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-760-GHG 

PERMITTEE: Formosa Plastics Corporation, Texas 

FACILITY NAME: Chemical Complex Expansion: Two New 

Combined-Cycle Gas-Fired Turbines 

FACILITY LOCATION: 201 Formosa Drive 

Point Comfort, Texas 77978 

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C (42 U.S.C. § 7470, 

et. Seq.), and the Code ofFederal Regulations (CFR) Title 40, Section 52.21, and the Federal 

Implementation Plan at 40 CFR § 52.2305 (effective May 1, 2011 and published at 76 FR 

25178), the U.S. Environmental Protection Agency, Region 6 is issuing a Prevention of 

· Significant Deterioration (PSD) permit to the Formosa Plastics Corporation, Texas (F01mosa) 

for Greenhouse Gas (GHG) emissions. The Permit applies to the expansion of the existing utility 

plant at the Point Comfort, Texas chemical complex by adding two natural gas-fired combinedcycle turbines to the existing six combined-cycle gas turbines. 

Formosa is authorized to construct two new natural gas-fired combined-cycle gas turbines as 

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

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

forth in this PSD permit in conjunction with the corresponding Texas Commission on 

Environmental Quality (TCEQ) PSD permit No. PSD-TX-760M9. Failure to comply with any 

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

Section 113 of the Clean Air Act (CAA). This PSD Permit does not relieve Formosa ofthe 

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

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

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

§ 52.2303). 

In accordance with 40 CFR § 124.15(b )(3), this PSD Permit becomes effective immediately upon 

issuance of this final d 

Wren Stenger, Dir c or 

Multimedia Planning and Permitting Division 
2

Formosa Plastics Corporation, Texas (PSD-TX-760-GHG) 

Prevention of Significant Deterioration Permit 

For Greenhouse Gas Emissions 

Final Permit Conditions 

PROJECT DESCRIPTION 

Formosa is proposing to add two new gas-fired combined-cycle gas turbines to the existing 

chemical complex’s utility plant in Point Comfort, C3alhoun County, Texas. The two proposed 

combined-cycle gas turbines project is to expand the existing utility plant’s generation capacity 

to support the overall chemical complex expansion project. Each gas turbine would have a 

capacity to generate 80 megawatts (MW) of gross electrical power. The existing utility plant will 

consist of the six existing General Electric (GE) 7EA gas-fired turbines plus the two proposed 

GE 7EA gas-fired turbines with duct burners, for a total of eight, each exhausting to a dedicated 

heat recovery steam generator (HRSG) to produce steam and electricity for the multiple 

operating plants at the existing Formosa chemical complex. 

Formosa will consist of the following sources of GHG emissions: 

 Two natural gas-fired combined-cycle combustion turbines equipped with dry low-NOx 

combustors; 

 Two HRSG with duct burners; 

 Natural gas and Olefins Unit (OL) Tail Gas piping and metering fugitives; 

 Electrical equipment insulated with sulfur hexafluoride (SF6); and 

 Turbine startup natural gas purges. 

EQUIPMENT LIST 

The following devices are subject to this GHG PSD permit: 

FIN EPN Description

7K

7L

7K

7L

2 Natural Gas-Fired Combined-cycle Combustion Turbines rated at 80 MW 

each. The combustion turbines are equipped with heat recovery steam 

generators (HRSG), duct burners, and selective catalytic reduction (SCR).

7K-NGVENT

7L-NGVENT

7K-NGVENT

7L-NGVENT

A portion of the natural gas supply line is purged through a purge vent stack 

during startup of each gas turbine.

SF6-FUG SF6-FUG SF6 Insulated Electrical Equipment (i.e., circuit breakers) with 248 lb SF6

capacity per circuit breaker.

NG-FUG NG-FUG Natural Gas Fugitives.
3

I. GENERAL PERMIT CONDITIONS 

A. PERMIT EXPIRATION 

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

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

approval takes effect; or 

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

3. is not completed within a reasonable time. 

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

showing that an extension is justified. 

B. PERMIT NOTIFICATION REQUIREMENTS

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

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

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

such date; and

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

provisions of Section V, 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 V.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-760M9 (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 

AVO Audio/Visual/Olfactory 

BACT Best Available Control Technology 

CAA Clean Air Act 

CC Carbon Content 

CCS Carbon Capture and Storage 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CH4 Methane 

CHP Combined Heat and Power 

CO2 Carbon Dioxide 

CO2e Carbon Dioxide Equivalent 

CT Combustion Turbine 

DCS Distributed Control System 

DLNB Dry Low-NOx Burner 

dscf Dry Standard Cubic Foot 

EF Emission Factor 

EPN Emission Point Number 

FIN Facility Identification Number 

FR Federal Register 

GCV Gross Calorific Value 

GHG Greenhouse Gas 

gr Grains 

GWP Global Warming Potential 

HHV High Heating Value 

HRSG Heat Recovery Steam Generator 

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 

MW Megawatt 

N2O Nitrous Oxides 

NOx Nitrogen Oxides 

NSPS New Source Performance Standards 

OL Olefins Unit Tail Gas 

PSD Prevention of Significant Deterioration 

QA/QC Quality Assurance and/or Quality Control 

SCFH Standard Cubic Feet per Hour 

SCR Selective Catalytic Reduction 

SF6 Sulfur Hexafluoride 

TAC Texas Administrative Code 

TCEQ Texas Commission on Environmental Quality 

TPY Tons per Year

USC United States Code 

VOC Volatile Organic Compound 
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II. Annual Emission Limits 

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

following: 

Table 1 Annual Emission Limits1 – General Electric 7EA 

FIN EPN Description

GHG Mass Basis TPY 

CO2e

2,3 BACT Requirements

TPY

7K 7K

Combined-cycle

Combustion 

Turbine/Heat 

Recovery Steam 

Generator with 

Duct Burner

CO2 571,875

572,466

11,650 Btu/kWh (gross) on a 365-

day rolling average. See Special 

Condition III. B.1 and III.B.2.

CH4 10.8

N2O 1.1

7L 7L

Combined-cycle

Combustion 

Turbine/Heat 

Recovery Steam 

Generator with 

Duct Burner

CO2 571,875

572,466

11,650 Btu/kWh (gross) on a 365-

day rolling average. See Special 

Condition III. B.1 and III.B.2.

CH4 10.8

N2O 1.1

NG-FUG NG-FUG

Natural Gas and 

OL Tail Gas 

Fugitives 

CO2

No Numerical 

Limit 

Established4

No 

Numerical 

Limit 

Established4

Implementation of an AVO 

program. See Special Condition 

III. C.1. and III.C.4. CH4

No Numerical 

Limit 

Established4

SF6-FUG SF6-FUG SF6 Insulated 

Equipment SF6

No Numerical 

Limit 

Established5

No 

Numerical 

Limit 

Established5

Good Combustion and Operating 

Practices. Limit to 50 hours of 

operation per year. See Special 

Condition III. C.2. through 

III.C.4.

7KNGVENT

7LNGVENT

7KNGVENT

7LNGVENT

Turbine Startup 

Natural Gas 

Purges

CO2 0.41

30 Limit turbines to 15 start ups per 

year. See Special Condition III.D. CH4 1.20

Totals6 CO2 1,143,751

CO2e 

1,145,489

CH4 41.6

N2O 2.2

SF6 0.0012

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. Fugitive process emissions from EPN NG-FUG are estimated to be 0.69 TPY CO2, 20 TPY of CH4 and 500

TPY CO2e. In lieu of an emission limit, the emissions will be limited by implementing a weekly AVO 

monitoring program. 

5. SF6 fugitive emissions from EPN SF6-FUG are estimated to be 0.0012 TPY of SF6 and 27 TPY of CO2e. In lieu 

of an emission limit, the emissions will be limited by using state of the art enclosed-pressure SF6 circuit 

breakers with leak detection. 

6. Total emissions include the PTE for fugitive emissions (including SF6). Totals are given for informational 

purposes only and do not constitute emission limits. 
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III. SPECIAL PERMIT CONDITIONS 

A. Combustion Turbine and Heat Recovery Steam Generators (HRSG) with Duct 

Burners (EPNs: 7K and 7L) Work Practice Standards, Operational Requirements, 

and Monitoring 

1. Permittee shall limit fuel to the combustion turbine to pipeline quality natural gas. 

Fuel for the HRSG duct burners shall be limited to pipeline quality natural gas, a pure 

hydrogen stream, and a hydrogen/methane mixture (OL tail gas). 

2. The gross calorific value of the fuel, except pipeline quality natural gas, shall be 

determined monthly by the procedures contained in 40 CFR Part 98 and records shall 

be maintained of the monthly fuel gross calorific value for a period of five years. 

3. The natural gas quality fuels carbon content will be obtained by semiannual testing 

per 40 CFR § 98.34(b)(3)(A). 

4. Upon request, Permittee shall provide a sample and/or analysis of the fuel that is fired 

in the combustion turbines or duct burners at the time of the request, or shall allow a 

sample to be taken by EPA for analysis. 

5. Permittee shall monitor fuel gas flow continuously; determine fuel higher heating 

value whenever there is a fuel change or monthly, whichever is less; and calculate the 

total daily heat input. 

6. The flow rate of the fuel combusted in the combustion turbine and HRSG duct 

burners shall be measured and recorded using an operational non-resettable elapsed 

flow meter. 

7. Natural gas, pure hydrogen, and OL tail gas flow meters shall be calibrated in 

accordance with 40 CFR § 98.34(b)(1). 

8. Flow meters shall meet the specification in 40 CFR Part 60, Appendix B, Spec. 6. 

9. All flow meters shall meet the Quality Assurance Specifications in 40 CFR Part 60, 

Appendix F. 

10. In accordance with 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 affected combustion unit commences 

commercial operation. 

11. Permittee shall measure and record the energy output (MWh [based on adjusted gross 

energy output and equivalent energy produced]) on an hourly basis. 

12. The emission limits established in Table 1 include emissions associated with MSS 

activities. 

13. Permittee shall monitor and record the following parameters daily: 

a. CT/HRSG fuel input – volumetric measurement of fuel flow converted into 

mass (lb/hr) and energy flow (MMBtu/hr); 

b. Gross hourly energy output (Mwh); 
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c. CT/HRSG plant efficiency; 

d. Gas turbine electrical output, MW; and 

e. Mass of steam produced. 

14. Permittee shall determine the hourly CO2 emission rate in accordance with 40 CFR § 

98.33(a)(1)(i) and 98.33(a)(3)(iii). 

15. Permittee shall calculate the CH4 and N2O emissions on a 12-month rolling basis to 

be updated by the last day of the following month. Permittee shall determine 

compliance with the CH4 and N2O emissions limits contained in this section using the 

default CH4 and N2O emission factors contained in Table C-2 and equation C-8 of 40 

CFR Part 98 and the HHV (for natural gas and/or OL tail gas), converted to short 

tons. 

16. Permittee shall calculate the CO2e emissions on a 12-month rolling basis, based on 

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

Regulations, 40 CFR Part 98, Subpart A, Table A-1, as published on November 29, 

2013 (78 FR 71904). The record shall be updated by the last day of the following 

month. 

B. Combustion Turbine/HRSG BACT Emission Limits 

1. Permittee shall not exceed a Combustion Turbine average heat rate of 11,650 

Btu/kWh (HHV, adjusted gross energy heat rate with compliance margin) on a 365-

day rolling average. To determine this limit, Permittee shall calculate the average heat 

rate on a hourly basis using the fuel flow rate, fuel HHV, and the measured hourly 

energy output (kwh [based on adjusted gross energy output and equivalent energy 

produced]). The calculated hourly heat rate is averaged daily. 

2. The Permittee shall calculate the combined-cycle unit thermal efficiency daily using 

the following equations: 

Thermal Efficiency = (

HIGT+HIHRSG

PGT+PHRSG

) x 1,000,000 

Where: 

Thermal efficiency = heat rate of combined-cycle unit (Btu/kWh) 

HIGT = Heat input of fuel to the gas turbine (MMBtu/day) 

HIHRSG = Heat input of fuels to the HRSG (MMBtu/day) 

PGT = Gross Electrical Power produced from the gas turbine (kWh/day) 

PHRSG = Gross energy (electrical equivalent) produced from the HRSG (kWh/day), 

calculated using Equation 11-2 below. 

1,000,000 = Btu/MMBtu conversion 
10

PHRSG = msteaṁ x 14.11 

Where: 

msteaṁ = mass flow rate of steam produced from the HRSG (lb/day) 

14.11 = steam to electric conversion rate (lb/kWh), based on the existing plant steam 

turbines 

3. Within 180 days of the date of initial startup of the combustion turbine, the Permittee 

shall perform an initial emission test for CO2 and use emission factors from 40 CFR 

Part 98, Subpart C, Table C-1. If the combustion turbine/HRSG does not meet the 

emissions limit, the Permittee may continue operation of the combustion 

turbine/HRSG in order to perform necessary corrective actions and to continue plant 

operations. Once corrective actions have been made, the Permittee will schedule a 

follow-on emissions test and will make appropriate notifications to the EPA. 

4. On or after initial performance testing, Permittee shall use the combustion turbines, 

HRSG energy efficiency processes, work practices, and designs as represented in the 

permit application. 

5. The BACT limit will be met at all times, including periods of startup, shutdown, and 

maintenance.

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

1. The Permittee shall implement an audio, visual, and olfactory (AVO) method for 

detecting leaks in natural gas piping components, OL tail gas piping components, 

and fugitive emission of methane from natural gas piping components. AVO 

monitoring shall be performed daily. 

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 248 lbs. 

3. Permittee shall equip the circuit breakers with instrumentation to identify and/or 

prevent leaks. The SF6 leak detection system shall be able to detect a leak of at least 

1 lb per year.

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

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

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

relating to compliance with the Monitoring and Quality Assurance and Quality 

Control (QA/QC) procedures outlined in 40 CFR 98.304. 
11

D. Requirements for Turbine Startup Natural Gas Purges (7K-NGVENT and 7LNGVENT) 

 Permittee shall limit the turbine startup purges to 15 per year per turbine. 

E. Continuous Emissions Monitoring Systems (CEMS) 

1. As an alternative to Special Conditions III.A.14. Permittee may install a CO2 CEMS and 

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

handling system for measuring and recording CO2 emissions discharged to the 

atmosphere, and use these values to show compliance with the annual emission limit in 

Table 1.

2. Permittee shall ensure that all required CO2 monitoring system/equipment are installed 

and all certification tests are completed on or before the earlier of 90 unit operating days 

or 180 calendar days after the date the unit commences operation.

3. Permittee shall ensure compliance with the specifications and test procedures for CO2

emission monitoring system at stationary sources, 40 CFR Part 98, or 40 CFR Part 60, 

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

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, except for fugitive 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); 

c. Annual fuel sampling for natural gas; and 

d. Any CO2 CEMS data. 

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

as well as the repair and maintenance records. 

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

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

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

facility; duration of startup, shutdown; the initial startup period for the emission units; 

pollution control units; malfunctions; all records relating to performance tests, 

calibrations, checks, and monitoring of combustion equipment; duration of an inoperative 
12

monitoring device and emission units with the required corresponding emission data; and 

all other information required by this permit recorded in a permanent form suitable for 

inspection. The records must be retained for not less than five years following the date of 

such measurements, maintenance, reports, and/or records. 

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

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

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

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

an applicable subpart; or the Administrator or authorized representative, on a case-bycase basis, determines that more frequent reporting is necessary to accurately assess the 

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

each semi-annual period and shall include the following: 

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

known), corrective actions taken and preventive measures adopted; 

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

was inoperative (monitoring down-time); 

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

excess emissions occurred or when the monitoring equipment has not been 

inoperative, repaired or adjusted; and

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

activities. 

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

maximum emission limit set forth in this permit. 

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

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

of this permit. 

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

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

V. 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 (7K and 7L) 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. 
13

2. If the above calculated CO2 emission total does not exceed the tons per year (TPY) 

specified in Table 1, no compliance strategy needs to be developed. 

If the above calculated CO2 emission total exceeds the tons per year (TPY) specified 

in Table 1, the facility shall: 

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

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

emission limit listed in Table 1. 

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

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

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

the EPA. Additional sampling may be required by TCEQ or EPA. 

C. Permittee shall submit a performance test protocol to EPA no later than 30 days prior to the 

test to allow review of the test plan and to arrange for an EPA observer to be present at the 

test. The performance test shall be conducted in accordance with the submitted protocol, and 

any changes required by EPA. 

D. The turbine shall be tested at or above ninety percent (90%) of maximum load operations for 

the atmospheric conditions which exist during testing. The 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 emission points 7K and 7L shall be tested while firing at the minimum 

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

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

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

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

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

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

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

follows: 

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

2. Safe sampling platform(s), 

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

4. Utilities for sampling and testing equipment. 

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. 

I. Emissions testing, as outlined above, shall be performed every five years, plus or minus 6 

months, of when the previous performance test was performed, or within 180 days after the 
14

issuance of a permit renewal, whichever comes later to verify continued performance at 

permitted emission limits. 

VI. 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 



GREENHOUSE GAS PERMIT APPLICATION

PREVENTION OF SIGNIFICANT DETERIORATION:

2012 EXPANSION PROJECT

GAS TURBINES

POINT COMFORT, TEXAS

SUBMITTED TO: 

ENVIRONMENTAL PROTECTION AGENCY

REGION VI 

MULTIMEDIA PLANNING AND PERMITTING DIVISION

FOUNTAIN PLACE 12TH FLOOR, SUITE 1200 

1445 ROSS AVENUE

DALLAS, TEXAS 75202-2733 

SUBMITTED BY:

FORMOSA PLASTICS CORPORATION, TEXAS

P.O. BOX 700 

POINT COMFORT, TEXAS 77978 

PREPARED BY: 

ZEPHYR ENVIRONMENTAL CORPORATION

2600 VIA FORTUNA, SUITE 450 

AUSTIN, TEXAS 78746 

NOVEMBER 2012 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

i 

TABLE OF CONTENTS 

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

2.0 GENERAL APPLICATION INFORMATION ...................................................................... 3

TCEQ Form PI-1 ............................................................................................................... 4

Expansion Overall Plot Plan ............................................................................................ 13

Gas Turbine Plot Plan ..................................................................................................... 14

Area Map ......................................................................................................................... 15

3.0 PROCESS DESCRIPTION AND GHG EMISSION SOURCES ...................................... 16

3.1 Process Description .............................................................................................. 16

3.2 GHG Emission Sources ........................................................................................ 16

3.2.1 Combustion Turbine Generators 16

3.2.2 Heat Recovery Steam Generators 17

3.2.3 Natural Gas and OL Tail Gas Piping 18

3.2.4 Electrical Equipment Insulated with Sulfur Hexafluoride (SF6) 18

3.2.5 Turbine Startup Natural Gas Purges 18

4.0 GHG EMISSION CALCULATIONS ................................................................................. 20

4.1 GHG Emissions From Natural Gas Combustion Sources ..................................... 20

4.2 GHG Emissions From OL Tail Gas Combustion Sources ..................................... 21

4.3 GHG Emissions From Electrical Equipment Insulated with SF6 ............................ 22

4.4 GHG Emissions From Natural Gas/Ol Tail Gas Piping Fugitives and Fuel Line 

Maintenance and Turbine Startup Releases ......................................................... 22

5.0 PREVENTION OF SIGNIFICANT DETERIORATION APPLICABILITY ......................... 24

6.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT) ................................................. 25

6.1 BACT for Carbon Capture and Sequestration ....................................................... 26

6.2 BACT for the Combined Cycle Combustion Turbines ........................................... 27

6.2.1 Step 1: Identify All Available Control Technologies 27

6.2.2 Step 3: Rank Remaining Control Technologies 31

6.2.3 Step 4: Evaluate Most Effective Controls and Document Results 31

6.2.4 Step 5: Select BACT 32

6.3 BACT for SF6 Insulated Electrical Equipment ....................................................... 35

6.3.1 Step 1: Identify All Available Control Technologies 35

6.3.2 Step 2: Eliminate Technically Infeasible Options 36

6.3.3 Step 3: Rank Remaining Control Technologies 36

6.3.4 Step 4: Evaluate Most Effective Controls and Document Results 37

6.3.5 Step 5: Select BACT 37

6.4 BACT for Natural Gas and OL Tail Gas Piping Fugitives ...................................... 37

6.4.1 Step 1: Identify All Available Control Technologies 37

6.4.2 Step 2: Eliminate Technically Infeasible Options 38

6.4.3 Step 3: Rank Remaining Control Technologies 38

6.4.4 Step 4: Evaluate Most Effective Controls and Document Results 39
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

ii 

6.4.5 Step 5: Select BACT 40

6.5 BACT for Natural Gas Venting .............................................................................. 41

6.5.1 Step 1: Identify All Available Control Technologies 41

6.5.2 Step 2: Eliminate Technically Infeasible Options 42

6.5.3 Step 3: Rank Remaining Control Technologies 42

6.5.4 Step 4: Evaluate Most Effective Controls and Document Results 42

6.5.5 Step 5: Select BACT 42

7.0 OTHER PSD REQUIREMENTS ..................................................................................... 43

7.1 Impacts Analysis ................................................................................................... 43

7.2 GHG Preconstruction Monitoring .......................................................................... 43

7.3 Additional Impacts Analysis ................................................................................... 44

8.0 PROPOSED GHG MONITORING PROVISIONS ........................................................... 45

APPENDICES 

Appendix A – GHG Emission Calculations 

Appendix B – PSD Netting Tables 

Appendix C – CCS Detailed BACT Analysis and Supplemental Information 

Appendix D - Kelly Hart & Hallman Memo Re: EPA Policy on Multiple PSD Permits
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

1 

1.0 INTRODUCTION

Formosa Plastics Corporation, Texas (FPC TX) currently operates a number of chemical plants 

at its chemical complex in Point Comfort, Calhoun County, Texas. FPC TX proposes to expand 

the chemical complex within the existing FPC TX Point Comfort site footprint. The 2012 

Expansion Project will consist of a two new Combined Cycle Turbines (Gas Turbines), an 

Olefins Expansion (a new Olefins 3 plant and a Propane Dehydrogenation (PDH) unit), and a 

new Low Density Polyethylene (LDPE) Plant. 

On June 3, 2010, the EPA published final rules for permitting sources of Greenhouse Gases 

(GHGs) under the prevention of significant deterioration (PSD) and Title V air permitting 

programs, known as the GHG Tailoring Rule.1

 After July 1, 2011, modified sources with GHG 

emission increases of more than 75,000 tons/yr on a carbon dioxide equivalent (CO2e) basis at 

existing major sources are subject to GHG PSD review. 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 FPC TX Point Comfort 2012 Expansion Project (which includes the Olefins 3 Plant and 

PDH Unit, LDPE plant, and two combined cycle combustion turbines) triggers PSD review for 

GHG pollutants because the GHG emissions from the expansion project will be more than 

75,000 tons/yr and the site is an existing major source. Therefore, the entire 2012 Expansion 

Project is subject to PSD review for GHG pollutants. The applications for GHG PSD air permits 

for this expansion are being submitted to the EPA. The applications for criteria pollutant PSD 

permits are being submitted to the Texas Commission on Environmental Quality (TCEQ) with 

copies for the EPA. 

As described in the July 13, 2012 Kelly Hart & Hallman memo to Mr. Brian Tomasovic of EPA 

(found in Appendix D of this application), the 2012 Expansion Project consists of the three new 

related plants (identified above) which comprise a single GHG PSD project. In order to align 

 

1

 75 FR 31514 (June 3, 2010). 

2

 75 FR 81874 (Dec. 29, 2010). 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

2 

FPC TX organizational responsibility and accountability for compliance with future permit 

requirements related to these plants, FPC TX is requesting a separate permit for each proposed 

new plant. Therefore, three separate permit applications are being submitted. Even though 

three separate applications are being submitted, FPC TX will perform and satisfy PSD 

permitting requirements, including ambient air quality impacts analysis, in aggregate for all the 

expansion project plants. 

FPC TX is hereby submitting this application for a GHG Prevention of Significant Deterioration 

(PSD) air quality permit for the gas turbines at FPC TX’s Point Comfort, Texas complex. The 

GHG emission unit descriptions, GHG emissions calculations and a GHG Best Available Control 

Technology (BACT) analysis are provided for those gas turbine GHG emission sources. 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

3 

2.0 GENERAL APPLICATION INFORMATION

A completed TCEQ Form PI-1 is included in this application to provide all the general 

administrative and project information for this GHG application. In addition, an overall 

expansion plot plan, plot plan of the gas turbine (cogeneration) area, and area map are included 

in this section. 

 
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 

For EPA GHG Permit Application 

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: Formosa Plastics Corporation, Texas 

Texas Secretary of State Charter/Registration Number (if applicable): 5107506 

B. Company Official Contact Name: Randy Smith, Vice President 

Title: General Manager 

Mailing Address: P.O. Box 700 

City: Point Comfort State: Texas ZIP Code: 77978 

Telephone No.: 361-987-7000 Fax No.: 361-987-2363 E-mail Address: 

C. Technical Contact Name: Tammy G. Lasater 

Title: EHS Department Staff 

Company Name: Formosa Plastics Corporation, Texas 

Mailing Address: P.O. Box 320 

City: Delaware City State: Delaware ZIP Code: 19706 

Telephone No.: 302-836-2241 Fax No.: 302-836-2239 E-mail Address: TammyL@fdde.fpcusa.com 

D. Site Name: Formosa Plastics Corporation, Texas

E. Area Name/Type of Facility:2012 Expansion Project: Utilities –Two Gas Turbines Permanent Portable 

F. Principal Company Product or Business: Petrochemical Manufacturing Facility

Principal Standard Industrial Classification Code (SIC): 2821 

Principal North American Industry Classification System (NAICS): 325211 

G. Projected Start of Construction Date: 2013

Projected Start of Operation Date: 2016 

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

Street Address: 201 Formosa Drive 

City/Town: Point Comfort County: Calhoun ZIP Code: 77978 

Latitude (nearest second): 28° 41′ 20′′ Longitude (nearest second): 096° 32′ 50′′
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 

For EPA GHG Permit Application 

I. Applicant Information (continued) 

I. Account Identification Number (leave blank if new site or facility): CB0038Q 

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): CN600130017 

L. Regulated Entity Number (RN): RN100218973 

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: 225 

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

Senator: Glenn Hegar District No.: 18 

Representative: Todd Hunter District No.: 32 

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): 19166, PSD-TX-760M8 

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 _3__ of __9___ 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

For EPA GHG Permit Application 

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.): SOP 01951 

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 _4__ of __9___ 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

For EPA GHG Permit Application 

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):

Greenhouse Gases – see permit application emission summary
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__ of __9___ 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

For EPA GHG Permit Application 

V. Public Notice Information (complete if applicable) 

A. Public Notice Contact Name: Tammy G Lasater

Title: Corporate Air Permitting Manager 

Mailing Address: P.O. Box 320 

City: Delaware City State: DE ZIP Code: 19706 

Telephone No.: (302) 836-2241 

B. Name of the Public Place: Calhoun County Branch Library & Point Comfort City Hall

Physical Address (No P.O. Boxes): 1 Lamar Street and 102 Jones Street

City: Point Comfort County: Calhoun ZIP Code: 77978

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, Library No, City Hall 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: 

Mailing Address: 

City: State: ZIP Code: 

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: 

Mailing Address: 

City: State: ZIP Code: 
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__ of __9___ 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

For EPA GHG Permit Application 

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: N/A 

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 
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___ of ___9__ 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

For EPA GHG Permit Application 

VII. Technical Information 

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

C. Maximum Operating Schedule:

Hours: 24 Day(s): 7 Week(s): 52 Year(s): 

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. 

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 
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___ of ___9__ 

Texas Commission on Environmental Quality 

Form PI-1 General Application for 

Air Preconstruction Permit and Amendment 

For EPA GHG Permit Application 

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: N/A 

Company name on check: Formosa Plastics Corporation 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 




FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

16 

3.0 PROCESS DESCRIPTION AND GHG EMISSION SOURCES

3.1 PROCESS DESCRIPTION

With this application, FPC TX is seeking authorization to construct two new combined cycle 

turbines at its existing plant, in Calhoun County, Texas. Both combustion turbines will be GE 

Model 7EA units with heat recovery steam generators (HRSGs). The combustion turbines have 

a nominal output of 80 megawatts each and the HRSGs have a nominal steam output of 

360,000 lb/hr with duct firing. Steam from the HRSGs will be routed to the existing utility plant 

steam header to combine with steam produced by the existing utility plant. Steam is routed 

from the steam header to the three existing steam turbines for electricity generation. 

The gas combustion turbines will be fired with sweet pipeline quality natural gas only. The 

HRSG will have the capability of firing fuel from three separate fuel sources. The first is sweet 

pipeline quality natural gas, the second is a pure hydrogen stream (from an existing process 

unit) and the third is tail gas from the Olefins plants (primarily methane and hydrogen), referred 

to as "OL tail gas". 

The following are the GHG emission sources related to the power generating equipment. 

 EPNs 7K, 7L - GE 7EA natural gas-fired combustion turbines 

 EPNs 7K, 7L - HRSG duct burner fuel combustion (natural gas and OL tail gas) 

 EPN NG-FUG- Natural gas piping and metering 

 EPN SF6-FUG - Electrical equipment insulated with sulfur hexafluoride (SF6) 

 EPNs 7K-NGVENT, 7L-NGVENT - Turbine startup natural gas purges 

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

3.2 GHG EMISSION SOURCES

3.2.1 Combustion Turbine Generators 

The plant will consist of two identical sweet pipeline quality natural gas-fired GE model 7EA 

combustion turbine generators (CTGs) with a nominal output of 80 megawatts each. Each 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

17 

combustion turbine will exhaust to a heat recovery steam generator, or HRSG, with duct firing 

capabilities. Emission point numbers (EPNs) for the combustion turbine/HRSG units are 

identified as 7K and 7L. 

The combustion turbine burns sweet pipeline quality natural gas to generate electricity. The 

main components of a CTG consist of a compressor, combustor, turbine, and generator. The 

compressor pressurizes ambient air and discharges it into the combustor section where the fuel 

is mixed with the compressed air and combusted. Hot exhaust gases then enter the turbine 

section where the gases expand across the turbine blades which rotate a shaft to power an 

electric generator. The exhaust gas exiting each combustion turbine will be routed to a HRSG 

for steam production. 

3.2.2 Heat Recovery Steam Generators 

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

HRSG will be discharged to the existing steam manifold that supplies three existing steam 

turbine generators. Steam from the manifold may also be used as utility steam for various plant 

uses. Each HRSG will be equipped with duct burners for supplemental heat input for steam 

production. The duct burners will have the capability of firing fuel from three different sources. 

These fuels are sweet pipeline-quality natural gas, a pure hydrogen stream (from another 

process unit) and a hydrogen/methane mixture (Olefins unit “OL” tail gas). It should be noted 

that combustion of the pure hydrogen fuel stream does not produce emissions of GHGs as this 

stream does not contain carbon. 

Each HRSG’s duct burners will have a maximum heat input capacity of 120 MMBtu/hr per unit 

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

duct burners will be located in the HRSG prior to the selective catalytic reduction (SCR) system. 

The exhaust gases from the unit, which includes emissions from the CT and the duct burners, 

will pass through the SCR and exit the stack to the atmosphere (EPNs: 7K, 7L). 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

18 

3.2.3 Natural Gas and OL Tail Gas Piping 

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

combustion turbines and HRSGs; OL tail gas will also be piped to the HRSGs. Project fugitive 

GHG emissions from the gas piping components associated with the combustion units will 

include emissions of methane (CH4) and carbon dioxide (CO2). Emissions from the natural gas 

and OL tail gas piping are designated as EPN: NG-FUG. 

3.2.4 Electrical Equipment Insulated with Sulfur Hexafluoride (SF6) 

The two circuit breakers associated with the proposed combustion turbine units will be insulated 

with SF6. SF6 is a colorless, odorless, non-flammable, and non-toxic synthetic gas. It is a 

fluorinated compound that has an extremely stable molecular structure. The unique chemical 

properties of SF6 make it an efficient electrical insulator. The gas is used for electrical 

insulation, arc quenching, and current interruption in high-voltage electrical equipment. SF6 is 

only used in sealed and safe systems which under normal circumstances do not leak gas. The 

capacity of each of the circuit breakers (two total) associated with the proposed plant is currently 

estimated to be 248 lbs. of SF6 (496 lbs in both breakers). 

The proposed circuit breakers 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. 

Emissions from the SF6-insulated circuit breakers are designated as EPN: SF6-FUG. 

3.2.5 Turbine Startup Natural Gas Purges 

During the startup sequence for each gas turbine, a portion of the natural gas supply line is 

purged through a separate purge vent stack. The purge results in GHG emissions of methane 

and CO2 from natural gas (EPNs: 7K-NGVENT, 7L-NGVENT). 
Utilities Plant – Two New Combined-Cycle 

Turbine Units

Process Flow Diagram

Natural Gas

Hydrogen

2 Frame 7EA

Gas Turbines Exhaust Gases

2 Heat Recovery 

Steam Generators

Steam

3 Existing Steam

Turbines

3 Existing Power 

Generators

Plant St

EPNs: 7K, 7

Air

Feed Water

Natural Gas

OL Tail Gas

Scope of Utilities 

Plant Changes

Electric Power to 

Plant Users

Existing Steam 

Generators

150600 

Existing Steam Header
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

20 

4.0 GHG EMISSION CALCULATIONS

This section provides a description of the methods used to estimate GHG emissions from the 

proposed combined cycle turbine GHG emission units. GHG emissions were estimated using 

the most appropriate unit-specific emission calculation methodologies available in EPA’s GHG 

Mandatory Reporting Rule (GHG MRR), 40 CFR 98. 

The following provides an explanation of calculation methodologies by source type. A summary 

of GHG emissions, detailed emission calculations and supporting information can be found in 

Appendix A. 

4.1 GHG EMISSIONS FROM NATURAL GAS COMBUSTION SOURCES 

GHG emission calculations for the natural gas-fired combustion units are calculated in 

accordance with the procedures in the Mandatory Greenhouse Reporting Rules, Subpart C – 

Stationary Fuel Combustion Sources.3

 

 (-1C .EQ (ࡲࡱ	ࢄ	ࢂࡴࡴ	࢞	࢒ࢋ࢛ࡲ	࢞૜ି૙૚	࢞	૚ ൌ૛ ࡻ࡯

Where: 

CO2 = Annual CO2 mass emissions for the specific fuel type, metric tons/yr 

Fuel = Volume of fuel combusted per year, standard cubic feet/yr, based on the 

maximum rated equipment capacity and maximum hours of operation (8,760 hours/yr) 

EF = Emission factor for natural gas from table C-1 

HHV = default high heat value of fuel, from table C-1 

0.001 = conversion from kg to metric tons 

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.4

 

 

3

 40 C.F.R. 98, Subpart C – General Stationary Fuel Combustion Sources
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

21 

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

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

4.2 GHG EMISSIONS FROM OL TAIL GAS COMBUSTION SOURCES

GHG emission calculations for the OL tail gas-firing in the duct burners are calculated in 

accordance with the procedures in the Mandatory Greenhouse Reporting Rules, Subpart C – 

Stationary Fuel Combustion Sources.5

 

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ࢃࡹ 	ࢄ	࡯࡯	࢞	࢒ࢋ࢛ࡲ ൈ

࡯ࢂࡹ

ൈ ૙. ૙૙૚ (EQ. C-5) 

Where: 

CO2 = Annual CO2 mass emissions for the specific fuel type, metric tons/yr 

Fuel = Volume of fuel combusted per year, standard cubic feet/yr, based on the 

maximum rated equipment capacity and maximum hours of operation (8,760 hours/yr) 

CC = Annual average carbon content of fuel (kg C per scf), obtained from the estimated 

fuel gas composition using an engineering estimate 

MW = Annual average molecular weight of fuel (kg/kg-mol), obtained from the estimated 

fuel gas composition using an engineering estimate 

MVC = molar volume conversion factor = 849.5 scf/kg-mol @ std. conditions 

0.001 = conversion from kg to metric tons 

In accordance with the Tier 3 fuel calculation methodology in 40 CFR 98, Subpart C, 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 Rules6

 and 

 

4 Default CH4 and N2O Emission Factors for Various Types of Fuel, 40 CFR 98, Subpart C, Table C-2

5

 40 C.F.R. 98, Subpart C – General Stationary Fuel Combustion Sources

6 Default CH4 and N2O Emission Factors for Various Types of Fuel, 40 CFR 98, Subpart C, Table C-2
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annual heat release for fuel gas combustion. The global warming potential factors used to 

calculate carbon dioxide equivalent (CO2e) emissions are based on Table A-1 of Mandatory 

Greenhouse Gas Reporting Rules. 

4.3 GHG EMISSIONS FROM ELECTRICAL EQUIPMENT INSULATED WITH SF6

Even though SF6 emissions from the circuit breakers associated with the proposed units are not 

expected, potential emissions were calculated using a conservative SF6 annual leak rate of 

0.5% by weight (of total charge) and the SF6 capacity for both breakers. The global warming 

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

Greenhouse Gas Reporting Rules.7

4.4 GHG EMISSIONS FROM NATURAL GAS/OL TAIL GAS PIPING FUGITIVES AND FUEL LINE 

MAINTENANCE AND TURBINE STARTUP RELEASES

GHG emission calculations for natural gas and OL tail gas piping component fugitive emissions 

are based on emission factors from Table W-1A of the Mandatory Greenhouse Gas Reporting 

Rules.8

 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 OL tail gas is variable, the concentrations of 

CH4 and CO2 from the typical natural gas analysis are used as a worst-case estimate. Although 

audio/visual/olfactory (AVO) inspections are being proposed as BACT for this source (see 

Section 6.4.5) no control efficiency credits were taken for AVO monitoring. The global warming 

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

Greenhouse Gas Reporting Rules.9

GHG emission calculations for releases of natural gas related to combustion unit 

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

 

7 Global Warming Potentials, 40 CFR Part 98, Subpart A, Table A-1. 

8 Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production, 40 CFR Part 98, Subpart 

W, Table. W-1A. 

9 Global Warming Potentials, 40 CFR Part 98, Subpart A, Table A-1. 
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and OL tail gas piping fugitives and the volume and initial temperature and pressure of gas prior 

to venting. 

 
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5.0 PREVENTION OF SIGNIFICANT DETERIORATION APPLICABILITY

Since the Point Comfort expansion project10 emissions increase of GHG is greater than 75,000 

ton/yr. of CO2e, PSD is triggered for GHG emissions. The emissions netting analysis for all 

2012 Expansion Project GHG emissions sources is documented on the attached TCEQ PSD 

netting tables: Table 1F and Table 2F found in Appendix B. Note that the 2012 Expansion 

Project emission sources associated with the two combined cycle turbines are new and, as 

such, there are no contemporaneous emission changes associated with these emission units. 

There are however, a few existing emission sources (Olefins II pyrolysis fuel oil and pyrolysis 

gasoline storage tanks) impacted by the Olefins Expansion portion of the 2012 Expansion 

Project. The contemporaneous emission rates for these sources are listed in Table 2F. 

Please note that, although separate permits are being requested and three separate permit 

applications have been submitted, the project increase shown here represents emissions from 

all three permits and the total project increase. 

 

 

10 Includes emission sources from Olefins 3 plant, LDPE plant and combined cycle turbines. 
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6.0 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.11

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.12 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 

 

11 40 C.F.R. § 52.21(b)(12.) 

12 EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, p. 18 (Nov. 2010).
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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 divided 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. 

Step 4: Evaluate most effective controls and document results. 

Step 5: Select the BACT. 

This evaluation is generally performed individually for each GHG emission source which are 

addressed in subsections 6.2 onward. One control technology, Carbon Capture and 

Sequestration (CCS), could be a potential control technology for multiple emissions sources 

associated with the 2012 Expansion Project. Therefore, before presenting the BACT evaluation 

for the individual gas turbine GHG emission sources, the first subsection 6.1, will present the 

BACT evaluation for CCS as a potential control technology. 

6.1 BACT FOR CARBON CAPTURE AND SEQUESTRATION

FPC TX addresses the potential to capture GHG emissions that are emitted from Carbon 

Capture and Sequestration (CCS) candidate sources associated with the 2012 Expansion 

Project listed below (plant names in parenthesis): 

 9 cracking furnaces (Olefins Expansion) 

 4 PDH reactors (Olefins Expansion) 

 4 steam boilers (Olefins Expansion) 

 2 combined cycle gas-fired turbines (Gas Turbines) 

 2 regenerative thermal oxidizers (LDPE) 
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The EPA five step top down BACT evaluation for this potential control technology options is 

provided in Appendix C. As shown in that analysis, CCS is not only not commercially available, 

not technically feasible but also economically unreasonable. Therefore, it is not included as a 

BACT option for any of the emissions sources associated with the 2012 Expansion Project. 

6.2 BACT FOR THE COMBINED CYCLE COMBUSTION TURBINES

6.2.1 Step 1: Identify All Available Control Technologies 

6.2.1.1 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. 

Combustion Turbine Energy Efficiency Processes, Practices, and Designs 

Combustion Turbine Design

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. 
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The most efficient way to generate electricity from a natural gas fuel source is the use of a 

combined cycle turbine design, as is proposed. For comparison sake, fossil fuel technologies’ 

efficiency ranges from approximately 30-50% (higher heating value [HHV]). A modern natural 

gas fired combined cycle unit operating under optimal conditions has a base load efficiency of 

approximately 50% (HHV). Based on this information, it is clear that the proposed facilities 

provide the most efficient option for electric generation. 

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. 

The following discussion lists those design elements and operating and maintenance practices 

that have been considered and selected to maximize energy efficiency. These individual 

elements are not being individually considered as BACT control options, rather overall unit 

energy-efficient design and operation is considered the BACT option. The individual elements’ 

effects on overall unit energy efficiency are reflected in the proposed holistic energy efficiencybased BACT limit in Step 5. 

Periodic Burner Tuning 

The GE Model 7EA 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. 
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Instrumentation and Controls 

The GE Model 7EA 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. The control 

system monitors the operation of the unit and modulates the fuel flow and turbine operation to 

achieve optimal high-efficiency low-emission performance for full-load and part-load conditions. 

Heat Recovery Steam Generator Energy Efficiency Processes, Practices, and Designs 

The HRSGs recover the energy from combustion turbine exhaust waste heat to convert boiler 

feed water to steam. In order to convert the recovered energy to electricity, additional natural 

gas, hydrogen, or OL tail gas is burned in the duct burners which increases the temperature of 

the exhaust coming from the combustion turbines and thereby creates additional steam for the 

steam turbine for electricity production. The duct burner firing provides additional power 

generation capacity during periods of high electrical demand. By firing hydrogen or OL tail gas 

in the duct burners, FPC TX will be recovering heating value from these process streams that 

are normally vented or flared, thereby reducing GHG emissions from flaring. 

The GE Model 7EA combustion turbine-based combined cycle HRSG is generally a horizontal, 

natural circulation, drum-type heat exchanger designed with two pressure levels of steam 

generation, split superheater sections with interstage attemperation, and post-combustion 

emissions control equipment. 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) and evaporator 

section. These heat transfer sections are made up of many thin-walled tubes to provide surface 

area to maximize the transfer of heat to the working fluid. Most of the tubes also include 
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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 postcombustion emissions control components. 

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 the GE Model 7EA combustion 

turbines, these temperatures can approach 1,000°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. 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 

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 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 
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repaired as soon as possible to maintain facility performance. Minimization of vented steam 

and repair of steam leaks will be performed for this project. 

Energy Efficiency Processes, Practices, and Designs 

There are a number of other components within the combined cycle plant that help improve 

overall efficiency, including: 

 Fuel gas superheating – The overall efficiency of the combustion turbine is 

increased with increased fuel inlet temperatures. The natural gas will be 

superheated with steam at the existing fuel gas conditioning skid. This improves 

the efficiency of the combustion turbine. 

 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. 

6.2.2 Step 3: Rank Remaining Control Technologies 

As documented above, implementation of CCS technology is currently infeasible, leaving 

energy efficiency measures as the only technically feasible emission control options. As all of 

the energy efficiency related processes, practices, and designs discussed in the previous 

section of this application are being proposed for this project, a ranking of the control 

technologies is not necessary for this application. 

6.2.3 Step 4: Evaluate Most Effective Controls and Document Results 

As all of the energy efficiency related processes, practices, and designs discussed in the 

previous section 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. 
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6.2.4 Step 5: Select BACT 

FPC TX proposes the selection of all available energy-efficient design options and 

operational/maintenance practices presented in Step 1 as BACT: 

 Use of Combined Cycle Power Generation Technology 

 Combustion Turbine Energy Efficiency Processes, Practices, and Designs, including 

some of the following: 

o Efficient turbine design 

o Periodic turbine burner tuning 

o Instrumentation and controls 

 HRSG Energy Efficiency Processes, Practices, and Designs 

o Efficient heat exchanger design, including recovering heating value from process 

streams by duct burner firing (hydrogen or OL tail gas) 

o Insulation of HRSG 

o Minimizing fouling of heat exchange surfaces 

o Minimizing vented steam and repair of steam leaks 

 Energy Efficiency Processes, Practices, and Designs 

o Fuel gas superheating 

o Multiple combustion turbine/HRSG trains 

Since the proposed energy efficiency design options, described in Step 1 above, are not 

independent features but are interdependent and represent an integrated energy efficiency 

strategy, FPC TX is proposing a BACT limit for each combined cycle unit which takes into 

consideration the operation, variability and interaction of all these energy efficient features in 

combination. A holistic BACT limit which accounts for the ultimate performance of the entire 

unit was chosen, rather than individual independent subsystem performance. Otherwise, 

monitoring and maintaining energy efficiency would be un-necessarily complex because the 

interdependent nature of operating parameters means that one parameter cannot necessarily 

be controlled independently without affecting the other operating parameters. 

FPC TX is proposing a 365-day rolling average net heat rate for the Project of 11,650 Btu/kWh 

(HHV, gross), with duct burner firing, for each combined cycle unit. This heat rate limit is 
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equivalent to an output based GHG BACT limit of 0.568 ton CO2e/MWhr (gross). Since the 

plant heat rate varies according to turbine operating load and the amount of duct burner firing, 

FPC TX proposes to demonstrate compliance with the 11,650 Btu/kWh (HHV) heat rate on a 

rolling 365-day average basis. 

To determine this proposed numeric output-based BACT limit, FPC TX started with the turbine’s 

design heat rate for combined cycle operation (gross, HHV basis) with duct firing and then 

calculated a compliance margin based upon reasonable degradation factors that may 

foreseeably reduce efficiency under real-world conditions. The design heat rate for the gas 

combustion turbines is approximately 12,100 BTU/kWh (HHV, gross basis) based on 

manufacturer information with a rating of 80 MW per turbine. 

Since existing steam turbines will be used to convert HRSG steam into electrical energy, FPC 

TX is proposing a combined cycle design heat rate that considers the steam generated in each 

HRSG (up to 360,000 lb/hr with duct firing) in addition to the 80 MW of electricity generated by 

each gas turbine. Using a steam turbine generator conversion rate of 14.11 klbs steam per 

MWh13, the equivalent combined cycle design heat rate for each unit is 10,330 Btu/kWhr (HHV, 

gross) with duct firing on a 365-day rolling average basis. Note that this rate reflects the 

facility’s “gross” power production, meaning the denominator is the total amount of energy 

produced by the unit (turbine electrical production plus HRSG steam production) prior to 

accounting for auxiliary load consumed by operation of the unit. 

To determine an appropriate heat rate BACT limit for the permit compliance margins are added 

to the base heat rate limit. Firstly, a 3.3% design margin reflecting the possibility that the 

constructed facility will not be able to achieve the design heat rate was considered. 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 calculates an “Installed 

 

13 This steam turbine conversion rate is based on historical annual average performance data for the existing steam 

turbines at the Point Comfort Utility plant. This is not intended to be a permit limit or enforceable representation. 

Rather, this value was selected to convert HRSG steam production to an electrical equivalent for purposes of 

developing a unit equivalent combined cycle heat rate. 
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Base Heat Rate”, which represents a design margin of 3.3% to address such items as 

equipment underperformance and short-term degradation. 

Secondly, 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, FPC TX 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. 

Finally, in addition to the heat rate degradation from normal wear and tear on the combustion 

turbines, FPC TX 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, heat transfer and ancillary equipment such as pumps and motors is 

also expected to occur over the course of a major maintenance cycle. 

FPC TX 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. FPC TX also reviewed pending GHG applications and permits issued by EPA 

Region 6 for combined cycle gas turbines. 

Several EPA Region 6 permit applications and issued permits included GE combined cycle 

Frame 7FA turbines, a larger unit by comparison, and were new power generation plants which 

included a new, high-efficiency steam turbine as part of the project scope. For example, the 

Calpine Channel Energy Center Draft GHG Permit includes a new combined cycle gas turbine 

unit that is sized significantly larger than FPC TX's proposed units. As a result, Calpine's 

proposed unit has a notably smaller heat rate and output-based BACT limit. 
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One application, the Air Liquide Large Industries permit application submitted on September 13, 

2012, includes several new combined cycle units that feature GE Frame 7EA gas turbines. In 

proposing a BACT heat rate limit, Air Liquide calculates an overall unit heat rate using a steam 

turbine conversion rate of 9.1 lbs steam per kWh, which is notably different that the conversion 

rate for FPC TX’s existing steam turbines, based on historical operating data. FPC TX does not 

believe it is appropriate to compare heat rate limits for other proposed new combined cycle units 

that will use new steam turbines with the FPC TX’s proposed new units (which will route steam 

to an existing steam header and steam turbines). 

After accounting for these compliance margins, FPC TX calculated the proposed heat rate limit 

of 11,650 (Btu/kWh, gross, HHV basis, rolling 365-day average) based on the base heat rate. 

The calculation of the heat rate and the equivalent ton CO2e/MWhr is provided in Appendix A of 

this application. 

FPC TX noted that its proposed BACT measures for the gas turbines are similar to those found 

in other GHG permit applications; however, the numeric output-based BACT limit is notably 

different for a few reasons. First, the size of turbine proposed with this project (e.g., GE Frame 

7EA) is significantly smaller than those proposed in other GHG applications (i.e., GE Frame 

7FA). Second, the HRSG steam conversion rate (based on existing steam turbines) is lower 

than that of a new combined cycle unit or new steam turbine generator. 

6.3 BACT FOR SF6 INSULATED ELECTRICAL EQUIPMENT

6.3.1 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 a fraction of the SF6 has escaped. The use of an alarm identifies 
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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.

14 

6.3.2 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.15 It is easy to use, exhibits exceptional insulation and arc-interruption 

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

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

SF6-insulated equipment. The report concluded that although “...various gas mixtures show 

considerable promise for use in new equipment, particularly if the equipment is designed 

specifically for use with a gas mixture... it is clear that a significant amount of research must be 

performed for any new gas or gas mixture to be used in electrical equipment.” Therefore there 

are currently no technically feasible options besides use of SF6. 

6.3.3 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. 

 

14 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. 

15 Id. at 28 – 29. 
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6.3.4 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.

6.3.5 Step 5: Select BACT 

Based on this top-down analysis, FPC TX concludes that using state-of-the-art enclosedpressure 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.16 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. 

6.4 BACT FOR NATURAL GAS AND OL TAIL GAS PIPING FUGITIVES

6.4.1 Step 1: Identify All Available Control Technologies 

The following available control technologies for fugitive piping components emitting GHGs 

(those in natural gas and fuel gas service) were identified: 

 Installation of leakless technology components to eliminate fugitive emission sources. 

 Implementing LDAR programs (those used for VOC components) in accordance with 

applicable state and federal air regulations. 

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

camera monitoring. 

 

16 ANSI Standard C37.013, Standard for AC High-Voltage Generator Circuit Breakers on a Symmetrical Current. 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

38 

 Implementing an audio/visual/olfactory (AVO) monitoring program typically used for nonVOC compounds. 

6.4.2 Step 2: Eliminate Technically Infeasible Options 

All the available options are considered technically feasible and have been used in industry as 

described below. 

Leakless valves are primarily used where highly toxic or otherwise hazardous materials are 

present. Leakless valves are expensive in comparison to a standard (non-leakless) valve. 

These technologies are generally considered cost prohibitive except for specialized service. 

LDAR programs are typically implemented for control of VOC emissions from materials in VOC 

service (at least 5 wt% VOC), however instrument monitoring may also be technically feasible 

for components in CH4 service, including the fuel gas and natural gas piping fugitives. 

Remote sensing technologies have been proven effective in leak detection and repair, 

especially on larger pipeline-sized lines. The use of sensitive infrared camera technology has 

become widely accepted as a cost-effective means for identifying leaks of hydrocarbons 

depending on the number of sources. 

AVO monitoring methods are also capable of detecting leaks from piping components as leaks 

can be detected by sound (audio) and sight. AVO programs are commonly used in industry and 

technically feasible for the GHG fugitives in the Olefins 3 unit. 

6.4.3 Step 3: Rank Remaining Control Technologies 

AVO monitoring has been implemented historically at the Point Comfort plant. AVO monitoring 

is as effective in detecting significant leaks as Method 21 instrument or remote sensing 

monitoring if AVO inspections are performed frequently enough. AVO detections can be 

performed very frequently, at lower cost and with less additional manpower and equipment than 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

39 

Method 21 instrument or remote sensing monitoring because it does not require a specialized 

piece of monitoring equipment. Therefore, for components in methane (natural gas or fuel gas) 

service AVO is considered the most preferred technically feasible alternative. 

Remote sensing using infrared imaging has accepted by EPA as an acceptable alternative to 

Method 21 instrument monitoring and leak detection effectiveness is expected to comparable. 

However, less manpower may be required for remote sensing compared to Method 21 

depending on the number of sources. The frequency of monitoring is more limited than AVO 

because the number of simultaneous measurements will be limited by the availability of the 

remote sensing equipment. 

Method 21 Instrument monitoring has historically been used to identify leaks in need of repair. 

However, instrument monitoring requires significant allocation of manpower as compared to 

AVO monitoring, while AVO is expected to be equally effective at identifying significant leaks. 

Leakless technologies are effective in eliminating fugitive emissions from the locations where 

installed. However, because of their high cost, these specialty components are, in practice, 

selectively applied only as absolutely necessary to toxic or hazardous components. 

6.4.4 Step 4: Evaluate Most Effective Controls and Document Results 

The AVO monitoring option is expected to be effective in finding leaks, can be implemented at 

the greatest frequency and lower cost due to being incorporated into routine operations. 

The use of Method 21 instrument leak detection is technically feasible, however the leak 

effectiveness, in comparison to AVO monitoring, is likely similar or less for components in 

methane service. However, Method 21 instrument monitoring is much more costly and requires 

much more manpower than AVO monitoring. In addition, AVO monitoring can be done at a 

much greater frequency thus allowing detection of leaks more quickly. 

Remote sensing monitoring costs less than Method 21 instrument monitoring but is still much 

more costly than AVO. Typically, remote sensing is more applicable to larger potential emission 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

40 

sources that contain critical fugitive components with the potential for high volume leaks. In 

addition, remote sensing can be performed on a limited frequency because it requires 

specialized equipment. Remote sensing is not practicable for small fugitive sources 

Leakless technologies have not been universally adopted as BACT for emission from fugitive 

piping components, even for hazardous services. Therefore, FPC TX believes that these 

technologies are not practical for control of GHG emissions from methane piping components. 

6.4.5 Step 5: Select BACT 

Please note the total GHG fugitive emissions are expected to be less than 0.05% of the total 

GHG emissions from the proposed new combined cycle turbines. FPC TX proposes to perform 

weekly AVO monitoring of piping components associated with the new combined cycle turbines 

that are in GHG service (natural gas and fuel gas service). 

FPC TX performed a search of the EPA’s RACT/BACT/LAER Clearinghouse for piping fugitive 

GHG emissions 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 other 

GHG permit applications submitted to EPA Region 6. A discussion of FPC TX’s proposed 

BACT as compared to those projects is provided below. 

 Equistar Channelview – Olefins I&II Expansions

o The Equistar applications request authorization of GHG emissions from piping 

components. These applications propose remote sensing of “pipeline sized” 

components that are not otherwise subject to Method 21 monitoring. 

 Equistar La Porte – Olefins Expansion

o The Equistar permit application proposes to employ TCEQ’s 28 LAER fugitive 

leak detection and repair program for components “in CH4 service” as BACT, 

however “in CH4 service” is not defined in the application. 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

41 

 Chevron Phillips Chemical Company LP – Cedar Bayou Plant, New Ethylene Unit

o The Chevron Phillips application proposes as-observed AVO 

(audio/visual/olfactory) monitoring for natural gas and fuel gas piping 

components as BACT. 

 ExxonMobil Baytown Olefins Plant

o The ExxonMobil application proposes as-observed AVO (audio/visual/olfactory) 

monitoring for natural gas piping components and applicable TCEQ LDAR 

programs for components in VOC service as BACT. 

 ExxonMobil Mont Belvieu Plastics Plant

o The ExxonMobil application proposes as-observed AVO (audio/visual/olfactory) 

monitoring for natural gas piping components and applicable TCEQ LDAR 

programs for components in VOC service as BACT. 

 INEOS USA LLC – Olefins Expansion

o The INEOS permit requires TCEQ’s 28VHP LDAR program for all methane 

piping components.

 BASF FINA - NAFTA Region Olefins Complex

o The BASF permit specifies the use of TCEQ’s 28LAER LDAR program for all 

fugitive emissions of methane. 

FPC TX’s proposed weekly AVO monitoring is equally as effective and can be performed at 

greater frequency as instrument monitoring. Therefore, FPC TX’s proposed BACT for fugitive 

components is as effective as BACT proposed in other applications. 

6.5 BACT FOR NATURAL GAS VENTING

6.5.1 Step 1: Identify All Available Control Technologies 

No physical GHG control technologies exist for natural gas venting from maintenance startup 

and shutdown activities. The primary means of limiting/controlling GHG emissions from this 

activity, is minimizing the frequency. FPC TX expects to operate the turbines with as much onstream time as possible, thus minimizing the frequency of startups and associated natural gas 

purges during startup. 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

42 

6.5.2 Step 2: Eliminate Technically Infeasible Options 

No options are being eliminated in this step. 

6.5.3 Step 3: Rank Remaining Control Technologies 

No options are being eliminated in this step. 

6.5.4 Step 4: Evaluate Most Effective Controls and Document Results 

No options are being eliminated in this step. 

6.5.5 Step 5: Select BACT 

FPC TX proposes to minimize the annual frequency of natural gas venting to no more than the 

frequencies specified as the bases for the emission calculations (Appendix A) for this activity: 15 

turbine startup purges per year per turbine. 

 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

43 

7.0 OTHER PSD REQUIREMENTS

7.1 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 or 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.17

An impacts analysis for non-GHG emissions is being submitted with the State/PSD/Nonattainment application submitted to the TCEQ. 

7.2 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.18

 

17 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases at 48-49. 

18 Id. at 49. 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

44 

A pre-construction monitoring analysis for non-GHG emissions is being submitted with the 

State/PSD/Nonattainment application submitted to the TCEQ. 

 

7.3 ADDITIONAL IMPACTS 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 

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.19

A PSD additional impacts analysis for non-GHG emissions is being submitted with the 

State/PSD/Nonattainment application submitted to the TCEQ. 

 

19 Id. 
FORMOSA PLASTICS CORPORATION, TEXAS NOVEMBER 2012

2012 EXPANSION PROJECT: GAS TURBINES

GHG PSD APPLICATION

45 

8.0 PROPOSED GHG MONITORING PROVISIONS

FPC TX proposes to monitor CO2 emissions by monitoring the quantity of fuels combusted in 

the turbines and heat recovery steam generators and performing periodic fuel sampling as 

required by the applicable provisions of 40 CFR 98 Subpart C as discussed in Section 4. FPC 

TX expects that this approach will allow for monitoring of GHG emissions in a manner 

consistent with existing plant operating procedures and the GHG monitoring and reporting 

requirements applicable to both existing sources and those sources proposed with this 

application. 
APPENDIX A 

GHG EMISSION CALCULATIONS 

 
 Unit: GE 7EA Gas 

Turbine

HRSG with 100% Duct 

Firing

Heat Input: 970 120 MMBtu/hr (HHV)

Energy Output (Gross): 80,000 25,521 kW (Gross)

Total Base Heat Rate, Combined Cycle Unit (Gross): Btu/kWh (HHV) (Gross)

Design Margin

Performance Margin

Degradation Margin

Calculated Base Heat Rate with Compliance Margins: Btu/kWh (HHV) (Gross)

Calculation of ton CO2e/MWhr Heat Rate Limit for Each combined cycle unit

EPNs

Total Energy 

Output (each 

unit)

GHG Emission 

Rate (each unit) 

[1]

GHG Emission 

Rate (each unit) 

[2]

ton CO2e/MWhr (gross) 

[3]

(MW) (ton CO2e/yr) (ton CO2e/hr)

7K, 7L 105.5 525,024 59.9

Notes:

[1] From CO2 Summary Sheet, combined cycle unit subtotal divided by two (two units).

[2] Based on 8760 hours per year operation.

[3] Calculated as GHG emission rate (ton CO2e/hr) divided by Total energy output (MW)

0.568

BACT Calculation of Heat Rate Limit

Formosa Plastic Corporation, Texas

2012 Expansion Project: Gas Turbines

3.0%

11,650

10,330

3.3%

6.0%

November 2012

Utility GHG Calc Template.xlsx 18
Table A-1

GHG Emission Summary

Formosa Plastic Corporation, Texas

2012 Expansion Project: Gas Turbines

November 2012

Source Name Operating Scenario EPN

Detailed 

Calculations in

GHG Mas

Emission

(tpy) 

Gas Turbine 1 7K 463,071 

Gas Turbine 2 7L 463,071 

Firing 100% Natural Gas Table A-3 61,449 Firing 100% OL Tail Gas Table A-4 52,975 

Firing 100% Hydrogen [2] N/A 0 

Firing 100% Natural Gas Table A-3 61,449 

Firing 100% OL Tail Gas Table A-4 52,975 

Firing 100% Hydrogen [2] N/A 0 

Subtotal Total, Combined Cycle Units [3] = 1,049,04

Turbine Startup, Fuel Line 

Maintenance Startup, Maintenance 7K-NGVENT, 7L- NGVENT Table A-5 1.24 

Fugitive Components N/A NG-FUG Table A-6 20.90 

SF6 Electrical Insulation N/A SF6-FUG Table A-7 <0.01 

Total = 1,049,06

Notes:[1] The duct burners may fire up to 100% heat input on any listed fuel or any combination thereof.[2] Combustion of 100% hydrogen fuel stream in the duct burners does not result in any GHG emissions (carbon content is zero).[3] Total GHG emissions are calculated as the maximum emissions from duct burner firing on any one of the three fuel types, plusGHG emission contributions from the Gas turbines.

Firing 100% Natural Gas Table A-2

Duct Firing, Unit 1 [1]Duct Firing, Unit 2 [1]

7K

7L

Utility GHG Calc Template.xlsx
GHG Emission Calculations - Natural Gas Combustion - Gas Turbines

Formosa Plastic Corporation, Texas

2012 Expansion Project: Gas Turbines

November 2012

GHG Emissions Contribution From Natural Gas Fired Combustion Turbines:

EPN Average Heat 

Input

Annual Heat 

Input

Pollutant Emission Factor GHG Mass Emissions2 

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)1 (tpy) 

CO2 53.02 463,062 

7K 997 8,733,720 CH4 1.0E-03 8.73 

N2O 1.0E-04 0.87 

Totals 463,071 

CO2 53.02 463,062 

7L 997 8,733,720 CH4 1.0E-03 8.73 

N2O 1.0E-04 0.87 

Totals 463,071 

Total for 2 Turbines 926,143 

Notes:1. CO 2 GHG factor from Table C-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting (GHG MRR). 

CH 4 and N 2 O GHG factors based on Table C-2 of GHG MRR. 

2. CO 2 emissions based on 40 CFR Part 98, Subpart C, Equation C-1.

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Sample Calculation, CO 2 :

GHG Mass Emissions (metric ton/yr) = 0.001 x 8733720 (MMBtu/yr) x 53.02 kg/MMBtu = 463062CO2e (metric ton/yr) = 463062 (tpy) x 1 = 463062

W

P

Table A-2

Utility GHG Calc Template.xlsx
GHG Emissions Contribution From Natural Gas Fired Combustion:

Source Type Average Heat 

Input/Unit

Annual Avg 

Heat Input, 

Each Unit

Pollutant Emission Factor GHG Mass Emissions2 

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu)1 (metric ton/yr) (m

CO2 53.02 55,735 1 

Turbine 1 Duct Burners 120 1,051,200 CH4 1.0E-03 1.05 21 

N2O 1.0E-04 0.11 310 

Totals 55,736 

CO2 53.02 55,735 1 

Turbine 2 Duct Burners 120 1,051,200 CH4 1.0E-03 1.05 21 

N2O 1.0E-04 0.11 310 

Totals 55,736 

Total, All Natural Gas Duct Firing 111,472 

Notes:1. CO2 GHG factor from Table C-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting (GHG MRR). CH4 and N2O GHG factors based on Table C-2 of GHG MRR. 2. CO 2 emissions based on 40 CFR Part 98, Subpart C, Equation C-1.

3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Sample Calculation, CO 2 :

GHG Mass Emissions (metric ton/yr) = 0.001 x 1051200 (MMBtu/yr) x 53.02 kg/MMBtu = 55735CO2e (metric ton/yr) = 55735 (metric ton/yr) x 1 = 55734.6

Table A-3

GHG Emission Calculations - Duct Burners Natural Gas Combustion

Formosa Plastic Corporation, Texas

Emissions pe

Global 

Warming 

Potential3

2012 Expansion Project: Gas Turbines

November 2012

Utility GHG Calc Template.xlsx
Olefins (OL) Tail Gas Data:

Variable Value Units Reference

Net Heating Value (LHV) 625 Btu/scf Formosa Design Specification

Carbon Content (Annual 

Avg) 0.677 kg C/kg Formosa Design Specification

Molecular Weight 

(Annual Avg) 9.8 kg/kg-mol Formosa Design Specification

GHG Emissions Contribution from OL Tail Gas Combustion:

Source Type Average Heat 

Input/Unit

Annual 

Average Fuel 

Gas 

Usage/Unit1

Annual Average 

Fuel Use, Each 

Unit

Annual 

Average Heat 

Input, Each 

Unit

Pollutant Emission Factor GHG Mass Emissions3 

(MMBtu/hr) (MMscf/hr) (scf/yr) (MMBtu/yr) (kg/MMBtu)2 (metric ton/yr) 

CO2 48,049 1 

Turbine 1 Duct Burners 120 0.192 1.68E+09 1.05E+06 CH4 1.0E-03 1.05 21 

N2O 1.0E-04 0.11 310 

Totals 48,050 

CO2 48,049 1 

Turbine 2 Duct Burners 120 0.192 1.68E+09 1.05E+06 CH4 1.0E-03 1.05 21 

N2O 1.0E-04 0.11 310 

Totals 48,050 

Total, All OL Tail Gas Combustion 96,099 

Notes:1. Fuel use calculated as: MMscf/hr = Firing rate (MMBtu/hr) / HHV (Btu/scf)2. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

CH 4 and N 2 O emissions based on 40 CFR Part 98, Subpart C, Equation C-8.

3. CO 2 emissions based on 40 CFR Part 98, Subpart C, Equation C-5.

4. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Sample Calculation: Duct Burners Turbine 1 - CO 2 :

GHG Mass Emissions (metric ton/yr) = (44/12) x 1.68E+09 (scf/yr) x 0.677 kg C/kg x 9.77 kg/kg-mol / 849.5 scf/kg-mole @ std cond. x 0.001 = 4.80E+04CO2e (metric ton/yr) = 4.80E+04 (metric ton/yr) x 1 = 4.80E+04

Global 

Warming 

Potential4

GHG Emission Calculations - OL Tail Gas Combustion

Formosa Plastic Corporation, Texas

2012 Expansion Project: Gas Turbines

Table A-4

November 2012

Utility GHG Calc Template.xlsx
CO23 

Volume1 Press. Temp. Press. Temp. Volume2 Annual 

(ft3) (psig) (°F) (psig) (°F) (scf) (tpy) 

75.0 300 90 0 68 1,635 30 0.0336 

20.0 300 90 0 68 436 24 0.00718 

GHG Mass-Based Emissions 0.0408 Global Warming Potential5 1 

CO2e Emissions 0.0408 

Notes:

1. Initial volume is calculated by multpilying the crossectional area by the length of pipe using the following formula: V i = pi * [(diameter in inches/12)/2] 2 * length in fee2. Final volume calculated using ideal gas law [(PV/ZT) i = (PV/ZT) f ]. V f = V i (P i /P f ) (T f /T i ) (Z f /Z i ), where Z is estimated using the following

 equation: Z = 0.9994 - 0.0002P + 3E-08P 2 .

3. CO 2 emissions based on vol% of CO 2 in natural gas 1.20% from natural gas analysis

4. CH 4 emissions based on vol% of CH 4 in natural gas 96.6% from natural gas analysis

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

1635 scf Nat Gas 0.012 scf CO2 lbmole ton = = 0.0336 ton/yr CO 

yr scf Nat Gas 385 scf 2000 lb

Table A-5

Turbine Startup

Fuel Line Maintenance

44 lb CO 2

lbmole

GHG Emission Calculations - 

Formosa Plastic Corporation, Texas

Initial Conditions Final Conditions

Gaseous Fuel Venting During Turbine Startup and

Fuel Line Maintenance, EPNs 7K-NGVENT, 7L-NGVENT

Annual 

Frequency of 

Location Event

2012 Expansion Project: Gas Turbines

November 2012

Utility GHG Calc Template.xlsx
GHG Emissions Contribution From Fugitive Piping Components:

EPN Source Fluid Count Emission CO2 Content CH4 Content CO2 Methan

Type State Factor1 (vol %) (vol %) (tpy) (tpy) 

scf/hr/comp

Valves Gas/Vapor 600 0.121 0.436 12.80

NG-FUG Flanges Gas/Vapor 2400 0.017 0.245 7.19

Relief Valves Gas/Vapor 5 0.193 5.80E-03 1.70E-0

Sampling Connections Gas/Vapor 10 0.031 1.86E-03 5.46E-0

Compressors Gas/Vapor 3 0.002 3.60E-05 1.06E-0

GHG Mass-Based Emissions 0.689 20.2 Global Warming Potential2 1 21

CO2e Emissions 0.69 424.5 

Notes:1. Emission factors from Table W-1A of 40 CFR 98 Mandatory Greenhouse Gas Reporting2. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Example calculation:

600 valves 0.121 scf gas lbmol 44.01 lb CO2 8760 hr ton 

hr * valve scf gas 385 scf lbmol yr 2000 lb

0.012 scf CO2

1.20% 96.6%

Table A-6

GHG Emission Calculations - Fugitive Component Emissions

Formosa Plastic Corporation, Texas

2012 Expansion Project: Gas Turbines

November 2012

Utility GHG Calc Template.xlsx
EPN Insulated SF6 Annual Leak Annual Leak Global Warming 

Circuit Breaker Capacity Rate, wt % Rate (tpy) Potential1 

 (pounds) 

SF6-FUG 495 0.50% 1.24E-03 23,900 

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

GHG Emission Calculations - Electrical Equipment Insulated with SF6

Formosa Plastic Corporation, Texas

2012 Expansion Project: Gas Turbines

Table A-7

November 2012

Utility GHG Calc Template.xlsx
APPENDIX B 

PSD NETTING TABLES 

 
TABLE 1F

AIR QUALITY APPLICATION SUPPLEMENT

Permit No.: TBD Application Submittal Date:

Company Formosa Plastic Corporation, Texas

RN: RN100218973 Facility Location: 201 Formosa DriveCity Point Comfort County: Calhoun

Permit Unit I.D.: 2012 Expansion Project Permit Name: TBD

Permit Activity:Project or Process Description: Complete for all pollutants with a project POLLUTANTSemission increase. Ozone CO SO2 PM G

NOx VOC

Nonattainment? (yes or no) 

Existing site PTE (tpy) >10Proposed project increases (tpy from 2F) 3,03

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) Y

If netting required, estimated start of construction: 9/1/13

5 years prior to start of construction: 9/1/08 Contemporaneous

estimated start of operation: 10/1/15 Period

Net contemporaneous change, including proposed project, 

from Table 3F (tpy) 3,03

FNSR applicable? (yes or no) Y

Olefins Expansion, LDPE Plant and Gas Turbines

This form for GHG only

New Major Source Modification
TABLE 2F

PROJECT EMISSION INCREASE

Pollutant(1): GHG Mass Emissions Permit: TBD

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit No.

FIN EPN

1 OL3-FUR1 OL3-FUR1 0.00 0.00 99,732 99,732 99,732

2 OL3-FUR2 OL3-FUR2 0.00 0.00 99,732 99,732 99,732

3 OL3-FUR3 OL3-FUR3 0.00 0.00 99,732 99,732 99,732

4 OL3-FUR4 OL3-FUR4 0.00 0.00 99,732 99,732 99,732

5 OL3-FUR5 OL3-FUR5 0.00 0.00 99,732 99,732 99,732

6 OL3-FUR6 OL3-FUR6 0.00 0.00 99,732 99,732 99,732

7 OL3-FUR7 OL3-FUR7 0.00 0.00 99,732 99,732 99,732

8 OL3-FUR8 OL3-FUR8 0.00 0.00 99,732 99,732 99,732

9 OL3-FUR9 OL3-FUR9 0.00 0.00 99,732 99,732 99,732

10 OL3-BOIL1 OL3-BOIL1 0.00 0.00 164,532 164,532 164,532

11 OL3-BOIL2 OL3-BOIL2 0.00 0.00 164,532 164,532 164,532

12 OL3-BOIL3 OL3-BOIL3 0.00 0.00 164,532 164,532 164,532

13 OL3-BOIL4 OL3-BOIL4 0.00 0.00 164,532 164,532 164,532

14 PDH-REAC1 PDH-REAC1 0.00 0.00 61,185 61,185 61,185

15 PDH-REAC2 PDH-REAC2 0.00 0.00 61,185 61,185 61,185

16 PDH-REAC3 PDH-REAC3 0.00 0.00 61,185 61,185 61,185

17 PDH-REAC4 PDH-REAC4 0.00 0.00 61,185 61,185 61,185

18 OL3-FUG OL3-FUG 0.00 0.00 3.91 3.91 3.91

19 PDH-FUG PDH-FUG 0.00 0.00 0.94 0.94 0.94

Olefins 3 Plant Sources

Project 

Increase(8)

Actual 

Emissions(

3)

Baseline 

Emissions(

4)

Proposed 

Emissions(5)

Projected

Actual

Emissions

Difference

(B - A) (6)

Correction (7)
Pollutant(1): GHG Mass Emissions Permit: TBD

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit No.

FIN EPN

Project 

Increase(8)

Actual 

Emissions(

3)

Baseline 

Emissions(

4)

Proposed 

Emissions(5)

Projected

Actual

Emissions

Difference

(B - A) (6)

Correction (7)

20 OL3-FLR OL3-FLR 0.00 0.00 118,050 see Note 1 118,050 118,050

21 OL3-LPFLR1 OL3-LPFLR1 0.00 0.00 985.6 985.6 985.6

22 OL3-LPFLR2 OL3-LPFLR2 0.00 0.00 985.6 985.6 985.6

23 OL3-DK1 OL3-DK1 0.00 0.00

24 OL3-DK2 OL3-DK2 0.00 0.00

25 OL3-MAPD OL3-MAPD 0.00 0.00 20.9 20.9 20.9

26 PDH-MSSVO PDH-MSSVO 0.00 0.00 2.55 2.55 2.55

27 OL3-MSSVO OL3-MSSVO 0.00 0.00 1.70 1.70 1.70

28 OL3-GEN OL3-GEN 0.00 0.00 447 447 447

29 PDH-GEN PDH-GEN 0.00 0.00 447 447 447

30 N6460FA/B 1087 19168 2.33 2.33 2.82 see Note 2 0.49 0.49

31 LD-022A/B LD-022A/B 0.00 0.00

32 LD-023A/B LD-023A/B 0.00 0.00

33 OL3-FLR OL3-FLR 0.00 0.00 21,933 see Note 1 21,933 21,933

34 LD-014 LD-014 0.00 0.00 4,818 4,818 4,818

35 LD-015 LD-015 0.00 0.00 4,818 4,818 4,818

36 LD-002 LD-002 0.00 0.00 207.1 207.1 207.1

37 NG-FUG NG-FUG 0.00 0.00 20.9 20.9 20.9

38 LD-MSS LD-MSS 0.00 0.00 0.01 0.01 0.01

39 7K 7K 0.00 0.00 524,520 524,520 524,520

40 7L 7L 0.00 0.00 524,520 524,520 524,520

41 7K-NGVENT, 

7L-NGVENT

7K-NGVENT, 

7L-NGVENT 0.00 0.00 1.24 1.24 1.24

42 NG-FUG NG-FUG 0.00 0.00 20.9 20.9 20.9

43 SF6-FUG SF6-FUG 0.00 0.00 <0.01 0.01 0.01

Notes: Total = 3,034,027

[1] Elevated flare emission rate includes MSS emissions from vessel degassing.

[2] Baseline period is January 2009 through December 2010.

LDPE Plant Sources

Combined Cycle Turbine Sources

211.6 211.6 211.6

31,550 31,550 31,550
TABLE 2F

PROJECT EMISSION INCREASE

Pollutant(1): CO2e Permit: TBD

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit No.

FIN EPN

1 OL3-FUR1 OL3-FUR1 0.00 0.00 99,865 99,865 99,865

2 OL3-FUR2 OL3-FUR2 0.00 0.00 99,865 99,865 99,865

3 OL3-FUR3 OL3-FUR3 0.00 0.00 99,865 99,865 99,865

4 OL3-FUR4 OL3-FUR4 0.00 0.00 99,865 99,865 99,865

5 OL3-FUR5 OL3-FUR5 0.00 0.00 99,865 99,865 99,865

6 OL3-FUR6 OL3-FUR6 0.00 0.00 99,865 99,865 99,865

7 OL3-FUR7 OL3-FUR7 0.00 0.00 99,865 99,865 99,865

8 OL3-FUR8 OL3-FUR8 0.00 0.00 99,865 99,865 99,865

9 OL3-FUR9 OL3-FUR9 0.00 0.00 99,865 99,865 99,865

10 OL3-BOIL1 OL3-BOIL1 0.00 0.00 164,754 164,754 164,754

11 OL3-BOIL2 OL3-BOIL2 0.00 0.00 164,754 164,754 164,754

12 OL3-BOIL3 OL3-BOIL3 0.00 0.00 164,754 164,754 164,754

13 OL3-BOIL4 OL3-BOIL4 0.00 0.00 164,754 164,754 164,754

14 PDH-REAC1 PDH-REAC1 0.00 0.00 289,840 289,840 289,840

15 PDH-REAC2 PDH-REAC2 0.00 0.00 289,840 289,840 289,840

16 PDH-REAC3 PDH-REAC3 0.00 0.00 289,840 289,840 289,840

17 PDH-REAC4 PDH-REAC4 0.00 0.00 289,840 289,840 289,840

18 OL3-FUG OL3-FUG 0.00 0.00 77.97 77.97 77.97

19 PDH-FUG PDH-FUG 0.00 0.00 15.76 15.76 15.76

20 OL3-FLR OL3-FLR 0.00 0.00 128,455 See Note 1 128,455 128,455

21 OL3-LPFLR1 OL3-LPFLR1 0.00 0.00 1,040.7 1,040.7 1,040.7

22 OL3-LPFLR2 OL3-LPFLR2 0.00 0.00 1,040.7 1,040.7 1,040.7

23 OL3-DK1 OL3-DK1 0.00 0.00

24 OL3-DK2 OL3-DK2 0.00 0.00

25 OL3-MAPD OL3-MAPD 0.00 0.00 20.90 20.90 20.90

26 PDH-MSSVO PDH-MSSVO 0.00 0.00 3.81 3.81 3.81

27 OL3-MSSVO OL3-MSSVO 0.00 0.00 35.1 35.1 35.1

28 OL3-GEN OL3-GEN 0.00 0.00 448.5 448.5 448.5

29 PDH-GEN PDH-GEN 0.00 0.00 448.5 448.5 448.5

30 N6460FA/B 1087 2.72 2.72 3.29 See Note 2 0.57 0.57

211.6 211.6 211.6

Olefins 3 Plant Sources

Project 

Increase(8)

Actual 

Emissions(

3)

Baseline 

Emissions(

4)

Proposed 

Emissions(

5)

Projected

Actual

Emissions

Difference

(B - A) (6)

Correction

(7)
Pollutant(1): CO2e Permit: TBD

Baseline Period: N/A to N/A

A B

Affected or Modified Facilities(2) Permit No.

FIN EPN

Project 

Increase(8)

Actual 

Emissions(

3)

Baseline 

Emissions(

4)

Proposed 

Emissions(

5)

Projected

Actual

Emissions

Difference

(B - A) (6)

Correction

(7)

31 LD-022A/B LD-022A/B 0.00 0.00

32 LD-023A/B LD-023A/B 0.00 0.00

33 OL3-FLR OL3-FLR 0.00 0.00 22,216 See Note 1 22,216 22,216

34 LD-014 LD-014 0.00 0.00 17,810 17,810 17,810

35 LD-015 LD-015 0.00 0.00 17,810 17,810 17,810

36 LD-002 LD-002 0.00 0.00 229.1 229.1 229.1

37 NG-FUG NG-FUG 0.00 0.00 425.2 425.2 425.2

38 LD-MSS LD-MSS 0.00 0.00 0.08 0.08 0.08

39 7K 7K 0.00 0.00 525,024 525,024 525,024

40 7L 7L 0.00 0.00 525,024 525,024 525,024

41 7K-NGVENT, 7LNGVENT

7K-NGVENT, 

7L-NGVENT 0.00 0.00 25.1 25.1 25.1

42 NG-FUG NG-FUG 0.00 0.00 425.2 425.2 425.2

43 SF6-FUG SF6-FUG 0.00 0.00 29.6 29.6 29.6

Summary of Contemporaneous Changes Total 3,990,283

Notes: 

[1] Elevated flare emission rate includes MSS emissions from vessel degassing.

[2] Baseline period is January 2009 through December 2010.

Combined Cycle Turbine Sources

LDPE Plant Sources

32,306 32,306 32,306
APPENDIX C 

CCS DETAILED BACT ANALYSIS AND SUPPLEMENTAL 

INFORMATION 
BACT FOR CARBON CAPTURE AND SEQUESTRATION

FPC TX addresses the potential to capture GHG emissions that are emitted from Carbon 

Capture and Sequestration (CCS) candidate sources associated with the 2012 Expansion 

Project listed below (plant names in parenthesis): 

 9 cracking furnaces (Olefins Expansion) 

 4 PDH Reactors (Olefins Expansion) 

 4 steam boilers (Olefins Expansion) 

 PDH regeneration vents (Olefins Expansion) 

 2 combined cycle gas-fired turbines (Gas Turbines) 

 2 regenerative thermal oxidizers (LDPE) 

The EPA five step top down BACT evaluation for this potential control technology options is 

provided in this Appendix. As shown in that analysis, CCS is not only not commercially 

available, not technically feasible but also economically unreasonable. Therefore, it is not 

included as a BACT option for any of the emissions sources associated with the 2012 

Expansion Project. 

6.1.1 STEP 1: IDENTIFY ALL AVAILABLE CONTROL TECHNOLOGIES 

The emerging carbon capture and sequestration (CCS) technologies generally consist of 

processes that separate CO2 from combustion or process flue gas (capture component), the 

compression and transport component, and then injection into geologic formations such as oil 

and gas reservoirs, unmineable coal seams, and underground saline formations (sequestration 

component). These three components of CCS are addressed separately below: 

Carbon Capture: 

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. 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. Although the DOE-NETL discussions focus on CCS 

application at combustion units in electrical generation service, elements of this discussion are 
applicable when discussing the application of CCS to sources in the chemical manufacturing 

industry. The following excerpts from DOE-NETL Information Portal illustrate some of the many 

challenges, but not all, that are present in applying available CO2 Capture technologies at 

combustion and process sources located at chemical manufacturing plants. 

...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...1

In its CCS information portal, 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. 

 Trace impurities (particulate matter, sulfur dioxide, nitrogen oxides) in the flue gas 

can degrade sorbents and reduce the effectiveness of certain CO2 capture 

processes. 

It should be noted that the majority of the candidate CCS source vent streams (previously listed 

in this section) are dilute in CO2 concentration and contain impurities such as PM, NOX and SO2, 

thus increasing the challenge of CO2 separation for the Point Comfort expansion project. 

 

1

 DOE-NETL, Carbon Sequestration: FAQ Information Portal, 

http://extsearch1.netl.doe.gov/search?q=cache:e0yvzjAh22cJ:www.netl.doe.gov/technologies/carbon_seq/FAQs/techstatus.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 July 26, 2012). 
Compression and Transport: 

The compression aspect of this component of CCS will represent a significant cost and 

additional environmental impact because of the energy required to provide the amount of 

compression needed. This is supported by DOE-NETL who states that:

Compressing captured or separated CO2 from atmospheric pressure to pipeline 

pressure (about 2,000 psia) represents a large auxiliary power load on the overall 

plant system...2

If CO2 capture and compression can be achieved at a process or combustion source, 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 and their associated 

technical challenges 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...3

 

2

 Id.

3

 DOE-NETL, Carbon Sequestration: Geologic Storage Focus Area,

http://www.netl.doe.gov/technologies/carbon_seq/corerd/storage.html (last visited July 26, 2012) 
Therefore, as can be seen from the DOE-NETL Information Portal, CCS as a whole cannot be 

considered a commercial available, technically feasible option for the combustion and process 

vent emissions sources under review in the FPC TX proposed expansion. FPC TX’s expansion 

project generates flue gas streams that contain CO2 in dilute concentrations and the project is 

not located in an acceptable geological storage location. Even so, FPC TX provides even 

further and more detailed evaluation to address all 5 steps of the EPA BACT analysis. 

6.1.2 STEP 2: ELIMINATE TECHNICALLY INFEASIBLE OPTIONS

Although, as described above, CCS should not be considered an available control technology, 

in this section, FPC-TX addresses, in more detail, the potential feasibility of implementing CCS 

technology as BACT for GHG emissions from the proposed expansion project GHG emission 

sources. The feasibility issues are different for each component of CCS technology (i.e., 

capture; compression and transport; and storage). Therefore, technical feasibility of each 

component is addressed separately below. 

6.1.2.1 CO2 Capture 

Though amine absorption technology for CO2 capture has routinely been applied to processes 

in the petroleum refining and natural gas processing industries it has not been applied to 

process vents at chemical manufacturing plants. 

The Obama Administration’s Interagency Task Force on Carbon Capture and Storage, in its 

recently completed report on the current status of development of CCS systems for power 

plants, states that carbon capture could be used on combustion units. However, the following 

discussion on carbon capture technology availability for high volume vent streams and large 

combustion unit shows that carbon capture is not commercially available for application. 

Large commercial applications, such as the expansion project sources, present even more 

difficult application of carbon capture, in part, due to the additional variability in flow volumes as 

typically experienced in chemical plants. Therefore, the discussion related to power plants also 

shows that of CO2 capture for chemical process combustion and process vent stream are not 

commercially available. 
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.

4

 

In its current CCS research program plans (which focus on power plant application), the DOENETL confirms that commercial CO2 capture technology for large-scale combustion units (e.g., 

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.5A

To corroborate that commercial availability of CO2 capture technology for large-scale 

combustion (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 

 

4 Report of the Interagency Task Force on Carbon Capture and Storage at 50 (Aug. 2010). 

5

 DOE-NETL, Carbon Sequestration Program: Technical Program Plan, at 10 (Feb. 2011). 
site that its CO2 capture technology will become commercially available in 2015.6

 However, it 

should be noted that in committing to this timeframe, the company does not indicate whether 

such technology will be available for CO2 emissions generated from chemical plant sources, like 

those included in the Point Comfort expansion project. 

6.1.2.2 CO2 Compression and Transport 

Notwithstanding the fact that the above discussion demonstrates that the carbon capture 

component of CCS is not commercial available for chemical plant combustion and process 

vents, FPC TX provides the following discussion concerning technical feasibility. This 

discussion further supports that the compression and transport component of CCS may be 

technically feasible but, as explained later, the cost evaluation shows that it is not economically 

reasonable. Therefore, CCS is not BACT for the 2012 Expansion Project. 

Even if it is assumed that CO2 capture could feasibly be achieved for the proposed project, the 

high-volume CO2 stream generated would need to be compressed and transported to a facility 

capable of storing it. Potential geologic storage sites in Texas, Louisiana, and Mississippi to 

which CO2 could be transported if a pipeline was constructed are delineated on the map found 

at the end of this Appendix.7

 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 15 miles of the proposed 

project. However, none of the South and Southeast Texas 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 (SWP) on Carbon 

Sequestration’s Scurry Area Canyon Reef Operators (SACROC) test site, which is located in 

Scurry County, Texas approximately 370 miles away (see the map at the end of this Appendix 

for the test site location). Therefore, to access this potentially large-scale storage capacity site, 

 

6

 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 July.26, 2012). 

7

 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 July 26, 2012). 
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. 

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 estimated to be the lesser of the following: 

 The distance to the closest site with established capability for some geological storage of 

CO2, which is an enhanced oil recovery (EOR) reservoir site8

 located more than 600 

kilometers from the proposed project; or 

 The distance to a CO2 pipeline that Denbury Green Pipeline-Texas is currently 

constructing approximately 150 kilometers (straight line distance) from the project site for 

the purpose of providing CO2 to support various EOR operations in Southeast Texas 

beginning in late 2013. 

6.1.2.3 CO2 Sequestration 

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 pipeline or sequestration site as 

addressed in Step 4 of the BACT analysis. 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, 

 

8 None of the nearby South Texas EOR reservoirs or other geologic formation sites have been technically 

demonstrated for large-scale, long-term CO2 storage. 
 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,9

 and 

 Potential effects on wildlife. 

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 15 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 370 

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. 

6.1.3 STEP 3: RANK REMAINING CONTROL TECHNOLOGIES

As documented above, implementation of CCS technology for the FPC TX expansion emission 

sources is not currently commercially available or feasible for both technical and economic 

reasons. Even so, FPC TX will provide detailed economic and impacts analyses in Step 4 

which provides further documentation for eliminating this option as a control Technology to be 

evaluated for the GHG emission sources associated with the FPC TX expansion. 

6.1.4 STEP 4: EVALUATE MOST EFFECTIVE CONTROLS AND DOCUMENT RESULTS

6.1.4.1 Additional Environmental Impacts and Considerations 

There are a number of other environmental and operational issues related to the installation and 

operation of CCS that must also be considered in this evaluation. First, operation of CCS 

capture and compression equipment would require substantial additional electric power. For 

 

9

 Id.
example, 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% 

(based on the fuel higher heating value (HHV)) to approximately 42.7% (based on fuel HHV).10 

To provide the amount of reliable electricity needed to power a capture system, FPC TX would 

need to significantly expand the scope of the utility plant expansion proposed with this project to 

install one or more additional electric generating units, which are sources of conventional (nonGHG) and GHG air pollutants themselves. To put these additional power requirements in 

perspective, gas-fired electric generating units typically emit more than 100,000 tons CO2e/yr 

and would themselves, require a PSD permit for GHGs in addition to non-GHG pollutants. 

FPC TX would need to construct a pipeline that is estimated to be at least 100 miles in length to 

transport captured GHGs to the nearest potential purchaser (Denbury Green Pipeline). 

Constructing a pipeline of this magnitude would require procurement of right-of-ways which can 

be a lengthy and potentially difficult undertaking. Pipeline construction would also require 

extensive planning, environmental studies and possible mitigation of environmental impacts 

from pipeline construction. Therefore, the transportation of GHGs for this project would 

potentially result in negative impacts and disturbance to the environment in the pipeline right-ofway. 

Finally, implementation of CCS for the 2012 Expansion Project poses several operational and 

business concerns. First, the sale of CO2 material to either a pipeline entity or to a storage 

facility (EOR) would be made under contractual terms. FPC TX is in the primary business of 

selling commodity and specialty chemicals; the sale of CO2 would be a secondary product. The 

GHG sources that would be tied into a CCS system must be periodically taken out of service for 

maintenance or other reasons to ensure maximum yield of primary product from the production 

unit, thereby temporary eliminating or reducing the supply of CO2 to the buyer. FPC TX has 

identified contractual issues relating to the sale of CO2 that conflict directly with existing 

contracts relating to the sale of primary products. For this reason, FPC TX believes that the 

sale of CO2 from the Point Comfort expansion sources poses an unacceptable business conflict. 

 

10 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 
6.1.4.2 CCS Cost Evaluation 

Based on the reasons provided above, FPC TX believes that CCS technology should be 

eliminated from further consideration as a potential feasible control technology for purposes of 

this BACT analysis. Furthermore, the Congressional Budget Office’s June 2012 document 

entitled Federal Efforts to Reduce the Cost of Capturing and Storing Carbon Dioxide states that 

“average capital costs for a CCS-equipped plant would be 76 percent higher than those for a 

conventional plant.”11 Even so, to address possible questions that the public or the EPA may 

have concerning the relative costs of implementing hypothetical CCS systems, FPC TX has 

estimated such costs. 

For the cost evaluation, FPC TX considered all plants project (Olefins Expansion, LDPE plant 

and gas turbines) associated the expansion GHG emission sources for which CCS is 

considered technically feasible, for purposes of this analysis, even though separate permits are 

requested for each plant. These GHG emissions sources include the following emission units 

(respective plant names/permit applications shown in parenthesis): 

 9 cracking furnaces (Olefins Expansion) 

 4 PDH Reactors (Olefins Expansion) 

 4 steam boilers (Olefins Expansion) 

 PDH regeneration vent (Olefins Expansion ) 

 2 combined cycle gas-fired turbines (Gas Turbines) 

 2 regenerative thermal oxidizers (LDPE Plant) 

FPC TX’s cost estimation is conservatively low because it does not include additional costs for 

the following items that would be needed to implement CCS for the FPC TX 2012 Expansion 

Project: 

 additional gas conditioning and stream cleanup to meet specifications for final sale 

 thousands of feet of gas gathering system piping to collect vent gas from sources 

located in different operating units 

 costs of additional electric generating units required to power the capture and 

compression system (including design, procurement, permitting, installation, operating 

and maintenance costs) 

 

11 Federal Efforts to Reduce the Cost of Capturing and Storing Carbon Dioxide, Page 7 (June 2012). 
 cost of obtaining rights of way for construction of a pipeline 

These items would require significantly more effort to estimate and, since the conservatively low 

cost estimate demonstrates that this technology is not economically reasonable, it was not 

necessary to expend the extra time and resources to gather this additional data for the cost 

analysis. 

The CCS system cost estimate, excluding these additional capital expenditure items, is 

presented on Table 6-1 at the end of this Appendix. The total CCS system cost is estimated at 

over 300 million dollars, which is more than 15% of the total Point Comfort expansion project 

capital cost (total estimated capital cost is 2 billion dollars). Based on the Congressional Budget 

Office’s indications, this estimate of cost as a percentage of the total capital investment is 

conservatively low. Increasing the capital cost of the expansion project by this margin and 

increasing the ongoing operating and maintenance costs would render this project economically 

unviable. The margins of additional capital and operating costs are significantly greater if the 

aforementioned additional capital cost items, which were excluded, are taken into consideration. 

As discussed above, CCS was determined to be not commercially available and not technically 

feasible; therefore, a detailed examination of the energy, environmental, and economic impacts 

of CCS is not required for this application. However, at the request of EPA Region 6, FPC-TX 

included the estimated costs for implementation of CCS which are presented in Table 6-1. As 

discussed above these costs show that CCS is not commercially available, not technically 

feasible but also economically unreasonable. Therefore, it is not included as BACT for the FPC 

TX expansion. 

6.1.5 STEP 5: SELECT BACT 

As demonstrated in Steps 2 and 4 of the BACT review, CCS is not only not commercially 

available, not technically feasible but also economically unreasonable. Therefore, it is not 

included as BACT for the FPC TX expansion. 

6.1.5.1 CCS in Other GHG Permits 

FPC TX searched GHG permits issued by EPA Region 6 and other states. Only one permit 

included the use of CCS, the Indiana Gasification, LLC (IG) project, permit no. 147-30464-
00060 issued by the Indiana Department of Environmental Management (IDEM). The IG project 

proposes the construction of a coal gasification power plant that will produce liquefied carbon 

dioxide which will be compressed and piped several hundred miles to EOR facilities in the Gulf 

Coast region. 

This project differs significantly from the Point Comfort expansion in most technical aspects, but 

it should also be noted that IG has secured federal loan guarantees and potentially state tax 

credits to make the project, including application of CCS, economically viable. Furthermore, on 

page 154 of 181 of the PSD/TV Permit, Step 4 of the GHG BACT evaluation for the acid gas 

removal units (the primary GHG emission vents) state that: 

IG will not begin construction of this facility without a fully financed project agreement for 

the pipeline that provides for the pipeline to be in place and ready to receive liquefied 

CO2 at the point when pipeline quality CO2 is available. 

This statement provides evidence that the project, including application of CCS, hinges on the 

approval and contracts for a new CO2 pipeline. It is clear from the following quote from the 

Indiana permit application that installation of CCS was not justified for this project as BACT. 

The GHG BACT evaluation for the proposed IG plant concludes that “Based on the technically 

feasibility analysis in Step 2, there are no viable control technologies for the control of GHG 

emissions from the acid gas recovery unit vent.” This is consistent with the results of FPC TX’s 

BACT analysis of CCS for the Point Comfort Expansion project. 
Annual System CO2 Throughput 

(tons of CO2 captured, transported, 

and stored) 1

Pipeline Length for CO2 

Transport System

(km CO2 transported) 5

Minimum Cost $44.11 / ton of CO2 avoided 2 2,913,739 

Maximum Cost $103.42 / ton of CO2 avoided 3 2,913,739 Average Cost $73.76 / ton of CO2 avoided 4 2,913,739 Minimum Cost $0.91 / ton of CO2 transported per 100 km 3 2,913,739 150 

Maximum Cost $2.72 / ton of CO2 transported per 100 km 3 2,913,739 150 Average Cost $1.81 / ton of CO2 transported per 100 km 4 2,913,739 150 Minimum Cost $0.51 / ton of CO2 stored 3, 6 2,913,739 

Maximum Cost $18.14 / ton of CO2 stored 3, 6 2,913,739 

Average Cost $9.33 / ton of CO2 stored 4 2,913,739 Minimum Cost $45.98 / ton of CO2 removed 2,913,739 

Maximum Cost $125.65 / ton of CO2 removed 2,913,739 Average Cost $85.81 / ton of CO2 removed 4 2,913,739 

4 The average cost factors were calculated as the arithmetic mean of the minimum and maximum factors for each CCS component system and for all systems combined.

Post-Combustion CO2 Capture and Compression 

System 

Table 6-1

Range of Approximate Annual Costs for Installation and Operation of Capture, Transport, and Storag

for Control of CO2 Emissions from the Point Comfort Expansion

Total Cost for CO2 Capture, Transport, and Storage 

Systems 

6 "Cost estimates [for geologic storage of CO2] are limited to capital and operational costs, and do not include potential costs associated with long-term liability." (from the Report of the In

Storage , p. 44)

5 The length of the pipeline was assumed to be the distance to the closest potential geologic storage site, as identified by the University of Texas at Austin, Bureau of Economic Geology, G

http://www.beg.utexas.edu/gccc/graphics/Basemap_state_lands_fp_lg.jpg (last visited Feb. 27, 2012).

3 These cost factors are from Report of the Interagency Task Force on Carbon Capture and Storage , pp.33, 34, 37, and 44 (Aug. 2010) (http://www.epa.gov/climatechange/policy/ccs_tas

the form of $/tonne of CO2 avoided, transported, or stored and have been converted to $/ton. Per the report, the factors are based on the increased cost of electricity (COE; in $/kW-h) of 

costs over its lifetime: initial investment, operations and maintenance, cost of fuel, and cost of capital".

Carbon Capture and Storage (CCS) Component 

System

Factors for Approximate Costs 

for CCS Systems

CO2 Transport System 

1 Assumes the maximum possible annual CO2 emissions scenario and assumes that a capture system would be able to capture 90% of the total CO2 emissions generated by the combus

CO2 Storage System 

2 This cost factor is the minimum found for implementation/operation of CO2 capture systems within the cost-related information reviewed for CCS technology. The factor is from the on th

Gas Mitigation Strategies Database (Apr. 2010) (http://ghg.ie.unc.edu:8080/GHGMDB/#data), which was obtained through the EPA GHG web site (http://www.epa.gov/nsr/ghgpermitting.hcost of electricity (COE; in $/MW-h) resulting from implementation and operation at a CO2 capture system on a natural gas-fired combined cycle power plant. The factor accounts for annu

variable operating costs, and fuel costs.

APPENDIX D 

KELLY HART & HALLMAN MEMO 

RE: EPA POLCY ON MULTIPLE PSD PERMITS
1371846-2 

KELLY HART &

HALLMAN

A PROFESSIONAL CORPORATION

MEMORANDUM 

To: Brian Tomasovic 

From: Bob Stewart and Steve Dickman 

Date: July 13, 2012 

Re: EPA Policy on Obtaining Multiple PSD Permits for a Single Source 

I. Purpose of Memo and Short Answer 

 Factual Summary: Formosa Plastics Corp. (“FPC”) intends to apply for federal Clean Air 

Act prevention of significant deterioration (“PSD”) greenhouse gas permitting authorization 

from EPA for its olefins expansion project. This single project consists of three new related 

major greenhouse gas emission sources at its Point Comfort facility which should be authorized 

under three separate PSD permits, rather than under a single PSD permit. The first PSD permit 

will cover greenhouse gas emissions from the proposed new olefins 3 cracker and an associated 

propane dehydrogenation (PDH) unit; the second PSD permit will cover greenhouse gas 

emissions from a proposed new low density polyethylene (LDPE) resin plant; and the third PSD 

permit will cover greenhouse gas emissions from a new power utilities facility serving the other 

new units. Applying for three new PSD permits is desired by FPC for administrative and 

compliance reasons including organizational responsibility and accountability within FPC. In 

support of this approach, TCEQ has historically permitted FPC’s various production facilities 

under separate PSD permits for criteria pollutants. FPC will subject all new units in the 

aggregate to normal PSD permitting requirements including application of BACT and fenceline 

air quality impacts analysis. 

 Issue: This proposal raises the question of whether it is permissible under EPA rules or 

policy guidance for FPC to obtain permitting of the new units under multiple PSD permits within 

a single PSD action rather than under a single PSD permit. 

 Short Answer: EPA has consistently stated that authorizing separate units at a major 

source facility under separate PSD permits is acceptable so long as doing so does not circumvent 

the full spectrum of PSD permitting requirements that would apply if the units were jointly 

permitted under a single permit. 

II. Background Controversy Regarding the Aggregation Issue 

 

 The issue of use of multiple PSD permits most commonly arises in the context of the 

PSD Aggregation issue which is the question of whether multiple physical or operational 
1371846-2 2

changes must be grouped together, or “aggregated”, as a single physical or operational change 

for purposes of determining applicability of PSD review. Typically, the Aggregation issue 

arises when a facility attempts to expedite a construction project by applying for several minor 

source permits for facility changes in order to evade or circumvent the more detailed PSD review 

that would occur if the changes were considered as a single “major source” PSD project or major 

modification. The Aggregation issue is important because of consequences in terms of higher 

costs and level of regulatory review associated with undergoing full PSD review. 

 EPA typically considers this issue on a case-by-case basis under three regulatory factors 

set forth in EPA rules along with a set other relevant factors identified in various EPA letters and 

memoranda. EPA rules as set forth in the definitions of “stationary source” and “building, 

structure, facility or installation” in 40 CFR Part 52 provide that two or more nominally-separate 

facility changes should be considered a single PSD project if they meet all of the following three 

criteria: 

1. They belong to the same SIC major (2-digit) group. If two different project facilities 

could have separate SIC codes but a support relationship exists (e.g., 50% or more of the 

product of one facility is utilized by the other facility) then one facility is considered a 

support facility and this criterion is deemed to have been met. 

2. They are located on one or more contiguous or adjacent properties in the same general 

area. 

3. They are under common ownership or control. (If this is in dispute, then EPA will 

review any contractual agreements between the facilities to determine if they are under 

common control.) 

 Other various factors used by EPA in conjunction with the above test include: 

• the closeness in time to the filing of applications for nominally-separate facility changes; 

• whether the nominally-separate changes were considered together in the permittee’s 

integrated facility planning documents or in financing proposals or in public statements; 

• whether the nominally-separate facility changes are operationally dependent on each 

other; 

• whether the nominally-separate facility changes are substantially related to each other in 

some other way; 

• whether it is feasible for the permittee to operate a proposed facility change as a minor 

source without the other facility changes. 

 

 The purpose of EPA’s Aggregation Policy is to prevent circumvention of PSD review. If 

multiple facility changes must undergo PSD review as a single PSD project then all relevant 

facility changes are considered together and are typically authorized under a single PSD permit. 

However, EPA has recognized that if the Aggregation Policy is so applied, all facilities need not 

necessarily be authorized under a single PSD permit. 

III. Obtaining Separate PSD Permits for Separate Projects 
1371846-2 3

A. The Nucor Case. The most recent expression of EPA policy on the subject of the 

Aggregation Policy and the use of multiple permits is an EPA Title V permit protest order signed 

by Lisa Jackson on March 23, 2012 in the case of Nucor Steel of Louisiana. In that case (copy 

attached), EPA granted three petitions for review of three Title V permits proposed to be issued 

to Nucor on the grounds that the Title V permits did not properly incorporate NSR permitting 

requirements as established in the Louisiana SIP. Specifically, the Louisiana Department of 

Environmental Quality (“LDEQ”) had issued separate PSD permits and separate Title V permits 

to Nucor’s pig iron process and its direct reduced iron (“DRI”) manufacturing process both of 

which processes were located at a single site (in a NSR attainment area). 

 In its objections to Nucor’s Title V permits, Zen-Noh Grain Corporation noted that even 

though both the pig iron process and the DRI process units would each be subject to BACT, 

LDEQ’s proposal to allow separate PSD permitting of the two processes would circumvent the 

air quality impact analysis prerequisites for the entire Nucor facility. For example, for SO2 and 

PM10/PM2.5 Nucor modeled only emissions from the DRI process and determined them to be 

below the significant impact level (“SIL”) PSD threshold, but Zen-Noh’s modeling showed that 

if aggregate emissions were modeled a full National Ambient Air Quality Standards (“NAAQS”) 

analysis would have been required for SO2 and PM10 and PM2.5, and that the combined Nucor 

facility would cause a violation of NAAQS for these pollutants. 

 Pages 8 through 14 of the EPA Order discusses EPA’s rationale for determining that 

emissions from both processes at Nucor should be aggregated. For the most part, EPA’s 

rationale was that LDEQ had not sufficiently demonstrated why the two facilities should be 

considered separate sources. However, EPA made clear that even though Nucor was not 

attempting to avoid PSD review for either process since each process was individually a major 

source, “Nucor’s ambient air quality impacts analysis did not consider whether the combined 

emissions from both the pig iron and DRI processes for all pollutants call for a more thorough 

cumulative analysis of the air quality impact of these sources.” Thus, EPA did not object to the 

authorization of separate projects under separate PSD and Title V permits, it only objected to 

Nucor’s failure to demonstrate that the combined air impacts of the combined projects met PSD 

requirements as would have been demonstrated if the two processes were considered in the 

aggregate. 

B. Other EPA Policy Statements. In other cases, the EPA has indicated that having 

multiple PSD permits for a single PSD project is acceptable so long as doing so does not result in 

circumvention of PSD requirements that would otherwise apply. 

 In an EPA objection to Colorado’s proposed Title V permit to TriGen-Colorado Energy 

Corporation which operates a power plant located at, and exclusively serving, the Coors 

Brewery, EPA required that the permittee’s air emissions be aggregated with those of the Coors 

Brewery for PSD and Title V permitting purposes even though TriGen and Coors had separate 

PSD and Title V permits. EPA stated that “future modifications of the two facilities that make 

up a single source must be addressed together to calculate net emissions increases for 

comparison with NSR and PSD significance levels.” 

 In a 2001 case concerning PSD applicability, EPA issued a determination that two 

adjacent and commonly-owned power generating facilities could be permitted separately as 
1371846-2 4

minor sources because regardless of whether the facilities each obtained a minor NSR permit, the 

permits would require BACT so that the facilities were not circumventing NSR emission control 

requirements by obtaining minor source permits. See, Oct. 12, 2001 letter “PSD Applicability 

for Frederickson Power, L.P.” from Doug Cole, Acting Manager Federal & Delegated Air 

Programs Unit, EPA Region 10 to Grant Cooper and Raymond McKay. 

 In several cases where EPA has determined that co-located facilities should be 

aggregated, it has also specified that the facilities need not share a common Title V operating 

permit. For example, in a November 27, 1996 letter to Jennifer Schlosstein at Simpson Paper 

Company from Matt Haber of EPA Region 9, EPA stated “There is no need for Simpson and 

SMI to certify or assure compliance over each other in a Title V permit. EPA recommends that 

even though they are considered one source, each facility apply for a separate Title V permit, 

each with its own responsible official, under the Title V application process.” 

 On August 2, 1996, EPA’s Office of Air Quality Planning and Standards issued a policy 

memo concerning “Major Source Determinations for Military Installations” in which EPA 

stated: 

“After determining that stationary sources at a military installation are subject to Title V 

permitting, permitting authorities have discretion to issue more than one Title V permit to 

each major source at that installation, so long as the collection of permits assures that all 

applicable requirements would be met that otherwise would be required under a single 

permit for each major source.” 

 EPA explained its rationale for allowing multiple Title V permits for different projects 

within a single facility in its November 15, 2002 order denying a petition for objection to the 

Title V permit for Shaw Industries in Georgia. According to the Georgia Environmental 

Protection Division, for administrative reasons Shaw requested that three separate Title V 

permits be issued for three different but co-located plants at the Shaw carpet manufacturing 

facility in Dalton, Georgia. EPA stated in its order: 

“Although multiple facilities meeting the definition of ‘same source’ must be evaluated 

as one source with respect to applicability, nothing in the CAA or Part 70 prohibits 

permitting authorities from issuing multiple Title V permits to one Part 70 source..... 

Thus under the CAA and EPA’s regulations, a Part 70 source is free to request that it be 

issued more than one Part 70 permit, and permitting authorities are not prohibited from 

issuing multiple permits to facilities that together constitute a single source. However, 

permitting authorities that issue multiple permits should do so in a way that makes each 

facility’s compliance obligations clear. Each permit narrative or statement of basis 

should refer to the other permits and explain the relationships between the facilities for 

purposes of applicability determinations. For instance, each permit narrative should 

indicate whether any changes at one facility may require offsetting measures at another 

facility.” 

 Although the above EPA policy statements in the three immediately preceding cases 

specifically concern Title V permits, there is no reason why the same rationale should not apply 
1371846-2 5

to NSR and PSD permits, especially since EPA has specifically so ruled in the Nucor, TriGen 

and Frederickson cases discussed above. 

IV. Conclusion 

 Based on the above-cited policy rulings, EPA has clearly accepted the practice of issuing 

PSD permits for multiple units located at a single major source facility. Separate PSD permits 

may be issued for separate units within a single PSD project so long as the issuance of separate 

permits does not allow the units in the aggregate to circumvent any regulatory requirements that 

would apply if the units were permitted in one permit as a single source . 

 In the case of FPC, although EPA’s Aggregation Policy would clearly apply so as to 

require FPC to aggregate the emissions from its proposed new facility units, all of those 

emissions will undergo the full spectrum of PSD review in the aggregate. So long as FPC 

applies BACT to the new units and performs the required PSD air impacts analysis on an 

aggregated basis for all of the new units, the use of three separate PSD permits for a single PSD 

project is acceptable under past EPA practice. In addition, FPC will address any future 

modifications by evaluating the upstream and downstream effects of the modification on any one 

or more of the three PSD permits (and other permits) in order to determine the PSD significance 

thresholds for the modification permitting action. Consequently, the PSD analysis for future 

modifications would not in any way be circumvented by the fact that three PSD permits are in 

effect, but rather FPC will evaluate all increases in actual emissions resulting from the 

modification. Finally, as indicated in the Shaw Industries case, the reasons for utilizing multiple 

permits may simply be for purposes of administrative convenience of the permittee. In this case, 

FPC is requesting three separate PSD permits, each of which would be covered under individual 

Title V permits, in order to comply with future CAA certification requirements and maintain 

accountability. FPC uses a system designed to assure, through each unit’s “chain of command,” 

that the statements and information submitted are true, accurate and complete. Accordingly, 

EPA should have no legal or practical reasons for objecting to authorization of FPC’s new single 

project for three new units under three separate PSD greenhouse gas permits.