjustments and/or 

maintenance performed on any system or device at the Facility; all records 

relating to performance tests and monitoring of auxiliary combustion 

equipment; for each diesel fuel oil delivery, documents from the fuel supplier 

certifying compliance with the fuel sulfur content limit of Special Condition 

X.E for Unit D3; and all other information required by this permit recorded in 

a permanent form suitable for inspection. The file must be retained for not 

less than five years following the date of such measurements, maintenance, 

reports, and/or records. 

2. Permittee shall maintain CEMS records that include the following: the 

occurrence and duration of any startup, shutdown, shakedown, or malfunction, 

performance testing, evaluations, calibrations, checks, adjustments, 

maintenance, duration of any periods during which a continuous monitoring 

system or monitoring device is inoperative, and corresponding emission 

measurements. 

3. Permittee shall maintain records of all source tests and monitoring and 

compliance information required by this permit. 

4. Permittee shall maintain records and submit a written report of all excess 

emissions to EPA semi-annually, except when: more frequent reporting is 

specifically required by an applicable subpart; or the Administrator, on a caseby-case basis, determines that more frequent reporting is necessary to 

accurately assess the compliance status of the source. The report is due on the 

30th day following the end of each semi-annual period and shall include the 

following: 

a. Time intervals, data and magnitude of the excess emissions, the nature 

and cause (if known), corrective actions taken and preventive 

measures adopted; 

b. Applicable time and date of each period during which the CEMS was 

inoperative (monitor down-time), except for zero and span checks, and 

the nature of CEMS repairs or adjustments; 

c. A statement in the report of a negative declaration; that is, a statement 
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Avenal Energy Project (SJ 08-01) 

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MayJune 2011 

when no excess emissions occurred or when the CEMS has not been 

inoperative, repaired, or adjusted; 

d. Any failure to conduct any required source testing, monitoring, or 

other compliance activities; and 

e. Any violation of limitations on operation, including but not limited to 

restrictions on hours of operation. 

5. Excess emissions shall be defined as any period in which the Facility 

emissions exceed the maximum emission limits set forth in this permit. 

6. A period of monitor down-time shall be any unit operating clock hour in 

which sufficient data are not obtained to validate the hour for NOx, CO or O2, 

while also meeting the requirements of Condition X.F.7. 

7. Excess emissions indicated by the CEM system, source testing, or compliance 

monitoring shall be considered violations of the applicable emission limit for 

the purpose of this permit. 

8. All records required by this PSD Permit shall be retained for not less than five 

years following the date of such measurements, maintenance, and reports. 

J. Shakedown Periods 

The combustion turbine emission limits and requirements in Conditions X.C, 

X.D, and X.E shall not apply during combustion shakedown periods. Shakedown 

is defined as the period beginning with initial startup and ending no later than 

initial performance testing, during which the Permittee conducts operational and 

contractual testing and tuning to ensure the safe, efficient and reliable operation of 

the plant. The shakedown period shall not exceed 90 days. The requirements of 

Section III of this permit shall apply at all times. 
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XI. ACROYNMS AND ABBREVIATIONS 

AEP Avenal Energy Project 

APCD Air Pollution Control District 

ASTM American Society for Testing and Materials 

Btu British Thermal Unit 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CTG Combustion Turbine Generator 

District San Joaquin Valley Air Pollution Control District 

DLN Dry Low NOx 

(d)scf (dry) Standard Cubic Feet 

EPA Environmental Protection Agency 

g Grams 

gr Grains 

HHV Higher Heating Value 

HRSG Heat Recovery Steam Generator 

hp Horsepower 

hr Hour 

kW Kilowatt 

lbs Pounds 

MMBtu Million British Thermal Units 

MW Megawatt 

NO2 Nitrogen Dioxide 

NOx Oxides of Nitrogen 

NSCR Non-Selective Catalytic Reduction 

OTM Other Test Method 

Ox-Cat Oxidation Catalyst 

O2 Oxygen 

PM Total Particulate Matter 

PM10 Particulate Matter with aerodynamic diameter less than 10 micrometers 

ppmvd Parts Per Million by Volume, Dry basis 

ppmv Parts Per Million by Volume 

PSD Prevention of Significant Deterioration 

PUC Public Utilities Commission 

RATA Relative Accuracy Test Audit 

SCR Selective Catalytic Reduction 

STG Steam Turbine Generator 

tpy Tons Per Year 

μm micrometers 

yr Year 
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Avenal Energy Project (SJ 08-01) 

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XII. AGENCY NOTIFICATIONS

 All correspondence as required by this Approval to Construct must be forwarded to: 

A. Director, Air Division (Attn: AIR-5) 

 EPA Region IX 

 75 Hawthorne Street 

 San Francisco, CA 94105-3901 

 Email: R9.AEO@epa.gov 

 Fax: (415) 947-3579 

B. Air Pollution Control Officer 

 San Joaquin Valley Air Pollution Control District 

 1990 E. Gettysburg Avenue 

 Fresno, CA 93726-0244 

 Email: sjvapcd@valleyair.org 

 Fax: (559) 230-6061