PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

FOR GREENHOUSE GAS EMISSIONS 

ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 6 

PSD PERMIT NUMBER: PSD-TX-1298-GHG 

PERMITTEE: Pinecrest Energy Center, LLC 

3608 Preston Road, Suite 225 

Plano, TX 75093 

FACILITY NAME: · Pinecrest Energy Center, LLC 

Pinecrest Energy Center (PEC) 

FACILITY LOCATION: 1002 East Park Avenue 

Lufkin, TX 75904 

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C ( 42 U.S.C. 

§ 7470, et seq.), and the Code of Federal Regulations (CFR) Title 40, Section 52.21, and theFederal Implementation Plan at 40 CFR § 52.2305 (effective May 1, 2011 and published at 76 

FR 25178), the U.S. Environmental Protcx:tion Agency, Region 6 is issuing a Prevention of 

Significant Deterioration (PSD) permit to Pinecrest Energy Center, LLC (Pinecrest) for 

greenhouse gas (GHG) emissions. The permit applies to the construction of a new natural gas 

fired combined cycle electric generating plant, Pinecrest Energy Center (PEC), to be located near 

Lufkin, Angelina County, Texas. 

Pinecrest is authorized to construct a new natural gas fired combined cycle electric generating 

plant as described herein, in accordance with the permit application (and plans submitted with 

the permit application), the federal PSD regulations at 40 CFR § 52.21, and other terms and 

conditions set forth in this PSD permit in conjunction with the corresponding Texas Commission 

on Environmental Quality (TCEQ) PSD pennit No. PSD-TX-1298. Failure to comply with any 

condition or term set f011h in this PSD permit may result in enforcement action pursuant to 

Section 113 of the Clean Air Act (CAA). This PSD permit does not relieve Pinecrest of the 

responsibility to comply with any other applicable provisions of the CAA (including applicable 

implementing regulations in 40 CFR Parts 51, 52, 60, 61, 72 through 75, and 98) or other federal and 

state requirements (including the state PSD program that remains under approval at 40 CFR 

§ 52.2303). 

In accordance with 40 CFR § 124.1 5(b)(3), this PSD Permit becomes effective immediately 

upon issuance of this fi 1 decision. 

_ A- I U I 

Wren Stenger, Director Date 

Multimedia Planning and Pennitting Division 
2 

Pinecrest LLC (PSD-TX-1298-GHG) 

Prevention of Significant Deterioration Permit 

For Greenhouse Gas Emissions

Final Permit Conditions

PROJECT DESCRIPTION

Pinecrest Energy Center is proposing to construct a new combined cycle electric generating 

plant (PEC) in Angelina County, Texas. PEC will generate 637 - 735 megawatts (MW) of 

gross electrical power near the City of Lufkin. The PEC will consist of the following sources 

of GHG emissions: 

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

combustors;

• Two natural gas-fired duct burner systems; 

• Natural gas piping and metering; 

• One diesel fuel-fired emergency electrical generator engine;

• One diesel fuel-fired fire water pump engine;

• One natural gas-fired auxiliary boiler; and 

• Electrical equipment insulated with sulfur hexafluoride (SF6).

EQUIPMENT LIST

The following devices are subject to this GHG PSD permit.

FIN EPN Description

CTG1/HRSG1

CTG2/HRSG2

U1-STK 

U2-STK

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

The combustion turbines are equipped with heat recovery steam generators

(HRSG) and selective catalytic reduction (SCR).

AUXBLR AUXBLR

1 Auxiliary Boiler (Combustion Unit). The boiler has a maximum design heat

input rate of 150 MMbtu/hr, and is fired with natural gas.

FWP1 FWP1-STK

1 Fire Water Pump (Combustion Unit). 500 horsepower (hp) Diesel-Fired Fire

Water Pump rated at 3.4 MMBtu/hr and limited to 100 hours of operation per 

year for non-emergency activities.

EMGEN1

EMGEN1-

STK

1 Emergency Generator (Combustion Unit). 1,072 horsepower (hp) Diesel-Fired

Emergency Generator rated at 7.9 MMBtu/hr and limited to 100 hours of 

operation per year for non-emergency activities.

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

capacity.

NG-FUG NG-FUG Process Fugitives.
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; 

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

3. is not completed within a reasonable time. 

Pursuant to 40 CFR § 52.21(r), EPA may extend the 18-month period upon a written satisfactory 

showing that an extension is justified. 

B. PERMIT NOTIFICATION REQUIREMENTS

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

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

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

such date; and 

3. date upon which initial performance tests will commence, in accordance with the 

provisions of Section VI, postmarked not less than 30 days prior to such date.

Notification may be provided with the submittal of the performance test protocol required 

pursuant to Condition VI.C.

C. FACILITY OPERATION

At all times, including periods of startup, shutdown, and maintenance, Permittee shall, to the 

extent practicable, maintain and operate the facility including associated air pollution control 

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

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

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

monitoring results, review of operating maintenance procedures and inspection of the facility. 
4 

D. MALFUNCTION REPORTING

1. Permittee shall notify EPA by mail within 48 hours following the discovery of any failure 

of air pollution control equipment, process equipment, or of a process to operate in a 

normal manner, which results in an increase in GHG emissions above the allowable 

emission limits stated in Sections II and III of this permit.

2. Within 10 days of the restoration of normal operations after any failure described in 

I.D.1., Permittee shall provide a written supplement to the initial notification that includes 

a description of the malfunctioning equipment or abnormal operation, the date of the 

initial malfunction, the period of time over which emissions were increased due to the 

failure, the cause of the failure, the estimated resultant emissions in excess of those 

allowed in Section II and III, and the methods utilized to mitigate emissions and restore 

normal operations. 

3. Compliance with this malfunction notification provision shall not excuse or otherwise 

constitute a defense to any violation of this permit or any law or regulation such 

malfunction may cause.

E. RIGHT OF ENTRY

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

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

kept under the terms and conditions of this PSD permit;

2. during normal business hours, to have access to and to copy any records required to be 

kept under the terms and conditions of this PSD permit;

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

permit; and,

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

F. TRANSFER OF OWNERSHIP

In the event of any changes in control or ownership of the facilities to be constructed, this PSD 

permit shall be binding on all subsequent owners and operators. Permittee shall notify the 

succeeding owner and operator of the existence of the PSD permit and its conditions by letter; a 

copy of the letter shall be forwarded to EPA Region 6 within thirty days of the letter signature.
5 

G. SEVERABILITY

The provisions of this PSD permit are severable, and, if any provision of the PSD permit is held 

invalid, the remainder of this PSD permit shall not be affected.

H. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LAWS

Permittee shall construct this project in compliance with this PSD Permit, the application on 

which this permit is based, the TCEQ PSD permit PSD-TX-1298 (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

API American Petroleum Institute BACT

Best Available Control Technology 

BSCFD Billion Standard Cubic Feet per Day 

CAA Clean Air Act

CC Carbon Content

CCS Carbon Capture and Sequestration 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

CT Combustion Turbine

DLNB Dry Low-NOx Burner 

dscf Dry Standard Cubic Foot 

EF Emission Factor 

EPN Emission Point Number

FIN Facility Identification Number

FR Federal Register 

GHG Greenhouse Gas 

gr Grains

GWP Global Warming Potential 

HHV High Heating Value 

hr Hour

LAER Lowest Achievable Emission Rate 

lb Pound

LDAR Leak Detection and Repair 

MMBtu Million British Thermal Units

MSS Maintenance, Start-up and Shutdown 

mtpa Million Tons per Annum 

NNSR Nonattainment New Source Review 

N2O Nitrous Oxides

NOx Nitrogen Oxides

NSPS New Source Performance Standards 

PSD Prevention of Significant Deterioration 

QA/QC Quality Assurance and/or Quality Control 

SCFH Standard Cubic Feet per Hour

SCR Selective Catalytic Reduction 

SF6 Sulfur Hexafluoride

TAC Texas Administrative Code 

TCEQ Texas Commission on Environmental Quality 

TPY Tons per Year

USC United States Code 

VOC Volatile Organic Compound 
7 

FIN EPN Description

GHG Mass Basis TPY 

CO e

2,3 BACT Requirements

TPY

2

CTG1/HRSG1 U1-STK

Combined Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4

CO2 1,446,186

1,447,653

942.0 lb CO2/MWh (gross) 

with duct burning.

5

See 

Special Condition III.A.1.

Startup emissions limited to

500 hours per year and 83 tons

CO2/hr. See Special 

Conditions III.A.1. and 

III.A.4.e.

CH4 26.8

N2O 2.7

CTG2/HRSG2 U2-STK

Combined Cycle 

Combustion 

Turbine/Heat 

Recovery Steam 

Generator4

CO2 1,446,186

1,447,653

942.0 lb CO2/MWh (gross) 

with duct burning.

5

See 

Special Condition III.A.1.

Startup emissions limited to

500 hours per year and 83 tons

CO2/hr. See Special 

Conditions III.A.1. and 

III.A.4.e.

CH4 26.8

N2O 2.7

AUXBLR AUXBLR Auxiliary Boiler

CO2 7,680

7,687

Good Combustion and

Operating Practices. Limit to

876 hours of operation per 

year. See Special Conditions 

III.B.

CH4 0.14

N2O 0.01

EMGEN1 EMGEN1

-STK

Emergency

Generator

CO2 64

 64

Good Combustion and

Operating Practices. Limit to

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No

Numerical 

Limit 

Established

6

N2O

No

Numerical 

Limit 

Established

6

FWP1 FWP1-

STK Fire Water Pump

CO2 28

 28

Good Combustion and

Operating Practices. Limit to

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No

Numerical 

Limit 

Established

6

N2O

No

Numerical 

Limit 

Established

6

II. Annual Emission Limits

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

following if the General Electric 7FA.05 is selected as the combustion turbine model:

Table 1A. Annual Emission Limits1 

- General Electric 7FA.05

2
8 

FIN EPN Description

GHG Mass Basis TPY

CO e

2,3 BACT Requirements

TPY

2

NG-FUG NG-FUG Natural Gas

Fugitives 6,8

CO2

0.81

510 Implementation of AVO 

Monitoring. See Special 

CH4 Condition III.D. 20.4

SF6-FUG SF6-FUG SF6 Insulated

Equipment6 SF6

No

Numerical 

Limit 

Established

6

 23

Instrumented monitoring and 

alarm. See Special condition 

III.D.

Totals

7 CO2 2,900,145

2,903,627

CH4 74

N2O 5.4

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

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

from the facility during all operations and include MSS activities. 

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

4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 

8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 

The annual emission limit includes emissions from MSS.

5. The lb/MWh BACT limit for the combustion turbine does not apply during startup. 

6. All values indicated as “No Numerical Limit Established” are less than 0.01 TPY with appropriate rounding. 

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

7. The total emissions for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

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

8. EPN NG-FUG includes fugitive emissions from piping and other components, as well as emissions from gaseous 

fuel line purging and maintenance/repair/replacement of fugitive components.
9 

FIN EPN Description

2

GHG Mass Basis TPY

CO e

2,3 BACT Requirements

TPY

2

CTG1/HRSG1 U1-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4

CO2 1,398,427

1,399,842

909.2 lb CO2/MWh (gross) 

with duct burning.

5

See 

Special Condition III.A.1.

Startup emissions limited to

500 hours per year and 84

tons CO2/hr. See Special 

Conditions III.A.1. and 

III.A.4.e.

CH4 25.9

N2O 2.6

CTG2/HRSG2 U2-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4

CO2 1,398,427

1,399,842

909.2 lb CO2/MWh (gross) 

with duct burning.

5

See 

Special Conditions III.A.1.

Startup emissions limited to

500 hours per year and 84 

tons CO2/hr. See Special 

Conditions III.A.1. and 

III.A.4.e.

CH4 25.9

N2O 2.6

AUXBLR AUXBLR

Auxiliary

Boiler

CO2 7,680

7,687

Good Combustion and

Operating Practices. Limit to

876 hours of operation per 

year. See Special Conditions 

III.B.

CH4 0.14

N2O 0.01

EMGEN1 EMGEN1

-STK

Emergency

Generator

CO2 64

 64

Good Combustion and

Operating Practices. Limit to

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No

Numerical 

Limit 

Established

6

N2O

No

Numerical 

Limit 

Established

6

FWP1 FWP1-

STK

Fire Water

Pump

CO2 28

28

Good Combustion and

Operating Practices. Limit to

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No

Numerical 

Limit 

Established

6

N2O

No

Numerical 

Limit 

Established

6

NG-FUG NG-FUG Natural Gas

Fugitives6

CO2

0.81

510 Implementation of AVO 

Monitoring. See Special 

CH4 Condition III.D. 20.4

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

the Siemens SGT6-5000F(4) is selected as the combustion turbine model:

Table 1B. Annual Emission Limits1- Siemens SGT6-5000F(4)
10

FIN EPN Description

2

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements

TPY

2

SF6-FUG SF6-FUG SF6 Insulated

Equipment

SF6

No

Numerical 

Limit 

Established

6

 23

Instrumented monitoring and 

alarm. See Special condition 

III.D.

Totals

7 CO2 2,804,627 2,808,007 CH4 72.3

N2O 5.2

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

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

from the facility during all operations and include MSS activities. 

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

4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 

8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 

The annual emission limit includes emissions from MSS.

5. The lb/MWh BACT limit for the combustion turbine does not apply during startup. 

6. All values indicated as “No Numerical Limit Established” are less than 0.01 TPY with appropriate rounding. The 

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

7. The total emissions for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

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

8. EPN NG-FUG includes fugitive emissions from piping and other components, as well as emissions from gaseous 

fuel line purging and maintenance/repair/replacement of fugitive components.
11

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

following if the Siemens SGT6-5000F(5) is selected as the combustion turbine model:

Table 1C. Annual Emission Limits1 

- Siemens SGT6-5000F(5) 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements

TPY

2

U1-STK U1-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4

CO2 1,569,269

1,570,854

912.7 lb CO2/MWh (gross) 

with duct burning.

5

See 

Special Condition III.A.1.

Startup emissions limited to

500 hours per year and 85

tons CO2/hr. See Special 

Conditions III.A.1. and 

III.A.4.e.

CH4 29

N2O 2.9

U2-STK U2-STK

Combined 

Cycle 

Combustion 

Turbine/Heat 

Recovery 

Steam 

Generator4

CO2 1,569,269

1,570,854

912.7 lb CO2/MWh (gross) 

with duct burning.

5

See 

Special Conditions III.A.1.

Startup emissions limited to

500 hours per year and 85 

tons CO2/hr. See Special 

Conditions III.A.1. and 

III.A.4.e.

CH4 29

N2O 2.9

AUXBLR AUXBLR

Auxiliary

Boiler

CO2 7,680

7,687

Good Combustion and

Operating Practices. Limit to

876 hours of operation per 

year. See Special Conditions 

III.B.

CH4 0.14

N2O 0.01

EMGEN1 EMGEN1

-STK

Emergency

Generator

CO2 64

 64

Good Combustion and

Operating Practices. Limit to

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No

Numerical 

Limit 

Established

6

N2O

No

Numerical 

Limit 

Established

6

FWP1 FWP1-

STK

Fire Water

Pump

CO2 28

 28

Good Combustion and

Operating Practices. Limit to

100 hours of operation per 

year. See Special Conditions 

III.C.

CH4

No

Numerical 

Limit 

Established

6

N2O

No

Numerical 

Limit 

Established

6

NG-FUG NG-FUG Natural Gas

Fugitives 6,8

CO2

0.8

510 Implementation of AVO 

Monitoring. See Special 

CH4 Condition III.D. 20.4
12

FIN EPN Description

GHG Mass Basis TPY 

CO e

2,3 BACT Requirements

TPY

2

SF6-FUG SF6-FUG SF6 Insulated

Equipment

SF6

No

Numerical 

Limit 

Established

6

23

Instrumented monitoring and 

alarm. See Special condition 

III.D.

Totals

7 CO2 3,146,311 3,150,030 CH4 78.7

N2O 5.8

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

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

from the facility during all operations and include MSS activities. 

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

4. The annual emissions limit for the combustion turbines is based on operating at maximum duct burner firing for 

8,260 hours per year, and operating during startup, shutdown, and maintenance (MSS) for 500 hours per year. 

The annual emission limit includes emissions from MSS.

5. The lb/MWh BACT limit for the combustion turbine does not apply during startup. 

6. All values indicated as “No Numerical Limit Established” are less than 0.01 TPY with appropriate rounding. 

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

7. The total emissions for CH4 and CO2e include the PTE for process fugitive emissions of CH4. Total emissions 

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

8. EPN NG-FUG includes fugitive emissions from piping and other components, as well as emissions from gaseous 

fuel line purging and maintenance/repair/replacement of fugitive components. 
13

III. SPECIAL PERMIT CONDITIONS

A. Requirements for Combustion Turbine Generators (CTG) and Heat Recovery Steam

Generators (HRSG) (EPNs: U1-STK and U2-STK)

The Permittee shall comply with Table 1A, 1B, or 1C depending on the selection of 

manufacturer and model of combined cycle combustion turbine selected. Upon selection of 

a combustion turbine model, Pinecrest must submit a permit application amendment to 

remove the turbine models not selected. 

1. Combustion Turbine Generator (CTG) BACT Emission Limits

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

Turbine Model

Gross Heat Rate, with 

duct burner firing 

(Btu/kWh) (HHV)

Output Based

Emission Limit (lb 

CO2/MWh) gross 

with duct burning

Startup Emission

Limit (tons 

CO2/hr)

General Electric 7FA.05 7,925.0 942.0 83

Siemens SGT6-5000F(4) 7,649.0 909.2 84

Siemens SGT6-5000F(5) 7,679.0 912.7 85

a. Within 60 days after achieving the maximum production rate at which the 

affected facility will be operated, but not later than 180 days of the date of 

initial startup of the combustion turbine generators, the Permittee shall perform 

an initial emission test for CO2 and use emission factors from 40 CFR Part 98. 

The Permittee shall ensure that GHG emissions from the Combustion Turbine 

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

atmosphere do not exceed the limits in lbs CO2/MWh (gross) from Table 2 

during the test. To determine this BACT emission limit, Permittee shall 

calculate the limit based on the measured hourly energy output (MWh (gross))

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 (59o

F, 14.7 

psia, and 67% humidity). If the CTG does not meet the design emissions limit, 

then the Permittee shall remedy the CTG’s failure to meet the design emissions 

limit, will make corrections to the CTG, and will only combust fuel to perform 

required tuning and modifications necessary to demonstrate compliance.

b. The hourly gross electric output from the steam turbine shall be apportioned based 

on either the measured steam load or measured heat input. A plan to demonstrate the 

apportionment of the gross electric output shall be submitted 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 generator. 
14

c. The CO2 mass emission values shall be calculated over each operational hour of the 

compliance period and summed. The summed hourly CO2 mass emission values 

shall be divided by the combined sum of the total gross electrical output from the 

steam turbine (as determined by the corresponding apportionment calculations 

represented in the plan) and the total gross electrical load from the combustion 

turbine generator. The resulting quotient is added to the sum of quotients of the 

previous 11 operating months and divided by 12 to determine compliance with the 

12-month rolling average. 

d. Upon initial demonstration that the combustion turbine complies with the emission 

limit via emission tests, the Permittee shall not exceed the combustion turbine and 

duct burner annual firing rate, Btu/kWh (HHV) from Table 2 on a 12-month rolling 

average. To determine the limit, the Permittee shall calculate the average hourly heat 

input rate over the applicable compliance period consistent with equation F-20 and 

procedure provided in 40 CFR Part 75, Appendix F § 5.5.2 and the GCV of the fuel 

combusted for the corresponding compliance period. Add the quotient to the sum of 

the quotients of the previous 11 operating months and divide by 12 to determine the 

12-month rolling average. 

e. The Permittee shall not discharge or cause the discharge of emissions into the 

atmosphere in excess of the limits in tons of CO2e on a 12-month rolling total as 

listed in Table 1. 

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

a. Upon initial demonstration that the combustion turbine generators are in 

compliance with the emissions limit via an emission test, the Permittee shall not 

discharge or cause the discharge of emissions from the Combustion Turbine 

Generator (CTG) and heat recovery steam generator (HRSG) (EPNs U1-STK and 

U2-STK) into the atmosphere in excess of limits in tons of CO2e on a 12-month 

rolling average as listed in Table 1A, 1B, or 1C, at all times including periods of 

startup and shutdown. To determine the amount of CO2e, the Permittee shall 

calculate the amount of CO2, CH4 and N2O in tpy based on the equation G-4 of 40 

CFR 75, Appendix G and 40 CFR Part 98, Appendix C. The tpy values are 

multiplied by the respective Global Warming Potentials (GWP) contained in the 

Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 to calculate 

the amount of CO2e emitted in Tons/hr for the operational month. The resulting 

CO2e value is added to the previous 11 months to determine the 12 month rolling 

total of CO2e emissions. The Permittee shall determine compliance with the CH4 

and N2O emissions on a 12-month rolling total. The Permittee shall determine 

compliance with the CH4 and N2O emissions limits contained in Section II using 

the default CH4 and N2O emission factors contained in Table C-2 of 40 CFR Part 

98 and the measured actual hourly heat input (HHV). 
15

b. As an alternative, the Permittee may install and operate a volumetric stack gas flow 

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

CO2 CEMS system provided in 40 CFR § 75.10(a)(3) and (a)(5). If a CO2 CEMS 

system is utilized, the hourly CO2 emission value shall be measured by installing and 

operating a volumetric stack gas flow monitor or calculating the volumetric stack gas 

flow by the procedures of 40 CFR Part 75, Appendix D and associated data 

acquisition and handling system in accordance with the CO2 CEMS system provided 

in 40 CFR § 75.10. 

c. In accordance with 40 CFR Part 75, Appendix D and 40 CFR Part 60, the Permittee 

shall ensure that all required fuel flow meters are installed, a periodic schedule for 

GCV fuel sampling is initiated and all certification tests are completed on or before 

the earlier of 90 unit operating days or 180 calendar days after the date the unit 

commences commercial operation (as defined in 40 CFR § 72.2). 

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

fuel flow meter and/or CO2 emission monitoring system at stationary sources, 40 

CFR Part 75 and 40 CFR Part 60. 

e. The Permittee shall meet the appropriate quality assurance requirements specified in 

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

and/or CO2 emission monitoring system. 

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

Requirements

a. The combined cycle combustion turbine and duct burners are limited to burning only 

pipeline natural gas. 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 combustion turbine and/or duct burners or shall allow a sample to be 

taken by EPA for analysis. 

b. The flow rate of the fuel combusted in the combustion turbine and duct burners shall 

be measured and recorded using an in-line flow meter and automatically record the 

data with a data acquisition and handling system. The steam load and/or heat input to 

the steam turbine shall also be measured and recorded. 

c. The Permittee shall measure and record the energy output (MWh, gross) on an 

hourly basis. 

d. 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 PSDTX1298. 

e. The Permittee shall perform an annual compliance test, at or above 90% of 

maximum load operations for the atmospheric conditions which exist during testing, 
16

corrected to ISO conditions to demonstrate compliance with the proposed heat rate 

in Table 2. 

f. On or after initial performance testing, the Permittee shall use BACT practices and 

designs represented in the permit application. 

4. Requirements during Combustion Turbine (EPNs: U1-STK and U2-STK) 

Startup and Shutdown

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

operating and maintaining the facility and associated air pollution control equipment 

in accordance with good air pollution control practices, safe operating practices, and 

protection of the facility. 

b. Emissions during startup and shutdown activities shall be minimized by limiting 

the duration of operation in startup and shutdown mode as follows: 

i. A startup is defined as the period that begins when the data acquisition and 

handling system measures fuel flow to the combustion turbine and ends when the 

combustion turbine generator load reaches 60 percent. A planned startup for each 

combustion turbine is limited to 360 minutes per event. 

ii. A shutdown is defined as the period that begins when the combustion 

turbine generator output drops below 60 percent load and ends when there is no 

longer measureable fuel flow to the combustion turbine. A planned shutdown of 

the combustion turbine is limited to 60 minutes per event. 

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

Table 2.

d. The maximum heat input shall be limited to the values identified in Table 3

during startup. 

e. Startups are limited to 500 hours on a 12-month rolling basis. 

f. The startup emissions and heat input limits are also shown in Table 3 below.

Table 3. Startup Emissions and Heat Input Limitations

Turbine Model

BACT Emission

Limit (tons CO2/hr)

Annual Emission

Limit (tons CO2e/yr)

Maximum Heat Input

(MMBtu/hr)

GE 7FA.05 83 41,678 1401.2

SGT6-5000F(4) 84 41,847 1406.9

SGT6-5000F(5) 85 42,475 1428.0

g. Permittee must record the time, date, fuel heat input (HHV) in MMBtu/hr and 

duration of each startup and shutdown event in order to calculate total CO2e 

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

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

stack gas flowrate) and the calculations based on the actual heat input for the 

CO2, CO2e, O2, N2O, and CH4 emissions during each startup and shutdown 
17

event based on the equations represented in the permit application. These records 

must be kept for five (5) years following the date of such event. 

h. The 12-month rolling average BACT emission limitations in Special Condition 

III.A.1. does not include periods of startup. 

B. Requirements for Auxiliary Boiler (EPN: AUXBLR)

1. Boiler shall combust only pipeline quality natural gas. 

2. Permittee shall measure and record the fuel flow rate using an inline flow meter and 

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

3. Permittee shall calibrate and perform preventative maintenance check of the fuel 

gas flow meters and document annually. 

4. Permittee shall perform cleaning of the burner tips annually, at a minimum. 

5. Permittee shall perform cleaning of the convection section tubes annually, at a 

minimum. 

6. The maximum firing rate for the auxiliary boiler shall not exceed 150 MMBtu/hr. 

7. The one-hour maximum firing rate shall be calculated daily to demonstrate 

compliance with the firing rate in III.B.6. 

8. Total firing hours of the auxiliary boiler must not exceed 876 hours per year. 

9. Records of firing hours shall be recorded daily. A 12-month rolling total of boiler 

hours of operation shall be calculated to demonstrate compliance with the limitation 

of hours in III.B.8. 

10. Permittee shall install, operate, and maintain an automated air/fuel control system. 

11. Permittee shall calibrate and perform preventative maintenance on the air/fuel 

control analyzers once per quarter, at a minimum. 

12. Permittee shall install, operate, and maintain an O2 analyzer on the boiler. 

13. Oxygen analyzers shall continuously monitor and record oxygen concentration in 

the boiler. It shall reduce the oxygen readings to an averaging period of 6 minutes 

or less and record it at that frequency. 

14. The oxygen analyzers shall be quality-assured at least quarterly using cylinder 

gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 

5.1.2, with the following exception: a relative accuracy test audit is not required 

once every four quarters (i.e., four successive quarterly CGAs may be conducted). 

15. Compliance with the Annual Emission Limit shall be demonstrated on a 12- 

 month total, rolling monthly, calculated in accordance with 40 CFR 

§ 98.33(a)(1)(i). 

C. Requirements for the Fire Water Pump (EPN: FWP1-STK) and Emergency Generator

(EPN: EMGEN1-STK)

1. The Fire Water Pump (FWP1-STK) and Emergency Generator (EMGEN1-STK) are 

authorized to fire diesel fuel containing no more than 0.5 percent sulfur by weight. 
18

Upon request, Permittee shall provide a sample and/or an analysis of the fuel-fired in the 

emission units (EMGEN1-STK and FWP1-STK) or shall allow a sample to be taken by 

EPA for analysis to demonstrate the percent sulfur of the fuel.

2. The Fire Water Pump and Emergency Generator are limited to 100 hours of nonemergency operation per year for each unit and a heat input value of 3.4 MMBtu/hr and 

7.9 MMBtu/hr for the Fire Water Pump and the Emergency Generator, respectively. 

Compliance with the 100 hour non-emergency operational requirement is determined 

on a 12-month rolling basis. 

3. The Fire Water Pump and Emergency Generator shall meet the applicable monitoring 

and recordkeeping requirements as required in 40 CFR Part 60 Subpart IIII, Standards 

of Performance for Stationary Compression Ignition Internal Combustion Engines.

4. Permittee shall install and maintain an operational non-resettable elapsed time meter for 

the Fire Water Pump and Emergency Generator. 

5. Permittee shall maintain a file of all records, data measurements, reports and 

documents related to the operation of the Fire Water Pumps and Emergency 

Generator, including, but not limited to, the following: all records or reports 

pertaining to maintenance performed, all records relating to performance tests and 

monitoring of the emergency generator and fire pump equipment; for each diesel fuel 

oil delivery, documents from the fuel supplier certifying compliance with the fuel 

sulfur content limit of Special Condition III.C.1., fuel heat input values and hours of 

operation required in Special Condition III.C.2.; and all other information required by 

this permit recorded in a permanent form suitable for inspection. The file must be 

retained for not less than five years following the date of such measurements, 

maintenance, reports, and/or records. 

D. Requirements for Fugitive Emission Sources (EPNs: NG-FUG and SF6-FUG)

1. The Permittee shall implement an auditory/visual/olfactory (AVO) method for 

detecting leaking from natural gas piping components and make observations on a 

daily basis. 

2. For emission unit SF6-FUG, SF6 emissions shall be calculated annually (calendar 

year) in accordance with the mass balance approach provided in equation DD-1 of 

the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and 

Distribution Equipment Use, 40 CFR Part 98, Subpart DD. Permittee shall not 

exceed insulated circuit breaker SF6 capacity exceeding 400 lbs. 

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

pressure lockout. The SF6 leak detection system shall be able to detect a leak of at 

least 1 lb per year. 

4. Permittee shall maintain a file of all records, data measurements, reports and 

documents related to the fugitive emission sources including, but not limited to, the 

following: all records or reports pertaining to maintenance performed, all records 
19

relating to compliance with the Monitoring and Quality Assurance and Quality 

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

5. The Permittee provided data to show that minimal quantities of natural gas are 

released to the atmosphere during turbine fuel line shutdown maintenance and when 

performing repair or maintenance on small equipment and fugitive components. 

IV. RECORDKEEPING AND REPORTING

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

Permittee will monitor the following parameters and summarize the data on a calendar 

month basis. 

a. Operating hours for all air emission sources;

b. The natural gas fuel usage for all combustion sources, using continuous fuel flow 

monitors (a group of equipment can utilize a common fuel flow meter, as long as 

actual fuel usage is allocated to the individual equipment based upon actual 

operating hours and maximum firing rate); and

c. Annual fuel sampling for natural gas.

2. Permittee shall implement an AVO program and keep records of the monitoring results, 

as well as the repair and maintenance records. 

3. Permittee shall maintain all records, data, measurements, reports, and documents related 

to the operation of the facility, including, but not limited to, the following: all records or 

reports pertaining to significant maintenance performed on any system or device at the 

facility; duration of startup 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. Permittee shall maintain records of all GHG emission units and CO2 emission 

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

5. Permittee shall maintain records and submit a written report of all GHG excess emissions 

to EPA semi-annually, except when more frequent reporting is specifically required by an 

applicable subpart or the Administrator or authorized representative, on a case-by-case

basis, determines that more frequent reporting is necessary to accurately assess the 

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

each semi-annual period and shall include the following: 

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

known), corrective actions taken and preventive measures adopted; 
20

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

was inoperative (monitoring down-time); 

c. A statement in the report of a negative declaration, that is, a statement when no 

excess emissions occurred or when the monitoring equipment has not been 

inoperative, repaired or adjusted; and 

d. Any failure to conduct any required source testing, monitoring, or other compliance 

activities.

6. Excess emissions shall be defined as any period in which the facility emissions exceed a 

maximum emission limit set forth in this permit.

7. Excess emissions indicated by GHG emission source certification testing or compliance 

monitoring shall be considered violations of the applicable emission limit for the purpose 

of this permit.

8. All records required by this PSD permit shall be retained and remain accessible for not 

less than 5 years following the date of such measurements, maintenance, and reporting.

V. SHAKEDOWN PERIODS

The combustion turbine emission limits and requirements in conditions II., III.A.1., and III.B. 

shall not apply during combustion shakedown periods. Shakedown is defined as the period 

beginning with initial startup and ending no later than initial performance testing, during 

which the Permittee conducts operational and contractual testing and tuning to ensure the 

safe, efficient and reliable operation of the plant. The shakedown period shall not exceed the 

time period for performance testing as specified in 40 CFR § 60.8. The requirements of 

special condition I.C. of this permit shall apply at all times.

VI. PERFORMANCE TESTING

A. The Permittee shall perform stack sampling and other testing to establish the actual pattern 

and quantities of air contaminants being emitted into the atmosphere from the stacks of the 

Combustion Turbines and HRSGs (U1-STK and U2-STK) and the Auxiliary Boiler 

(AUXBLR) to determine the initial compliance with the CO2 emission limits established in 

this permit. Sampling shall be conducted in accordance with 40 CFR § 60.8 and EPA Method 

3a or 3b for the concentration of CO2.

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

operating test conditions by 8,760 hours for the combustion turbines and 876 hours 

for the auxiliary boiler. 

2. If the above calculated CO2 emission total does not exceed the TPY specified on 

Table 1, no compliance strategy needs to be developed. 

If the above calculated CO2 emission total exceeds the TPY specified in Table 1, the 

facility shall:
21

a. Document the potential to exceed in the test report; and

b. Explain within the report how the facility will assure compliance with the CO2

emission limit listed in Table 1.

B. Within 60 days after achieving the maximum production rate at which the affected facility 

will be operated, but not later than 180 days after initial startup of the facility, performance 

tests(s) must be conducted and a written report of the performance testing results furnished to 

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. Air emissions from each HRSG exhaust stack shall be tested while firing at the minimum 

load in the normal operating range. The normal operating range consistent with emission 

limits is to be determined during stack testing. Air emissions that will be sampled and 

analyzed while at the minimum load include (but are not limited to) CO2.

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

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

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

G. The owner or operator shall provide, or cause to be provided, performance testing facilities as 

follows: 

1. Sampling ports adequate for test methods applicable to this facility, 

2. Safe sampling platform(s),

3. Safe access to sampling platform(s), and 

4. Utilities for sampling and testing equipment. 

H. Unless otherwise specified, each performance test shall consist of three separate runs using 

the applicable test method. Each run shall be conducted for the time and under the 

conditions specified in the applicable standard. For purposes of determining compliance 

with an applicable standard, the arithmetic mean of the results of the three runs shall apply. 
22

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 



PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

i

TABLE OF CONTENTS

1.0 INTRODUCTION............................................................................................................. 1

FORM PI-1 GENERAL APPLICATION ....................................................................................... 2

2.0 PROJECT SCOPE........................................................................................................11

2.1 Introduction..........................................................................................................11

2.2 Combustion Turbine Generator............................................................................11

2.3 Heat Recovery Steam Generator.........................................................................12

2.4 Auxiliary Boiler.....................................................................................................12

2.5 Diesel Fired Emergency Equipment.....................................................................12

2.6 Natural Gas/Fuel Gas Piping ...............................................................................12

2.7 Electrical Equipment Insulated with Sulfur Hexafluoride (SF6) ..............................13

PROCESS FLOW DIAGRAM....................................................................................................14

PLOT PLAN..............................................................................................................................15

AREA MAP ...............................................................................................................................16

3.0 GHG EMISSION CALCULATIONS................................................................................17

3.1 GHG Emissions From Combined Cycle Combustion Turbine ..............................17

3.2 Auxiliary Boiler.....................................................................................................17

3.3 GHG Emissions From Natural Gas/Fuel Gas Piping Fugitives and Natural 

Gas/Fuel Gas Maintenance and Startup/Shutdown Related Releases ................18

3.4 GHG Emissions From Diesel Fired Emergency Engines......................................18

3.5 GHG Emissions From Electrical Equipment Insulated with SF6............................19

TABLE 3-1 ANNUAL GHG EMISSION SUMMARY ...............................................................20

TABLE 3-2 ANNUAL GHG EMISSION CALCULATIONS – GE 7FA COMBINED CYCLE 

COMBUSTION TURBINE..............................................................................................21

TABLE 3-3 STARTUP GHG EMISSION CALCULATIONS - GE F7FA TURBINES ...............22

TABLE 3-4 GHG ANNUAL EMISSION CALCULATIONS - SIEMENS SGT6-5000F(4) 

COMBINED CYCLE COMBUSTION TURBINES ..........................................................23

TABLE 3-5 STARTUP GHG EMISSION CALCULATIONS - SIEMENS SGT6-5000F(4) 

TURBINES....................................................................................................................24

TABLE 3-6 GHG EMISSION CALCULATIONS - SIEMENS SGT6-5000F(5) COMBINED 

CYCLE COMBUSTION TURBINES ..............................................................................25

TABLE 3-7 STARTUP GHG EMISSION CALCULATIONS - SIEMENS SGT6-5000F(5) 

TURBINES....................................................................................................................26

TABLE 3-8 GHG EMISSION CALCULATIONS - AUXILIARY BOILER..................................27

TABLE 3-9 GHG EMISSION CALCULATIONS - NATURAL GAS PIPING.............................28

TABLE 3-10 GASEOUS FUEL VENTING DURING TURBINE SHUTDOWN/MAINTENANCE

AND SMALL EQUIPMENT AND FUGITIVE COMPONENT REPAIR/REPLACEMENT . 29

TABLE 3-11 GHG EMISSION CALCULATIONS - EMERGENCY ENGINES..............30
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

ii

TABLE 3-12 GHG EMISSION CALCULATIONS - ELECTRICAL EQUIPMENT INSULATED 

WITH SF6 .....................................................................................................................31

4.0 PREVENTION OF SIGNIFICANT DETERIORATION APPLICABILITY .........................32

TCEQ PSD NETTING TABLES ................................................................................................33

5.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT)................................................36

5.1 BACT for the Combined Cycle Combustion Turbine ............................................37

5.1.1 Step 1: Identify All Available Control Technologies 37

5.1.2 Step 2: Eliminate Technically Infeasible Options 43

5.1.3 Step 3: Rank Remaining Control Technologies 44

5.1.4 Step 4: Evaluate Most Effective Controls and Document Results 44

5.1.5 Step 5: Select BACT 48

5.2 BACT for SF6 Insulated Electrical Equipment.......................................................57

5.2.1 Step 1: Identify All Available Control Technologies 57

5.2.2 Step 2: Eliminate Technically Infeasible Options 57

5.2.3 Step 3: Rank Remaining Control Technologies 58

5.2.4 Step 4: Evaluate Most Effective Controls and Document Results 58

5.2.5 Step 5: Select BACT 58

5.3 BACT for Auxiliary Boiler .....................................................................................58

5.3.1 Step 1: Identify All Available Control Technologies 58

5.3.2 Step 2: Eliminate Technically Infeasible Options 59

5.3.3 Step 3: Rank Remaining Control Technologies 60

5.3.4 Step 4: Evaluate Most Effective Controls and Document Results 60

5.3.5 Step 5: Select BACT 60

5.4 BACT for Emergency Engines .............................................................................60

5.4.1 Step 1: Identify All Available Control Technologies 61

5.4.2 Step 2: Eliminate Technically Infeasible Options 61

5.4.3 Step 3: Rank Remaining Control Technologies 62

5.4.4 Step 4: Evaluate Most Effective Controls and Document Results 62

5.4.5 Step 5: Select BACT 62

5.5 BACT for Natural Gas Fugitives...........................................................................62

5.5.1 Step 1: Identify All Available Control Technologies 62

5.5.2 Step 2: Eliminate Technically Infeasible Options 62

5.5.3 Step 3: Rank Remaining Control Technologies 63

5.5.4 Step 4: Evaluate Most Effective Controls and Document Results 63

5.5.5 Step 5: Select BACT 63

MAP OF EXISTING CO2 PIPELINES AND POTENTIAL GEOLOGIC STORAGE SITES IN 

TEXAS ..........................................................................................................................65

TABLE 5-1 CALCULATION OF DESIGN HEAT RATE FOR GE 7FA....................................66

TABLE 5-2 CALCULATION OF DESIGN HEAT RATE FOR SIEMENS SGT6-5000F(4).......67

TABLE 5-3 CALCULATION OF DESIGN HEAT RATE FOR SIEMENS SGT6-5000F(5).......68

6.0 OTHER PSD REQUIREMENTS....................................................................................69

6.1 Impacts Analysis..................................................................................................69
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

iii

6.2 GHG Preconstruction Monitoring .........................................................................69

6.3 Additional Impacts Analysis .................................................................................69

7.0 PROPOSED GHG MONITORING PROVISIONS..........................................................71

APPENDICES

APPENDIX A: GHG PSD APPLICABILITY FLOWCHART – NEW SOURCES
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

1

1.0 INTRODUCTION

Pinecrest Energy Center, LLC (Pinecrest) is hereby submitting this application for a Greenhouse 

Gas (GHG) Prevention of Significant Deterioration (PSD) air quality permit for the construction 

of a new combined cycle electric generating plant, Pinecrest Energy Center (PCEC), in Angelina

County, Texas. PCEC will consist of two natural gas-fired combustion turbines, each 

exhausting to a fired heat recovery steam generator (HRSG) to produce steam to drive a shared 

steam turbine. Three models of combustion turbines are being considered for this site: the 

General Electric 7FA.05, the Siemens SGT6-5000F(4), and the Siemens SGT6-5000F(5). The 

final selection of the combustion turbine model will not be made until after the permit is issued. 

The State and PSD air permit application for non-GHG pollutants was submitted to the Texas 

Commission on Environmental Quality (TCEQ) on June 22, 2012.

The General Electric 7FA.05 combustion turbine has a maximum base-load electric power 

output of approximately 183 MW, the Siemens SGT6-5000F(4) is approximately 205 MW, and 

the Siemens SGT6-5000F(5) is approximately 232 MW. The maximum electric power output 

from the steam turbine is approximately 271 MW for both the GE and Siemens configurations. 

All three combustion turbines are F-Class turbines.

On June 3, 2010, the EPA published final rules for permitting sources of GHGs under the PSD 

and Title V air permitting programs, known as the GHG Tailoring Rule.1

 

 After July 1, 2011, new 

sources having the potential to emit more than 100,000 tons/yr of GHGs and modifications 

increasing GHG emissions more than 75,000 tons/yr on a carbon dioxide equivalent (CO2e) 

basis at existing major sources are subject to GHG PSD review, regardless of whether PSD 

was triggered for other pollutants.

On December 23, 2010, EPA issued a Federal Implementation Plan (FIP) authorizing EPA to 

issue PSD permits in Texas for GHG sources until Texas submits the required SIP revision for 

GHG permitting and it is approved by EPA.2

 

The PCEC project for construction of two combined cycle power plant units triggers PSD review 

for GHG regulated pollutants because the project will increase GHG emissions by more than 

100,000 tons/yr. Included in this application are a project scope description, GHG emissions 

calculations, GHG netting analysis, and a GHG Best Available Control Technology (BACT) 

analysis.

 

1 75 FR 31514 (June 3, 2010).

2 75 FR 81874 (Dec. 29, 2010).
Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

Important Note: The agency requires that a Core Data Form be submitted on all incoming applications unless a 

Regulated Entity and Customer Reference Number have been issued and no core data information has changed. For more 

information regarding the Core Data Form, call (512) 239-5175 or go to 

www.tceq.texas.gov/permitting/central_registry/guidance.html. 

I. Applicant Information 

A. Company or Other Legal Name: Pinecrest Energy Center, LLC 

Texas Secretary of State Charter/Registration Number (if applicable): 0801593860 

B. Company Official Contact Name: Kathleen Smith 

Title: President 

Mailing Address: 4011 West Plano Parkway, Suite 128 

City: Plano State: TX ZIP Code: 75093 

Telephone No.: 281-253-4385 Fax No.: 972-964-0807 E-mail Address: ksmith@coronado-ventures.com 

C. Technical Contact Name: Kathleen Smith 

Title: President 

Company Name: Pinecrest Energy Center, LLC 

Mailing Address: 4011 West Plano Parkway, Suite 128 

City: Plano State: TX ZIP Code: 75093 

Telephone No.: 281-253-4385 Fax No.: 972-964-0807 E-mail Address: ksmith@coronado-ventures.com 

D. Site Name: Pinecrest Energy Center

E. Area Name/Type of Facility: Electric Generating Facility Permanent Portable 

F. Principal Company Product or Business: Generation of Electricity

Principal Standard Industrial Classification Code (SIC): 4911 

Principal North American Industry Classification System (NAICS): 221112 

G. Projected Start of Construction Date: 06/01/2013

Projected Start of Operation Date: 10/01/2015 

H. Facility and Site Location Information (If no street address, provide clear driving directions to the site in writing.): 

Street Address: 1002 East Park Avenue 

City/Town: Lufkin County: Angelina ZIP Code: 75904

Latitude (nearest second): 31°21'35"N Longitude (nearest second): 94°41'43"W 

TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 1 of 9 .
Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

I. Applicant Information (continued) 

I. Account Identification Number (leave blank if new site or facility): 

J. Core Data Form. 

Is the Core Data Form (Form 10400) attached? If No, provide customer reference number and 

regulated entity number (complete K and L). 

 YES NO 

K. Customer Reference Number (CN): 

L. Regulated Entity Number (RN): 

II. General Information 

A. Is confidential information submitted with this application? If Yes, mark each confidential page 

confidential in large red letters at the bottom of each page. 

 YES NO 

B. Is this application in response to an investigation or enforcement action? If Yes, attach a copy of 

any correspondence from the agency.

 YES NO 

C. Number of New Jobs: 50 

D. Provide the name of the State Senator and State Representative and district numbers for this facility site: 

Senator: Robert Nichols District No.: 3 (1 for 2012 elections) 

Representative: James White District No.: 12 (57 for 2012 elections) 

III. Type of Permit Action Requested 

A. Mark the appropriate box indicating what type of action is requested.

Initial Amendment Revision (30 TAC 116.116(e)) Change of Location Relocation 

B. Permit Number (if existing): 

C. Permit Type: Mark the appropriate box indicating what type of permit is requested. (check all that apply, skip for 

change of location)

Construction Flexible Multiple Plant Nonattainment Prevention of Significant Deterioration 

Hazardous Air Pollutant Major Source Plant-Wide Applicability Limit 

Other: 

D. Is a permit renewal application being submitted in conjunction with this amendment in 

accordance with 30 TAC 116.315(c).

 YES NO 

TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 2 of 9 .
Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

III. Type of Permit Action Requested (continued) 

E. Is this application for a change of location of previously permitted facilities? If Yes, complete 

III.E.1 - III.E.4.

 YES NO 

1. Current Location of Facility (If no street address, provide clear driving directions to the site in writing.): 

Street Address: 

City: County: ZIP Code: 

2. Proposed Location of Facility (If no street address, provide clear driving directions to the site in writing.): 

Street Address: 

City: County: ZIP Code: 

3. Will the proposed facility, site, and plot plan meet all current technical requirements of the 

permit special conditions? If No, attach detailed information. 

 YES NO 

4. Is the site where the facility is moving considered a major source of criteria pollutants or 

HAPs? 

 YES NO 

F. Consolidation into this Permit: List any standard permits, exemptions or permits by rule to be consolidated into this 

permit including those for planned maintenance, startup, and shutdown.

List: None

G. Are you permitting planned maintenance, startup, and shutdown emissions? If Yes, attach 

information on any changes to emissions under this application as specified in VII and VIII. 

 YES NO 

H. Federal Operating Permit Requirements (30 TAC Chapter 122 Applicability) 

Is this facility located at a site required to obtain a federal operating permit? If 

Yes, list all associated permit number(s), attach pages as needed). 

 YES NO To be determined 

Associated Permit No (s.): 

1. Identify the requirements of 30 TAC Chapter 122 that will be triggered if this application is approved. 

FOP Significant Revision FOP Minor Application for an FOP Revision To Be Determined 

Operational Flexibility/Off-Permit Notification Streamlined Revision for GOP None 

TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 3 of 9 .
Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

III. Type of Permit Action Requested (continued) 

H. Federal Operating Permit Requirements (30 TAC Chapter 122 Applicability) (continued)

2. Identify the type(s) of FOP(s) issued and/or FOP application(s) submitted/pending for the site. (check all that 

apply) 

GOP Issued GOP application/revision application submitted or under APD review 

SOP Issued SOP application/revision application submitted or under APD review 

IV. Public Notice Applicability 

A. Is this a new permit application or a change of location application? YES NO 

B. Is this application for a concrete batch plant? If Yes, complete V.C.1 – V.C.2. YES NO 

C. Is this an application for a major modification of a PSD, nonattainment, FCAA 112(g) permit, 

or exceedance of a PAL permit? 

 YES NO 

D. Is this application for a PSD or major modification of a PSD located within 100 kilometers or 

less of an affected state or Class I Area?

 YES NO 

If Yes, list the affected state(s) and/or Class I Area(s). 

E. Is this a state permit amendment application? If Yes, complete IV.E.1. – IV.E.3.

1. Is there any change in character of emissions in this application? YES NO

2. Is there a new air contaminant in this application? YES NO

3. Do the facilities handle, load, unload, dry, manufacture, or process grain, seed, legumes, or 

vegetables fibers (agricultural facilities)? 

 YES NO

F. List the total annual emission increases associated with the application (list all that apply and attach additional 

sheets as needed):

Volatile Organic Compounds (VOC): 156.2 tpy

Sulfur Dioxide (SO2): 38.8 tpy

Carbon Monoxide (CO): 418.8 tpy

Nitrogen Oxides (NOx): 260.2 tpy 

Particulate Matter (PM): 289.3 tpy 

PM 10 microns or less (PM10): 257.9 tpy 

PM 2.5 microns or less (PM2.5): 250.9 tpy 

Lead (Pb): 

Hazardous Air Pollutants (HAPs): < 10 tons/yr for individual HAP and < 25 ton/yr for all HAPs 

Other speciated air contaminants not listed above: 267.2 ton/yr NH3; 17.8 ton/yr H2SO4; 24.0 ton/yr (NH4)2SO4

TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 4 of 9 .
TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 5 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

V. Public Notice Information (complete if applicable) 

A. Public Notice Contact Name: Kathleen Smith

Title: President 

Mailing Address: 4011 West Plano Parkway, Suite 128 

City: Plano State: TX ZIP Code: 75093 

Telephone No.: 281-253-4385 

B. Name of the Public Place: Kurth Memorial Library 

Physical Address (No P.O. Boxes): 706 South Raguet

City: Lufkin County: TX ZIP Code:75904

The public place has granted authorization to place the application for public viewing and copying. YES NO

The public place has internet access available for the public. YES NO

C. Concrete Batch Plants, PSD, and Nonattainment Permits

1. County Judge Information (For Concrete Batch Plants and PSD and/or Nonattainment Permits) for this facility site. 

The Honorable: Wes Suiter 

Mailing Address: P.O. Box 908 

City: Lufkin State: TX ZIP Code: 75902-0908 

2. Is the facility located in a municipality or an extraterritorial jurisdiction of a municipality? 

(For Concrete Batch Plants)

 YES NO 

Presiding Officers Name(s): 

Title: 

Mailing Address: 

City: State: ZIP Code: 

3. Provide the name, mailing address of the chief executive of the city for the location where the facility is or will be 

located. 

Chief Executive: Bob Brown 

Mailing Address: 300 E. Shepherd Avenue 

City: Lufkin State: TX ZIP Code: 75901 

 of 9 .
TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 6 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

V. Public Notice Information (complete if applicable) (continued) 

3. Provide the name, mailing address of the Indian Governing Body for the location where the facility is or will be 

located. (continued) 

Name of the Indian Governing Body: NA 

Title: 

Mailing Address: 

City: State: ZIP Code: 

D. Bilingual Notice

Is a bilingual program required by the Texas Education Code in the School District? YES NO 

Are the children who attend either the elementary school or the middle school closest to your 

facility eligible to be enrolled in a bilingual program provided by the district? 

 YES NO 

If Yes, list which languages are required by the bilingual program? Spanish 

VI. Small Business Classification (Required) 

A. Does this company (including parent companies and subsidiary companies) have fewer than 

100 employees or less than $6 million in annual gross receipts? 

 YES NO 

B. Is the site a major stationary source for federal air quality permitting? YES NO 

C. Are the site emissions of any regulated air pollutant greater than or equal to 50 tpy? YES NO 

D. Are the site emissions of all regulated air pollutants combined less than 75 tpy? YES NO 

VII. Technical Information 

A. The following information must be submitted with your Form PI-1 (this is just a checklist to make sure you have 

included everything) 

1. Current Area Map 

2. Plot Plan 

3. Existing Authorizations 

4. Process Flow Diagram 

5. Process Description 

6. Maximum Emissions Data and Calculations 

7. Air Permit Application Tables 

a. Table 1(a) (Form 10153) entitled, Emission Point Summary 

b. Table 2 (Form 10155) entitled, Material Balance 

c. Other equipment, process or control device tables 

 of 9 .
TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 7 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

VII. Technical Information 

B. Are any schools located within 3,000 feet of this facility? YES NO 

C. Maximum Operating Schedule:

Hours: 24 hr/day Day(s): 7 day/week Week(s): 52 week/year Year(s): 8,760 hr/year 

Seasonal Operation? If Yes, please describe in the space provide below. YES NO 

D. Have the planned MSS emissions been previously submitted as part of an emissions inventory? YES NO 

Provide a list of each planned MSS facility or related activity and indicate which years the MSS activities have been 

included in the emissions inventories. Attach pages as needed. 

MSS activities are listed on Tables A-16 and A-17 of the attached application. 

This is a new site and there have been no previous emission inventories. 

E. Does this application involve any air contaminants for which a disaster review is required? YES NO 

F. Does this application include a pollutant of concern on the Air Pollutant Watch List (APWL)? YES NO 

VIII. State Regulatory Requirements 

Applicants must demonstrate compliance with all applicable state regulations to obtain a permit or 

amendment. The application must contain detailed attachments addressing applicability or non applicability; 

identify state regulations; show how requirements are met; and include compliance demonstrations.

A. Will the emissions from the proposed facility protect public health and welfare, and comply 

with all rules and regulations of the TCEQ? 

 YES NO 

B. Will emissions of significant air contaminants from the facility be measured? YES NO 

C. Is the Best Available Control Technology (BACT) demonstration attached? YES NO 

D. Will the proposed facilities achieve the performance represented in the permit application as 

demonstrated through recordkeeping, monitoring, stack testing, or other applicable methods? 

 YES NO 

IX. Federal Regulatory Requirements 

Applicants must demonstrate compliance with all applicable federal regulations to obtain a permit or 

amendment The application must contain detailed attachments addressing applicability or non applicability; 

identify federal regulation subparts; show how requirements are met; and include compliance demonstrations.

A. Does Title 40 Code of Federal Regulations Part 60, (40 CFR Part 60) New Source 

Performance Standard (NSPS) apply to a facility in this application? 

 YES NO 

B. Does 40 CFR Part 61, National Emissions Standard for Hazardous Air Pollutants (NESHAP) 

apply to a facility in this application?

 YES NO 

C. Does 40 CFR Part 63, Maximum Achievable Control Technology (MACT) standard apply to 

a facility in this application?

 YES NO 

 of 9 .
TCEQ – 10252 (Revised 02/12) PI-1 Form 

This form is for use by facilities subject to air quality permit requirements and 

may be revised periodically. (APDG 5171v18) Page 8 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

IX. Federal Regulatory Requirements 

Applicants must demonstrate compliance with all applicable federal regulations to obtain a permit or 

amendment The application must contain detailed attachments addressing applicability or non applicability; 

identify federal regulation subparts; show how requirements are met; and include compliance demonstrations.

D. Do nonattainment permitting requirements apply to this application? YES NO 

E. Do prevention of significant deterioration permitting requirements apply to this application? YES NO 

F. Do Hazardous Air Pollutant Major Source [FCAA 112(g)] requirements apply to this 

application? 

 YES NO 

G. Is a Plant-wide Applicability Limit permit being requested? YES NO 

X. Professional Engineer (P.E.) Seal 

Is the estimated capital cost of the project greater than $2 million dollars? YES NO 

If Yes, submit the application under the seal of a Texas licensed P.E. 

XI. Permit Fee Information 

Check, Money Order, Transaction Number ,ePay Voucher Number: Fee Amount: $75,000 

Company name on check: Coronado Power Investments 1 LLC Paid online?: YES NO 

Is a copy of the check or money order attached to the original submittal of this 

application? 

 YES NO N/A 

Is a Table 30 (Form 10196) entitled, Estimated Capital Cost and Fee Verification, 

attached? 

 YES NO N/A 

 of 9 .

PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

11

2.0 PROJECT SCOPE

2.1 INTRODUCTION

With this application, Pinecrest is seeking authorization to construct a new combined cycle 

electric generating plant, PCEC, in Angelina County, Texas. The power generating equipment, 

as well as ancillary equipment that will be sources of GHG emissions at the site, are listed 

below:

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

combustors

 Two natural gas-fired duct burner systems

 Natural gas piping and metering

 One diesel fuel-fired emergency electrical generator engine

 One diesel fuel-fired fire water pump engine

 One natural gas-fired auxiliary boiler

 Electrical equipment insulated with sulfur hexafluoride (SF6) 

A process flow diagram is included at the end of this section. 

The business purpose of the PCEC is to generate 637 - 735 megawatts (MW), of gross 

electrical power near the City of Lufkin in an efficient manner while increasing the reliability of 

the electrical supply for the State of Texas. One of the factors in siting the plant is the availability 

of surface water from the City of Lufkin to be used as cooling water at the plant. Pipeline natural 

gas is chosen as the only fuel for the combustion turbines and duct burner systems due to local 

availability of fuel and infrastructure to support delivery of the fuel to the facility in adequate 

volume and pressure. 

 

2.2 COMBUSTION TURBINE GENERATOR

The plant will consist of two identical natural gas-fired combustion turbine generators (CTGs), 

with three models being considered: the General Electric 7FA.05, the Siemens SGT6-5000F(4), 

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

be made after the permit is issued. Each combustion turbine will exhaust to an HRSG. 

Emission point numbers (EPNs) for the combustion turbine/HRSG units are identified as U1-

STK and U2-STK.

The combustion turbine will burn pipeline natural gas to rotate an electrical generator to 

generate electricity. The main components of a combustion turbine generator consist of a 

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

the combustor where the fuel is mixed with the combustion air and burned. Hot exhaust gases 

then enter the turbine where the gases expand across the turbine blades, driving a shaft to 

power an electric generator. The exhaust gas will exit the combustion turbine and be routed to 

the HRSG for steam production.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

12

2.3 HEAT RECOVERY STEAM GENERATOR

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

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

will be equipped with duct burners for supplemental steam production. The duct burners will be 

fired with pipeline-quality natural gas. The duct burners have a maximum heat input capacity of 

750 MMBtu/hr per unit. The exhaust gases from the unit, including emissions from the CT and 

the duct burners, will exit through a stack to the atmosphere.

The normal duct burner operation will vary from 0 to 100 percent of the maximum capacity. 

Duct burners will be located in the HRSG prior to the selective catalytic reduction system.

Steam produced by each of the two HRSGs will be routed to the steam turbine (FIN STG-1). 

The two combustion turbines and one steam turbine will be coupled to electric generators to 

produce electricity for sale to the Electric Reliability Council of Texas power grid. Each GE 

combustion turbine model has a maximum base-load electric power output of approximately 215

MW, the Siemens SGT6-5000F(4) is approximately 205 MW, and the Siemens SGT6-5000F(5) 

is approximately 232 MW. The maximum electric power output from the steam turbine is 

approximately 271 MW for both the GE and Siemens configurations.

The units may operate at reduced load to respond to changes in system power requirements 

and/or stability.

2.4 AUXILIARY BOILER

One auxiliary boiler (EPN AUXBLR) will be available to facilitate startup of the combined cycle 

units. The auxiliary boiler will have a maximum heat input of 150 MMBtu/hr and will burn 

pipeline natural gas. The auxiliary boiler could operate up to 876 hours per year. 

2.5 DIESEL FIRED EMERGENCY EQUIPMENT

The site will be equipped with one nominally rated 1,072-hp diesel-fired emergency generator 

(EPN: EMGEN1-STK) to provide electricity to the facility in case of power failure. A nominally 

rated 500-hp diesel-fired pump (EPN: ENG-FWMAIN) will be installed at the site to provide 

water in the event of a fire. Each emergency engine will be limited to 100 hours operation per 

year for purposes of maintenance checks and readiness testing.

2.6 NATURAL GAS/FUEL GAS PIPING

Natural gas will be delivered to the site via pipeline. Gas will be metered and piped to the new 

combustion turbines and duct burners. Project fugitive emissions from the gas piping 

components associated with the new CTG/HRSG units will include emissions of methane (CH4) 

and carbon dioxide (CO2). The natural gas piping is designated as EPN NG-FUG. 
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

13

2.7 ELECTRICAL EQUIPMENT INSULATED WITH SULFUR HEXAFLUORIDE (SF6) 

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

SF6 is a colorless, odorless, non-flammable gas. It is a fluorinated compound that has an 

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

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

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

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

associated with the proposed plant is currently estimated to be 400 lb of SF6. 

The proposed circuit breaker at the generator output will have a low pressure alarm and a low 

pressure lockout. The alarm will alert operating personnel of any leakage in the system and the 

lockout prevents any operation of the breaker due to lack of “quenching and cooling” SF6 gas. 
WATER

STEAM

EPN: U2‐STK

COMBUSTOR STEAM

HEAT RECOVERY STEAM

GENERATOR, SCR, & OXIDATION

CATALYST

STEAM TURBINE

EPN: U1‐STK

COMPRESSOR TURBINE

AIR

ELECTRIC

GENERATOR

EPN: CT1LOV‐VNT

EPN: ST1LOV

NATURAL GAS FROM

PIPELINE AMMONIA

STORAGE AND

EPN: NG‐FUG

EPN: NH3‐FUG

Permit Application Filen

Drawn by: Checked by: Proje

E Rapier L Moon 0

PINECREST ENERGY CENTER P

EPN: CT2LOV‐VNT

WATER

STEAM

CONDENSER

COMPRESSOR

COMBUSTOR

AIR

ELECTRIC

GENERATOR TURBINE

HEAT RECOVERY STEAM

GENERATOR, SCR, & OXIDATION

CATALYST

STEAM

WA

DISTRIBUTION
Pinecrest Energy Center,LLC

Lufkin, Texas

Drafted By:

J. Knowles Date:

06/19/2012

Project No.:

12205

Reviewed By:

L. Moon

Datum: NAD 1983

Map Sources: 

ESRI i-cubed imagery q

PLOT PLAN

Pinecrest Energy Center

Site Boundary

!(

SITE 

LOCATION

0 500 1,000

Feet

0 150 300

Meters

Scale 1:4,500 1 inch = 375 feet

BENCHMARK 2: 

UTM Zone 15

339265.71 m E

3470756.41 m N

BENCHMARK 1: 

UTM Zone 15

338752.77 m E

3470718.90 m N

Cooling Tower

FWP1-STK

DSL-TK2

NG-FUG

U1-STK

U2-STK

NH3-FUG AUXBLR

ST1LOV-VNT

DSL-TK1

EMGEN1-STK CT2LOV-VNT

CT1LOV-VNT
Pinecrest Energy Center , LLC

Lufkin, Texas

Drafted By:

J. Knowles Date:

06/19/2012

Project No.:

12205

Reviewed By:

L. Moon

Datum: NAD 1983 q Map Sources: ESRI i-cubed imagery,

!(

AREA MAP

Pinecrest Energy Center

SITE 

LOCATION

0 0.5 1

Miles

0 0.5 1

Kilometers

Scale 1:24,000 1 inch = 2,000 feet

Benchmark 1:

UTM Zone 15

339529.85 mE

3470588.75 mN

Benchmark 2:

UTM Zone 15

338311.32 mE

3471017.83 mN

Site Boundary

3000 Foot Boundary
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

17

3.0 GHG EMISSION CALCULATIONS

3.1 GHG EMISSIONS FROM COMBINED CYCLE COMBUSTION TURBINE

GHG emissions for the combustion turbines and HRSG are calculated in accordance with the 

procedures in the Mandatory Greenhouse Reporting Rules, Subpart D – Electric Generation.3

 

Annual CO2 emissions are calculated using the methodology in equation G-4 of the Acid Rain 

Rules.

4

Where: 

WCO2= CO2 emitted from combustion, tons/yr. 

MW CO2= Molecular weight of carbon dioxide, 44.0 lb/lb-mole. 

Fc= Carbon based F-factor, 1040 scf/MMBtu for natural gas. 

H = Annual heat input in MMBtu. 

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

Emissions of CH4 and nitrous oxide (N2O) are calculated using the emission factors (kg/MMBtu) 

for natural gas combustion from Table C-2 of the Mandatory Greenhouse Gas Reporting Rules.5

 

The global warming potential factors used to calculate carbon dioxide equivalent (CO2e) 

emissions are based on Table A-1 of the Mandatory Greenhouse Gas Reporting Rules.

A separate set of turbine/HRSG calculations is provided for each of the three models being 

considered: the General Electric 7FA, the Siemens SGT6-5000F(4), and the Siemens SGT6-

5000F(5). Calculations of GHG emissions from the combined cycle turbines are presented on 

Tables 3-2, 3-3, 3-4, 3-5, 3-6, and 3-7. 

3.2 AUXILIARY BOILER

CO2 emissions from the natural-gas-fired auxiliary boilers are calculated using the emission 

factors (kg/MMBtu) for natural gas from Table C-1 of the Mandatory Greenhouse Gas Reporting 

 

3 40 C.F.R. 98, Subpart D – Electricity Generation

4 40 C.F.R. 75, Appendix G – Determination of CO2 Emissions

5 Default CH4 and N2O Emission Factors for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-2
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

18

Rules.6 CH4 and N2O emissions from the auxiliary boilers are calculated using the emission 

factors (kg/MMBtu) for natural gas from Table C-2 of the Mandatory Greenhouse Gas Reporting 

Rules.7

 The global warming potential factors used to calculate CO2e emissions are based on 

Table A-1 of the Mandatory Greenhouse Gas Reporting Rules.8

Calculations of GHG emissions from the auxiliary boiler are presented on Table 3-8. 

3.3 GHG EMISSIONS FROM NATURAL GAS/FUEL GAS PIPING FUGITIVES AND NATURAL 

GAS/FUEL GAS MAINTENANCE AND STARTUP/SHUTDOWN RELATED RELEASES

GHG emission calculations for natural gas/fuel gas piping component fugitive emissions are 

based on emission factors from Table W-1A of the “2012 Technical Corrections, Clarifying and 

Other Amendments to the Greenhouse Gas Reporting Rule, and Proposed Confidentiality 

Determinations for Certain Data Elements of the Fluorinated Gas Source Category” which was 

signed on August 3, 20129

. The concentrations of CH4 and CO2 in the natural gas are based on 

a typical natural gas analysis. Since the CH4 and CO2 content of natural gas is variable, the 

concentrations of CH4 and CO2 from the typical natural gas analysis are used as a worst case 

estimate. The global warming potential factors used to calculate CO2e emissions are based on 

Table A-1 of the Mandatory Greenhouse Gas Reporting Rules.10

GHG emission calculations for releases of natural gas related to piping maintenance and turbine 

startup/shutdowns are calculated using the same CH4 and CO2 concentrations as natural 

gas/fuel gas piping fugitives.

Calculations of GHG emissions from natural gas piping fugitives is presented on Table 3-9. 

Calculations of GHG emissions from releases of natural gas related to piping maintenance and 

turbine startup/shutdowns is presented on Table 3-10. 

3.4 GHG EMISSIONS FROM DIESEL FIRED EMERGENCY ENGINES

CO2 emission calculations from the diesel-fired emergency generator and fire pump engine are 

calculated using the emission factors (kg/MMBtu) for Distillate Fuel Oil No. 2 from Table C-1 of 

the Mandatory Greenhouse Gas Reporting Rules.11 CH4 and N2O emission calculations from 

the diesel-fired engines are calculated using the emission factors (kg/MMBtu) for Petroleum 

from Table C-2 of the Mandatory Greenhouse Gas Reporting Rules.12

 

6 Default CO2 Emission Factors and High Heat Values for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-1 

 The global warming 

7 Default CH4 and N2O Emission Factors for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-2 

8 Global Warming Potentials, 40 C.F.R. Pt. 98, Subpt. A, Tbl. A-1.

9 http://www.epa.gov/climatechange/emissions/technical-corrections.html (last visited August 9, 2012)

10 Global Warming Potentials, 40 C.F.R. Pt. 98, Subpt. A, Tbl. A-1.

11 Default CO2 Emission Factors and High Heat Values for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-1 

12 Default CH4 and N2O Emission Factors for Various Types of Fuel, 40 C.F.R. 98, Subpt. C, Tbl. C-2 
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

19

potential factors used to calculate CO2e emissions are based on Table A-1 of the Mandatory 

Greenhouse Gas Reporting Rules.13

Calculations of GHG emissions from the emergency engines are presented on Table 3-11. 

3.5 GHG EMISSIONS FROM ELECTRICAL EQUIPMENT INSULATED WITH SF6

SF6 emissions from the new generator circuit breaker and yard breaker associated with the 

proposed units are calculated using a predicted SF6 annual leak rate of 0.5% by weight. The 

global warming potential factors used to calculate CO2e emissions are based on Table A-1 of 

the Mandatory Greenhouse Gas Reporting Rules.14

Calculations of GHG emissions from electrical equipment insulated with SF6 are presented on 

Table 3-12.

 

13 Global Warming Potentials, 40 C.F.R. Pt. 98, Subpt. A, Tbl. A-1.

14 Global Warming Potentials, 40 C.F.R. Pt. 98, Subpt. A, Tbl. A-1.
Table 3-1

Plantwide GHG Emission Summary

Pinecrest Energy Center

Name EPN

Normal 

Operation 

GHG Mass 

Emissions

Startup/Shutdown 

GHG Mass 

Emissions

Total GHG 

Mass 

Emissions

Normal 

Operation 

CO2e

Startup/Shutdown 

CO2e Total CO2e

ton/yr ton/yr ton/yr ton/yr ton/yr ton/yr

Unit 1 (GE F7FA.05) U1-STK 1,404,579 41,637 1,446,216 1,405,902 41,676 1,447,578

Unit 2 (GE F7FA.05) U2-STK 1,404,579 41,637 1,446,216 1,405,902 41,676 1,447,578

Unit 1 (Siemens SGT6-5000F(4)) U1-STK 1,356,650 41,806 1,398,455 1,357,928 41,845 1,399,773

Unit 2 (Siemens SGT6-5000F(4)) U2-STK 1,356,650 41,806 1,398,455 1,357,928 41,845 1,399,773

Unit 1 (Siemens SGT6-5000F(5)) U1-STK 1,526,868 42,433 1,569,300 1,528,306 42,473 1,570,779

Unit 2 (Siemens SGT6-5000F(5)) U2-STK 1,526,868 42,433 1,569,300 1,528,306 42,473 1,570,779

Auxiliary Boiler AUXBLR 7,680 7,680 7,687 7,687

Natural Gas Fugitives NG-FUG 21 21 426 426

Gas Venting TRB-MSS 0.11 0 426 426

Emergency Generator EMGEN1-STK 64 64 65 65

Fire Water Pump FWP1-STK 28 28 28 28

SF6 Insulated Equipment SF6-FUG 0.001 0.001 24 24

Sitewide Emissions1 3,061,528 3,146,393 3,065,268

2/11/2013
Table 3-2

GHG Annual Emission Calculations - GE F7FA.05 Combined Cycle Combustion Turbines

Pinecrest Energy Center

GHG Emissions Contribution From Natural Gas Fired Combustion Turbines

EPN Average Heat 

Input1

Annual Heat 

Input2 Pollutant Emission 

Factor

GHG Mass 

Emissions4 CO2e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)3 (tpy) (tpy)

CO2 1,404,550.5 1 1,404,550.5

U1-STK 2,861 23,634,263 CH4 1.0E-03 26.0 21 546.0

(GE F7FA) N2O 1.0E-04 2.6 310 805.9

Totals 1,404,579.1 1,405,902.4

CO2 1,404,550.5 1 1,404,550.5

U2-STK 2,861 23,634,263 CH4 1.0E-03 26.0 21 546.0

(GE F7FA) N2O 1.0E-04 2.6 310 805.9

Totals 1,404,579.1 1,405,902.4

Total for 2 Turbines 2,809,158.1 2,811,804.7

Note

1. The average heat input for the GE F7FA scenario is based on the HHV heat input at 100% load, with maximum duct

 firing, at 69 o F ambient temperature.

2. Annual heat input based on 8,260 hours per year operation.

3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MWCO2 = Molecule weight of CO 2 , 44.0 lb/lbmole

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Global 

Warming 

Potential5

2/11/2013
Startup/Shutdown GHG Emissions From GE F7FA Turbine

EPN

Heat Input 

During 

Startup1

Annual Heat 

Input During 

Startup2

Pollutant Emission 

Factor

GHG Mass 

Emissions4

Global 

Warming 

Potential5

CO2e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)3 (ton/hr) (ton/hr)

CO2 41,636 1 41,636

U1-STK 1,401.2 700,600.0 CH4 1.0E-03 0.7723 21 16.2

N2O 1.0E-04 0.0772 310 23.9

41,636.5 41,676

CO2 41,636 1 41,636

U2-STK 1,401.2 700,600.0 CH4 1.0E-03 0.7723 21 16.2

N2O 1.0E-04 0.0772 310 23.9

41,636.5 41,676

Note

1. The following hourly firing rates Information is from Table A-3, in Appendix A of the PSD application

 submitted to TCEQ on 06/22/2012.

Turbine Duct Burner Total Hourly

Operating CTG Data Heat Input Heat Input Heat Input

Mode Case Number MMBtu/hr MMBtu/hr MMBtu/hr

Maximum Hourly Heat 

Input During Startup

48% Load, 

15 °F 

Ambient, no 

Duct Burner 

Firing

13 1,401.2 0 1,401.2

2. Based on 500 hours per year of startups.

3. CH 4 and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/hr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/hr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO2 , 44.0 lb/lbmole

5. Global Warming Potential factors from Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-3

Startup GHG Emission Calculations - GE F7FA.05 Turbines

Pinecrest Energy Center

2/11/2013
EPN Average Heat 

Input1

Annual Heat 

Input2 Pollutant Emission 

Factor

GHG Mass 

Emissions4 CO2e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)3 (tpy) (tpy)

CO2 1,356,622.0 1 1,356,622.0

U1-STK 2,764 22,827,773 CH4 1.0E-03 25.1 21 527.3

(Siemens SGT6-5000F(4)) N2O 1.0E-04 2.5 310 778.4

Totals 1,356,649.6 1,357,927.7

CO2 1,356,622.0 1 1,356,622.0

U2-STK 2,764 22,827,773 CH4 1.0E-03 25.1 21 527.3

(Siemens SGT6-5000F(4)) N2O 1.0E-04 2.5 310 778.4

Totals 1,356,649.6 1,357,927.7

Total for 2 Turbines 2,713,299.1 2,715,855.4

Note

1. The average heat input for the Siemens scenarios are based on the HHV heat input at 100% load, with maximum duct

 firing, at 59 o F ambient temperature.

2. Annual heat input based on 8,260 hours per year operation.

3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MWCO2 = Molecule weight of CO 2 , 44.0 lb/lbmole

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-4

GHG Annual Emission Calculations - Siemens SGT6-5000F(4) Combined Cycle Combustion Turbines

Pinecrest Energy Center

Global 

Warming 

Potential5

2/11/2013
Startup/Shutdown GHG Emissions From Siemens SGT6-5000F(4)

EPN

Heat Input 

During 

Startup1

Heat Input 

During 

Startup2

Pollutant Emission 

Factor

GHG Mass 

Emissions4

Global 

Warming 

Potential5

CO2e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)

3 (ton/hr) (ton/hr)

CO2 41,805 1 41,805

U1-STK 1,406.9 703,446.6 CH4 1.0E-03 0.7754 21 16.2837

N2O 1.0E-04 0.0775 310 24.0379

Totals 41,806 41,845

CO2 41,805 1 41,805

U2-STK 1,406.9 703,446.6 CH4 1.0E-03 0.7754 21 16.2837

N2O 1.0E-04 0.0775 310 24.0379

Totals 41,806 41,845

Note

1. The following hourly firing rates Information is from Table A-3, in Appendix A of the PSD application

 submitted to TCEQ on 06/22/2012.

Turbine Duct Burner Total Hourly

Operating CTG Data Heat Input Heat Input Heat Input

Mode Case Number MMBtu/hr MMBtu/hr MMBtu/hr

Maximum Hourly Heat 

Input During Startup

50% Load, 

10 °F 

Ambient, no 

Duct Burner 

Firing

13 1,406.9 0 1,406.9

2. Based on 500 hours per year of startup.

3. CH 4 and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/hr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/hr)

U f = 1/385 scf CO2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO2 , 44.0 lb/lbmole

5. Global Warming Potential factors from Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-5

Startup GHG Emission Calculations - Siemens SGT6-5000F(4) Turbines

Pinecrest Energy Center

2/11/2013
EPN Average Heat 

Input1

Annual Heat 

Input2 Pollutant Emission 

Factor

GHG Mass 

Emissions4 CO2e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)3 (tpy) (tpy)

CO2 1,526,836.5 1 1,526,836.5

U1-STK 3,110 25,691,961 CH4 1.0E-03 28.3 21 593.5

(Siemens SGT6-5000F(5)) N2O 1.0E-04 2.8 310 876.1

Totals 1,526,867.6 1,528,306.1

CO2 1,526,836.5 1 1,526,836.5

U2-STK 3,110 25,691,961 CH4 1.0E-03 28.3 21 593.5

(Siemens SGT6-5000F(5)) N2O 1.0E-04 2.8 310 876.1

Totals 1,526,867.6 1,528,306.1

Total for 2 Turbines 3,053,735.3 3,056,612.2

Note

1. The average heat input for the Siemens scenarios are based on the HHV heat input at 100% load, with maximum duct

 firing, at 59 o F ambient temperature.

2. Annual heat input based on 8,260 hours per year operation.

3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MWCO2 = Molecule weight of CO 2 , 44.0 lb/lbmole

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-6

GHG Emission Calculations - Siemens SGT6-5000F(5) Combined Cycle Combustion Turbines

Pinecrest Energy Center

Global 

Warming 

Potential5

2/11/2013
Startup/Shutdown GHG Emissions From Siemens SGT6-5000F(5)

EPN

Heat Input 

During 

Startup1

Annual Heat 

Input During 

Startup2

Pollutant Emission 

Factor

GHG Mass 

Emissions4

Global 

Warming 

Potential5

CO2e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)

3 (ton/hr) (ton/hr)

CO2 42,432 1 42,432

U1-STK 1,428.0 713,994.5 CH4 1.0E-03 0.7870 21 16.5279

N2O 1.0E-04 0.0787 310 24.3983

Totals 42,433 42,473

CO2 42,432 1 42,432

U2-STK 1,428.0 713,994.5 CH4 1.0E-03 0.7870 21 16.5279

N2O 1.0E-04 0.0787 310 24.3983

Totals 42,433 42,473

Note

1. The following hourly firing rates Information is from Table A-3, in Appendix A of the PSD application

 submitted to TCEQ on 06/22/2012.

Turbine Duct Burner Total Hourly

Operating CTG Data Heat Input Heat Input Heat Input

Mode Case Number MMBtu/hr MMBtu/hr MMBtu/hr

Maximum Hourly Heat 

Input During Startup

50% Load, 

10 °F 

Ambient, no 

Duct Burner 

Firing

15 1,428.0 0 1,428.0

2. Based on 500 hours per year of startups.

3. CH 4 and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/hr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/hr)

U f = 1/385 scf CO2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO2 , 44.0 lb/lbmole

5. Global Warming Potential factors from Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-7

Startup GHG Emission Calculations - Siemens SGT6-5000F(5) Turbines

Pinecrest Energy Center

2/11/2013
GHG Potential To Emit Emissions From Natural Gas Fired Auxilliary Boiler

EPN Maximum Heat 

Input1 Pollutant Emission Factor GHG Mass 

Emissions CO2e

(MMBtu/yr) (kg/MMBtu)2 (tpy) (tpy)

CO2 53.02 7,679.53 1 7,679.5

131,400 CH4 1.0E-03 0.14 21 3.0

N2O 1.0E-04 0.01 310 4.5

Totals 7,679.7 7,687.1

Note

1. Annual fuel use and heating value of natural gas from Table A-10 State/PSD air permit application

2. Factors based on Table C-1 and C-2 of 40 CFR Part 98, Mandatory Greenhouse Gas Reporting. 

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-8

GHG Emission Calculations - Auxilliary Boiler

Pinecrest Energy Center

Global Warming 

Potential3

AUXBLR

2/11/2013
Table 3-9

GHG Emission Calculations - Natural Gas Piping

Pinecrest Energy Center

GHG Emissions Contribution From Fugitive Natural Gas Piping Components

EPN Source Fluid Count Emission CO2

2 Methane3 Total

Type State Factor1 (tpy) (tpy) (tpy)

scf/hr/comp

Valves Gas/Vapor 600 0.121 0.51 12.73

NG-FUG Flanges Gas/Vapor 2400 0.017 0.29 7.15

Relief Valves Gas/Vapor 5 0.193 0.007 0.17

Sampling Connections Gas/Vapor 10 0.031 0.0022 0.054

Compressors Gas/Vapor 3 0.30 0.006332 0.1578

GHG Mass-Based Emissions 0.81 20.27 21.1

Global Warming Potential 4 1 21

CO2e Emissions 0.81 425.6 426.4

Note

1. Emission factors from Table W-1A of 40 CFR 98 Mandatory Greenhouse Gas Reporting included in the August 3, 2012 Technical Corrections

2. CO 2 emissions based on vol% of CO 2 in natural gas 1.41%

3. CH 4 emissions based on vol% of CH 4 in natural gas 96.10%

4. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Example calculation:

600 valves 0.123 scf gas lbmole 44 lb CO2 8760 hr ton = 0.51 ton/yr

hr * valve scf gas 385 scf lbmole yr 2000 lb

0.0141 scf CO2

2/11/2013
CO2

3 CH44 Total

Volume1 Press. Temp. Press. Temp. Volume2 Annual Annual Annual

(ft3

) (psig) (°F) (psig) (°F) (scf) (tpy) (tpy) (tpy)

1,146 50 50 0 68 5,277 0.0042 0.11

6.7 50 50 0 68 31 0.00002 0.00061

GHG Mass-Based Emissions 0.0043 0.1060 0.11

Global Warming Potential5

1 21

CO2e Emissions 0.0043 2.2 2.2

1. Initial volume is calculated by multpilying the crossectional area by the length of pipe using the following formula: Vi

 = pi * [(diameter in inches/12)/2]2 * length in feet = ft3

2. Final volume calculated using ideal gas law [(PV/ZT)i = (PV/ZT)f]. Vf = Vi (Pi/Pf) (Tf/Ti) (Zf/Zi), where Z is estimated using the following

 equation: Z = 0.9994 - 0.0002P + 3E-08P2

.

3. CO 2 emissions based on vol% of CO2 in natural gas 1.41% from natural gas analysis

4. CH 4 emissions based on vol% of CH4 in natural gas 96.1% from natural gas analysis

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Example calculation:

5277 scf Nat Gas 0.014 scf CO2 lbmole ton = = 0.0042 ton/yr CO2

yr scf Nat Gas 385 scf 2000 lb

Location

Turbine Fuel Line Shutdown/Maintenance

Small Equipment/Fugitive Component 

Repair/Replacement

44 lb CO2

lbmole

TABLE 3-10

Gaseous Fuel Venting During Turbine Shutdown/Maintenance and

Small Equipment and Fugitive Component Repair/Replacement

Pinecrest Energy Center

Initial Conditions Final Conditions

2/11/2013
GHG Emissions Contribution From Diesel Combustion In Emergency Engines

Assumptions Generator Fire Water 

Pump

Ann.Operating Schedule 100 100 hours/year

Power Rating 1,072 500 hp

Max Fuel Combustion 57.3 24.7 gal/hr

Heating Value of No. 2 Fuel Oil1 0.138 0.138 MMBtu/gal

Max Hourly Heat Input 7.9 3.4 MMBtu/hr

Annual Heat Input 790.7 340.9 MMBtu/yr

EPN Heat Input Pollutant Emission 

Factor

GHG Mass 

Emissions CO2e

(MMBtu/yr) (kg/MMBtu)2 (tpy) (tpy)

CO2 73.96 64.3 1 64.3

EMGEN1-STK 790.7 CH4 3.0E-03 0.0026 21 0.1

N2O 6.0E-04 0.0005 310 0.2

64.33 64.5

CO2 73.96 27.7 1 27.7

FWP1-STK 340.9 CH4 3.0E-03 0.0011 21 0.0

N2O 6.0E-04 0.0002 310 0.1

Totals 27.73 27.8

Calculation Procedure

Annual Emission Rate = annual heat Input X Emission Factor X 2.2 lbs/kg X Global Warming Potential / 2,000 lbs/ton

Note

1. Default high heat value based on Table C-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

2. GHG factors based on Tables C-1 and C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

Table 3-11

GHG Emission Calculations - Emergency Engines

Pinecrest Energy Center

Global 

Warming 

Potential3

2/11/2013
Table 3-12

GHG Emission Calculations - Electrical Equipment Insulated With SF6

Pinecrest Energy Center

Assumptions

Insulated circuit breaker SF6 capacity 400 lb

Estimated annual SF6 leak rate 0.5% by weight

Estimated annual SF6 mass emission rate 0.001 ton/yr

Global Warming Potential1 23,900

Estimated annual CO2e emission rate 23.9 ton/yr

Note

1. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

2/11/2013
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

32

4.0 PREVENTION OF SIGNIFICANT DETERIORATION APPLICABILITY

Because the project emissions increase of GHG is greater than 100,000 ton/yr of CO2e, PSD is 

triggered for GHG emissions. The emissions netting analysis is documented on the attached 

TCEQ PSD netting tables: Table 1F and Table 2F. Note that this is a new Greenfield site and, 

as such, there are no contemporaneous emission changes associated with the project. Also 

included in Appendix A is the “The GHG PSD APPLICABILITY FLOWCHART – NEW 

SOURCES” from the PSD and Title V Permitting Guidance for Greenhouse Gases. 

.
TABLE 1F

AIR QUALITY APPLICATION SUPPLEMENT

Permit No.: 179334, PSD-TX-1298 Application Submittal Date:

Company Pinecrest Energy Center, LLC

RN: RN106444755 Facility Location: 1002 East Park Avenue

City Lufkin County: Angelina

Permit Unit I.D.: GTG/HRSG1 and GTG/HRSG2 Permit Name: Pinecrest Energy Center

Permit Activity:

Project or Process Description: 

Complete for all pollutants with a project POLLUTANTS

emission increase. Ozone CO SO2 PM GHG CO2e

NOx VOC

Nonattainment? (yes or no) No No

Existing site PTE (tpy) 0 0

Proposed project increases (tpy from 2F)3 3,146,393 3,150,162

Is the existing site a major source? If not, is the project a 

major source by itself? (yes or no) Yes

If site is major, is project increase significant? (yes or no) Yes Yes

If netting required, estimated start of construction: 6/1/13

5 years prior to start of construction: 6/1/08 Contemporaneous

estimated start of operation: 10/1/15 Period

Net contemporaneous change, including proposed project, 

from Table 3F (tpy) 3,146,393 3,150,162

FNSR applicable? (yes or no) Yes Yes

1. Other PSD pollutants

2. Nonattainment major source is defined in Table 1 in 30 TAC 116.12(11) by pollutant and county. PSD thresholds

 are found in 40 CFR §51.166(b)(1).

Construction of new combined cycle electric generating plant

This form for GHG only

 New Major Source Modification

3. Sum of proposed emissions minus baseline emissions, increases only. Nonattainment thresholds are found in 

 Table 1 in 30 TAC 116.12(11) and PSD thresholds in 40 CFR §51.166(b)(23).

4. Since there are no contemporaneous decreases which would potentially affect PSD applicability and an impacts analysis

 is not required for GHG emissions, contemporaneous emission changes are not included on this table.

The presentations made above and on the accompanying tables are true and correct to the best of my knowledge.

Signature Title Date

 New Major Source Modification
TABLE 2F

PROJECT EMISSION INCREASE

Pollutant(1): GHG Permit: 101542

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit No.

FIN EPN

1 CTG1/HRSG1 U1-STK 101542 0.00 0.00 1,569,300 1,569,300 2 CTG2/HRSG2 U2-STK 101542 0.00 0.00 1,569,300 1,569,300 3 AUXBLR AUXBLR 101542 0.00 0.00 7,680 7,680 

4 NG-FUG NG-FUG 101542 0.00 0.00 21 21 

5 TRB-MSS TRB-MSS 101542 0.00 0.00 0.11 0 6 EMGEN1 EMGEN1-STK 101542 0.00 0.00 64 64 7 FWP1 FWP1-STK 101542 0.00 0.00 28 28 8 SF6-FUG SF6-FUG 101542 0.00 0.00 0.0010 0.0010 

9

1011121415

Page Subotal(9) 

Actual 

Emissions(3)

Baseline 

Emissions(4)

Proposed 

Emissions(5)

Projected

Actual

Emissions

Difference

(B - A) (6)

Corre
TABLE 2F

PROJECT EMISSION INCREASE

Pollutant(1): CO2e Permit: 101542

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit No.

FIN EPN

1 CTG1/HRSG1 U1-STK 101542 0.00 0.00 1,570,779 1,570,779 2 CTG2/HRSG2 U2-STK 101542 0.00 0.00 1,570,779 1,570,779 3 AUXBLR AUXBLR 101542 0.00 0.00 7,687 7,687 

4 NG-FUG NG-FUG 101542 0.00 0.00 426 426 

5 TRB-MSS TRB-MSS 101542 0.00 0.00 426 426 

6 EMGEN1 EMGEN1-STK 101542 0.00 0.00 65 65 

7 FWP1 FWP1-STK 10154289

101112131415

Page Subotal(9) 

Actual 

Emissions(3)

Baseline 

Emissions(4)

Proposed 

Emissions(5)

Projected

Actual

Emissions

Difference

(B - A) (6)

Corre

Page Subotal 

All emissions must be listed in tons per year (tpy). The same baseline period must apply for all facilities for a given NSR pollutant.

1. Individual Table 2F's should be used to summarize the project emission increase for each criteria pollutant.2. Emission Point Number as designated in NSR Permit or Emissions Inventory.3. All records and calculations for these values must be available upon request.4. Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained in the Table 2F supplement.5. If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement.6. Proposed Emissions (column B) Baseline Emissions (column A).7. Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement.8. Obtained by subtracting the correction from the difference. Must be a positive number.9. Sum all values for this page.
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

36

5.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT)

The PSD rules define BACT as:

Best available control technology means an emissions limitation (including a visible 

emission standard) based on the maximum degree of reduction for each pollutant 

subject to regulation under [the] Act which would be emitted from any proposed major 

stationary source or major modification which the Administrator, on a case-by-case 

basis, taking into account energy, environmental, and economic impacts and other 

costs, determines is achievable for such source or modification through application of 

production processes or available methods, systems, and techniques, including fuel 

cleaning or treatment or innovative fuel combustion techniques for control of such 

pollutant. In no event shall application of best available control technology result in 

emissions of any pollutant which would exceed the emissions allowed by any applicable 

standard under 40 CFR parts 60 and 61. If the Administrator determines that 

technological or economic limitations on the application of measurement methodology to 

a particular emissions unit would make the imposition of an emissions standard 

infeasible, a design, equipment, work practice, operational standard, or combination 

thereof, may be prescribed instead to satisfy the requirement for the application of best 

available control technology. Such standard shall, to the degree possible, set forth the 

emissions reduction achievable by implementation of such design, equipment, work 

practice or operation, and shall provide for compliance by means which achieve 

equivalent results.15

In the EPA guidance document titled PSD and Title V Permitting Guidance for Greenhouse 

Gases, EPA recommended the use of the Agency’s five-step “top-down” BACT process to 

determine BACT for GHGs.16 In brief, the top-down process calls for all available control 

technologies for a given pollutant to be identified and ranked in descending order of control 

effectiveness. The permit applicant should first examine the highest-ranked (“top”) option. The 

top-ranked options should be established as BACT unless the permit applicant demonstrates to 

the satisfaction of the permitting authority that technical considerations, or energy, 

environmental, or economic impacts justify a conclusion that the top ranked technology is not 

“achievable” in that case. If the most effective control strategy is eliminated in this fashion, then 

the next most effective alternative should be evaluated, and so on, until an option is selected as 

BACT.

EPA has broken down this analytical process into the following five steps:

Step 1: Identify all available control technologies.

Step 2: Eliminate technically infeasible options.

Step 3: Rank remaining control technologies.

 

15 40 C.F.R. § 52.21(b)(12.)

16 EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 18 (Nov. 2010).
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

37

Step 4: Evaluate most effective controls and document results.

Step 5: Select the BACT.

5.1 BACT FOR THE COMBINED CYCLE COMBUSTION TURBINE

5.1.1 Step 1: Identify All Available Control Technologies

5.1.1.1 Inherently Lower-Emitting Processes/Practices/Designs

A summary of available, lower greenhouse gas emitting processes, practices, and designs for 

combustion turbine power generators is presented below. The proposed energy efficiency 

processes, practices and designs discussed in Step 1 will be the same for three models of 

combustion turbines being considered for this site: the General Electric 7FA, the Siemens 

SGT6-5000F(4), and the Siemens SGT6-5000F(5). The BACT limits proposed in Step 5 are 

specific to each turbine model. 

5.1.1.1.1

Combustion Turbine Design

Combustion Turbine Energy Efficiency Processes, Practices, and Designs

CO2 is a product of combustion of fuel containing carbon, which is inherent in any power 

generation technology using fossil fuel. It is not possible to reduce the amount of CO2

generated from combustion, as CO2 is the essential product of the chemical reaction between 

the fuel and the oxygen in which it burns, not a byproduct caused by imperfect combustion. As 

such, there is no technology available that can effectively reduce CO2 generation by adjusting 

the conditions in which combustion takes place. 

The only effective means to reduce the amount of CO2 generated by a fuel-burning power plant 

is to generate as much electric power as possible from the combustion, thereby reducing the 

amount of fuel needed to meet the plant’s required power output. This result is obtained by 

using the most efficient generating technologies available, so that as much of the energy 

content of the fuel as possible goes into generating power.

The most efficient way to generate electricity from a natural gas fuel source is the use of a 

combined cycle design. For fossil fuel technologies, efficiency ranges from approximately 

30-50% (higher heating value [HHV]). A typical coal-fired Rankine cycle power plant has a base 

load efficiency of approximately 30% (HHV), while a modern F-Class natural gas fired combined 

cycle unit operating under optimal conditions has a base load efficiency of approximately 50% 

(HHV).

Combined cycle units operate based on a combination of two thermodynamic cycles: the 

Brayton and the Rankine cycles. A combustion turbine operates on the Brayton cycle and the 

HRSG and steam turbine operate on the Rankine cycle. The combination of the two 

thermodynamic cycles allows for the high efficiency associated with combined cycle plants.
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In addition to the high-efficiency primary components of a combustion turbine, there are a 

number of other design features employed within the turbine that can improve the overall 

efficiency of the machine. These additional features include those summarized below.

Periodic Burner Tuning

Modern F-Class combustion turbines have regularly scheduled maintenance programs. These 

maintenance programs are important for the reliable operation of the unit, as well as to maintain 

optimal efficiency. As the combustion turbine is operated, the unit experiences degradation and 

loss in performance. The combustion turbine maintenance program helps restore the 

recoverable lost performance. The maintenance program schedule is determined by the 

number of hours of operation and/or turbine starts. There are three basic maintenance levels, 

commonly referred to as combustion inspections, hot gas path inspections, and major 

overhauls. Combustion inspections are the most frequent of the maintenance cycles. As part of 

this maintenance activity, the combustors are tuned to restore highly efficient low-emission 

operation.

Reduction in Heat Loss

Modern F-Class combustion turbines have high operating temperatures. The high operating 

temperatures are a result of the heat of compression in the compressor along with the fuel 

combustion in the burners. To minimize heat loss from the combustion turbine and protect the 

personnel and equipment around the machine, insulation blankets are applied to the 

combustion turbine casing. These blankets minimize the heat loss through the combustion 

turbine shell and help improve the overall efficiency of the machine.

Instrumentation and Controls

Modern F-Class combustion turbines have sophisticated instrumentation and controls to 

automatically control the operation of the combustion turbine. The control system is a digitaltype and is supplied with the combustion turbine. The distributed control system (DCS) controls 

all aspects of the turbine’s operation, including the fuel feed and burner operations, to achieve 

efficient low-NOX combustion. The control system monitors the operation of the unit and 

modulates the fuel flow and turbine operation to achieve optimal high-efficiency low-emission 

performance for full-load and part-load conditions.

5.1.1.1.2

The HRSG takes waste heat from the combustion turbine exhaust and uses the waste heat to 

convert boiler feed water to steam. Duct burning involves burning additional natural gas in the 

ducts to the heat recovery boiler, which increases the temperature of the exhaust coming from 

the combustion turbines and thereby creates additional steam for the steam turbine. The duct 

burner firing provides additional power generation capacity during periods of high electrical 

demand.

Heat Recovery Steam Generator Energy Efficiency Processes, Practices, 

and Designs
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The modern F-Class combustion turbine-based combined cycle HRSG is generally a horizontal, 

natural circulation, drum-type heat exchanger designed with three pressure levels of steam 

generation, reheat, split superheater sections with interstage attemperation, post-combustion 

emissions control equipment, and condensate recirculation. The HRSG is designed to 

maximize the conversion of the combustion turbine exhaust gas waste heat to steam for all 

plant ambient and load conditions. Maximizing steam generation will increase the steam 

turbine’s power generation, which maximizes plant efficiency. 

Heat Exchanger Design Considerations

HRSGs are heat exchangers designed to capture as much thermal energy as possible from the 

combustion turbine exhaust gases. This is performed at multiple pressure levels. For a drumtype configuration, each pressure level incorporates an economizer section(s), evaporator 

section, and superheater section(s). These heat transfer sections are made up of many thinwalled tubes to provide surface area to maximize the transfer of heat to the working fluid. Most 

of the tubes also include extended surfaces (e.g., fins). The extended surface optimizes the 

heat transfer, while minimizing the overall size of the HRSG. Additionally, flow guides are used 

to distribute the flow evenly through the HRSG to allow for efficient use of the heat transfer 

surfaces and post-combustion emissions control components. Low-temperature economizer 

sections employ recirculation systems to minimize cold-end corrosion, and stack dampers are 

used for cycling operation to conserve the thermal energy within the HRSG when the unit is off

line.

Insulation

HRSGs take waste heat from the combustion turbine exhaust gas and uses that waste heat to

convert boiler feed water to steam. As such, the temperatures inside the HRSG are nearly 

equivalent to the exhaust gas temperatures of the turbine. For F-Class combustion turbines, 

these temperatures can approach 1,200°F. HRSGs are designed to maximize the conversion of 

the waste heat to steam. One aspect of the HRSG design in maximizing this waste heat 

conversion is the use of insulation. Insulation minimizes heat loss to the surrounding air, 

thereby improving the overall efficiency of the HRSG. Insulation is applied to the HRSG panels 

that make up the shell of the unit, to the high-temperature steam and water lines, and typically 

to the bottom portion of the stack.

Minimizing Fouling of Heat Exchange Surfaces

HRSGs are made up of a number of tubes within the shell of the unit that are used to generate 

steam from the combustion turbine exhaust gas waste heat. To maximize this heat transfer, the 

tubes and their extended surfaces need to be as clean as possible. Fouling of the tube surfaces 

impedes the transfer of heat. Fouling occurs from the constituents within the exhaust gas 

stream. To minimize fouling, filtration of the inlet air to the combustion turbine is performed. 

Additionally, cleaning of the tubes is performed during periodic outages. By reducing the 

fouling, the efficiency of the unit is maintained.

Minimizing Vented Steam and Repair of Steam Leaks

As with all steam-generated power facilities, minimization of steam vents and repair of steam 

leaks is important in maintaining the plant’s efficiency. A combined cycle facility has just a few 
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locations where steam is vented from the system, including at the deaerator vents, blowdown 

tank vents, and vacuum pumps/steam jet air ejectors. These vents are necessary to improve 

the overall heat transfer within the HRSG and condenser by removing solids and air that 

potentially blankets the heat transfer surfaces lowering the equipment’s performance. 

Additionally, power plant operators are concerned with overall efficiency of their facilities. 

Therefore, steam leaks are repaired as soon as possible to maintain facility performance. 

Minimization of vented steam and repair of steam leaks will be performed for this project. 

5.1.1.1.3

The steam turbine for this project will be a modern, high-efficiency, reheat, condensing unit. 

Steam turbines have been in operation for over a century, and are generally classified as 

impulse or reaction. However, most modern turbines employ both impulse and reaction blading. 

The overall efficiency of the unit is affected by a number of items, including the inlet steam 

conditions, the exhaust steam conditions, the blading design, the turbine seals, and the 

generator efficiency.

Steam Turbine Energy Efficiency Processes, Practices, and Designs

Use of Reheat Cycles

The efficiency of a steam turbine is directly related to the steam conditions entering the turbine. 

The higher the steam temperature and pressure, the higher the overall efficiency. To achieve 

the higher temperatures, reheat cycles are employed. This is necessary to minimize the 

moisture content of the exhaust steam. If the moisture content of the exhaust steam is too high, 

erosion of the last-stage turbine blades occurs. This cycle reheats partially expanded steam 

from the steam turbine. For a modern combined cycle facility, the high-pressure inlet and 

intermediate-pressure inlet steam temperatures typically are 1,050°F and above, and the highpressure steam turbine inlet pressure is typically in the range of 1,800-2,400 psig.

Use of Exhaust Steam Condenser

Steam turbine efficiency is also improved by lowering the exhaust steam conditions of the unit. 

The lower the exhaust pressure, the higher the overall turbine efficiency. For high-efficiency 

units, the exhaust steam is saturated under vacuum conditions. This is accomplished by the 

use of a condenser. The condenser is typically a shell and tube heat exchanger with cooling 

water flowing through the tubes and the turbine exhaust steam condensing in the shell. The 

condensing steam creates a vacuum in the condenser, which increases steam turbine 

efficiency. This vacuum is dependent on the temperature of the cooling water. As the 

temperature of the cooling water is lowered, the absolute vacuum attainable is lowered and the 

steam turbine is more efficient.

Efficient Blading Design

Blading design also affects the overall efficiency of the turbine. As noted earlier, steam turbines 

have been used to generate power for over a century, and are either impulse or reaction design. 

The blade design has evolved for high-efficiency transfer of the energy in the steam to power 

generation. Additionally, 3-D computer-aided design technology is also employed to provide the 
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highest efficiency blade design. Blade materials are also important components in blade 

design, which allow for high-temperature and large exhaust areas to improve performance.

Turbine seals are also important in the overall performance of the steam turbine. The highpressure steam will leak to the atmosphere along the turbine shaft, as well as bypass the 

turbine stages if sealing is not employed. The steam turbine designers have multiple steam 

seal designs to obtain the highest efficiency from the steam turbine.

Efficient Steam Turbine Generator Design

The steam turbine generator is also a key element in the overall performance of the steam 

turbine. The modern generator is a high-efficiency unit. The generator for modern steam 

turbines is typically cooled by one of three methods. These methods are open-air cooling, 

totally enclosed water to air cooling, or hydrogen cooling. These cooling methods allow for the 

highest efficiency of the generator, resulting in an overall high-efficiency steam turbine. 

According to Siemens representatives, there is no energy penalty between the three cooling 

methods. The cooling method for the PCEC steam turbine will be either totally enclosed water 

to air cooling or hydrogen cooling. The selection of the cooling method will be made by the 

equipment provider based on atmospheric conditions for the particular site. 

5.1.1.1.4

There are a number of other components within the combined cycle plant that help improve 

overall efficiency, including:

Plant-wide Energy Efficiency Processes, Practices, and Designs

• Fuel gas preheating – The overall efficiency of the combustion turbine is 

increased with increased fuel inlet temperatures. For the F-Class combustion 

turbine based combined cycle, the fuel gas is generally heated with high 

temperature water from the HRSG. This improves the efficiency of the 

combustion turbine.

• Drain operation – Drains are required to allow for draining the equipment for 

maintenance (i.e., maintenance drains), and also to allow condensate to be 

removed from the steam piping and drains for operation (i.e., operation drains). 

Operation drains are generally controlled to minimize the loss of energy from the 

cycle. This is accomplished by closing the drains as soon as the appropriate 

steam conditions are achieved.

• Multiple combustion turbine/HRSG trains – Multiple combustion 

turbine/HRSG trains help with part-load operation. The multiple trains allow the 

unit to achieve higher overall plant part-load efficiency by shutting down a train 

operating at less efficient part-load conditions and ramping up the remaining 

train to high-efficiency full-load operation.

• Boiler feed pump fluid drives – The boiler feed pumps are used as the means 

to impart high pressure on the working fluid. The pumps require considerable 

power. To minimize the power consumption at part-loads, the use of fluid drives 

or variable-frequency drives can be employed. For this project, fluid drives are 
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being used to minimize power consumption at part-load, improving the facility’s 

overall efficiency.

5.1.1.2 Add-On Controls

In addition to power generation process technology options discussed above, it is appropriate to 

consider add-on technologies as possible ways to capture GHG emissions that are emitted from 

natural gas combustion in the proposed project’s CTG/HRSG units and to prevent them from 

entering the atmosphere. These emerging carbon capture and storage (CCS) technologies 

generally consist of processes that separate CO2 from combustion process flue gas, and then 

inject it into geologic formations such as oil and gas reservoirs, unmineable coal seams, and 

underground saline formations. Of the emerging CO2 capture technologies that have been 

identified, only amine absorption is currently commercially used for state-of-the-art CO2

separation processes. Amine absorption has been applied to processes in the petroleum 

refining and natural gas processing industries and for exhausts from gas-fired industrial boilers. 

Other potential absorption and membrane technologies are currently considered developmental.

The U.S. Department of Energy’s National Energy Technology Laboratory (DOE-NETL) 

provides the following brief description of state-of-the-art post-combustion CO2 capture 

technology and related implementation challenges:

“...In the future, emerging R&D will provide numerous cost-effective technologies for 

capturing CO2 from power plants. At present, however, state-of-the-art technologies for 

existing power plants are essentially limited to amine absorbents. Such amines are used 

extensively in the petroleum refining and natural gas processing industries... Amine solvents 

are effective at absorbing CO2 from power plant exhaust streams—about 90 percent 

removal—but the highly energy-intensive process of regenerating the solvents decreases 

plant electricity output...”

17

The DOE-NETL adds:

“...Separating CO2 from flue gas streams is challenging for several reasons:

• CO2 is present at dilute concentrations (13-15 volume percent in coal-fired systems 

and 3-4 volume percent in gas-fired turbines) and at low pressure (15-25 pounds per 

square inch absolute [psia]), which dictates that a high volume of gas be treated.

 

17 DOE-NETL, Carbon Sequestration: FAQ Information Portal, 

http://extsearch1.netl.doe.gov/search?q=cache:e0yvzjAh22cJ:www.netl.doe.gov/technologies/carbon_seq/FAQs/te

ch-status.html+emerging+R%26D&access=p&output=xml_no_dtd&ie=UTF8&client=default_frontend&site=default_collection&proxystylesheet=default_frontend&oe=ISO-8859-1 (last visited 

Feb. 27, 2012). 
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• Trace impurities (particulate matter, sulfur dioxide, nitrogen oxides) in the flue gas 

can degrade sorbents and reduce the effectiveness of certain CO2 capture 

processes.

• Compressing captured or separated CO2 from atmospheric pressure to pipeline 

pressure (about 2,000 psia) represents a large auxiliary power load on the overall 

power plant system...”

18

For the combustion turbines being considered for this project, the CO2 stack concentration at 

base load and ISO conditions for the General Electric 7FA is 3.9 vol% without duct burner firing 

and 5.4 vol% with duct burner firing; the Siemens SGT6-5000F(4) is 3.9 vol% without duct 

burner firing and 5.2 vol% with duct burner firing; and the Siemens SGT6-5000F(5) is 3.8 vol% 

without duct burner firing and 4.9 vol% with duct burner firing. 

If CO2 capture can be achieved at a power plant, it would need to be routed to a geologic 

formation capable of long-term storage. The long-term storage potential for a formation is a 

function of the volumetric capacity of a geologic formation and CO2 trapping mechanisms within 

the formation, including dissolution in brine, reactions with minerals to form solid carbonates, 

and/or adsorption in porous rock. The DOE-NETL describes the geologic formations that could 

potentially serve as CO2 storage sites as follows:

“Geologic carbon dioxide (CO2) storage involves the injection of supercritical CO2 into deep 

geologic formations (injection zones) overlain by competent sealing formations and geologic 

traps that will prevent the CO2 from escaping. Current research and field studies are 

focused on developing better understanding of 11 major types of geologic storage reservoir 

classes, each having their own unique opportunities and challenges. Understanding these 

different storage classes provides insight into how the systems influence fluids flow within 

these systems today, and how CO2 in geologic storage would be anticipated to flow in the 

future. The different storage formation classes include: deltaic, coal/shale, fluvial, alluvial, 

strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef. 

Basaltic interflow zones are also being considered as potential reservoirs. These storage 

reservoirs contain fluids that may include natural gas, oil, or saline water; any of which may 

impact CO2 storage differently...”19

5.1.2 Step 2: Eliminate Technically Infeasible Options

Amine absorption technology for CO2 capture has been applied to processes in the petroleum 

refining and natural gas processing industries, so it is technically feasible to apply that 

technology to exhausts for power plants. However, that technology has not been commercially 

available to power plants gas turbine exhausts, which have considerably larger flow volumes 

and considerably lower CO2 concentrations. The high energy demand, high water demand, 

 

18 Id.

19 DOE-NETL, Carbon Sequestration: Geologic Storage Focus Area,

http://www.netl.doe.gov/technologies/carbon_seq/corerd/storage.html (last visited Feb. 27, 2012)
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technical difficulties and economic costs associated with CCS are addressed in Step 4 of this 

section.

5.1.3 Step 3: Rank Remaining Control Technologies

As all of the energy efficiency related processes, practices, and designs discussed in Section 

5.1.1.1 of this application are being proposed for this project, a ranking of the control 

technologies is not necessary for this application. As documented in Step 4 below, 

implementation of CCS technology is not economically reasonable, leaving energy efficiency 

measures as the only feasible emission control options. 

5.1.4 Step 4: Evaluate Most Effective Controls and Document Results

As all of the energy efficiency related processes, practices, and designs discussed in Section 

5.1.1.1 of this application are being proposed for this project, an examination of the energy, 

environmental, and economic impacts of the efficiency designs is not necessary for this 

application. 

In this section, PCEC addresses the potential energy, environmental, and economic feasibility of 

implementing CCS technology as BACT for GHG emissions from the proposed project’s gas 

turbine/HRSG trains. Each component of CCS technology (i.e., capture and compression, 

transport, and storage) is discussed separately.

5.1.4.1 CO2 Capture and Compression

Though amine absorption technology for CO2 capture has been applied to processes in the 

petroleum refining and natural gas processing industries and to exhausts from gas-fired 

industrial boilers, it is more difficult to apply to power plant gas turbine exhausts, which have 

considerably larger flow volumes and considerably lower CO2 concentrations. The Obama 

Administration’s Interagency Task Force on Carbon Capture and Storage confirms this in its 

recently completed report on the current status of development of CCS systems:

“Current technologies could be used to capture CO2 from new and existing fossil energy 

power plants; however, they are not ready for widespread implementation primarily because 

they have not been demonstrated at the scale necessary to establish confidence for power 

plant application. Since the CO2 capture capacities used in current industrial processes are 

generally much smaller than the capacity required for the purposes of GHG emissions 

mitigation at a typical power plant, there is considerable uncertainty associated with 

capacities at volumes necessary for commercial deployment.”20 

 

20 Report of the Interagency Task Force on Carbon Capture and Storage at 50 (Aug. 2010). 
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In its current CCS research program plans, the DOE-NETL confirms that commercial CO2

capture technology for large-scale power plants is not yet available and suggests that it may not 

be available until at least 2020:

“The overall objective of the Carbon Sequestration Program is to develop and advance 

CCS technologies that will be ready for widespread commercial deployment by 2020. 

To accomplish widespread deployment, four program goals have been established: 

(1) Develop technologies that can separate, capture, transport, and store CO2 using

either direct or indirect systems that result in a less than 10 percent increase in the 

cost of energy by 2015; 

(2) Develop technologies that will support industries’ ability to predict CO2 storage 

capacity in geologic formations to within ±30 percent by 2015; 

(3) Develop technologies to demonstrate that 99 percent of injected CO2 remains in 

the injection zones by 2015;

(4) Complete Best Practices Manuals (BPMs) for site selection, characterization, site 

operations, and closure practices by 2020. Only by accomplishing these goals will 

CCS technologies be ready for safe, effective commercial deployment both 

domestically and abroad beginning in 2020 and through the next several decades.”21A

To corroborate that commercial availability of CO2 capture technology for large-scale power 

plant projects will not occur for several more years, Alstom, one of the major developers of 

commercial CO2 capture technology using post-combustion amine absorption, post-combustion 

chilled ammonia absorption, and oxy-combustion, states on its web site that its CO2 capture 

technology will become commercially available in 2015.22B

 However, it should be noted that in 

committing to this timeframe, the company does not indicate whether such technology will be 

able to handle the volume of CO2 emissions generated by a project of the size of PCEC. 

Another challenge of CO2 capture is conservation of water resources. A modern natural gas 

fired combined cycle facility requires four to five million gallons of water per day for condenser 

cooling and boiler make-up service. This amount will vary based on ambient temperature and 

humidity's as well as the level of duct firing in the HRSG. Adding CO2 separation facilities and 

compression equipment significantly increases the cooling water requirements of a generating 

station. Studies have indicated that the water consumption of a natural fired combined cycle 

facility with CCS may have an increased water consumption of more than 90%. 

5.1.4.2 CO2 Transport

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the 

proposed project, the high-volume CO2 stream generated would need to be transported to a 

facility capable of storing it. Potential geologic storage sites in Texas, Louisiana, and 

 

21 DOE-NETL, Carbon Sequestration Program: Technical Program Plan, at 10 (Feb. 2011).

22 Alstom, Alstom’s Carbon Capture Technology Commercially “Ready to Go” by 2015, Nov.30, 2010, 

http://www.alstom.com/australia/news-and-events/pr/ccs2015/ (last visited Sept.28, 2011).
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Mississippi to which CO2 could be transported if a pipeline was constructed are delineated on 

the map found at the end of Section 5.23 The potential length of such a CO2 transport pipeline is 

uncertain due to the uncertainty of identifying a site(s) that is suitable for large-scale, long-term 

CO2 storage. The hypothetical minimum length required for any such pipeline(s) is the distance 

to the closest site with recognized potential for some geological storage of CO2, which is an 

enhanced oil recovery (EOR) reservoir site located within 45 miles of the proposed project.

However, none of the EOR reservoir or other geologic formation sites have yet been technically 

demonstrated for large-scale, long-term CO2 storage. 

In comparison, the closest site that is currently being field-tested to demonstrate its capacity for 

large-scale geological storage of CO2 is the Southwest Regional Partnership on Carbon 

Sequestration’s (SWP) SACROC test site, which is located in Scurry County, Texas 

approximately 490 miles away (see the map at the end of Section 5 for the test site location). 

Therefore, to access this potentially large-scale storage capacity site, assuming that it is 

eventually demonstrated to indefinitely store a substantial portion of the large volume of CO2

generated by the proposed project, a very long and sizable pipeline would need to be 

constructed to transport the large volume of high-pressure CO2 from the plant to the storage 

facility, thereby rendering implementation of a CO2 transport system infeasible.

5.1.4.3 CO2 Storage

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the 

proposed project and that the CO2 could be transported economically, the feasibility of CCS 

technology would still depend on the availability of a suitable sequestration site. The suitability 

of potential storage sites is a function of volumetric capacity of their geologic formations, CO2

trapping mechanisms within formations (including dissolution in brine, reactions with minerals to 

form solid carbonates, and/or adsorption in porous rock), and potential environmental impacts 

resulting from injection of CO2 into the formations. Potential environmental impacts resulting 

from CO2 injection that still require assessment before CCS technology can be considered 

feasible include:

• Uncertainty concerning the significance of dissolution of CO2 into brine,

• Risks of brine displacement resulting from large-scale CO2 injection, including a 

pressure leakage risk for brine into underground drinking water sources and/or surface 

water,

• Risks to fresh water as a result of leakage of CO2, including the possibility for damage to 

the biosphere, underground drinking water sources, and/or surface water,24

• Potential effects on wildlife.

and

 

23 Susan Hovorka, University of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, New 

Developments: Solved and Unsolved Questions Regarding Geologic Sequestration of CO2 as a Greenhouse Gas 

Reduction Method (GCCC Digital Publication #08-13) at slide 4 (Apr. 2008), available at: 

http://www.beg.utexas.edu/gccc/forum/codexdownloadpdf.php?ID=100(last visited Feb. 27, 2012).

24 Id.
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Potentially suitable storage sites, including EOR sites and saline formations, exist in Texas, 

Louisiana, and Mississippi. In fact, sites with such recognized potential for some geological 

storage of CO2 are located within 45 miles of the proposed project, but such nearby sites have 

not yet been technically demonstrated with respect to all of the suitability factors described 

above. In comparison, the closest site that is currently being field-tested to demonstrate its 

capacity for geological storage of the volume of CO2 that would be generated by the proposed 

power unit, i.e., SWP’s SACROC test site, is located in Scurry County, Texas approximately 490 

miles away. It should be noted that, based on the suitability factors described above, currently 

the suitability of the SACROC site or any other test site to store a substantial portion of the large 

volume of CO2 generated by the proposed project has yet to be fully demonstrated.

Based on the reasons provided above, PCEC believes that CCS technology should be 

eliminated from further consideration as a potential feasible control technology for purposes of 

this BACT analysis. However, to answer possible questions that the public or the EPA may 

have concerning the relative costs of implementing hypothetical CCS systems, PCEC has 

estimated such costs. Construction of a carbon capture system at the PCEC site would require 

installation of the following major pieces of equipment:

• Two Amine Scrubber Vessels

• Two CO2 Strippers

• Four Amine Transfer Pumps

• Four Flue Gas Fans

• Four CO2 Gas Compressor

• One Amine Storage Tank

The estimated costs associated with implementation of a carbon capture system at the PCEC

Plant are shown in the table below. A control cost for implementing CCS in terms of $/ton of 

CO2 avoided was calculated using the “cost of electricity” methodology outlined in the U.S. 

Department of Energy document “Cost and Performance Baseline for Fossil Energy Plants 

Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision2, November 2010, 

DOE/NETL-2010/1397.

Two Combustion Turbines 

and One Steam Turbine 

Without CCS

Two Combustion Turbines 

and One Steam Turbine With 

CCS

Estimated Plant Construction 

Cost

$443,800,000 $974,000,000

Net Power Output (MW) 688.4 595.3

Net Plant HHV efficiency 49.9% 42.9%

Annualized Cost of CO2

Capture

$242,608,288/yr

Annualized Cost of CO2

Transport

$3,883,000/yr
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Annualized Cost of CO2

Storage

$27,542,874/yr

Cost-of-Electricity (COE) 

($/MWh) @ 85% capacity 

factor

73.3 $/MWh 125.8 $/MWh

CO2 Emissions (Siemens 

SGT6-5000F(5)) 

3,238,586

tons/yr

323,858.6 tons/yr

Cost of CO2 Avoided $92.65/ton CO2

In addition to the high construction and operating costs associated with CCS, the carbon 

capture equipment requires a substantial amount of energy to operate, thereby reducing the net 

electrical output of the plant. Operation of carbon capture equipment at a typical natural gas 

fired combined cycle plant is estimated to reduce the net energy efficiency of the plant from 

approximately 50% (HHV) to approximately 42.9% (HHV).25 

5.1.5 Step 5: Select BACT

PCEC proposes as BACT for this project, the following energy efficiency processes, practices, 

and designs for the proposed combined cycle combustion turbines: 

• Use of Combined Cycle Power Generation Technology

• Combustion Turbine Energy Efficiency Processes, Practices, and Designs

o 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 Designs

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 Designs

o Use of Reheat Cycles

o Use of Exhaust Steam Condenser

o Efficient Blading Design

o Efficient Generator Design

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

o Fuel gas preheating

o Drain operation

o Multiple combustion turbine/HRSG trains

 

25 US Department of Energy, National Energy Technology Laboratory, “Costs and Performance Baseline For Fossil 

Energy Plants, Volume 1 - Bituminous Coal and Natural Gas to Energy”, Revision 2, November 2010
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o Boiler feed pump fluid drive design

To determine the appropriate heat-input efficiency limit, PCEC started with the turbine’s design 

base load net heat rate for combined cycle operation and then calculated a compliance margin 

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

considered for this project are as follows: the General Electric 7FA design base load net heat 

rate is 6674 Btu/kWhr (HHV) without duct burner firing and 7051 Btu/kWhr (HHV) with duct 

burner firing; the Siemens SGT6-5000F(4) design base load net heat rate is 6782 Btu/kWhr 

(HHV) without duct burner firing and 7045 Btu/kWhr (HHV) with duct burner firing; and the 

Siemens SGT6-5000F(5) design base load net heat rate is 6845 Btu/kWhr (HHV) without duct 

burner firing and 7050 Btu/kWhr (HHV) with duct burner firing. Note that these rates reflect the 

facility’s “net” power production, meaning the denominator is the amount of power provided to 

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

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

BACT determinations, the net heat rate without duct firing is used to calculate the heat-input 

efficiency limit.

To determine an appropriate heat rate limit for the permit, the following compliance margins are 

added to the base heat rate limit: 

• A 3.3% design margin reflecting the possibility that the constructed facility will not be 

able to achieve the design heat rate.

• A 6% performance margin reflecting efficiency losses due to equipment degradation 

prior to maintenance overhauls.

• A 3% degradation margin reflecting the variability in operation of auxiliary plant

equipment due to use over time. 

Design and construction of a combined-cycle power plant involves many assumptions about 

anticipated performance of the many elements of the plant, which are often imprecise or not 

reflective of conditions once installed at the site. As a consequence, the facility also calculates 

an “Installed Base Heat Rate”, which represents a design margin of 3.3% to address such items 

as equipment underperformance and short-term degradation. 

To establish an enforceable BACT condition that can be achieved over the life of the facility, the 

permit limit must also account for anticipated degradation of the equipment over time between 

regular maintenance cycles. The manufacturer’s degradation curves project anticipated 

degradation rate of 5% within the first 48,000 hours of the gas turbine’s useful life; they do not 

reflect any potential increase in this rate which might be expected after the first major overhaul 

and/or as the equipment approaches the end of its useful life. Further, the projected 5% 

degradation rate represents the average, and not the maximum or guaranteed, rate of 

degradation for the gas turbines. Therefore, PCEC proposes that, for purposes of deriving an 

enforceable BACT limitation on the proposed facility’s heat rate, gas turbine degradation may 

reasonably be estimated at 6% of the facility’s heat rate. 
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Finally, in addition to the heat rate degradation from normal wear and tear on the combustion 

turbines, PCEC is also providing a reasonable compliance margin based on potential 

degradation in other elements of the combined cycle plant that would cause the overall plant 

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

recovery steam generator, steam turbine, heat transfer, cooling tower, and ancillary equipment 

such as pumps and motors is also expected to occur over the course of a major maintenance 

cycle. 

As a result of these adjustments, PCEC is proposing the following output based CO2/MWh 

BACT limits for the Project, on a 12 month rolling average, excluding startup hours: 

Turbine Model Gross Heat 

Rate With 

Duct Firing

(Btu/kWh) 

(HHV)

Output Based 

Emission Limit With 

Duct Firing (lb

CO2/MWh) gross

General Electric 

7FA.05

7925.0 942.0

Siemens SGT6-

5000F(4)

7649.0 909.2

Siemens SGT6-

5000F(5)

7679.0 912.7

The calculation of the heat rates and the equivalent lb CO2/MWhr is provided on Tables 5-2, 5-

3, and 5-4 of this application. While energy efficiency will be a consideration for final selection 

of a turbine, other considerations will include the capacity of the turbine, cost, reliability, and 

predicted longevity of the turbines.

While starting up the combustion turbines following ignition, a large portion of the energy input 

to the combustion turbine is used for heating the turbine casings and rotors, boiler tubes, main 

steam piping, and other portions of the thermal system rather than the production of electricity. 

During this startup period, the steam turbine does not generate electricity in a combined cycle 

mode until the thermal equipment is at an appropriate operating temperature and sufficient 

steam is produced in the heat recovery steam generator. Therefore, PCEC proposes that the 12 

month rolling average output based BACT limits exclude startup hours. For purposes of 

compliance with the emission limits for non-GHG pollutants, the startup period is defined as the 

period of time when there is measurable fuel flow to the combustion turbine and ends when the 

combustion turbine load reaches 60 percent. However, for purposes of an output based GHG

emission limit, the plant start up period will be defined as the period of time when there is 

measurable fuel flow to the combustion turbine and ends when the steam turbine is 

synchronized to the electrical grid. The annual emissions of GHG and CO2e during periods of 

startup are provided on Tables 3-3, 3-5, and 3-7. 
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On March 27, 2012, the EPA proposed New Source Performance Standard (NSPS), Subpart 

TTTT, that would control GHG emissions from new power plants.26 The proposed rule would 

apply to fossil-fuel fired electric generating units that generate electricity for sale and are larger 

than 25 MW. The EPA proposed that new power plants meet a twelve month rolling average 

output based standard of 1,000 lb CO2/MWh gross. The proposed emission rate for the PCEC

turbines on a gross electrical output basis are all well within the emission limit in proposed 

NSPS Subpart TTTT.

PCEC performed a search of the EPA’s RACT/BACT/LAER Clearinghouse for natural gas fired 

combustion turbine generators and found no entries which address BACT for GHG emissions. 

Although not listed in the RACT/BACT/LAER Clearinghouse, a GHG BACT analysis was 

performed by the following natural gas fired power generation facilities: Russell City Energy 

Center, Palmdale Hybrid Power Plant, Lower Colorado River Authority Ferguson Plant, Cricket 

Valley Energy Center, Pioneer Valley Energy Center, Deer Park Energy Center, Channel 

Energy Center, and La Paloma Energy Center. A discussion of the PCEC’s proposed BACT as 

compared to those projects is provided below. Note that the BACT limits represented in these 

permits are typically reported without duct burner firing, so the PCEC without duct burner firing 

BACT limits are used in the comparison.

Palmdale Hybrid Power Project

The application for the Palmdale Hybrid Power Project (PHPP) was submitted in May 2011 and 

a final permit was issued by the Antelope Valley Air Quality Management District on October 18, 

2011. The permit authorizes the construction of two natural-gas-fired GE 7FA combustion 

turbine generators, with 500 MMBtu/hr duct fired heat recovery steam generators, and one 

steam turbine generator to be located in Palmdale, California. The project included a 50 MW, 

251 acre solar thermal array field with a solar steam boiler on the 333 acre site. The permit 

listed a GHG BACT limit of 774 lb CO2/MW-hr source-wide net output and 7,319 Btu/kWhr 

source wide net heat rate, 365 rolling average. 

The application submitted by PHPP represented as BACT, a heat rate of 6,970 Btu/kWh, based 

on the higher heating value (HHV) of natural gas with two CTGs operating at 100% with no solar 

input and with no duct firing.27 The PHPP application did not state whether the 6,970 Btu/kWh 

heat rate represented as BACT, is on a gross electrical output basis or a net electrical output 

basis. A CO2 emission rate of 0.408 short tons of CO2/MW-hr was derived from the heat rate of 

6,970 Btu/Kw-hr, based on a CO2 emission factor of 53.06 kg CO2/MMBtu. 0.408 short tons of 

CO2/MW-hr equates to 816 lb CO2/MW-hr. 

The BACT representations in the Palmdale permit and the application cannot be directly 

compared to the representations for the PCEC for the following reasons:

 

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

Units, 77 Fed Reg 22392, April 13, 2012

27 AECOM Memorandum to Lisa Bingham and Joe Lapka, Response to EPA Comments on PHPP GHG BACT 

Analysis, July 15, 2011.
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1. The permit limit of 774 lb CO2/MW-hr does not correspond to the representations in the 

PHPP application. PHPP represented a CO2 emission rate of 0.408 short tons CO2/MWhr (816 lb CO2/MW-hr) for the two combustion turbines, without duct burner firing which 

was derived from the represented design heat rate of 6,970 Btu/kW-hr. The CO2

emission rate associated with the permit heat rate limit of 7,319 Btu/kW-hr would be 

856.9 lb CO2/MW-hr. The basis of the 774 lb CO2/MWhr permit limit is unclear. 

2. The U.S. EPA, Region 9, in its response to comments, stated that the BACT limit was 

being set at 7,319 Btu/kWh to account for “a variety of factors that can affect heat rate, 

including seasonal variations (i.e. temperature, humidity) and equipment degradation”.28 

The 7,319 Btu/kWh limit provides only a 5% compliance margin over the represented 

“design” heat rate of 6,970 Btu/kWh. This is not consistent with the Cricket Valley 

Energy Center, Pioneer Valley Energy Center, Lower Colorado River Authority 

Ferguson Plant, Deer Park Energy, and Channel Energy Center GHG permits discussed 

below. The Palmdale permit does not account for the design margin of the equipment or 

degradation of supporting equipment. 

3. The “design” heat rate proposed by PHPP was for two CTGs operating at 100% load. 

The 365 day rolling average permit limit of 7,319 Btu/kW-hr does not account for lower 

efficiencies at reduced loads. 

Lower Colorado River Authority Ferguson Plant

The application for the LCRA Ferguson Plant was submitted in March 2011. The application 

included two natural-gas-fired GE 7FA combustion turbines, heat recovery steam generators 

without no additional duct firing, and one steam turbine generator to be located in Marble Falls, 

Texas. The permit, issued November 10, 2011, included BACT limits of 0.459 ton CO2/MWh 

(net) on a 365 day rolling average and an average net heat rate of 7,720 Btu/kWh (HHV) on a 

365 day rolling average. 

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins. The proposed emission 

rates on a ton CO2/MWh (net) basis for General Electric 7FA, Siemens SGT6-5000F(4), and 

Siemens SGT6-5000F(5) turbines, without duct firing, are 0.447, 0.455, and 0.467 ton 

CO2/MWh (net). 

Cricket Valley Energy Center

The Cricket Valley Energy Center (CVEC) air permit application proposed the construction of 

three natural-gas-fired GE 7FA combustion turbines, with 596.8 MMBtu/hr duct fired heat 

 

28 U.S. Environmental Protection Agency, Region 9, “Responses to Public Comments on the Proposed Prevention of 

Significant Deterioration Permit for the Palmdale Hybrid Power Project”, Oct. 2011.
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recovery steam generators, and three steam turbine generators to be located in Dover, New 

York. The CVEC application represented that the GE 7FA turbines operating in combined cycle 

mode have a design base heat rate of 6,742 Btu/kW-hr at ISO conditions with no duct firing 

(based on net output). Based upon the design efficiency, and adding a reasonable margin of 

compliance, CVEC proposed a limit of 7,605 Btu/kW-hr (ISO conditions without duct firing) as 

BACT for the proposed project. The draft permit specifies that the facility is required conduct a 

thermal efficiency test on a minimum of one combustion turbine annually.

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins. The highest proposed 

heat rate for the PCEC application is within 2.2% of the proposed CVEC proposed limit and the 

lowest proposed heat rate is 1.0% lower than the proposed CVEC proposed limit. The 

efficiencies from two similarly sized combined cycle electric generating units will not be identical 

due to differences in the properties and variability of the natural gas; the geographic location - 

higher combustion turbine efficiencies are achieved at lower elevations and at cooler ambient 

temperatures due to denser ambient air; differences in combustion turbine designs, heat 

recovery steam generator designs and steam turbine designs; and electric generating unit load 

generation flexibility requirements - operating an electric generating unit as a base load unit is 

more efficient than operating as a load cycling unit to respond to fluctuations in customer 

electricity or steam demands. 

Pioneer Valley Energy Center

The Pioneer Valley Energy Center (PVEC) air permit application proposed the construction of a 

431 MW natural-gas-fired combined cycle turbine generator to be located in Westfield, 

Massachusetts. The PVEC air application proposed to construct a Mitsubishi M501G combined 

cycle turbine. The air permit for the project was issued April 12, 2012. The permit contained an 

initial GHG limit of 825 lbs of CO2e/MWhgrid to be demonstrated during initial performance test 

and a 365-day rolling average limit of 895 lbs of CO2e/MWhgrid. 

For comparison purposes, PCEC proposes CO2e emission rates for the General Electric 7FA, 

Siemens SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines, without duct firing, at ISO 

conditions, of 894.9, 909.2, and 923.7lb CO2e/MWh (net basis), respectively, which accounts for 

design margins, performance margins, and degradation margins. The highest proposed CO2e 

emission rate in the PCEC application is within 3.2% of the proposed PVEC limit and the lowest 

proposed CO2e emission rate is within 0.01% of the proposed PVEC limit. The efficiencies 

from two similarly sized combined cycle electric generating units will not be identical due to 

differences in the properties and variability of the natural gas; the geographic location - higher 

combustion turbine efficiencies are achieved at lower elevations and at cooler ambient 

temperatures due to denser ambient air; differences in combustion turbine designs, heat 

recovery steam generator designs and steam turbine designs; and electric generating unit load 

generation flexibility requirements - operating an electric generating unit as a base load unit is 
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more efficient than operating as a load cycling unit to respond to fluctuations in customer 

electricity or steam demands.

Deer Park Energy Center

The application for the Calpine Deer Park Energy Center was submitted in September 2011 and 

the permit was issued on November 29, 2012. The permit authorizes a fifth Siemens 501F 

CTG/HRSG train and ancillary equipment at the existing Deer Park Energy Center located in 

Deer Park, Texas. The permit contains a CO2 emission rate limit of 0.460 ton CO2/MWh (net) 

and a BACT net heat rate for the Project of 7,730 Btu/kWh (HHV), (without duct burner firing). 

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins. The proposed emission 

rates on a ton CO2/MWh (net) basis for General Electric 7FA, Siemens SGT6-5000F(4), and 

Siemens SGT6-5000F(5) turbines, without duct firing, are 0.447, 0.455, and 0.467 ton 

CO2/MWh (net). 

Channel Energy Center

The application for the Calpine Channel Energy Center was submitted in October 2011 and the 

permit was issued on November 29, 2012. The permit authorizes a third Siemens 501F 

CTG/HRSG train and ancillary equipment at the existing Channel Energy Center located in 

Pasadena, Texas. The permit contains a CO2 emission rate limit of 0.460 ton CO2/MWh (net) 

and a BACT net heat rate for the Project of 7,730 Btu/kWh (HHV), (without duct burner firing). 

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins. The proposed emission 

rates on a ton CO2/MWh (net) basis for General Electric 7FA, Siemens SGT6-5000F(4), and 

Siemens SGT6-5000F(5) turbines, without duct firing, are 0.447, 0.455, and 0.467 ton 

CO2/MWh (net). 

La Paloma Energy Center

The application for the La Paloma Energy Center was submitted in March 2012 and a draft 

permit has not yet been issued. The Pinecrest Energy Center proposes the same plant 

configuration and same gas turbine options as the La Paloma Energy Center application, with 

the exception that the GE 7FA.05 turbine is being proposed for the Pinecrest Energy Center and 

the GE 7FA.04 turbine is being proposed for the La Paloma Energy Center. The proposed 

GHG BACT net heat rate limits for the Siemens turbines for both applications are the same and 

the proposed heat rate limits for the GE 7FA.05 turbine is slightly higher than the heat rate limit 

for the GE 7FA.04. 
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E.S. Joslin Power Station

The application for the E.S. Joslin Power Station was submitted to the TCEQ in June 2012 and 

a draft permit has not yet been issued. Calhoun Port Authority (CPA) proposed to convert the 

existing conventional steam plant at the station, located in Calhoun County, Texas, to a 

combined cycle configuration by adding three natural gas-fired General Electric 7FA CTGs and 

three unfired HRSGs with a shared steam turbine (a 3x3x1 combined cycle configuration). CPA 

proposed an efficiency limit of 7,730 Btu/KWh as BACT for GHG emissions; however, CPA did 

not propose an output-based emission limitation (e.g., lb CO2e/MWh) for the project.

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins.

S.R. Bertron Unit 5

The application for Unit 5 at the S.R. Bertron Generating Station was submitted to the TCEQ in 

November 2012. NRG Texas Power, LLC (NRG) proposed to construct a new natural gas-fired 

combined cycle electric generating unit and ancillary equipment at the S.R. Bertron Generating 

Station in Harris County, Texas. The new facility will have either a 2x2x1 or a 2x2x2 

configuration (two CTGs, two fired HRSGs, and either one or two steam turbines). Three CTG 

models are under consideration for the project: the General Electric 7FA.05, the Mitsubishi 

Heavy Industries (MHI) 501GAC, and the Siemens F(5). NRG proposed a heat rate standard of 

7,730 Btu/kWh (HHV), net generation, without duct burner firing, (for any CTG model). NRG 

also proposed CO2e mass emission limits of 1,203,838 tpy for each CTG/HRSG unit 

(supplementary fired) with the General Electric 7FA.05, 1,344,347 tpy for each CTG/HRSG unit 

(supplementary fired) with the Siemens F(5), and 1,468,007 tpy for each CTG/HRSG unit 

(supplementary fired) with the MHI 501GAC. (Note that NRG did not propose emission limits in 

terms of mass of emitted CO2e/MWh.) 

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins.

Cedar Bayou Unit 5

The application for Unit 5 at the Cedar Bayou Generating Station was submitted to the TCEQ in 

November 2012. NRG Texas Power, LLC (NRG) proposed to construct a new natural gas-fired 

combined cycle electric generating unit and ancillary equipment at the Cedar Bayou Generating 

Station in Chambers County, Texas. The new facility will have either a 2x2x1 or a 2x2x2 

configuration (two CTGs, two fired HRSGs, and either one or two steam turbines). Three CTG 

models are under consideration for the project: the General Electric 7FA.05, the Mitsubishi 
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Heavy Industries (MHI) 501GAC, and the Siemens F(5). NRG proposed a heat rate standard of 

7,730 Btu/kWh (HHV), net generation, without duct burner firing, (for any CTG model). NRG 

also proposed CO2e mass emission limits of 1,203,838 tpy for each CTG/HRSG unit 

(supplementary fired) with the General Electric 7FA.05, 1,344,347 tpy for each CTG/HRSG unit 

(supplementary fired) with the Siemens F(5), and 1,468,007 tpy for each CTG/HRSG unit 

(supplementary fired) with the MHI 501GAC. (Note that NRG did not propose emission limits in 

terms of mass of emitted CO2e/MWh.) 

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens 

SGT6-5000F(4), and Siemens SGT6-5000F(5) turbines at ISO conditions, without duct burner 

firing, of 7,528.8, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts 

for design margins, performance margins, and degradation margins.

5.2 BACT FOR SF6 INSULATED ELECTRICAL EQUIP MENT

5.2.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top-Down BACT analysis is to identify all feasible control technologies. One 

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

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

totally enclosed-pressure system with far lower potential for SF6 emissions. In addition, the 

effectiveness of leak-tight closed systems can be enhanced by equipping them with a density 

alarm that provides a warning when 10% of the SF6 (by weight) has escaped. The use of an 

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

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

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

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

National Institute of Standards and Technology (NTIS) Technical Note 1425, Gases for 

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

SF6.

29 

5.2.2 Step 2: Eliminate Technically Infeasible Options

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

high voltage applications.

30

 

29 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible 

Present and Future Alternatives to Pure SF6, NIST Technical Note 1425, Nov.1997.

 It is easy to use, exhibits exceptional insulation and arc-interruption 

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

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

SF6-insulated equipment. The report concluded that although “...various gas mixtures show 

30 Id. at 28 – 29.
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considerable promise for use in new equipment, particularly if the equipment is designed 

specifically for use with a gas mixture... it is clear that a significant amount of research must be 

performed for any new gas or gas mixture to be used in electrical equipment.” Therefore there 

are currently no technically feasible options besides use of SF6. 

5.2.3 Step 3: Rank Remaining Control Technologies

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

highest ranked control technology that is technically feasible for this application.

5.2.4 Step 4: Evaluate Most Effective Controls and Document Results

Energy, environmental, or economic impacts were not addressed in this analysis because the 

use of alternative, non-greenhouse-gas substance for SF6 as the dielectric material in the 

breakers is not technically feasible.

5.2.5 Step 5: Select BACT

Based on this top-down analysis, PCEC concludes that using state-of-the-art enclosed-pressure 

SF6 circuit breakers with leak detection would be 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.

31 The proposed circuit breaker at the 

generator output will have a low pressure alarm and a low pressure lockout. This alarm will 

function as an early leak detector that will bring potential fugitive SF6 emissions problems to light 

before a substantial portion of the SF6 escapes. The lockout prevents any operation of the 

breaker due to lack of “quenching and cooling” SF6 gas.

PCEC will monitor emissions annually in accordance with the requirements of the Mandatory 

Greenhouse Gas Reporting rules for Electrical Transmission and Distribution Equipment Use.

32 

Annual SF6 emissions will be calculated according to the mass balance approach in Equation 

DD-1 of Subpart DD.

5.3 BACT FOR AUXILIARY BOILER

One nominally rated 150 MMBtu/hr auxiliary boiler (EPN AUXBLR) will be utilized to facilitate 

startup of the combined cycle units. The auxiliary boiler will be limited to 876 hours of operation 

per year. 

 

31 ANSI Standard C37.013, Standard for AC High-Voltage Generator Circuit Breakers on a Symmetrical Current. 

32 See 40 C.F.R. Pt. 98, Subpt. DD.
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5.3.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top-Down BACT analysis is to identify all feasible control technologies. The 

following technologies were identified as potential control options for boilers:

• Use of low carbon fuels

• Use of good operating and maintenance practices

• Energy efficient design

• Low Annual Capacity

The auxiliary boiler will utilize natural gas which is the lowest carbon fuel available at the PCEC

site. Therefore, formation of CO2 from combustion of the fuel will be minimized.

Good operating and maintenance practices for the boiler include following the manufacturer’s 

recommended operating and maintenance procedures; maintaining good fuel mixing in the 

combustion zone; and maintain the proper air/fuel ratio so that sufficient oxygen is provided to 

provide complete combustion of the fuel while at the same time preventing introduction of more 

air than is necessary into the boiler.

The auxiliary boiler is designed for a thermal energy efficiency of approximately 80%. The 

energy efficient design of the boiler includes insulation to retain heat within the boiler and a 

computerized process control system that will optimize the fuel/air mixture and limit excess air in 

the boiler.

The auxiliary boiler will be used to facilitate startup of the two combustion turbines and the 

annual hours of operation will be limited to 876 hours per year.

 

5.3.2 Step 2: Eliminate Technically Infeasible Options

This step of the top-down BACT analysis eliminates any control technology that is not 

considered technically feasible unless it is both available and applicable.

Use of natural gas as a low carbon fuel is technically feasible for this emission source.

Use of good operating and maintenance practices is technically feasible for this emission 

source.

Use of an energy efficient design for the boiler is technically feasible.

Use of a low annual capacity for the auxiliary boiler is technical feasible since the boiler is only 

used to facilitate startups for the two combustion turbines.
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5.3.3 Step 3: Rank Remaining Control Technologies

As all of the energy efficiency related processes, practices, and designs discussed in Section 

5.3.1 of this application are being proposed for the auxiliary boiler, a ranking of the control 

technologies is not necessary for this application.

5.3.4 Step 4: Evaluate Most Effective Controls and Document Results

As all of the energy efficiency related processes, practices, and designs discussed in Section 

5.3.1 of this application are being proposed for this project, an examination of the energy, 

environmental, and economic impacts of the efficiency designs is not necessary for this 

application. 

5.3.5 Step 5: Select BACT

Based on this top-down analysis, PCEC concludes that the use of natural gas as a low carbon 

fuel; good operating and maintenance practices; energy efficient design; and low annual 

capacity is selected as BACT for the auxiliary boiler. With the limit annual operation of the 

auxiliary boiler, the total CO2e emissions from the boilers are 0.23% of the total site wide 

emissions.

Among other recently issued or currently pending GHG permits, the Wolverine Power Supply 

Cooperative permit and the Palmdale Hybrid Power Project permit included BACT 

determinations for limited use, auxiliary boilers and heaters. The Wolverine Permit included a 

72.4 MMBtu/hr diesel-fired auxiliary boiler, limited to 4,000 hours operation per year. The 

Permit listed BACT for GHG for the auxiliary boiler to incorporate energy efficient equipment 

wherever practical in the design of the auxiliary boiler. The Wolverine Permit did not include an 

output based BACT limit for the auxiliary boiler.

The application for the Palmdale Hybrid Power Project (PHPP) was submitted in May 2011 and 

a draft permit was issued by the Antelope Valley Air Quality Management District in August 

2011. The PHPP application proposed the construction of a power plant utilizing natural-gasfired combustion turbine combined cycle generators located in Palmdale, California. The project 

also included a 110 MMBtu/hr natural-gas-fired auxiliary boiler, limited to 500 hours per year 

operation, and a 40 MMBtu/hr natural-gas-fired heater, limited to 1,000 hours per year 

operation. The Palmdale Permit listed BACT for GHG for the auxiliary boiler and heater as 

annual tune-ups. The Palmdale Permit did not include an output based BACT limit for the 

auxiliary boiler or heater.

5.4 BACT FOR EMERGENCY ENGINES

The PCEC site will be equipped with one nominally rated 1,072-hp diesel-fired emergency 

generator to provide electricity to the facility in case of power failure and one nominally rated 

500-hp diesel-fired pump to provide water in the event of a fire. 
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5.4.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top-Down BACT analysis is to identify all feasible control technologies. The 

following technologies were identified as potential control options for emergency engines: 

• Use of low carbon fuel;

• Use of good operating and maintenance practices; 

• Low annual capacity factor.

Engine options includes engines powered with electricity, natural gas, or liquid fuel, such as 

gasoline or fuel oil.

Good operating and maintenance practices for the engines include the following:

• Operating with recommended fuel to air ratio recommended by the manufacturer and 

• Appropriate maintenance of equipment, such as periodic readiness testing.

The energy efficiency (energy output divided by energy input) associated with the emergency 

generator is 34.0% and the energy efficiency associated with the fire pump engine is 36.8%. 

These are typical efficiencies for emergency engines. 

Each emergency engine will be limited to 100 hours operation per year for purposes of 

maintenance checks and readiness testing.

5.4.2 Step 2: Eliminate Technically Infeasible Options

This step of the top-down BACT analysis eliminates any control technology that is not 

considered technically feasible unless it is both available and applicable. 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, such as floods and 

hurricanes. As such, the engines must be available during emergencies. Electricity and natural 

gas may not be available during an emergency and therefore cannot be used as an energy 

source for the emergency engines.

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 motor gasoline or diesel. The default CO2 emission factors 

for gasoline and diesel are very similar, 70.22 kg/MMBtu for gasoline and 73.96 kg/MMBtu for 

diesel. Diesel fuel has a much lower volatility than gasoline and can be stored for longer 

periods of time. Therefore, diesel is typically the chosen fuel for emergency engines.

Because of the need to store the emergency engine fuel on-site and the ability to store diesel for 

longer periods of time than gasoline, it is technically infeasible to utilize a lower carbon fuel than 

diesel. 
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The use of good operating and maintenance practices is technically feasible for the emergency 

engines. Also, a low annual capacity factor for the engines is technically feasible since the 

engines will only be operated either for readiness testing or for actual emergencies.

5.4.3 Step 3: Rank Remaining Control Technologies

Since the remaining technically feasible processes, practices, and designs discussed in Section 

5.4.1 of this application for the emergency engines are being proposed for the engines, a 

ranking of the control technologies is not necessary for this application.

5.4.4 Step 4: Evaluate Most Effective Controls and Document Results

Since the remaining technically feasible processes, practices, and designs discussed in Section 

5.4.1 of this application for the emergency engines are being proposed for the engines, an 

evaluation of the most effective controls is not necessary for this application. 

5.4.5 Step 5: Select BACT

As a result of this analysis, appropriate operation of the engines through proper fuel to air ratios 

and maintenance based on recommended readiness testing and low annual hours of operation 

are selected as BACT for the proposed engines. 

5.5 BACT FOR NATURAL GAS FUGITIVES

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

potential sources of methane and CO2 emissions due to emissions from rotary shaft seals, 

connection interfaces, valve stems, and similar points. 

5.5.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top-Down BACT analysis is to identify all feasible control technologies. The 

following technologies were identified as potential control options for piping fugitives: 

• Implementation of leak detection and repair (LDAR) program using a hand held 

analyzer; 

• Implementation of alternative monitoring using a remote sensing technology such as 

infrared cameras; and 

• Implementation of audio/visual/olfactory (AVO) leak detection program

5.5.2 Step 2: Eliminate Technically Infeasible Options

This step of the top-down BACT analysis eliminates any control technology that is not 

considered technically feasible unless it is both available and applicable. The use of instrument 
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LDAR and remote sensing technologies are technically feasible. Since pipeline natural gas is 

odorized with a small amount of mercaptan, an AVO leak detection program for natural gas 

piping components is technically feasible.

5.5.3 Step 3: Rank Remaining Control Technologies

The use of a LDAR program with a portable gas analyzer meeting the requirements of 40 CFR 

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

instrument monitoring with a leak definition of 10,000 part per million by volume (ppmv) (TCEQ 

28M LDAR Program) is generally assigned a control efficiency of 75% for valves, relief valves, 

sampling connections, and compressors and 30% for flanges.

33 Quarterly instrument 

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

assigned a control efficiency of 97% for valves, relief valves, and sampling connections, 85% for 

compressors, and 30% for flanges.

34 The U.S. EPA has allowed the use of an optical gas 

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

monitoring equipment for leaks in 40 CFR 60.18(g). For components containing inorganic or 

odorous compounds, periodic AVO walk-through inspections provide predicted control 

efficiencies of 97% control for valves, flanges, relief valves, and sampling connections, and 

95% for compressors.35 

5.5.4 Step 4: Evaluate Most Effective Controls and Document Results

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

inspections an effective means of detecting leaking components in natural gas service. As 

discussed in Section 5.5.3, the predicted emission control efficiency is comparable to the LDAR 

programs using Method 21 portable analyzers. 

5.5.5 Step 5: Select BACT

Due to the very low Volatile Organic Compound (VOC) content of natural gas, the PCEC will not 

be subject to any VOC leak detection programs by way of its State/PSD air permit, TCEQ 

Chapter 115 – Control of Air Pollution from Volatile Organic Compounds, New Source 

Performance Standards (40 CFR Part 60), National Emission Standard for Hazardous Air 

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

Source Categories (40 CFR Part 63). Therefore, any leak detection program implemented will 

be solely due to potential greenhouse emissions. Since the uncontrolled CO2e emissions from 

the natural gas piping represent approximately 0.01% of the total site wide CO2e emissions, any 

emission control techniques applied to the piping fugitives will provide minimal CO2e emission 

reductions. 

 

33 Air Permit Technical Guidance for Chemical Sources: Equipment Leak Fugitives, TCEQ, Oct. 2000

34 Id. at page 52.

35 Id. at page 52.
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Based on this top-down analysis, PCEC concludes that daily AVO inspections is BACT for 

piping components in natural gas service.
Pine Crest

Energy Center
Net Output Gross Output

Base Net Heat Rate 6,675.5 6534.6 Btu/kWH (HHV) (Without Duct Firing)

3.3% 3.3% Design Margin

6.0% 6.0% Performance Margin

3.0% 3.0% Degradation Margin

Calculated Base Heat Rate with Compliance Margins 7528.8 7369.9 Btu/kWH (HHV) (Without Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit Without Duct Burner Firing

EPN Base Heat Rate Electrical Output 

Basis

Heat Input 

Required to 

Produce 1 MW

Pollutant Emission Factor lb GHG/MWhr2 Global Warming 

Potential3 lb CO2e/MWhr4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu)1

CO2 894.852 1 894.852

CTG/HRSG3 7528.8 Net 7.53 CH4 1.0E-03 1.66E-02 21 3.49E-01

N2O 1.0E-04 1.66E-03 310 5.15E-01

894.9 895.7

CO2 875.970 1 875.970

CTG/HRSG3 7369.9 Gross 7.37 CH4 1.0E-03 1.62E-02 21 3.41E-01

N2O 1.0E-04 1.62E-03 310 5.04E-01

Totals 876.0 876.8

Net Output Gross Output

Base Net Heat Rate 7,249.3 7026.8 Btu/kWH (HHV) (With Duct Firing)

3.3% 3.3% Design Margin

6.0% 6.0% Performance Margin

3.0% 3.0% Degradation Margin

Calculated Base Heat Rate with Compliance Margins 8176.0 7925.0 Btu/kWH (HHV) (With Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit With Duct Burner Firing

EPN Base Heat Rate Electrical Output 

Basis

Heat Input 

Required to 

Produce 1 MW

Pollutant Emission Factor lb GHG/MWhr2 Global Warming 

Potential3 lb CO2e/MWhr4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu)1

CO2 971.778 1 971.778

CTG/HRSG3 8176.0 Net 8.18 CH4 1.0E-03 1.80E-02 21 3.79E-01

N2O 1.0E-04 1.80E-03 310 5.59E-01

971.8 972.7

CO2 941.942 1 941.942

CTG/HRSG3 7925.0 Gross 7.92 CH4 1.0E-03 1.75E-02 21 3.67E-01

N2O 1.0E-04 1.75E-03 310 5.42E-01

Totals 942.0 942.9

Note

1. CH 4 and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

2. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x Uf X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO2 , 44.0 lb/lbmole

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. Example calculation: GHG emissions (lbs) x Global Warming Potential / 1 MW = lb CO2e/MWhr

Table 5-1

GHG Emission Calculations - Calculation of Design Heat Rate Limit for GE 7FA.05

Pinecrest Energy Center

2/11/2013
Net Output Gross Output

Base Net Heat Rate 6,782.0 6615.5 Btu/kWH (HHV) (Without Duct Firing)

3.3% 3.3% Design Margin

6.0% 6.0% Performance Margin

3.0% 3.0% Degradation Margin

Calculated Base Heat Rate with Compliance Margins 7649.0 7461.2 Btu/kWH (HHV) (Without Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit Without Duct Burner Firing

EPN Base Heat Rate Electrical Output 

Basis

Heat Input 

Required to 

Produce 1 MW

Pollutant Emission Factor lb GHG/MWhr2 Global Warming 

Potential3 lb CO2e/MWhr4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu)1

CO2 909.136 1 909.136

CTG/HRSG3 7649.0 Net 7.65 CH4 1.0E-03 1.69E-02 21 3.54E-01

N2O 1.0E-04 1.69E-03 310 5.23E-01

909.2 910.0

CO2 886.817 1 886.817

CTG/HRSG3 7461.2 Gross 7.46 CH4 1.0E-03 1.64E-02 21 3.45E-01

N2O 1.0E-04 1.64E-03 310 5.10E-01

Totals 886.8 887.7

Net Output Gross Output

Base Net Heat Rate 7,045.1 6782.0 Btu/kWH (HHV) (With Duct Firing)

3.3% 3.3% Design Margin

6.0% 6.0% Performance Margin

3.0% 3.0% Degradation Margin

Calculated Base Heat Rate with Compliance Margins 7945.7 7649.0 Btu/kWH (HHV) (With Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit With Duct Burner Firing

EPN Base Heat Rate Electrical Output 

Basis

Heat Input 

Required to 

Produce 1 MW

Pollutant Emission Factor lb GHG/MWhr2 Global Warming 

Potential3 lb CO2e/MWhr4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu)1

CO2 944.400 1 944.400

CTG/HRSG3 7945.7 Net 7.95 CH4 1.0E-03 1.75E-02 21 3.68E-01

N2O 1.0E-04 1.75E-03 310 5.43E-01

944.4 945.3

CO2 909.136 1 909.136

CTG/HRSG3 7649.0 Gross 7.65 CH4 1.0E-03 1.69E-02 21 3.54E-01

N2O 1.0E-04 1.69E-03 310 5.23E-01

Totals 909.2 910.0

Note

1. CH 4 and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

2. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x Uf X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO2 , 44.0 lb/lbmole

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. Example calculation: GHG emissions (lbs) x Global Warming Potential / 1 MW = lb CO2e/MWhr

Table 5-2

GHG Emission Calculations - Calculation of Design Heat Rate Limit for SGT6-5000F(4)

Pinecrest Energy Center

2/11/2013
Net Output Gross Output

Base Net Heat Rate 6,890.8 6582.2 Btu/kWH (HHV) (Without Duct Firing)

3.3% 3.3% Design Margin

6.0% 6.0% Performance Margin

3.0% 3.0% Degradation Margin

Calculated Base Heat Rate with Compliance Margins 7771.7 7423.6 Btu/kWH (HHV) (Without Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit Without Duct Burner Firing

EPN Base Heat Rate Electrical Output 

Basis

Heat Input 

Required to 

Produce 1 MW

Pollutant Emission Factor lb GHG/MWhr2 Global Warming 

Potential3 lb CO2e/MWhr4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu)1

CO2 923.718 1 923.718

CTG/HRSG3 7771.7 Net 7.77 CH4 1.0E-03 1.71E-02 21 3.60E-01

N2O 1.0E-04 1.71E-03 310 5.31E-01

923.7 924.6

CO2 882.353 1 882.353

CTG/HRSG3 7423.6 Gross 7.42 CH4 1.0E-03 1.64E-02 21 3.44E-01

N2O 1.0E-04 1.64E-03 310 5.07E-01

Totals 882.4 883.2

Net Output Gross Output

Base Net Heat Rate 7,203.8 6808.7 Btu/kWH (HHV) (With Duct Firing)

3.3% 3.3% Design Margin

6.0% 6.0% Performance Margin

3.0% 3.0% Degradation Margin

Calculated Base Heat Rate with Compliance Margins 8124.7 7679.0 Btu/kWH (HHV) (With Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit With Duct Burner Firing

EPN Base Heat Rate Electrical Output 

Basis

Heat Input 

Required to 

Produce 1 MW

Pollutant Emission Factor lb GHG/MWhr2 Global Warming 

Potential3 lb CO2e/MWhr4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu)1

CO2 965.678 1 965.678

CTG/HRSG3 8124.7 Net 8.12 CH4 1.0E-03 1.79E-02 21 3.76E-01

N2O 1.0E-04 1.79E-03 310 5.55E-01

965.7 966.6

CO2 912.707 1 912.707

CTG/HRSG3 7679.0 Gross 7.68 CH4 1.0E-03 1.69E-02 21 3.56E-01

N2O 1.0E-04 1.69E-03 310 5.25E-01

Totals 912.7 913.6

Note

1. CH 4 and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

2. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x Uf X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr

Fc = Carbon based F-factor,1040 scf/MMBtu

H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO2 , 44.0 lb/lbmole

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

4. Example calculation: GHG emissions (lbs) x Global Warming Potential / 1 MW = lb CO2e/MWhr

Table 5-3

GHG Emission Calculations - Calculation of Design Heat Rate Limit for SGT6-5000F(5)

Pinecrest Energy Center

2/11/2013
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6.0 OTHER PSD REQUIREMENTS

6.1 IMPACTS ANALYSIS

An impacts analysis is not being provided with this application in accordance with EPA’s 

recommendations: 

Since there are no NAAQS or PSD increments for GHGs, the requirements in sections 

52.21(k) and 51.166(k) of EPA’s regulations to demonstrate that a source does not cause 

contribute to a violation of the NAAQS are not applicable to GHGs. Therefore, there is no 

requirement to conduct dispersion modeling or ambient monitoring for CO2 or GHGs.36

An impacts analysis for non-GHG emissions is being submitted with the State/PSD/Nonattainment application submitted to the TCEQ.

6.2 GHG PRECONSTRUCTION MONITORING

A pre-construction monitoring analysis for GHG is not being provided with this application in 

accordance with EPA’s recommendations: 

EPA does not consider it necessary for applicants to gather monitoring data to assess 

ambient air quality for GHGs under section 52.21(m)(1)(ii), section 51.166(m)(1)(ii), or 

similar provisions that may be contained in state rules based on EPA’s rules. GHGs do 

not affect “ambient air quality” in the sense that EPA intended when these parts of EPA’s 

rules were initially drafted. Considering the nature of GHG emissions and their global 

impacts, EPA does not believe it is practical or appropriate to expect permitting 

authorities to collect monitoring data for purpose of assessing ambient air impacts of 

GHGs.37

A pre-construction monitoring analysis for non-GHG emissions is being submitted with the 

State/PSD/Nonattainment application submitted to the TCEQ.

 

6.3 ADDITIONAL IMP ACTS ANALYSIS

A PSD additional impacts analysis is not being provided with this application in accordance with 

EPA’s recommendations:

Furthermore, consistent with EPA’s statement in the Tailoring Rule, EPA believes it is

not necessary for applicants or permitting authorities to assess impacts from GHGs in 

the context of the additional impacts analysis or Class I area provisions of the PSD 

regulations for the following policy reasons. Although it is clear that GHG emissions 

 

36 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases at 48-49.

37 Id. at 49.
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contribute to global warming and other climate changes that result in impacts on the 

environment, including impacts on Class I areas and soils and vegetation due to the 

global scope of the problem, climate change modeling and evaluations of risks and 

impacts of GHG emissions is typically conducted for changes in emissions orders of 

magnitude larger than the emissions from individual projects that might be analyzed in 

PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG

source obtaining a permit in specific places and points would not be possible with 

current climate change modeling. Given these considerations, GHG emissions would 

serve as the more appropriate and credible proxy for assessing the impact of a given 

facility. Thus, EPA believes that the most practical way to address the considerations 

reflected in the Class I area and additional impacts analysis is to focus on reducing GHG 

emissions to the maximum extent. In light of these analytical challenges, 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.38

A PSD additional impacts analysis for non-GHG emissions is being submitted with the 

State/PSD/Nonattainment application submitted to the TCEQ. 

 
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7.0 PROPOSED GHG MONITORING PROVISIONS

PCEC proposes to monitor CO2 emissions by monitoring the quantity of fuel combusted in the 

turbines and heat recovery steam generators and performing periodic fuel sampling as specified 

in 40 CFR 75.10(3)(ii) (refer to procedure below). Results of the fuel sampling will be used to 

calculate a site-specific Fc factor, and that factor will be used in the equation below to calculate 

CO2 mass emissions. 

The PCEC natural gas-fired turbines will comply with the fuel flow metering and Gross Calorific 

Value (GCV) sampling requirements of 40 CFR Part 75, Appendix D. The site-specific Fc factor 

will be determined using the ultimate analysis and Gross Calorific Value in equation F-7b of 40 

CFR 75, Appendix F. The site-specific Fc factor will be re-determined annually in accordance 

with 40 CFR 75, Appendix F, §3.3.6.

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

Affected gas-fired and oil-fired units may use the following equation:

WCO2 = (Fc x H x Uf x MWCO2)/2000

Where:

WCO2 = CO2 emitted from combustion, tons/hr

MWCO2 = molecular weight of CO2, 44.0 lb/lbmole

Fc = Carbon Based Fc-Factor, (1040 scf/MMBtu for natural gas or a site-specific 

Fc factor) 

H = Hourly heat input in MMBtu, as calculated using the procedure in 40 CFR 75, 

Appendix F, §5)

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

The requirements for fuel flow monitoring and quality assurance in 40 CFR 75 Appendix D are 

as follows:

Fuel flow meter: meet an accuracy of 2.0 %, required to be tested once each calendar 

quarter (40 CFR 75, Appendix D, §2.1.5 and §2.1.6(a))

Gross Calorific Value (GCV): determine the GCV of pipeline natural gas at least once 

per calendar month (40 CFR 75, Appendix D, §2.3.4.1)

This monitoring approach is consistent with the CO2 reporting requirements of the GHG 

Mandatory Reporting Rule for Electricity Generation (40 CFR 98, Subpart D). Subpart D 
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requires electric generating sources that report CO2 emissions under 40 CFR 75 to report CO2

under 40 CFR 98 by converting CO2 tons reported under Part 75 to metric tons. 

Also, the recently proposed NSPS Subpart TTTT –Standards of Performance for Greenhouse 

Gas Emissions for Electric Utility Generating Units ((40 CFR §60.5535(c)) allows electric 

generating units firing gaseous fuel and liquid fuel oil to determine CO2 mass emissions by 

monitoring fuel combusted in the affected Electric Generating Unit and using a site specific Fc 

factor determined in accordance with 40 CFR 75, Appendix F. Therefore, PCEC’s proposed 

CO2 monitoring method is consistent with the proposed NSPS Subpart TTTT. 
PREVENTION OF SIGNIFICANT DETERIORATION GREENHOUSE GAS PERMIT APPLICATION

FOR A COMBINED CYCLE POWER PLANT AT THE PINECREST ENERGY CENTER

PINECREST ENERGY CENTER, LLC

Zephyr Environmental Corporation 010303

APPENDIX A

GHG PSD APPLICABILITY FLOWCHART – NEW SOURCES
B-1 

Appendix A - GHG Applicability Flow Chart – New Sources 

(On or after July 1, 2011) 

2 

Determine the new source’s potential to 

emit (PTE) in tons per year (TPY) for 

each of the 6 GHG pollutants (CO2, 

CH4, N2O, HFCs, PFCs and SF6) taking 

into account enforceable limits. 

4 

Are the potential GHG emissions on a 

CO2e basis equal to or greater than 

100,000 TPY? 

Go to next 

page 

START

NO

YES

NO

If earlier, see New 

Source Flow Chart in 

Appendix A. 

1 

Will the permit be 

issued on or after 

July 1, 2011? 

YES

3 

Calculate the GHG emissions on a CO2 

equivalent (CO2e) basis using the global 

warming potential factors applied to the 

mass of each of the 6 GHG pollutants. 

Go to 

Element 7 
B-2 

From prior 

page 

YES

NO

NO

NO

6 

Are the potential GHG emissions 

on a mass basis less than 250 TPY 

(or 100 TPY if the new source is in a 

listed category)? 

7 

Is this a new stationary source 

subject to PSD for a regulated NSR 

pollutant other than GHGs? 

8 

Are the potential GHG emissions equal 

to or greater than 75,000 TPY? 

GHG emissions 

are subject to 

PSD as part of 

this permit 

review.

5 

Calculate the total 

GHG emissions on 

a mass basis. 

*The mass-based emission threshold of zero TPY 

has been excluded from this flow chart because any 

new source that meets the 75,000 TPY CO2e 

requirement would automatically exceed that mass 

based rate. 

GHG emissions 

are subject to 

PSD as part of 

this permit 

review. 

GHG emissions 

are not subject to 

PSD as part of this 

permit review. 

GHG emissions 

are not subject to 

PSD as part of this 

permit review. 

YES

YES