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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

PALMDALE HYBRID POWER PROJECT (SE 09-01)

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT

PERMIT CONDITIONS

PROJECT DESCRIPTION

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 of the 

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 (NOx), carbon 

monoxide (CO), total particulate matter (PM), particulate matter under 10 micrometers (μm) in 

diameter (PM10), particulate matter under 2.5 (μm) in diameter (PM2.5), 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:
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

Unit ID Description

GEN1  154 MW (gross) combustion turbine generator (CTG), with a maximum heat 

input rate of 1,736 MMBtu/hr (HHV)

 Natural gas-fired 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 NOx 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 MMBtu/hr (HHV)

 Natural gas-fired 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 NOx and CO controlled by Dry Low-NOX (DLN) Combustors, 

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

DB1  500 MMBtu/hr (HHV) Duct Burner for GEN1, fired on natural gas

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

D1  110 MMBtu/hr (HHV) Auxiliary Boiler with ultra low-NOX burner, fired on 

natural gas

D2

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

Diesel fuel

 40 CFR Part 60, Subpart IIII emission standards

 California Air Resources Board Tier 2 emission standards

D3

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

 40 CFR Part 60, Subpart IIII emission standards

 California Air Resources Board Tier 3 emission standards
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

Unit ID Description

D4  40 MMbtu/hr (HHV) Auxiliary Heater with ultra low-NOX burner, fired on 

natural gas

D5  Cooling tower with 130,000 gallons per minute maximum circulation rate

 Total dissolved solids (TDS) concentration in makeup water of 5,000 ppm (531 

mg/L) 

 Drift eliminator with drift losses less than or equal to 0.0005 percent based on 

circulation rate

CB  Enclosed-pressure SF6 Circuit Breakers 

 0.5% (by weight) annual leakage rate

 10% (by weight) leak detection 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 § 52.21(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 
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

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

monitoring system (CEMS) will commence in accordance with 40 CFR § 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

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 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 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 performance 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.AEO@epa.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 of the initial malfunction, the period of time over 

which emissions were increased due to the failure, the cause of the failure, the 
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

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 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, 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 of the 

existence of this 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.

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 the Project in compliance with this PSD permit, the application 
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

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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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

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 PM2.5

Total 

Facility 114.9 tpy 244.1 tpy 111.1tpy 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 of the following:
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

Emission Limit (per CTG) 

(no duct burning)

Emission Limit (per CTG) 

(with duct burning)

NOx

 13.47 lb/hr

 1-hr average

 2.0 ppmvd @ 15% O2

 16.60 lb/hr

 1-hr average

 2.0 ppmvd @ 15% O2

CO

3-Year Demonstration Period

 8.20 lb/hr

 1-hr average

 2.0 ppmvd @ 15% O2

Post-Demonstration Period

 6.15 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.

 10.10 lb/hr

 1-hr average

 2.0 ppmvd @ 15% O2

PM, PM10, 

PM2.5

 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

 11.3 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)

GHG

 774 lb CO2/MWh source-wide net output

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

 365-day rolling average

2. The hours of operation for each duct burner (DB1 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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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

3. CO Emissions Limit Demonstration Period – The Demonstration Period is defined as the 

first 3 years immediately following the commencement of commercial operations (as 

defined in 40 CFR § 72.2). 

a. Permittee shall design the gas turbines to achieve a CO emission rate of 1.5 ppmvd @ 

15% O2 and 6.15 lb/hr over a 1-hour period without duct firing. Prior to construction, 

Permittee shall submit design specifications to EPA as proof that the gas turbines 

were designed to achieve such a rate, and a plan that sets forth the measures that will 

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% O2 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 (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. 6.15 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 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 
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Palmdale Hybrid Power Project (SE 09-01) 

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October 2011

shall remain in effect until EPA evaluates the application and makes a final decision 

regarding the revision of the limits 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 beginning with ignition and lasting until either the 

equipment complies with all operating permit limits for two consecutive 15-minute 

averaging periods or the maximum time allowed for the event after ignition, whichever 

occurs first; and 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 

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 of startup and shutdown periods and emissions of NOX and CO shall not 

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

verified by the CEMS:

NOx CO Duration

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

Warm and Hot 

Startup 40 lb/event 329 lb/event 80 minutes

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 of such 

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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Palmdale Hybrid Power Project (SE 09-01) 

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7. During startup or shutdown, emissions of NOx from both CTGs (GEN1 and GEN2) 

combined shall not exceed 130 lb/hr, as verified by the CEMS.

8. During startup or shutdown, emissions of CO from both CTGs (GEN1 and GEN2) 

combined shall not exceed 790 lb/hr, as verified by the CEMS.

E. Auxiliary Combustion Equipment Emission Limits and Work Practices

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, and shall otherwise comply with the following specifications:

Unit ID NOx CO PM / PM10 PM2.5 GHG

Unit D1

110 MMBtu/hr 

(HHV) Boiler

 9 ppmvd @ 

3% O2

 3-hr average

 50 ppmvd @ 

3% O2

 3-hr average

 0.8 lb/hr

 PUC-quality 

pipeline natural gas

Annual boiler 

tune-ups

Unit D2 

2,000 kW 

(2,683 hp) engine

 6.4 g/kW-hr, 

(4.8 g/hp-hr), 

includes 

NMHC

 3-hr average

 3.5 g/KW-hr, 

(2.6 g/hp-hr)

 0.20 g/kW-hr, 

(0.15 g/hp-hr )

 Use of ultra-low 

sulfur fuel, not to 

exceed 15 ppm 

fuel sulfur 

 Fuel supplier 

certification

Not applicable

Unit D3

182 hp firewater 

pump

 4.0 g/KW-hr, 

(3.0 g/hp-hr), 

includes 

NMHC

 3-hr average

Not applicable

Unit D4

40 MMBtu/hr 

(HHV) Heater

 9 ppmvd @ 

3% O2

 3-hr average

 50 ppmvd @ 

3% O2

 3-hr average

 0.3 lb/hr

 PUC-quality 

pipeline natural 

gas

Annual boiler 

tune-ups

Unit D5

130,000 gpm 

Cooling Tower

Not applicable Not applicable

 1.6 lb/hr (as total 

PM)

 < 0.0005% drift

 < 5,000 ppm total 

dissolved solids

Not applicable
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

Unit ID NOx CO PM / PM10 PM2.5 GHG

CB

SF6 Circuit 

Breakers

Not applicable Not applicable Not applicable

 9.56 tpy CO2e

 12-month 

rolling total

MV

Maintenance 

Vehicles

Not applicable Not applicable

Conditions in X.E.9 

including a Fugitive 

Dust Control Plan

Not applicable

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. 

Annual hours of operation for Unit D1 shall not exceed 500 hours per 12-month rolling 

average.

3. Except during an emergency, Unit D2 shall be limited to operation of the 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 a maximum 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 SF6 circuit breakers:
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Palmdale Hybrid Power Project (SE 09-01) 

PSD Permit

October 2011

a. Emissions shall not exceed an annual leakage rate of 0.5% by weight; and

b. Shall be equipped with a 10% by weight leak detection system.

9. For Unit MV, maintenance vehicles that travel on paved and unpaved roadways in the 

solar field associated with the Project, Permittee shall complete the following prior to the 

commencement of commercial operation (as defined in 40 CFR § 72.2):

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 of water trucks applying water on disturbed areas where soil stabilizers are not 

as effective;

v. use of water in 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 vehicles 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 D1 and D4 shall undergo annual tune-ups and meet the associated requirements of 

Condition X.I.9 as follows (if the 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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Palmdale Hybrid Power Project (SE 09-01) 

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e. Measure the concentrations in the effluent stream of carbon monoxide in parts per 

million, by volume, and oxygen in volume percent, before and after the adjustments 

are made (measurements may be either on a dry or wet basis, as long as it is the same 

basis before and after the adjustments are made).

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:

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

measures stack gas NOX, CO, and 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 CO2 concentrations in 

ppmv, and shall 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. 

 

b. If Permittee chooses to install an O2 CEMS, it shall be installed, calibrated and 

operated to measure O2 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, Permittee shall also maintain, certify, and qualityassure the CEMS for each CTG that measures O2 concentrations in ppmv, and shall 

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

Permittee may not install an O2 CEMS in lieu of the CO2 CEMS in Condition 

X.F.1.a.

2. The NOX, CO2, 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. 
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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. 

The CEMS must undergo and pass initial performance specification testing on or before 

the date of the initial performance test.

7. The 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 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 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. Exhaust gas temperature at the inlet to the SCR reactor.
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14. Permittee shall measure and record, for each Unit GEN1/DB1 and Unit GEN2/DB2, the 

actual heat input (Btu) on an hourly basis.

15. Permittee shall measure and record, for the entire facility, the following:

a. Net energy output (MWhnet and kWhnet) on an hourly basis;

b. Pounds of CO2 per net energy output (lb CO2/MWhnet) on an hourly basis;

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

facility;

d. The 365-day rolling average emission rate of lb CO2/MWhnet and Btu/kWhnet. 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 of the initial performance test anniversary), Permittee shall conduct 

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

i. NOX, CO, CO2, PM, PM10, and PM2.5 emissions from each gas turbine (Units 

GEN1/DB1 and GEN2/DB2);

ii. NOX and CO emissions from the 110 MMBtu/hr boiler (D1) and the 40 

MMBtu/hr heater (D4); PM, PM10, and PM2.5 emissions from the 110 MMBtu/hr 

boiler (D1) and the 40 MMBtu/hr 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 PM2.5 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 of the initial 

performance test anniversary);

iv. NOX, CO, PM, PM10, and PM2.5 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 PM2.5 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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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 1-4 and 3B for CO2 emissions

v. EPA Methods 5 and 202, or Methods 201A and 202, for PM, PM10, and PM2.5, 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 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 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, 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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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. Cooling Tower Total Dissolved Solids Testing

a. Permittee shall perform weekly tests of the 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 of the 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 PM2.5 emission 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 of the 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 for Units GEN1/DB1, GEN2/DB2, D1, and D4. As an 
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alternative, Permittee may obtain laboratory analysis of sulfur content from the fuel 

supplier on a monthly basis, if Permittee can demonstrate that the fuel tested is 

representative of fuel delivered to the facility.

H. Monitoring for Auxiliary Equipment

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

volumetric flow meter in each fuel line for the 110 MMBtu/hr boiler (Unit D1) and the 40 

MMBtu/hr heater (Unit D4).

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

the 110 MMBtu /hr boiler (Unit D1), 2,000 kW emergency use engine (Unit D2), the 182 

hp emergency-use firewater pump (Unit D3), and the 40 MMBtu/hr 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% of its 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 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 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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applicable subpart; or the Administrator, on a case-by-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 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, CO2, or O2, 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 of the applicable emission limit for the purpose of this 

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 D1 

and D4 and maintain onsite, and submit if requested 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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oxygen in volume percent, measured before and after the tune-up of the boiler.

b. A description of any corrective actions taken as a part of the tune-up of the boiler.

c. The type and amount of fuel used over the 12 months prior to the biennial tune-up 

of the boiler.

10. Permittee shall record the pounds of dielectric fluid added to the circuit breakers each 

month.

11. The Permittee shall maintain a copy of the current operation and maintenance plan for the 

STP, and shall keep a copy of all prior versions of the plan for a minimum of five years. 

The Permittee shall also keep records of the monitoring data for each of the 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 of such measurements, 

maintenance, reports, and/or 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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XI. ACROYNMS AND ABBREVIATIONS

AQMD Air Quality Management District

ASTM American Society for Testing and Materials

BACT Best Available Control Technology

BTU British Thermal Unit

CAA Clean Air Act

CEMS Continuous Emissions Monitoring System

CFR Code of Federal Regulations

CO Carbon Monoxide

CO2e Carbon Dioxide Equivalent

CTG Combustion Turbine Generator

CTM Conditional Test Method

District Antelope Valley Air Quality Management District

DLN Dry Low NOX

(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

HRSG 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

NOX Oxides of Nitrogen

NSPS New Source Performance Standards

O2 Oxygen

Ox-Cat Oxidation Catalyst

PHPP Palmdale Hybrid Power Project
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PM Total Particulate Matter

PM2.5 Particulate Matter with aerodynamic diameter less than 2.5 micrometers

PM10 Particulate Matter with aerodynamic diameter less than 10 micrometers

ppm Parts Per Million

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

SF6 Sulfur Hexafluoride

SO2 Sulfur Dioxide

SOX 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.AEO@epa.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