2 

FGE Power, LLC (PSD-TX-1364-GHG)

Prevention of Significant Deterioration Permit

For Greenhouse Gas Emissions

Final Permit Conditions

PROJECT DESCRIPTION

FGE is proposing to construct a new combined cycle electric generating plant (FGETP) in 

Mitchell County, Texas. FGETP will generate 1,620 megawatts (MW) of gross electrical power 

near the City of Westbrook. FGETP will consist of the following sources of GHG emissions:

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

combustors; 

• Four natural gas-fired duct burner systems; 

• Natural gas piping and metering;

• Two diesel fuel-fired emergency electrical generator engines; 

• Two diesel fuel-fired fire water pump engines; and

• Electrical equipment insulated with sulfur hexafluoride (SF6).

EQUIPMENT LIST

The following devices are subject to this GHG PSD permit.

FIN EPN Description

GT-1

GT-2 

GT-3 

GT-4

GT-1

GT-2 

GT-3 

GT-4

4 Natural Gas-Fired Combined Cycle Combustion Turbines (Combustion Units). 

The combustion turbines are equipped with duct burner fired heat recovery 

steam generators (HRSGs), selective catalytic reduction (SCR), and oxidation 

catalyst.

FWP-1 

FWP-2 

FWP-1 

FWP-2 

2 Fire Water Pumps (Combustion Unit). Each 389 horsepower (hp) Diesel Fired 

Fire Water Pump is rated at 2.7 MMBtu/hr and limited to 52 hours of operation 

per year for non-emergency activities.

EG-1 

EG-2 

EG-1 

EG-2 

2 Emergency Generators (Combustion Unit). Each 900 horsepower (hp) Diesel 

Fired Emergency Generator is rated at 6.3 MMBtu/hr and limited to 52 hours of 

operation per year for non-emergency activities.

FUG-SF6 FUG-SF6 SF6 Insulated Electrical Equipment (i.e., circuit breakers) with 462 lb SF6

capacity.

FUG-NGAS FUG-NGAS Process Fugitives.
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 (MSS), Permittee 

shall, to the extent practicable, maintain and operate the facility including associated air 

pollution control equipment in a manner consistent with good air pollution control 

practice for minimizing emissions. Determination of whether acceptable operating and 

maintenance procedures are being used will be based on information available to EPA, 

which may include, but is not limited to, monitoring results, review of operating 

maintenance procedures and inspection of the facility.

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 
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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 Sections 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, and a copy of the letter shall be forwarded to EPA Region 6 within 

30 days of the letter signature.

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.
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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 Number PSDTX1364 (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.
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I. ACRONYMS AND ABBREVIATIONS 

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 

CTG Combustion Turbine Generator 

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 

HRSG Heat Recovery Steam Generator

LAER Lowest Achievable Emission Rate

lb Pound 

LDAR Leak Detection and Repair

MMBtu Million British Thermal Units

MSS Maintenance, Start-up and Shutdown 

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 
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II. Annual Emission Limits 

Annual emissions, in tons per year (TPY) on a 12-month rolling total, shall not exceed the 

following:

Table 1. Annual Emission Limits1

 

FIN EPN Description GHG Mass Basis TPY

CO2e

3 BACT Requirements TPY2

GT-1 GT-1 

CT

Combined 

Cycle

CO2 1,459,718

1,472,228

889 lb CO2/MWh (gross) on a 

12-month rolling average per 

turbine. Special Condition 

III.A.1. and Table 2.

Startup Emissions – 48 tons 

CO2/hour per turbine and 1,735 

lbs CH4/event per turbine.

Shutdown Emissions - 192 

tons CO2/hour per turbine and 

510 lbs CH4/event per turbine. 

MSS Emissions - Special 

Condition III.A.4. and Table 3.

 

CH4 469.44

N2O 2.6

GT-2 GT-2 

CT

Combined 

Cycle

CO2 1,459,718

CH4 469.44 1,472,228

N2O 2.6

GT-3 GT-3 

CT

Combined 

Cycle

CO2 1,459,718

CH4 469.44 1,472,228

N2O 2.6

GT-4 GT-4 

CT

Combined 

Cycle

CO2 1,459,718

CH4 469.44 1,472,228

N2O 2.6

FWP-1 FWP-1 Firewater Pump

CO2 11.55

12

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 

FWP-2 FWP-2 Firewater Pump

CO2 11.55

12

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 

EG-1 EG-1 Emergency

Generator

CO2 26.71

27

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 
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FIN EPN Description GHG Mass Basis TPY

CO2e

3 BACT Requirements TPY2

EG-2 EG-2 Emergency

Generator

CO2 26.71

27

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 

FUGNGASFUGNGASNatural Gas 

Fugitives

CO2 

No Emission 

Limit 

Established5 No Emission 

Limit 

Established5

AVO monitoring - Special 

Condition III.C.1.

CH4 

No Emission 

Limit 

Established5 

FUGSF6FUGSF6

Electric 

Equipment

Fugitives

SF6 

No Emission 

Limit 

Established6 

No Emission 

Limit 

Established6

Instrument monitoring and 

alarm system - Special 

Condition III.C.3.

Totals7

CO2 5,838,948

5,889,434 CH4 1,894

N2O 10.40

SF6 0.0012

1. Compliance with the annual emission limits (tons per year) is based on a 12-month rolling total, to be updated 

the last day of the following month. 

2. The TPY GHG Mass Basis values are for informational purposes only and do not constitute an emission limit.

3. The TPY emission limits specified in this table shall not to be exceeded for this facility and include emissions 

from the facility during all operations including MSS activities. 

4. Global Warming Potentials (GWP): CH4 = 25, N2O = 298, SF6 = 22,800

5. These values are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work 

practice standard as specified in the permit.

6. Fugitive process emissions from EPN FUG are estimated to be 16.64 TPY of CH4, 0.08 TPY CO2, and 418 TPY 

CO2e. Fugitive process emission totals are for information only and do not constitute an emission limit. The 

emission limit will be a design/work practice standard as specified in the permit.

7. SF6 emissions from EPN FUG-SF6 are estimated to be 0.0012 TPY SF6 and 26.4 TPY CO2e. Fugitive process 

emission totals are for information only and do not constitute an emission limit. The emission limit will be a 

design/work practice standard as specified in the permit.

8. 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.
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III. SPECIAL PERMIT CONDITIONS

A. Requirements for Combustion Turbine Generators and Heat Recovery Steam 

Generators (EPNs: GT-1, GT-2, GT-3, and GT-4) 

1. Combustion Turbine Generator BACT Emission Limits

 Table 2. BACT Emission Limits for Combustion Turbines on a 12-month rolling 

average 

Turbine Model Gross Heat Rate1

 

(Btu/kWh) (HHV)

Output Based Emission 

Limit gross1 

(lb CO2/MWh)

Alstom GT24 7,625 889

 1These limits apply with and without duct burner firing. 

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 

Generators (CTGs) and Heat Recovery Steam Generators (HRSGs) (EPNs: GT-1, 

GT-2, GT-3, and GT-4) into the atmosphere do not exceed the limits in lbs 

CO2/MWh (gross) from Table 2 during the test. To determine compliance with 

the BACT emission limit, the Permittee shall calculate the limit based on the 

measured hourly energy output (MWh) (gross) while the CTG is operating at or 

above 90% of its design capacity with duct burner firing, and the results shall be 

corrected to ISO conditions (59 oF, 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 only combust fuel to perform required tuning and modifications 

necessary to demonstrate compliance.

b. Upon demonstration that the CTGs 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 CTGs and HRSGs 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 total as listed in Table 1. 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 using 

the CO2 emissions CEMS data. 
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c. Upon initial demonstration that the CTGs comply with the emissions limit via 

emission tests, the Permittee shall not exceed the CTG net heat rate Btu/kWh 

(HHV) from Table 2 on a 12-month rolling average. To determine this limit, the 

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. The Permittee shall determine the hourly CO2 emission rate by installing and 

operating a volumetric stack gas flow monitor or volumetric stack gas flow can be 

determined using those procedures of 40 CFR 75, Appendix D 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). 

e. The 12-month rolling average BACT emission limitations in this Special 

Condition do not include periods of MSS. 

2. Monitoring of CO2 Emissions for EPNs: GT-1, GT-2, GT-3, and GT-4

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

emissions for the CTGs and HRSGs using a CO2 CEMS and volumetric stack gas 

flow monitoring system or volumetric stack gas flow can be determined using 

those procedures of 40 CFR 75, Appendix D with an automated data acquisition 

and handling system for measuring and recording CO2 emissions discharged to 

the atmosphere. 

b. 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 

§ 72.2).

c. The 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. 

d. The Permittee shall meet the appropriate quality assurance requirements specified 

in 40 CFR Part 75, Appendixes D and F and 40 CFR Part 60 for the fuel flow 

meter and/or CO2 emission monitoring system.
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3. Combustion Turbine Work Practice and Operational Requirements

a. The Permittee shall calculate the amount of CO2 emitted from the CTs from 

combustion in tons per hour (tons/hr) on a 12-month rolling total, and converted 

to tons per year (tpy) based on CO2 CEMS data. 

b. The Permittee shall calculate the CH4 and N2O emissions on a 12-month rolling 

total. The 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. The Permittee shall calculate the CO2e emissions on a 12-month rolling total, 

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 CTs shall be limited to natural gas with a fuel sulfur content of up to 

1 grain 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, the Permittee shall provide a sample and/or analysis of the fuelfired in the CTs or shall allow a sample to be taken by EPA for analysis. 

e. The flow rate of the fuel combusted in CTs shall be measured and recorded using 

an inline flow meter and automatically record the data with a data acquisition and 

handling system. 

f. The Permittee shall measure and record the energy output (MWh net/gross) on an 

hourly basis. 

g. On or before the date of initial performance test required by 40 CFR §60.8, and 

thereafter, the 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 PSDTX1364. 

h. The Permittee shall perform an annual compliance test, at or above 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, the Permittee shall use the CTGs, HRSGs, 

Steam Turbines and Plant-wide energy efficiency processes, work practices and 

designs as represented in the permit application. 

4. Requirements during Combustion Turbine Startup and Shutdown

a. The Permittee shall minimize emissions during start-up and shutdown activities 

by operating and maintaining the facility and associated air pollution control 
12 

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 fuel is first fired. A 

planned startup for each combustion turbine is limited to 180 minutes (cold 

startup) per event. 

ii. A planned shutdown is defined as the period that begins when the gas turbine 

passes below 50% of full load and fuel flow ceases. The shutdown shall not 

exceed 60 minutes.

iii. Startup and shutdown activities are limited to 1,460 hours per year per turbine 

on a 12-month rolling total basis.

c. Startup and shutdown emissions shall not exceed the BACT emission and 

maximum heat inputs limits in Table 3. 

 Table 3. Startup/Shutdown, Emission, and Heat Input Limitations (per turbine)

Alstom GT24

BACT Emission 

Limit 

(tons CO2/hr)

BACT Emission 

Limit (lb CH4 per 

Event) 

Maximum Heat 

Input 

(MMBtu/hr)

Startup 48 1,735 820.0

Shutdown 192 510 2,236.8

d. 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 CO2 CEMS with volumetric stack gas flowrate, and the calculations based on 

the actual heat input for the 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 years following the date of such event.

B. Requirements for the Fire Water Pumps (EPNs: FWP-1 and FWP-2) and 

Emergency Generators (EPNs: EG-1 and EG-2) 

1. The Fire Water Pumps and Emergency Generators are authorized to fire diesel fuel 

containing no more than 0.0015 percent sulfur by weight. Upon request, Permittee 

shall provide a sample and/or an analysis of the fuel fired in the emission units 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 52 hours of nonemergency operation per year for each unit and a heat input value of 2.7 MMBtu/hr 
13 

and 6.3 MMBtu/hr, respectively. Compliance with the 52 hour non-emergency 

operational requirement is determined on a 12-month rolling total basis.

3. The Fire Water Pumps and Emergency Generators 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. The Permittee shall install and maintain an operational non-resettable elapsed time 

meter for the Fire Water Pump and Emergency Generator.

5. The 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, and 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.B.1., fuel heat input values and hours of 

operation required in Special Condition III.B.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. 

C. Requirements for Fugitive Emission Sources (FUG-NGAS and FUG-SF6)

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 FUG-SF6, 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 of 462 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 

relating to compliance with the Monitoring and Quality Assurance and Quality 

Control (QA/QC) procedures outlined in 40 CFR § 98.304. 
14 

D. Continuous Emissions Monitoring Systems (CEMS)

1. The Permittee shall ensure that all required CO2 monitoring systems/equipment is

installed at first fire 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 

operation.

2. The Permittee shall ensure compliance with the specifications and test procedures for 

CO2 emission monitoring system at stationary sources, 40 CFR Part 75, or 40 CFR 

Part 60, Appendix B, Performance Specification numbers 1 through 9, as applicable. 

3. The Permittee shall meet either the appropriate quality assurance requirements 

specified in 40 CFR Part 60, Appendix F for the CO2 emission monitoring system, or 

the quarterly linearity tests in 40 CFR Part 60, Appendix F.

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. The Permittee shall implement an AVO program and keep records of the monitoring 

results, as well as the repair and maintenance records.

3. The 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 and 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. The Permittee shall maintain records of all GHG emission units and CO2 emission 

certification tests and monitoring and compliance information required by this permit.

5. The 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 
15 

required by an applicable subpart or the Administrator or authorized representative, on a 

case-by-case basis, determines that more frequent reporting is necessary to accurately 

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

end of each semi-annual period and shall include the following:

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

known), corrective actions taken and preventive measures adopted; 

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

general permit 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 CTGs and HRSGs (EPNs: GT-1, GT-2, GT-3, and GT-4) 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. 
16 

1. Multiply the CO2 hourly average emission rate determined under maximum operating 

test conditions by 8,760 hours for the combustion turbines. 

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 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. Other than within the Shakedown Period described under Section V of this permit, 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 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 90% of maximum load operations for the 

atmospheric conditions which exist during testing. The duct burners shall be tested at 

their 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. Performance tests must be conducted under such conditions to ensure representative 

performance of the affected facility. The owner or operator must make available to EPA 

such records as may be necessary to determine the conditions of the performance tests.

F. 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.

G. 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 
17 

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

apply. 

H. Emissions testing, as outlined above, shall be performed on an annual basis, beginning 

one year after the initial performance test is completed. 

VII. Agency Notifications 

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

applicable permit information to: 

Multimedia 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 FGE Power, LLC

Permit Number: PSD-TX-1364-GHG

March 2014 

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 will apply if the permit is 

finalized. This document is intended for use by all parties interested in the permit. 

I. Executive Summary

On May 6, 2013, FGE Power, LLC (FGE), submitted to EPA Region 6 a Prevention of 

Significant Deterioration (PSD) permit application for Greenhouse Gas (GHG) 

emissions for a proposed construction project. On January 17, 2014, FGE submitted 

additional information for inclusion into the application. In connection with the same 

proposed construction project, FGE submitted an application for a PSD permit for 

non-GHG pollutants to the Texas Commission on Environmental Quality (TCEQ) on 

May 6, 2013. The project proposes to construct a natural gas fired combined cycle 

electric generating plant, known as the FGE Texas Project (FGETP), to be located 

near Westbrook, Mitchell County, Texas. The FGETP will consist of two combined 

cycle power blocks, each in a 2-on-1 configuration consisting of two combustion 

turbines (CTGs), two supplementally fired (duct burners) heat recovery steam 

generators (HRSGs) and one steam turbine. After reviewing the application, EPA 

Region 6 prepared the following SOB and draft air permit to authorize construction of 

air emission sources at the FGETP. 

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 FGE’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 FGE, and EPA's own 

technical analysis. EPA is making all this information available as part of the public record.
2 

II. Applicant

FGE Power, LLC

21 Waterway Avenue 

Suite 300 

The Woodlands, TX 77380 

Facility Physical Address:

3.5 miles south southwest of the intersection of Interstate 20 and Main Street 

Westbrook, TX 79565 

Contact: 

Emerson Farrell

CEO and President

FGE Power, LLC

(281) 362-2830 

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 
Copyrighted page(s) removed. Copyrighted 

material is not available in Regulations.gov since 

it may not be reproduced without consent of the 

copyright holder. 

Removed pages can be viewed at the USEPA 

Docket Center, Public Reading Room. 

Address: 1301 Constitution Ave, NW 

Room 3334 

Washington, DC 20004 

Telephone: 202-566-1744 

Email: docket-customerservice@epa.gov
4 

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

EPA concludes that FGE’s application is subject to PSD review for GHGs, because the 

project will constitute a new stationary source that will emit or have the potential to emit 

(PTE) 100,000 tons per year (TPY) CO2e, as described at 40 CFR § 52.21(b)(49)(v)(a), 

and greater than 100/250 TPY on a mass basis (FGE calculates CO2e emissions of 

5,889,434 TPY). 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. 

FGE represents that TCEQ, the permitting authority for regulated NSR pollutants other 

than GHGs, will determine that FGETP is also subject to PSD review for NOx, CO, VOC, 

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

will issue the non-GHG portion of the permit and EPA will issue the GHG portion.1 

In evaluating this permit application, 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 of 40 

CFR § 52.21(o) and (p), respectively. Instead, EPA 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. Air quality 

modeling or ambient monitoring may be required for TCEQ to issue the permit for the nonGHG pollutants. 

VI. Project Description

The proposed GHG PSD permit, if finalized, would authorize FGE to construct a new 

combined cycle electric generating plant (FGETP) in Mitchell County, Texas. FGETP will 

generate 1,620 megawatts (MW) of gross electrical power near the City of Westbrook. The 

gross electrical power output is based on four combustion turbines rated at nominal 230.7 

MW each and two steam turbines with duct burner firing that are designed to produce an 

additional 336 MW each. FGE’s rated output for a single power block is 810 MW of gross 

electrical output. FGETP will consist of the following sources of GHG emissions: 

• Four natural gas-fired CTGs equipped with lean pre-mix low-NOx combustors; 

 

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 

• Four natural gas-fired duct burner system equipped heat recovery steam generators 

(HRSGs); 

• Natural gas piping and metering;

• Two diesel fuel-fired emergency electrical generator engines; 

• Two diesel fuel-fired fire water pump engines; and

• Electrical equipment insulated with sulfur hexafluoride (SF6).

Combustion Turbine Generator

The plant will consist of four identical Alstom GT24 natural gas-fired CTGs. The CTGs 

will burn pipeline quality natural gas to rotate an electrical generator to generate electricity. 

The main components of a CTG 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 CTG and be routed to the heat recovery steam generator 

(HRSG) for steam production. 

Heat Recovery Steam Generator (HRSG) with Duct Burners

Heat recovered in the HRSGs will be utilized to produce steam. Steam generated within the 

HRSGs will be utilized to drive a steam turbine and associated electrical generator. The 

HRSGs will be equipped with duct burners (DBs) for supplemental steam production. The 

DBs will be fired with pipeline quality natural gas. Each DB has a maximum heat input 

capacity of 409 million British thermal units per hour (MMBtu/hr). The exhaust gases from 

the unit, including emissions from the CTG and the DBs, will exit through a stack to the 

atmosphere.

The normal DB operation will vary from 0 to 100 percent of the maximum capacity. DBs 

are located prior to the HRSGs, selective catalytic reduction (SCR) system, and the 

oxidation catalyst (OC). 

Generators Overall

Steam produced by each of the two HRSGs will be routed to the steam turbine. The two 

CTGs and one steam turbine will be coupled to electric generators to produce electricity for 

sale to the Electric Reliability Council of Texas (ERCOT) power grid. Each CTG has an 

approximate maximum base-load electric power output of 230.7 MW. The maximum 

electric power output from each steam turbine is approximately 336 MW. The units may 

operate at reduced load to respond to changes in system power requirements and/or 

stability.
6 

Emergency Equipment

The site will be equipped with two diesel-fired emergency generators, each nominally rated 

at 900-hp, to provide electricity to the facility in case of power failure. Two diesel-fired 

fire water pumps, each nominally rated 389-hp, will be installed at the site to provide water 

in the event of a fire. Each emergency engine and fire water pump will be limited to 52 

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 462 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 

EPA conducted the BACT analyses for this draft permit by following the “top-down” 

BACT approach recommended in EPA’s PSD and Title V Permitting Guidance for 

Greenhouse Gases (March 2011) and earlier EPA guidance. The five steps in a top-down 

BACT process are listed below.

(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, duct burners, emergency engines, and 

fire water pumps). The project will have fugitive emissions from piping components which 

will account for 444 tpy of CO2e, or less than 0.01% of the project’s total CO2e emissions. 
7 

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

SF6. The following equipment is included in this proposed GHG PSD permit: 

• Combined Cycle Combustion Turbines (GT-1, GT-2, GT-3, and GT-4) 

• Emergency Generators (EG-1 and EG-2) 

• Fire Water Pumps (FWP-1 and FWP-2) 

• Natural Gas Fugitives (FUG-NGAS) 

• SF6 Insulated Equipment (FUG -SF6) 

IX. Combined Cycle Combustion Turbines (EPNs: GT-1, GT-2, GT-3, and GT-4) 

The four Alstom GT24 natural gas-fired combined cycle turbines (i.e., the combustion 

turbine, HRSG, and steam turbine) will be used for power generation. The BACT analysis 

for these 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 (CCS). 

As part of the PSD review, FGE provided in the GHG permit application a 5-step top-down 

BACT analysis for the combustion turbines. EPA has reviewed FGE’S BACT analysis for 

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

• Periodic Burner Tuning – Regularly scheduled combustion inspections involving 

tuning of the combustors are used to maintain optimal thermal efficiency and 

performance. 

• Reduction in Heat Loss – Insulation blankets are applied to the combustion turbine 

casing to minimize heat loss to the environment. These blankets minimize the heat 

loss through the combustion turbine shell and help improve the overall efficiency of 

the machine.

• Instrumentation and Controls – Distributed digital system controls are used to 

automate processes for optimal operation. 
8 

Heat Recovery Steam Generator: 

• Heat Exchanger Design Considerations – HRSGs are shell-and-tube style heat 

exchangers designed to maximize the contact surface between the turbine exhaust 

gas and the feed water. 

• Insulation – The use of insulation prevents heat loss. 

• Minimizing Fouling of Heat Exchange Surfaces – Fouling occurs when deposition of 

constituents in the exhaust gases occurs on heat transfer surfaces within the heat 

exchanger. 

• Minimizing Vented Steam and Repair of Steam Leaks – Steam loss through venting 

and leakage reduces the efficiency of the heat exchanger. Restricting the venting 

outlets is used to maximize steam retention for power generation. 

Steam Turbine: 

• Use of Reheat Cycles – Steam turbine efficiency is dependent on the nature of the 

steam entering the turbine. 

• Use of Exhaust Steam Condenser – Steam turbine efficiency is improved by 

lowering the exhaust pressure of the steam. Condensing units are utilized to lower 

the exhaust steam to the saturation point, which reduces the exhaust pressure.

• Efficient Blading Design and Turbine Seals – Blade design has evolved for highefficiency transfer of the energy in the steam to power generation. 

• Efficient Steam Turbine Generator Design – The generator for modern steam 

turbines is cooled allowing for the highest efficiency of the generator, resulting in an 

overall high-efficiency steam turbine.

Other Plant-wide Energy Efficiency Features 

FGE 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: 

• Multiple Combustion Turbine/HRSG Trains – Part-load operation is improved 

through the use of multiple combustion turbine and HRSG trains. Optimum 

operating conditions are obtained through the automated shutting down/ramping up 

of less- and more-efficient operating trains.

• Cooling Towers – A closed-loop design, which includes a cooling tower to cool the 

water, will be utilized for the project. 
9 

(2) Carbon Capture and Storage (CCS) 

CCS is classified as an add-on pollution control technology, which involves the separation 

and capture of CO2 from flue gas, pressurizing of the captured CO2 into a pipeline for 

transport, and injection/storage within a geologic formation. CCS is general applied to 

“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 

 

2 U.S. EPA, Office of Air Quality Planning and Standards, PSD and Title V Permitting Guidance for 

Greenhouse Gases. March 2011. Available at: http://www.epa.gov/nsr/ghgdocs/ghgpermttingguidance.pdf. 
10 

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 

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). 

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

FGE’s application examines the technical feasibility of CCS for this project and concludes 

that:

While amine absorption technology for the capture of CO2 has been applied to 

natural gas–fired processes in the petroleum industry and natural gas processing 

industry, and therefore it is technically feasible to apply the technology to that of 

power plant turbine exhaust streams. However, the technologies have not been 

proven to be reliable, nor are they ready for full-scale commercial deployment. 

Although numerous research pilot-scale projects for high-volume carbon 

sequestration are underway, these projects are still a few years from 

implementation. Furthermore, although a single natural gas–fired combined cycle 

combustion turbine project with CO2 capture capabilities has been issued a standard 

permit by the TCEQ, this project has yet to be constructed. Although FGE 

questions whether it is feasible to implement CCS on a full-scale natural gas-fired 

combustion turbine project, an economic feasibility analysis for implementing CCS 

 

3 We note that EPA’s recent proposed rule addressing Standards of Performance for Greenhouse Gas 

Emissions from New Stationary Sources: Electric Utility Generating Units rejected CCS as the best system of 

emission reduction for nation-wide standard for natural gas combined cycle (NGCC) turbines based on both 

“insufficient information to determine technical feasibility” and “adverse impact on electricity prices and the 

structure of the electric power sector.” 79 Fed. Reg. at 1485 (Jan. 8, 2014). However, that proposal did not 

state that CCS was technically infeasible for individual NGCC sources and thus does not conflict with the 

type of case-by-case PSD BACT analysis (which separates the technical and cost issues) as presented here.
11 

for control of the CO2 emissions from the four combustion turbines is discussed in 

detail in Step 4 of this section.

FGE Application at 65. EPA’s recent proposed rule addressing Standards of Performance for 

Greenhouse Gas Emissions from New Stationary Sources: Electric Utility Generating Units

concluded that CCS was not the best system of emission reduction for a nation-wide standard 

for natural gas combined cycle (NGCC) turbines based on questions about whether full or 

partial capture CCS is technical feasible for the NGCC source category. 79 Fed. Reg. at 1485 

(Jan. 8, 2014). Considering this, EPA is evaluating whether there is sufficient information to 

conclude that CCS is technically feasible at this specific NGCC source and will consider 

public comments on this issue. However, because the applicant has provided a basis to 

eliminate CCS on other grounds, we have assumed, for purposes of this specific permitting 

action, that potential technical or logistical barriers do not make CCS technically infeasible 

for this project and have addressed the economic feasibility issues in Step 4 of the BACT 

analysis in order to assess whether CCS is BACT for this project. In addition, the other 

control options identified in Step 1 are considered technically feasible for this project. 

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

FGE developed an initial cost analysis for CCS that provided a total estimated capital cost 

for CCS as $1,508 million and stated that this would result in a more than 100% increase of 

the total capital cost of the proposed project. Based on these costs, FGE maintains that CCS 

is not economically feasible. While FGE provided some general information relating to this 

cost estimate that is provided in the record for this proposed permit (including more detailed 

cost information that is provided in Appendix B), FGE asserts that detailed capital cost 

information for this facility as a whole is protected as Confidential Business Information. 

Accordingly, to assess FGE’s cost claims, EPA has summarized some of the publically 

available cost information FGE provided below and compared FGE’s overall cost assertions

with cost estimates for similar facility types developed by the Agency and by the U.S. 

Department of Energy (DOE).4

 

4 See U.S. EPA, Air and Radiation, No. 450R13002, Documentation for EPA Base Case v.5.13 Using the 

Integrated Planning Model (Nov. 2013) (EPA Report), available at 
12 

Capital costs associated with CCS fall into two primary areas – CO2 Capture and 

Compression Equipment and CO2 Transport. The capture and compression equipment 

associated with CCS would have cost impacts based on the installation of the additional 

process equipment (e.g., amine units, cryogenic units, dehydration units, and compression 

facilities), while transport costs are associated with construction of a pipeline to transport the 

captured CO2. FGE conducted an analysis of the capital cost impact of CCS capture and 

compression equipment on the FGETP using project specific data along with the 

methodology provided by the U.S. Department of Energy’s Cost and Performance Baseline 

for Fossil Energy Plants, Volume 1: Bituminous and Natural Gas to Electricity, 

DOE/2010/1397 (Revision 2, November 2010). These cost have been prepared based upon 

project specific criteria and have been updated to calendar year 2014 dollars. The estimated 

capital cost for post-combustion CO2 capture and compression equipment was estimated to 

be $1,425 million. For transportation costs, FGE identified two possible options for 

transporting the captured CO2 – building a pipeline to the nearest existing CO2 pipeline (25 

miles) or to build a separate line to the nearest enhanced oil recovery (EOR) market (100 

miles) 5 – and estimated the cost for a 100 mile long 10 inch diameter pipeline at $83 million. 

Accordingly, FGE’s total estimated capital cost for CCS at this facility is approximately 

$1,508 million. 

Examining the proposed FGETP – a 1,610 MW Natural Gas Advanced Combined Cycle 

(CC) facility located in Mitchell County, TX – using the EPA and DOE cost estimates, EPA 

estimates that the capital costs of the entire facility without CCS would be approximately 

$1,500 million.6 EPA estimates that the capital costs of the entire facility with CCS would be 

approximately $3,035 million.7 These cost estimates are similar to the estimated CCS costs 

provided by FGE.8 These estimates also support FGE’s assertion that adding CCS to the 

 

http://www.epa.gov/airmarkt/progsregs/epa-ipm/docs/v513/Documentation.pdf, and U.S. Department of 

Energy, U.S. Energy Information Administration, Updated Capital Cost Estimates for Utility Scale 

Electricity Generating Plants (April 2013) (DOE Report).

available at http://www.eia.gov/forecasts/capitalcost/pdf/updated_capcost.pdf. 5 The closest potential transportation route (an existing Kinder Morgan CO2 pipeline) is approximately 25 

miles to the north-northwest from the proposed FGE facility. In addition, based upon information FGE 

obtained from local exploration and production (E&P) companies, there is an absence of the market need for 

CO2 for EOR activities in the immediate vicinity and the nearest enhanced oil recovery (EOR) market need is 

more than 100 miles to the west near Midland, Texas.

6 See EPA Report at Table 4-13 (initial capital costs of $1,006/kW) and Table 4-15 (0.954 locality cost 

adjustment) and DOE Report at Table 1 (initial capital costs of $1,023/kW) and Table 4 (0.92 locality cost 

adjustment).

7 See DOE Report at Table 1 (initial capital costs of $2,095/kW) and Table 4 (0.90 locality cost adjustment). 

The EPA Report does not contain similar CCS cost information in Table 4-13. 8 It is unclear whether the CCS cost estimates provided in the DOE Report include pipeline costs, but EPA 

estimates that adding separate pipeline construction costs would increase the CCS costs estimates for this 

facility by 1-5% (based on a CCS costs of approximately $1,535 million). Based on the estimated CO2 flow 

rate from the facility, EPA estimates that a 6-inch to 10-inch pipeline would be required to transport the 

captured CO2 from FGETP, and that the cost associated to construct a pipeline of this size would be 

approximately $650,000 to $750,000 per mile. This would result in costs of approximately $16-75 million 
13 

proposed facility would increase of the total capital cost of the proposed project by more than 

100%.9

 

CCS Conclusion 

Based on the normalized control cost, comparison of total capital cost of control to project 

cost, and decrease in net power output due the additional power requirements for CCS, FGE 

maintains that CCS is not economically feasible. EPA has reviewed FGE’s estimated CCS 

cost projections, and based upon the potential volume of CO2 emissions from the project that 

would be available for capture and current estimates of CCS costs that would be associated 

with a project such as this, we believe FGE’s estimated costs to install CCS add-on pollution 

controls for the facility are credible. Accordingly, we conclude that such costs would render 

the project economically unfeasible for FGETP and eliminate CCS as BACT for this facility.

Energy Efficiency Processes, Practices, and Design

There are no known adverse economic, energy, or environmental impacts associated with the 

control technologies identified in Step 1 for energy efficiency process, practices, and design. 

All these options are proposed for the facility as outlined below. 

Combustion Turbine:

• Combustion Turbine Design –The Alstom turbine model under consideration 

for the FGETP facility has a sequential combustion design that allows the 

injection of fuel into two combustion systems in series. This design makes it is 

possible to increase output and cycle efficiency without significantly increasing 

emissions during normal and low load operations. The sequential combustion 

technology is unique in that it allows the turbines to meet current BACT during 

low load operations. 

• Periodic Burner Tuning – Regularly scheduled combustion inspections 

involving tuning of the combustors are used to maintain optimal thermal 

efficiency and performance.

 

dollars for a 25 to 100 mile pipeline. EPA’s pipeline size estimate is based on distance transported of pure 

CO2 gas flowing at 282,340 lb/hr, as obtained from SNC Lavalin on April 12, 2013. Pipeline capital costs are 

based on equations from DOE NETL analysis as described in CO2 Transport, Storage & Monitoring Costs 

Quality Guidelines for Energy Systems Studies (March 2010) utilizing estimated pipeline length and 

diameter values. Calculations are included in Appendix B. 9 This summary of cost estimates does not address costs associated with CO2 storage. FGE’s initial analysis 

discusses possible cost offsets that might occur by selling the captured CO2 for EOR and taking advantage of 

limited tax credits for CO2 sequestration, but any resulting cost reductions would relatively small in 

comparison to overall CCS costs and would still not result in costs that would make CCS economically 

feasible for this facility. Moreover, the cost estimates could increase if FGE had to pay for non-EOR 

geologic sequestration of the CO2 emissions.
14 

• Reduction in Heat Loss – Insulation blankets are applied to the combustion 

turbine casing to minimize heat loss to the environment. These blankets 

minimize the heat loss through the combustion turbine shell and help improve 

the overall efficiency of the machine.

• Instrumentation and Controls – Distributed digital system controls are used to 

automate processes for optimal operation. Higher efficiencies and lower 

emissions are obtained through automation and easy-to-read digital readouts, 

which simplify turbine operation. 

Heat Recovery Steam Generator: 

• Heat Exchanger Design Considerations – HRSGs are shell-and-tube style heat 

exchangers designed to maximize the contact surface between the turbine 

exhaust gas and the feed water. The heat transfer is carried out at multiple

pressure levels within the HRSG, with fins used to extend heat transfer surfaces. 

In the low-pressure section, condensate is heated using the combustion turbine 

exhaust gas. Steam is further heated and pressured as it moves through the heat 

exchanger until the saturated high-pressure steam moves through the 

superheater section of the HRSG, where additional heat is added from ductburners, as necessary. The expansion of the superheated, high-pressure steam 

then powers the turbine. Exhaust gas bypass systems and economizer sections 

are utilized during startup and shutdown to reduce startup and shutdown times, 

minimizing exhaust emissions and reducing cold-end corrosion. 

• Insulation – HRSGs are designed to minimize waste heat from combustion by 

utilizing that waste heat to generate steam to power a steam turbine. The 

efficient transfer of this heat from the turbine exhaust gases and the 

minimization of heat losses to the environment is an integral part of HRSG 

design. The shell-side housing of the HRSG is well insulated to prevent 

unnecessary heat losses to the environment. 

• Minimizing Fouling of Heat Exchange Surfaces – Fouling occurs when 

deposition of constituents in the exhaust gases occurs on heat transfer surfaces 

within the heat exchanger. This fouling “insulates” the heat exchange surfaces 

from heat transfer between the exhaust gases and the feed water, reducing heat 

transfer efficiency. Fouling is reduced through filtration of the inlet exhaust 

gases and periodic cleaning of heat exchange surfaces. 

• Minimizing Vented Steam and Repair of Steam Leaks – Steam loss through 

venting and leakage reduces the efficiency of the heat exchanger. Venting 

operations are utilized in certain system areas, such as de-aerator vents, to 

improve operation. Restricting the venting outlets maximizes steam retention 

for power generation. If a leak is large enough, reduction in power generation 

efficiency is apparent and will be identified quickly through automatic 
15 

monitoring and low-pressure alarms. Smaller steam leaks are identified and 

repaired quickly through the proper implementation of operator SOPs requiring 

routine checks of the equipment. 

Steam Turbine: 

• Use of Reheat Cycles – Steam turbine efficiency is dependent on the nature of 

the steam entering the turbine. Reheat cycles are used to achieve higher steam 

temperatures and pressures and to reduce moisture content of the exhaust steam, 

increasing turbine efficiency.

• Use of Exhaust Steam Condenser – Steam turbine efficiency is improved by 

lowering the exhaust pressure of the steam. This lowering of the exhaust 

pressure creates a vacuum, creating a natural draw through the turbine and thus 

increasing turbine efficiency. Condensing units are utilized to lower the exhaust 

steam to the saturation point, which reduces the exhaust pressure. 

• 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 hightemperature 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 generators for modern steam 

turbines are cooled, allowing for the highest efficiency of the generator and

resulting in an overall high-efficiency steam turbine. The cooling method for 

the FGETP steam turbine will be either totally enclosed water-to-air cooling or 

hydrogen cooling. 

Other Plant-wide Energy Efficiency Features 

FGE 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: 

• Multiple Combustion Turbine/HRSG Trains – Part-load operation is improved 

through the use of multiple combustion turbine and HRSG trains. Optimum 

operating conditions are obtained through the automated shutting down/ramping 

up of less- and more-efficient operating trains. 

• Cooling Towers – A closed-loop design, which includes a cooling tower to cool 

the water, will be utilized for the project. Closed-loop designs are either natural 

circulation or forced circulation. Both natural circulation and forced circulation 

designs require higher cooling water pump heads; therefore, increasing the 

pump’s power consumption and reducing overall plant efficiency. Additionally, 
16 

to provide the forced circulation, fans are used for the forced circulation 

designs, which consume additional auxiliary power and reduce the plant’s 

efficiency.

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

La Paloma 

Energy Center

Harlingen, TX

183 MW

Combined cycle

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Input – 7,861

Btu/kWh

934 lb CO2/MWh

2013* PSD-TX-1288-

GHG

La Paloma 

Energy Center

Harlingen, TX

265 MW

Combined cycle

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Input - 7,649 

Btu/kWh

909 lb CO2/MWh

2013* PSD-TX-1288-

GHG

La Paloma 

Energy Center

Harlingen, TX

271 MW

Combined cycle

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Input - 7,679 

Btu/kWh

913 lb CO2/MWh

2013* PSD-TX-1288-

GHG

Calpine 

Deer Park 

Energy Center

Deer Park, TX

168 MW/180 

MW 

Combustion 

Turbine (CT) / 

Duct Burner 

(DB)

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Input – 7,730 

But/kWh

920 lb CO2/MWh

2012 PSD-TX-979-

GHG

Calpine 

Channel 

Energy Center

Pasadena, TX

168 MW/180 

MW 

CT/DB

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Input – 7,730 

Btu/kWh

920 lb CO2/MWh 

2012 PSD-TX-955-

GHG

Pioneer Valley 

Energy Center

Westfield, 

MA

431 MW 

combined cycle 

Energy Efficiency 

Good Design & 

Combustion 

Practices

825 lb CO2e/MWhgrid (initial 

performance test)

895 lb CO2e/MWhgrid on a 

365-day rolling average

2012 052-042-MA15

LCRA

Thomas C. 

Ferguson 

Plant

Horseshoe 

Bay, TX

195 MW 

CTG/DB 

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Rate - 7,720 

Btu/kWh 

920 lb CO2/MWh

2011 PSD-TX-1244-

GHG

Palmdale 

Hybrid Power 

Plant Project

Palmdale, CA

195 MW 

CTG/DB

Energy Efficiency 

Good Design & 

Combustion 

Practices

Annual Heat Rate - 7,319 

Btu/kWh

774 lb CO2/MWh 

2011** SE 09-01
17 

Company / 

Location

Process 

Description Control Device BACT Emission Limit / Requirements

Year 

Issued Reference

PacifiCorp 

Energy - Lake 

Side Power 

Plant

Vineyard, UT

629 MW 

(without duct 

burning) 

combined cycle 

turbine

Energy Efficiency

Good Design & 

Combustion 

Practices

950 lb CO2e/MWh (gross) 2011

DAQEAN0130310010-

11

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

*Permit currently under review by the EPA Environmental Appeals Board (EAB).

**The Palmdale facility BACT limit is reduced due to the offset of emissions from the use of a 50 MW SolarThermal 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

• Plant-wide Energy Efficiency Processes, Practices, and Design

o Multiple Combustion Turbine/HRSG Trains 

o Closed Loop Cooling Towers 

BACT Limits and Compliance:

To determine the appropriate heat-input efficiency limit, FGE 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 
18 

efficiency under real-world conditions. The design base load gross heat rates for the 

combustion turbines being considered for this project are as follows: 

• Alstom 

o 7,625 Btu/kWhr (HHV) without duct burner firing 

o 7,567 Btu/kWh (HHV) with duct burner firing 

These rates reflect the facility’s “gross” 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 gross 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 Margin - 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 reflective of conditions once installed at the site. Typically, the 

market for contracting the engineering and construction of combined cycle power plants 

has a design margin of 5% for the guaranteed net MW output and net heat rate. This is the 

condition for which the contractor has a "make right" obligation to continue tuning the 

facility's performance to achieve this minimum value. Therefore, the contractor must 

deliver a facility that is capable of generating 95% of the guaranteed MW and must have a 

heat rate that is no more than 105% of the guaranteed heat rate. Given FGE's confidence 

surrounding the expertise and experience of combined cycle power plant construction, FGE 

has elected to reduce the 5% design margin to 3.3%. 

Performance Margin on Combustion Turbine and Steam Turbine Generators - The 

performance margin for equipment degradation relates to the combustion turbine and steam 

turbine generators. According to Figure 24 of the California Energy Commission 

publication CEC-200-2010-002, Cost of Generation Model Users Guide Version 2 (March 

2010), the “sawtooth curve” indicates that the degradation will be limited to 2% between 

inspections and that 75% of that performance will be recovered, resulting in a 20-year 
19 

degradation of 4.5%. According to the combustion turbine vendor (Alstom Power), 

typically, performance degradation during the first 36,000 hours (the normally 

recommended interval for inspection and maintenance) is 2.01% (heat rate degradation) to 

2.64% (power output degradation). Alstom also indicated that, depending on the equivalent 

operating hours (EOH), approximately 28% to 44% of that performance will be recovered 

and would result in a 20-year degradation of approximately 2.23% and a 25-year

degradation of approximately 2.32%. Considering the atmospheric conditions at the project 

location (e.g., high ambient temperature, humidity, and ~2,200 foot elevation, etc.); FGE 

has taken a slightly more conservative view of this degradation. FGE projects the potential 

degradation to be 3.5% between the 36,000 EOH inspections (considerably less than the 

potential 4.5% stated in the CEC publication) and, assuming a 44% performance recovery, 

FGE calculated a 20-year degradation of 6%. 

Degradation Margin for the Auxiliary Plant Equipment - The degradation margin for the 

auxiliary plant equipment encompasses the HRSGs. This margin accounts for the scaling 

and corrosion of the boiler tubes over time as well as minor potential fouling of the heating 

surface of the tubes. Similar to the HRSGs, scaling and corrosion of the condenser tubes 

will also degrade the heat transfer characteristics, thus degrading the performance of the 

steam turbine generator. Because combustion turbine degradation accounts for the majority 

of the performance loss and as well as the large variation in operating parameters (fuels,

temperatures, water treatment, cycling conditions, etc.), little operating data has been 

gathered and published that illustrate a clear performance degradation characteristic for this 

auxiliary plant equipment. 

The following BACT limits are proposed: 

Turbine Model Gross Heat Rate1

(Btu/kWh) (HHV)

Output Based Emission 

Limit (lb CO2/MWh) gross1

Alstom 7,625 889

1

BACT limits apply with or without duct burner firing. 

The calculation of the gross heat rate and the equivalent lb CO2/MWh is provided in Tables 

7 and 8 of the supplemental information provided by FGE on January 17, 2014. The BACT 

limit will apply during startup conditions, shutdown and periods of maintenance (MSS will 

account for no more than 1,460 hours of operation a year). The BACT limit will apply to 

the turbines during all operational conditions, with and without duct burner firing. FGETP 

shall meet the BACT limit on a 12-month rolling average. Each combined MSS event is 

expected to not exceed 240 minutes (including cold startup and shutdown) during 

combined cycle operations. MSS events are estimated as follows: 180 minutes for a cold 

startup, 151 minutes for a warm startup, 56 minutes for a hot startup, and 60 minutes for a 

shutdown. The MSS emissions will also have a per event emission limit of 48 tons CO2/hr 

during startup, 1,735 lb CH4 per startup, 192 tons CO2/hr during shutdown, and 510 lb CH4

per shutdown. 
20 

Since the plant heat rate varies according to turbine operating load and amount of duct 

burner firing, FGETP proposes to demonstrate compliance with the proposed heat rate with 

an annual compliance test at 90% load, corrected to ISO conditions. 

FGETP requested the BACT limit to be expressed in lb CO2/MWh. When converting the 

BACT limits to tons CO2/MWh, FGETP provides a value of 889 lb CO2/MWh with or 

without duct burner firing. When compared to other BACT limits established for other 

combined cycle/heat recovery steam generating units, and when taking into account the 

mode of operation for the FGE facility, the proposed limits for FGETP 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 limits 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 FGETP is higher than those at LCRA and CVEC. The BACT limit 

proposed for FGETP is higher than the limit proposed for Pioneer Valley Energy Center 

(PVEC). PVEC is more likely to operate at base load conditions, whereas FGETP will 

operate as a load cycling unit. The BACT for FGETP (889 lb CO2e/MWh) is less than that 

established for both Calpine facilities (920 lb CO2e/MWh). 

On January 8, 2014, EPA proposed New Source Performance Standard (NSPS) 40 CFR 

Part 60 Subpart TTTT (Standards of Performance for Greenhouse Gas Emissions for New 

Stationary Sources: Electric Utility Generating Units, 77 FR 22392) that would control 

CO2 emissions from new electric generating units (EGUs).10 The proposed rule would 

apply to fossil-fuel fired EGUs that generate electricity for sale and are larger than 25 MW. 

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 FGETP turbines on a gross 

electrical output basis is 889 lb CO2/MWh with or without duct burner firing. The 

proposed CO2 emission rates from the FGETP combined cycle turbines are well within the 

emission limit proposed in the NSPS at 40 CFR Part 60 Subpart TTTT.

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, thereby increasing 

the turbine’s efficiency;

 

10 Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility 

Generating Units, 79 Fed Reg 1430, January 8, 2014. Available at http://www.gpo.gov/fdsys/pkg/FR-2014-

01-08/pdf/2013-28668.pdf
21 

• Periodic burner tuning as part of a regularly scheduled maintenance program to 

help ensure more reliable operation of the unit and to maintain optimal 

efficiency;

• A Distributed Control System will control all aspects of the turbine’s operation, 

including fuel feed and burner operations, to achieve optimal high-efficiency, 

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 HRSG energy efficiency processes, practices, and designs considered include: 

• Energy efficient heat exchanger design, including each pressure level 

incorporating 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 to minimize fouling; and

• Minimization of steam vents and repair 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: 

• 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 

• Cooling Towers. A closed-loop design, which includes a cooling tower to cool 

the water, will be utilized for the project. Closed-loop designs are either natural 

circulation or forced circulation. Both natural circulation and forced circulation 

designs require higher cooling water pump heads; therefore, increasing the 

pump’s power consumption and reducing overall plant efficiency. Additionally, 

to provide the forced circulation, fans are used for the forced circulation 

designs, which consume additional auxiliary power and reduce the plant’s 

efficiency.
22 

FGE will demonstrate compliance with the CO2 limit established as BACT by the use of a 

CO2 continuous emission monitoring system (CEMS) and also by recording the heat input 

to and the net power output from the generating station to demonstrate on an ongoing basis 

the 7,625 Btu/kWh GHG BACT limit. FGE shall install, calibrate, and operate the 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. For any 

period of time that the CO2 CEMS is nonfunctional, FGE shall use the methods and 

procedures outlined in the Missing Data Substitution Procedures as specified in 40 CFR 

Part 75, Subpart D. 

FGE will determine a site-specific Fc factor using the ultimate analysis and GCV in 

equation F-7b of 40 CFR Part 75, Appendix F. The site-specific Fc factor will be redetermined annually in accordance with 40 CFR Part 75, Appendix F § 3.3.6. 

FGE is subject to all applicable requirements for fuel flow monitoring and quality 

assurance pursuant to 40 CFR Part 75, Appendix D, which include: 

• Fuel flow meter shall meet an accuracy of 2.0% and is required to be tested 

once each calendar quarter pursuant to 40 CFR Part 75, Appendix D § 2.1.5 and 

2.1.6(a). 

• Gross Calorific Value (GCV) of pipeline natural gas shall be determined at least 

once per calendar month pursuant to 40 CFR Part 75, Appendix D § 2.3.4.1 

This approach is consistent with the CO2 reporting requirements of 40 CFR Part 98, 

Subpart D (Mandatory GHG Reporting Rule for Electricity Generation). The CO2

monitoring method proposed by FGE is consistent with the recently proposed NSPS, 

Subpart TTTT (40 CFR 60.5535(c)), which allows for EGUs firing gaseous fuel to 

determine CO2 mass emissions by monitoring fuel combusted in the affected EGU and 

using a site specific Fc factor determined in accordance to 40 CFR Part 75, Appendix F. 

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

provided in 40 CFR Part 98, Subpart C, Table C-2, fuel usage, and the actual heat input 

(HHV). Comparatively, CO2 emissions contribute the most volume (greater than 99%) to 

the overall emissions from the combined cycle combustion turbines; 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 shall be required to be kept to demonstrate 

compliance with the emission limits on a 12-month rolling total. 
23 

An initial stack test demonstration will be required for CO2 emissions from GT-1, GT-2, 

GT-3, and GT-4. FGE proposes to demonstrate compliance with the proposed heat rate 

with an annual compliance test at 90% load, corrected to ISO conditions. An initial stack 

test demonstration for CH4 and N2O emissions is not required because the CH4 and N2O 

emissions comprise approximately 0.01% of the total CO2e emissions from the combustion 

turbines. 

X. Emergency Engines (EG-1, EG-2, FWP-1, and FWP-2)

The FGETP site will be equipped with two nominally rated 900-hp diesel-fired emergency 

generators to provide electricity to the facility in the case of power failure and two 

nominally rated 389-hp diesel-fired pumps to provide water in the event of a fire. 

Step 1 – Identification of Potential Control Technologies 

• Low Carbon Fuels – Engine options include 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 52 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 relied on as an energy 

source for the emergency engines and are eliminated as technically infeasible for 

this use at 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. The default CO2 emission factors for gasoline and diesel are very 

similar, 70.22 kg/MMBtu and 73.96 kg/MMBtu respectively; however, gasoline 

has a higher volatility than and cannot be stored for as long as diesel fuel. Due to 

the need to store the emergency equipment fuel on site and the ability to store 

diesel for longer periods of time than gasoline, it is technically infeasible to 

utilize gasoline as a lower-carbon fuel for this use at this facility. 

• Good Combustion Practices and Maintenance – Technically feasible. 
24 

• Low Annual Capacity Factor – 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. 

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 the manufacturer. 

• Low Annual Capacity Factor – Each emergency engine will not be operated more than 

52 hours per year. Emergency engines will only be operated for maintenance and 

readiness testing and in actual emergency operation.

Using the BACT practices identified above results in an emission limit of 27 tpy CO2e for 

each of the Emergency Generators (EPNs: EG-1 and EG-2) and 12 tpy CO2e for each of

the Fire Water Pumps (EPNs: FWP-1 and FWP-2). FGE 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: 

CO2 = 1 × 10−3 ∗ Fuel ∗ HHV ∗ EF ∗ 1.102311

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 = Default high heat value of the fuel, from Table C-1 of 40 CFR Part 98, Subpart C. 
25 

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

C. 

1 × 10−3 = Conversion of kg to metric tons. 

1.102311 = Conversion of metric tons to short tons. 

As BACT for the engines is focused on reductions in GHGs through reductions in fuel 

usage, the reductions in fuel use conferred by the CO2 emission limits will also lead to a 

reduction of, and thus act as a surrogate for limitations on, CH4 and N2O.

XI. Natural Gas Fugitive Emissions (NG-FUG)

The proposed project will include natural gas piping components. These components are 

potential sources of CH4 emissions due to emissions from rotary shaft seals, connection 

interfaces, valve stems, and similar points. The additional CH4 emissions from process 

fugitives have been conservatively estimated to be 418 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. Remote sensing is a technically feasible option. Since pipeline natural gas is 

odorized with a small amount of mercaptan, an AVO detection plan for natural gas piping 

fugitives is technically feasible.

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.11 The use of an 

LDAR program with a portable gas analyzer meeting the requirements of 40 CFR Part 60, 

Appendix A, Method 21 can be effective for identifying leaking methane. Quarterly 

instrument monitoring with a leak definition of 10,000 ppmv (TCEQ 28M LDAR 

Program) is generally assigned a control efficiency of 75% for valves, relief valves, 

 

11 73 FR 78199, December 22, 2008.
26 

sampling connections, and compressors, and 30% for flanges. Quarterly instrument 

monitoring with a leak definition of 500 ppmv (TCEQ 28VHP LDAR Program) is 

generally assigned a control efficiency of 97% for valves, relief valves, and sampling 

connections, 85% for compressors, and 30% for flanges. EPA has allowed the use of an 

optical gas imaging instrument as an alternative work practice for a Method 21 portable 

analyzer for monitoring equipment for leaks in 40 CFR § 60.18(g). For components 

containing inorganic or odorous compounds, periodic AVO walk-through inspections 

provide predicted control efficiencies of 97% control for valves, flanges, relief valves, and 

sampling connections, and 95% for compressors.12 

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 0.01% 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. The 

frequency of inspection and the low odor threshold of mercaptans in natural gas make 

AVO inspections an effective means of detecting leaking components in natural gas 

service. As discussed in Step 3, the predicted emission control efficiency is comparable to 

the LDAR programs using Method 21 portable analyzers.

Step 5 – Selection of BACT

Due to the very low VOC content of natural gas, FGE will not be subject to any VOC leak 

detection programs by way of its State/PSD air permit, TCEQ Chapter 115 – Control of Air 

Pollution from Volatile Organic Compounds, New Source Performance Standards (40 CFR 

Part 60), National Emission Standard for Hazardous Air Pollutants (40 CFR Part 61), or 

National Emission Standard for Hazardous Air Pollutants for Source Categories (40 CFR 

Part 63). Therefore, any leak detection program implemented will be solely due to potential 

greenhouse emissions. Since the uncontrolled CO2e emissions from the natural gas piping 

represent approximately 0.01% of the total site-wide CO2e emissions, any emission control 

techniques applied to the piping fugitives will provide minimal CO2e emission reductions. 

Based on the economic impracticability of instrument monitoring and remote sensing for 

natural gas piping components, EPA proposes to incorporate as-observed AVO as BACT 

 

12 TCEQ – Control Efficiencies for TCEQ Leak Detection and Repair Programs (revised July 2011). 

Available at: 

http://www.tceq.texas.gov/assets/public/permitting/air/Guidance/NewSourceReview/control_eff.pdf. 

Accessed March 2014.
27 

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. 

XII. 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 462 lb of SF6. 

Step 1 – Identification of Potential Control Technologies for GHGs 

In determining whether a technology is available for controlling and reducing SF6

emissions from circuit breakers, permits and permit applications and EPA’s RBLC were 

consulted. In addition, currently available literature was reviewed to identify emission 

reduction methods.13,14,15 Based on these resources, the following available control 

technologies were identified:

• Use of new and state-of-the-art circuit breakers that are gas-tight and require less 

sSF6. 

• Evaluating alternate substances to SF6 (e.g., oil or air blast circuit breakers). 

• Implementing an LDAR program to identify and repair leaks and leaking 

equipment as quickly as possible. 

• Systematic operations tracking, including cylinder management and SF6 gas 

recycling cart use.

• Educating and training employees onabout proper SF6 handling methods and 

maintenance operations. 

Step 2 – Elimination of Technically Infeasible Alternatives

Of the control technologies identified above, only substitution of SF6 with another nonGHG substance is determined as technically infeasible. Though dielectric oil or 

compressed air circuit breakers have been used historically, these units require large 

equipment components to achieve the same insulating capabilities of SF6 circuit breakers. 

In addition, per an EPA report, “no clear alternative exists for this gas that is used 

 

13 Robert Mueller. 10 Steps to Help Reduce SF6 Emissions in T&D. Airgas Inc. Available at: 

http://www.airgas.com/documents/pdf/50170-120.pdf. 

14 U.S. EPA. 2008. SF6 Emission Reduction Partnership for Electric Power Systems 2007 Annual Report. 

Available at: http://www.epa.gov/electricpower-sf6/documents/sf6_2007_ann_report.pdf. 

15 J. Blackman (U.S. EPA, Program Manager, SF6 Emission Reduction Partnership for Electric Power 

Systems), M. Averyt (ICF Consulting), and Z. Taylor (ICF Consulting). 2006. SF6 Leak Rates from High 

Voltage Circuit Breakers – U.S. EPA Investigates Greenhouse Gas Emissions Source. Available at: 

http://www.epa.gov/electricpower-sf6/documents/leakrates_ circuitbreakers.pdf.
28 

extensively in circuit breakers, gas-insulated substations, and switch gear, due to its 

inertness and dielectric properties.”16 According to the report NTIS Technical Note 1425, 

SF6 is a superior dielectric gas for nearly all high voltage applications.17 It is easy to use, 

exhibits exceptional insulation and arc-interruption properties, and has proven its 

performance through 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.” 

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 the 

highest ranked remaining control technology – state-of-the-art SF6 technology with leak 

detection – is being proposed to limit fugitive emissions from the circuit breakers. 

Step 5 – Selection of BACT

EPA 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.18 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. 

FGETP will monitor emissions annually in accordance with the requirements of the 

Mandatory Greenhouse Gas Reporting rules for Electrical Transmissions and Distribution 

 

16 U.S. Environmental Protection Agency. 2008. SF6 Emission Reduction Partnership for Electric Power 

Systems 2007 Annual Report. Available at: http://www.epa.gov/electricpowersf6/documents/sf6_2007_ann_report.pdf. 17 Chrsitophorous, L.G., J.K. Olthoff, and D.S. Green. 1997. Gases for Electrical Insulation and Arc 

Interruption: Possible Present and Future Alternatives to Pure SF6. NIST Technical Note 1425. 18 ANSI Standard C37.013, Standard for AC High-Voltage Generator Circuit Breakers on a Symmetrical 

Current. 
29 

Equipment Use.19 Annual SF6 emissions will be calculated according to the mass balance 

approach in Equation DD-1 of 40 CFR Part 98, Subpart DD. 

FGE will implement the following work practices as SF6 BACT:

• Use of state-of-the-art circuit breakers that are gas-tight and guaranteed to achieve a 

leak rate of 0.5% by year by weight or less (the current maximum leak rate standard 

established by the International Electrotechnical Commission);

• An LDAR program to identify and repair leaks and leaking equipment as quickly as 

possible; 

• Systematic operations tracking, including cylinder management and SF6 gas 

recycling cart use; and 

• Educating and training employees with proper SF6 handling methods and 

maintenance operations

XIII. 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, FGE Power, LLC and its consultant, SWCA Environmental 

Consultants, and adopted by EPA. 

A draft BA has identified six (6) species listed as federally endangered or threatened in 

Mitchell County, Texas: 

Federally Listed Species for Mitchell County by the 

U.S. Fish and Wildlife Service (USFWS) and the Texas 

Parks and Wildlife Department (TPWD) 

Scientific Name 

Birds

Black-capped vireo Vireo atricapilla

Interior least tern Sterna anillarum alhalossos

Whooping Crane Grus americana 

Flowering Plants

Texas poppy mallow Callirhoe scabriuscula

 

19 See 40 CFR Part 98 Subpart DD.
30 

Federally Listed Species for Mitchell County by the 

U.S. Fish and Wildlife Service (USFWS) and the Texas 

Parks and Wildlife Department (TPWD) 

Scientific Name 

Mammals

Black footed ferret Mustela nigripes

Gray wolf Rufus lupus

EPA has determined that issuance of the proposed permit will have no effect on any of the 

six (6) listed species, as there are no records of occurrence, no designated critical habitat, 

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

Because of EPA’s “no effect” determination for the six species because they are not 

expected to occur in the geographical, no further consultation with the USFWS is needed. 

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. 

XIV. National Historic Preservation Act (NHPA) 

Section 106 of the NHPA requires EPA to consider the effects of this permit action on 

properties eligible for inclusion in the National Register of Historic Places. To make this 

determination, EPA relied on and adopted a cultural resource report and pipeline 

addendum prepared by SWCA Environmental Consultants, Inc, submitted in February 

2014. 

For purposes of the NHPA review, the Area of Potential Effect (APE) was determined to 

be location of the proposed natural gas combined cycle combustion turbine electrical 

generating station. SWCA Environmental Consultants conducted a desktop review within a 

1.0-mile radius area of potential effect (APE). The desktop review included an 

archaeological background and historical records review using 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 desktop review, 

including shovel testing, within the APE, no cultural resources were recorded at the 

location of the proposed natural gas combined cycle combustion turbine electrical 

generating station. Based on the desktop review, no cultural resources were identified 

within 1-mile of the APE. However, two historic markers for the former Conway School 

540 meters south of the proposed facility were identified but the school was dismantled in 

1947. Secondly, a farmstead was located with 11 structures was located about 0.85 miles 

northeast of the project area. The farmstead is recommended as not eligible for listing 

based on the poor condition of the structures. 
31 

For purposes of the NHPA review, the Area of Potential Effect (APE) was determined to 

be approximately 386.5 acres of land that includes 339 acres of the site facility that 

contains the construction footprint of the project, 46 acres for a 3.8-mile long pipeline 

corridor with 100 feet right-of-way, and 1.5 acres for 900 feet of a proposed water 

discharge line associated with this project. Following consultation with the State Historic 

Preservation Officer (SHPO), SWCA conducted a field survey of the APE and a desktop 

review on the archaeological background and historical records within a 1.0-mile radius 

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) were done. 

Based on the desktop review for the site facility and the linear facilities, Spindletop Oil 

Field, which is listed in the NHRP and also listed as a National Historic Landmark (NHL), 

is located 0.92 miles from the project area. Numerous surveys have been performed within 

the Spindletop property and at least seven cultural surveys were previously conducted 

within a 1-mile radius of the APE. Ten historic sites associated with Spindletop Oil Field 

were identified and were located within 1 mile of the APE; two of those sites are within the 

APE along the proposed 3.8-mile long pipeline corridor. Both of those sites located within 

the APE did not meet the any criteria for NHRP listing and were therefore were not 

recommended to be eligible for listing on the National Register. Eleven other historic or 

archaeological sites were identified from previous reports, all of which are outside of the 

APE. Based on the results of the field survey, which included 223 shovel tests, of the site 

facility, water discharge pipeline and pipeline corridor, no intact archaeological resources 

or historic structures were found. 

With regard to the linear facilities, 291 shovel tests along the gas pipeline and a total of 

five isolated finds were also recorded (four prehistoric and one historic), which 

investigations determined were not associated with an archaeological site. Due to the 

potential for deeply buried cultural deposits in the area immediately south of Beals Creek, 

FGE plans to cross this area using an above ground pipeline for a distance of 300 m, thus 

avoiding impacts. If future construction occurs immediately south of Beals Creek that 

differs from the currently proposed project then further investigations are recommended; 

specifically, deep, mechanical excavation (e.g., backhoe trenching) to determine the 

presence/absence of deeply buried cultural deposits. With this stipulation, SWCA 

recommends that a determination of No Historic Properties Affected be granted for the 

project to proceed as planned 

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 FGE Power will not affect properties 

potentially eligible for listing on the National Register.
32 

On February 24, 2014, 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 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. 

XV. 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 GHG. 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. 

XVI. Conclusion and Proposed Action 

Based on the information supplied by FGE, 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 FGE a PSD permit for 
33 

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. 
34 

Appendix A 

Annual Emission Limits

Annual emissions, in tons per year (TPY) on a 12-month rolling total, shall not exceed the 

following:

Table 1. Annual Emission Limits1 

FIN EPN Description GHG Mass Basis TPY

CO2e

3 BACT Requirements TPY2

GT-1 GT-1 

CT

Combined 

Cycle

CO2 1,459,718

1,472,228

889 lb CO2/MWh (gross) on a 

12-month rolling average per 

turbine. Special Condition 

III.A.1. and Table 2.

Startup Emissions – 48 tons 

CO2/hour per turbine and 1,735 

lbs CH4/event per turbine.

Shutdown Emissions - 192 tons 

CO2/hour per turbine and 510

lbs CH4/event per turbine. 

MSS Emissions - Special 

Condition III.A.4. and Table 3.

 

CH4 469.44

N2O 2.6

GT-2 GT-2 

CT

Combined 

Cycle

CO2 1,459,718

CH4 469.44 1,472,228

N2O 2.6

GT-3 GT-3 

CT

Combined 

Cycle

CO2 1,459,718

CH4 469.44 1,472,228

N2O 2.6

GT-4 GT-4 

CT

Combined 

Cycle

CO2 1,459,718

CH4 469.44 1,472,228

N2O 2.6

FWP-1 FWP-1 Firewater Pump

CO2 11.55

11.59

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 

FWP-2 FWP-2 Firewater Pump

CO2 11.55

11.59

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 

EG-1 EG-1 Emergency

Generator

CO2 26.71

26.82

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 
35 

FIN EPN Description GHG Mass Basis TPY

CO2e

3 BACT Requirements TPY2

EG-2 EG-2 Emergency

Generator

CO2 26.71

26.82

Good Combustion and

Operating Practices 

Limit to 52 hr/yr - Special 

Condition III.B.2.

CH4 

No Emission 

Limit 

Established4 

N2O 

No Emission 

Limit 

Established4 

FUGNGASFUGNGASNatural Gas 

Fugitives

CO2 

No Emission 

Limit 

Established5 No Emission 

Limit 

Established5

AVO monitoring - Special 

Condition III.C.1.

CH4 

No Emission 

Limit 

Established5 

FUGSF6FUGSF6

Electric

Equipment

Fugitives

SF6 

No Emission 

Limit 

Established6 

No Emission 

Limit 

Established6

Instrument monitoring and 

alarm system - Special 

Condition III.C.3.

Totals7

CO2 5,838,948

5,889,434 CH4 1,894

N2O 10.40

SF6 0.0012

1. Compliance with the annual emission limits (tons per year) is based on a 12-month rolling total, to be updated 

the last day of the following month.

2. The TPY GHG Mass Basis values are for informational purposes only and do not constitute an emission limit.

3. The TPY emission limits specified in this table shall not to be exceeded for this facility and include emissions 

from the facility during all operations including MSS activities.

4. Global Warming Potentials (GWP): CH4 = 25, N2O = 298, SF6 = 22,800

5. These values are less than 0.01 TPY with appropriate rounding. The emission limit will be a design/work 

practice standard as specified in the permit.

6. Fugitive process emissions from EPN FUG are estimated to be 16.64 TPY of CH4, 0.08 TPY CO2, and 418 TPY 

CO2e. Fugitive process emission totals are for information only and do not constitute an emission limit. The 

emission limit will be a design/work practice standard as specified in the permit.

7. SF6 emissions from EPN FUG-SF6 are estimated to be 0.0012 TPY SF6 and 26.4 TPY CO2e. Fugitive process 

emission totals are for information only and do not constitute an emission limit. The emission limit will be a 

design/work practice standard as specified in the permit.

8. 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.
2

2

2

2

2

5

7

7

Appendix B

FGE Texas Project

GHG BACT Analysis

Conceptual Carbon Capture and Sequestration Cost Estimate (Updated: 03/09/14) 

Post---Combustion CO2 Capture and Compression Equipment

Plant Output (kW) 1 = 1,621,462

Total Heat Input, HHV (mmBtu/hr) 1 = 10,786 2 CO2 Captured 3,919,629

Capture and Compression Cost Breakdown

Capital 3 $878.84/kW $1,425,005,664

Annual O&M (Fixed) 3 $22.61/kW $36,661,256

Annual O&M (Variable) 3 $0.0014/kWh $18,160,374

Total Annual O&M Costs Fixed + Variable $54,821,630

Annual Fuel 4

14.7% fuel use at $2.77/mmBtu $38,473,494

CO2 Transport --- Pipeline Cost Breakdown 

L, Pipeline Length (miles) = 100

D, Pipeline Diameter (inches) = 10

Pipeline Costs

Materials $70,350 + $2.01 x L x (330.5 x D2 + 686.7 x D + 26,960) $13,512,627

Labor $371,850 + $2.01 x L x (343.2 x D2 + 2,074 x D + 170,013) $45,611,523

Miscellaneous $147,250 + $1.55 x L x (8,417 x D + 7,234) $14,314,870

Right of Way $51,200 + $1.28 x L x (577 x D + 29,788) $4,602,624

Other Capital

CO2 Surge Tank $1,244,724 $1,244,724

Pipeline Control System $111,907 $111,907

Total Pipeline Capital Cost 6 $82,574,206

O&M

Fixed O&M ($/year) $8454 x L $879,216

CO2 Transport ($/year) 

CO2 Transport --- Compression Cost Breakdown

$3.32 x ton CO2 captured/year $13,533,694

EOR Revenue

EOR Revenue ($/year) 8

$9.09 x ton CO captured/year $17,814,713

CO2 Storage ($/year) 

Non---EOR/Geologic Storage Costs

$6.06 x ton CO2 captured/year $24,703,069

Capital Recovery Factor

% of Project Funded by Equity (%)

% of Project Funded by Debt (%) 

Cost of Equity (%)

Cost of Debt (%)

49

51

20

7

Weighted Cost of Capital (%) 9 13.37

Equipment Lifetime (years) 20

Capital Recovery Factor 10 0.1455

Annualized Cost Estimate

Total Capital Cost ($) $1,507,579,870

Annualized Capital Cost ($) 11 $219,398,315

Total Annualized Cost --- non EOR ($) $351,809,418

Total Annualized Cost --- EOR ($) $321,643,171

CO2 Cost Effectiveness --- non EOR ($/ton) 90

CO2 Cost Effectiveness ($/ton) --- EOR ($/ton) 82

1 Alstom turbine performance data represents the maximum value from all normal and LLOC operating scenarios. 

2 For the purposes of the conceptual cost estimate, the tons of CO2 captured is based on the average CO2 emission rate represented by the Alstom 

turbine performance data during base load conditions (100% Load) operating 8,000 hours with an assumed CO2 capture rate of 85%.

3 Adapted from Cost and Performance Baseline for Fossil Energy Plants, Volume 1: Bituminous and Natural Gas to Electricity, DOE/2010/1397 (Revision 

2, November 2010). The difference in the plant ($779/kW) and O&M (fixed = $20.039/kW and variable = $0.00124/kWh) costs between Case 14 (NGCC 

w/ CCS) and Case 13 (NGCC w/o CCS) was used to estimate the capital cost of the CCS capture and compression equipment for the FGE Texas Project. 

Capital costs adjusted using the U.S. BLS CPI Inflation Calculator from 2007 ($779/kW) to 2014 dollars ($878.84/kW) (http://www.bls.gov/data/ 

inflation_calculator.htm). O&M costs adjusted using the U.S. BLS CPI Inflation Calculator from 2007 ($20.039/kW and $0.00124/kWh) to 2014 dollars 

($22.61/kW and $0.0014/kWh).

4 Fuel costs represent the additional fuel necessary to compensate for parasitic load caused by the addition of CCS. Based on review of the plant heat 

rates used in Case 13 and 14 presented in Cost and Performance Baseline For Fossil Energy Plants, Volume 1: Bituminous and Natural Gas to Electricity,

DOE/2010/1397 (Revision 2, November 2010), CCS imposes a 14.7% increase in the plant heat rate. Therefore, 14.7% more fuel would be necessary to 

meet the plant output.

5 Pipeline capital cost and O&M costs based on equations from DOE NETL analysis CO Transport, Storage & Monitoring Costs Quality Guidelines for

Energy Systems Studies, DOE/NETL---2013/1614 (March 2013) utilizing pipeline length and diameter values. Capital and O&M costs multiplied by 1.04 to 

convert from 2011 to 2014 dollars (http://www.bls.gov/data/inflation_calculator.htm).

6 Sum of materials, labor, miscellaneous, right of way, CO surge tank, and pipeline control system capital costs, multiplied by 1.04 to convert from 2011 

to 2014 dollars (http: //www.bls.gov/data/inflation_calculator.htm).

7 CO transport and storage costs from DOE NETL analysis CO2 Transport, Storage & Monitoring Costs Quality Guidelines for Energy Systems Studies,

DOE/NETL---2013/1614 (March 2013) using the Texas location, East Texas basin as representative of transport and storage costs. Transport cost for East 

Texas basin were listed as $3.65/tonne ($3.32/ton) in 2011 and storage cost for the East Texas basin were listed at $6.06/tonne ($5.51/ton) in 2011. 

Capital costs multiplied by 1.04 to convert from 2011 to 2014 dollars (http: //www.bls.gov/data/inflation_calculator.htm).

8 US price from sale of CO for Enhanced Oil Recovery (EOR) is $10---40/tonne ($9.09/ton---$36.36/ton) obtained from Global CCS Institute’s report, The

Global Status of CCS, Chapter 9 – CO2 Enhanced Oil Recovery as CCS, Section 9.2 – Potential role of CO2 EOR in CCS, page 146 (2012). Once the

captured CO2 in the pipeline reaches the oil producers in the nearest EOR markets (100 miles to the west); FGE is uncertain of the ability for existing

EOR markets and the availability of other existing pipelines to accept the volume of CO2 produced by the FGE project. Therefore, it has been assumed 

for the purposes of this calculation that FGE would be able to sell 50% of its captured CO2.

http://cdn.globalccsinstitute.com/sites/default/files/publications/47936/global-status-ccs-2012.pdf

9 Weighted cost of capital calculated by summing the products of the weighted averages of the different financing components with the cost of the

particular financing component.

10 Capital recovery factor calculated via the following equation:

CRF= (i〖(1+i)〗^n)/ 

(〖(1+i)〗^n−1) with:

CFR = capital recovery factor

i = weighted cost of capital (interest rate)

n = number of years over which project is annualized

11 Annualized capital cost calculated by multiplying the total capital cost by the capital recovery factor.