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 Prevention 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. Failure to comply with any 

condition or term set forth in this PSD Permit may result in enforcement action pursuant to 

Section 113 of the Clean Air Act (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 accordance 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 Division
Draft 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 LPEC 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 (SF6).

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 generators

(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 SF6 Insulated Electrical Equipment (i.e., circuit breakers) with 400 lb SF6

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 VI, 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 facility including associated air pollution control 

equipment in a manner consistent with good air pollution control practice for minimizing 

emissions. Determination of whether acceptable operating and maintenance procedures are being 

used will be based on information available to the EPA, which may include, but is not limited to, 

monitoring results, review of operating maintenance procedures and inspection of the facility. 
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 Sections 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 representatives, upon the presentation of credentials, shall be permitted: 

1. to enter the premises where the facility is located or where any records are required to be 

kept under the terms and conditions of this PSD Permit; 

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 Permit and its conditions by letter; a 

copy of the 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

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

CT Combustion Turbine

DLNB Dry Low-NOx 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 Heating 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

N2O Nitrous Oxides

NOx 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

SF6 Sulfur Hexafluoride

TAC Texas Administrative Code

TCEQ Texas Commission on Environmental Quality

TPY Tons per Year

USC United States Code

VOC Volatile Organic Compound
Draft 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 Limits1 - General Electric 7FA 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

U1-STK U1-STK

Combined Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4 

CO2 1,261,820

1,263,055

934.5 lb CO2/MWh (gross) 

with duct burning.

5 See 

Special Conditions III.A.1.

CH4 23.4

N2O 2.4

U2-STK U2-STK

Combined Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4 

CO2 1,261,820

1,263,055

934.5 lb CO2/MWh (gross) 

with duct burning.

5 See 

Special Conditions III.A.1.

CH4 23.4

N2O 2.4

AUXBLR AUXBLR Auxiliary Boiler

CO2 7,680

7,687

Good Combustion and 

Operating Practices. Limit to 

876 hours of operation per 

year. See Special Conditions 

III.B.

CH4 0.14

N2O 0.01

EMGEN1

-STK

EMGEN1

-STK

Emergency 

Generator

CO2 64

64

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No 

Numerical 

Limit 

Established6 

N2O 

No 

Numerical 

Limit 

Established6

FWP1-

STK

FWP1-

STK Fire Water Pump

CO2 28

28

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

TRBMSSTRBMSS

Maintenance , 

Startup, and 

Shutdown

CO2

No 

Numerical 

Limit 

Established6 2.2 Negligible emissions, EPA 

verified the provided analysis.

CH4 0.106

NG-FUG NG-FUG Natural Gas 

Fugitives

CO2

Not 

Applicable Not 

Applicable

Implementation of AVO 

Monitoring. See Special 

CH Condition III.D. 4

Not 

Applicable
Draft for March 20, 2013 public notice. 8 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No 

Numerical 

Limit 

Established6

23.9

Instrumented monitoring and 

alarm. See Special condition 

III.D.

Totals7 CO2 2,531,413 CO2e 

2,534,338 CH4 67

N2O 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): CH4 = 21, N2O = 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 for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

are for information only and do not constitute 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. Annual Emission Limits1 - Siemens SGT6-5000F(4) 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

U1-STK U1-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4 

CO2 1,415,907

1,417,263

909.2 lb CO2/MWh (gross) 

with duct burning.

5 See 

Special Conditions III.A.1.

CH4 26.27 

N2O 2.6

U2-STK U2-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4 

CO2 1,415,907

1,417,263

909.2 lb CO2/MWh (gross) 

with duct burning.

5 See 

Special Conditions III.A.1.

CH4 26.2

N2O 2.6

AUXBLR AUXBLR Auxiliary 

Boiler

CO2 7,680

7,687

Good Combustion and 

Operating Practices. Limit to 

876 hours of operation per 

year. See Special Conditions 

III.B.

CH4 0.14

N2O 0.01

EMGEN1

-STK

EMGEN1

-STK

Emergency 

Generator

CO2 64

64

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

FWP1-

STK

FWP1-

STK

Fire Water 

Pump

CO2 28

28

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

TRB-MSS TRBMSS

Maintenance , 

Startup, and 

Shutdown

CO2

No 

Numerical 

Limit 

Established6 2.2

Negligible emissions, EPA 

verified the provided 

analysis.

CH4 0.106

NG-FUG NG-FUG Natural Gas 

Fugitives

CO2

Not 

Applicable Not 

Applicable

Implementation of AVO 

Monitoring. See Special 

CH Condition III.D. 4

Not 

Applicable
Draft for March 20, 2013 public notice. 10 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No 

Numerical 

Limit 

Established6

23.9

Instrumented monitoring and 

alarm. See Special condition 

III.D.

Totals7 CO2 2,839,587 CO2e 

2,842,754 CH4 73

N2O 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): CH4 = 21, N2O = 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 for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

are for information only and do not constitute an emission limit.
Draft for March 20, 2013 public notice. 11 

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 selected as the combustion turbine model: 

Table 1C. Annual Emission Limits1

 - Siemens SGT6-5000F(5)

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

U1-STK U1-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator

CO2 1,594,162

1,595,712

912.7 lb CO2/MWh (gross) 

with duct burning. See Special 

Conditions III.A.1.

CH4 29.5

N2O 3 

U2-STK U2-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator

CO2 1,594,162

1,595,712

912.7 lb CO2/MWh (gross) 

with duct burning. See Special 

Conditions III.A.1.

CH4 29.5

N2O 3 

AUXBLR AUXBLR Auxiliary 

Boiler

CO2 7,680

7,687

Good Combustion and 

Operating Practices. Limit to 

876 hours of operation per 

year. See Special Conditions 

III.B.

CH4 0.14

N2O 0.01

EMGEN1

-STK

EMGEN1

-STK

Emergency 

Generator

CO2 64

64

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

FWP1-

STK

FWP1-

STK

Fire Water 

Pump

CO2 28

28

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

TRB-MSS TRBMSS

Maintenance , 

Startup, and 

Shutdown

CO2

No 

Numerical 

Limit 

Established6 2.2 Negligible emissions, EPA 

verified the provided analysis.

CH4 0.106

NG-FUG NG-FUG Natural Gas 

Fugitives

CO2

Not 

Applicable Not 

Applicable

Implementation of AVO 

Monitoring. See Special 

CH Condition III.D. 4

Not 

Applicable
Draft for March 20, 2013 public notice. 12 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No 

Numerical 

Limit 

Established6

23.9

Instrumented monitoring and 

alarm. See Special condition 

III.D.

Totals7 CO2 3,196,097 CO2e 

3,199,650 CH4 80

N2O 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): CH4 = 21, N2O = 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 for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

are for information only and do not constitute an emission limit.
Draft for March 20, 2013 public notice. 13 

III. SPECIAL PERMIT 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 

turbine models not selected. 

 1. Combustion Turbine Generator (CTG) BACT Emission Limits

Table 2. BACT Emission 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 CO2/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 CO2 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 CO2/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 (59oF, 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 compliance with 

the design emissions limit via an emission test, the Permittee shall not discharge or 

cause the discharge of emissions from the Combustion Turbine Generator (CTG) 

and heat recovery steam generator (HRSG) (EPNs U1-STK and U2-STK) into the 

atmosphere in excess of the limits in lb CO2/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 CO2e on a 12-month rolling average as 
Draft for March 20, 2013 public notice. 14 

listed in Table 1A, 1B, or 1C. To determine the BACT emission limit, the Permittee 

shall calculate the limit based on the measured net hourly energy output (MWh 

(gross)) and the tons of CO2 calculated from the equations provided in 40 CFR 75, 

Appendix D and F or the CO2 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/kWh (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 CO2 emission rate from 40 CFR Part 75, 

Appendix G, using Fc factors updated monthly from fuel analysis or, as an 

alternative, Permittee may install and operate a volumetric stack gas flow monitor 

and associated data acquisition and handling system in accordance with the CO2

CEMS system provided in 40 CFR § 75.10(a)(3) and (a)(5). 

2. Monitoring of CO2 Emissions for U1-STK and U2-STK

a. The Permittee shall determine the CO2 hourly emission rate and CO2 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 and 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, 

Appendix D and 40 CFR Part 60 to be used in conjunction with the Fc factor based 

on the procedures to calculate the CO2 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 CO2

CEMS and volumetric stack gas flow monitoring system with an automated data 

acquisition and handling system for measuring and recording CO2 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 Permittee 

shall ensure that all required fuel flow meters 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 CO2 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 

CO2 emission monitoring system.

3. U1-STK and U2-STK Combustion Turbine Work Practice and Operational 

Requirements

a. Permittee shall calculate the amount of CO2 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 CH4 and N2O emissions on a 12 month rolling average.

Permittee shall determine compliance with the CH4 and N2O emissions limits 

contained in section II using the default CH4 and N2O 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 CO2e 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 shall 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 SCR 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 test, at or above ninety percent 

(90%) of maximum load operations for the atmospheric conditions which 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, Permittee shall use the combustion turbines, 

Heat Recovery Steam Generators, 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 protection 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 CO2e 

emissions. The records must include hourly CO2 emission levels as measured by the 

fuel flow meter and/or O2 emission monitor (or CO2 CEMS with volumetric stack 

gas flowrate) and the calculations based on the actual heat input for the CO2, CO2e, 

O2, N2O, and CH4 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 Special Condition 

III.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 calibrate and perform preventative 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 maintenance on the air/fuel control 

analyzers once per quarter, at a minimum. 

12. Permittee shall install, operate, and maintain an O2 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 in 
Draft 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 Water 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 the Fire Water Pumps 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 

fuel 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 Permittee 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, SF6 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, Subpart DD. Permittee shall not 

exceed insulated circuit breaker SF6 capacity exceeding 400 lbs. 

3. Permittee shall equip the circuit breakers with a low pressure alarm and a low 

pressure lockout. The SF6 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 records 
Draft 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 Shutdown (TRB-MSS) 

The Permittee 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 CO2e.

IV. RECORDKEEPING AND REPORTING

1. In order to demonstrate compliance with the GHG emission limits in Table 1, the 

Permittee 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 utilize 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 records 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 records 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 performance 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 CO2 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 specifically required by 

an applicable subpart; or the Administrator or authorized representative, on a case-bycase basis, determines that more frequent reporting is necessary to accurately assess the 
Draft for March 20, 2013 public notice. 20 

compliance status of the source. The report is due on the 30th day following the end of 

each semi-annual period and shall include the following: 

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

known), corrective actions taken and preventive measures adopted; 

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

inoperative, 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 emissions 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 times.

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 CO2 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 CO2. 
Draft for March 20, 2013 public notice. 21 

1. Multiply the CO2 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 CO2 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 CO2 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 CO2

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 test 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) CO2. 

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 determining compliance with 

an applicable standard, the arithmetic mean of the results of the three runs shall apply.

VII. Agency Notifications 

Permittee shall submit GHG permit applications, permit amendments, and other applicable 

permit information to: 

Multi 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 75202 
1

Statement of Basis 

Draft Greenhouse Gas Prevention of Significant 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 forth the legal and factual basis for the draft 

permit conditions and provides references to the statutory or regulatory 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 construction 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 Texas 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 LPEC 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. After reviewing the application, EPA Region 6 has 

prepared the following SOB and draft air permit to authorize construction of air emission 

sources at the La Paloma Energy Center. 

This SOB documents the information and analysis 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 application is complete and provides the necessary 

information to demonstrate that the proposed project meets the applicable 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 available 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 implementation 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 78711-3087 
3

IV. Facility Location 

The La Paloma Energy Center (LPEC) will be located 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 over 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 facility location for this draft permit. 

 Figure 1. La Paloma Energy Center Location 
4

V. Applicability of Prevention of Significant Deterioration (PSD) Regulations 

EPA Region 6 implements a GHG PSD FIP for the 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 emissions of 3,292,862 tons per year (tpy) of CO2e. 

Since the proposed project’s GHG emissions would make LPEC a major stationary source for 

pursuant to 40 CFR 52.21(b)(1)(i) and (b)(49)(iv), EPA concludes that 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, 

PM10, PM2.5, and H2SO4. Accordingly, under the circumstances of this project, the TCEQ will 

issue the non-GHG portion of the permit 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 additional 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 pollutants, which are addressed by the PSD permit 

to be issued by TCEQ. 

VI. Project Description 

The proposed GHG PSD permit, if finalized, would authorize La Paloma Energy Center 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 gross electrical power output is based on two turbines rated between 183 and 232 

MW each and the steam from the HRSGs driving a third electric generator with an electricity 

output capacity of 271 MW. The LPEC 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.pdf 
5

 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 (SF6). 

Combustion Turbine Generator

The plant will consist of two identical natural gas-fired combustion turbines (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 selection of the combustion turbine model to be used 

at the plant will likely be made after the permit 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 each of the possible turbine models. If a final 

selection of combustion turbine is made after the 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 consist of a compressor, 

combustor, turbine, and generator. The compressor pressurizes combustion air to the combustor 

where the fuel is mixed with the combustion air 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 the unit, including emissions from the CT and 

the duct burners, will exit through 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 produce 
6

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 Siemens 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 available 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 year for purposes of maintenance checks and 

readiness testing. 

Electrical Equipment Insulated with Sulfur Hexafluoride (SF6)

The generator circuit breakers associated with the proposed units will be insulated with SF6. SF6

is a colorless, odorless, non-flammable, and non-toxic synthetic gas. It is a fluorinated compound 

that has an extremely stable molecular structure. The unique chemical properties of SF6 make it 

an efficient electrical insulator. The gas is used for electrical insulation, arc quenching, and 

current interruption in high-voltage electrical equipment. SF6 is only used in sealed and safe 

systems which under normal circumstances do not leak gas. The capacity of the circuit breakers 

associated with the proposed plant is currently estimated to be 400 lbs of SF6. 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 SF6 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 available control options; 

(2) Eliminate technically infeasible control options; 

(3) Rank remaining control options; 

(4) Evaluate the most effective controls (taking 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, auxiliary boiler, emergency engine, and fire water 

pump). The project will have fugitive emissions from piping components which will account for 

423 TPY of CO2e, or less than 0.01% of the project’s total CO2e emissions. Stationary 

combustion sources primarily emit CO2, and small amounts of N2O and CH4. 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) 

 SF6 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 two types of GHG emission reduction alternatives: 

(1) energy efficiency processes, practices, and designs for the turbines and other facility 

components; and (2) carbon capture and storage/sequestration (CCS). The proposed energy 

efficiency processes, practices, and designs discussed 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 provided in the GHG permit application a 5-step topdown BACT analysis for the combustion turbines. EPA has reviewed La Paloma’s BACT 

analysis for the combustion turbines, which is part of the record for this permit (including this 
8

Statement of Basis), and we also provide our own analysis in setting forth BACT for this 

proposed permit, as summarized below. 

Step 1 – Identify All Available Control Options 

(1) Energy Efficiency Processes, Practices, and Design

Combustion Turbine:

 Combustion Turbine Design – The most efficient way to generate electricity from a natural 

gas fuel source is the use of a combined cycle combustion turbine. Furthermore, the three 

turbine models under consideration for the LPEC facility are highly efficient turbines, in 

terms of their heat rate (expressed as number of BTUs of heat energy required to produce a 

kilowatt-hour of electricity), which is a measure that reflects how efficiently a generator uses 

heat energy. 

 Periodic Burner Tuning – Periodic combustion inspections involving tuning of the 

combustors to restore highly efficient 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 digital type supplied with the 

combustion turbine. The control system monitors the operation of the unit and modulates the 

fuel flow and turbine operation to achieve optimal 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), evaporator section, and 

superheater section(s). These heat transfer sections are made up of many thin-walled tubes to 

provide surface area to maximize the transfer 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 steam and water lines, and typically to the bottom 

portion of the stack. 

 Minimizing Fouling of Heat Exchange Surfaces – Filtration of the inlet air to the combustion 

turbine is performed to minimize fouling. Additionally, cleaning of the tubes is performed 

during periodic outages. By reducing the fouling, 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, and vacuum pumps/steam jet air ejectors. These 
9

vents are necessary to improve the overall heat transfer within the HRSG and condenser by 

removing solids and air that potentially blankets the heat transfer surfaces lowering the 

equipment’s performance. Steam leaks are repaired 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 saturated under vacuum condition 

by the use of a condenser. The condensing steam 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, resulting in an overall highefficiency steam turbine. The cooling method for the LPEC steam turbine will be either 

totally enclosed water to air 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 emissions from the emission units), including: 

 Fuel Gas Preheating – The overall efficiency of the combustion 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 down a train operating at less efficient part-load 

conditions and ramping up the remaining train 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 process that can be used by “facilities emitting CO2

in large concentrations, including fossil fuel-fired power plants, and for industrial facilities with 

high-purity CO2 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 adsorption or absorption processes to remove 

CO2 from flue gas, with subsequent desorption to produce a concentrated CO2 stream. The three 

main capture technologies for CCS are pre-combustion capture, post-combustion capture, and 

oxyfuel combustion (IPCC, 2005). Of these approaches, pre-combustion capture is applicable 

primarily to gasification plants, where solid fuel 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 tolerances (IPCC, 2005). 

Accordingly, pre-combustion capture and oxyfuel combustion are not considered available 

control options for this proposed gas turbine facility; the third approach, post-combustion 

capture, is applicable to gas turbines. 

With respect to post-combustion capture, a number of methods may potentially be used for 

separating the CO2 from the exhaust gas stream, including 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 capture with an amine solvent such as 

monoethanolamine (MEA) is currently the preferred 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 practice on gas turbines (Reddy, Scherffius, Freguia, & Roberts, 

2003). As such, post-combustion capture 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 solvent 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 manner, and it uses an MEA-based solvent that has 

been specially designed to recover CO2 from oxygen-containing streams with low CO2

concentrations typical of gas turbine exhaust (Fluor, 2009). This process has been used 

successfully to capture 365 tons per day of CO2 from the exhaust of a natural gas combinedcycle plant owned by Florida Power and Light in Bellingham, Massachusetts. The CO2 capture 

plant was maintained in continuous operation from 1991 to 2005 (Reddy, Scherffius, Freguia, & 

Roberts, 2003). As this technology is commercially 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 CO2 is captured from the flue gas, the captured CO2 is compressed to 100 atmospheres 

(atm) or higher for ease of transport (usually by pipeline). The CO2 would then be transported to 

an appropriate location for underground 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 the science and technologies for CO2 storage.3

Step 2 – Elimination of Technically Infeasible Alternatives 

All options identified in Step 1 are considered 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, Energy, and Environmental Impacts 

Carbon Capture and Storage

La Paloma developed a cost analysis for CCS. The estimated total annual cost of CCS would be 

$271,000,000 per year. The estimated plant construction 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 reviewed 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 control for this project and demonstrates those costs 

are high in relation to the overall cost of the proposed project without CCS, which is estimated at 

$443,800,000. 

Furthermore, the recovery and purification of CO2 from the stack gases would necessitate 

significant additional processing, including energy, and environmental/air quality penalties, to 

achieve the necessary CO2 concentration for effective sequestration. The additional process 

equipment required to separate, cool, and compress the CO2, would require a significant 

additional water and power expenditure. This equipment would include amine scrubber vessels, 

CO2 strippers, amine transfer pumps, flue gas fans, an amine storage tank, and CO2 gas 

compressors. The LPEC will utilize 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 and discharges a daily average of seven million 

gallons of effluent. This volume of effluent cannot support the daily water requirements of an Fclass natural gas fired combined cycle facility 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 captured for sequestration, or reduce the net amount 

GHG emission reduction, making CCS even less cost effective than expected. 

Therefore, since the cost of CCS would more than double the cost of the current project, and 

considering the adverse energy and environmental impacts of CCS, CCS has been eliminated as 

BACT for this project. 

Energy Efficiency Measures

None of the Energy Efficiency Measures have been eliminated from the BACT review based on 

adverse economic, environmental, or energy impacts. As noted above, the three turbine models 

under consideration are some of the most efficient combined cycle turbines, based on their lower 

heat rate in comparison to other combustion turbine models. From a GHG perspective, these 

factors may make IC engines the preferred generation alternative in some situations. 

Furthermore, the other energy efficiency measures 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 CO2/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 

and 

50 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 CO2/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 

CO2e/MWh (gross) on 

a 12-month rolling 

average basis 

2011 

DAQEAN0130310010-

11 

Kennecott 

Utah CopperRepowering 

South Jordan, 

UT 

275 MW 

combined 

combustion 

Energy Efficiency/ 

Good Design & 

Combustion 

Practices 

Combustion turbine 

BACT limit of 

1,162,552 tpy CO2e 

rolling 12-month 

period 

2011 DAQEIN105720026-11 
14

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 CO2e/MWhgrid

(initial performance 

test) 

895 lb CO2e/MWhgrid

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 CO2/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 CO2/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 Processes, Practices, and Design 

o Efficient Heat Exchanger Design 

o Insulation of HRSG 

o Minimizing Fouling of Heat 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 Design 
15

 Plant-wide Energy Efficiency Processes, 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 calculated a compliance margin 

based upon reasonable degradation factors that may foreseeably reduce efficiency under realworld conditions. The design base load net heat rates for the combustion turbines being 

considered for this project are as follows: 

 General Electric 7FA 

o 6674 Btu/kWhr (HHV) without duct burner firing 

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

 Siemens SGT6-5000F(4) 

o 6782 Btu/kWhr (HHV) without duct burner firing 

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

 Siemens SGT6-5000F(5) 

o 6891 Btu/kWhr (HHV) without duct burner firing 

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

These rates reflect the facility’s “net” power production, meaning the amount of power provided 

to the grid; it does not reflect the total amount of energy produced by the plant, which also 

includes auxiliary load consumed by operation of the plant. To be consistent with other recent 

GHG BACT determinations, the net heat rate without duct burner firing 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 constructed facility will not be 

able to achieve the design heat rate. 

 A 6% performance margin reflecting 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 many elements of the plant, which are often imprecise or not 
16

reflective of conditions once installed 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 over 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 turbine’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. Further, 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 rate is comparable to the rates 

estimated by other natural gas fired power plants 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 providing a reasonable compliance margin based on potential degradation 

in other elements of the combined cycle plant that would cause the overall plant heat rate to rise 

(i.e., cause efficiency to fall). Degradation in the performance of the heat recovery steam 

generator, steam turbine, heat transfer, cooling 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 CO2/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 CO2/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 efficiency will be a consideration 

for final selection of a turbine, other considerations 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 burner firing, LPEC proposes to demonstrate 
17

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 CO2/MWh. When converting the BACT 

limits to tons CO2/MWh gives a range of 0.455 tons CO2/MWh to 0.467 tons CO2/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, Calpine Channel Energy Center, Pioneer Valley 

Energy Center, and PacifiCorp Energy Lake Side Power Plant. The differences in BACT 

between La Paloma and LCRA and 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 CO2e/MWh) is less than that established for both 

Calpine facilities (0.46 tons CO2e/MWh). 

On March 27, 2012, the EPA proposed New Source Performance Standard (NSPS), 40 CFR Part 

60 Subpart TTTT, that would control CO2 emissions from new electric generating units (EGUs).5

The proposed rule would apply to fossil-fuel fired EGUs that generate electricity for sale and are 

larger than 25 MW. The EPA proposed that new EGUs meet an annual average output based 

standard of 1,000 lb CO2/MWh, on a gross basis. The proposed 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 CO2 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 combined 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 the 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/nsps/electric/fr13ap12.pdf 
18

 A Distributed Control System (DCS) will control all aspects of the turbine’s 

operation, including fuel feed and burner operations, to achieve optimal highefficiency low-emission performance for full-load and partial-load conditions; 

 Insulation blankets are utilized to minimize 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 electrical loss and higher unit efficiency. 

The Heat Recovery Steam Generator (HRSG) energy efficiency processes, practices and designs 

considered include: 

 Energy efficient heat exchanger design. In this design, each pressure level 

incorporates an economizer section(s), evaporator section, and superheater section(s); 

 Addition of insulation to the 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 maintain the efficiency of the turbine. The requirements include: 

 Fuel gas preheating. For the F-class combustion turbine based combined-cycle, the 

fuel gas is pre-heated to temperature of approximately 300o

F with high temperature 

water from the HRSG; 

 Drain operation. Operation drains are controlled 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. Multiple combustion turbine/HRSG trains 

help with part-load operation. A higher overall plant part-load efficiency is achieved 

by shutting down trains operating at less efficient part-load conditions and ramping 

up the remaining train(s) to high-efficiency full-load operation; and 

 Boiler feed pump fluid drives. To minimize the power consumption at part-loads, the 

use of fluid drives or variable-frequency drives are used to minimize the power 

consumption at part-load conditions 

La Paloma will demonstrate compliance with the CO2 limit established as BACT by using fuel 

flow meters to monitor the quantity of fuel combusted in the electric generating unit and 

performing periodic scheduled fuel sampling pursuant to 40 CFR 75.10(3)(ii) and the procedures 

listed in 40 CFR 75, Appendix G. Results of the fuel sampling will be used to calculate a sitespecific Fc factor, and that factor will be used in the equation below to calculated CO2 mass 
19

emissions. The proposed permit also includes an alternative compliance demonstration method in 

which LPEC may install, calibrate, and operate a CO2 CEMS and volumetric stack gas flow 

monitoring system with an automated data acquisition and handling system for measuring and 

recording CO2 emissions. To demonstrate compliance with the CO2 BACT limit using CO2

CEMS, the measured hourly CO2 emissions are divided by the net hourly energy output and 

averaged daily. 

La Paloma proposes to determine a site-specific Fc factor using the ultimate analysis and GCV in 

equation F-7b of 40 CFR 75, Appendix F. The site-specific Fc factor will be re-determined 

annually in accordance with 40 CFR 75, Appendix F, §3.3.6. 

The equation for estimating CO2 emissions as specified in 40 CFR 75.10(3)(ii) is as follows: 

ܹ஼ைమ ൌ ሺܨܿ 	ൈ ܪ 	ൈ ܷ݂	 ൈ ܯܹ஼ைమሻ/2000

Where: 

WCO2 = CO2 emitted from combustion, tons/hour 

MWCO2 = molecular weight of CO2, 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 MMBtu, as calculated using the procedure in 40 CFR 75, 

Appendix F, §5 

 Uf = 1/385 scf CO2/lb-mole at 14.7 psia and 68°F 

La Paloma is subject to all applicable requirements 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 pursuant to 40 CFR 75, Appendix D, §2.3.4.1 

Additionally, this approach is consistent with the CO2 reporting requirements of 40 CFR 98, 

Subpart D- GHG Mandatory Reporting Rule for Electricity Generation. Furthermore, La Paloma 

proposed CO2 monitoring method is consistent with the recently proposed New Source 

Performance Standards, Subpart TTTT- Standards 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 CO2 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 CO2 CEMS equipped with a volumetric stack 

gas monitoring system, the applicant shall rely on the data from the CO2 CEMS for compliance 

purposes. 

The emission limits associated with CH4 and N2O are calculated based on emission factors 

provided in 40 CFR Part 98, Table C-2 and the actual heat input (HHV). Comparatively, the 

emissions from CO2 contribute the most (greater than 99%) to the overall emissions from the 

combined cycle combustion turbines and; therefore, additional analysis is not required for CH4

and N2O. To calculate the CO2e emissions, the draft permit requires calculation of the emissions 

based on the procedures and Global Warming Potentials (GWP) contained in the Greenhouse 

Gas Regulations, 40 CFR Part 98, Subpart A, Table 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 CO2 emissions from U1-STK and U2-

STK. La Paloma also proposes to demonstrate compliance with the proposed heat rate with an 

annual compliance test, at 100% load, corrected to ISO conditions. An initial stack test 

demonstration for CH4 and N2O emissions are not required because the CH4 and N2O emission 

are approximately 0.01% of the total CO2e emissions from the combustion turbines. 

X. Auxiliary Boiler (AUXBLR) 

One nominally rated 150 MMBtu/hr auxiliary boiler (EPN AUXBLR) will 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 Potential Control Technologies for GHGs 

 Use of Low Carbon Fuels – Fuels vary in the amount of carbon per Btu, which in turn affects 

the quantity of CO2 emissions generated per unit of heat input. Selecting low carbon fuels is 

a viable method of reducing GHG emissions. Natural gas is the lowest carbon fuel available 

at LPEC. 

 Use of Good Operating and Maintenance Practices – Following the manufacturer’s 

recommended operating and maintenance procedures; 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 designed for a thermal efficiency of 

approximately 80%. The energy efficient design includes insulation to retain heat within the 
21

boiler and a computerized process 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 discussed in Step 1 are 

being proposed. Therefore, a ranking of the control technologies is not necessary. 

Step 4 – Evaluation of Control Technologies in Order of Most Effective to Least Effective, with 

Consideration of Economic, Energy, and Environmental Impacts 

As all of the energy efficiency related processes, practices, and designs discussed 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 will include following the manufacturer’s 

recommended operating and maintenance procedures; maintaining good fuel mixing, and 

limiting the amount of excess air in the combustion chamber to maximize thermal efficiency. 

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

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

Use of these practices corresponds with a permit limit of 7,687 tpy CO2e 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 nominally rated 1,072-hp diesel-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 provide water in the event of a fire. 

Step 1 – Identification of Potential Control Technologies 

 Low Carbon Fuels – Engine options includes engines powered by electricity, natural gas, or 

liquid fuel, such as gasoline 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 limited to 100 hours of operation per year for 

purposes of maintenance checks 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 combustion 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 cannot 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 feasible since the engines will only 

be operated either for readiness testing or for actual emergencies. 

Step 3 – Ranking of Remaining Technologies Based on Effectiveness 

Since the remaining technically feasible processes, practices, and designs in Step 1 are being 

proposed for the engines, a ranking of the control technologies is not necessary. 
23

Step 4 – Evaluation of Control Technologies in Order of Most Effective to Least Effective, with 

Consideration of Economic, Energy, and Environmental Impacts 

Since the remaining technically feasible processes, 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 appropriate maintenance of equipment, periodic testing conducted 

weekly, and operating within the recommended air 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 for maintenance and readiness testing, and in 

actual emergency operation. 

Using the BACT practices identified above results in a BACT limit of 65 tpy CO2e for the 

Emergency Generator (EMGEN1-STK) and 28 tpy CO2e for the Fire Water Pump (FWP1-STK). 

La Paloma will demonstrate compliance with the CO2 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 CO2 emissions as specified in 40 CFR 98.33(a)(3)(iii) is as follows: 

1.102311 ∗ ܨܧ ∗ ܸܪܪ ∗ ݈݁ݑܨ ∗ 	ଷ10ି ൈ 1 	ൌ ଶܱܥ

Where: 

CO2 = Annual CO2 mass emissions from combustion 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, from Table C-1 of 40 CFR Part 98 Subpart C. 

EF = Fuel specific default CO2 emission factor, from Table C-1 of 40 CFR Part 98 Subpart C. 

1 ൈ 10ିଷ	= Conversion of kg to metric tons. 

1.102311 = Conversion of metric tons to short tons. 

The emission limits associated with CH4 and N2O are calculated based on emission factors 

provided in 40 CFR Part 98, Table C-2, site specific analysis of process 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 CO2 emissions due to emissions from rotary shaft seals, 

connection interfaces, valve stems, and similar points. The additional methane and CO2

emissions from process fugitives have been conservatively estimated to be 423 tpy as CO2e. 

Fugitive emissions are negligible, and account for less than 0.01% of the project’s total CO2e 

emissions. 

Step 1 – Identification of Potential Control Technologies for GHGs 

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

 Implement alternative monitoring using a remote sensing technology such as infrared 

camera monitoring; and

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

Step 2 – Elimination of Technically Infeasible Alternatives 

LDAR programs are a technically feasible option for controlling process fugitive GHG 

emissions. 

Step 3 – Ranking of Remaining Technologies Based on Effectiveness 

Instrument LDAR programs and remote sensing using 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 facility is TCEQ’s 28LAER, which provides for 97% 

control credit for valves, flanges, and connectors. 

As-observed audio, visual, and olfactory (AVO) observation methods 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 natural gas systems. Due to the pressure and other physical properties of plant 

fuel gas, as-observed audio and visual observations of potential fugitive leaks are likewise 

moderately effective. 

                                                           

6

 73 FR 78199-78219, December 22, 2008. 
25

Step 4 – Evaluation of Control Technologies in Order of Most Effective to Least Effective, with 

Consideration of Economic, Energy, and Environmental Impacts 

Although instrument LDAR and/or remote sensing of piping fugitive emissions in natural gas 

service may be somewhat more effective than 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 CO2e emissions. 

Accordingly, given the costs of implementing 28LAER or a comparable remote sensing program 

when not otherwise required, these methods are not economically practicable for GHG control 

from components in natural gas service. 

Step 5 – Selection of BACT 

Based on the economic impracticability of instrument monitoring and 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 power plant in natural gas service. The proposed 

permit contains a condition to implement AVO inspections on a daily basis. 

XIII. SF6 Insulated Electrical Equipment (SF6-FUG) 

The generator circuit breakers associated with the proposed units will be insulated with SF6. The 

capacity of the circuit breakers associated with the proposed plant is currently estimated to be 

400 lb of SF6. 

Step 1 – Identification of Potential Control Technologies for GHGs 

In comparison to older SF6 circuit breakers, modern circuit breakers are designed as a totally 

enclosed-pressure system with far lower potential for SF6 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 SF6 (by weight) has escaped. The use of an 

alarm identifies potential leak problems before the bulk of the SF6 has escaped, so that it can be 

addressed proactively in order to prevent further release of the gas. 

One alternative considered in this analysis is to substitute another non-GHG substance for SF6 as 

the dielectric material in the breakers. Potential alternatives to SF6 were addressed in the 

National Institute of Standards and Technology (NIST) Technical note 1425, Gases for 
26

Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure 

SF6.

7

Step 2 – Elimination of Technically Infeasible Alternatives 

According to the report NIST Technical Note 1425, SF6 is a superior dielectric gas for nearly all 

high voltage applications. It is easy to use, exhibits exceptional insulation and arc-interruption 

properties, and has proven its performance by many years of use and investigation. It is clearly 

superior in performance to the air and oil insulated equipment used prior to the development of 

SF6 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 mixture...it is clear that a significant 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 feasible options besides the use of SF6. 

Step 3 – Ranking of Remaining Technologies Based on Effectiveness 

The use of state-of-the-art SF6 technology with leak detection to limit fugitive emissions is the 

highest ranked control technology that is feasible for this application. 

Step 4 – Evaluation of Control Technologies in Order of Most Effective to Least Effective, with 

Consideration of Economic, Energy, and Environmental Impacts 

Energy, environmental, or economic impacts are not addressed because the use of alternative, 

non-greenhouse gas substance for SF6 as the dielectric material in the breakers is not technically 

feasible. 

Step 5 – Selection of BACT 

La Paloma concludes that using state-of-the-art enclosed-pressure SF6 circuit breakers 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 generator output will have a low pressure 

alarm and a low pressure lockout. This alarm will function as an early leak detector that will 

bring potential fugitive SF6 emissions problems to light before a substantial portion of the SF6

escapes. The lockout prevents any operation of the breaker due to the lack of “quenching and 

cooling” SF6 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 SF6. 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 annually in accordance with the requirements of the Mandatory 

Greenhouse Gas Reporting rules for Electrical Transmissions and Distribution Equipment Use.9

Annual SF6 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 activities account for less than 0.0001% of the total 

project GHG emissions. Due to the infrequent nature 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 Endangered Species Act (ESA) (16 U.S.C. 1536) and its 

implementing regulations at 50 CFR Part 402, EPA is required to insure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued existence of 

any federally-listed endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated 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 purposes of preparation of the BA. 

A draft BA has identified eighteen (18) species listed as federally 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, EPA 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 designated critical habitat, 

nor potential suitable habitat for any of these species within the action area. Those fifteen species 

include: piping plover, Eskimo curlew, interior least tern, smalltooth sawfish, Rio Grande silvery 

minnow, jaguar, West Indian manatee, South Texas ambrosia, star cactus, Texas ayenia, green 

sea turtle, Kemp’s ridley sea turtle, leatherback sea turtle, loggerhead sea turtle, and Atlantic 

hawksbill sea turtle. 

However, based on the information provided in the 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 the ocelot. EPA and La Paloma (as EPA’s 

designated non-federal representative) 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 County, 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 constructed 
29

for this project. The USFWS also indicated that an irrigation canal located adjacent to the facility 

as well as other vegetated areas within the action area may provide travel or migration corridors 

for the ocelot or jaguarundi. USFWS provided recommendations 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 cultural 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 Potential Effect (APE) was determined to be 

approximately 78 acres of land within and adjacent to the construction footprint of the existing 

facility. Horizon conducted a field survey of the property and a desktop review on the 

archaeological background and historical records within a 1-mile radius area of potential effect 

(APE) which included a review of the Texas 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 recommended 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 archaeological 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 historical 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 concurrence with its determination. Any interested party is welcome 
30

to bring particular concerns or information to our attention regarding this project’s potential 

effect on historic properties. A copy 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 environmental justice issues must be considered in 

connection with the issuance of federal Prevention 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 emissions of GHG, controlled by what we have 

determined is the Best Available Control Technology 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 Quality Standard (NAAQS) 

for GHGs. The global climate-change inducing effects 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 evaluations of risks and impacts are typically 

conducted for changes in emissions that are orders of magnitude larger than the emissions from 

individual projects that might be analyzed in PSD permit reviews. Quantifying the exact impacts 

attributable to a specific GHG source obtaining a permit in specific 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 community 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 PSD Permit Application, and our independent 

evaluation of the information contained in our Administrative 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 conditions specified therein. This permit 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: the General Electric 7FA, the Siemens SGT6-

5000F(4), and the Siemens SGT6-5000F(5). The final selection of the combustion turbine model 

to be used at the plant will likely be made after 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 Limits1

 - General Electric 7FA 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

U1-STK U1-STK 

Combined Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4 

CO2 1,261,820 

1,263,055

934.5 lb CO2/MWh (gross) 

with duct burning5

. See 

Special Conditions III.A.1. 

CH4 23.4 

N2O 2.4 

U2-STK U2-STK 

Combined Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4 

CO2 1,261,820 

1,263,055 

934.5 lb CO2/MWh (gross) 

with duct burning5

. See 

Special Conditions III.A.1. 

CH4 23.4 

N2O 2.4 

AUXBLR AUXBLR Auxiliary Boiler 

CO2 7,680 

7,687 

Good Combustion and 

Operating Practices. Limit to 

876 hours of operation per 

year. See Special Conditions 

III.B. 

CH4 0.14 

N2O 0.01 

EMGEN1

-STK 

EMGEN1

-STK 

Emergency 

Generator 

CO2 64 

64 

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C. 

CH4

No 

Numerical 

Limit 

Established6 

N2O 

No 

Numerical 

Limit 

Established6
32

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

FWP1-

STK

FWP1-

STK Fire Water Pump 

CO2 28 

28 

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C. 

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

TRBMSS TRBMSS 

Maintenance , 

Startup, and 

Shutdown 

CO2

No 

Numerical 

Limit 

Established6 2.2 Negligible emissions, EPA 

verified the provided analysis. 

CH4 0.106 

NG-FUG NG-FUG Natural Gas 

Fugitives 

CO2

Not 

Applicable Not 

Applicable 

Implementation of AVO 

Monitoring. See Special 

CH Condition III.D. 4

Not 

Applicable 

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No 

Numerical 

Limit 

Established6

23.9 

Instrumented monitoring and 

alarm. See Special condition 

III.D. 

Totals7 CO2 2,531,413 CO2e 

2,534,338 CH4 67 

N2O 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): CH4 = 21, N2O = 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 for CH4 and CO2e include the PTE for process fugitive emissions of CH4. 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 selected as the combustion turbine 

model: 

Table 1B. Annual Emission Limits1

 - Siemens SGT6-5000F(4) 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

U1-STK U1-STK 

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4 

CO2 1,415,907 

1,417,263

909.2 lb CO2/MWh (gross) 

with duct burning5

. See 

Special Conditions III.A.1. 

CH4 26.2 

N2O 2.6 

U2-STK U2-STK 

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4 

CO2 1,415,907 

1,417,263 

909. 2 lb CO2/MWh (gross) 

with duct burning5

. See 

Special Conditions III.A.1. 

CH4 26.2 

N2O 2.6 

AUXBLR AUXBLR Auxiliary Boiler 

CO2 7,680 

7,687 

Good Combustion and 

Operating Practices. Limit to 

876 hours of operation per 

year. See Special Conditions 

III.B. 

CH4 0.14 

N2O 0.01 

EMGEN1

-STK 

EMGEN1

-STK 

Emergency 

Generator 

CO2 64 

64 

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C. 

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

FWP1-

STK

FWP1-

STK 

Fire Water 

Pump 

CO2 28 

28 

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C. 

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

TRBMSS TRBMSS 

Maintenance , 

Startup, and 

Shutdown 

CO2

No 

Numerical 

Limit 

Established6 2.2 Negligible emissions, EPA 

verified the provided analysis. 

CH4 0.106 
34

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

NG-FUG NG-FUG Natural Gas 

Fugitives 

CO2

Not 

Applicable Not 

Applicable 

Implementation of AVO 

Monitoring. See Special 

CH Condition III.D. 4

Not 

Applicable 

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No 

Numerical 

Limit 

Established6

23.9 

Instrumented monitoring and 

alarm. See Special condition 

III.D. 

Totals7 CO2 2,839,587 CO2e 

2,842,754 CH4 73 

N2O 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): CH4 = 21, N2O = 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 for CH4 and CO2e include the PTE for process fugitive emissions of CH4. 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 selected as the combustion turbine model: 

Table 1C. Annual Emission Limits1

 - Siemens SGT6-5000F(5)

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

U1-STK U1-STK 

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4 

CO2 1,594,162 

1,595,712

912.7 lb CO2/MWh (gross) 

with duct burning5

. See 

Special Conditions III.A.1. 

CH4 29.5 

N2O 3 

U2-STK U2-STK 

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4 

CO2 1,594,162 

1,595,712 

912.7 lb CO2/MWh (gross) 

with duct burning5

. See 

Special Conditions III.A.1. 

CH4 29.5 

N2O 3 

AUXBLR AUXBLR Auxiliary 

Boiler 

CO2 7,680 

7,687 

Good Combustion and 

Operating Practices. Limit to 

876 hours of operation per 

year. See Special Conditions 

III.B. 

CH4 0.14 

N2O 0.01 

EMGEN1

-STK 

EMGEN1

-STK 

Emergency 

Generator 

CO2 64 

64 

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C. 

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6

FWP1-

STK

FWP1-

STK 

Fire Water 

Pump 

CO2 28 

28 

Good Combustion and 

Operating Practices. Limit to 

100 hours of operation per 

year. See Special Conditions 

III.C. 

CH4

No 

Numerical 

Limit 

Established6

N2O 

No 

Numerical 

Limit 

Established6
36

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements TPY2

TRB-MSS TRBMSS 

Maintenance , 

Startup, and 

Shutdown 

CO2

No 

Numerical 

Limit 

Established6 2.2 Negligible emissions, EPA 

verified the provided analysis. 

CH4 0.106 

NG-FUG NG-FUG Natural Gas 

Fugitives 

CO2

Not 

Applicable Not 

Applicable 

Implementation of AVO 

Monitoring. See Special 

CH Condition III.D. 4

Not 

Applicable 

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No 

Numerical 

Limit 

Established6

23.9 

Instrumented monitoring and 

alarm. See Special condition 

III.D. 

Totals7 CO2 3,196,097 CO2e 

3,199,650 CH4 80 

N2O 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): CH4 = 21, N2O = 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 for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

are for information only and do not constitute an emission limit.