PERMITTEE: City of Palmdale

38300 Sierra Highway, Suite A

Palmdale, CA 93550

FACILITY NAME: Palmdale Hybrid Power Project

FACILITY LOCATION: 950 East Avenue M

Palmdale, CA

Pursuant to the provisions ofthe 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 a Prevention ofSignficanz’ Deterioration (PSD) permit to the City of Palmdale. The Permit

applies to the construction and operation of a new 570 megawatt (MW, nominal) natural gas-fired combined-cycle power plant, with an integrated 50 MW solar-thermal plant, known as the Palmdale Hybrid Power Project (PHPP) in Palmdale, California.

The City of Palmdale is authorized to construct and operate the PHPP 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 the City of Palmdale 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, and72 through 75), or other federal, state, and Antelope Valley Air Quality Management District requirements.

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

notice ofthis final permit decision unless review is requested on the permit pursuant to 40 CFR § 124.19.

/,? 1•

/ ( --cfDeborah Jordaj DATE

Director, Air iivision

The Palmdale Hybrid Power Project (Project) consists of two General Electric (GE) Frame 7FA natural gas-fired combustion turbine-generators (CTGs) rated at 154 megawatt (MW, gross) each, two heat recovery steam generators (HRSGs), one steam turbine generator (STG) rated at 267 MW, and 251 acres of parabolic solar-thermal collectors with associated heat-transfer

equipment. The Project will have an electrical output of 570 MW (nominal) or 563 MW (net). The Project will be located on a parcel of land owned by the city of Palmdale, currently zoned for industrial use, in Los Angeles County. The approximately 333-acre parcel is west ofthe northwest corner of Air Force Plant 42, and east of the intersection of Sierra Highway and East Avenue M. The City of Palmdale is located within the Antelope Valley Air Quality Management District (District).

This Prevention of Significant Deterioration (PSD) permit for the Project requires the use of Best Available Control Technology (BACT) to limit emissions of nitrogen oxides (NO), carbon monoxide (CO), total particulate matter (PM), particulate matter under 10 micrometers (jim) in diameter (PM10),particulate matter under 2.5 (jim) in diameter (PM25),and greenhouse gases (GHG), to the greatest extent feasible. Air pollution emissions from the Project would not cause

or contribute to violations of any National Ambient Air Quality Standards (NAAQS) or any applicable PSD increments for the pollutants regulated under the PSD permit.

Additional equipment includes auxiliary equipment including a natural gas heater and boiler, a diesel-fired emergency generator and emergency firewater pump engine, cooler towers, and circuit breakers.

EQUiPMENT LIST

The following devices and activities are subject to this PSD permit:

Palindale Hybrid Power Project (SE 09-0 1)

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g

(

g

(STP) consisting of parabolic solar-thermal collectors and associated heattransfer equipment designed to contribute up to 50 MW of generation from the

STG

• Emissions of NO and CO controlled by Dry Low-NOx (DLN) Combustors,

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

GEN2 • 154 MW (gross) combustion turbine generator (CTG), with a maximum heat

input rate of 1,736 MMBtulhr (HHV)

• Natural gas-tired GE Model Frame 7FA Rapid Start Process CTG

• Vented to a dedicated Heat Recovery Steam Generator (HRSG) and a 267 MW

Steam Turbine Generator (STG) shared with GEN2

• Integrated (through the HRSG and STG) with a 251-acre solar-thermal plant

(STP) consisting of parabolic solar-thermal collectors and associated heattransfer equipment designed to contribute up to 50 MW of generation from the

STG

• Emissions of NO and CO controlled by Dry Low-NOx (DLN) Combustors,

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

DBI • 500 MMBtuJhr (HHV) Duct Burner for GENI, fired on natural gas

DB2 • 500 MMBtu/hr (FIHV) Duct Burner for GEN2, fired on natural gas

Dl

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

natural gas

• 2,000 kW (2,683 hp) Emergency Internal Combustion (IC) Engine, fired on

D2 Diesel fuel

• 40 CFR Part 60, Subpart 1111 emission standards

• California Air Resources Board Tier 2 emission standards

• 182 hp (135 kW) Emergency Diesel-fired IC Engine Firewater Pump Engine

D3 • 40 CFR Part 60, Subpart 1111 emission standards

• California Air Resources Board Tier 3 emission standards

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p

circulation rate

CB • Enclosed-pressure SF6 Circuit Breakers

• 0.5% (by weight) annual leakage rate

• 10% (by weight) leak deWction system

MV • Maintenance vehicles generating fugitive road dust when traveling on paved

and unpaved roadways in the solar field for the Project

• Project Fugitive Dust Control Plan

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 § 52.2 1(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 ofthe:

A. date construction is commenced, postmarked within 30 days ofsuch date;B. actual date ofinitial 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 ofthe performance test protocol required pursuant to Condition X.G; and

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IlL FACILITY OPERATION

A. 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 airpollution control practice for minimizing emissions. Determination of whether

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

information available to EPA, which may include, but is not limited to, monitoring

results, opacity observations, review of operating maintenance procedures and

inspection of the Facility.

B. The Permittee shall operate and maintain the STP in a manner consistent with good

engineering practices for its full utilization.

C. As soon as practicable following initial startup of the power plant (as defined in 40

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

CFR § 72.2), and thereafter, the Permittee shall develop and implement an operation

and maintenance plan for the STP, consistent with Condition III.B above. At a

minimum, the plan shall identify measures for assessing the performance of the STP,the acceptable range of the plant performaice measures for achieving the design

electrical output, the methods for monitoring the plant performance measures, and the

routine procedures for maintaining the STP in good operating condition.

IV. MALFUNCTION REPORTING

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

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

equipment, or failure 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 ofthe initial malfunction, the period of time over

which emissions were increased due to the failure, the cause ofthe failure, the

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Palmdale Hhrid Power Project (SE 09-0 1)PSD Permit

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V. RIGHT OF ENTRY

The EPA Regional Administrator, andlor 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 required to be kept under the terms and conditions ofthis 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 ofthis 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 ofthe Facility, this PSD Permit shall be binding on all subsequent owners and operators. Within 14 days of any such change in control or ownership, Permittee shall notify the succeeding owner and operator ofthe existence ofthis PSD Permit and its conditions by letter. Permittee shall send a copy of this letter to EPA Region IX within thirty (30) days of its issuance.

VI!. SEVERABILITY

The provisions ofthis PSD Permit are severable, and, if any provision ofthe 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 the Project in compliance with this PSD permit, the application

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NO CO PM PM10 PM2.

Facility 114.9 ipy 244.1 tpy 111.Itpy 94.5tpy 88.0

CO2e

Total Facility 1,913,000 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 0.20 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, Permittee shall

install, continuously operate, and maintain the SCR systems for control of NOx and the

Ox-Cat systems for control of CO for Units GEN1 and GEN2. 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 ofthe following:

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• 8.20 lb/hr

• 1-hr average

Post-Demonstration

• 2.Oppmvd@15%0 2

Period

• 6.15 lb/hr

• 1-hr average

• 1.5ppmvd@15%0 2

• 10.10 lb/hr

• 1 -hr average

• 2.Oppmvd@15%0 2

PM, PM10

PM2.5

Conditions in X.C.3 may affect

the timing and applicability of

post-demonstration period

emission limits.

• 0.0048 lb/MMBtu

• 8.46 lb/hr

• 9-hr average

• PUC-quality natural gas

(Sulfur content of no

greater than 0.20 grains per

100 dscf on a 12-month

average and not greater

than 1.0 gr/dscf at any

time)

• 0.0049 lb/MMBtu

• 11.31b/hr

• 9-hr average

• PUC-quality natural gas

(Sulfur content of no greater

than 0.20 grains per 100

dscf on a 12-month average

and not greater than 1.0

gr/dscf at any time)

• 774 lbC0 2/MWh source-wide net output

• 7,319 Btu/kWh source-wide net heat rate

• 365-day rolling average

Co

GHG

2. The hours of operation for each duct burner (DBI and DB2) shall not exceed 2,000 hours

per 12-month rolling average. Permittee shall ensure that the duct burners are not

operated unless the associated turbine units are in operation.

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be taken to maintain the system and optimize its performance.

b. During the Demonstration Period, 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, 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% 02 and (1) 10.10 lb/hr with duct firing or (2) 8.20 lb/hr without

duct firing.

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

discharge of CO emissions from each CTG Unit (GEN 1 and GEN2) into the

atmosphere in excess ofthe following amounts over a 1-hour averaging period except

as specified in Condition X.C.3.d:

i. 1.5 ppmvd @ 15% 02 without duct firing;

ii. 2.0 ppmvd @ 15% 02 with duct firing;

iii. 6.15 lb/hr without duct firing; and

iv. 10.10 lb/hr with duct firing.

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

Conditions X.C.3.i or X.C.3.iii are not feasible, Permittee shall submit an application

to EPA prior to the end ofthe Demonstration Period requesting a revision ofthose

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 ConditionX.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 ofthe Demonstration Period, the emission limits in Condition X.C.3.b

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averaging periods Or the maximum time allowed for t

e ev

g

, 

occurs first; and the period of time during whih 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

Condition X.C.

a. A cold startup means a startup when the CTG has not been in operation during the

preceding 48 hours.

b. Warm and hot start-ups include all startups that are not a cold startup.

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

operating load and lasting until fuel flow is completely off and combustion has ceased.

3. The duration ofstartup and shutdown periods and emissions of NO and CO shall not

exceed the following, for each CTG (GEN1 and GEN2) and associated HRSG unit, as

verified by the CEMS:

NO . CO Duration

Cold Startup 96 lb/event 410 lb/event 110 minutes

Warm and Hot 40 lb/event 329 lb/event 80 minutes Startup

Shutdown 57 lb/event 337 lb/event 30 minutes

4. Permittee must operate the CEMS during startup and shutdown periods.

5. 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 ofsuch

event.

6. During startup, the SCR system, including ammonia injection, shall be operated as soon

as the SCR reaches an operating temperature of 550 degrees Fahrenheit.

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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 ofthe

following, and shall otherwise comply with the following specifications:

UnitiD NO CO PM/PM 10PM2.5 GHG

Unit Dl • 9 ppmvd @ • 50 ppmvd • 0.8 lb/hr Annual boiler

110 MMBtu!hr 3% 02 3% 02 • PUC-quality tUfle-UpS

(l-IHV) Boiler • 3-hr average • 3-hr average pipeline natural gas

• 6.4 g/kW-hr, • 0.20 g/kW-hr, Not applicable

Unit D2 (4.8 g/hp-hr), (0.15 g/hp-hr )

000 kW includes • 3.5 g/KW-hr, • Use of ultra-low

(2,683 hp) engine NMHC . (2.6 g/hp-hr) sulfur fuel, not to

• 3-hr average exceed 15 ppm

fuel sulfur

Unit D3 • 4.0 g/KW-hr, • Fuel supplier Not applicable 182 hp firewater (3.0 g/hp-hr), certification

pump includes

NMHC

• 3-hr average

Unit D4 • 9 ppmvd @ • 50 pprnvd @ • 0.3 lb/hr Annual boiler 40 MMBtu/hr 3% 02 3% 02 • PUC-quality tune-ups (HHV) Heater • 3-hr average • 3-hr average pipeline natural

gas

Unit D5 • 1.6 lb/hr (as total 130,000 gpm Not applicable Not applicable PM) Not applicable Cooling Tower • <0.0005% drift

• <5,000 ppm total

dissolved solids

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Maintenance Not applicable Not applicable including a Fugitive Not applicable

Vehicles Dust Control Plan

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

periods of, or immediately following, startup. Unit Dl shall be shut down as soon as

practicable after the completion of any startup process as defined in Condition X.D. 1.

Annual hours of operation for Unit Dl shall not exceed 500 hours per 12-month rolling

average.

3. Except during an emergency, Unit D2 shall be limited to operation ofthe engine for

maintenance and testing purposes. Annual hours of operation for Unit D2, for

maintenance and testing, shall not exceed 50 hours per 12-month rolling average.

4. Except during an emergency, Unit D3 shall be limited to operation of the engine for

maintenance and testing purposes, including as required for fire safety testing. Annual

hours of operation for Unit D3, for maintenance and testing, shall not exceed 50 hours per

12-month rolling average.

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

D2 or D3 are required for emergency operations.

6. Unit D4 restrictions on usage shall be limited to annual hours of operation of not to

exceed 1,000 hours per 12-month rolling average.

7. Unit D5 cooling tower emission limits shall not exceed the following:

a. Drift rate shall not exceed 0.0005% with amaximum circulation rate of 130,000

gallons per minute (gpm). The maximum total dissolved solids (TDS) shall not

exceed 5,000 ppm.

b. The maximum hourly total PM emission rate from the cooling tower and the

evaporative condenser combined shall not exceed 1.6 lb/hr.

8. Unit CB enclosed-pressure SF6circuit breakers:

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a. Pave the main access road into the plant site;

b. Submit a Project Fugitive Dust Control Plan to EPA that includes fugitive road dust

control measures for unpaved and paved roads, including, but not limited to:

i. use of a durable non-toxic soil stabilizer applied throughout the solar field for dust

control;

ii. use of a durable non-toxic soil stabilizer to treat unpaved roads within the solar

field used by wash trucks that spray and clean the mirrors;

iii. inspection and maintenance procedures to ensure that the unpaved roads remain

stabilized;

iv. use ofwater trucks applying water on disturbed areas where soil stabilizers are not

as effective;

v. use of water n the mirror washing for incidental dust control; and

vi. limiting vehicle speeds to no more than 10 miles per hour on unpaved roadways, with the exception that vehi1es may travel up to 25 miles per hour on stabilized

unpaved roads as long as such speeds do not create visible dust emissions.

10. Units Dl and D4 shall undergo annual tune-ups and meet the associated requirements of Condition X.I.9 as follows (ifthe unit is not operating on the required date for a tune-up, the tune-up must be conducted within one week of startup):

a. Inspect the burner, and clean or replace any components of the burner as necessary (you may delay the burner inspection until the next scheduled unit shutdown, but you

must inspect each burner at least once every 18 months).

b, Inspect the flame pattern, and adjust the burner as necessary to optimize the flame

pattern. The adjustment should be consistent with the manufacturer’s specifications.

c. Inspect the system controlling the air-to-fuel ratio, and ensure that it is correctly calibrated and functioning properly.

d. Optimize total emissions of carbon monoxide. This optimization should be consistent

with the manufacturer’s specifications.

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1. At the earliest feasible opportunity after first fire of GEN I and GEN2 and before GEN 1

and GEN2 commence commercial operation (as defined in 40 CFR § 72.2), in accordance

with the recommendations ofthe equipment manufacturer and the construction

contractor:

a. Permittee shall install, calibrate, and operate a CEMS each for GEN1 and GEN2 that

measures stack gas N0, CO, and CO2concentrations in ppmv. The concentrations

shall be corrected to 15% 02 on a dry basis. No later than the end ofthe 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 CO2concentrations in

ppmv, and shall conduct initial certification ofthe CEMS in accordance with

Condition X.F.6. The concentrations shall be corrected to 15% 02 on a dry basis.

b. If Permittee chooses to install an 02 CEMS, it shall be installed, calibrated and

operated to measure 02 concentrations in ppmv. No later than the end of the

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

operations, whichever comes first, Permittëe shall also maintain, certify, and qualityassure the CEMS for each CTG that measures 02 concentrations in ppmv, and shall

conduct initial certification of the CEMS in accordance with Condition X.F.6.

Permittee may not install an 02 CEMS in lieu ofthe CO2çEMS in Condition

X.F. I .a.

2. The NON, CU2,and 02 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.

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Palmdale Hybrid Power Project (SE 09-01)

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q

p

during startup and shutdown.

8. Not less than 90 days prior to the date ofinitial startup ofthe Facility, the Permittee shall

submit to the EPA a quality assurance project plan for the certification and operation of the CEMS. Such a plan shall conform to EPA requirements contained in 40 CFR Part 60

Appendix F for CO, 40 CFR Part 75 for NOx and 02 or C0 2,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 bedetermined 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 ofthe 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 r.eview 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 thesubmitted 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 ofthe SCR system.

b. Exhaust gas temperature at the inlet to the SCR reactor.

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b. Pounds of CO2per net energy output (lbC0 2/MWhnet) on an hourly basis;

c. Net heat rate (BtulkWhnet) on an hourly basis, based on total heat input for the

facility;

d. The 365-day rolling average emission rate of lbC0 2/MWhnet and BtUlkWhnet. The

365-day rolling average shall be based on the average hourly recordings.

G. Performance Tests

1. Stack Tests

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

the initial startup of equipment, and, unless otherwise specified, annually thereafter

(within 30 days ofthe initial performance test anniversary), Permittee shall conduct

performance tests (as described in 40 CFR § 60.8) as follows:

i. NOx, CO, C0 2,PM, PM10 and PM25 emissions from each gas turbine (Units

GEN1/DB1 and GEN2/DB2);

ii. NOx and CO emissions from the 110 MMBtu/hr boiler (Dl) and the 40

MMBtuJhr heater (D4); PM, PM10 and PM25 emissions from the 110 MMBtuJhr

boiler (Dl) and the 40 .MMBtuJhr heater (D4) shall be tested initially and at least

every five years (within 30 days of the initial performance test anniversary);

iii. NOx, CO. PM, PM10 and PM25 emissions from the 2,000 kW (2,683 hp) internal

combustion engine (D2), initial performance test and at least every five years

beginning ten years after the initial performance test (within 30 days ofthe initial

performance test anniversary);

iv. NOx, CO. PM, PM10 and PM25 emissions from the 182 hp firewater pump (D3),

initial performance test and at least every five years beginning ten years after the

initial performance test (within 30 days of the initial performance test

anniversary); and

v. PM, PM10 and PM25 emissions from the cooling tower (D5).

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

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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 1-4 and 3B for CO2emissions

v. EPA Methods 5 and 202, or Methods 201A and 202, for PM, PM10 and PM25,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, Permittee

may use EPA Conditional Test Methods for particulate matter CTM-039

vi. Modified Method 306 or the Cooling Tower Institute’s heated bead test method

for PM emissions from the cooling tower, and

vii. 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 NO2emission site,” as specified in San Diego Test Method 100, to measure NOx emissions. The source shall be classified as either a “low” or

“high” NO2emission site based on these test results. Ifthe emission source is

classified as a:

i. “high NO2emission site,” then each subsequent performance test shall use the test

procedures for a “high NO2emission site,” as specified in San Diego Test Method 100.

ii. “low NO2emission site,” then the test procedures for a “high NO2emission 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 NO2emission site.”

e. The performance test methods for NO 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, and

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.

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40 CFR § 60.8(e).

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

within 60 days of completion.

2. Cooling Tower Total Dissolved Solids Testing

a. Permittee shall perform weekly tests ofthe blow-down water quality using an EPAapproved method. The operator. shall maintain a log that contains the date and result

of each blow-down water quality test, the water circulation rate at the time ofthe test,

and the resulting mass emission rate. This log shall be maintained onsite for a

minimum of five years and shall be provided to EPA and District personnel upon

request.

b. Permittee shall calculate PM, PM10 and PM2.5emission rate using an EPA-approved

calculation based on the TDS and water circulation rate.

c. The operator shall conduct all required cooling tower water quality tests in

accordance with an EPA-approved test and emissions calculation protocol. Thirty

(30) days prior to the first such test, the operator shall provide a written test and

emissions calculation protocol for EPA review and approval, with a copy to the

District as specified in Condition XII below.

d. A maintenance procedure shall be established that states how often and what

procedures will be used to ensure the integrity ofthe drift eliminators, to ensure that

the TDS limits are not exceeded, and to ensure compliance with recirculation rates.

This procedure is to be kept onsite and made available to EPA and District personnel

upon request. Permittee shall promptly report any deviations from this procedure.

3. 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 onsite and taken to ensure compliance with Special

Conditions X.C and X.E fbr Units GEN1/DBI, GEN2/DB2, Dl, and D4. As an

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MMBtuJhr heater (Unit D4).

2. Permittee shall install and maintain an operational non-resettable elapsed time meter for the 110 MMBtu /hr boiler (Unit D t), 2,000 kW emergency use engine (Unit D2), the 182 hp emergency-use firewater pump (Unit D3), and the 40 MMBtuJhr heater (Unit D4).

3. Permittee shall install and maintain a leak detection system on the circuit breakers that

signals an alarm in the facility’s control room in the event that any circuit breaker loses

more than 10% ofits dielectric fluid. The owner/operator shall promptly respond to any alarm, investigate the circuit breaker involved, and fix any leak-tightness problems that caused the alarm.

I. Recordkeeping and Reporting

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

related to the operation ofthe 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 Condition X.E;

and all other information required by this permit recorded in a permanent form suitable

for inspection.

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

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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 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 by the CEMS to validate the hour for NOx, CO, C0 2,or 02, while

the CEMS is 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 ofthe applicable emission limit for the purpose ofthis

permit.

8. Permittee shall maintain the Fugitive Dust Control Plan on-site, which shall include all

documentation related to demonstrating compliance with Condition X.E.9 for Unit MV,

in a permanent form suitable for inspection.

9. Permittee shall conduct annual tune-ups as required by Condition X.E. 10 for Units Dl

and D4 and maintain onsite, and submit ifrequested by the Administrator, a biennial

report containing the information in paragraphs (a) through (c) below:

a. The concentrations of CO in the effluent stream in parts per million, by volume, and

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each

month.

11. The Permittee shall maintain a cop5r ofthe current operation and maintenance plan for the STP, and shall keep a copy of all prior versions of the plan for a minimum offive years. The Permittee shall also keep records ofthe monitoring data for each ofthe plant performance measures and all maintenance activities; the Permittee shall maintain such

records for a minimum of five years following the date they are created

12. Unless otherwise specified herein, all records required by this PSD Permit shall be retained for not less than five years following the date ofsuch measurements,

maintenance, reports, andJor records.

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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CEMS Continuous Emiss

o

g 

y

CFR Code of Federal Regulations

CO Carbon Monoxide

C0 2e Carbon Dioxide Equivalent

CTG Combustion Turbine Generator

CTM Conditional Test Method

District Antelope Valley Air Quality Management District

DLN Dry LowNOx

(d)scf (dry) Standard Cubic Feet

EPA Environmental Protection Agency

FDOC Final Determination of Compliance

g grams

GE General Electric

GHG Greenhouse Gas

gpm Gallons Per Minute

gr grains

HHV Higher Heating Value

l-IRSG Heat Recovery Steam Generator

hp Horsepower

hr Hour

IC Internal Combustion

kPa kilopascals

kW Kilowatt

lb Pounds

lbs Pounds

MMBtu Million British Thermal Units

MW Megawatt

NAAQS National Ambient Air Quality Standards

NNSR Nonattainment New Source Review

NO2 Nitrogen Dioxide

NO Oxides of Nitrogen

NSPS New Source Performance Standards

02 Oxygen

Ox-Cat Oxidation Catalyst

PHPI Palmdale Hybrid Power Project

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RATA Relative Accuracy Test Audit

SCR Selective Catalytic Reduction

SF6 Sulfur Hexafluoride

SO2 Sulfur Dioxide

5Ox Oxides of Sulfur

STG Steam Turbine Generator

STP Solar-thermal Plant

TDS Total Dissolved Solids

tpy Tons Per Year

yr Year

XII. AGENCY NOTIFICATIONS

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

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

EPA Region IX

75 Hawthorne Street

San Francisco, CA 94105-3901

Email: R9.AEOepa.gov

Fax: (415) 947-3579

With a copy to:

B. Air Pollution Control Officer

Antelope Valley Air Quality Management District

43301 Division Street, Suite 206

Lancaster, CA 93535

Fax: (661)723-3450

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