## PREVENTION OF SIGNIFICANT DETERIORATION P E RMIT FOR GREENHOUS E GAS EMISSIONS ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR § 52.21

U.S. ENVIRONMENTAL PROTECTION AGENCY
, REGION 6

PSD P E RMIT NUMBER: PSD-TX-760

- GHG

PERMITT EE : Formos a Plastic s Corporation, Texas

F ACILITY NAME: Chemica l Complex Expansion: Two New Combine d- Cycle Gas-Fired Turbines

FACILITY LOCATION: 201 Formosa Drive Po i n t 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 R egulations (CF R) Title 40
, Section 52.21, and the Federal I mplementation Plan at 40 CFR 

### § 52.2305 (effective May 1, 2011 and published at 76 F R 25 178), the U.S

. Environmental P rotection Agency, Region 6 is issuing a Prevention of

· Significant Det erioration ( P SD) permit to the Formosa Plastics Corporati on, Texas (F01 mo sa) for Gree nh o u se Gas (GHG) e mi ssions

. The Permit applies to the expan sion of th e existing utility plant at the Point Comfort, Texas chemical comp l ex by adding two natural gas-fired combinedcycle turbines to the exis t ing 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 applicatio n (and pla n s submitted with the permit appl ic ation), the federal PSD regulations at 40 CFR 

### § 52.21, and other terms and conditions set forth in this PSD permit in conjunction with the co rr espo nding Texas Comm i ssion on Env ironmental Quality (TCEQ) PSD p ermit No. PSD- TX-760M9. Failur e to comply with any cond i t i o n or t erm set forth in this PSD P ermit may result in enforcement act ion pursua n t to Section 113 of the Clean Air Act (CAA). This PSD P ermi t does not reli eve Formo sa ofthe responsibility to comply with a ny other applicable prov i sions of the CAA (including applicable implementing regulations in 40 CFR Part s 51
, 52
, 60, 61, 72 through 75, and 98) or othe r federal and state requir ements (includi ng the state P S D program t h at r emains und er app r oval at 40 CFR 

### § 52.2303).

In accordance with 40 CFR 

### § 124.15(b )(3)
, this PSD Permit become s effective immediately upon i ss uance of this final d

Wren Stenger, Dir c o r Multimedia Planning and P ermitting D ivision

### 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

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

c ombined-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 equi pment insulated with sulfur hexafluoride (SF 6 

### ); 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 gener a tors (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.

SF 6 - FUG SF 6 - FUG SF 6 Insulated Electrical Equipment (i.e., circuit breakers) with 248 lb SF 6 capacity per circuit breaker.

NG

- FUG NG

- FUG Natural Gas F ugitives.

### 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

ma y be provided with the submittal of the performance test protocol required pursuant to C ondition 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

use d 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 a ir 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 de scription 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 fa ilure, 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

c opy 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 -7 60M9 (when issued) and all other

a pplicable 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 CH 4 Methane CHP Combined Heat and Power CO 2 Carbon Dioxide CO 2 e Carbon Dioxide Equivalent CT Combustion Turbine DCS Distributed Control System DLNB Dry Low- NO x Burner dscf Dry Standard Cubic Foot EF Emission Factor EPN Emission Point Number FIN Facility Identification Number FR Federal Register 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 N 2 O Nitrous Oxides NO x 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 SF 6 Sulfur Hexafluoride TAC Texas Administrative Code TCEQ Texas Commission on Environmental Quality TPY Tons per Year USC United States Code VOC Volatile Organic Compound

### 7

II. Annual Emission Limits Annual emissions, in tons per year (TPY) on a 12-month, rolling total, shall not exceed the following :
Table 1 Annual Emission Limits 1



### – General Electric 7EA

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

7K 7K Combined

- cycle Combustion Turbine/Heat Recovery Steam Generator with Duct Burner CO 2 571, 875

572, 466 11,650 Btu/kWh (gross) on a 365

- day rolling average

. See Special Condition III. B .1 and III.B.2. CH 4 10 .8

N 2 O 1 .1

7L 7L Combined

- cycle Combustion Turbine/Heat Recovery Steam Generator with Duct Burner CO 2 571, 875

572, 466 11,650 Btu/kWh (gross) on a 365

- day rolling average

. See Special Condition III. B .1 and III.B.2. CH 4 10.8

N 2 O 1.1

NG

- FUG NG

- FUG Natural Gas and OL Tail Gas Fugitives CO 2 No Numerical Limit Established 4 No

Numerical Limit Established 4 Implementation of an AVO

program. See Special Condition III. C

. 1. and III.C.4. CH 4 No Numerical

Limit Established 4

SF6

- FUG SF6

- FUG SF 6 Insulated Equipment SF 6 No Numerical Limit Established 5 No

Numerical Limit Established 5 Good Combustion and Operating

Practices. Limit to 50 hours of operation per year. See Special Condition III. C

. 2. through III.C.4. 7K

NGVENT 7L

NGVENT 7K

NGVENT 7L

NGVENT Turbine Startup

Natural Gas Purges CO 2 0.41 30 Limit turbine s to 15 start ups per year. See Special Condition III. D

. CH 4 1.20

Totals 6 CO 2 1, 143 , 751
CO 2 e 1, 145, 489 CH 4 41. 6
N 2 O 2 .2 

### SF 6 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): CH 4 = 25 , N 2 O = 298, SF 6 = 22,800 4. Fugitive pr ocess emissions from EPN NG-FUG are estimated to be 0.69 TPY CO 2 , 20 TPY of CH 4 and 500 TPY CO 2 e. In lieu of an emission limit, the emissions will be limited by implementing a weekly AVO monitoring program. 5. SF 6 fugitive emissions from EPN SF6-FUG are estimated to be 0.0012 TPY of SF 6 and 27 TPY of CO 2 e. In lieu of an emission limit, the emissions will be limited by using state of the art enclosed-pressure SF 6 circuit breakers with leak detection. 6. To tal emissions include the PTE for fugitive emissions (including SF 6 ). Totals are given for informational purposes only and do not constitute emission limits.

### 8

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. F uel 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 de termined 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 n atural 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

sa mple to be taken by EPA for analysis. 5. Permittee shall monitor fuel gas flow continuously; determine fuel higher heating value whene v er 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

a ccordance 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, Appe ndix 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 18 0 calendar days after the date the affected combustion unit commences

c ommercial 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);

### 9 c. CT /HRSG plant efficiency; d. Gas turbine electrical output, MW; and

e. Ma ss of steam produced. 14. Permittee shall determine the hourly CO 2 

### emission rate in accordance with 40 CFR § 98.33(a)(1)(i) and 98.33(a)(3)(iii). 15. Permittee shall calculate the CH 4 

### and N 2 

### O emissions on a 12-month rolling basis to be updated by the last day of the following month. Permittee shall determine compliance with the CH 4 

### and N 2 

### O emissions limits contained in this section using the default CH 4 

### and N 2 

### O 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. Perm ittee shall calculate the CO 2 

### e 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, 20 13 (7 8 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, 65 0 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

e nergy 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 = ( HI GT + HI HRSG P GT +P HRSG 

## ) x 1, 000 ,000

Where:

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

### = Heat input of fuel to the gas turbine (MMBtu/day) HI HRSG 

### = Heat input of fuels to the HRSG (MMBtu/day) P GT 

### = Gross Electrical Power produced from the gas turbine (kWh/day) P HRSG 

### = Gross energy (electrical equivalent) produced from the HRSG (kWh/day), calculated using Equation 11-2 below. 1,000,000 = Btu/MMBtu conversion

### 10



## P HRSG 

## = m steam



## ̇ x 14

. 11

Where:

m steam 

### ̇ = 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 CO 2 

### and use emission factors from 40 CFR Part 98 , Subpart C, Table C-1. If the combustion turbine/HRSG does not meet the

e missions limit, the Permittee may continue operation of the combustion turbine/HRSG in order to perform necessary corrective actions and to continue plant
ope rations. 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 maintenan ce.

C. Requirements for Fugitive Emission Sources ( NG

- FUG and SF6-FUG)

1. The Permittee shall implement an audio, visual, and olfactory (AVO) method for de tecting 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, SF 6 

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

e xceed insulated circuit breaker SF6 capacity exceeding 248 lbs. 3. Permittee shall equip the circuit breakers with instrumentation to identify and/or prevent leaks. The SF 6 

### leak detection system shall be able to detect a leak of at least 1 lb per year. 4. Permittee shall maintain a file of all records, data measurements, reports and documents related to the fugitive emission sources including, but not limited to, the following: all records or reports pertaining to maintenance performed, all records relating to compliance with the Monitoring and Quality Assurance and Quality Control (QA/QC) procedures outlined in 40 CFR 98.304.

### 11

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

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

E. Contin uous Emissions Monitoring Systems (CEMS)

1. As an alternative to Special Conditions III.A.14. Permittee may install a CO 2 

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

### emissions discharged to the atmosphere, and use these values to show compliance with the annual emission limit in Ta ble 1. 2. Permittee shall ensure that all required CO 2 

### 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 CO 2 

### 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 P ermittee 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 CO 2 

### CEMS data.

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

a s 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 CO 2 

### 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 e xcess emissions to EPA semi-annually, except when: more frequent reporting is specifically required by an applicable subpart; or the Administrator or authorized representative, on a case- by

case basis

, 

### determines that more frequent reporting is necessary to accurately assess the compliance status of the source. The report is due on the 30 th 

### 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

max imum 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 C ombustion Turbines and HRSGs (7K and 7L ) to determine the initial compliance with the CO 2 

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


### .

1. Multiply the CO 2 

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

### 13

2. If the above calculated CO 2 

### 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 CO 2 

### 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 CO 2 

### 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 a tmospheric 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

c ompliance 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

a nalyzed while at the minimum load include (but are not limited to) CO 2


### . 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

P ermittee 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

# G REENHOUSE 

# G AS 

# P ERMIT 

# A PPLICATION 

# P REVENTION OF 

# S IGNIFICANT 

# D ETERIORATION 

# : 2012 E XPANSION 

# P ROJECT 

# G AS 

# T URBINES 

# P OINT 

# C OMFORT 

# , T EXAS

S UBMITTED TO : 

### E NVIRONMENTAL 

### P ROTECTION 

### A GENCY 

### R EGION 

### VI M ULTIMEDIA 

### P LANNING AND 

### P ERMITTING 

### D IVISION 

### F OUNTAIN 

### P LACE 

### 12 TH 

### F LOOR 

### , S UITE 

### 1200 1445 R OSS 

### A VENUE 

### D ALLAS 

### , T EXAS 

### 75202-2733

S UBMITTED BY :



### F ORMOSA 

### P LASTICS 

### C ORPORATION 

### , T EXAS 

### P.O. B OX 

### 700 P OINT 

### C OMFORT 

### , T EXAS 

### 77978

P REPARED BY : 

### Z EPHYR 

### E NVIRONMENTAL 

### C ORPORATION 

### 2600 V IA 

### F ORTUNA 

### , S UITE 

### 450 A USTIN 

### , T EXAS 

### 78746

N OVEMBER 

### 2012F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 (SF 6 ) 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 SF 6 ............................ 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 SF 6 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 39F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 PermitsF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

1 

## 1.0 I NTRODUCTION

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 (CO 2 e) basis at existing major sources are subject to GHG PS D 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 Comm ission 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).F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

3 

## 2.0 G ENERAL 

## A PPLICATION 

## I NFORMATION

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, pr ovide 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 submitte d 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 Repr esentative 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 indica ting 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 applicati on being submitted in conjunctio n with this amendment in accordance with 30 TAC 116.315(c). YES NOTCEQ – 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 st reet 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, provi de 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 cons idered a major source of criteria pollutants or HAPs? YES NO

F. Consolidation into this Permit: List any standard permits, exempti ons 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 th is application as specified in VII and VIII. YES NO

H. Federal Operating Permit Requirement s (30 TAC Chapter 122 Applicability) Is this facility located at a site require d 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 NoneTCEQ – 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 Requirement s (30 TAC Chapter 122 Applicability) (continued) 2. Identify the type(s) of FOP(s) issued and/or FOP app lication(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 modifica tion 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 modifica tion 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 contam inant 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 summaryTCEQ – 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 b ilingual 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 s ource for federal air quality permitting? YES NO
C. Are the site emissions of any regulated air po llutant greater than or equal to 50 tpy? YES NO
D. Are the site emissions of all regulated ai r 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 tablesTCEQ – 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 activ ity 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 app licable state regulations to obtain a permit or amendment . The application must contain detailed attach ments addressing applicability or non applicability; identify state regulations; show how requirements are met; and include comp liance 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 perform ance 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 app licable federal regulations to obtain a permit or amendment The application must contain detailed attachme nts addressing applicability or non applicability; identify federal regulation subparts; show how requiremen ts 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 NOTCEQ – 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 app licable federal regulations to obtain a permit or amendment The application must contain detailed attachme nts addressing applicability or non applicability; identify federal regulation subparts; show how requiremen ts are met; and include compliance demonstrations.
D. Do nonattainment permitting requirements apply to this application? YES NO
E. Do prevention of significant deterioration perm itting 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 a ttached 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/AF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

16 

## 3.0 P ROCESS 

## D ESCRIPTION AND 

## GHG E MISSION 

## S OURCES



### 3.1 P ROCESS 

### D ESCRIPTION
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 (SF 6 )

 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 E MISSION 

### S OURCES



### 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. EachF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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).F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 (CH 4 ) and carbon dioxide (CO 2 ). Emissions from the natural gas and OL tail gas piping are designated as EPN: NG-FUG.



### 3.2.4 Electrical Equipment Insulate d with Sulfur Hexafluoride (SF 6 

### )
The two circuit breakers associated with the proposed combustion turbine units will be insulated
with SF 6 . SF 6 is a colorless, odorless, non-flammable, and non-toxic synthetic gas. It is a fluorinated compound that has an extremely stable molecular structure. The unique chemical properties of SF 6 make it an efficient electrical insulator. The gas is used for electrical insulation, arc quenching, and current interruption in high-voltage electrical equipment. SF 6 is only used in sealed 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 SF 6 (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” SF 6 gas. Emissions from the SF 6 -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 CO 2 from natural gas (EPNs: 7K-NGVENT, 7L-NGVENT).Utilities Plant – Two New Combined-Cycle GasTurbine UnitsProcess Flow DiagramNatural GasHydrogen2 Frame 7EAGas TurbinesExhaust Gases2 Heat RecoverySteam GeneratorsSteam3 Existing SteamTurbines3 Existing PowerGeneratorsPlant SteamEPNs: 7K, 7LAirFeed WaterNatural GasOL Tail GasScope of UtilitiesPlant ChangesEPN: NG-FUGEPN: SF6-FUGElectric Power toPlant UsersEPNs:7K-NGVENT,7L-NGVENTExisting SteamGenerators150, 300, and600 psig SteamExisting Steam HeaderF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

20 

## 4.0 GHG E MISSION 

## C ALCULATIONS

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 calculat ion methodologies by source type. A summary of GHG emissions, detailed emission calculations and supporting information can be found in Appendix A.



### 4.1 GHG E MISSIONS 

### F ROM 

### N ATURAL 

### G AS 

### C OMBUSTION 

### S OURCES
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



### ࡻ࡯ ૛ 

### ૙૚	࢞	૚ ൌ ૜ି 

### ࡲࡱ	ࢄ	ࢂࡴࡴ	࢞	࢒ࢋ࢛ࡲ	࢞ (-1C .EQ (

Where:

CO 2 = Annual CO 2 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 CH 4 and nitrous oxide (N 2 O) 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 SourcesF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

21 The global warming potential factors used to calculate carbon dioxide equivalent (CO 2 e) emissions are based on Table A-1 of Mandatory Greenhouse Gas Reporting Rules.



### 4.2 GHG E MISSIONS 

### F ROM 

### OL T AIL 

### G AS 

### C OMBUSTION 

### S OURCES

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



### ࡻ࡯ ૛ 

### ൌ ૝૝
૚૛ 

### ࢄ	࡯࡯	࢞	࢒ࢋ࢛ࡲ ൈ ࢃࡹ ࡯ࢂࡹ 

### ൈ ૙. ૙૙૚ (EQ. C-5)

Where:

CO 2 = Annual CO 2 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 CH 4 and nitrous oxide (N 2 O) are calculated using the emission factors (kg/MMBtu) for natural gas combustion from Table C-2 of the Mandatory Greenhouse Gas Reporting Rules 6 and

4 Default CH 4 and N 2 O 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 CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 CFR 98, Subpart C, Table C-2F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

22 annual heat release for fuel gas combustion. The global warming potential factors used to calculate carbon dioxide equivalent (CO 2 e) emissions are based on Table A-1 of Mandatory Greenhouse Gas Reporting Rules.



### 4.3 GHG E MISSIONS 

### F ROM 

### E LECTRICAL 

### E QUIPMENT 

### I NSULATED WITH 

### SF 6

Even though SF 6 emissions from the circuit breakers associated with the proposed units are not expected, potential emissions were calculated using a conservative SF 6 annual leak rate of 0.5% by weight (of total charge) and the SF 6 capacity for both breakers. The global warming potential factors used to calculate CO 2 e emissions are based on Table A-1 of the Mandatory Greenhouse Gas Reporting Rules. 7



### 4.4 GHG E MISSIONS 

### F ROM 

### N ATURAL 

### G AS 

### /O L 

### T AIL 

### G AS 

### P IPING 

### F UGITIVES AND 

### F UEL 

### L INE 

### M AINTENANCE AND 

### T URBINE 

### S TARTUP 

### R ELEASES

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 CH 4 and CO 2 in the natural gas are based on a typical natural gas analysis. Since the CH 4 and CO 2 content of OL tail gas is variable, the concentrations of
CH 4 and CO 2 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 CO 2 e 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 CH 4 and CO 2 concentrations as natural gas

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

8 Default Whole Gas Emission Factors for On shore 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

23 and OL tail gas piping fugitives and the volume and initial temperature and pressure of gas prior to venting.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

24 

## 5.0 P REVENTION OF 

## S IGNIFICANT 

## D ETERIORATION 

## A PPLICABILITY

Since the Point Comfort expansion project 10 emissions increase of GHG is greater than 75,000 ton/yr. of CO 2 e, 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 f uel 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

25 

## 6.0 B EST 

## A VAILABLE 

## C ONTROL 

## T ECHNOLOGY 

## (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 ex ceed 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 implement ation 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).F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

26 the satisfaction of the permitting authority that technical considerations, or energy, environmental, or economic impacts justify a conclu sion that the top ranked technology is not
“achievable” in that case. If the most effective c ontrol strategy is eliminated in this fashion, then
the next most effective alternative should be eval uated, 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. O ne 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 

### C ARBON 

### C APTURE AND 

### S EQUESTRATION

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)F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

27 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 

### C OMBINED 

### C YCLE 

### C OMBUSTION 

### T URBINES



### 6.2.1 Step 1: Identify A ll 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 Efficien cy Processes, Practices, and Designs
Combustion Turbine Design
CO 2 is a product of combustion of fuel contai ning carbon, which is inherent in any power generation technology using fossil fuel. It is not possible to reduce the amount of CO 2 generated from combustion, as CO 2 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 CO 2 generation by adjusting the conditions in which combustion takes place.

The only effective means to reduce the amount of CO 2 generated by a fuel-burning power plant is to generate as much electric power as possi ble 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

28 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

29 Instrumentation and Controls The GE Model 7EA combustion turbines have sophisticated instrumentation and controls to automatically control the operation of the combus tion 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 per formance for full-load and part-load conditions.



### Heat Recovery Steam Generat or 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 thecombustion turbine exhaust gases. This is performed at multiple pressure levels. For a drumtype configuration, each pressure level incor porates 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 includeF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

30 extended surfaces (e.g., fins). The extended surface optimizes the heat transfer, while minimizing the overall size of the HRSG. Additiona lly, flow guides are used to distribute the flowevenly 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 areF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

31 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 te chnology is currently infeasible, leaving energy efficiency measures as the only technically feasible emission control options. As all of the energy efficiency related processes, practi ces, 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 Eff ective 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 e fficiency designs is not necessary for this application.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

32 

### 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 m eans 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 isF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

33 equivalent to an output based GHG BACT limit of 0.568 ton CO 2 e/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
MWh 13 , 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 co nsequence, the facility calculates an “Installed

13 This steam turbine conversion rate is based on historic al annual average performance data for the existing steam turbines at the Point Comfort Utility plant. This is not in tended 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

34 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 Perm it 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

35 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 calcul ates 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 CO 2 e/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 

### SF 6 

### I NSULATED 

### E LECTRICAL 

### E QUIPMENT



### 6.3.1 Step 1: Identify A ll 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 SF 6 technology with leak detection to limit fugitive emissions. In comparison to older SF 6 circuit breakers, modern breakers are designed as a totally enclosed-pressure system with far lower potential for SF 6 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 SF 6 has escaped. The use of an alarm identifiesF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

36 potential leak problems before the bulk of the SF 6 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 SF 6 as the dielectric material in the breakers. Potential alternatives to SF 6 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
SF 6. 14



### 6.3.2 Step 2: Eliminate T echnically Infeasible Options

According to the report NTIS Technical Note 1425, SF 6 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 y ears of use and investigation. It is clearly superior in performance to the air and oil insulated equipment used prior to the development of
SF 6 -insulated equipment. The report concluded that although “...various gas mixtures show considerable promise for use in new equipmen t, particularly if the equipment is designed specifically for use with a gas mixture... it is cl ear 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 SF 6 .



### 6.3.3 Step 3: Rank Remaining Control Technologies

The use of state-of-the-art SF 6 technology with leak detection to limit fugitive emissions is the highest ranked control technology that is 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 SF 6, NIST Technical Note 1425, Nov.1997.

15 Id. at 28 – 29.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

37 

### 6.3.4 Step 4: Evaluate Most Eff ective 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 SF 6 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 SF 6 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 SF 6 emissions problems to light before a substantial portion of the SF 6 escapes. The lockout prevents any operation of the breaker due to lack of “quenching and cooling” SF 6 gas.



### 6.4 BACT FOR 

### N ATURAL 

### G AS AND 

### OL T AIL 

### G AS 

### P IPING 

### F UGITIVES



### 6.4.1 Step 1: Identify A ll 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 re mote sensing technology such as infrared camera monitoring.

16 ANSI Standard C37.013, Standard for AC High-Voltage Generator Circuit Breakers on a Symmetrical Current

.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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



### 6.4.2 Step 2: Eliminate T echnically Infeasible Options

All the available options are considered techni cally 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 impl emented 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 wi th less additional manpower and equipment thanF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 detecti on 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 equa lly 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 Eff ective Controls and Document Results

The AVO monitoring option is expected to be effect ive 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 emissionF ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 Regi on 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 

### N ATURAL 

### G AS 

### V ENTING



### 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 thisactivity, 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

42 

### 6.5.2 Step 2: Eliminate T echnically 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 Eff ective 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

43 

## 7.0 O THER 

## PSD R EQUIREMENTS



### 7.1 I MPACTS 

### A NALYSIS
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 CO 2 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 P RECONSTRUCTION 

### M ONITORING

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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

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 A DDITIONAL 

### I MPACTS 

### A NALYSIS

A PSD additional impacts analysis is not being prov ided 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 author ities 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.F ORMOSA P LASTICS C ORPORATION , T EXAS N OVEMBER 2012 2012 E XPANSION P ROJECT : G AS T URBINES GHG PSD A PPLICATION

45 

## 8.0 P ROPOSED 

## GHG M ONITORING 

## P ROVISIONS

FPC TX proposes to monitor CO 2 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 CALCULATIONSUnit: 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 CO 2 e/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 18Table A-1GHG Emission SummaryFormosa Plastic Corporation, Texas2012 Expansion Project: Gas TurbinesNovember 2012Source Name Operating Scenario EPNDetailedCalculations inGHG MassEmissionsCO2e(tpy)(tpy)Gas Turbine 17K463,071463,516Gas Turbine 27L463,071463,516Firing 100% Natural GasTable A-361,44961,508Firing 100% OL Tail GasTable A-452,97553,034Firing 100% Hydrogen [2]N/A00Firing 100% Natural GasTable A-361,44961,508Firing 100% OL Tail GasTable A-452,97553,034Firing 100% Hydrogen [2]N/A00Subtotal Total, Combined Cycle Units [3] =1,049,040 1,050,047Turbine Startup, Fuel LineMaintenanceStartup, Maintenance7K-NGVENT, 7L-NGVENTTable A-5 1.24 25.1Fugitive Components N/A NG-FUG Table A-6 20.90 425.2SF6Electrical InsulationN/A SF6-FUG Table A-7 <0.01 29.6Total = 1,049,062 1,050,527Notes:[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.Table A-2Firing 100% Natural GasDuct Firing, Unit 1 [1]Duct Firing, Unit 2 [1]7K7LUtility GHG Calc Template.xlsxGHG Emission Calculations - Natural Gas Combustion - Gas TurbinesFormosa Plastic Corporation, Texas2012 Expansion Project: Gas TurbinesNovember 2012GHG Emissions Contribution From Natural Gas Fired Combustion Turbines:EPNAverage HeatInputAnnual HeatInputPollutantEmissionFactorGHG MassEmissions2CO2e(MMBtu/hr) (MMBtu/yr)(kg/MMBtu)1(tpy)(tpy)CO253.02 463,062 1 463,0627K 997 8,733,720CH41.0E-03 8.73 21 183.4N2O1.0E-04 0.87 310 270.7Totals 463,071463,516CO253.02 463,062 1 463,0627L 997 8,733,720CH41.0E-03 8.73 21 183.4N2O1.0E-04 0.87 310 270.7Totals 463,071463,516Total for 2 Turbines926,143 927,032Notes:1. CO2GHG factor from Table C-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting (GHG MRR).CH4and N2O GHG factors based on Table C-2 of GHG MRR.2. CO2emissions 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, CO2: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 = 463062GlobalWarmingPotential3Table A-2Utility GHG Calc Template.xlsxGHG Emissions Contribution From Natural Gas Fired Combustion:Source TypeAverage HeatInput/UnitAnnual AvgHeat Input,Each UnitPollutantEmissionFactorGHG MassEmissions2CO2e CO2e(MMBtu/hr) (MMBtu/yr)(kg/MMBtu)1(metric ton/yr)(metric ton/yr) (tpy)CO253.0255,735155,735 61,447Turbine 1 Duct Burners 120 1,051,200CH41.0E-031.052122.124.3N2O1.0E-04 0.11 310 32.6 35.9Totals 55,736 55,789 61,508CO253.0255,735155,735 61,447Turbine 2 Duct Burners 120 1,051,200CH41.0E-031.052122.124.3N2O1.0E-04 0.11 310 32.6 35.9Totals 55,736 55,789 61,508Total, All Natural Gas Duct Firing111,472 111,579 123,015Notes: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. CO2emissions 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, CO2: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 = 55734.6Table A-3GHG Emission Calculations - Duct Burners Natural Gas CombustionFormosa Plastic Corporation, TexasEmissions per UnitGlobalWarmingPotential32012 Expansion Project: Gas TurbinesNovember 2012Utility GHG Calc Template.xlsxOlefins (OL) Tail Gas Data:Variable Value Units ReferenceNet Heating Value (LHV)625Btu/scfFormosa DesignSpecificationCarbon Content (AnnualAvg)0.677kg C/kgFormosa DesignSpecificationMolecular Weight(Annual Avg)9.8kg/kg-molFormosa DesignSpecificationGHG Emissions Contribution from OL Tail Gas Combustion:Source TypeAverage HeatInput/UnitAnnualAverage FuelGasUsage/Unit1Annual AverageFuel Use, EachUnitAnnualAverage HeatInput, EachUnitPollutantEmissionFactorGHG MassEmissions3CO2e CO2e(MMBtu/hr) (MMscf/hr) (scf/yr) (MMBtu/yr)(kg/MMBtu)2(metric ton/yr)(metric ton/yr) (tpy)CO248,049148,04952,974Turbine 1 Duct Burners 120 0.192 1.68E+09 1.05E+06CH41.0E-031.052122.0824N2O1.0E-04 0.11 310 32.59 36Totals 48,050 48,103 53,034CO248,049148,04952,974Turbine 2 Duct Burners 120 0.192 1.68E+09 1.05E+06CH41.0E-031.052122.0824N2O1.0E-04 0.11 310 32.59 36Totals 48,050 48,103 53,034Total, All OL Tail Gas Combustion96,099 96,206 106,068Notes:1. Fuel use calculated as: MMscf/hr = Firing rate (MMBtu/hr) / HHV (Btu/scf)2. CH4and N2O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.CH4and N2O emissions based on 40 CFR Part 98, Subpart C, Equation C-8.3. CO2emissions 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 - CO2: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+04GlobalWarmingPotential4GHG Emission Calculations - OL Tail Gas CombustionFormosa Plastic Corporation, Texas2012 Expansion Project: Gas TurbinesTable A-4November 2012Utility GHG Calc Template.xlsxCO23CH44Total, bothTurbinesVolume1Press. Temp. Press. Temp. Volume2Annual Annual Annual(ft3)(psig) (°F) (psig) (°F) (scf) (tpy) (tpy) (tpy)75.0300900681,63530 0.0336 0.9820.03009006843624 0.00718 0.210GHG Mass-Based Emissions0.0408 1.19 1.24Global Warming Potential51 21CO2e Emissions0.0408 25.1 25.1Notes:1. Initial volume is calculated by multpilying the crossectional area by the length of pipe using the following formula: Vi= pi * [(diameter in inches/12)/2]2* length in feet = ft32. Final volume calculated using ideal gas law [(PV/ZT)i= (PV/ZT)f]. Vf= Vi(Pi/Pf) (Tf/Ti) (Zf/Zi), where Z is estimated using the followingequation: Z = 0.9994 - 0.0002P + 3E-08P2.3. CO2emissions based on vol% of CO2in natural gas1.20% from natural gas analysis4. CH4emissions based on vol% of CH4in natural gas96.6% from natural gas analysis5. 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 = = 0.0336ton/yr CO2yrscf Nat Gas 385 scf2000 lbTable A-5Turbine StartupFuel Line Maintenance44 lb CO2lbmoleGHG Emission Calculations -Formosa Plastic Corporation, TexasInitial ConditionsFinal ConditionsGaseous Fuel Venting During Turbine Startup andFuel Line Maintenance, EPNs 7K-NGVENT, 7L-NGVENTAnnualFrequency ofEventLocation2012 Expansion Project: Gas TurbinesNovember 2012Utility GHG Calc Template.xlsxGHG Emissions Contribution From Fugitive Piping Components:EPN SourceFluidCount EmissionCO2Content CH4Content CO2MethaneTotalTypeStateFactor1(vol %) (vol %) (tpy)(tpy)(tpy)scf/hr/compValvesGas/Vapor 600 0.1210.43612.80NG-FUGFlanges Gas/Vapor 2400 0.0170.2457.19Relief Valves Gas/Vapor 5 0.1935.80E-03 1.70E-01Sampling Connections Gas/Vapor 10 0.0311.86E-03 5.46E-02Compressors Gas/Vapor 3 0.0023.60E-05 1.06E-03GHG Mass-Based Emissions0.68920.220.9Global Warming Potential21 21CO2e Emissions0.69 424.5425.2Notes: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 gaslbmol44.01 lb CO28760 hr ton0.44 ton/yrhr * valvescf gas385 scf lbmolyr2000 lb0.012 scf CO21.20% 96.6%Table A-6GHG Emission Calculations - Fugitive Component EmissionsFormosa Plastic Corporation, Texas2012 Expansion Project: Gas TurbinesNovember 2012Utility GHG Calc Template.xlsxEPNInsulated SF6Annual Leak Annual Leak Global Warming Estimated AnnualCircuit Breaker Capacity Rate, wt % Rate (tpy)Potential1CO2e Emission Rate(pounds)(tpy)SF6-FUG495 0.50% 1.24E-03 23,900 29.6Notes: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 SF6Formosa Plastic Corporation, Texas2012 Expansion Project: Gas TurbinesTable A-7November 2012Utility GHG Calc Template.xlsx

## APPENDIX B

PSD NETTING TABLESTABLE 1FAIR QUALITY APPLICATION SUPPLEMENTPermit No.:TBDApplication Submittal Date:CompanyFormosa Plastic Corporation, TexasRN:RN100218973Facility Location:201 Formosa DriveCityPoint ComfortCounty:CalhounPermit Unit I.D.:2012 Expansion ProjectPermit Name:TBDPermit Activity:Project or Process Description:Complete for all pollutants with a project POLLUTANTSemission increase. Ozone COSO2PM GHGCO2eNOx VOCNonattainment? (yes or no)No NoExisting site PTE (tpy)>100,000 >100,000Proposed project increases (tpy from 2F)3,034,027 3,990,283Is the existing site a major source? If not, is the project amajor source by itself? (yes or no)YesIf site is major, is project increase significant? (yes or no)Yes YesIf netting required, estimated start of construction:9/1/135 years prior to start of construction:9/1/08Contemporaneousestimated start of operation:10/1/15PeriodNet contemporaneous change, including proposed project,from Table 3F (tpy)3,034,027 3,990,283FNSR applicable? (yes or no)Yes YesOlefins Expansion, LDPE Plant and Gas TurbinesThis form for GHG onlyNew Major SourceModificationTABLE 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 Ja nuary 2009 through December 2010. LDPE Plant Sources

Combined Cycle Turbine Sources 211.6 211.6 211.6

31,550 31,550 31,550TABLE 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, 7L

NGVENT 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 ANAL YSIS AND SUPPLEMENTAL INFORMATION

### BACT FOR 

### C ARBON 

### C APTURE AND 

### S EQUESTRATION

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.



### S TEP 

### 1: I DENTIFY ALL AVAILABLE CONTROL TECHNOLOGIES 

### 6.1.1

The emerging carbon capture and sequestration (CCS) technologies generally consist of processes that separate CO 2 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 CO 2 capture technologies that have been identified, only amine absorption is currently commercially used for state-of-the-art CO 2 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 CO 2 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 areapplicable 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 CO 2 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 CO 2 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 CO 2 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 CO 2 from flue gas streams is challenging for several reasons:

 CO 2 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 CO 2 capture
processes.

It should be noted that the majority of the candidat e CCS source vent streams (previously listed in this section) are dilute in CO 2 concentration and contain impurities such as PM, NO X and SO 2 , thus increasing the challenge of CO 2 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 CO 2 from atmospheric pressure to pipeline pressure (about 2,000 psia) represents a large auxiliary power load on the overall plant system... 2

If CO 2 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 CO 2 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 CO 2 storage sites and their associated technical challenges as follows:

Geologic carbon dioxide (CO 2 ) storage involves the injection of supercritical CO 2 into deep geologic formations (injection zones) overlain by competent sealing formations and geologic traps that will prevent the CO 2 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 CO 2 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 CO 2 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 FP C TX proposed expansion. FPC TX’s expansion project generates flue gas streams that contain CO 2 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.



### S TEP 

### 2: E LIMINATE 

### T ECHNICALLY 

### I NFEASIBLE 

### O PTIONS 

### 6.1.2

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 CO 2 

### Capture

Though amine absorption technology for CO 2 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 availabilit y for high volume vent streams and large combustion unit shows that carbon captur e 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 CO 2 capture for chemical process combus tion and process vent stream are not commercially available.Current technologies could be used to capture CO 2 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 CO 2 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 CO 2 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 CO 2 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 CO 2 storage capacity in geologic formations to within ±30 percent by 2015; (3) Develop technologies to demonstrate that 99 percent of injected CO 2 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 CO 2 capture technology for large-scale combustion (power plant) projects will not occur for several more years, Alstom, one of the major developers of commercial CO 2 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 Fo rce 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 CO 2 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 CO 2 emissions generated from chemical plant sources, like those included in the Point Comfort expansion project.



### 6.1.2.2 CO 2 

### 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 disc ussion 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 CO 2 capture could feasibly be achieved for the proposed project, the high-volume CO 2 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 CO 2 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 CO 2 , 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 CO 2 storage.

In comparison, the closest site that is currently being field-tested to demonstrate its capacity for large-scale geological storage of CO 2 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 aw ay (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-event s/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 CO 2 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 CO 2 generated by the proposed project, a very long and sizable pipeline would need to be constructed to transport the large volume of high-pressure CO 2 from the plant to the storage facility, thereby rendering implementation of a CO 2 transport system infeasible.

The potential length of such a CO 2 transport pipeline is uncertain due to the uncertainty of identifying a site(s) that is suitable for large-scale, long-term CO 2 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
CO 2 , which is an enhanced oil recovery (EOR) reservoir site 8 located more than 600 kilometers from the proposed project; or

 The distance to a CO 2 pipeline that Denbury Green Pipeline-Texas is currently constructing approximately 150 kilometers (strai ght line distance) from the project site for the purpose of providing CO 2 to support various EOR operations in Southeast Texas beginning in late 2013.



### 6.1.2.3 CO 2 

### Sequestration

Even if it is assumed that CO 2 capture and compression could feasibly be achieved for the proposed project and that the CO 2 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, CO 2 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 CO 2 into the formations. Potential environmental impacts resulting from CO 2 injection that still require assessment before CCS technology can be considered feasible include:

 Uncertainty concerning the significance of dissolution of CO 2 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 CO 2 storage. Risks of brine displacement resulting from large-scale CO 2 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 CO 2 , 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 CO 2 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 CO 2 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 CO 2 generated by the proposed project has yet to be fully demonstrated.



### S TEP 

### 3: R ANK 

### R EMAINING 

### C ONTROL 

### T ECHNOLOGIES 

### 6.1.3

As documented above, implementation of CCS te chnology 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.



### S TEP 

### 4: E VALUATE 

### M OST 

### E FFECTIVE 

### C ONTROLS AND 

### D OCUMENT 

### R ESULTS 

### 6.1.4

6.1.4.1 Additional Environmen tal 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 toinstall 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 CO 2 e/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 distur bance 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 CO 2 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 CO 2 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 CO 2 to the buyer. FPC TX has identified contractual issues relating to the sale of CO 2 that conflict directly with existing contracts relating to the sale of primary products. For this reason, FPC TX believes that the
sale of CO 2 from the Point Comfort expansion sources poses an unacceptable business conflict.

10 US Department of Energy, National Energy Technolog y Laboratory, “Costs and Perf ormance Baseline For Fossil Energy Plants, Volume 1 - Bituminous Coal and Natu ral 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 questi ons that the public or the EPA may have concerning the relative costs of implem enting 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 t hese 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 th e 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.



### S TEP 

### 5: S ELECT 

### BACT 6.1.5

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
CO 2 at the point when pipeline quality CO 2 is available.

This statement provides evidence that the proj ect, including application of CCS, hinges on the approval and contracts for a new CO 2 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 CO2Throughput(tons of CO2captured, transported,and stored)1Pipeline Length for CO2Transport System(km CO2transported)5Range of Approximate Annual Costsfor CCS Systems($)Minimum Cost $44.11/ ton of CO2avoided22,913,739$128,525,043Maximum Cost$103.42/ ton of CO2avoided32,913,739$301,336,173Average Cost$73.76/ ton of CO2avoided42,913,739$214,930,608Minimum Cost$0.91/ ton of CO2transported per 100 km32,913,739150$3,964,950Maximum Cost$2.72/ ton of CO2transported per 100 km32,913,739150$11,894,849Average Cost$1.81/ ton of CO2transported per 100 km42,913,739150$7,929,899Minimum Cost$0.51/ ton of CO2stored3,62,913,739$1,480,248Maximum Cost$18.14/ ton of CO2stored3,62,913,739$52,865,995Average Cost$9.33/ ton of CO2stored42,913,739$27,173,122Minimum Cost$45.98/ ton of CO2removed2,913,739 $133,970,240Maximum Cost $125.65/ ton of CO2removed2,913,739 $366,097,017Average Cost $85.81/ ton of CO2removed42,913,739$250,033,6294The 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 CO2Capture and CompressionSystemTable 6-1Range of Approximate Annual Costs forInstallation and Operation of Capture, Transport, and Storage Systemsfor Control of CO2Emissions from the Point Comfort ExpansionTotal Cost for CO2Capture, Transport, and StorageSystems6"Cost estimates [for geologic storage of CO2] are limited to capital and operational costs, and do not includepotential costs associated with long-term liability." (fromtheReport of the Interagency Task Force on Carbon Capture andStorage, p. 44)5The length of the pipeline was assumed to be the distance to the closest potential geologic storage site, as identified by theUniversity of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, available at:http://www.beg.utexas.edu/gccc/graphics/Basemap_state_lands_fp_lg.jpg (last visited Feb. 27, 2012).3These cost factors are fromReport 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_task_force.html). The factors from the report inthe form of $/tonne of CO2avoided, 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 an "energy‐generating system, including all thecosts over its lifetime: initial investment, operations and maintenance, cost of fuel, and cost of capital".Carbon Capture and Storage (CCS) ComponentSystemFactors for Approximate Costsfor CCS SystemsCO2Transport System1Assumes the maximum possible annual CO2emissions scenario and assumes that a capture system would be able to capture 90% of the total CO2emissions generated by the combustion turbines.CO2Storage System2This cost factor is the minimum found for implementation/operation of CO2capture systems within the cost-related information reviewed for CCS technology. The factor is from the on the "Properties" spreadsheet of theGreenhouseGas Mitigation Strategies Database(Apr. 2010) (http://ghg.ie.unc.edu:8080/GHGMDB/#data), which was obtained throughthe EPA GHG web site (http://www.epa.gov/nsr/ghgpermitting.html). The factor is based on the increasedcost of electricity (COE; in $/MW-h) resulting from implementation and operation at a CO2capture system on a natural gas-fired combined cycle power plant. The factor accounts for annualized capital costs, fixed operating costs,variable operating costs, and fuel costs.

## APPENDIX D

KELLY HART & HALLMAN MEMO RE: EPA POLCY ON MULTIPLE PSD PERMITS1371846-2 

### K ELLY 

### H ART 

### &

H ALLMAN 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 operational1371846-2 

### 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 Projects1371846-2 

### 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 SO 2 

### and PM 10 

### /PM 2.5 

### 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 SO 2 

### and PM 10 

### and PM 2.5 

### , 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 as1371846-2 

### 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 apply1371846-2 

### 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.