1

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 turbi ne

- 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 P r oject 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).

Th is Prevention of Significant Deterior ation (PSD) permit for the Project requires the use of Best Available Control Technology (BACT) to limit emissions of n itrogen o xides ( NO

x ), c arbon

m onoxide (CO), t otal p articulate m atter (PM), p articulate m atter under 10 micrometers ( μ m) in diameter (PM 10 ), p articulate m atter under 2.5 ( μ m) in diameter (PM 2.5 ), and g reenhouse g ases (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 (NAAQ S) 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, c ooler towers, and

circuit breakers.

EQUIPMENT LIST

The following devices and activities are subject to this PSD permit:2

Palmdale Hybrid Power Project (SE 09

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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 (S TP) consisting of parabolic solar

- thermal collectors and associated heat

transfer equipment designed to contribute up to 50 MW of generation from the

STG

 Emissions of NO

x and CO controlled by Dry Low

- NO X (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 Ge nerator (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 heat

transfer equipment designed to c ontribute up to 50 MW of generation from the

STG

 Emissions of NO

x and CO controlled by Dry Low

- NO X (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

- NO X burner, fired on

natural gas

D2  2,000 kW (2,683 hp) Emergency Internal Combustion (IC) Engine, fired on

Diesel fuel

 40 CFR Part 6 0, 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 emi ssion standards3

Palmdale Hybrid Power Project (SE 09

- 01)

PSD Permit

October 2011 Unit ID Description

D4  40 MMbtu/hr (HHV) Auxiliary Heater with ultra low

- NO X 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

m g/L)

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

circulation rate

CB  Enclosed

- pressure SF 6 Circuit Breakers

 0.5% (by weight) annual leakage rate

 10% (by weight) leak detection system

MV  Maintenance vehicles generati ng fugitive road dust when traveling on paved

and unpaved roadways in the solar fie l d 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 NOTIFICATI ON 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 1 5 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; and4

Palmdale Hybrid Power Project (SE 09

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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 su ch 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 shal l, 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 Pe rmittee 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 comm ercial 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 th e 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 con dition.

IV. MALFUNCTION REPORTIN G

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

electroni c 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 emi ssions were increased due to the failure, the cause of the failure, the5

Palmdale Hybrid Power Project (SE 09

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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 malfunct ion 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, up on 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 acces s 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 OWNERSHI P

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 Permi t 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 APPLICA TION AND COMPLIANCE WITH OTHER

ENVIRONMENTAL LAWS

Permittee shall construct th e P roject in compli ance with this PSD permit, the application6

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 fed eral, state and local environmental laws and regulations, including the Clean Air Act.



### IX. RESERVED7

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

ex ceed the following:

NO

x CO PM PM 10 PM 2.5

Total Facility 114.9 tpy 244.1 tpy 111.1 tpy 94.5 tpy 88.0

CO 2 e

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 Con trol 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 i n Condition X.D, Permittee shall install, continuously operate, and maintain the SCR systems for control of NO X and the

Ox

- Cat systems for control of CO for Units GEN1 and GEN2. Permittee shall also perform any necessary operations to minimize emissions s o 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 caus e the discharge of emissions from each CTG Unit (of GEN1 and GEN2) into the atmosphere in excess of the following:8

Palmdale Hybrid Power Project (SE 09

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PSD Permit

October 2011 Emission Limit (per CTG) (no duct burning) Emission Limit (per CTG) (with duct burning)

NO

x  13.47 lb /hr

 1

- hr average

 2.0 ppmvd @ 15% O 2  16.60 lb/hr

 1

- hr average

 2.0 ppmvd @ 15% O 2

CO 3

- Year Demonstration Period

 8.20 lb/hr

 1

- hr average

 2.0 ppmvd @ 15% O 2

Post

- Demonstration Period

 6.15 lb/hr

 1

- hr average

 1.5 ppmvd @ 15% O 2

Conditions in X.C.3 may affect the timing and applicability of

po st

- demonstration period

emission limits.  10.10 lb/hr

 1

- hr average

 2.0 ppmvd @ 15% O 2

PM, PM 10 , PM 2.5  0.0048 lb/MMBtu

 8.46 lb/hr

 9

- hr average

 PUC

- quality natural gas ( Sulfur content of no greater than 0.2 0 grains per

100 dscf on a 12

- month average and no t 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 0.2 0 grains per 100

dscf on a 12

- month average and not greater than 1.0 gr/dscf at any time)

GHG  774 lb CO 2 /MWh sour ce

- 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.9

Palmdale Hybrid Power Project (SE 09

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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% O 2 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 turb ines 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 sp ecifications, 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 f rom 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% O 2 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% O 2 wit hout duct firing;

ii. 2.0 ppmvd @ 15% O 2 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, Per mittee 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 sp ecifications 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 follo wing 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.b10

Palmdale Hybrid Power Project (SE 09

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PSD Permit

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 eithe r 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 shutdow n 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 oper ation 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 comp letely off and combustion has ceased.

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

exce ed the following , for each CTG (GEN1 and GEN2) and associated HRSG unit

, as verified by the CEMS :

NO

x CO Duration

Cold Sta rtup 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 NO X 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.11

Palmdale Hybrid Power Project (SE 09

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PSD Permit

October 2011 7. During startup or shutdown, emissions of NO

x from both CTGs (GEN1 and GEN2) combined shall not exceed 130 lb/hr, as ver ified 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 equipme nt 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 NO

x CO PM / PM 10 PM 2.5 GHG

Un it D1

110 MMBtu/hr (HHV) Boiler  9 ppmvd @

3% O 2

 3

- hr average  50 ppmvd @

3% O 2

 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 a pplicable

Unit D4

40 MMBtu/hr (HHV) Heater  9 ppmvd @

3% O 2

 3

- hr average  50 ppmvd @

3% O 2

 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 applicable12

Palmdale Hybrid Power Project (SE 09

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PSD Permit

October 2011 Unit ID NO

x CO PM / PM 10 PM 2.5 GHG

CB

SF 6 Circuit

Breakers Not applicable Not applicable Not applicable  9.56 tpy CO 2 e

 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 complet ion 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 te sting 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 purpose s, 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 Uni ts 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 followi ng:

a. D rift rate shall not exceed 0.0005 % with a maximum circulation rate of 1 30,000 gallons per minute (gpm). T he 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 SF 6 circuit breakers :13

Palmdale Hybrid Power Project (SE 09

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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 U nit 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 ac cess 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

s tabilized;

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 (i f 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. I nspect the burner, and clean or replace any components of the burner as necessary (you may delay the burner insp ection 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 manu facturer'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 manufacture r's specifications.14

Palmdale Hybrid Power Project (SE 09

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PSD Permit

October 2011 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 opera tion (as defined in 40 CFR § 72.2), in accordance with the recommendations of the equipment manufacturer and the construction

contractor :

a. Permittee shall i nstall, calibrate, and operate a CEMS each for GEN1 and GEN2 that measures stack gas NO X , CO, and CO 2 concentrations in ppmv. The concentrations

shall be corrected to 15% O 2 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 main tain, certify, and quality

- assure a CEMS for each CTG that measures stack gas NO X , CO, and CO 2 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% O 2 o n a dry basis.

b. If Permittee chooses to install an O 2 CEMS, it shall be installed, calibrated and operated to measure O 2 concentrations in ppmv. No later than the end of the shakedown period as defined in Condition X.J. or upon commencing commercial

ope rations, whichever comes first, Permittee shall also maintain, certify, and quality

assure the CEMS for each CTG that measures O 2 concentrations in ppmv, and shall

conduct initial certification of the CEMS in accordance with Condition X.F.6. Permittee may not install an O 2 CEMS in lieu of the CO 2 CEMS in Condition

X.F.1.a.

2. The NO X , CO 2 , and O 2 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 Specif

ication 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 operati on (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.3.15

Palmdale Hybrid Power Project (SE 09

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PSD Permit

October 2011 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 requiremen ts 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 sha ll 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 NO X and O 2 or CO 2 , and 40 CFR Part 75 App endix 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 selec ted 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 tes t. 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 vo lumetric 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 inst all, 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 temperatur e at the inlet to the SCR reactor.16

Palmdale Hybrid Power Project (SE 09

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PSD Permit

October 2011 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 o utput (MWh

ne t and kWh net ) on an hourly basis;

b. Pounds of CO 2 per net energy output (lb CO 2 /MWh net ) on an hourly basis;

c. Net heat rate (Btu/kWh net ) on an hourly basis, based on total heat input for the facility;

d. The 365

- day rolling average emission rate of lb CO 2 /MWh net and Btu/kWh net . 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 equ ipment, 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. NO X , CO , CO 2 , PM, PM 10 , and PM 2.5 emissions fr om each gas turbine (Units GEN1/DB1 and GEN2/DB2) ; ii. NO X and CO emissions from the 110 MMBtu/hr boiler (D1) and the 40 MMBtu/hr heater (D4); PM, PM 10 , and PM 2.5 emissions from the 110 MMBtu/hr boiler (D1) and the 40 MMBtu/hr heater (D4) shall be tested ini tially and at least every five years (within 30 days of the initial performance test anniversary) ; iii. NO X , CO, PM, PM 10 , and PM 2.5 emissions from the 2,000 kW (2,683 hp) internal combustion engine (D2), initial performance test and at least every five years

b eginning ten years after the initial performance test (within 30 days of the initial performance test anniversary);

iv. NO X , CO, PM, PM 10 , and PM 2.5 emissions from the 182 hp firewater pump (D3), initial performance test and at least every five years beginnin g ten years after the initial performance test (within 30 days of the initial performance test anniversary); and

v. PM, PM 10 , and PM 2.5 emissions from the cooling tower (D5).

b. Permittee shall submit a performance test protocol to EPA no later than 30 days pr ior to the test to allow review of the test plan and to arrange for an observer to be present17

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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 con ducted 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 NO X emissions measured in ppmvd

ii. EPA Methods 1

- 4, 7E, and 19 for NO X 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 CO 2 emissions

v. EPA Methods 5 and 202, or Methods 201A and 202, for PM, PM 10 , an d PM 2.5 , 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 ; i n lieu of Method 202, Permittee may use EPA Conditional Test Methods for particulate matter CTM

- 039

vi. Modified Method 306 or t he 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 NO 2 emission site ,” as specified in San Diego Test Method
100, to measure NO X emissions. The source shall be classified as either a “low” or “high” NO 2 emission site based on these test results. If the emission source is

classified as a:

i. “high NO 2 emission site,“ th en each subsequent performance test shall use the test procedures for a “high NO 2 emission site,” as specified in San Diego Test Method

100.

ii. “low NO 2 emission site,” then the test procedures for a “high NO 2 emission site,” as specified in San Diego Te st Method 100, shall be performed once every five years to verify the source's classification as a “low NO 2 emission site.”

e. The performance test methods for NO X emissions specified in Condition X.G.1.c.i and ii., may be modified as follows:

i. Pe rform 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 NO X emission limit and to provide the required reference method data for the RATA of

the CEMS.18

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October 2011 f. Upon written request and adequate justification from the Permittee, EPA may waive a specific annual test and/or allow for testi ng 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 fur nish 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 a n EPA

approved method. The operator sh all 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 b e provided to EPA and District personnel up on request.

b. Permittee shall calculate PM, PM 10 , and PM 2.5 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 month ly 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 an19

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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. Mon itoring 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 inst all 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 ins tall 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

alar m, 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 th e 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 combustio n 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 inspecti on.

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 peri ods 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. Permitte e 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 an20

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October 2011 applicable subpart; or the Administrator, on a case

- by

- case basis, determines that more

f requent reporting is necessary to accurately assess the compliance status of the source. The report is due on the 30 th day following the end of each semi

- annual period and shall include the following:

a. Time intervals, data and magnitude of the excess emis sions, 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

re pairs 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, monito ring, 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 emiss ion 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 NO X , CO

, CO 2 , or O 2 , while the CEMS is also meeting the requirements o f 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 P lan 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, and21

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October 2011 oxygen in volume p ercent, 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 , a ll 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 emissio n 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 Permitte e 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.22

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October 2011 XI. ACRO YNMS AND ABBREVIATIO NS

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 Fed eral Regulations

CO Carbon Monoxide

CO 2 e Carbon Dioxide Equivalent

CTG Combustion Turbine Generator

CTM Conditional Test Method

District Antelope Valley Air Quality Management District

DLN Dry Low NO X (d)scf (dry) Standard Cubic Feet

EPA Environmen tal 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

NO 2 Nitrogen Dioxide

NO X Oxides of Nitrogen

NSPS New Source Perfo rmance Standards

O 2 Oxygen

Ox

- Cat Oxidation Catalyst

PHPP Palmdale Hybrid Power Project23

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October 2011 PM Total Particulate Matter

PM 2.5 Particulate Matter with aerodynamic diameter less than 2.5 micrometers

PM 10 Particulate Matter with aerodynamic diameter less th an 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 Catalyt ic Reduction

SF 6 Sulfur Hexafluoride

SO 2 Sulfur Dioxide

SO X 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 require d b y this Approval to Construct must be sent to:

A

. D irector, 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

Antel ope Valley Air Quality Management District

43 301 Division Street, Suite 206 Lancaster, CA 9353 5

Fax: (661) 723

- 3450