### 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

- NO x 

### combustors;

• Four natural gas -fired duct burner systems;

• Natural gas piping and metering;

• Two diesel fuel

- fired emergency electrical generator engine s;

• Two diesel fuel

- fired fire water pump engine s; and

• Electrical equipment insulated with sulfur hexafluoride (SF 6 

### ).

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 (HRSG s ), selective catalytic reduction (SCR), and oxidation catalyst.

FWP -1
FWP -2 FWP -1
FWP -2 2 Fire Water Pump s (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 SF 6 Insulated Electrical Equipment (i.e., circuit breakers) with 462 lb SF 6 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. Determinatio n 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 facili ty.

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

### 4 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 notificati on 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 emission s 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 requi rements 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.

### 5 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.

### 6 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 CH 4 

### Methane CO 2 

### Carbon Dioxide CO 2 

### e Carbon Dioxide Equivalent CT Combustion Turbine CTG Combustion Turbine Generator
DLNB Dry Low

- NO x 

### Burner dscf Dry Standard Cubic Foot
EF Emission Factor EPN Emission Point Number
FIN Facility Identification Number
FR Federal Register GHG Greenhouse Gas

gr Grains GWP Global Warming Potential
HHV High Heating Value hr Hour HRSG Heat Recovery Steam Generator LAER Lowest Achievabl e 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
N 2 

### O Nitrous Oxides NO x 

### Nitrogen Oxides NSPS New Source Performance Standards PSD Prevention of Significant Deterioration QA/QC Quality Assurance and/or Quality Control SCFH Standard Cubic Feet per Hour SCR Selective Catalytic Reduction SF 6 

### Sulfur Hexafluoride TAC Texas Administrative Code TCEQ Texas Commission on Environmental Quality
TPY Tons per Year USC United States Code VOC Volatile Organic Compound

### 7 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 Limits 1

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

GT -1 GT -1 CT Combined Cycle CO 2 1,459,718

1,472,228

889 lb CO 2 /MWh (gross) on a 12

- month rolling average per turbine. Special Condition III.A.1. and Table 2.

Startup Emissions
– 48 tons CO 2 /hour per turbine and 1,735 lbs CH 4 /event per turbine.

Shutdown Emissions

- 192 tons CO 2 /hour per turbine and 510 lbs CH 4 /event per turbine.

MSS Emissions - Special Condition III.A.4. and Table 3. CH 4 469.44

N 2 O 2.6

GT -2 GT -2 CT Combined Cycle CO 2 1,459,718

1,472,228 CH 4 469.44

N 2 O 2.6

GT -3 GT -3 CT Combined Cycle CO 2 1,459,718

1,472,228 CH 4 469.44

N 2 O 2.6

GT -4 GT -4 CT Combined Cycle CO 2 1,459,718

1,472,228 CH 4 469.44

N 2 O 2.6

FWP -1 FWP -1 Firewater Pump CO 2 11.55

12 Good Combustion and Operating Practices

Limit to 52 h r/yr - Special Condition III.B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

FWP -2 FWP -2 Firewater Pump CO 2 11.55

12 Good Combustion and Operating Practices

Limit to 52 h r/yr - Special Condition III.B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

EG -1 EG -1 Emergency Generator CO 2 26.71

27 Good Combustion and Operating Practices

Limit to 52 h r/yr - Special Condition III.B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

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

EG -2 EG -2 Emergency Generator CO 2 26.71

27 Good Combustion and Operating Practices

Limit to 52 h r/yr - Special Condition III.B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

FUG

NGAS FUG

NGAS Natural Gas Fugitives CO 2 No Emission Limit Established 5 No Emission Limit Established 5 AVO monitoring - Special Condition III .C.1.
CH 4 No Emission Limit Established 5

FUG

SF6 FUG

SF6 Electric Equipment Fugitives SF 6 No Emission Limit Established 6 No Emission Limit Established 6 Instrument monitoring and alarm system - Special Condition III .C.3.

Totals 7 CO 2 5,838,948

5,889,434 CH 4 1,894
N 2 O 10.40
SF 6 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): CH 4 = 25 , N 2 O = 298 , SF 6 = 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 CH 4, 0. 08 TPY CO 2 , and 418 TPY CO 2 e. Fugitive process emission totals are for information only and do not constitute an emission limit. The emission limit will be a design/work practi ce standard as specified in the permit.
7. SF 6 emissions from EPN FUG

- SF6 are estimated to be 0. 001 2 TPY SF 6 and 26.4 TPY CO 2 e. 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 CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4. Total emissions are for information only and do not constitute an emission limit.

### 9 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 Rate 1


### (Btu/kWh) (HHV) Output Based Emission Limit gross 1


### (lb CO 2 

### /MWh)
Alstom GT24 7,625 889

1 These 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 CO 2 

### and use emission factors from 40 CFR Part 98. The
Permittee shall ensure that GHG emissions from the Combustion Turbine
Generator s (CTGs) and H eat R ecovery S team G enerator s (HRSGs) ( EPNs: GT -1,
GT -2, GT-3, and GT-4 ) into the atmosphere do not exceed the limits in lbs
CO 2 

### /MWh (gross) from Table 2 during the test. To determine compliance with
th e 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 o 

### F, 14.7 psia, and 67% humidity). If the CTG does not meet the design emissions limit, then the Permittee shall remedy the CTG’s failure to meet the design emissions limi t 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 CO 2 

### /MWh (gross) on a 12-month rolling a verage and shall not discharge or cause the discharge of emissions into the atmosphere in excess of the
limits in tons of CO 2 

### e on a 12-month rolling total as listed in Table 1. To determine the BACT emission limit, the Permittee shall calculate the limit b ased on the measured net hourly energy output (MWh gross) and the tons of CO 2 

### using
the CO 2 

### emissions CEMS data.

### 10 c. Upon initial demonstration that the CTGs comply with the emissions limit via
emission test s , 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 CO 2 

### emission rate by install ing and
operat ing a volumetric stack gas flow m onitor 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 CO 2 

### 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 CO 2 

### Emissions for EPNs: GT

- 1, GT

- 2, GT -3, and GT-4

a. The Permittee shall determine the CO 2 

### hourly emission rate and CO 2 

### mass emissions for the CTGs and HRSGs using a CO 2 

### 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 CO 2 

### 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 4 0 CFR § 72.2 ).

c. The Permittee shall ensure compliance with the specifications and test procedures
for fuel flow meter and/or CO 2 

### emission monitoring system at stationary sources,
40 CFR Part 75 and 40 CFR Part 60.
d. The Permittee shall meet the appropria te quality assurance requirements specified in 40 CFR Part 75, Appendix es D and F and 40 CFR Part 60 for the fuel flow
meter and/or CO 2 

### emission monitoring system.

### 11 3. Combustion Turbine Work Practice and Operational Requirements

a. The Permittee shall calculate the amount of CO 2 

### 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 CO 2 

### CEMS data

. b. The Permittee shall calculate the CH 4 

### and N 2 

### O emissions on a 12-month rolling
total

. The Permittee shall determine compliance with the CH 4 

### and N 2 

### O emissions
limits contained in S ection II using the default CH 4 

### and N 2 

### O emission factors contained in Table C-2 of 40 CFR Part 98 and the measured actual hourly heat input (HHV).

c. The Permittee shall calculate the CO 2 

### e 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 limit ed 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 fuel

fired 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 PSDTX 1364.
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 us e 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 duri ng 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 CO 2 

### /hr) BACT Emission Limit (lb CH 4 

### 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 CO 2 

### e emissions. The records must include hourly CO 2 

### emission levels as measured by
the CO 2 

### CEMS with volumetric stack gas f lowrate

, and the calculations based on the actual heat input for the N 2 

### O, and CH 4 

### emissions during each startup and shutdown event based on the equations represented in the permit application. These records must be kept for five years following the date of such event.

B. Requirements for the Fire Water Pump s (EPNs: FWP -1 and FWP- 2) and Emergency Generator s (EPNs: EG -1 and EG- 2)

1. The Fire Water Pump s and Emergency Generators are authorized to fire diesel fuel containing no more than 0.0015 p ercent 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 an d 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 Pump s 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 fil e 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., fue l 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, SF 6 

### emissions shall be calculated annually (calendar year) in accordance with the mass balance approach provided in equation DD-1 of the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and Distribution Equipment Use, 40 CFR Part 98, Subpart DD. Permittee shall not exceed
insulated circuit breaker SF 6 

### capacity of 462 lbs.
3. Permittee shall equip the circuit breakers with a low pressure alarm and a low

pressure lockout. The SF 6 

### leak detection system shall be able to detect a leak of at least 1 lb per year

. 4. Permittee shall maintain a file of all records, data measurements, reports and documents related to the fugitive emission sources including, but not limited to, the following: all records or reports pertaining to maintenance performed, all 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 CO 2 

### 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
CO 2 

### emission monitoring system at stationary sources, 40 CFR Part 75, or 40 C FR 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 CO 2 

### 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 reco rds.
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 CO 2 

### emission certification tests and monitoring and compliance information required b y 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 30 th 

### day following the
end of each semi -annual period and shall include the followin g:

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, du ring which the Permittee conducts operational and contractu al 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 CT Gs and HRSGs (EPNs: GT -1, GT-2, GT-3, and GT -4) to determine the initial compliance with the CO 2 

### emission limits established in this permit. Sampling shall be conducted in accordance with 40 CFR § 60.8 and EPA Method 3a or 3b for the
concentration of CO 2



### .

### 16 1. Multiply the CO 2 

### hourly average emission rate determined under maximum operating test conditions by 8,760 hours for the combustion turbines.
2. If the above calculated CO 2 

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

### emission total exceeds the TPY specified in Table 1, the facility shall:

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

### emission limit listed in Table 1.

B. 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 co mpliance

### 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 regu latory 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 connectio n with the same proposed construction project, FGE submitted an application for a PSD p ermit 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 (HRSG s) 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 F GETP

.

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 appl icant 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 (F IP) 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 proje ct will constitute a new stationary source that will emit or have the potential to emit (PTE) 100,000 tons per year ( TPY ) CO 2 

### e, as described at 40 CFR § 52.21(b)(49)(v)( a ), and greater than 100/250 TPY on a mass basis (FGE calculates CO 2 

### e 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 NO x 

### , CO, VOC, PM, PM 10 

### , PM 2.5 

### , and H 2 

### SO 4 

### . Accordingly, under the circumstances of this project, TCEQ
wi ll 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 qualitymodeling 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

- NO x 

### 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 ( HRSG s);

• Natural gas piping and metering;

• Two diesel fuel

- fired emergency electrical generator engine s;

• Two diesel fuel

- fired fire water pump engine s; and

• Electrical equipment insulated with sulfur hexafluoride (SF 6 

### ).

Combustion Turbine Generator

The plant will consist of four identical Alstom GT24 natural gas

- fired CTGs

. The CTG s 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 expan d 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 rec overed in the HRSGs will be utilized to produce steam. Steam generated within the
HRSG s will be utilized to drive a steam turbine and associated electrical generator. The
HRSG s 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. D Bs
are located prior to the HRSG s, 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
stab ility.

### 6 Emergency Equipment

The site will be equipped with two diesel

- fired emergency generator s, each nominally rated

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

- fired
fire water pumps, each n ominally 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 Insulat ed with Sulfur Hexafluoride (SF 6 

### )

The generator circuit breakers associated with the proposed units will be insulated with
SF 6 

### . SF 6 

### is a colorless, odorless, non-flammable, and non- toxic synthetic gas. It is a fluorinated compound that has an extremely st able molecular structure. The unique chemical properties of SF 6 

### make it an efficient electrical insulator. The gas is used for electrical insulation, arc quenching, and current interruption in high- voltage electrical equipment. SF 6 

### is only used in sealed a nd 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 SF 6 

### . The proposed circuit breaker at the generator output will have a low pre ssure alarm and a low pressure lockout. The alarm will alert personnel of any leakage in the system, and the lockout prevents any operation of the breaker due to lack of “quenching and cooling” of SF 6 

### gas.

VII. General Format of the BACT Analysis

EPA conducted t he 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 be low.

(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 engine s, and fire water pump s). The project will have fugitive emissions from piping components which
will account for 444 tpy of CO 2 

### e, or less than 0.01% of the project’s total CO 2 

### e emissions.

### 7 Stationary combustion sources primarily emit CO 2 

### and small amo unts of N 2 

### O, CH 4 

### , and
SF 6 

### . 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 Generator s ( EG -1 and EG-2)

• Fire Water Pump s (FWP -1 and FWP-2)

• Natural Gas Fugitives ( FUG

- NGAS )

• SF 6 

### Insulated Equipment ( FUG

- SF6 )

IX. Combined Cycle Combustion Turbines ( EPNs: GT

- 1, GT -2, GT-3, and GT-4)

The f our Alstom GT24 natural gas -fired combined cycle turbines (i.e., the combustion turbine, HRSG, and steam turbine) will be used for pow er generation. The BACT analysis
for the se 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 Generat or:

• 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 with in 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 r educes 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.

• Efficient Steam Turbine Generator Design
– The generator for modern steam
turbi nes 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 CO 2 

### from flue gas, pressurizing of the captured CO 2 

### into a pipeline for transport, and injection/storage within a geologic formation. CCS is general applied to “facilities emitting CO 2 

### in large concentrations, including fossil fuel-fired power plants, and for industrial facilities with high -purity CO 2 

### streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production, and iron and steel manufacturing).” 2



### CCS systems involve the use of adsorption or absorption processes to remove CO 2 

### from flue gas, with subsequent desorption to produce a conce ntrated CO 2 

### 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 soli d 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 tu rbine 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 CO 2 

### from the exhaust gas stream, inclu ding 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 characteris tics 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 Per mitting 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 e levated 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 CO 2 

### from oxygen

- containing streams with low CO 2



### conce ntrations typical of gas turbine exhaust (Fluor, 2009). This process has been used successfully to capture 365 tons per day of CO 2 

### from the exhaust of a natural gas combinedcycle plant owned by Florida Power and Light in Bellingham, Massachusetts. The CO 2 

### capture plant was maintained in continuous operation from 1991 to 2005 (Reddy, Scherffius, Freguia, & Roberts, 2003).

Once CO 2 

### is captured from the flue gas, the captured CO 2 

### is compressed to 100 atmospheres (atm) or higher for ease of transport (usuall y by pipeline). The CO 2 

### 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
CO 2 

### 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 CO 2 

### 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 CO 2 

### 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 “insuffic ient 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 f or 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 CO 2 

### 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

pa rtial 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 no t 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 c onsidered 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 a n 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
– CO 2 

### Capture and Compression Equipment and CO 2 

### 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 CO 2 

### . 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 CO 2 

### capture and compression equipment was estimated to be $1,425 million. For transportation costs, FGE identified two possible options for transporting the captured CO 2 

### – building a pipeline to the nearest existing CO 2 

### 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 f or 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 CO 2 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 CO 2 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 $1,0 06/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 c ost 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 co sts 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 CO 2 flow rate from the facility, EPA estimates that a 6

- inch to 10

- inch pipeline would be required to transport the captured CO 2 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 CO 2 

### emissions from the project that would be available for capture and current estimates of CCS costs that would be associated with a proje ct 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 tw o 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 CO 2 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 CO 2 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 Th is summary of cost estimates do es not address costs associated with CO 2 stor age. FGE’s initial analysis discusses possible cost offsets that might occur by selling the captured CO 2 for EOR and taking advantage of limited tax credits for CO 2 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 CO 2 emissions.

### 14 • Reduction in Heat Loss
– Ins ulation 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 unti l the saturated high -pressure steam moves through thesuperheater 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 w aste 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. T he 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
im prove operation. Restricting the venting outlets maximizes steam retention for power generation. If a leak is large enough, r eduction in power generation efficiency is apparent and will be identified quickly through automatic

### 15 monitoring and low- pressure al arms. 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 satur ation 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 desig n, 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 generator s 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 hy drogen 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 au xiliary 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

, 86 1 Btu/kWh

934 lb CO 2 /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 CO 2 /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 CO 2 /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 CO 2 /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 CO 2 /MWh 2012 PSD

- TX

- 955

- GHG

Pioneer Valley Energy Center

Westfield,
MA 431 MW

combined cycle Energy Efficiency Good Design & Combustion Practices 825 lb CO 2 e/MWh grid (initial performance test)

895 lb CO 2 e/MWh grid on a 365

- day rolling average 2012 052

- 042

- MA15

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 CO 2 /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 CO 2 /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 CO 2 e/MWh (gross) 2011 DAQE

AN0130310010

- 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 Solar

Thermal Plant that was part of the permitted project.



### The following specific BACT practices are proposed for the turbines:

• Use of Combined Cycle Power Generation Technology

• Combustion Turbine Energy Efficiency Processes, Practices, and Design

o Highly Efficient Turbine Design

o Turbine Inlet Air Cooling

o Periodic Turbine Burner Tuning

o Reduction in Heat Loss

o Instrumentation and Controls

• HRSG Energy Efficiency Processes, Practices, and Design

o Efficient heat exchanger design

o Insulation of HRSG

o Minimizing Fouling of Heat Exchange Surfaces

o Minimizing Vented Steam and Repair of Steam Leaks

• Steam Turbine Energy Efficiency Processes, Practices, and Design

o Use of Reheat Cycles

o Use of Exhaust Steam Condenser

o Efficient Blading Design

o Efficient Generato r 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, t he 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 ref lecting 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, whic h 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 degradat ion 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 characteristi c for this auxiliary plant equipment.

The following BACT limits are proposed:

Turbine Model Gross Heat Rate 1 

### (Btu/kWh) (HHV) Output Based Emission Limit (lb CO 2 

### /MWh) gross 1



### 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 CO 2 

### /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 (M SS will account for no more than 1,460 hours of operation a year). T he 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 (includ ing 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 ton s CO 2 

### /hr during startup, 1,735 lb CH 4 

### per startup, 192 tons CO 2 

### /hr during shutdown, and 510 lb CH 4 

### 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.

FGE TP requ ested the BACT limit to be expressed in lb CO 2 

### /MWh. When converting the
BACT limits to tons CO 2 

### /MWh , FGETP provides a value of 889 lb CO 2 

### /MWh with or without duct burn er 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 FGE TP 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 oper ate at base load conditions, whereas FGETP will operate as a load cycling unit. The BACT for FGETP (889 lb CO 2 

### e/MWh) is less than that established for both Calpine facilities ( 920 lb CO 2 

### e/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
CO 2 

### 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
CO 2 

### /MWh, on a gross basis. The proposed emission rate for the FGETP turbines on a gross electrical output basis is 889 lb CO 2 

### /MWh with or without duct burner firing. The proposed CO 2 

### emission rates from the FGETP combined cycle turbines are well within the emission limit proposed in the NSPS at 40 CFR Part 6 0 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 inl et 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 contro l 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 s team 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 demonst rate compliance with the CO 2 

### limit established as BACT by the use of a
CO 2 

### 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 7,62 5 Btu/kWh GHG BACT limit. FGE shall ins tall, calibrate, and operate the CO 2 

### CEMS and volumetric stack gas flow monitoring system with an automated data acquisition and handling system for measuring and recording CO 2 

### emissions. To demonstrate compliance wit h the CO 2 

### BACT limit using CO 2 

### CEMS, the measured hourly
CO 2 

### emissions are divided by the net hourly energy output and averaged daily. For any period of time that the CO 2 

### 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 re

determined 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 4 0 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 g as 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 CO 2 

### reporting requirements of 40 CFR Part 98, Subpart D (Mandatory GHG Reporting Rule for Electricity Generation ). The CO 2 

### 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 CO 2 

### 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 CH 4 

### and N 2 

### O are calculated based on emission factors provided in 40 CFR Part 98, Subpart C, Table C -2, fuel usage, and the act ual heat input (HHV). Comparatively, CO 2 

### 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 CH 4 

### and N 2 

### O. To calculate the CO 2 

### e emi ssions, 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 CO 2 

### 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 CH 4 

### and N 2 

### O emissions is not required because the CH 4 

### and N 2 

### O
emission s comprise approximately 0.01% of the total CO 2 

### e 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 n ominally 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 in clude 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 op erating 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 purp oses 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 CO 2 

### emission factors for gasoline and diesel are very similar, 70.22 kg/MMBtu and 73.96 kg/MMBtu respectively; h owever, 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 fue l 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 – T echnically feasible

.

### 24 • Low Annual Capacity Factor – T echnically 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 a n emission limit of 27 tpy CO 2 

### e for each of the Emergency Generator s ( EPN s : EG -1 and EG -2) and 12 tpy CO 2 

### e for each of the Fire Water Pump s ( EPNs: FWP -1 and FWP -2 ). FGE will demonstrate compliance with
the CO 2 

### emission limit using the default emission factor and default high heating value for diesel fuel from 40 CFR Part 98, Subpart C, Table C-1. The equation for estimating CO 2 

### emissions as specified in 40 CFR § 98.33(a)(3)(iii) is as follows:

CO 2 

### = 1 × 10 −3 

### ∗ Fuel ∗ HHV ∗ EF ∗ 1. 102311

Where:
CO 2 

### = Annual CO 2 

### 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 CO 2 

### 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 CO 2 

### emission limits will also lead to a reduction of, and thus act as a surrogate for limitations on, CH 4 

### and N 2 

### O.

XI. Natural Gas Fugitive Emissions (NG- FUG)

The proposed project will include natural gas piping components. These components are potential sources of CH 4 

### emissions due to emissions from rotary shaft seals, connection interfaces, valve stems, and similar points. The additional CH 4 

### emissions from process fugitives have been conservatively estimated to be 418 tpy as CO 2 

### e. Fugitive emissions are negligi ble, and account for less than 0.01% of the project’s total CO 2 

### e emissions.

Step 1 – Identification of Potential Control Technologies for GHGs

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

• Implement alternative monito ring 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 ass igned 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 sampli ng 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 CO 2 

### e 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 discu ssed 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 p rograms 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 CO 2 

### e emissions from the natural gas pipi ng represent approximately 0.01% of the total site

- wide CO 2 

### e emissions, any emission control techniques applied to the piping fugitives will provide minimal CO 2 

### e 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 a t: 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. SF 6 

### Insulated Electrical Equipment (SF6

- FUG)

The generator circuit breakers associated with the proposed units will be insulated with
SF 6 

### . The capacity of the circu it breakers associated with the proposed plant is currently
estimated to be 4 62 lb of SF 6


### .

Step 1 – Identification of Potential Control Technologies for GHGs

In determining whether a technology is available for controlling and reducing SF 6 

### 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 w ere identified:

• Use of new and state

- of -the- art circuit breakers that are gas -tight and require less

s SF 6


### .

• Evaluating alternate substances to SF 6 

### (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 SF 6 

### gas recycling cart use.

• Educating and training employees onabout proper SF 6 

### handling methods and maintenance operations

.

Step 2
– Elimination o f Technically Infeasible Alternatives

Of the control technologies identified above, only substitution of SF 6 

### 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 SF 6 

### 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, SF 6 Emission Reduction Partnership for Electric Power Systems), M. Averyt (ICF Consulting), and Z. Taylor (ICF Consulting). 2006. SF 6 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,
SF 6 

### 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 investig ation. It is clearly superior in performance to the air - and oil-insulated equipment used prior to the development of SF 6 

### - insulated equipment. The report concluded that although “various gas mixtures show considerable promise for use in new equipment, part icularly 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 Technolog ies Based on Effectiveness

The use of state -of-the- art SF 6 

### technology with leak detection to limit fugitive emissions is the highest ranked control 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 remai ning control technology – state -of-the- art SF 6 

### 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 SF 6 

### circuit b reakers 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 breake r 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 SF 6 

### emissions problems to light before a substantial portion of the SF 6 

### escapes. The lockout prevents any operation of the breaker due to the lack of “quenching and cooling” SF 6 

### gas.

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. SF 6 Emission Reduction Partnership for Electric Power Systems 2007 Annual Report . Available at: http://www.epa.gov/electricpower

sf6/documents/sf6_2007_ann_report.pdf

. 17 Chrs itophorous, 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 Cir cuit Breakers on a Symmetrical
Current

.

### 29 Equipment Use. 19 

### Annual SF 6 

### 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 SF 6 

### 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 equip ment as quickly as possible;

• Systematic operations tracking, including cylinder management and SF 6 

### gas recycling car t 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)

prepare d 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 Mit chell 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 Mit chell 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 i ssuance 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 geo graphical, 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 c an 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 pipeli ne 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 elect rical 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
locat ion 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 l isting 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 Off icer (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 At las (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 crite ria 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 alon g 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 a rea 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 Histo ric 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 footp rint 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 h istorical 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 an y 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 o r 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 individua l 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 an d 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 Limits 1

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

GT -1 GT -1 CT Combined Cycle CO 2 1,459,718

1,472,228

889 lb CO 2 /MWh (gross) on a 12-m ont h rolling average per turbine

. Special Condition III.A.1. and Table 2.

Startup Emissions
– 48 tons CO 2 /hour per turbine and 1,735 lbs CH 4 /event per turbine.

Shutdown Emissions - 192 tons CO 2 /hour per turbine and 510 lbs CH 4 /event per turbine

.

MSS Emissions - Special Condition III.A.4. and Table 3. CH 4 469.44

N 2 O 2.6

GT -2 GT -2 CT Combined Cycle CO 2 1,459,718

1,472,228 CH 4 469.44

N 2 O 2.6

GT -3 GT -3 CT Combined Cycle CO 2 1,459,718

1,472,228 CH 4 469.44

N 2 O 2.6

GT -4 GT -4 CT Combined Cycle CO 2 1,459,718

1,472,228 CH 4 469.44

N 2 O 2.6

FWP -1 FWP -1 Firewater Pump CO 2 11.55

11.59 Good Combustion and Operating Practices

Limit to 52 hr/yr - Special Condition III .B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

FWP -2 FWP -2 Firewater Pump CO 2 11.55

11.59 Good Combustion and Operating Practices

Limit to 52 hr/yr - Special Condition III .B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

EG -1 EG -1 Emergency Generator CO 2 26.71

26.82 Good Combustion and Operating Practices

Limit to 52 hr/yr - Special Condition III .B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

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

EG -2 EG -2 Emergency Generator CO 2 26.71

26.82 Good Combustion and Operating Practices

Limit to 52 hr/yr - Special Condition III .B.2. CH 4 No Emission Limit Established 4

N 2 O No Emission Limit Established 4

FUG

NGAS FUG

NGAS Natural Gas Fugitives CO 2 No Emission Limit Established 5 No Emission Limit Established 5 AVO monitoring - Special Condition III.C.1.
CH 4 No Emission Limit Established 5

FUG

SF6 FUG

SF6 Electric Equipment Fugitives SF 6 No Emission Limit Established 6 No Emission Limit Established 6 Instrument monitoring and alarm system - Special Condition III .C.3.

Totals 7 CO 2 5,838,948

5,889,434 CH 4 1,894
N 2 O 10.40
SF 6 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): CH 4 = 25, N 2 O = 298, SF 6 = 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. Fu gitive process emissions from EPN FUG are estimated to be 16.64 TPY of CH 4, 0.08 TPY CO 2 , and 418 TPY
CO 2 e. 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. SF 6 emissions from EPN FUG

- SF6 are estimated to be 0.0012 TPY SF 6 and 26.4 TPY CO 2 e. Fugitive process emission totals are for information only and do not constitute an emission limit. The emission limit will be a desig n/work practice standard as specified in the permit.
8. The total emissions for CH 4 and CO 2 e include the PTE for process fugitive emissions of CH 4. Total emissions are for information only and do not constitute an emission limit.2

2

2

2

2 5

7

7 Appendix B

F GE T ex as P r oject
GHG BA CT Anal y sis

Conce p tual Carbon Captu r e and Seque s t r a tio n Co s t E stim a t e (Upd at ed: 03/09/14)

P o s t

- -- C o m bu s ti on C O 2 Captu r e and Comp r ession E quip me n t

Pla n t Output (kW) 1 = 1,621,462

T o t al He a t Input, HHV (mm B tu/hr) 1 = 10,786

2 C O 2 Captu r e d 3,919,629 Capture and Compression Co s t B re a k down
Capi t al 3 $878.84/kW $1,425,005,664

Annual O&M (Fi x ed) 3 $22.61/kW $36,661,256

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

T o t al Annual O &M Co s ts Fi x ed + V ar iabl e $54,821,630

Annual Fuel 4 14.7% fuel use a t $2.77/mm B tu $38,473,494

C O 2 T r anspo rt

- -- Pi p el in e Co s t B r ea k do wn
L

, Pipeline Len g th (miles) = 100

D

, Pipeline Diame t er (inches) = 10 Pipeline Co s ts

M at erials $70,350 + $2.01 x L x (330.5 x D 2 + 686.7 x D + 26,960) $13,512,627

Labor $371,850 + $2.01 x L x (343.2 x D 2 + 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 Rig h t of W a y $51,200 + $1.28 x L x (577 x D + 29,788) $4,602,624

Other Capi t al

C O 2 Su rg e T ank $1,244,724 $1,244,724
Pipeline Co n t r ol Syst em $111,907 $111,907

T o t al Pipeline Capi t al Co s t 6 $82,574,206

O&M

Fi x ed O&M ($/ y ear) $8454 x L $879,216

C O 2 T r anspo r t ($/ y ear ) C O 2 T r ansport

- -- Comp r ession Co s t B r ea k do wn
$3.32 x t on C O 2 c aptu r ed/ y ear $13,533,694

E OR R e v e nu e
E OR R e v enue ($/ y ear) 8 $9.09 x t on C O c aptu r ed/ y ear $17,814,713

C O 2 S t o r a g e ($/ y ear ) Non

- -- E OR/Ge olo g i c S t o r a g e C o s t s $6.06 x t on C O 2 c aptu r ed/ y ear $24,703,069

Capi t al R e c o v ery F a c t o r % of P r oject Funded by E quity (%)

% of P r oject Funded by Debt (%)

Co s t of E quity (%)

Co s t of Debt (%) 49

51

20

7

W eig ht ed Co s t of Capi t al (%) 9 13.37

E quipme n t Li f e time ( y ea r s) 20
Capi t al R e c o v ery F ac t or 10 0.1455

Annuali z ed Co s t Esti m at e T o t al Capi t al Co s t ($) $1,507,579,870

Annuali z ed Capi t al Co s t ($) 11 $219,398,315

T o t al Annuali z ed Co s t

- -- non E OR ($) $351,809,418

T o t al Annuali z ed Co s t

- -- E OR ($) $321,643,171

C O 2 Co s t E ff e cti v e n e ss

- -- non E OR ($/ t on) 90

C O 2 Co s t E ff e cti v e n e ss ($/ t on)

- -- E OR ($/ t on) 82

1 A l st om tu r bin e p er f o r manc e d at a r e p r e s e n ts th e m a ximum v alu e f r om all no r mal and L L OC op e rati n g sc e n ar io s

.

2 F o r th e pu r pos e s of th e c onc e ptual c o s t e stim at e, th e t ons of C O 2 c aptu r e d is bas e d on th e a v e r a g e C O 2 e mission r at e r e p r e s e nt e d b y th e A l st om

turbine per f ormance d at a during base load c onditi ons (100% Load) op e ratin g 8,000 hou r s with an assumed C O 2 c aptu r e r at e of 8 5%.

3 A dap t e d f r om Co s t and P er f o r man c e Bas e lin e f o r F ossil E n er gy P la n ts
, V

olume 1 : Bituminous and N atu r al Gas t o El e ctricit y , DOE/2010/1397 ( R e vision 2, No v ember 2010). The di ff e r ence in the pla n t ($779/kW) and O&M (fi x ed = $20.039/kW and v ariable = $0.00124/kWh) c o s ts bet w een Case 14 ( N GCC w/ CCS) and Case 13 (NGCC w / o CCS) w as used t o e stim at e the c api t al c o s t of the CCS c aptu r e and c omp r ession equipme n t f or the F GE T e x as P r oj e ct. Capi t al c o s ts adju st ed using the U .S. BLS CPI I n fl ation Calcul at or f r om 2007 ($779/kW) t o 2014 dolla r s ($878.84/kW) (http : //ww w .bls

. g o v /d at a/

i n flation_ c alcul at o r

. h tm). O&M c o s ts adju st ed using the U .S. BLS CPI I n fl ation Calcul at or f r om 2007 ($20.039/kW and $0.00124/kWh) t o 2014 doll a r s ($22.61/kW and $0.0014/ kW h).

4 Fuel c o s ts r ep r ese n t the additi onal fuel necessary t o c ompens at e f or p a r asitic load c aused by the additi on of CCS. Based on r eview of the pla n t h e a t

r at es used in Case 13 and 14 p r ese nt ed in Co s t and P er f ormance Baseline F or F ossil Ene r gy Pla n ts, V olume 1: Bituminous and N a tu r al Gas t o El e c tr ici t y , DOE/2010/1397 ( R evision 2, No v ember 2010), CCS imposes a 14.7% inc r ease in the pla n t he a t r at e. The re f o r e, 14.7% mo r e fuel w ould be necessary t o

meet the pla n t output.

5 Pipeline c api t al c o s t and O&M c o s ts based on e quations f r om DOE NETL anal y sis C O T r ansport, S t o r a g e & Moni t oring Co s ts Quality Guidelines f o r
Ene r gy Syst ems Studies, DOE/ N ETL

- -- 2013/1614 (Ma r ch 2013) uti lizin g pipeline len g th and diame t er v alues. Capi t al and O&M c o s ts multi pli e d by 1.04 t o

c o n v ert f r om 2011 t o 2014 dolla r s (http : //ww w .bls

. g o v /d at a/i n flati on

_ c alcul at o r

. h tm).

6 Sum of m at erials, labo r , miscellaneous, rig h t of w a y , C O su rg e t ank, and pipeline c o n t r ol s yst em c api t al c o s ts, multi pli e d by 1.04 t o c o n v ert f r om 2011

t o 2014 dolla r s (http : //ww w .bls

. g o v /d at a/i n flati on

_ c alcul at o r

. h tm).

7 C O t r ansport and st o r a g e c o s ts f r om DOE NETL anal y sis C O2 T ransport, S t orage & Moni t oring Co s ts Quality Guidelines f or E nergy S y st ems Studi e s , DOE/ N ETL

- -- 2013/1614 (Ma r ch 2013) using the T e x as lo c ation, E a s t T e x as basin as r e p r e sentative of t r ansport and st o r a g e c o s ts. T r ansport c o s t f or E a s t

T e x as basin w e r e li st ed as $3.65/ t onne ($3.32/ t on) in 2011 and st o r a g e c o s t f or the E a s t T e x as basin w e r e li st ed a t $6.06/ t onne ($5.51/ t on) in 2011. Capi t al c o s ts multi pli e d by 1.04 t o c o n v ert f r om 2011 t o 2014 dolla r s (http : //ww w .bls

. g o v /d at a/i n flati on

_ c alcul at o r

. h tm).

8 US price f r om sale of C O f or Enhanced Oil R e c o v ery ( E OR) is $10

- -- 40/ t onn e ($9.09/ t on

- -- $36.36/ t on) ob t ained f r om Global CCS Insti tu t e ’ s r eport, Th e

Global S ta tus of CCS, Chap t er 9

– C O 2 E nhan c ed Oil R e c overy as CCS

, S e ction 9.2

– P o t e ntial role of C O2 E OR in CC S

, pa g e 146 (2012). Once th e

c aptu r ed C O 2 in the pipeline r eaches the oil p r oduce r s in the nea r e s t E OR mar k ets (100 miles t o the w e s t); F GE is uncer t ain of the ability f or e xistin g

E OR mar k ets and the a v ailability of other e xistin g pipelines t o accept the v olume of C O 2 p r oduced by the F GE p r oject. The re f o r e, it has been assum e d

f or the purposes of this c alculati on th a t F GE w ould be able t o sell 50% of its c aptu r ed C O 2 . http : / / cdn

. g lobalccsinstitu t e

. c om / si t e s/d e f ault/fil e s/publi cati ons/47936 / g lobal

- sta tus

- ccs

- 2012.pdf

9 W e i g ht e d c o s t of c api t al c alcul at e d b y summin g th e p r oducts of th e w e i g ht e d a v e r a g e s of th e di ff e r e n t financin g c ompon e n ts with th e c o s t of th e

p arti cul ar fi nancing c ompon e n t.

10 Capi t al r e c o v ery f ac t o r c alcul at e d v ia th e f ollowin g e quation :

CRF= (i 〖 (1+i) 〗 ^n)/ ( 〖 (1+i) 〗 ^n−1) with :
CFR = c api t al r e c o v ery f ac t o r i = w eig ht ed c o s t of c api t al (i nt e r e s t r at e )

n = number of y ea r s o v er which p r oject is annuali z e d

1 1 Annuali z ed c api t al c o s t c alcul at ed by multi pl y in g the t o t al c api t al c o s t by the c api t al r e c o v ery f ac t o r

.