Draft for March 20, 2013 public notice. 

### PREVENTION OF SIGNIFICANT DETERIORATION PERMIT FOR GREENHOUSE GAS EMISSIONS ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR § 52.21

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 6

PSD PERMIT NUMBER:

PERMITTEE:

FACILITY NAME:

FACILITY LOCATION: PSD

- TX -1288- GHG

La Paloma Energy Center, LLC 4011 West Plano Parkway, Suite 128 Plano , TX 75093

La Paloma Energy Center, LLC La Paloma Energy Center (LPEC)

24684 FM 1595 Harlingen , TX 78550

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C (42 U.S.C. Section 7470, et. Seq. ), and the Code of Federal Regulations (CFR) Title 40, Section 52.21, and the Federal Implementation Plan at 40 CFR § 52.2305 (effective May 1, 2011 and published at 76 FR 25178), the U.S. Environmental Protection Agency, Region 6 is issuing a Pr evention of Significant Deterioration (PSD) permit to La Paloma Energy Center, LLC ( La Paloma ) for Greenhouse Gas (GHG) emissions . The Permit applies to the construction of a new natural gas fired combined cycle electric generating plant, La Paloma Energy Center (LPEC), to be located near Harlingen, Cameron County, Texas.

La Paloma is authorized to construct a new natural gas fired combined cycle electric generating plant as described herein, in accordance with the permit application (and plans submitted with the permit application), the federal PSD regulations at 40 CFR § 52.21, and other terms and conditions set forth in this PSD permit in conjunction with the corresponding Texas Commission on Environmental Quality (TCEQ) PSD permit No. PSD

- TX -1288. Failu re to comply with any condition or term set forth in this PSD Permit may result in enforcement action pursuant to Section 113 of the Clean Air Act (CAA). This PSD Permit does not relieve La Paloma of the responsibility to comply with any other applicable provisions of the CAA (including applicable implementing regulations in 40 CFR Parts 51, 52, 60, 61, 72 through 75, and 98) or other federal and state requirements (including the state PSD program that remains under approval at 40 CFR § 52.2303).

In accor dance with 40 CFR §124.15(b), this PSD Permit becomes effective 30 days after the service of notice of this final decision unless review is requested on the permit pursuant to 40 CFR §124.19.

__________________________________ David F. Garcia

, Acting Director Date Multimedia Planning and Permitting DivisionDraft for March 20, 2013 public notice. 2 La Paloma LLC ( PSD

- TX -1288- GHG ) Prevention of Significant Deterioration Permit For Greenhouse Gas Emissions Draft Permit Conditions

PROJECT DESCRIPTION

La Paloma Energy Center is proposing to construct a new combined cycle electric generating plant (LPEC) in Cameron County, Texas. LPEC will generate 637 - 735 megawatts (MW) of gross electrical power near the City of Harlingen. The LP EC will consist of the following sources of GHG emissions:

• Two natural gas -fired combustion turbines equipped with lean pre- mix low

- NOx combustors;

• Two natural gas -fired duct burner systems;

• Natural gas piping and metering;

• One diesel fuel

- fired emergency electrical generator engine;

• One diesel fuel

- fired fire water pump engine;

• One natural gas

- fired auxiliary boiler; and

• Electrical equipment insulated with sulfur hexafluoride (SF 6 ).

EQUIPMENT LIST

The following devices are subject to this GHG PSD permit

.

FIN EPN Description

CTG1/HRSG1 CTG2/HRSG2 U1

- STK U2

- STK 2 Natural Gas

- Fired Combined Cycle Combustion Turbines (Combustion Units). The combustion turbines are equipped with heat recovery steam gener a tors (HRSG) and selective catalytic reduction (SCR).

AUXBLR AUXBLR 1 Auxiliary Boiler (Combustion Unit)

. The boiler has a maximum design heat input rate of 150 MMbtu/hr, and is fired with natural gas.

TRB

- MSS TRB

- MSS Gas venting during MSS of the turbines.

FWP1

- STK FWP 1 Fire Water Pump (Combustion Unit). 500 horsepower (hp) Diesel Fired Fire Water Pump rated at 3.4 MMBtu/hr and limited to 100 hours of operation per year for non

- emergency activities.

EMGEN1

- STK EMGEN1 1 Emergency Generator (Combustion Unit). 1,072 horsepower (hp) Diesel Fired Emergency Generator rated at 7.9 MMBtu/hr and limited to 100 hours of operation per year for non

- emergency activities.

SF6

- FUG SF6

- FUG SF 6 Insulated Electrical Equipment (i.e., circuit breakers) with 400 lb SF 6 capacity

. NG

- FUG NG

- FUG Process Fugitives.Draft for March 20, 2013 public notice. 3 I. GENERAL PERMIT CONDITIONS

A. PERMIT EXPIRATION

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

1. is not commenced (as defined in 40 CFR §52.21(b)(9)) within 18 months after the approval takes effect; or

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

3. is not completed within a reasonable time.

Pursuant to 40 CFR §52.21(r), EPA may extend the 18-month period upon a written satisfactory showing that an extension is justified.

B. PERMIT NOTIFICATION REQUIREMENTS

Permittee shall notify EPA Region 6 in writing or by electronic mail of the:

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

2. actual date of initial startup, as defined in 40 CFR §60.2, postmarked within 15 days of such date; and

3. date upon which initial performance tests will commence, in accordance with the provisions of Section V I, 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 VI.C.

C. FACILITY OPERATION

At all times, including periods of startup, shutdown, and maintenance , Permittee shall, to the extent practicable, maintain and operate the f acility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the EPA, which may include, but is not limited to, monitoring results, review of operating maintenance procedures and inspection of the f acility

.Draft for March 20, 2013 public notice. 4 D. MALFUNCTION REPORTING

1. Permittee shall notify EPA by mail within 48 hours following the discovery of any failure of air pollution control equipment, process equipment, or of a process to operate in a normal manner, which results in an increase in GHG emissions above the allowable emission limits stated in Section s II and III of this permit.

2. Within 10 days of the restoration of normal operations after any failure described in I.D.1. , Permittee shall provide a written supplement to the initial notification that includes

a description of the malfunctioning equipment or abnormal operation, the date of the initial malfunction, the period of time over which emissions were increased due to the failure, the cause of the failure, the estimated resultant emissions in excess of those allowed in Section II and III, and the methods utilized to mitigate emissions and restore normal operations.

3. 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.

E. RIGHT OF ENTRY

EPA authorized representative s, upon the presentation of credentials, shall be permitted:

1. t o 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;

2. 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;

3. to inspect any equipment, operation, or method subject to requirements in this PSD Permit; and,

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

F. TRANSFER OF OWNERSHIP

In the event of any changes in control or ownership of the facilities to be constructed, this PSD Permit shall be binding on all subsequent owners and operators. Permittee shall notify the succeeding owner and operator of the existence of the PSD Perm it and its conditions by letter; a copy of th e letter shall be forwarded to EPA Region 6 within thirty days of the letter signature

.Draft for March 20, 2013 public notice. 5 G. 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.

H. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER ENVIRONMENTAL LAWS

Permittee shall construct this project in compliance with this PSD Permit, the application on which this permit is based , the TCEQ PSD Permit PSD

- TX -1288 (when issued) 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.Draft for March 20, 2013 public notice. 6 I. ACRONYMS AND ABBREVIATIONS

API American Petroleum Institute BACT Best Available Control Technology BSCFD Billion Standard Cubic Feet per Day CAA Clean Air Act CC Carbon Content CCS Carbon Capture and Sequestration CEMS Continuous Emissions Monitoring System CFR Code of Federal Regulations CH 4 Methane CO 2 Carbon Dioxide CO 2 e Carbon Dioxide Equivalent CT Combustion Turbine DLNB Dry Low

- NO x Burner dscf Dry Standard Cubic Foot EF Emission Factor EPN Emission Point Number FIN Facility Identification Number FR Federal Register GHG Greenhouse Gas
gr Grains GWP Global Warming Potential HHV High Heat ing Value hr Hour LAER Lowest Achievable Emission Rate lb Pound LDAR Leak Detection and Repair MMBtu Million British Thermal Units MSS Maintenance, Start

- up and Shutdown mtpa Million Tons per Annum NNSR Nonattainment New Source Review N 2 O Nitrous Oxides NO x Nitrogen Oxides NSPS New Source Performance Standards PSD Prevention of Significant Deterioration QA/QC Quality Assurance and/or Quality Control SCFH Standard Cubic Feet per Hour SCR Selective Catalytic Reduction SF 6 Sulfur Hexafluoride TAC Texas Administrative Code TCEQ Texas Commission on Environmental Quality TPY Tons per Year USC United States Code VOC Volatile Organic CompoundDraft for March 20, 2013 public notice. 7 II. Annual Emission Limits
Annual emissions, in tons per year ( TPY ) on a 12-month, rolling average , shall not exceed the following if the General Electric 7FA is selected as the combustion turbine model :

Table 1A. Annual Emission Limits 1
- General Electric 7FA

FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

U1

- STK U1

- STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,261,820

1,263,055 934.5 lb CO 2 /MWh (gross) with duct burning

. 5 See Special Conditions III. A. 1. CH 4 23.4

N 2 O 2.4

U2

- STK U2

- STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,261,820

1,263,055 934.5 lb CO 2 /MWh (gross) with duct burning

. 5 See Special Conditions III. A. 1. CH 4 23.4

N 2 O 2.4

AUXBLR AUXBLR Auxiliary Boiler CO 2 7,680

7,687 Good Combustion and Operating Practices. Limit to 876 hours of operation per year. See Special Conditions III. B

. CH 4 0.14

N 2 O 0.01

EMGEN1

- STK EMGEN1

- STK Emergency Generator CO 2 64

64 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III. C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

FWP1

- STK FWP1

- STK Fire Water Pump CO 2 28

28 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III. C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

TRB

MSS TRB

MSS Maintenance , Startup, and Shutdown CO 2 No Numerical Limit Established 6 2.2 Negligible emissions, EPA verified the provided analysis.

CH 4 0.106

NG

- FUG NG

- FUG Natural Gas Fugitives CO 2 Not Applicable Not Applicable Implementation of AVO Monitoring. See Special Condition III.D. CH 4 Not ApplicableDraft for March 20, 2013 public notice. 8 FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

SF6

- FUG SF6

- FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 6 23.9 Instrumented monitoring and alarm. See Special condition III.D.

Totals 7 CO 2 2,531,413 CO 2 e 2,534,338 CH 4 67 N 2 O 4.8 1. Compliance with the annual emission limits (tons per year) is based on a 12

- month rolling average. 2. The TPY emission limits specified in this table are not to be exceeded for this facility and include emissions from the facility during all operations and include MSS activities. 3. Global Warming Potentials (GWP): CH 4 = 21, N 2 O = 310 4. The annual emissions limit for the combustion turbines is based on operating at ma ximum duct burner firing for 8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 5. The BACT limit for the combustion turbine does not apply during MSS. 6. All values indicated as “No Numerical Limit Establ ished” are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work practice standard as specified in the permit. 7. The total emissions f or CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4 . Total emissions

are for informa tion only and do not const i tute an emission limit.Draft for March 20, 2013 public notice. 9 Annual emissions, in tons per year (TPY) on a 12-month, rolling average, shall not exceed the following if the Siemens SGT6 -5000F(4) is selected as the combustion turbine model:

Table 1B. An nual Emission Limits 1
- Siemens SGT6 -5000F(4)

FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

U1

- STK U1

- STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,415,907

1,417,263 909.2 lb CO 2 /MWh (gross) with duct burning

. 5 See Special Conditions III. A. 1. CH 4 26.2 7

N 2 O 2.6

U2

- STK U2

- STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,415,907

1,417,263 909.2 lb CO 2 /MWh (gross) with duct burning

. 5 See Special Conditions III. A. 1. CH 4 26.2

N 2 O 2.6

AUXBLR AUXBLR Auxiliary Boiler CO 2 7,680

7,687 Good Combustion and Operating Practices. Limit to 876 hours of operation per year. See Special Conditions III.B. CH 4 0.14

N 2 O 0.01

EMGEN1

- STK EMGEN1

- STK Emergency Generator CO 2 64

64 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

FWP1

- STK FWP1

- STK Fire Water Pump CO 2 28

28 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

TRB

- MSS TRB

MSS Maintenance , Startup, and Shutdown CO 2 No Numerical Limit Established 6 2.2 Negligible emissions, EPA verified the provided analysis. CH 4 0.106

NG

- FUG NG

- FUG Natural Gas Fugitives CO 2 Not Applicable Not Applicable Implementation of AVO Monitoring. See Special Condition III.D. CH 4 Not ApplicableDraft for March 20, 2013 public notice. 10 FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

SF6

- FUG SF6

- FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 6 23.9 Instrumented monitoring and alarm. See Special condition III.D.

Totals 7 CO 2 2,839,587 CO 2 e 2,842,754 CH 4 73 N 2 O 5.2 1. Compliance with the annual emission limits (tons per year) is based on a 12 month rolling average. 2. The TPY emission limits specified in this table are not to be exceeded for this facility and include emissions from the facility during all operations and include MSS activities. 3. Global Warming Potentials (GWP): CH 4 = 21, N 2 O = 310 4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 5. The BACT limit for the combustion turbine does not apply during MSS. 6. All values indicated as “No Numerical Limit Established” are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work practice standard as specified in the permit. 7. The total emissions f or CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4 . Total emissions are for informa tion only and do not const i tute an emission l imit.Draft for March 20, 2013 public notice. 11 Annual emissions, in tons p er year (TPY) on a 12-month, rolling average, shall not exceed the following if the Siemens SGT6 -5000F(5) is selected as the combustion turbine model:

Table 1C. Annual Emission Limits 1
- Siemens SGT6 -5000F(5)

FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

U1

- STK U1

- STK Combined Cycle Combu stion Turbine/Heat Recovery Steam Generator CO 2 1,594,162

1,595,712 912.7 lb CO 2 /MWh (gross) with duct burning . See Special Conditions III. A. 1. CH 4 29.5

N 2 O 3

U2

- STK U2

- STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator CO 2 1,594,162

1,595,712 912.7 lb CO 2 /MWh (gross) with duct burning . See Special Conditions III. A. 1. CH 4 29.5

N 2 O 3

AUXBLR AUXBLR Auxiliary Boiler CO 2 7,680

7,687 Good Combustion and Operating Practices. Limit to 876 hours of operation per year. See Special Conditions III.B. CH 4 0.14

N 2 O 0.01

EMGEN1

- STK EMGEN1

- STK Emergency Generator CO 2 64

64 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

FWP1

- STK FWP1

- STK Fire Water Pump CO 2 28

28 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

TRB

- MSS TRB

MSS Maintenance , Startup, and Shutdown CO 2 No Numerical Limit Established 6 2.2 Negligible emissions, EPA verified the provided analysis.

CH 4 0.106

NG

- FUG NG

- FUG Natural Gas Fugitives CO 2 Not Applicable Not Applicable Implementation of AVO Monitoring. See Special Condition III.D. CH 4 Not ApplicableDraft for March 20, 2013 public notice. 12 FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

SF6

- FUG SF6

- FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 6 23.9 Instrumented monitoring and alarm. See Special condition III.D.

Totals 7 CO 2 3,196,097 CO 2 e 3,199,650 CH 4 80 N 2 O 6 1. Compliance with the annual emission limits (tons per year) is based on a 12 month rolling average. 2. The TPY emission limits specified in this table are not to be exceeded for this facility and include emissions from the facility during all operations and include MSS activities. 3. Global Warming Potentials (GWP): CH 4 = 21, N 2 O = 310 4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 5. The BACT limit for the combustion turbine does not apply during MSS. 6. All values indicated as “No Numerical Limit Established” are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/wo rk practice standard as specified in the permit. 7. The total emissions f or CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4 . Total emissions are for informa tion only and do not const i tute an emission limit.Draft for March 20, 2013 public notice. 13 III. SPECIAL PERM IT CONDITIONS

A. Requirements for Combustion Turbine Generators (CTG) and Heat Recovery Steam Generators (HRSG) ( EPNs - U1

- STK and U2

- STK)

The Permittee shall comply with Table 1A, 1B, or 1C depending on the selection of manufacturer and model of combined cycle combustion turbine selected. Upon selection of a combustion turbine model, LPEC must submit a permit application amendment to remove the

tu rbine models not selected.

1. Combustion Turbine Generator (CTG) BACT Emission Limits

Table 2. BACT Emissi on Limits for Combustion Turbines on a 12 month rolling average

Turbine Model Gross Heat Rate, with duct burner firing (Btu/kWh) (HHV) Output Based Emission Limit (lb CO 2 /MWh) gross with duct burning
General Electric 7FA 7,861.8 934.5
Siemens SGT6

- 5000F (4) 7,649.0 909.2
Siemens SGT6

- 5000F (5) 7, 679.0 912.7

a. Within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days of the date of initial startup of the combustion turbine generators, the Permittee shall perform an initial emission test for CO 2 and use emission factors from 40 CFR Part 98. The Permittee shall ensure that GHG emissions from the Combustion Turbine Generator and heat recovery steam generator (U1

- STK and U2

- STK) into the atmosphere do not exceed the limits in lbs CO 2 /MWh ( gross ) from Table 2 , during the test. To determine this BACT emission limit, Permittee shall calculate the limit based on the measured hourly energy output (MWh ( gross )), the CTG is operating at , or above 90% of its design capacity without duct burning firing and the results shall be corrected to ISO conditions (59 o F, 14.7 psia, and 67% humidity). If the CTG does not meet the design emissions limit, then the Permittee shall remedy the CTG’s failure to meet the design emissions limit, and will make corrections to the CTG and will only combust fuel to perform required tuning and modifications necessary to demonstrate compliance. b. Upon demonstration that the combustion turbine generators are in compli ance with the design emissions limit via an emission test, the Permittee shall not discharge or cause the discharge of emissions from the Co mbustion Turbine Generator (CTG ) and heat recovery steam generator (HRSG ) (EPNs U1

- STK and U2

- STK) into the atmosphe re in excess of the limits in lb CO 2 /MWh ( gross) on a 12-month rolling average and shall not discharge or cause the discharge of emissions into the atmosphere in excess of the limits in tons of CO 2 e on a 12-month rolling average asDraft for March 20, 2013 public notice. 14 listed in Table 1A, 1B, or 1C. To det ermine the BACT emission limit , the Permittee shall calculate the limit based on the measured net hourly energy output (MWh (gross)) and the tons of CO 2 calculated from the equations provided in 40 CFR 75, Appendix D and F or the CO 2 emissions CEMS data. The calculated hourly rate is averaged daily.

c. Upon initial demonstration that the combustion turbine generators complies with the emissions limit via an emission test, the Permittee shall not exceed a Combustion Turbine Generator net heat rate Btu/k W h (HHV) from Table 2 on a 12 month rolling average . To determine this limit, Permittee shall calculate the average heat rate on a hourly basis consistent with equation F-20 and procedure provided in 40 CFR Part 75, Appendix F, § 5.5.2 and the measured net hourly energy output (kWh). Sum the hourly heat input for the operating month and sum the hourly gross output for the operating month. Divide the total heat input for the month by the total gross output for the month. Add the quotient to the sum of the quotients of the previous 11 operating months and divide by 12 to determine the 12- operating month rolling average. d. Permittee shall determine the hourly CO 2 emission rate from 40 CFR Part 75, Appendix G, using F c factors updated monthly from fuel analysis or, as an alternative, P ermittee may install and operate a volumetric stack gas flow monitor and associated data acquisition and handling system in accordance with the CO 2 CEMS system provided in 40 CFR § 75.10(a)(3) and (a)(5).

2. Monitoring of CO 2 Emissions for U1

- STK and U2

- STK

a. The P ermittee shall determine the CO 2 hourly emission rate and CO 2 mass emissions for the combustion turbine generator and heat recovery steam generator, identified as U1

- STK and U2

- STK , based on equation G-4 of 40 CFR Part 75 and the average heat rate on an hourly basis based on the heat input calculation procedures contained in 40 CFR Part 75, Appendix F, equation F-20.

b. Permittee shall install, calibrate, and operate a fuel flow meter a nd perform periodic scheduled GCV fuel sampling for the combustion turbine generator and heat recovery steam generator, identified as U1

- STK and U2

- STK , and shall meet the applicable requirements, including certification testing, of 40 CFR Part 75, Appendi x D and 40 CFR Part 60 to be used in conjunction with the F c factor based on the procedures to calculate the CO 2 emission rate in 40 CFR Part 75, Appendix
F.

c. As an alternative to Special Condition III.A.2.a, the Permittee may install a CO 2 CEMS and volume tric stack gas flow monitoring system with an automated data acquisition and handling system for measuring and recording CO 2 emissions discharged to the atmosphere.Draft for March 20, 2013 public notice. 15 d. In accordance with 40 CFR Part 75, Appendix D and 40 CFR Part 60, the P ermittee shall ensure that all required fuel flow meter s are installed, a periodic schedule for GCV fuel sampling is initiated and all certification tests are completed on or before the earlier of 90 unit operating days or 180 calendar days after the date the unit commences commercial operation (as defined in 40 CFR Part 75, Appendix D and G).

e. Permittee shall ensure compliance with the specifications and test procedures for fuel flow meter and/or CO 2 emission monitoring system at stationary sources, 40 CFR Part 75 and 40 CFR Part 60

. f. Permittee shall meet the appropriate quality assurance requirements specified in 40 CFR Part 75, Appendix D and F and 40 CFR Part 60 for the fuel flow meter and/or CO 2 emission monitoring system.

3. U1

- STK and U2

- STK Combustion Turbine Wor k Practice and Operational Requirements

a. Permittee shall calculate the amount of CO 2 emitted for both the CTGs from combustion in tons per hour (tons/hr) on a 12 month rolling average, and converted

to tons per year ( tpy ) based on equation G-4 of 40 CFR Part 75 and the average heat

rate (gross) on an hourly basis based on the heat input calculation procedures contained in 40 CFR Part 75, Appendix F, equation F-20. b. Permittee shall calculate the CH 4 and N 2 O emissions on a 12 month rolling average. Permittee shall determine compliance with the CH 4 and N 2 O emissions limits contained in section II using the default CH 4 and N 2 O emission factors contained in Table C -2 of 40 CFR Part 98 and the measured actual hourly heat input (HHV).

c. Permittee shall calculate the CO 2 e emissions on a 12 month rolling average, based on the procedures and Global Warming Potentials (GWP) contained in Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1. d. Fuel for the Combustion Turbines shall be limited to natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). The gross calorific value of the fuel shall be determined monthly by the procedures contained in 40 CFR Part 75, Appendix F, §5.5.2 and records sha ll be maintained of the monthly fuel gross calorific value for a period of five years. Upon request, Permittee shall provide a sample and/or analysis of the fuel -fired in the Combustion Turbines or shall allow a sample to be taken by EPA for analysis.

e. The flow rate of the fuel combusted in combustion turbine emission units , identified

as U1

- STK and U2

- STK , shall be measured and recorded using an inline flow

meter and automatically record the data with a data acquisition and handling system

. f. Permittee shall measure and record the net energy output (MWh (net)) on an hourly basis.Draft for March 20, 2013 public notice. 16 g. On or before the date of initial performance test required by 40 CFR 60.8, and thereafter, Permittee shall install, and continuously operate, and maintain the HRSGs equipped with a S CR so emissions are at or below the emissions limits specified in this permit and TCEQ permit PSD

- TX -1288. h. The Permittee shall perform an annual compliance t est, at or above ninety percent (90%) of maximum load operations for the atmospheric conditions wh ich exist during testing , corrected to ISO conditions to demonstrate compliance with the proposed heat rate in Table 2. i. On or after initial performance testing, P ermittee shall use the combustion turbine s, Heat Recovery Steam Generator s, Steam Turbines and Plant

- wide energy efficiency processes, work practices and designs as represented in the permit application.

4. Requirements during Combustion Turbine ( U1

- STK and U2

- STK ) Startup and Shutdown

a. Permittee shall minimize emissions during start -up and shutdown activities by operating and maintaining the facility and associated air pollution control equipment in accordance with good air pollution control practices, safe operating practices, and prote ction of the facility. b. Emissions during startup and shutdown activities shall be minimized by limiting the duration of operation in startup and shutdown mode as follows:

i. A startup is defined as the period that begins when the data acquisition and handling system measures fuel flow to the combustion turbine and ends when the combustion turbine generator load reaches 60 percent. A planned startup for each combustion turbine is limited to 360 minutes per event

.

ii. A shutdown is defined as the period that begins when the combustion turbine generator output drops below 60 percent load and ends when there is no longer measureable fuel flow to the combustion turbine . A planned shutdown of the combustion turbine is limited to 60 minutes per event

.

c. Permittee must record the time, date, fuel heat input (HHV) in MMBtu /hr and duration of each startup and shutdown event in order to calculate total CO 2 e emissions. The records must include hourly CO 2 emission levels as measured by the fuel flow meter and/or O 2 emission monitor (or CO 2 CEMS with volumetric stack gas flowrate) and the calculations based on the actual heat input for the CO 2 , CO 2 e, O 2 , N 2 O, and CH 4 emissions during each startup and shutdown event based on the equations represented in the permit application. These records must be kept for five (5) years following the date of such event.Draft for March 20, 2013 public notice. 17 d. The 12-month rolling average BACT emission limitations in Specia l Condition
II I. A.1. does not include periods of startup and shutdown.

B. Requirements for Auxiliary Boiler (AUXBLR)

1. Boiler shall combust only pipeline quality natural gas. 2. Permittee shall measure and record the fuel flow rate using an inline flow meter and automatically record the data with a data acquisition and handling system

. 3. Permittee shall c alibrate and perform prevent a tive maintenance check of the fuel gas flow meters and document annually. 4. Permittee shall perform cleaning of the burner tips annually, at a minimum. 5. Permittee shall perform cleaning of the convection section tubes annually, at a minimum.
6. The maximum firing rate for the auxiliary boiler shall not exceed 150 MMBtu /hr.
7. A rolling 12 month average and the one- hour maximum firing rate shall be calculated daily to demonstrate compliance with the firing rates in III. B.5. 8. Total firing hours of the auxiliary boiler must not exceed 876 hours per year.
9. Daily records of firing hours shall be recorded daily. A 12 month rolling total of boiler hours of operation shall be calculated daily to demonstrate compliance with the limitation of hours in III. B.8. 10. Permittee shall install, operate, and maintain an automated air/fuel control system. 11. Permittee shall calibrate and perform preventative mainten ance on the air/fuel control analyzers once per quarter, at a minimum. 12. Permittee shall install, operate, and maintain an O 2 analyzer on the boiler. 13. Oxygen analyzers shall continuously monitor and record oxygen concentration in the boiler. It shall reduce the oxygen readings to an averaging period of 6 minutes or less and record it at that frequency. 14. The oxygen analyzers shall be quality- assured at least quarterly using cylinder gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 5.1.2, with the following exception: a relative accuracy test audit is not required once every four quarters (i.e., four successive quarterly CGAs may be conducted). 15. Compliance with the Annual Emission Limit shall be demonstrated on a 12 -month total, rolling monthly, calculated in accordance with 40 CFR Part 98 Subpart C § 98.33(a)(1)(i)

.

C. Requirements for the Fire Water Pump (FWP1

- STK) and Emergency Generator (EMGEN1

- STK)

1. The Fire Water Pump ( FWP1

- STK ) and Emergency Generator ( EMGEN1

- STK ) are authorized to fire diesel fuel containing no more than 0.5 percent sulfur by weight. Upon request, Permittee shall provide a sample and/or an analysis of the fuel- fired inDraft for March 20, 2013 public notice. 18 the emission units ( EMGEN1 -STK and FWP1- STK ) or shall allow a sample to be taken by EPA for analysis to demonstrate the percent sulfur of the fuel. 2. The Fire Water Pump and Emergency Generator are limited to 100 hours of nonemergency operation per year for each unit and a heat input value of 3.4 MMBtu/hr and 7.9 MMBtu/hr for the Fire Wate r Pump and the Emergency Generator, respectively. Compliance with the 100 hour non- emergency operational requirement is determined on a 12 month rolling basis. 3. The Fire Water Pump and Emergency Generator shall meet the applicable monitoring and recordkeeping requirements as required in 40 CFR Part 60 Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines.
4. Permittee shall install and maintain an operational non

- resettable elapsed time meter for the Fire Water Pump and Emergency Generator

. 5. Permittee shall maintain a file of all records, data measurements, reports and documents related to the operation of t he Fire Water Pump s and Emergency Generator , including, but not limited to, the following: all records or reports pertaining to maintenance performed, all records relating to performance tests and monitoring of the emergency generator and fire pump equipment; for each diesel fuel oil delivery, documents from the fuel supplier certifying compliance with the fue l sulfur content limit of Special Condition III. C.1., fuel heat input values and hours of operation required in Special Condition III.C.2. ; and all other information required by this permit recorded in a permanent form suitable for inspection. The file must be retained for not less than five years following the date of such measurements, maintenance, reports, and/or records.

D. Requirements for Fugitive Emission Sources ( NG

- FUG and SF6

- FUG )

1. The P ermittee shall implement an auditory /visual/ olfactory (AVO) method for detecting leaking from natural gas piping components , and make observations on a daily basis. 2. For emission unit SF6- FUG, SF 6 emissions shall be calculated annually (calendar year) in accordance with the mass balance approach provided in equation DD-1 of the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and Distribution Equipment Use, 40 CFR Part 98, Subpar t DD. Permittee shall not exceed insulated circuit breaker SF6 capacity exceeding 400 lb s. 3. Permittee shall equip the circuit breakers with a low pressure alarm and a low pressure lockout. The SF 6 leak detection system shall be able to detect a leak of at least 1 lb per year. 4. Permittee shall maintain a file of all records, data measurements, reports and documents related to the fugitive emission sources including, but not limited to, the following: all records or reports pertaining to maintenance performed, all recordsDraft for March 20, 2013 public notice. 19 relating to compliance with the Monitoring and Quality Assurance and Quality Control (QA/QC) procedures outlined in 40 CFR 98.304.

E. Requirements for Maintenance, Startup, and Shutdow n ( TRB

- MSS )

The P ermittee provided data to show that minimal quantities of natural gas are released to the atmosphere during turbine fuel line shutdown maintenance and when performing repair or maintenance on small equipment and fugitive components. Emissions related to these type of events are not expected to exceed 2.2 tons per year of CO 2 e.

IV. RECORDKEEPING AND REPORTING

1. In order to demonstrate compli ance with the GHG emission limits in Table 1, the
P ermittee will monitor the following parameters and summarize the data on a calendar month basis.

a. Operating hours for all air emission sources; b. The natural gas fuel usage for all combustion sources, using continuous fuel flow monitors (a group of equipment can uti lize a common fuel flow meter, as long as actual fuel usage is allocated to the individual equipment based upon actual operating hours and maximum firing rate); and

c. Annual fuel sampling for natural gas.

2. Permittee shall implement an AVO program and keep r ecords of the monitoring results, as well as the repair and maintenance records. 3. Permittee shall maintain all records, data, measurements, reports, and documents related to the operation of the facility, including, but not limited to, the following: all r ecords or reports pertaining to significant maintenance performed on any system or device at the facility; duration of startup, shutdown; the initial startup period for the emission units; pollution control units; malfunctions; all records relating to perf ormance tests, calibrations, checks, and monitoring of combustion equipment; duration of an inoperative monitoring device and emission units with the required corresponding emission data; and all other information required by this permit recorded in a permanent form suitable for inspection. The records must be retained for not less than five years following the date of such measurements, maintenance, reports, and/or records. 4. Permittee shall maintain records of all GHG emission units and CO 2 emission certification tests and monitoring and compliance information required by this permit. 5. Permittee shall maintain records and submit a written report of all GHG excess emissions to EPA semi -annually, except when: more frequent reporting is specifi cally required by an applicable subpart; or the Administrator or authorized representative, on a case- by

case basis

, determines that more frequent reporting is necessary to accurately assess theDraft for March 20, 2013 public notice. 20 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 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 monitoring equipment was inoperative (monitoring down- time);

c. A statement in the report of a negative declaration; that is; a statement when no excess emissions occurred or when the monitoring equipment has not been inop erative, repaired or adjusted; and d. Any failure to conduct any required source testing, monitoring, or other compliance activities

.

6. Excess emissions shall be defined as any period in which the facility emission s exceed a maximum emission limit set forth in this permit.
7. Excess emissions indicated by GHG emission source certification testing or compliance monitoring shall be considered violations of the applicable emission limit for the purpose of this permit. 8. All records required by this PSD Permit shall be retained and remain accessible for not less than 5 years following the date of such measurements, maintenance, and reporting.

V. SHAKEDOWN PERIODS

The combustion turbine emission limits and requirements in conditions II., III.A .1. , and III.B. 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 the time period for performance testing as specified in 40 CFR § 60.8. The requirements of special condition I.C. of this permit shall apply at all ti mes.

VI. PERFORMANCE TESTING

A. The Permittee shall perform stack sampling and other testing to establish the actual pattern and quantities of air contaminants being emitted into the atmosphere from the stacks of the Combustion Turbines and HRSGs (U1 -STK and U2

- STK) and the Auxiliary Boiler ( AUXBLR ) to determine the initial compliance with the CO 2 emission limits established in this permit. Sampling shall be conducted in accordance with 40 CFR § 60.8 and EPA Method 3a or 3b for the concentration of CO 2
.Draft for March 20, 2013 public notice. 21 1. Multi ply the CO 2 hourly average emission rate determined under maximum operating test conditions by 8,760 hours for the combustion turbines and 876 hours for the auxiliary boiler

. 2. If the above calculated CO 2 emission total does not exceed the tons per year (TPY ) specified on Table 1, no compliance strategy needs to be developed. If the above calculated CO 2 emission total exceeds the tons per year (TPY) specified in Table 1, the facility shall:

a. Document the potential to exceed in the test report; and b. Explain within the report how the facility will assure compliance with the CO 2 emission limit listed in Table 1.

B. Within 60 days after achieving the maximum production rate at which the affected facility will be operated, but not later than 180 days after initial startup of the facility, performance tests(s) must be conducted and a written report of the performance testing results furnished to the EPA. Additional sampling may be required by TCEQ or EPA. C. 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 EPA 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. D. The turbine shall be tested at or above ninety percent (90%) of maximum load operations for the atmospheric conditions which exist during testing. The duct burners shall be tested at its maximum firing rate within the mechanical limits of the equipment for the atmospheric conditions which exists during the performance test while the turbine is operating as close to base load as possible. The tested turbine load shall be identified in the sampling report. The permit holder shall present in the performance tes t protocol the manner in which stack sampling will be executed in order to demonstrate compliance with the emissions limits contained in Section II. E. Air emissions from each HRSG exhaust stack shall be tested while firing at the minimum load in the normal operating range. The normal operating range consistent with emission limits is to be determined during stack testing. Air emissions that will be sampled and analyzed while at the minimum load include (but are not limited to) CO 2
. F. Performance tests must be conducted under such conditions to ensure representative performance of the affected facility. The owner or operator must make available to the EPA such records as may be necessary to determine the conditions of the performance tests. G. The owner or operator shall provide, or cause to be provided, performance testing facilities as follows:
1. Sampling ports adequate for test methods applicable to this facility, 2. Safe sampling platform(s), 3. Safe access to sampling platform(s), and 4. Utilities for sampling and testing equipment.Draft for March 20, 2013 public notice. 22 H. Unless otherwise specified, each performance test shall consist of three separate runs using the applicable test method. Each run shall be conducted for the time and under the conditions specified in the applicable standard. For purposes of de termining compliance with an applicable standard, the arithmetic mean of the results of the three runs shall apply.

VII. A gency Notifications

Permittee shall submit GHG permit applications, permit amendments, and other applicable permit information to:

Mul ti Media Planning and Permitting Division EPA Region 6 1445 Ross Avenue (6 PD -R) Dallas, TX 75202 Email: Group R6AirPermits@EPA.gov

Permittee shall submit a copy of all compliance and enforcement correspondence as required by this Approval to Construct to:

Compliance Assurance and Enforcement Division EPA Region 6 1445 Ross Avenue (6EN) Dallas, TX 752021 Statement of Basis Draft Greenhouse Gas Prevention of Signifi cant Deterioration Preconstruction Permit for the La Paloma Energy Center, LLC

Permit Number: PSD-TX-1288-GHG

March 2013

This document serves as the Statement of Basis (SOB) for the above-referenced draft permit, as required by 40 CFR 124.7. This document sets fort h the legal and factua l basis for the draft permit conditions and provides references to th e statutory or regulator y provisions, including provisions under 40 CFR 52.21, that would apply if the permit is finalized. This document is intended for use by all parties interested in the permit.

I. Executive Summary

On April 30, 2012, La Paloma Energy Center, LLC (La Paloma), submitted to EPA Region 6 a Prevention of Significant Deterioration (PSD) permit application for Greenhouse Gas (GHG) emissions for a proposed constructi on project. On July 17, 2012 and August 6, 2012, La Paloma submitted additional information for inclusion into the application. In connection with the same proposed construction project, La Paloma submitted an application for a PSD Permit for non-GHG pollutants to the Texa s Commission on Environmental Quality (TCEQ) on March 15, 2012. The project proposes to construct a new natural gas fired combined cycle electric generating plant, La Paloma Energy Center (LPEC), to be located near Harlingen, Cameron County, Texas. The LP EC will consist of two natural gas fired combustion turbines, each exhausting to a heat recovery steam generator (HRSG) to produce steam to drive a shared steam turbine. Afte r reviewing the application, EPA Region 6 has prepared the following SOB and draft air perm it to authorize construction of air emission sources at the La Paloma Energy Center.

This SOB documents the information and anal ysis EPA used to support the decisions EPA made in drafting the air permit. It includes a description of the proposed facility, the applicable air permit requirements, and an analysis showing how the applicant complied with the requirements.

EPA Region 6 concludes that La Paloma’s applic ation is complete and provides the necessary information to demonstrate that the proposed project meets the a pplicable air permit regulations. EPA's conclusions rely upon information provided in the permit application, supplemental information requested by EPA and provided by La Paloma, and EPA's own technical analysis. EPA is making all this information ava ilable as part of the public record

.2 II. Applicant

La Paloma Energy Center, LLC 4011 West Plano Parkway Suite 128 Plano, TX 75093

Facility Physical Address: 24684 FM 1595 Harlingen, TX 78550

Contact: Kathleen Smith President La Paloma Energy Center, LLC (281) 253-4385

III. Permitting Authority

On May 3, 2011, EPA published a federal implemen tation plan (FIP) that makes EPA Region 6 the PSD permitting authority for the pollutant GHGs. See 75 FR 25178 (promulgating 40 CFR § 52.2305).

The GHG PSD Permitting Authority for the State of Texas is:

EPA, Region 6 1445 Ross Avenue Dallas, TX 75202

The EPA, Region 6 Permit Writer is: Aimee Wilson Air Permitting Section (6PD-R) (214) 665-7596

The Non-GHG PSD Permitting Authority for the State of Texas is:

Air Permits Division (MC-163) TCEQ P.O. Box 13087 Austin, TX 78711-30873 IV. Facility Location

The La Paloma Energy Center (LPEC) will be lo cated in Cameron County, Texas, and this area is currently designated “attainment” for all criteria pollutants. The nearest Class 1 area is the Big Bend National Park, which is located well ove r 100 miles from the site. The geographic coordinates for this proposed facility site are as follows:

Latitude: 26o 12’ 58.9” North Longitude: -97o 37’41.02” West

Below, Figure 1 illustrates the proposed f acility location for this draft permit.

Figure 1. La Paloma Energy Center Location4 V. Applicability of Prevention of Significant Deterioration (PSD) Regulations

EPA Region 6 implements a GHG PSD FIP for th e State of Texas under the provisions of 40 CFR 52.21 (except paragraph (a)(1)). See 40 CFR § 52.2305. For the proposed construction project, La Paloma estimates potential GHG em issions of 3,292,862 tons per year (tpy) of CO 2 e. Since the proposed project’s GHG emissions woul d make LPEC a major stationary source for pursuant to 40 CFR 52.21(b)(1)(i) a nd (b)(49)(iv), EPA concludes th at La Paloma’s application is subject to PSD review for GHG.

La Paloma represents that TCEQ, the permitting authority for regulated NSR pollutants other than GHGs, will determine that LPEC is also subject to PSD review for VOC, NOx, CO, PM,
PM 10 , PM 2.5 , and H 2 SO 4 . Accordingly, under the circumstance s of this project, the TCEQ will issue the non-GHG portion of the perm it and EPA will issue the GHG portion. 1

EPA Region 6 applies the policies and practices reflected in EPA’s PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011). Consistent with that guidance, we have not required the applicant to model or conduct ambient monitoring for GHGs, nor have we required any assessment of impacts of GHGs in the context of the additional impacts analysis or Class I area provisions. Instead, EPA has determined that compliance with the BACT analysis is the best technique that can be employed at present to satisfy the additiona l impacts analysis and Class I area requirements of the rules related to GHGs. We note again, however, that the project has regulated NSR pollutants that are non-GHG pollu tants, which are addressed by the PSD permit to be issued by TCEQ.

VI. Project Description

The proposed GHG PSD permit, if finalized, woul d authorize La Paloma Energy Center to construct a new combined cycle electric gene rating plant (LPEC) in Cameron County, Texas. LPEC will generate 637 - 735 megawatts (MW) of gross electrical power near the City of Harlingen. The gross electrical power output is based on two turb ines rated between 183 and 232 MW each and the steam from the HRSGs driving a third electric generato r with an electricity output capacity of 271 MW. The LP EC will consist of the following sources of GHG emissions:

 Two natural gas-fired combustion turbines equipped with lean pre-mix low-NOx combustors;

 Two natural gas-fired duct burner system equipped Heat Recovery Steam Generators (HRSG);

 Natural gas piping and metering;

1 See EPA, Question and Answer Document: Issuing Permits for Sources with Dual PSD Permitting Authorities, April 19, 2011, http://www.epa.gov/nsr/ghgdocs/ghgissuedualpermitting.pdf5  One diesel fuel-fired emergenc y electrical generator engine;

 One diesel fuel-fired fire water pump engine;

 One natural gas-fired auxiliary boiler; and

 Electrical equipment insulated with sulfur hexafluoride (SF 6 ).

Combustion Turbine Generator

The plant will consist of two identical natural gas-fired combustion turb ines (CTGs). There are three models being considered by LPEC: the General Electric 7FA, the Siemens SGT6-5000F(4), and the Siemens SGT6-5000F(5). The final selecti on of the combustion turb ine model to be used at the plant will likely be made after the perm it is issued. Each combustion turbine will exhaust to a heat recovery steam generator (HRSG). As explained below, the final permit will include BACT limits and related conditions specific to ea ch of the possible turb ine models. If a final selection of combustion turbine is made after th e public notice begins, and before the issuance of the final permit, EPA will issue a final permit including only the limits for the selected turbine.

The combustion turbine will burn pipeline natural gas to rotate an electrical generator to generate electricity. The main components of a combustion turbine generator cons ist of a compressor, combustor, turbine, and generator. The compre ssor pressurizes combustion air to the combustor where the fuel is mixed with the combustion ai r and burned. Hot exhaust gases then enter the turbine where the gases expand across the turbine blades, driving a shaft to power an electric generator. The exhaust gas will exit the combustion turbine and be routed to the HRSG for steam production.

Heat Recovery Steam Generator with Duct Burners

Heat recovered in the HRSG will be utilized to produce steam. Steam generated within the HRSG will be utilized to drive a steam turbine and associated electrical generator. The HRSG will be equipped with duct burners for supplemental steam production. The duct burners will be fired with pipeline quality natural gas. The duct burners have a maximum heat input capacity of 750 MMBtu/hr per unit. The exhaust gases from th e unit, including emissions from the CT and the duct burners, will exit thr ough a stack to the atmosphere.

The normal duct burner operation will vary from 0 to 100 percent of the maximum capacity. Duct burners will be located in the HRSG prior to the selective catalytic reduction (SCR) system.

Generators Overall

Steam produced by each of the two HRSGs will be routed to the steam turbine. The two combustion turbines and one steam turbine will be coupled to electric generators to produce6 electricity for sale to the Electric Reliability Council of Texas (ERCOT) power grid. Each combustion turbine model has an approximate maximum base-load electric power output as follows: GE 7FA output of 183 MW, the Siem ens SGT6-5000F(4) output of 205 MW, and the Siemens SGT6-5000F(5) output of 232 MW. The maximum electric power output from the steam turbine is approximately 271 MW for both the GE and Siemens configurations. The units may operate at reduced load to respond to changes in system power requirements and/or stability.

Auxiliary Boiler

One auxiliary boiler will be avai lable to facilitate startup of the combined cycle turbine units. The auxiliary boiler will have a maximum heat input of 150 MMBtu/hr and will burn pipeline natural gas. The auxiliary boiler is proposed to be permitted to operate up to 876 hours per year.

Emergency Equipment

The site will be equipped with one nominally rated 1,072-hp diesel-fired emergency generator to provide electricity to the facility in case of power failure. A nominally rated 500-hp diesel-fired pump will be installed at the site to provide water in the event of a fire. Each emergency engine will be limited to 100 hours of operation per ye ar for purposes of maintenance checks and readiness testing.

Electrical Equipment Insulated with Sulfur Hexafluoride (SF 6 )

The generator circuit breakers associated with the proposed units will be insulated with SF 6 . SF 6 is a colorless, odorless, non-flamma ble, and non-toxic synthetic gas. It is a fluorinated compound that has an extremely stable molecular stru cture. The unique chemical properties of SF 6 make it an efficient electrical insulato r. The gas is used for electric al insulation, arc quenching, and current interruption in high-vol tage electrical equipment. SF 6 is only used in sealed and safe systems which under normal circumstances do not l eak gas. The capacity of the circuit breakers associated with the proposed plant is currently estimated to be 400 lbs of SF 6 . The proposed circuit breaker at the generator output will have a low pressure alarm and a low pressure lockout. The alarm will alert personnel of any leakage in the system and the lockout prevents any operation of the breaker due to lack of “quenching and cooling” of SF 6 gas.

VII. General Format of the BACT Analysis

The BACT analyses for this draft permit were conducted in accordance with EPA’s PSD and Title V Permitting Guidance for Greenhouse Gases (March 2011), which outlines the steps for conducting a “top-down” BACT analysis . Those steps are listed below.7 (1) Identify all availa ble control options; (2) Eliminate technically infeasible control options; (3) Rank remaining control options; (4) Evaluate the most effective controls (t aking into account the energy, environmental, and economic impacts) and document the results; and (5) Select BACT.

VIII. Applicable Emission Units for BACT Analysis

The majority of the GHGs associated with the project are from emissions at combustion sources (i.e., combined cycle combustion turbines, auxili ary boiler, emergency engine, and fire water pump). The project will have fugitive emissions from piping components which will account for 423 TPY of CO 2 e, or less than 0.01% of the project’s total CO 2 e emissions. Stationary combustion sources primarily emit CO 2 , and small amounts of N 2 O and CH 4 . The following equipment is included in this proposed GHG PSD permit:

 Combined Cycle Combustion Turbines (U1-STK and U2-STK)

 Auxiliary Boiler (AUXBLR)

 Emergency Generator (EMGEN1-STK)

 Fire Water Pump (FWP1-STK)

 Natural Gas Fugitives (NG-FUG)

 SF 6 Insulated Equipment (SF6-FUG)

 Gaseous Fuel Venting (TRB-MSS)

IX. Combined Cycle Combustion Turbines (U1-STK and U2-STK)

There will be two new natural gas fired combined cycle combustion turbines (U1-STK and U2- STK) used for power generation. La Paloma is evaluating three combustion turbines for this project: General Electric 7FA, Siemens SGT6 -5000F(4), and Siemens SGT6-5000F(5). The BACT analysis for the turbines considered tw o types of GHG emission re duction alternatives: (1) energy efficiency processes, practices, and designs for the turbines and other facility components; and (2) carbon capture and storag e/sequestration (CCS). The proposed energy efficiency processes, practices, and designs disc ussed in Step 1 will be the same for the three models being considered. The proposed BACT limits listed in Step 5 section are specific to each turbine model.

As part of the PSD review, La Paloma provi ded in the GHG permit application a 5-step topdown BACT analysis for the combustion turbin es. EPA has reviewed La Paloma’s BACT analysis for the combustion turbines, which is part of the record for this permit (including this8 Statement of Basis), and we also provide our own analysis in setti ng forth BACT for this proposed permit, as summarized below.

Step 1 – Identify All Available Control Options

(1) Energy Efficiency Processe s, Practices, and Design

Combustion Turbine:

 Combustion Turbine Design – The most efficient way to gene rate electricity from a natural gas fuel source is the use of a combined cycl e combustion turbine. Furthermore, the three turbine models under cons ideration for the LPEC facility are highly efficient turbines, in terms of their heat rate (expre ssed as number of BTUs of he at energy required to produce a kilowatt-hour of electricity), wh ich is a measure that reflects how efficiently a generator uses heat energy.

 Periodic Burner Tuning – Periodic combustion inspect ions involving tuning of the combustors to restore highly e fficient low-emission operation.

 Reduction in Heat Loss – Insulation blankets are applied to the combustion turbine casing. These blankets minimize the heat loss through the combustion turbine shell and help improve the overall efficiency of the machine.

 Instrumentation and Controls – The control system is a digi tal type supplied with the combustion turbine. The control system monitors th e operation of the unit and modulates the fuel flow and turbine operation to achieve opt imal high-efficiency low-emission performance for full load and part-load conditions.

Heat Recovery Steam Generator:

 Heat Exchanger Design Considerations – The HRSG’s are designed with multiple pressure levels. Each pressure level incorporates an economizer section(s), ev aporator section, and superheater section(s). These heat transfer sect ions are made up of ma ny thin-walled tubes to provide surface area to maximize the tran sfer of heat to the working fluid.

 Insulation – Insulation minimizes heat loss to the surrounding air thereby improving the overall efficiency of the HRSG . Insulation is applied to the HRSG panels that make up the shell of the unit, to the high-temperature stea m and water lines, and typically to the bottom portion of the stack.

 Minimizing Fouling of He at Exchange Surfaces – Filtration of the in let air to the combustion turbine is performed to mini mize fouling. Additionally, cleani ng of the tubes is performed during periodic outages. By reducing the fouli ng, the efficiency of the unit is maintained.

 Minimizing Vented Steam and Repair of Steam Leaks – Steam is vented from the system from deaerator vents, blowdown tank vents, a nd vacuum pumps/steam jet air ejectors. These9 vents are necessary to improve the overall heat transfer with in the HRSG and condenser by removing solids and air that potentially blanke ts the heat transfer surfaces lowering the equipment’s performance. Steam leaks are repair ed as soon as possible to maintain facility performance.

Steam Turbine:

 Use of Reheat Cycles – Reheat cycles are employed to minimize the moisture content of the exhaust steam. This cycle reheats partially expanded steam from the steam turbine.

 Use of Exhaust Steam Condenser – The exhaust steam is satu rated under vacuum condition by the use of a condenser. The condensing stea m creates a vacuum in the condenser, which increases steam turbine efficiency.

 Efficient Blading Design and Turbine Seals – Blade design has evolved for high-efficiency transfer of the energy in the steam to power generation. Blade materials are also important components in blade design, which allow for high-temperature and large exhaust areas to improve performance. The steam turbines have a multiple steam seal design to obtain the highest efficiency from the steam turbine.

 Efficient Steam Turbine Generator Design – The generator for modern steam turbines are cooled allowing for the highest efficiency of the generator, resul ting in an overall highefficiency steam turbine. The cooling method for the LPEC steam turbine will be either totally enclosed water to ai r cooling or hydrogen cooling.

Other Plant-wide Energy Efficiency Features

La Paloma has proposed a number of other measures that help improve overall energy efficiency of the facility (and thereby reducing GHG emi ssions from the emission units), including:

 Fuel Gas Preheating – The overall efficiency of the co mbustion turbine is increased with increased fuel inlet temperatures.

 Drain Operation – Drains are required to allow for draining the equipment for maintenance, and also allow condensate to be removed from steam piping and drains for operation. Closing the drains as soon as the appropriate steam conditions are achieved will minimize the loss of energy from the cycle.

 Multiple Combustion Turbine/HRSG Trains – Multiple trains allow the unit to achieve higher overall plant part-load efficiency by shutting dow n a train operating at le ss efficient part-load conditions and ramping up the remaining trai n to high-efficiency full-load operation.

 Boiler Feed Pump Variable Speed Drives – To minimize the power consumption at partloads, the use of variable speed drives will be used improving the facility’s overall efficiency.10 (2) Carbon Capture and Sequestration (CCS)

Carbon capture and storage is a GHG control proce ss that can be used by “facilities emitting CO 2 in large concentrations, including fossil fuel-fired power plan ts, and for industrial facilities with high-purity CO 2 streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing).” 2 CCS systems involve the use of adsorp tion or absorption processes to remove CO 2 from flue gas, with subsequent desorption to produce a concentrated CO 2 stream. The three main capture technologies for CCS are pre-co mbustion capture, post-combustion capture, and oxyfuel combustion (IPCC, 2005). Of these appro aches, pre-combustion capture is applicable primarily to gasification plants, where solid fu el such as coal is converted into gaseous components by applying heat under pressure in the presence of steam and oxygen (U.S. Department of Energy, 2011). At this time, oxyfuel combustion has not yet reached a commercial stage of deployment for gas turbine applications and still requires the development of oxy-fuel combustors and other components with higher temperature to lerances (IPCC, 2005). Accordingly, pre-combustion capture and oxyfue l combustion are not considered available control options for this propos ed gas turbine fac ility; the third approach, post-combustion capture, is applicable to gas turbines.

With respect to post-combustion capture, a num ber of methods may potentially be used for separating the CO 2 from the exhaust gas stream, in cluding adsorption, physical absorption, chemical absorption, cryogenic separation, and membrane separation (Wang et al., 2011). Many of these methods are either still in development or are not suitable for treating power plant flue gas due to the characteristics of the exhaust stream (Wang, 2011; IPCC, 2005). Of the potentially applicable technologies, post-combustion cap ture with an amine solvent such as monoethanolamine (MEA) is currently the prefer red option because it is the most mature and well-documented technology (Kvamsdal et al., 2011), and because it offers high capture efficiency, high selectivity, and the lowest energy use compared to the other existing processes (IPCC, 2005). Post-combustion capture using MEA is also the only process known to have been previously demonstrated in pr actice on gas turbines (Reddy, Scherffius, Freguia, & Roberts, 2003). As such, post-combustion capt ure is the sole carbon capture technology considered in this BACT analysis.

In a typical MEA absorption process, the flue gas is cooled before it is contacted countercurrently with the lean solvent in a reactor vessel. The scrubbed flue gas is cleaned of solvent and vented to the atmosphere while the rich solv ent is sent to a separate stripper where it is regenerated at elevated temperatures and then returned to the absorber for re-use. Fluor’s

2 U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, PSD and Title V Permitting Guidance for Greenhouse Gases , March 2011, < http:/www.epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf > (March 2011)11 Econamine FG Plus process operates in this mann er, and it uses an MEA-based solvent that has been specially designed to recover CO 2 from oxygen-containing streams with low CO 2 concentrations typical of ga s turbine exhaust (Fluor, 2009). This process has been used successfully to capture 365 tons per day of CO 2 from the exhaust of a natural gas combinedcycle plant owned by Florida Power and Li ght in Bellingham, Massachusetts. The CO 2 capture plant was maintained in continuous operation from 1991 to 2005 (Reddy, Sche rffius, Freguia, & Roberts, 2003). As this technology is commercia lly available and has been demonstrated in practice on a combined-cycle plant, EPA generally considers it to be technically feasible for natural gas combined cycle turbines.

Once CO 2 is captured from the flue gas, the captured CO 2 is compressed to 100 atmospheres (atm) or higher for ease of trans port (usually by pipeline). The CO 2 would then be transported to an appropriate location for underg round injection into a suitable geological storage reservoir, such as a deep saline aquifer or depleted coal seam, or used in crude oil production for enhanced oil recovery (EOR). There is a large body of ongoing research and field studies focused on developing better understanding of th e science and technologies for CO 2 storage. 3

Step 2 – Elimination of Technically Infeasible Alternatives

All options identified in Step 1 are consider ed technically feasible for this project. 4

Step 3 – Ranking of Remaining Technologies Based on Effectiveness

Since all of the energy efficiency processes, practices, and designs discussed in Step 1, are proposed for this project, we will rank CCS and the suite of energy efficiency measures in BACT Step 4.

Step 4 – Evaluation of Control Options in Order of Most Effective to Least Effective, with Consideration of Economic, En ergy, and Environmental Impacts

Carbon Capture and Storage

La Paloma developed a cost analysis for CCS. Th e estimated total annual cost of CCS would be $271,000,000 per year. The estimated plant construc tion cost with CCS is approximately $974,000,000. EPA Region 6 reviewed La Paloma’s CCS cost estimate and believes it

3 U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory Carbon Sequestration Program: Technology Program Plan

, < http://www.netl.doe.gov/technologies/carbon_seq/ refshelf/2011_Sequestration_Program_Plan.pdf >, February 2011
4 Based on the information provided by La Paloma and re viewed by EPA for this BACT analysis, while there are some portions of CCS that may be technically infeasible for this project, EPA has determined that overall Carbon Capture and Storage (CCS) technology is technologically feasible at this source.12 adequately approximates the cost of a CCS contro l for this project and demonstrates those costs are high in relation to the overall cost of the proposed project w ithout CCS, which is estimated at $443,800,000.

Furthermore, the recovery and purification of CO 2 from the stack gases would necessitate significant additional processing, including energy, a nd environmental/air quality penalties, to achieve the necessary CO 2 concentration for effective se questration. The additional process equipment required to separate, cool, and compress the CO 2 , would require a significant additional water and power expenditure. This eq uipment would include amine scrubber vessels, CO 2 strippers, amine transfer pumps, flue gas fans, an amine storage tank, and CO 2 gas compressors. The LPEC will utili ze the effluent discharge from the local waste water treatment facility to provide both the cooling water and the boiler make-up water requirements. The local waste treatment facility currently processes a nd discharges a daily av erage of seven million gallons of effluent. This volume of effluent cannot support the da ily water requirements of an Fclass natural gas fired combined cycle facili ty if equipped with CCS. The water use for a combined cycle plant with CCS would be 7.6 - 9.5 million gallons per day. The additional GHG emissions resulting from additional fuel combustion would either further increase the cost of the CCS system, if the emissions were also captu red for sequestration, or reduce the net amount GHG emission reduction, making CCS even less cost effective than expected.

Therefore, since the cost of CC S would more than double the cost of the current project, and considering the adverse energy a nd environmental impacts of CCS, CCS has been eliminated as BACT for this project.

Energy Efficiency Measures

None of the Energy Efficiency Measures have be en eliminated from the BACT review based on adverse economic, environmental, or energy imp acts. As noted above, the three turbine models under consideration are some of the most efficien t combined cycle turbin es, based on their lower heat rate in comparison to other combustion tu rbine models. From a GHG perspective, these factors may make IC engines the preferred generation alternative in some situations. Furthermore, the other energy efficiency measur es proposed by La Paloma make the suite of Energy Efficiency options the preferred option for BACT.13 Step 5 – Selection of BACT

To date, other similar facilities with a GHG BACT limit are summarized in the table below:

Company /

Location Process Description Control Device BACT Emission Limit / Requirements Year Issued Reference

Lower Colorado River Authority (LCRA), Thomas C. Ferguson Plant

Horseshoe Bay, TX 590 MW combined cycle combustion turbine and heat recovery
steam generator Energy Efficiency/ Good Design & Combustion Practices Combustion turbine annual net heat rate limited to 7,720 Btu/kWh (HHV)

GHG BACT limit of 0.459 tons CO 2 /MWh (net) without duct burning.

365-day average, rolling daily for the combustion turbine unit 2011 PSD-TX-1244- GHG

Palmdale Hybrid Power Plant Project

Palmdale, CA 570 MW combined cycle combustion turbine and heat recovery
steam generator and50 MW SolarThermal Plant Energy Efficiency/ Good Design & Combustion Practices Combustion turbine annual net heat rate limited to 7,319 Btu/kWh (HHV)

GHG BACT limit of 0.387 tons CO 2 /MWh (net) *

365-day average, rolling daily for the combustion turbine unit 2011 SE 09-01

Calpine Russell City Energy

Hayward, CA 600 MW combined cycle power plant Energy Efficiency/ Good Design & Combustion Practices Combustion Turbine Operational limit of 2,038.6 MMBtu/kWh 2011 15487

PacifiCorp Energy - Lake Side Power Plant

Vineyard, UT 629 MW (without duct burning) combined cycle turbine Energy Efficiency/ Good Design & Combustion Practices Combustion turbine BACT limit of 950 lb CO 2 e/MWh (gross) on a 12-month rolling average basis 2011 DAQEAN0130310010- 11

KennecottUtah CopperRepowering

South Jordan, UT 275 MW combined combustion Energy Efficiency/ Good Design & Combustion Practices Combustion turbine BACT limit of 1,162,552 tpy CO 2 e rolling 12-month period 2011 DAQEIN105720026-1114 Company /

Location Process Description Control Device BACT Emission Limit / Requirements Year Issued Reference

Pioneer Valley Energy Center

Westfield, MA 431 MW combined cycle turbine generator Energy Efficiency/ Good Design & Combustion Practices 825 lbs CO 2 e/MWh grid (initial performance test)

895 lb CO 2 e/MWh grid on a 365-day rolling
average 2012 052-042-MA15

Calpine Deer Park Energy Center

Deer Park, TX 168 MW/180 MW combustion turbine generator with heat recovery
steam generator Energy Efficiency/ Good Design & Combustion Practices 0.460 tons CO 2 /MWh on a 30 day rolling average without duct burning. 2012 PSD-TX-979- GHG

Calpine Channel Energy Center

Pasadena, TX 168 MW/180 MW combustion turbine generator with heat recovery
steam generator Energy Efficiency/ Good Design & Combustion Practices 0.460 tons CO 2 /MWh on a 30 day rolling average without duct burning. 2012 PSD-TX-955- GHG

*The Palmdale facility BACT limit is reduced due to the offset of emissions from the use of a 50 MW Solar-Thermal Plant that was part of the permitted project.

The following specific BACT practices are proposed for the turbines:

 Use of Combined Cycle Power Generation Technology

 Combustion Turbine Energy Efficiency Processes, Practices, and Design

o Highly Efficient Turbine Design

o Turbine Inlet Air Cooling

o Periodic Turbine Burner Tuning

o Reduction in Heat Loss

o Instrumentation and Controls

 HRSG Energy Efficiency Pro cesses, Practices, and Design

o Efficient Heat Exchanger Design

o Insulation of HRSG

o Minimizing Fouling of H eat Exchange Surfaces

o Minimizing Vented Steam and Repair of Steam Leaks

 Steam Turbine Energy Efficiency Processes, Practices, and Design

o Use of Reheat Cycles

o Use of Exhaust Steam Condenser

o Efficient Blading Design

o Efficient Generator Design15  Plant-wide Energy Efficiency Pr ocesses, Practices, and Design

o Fuel Gas Preheating

o Drain Operation

o Multiple Combustion Turbine/HRSG Trains

o Boiler Feed Pump Fluid Drive Design

BACT Limits and Compliance:

To determine the appropriate heat-input efficiency limit, LPEC started with the turbine’s design base load net heat rate for combined cycle operation and then calcula ted a compliance margin based upon reasonable degradation factors that may foreseeably reduce efficiency under realworld conditions. The design base load net he at rates for the combustion turbines being considered for this project are as follows:

 General Electric 7FA

o 6674 Btu/kWhr (HHV) wit hout duct burner firing

o 7051 Btu/kWhr (HHV) with duct burner firing

 Siemens SGT6-5000F(4)

o 6782 Btu/kWhr (HHV) wit hout duct burner firing

o 7045 Btu/kWhr (HHV) with duct burner firing

 Siemens SGT6-5000F(5)

o 6891 Btu/kWhr (HHV) wit hout duct burner firing

o 7204 Btu/kWhr (HHV) with duct burner firing

These rates reflect the facility’s “net” power production, meani ng the amount of power provided to the grid; it does not reflect the total amount of energy prod uced by the plant, which also includes auxiliary load c onsumed by operation of the plant. To be consistent with other recent GHG BACT determinations, the net h eat rate without duct burner fi ring is used to calculate the heat-input efficiency limit.

To determine an appropriate heat rate limit for the permit, the following compliance margins are added to the base heat rate limit:

 A 3.3% design margin reflecting the possibility that the cons tructed facility will not be able to achieve the design heat rate.

 A 6% performance margin re flecting efficiency losses due to equipment degradation prior to maintenance overhauls.

 A 3% degradation margin reflecting the variability in operation of auxiliary plant equipment due to use over time.

Design and construction of a combined-cycle power plant involves many assumptions about anticipated performance of the ma ny elements of the plant, wh ich are often imprecise or not16 reflective of conditions once installe d at the site. As a consequence, the facility also calculates an “Installed Base Heat Rate,” which represents a design margin of 3.3% to address such items as equipment underperformance and short-term degradation.

To establish an enforceable BACT condition that can be achieved ove r the life of the facility, the permit limit must also account for anticipated degradation of the equipment over time between regular maintenance cycles. The manufacturer ’s degradation curves project anticipated degradation rates of 5% within the first 48,000 hours of the gas turb ine’s useful life; they do not reflect any potential increase in this rate which might be expected after the first major overhaul and/or as the equipment approaches the end of its useful life. Furt her, the projected 5% degradation rate represents the average, and not the maximum or guaranteed, rate of degradation for the gas turbines. Therefore, LPEC proposes that, for purposes of deriving an enforceable BACT limitation on the proposed facility’s heat rate, gas turbine degradation may reasonably be estimated at 6% of the facility’s heat rate. This degradation ra te is comparable to the rates estimated by other natural gas fired power pl ants that have received a GHG PSD permit.

Finally, in addition to the heat rate degradation from normal wear and tear on the combustion turbines, LPEC is also providi ng a reasonable compliance margin based on potential degradation in other elements of the combined cycle plant that would cause the overall pl ant heat rate to rise (i.e., cause efficiency to fall) . Degradation in the performan ce of the heat recovery steam generator, steam turbine, heat transfer, cooli ng tower, and ancillary equipment such as pumps and motors is also expected to occur over the course of a major maintenance cycle.

The following BACT limits are proposed:

Turbine Model Gross Heat Rate, with duct burner firing (Btu/kWh) (HHV) Output Based Emission Limit (lb CO 2 /MWh) gross with duct burning
General Electric 7FA 7,861.8 934.5 Siemens SGT6-5000F(4) 7,649.0 909.2 Siemens SGT6-5000F(5) 7,679.0 912.7

The calculation of the gross heat rate and the equivalent lb CO 2 /MWh is provided in Tables 5-1, 5-2, and 5-3 of the application. There is a 2.6% variation from the lowest proposed BACT limit to the highest proposed BACT limit. The BACT limit will not apply during startup conditions, shutdown, or during periods of maintenance (MSS will account for no more than 500 hours of operation a year). The turbines will comply with the BACT limit during all operational conditions, with and without duct burner firing. While energy effi ciency will be a consideration for final selection of a turbine, other consideratio ns will include the capacity of the turbine, cost, reliability, and predicted longevity of the turbines. Since the plant heat rate varies according to turbine operating load and amount of duct bur ner firing, LPEC proposes to demonstrate17 compliance with the proposed heat rate with an annual compliance test, at 100% load, corrected to ISO conditions.

LPEC requested the BACT limit to be expressed in lbs CO 2 /MWh. When converting the BACT limits to tons CO 2 /MWh gives a range of 0.455 tons CO 2 /MWh to 0.467 tons CO 2 /MWh with duct burning. When compared to other BACT limits established for other combined cycle/heat recovery steam generating units, the proposed limits for LPEC are comparable to the limits established for LCRA, Calpine Deer Park, Ca lpine Channel Energy Center, Pioneer Valley Energy Center, and PacifiCorp Energy Lake Si de Power Plant. The differences in BACT between La Paloma and LCRA a nd Cricket Valley Energy Center (CVEC) are related to the net heat rate for the turbines. The net heat rate of the turbines proposed by LPEC are higher than those at LCRA and CVEC. The BACT limit proposed for LPEC is higher than the limit proposed for Pioneer Valley Energy Center (PVEC). PVEC is more likely to operate at base load conditions, whereas LPEC will operate as a load cycling unit. The BACT for LPEC (without duct burner firing is 0.437 to 0.443 tons CO 2 e/MWh) is less than that established for both Calpine facilities (0.46 tons CO 2 e/MWh).

On March 27, 2012, the EPA proposed New Source Performance Standard (NSPS), 40 CFR Part 60 Subpart TTTT, that would control CO 2 emissions from new electric generating units (EGUs). 5 The proposed rule would apply to fossil-fuel fired EGUs that genera te electricity for sale and are larger than 25 MW. The EPA proposed that ne w EGUs meet an annual average output based standard of 1,000 lb CO 2 /MWh, on a gross basis. The propos ed emission rate for the LPEC turbines on a gross electrical output basis ranges from 909.2 to 934.5 lb/MWh with maximum duct burner firing. The proposed CO 2 emission rates from the LPEC combined cycle turbines are well within the emission limit proposed in the NSPS at 40 CFR §60 Subpart TTTT.

LPEC shall meet the BACT limit, for the chosen combustion turbine, on a 12-month rolling

average.

For all combustion turbines considered, the co mbined cycle combustion turbine unit will be designed with a number of features to improve the overall efficiency. The additional combustion turbine design features include:

 Inlet evaporative cooling to utilize water to cool the inlet air and thereby increasing the turbine’s efficiency;

 Periodic burner tuning as part of a regularly scheduled maintenance program to help ensure a more reliable operation of th e unit and maintain optimal efficiency;

5 Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, 77 Fed Reg 22392, April 13, 2012. Available at http://www.epa.gov/ttn/atw/n sps/electric/fr13ap12.pdf18  A Distributed Control System (DCS) will control all aspects of the turbine’s operation, including fuel feed and burne r operations, to achieve optimal highefficiency low-emission performance for full-load and partial-load conditions;

 Insulation blankets are utilized to mini mize the heat loss through the combustion turbine shell and help improve the overall efficiency of the machine; and

 Totally enclosed water to air cooling or hydrogen cooling will be used to cool the generators resulting in a lower elect rical loss and higher unit efficiency.

The Heat Recovery Steam Generator (HRSG) ener gy efficiency processes, practices and designs considered include:

 Energy efficient heat exchanger desig n. In this design, each pressure level incorporates an economizer section(s), eva porator section, and s uperheater section(s);

 Addition of insulation to th e HRSG panels, high-temperature steam and water lines and to the bottom portion of the stack;

 Filtration of the inlet air to the combustion turbine and periodic cleaning of the tubes (performed at least every 18 months) is performed to minimize fouling; and

 Minimization of steam vents and repairs of steam leaks.

Within the combined-cycle power plant, several plant-wide, overall energy efficiency processes, practices and designs are included as BACT requirements because the additional operating conditions/practices help mainta in the efficiency of the turb ine. The requirements include:

 Fuel gas preheating. For the F-class com bustion turbine based combined-cycle, the fuel gas is pre-heated to te mperature of approximately 300 o F with high temperature water from the HRSG;

 Drain operation. Operation drains are contro lled to minimize the loss of energy from the cycle but closing the drains as soon as the appropriate steam conditions are achieved;

 Multiple combustion turbine/HRSG trains. Mu ltiple combustion turbine/HRSG trains help with part-load operation. A higher overall plant part-load effi ciency is achieved by shutting down trains operating at less e fficient part-load conditions and ramping up the remaining train(s) to high-e fficiency full-load operation; and

 Boiler feed pump fluid drives. To minimize the power consumption at part-loads, the use of fluid drives or variable-frequenc y drives are used to minimize the power consumption at part-load conditions

La Paloma will demonstrate compliance with the CO 2 limit established as BACT by using fuel flow meters to monitor the quantity of fuel combusted in the electr ic generating unit and performing periodic scheduled fuel sampling pur suant to 40 CFR 75.10(3)(ii) and the procedures listed in 40 CFR 75, Appendix G. Results of the fu el sampling will be used to calculate a sitespecific Fc factor, and that factor will be used in the equation below to calculated CO 2 mass19 emissions. The proposed permit also includes an alternative compliance de monstration method in which LPEC may install, calibrate, and operate a CO 2 CEMS and volumetric stack gas flow monitoring system with an automated data acq uisition and handling system for measuring and recording CO 2 emissions. To demonstrate compliance with the CO 2 BACT limit using CO 2 CEMS, the measured hourly CO 2 emissions are divided by th e net hourly energy output and averaged daily. La Paloma proposes to determine a site-specific Fc factor using the ultimat e analysis and GCV in equation F-7b of 40 CFR 75, Appendix F. The site -specific Fc factor wi ll be re-determined annually in accordance with 40 CFR 75, Appendix F, §3.3.6.

The equation for estimating CO 2 emissions as specified in 40 CFR 75.10(3)(ii) is as follows:

ܹ

஼ை మ ൌ ሺܨܿ 	ൈ ܪ 	ൈ ܷ݂	 ൈ ܯܹ ஼ை మ ሻ/2000

Where:
W CO2 = CO 2 emitted from combustion, tons/hour
MW CO2 = molecular weight of CO 2 , 44.0 lbs/mole Fc = Carbon-based Fc-Factor, 1040 scf/MMBtu for natural gas or site-specific Fc factor H = hourly heat input in MMB tu, as calculated using th e procedure in 40 CFR 75, Appendix F, §5 Uf = 1/385 scf CO 2 /lb-mole at 14.7 psia and 68°F

La Paloma is subject to all applicable requi rements for fuel flow monitoring and quality assurance pursuant to 40 CFR 75, Appendix D, which include:

 Fuel flow meter- meets an accuracy of 2.0% , required to be tested once each calendar quarter pursuant to 40 CFR 75, Appendix D, §2.1.5 and §2.1.6(a))

 Gross Calorific Value (GCV)- determine the GCV of pipeline natural gas at least once per calendar month pursuan t to 40 CFR 75, Appendix D, §2.3.4.1

Additionally, this approach is consistent with the CO 2 reporting requirements of 40 CFR 98, Subpart D- GHG Mandatory Reporti ng Rule for Electricity Genera tion. Furthermore, La Paloma proposed CO 2 monitoring method is consistent w ith the recently proposed New Source Performance Standards, Subpart TTTT- St andards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units (40 CFR 60.5535(c )) which allows for electric generating units firing gaseous fuel to determine CO 2 mass emissions by monitoring fuel combusted in the affected electric generating unit and using a site specific Fc factor determined in accordance to 40 CFR 75, Appendix F.20 If La Paloma chooses to install and operate the CO 2 CEMS equipped with a volumetric stack gas monitoring system, the applicant sh all rely on the data from the CO 2 CEMS for compliance

purposes.

The emission limits associated with CH 4 and N 2 O are calculated based on emission factors provided in 40 CFR Part 98, Tabl e C-2 and the actual heat in put (HHV). Comparatively, the emissions from CO 2 contribute the most (greater than 99%) to the overall emissions from the combined cycle combustion turbines and; therefor e, additional analysis is not required for CH 4 and N 2 O. To calculate the CO 2 e emissions, the draft permit require s calculation of the emissions based on the procedures and Gl obal Warming Potentials (GWP) contained in the Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Tabl e A-1. Records of the calculations would be required to be kept to demonstrate compliance with the emission limits on a 12-month, rolling

average.

An initial stack test demonstration will be required for CO 2 emissions from U1-STK and U2- STK. La Paloma also proposes to demonstrate co mpliance with the proposed heat rate with an annual compliance test, at 100% load, corrected to ISO conditi ons. An initial stack test demonstration for CH 4 and N 2 O emissions are not required because the CH 4 and N 2 O emission are approximately 0.01% of the total CO 2 e emissions from the combustion turbines.

X. Auxiliary Boiler (AUXBLR)

One nominally rated 150 MMBtu/hr auxiliary boiler (EPN AUXBLR) w ill be utilized to facilitate startup of the combined cycle units. The auxiliary boiler will be limited to 876 hours of operation per year.

Step 1 – Identification of Potentia l Control Technologies for GHGs

 Use of Low Carbon Fuels – Fuels vary in the amount of carb on per Btu, which in turn affects the quantity of CO 2 emissions generated per unit of heat input. Selecting low carbon fuels is a viable method of reducing GHG emissions. Natura l gas is the lowest carbon fuel available at LPEC.

 Use of Good Operating and Maintenance Practices – Following the manufacturer’s recommended operating and maintenance proce dures; maintaining good fuel mixing in the combustion zone; and maintain the proper air/fuel ratio so that sufficient oxygen is provided to provide complete combustion of fuel while at the same time preventing introduction of more air than is necessary into the boiler.

 Energy Efficient Design – The auxiliary boiler is designe d for a thermal efficiency of approximately 80%. The energy efficient design in cludes insulation to retain heat within the21 boiler and a computerized proce ss control system that will optimize the fuel/air mixture and limit excess air in the boiler.

 Low Annual Capacity – The auxiliary boiler will be used to facilitate the startup of the two combustion turbines and the annual hours of operation will be limited to 876 hours per year.

Step 2 – Elimination of Technically Infeasible Alternatives

All options identified in Step 1 are technically feasible.

Step 3 – Ranking of Remaining Technologies Based on Effectiveness

All of the energy efficiency related processes, practices, and designs di scussed in Step 1 are being proposed. Therefore, a ranking of th e control technologies is not necessary.

Step 4 – Evaluation of Control Technol ogies in Order of Most Effec tive to Least Effective, with Consideration of Economic, En ergy, and Environmental Impacts

As all of the energy efficiency related processes, practices, and designs di scussed in Step 1 are being proposed for this project, an examination of the energy, environmental, and economic impacts of the efficiency designs is not necessary.

Step 5 – Selection of BACT

La Paloma proposes to use natural gas as a low carbon fuel; good operation and maintenance practices; energy efficient design, and low annual capacity as BACT for the auxiliary boiler. The following specific BACT practices are proposed for the heaters:

 Use of low carbon fuel (natural gas). Natural gas will be the only fuel fired in the proposed auxiliary boiler. It is the lowest carbon fuel available for use at LPEC.

 Good operation and maintenance practices wi ll include following the manufacturer’s recommended operating and maintenance pro cedures; maintaining good fuel mixing, and limiting the amount of excess air in the combus tion chamber to maximize thermal efficiency.

 Energy efficient design will incorporate insula tion to retain heat within the boiler.

 The auxiliary boiler will be limite d to 876 hours of operation a year.

Use of these practices corresponds with a permit limit of 7,687 tpy CO 2 e for the auxiliary boiler. Compliance will be determined by the number of hours of operation and the calculated emissions using Equation C-1 from 40 CFR Part 98 Subpart C which is based on metered fuel usage and the emission factor for natural gas.22 XI. Emergency Engines (EMGEN1-STK and FWP1-STK)

The LPEC site will be equipped with one nom inally rated 1,072-hp di esel-fired emergency generator to provide electricity to the facility in the case of power failure and one nominally rated 500-hp diesel-fired pump to pr ovide water in the event of a fire.

Step 1 – Identification of Pote ntial Control Technologies

 Low Carbon Fuels – Engine options includes engines pow ered by electricity, natural gas, or liquid fuel, such as gaso line or fuel oil.

 Good Combustion Practices and Maintenance – Good combustion practices include appropriate maintenance of equipment, such as periodic readiness testing, and operating within the recommended air to fuel ratio recommended by the manufacturer.

 Low Annual Capacity Factor – Limiting the hours of operation reduces the emissions produced. Each emergency engine will be lim ited to 100 hours of operation per year for purposes of maintenance check s and readiness testing.

Step 2 – Elimination of Technically Infeasible Alternatives

 Low Carbon Fuels – The purpose of the engines is to provide a power source during emergencies, which includes outages of the co mbustion turbines, natural gas supply outages, and natural disasters. Electricity and natural gas may not be available during an emergency and therefore cannot be used as an energy source for the emergency engines and are eliminated as technically infeasible for this facility. The engines must be powered by a liquid fuel that can be stored on-site in a tank and supplied to the engines on demand, such as gasoline or diesel. Gasoline fuel has a much higher volatility than diesel, and is thus less safe for use in an emergency situation, and it canno t be stored for long periods of time, which may be necessary for emergency use. Therefore, gasoline is eliminated as infeasible for these emergency engines.

 Good Combustion Practices and Maintenance – Is considered technically feasible

 Low Annual Capacity Factor – Is considered technically feas ible since the engines will only be operated either for readiness te sting or for actual emergencies.

Step 3 – Ranking of Remaining Technologies Based on Effectiveness

Since the remaining technically feasible processe s, practices, and designs in Step 1 are being proposed for the engines, a ranking of th e control technologies is not necessary.23 Step 4 – Evaluation of Control Technol ogies in Order of Most Effec tive to Least Effective, with Consideration of Economic, En ergy, and Environmental Impacts

Since the remaining technically feasible processe s, practices, and designs in Step 1 are being proposed for the engines, an evaluation of the most effective controls is not necessary.

Step 5 – Selection of BACT

The following specific BACT practices are proposed for the diesel-fired emergency generators:

 Good Combustion Practices and Maintenance – Good combustion practices for compression ignition engines include appropr iate maintenance of equipmen t, periodic testing conducted weekly, and operating within the recommended ai r to fuel ratio, as specified by its design.

 Low Annual Capacity Factor – The emergency engines will not be operated more than 100 hours per year each. They will only be operated fo r maintenance and readiness testing, and in actual emergency operation.

Using the BACT practices identified above results in a BACT limit of 65 tpy CO 2 e for the Emergency Generator (EMGEN1-STK) and 28 tpy CO 2 e for the Fire Water Pump (FWP1-STK). La Paloma will demonstrate compliance with the CO 2 emission limit using the default emission factor and default high heating value for diesel fuel from 40 CFR Part 98 Subpart C, Table C-1. The equation for estimating CO 2 emissions as specified in 40 CF R 98.33(a)(3)(iii) is as follows:

ܱܥ ଶ 10 ൈ 1 	ൌ ଷି 1.102311 ∗ ܨܧ ∗ ܸܪܪ ∗ ݈݁ݑܨ ∗

Where: CO 2 = Annual CO 2 mass emissions from combusti on of diesel fuel (short tons) Fuel = Mass or volume of fuel combusted per year, from company records. HHV = Defaullt high heat value of the fuel, fr om Table C-1 of 40 CFR Part 98 Subpart C. EF = Fuel specific default CO 2 emission factor, from Table C-1 of 40 CFR Part 98 Subpart C.
1 ൈ 10 ିଷ = Conversion of kg to metric tons. 1.102311 = Conversion of metric tons to short tons.

The emission limits associated with CH 4 and N 2 O are calculated based on emission factors provided in 40 CFR Part 98, Table C- 2, site specific analysis of pr ocess fuel gas, and the actual heat input (HHV).24 XII. Natural Gas Fugitive Emissions (NG-FUG)

The proposed project will include natural gas piping components. These components are potential sources of methane and CO 2 emissions due to emissions from rotary shaft seals, connection interfaces, valve stems, and similar points. The additional methane and CO 2 emissions from process fugitives have been conservatively estimated to be 423 tpy as CO 2 e. Fugitive emissions are negligible, and account fo r less than 0.01% of the project’s total CO 2 e emissions.

Step 1 – Identification of Potentia l Control Technologies for GHGs

 Implementing a leak detec tion and repair (LDAR) program using a handheld analyzer;

 Implement alterna tive monitoring using a remote sens ing technology such as infrared camera monitoring; and

 Implementing an auditory/visual/olfa ctory (AVO) monitoring program.

Step 2 – Elimination of Technically Infeasible Alternatives

LDAR programs are a technically feasible option for controlli ng process fugitive GHG emissions.

Step 3 – Ranking of Remaining Technologies Based on Effectiveness

Instrument LDAR programs and remote sensing us ing an infrared camera have been determined by EPA to be equivalent methods of piping fugitive controls. 6 The most stringent LDAR program potentially applicable to this facili ty is TCEQ’s 28LAER, which provides for 97% control credit for valves, flanges, and connectors.

As-observed audio, visual, and olfactory (AVO) observation met hods are generally somewhat less effective than instrument LDAR and remote sensing, since they are not conducted at specific intervals. However, since pipeline natural gas is odorized with very small quantities of mercaptan, as-observed olfactory observation is a very effective method for identifying and correcting leaks in natura l gas systems. Due to the pressure and other physical properties of plant fuel gas, as-observed audio and visual observa tions of potential fugitive leaks are likewise moderately effective.

6 73 FR 78199-78219, December 22, 2008.25 Step 4 – Evaluation of Control Technol ogies in Order of Most Effec tive to Least Effective, with Consideration of Economic, En ergy, and Environmental Impacts

Although instrument LDAR and/or remote sensi ng of piping fugitive emissions in natural gas service may be somewhat more effective th an as-observed AVO methods, the incremental GHG emissions controlled by implementation of the TCEQ 28LAER LDAR program or a comparable remote sensing program is less than 0.05% of the total project’s proposed CO 2 e emissions. Accordingly, given the costs of implementing 28L AER or a comparable remote sensing program when not otherwise required, these methods ar e not economically practicable for GHG control from components in natural gas service.

Step 5 – Selection of BACT

Based on the economic impracticabil ity of instrument monitoring a nd remote sensing for natural gas piping components, La Paloma proposes to incorporate as-observed AVO as BACT for the piping components in the new combined cycle powe r plant in natural gas service. The proposed permit contains a condition to implement AVO inspections on a daily basis.

XIII. SF 6 Insulated Electrical Equipment (SF6-FUG)

The generator circuit breakers associated with the proposed units will be insulated with SF 6 . The capacity of the circuit breakers associated with the proposed plant is currently estimated to be 400 lb of SF 6 .

Step 1 – Identification of Potentia l Control Technologies for GHGs

In comparison to older SF 6 circuit breakers, modern circuit breakers are designed as a totally enclosed-pressure system with far lower potential for SF 6 emissions. In addition, the effectiveness of leak-tight closed systems can be enhanced by equipping them with a density alarm that provides a warning when 10% of the SF 6 (by weight) has escaped. The use of an alarm identifies potential leak problems before the bulk of the SF 6 has escaped, so that it can be addressed proactively in order to pr event further release of the gas.

One alternative considered in this analysis is to substitute another non-GHG substance for SF 6 as the dielectric material in the breakers. Potential alternatives to SF 6 were addressed in the National Institute of Standards and Technology (NIST) Technical note 1425, Gases for26 Electrical Insulation and Arc Inte rruption: Possible Present and Fu ture Alternatives to Pure
SF 6
. 7

Step 2 – Elimination of Technically Infeasible Alternatives

According to the report NIST Technical Note 1425, SF 6 is a superior dielectric gas for nearly all high voltage applications. It is easy to use, exhibits exceptiona l insulation and arc-interruption properties, and has proven its pe rformance by many years of use a nd investigation. It is clearly superior in performance to the air and oil insula ted equipment used prior to the development of SF 6 insulated equipment. The report concluded that although “...various gas mixtures show considerable promise for use in new equipment, particularly if the equipment is designed specifically for use with a gas mi xture...it is clear that a significan t amount of research must be performed for any new gas or gas mixture to be used in electrical equipment”. Therefore, there are currently no technically feasib le options besides the use of SF 6 .

Step 3 – Ranking of Remaining Technologies Based on Effectiveness

The use of state-of-the-art SF 6 technology with leak detection to limit fugitive emissions is the highest ranked control te chnology that is feasible for this application.

Step 4 – Evaluation of Control Technol ogies in Order of Most Effec tive to Least Effective, with Consideration of Economic, En ergy, and Environmental Impacts

Energy, environmental, or economic impacts are no t addressed because the use of alternative, non-greenhouse gas substance for SF 6 as the dielectric material in the breakers is not technically feasible.

Step 5 – Selection of BACT

La Paloma concludes that using st ate-of-the-art enclosed-pressure SF 6 circuit breaker s with leak detection as the BACT control technology option. The circuit breakers will be designed to meet the latest of the American National Standards Institute (ANSI) C37.013 standard for high voltage circuit breakers. 8 The proposed circuit breaker at the gene rator output will ha ve a low pressure alarm and a low pressure lockout. This alarm will function as an early leak detector that will bring potential fugitive SF 6 emissions problems to light before a substantial portion of the SF 6 escapes. The lockout prevents any operation of the breaker due to the lack of “quenching and cooling” SF 6 gas.

7 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF 6 . NIST Technical Note 1425, Nov. 1997. Available at http://www.epa.gov/electricpower-sf6 /documents/new_report_final.pdf
8 ANSI Standard C37.013, Standard for AC High-Voltage Generator Circuit Breakers on a Symmetrical Current

.27 LPEC will monitor emissions a nnually in accordance with the re quirements of the Mandatory Greenhouse Gas Reporting rules for Electrical Tr ansmissions and Distribution Equipment Use. 9
Annual SF 6 emissions will be calculated according to the mass balance approach in Equation DD-1 of Subpart DD.

XIV. Gaseous Venting (TRB-MSS)

LPEC will have small amounts of GHGs emitted from gaseous fuel venting during turbine shutdown and maintenance from the fuel lines being cleared of fuel. They will also have small amounts of GHGs emitted from the repair and replacement of small equipment and fugitive components. The GHG emissions from these activ ities account for less th an 0.0001% of the total project GHG emissions. Due to the infrequent natu re of these activities and small quantity of GHG emissions, a BACT analysis is not warranted.

XV. Endangered Species Act

Pursuant to Section 7(a)(2) of the Endangere d Species Act (ESA) (16 U.S.C. 1536) and its implementing regulations at 50 CFR Part 402, EP A is required to insure that any action authorized, funded, or carried out by EPA is not likely to jeopardi ze the continued existence of any federally-listed endangered or threatened sp ecies or result in the destruction or adverse modification of such species’ de signated critical habitat.

To meet the requirements of Section 7, EPA is relying on a Biological Assessment (BA) prepared by the applicant and adopted by EPA. Further, EPA designated La Paloma Energy Center, LLC (“La Paloma”) and its consultant , Zephyr Environmental Corporation (“Zephyr”), as non-federal representatives for pur poses of preparation of the BA.

A draft BA has identified eighteen (18) species listed as fede rally endangered or threatened in Cameron County, Texas:

Federally Listed Species for Cameron County by the U.S. Fish and Wildlife Service (USFWS), National Marine Fisheries Service (NMFS) and the Texas Parks and Wildlife Department (TPWD) Scientific Name

Birds Piping Plover Charadrius melodus Eskimo Curlew Numenius borealis Northern Aplomado Falcon Falco femoralis septentrionalis Interior Least Tern Sterna antillarum athalassos

9 See 40 CFR Part 98 Subpart DD.28 Federally Listed Species for Cameron County by the U.S. Fish and Wildlife Service (USFWS), National Marine Fisheries Service (NMFS) and the Texas Parks and Wildlife Department (TPWD) Scientific Name

Fish
Smalltooth Sawfish Pristis pectinata Rio Grande Silvery Minnow Hybognathus amarus
Mammals Gulf Coast Jaguarundi Herpailurus yaguarondi Ocelot Leopardus pardalis Jaguar Panthera onca West Indian Manatee Trichechus manatus
Plant
South Texas ambrosia Ambrosia cheiranthifolia Star cactus Astrophytum asterias Texas ayenia Ayenia limitaris Reptiles
Green Sea Turtle Chelonia mydas Kemp’s Ridley Sea Turtle Lepidochelys kempii Leatherback Sea Turtle Dermochelys coriacea Loggerhead Sea Turtle Caretta caretta Atlantic Hawksbill Sea Turtle Eretmochelys imbricata

Based on the information provided in the BA, EP A determines that issuance of the proposed PSD permit allowing La Paloma to construct two natural gas-fired combustion turbines will have no effect on 15 species because there are no records of occurrence, no designa ted critical habitat, nor potential suitable habitat for a ny of these species within the act ion area. Those fifteen species include: piping plover, Eskimo curlew, interior l east tern, smalltooth sawfish, Rio Grande silvery minnow, jaguar, West Indian manatee, South Te xas ambrosia, star cactus, Texas ayenia, green sea turtle, Kemp’s ridley sea turtle, leatherback sea turtle, loggerhead s ea turtle, and Atlantic hawksbill sea turtle.

However, based on the information provided in th e BA and by the USFWS, EPA determines that the issuance of the permit may affect, but is not likely to adversely affect, the Northern Aplomado falcon, Gulf Coast jaguarundi and th e ocelot. EPA and La Paloma (as EPA’s designated non-federal represen tative) engaged in informal consultation with the USFWS’s Southwest Region, Corpus Christi, Texas Ecological Services Field Office and the sub-office in Alamo, Texas. During consultation, USFWS indicated that they have recently released Northern Aplomado falcons in Cameron Count y, outside of the action area, and that there is potential that the falcon could forage within the action area or perch on transmission lines being constructed29 for this project. The USFWS also indicated that an irrigation canal located adjacent to the facility as well as other vegetated areas within the acti on area may provide travel or migration corridors for the ocelot or jaguarundi. USFWS provided re commendations for additional protections of all of these species, which La Paloma has committed to implement. By letter dated March 7, 2013, EPA requested USFWS’s written concurrence with EPA’s “may effect” determination.

Any interested party is welcome to bring particular concerns or information to our attention regarding this project’s potential effect on listed species. The final draft biological assessment can be found at EPA’s Region 6 Air Permits website at http://yosemite.epa.gov/r6/Apermit.nsf/AirP

.

XVI. National Historic Preservation Act (NHPA)

Section 106 of the NHPA requires EPA to consider the effects of this permit action on properties on or eligible for inclusion in the National Register of Historic Places. To make this determination, EPA relied on and adopted a cult ural resource report prepared by Horizon Environmental Services, Inc. (“Horizon”) on behalf of Zephyr submitted on December 19, 2012.

For purposes of the NHPA review, the Area of Po tential Effect (APE) was determined to be approximately 78 acres of land within and adjacent to the construction f ootprint of the existing facility. Horizon conducted a field survey of the property and a desktop review on the archaeological background and histor ical records within a 1-mile radius area of potential effect (APE) which included a review of the Te xas Historical Commission’s online Texas Archaeological Site Atlas (TASA) and the National Park Service’s National Register of Historic Places (NRHP). Based on the results of the field survey, no archaeological resources or historic structures were found within the APE. Based on the desktop review, one archaeological site was located 0.7 miles from the APE but was not reco mmended to be eligible to be listed on the National Register.

EPA Region 6 determines that because no historic properties are located within the APE and that a potential for the location of ar chaeological resources within the construction footprint itself is low, issuance of the permit to La Paloma will not affect properties potentially eligible for listing on the National Register.

On January 10, 2013, EPA sent letters to Indian tribes identified by the Texas Historical Commission as having histori cal interests in Texas to inquire if any of the tribes have historical interest in the particular location of the project and to inquire whether any of the tribes wished to consult with EPA in the Section 106 process. EPA received no requests from any tribe to consult on this proposed permit. EPA will provide a copy of the report to the State Historic Preservation Officer for consultation and concu rrence with its determination. A ny interested party is welcome30 to bring particular concerns or information to our attention regarding th is project’s potential effect on historic properties. A c opy of the report may be found at http://yosemite.epa.gov/r6/Apermit.nsf/AirP

.

XVII. Environmental Justice (EJ)

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive branch policy on environmental justice. Based on this Executive Order, the EPA’s Environmental Appeals Board (EAB) has held that environmen tal justice issues must be considered in connection with the issuance of federal Preventi on of Significant Deterioration (PSD) permits issued by EPA Regional Offices [See, e.g., In re Prairie State Generating Company , 13 E.A.D. 1, 123 (EAB 2006); In re Knauf Fiber Glass , Gmbh, 8 E.A.D. 121, 174-75 (EAB 1999)]. This permitting action, if finalized, authorizes emissi ons of GHG, controlled by what we have determined is the Best Available Control Te chnology for those emissions. It does not select environmental controls for any other pollutants. Unlike the criteria pollutants for which EPA has historically issued PSD permits, there is no National Ambient Air Qual ity Standard (NAAQS) for GHGs. The global climate-change inducing e ffects of GHG emissions, according to the “Endangerment and Cause or Contribute Finding”, are far-reaching and multi-dimensional (75 FR 66497). Climate change modeling and evalua tions of risks and impacts are typically conducted for changes in emissions that are orders of magnitude larger th an the emissions from individual projects that might be analyzed in PSD permit re views. Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in speci fic places and points would not be possible [PSD and Title V Permitting Guidance for GHGs at 48]. Thus, we conclude it would not be meaningful to evaluate impacts of GHG emissions on a local commun ity in the context of a single permit. Accordingly, we have determined an environmental justice analysis is not necessary for the permitting record.

XVIII. Conclusion and Proposed Action

Based on the information supplied by La Paloma, our review of the analyses contained the TCEQ PSD Permit Application and the GHG PS D Permit Application, and our independent evaluation of the information contained in our Admi nistrative Record, it is our determination that the proposed facility would employ BACT for GHGs under the terms contained in the draft permit. Therefore, EPA is proposing to issue La Paloma a PSD permit for GHGs for the facility, subject to the PSD permit conditi ons specified therein. This perm it is subject to review and comments. A final decision on issuance of the permit will be made by EPA after considering comments received during the public comment period.31 APPENDIX
Annual Facility Emission Limits
Three models being considered by LPEC: th e General Electric 7FA, the Siemens SGT6- 5000F(4), and the Siemens SGT6-5000F(5). The fina l selection of the co mbustion turbine model to be used at the plant will likely be made af ter the permit is issued. Accordingly, this action proposes to issue a final permit that will include BACT limits and related conditions specific to each of the possible turbine models, and EPA will require the applicant to amend the permit after it has made a final turbine selection to remove the turbine options not selected.

Annual emissions, in tons per year (TPY) on a 12-month, rolling average, shall not exceed the following if the General Electric 7FA is selected as the combustion turbine model:

Table 1A. Annual Emission Limits 1 - General Electric 7FA

FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

U1-STK U1-STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,261,820

1,263,055 934.5 lb CO 2 /MWh (gross) with duct burning 5 . See Special Conditi ons III.A.1. CH 4 23.4

N 2 O 2.4

U2-STK U2-STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,261,820

1,263,055 934.5 lb CO 2 /MWh (gross) with duct burning 5 . See Special Conditi ons III.A.1. CH 4 23.4

N 2 O 2.4

AUXBLR AUXBLR Auxiliary Boiler CO 2 7,680

7,687 Good Combustion and Operating Practices. Limit to 876 hours of operation per year. See Special Conditions III.B. CH 4 0.14

N 2 O 0.01

EMGEN1 -STK EMGEN1 -STK Emergency Generator CO 2 64

64 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 632 FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

FWP1- STK FWP1- STK Fire Water Pump CO 2 28

28 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

TRBMSS TRBMSS Maintenance , Startup, and Shutdown CO 2 No Numerical Limit Established 6 2.2 Negligible emissions, EPA verified the provided analysis.

CH 4 0.106

NG-FUG NG-FUG Natural Gas Fugitives CO 2 Not Applicable Not Applicable Implementation of AVO Monitoring. See Special Condition III.D. CH 4 Not Applicable

SF6-FUG SF6-FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 6 23.9 Instrumented monitoring and alarm. See Special condition III.D.

Totals 7 CO 2 2,531,413 CO 2 e 2,534,338 CH 4 67 N 2 O 4.8 1. Compliance with the annual emission limits (tons per year) is based on a 12 month rolling average. 2. The TPY emission limits specified in this table are no t to be exceeded for this facility and include emissions from the facility during all operations and include MSS activities. 3. Global Warming Potentials (GWP): CH 4 = 21, N 2 O = 310 4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 5. The BACT limit for the combustion turbine does not apply during MSS. 6. All values indicated as “No Numerical Limit Establishe d” are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work practice standard as specified in the permit. 7. The total emissions for CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4 . Total emissions are for information only and do not constitute an emission limit.33 Annual emissions, in tons per year (TPY) on a 12-month, rolling average, shall not exceed the following 

### if the Siemens SGT6-5000F(4) is se lected as the combustion turbine model :

Table 1B. Annual Emission Limits 1 - Siemens SGT6-5000F(4)

FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

U1-STK U1-STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,415,907

1,417,263 909.2 lb CO 2 /MWh (gross) with duct burning 5 . See Special Conditi ons III.A.1. CH 4 26.2

N 2 O 2.6

U2-STK U2-STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,415,907

1,417,263 909. 2 lb CO 2 /MWh (gross) with duct burning 5 . See Special Conditi ons III.A.1. CH 4 26.2

N 2 O 2.6

AUXBLR AUXBLR Auxiliary Boiler CO 2 7,680

7,687 Good Combustion and Operating Practices. Limit to 876 hours of operation per year. See Special Conditions III.B. CH 4 0.14

N 2 O 0.01

EMGEN1 -STK EMGEN1 -STK Emergency Generator CO 2 64

64 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

FWP1- STK FWP1- STK Fire Water Pump CO 2 28

28 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

TRBMSS TRBMSS Maintenance , Startup, and Shutdown CO 2 No Numerical Limit Established 6 2.2 Negligible emissions, EPA verified the provided analysis.

CH 4 0.10634 FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

NG-FUG NG-FUG Natural Gas Fugitives CO 2 Not Applicable Not Applicable Implementation of AVO Monitoring. See Special Condition III.D. CH 4 Not Applicable

SF6-FUG SF6-FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 6 23.9 Instrumented monitoring and alarm. See Special condition III.D.

Totals 7 CO 2 2,839,587 CO 2 e 2,842,754 CH 4 73 N 2 O 5.2 1. Compliance with the annual emission limits (tons per year) is based on a 12 month rolling average. 2. The TPY emission limits specified in this table are no t to be exceeded for this facility and include emissions from the facility during all operations and include MSS activities. 3. Global Warming Potentials (GWP): CH 4 = 21, N 2 O = 310 4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 5. The BACT limit for the combustion turbine does not apply during MSS. 6. All values indicated as “No Numerical Limit Establishe d” are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work practice standard as specified in the permit. 7. The total emissions for CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4 . Total emissions are for information only and do not constitute an emission limit.35 Annual emissions, in tons per year (TPY) on a 12-month, rolling average, shall not exceed the following if the Siemens SGT6-5000F(5) is se lected as the combustion turbine model:

Table 1C. Annual Emission Limits 1 - Siemens SGT6-5000F(5)

FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

U1-STK U1-STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,594,162

1,595,712 912.7 lb CO 2 /MWh (gross) with duct burning 5 . See Special Conditi ons III.A.1. CH 4 29.5

N 2 O 3

U2-STK U2-STK Combined Cycle Combustion Turbine/Heat Recovery Steam Generator 4 CO 2 1,594,162

1,595,712 912.7 lb CO 2 /MWh (gross) with duct burning 5 . See Special Conditi ons III.A.1. CH 4 29.5

N 2 O 3

AUXBLR AUXBLR Auxiliary Boiler CO 2 7,680

7,687 Good Combustion and Operating Practices. Limit to 876 hours of operation per year. See Special Conditions III.B. CH 4 0.14

N 2 O 0.01

EMGEN1 -STK EMGEN1 -STK Emergency Generator CO 2 64

64 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 6

FWP1- STK FWP1- STK Fire Water Pump CO 2 28

28 Good Combustion and Operating Practices. Limit to 100 hours of operation per year. See Special Conditions III.C. CH 4 No Numerical Limit Established 6

N 2 O No Numerical Limit Established 636 FIN EPN Description GHG Mass Basis TPY CO 2 e 2,3 BACT Requirements TPY 2

TRB-MSS TRBMSS Maintenance , Startup, and Shutdown CO 2 No Numerical Limit Established 6 2.2 Negligible emissions, EPA verified the provided analysis.

CH 4 0.106

NG-FUG NG-FUG Natural Gas Fugitives CO 2 Not Applicable Not Applicable Implementation of AVO Monitoring. See Special Condition III.D. CH 4 Not Applicable

SF6-FUG SF6-FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 6 23.9 Instrumented monitoring and alarm. See Special condition III.D.

Totals 7 CO 2 3,196,097 CO 2 e 3,199,650 CH 4 80 N 2 O 6 1. Compliance with the annual emission limits (tons per year) is based on a 12 month rolling average. 2. The TPY emission limits specified in this table are no t to be exceeded for this facility and include emissions from the facility during all operations and include MSS activities. 3. Global Warming Potentials (GWP): CH 4 = 21, N 2 O = 310 4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 5. The BACT limit for the combustion turbine does not apply during MSS. 6. All values indicated as “No Numerical Limit Establishe d” are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work practice standard as specified in the permit. 7. The total emissions for CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4 . Total emissions are for information only and do not constitute an emission limit.