Draft Environmental Impact Statement

Corpus Christi LNG Project

Corpus Christi Liquefaction, LLC Docket No. CP12-507-000

Cheniere Corpus Christi Pipeline, L.P. Docket No. CP12-508-000

DOE Docket No. FE 12-97-LNG

FERC/EIS-0252D

Federal Energy Regulatory Commission

Office of Energy Projects

Washington, DC 20426

Cooperating Agencies:

U.S. Army Corps of Engineers

U.S. Coast Guard

U.S. Department of Transportation

U.S. Environmental Protection Agency

U.S. Department of Energy

June 2014

Docket Nos.

CP12-507-000

CP12-508-000

DOE FE 12-97-LNG

FERC/EIS-0252D

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June 2014
FEDERALENERGY REGULATORY COMMISSION

WASHINGTON, D.C. 20426

OFFICE OF ENERGY PROJECTS In Reply Refer To:

OEP/DG2E/Gas 2

Corpus Christi Liquefaction, LLC and

Cheniere Corpus Christi Pipeline, LP

Docket Nos. CP12-507-000

CP12-508-000

TO THE PARTY ADDRESSED:

The staff of the Federal Energy Regulatory Commission (FERC or Commission)

has prepared a draft environmental impact statement (EIS)for the Corpus Christi LNG

Project (Project), proposed by Corpus Christi Liquefaction, LLC and Cheniere Corpus

Christ Pipeline, LP (collectively Cheniere)in the above-referenced dockets. Cheniere

requests authorization to construct and operate the facilities necessary to import, export,

store, vaporize, and liquefy natural gas and deliver the resulting product either into

existing interstate and intrastate natural gas pipelines in the Corpus Christi area, or export

liquefied natural gas (LNG)elsewhere.

The draft EIS assesses the potential environmental effects of the construction and

operation of the Project in accordance with the requirements of the National

Environmental Policy Act (NEPA). The FERC staff concludes that approval of the

proposed Project, with the mitigation measures recommended in the EIS, would ensure

that impacts in the Project area would be avoided or minimized and would not be

significant. Construction and operation of the Project would result in mostly temporary

and short-term environmental impacts;however, some long-term and permanent

environmental impacts would occur.

The U.S. Army Corps of Engineers (COE), U.S. Coast Guard, U.S. Department of

Energy (DOE), U.S. Environmental Protection Agency (EPA), and U.S. Department of

Transportation (DOT)participated as cooperating agencies in the preparation of the EIS.

Cooperating agencies have jurisdiction by law or special expertise with respect to

resources potentially affected by the proposal and participate in the NEPA analysis. The

U.S. Coast Guard, EPA, and DOT cooperated in the preparation of this EIS because of

their special expertise with respect to resources potentially affected by the proposal.

Although the cooperating agencies provide input to the conclusions and

recommendations presented in the draft EIS, the agencies will present their own

conclusions and recommendations in their respective Records of Decision or

determinations for the Project.
2

The draft EIS addresses the potential environmental effects of the construction and

operation of the following Project facilities:

 liquefaction facilities, including three liquefaction trains capable of

producing 782 million British thermal units (MMBtu)per year of LNG;

 vaporization facilities, including two trains of ambient air vaporizers and

send out pumps capable of vaporizing sufficient LNG volume for each to

send out 200 MMBtu per day of natural gas;

 LNG storage facilities, including three LNG storage tanks each capable of

storing 160,000 cubic meters of LNG;

 marine terminal with two LNG carrier berths;

 23 miles of 48-inch-diameter pipeline;

 one 41,000 horsepower compressor station and one 12,260 horsepower

compressor station;and

 ancillary facilities.

The FERC staff mailed copies of the draft EIS to federal, state, and local

government representatives and agencies;elected officials;environmental and public

interest groups;Native American tribes;potentially affected landowners and other

interested individuals and groups;newspapers and libraries in the Project area;and

parties to this proceeding. Everyone on our environmental mailing list will receive a CD

version of the draft EIS. In addition, the draft EIS is available for public viewing on the

FERC’s website (www.ferc.gov)using the eLibrary link. A limited number of copies are

available for distribution and public inspection at:

Federal Energy Regulatory Commission

Public Reference Room

888 First Street NE, Room 2A

Washington, DC 20426

(202)502-8371

If you would like a hard copy of the draft EIS, please contact the Public Reference

Room.

Any person wishing to comment on the draft EIS may do so. To ensure

consideration of your comments on the proposal in the final EIS, it is important that the

Commission receive your comments before August 4,2014.
3

For your convenience, there are four methods you can use to submit your

comments to the Commission. In all instances, please reference the Project docket

numbers (CP12-507-000 and CP12-508-000)with your submission. The Commission

encourages electronic filing of comments and has expert staff available to assist you at

(202)502-8258 or efiling@ ferc.gov.

1) You can file your comments electronically using the eComment feature on

the Commission’s website (www.ferc.gov)under the link to Documents

and Filings. This is an easy method for submitting brief, text-only

comments on a project;

2) You can file your comments electronically by using the eFiling feature on

the Commission’s website (www.ferc.gov)under the link to Documents

and Filings. With eFiling, you can provide comments in a variety of

formats by attaching them as a file with your submission. New eFiling

users must first create an account by clicking on “eRegister.” If you are

filing a comment on a particular project, please select “Comment on a

Filing”as the filing type;or

3) You can file a paper copy of your comments by mailing them to the

following address:

Kimberly D. Bose, Secretary

Federal Energy Regulatory Commission

888 First Street NE, Room 1A

Washington, DC 20426

4) In lieu of sending written or electronic comments, the Commission invites

you to attend the public comment meeting its staff will conduct in the

Project area to receive comments on the draft EIS. We encourage

interested groups and individuals to attend and present oral comments on

the draft EIS. Transcripts of the meetings will be available for review in

eLibrary under the Project docket numbers. The meeting will begin at

7:00 p.m. and is scheduled as follows:

Date Location

July 15, 2014 Portland Community Center

2000 Billy G Webb Drive

Portland, TX 78374
4

Any person seeking to become a party to the proceeding must file a motion to

intervene pursuant to Rule 214 of the Commission’s Rules of Practice and Procedures

(18 CFR Part 385.214).1 Only intervenors have the right to seek rehearing of the

Commission’s decision. The Commission grants affected landowners and others with

environmental concerns intervenor status upon showing good cause by stating that they

have a clear and direct interest in this proceeding which no other party can adequately

represent. Simplyfiling environmental comments will not give youintervenor status,

but youdo not need intervenor status to have your comments considered.

Questions?

Additional information about the Project is available from the Commission’s

Office of External Affairs, at (866)208-FERC,or on the FERC website (www.ferc.gov)

using the eLibrary link. Click on the eLibrary link, click on “General Search,”and enter

the docket number excluding the last three digits in the Docket Number field (i.e., CP12-

507 and CP12-508). Be sure you have selected an appropriate date range. For assistance,

please contact FERC Online Support at FercOnline Support@ ferc.gov or toll free at

(866)208-3676;for TTY, contact (202)502-8659. The eLibrary link also provides

access to the texts of formal documents issued by the Commission, such as orders,

notices, and rulemakings.

In addition, the Commission offers a free service called eSubscription that allows

you to keep track of all formal issuances and submittals in specific dockets. This can

reduce the amount of time you spend researching proceedings by automatically providing

you with notification of these filings, document summaries, and direct links to the

documents. Go to http://www.ferc.gov/docs-filing/esubscription.asp.

Kimberly D. Bose,

Secretary.

1

See the previous discussion on the methods for filing comments.
Environmental Impact Statement ii Corpus Christi LNG

CORPUSCHRISTILNG PROJECT

DRAFT ENVIRONMENTAL IMPACT STATEMENT

TABLE OFCONTENTS

EXECUTIVE SUMMARY ...................................................................................................ES-1

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

1.1 REGULATORY BACKGROUND.......................................................................... 1-1

1.2 PROJECT PURPOSE AND NEED ......................................................................... 1-6

1.3 PURPOSE AND SCOPE OF THE EIS.................................................................... 1-6

1.3.1 Federal Energy Regulatory Commission Purpose and Role .............................. 1-7

1.3.2 U.S. Army Corps of Engineers Purpose and Role............................................. 1-7

1.3.3 U.S. Coast Guard Purpose and Role ................................................................. 1-8

1.3.4 U.S. Department of Transportation Purpose and Role....................................... 1-8

1.3.5 U.S. Environmental Protection Agency Purpose and Role................................ 1-9

1.3.6 U.S. Department of Energy Purpose and Role .................................................. 1-9

1.4 PUBLIC REVIEW AND COMMENT................................................................... 1-10

1.5 NON-JURISDICTIONAL FACILITIES................................................................ 1-13

1.5.1 Electrical Power Lines and Substations .......................................................... 1-16

1.5.2 Waterline ....................................................................................................... 1-16

1.6 PERMITS, APPROVALS, AND REGULATORY REVIEWS .............................. 1-16

1.6.1 Endangered Species Act................................................................................. 1-17

1.6.2 Magnuson-Stevens Fishery Conservation Management Act ........................... 1-17

1.6.3 Rivers and Harbors Act.................................................................................. 1-17

1.6.4 Clean Water Act............................................................................................. 1-17

1.6.5 Clean Air Act................................................................................................. 1-18

1.6.6 Federal Aviation Act...................................................................................... 1-18

1.6.7 Maritime Transportation Security Act ............................................................ 1-19

1.6.8 National Historic Preservation Act ................................................................. 1-19

1.6.9 Coastal Zone Management Act ...................................................................... 1-19

1.6.10 National Flood Insurance Act......................................................................... 1-19

2.0 DESCRIPTION OF PROPOSED ACTION............................................................. 2-1

2.1 TERMINAL (IMPORT AND EXPORT)FACILITIES ........................................... 2-1

2.1.1 Liquefaction Facilities –Export ....................................................................... 2-1
Environmental Impact Statement iii Corpus Christi LNG

2.1.2 LNG Vaporization Facilities –Import .............................................................. 2-2

2.1.3 LNG Storage Facilities..................................................................................... 2-2

2.1.4 Marine Terminal and LNG Transfer Lines ....................................................... 2-3

2.1.5 Flare Facilities ................................................................................................. 2-8

2.1.6 Other Terminal Infrastructure........................................................................... 2-8

2.2 PIPELINE FACILITIES.......................................................................................... 2-9

2.2.1 Pipeline............................................................................................................ 2-9

2.2.2 Compressor Stations ...................................................................................... 2-10

2.3 LAND AND WATER REQUIREMENTS............................................................. 2-10

2.3.1 Terminal Facilities ......................................................................................... 2-10

2.3.2 Pipeline Facilities........................................................................................... 2-12

2.4 CONSTRUCTION PROCEDURES ...................................................................... 2-17

2.4.1 Construction Schedule ................................................................................... 2-18

2.4.2 Terminal Facilities ......................................................................................... 2-18

2.4.3 Pipeline Facilities........................................................................................... 2-20

2.5 OPERATION AND MAINTENANCE.................................................................. 2-26

2.5.1 Environmental Compliance and Monitoring ................................................... 2-27

2.6 FUTURE PLANS AND ABANDONMENT.......................................................... 2-29

3.0 ALTERNATIVES ................................................................................................... 3-1

3.1 TERMINAL FACILITIES....................................................................................... 3-1

3.1.1 No-Action Alternative...................................................................................... 3-1

3.1.2 Alternative Energy Sources.............................................................................. 3-2

3.1.3 System Alternatives ......................................................................................... 3-4

3.1.4 Alternative Terminal Sites.............................................................................. 3-12

3.1.5 Alternative Dredge Disposal Locations .......................................................... 3-17

3.2 PIPELINE FACILITIES........................................................................................ 3-20

3.2.1 No-Action Alternative.................................................................................... 3-20

3.2.2 System Alternatives ....................................................................................... 3-20

3.2.3 Pipeline Route Alternatives............................................................................ 3-22

3.2.4 Pipeline and Compressor Alternatives Conclusions ........................................ 3-30

4.0 ENVIRONMENTAL ANALYSIS........................................................................... 4-1

4.1 GEOLOGIC RESOURCES ..................................................................................... 4-1

4.1.1 Terminal Facilities ........................................................................................... 4-1

4.1.2 Pipeline Facilities............................................................................................. 4-7
Environmental Impact Statement iv Corpus Christi LNG

4.2 SOILS AND SEDIMENTS ..................................................................................... 4-9

4.2.1 Terminal Facilities ........................................................................................... 4-9

4.2.2 Pipeline Facilities........................................................................................... 4-16

4.3 WATER RESOURCES ......................................................................................... 4-18

4.3.1 Terminal Facilities ......................................................................................... 4-18

4.3.2 Pipeline.......................................................................................................... 4-24

4.4 WETLANDS......................................................................................................... 4-26

4.4.1 Terminal Facilities ......................................................................................... 4-26

4.4.2 Pipeline Facilities........................................................................................... 4-29

4.5 VEGETATION ..................................................................................................... 4-30

4.5.1 Terminal Facilities ......................................................................................... 4-30

4.5.2 Pipeline Facilities........................................................................................... 4-31

4.6 WILDLIFE AND AQUATIC RESOURCES ......................................................... 4-32

4.6.1 Wildlife Resources......................................................................................... 4-32

4.6.2 Fisheries Resources........................................................................................ 4-36

4.6.3 Migratory Birds ............................................................................................. 4-45

4.7 THREATENED, ENDANGERED, AND OTHER SPECIAL STATUS SPECIES 4-47

4.7.1 Federally Listed Threatened and Endangered Species .................................... 4-47

4.7.2 State Listed Threatened and Endangered Species ........................................... 4-55

4.8 LAND USE, RECREATION, AND VISUAL RESOURCES ................................ 4-59

4.8.1 Terminal Facilities ......................................................................................... 4-59

4.8.2 Pipeline Facilities........................................................................................... 4-66

4.9 SOCIOECONOMICS............................................................................................ 4-72

4.9.1 Population...................................................................................................... 4-72

4.9.2 Economy and Employment ............................................................................ 4-73

4.9.3 Property Values.............................................................................................. 4-75

4.9.4 Construction Payroll and Material Purchases.................................................. 4-76

4.9.5 Tax Revenues ................................................................................................ 4-76

4.9.6 Housing ......................................................................................................... 4-77

4.9.7 Removal of Agricultural, Pasture, or Timberland from Production................. 4-78

4.9.8 Public Services............................................................................................... 4-78

4.9.9 Environmental Justice .................................................................................... 4-81

4.9.10 Transportation and Traffic.............................................................................. 4-84

4.10 CULTURAL RESOURCES .................................................................................. 4-88
Environmental Impact Statement v Corpus Christi LNG

4.10.1 Consultations ................................................................................................. 4-88

4.10.2 Overview and Survey Results......................................................................... 4-90

4.10.3 Unanticipated Discoveries.............................................................................. 4-91

4.10.4 Compliance with NHPA................................................................................. 4-91

4.11 AIR QUALITY AND NOISE................................................................................ 4-92

4.11.1 Air Quality..................................................................................................... 4-92

4.11.2 Noise ........................................................................................................... 4-125

4.12 RELIABILITY AND SAFETY ........................................................................... 4-141

4.12.1 LNG Facility Regulatory Oversight.............................................................. 4-141

4.12.2 LNG Facility Hazards .................................................................................. 4-142

4.12.3 Technical Review of the Facility Preliminary Engineering Design ............... 4-152

4.12.4 LNG Facility Siting Requirements ............................................................... 4-166

4.12.5 LNG Facility Siting Analysis ....................................................................... 4-170

4.12.6 LNG Carrier Hazards ................................................................................... 4-189

4.12.7 LNG Facility and LNG Carrier Emergency Response .................................. 4-197

4.12.8 Conclusions on Facility Reliability and Safety ............................................. 4-198

4.12.9 Pipeline Safety Standards............................................................................. 4-200

4.13 CUMULATIVE IMPACTS ANALYSIS............................................................. 4-207

4.13.1 Projects Potentially Contributing to Cumulative Impacts.............................. 4-208

4.13.2 Existing LNG Terminals and Projects .......................................................... 4-214

4.13.3 Currently Operating Oil and Gas Facilities................................................... 4-215

4.13.4 Other Projects and Activities Considered ..................................................... 4-215

4.13.5 Potential Cumulative Impacts by Resource................................................... 4-216

4.13.6 Conclusions for Overall Cumulative Impacts ............................................... 4-227

5.0 CONCLUSIONS AND RECOMMENDATIONS.................................................... 5-1

5.1 SUMMARY OF THE ENVIRONMENTAL ANALYSIS........................................ 5-1

5.1.1 Geologic Resources.......................................................................................... 5-1

5.1.2 Soils................................................................................................................. 5-1

5.1.3 Water Resources .............................................................................................. 5-2

5.1.4 Wetlands.......................................................................................................... 5-3

5.1.5 Vegetation........................................................................................................ 5-3

5.1.6 Wildlife and Aquatic Resources ....................................................................... 5-4

5.1.7 Threatened, Endangered, and Other Sensitive Species...................................... 5-5

5.1.8 Land Use, Recreation, and Visual Resources.................................................... 5-5
Environmental Impact Statement vi Corpus Christi LNG

5.1.9 Socioeconomics ............................................................................................... 5-6

5.1.10 Cultural Resources ........................................................................................... 5-6

5.1.11 Air Quality and Noise ...................................................................................... 5-7

5.1.12 Safety............................................................................................................... 5-8

5.1.13 Cumulative Impacts ......................................................................................... 5-8

5.2 ALTERNATIVES ................................................................................................... 5-9

5.3 FERC STAFF’S RECOMMENDED MITIGATION ............................................. 5-10
Environmental Impact Statement vii Corpus Christi LNG

LIST OFAPPENDICES

Appendix A Alignment Sheets

Appendix B Essential Fish Habitat Assessment

Appendix C Tables

Appendix D Cheniere’s Fugitive Dust Control Plan

Appendix E Distribution List for Draft Environmental Impact Statement

Appendix F References

Appendix G List of Preparers and Reviewers
Environmental Impact Statement viii Corpus Christi LNG

LIST OFFIGURES

Figure 1.1-1 Corpus Christi LNG Project General Location ................................................. 1-3

Figure 1.1-2 Artist Impression of Proposed Terminal Facilities ............................................ 1-4

Figure 1.1-3 Terminal Facilities Boundary ........................................................................... 1-5

Figure 1.5-1 Locations of Non-Jurisdictional Facilities ...................................................... 1-15

Figure 2.1-1 Proposed Dredge Material Placement Areas..................................................... 2-7

Figure 2.3-1 Typical pipeline right-of-way configuration with overlapping rights-of-way .. 2-15

Figure 2.3-2 Typical pipeline right-of-way configuration with abutting rights-of-way........ 2-16

Figure 2.4-1 Typical Pipeline Construction Sequence......................................................... 2-21

Figure 3.1-1 System alternatives for the Terminal ................................................................ 3-5

Figure 3.1-2 Terminal Site Alternatives.............................................................................. 3-14

Figure 3.1-3 Alternative Dredge Disposal Areas ................................................................ 3-19

Figure 3.2-1 Pipeline Route Alternatives............................................................................ 3-25

Figure 3.2-2 Taft Compressor Station Site Alternative ....................................................... 3-27

Figure 3.2-3 Sinton Compressor Station Site Alternatives .................................................. 3-29

Figure 4.8-1 Current View of the Terminal Site from California Drive, Portland................ 4-64

Figure 4.8-2 Post-construction Visual Simulation View of the Terminal Site from California

Drive, Portland....................................................................................................... 4-64

Figure 4.8-3 Visual Simulation View of the Terminal at Night from California Drive, Portland

...................................................................................................................... 4-65

Figure 4.11-1 Terminal and Dredging NSA Locations and Distances ............................... 4-127

Figure 4.11-2 Sinton Compressor Station NSA Locations and Distances .......................... 4-129

Figure 4.11-3 Taft Compressor Station NSA Locations and Distances.............................. 4-130

Figure 4.11-4 US 181/SH 35 HDD (HDD-1)and Oliver Creek HDD (HDD-2)NSA Locations

and Distances ....................................................................................................... 4-132

Figure 4.11-5 Chiltipin Creek HDD (HDD-3)NSA Locations and Distances ................... 4-133

Figure 4.12-1 Vapor Fences (20 feet high in green;12 feet high in yellow;10 feet high in

purple)................................................................................................................. 4-181

Figure 4.12-2 Flammable and Toxic Vapor Cloud Dispersion Contours ........................... 4-182

Figure 4.12-3 Vapor Cloud Explosion Overpressure Contours.......................................... 4-185

Figure 4.12-4 Thermal Radiation Exclusion Zones 1,600-BTU for Storage Tank and

Impoundments ..................................................................................................... 4-188

Figure 4.12-6 Accidental Hazard Zones Along LNG Carrier Route .................................. 4-195

Figure 4.12-7 Intentional Hazard Zones Along LNG Carrier Route .................................. 4-196
Environmental Impact Statement ix Corpus Christi LNG

Figure 4.13-1 General Locations of Projects Potentially Contributing to Cumulative Impacts....

................................................................................................................... 4-210
Environmental Impact Statement x Corpus Christi LNG

LIST OFTABLES

Table 1.4-1 Issues Identified and Comments Received During the Scoping Process for the

Corpus Christi LNG Project ................................................................................... 1-12

Table 1.6-1 Environmental Permits and Agency Reviews for the Corpus Christi LNG Project .....

.............................................................................................................................. 1-20

Table 2.3-1 Land and Water Requirements for the Terminal.................................................. 2-11

Table 2.3-2 Land Requirements for the Pipeline and Associated Facilities ............................ 2-12

Table 2.3-3 Locations Where the Pipeline may be adjacent to Existing Rights-of-Way.......... 2-14

Table 3.1-1 Alternate Site Location Comparisons.................................................................. 3-16

Table 3.2-1 Natural Gas Pipelines Identified in San Patricio County, Texas .......................... 3-21

Table 3.2-2 Environmental Comparison of the Proposed Pipeline Route with Route Alternatives

.............................................................................................................................. 3-23

Table 3.2-3 Environmental Comparison of Cheniere’s Proposed and Alternative Taft

Compressor Station Sites........................................................................................ 3-26

Table 3.2-4 Environmental Comparison of Cheniere’s Proposed and Alternative Sinton

Compressor Station Sites........................................................................................ 3-28

Table 4.1-1 Federal Emergency Management Agency Flood Hazard Zone Designations Within

the Terminal............................................................................................................. 4-6

Table 4.2-1 Soil Series Impacted by the Terminal ................................................................. 4-10

Table 4.2-2 Gradation Criteria for Granular Structural Fill .................................................... 4-15

Table 4.2-3 Gradation Criteria for Bedding Material ............................................................. 4-15

Table 4.2-4 Characteristics of Soil Types Crossed by the Pipeline Facilities.......................... 4-16

Table 4.2-5 Aboveground Facilities Along the Pipeline Located on Prime Farmland............. 4-17

Table 4.3-1 Water Requirements to Construct the Terminal .................................................. 4-23

Table 4.3-2 Water Requirements to Operate the Terminal ..................................................... 4-23

Table 4.3-3 Waterbodies Crossed by the Pipeline .................................................................. 4-25

Table 4.4-1 Approximate Acreages of Wetland Vegetation Communities that would be Impacted

by the Terminal...................................................................................................... 4-27

Table 4.4-2 Approximate Acreages of Wetland Vegetation Communities that would be Impacted

by the Pipeline ....................................................................................................... 4-29

Table 4.5-1 Seed Mixtures for Terrestrial Vegetation Restoration Following Construction.... 4-32

Table 4.6-1 Marine Mammals Observed in the Gulf of Mexico ............................................. 4-33

Table 4.6-2 Recreational and Commercial Fisheries in Corpus Christi Bay ........................... 4-39

Table 4.6-3 Representative Commercial and Game Fish Species with Potential to Occur in

Waterbodies Crossed by the Pipeline...................................................................... 4-45
Environmental Impact Statement xi Corpus Christi LNG

Table 4.8-1 Land Use Required to Construct and Operate the Terminal................................. 4-60

Table 4.8-2 Locations Where the Pipeline Would be Collocated, Overlap, or Parallel with

Existing Rights-of-Way.......................................................................................... 4-67

Table 4.8-3 Land Use Affected by Construction and Operation of the Pipeline and Associated

Facilities ................................................................................................................ 4-69

Table 4.8-4 Access Roads to be Used for Construction and Operation of the Pipeline and

Associated Facilities............................................................................................... 4-70

Table 4.9-1 Existing Population in the Project Area .............................................................. 4-73

Table 4.9-2 Existing Income and Employment Conditions in the Project Area ...................... 4-74

Table 4.9-3 Number of Workers During Project Construction and Operation ........................ 4-75

Table 4.9-4 Temporary Housing Units Available in the Project Area..................................... 4-77

Table 4.9-5 School Districts and School Enrollment in the Project Area................................ 4-80

Table 4.9-6 Minority Populations in Census Tracts within 0.5 mile of the Project ................. 4-82

Table 4.9-7 Poverty and Minority Populations in Census Tracts within 0.5 mile of the Project.....

.............................................................................................................................. 4-83

Table 4.9-8 Roadways Crossed by the Pipeline ..................................................................... 4-87

Table 4.10-1 Indian Tribes Contacted.................................................................................... 4-89

Table 4.11-1 Ambient Air Quality Standards......................................................................... 4-94

Table 4.11-2 Existing Ambient Air Concentrations for the Project Area................................ 4-96

Table 4.11-3 Construction Barge NOx and VOC Emissions Subject to Evaluation for General

Conformity........................................................................................................... 4-104

Table 4.11-4 Total Construction Emissions by Year Associated with the Terminal.............. 4-107

Table 4.11-5 Total Construction Emissions Associated with the Pipeline and M&R Facility

Areas a/, b/........................................................................................................... 4-108

Table 4.11-6 Annual Emissions Associated with Operation of On-Shore Emission Sources at the

Terminal .............................................................................................................. 4-110

Table 4.11-7 Short-Term Emissions Associated with Operation of On-Shore Emission Sources at

the Terminal......................................................................................................... 4-111

Table 4.11-8 Annual Emissions Associated with Initial Start-Up of the Terminal................ 4-112

Table 4.11-9Annual Emissions Associated with Operation of Marine Vessels within the Security

Zone at the Terminal ............................................................................................ 4-113

Table 4.11-10 Annual Emissions Associated with Operation of Marine Vessels Outside the

Security Zone....................................................................................................... 4-114

Table 4.11-11 Short-Term Emissions Associated with Operation of Marine Vessels within the

Security Zone....................................................................................................... 4-114
Environmental Impact Statement xii Corpus Christi LNG

Table 4.11-12 Annual Emissions Associated with Operation of the Sinton and Taft Compressor

Stations ................................................................................................................ 4-116

Table 4.11-13 Short-Term Emissions Associated with Operation of the Sinton Compressor

Station.................................................................................................................. 4-117

Table 4.11-14 Terminal - SIL Analysis Modeling Results ................................................... 4-119

Table 4.11-15 Terminal - Cumulative NAAQS Analysis Results......................................... 4-119

Table 4.11-16 Terminal - SO2 NAAQS Analysis Modeling Results .................................... 4-122

Table 4.11-17 Terminal - State Property Line Standards Modeling Results ......................... 4-122

Table 4.11-18 Terminal - State Effects Evaluation Modeling Results .................................. 4-123

Table 4.11-19Sinton Compressor Station –SIL Analysis Modeling Results ....................... 4-123

Table 4.11-20 Sinton Compressor Station - Cumulative NAAQS Analysis Results ............. 4-124

Table 4.11-21 Sinton Compressor Station - PSD Increment Consumption Modeling Results .......

............................................................................................................................ 4-124

Table 4.11-22 Terminal - Baseline Measurement Results .................................................... 4-126

Table 4.11-23 Compressor Stations - Baseline Measurement Results .................................. 4-131

Table 4.11-24 HDD Locations - Baseline Measurement Results.......................................... 4-134

Table 4.11-25 Summary of HDD Acoustic Modeling Results............................................. 4-137

Table 4.11-26 Terminal Operational Noise Impact Results.................................................. 4-138

Table 4.11-27 Operational Noise Impact Results - Compressor Stations.............................. 4-140

Table 4.12-1 Toxicity Levels (in ppm), ............................................................................... 4-148

Table 4.12-2 Flammable Properties ..................................................................................... 4-150

Table 4.12-3 Cheniere Responses Indicating Features to be Included in the Final Design of the

Projects ................................................................................................................ 4-156

Table 4.12-4 Impoundment Area Sizing .............................................................................. 4-172

Table 4.12-5 LNG Design Spills ......................................................................................... 4-178

Table 4.12-6 Other Hazardous Design Spills ....................................................................... 4-180

Table 4.12-7 Overpressure Scenarios .................................................................................. 4-184

Table 4.12-8 Thermal Radiation Exclusion Zones for Impoundment Basins ........................ 4-187

Table 4.12-9Natural Gas Transmission Pipeline Significant Incidents by Cause ................. 4-204

Table 4.12-10 Outside Forces Incidents by Cause................................................................ 4-205

Table 4.12-11 Injuries and Fatalities - Natural Gas Transmission Pipelines ......................... 4-206

Table 4.12-12 Nationwide Accidental Deaths a/ .................................................................. 4-207
Environmental Impact Statement xiii Corpus Christi LNG

TECHNICAL ACRONYMSAND ABBREVIATIONS

°F degrees Fahrenheit

μPa micropascal

μg/Sm

3 microgram per standard cubic meter

% vol percent by volume

AAV ambient air vaporizer

ACHP Advisory Council on Historic Preservation

AEP American Electric Power, Inc.

AEGL Acute Exposure Guideline Level

AMSL above mean sea level

APE area of potential effect

API American Petroleum Institute

AQCR Air Quality Control Region

ARMP Aquatic Resources Mitigation Plan

ASCE American Society of Civil Engineers

ASME American Society of Mechanical Engineers

ATWS additional temporary workspace

BA biological assessment

BACT Best Available Control Technology

Bcf billion cubic feet

Bcf/d billion cubic feet per day

BIA Bureau of Indian Affairs

BLEVE boiling-liquid-expanding-vapor explosion

BMP best management practice

BOG boil-off gas

BTEX benzene, toluene, ethylbenzene, and xylene

BTU/ft2-hr British thermal units per square foot per hour

CAA Clean Air Act

CAAA Clean Air Act Amendments

CAMx Comprehensive Air Quality Model with Extensions

Cameron LNG Cameron LNG, LLC

CCMSA Corpus Christi Metropolitan Statistical Area
Environmental Impact Statement xiv Corpus Christi LNG

CCS carbon capture and storage

CE FLNG CE FLNG, LLC

CEQ Council on Environmental Quality

CFR Code of Federal Regulations

CH4 methane

Cheniere Corpus Christi Liquefaction, LLC and Cheniere Corpus Christi Pipeline,

L.P.

CO carbon monoxide

CO2 carbon dioxide

CO2e carbon dioxide equivalent

Coast Guard U.S. Coast Guard

Commission Federal Energy Regulatory Commission

COE U.S. Army Corps of Engineers

COTP Captain of the Port

Crosstex Crosstex Corpus Christi Natural Gas Transmission

CWA Clean Water Act

CZMA Coastal Zone Management Act of 1972

CZMP Coastal Zone Management Program

dB decibel

dBA A-weighted decibel

DCS Distributed Control System

DMPA dredge material placement area

DOE U.S. Department of Energy

DOI U.S. Department of the Interior

DOT U.S. Department of Transportation

DRI direct iron reduced

DRS Dispute Resolution Service

E1AB estuarine submerged aquatic bed

E2EM estuarine intertidal emergent

E2FL estuarine intertidal flats

E2SS estuarine intertidal scrub/shrub

EEZ Exclusive Economic Zone

EFH essential fish habitat
Environmental Impact Statement xv Corpus Christi LNG

EI Environmental Inspector

EIS Environmental Impact Statement

ELS Excelerate Liquefaction Solutions, LLC

EOS Eos LNG, LLC

EPA Environmental Protection Agency

EPAct 2005 Energy Policy Act of 2005

ERDC Engineering Research and Development Center

ERL Effects Range Low

ERP Emergency Response Plan

ERPG Emergency Response Planning Guideline

ESA Endangered Species Act of 1973

ESD Emergency Shutdown

FAA Federal Aviation Administration

FDCP Fugitive Dust Control Plan

FE Fossil Energy

FEED Front End Engineering Design

FEMA Federal Emergency Management Administration

FERC Federal Energy Regulatory Commission

FHR Flint Hills Resources Corpus Christi, LLC

FIP Federal Implementation Plan

FLEX Freeport LNG Expansion, LP and FLNG Liquefaction, LLC

FLNG floating liquefied natural gas

FLSO Floating Liquefaction Storage Offloading

FR Federal Register

Freeport LNG Freeport LNG Development, LP

ft3cubic feet

FWS U.S. Fish and Wildlife Service

g gravity

Gasfin Gasfin Development USA, LLC

GCRA Global Change Research Act of 1990

GHG greenhouse gas

GIWW Gulf Intracoastal Waterway

Golden Pass Golden Pass Products, LLC
Environmental Impact Statement xvi Corpus Christi LNG

gpm gallons per minute

Gulf LNG Gulf LNG Energy, LLC

Gulf Coast LNG Gulf Coast LNG Export, LLC

Gulf South Gulf South Pipeline Company, L.P.

GWP Global warming potential

H2S hydrogen sulfide

HAP hazardous air pollutants

HAZOP hazard and operability review

HCA high consequence areas

HDD horizontal directional drill

hp horsepower

HRC Heavies Removal Column

IEA International Energy Agency

IMO International Maritime Organization

IPCC Intergovernmental Panel on Climate Change

ISA International Society for Automation

ISD Independent School District

kPa Kilopascal

kW/m2kilowatt per square meter

lb/hr pound per hour

lb/MWh pounds per megawatt-hour

lb/y pounds per year

Ld day-time sound level

Ldn day-night average sound level

Leq equivalent sound level

LFL lower flammable limit

LNG liquefied natural gas

LOR Letter of Recommendation

LPG liquid petroleum gas

M&R meter and regulator

m

3

cubic meters

MACT Maximum Achievable Control Technology

MAOP maximum allowable operating pressure
Environmental Impact Statement xvii Corpus Christi LNG

mcy million cubic yards

Memorandum Memorandum of Understanding on Natural Gas Transportation Facilities

mg/L milligrams per liter

MLV mainline valves

MMBtu million British thermal units

MP milepost

MRR Mandatory Greenhouse Gas Reporting Rule

MSA Magnuson-Stevens Fishery Conservation and Management Act of 1976

mtpa million tons per annum

mtpy million tons per year

MTSA Maritime Transportation Security Act of 2002

MW megawatt

N2O nitrous oxide

NAAQS National Ambient Air Quality Standards

NAISA National Aquatic Invasive Species Act of 2003

NANPCA Nonindigenous Aquatic Nuisance Prevention and Control Act of 1990

NAVD 88 North American Vertical Datum of 1988

NEPA National Environmental Policy Act of 1969

NESHAP National Emission Standards for Hazardous Air Pollutants

NFIA National Flood Insurance Act of 1968

NFPA National Fire Protection Association

NGA Natural Gas Act

NGL natural gas liquids

NGPL Natural Gas Pipeline Company, LLC

NGVD29 National Geodetic Vertical Datum of 1929

NHPA National Historic Preservation Act of 1966

nm nautical mile

NOAA National Oceanic and Atmospheric Administration

NOAA Fisheries National Oceanic and Atmospheric Administration National Marine

Fisheries Service

NOI Notice of Intent

NOx Nitrogen oxides

NO2 Nitrogen dioxide
Environmental Impact Statement xviii Corpus Christi LNG

NPDES National Pollutant Discharge Elimination System

NRCS Natural Resource Conservation Service

NRHP National Register of Historic Places

NSA noise sensitive areas

NSPS New Source Performance Standards

NSR New Source Review

O3 Ozone

OEP Office of Energy Projects

Offshore Wind Offshore Wind Power Systems of Texas, LLC

OSBL outside battery limit

OSHA Occupational Safety and Health Administration

OxyChem Occidental Chemical Corporation

P&IDs Piping and Instrument Diagrams

PCL protective concentration level

PEM palustrine emergent

PFD process flow diagram

PHMSA Pipeline and Hazardous Materials Safety Administration

Pipeline new bi-directional natural gas pipeline

Plan Upland Erosion Control, Revegetation, and Maintenance Plan

PM particulate matter

PM2.5 particulate matter with an aerodynamic diameter less than or equal to 2.5

microns

PM10 particulate matter with an aerodynamic diameter less than or equal to 10

microns

POCCA Port of Corpus Christi Authority

ppb part per billion

ppm part per million

ppm-v parts per million by volume

Procedure Wetland and Waterbody Construction and Mitigation Procedures

Project Corpus Christi LNG Project

PSD prevention of significant deterioration

psf pounds per square foot

psi pounds per square inch
Environmental Impact Statement xix Corpus Christi LNG

psig pounds per square inch gauge

PSM Process Safety Management of Highly Hazardous Chemicals, Explosives

and Blasting Agents

PTE potential to emit

RACT Reasonably Available Control Technology

RHA Rivers and Harbors Act

Royal Royal Production Company

RRC Railroad Commission of Texas

RPT rapid phase transition

RSZ reduced speed zone

RV recreational vehicle

Sabine Pass LNG Sabine Pass LNG, LP

SAV Submerged Aquatic Vegetation

SEP surface emissive power

SH State Highway

SHPO Texas State Historic Preservation Office

SILs Significant impact levels

SIP State Implementation Plan

SIS Safety Implemented System

SO2 sulfur dioxide

SPCC Spill Prevention, Control, and Countermeasure

SWPPP Stormwater Pollution Prevention Plan

TAC Texas Administrative Code

TCEQ Texas Council on Environmental Quality

Tejas Kinder Morgan Tejas Pipeline LLC

Tennessee Gas Tennessee Gas Pipeline Company, LLC

Terminal LNG export and import facility

Texas Eastern Texas Eastern Transmission, LP

TGLO Texas General Land Office

THC Texas Historical Commission

TPCO Tianjin Pipe Corporation

TPWD Texas Parks and Wildlife Department

tpy tons per year
Environmental Impact Statement xx Corpus Christi LNG

Transco Transcontinental Gas Pipe Line Company, LLC

Trunkline LNG Trunkline LNG Company, LLC

TxDOT Texas Department of Transportation

UFL upper flammable limit

US United States Highway

USC United States Code

USDA U.S. Department of Agriculture

USGCRP U.S. Global Change Research Program

USGS U.S. Geological Survey

VOC volatile organic compounds

Waller Waller Point LNG

WSA Waterway Suitability Assessment

EXECUTIVE SUMMARY

Environmental Impact Statement ES-1 Corpus Christi LNG

EXECUTIVE SUMMARY

The staff of the Federal Energy Regulatory Commission (FERC or Commission)

prepared this draft Environmental Impact Statement (EIS)to assess the environmental issues

associated with the construction of facilities proposed by Corpus Christi Liquefaction, LLC and

Cheniere Corpus Christi Pipeline, LP, which are collectively referred to as Cheniere. The draft

EIS was prepared in accordance with the requirements of the National Environmental Policy Act

of 1969 (NEPA)and its implementing regulations under Title 18 of the Code of Federal

Regulations, Part 380 (18 CFR 380). On August 31, 2012, Cheniere filed an application with the

FERC in Docket Numbers CP12-507-000 and CP12-508-000 pursuant to Section 3(a)and

Section 7 of the Natural Gas Act (NGA)and Parts 153, 157, and 284 of the Commission’s

regulations. This project is referred to as the Corpus Christi LNG Project (Project)and consists

of both a liquefied natural gas (LNG)terminal and natural gas pipeline facilities.

The purpose of this EIS is to inform the FERC decision-makers, the public, and the

permitting agencies about the potential adverse and beneficial environmental impacts of the

proposed Project and its alternatives, and recommend mitigation measures that would reduce

adverse impacts to the extent practicable. We2prepared our analysis based on information

provided by Cheniere and further developed from data requests, field investigations, scoping,

literature research, and contacts with or comments from federal, state, and local agencies, Native

American tribes, and individual members of the public.

The FERC is the federal agency responsible for authorizing interstate natural gas

transmission facilities under the NGA, and is the lead federal agency for the preparation of this

EIS in compliance with the requirements of NEPA. The U.S. Army Corps of Engineers (COE),

U.S. Coast Guard (Coast Guard), U.S. Department of Energy (DOE), U.S. Environmental

Protection Agency (EPA), and U.S. Department of Transportation (DOT)are cooperating

agencies for the development of this EIS consistent with 40 CFR 1501.6(b). A cooperating

agency has jurisdiction by law or has special expertise with respect to environmental resource

issues associated with the Project.

PROPOSED ACTION

According to Cheniere, the Project would provide facilities necessary to import, export,

store, vaporize, and liquefy natural gas and deliver the resulting product either into existing

interstate and intrastate natural gas pipelines in the Corpus Christi area, or export LNG

elsewhere.

Terminal

Cheniere would construct the LNG import and export terminal (Terminal)on a 991-acre

site located along the northern shore of Corpus Christi Bay at the north end of the La Quinta

Channel in San Patricio and Nueces Counties, Texas. The Terminal would include the following

key facilities:

 liquefaction facilities, including three liquefaction trains capable of producing 782

million British thermal units (MMBtu)per year of LNG;

2 “We,”“us,”and “our”refer to the environmental staff of the FERC’s Office of Energy Projects.
Environmental Impact Statement ES-2 Corpus Christi LNG

 vaporization facilities, including two trains of ambient air vaporizers (AAV)and

send out pumps capable of vaporizing sufficient LNG volume for each to send out

200 MMBtu per day of natural gas;

 LNG storage facilities, including three LNG storage tanks each capable of storing

160,000 cubic meters of LNG;and

 marine terminal facilities with two LNG carrier berths.

Pipeline

Cheniere proposes to construct and operate about 23 miles of 48-inch-diameter natural

gas pipeline (Pipeline)and two compressor stations, the Taft Compressor Station (12,260

horsepower)and the Sinton Compressor Station (41,000 horsepower). Additional ancillary

facilities include six meter and regulator stations installed at the Terminal as well as

interconnects with Texas Eastern Transmission, L.P.;Kinder Morgan Tejas Pipeline, LLC;

Natural Gas Pipeline Company, LLC;Transcontinental Gas Pipe Line Company, LLC;and

Tennessee Gas Pipeline Company, LLC. Cheniere would install five mainline valves along the

pipeline route, including a pig3launcher and receiver at the beginning and end of the pipeline,

respectively.

PUBLIC INVOLVMENT

On December 22, 2011, the FERC began its pre-filing review of Cheniere’s Project and

established the pre-filing Docket Number PF12-3-000 to place information related to the Project

into the public record. As part of the pre-filing process, Cheniere sponsored a public open house

in Portland, Texas on February 28, 2012. The purpose of the open house was to provide affected

landowners, government and agency officials, and the general public with information about the

Project and to give them an opportunity to ask questions and express their concerns. We

participated in the open house and provided information regarding the Commission’s

environmental review process to interested stakeholders.

On June 1, 2012, the FERC issued a Notice of Intent to Prepare an Environmental Impact

Statement for the Planned Corpus Christi LNG Terminal and Pipeline Project, Request for

Comments on Environmental Issues, and Notice of Public Scoping Meeting. This notice was sent

to about 500 interested parties including federal, state, and local officials;agency representatives;

conservation organizations;Native American tribes;local libraries and newspapers in the Project

area;and property owners in the vicinity of the proposed Project facilities. On June 26, 2012, we

conducted a site visit and held a public scoping meeting in Portland, Texas to provide an

opportunity for the public to learn more about the Project and to provide oral comments on

environmental issues to be addressed in the EIS.

Additionally, we initiated consultations with federal and state agencies to identify issues

that should be addressed in the EIS. We conducted an interagency meeting for the Project on

June 27, 2012 in Corpus Christi, Texas.

Through the scoping and agency comment process, we received comments on a variety of

environmental issues. We continued to receive and consider public comments during the entire

pre-filing period and throughout development of this EIS. Substantive environmental issues

3 A pipeline “pig”is an internal device to clean or inspect the pipeline. A pig launcher/receiver is an aboveground

facility where pigs are inserted into or retrieved from the pipeline.
Environmental Impact Statement ES-3 Corpus Christi LNG

identified through this public review process are addressed in this EIS. The transcripts of the

public scoping meeting and all written comments are part of the FERC’s public record for the

Project and are available for viewing under the Project docket numbers. 4,5

PROJECT IMPACTS

We evaluated the potential impacts of construction and operation of the Project on

geology;soils;water use and quality;wetlands;vegetation;wildlife, aquatic resources, and

essential fish habitat (EFH);threatened, endangered, and special status species;land use,

recreation, and visual resources;socioeconomics;cultural resources;air quality and noise;

reliability and safety;and cumulative impacts. Where necessary, we are recommending

additional mitigation to minimize or avoid these impacts. Section 5.3 of the EIS contains a

compilation of our recommendations.

Overall, construction of the Project facilities would temporarily disturb approximately

1,412 acres for construction, including extra temporary workspaces, contractor yards, access

roads, and aboveground facilities. About 647 acres would be retained as permanent easements

for operation of the facilities. Cheniere would allow the remaining 765 acres to return to

preconstruction uses.

Construction of the Terminal would result in permanent impacts on about 469acres of

open land and open water. All affected land areas would be permanently converted to industrial

land. The 23-mile pipeline right-of-way would be collocated with existing right-of-way

corridors to the extent practicable (about 86 percent of the total length. Construction of the

pipeline would impact about 421 acres of agricultural, open, and industrial land, but we have

determined that impacts would not be significant as the majority of the area disturbed by the

pipeline is within agricultural areas and would return to preconstruction conditions soon after

construction is complete.

Regarding federally listed threatened and endangered species, on October 29, 2012,

National Oceanic and Atmospheric Administration National Marine Fisheries Service notified

Cheniere that initiation of Section 7 consultation would not be required;and in letters dated

August 8, 2013 and November 5, 2013, the U.S. Fish and Wildlife Service (FWS)concurred

with determinations that the Project is not likely to adversely affect species under its

jurisdiction. Additionally, no traditional cultural resources, burials, or sites of religious

significance to Indian tribes were identified and no historic properties would be affected in areas

that have been inventoried. The State Historic Preservation Office concurred with this

determination in a letter dated July 3, 2012. Furthermore, to ensure our responsibilities under

Section 106 of the National Historic Preservation Act are met, we are recommending that

Cheniere should not begin construction of facilities until all cultural resource surveys have been

completed and filed. Based on our analysis, scoping, and agency consultations, the major issues

are impacts on aquatic resources, including EFH and wetlands;air quality and noise;safety and

reliability;and cumulative impacts.

4 Transcript of the public scoping meeting for the Project (Docket No. PF12-3-000, Accession No. 20120626-4008)

is available on the FERC website at http://ferc.gov/docs-filing/elibrary.asp.

5 Comments submitted after the Project application was filed with the FERC are part of the public record for the

Project (Docket No. CP12-507-000 and CP12-508-000)and are available on the FERC website at

http://ferc.gov/docs-filing/elibrary.asp.
Environmental Impact Statement ES-4 Corpus Christi LNG

Wetlands and Aquatic Resources

Based on consultations with the National Oceanic and Atmospheric Administration, and

COE we determined that the proposed Terminal would impact wetlands and EFH. Although

construction of the marine berths at the Terminal would result in the loss and permanent

conversion of estuarine submerged aquatic seagrass beds, cordgrass salt marsh, emergent marsh,

vegetated sand flats, unvegetated sand flats, and unvegetated shallow water EFH, to deep water

habitat, the deep water habitat would recolonize with soft-bottom benthic organisms after

completion of dredging and would continue to provide a prey base for EFH species. To minimize

impacts on wetlands, EFH, and EFH species, Cheniere has reduced its work space requirements

and would user a hydraulic cutterhead dredge that would reduce sedimentation and turbidity.

Cheniere would further mitigate impacts on EFH by implementing its Aquatic Resources

Mitigation Plan. However, because the ARMP has not been approved by the COE we are

recommending that Cheniere file the final ARMP with the Secretary of the Commission prior to

construction

Air Quality and Noise

Most Project-related air emissions would be produced by operation of the Terminal and

the Sinton and Taft Compressor Stations. Cheniere would comply with all applicable air permit

requirements for those facilities. Multiple air dispersion modeling analyses, which included

LNG carriers and other nearby emission sources, demonstrated that operation of these facilities

would not result in an exceedance of the National Ambient Air Quality Standards at any location,

with the exception of nitrogen dioxide for the Terminal. An expanded analysis determined that

operation of the Terminal would not contribute significantly to exceedances of the 1-hour

nitrogen dioxide National Ambient Air Quality Standard. As a result, we conclude that the

Project would not result in a significant adverse impact on either the regional or local air quality.

Cheniere performed detailed noise assessments for each of the proposed horizontal

directional drilling locations. To mitigate significant noise impacts at several noise sensitive

areas, Cheniere has committed to performing all horizontal directional drilling activities, except

the pipe pullback, during daylight hours. During operation of the Project, potential noise impacts

would be limited to the vicinity of the Terminal and Sinton and Taft Compressor Stations. These

facilities would include design measures to minimize sound generation. The proposed facilities

with noise mitigation measures implemented are projected to comply with the FERC day-night

sound level criterion of 55 decibels on the A-weighted scale at the nearest noise sensitive areas.

We are also recommending that Cheniere conduct noise surveys during operation of each facility

to ensure that noise levels meet our criterion.

Safety and Reliability

We evaluated the safety of the proposed Terminal facility, the related LNG carrier transit,

and the sendout pipeline. As part of our evaluation of the Terminal, we performed a technical

review of the preliminary engineering design to ensure sufficient layers of protection would be

included in the facility designs to mitigate the potential for an incident that could impact the

safety of the public. The DOT reviewed the data and methodology Cheniere used to determine

the design spills from various leakage sources, including piping, containers, and equipment

containing hazardous liquids, and stated it has no objection to Cheniere’s methodology for

determining the candidate design spills used to establish the required siting for its proposed

Terminal. The Coast Guard reviewed the suitability of the Corpus Christi Ship Channel from the
Environmental Impact Statement ES-5 Corpus Christi LNG

entrance approach at Port Aransas to the La Quinta Junction and the entire length of La Quinta

Channel, and issued a letter of recommendation (LOR)indicating the waterway would be

suitable for the type and frequency of the marine traffic associated with the proposed project. In

addition, Cheniere would be required to comply with all regulations in 49 CFR 192 for its

pipeline and 33 CFR 105, 33 CFR 127, and 49CFR 193 for its Terminal facilities. Based on our

engineering design analysis and recommendations presented in section 4.12 for the Terminal, the

design spill methodology reviewed by DOT for the Terminal, the LOR issued by the Coast

Guard for the LNG carrier transit, and the regulatory requirements for the pipeline and Terminal,

we conclude that the Project would not result in significantly increased public safety risks.

Cumulative Impacts

We also conclude that the potential impact of the Project, when combined with the

impacts from the other projects considered, would not result in a significant impact on resources

within the cumulative impact areas. Although we recognize concurrent construction of the

proposed Project and other projects in the vicinity of the Terminal site would result in increased

workers in the area, periods of increased traffic, and impacts on public services, we are not

recommending additional mitigation at this time. Therefore, we have determined that with the

implementation of Cheniere’s mitigation measures, the impacts of the Project when added with

other projects’impacts would not result in significant cumulative impacts.

More detailed discussions of impacts on all resources affected by the Project, Cheniere’s

proposed mitigation, and our recommendations to avoid or further reduce impacts, are presented

in sections 4.0 and 5.0 of this EIS.

ALTERNATIVESCONSIDERED

We assessed alternatives that could achieve the Project objectives. The range of

alternatives analyzed included the No-Action Alternative, alternative energy sources, system

alternatives, alternative Terminal sites, alternative Pipeline routes, and alternative compressor

station sites. Alternatives were evaluated and compared to the Project to determine if these

alternatives were environmentally preferable to the proposed Project.

While the No-Action Alternative would avoid the environmental impacts identified in

this EIS, adoption of this alternative would also preclude meeting the Project objectives. If the

Project is not approved and built, the need could potentially be met by other LNG export and

import projects developed elsewhere in the Gulf Coast region or in other areas of the U.S.

Implementation of other LNG export/import projects would likely result in impacts similar to or

greater than those of the proposed Project.

We evaluated 12 system alternatives for the Terminal, including 6 operating LNG import

terminals in the Gulf of Mexico area, and 6 proposed or planned export projects along the Gulf

Coast. All of the systems were eliminated from further consideration for reasons that include the

need for substantial construction beyond that currently proposed, production volume limitations,

in-service dates scheduled significantly beyond Cheniere’s schedule, including any customer

commitments, and environmental impacts that were considered comparable to or greater than

those of the proposed Project.

We also evaluated three alternative Terminal sites, two in proximity to the proposed site

and one near Brownsville, Texas. Construction of the Terminal at each of the alternative sites
Environmental Impact Statement ES-6 Corpus Christi LNG

would have comparable or greater impacts when compared to the proposed Terminal site;

therefore, none of the three sites evaluated were determined to be environmentally preferable.

Approximately 86 percent of the pipeline would be collocated, overlap, or parallel

existing rights-of-way. As a result, many types of environmental impacts have been lessened.

Two route alternatives were evaluated; however, we did not identify any site-specific

environmental concerns along the proposed route that would drive the need to recommend the

alternative pipeline routes.

We evaluated a total of five alternative sites for the proposed compressor stations, but

determined that none of these sites were environmentally preferable to the proposed sites.

CONCLUSIONS

We conclude that if the Project is constructed and operated in accordance with applicable

laws and regulations, Cheniere’s proposed mitigation, and our recommendations presented in

section 5.3 of this EIS, it would result in some adverse environmental impacts;however, those

impacts would not be significant. The principal reasons for our decision include:

 the Terminal facilities are sited in an existing industrialized area;

 dredge material would be disposed of beneficially to cap bauxite disposal beds;

 impacts on wetlands and aquatic habitat, including EFH, would be mitigated per

Cheniere’s Aquatic Resources Mitigation Plan;

 adequate safety features would be incorporated into the design and operation of the

Terminal facilities;

 the proposed pipeline route would be collocated, overlap, or parallel existing rights-ofway;

 Cheniere would implement the FERC Upland Erosion Control, Revegetation, and

Maintenance Plan and Wetland and Waterbody Construction and Mitigation Procedures

to minimize construction impacts on soils, wetlands, and waterbodies;

 the use of the horizontal directional drilling method for crossing major waterbodies

would avoid disturbances to the beds and banks of these waterbodies;

 the Project would have no effect or would be not likely to adversely affect any federally

or state listed threatened or endangered species;

 the Project would have no effect on cultural resources;

 all appropriate consultations with the U.S. Fish and Wildlife Service, Texas Department

of Wildlife and Fisheries, and National Oceanic and Atmospheric Administration,

National Marine Fisheries Service would be completed before construction is allowed to

start;and

 the FERC’s environmental and engineering inspection and mitigation monitoring

program for this Project would ensure compliance with all mitigation measures and

conditions of any FERC Authorization.

In addition, we developed site-specific mitigation measures that Cheniere should

implement to further reduce the environmental impacts that would otherwise result from
Environmental Impact Statement ES-7 Corpus Christi LNG

construction of the Project. We are recommending these mitigation measures, presented in

section 5.3 of this EIS, be attached as conditions to any authorization issued by the Commission

for this Project.

INTRODUCTION

SECTION 1

Environmental Impact Statement 1-1 Corpus Christi LNG

1.0 INTRODUCTION

The staff of the Federal Energy Regulatory Commission (FERC or Commission)

prepared this draft Environmental Impact Statement (EIS)to describe our assessment of the

potential environmental impacts that may occur from constructing and operating the Corpus

Christi Liquefaction, LLC’s and Cheniere Corpus Christi Pipeline, L.P.’s liquefied natural gas

(LNG)import and export terminal and associated natural gas pipeline in Nueces and San Patricio

Counties, Texas (collectively referred to as the Corpus Christi LNG Project or Project).

On August 31, 2012, Corpus Christi Liquefaction, LLC filed an application with the

FERC, in Docket No. CP12-507-000, under Section 3(a)of the Natural Gas Act (NGA)and

under Title 18 of the Code of Federal Regulations (CFR), Parts 153 and 380 of the

Commission’s regulations to construct and operate LNG import and export facilities. On the

same day, Cheniere Corpus Christi Pipeline, L.P. also filed an application with the FERC in

Docket No. CP12-508-000, under Section 7(c)of the NGA and 18 CFR Parts 157, 284, and 380

of the Commission’s regulations. These applications were noticed in the Federal Register (FR)

on September 14, 2012.

Corpus Christi Liquefaction, LLC and Cheniere Corpus Christi Pipeline, L.P. are both

subsidiaries of Cheniere Inc. (hereafter collectively referred to as Cheniere). As part of the

Commission’s consideration of these applications, we6prepared this EIS to assess the potential

environmental impacts resulting from construction and operation of the proposed Project in

accordance with the National Environmental Policy Act of 1969(NEPA).

1.1 REGULATORY BACKGROUND

Cheniere initially filed an application with the FERC in Docket Nos. CP04-37-000,

CP04-44-000, CP04-45-000, and CP04-46-000 on December 22, 2003, seeking Commission

approvals under Sections 3 and 7 of the NGA to construct and operate a LNG import terminal

and associated natural gas pipeline at the Project site. The Commission issued a final EIS on

March 3, 2005. Cheniere received an authorization under Docket No. CP04-37-000 on April 18,

2005. On June 8, 2012, the Commission issued an Order vacating the authorization to construct

the facilities since Cheniere did not construct the facilities in its authorized timeframe.

In this revised proposed Project, Docket Nos. CP12-507-000 and CP12-508-000,

Cheniere seeks authorization to construct and operate an LNG export and import facility

(Terminal)at the site of the previously authorized Corpus Christi import terminal. In addition,

Cheniere seeks authority for: a Certificate of Public Convenience and Necessity (Certificate), to

authorize the construction and operation of a new bi-directional natural gas pipeline (Pipeline), to

be located along the same route as was previously authorized;a blanket certificate authorizing

Cheniere to engage in certain self-implementing routine activities under 18 CFR Part 157,

Subpart F, of the Commission’s regulations;and a blanket certificate authorizing Cheniere to

transport natural gas, on an open access and self-implementing basis, under 18 CFR Part 284,

Subpart G of the Commission’s regulations. The new Pipeline would extend from the Terminal

to north of Sinton, Texas, and be capable of transporting up to a maximum of 2.25 billion cubic

feet per day (Bcf/d)of natural gas to markets throughout the United States or to the Terminal, via

interconnections with a number of existing interstate pipeline systems.

6 “We”, “us”, and “our”refer to the environmental staff of the FERC’s Office of Energy Projects.
Environmental Impact Statement 1-2 Corpus Christi LNG

Figure 1.1-1 shows the general location of the proposed facilities, figure 1.1-2 shows an

artist’s rendering of the proposed Terminal facilities, and the Terminal boundary is shown in

figure 1.1-3. Pipeline alignment sheets for the Project are provided in appendix A.
Environmental Impact Statement 1-3 Corpus Christi LNG

Figure 1.1-1 Corpus Christi LNG Project General Location
Environmental Impact Statement 1-4 Corpus Christi LNG

Figure 1.1-2 Artist Impression of Proposed Terminal Facilities
Environmental Impact Statement 1-5 Corpus Christi LNG

Figure 1.1-3 Terminal Facilities Boundary
Environmental Impact Statement 1-6 Corpus Christi LNG

1.2 PROJECT PURPOSE AND NEED

Cheniere states that the purpose of the Project is to provide facilities necessary to import,

export, store, vaporize, and liquefy natural gas and deliver the resulting product either into

existing interstate and intrastate natural gas pipelines in the Corpus Christi area, or export LNG

elsewhere. Depending on market dynamics, the Project would enable LNG to be imported,

vaporized, and sent out for delivery to U.S. consumers, or the liquefaction facilities would allow

the export of natural gas as LNG to other countries for consumption.

Section 3 of the NGA, as amended, requires that authorization be obtained from the U.S.

Department of Energy (DOE)prior to importing or exporting natural gas, including LNG, from

or to a foreign country. For applicants that have, or intend to have, a signed gas purchase or

sales agreement/contract for a period of time longer than two years, long-term authorization is

required. Under Section 3 of the NGA, the FERC considers, as part of its decision to authorize

natural gas facilities, all factors bearing on the public interest. Specifically, regarding whether to

authorize natural gas facilities for importation or exportation, the FERC shall authorize the

proposal unless it finds that the proposed facilities will not be consistent with the public interest.

Under Section 7(c)of the NGA, the Commission determines whether interstate natural

gas transportation facilities are in the public convenience and necessity, and if so, grants a

Certificate to construct and operate them. The Commission bases its decisions on technical

competence, financing, rates, market demand, gas supply, environmental impact, long-term

feasibility, and other issues concerning the proposed Project.

1.3 PURPOSE AND SCOPE OFTHE EIS

The EIS describes the affected environment as it currently exists, the environmental

consequences of the Project, and compares the Project’s potential impact with various

alternatives. The EIS also presents our conclusions and recommended mitigation measures. The

FERC would use the EIS as an element in its review of Cheniere’s applications to determine

whether to authorize the Project.

Our principal purposes in preparing this EIS are to:

 identify and assess potential impacts on the human environment that would result from

the implementation of the proposed action;

 identify and assess reasonable alternatives to the proposed action that would avoid or

minimize adverse impacts on the human environment;

 identify and recommend specific mitigation measures to minimize environmental

impacts;and

 facilitate public involvement in identifying significant environmental impacts on specific

resources.

Topics addressed in this EIS include alternatives;geology;soils and sediments;water

resources;wetlands;vegetation;wildlife and aquatic resources;threatened, endangered, and

other special status species; land use, recreation, and visual resources; socioeconomics;

transportation and traffic;cultural resources;air quality and noise;reliability and safety;and

cumulative impacts. Our analysis in this EIS focuses on facilities that are under the

Commission’s jurisdiction (i.e., the proposed Terminal and Pipeline). Minor non-jurisdictional
Environmental Impact Statement 1-7 Corpus Christi LNG

facilities would also be constructed and abandoned in association with the Project (see section

1.5).

When considering the environmental consequences of constructing and operating the

Project, the duration and significance of any potential impacts are described according to the

following four levels:

 Temporary impacts generally occur during construction, with the resources returning to

preconstruction conditions almost immediately after construction;

 Short-term impacts could continue for approximately 3 years following construction;

 Long-term impacts would require more than 3 years to recover, but eventually would

recover to preconstruction conditions;and

 Permanent impacts could occur as a result of activities that modify resources to the

extent that they may not return to preconstruction conditions during the life of the Project

such as with the construction of an aboveground facility.

1.3.1 Federal EnergyRegulatoryCommission Purpose and Role

The FERC is the federal agency responsible for authorizing onshore LNG facilities. As

such, the FERC is the lead federal agency for the preparation of this EIS in compliance with the

requirements of the NEPA, the Council on Environmental Quality (CEQ)regulations for

implementing the NEPA (40 CFR 1500-1508), and the FERC regulations for implementing the

NEPA (18 CFR 380).

Several agencies are cooperating agencies for the development of this EIS. A

cooperating federal agency has jurisdiction by law or special expertise with respect to

environmental impacts associated with the proposal, and is involved in the NEPA analysis.

Cooperating agencies for the Project include: the U.S. Army Corps of Engineers (COE), U.S.

Coast Guard (Coast Guard), U.S. Department of Transportation (DOT), U.S. Environmental

Protection Agency (EPA), and DOE.

FERC consulted with the cooperating agencies throughout the pre-filing and the

application phases of the Project. The cooperating agencies provided input on the Project during

several conference calls and an interagency scoping meeting held on June 27, 2012 in order to

solicit comments and concerns regarding the Project. Agency representatives also participated in

the public scoping meeting held on June 26, 2012. The cooperating agencies had the opportunity

to comment on the preliminary draft EIS. FERC consulted with those agencies about their

comments and incorporated them into this EIS.

1.3.2 U.S. ArmyCorps of Engineers Purpose and Role

The COE has jurisdictional authority pursuant to Section 404 of the Clean Water Act

(CWA)(Title 33 of the United States Code [USC], Section 1344 [33 USC 1344]), which governs

the discharge of dredged or fill material into waters of the U.S., and Section 10 of the Rivers and

Harbors Act (RHA)(33 USC 403), which regulates any work or structures that potentially affect

the navigable capacity of a waterbody. Because the COE would need to evaluate and approve

several aspects of the Project and must comply with the requirements of NEPA before issuing

permits under the above statutes, it has elected to participate as a cooperating agency in the

preparation of this EIS. The COE would adopt the EIS per 40 CFR 1506.3 if, after an
Environmental Impact Statement 1-8 Corpus Christi LNG

independent review of the document, it concludes that the EIS satisfies the COE’s comments and

suggestions. The Project occurs within the Galveston District of the COE. Staff from this COE

district participated in the NEPA review and would evaluate COE authorizations, as applicable.

The primary decisions to be addressed by the COE include:

 issuance of a Section 404 Permit for wetland impacts associated with construction of the

Pipeline and Terminal;and

 issuance of Section 10 Permit for construction activities within navigable waters of the

U.S.

This EIS contains information needed by the COE to reach decisions on these issues.

Through the coordination of this document, the COE would obtain the views of the public and

natural resource agencies prior to reaching the COE’s decisions on the Project.

As an element of its review, the COE must consider whether a proposed project avoids,

minimizes, and compensates for impacts on existing aquatic resources, including wetlands, to

strive to achieve a goal of no overall net loss of values and functions. Based on its participation

as a cooperating agency and its consideration of the EIS (including responses to public

comments), the COE would issue a Record of Decision to formally document its decision on the

proposed action, including Section 404 (b)(1)analysis and required environmental mitigation

commitments.

1.3.3 U.S. Coast Guard Purpose and Role

The Coast Guard is the federal agency responsible for determining the suitability of

waterways for LNG marine traffic. The Coast Guard exercises regulatory authority over LNG

facilities that affect the safety and security of port areas and navigable waterways under

Executive Order 10173, the Magnuson Act (50 USC 191), the Ports and Waterways Safety Act

of 1972, as amended (33 USC 1221, et seq.), and the Maritime Transportation Security Act of

2002 (MTSA)(46 USC 701). The Coast Guard is responsible for matters related to navigation

safety, vessel engineering and safety standards, and all matters pertaining to the safety of

facilities or equipment in or adjacent to navigable waters up to the last valve immediately before

the receiving tanks. The Coast Guard also has authority for LNG facility security plan reviews,

approval and compliance verification as provided in 33 CFR 105, and siting as it pertains to the

management of vessel traffic in and around LNG facilities to a point 12 nautical miles (nm)

seaward from the coastline (to the territorial seas).

As required by its regulations, the Coast Guard is responsible for issuing a Letter of

Recommendation (LOR)as to the suitability of the waterway for LNG marine traffic following a

Waterway Suitability Assessment (WSA). In a letter dated March 21, 2013, the Coast Guard

issued a LOR for the Project. In the LOR the Coast Guard stated that after reviewing the WSA,

they recommend that the Corpus Christi Ship Channel from the entrance approach at Port

Aransas to the La Quinta Junction and the entire length of the La Quinta Channel be considered

suitable for LNG marine traffic.

1.3.4 U.S. Department of Transportation Purpose and Role

The DOT has prescribed the minimum federal safety standards for LNG facilities in

compliance with 49USC 60101. Those standards are codified in 49CFR Part 193 and apply to
Environmental Impact Statement 1-9 Corpus Christi LNG

the siting, design, construction, operation, maintenance, and security of LNG facilities. The

National Fire Protection Association (NFPA)Standard 59A, Standard for the Production,

Storage, and Handling of Liquefied Natural Gas, is incorporated into these requirements by

reference, with regulatory preemption in the event of conflict. In accordance with the 1985

Memorandum of Understanding on LNG facilities and the 2004 Interagency Agreement on the

safety and security review of waterfront import/export LNG facilities, the DOT participates as a

cooperating agency and assists in assessing any mitigation measures that may become conditions

of approval for any project. DOT staff is reviewing our analysis and would provide comments

on our conclusions regarding compliance with Part 193 regulations.

1.3.5 U.S. Environmental Protection AgencyPurpose and Role

The EPA has delegated water quality certification, under Section 401 of the CWA, to the

jurisdiction of individual state agencies. The EPA may assume Section 401 authority if no state

program exists, if the state program is not functioning adequately, or at the request of the state.

The EPA also oversees the issuance of a National Pollutant Discharge Elimination System

(NPDES)permit by the state agency, under Section 402 of the CWA, for point-source discharge

of used water into waterbodies. In addition to its authority under the CWA, the EPA also has

jurisdictional authority under the Clean Air Act of 1970 (CAA)to control air pollution by

developing and enforcing rules and regulations for all entities that emit toxic substances into the

air. Under this authority, the EPA has developed regulations for major sources of air pollution,

and has delegated the authority to implement these regulations to state and local agencies. State

and local agencies are allowed to develop and implement their own regulations for non-major

sources of air pollutants.

In addition to its permitting responsibilities, the EPA is required under Section 309of the

CAA to review and publicly comment on the environmental impacts of major federal actions

including actions that are the subject of draft and final EISs, and responsible for implementing

certain procedural provisions of NEPA (e.g., publishing Notices of Availability of the draft and

final EISs)to establish statutory timeframes for the environmental review process.

1.3.6 U.S. Department of EnergyPurpose and Role

The DOE, Office of Fossil Energy must meet its obligation under Section 3 of the NGA

to authorize the import and export of natural gas, including LNG, unless it finds that the import

or export is not consistent with the public interest. The purpose and need for DOE action for the

current proposal is to respond to the August 31, 2012 application for authority to export LNG

from the Project filed by Cheniere with the Office of Fossil Energy (FE Docket No. 12-97-

LNG).

The DOE is conducting its review under Section 3 of the NGA to evaluate the Cheniere

application for long-term, multi-contract authorization to export up to 767 billion cubic feet per

year of domestic natural gas as LNG for a 25-year period, commencing the earlier of either the

date of first export or 10 years from the date of issuance of the requested authorization. Cheniere

seeks to export LNG from the Terminal to any country (1)with which the U.S. does not have a

free trade agreement requiring the national treatment for trade in natural gas and LNG;(2)that

has, or in the future develops, the capacity to import LNG;and (3)with which trade is not

prohibited by U.S. law or policy. In accordance with 40 CFR 1506.3, after an independent

review of the EIS, DOE may adopt the EIS prior to issuing a Record of Decision.
Environmental Impact Statement 1-10 Corpus Christi LNG

On October 16, 2012, in FE Docket No. 12-99-LNG, DOE issued DOE/FE Order No.

3164 granting Cheniere the authorization to export LNG by vessel from the Terminal to any

country which has or in the future develops the capacity to import LNG via ocean-going carrier

and with which the U.S. has, or in the future enters into, a free trade agreement requiring the

national treatment for trade in natural gas.

DOE has exclusive jurisdiction over the export of natural gas as a commodity. DOE has

delegated to the Commission authority to approve or disapprove the construction and operation

of particular facilities. The facilities are considered the site at which such facilities would be

located, and with respect to natural gas that involves the construction of new domestic facilities,

the place of entry for imports or exit for exports. However, the DOE Secretary has not delegated

to the Commission any authority to approve or disapprove the import or export of the commodity

itself as part of the Commission’s public interest determination. The Commission’s

authorization alone would not enable the export of any additional volumes of LNG.

1.4 PUBLIC REVIEW AND COMMENT

Cheniere initiated the FERC pre-filing process for the Project on December 13, 2011. On

December 22, 2011, the Commission staff granted Cheniere’s request to utilize the pre-filing

process and assigned Docket No. PF11-3-000 to staff activities involved with the Project. The

pre-filing process ended on August 31, 2012 when Cheniere submitted its applications to the

FERC. The pre-filing process allows the FERC staff to become involved with scoping of

environmental issues before the applicant files its application, thus overlapping the applicant’s

planning process with the FERC process.

During the pre-filing process, we conducted biweekly conference calls with Cheniere to

discuss Project progress and identify and address issues and concerns that had been raised.

Interested agencies were invited to participate on these calls. Summaries of biweekly conference

calls and written scoping comments are part of the public record for the Project and are available

for viewing on the FERC website (http://www.ferc.gov).

On February 28, 2012, the FERC staff participated in a visit to the proposed facility site.

Cheniere hosted an open house information session for landowners, agencies, and other

interested stakeholders on February 28, 2012 in Portland, Texas, which FERC staff also

participated in. The open house provided stakeholders the opportunity to learn about the Project

and ask questions in an informal setting. Notification of the open house was mailed to

stakeholders and published in local newspapers. Approximately 120 interested parties attended

the open house. On June 1, 2012, the FERC issued a Notice of Intent to Prepare an

Environmental Assessment for the Planned Corpus Christi LNG Terminal and Pipeline Project,

Request for Comments on Environmental Issues, and Notice of Public Scoping Meeting (NOI)7.

The NOI was sent to over 500 interested parties including federal, state, and local officials;

agency representatives;conservation organizations;local libraries and newspapers;property

owners along the proposed pipeline route, and interveners in the proceeding. There was a 30-day

comment period on the NOI which ended on July 2, 2012. We received 25 comments in

response to the NOI.

Of the 25 comments filed during the public scoping period, four were from state or

federal agencies, one was from a non-profit environmental group, and the remaining 20 were

7 Based on comments during scoping and Project impacts, we determined that an EIS would be more appropriate.
Environmental Impact Statement 1-11 Corpus Christi LNG

from adjacent landowners or individuals. The majority of comments indicated concerns

regarding water contamination, air quality, safety, outdoor recreation, fish and wildlife, visual

resources, and noise and light pollution. Commenters also expressed a preference that the FERC

prepare an EIS in lieu of an Environmental Assessment. Cheniere addressed all comments filed

during the public scoping period on July 16, 2012.

On June 26, 2012, the FERC conducted another site visit of the Terminal site and the

Pipeline route. That same day, the FERC conducted a public scoping meeting in Portland, Texas

to provide an opportunity for the public to learn more about the Project and provide comments

on environmental issues addressed in the EIS. Nine people provided verbal comments at the

scoping meeting and three individuals submitted written comments. A transcript of the scoping

meeting and all written comments provided at the meeting has been entered into the public

record for the Project, under Docket No. PF11-3-000.

On June 27, 2012, the FERC held an interagency scoping meeting to solicit comments

and concerns regarding the Project from other jurisdictional agencies. Representatives from

eight state and federal agencies were present including the COE, DOT, Coast Guard, U.S. Fish

and Wildlife Service (FWS), National Oceanic and Atmospheric Administration, National

Marine Fisheries Service (NOAA Fisheries), Railroad Commission of Texas (RRC), Texas

General Land Office (TGLO), and Texas Parks and Wildlife Department (TPWD).

On April 26, 2012, FERC staff issued a letter to the U.S. Department of Defense

requesting comments on whether the Project could potentially have an impact on the test,

training, or operational activities of any active military installation. To date, no military

installations have been identified as being potentially impacted.

Table 1.5-1 lists the environmental issues that were identified during the scoping process

described above, as well as comments received in response to our Notice of Application issued

September 14, 2012. Table 1.5-1 also indicates the section of this EIS in which each issue is

addressed. Additional issues that we independently identified are also addressed.

On October 16, 2012, April 30, 2013, and October 30, 2013, the FERC issued a Project

update to inform the public and agencies of the status of the FERC review process. This

document, as well as all documents and comments submitted as a part of the Project pre-filing

and application processes, are publically available online at www.ferc.gov/docsfiling/elibrary.asp.
Environmental Impact Statement 1-12 Corpus Christi LNG

Table 1.4-1

Issues Identified and Comments Received During the Scoping Process for the Corpus Christi LNG Project

Issue/Specific Comment EIS Section Addressing

Comment

General

Right of eminent domain 2.4.3

Spill contingency plan 2.4

Hurricane response plan 4.1.1.5

LNG capacity of ships 2.1.4.1

Alternatives

Alternative flare locations 3.1.5.1

Alternative facility locations 3.1.4

Renewable energy alternatives 3.1.2

Alternatives in production volumes/capacity 3.1.3.2

Water Resources

Water use during construction and operation, including source and discharges 4.3.1.2

Surface water and groundwater contamination 4.3

Waterbody crossings 4.3.2.2

Stormwater pollution 4.3.1.2 & 4.3.2.2

Hydrostatic testing 4.3.1.2 & 4.3.2.2

Turbidity and resuspension of bottom sediments 4.3.1.2

Ballast water 4.6.2.1

Wildlife and Aquatic Resources

Impacts of water discharges on aquatic species 4.6.2

Underwater noise/vibrations 4.6.2.1

Impacts from ship traffic on aquatic resources 4.6.2.1

Invasive species 4.6.2

Migratory birds 4.6.3

Habitat loss 4.6

Impacts of storage tanks on birds 4.6.3.1

Threatened and Endangered Species

Measures to avoid/minimize impacts on sensitive species 4.7.3

Land Use, Recreation, and Aesthetics

Light pollution 4.8.1.6

Impacts of storage tanks on visual resources 4.8.1.5

Impacts on outdoor recreation opportunities 4.8.1.3 & 4.8.2.3

Recreational fishing and boating 4.8.1.3 & 4.8.2.3

Changes in land use 4.8.1.6 & 4.8.2.6

Socioeconomics

Available workforce 4.9.2

Economic impacts of LNG exports 3.1.2

Economic impacts of domestic use of LNG 3.1.2

Property values 4.9.3
Environmental Impact Statement 1-13 Corpus Christi LNG

Table 1.4-1

Issues Identified and Comments Received During the Scoping Process for the Corpus Christi LNG Project

Issue/Specific Comment EIS Section Addressing

Comment

Insurance rates 4.9

Job growth 4.9.2

Natural gas prices 3.1.2

Transportation and Traffic

Safe navigation of ship channel 4.9.10.1

Impacts of increased ship traffic 4.9.10.1

Cultural Resources

Proximity to the Taft House and Native American historical site 4.10.2 & 4.10.4

Air Quality

Greenhouse gas emissions and mitigation 4.11.1.4

Attainment status 4.11.1.2

Dust mitigation 4.11.1.4

Impacts of emissions on human health 4.11.1.3

Increased coal production/use 3.1.2

Global oil and coal use 3.1.2

Noise

Impacts from noise during construction 4.11.2

Impacts from noise during operations 4.11.2

Reliability and Safety

Safety of flares 4.12.1

Emergency notification systems 4.12.1

Catastrophic system failures 4.12.1

Potential for terminal to be a terrorist target 4.12.1

Proximity to a densely populated area 4.12.1

Cumulative Impacts

Induced production 4.13.1

Impacts of increased natural gas production 4.13.1

Hydraulic fracturing 4.13.1

1.5 NON-JURISDICTIONAL FACILITIES

Under Section 7 of the NGA, the FERC is required to consider, as part of a decision to

authorize jurisdictional facilities, all facilities that are directly related to a proposed project where

there is sufficient federal control and responsibility to warrant environmental analysis as part of

the NEPA environmental review for the proposed project. Some proposed projects have

associated facilities that do not come under the jurisdiction of the Commission. These “nonjurisdictional”facilities may be integral to the need for the proposed facilities, or they may be

merely associated as minor components of jurisdictional facilities that would be constructed and

operated as a result of authorization of the proposed facilities.
Environmental Impact Statement 1-14 Corpus Christi LNG

The jurisdictional facilities for the Project include the Terminal and the Pipeline and are

discussed extensively throughout this EIS. Two non-jurisdictional facilities were identified in

association with the proposed Project: an electrical powerline and substations and a potable

waterline. These facilities are addressed below and are also addressed in our cumulative impacts

analysis in section 4.13 of this EIS. Figure 1.6-1 shows the locations of the non-jurisdictional

facilities to be constructed concurrent with the Terminal facilities. Both the electrical powerline

and the potable waterline would be constructed within the Utility/Access Easement. These nonjurisdictional facilities would be constructed in compliance with all applicable federal and state

regulations.
Environmental Impact Statement 1-15 Corpus Christi LNG

Figure 1.5-1 Locations of Non-Jurisdictional Facilities
Environmental Impact Statement 1-16 Corpus Christi LNG

1.5.1 Electrical Power Lines and Substations

An electrical power line extension and a substation would be required for construction

and operation power supply. An overhead power line would be extended from the junction of

State Highway (SH)35 and SH 361 to a new facilities substation located on approximately 11.6

acres of previously disturbed industrial, road, and utility corridor. The electrical substation

would be placed on a 4.8-acre lease at the south end of the power line easement. The overhead

power line and electrical substation would be designed, built, owned, and operated by American

Electric Power, Inc. (AEP), the local power transmission provider.

Cheniere would also design, build, own, and operate an underground power line that

would extend from the AEP substation to the facilities substation at the Terminal. The

underground power would be constructed within previously disturbed areas adjacent to La

Quinta Road and/or within the Terminal property. Environmental impacts associated with the

installation of the power lines and substations would be confined to existing, previously

disturbed industrial areas and would be negligible.

1.5.2 Waterline

The Project would require a pipeline connection to the San Patricio Municipal Water

District potable water system at the north end of La Quinta Road for site personnel and the

supply by pipeline of raw or semi-processed water to be used for Terminal operations. Examples

of use include: use as a feed source to the demineralized water system for injection into the gas

turbines for nitrogen dioxide control and for make-up of the amine unit;for humidification

equipment at the inlet to the gas turbine drivers;and potable water for the additional operation

and maintenance activities. Water use associated with the Project is further discussed in section

4.3 of this EIS. The waterline would be constructed within the same corridor as the power lines

discussed above and would be located entirely within previously disturbed areas, resulting in

negligible environmental impacts.

1.6 PERMITS,APPROVALS,AND REGULATORY REVIEWS

As the lead federal agency for the Project, the FERC is required to comply with various

federal environmental laws and regulations, including but not limited to, the Endangered Species

Act of 1973 (ESA), the Magnuson-Stevens Fishery Conservation and Management Act of 1976

(MSA), the RHA, the CWA, the CAA, the Federal Aviation Act of 1958, the NGA, the MTSA,

the National Historic Preservation Act of 1966 (NHPA), the Coastal Zone Management Act of

1972 (CZMA), and the National Flood Insurance Act of 1968 (NFIA). Each of these statutes has

been taken into account in the preparation of this document.

Major permits, approvals, and consultations for the Project are identified in table 1.6-1

and discussed below. The FERC encourages cooperation between applicants and state and local

authorities, but this does not mean that state and local agencies, through applications of state and

local laws, may prohibit or unreasonably delay the construction or operation of facilities

approved by the FERC. Any state or local permits issued with respect to jurisdictional facilities

must be consistent with the conditions of any authorization issued by the FERC.
Environmental Impact Statement 1-17 Corpus Christi LNG

1.6.1 Endangered Species Act

Section 7 of the ESA, as amended, states that any project authorized, funded, or

conducted by any federal agency (e.g., FERC)should not “... jeopardize the continued existence

of any endangered species or threatened species or result in the destruction or adverse

modification of habitat of such species which is determined... to be critical... ”(16 USC Section

1536(a)(2)(1988)). The FERC, or Cheniere as a non-federal party, is required to consult with the

FWS and NOAA Fisheries to determine whether any federally listed or proposed endangered or

threatened species or their designated critical habitat occur in the vicinity of the Project. If the

FERC determines that these species or habitats may be impacted by the Project, the FERC is

required to prepare a biological assessment (BA)to identify the nature and extent of adverse

impact, and to recommend measures to avoid or reduce potential impacts on habitat and/or

species. If, however, the FERC determines that no federally listed or proposed endangered or

threatened species or their designated critical habitat would be impacted by the Project, no

further action is necessary under the ESA (see section 4.7 of this EIS for the status of our

compliance with Section 7 of the ESA).

1.6.2 Magnuson-Stevens FisheryConservation Management Act

The MSA, as amended by the Sustainable Fisheries Act of 1996 (Public Law 104-267),

established procedures designed to identify, conserve, and enhance essential fish habitat (EFH)

for those species regulated under a federal fisheries management plan. The MSA requires

federal agencies to consult with NOAA Fisheries on all actions or proposed actions authorized,

funded, or undertaken by the agency that may adversely impact EFH (MSA Section 305(b)(2)).

Although absolute criteria have not been established for conducting EFH consultations, NOAA

Fisheries recommends consolidating EFH consultations with interagency coordination

procedures required by other statutes such as NEPA, the Fish and Wildlife Coordination Act, or

the ESA (50 CFR 600.920(e))in order to reduce duplication and improve efficiency. As part of

the consultation process, the FERC has prepared an EFH Assessment included in appendix B of

this EIS.

1.6.3 Rivers and Harbors Act

The RHA pertains to activities in navigable waters as well as harbor and river

improvements. Section 10 of the RHA prohibits the unauthorized obstruction or alteration of

any navigable water of the U.S. Construction of any structure or the accomplishment of any

other work affecting course, location, condition, or physical capacity of waters of the U.S. must

be authorized by the COE (see section 4.3 for the status of our compliance with the RHA).

1.6.4 Clean Water Act

The CWA, as amended, regulates the discharges of pollutants into waters of the U.S. and

regulates quality standards for surface waters. To enact this goal both the EPA and the COE

have regulatory authority under the CWA. The EPA has implemented pollution control

programs including setting wastewater standards for industry and creating water quality

standards for all contaminants in surface waters. Under the CWA, it is unlawful to discharge any

pollutant from a point source into waters of the U.S. without a permit. The EPA operates the

NPDES permit program which regulates discharges by industrial, municipal, and other facilities,

that directly enter surface waters. Section 404 of the CWA regulates the discharge of dredged or
Environmental Impact Statement 1-18 Corpus Christi LNG

fill material into waters of the U.S. and is under jurisdiction of the COE. The status of NPDES

and Section 404 permitting requirements are further addressed in section 4.3 of this EIS.

Section 401 of the CWA requires that an applicant for a federal permit to conduct any

activity that may result in a discharge to waters of the U.S. must provide the federal regulatory

agency with a Section 401 certification. Section 401 certifications are made by the state in

which the discharge originates and declares that the discharge would comply with applicable

provisions of the act, including the state water quality standards. The RRC is the regulatory

authority delegated with Section 401 certification for the state of Texas for oil and gas

operations. The RRC also permits nonpoint discharges associated with oil and gas activities

from stormwater to waters of the U.S. under the Texas Administrative Code (TAC)Title 16 Part

1 Chapter 3.

1.6.5 Clean Air Act

The CAA, as amended, defines the EPA’s responsibilities for protecting and improving

the nation’s air quality and the stratospheric ozone layer. Under the CAA, the EPA sets limits on

certain air pollutants and limits emissions of air pollutants coming from sources such as

industrial facilities. The EPA has delegated the authority to implement these regulations to state

and local agencies. In Texas, the Texas Council on Environmental Quality (TCEQ) is

responsible for enforcement of air quality standards at a state level as well as implementation of

federal air programs, with the exception of issuing permits for greenhouse gas (GHG)emissions.

However, on February 18, 2014, EPA issued a proposed rulemaking approving Texas' GHG

permitting program. In anticipation of a final rulemaking, EPA has offered applicants who are

currently in the permitting process with EPA the choice of continuing the permitting process

with EPA, or moving their applications to the TCEQ. The EPA also issued a rule in 2010

finalizing GHG reporting requirements for the petroleum and natural gas industry (40 CFR Part

98).

1.6.6 Federal Aviation Act

The Federal Aviation Act of 1958 (as amended) created the Federal Aviation

Administration (FAA)and delegates their authority “to provide for the regulation and promotion

of civil aviation in such manner as to best foster its development and safety, and to provide for

the safe and efficient use of the airspace by both civil and military aircraft, and for other

purposes.” Title 14 of the USC, Section 44718, Structures Interfering with Air Commerce,

outlines the regulations associated with “the construction, alteration, establishment, or expansion,

or the proposed construction, alteration, establishment, or expansion of a structure or sanitary

landfill when notice would promote safety in air commerce and the efficient use and preservation

of the navigable airspace and of airport traffic capacity at public-use airports.”

Any construction or alteration of structures meeting the requirements outlined in

49CFR 77, Safe, Efficient Use, and Preservation of the Navigable Airspace, requires that

adequate notice is provided to the FAA of that construction or alteration. Subsequent to the

receipt of that notice the FAA would issue a public notice of their intent to perform an

aeronautical study of the obstruction to air navigational facilities and would determine the effect

the obstruction would have on the safe and efficient use of navigable airspace. Following the

completion of the study, the FAA would issue a determination stating whether the proposed

construction or alteration would be a hazard to air navigation. The FAA issued a public notice in
Environmental Impact Statement 1-19 Corpus Christi LNG

regards to the proposed flare stacks associated with the Terminal on September 14, 2012.

Additional information regarding safety associated with the flare stacks is provided in section

4.12 of this EIS.

1.6.7 Maritime Transportation SecurityAct

The MTSA is designed to protect the nation’s ports and waterways from a terrorist attack.

It requires vessels and port facilities to conduct vulnerability assessments and develop security

plans. The MTSA also requires the establishment of Area Maritime Security Committees at all

of the nation’s ports. These committees are tasked with coordinating activities of all port

stakeholders including the Maritime Industry, the boating public, and other federal, state, and

local agencies. As a cooperating agency with the FERC, the Coast Guard prepared a LOR to

analyze the potential navigation safety and maritime security risks associated with the Project.

The Coast Guard also has responsibilities relating to LNG waterfront facilities at 33 CFR 127.

1.6.8 National Historic Preservation Act

Section 106 of the NHPA, as amended, requires the FERC to take into account the

impacts of its undertakings on historic properties, and afford the Advisory Council on Historic

Preservation (ACHP)an opportunity to comment. Historic properties include prehistoric or

historic sites, districts, buildings, structures, objects, or properties of traditional religious or

cultural importance listed in or eligible for listing in the National Register of Historic Places

(NRHP). In accordance with the ACHP’s regulations for implementing Section 106, at 36 CFR

800.2(a)(3), the FERC staff is using the services of the applicant and its consultants to prepare

information, analyses, and recommendations. However, we remain responsible for all findings

and determinations. We will follow the process of complying with Section 106 outlined in Part

800 by consulting with the Texas State Historic Preservation Office (SHPO), identifying historic

properties in the area of potential effect (APE), and assessing potential project effects. In Texas,

the Texas Historical Commission (THC)houses the SHPO. Section 4.10 of this EIS summarizes

the status of our compliance with the NHPA.

1.6.9 Coastal Zone Management Act

The CZMA calls for the “effective management, beneficial use, protection, and

development”of the nation’s coastal zone and promotes active state involvement in achieving

those goals. As a means to reach those goals, the CZMA requires participating states to develop

management programs that demonstrate how these states would meet their obligations and

responsibilities in managing their coastal areas. In the state of Texas, the TGLO is the agency

responsible for administering its Coastal Zone Management Program (CZMP). Because Section

307 of the CZMA requires federal agency activities to be consistent to the maximum extent

practicable with the enforceable policies of a management program, the FERC has requested that

Cheniere seek a determination of consistency with Texas’s CZMP. Sections 4.8.1.5 and 4.8.2.5

of this EIS summarize our compliance with the CZMA.

1.6.10 National Flood Insurance Act

The NFIA created the National Flood Insurance Program and delegated the authority to

manage the program to the Federal Emergency Management Administration (FEMA). The

purpose of the NFIA was to make flood insurance available, improve floodplain management,

and develop maps of flood hazard zones. State and local governments must implement
Environmental Impact Statement 1-20 Corpus Christi LNG

floodplain management regulations consistent with the federal criteria outlined in 44 CFR 60,

Criteria for Land Management and Use. Participating local governments in flood-prone areas,

as designated by FEMA, agree to adopt and enforce ordinances that meet or exceed FEMA

requirements to reduce the risk of flooding. Additional information regarding flood risks and our

compliance with the NFIA is provided in section 4.1.1.5 of this EIS.

Table 1.6-1

Environmental Permits and Agency Reviews for the Corpus Christi LNG Project

Agency Regulation/Permit/Approval Agency Actions Submission Date/Status

Federal

COE

Section 404 of the CWA;

Section 10 of the Rivers and Harbors

Act

Section 404/10 Individual

Permit -Request to amend

Permit No. SWG-2007-01637

Submitted August 31, 2012

Coast Guard

33 CFR 105;33 CFR 127 ;

Notice to mariners;

Maritime Transportation Security Act

Letter of Recommendation Received March 21, 2013

EPA

Section 402 of the CWA;

44 CFR 9;

CAA

GHG PSD Permit/Sinton CS Draft issued February 6, 2014

NPDES Stormwater

Construction Permit Notification prior to construction

FWS Section 7 of the ESA Threatened and endangered

species consultation

Concurrence received August 8,

2013 and November 5, 2013.

NOAA Fisheries

Section 7 of the ESA;

Section 305 of the MSA;

Marine Mammal Protection Act;

Fish and Wildlife Coordination Act

Marine threatened and

endangered species

consultation

Issued response October 29,

2012 stating that reinitiation of

consultations is not required and

the “may affect, but not likely to

adversely affect”determination

from the 2005 consultation

remains valid. Issued comments

to the COE in response to the

public notice on June 28, 2013

regarding recommendations for

Essential Fish Habitat impacts.

Federal Aviation

Administration

Section 1101 of the Federal Aviation

Act

Notice of proposed

construction of a structure

(flare stacks)exceeding

airspace obstruction standards

FAA issued a response that the

structure would have no

substantial adverse effect on the

safe and efficient utilization of

the navigable airspace by

aircraft or on the operation of air

navigation on January 29, 2013

DOE a/ Section 3 of the NGA;

15 USC Section 717b

Application for authorization to

export LNG to non-Free Trade

Agreement countries

Application submitted August 31,

2012

Application for long-term

authorization to export LNG to

Free Trade Agreement

countries

Authorization granted October

16, 2012

State

RRC

Section 401 of the CWA; Water Quality Certification Submitted August 31, 2012

TAC Title 16 Part 1 Chapter 3 Stormwater Discharge Permit Submitted August 31, 2012
Environmental Impact Statement 1-21 Corpus Christi LNG

Table 1.6-1

Environmental Permits and Agency Reviews for the Corpus Christi LNG Project

Agency Regulation/Permit/Approval Agency Actions Submission Date/Status

TCEQ Texas Clean Air Act;CAA;

40 CFR 50-99

GHG PSD permit/Terminal Submitted April 14, 2014

PSD Air Permit Terminal

PSD Air permit Sinton CS

Draft issued July 8, 2013

Final issued December 20, 2013

Title V Air Permit/Terminal

Title V Air Permit/Sinton CS

Submitted November 7, 2012

Submitted November 7, 2012

THC Section 106 of the NHPA

Comment on request that

previously submitted reports

and determinations remain

valid.

SHPO comments dated May 25,

2012 and July 3, 2012.

Comment on request that no

additional archaeological

investigations would be

necessary at the laydown area,

parking area, borrow pit, and

compressor station.

SHPO comments dated August

15, 2012.

Local

San Patricio County

Emergency

Management

44 CFR 60 County Floodplain Permit Submitted August 22 , 2012

PROPOSED ACTION

SECTION 2

Environmental Impact Statement 2-1 Corpus Christi LNG

2.0 DESCRIPTION OFPROPOSED ACTION

The Project consists of a new natural gas liquefaction and export plant, as well as LNG

import facilities with regasification capabilities (Terminal)all located along the northern shore of

Corpus Christi Bay at the north end of the La Quinta Channel in San Patricio and Nueces

Counties, Texas. The Terminal includes two marine berths each containing a maneuvering area

as well as a protected marine berth area capable of accommodating one LNG carrier at a time for

import/export activities.

Additionally, the Project involves the construction and operation of a new 48-inchdiameter, 23-mile, bi-directional natural gas pipeline (Pipeline)extending from the proposed

Terminal to north of Sinton in San Patricio County. The new Pipeline would transfer the

imported natural gas to markets throughout Texas and the U.S. via interconnections with a

number of existing intrastate and interstate pipeline systems, and to transfer natural gas to the

Terminal for liquefaction and export.

A general map of the Terminal facilities is provided as figure 1.1-1 and the proposed site

boundary is provided as figure 1.1-3. The following sections describe the proposed facilities

associated with the Project, construction procedures and schedule, environmental compliance

and inspection monitoring, operation and maintenance procedures, safety controls, and land

requirements.

2.1 TERMINAL (IMPORT AND EXPORT)FACILITIES

The Terminal would include liquefaction facilities, marine terminal and LNG transfer

lines, LNG storage facilities, LNG vaporization facilities, flare facilities, and other infrastructure.

2.1.1 Liquefaction Facilities –Export

The Terminal would include three LNG liquefaction trains, necessary to liquefy natural

gas, capable of producing approximately 782 million British thermal units (MMBtu)per year of

LNG. Each liquefaction train consists of multiple facilities which include:

 facilities which remove carbon dioxide (CO2), hydrogen sulfide (H2S), and sulfur

compounds from feed gas;

 facilities to remove water and mercury from the feed gas;

 facilities to remove heavy hydrocarbons (such as benzene, toluene, ethylbenzene, and

xylene [BTEX])from the feed gas to avoid freezing in the liquefaction unit;

 standard annular combustor aero-derivative LM2500 G4+ gas turbine-driven refrigerant

compressors –each gas turbine would have water injection for emissions control, and

Inlet Air Humidification Systems to be operated when the ambient temperature is at or

above 60 degrees Fahrenheit (°F);

 waste heat recovery systems for regenerating the gas driers and amine system;

 induced draft air coolers;

 associated control systems and electrical infrastructure;

 utility connections and distribution systems;and
Environmental Impact Statement 2-2 Corpus Christi LNG

 piping, piperacks, foundations, and structures within the LNG train battery limits.

BTEX and acid gas impurities removed from the natural gas stream prior to liquefaction

would be disposed of by passing through a triazine scavenger bed which absorbs any H2S. The

remaining waste gas contains CO2 and would be mixed with a small amount of fuel gas and sent

to a thermal oxidizer. Cheniere would then send the spent solvent to a licensed disposal facility.

While the feed gas contains no mercury, as a precaution, Cheniere would provide mercury

removal beds and any mercury collected would be sent to a licensed disposal facility.

2.1.2 LNG Vaporization Facilities –Import

Cheniere would install two trains of ambient air vaporizers (AAVs)and send out pumps

capable of vaporizing sufficient LNG volume for each to send out 200 MMBtu per day of natural

gas. Each AAV train would be comprised of approximately 18 to 20 AAV cells and associated

piping, valves, and one high-pressure LNG send-out pump. Each AAV train would cycle the

AAV cells between operation and defrost, with some cells vaporizing and some cells in defrost

mode at any one time, depending on ambient conditions. Cheniere selected the AAV

vaporization system because they provide the most fuel efficient method for regasifying LNG.

The AAVs do not require combustion to regasify as opposed to traditional Submerged

Combustion Vaporizers.

2.1.3 LNG Storage Facilities

The LNG would be stored in three, full containment storage tanks. The tanks would be

oriented in a straight line, separated by 50 meters. Each tank would be 194 feet above grade and

258.5 feet in diameter. The tanks would be designed to store a nominal volume of 160,000 cubic

meters (m3)(1,006,400 barrels)of LNG at a temperature of -270°F and a maximum internal

pressure of 3.5 pounds per square inch gauge (psig)(though the normal operating conditions

would be -260°F and 1.5 psig). The tank system would meet the requirements of the NFPA 59A,

49CFR Part 193, and American Petroleum Institute (API)Standard 620 Appendix Q.

There would be several major components to the LNG storage tanks:

 A 9percent nickel steel open top inner container, designed to withstand the hydrostatic

pressures and cryogenic temperatures of the LNG, as well as the predicted seismic,

insulation, and thermal gradient loads. The space between the inner container and the

outer container would be insulated with expanded perlite to maintain the outer container

at near ambient temperature. The insulation beneath the inner container would be cellular

glass load-bearing insulation that would support the weight of the inner container and the

LNG.

 An outer tank comprised of reinforced concrete with a domed concrete roof. The outer

tank would be designed for the specified internal pressure of 3.5 psig, and a sustained

wind speed of 150 miles per hour (mph). In addition, the tank would be designed for

seismic loads in accordance with NFPA 59A and the site specific seismic reports, internal

pressure imposed by insulation loads, and roof and platform dead loads.

 An insulated aluminum deck over the inner container, suspended from the roof. The

aluminum support deck would be insulated with fiberglass blankets so that the outer tank

roof and vapor space above the suspended deck would be at ambient temperature. The
Environmental Impact Statement 2-3 Corpus Christi LNG

vapor pressure from the LNG would be equalized through ports in the suspended deck

and would be contained by the outer container.

The tanks would be supported on a reinforced concrete mat with electric base heating to

prevent frost heave. Each tank would also have five in-tank pump well columns, four of which

would be fully installed with foot valve, electrical components, structural supports,

instrumentation, piping, etc. The fifth pump well column would be equipped with a foot valve

only for use as a future spare pump. All LNG piping would enter the tank through the concrete

tank roof. All piping systems would be in accordance with American Society of Mechanical

Engineers (ASME)B31.3 and NFPA 59A Chapter 6. Each LNG tank would also be equipped

with a cool down temperature detection system to monitor the inner tank bottom plate and inner

tank shell continuously during cool-down procedures;foundation temperature sensors located at

strategic locations under the tank;instrumentation to monitor the quality and level of LNG in the

tank and to monitor tank contents for stratification;a safety-rated control system to monitor the

LNG level and control the fill line shutoff valves;pressure and vacuum relief systems;platforms,

elevators, and stairways with intermediate landings attached to the outer tank;spill protection of

the tank roof over the edge of the roof dome;lighting and aircraft warning lights;electrical

grounding system;electrical base heating;a settlement monitoring system to measure and record

inner and outer container movements during construction, hydrostatic testing, and operation;and

seismic monitors.

2.1.4 Marine Terminal and LNG Transfer Lines

Access to the proposed marine terminal associated with the Terminal facilities from the

Gulf of Mexico would be through a series of channels. The navigation channels that would be

used to reach the marine terminal include the Aransas Pass Safety Fairway, Aransas Pass Outer

Bar Channel, Jetty Channel, Corpus Christi Ship Channel (including the Inner Basins at Harbor

Island and the junction with the La Quinta Channel), and the La Quinta Channel. The marine

terminal would be located on the north end of the La Quinta Channel. Land-based facilities

associated with the Terminal would be located in San Patricio County, while marine facilities

would be in Nueces County.

2.1.4.1 LNG Carriers and Marine Berths

The proposed marine terminal would include two LNG carrier berths. Both berths would

consist of a maneuvering area and a protected marine berth area. Cheniere estimates that

approximately 200 to 300 LNG carrier transits through the Corpus Christi Bay would occur

annually. To facilitate maneuvering of the LNG carriers, Cheniere would keep tug boats

available. When not in use, the tug boats would be docked at the marine facilities.

Each marine berth would consist of at least four breasting dolphins, consisting of

reinforced concrete structures on piles. The dolphins would be equipped with fenders suitable to

safely berth and moor the full-size range of ships anticipated at the Terminal. The breasting

dolphins would also be equipped with quick-release mooring hooks for spring lines to provide

the necessary mooring lines arrangement flexibility for various sizes of vessels. In addition to

the breasting dolphins, six mooring dolphins would be provided, each consisting of reinforced

concrete structures on piles and equipped with quick release mooring hooks.

The LNG cargo transfer docks would be single-level concrete structures supported on

piles. Each dock would consist of a reinforced concrete beam and slab structure, approximately
Environmental Impact Statement 2-4 Corpus Christi LNG

90 feet wide by approximately 116 feet long. The piles to support the dock and dolphins would

be driven during daylight hours only and operations would observe the procedures necessary to

minimize impacts on aquatic life and marine mammals (see sections 4.6 and 4.7). The

procedures would include exclusion zones, sound attenuation, soft start procedures, visual

monitoring, and shut down and delay procedures. Each dock would be curbed to confine

potential LNG spillage and its surface would be sloped to a collection point. Drainage from the

collection point would be via the LNG spill collecting trough to a spill impoundment basin.

Shipboard LNG cargo pumps would deliver the LNG from each marine berth to the LNG

storage tanks at a design rate no more than 12,000 m3per hour via two parallel LNG transfer

lines for the unloading/vaporizing (import)mode. During the liquefaction (export)mode, in-tank

pumps would deliver LNG to ships from the storage tanks at a design rate no more than 12,000

m

3

per hour. Three 20-inch-diameter marine cryogenic cargo transfer arms would be installed

for liquid delivery to/from the storage tanks, and one 20-inch-diameter arm would provide vapor

return flow between the ship and the Terminal. The cargo transfer arms would be designed with

swivel joints and equipped with sensors to provide the required range of movement between the

ship and the shore connections. Each arm would be fitted with a powered emergency release

coupling and associated valves to protect the arm and ship’s manifold while also avoid spillage

of its liquid contents in the case of unusual movement of the ship continuing beyond the normal

operating envelope. Each arm would be operated by a hydraulic system with a counterbalance

weight to reduce the weight of the arm bearing on the shipside connection and to reduce the

power required to maneuver the arm into position.

The LNG cargo transfer docks would also allow access for a mobile crane that Cheniere

anticipates would be required to facilitate maintenance service on the cargo transfer arms. A

boat launch ramp would also be constructed to facilitate seaside inspection of the berths in the

channel.

The facilities would be designed to provide safe berthing for receipt and mooring of LNG

carriers and to ensure the safe transfer of LNG cargoes between the ships and the onshore storage

facilities. Design of the marine facilities would be in accordance with applicable codes and

standards, including but not limited to, Oil Companies International Marine Forum, Society of

International Gas Tanker and Terminal Operators, API, and American Society of Civil Engineers

(ASCE).

Cheniere indicated that they confirmed its proposed facility design with simulations

which demonstrated maneuvering and docking of all modeled LNG carriers would be

accomplished with no more than three Z-drive tractor tugs (each having approximately 70 metric

tons shallow water bollard pull capability)under most anticipated environmental conditions of

weather, current, tide, etc. However, Cheniere plans to have four tugs boats in reserve at the

Terminal site to assist in LNG carrier maneuvering. Cheniere also had the berth layout reviewed

by experienced pilots, and changes were made based on their recommendations. Computer

simulations of the maneuvering and berthing evolutions were then conducted at the COE

Engineering Research and Development Center’s (ERDC)Ship and Tow Simulator located in

Vicksburg, Mississippi. Additional computer simulations were conducted using updated LNG

carrier computer models on a Transas full-mission bridge simulator at the Maritime Institute of

Training and Graduate Studies located in Linthicum, Maryland.
Environmental Impact Statement 2-5 Corpus Christi LNG

The LNG carrier berths would be protected as much as practicable from other ship traffic,

particularly in the unlikely case of a ship becoming disabled while passing the Terminal. The

location and configuration of the berths would be such that the LNG carrier berths would be

recessed and at enough of an angle to avoid this, while maintaining sufficient maneuvering area

in case a docked LNG carrier needs to make an emergency departure. Cheniere’s final berth

layout was confirmed to meet these criteria at the ERDC.

LNG carriers would load/discharge LNG cargoes at the berths via the bidirectional cargo

transfer arms. LNG would flow via the stainless steel insulated LNG transfer lines for delivery

to the LNG storage tanks or to the LNG carrier. During berth idle periods when no cargo

transfer operations are being conducted, the contents of the LNG transfer lines would be

recirculated from one LNG storage tank to the jetty and back to another LNG tank to keep the

LNG lines cold.

Ballast is a necessary safety feature of commercial shipping that provides control of

longitudinal trim and transverse stability during voyages and while in port. Controlling ballast

weight and placement also ensures adequate submergence of the propeller, reduces stresses on

the ship’s hull, and controls both the longitudinal and vertical locations of the center of gravity as

required for safe navigation and operation of ships. Impacts resulting from ballast water are

discussed in sections 4.3 and 4.6.

2.1.4.2 Barges

Barges would be necessary for transportation of equipment to the Terminal site during

construction. A roll-on/roll-off area would be sited to the west of the LNG carrier berths for

unloading equipment from barges. The primary materials that would be used in construction of

the marine berth include steel-pipe pilings, concrete, and reinforcing steel for the concrete.

Cheniere anticipates that the reinforcing steel would be fabricated off site and trucked to the

Terminal site or delivered by barge to the construction dock. The concrete would be produced in

a batch located at the main Project site or purchased from a local supplier, depending on local

availability at the time of construction.

2.1.4.3 Dredge Disposal

To accommodate the deepest draft LNG carriers, Cheniere would dredge the berth areas

to a minimum depth of -46 feet, plus 2 feet paid allowed overdredge to ensure the minimum

depth is met, and 2 feet advanced maintenance dredge. Cheniere anticipates that 2 feet of

maintenance dredging would be required approximately every three years to ensure minimum

depth is maintained. A 3:1 side slope would form the sides of the slip, portions of which would

be protected using articulated block mats or other suitable means of stabilization, where required.

Cheniere would also expand the existing maneuvering area to the same parameters described for

the berths.

Initial dredging of the berths would result in the dredging of approximately 4.4 million

cubic yards (mcy)of material, while maintenance dredging is anticipated to occur every three

years and produce approximately 200,000 cubic yards of material. Dredge materials would be

disposed of in two ways. Some of the dredged material would be used to fill a portion of a

former 90-acre clay borrow pit northeast of the Project site. The remainder of the dredged

material would be used to cap old bauxite disposal beds located in a 385-acre area immediately

north of the Project site. This area is known as dredge material placement area (DMPA)2. The
Environmental Impact Statement 2-6 Corpus Christi LNG

dredge material would be transferred to DMPA 2 via an approximately 11,000-foot-long, 30-

inch-diameter slurry pipe. The dredge material would be evenly distributed across the bauxite

beds and the water would be decanted and monitored as it leaves the DMPA to permitted

outfalls. The resulting soil would be a cap over the old bauxite beds which would allow

revegetation to occur, reducing the red dust in the area. Figure 2.1-1 shows the location of the

90-acre clay pit disposal area as well as DMPA 2, in relation to the Terminal site.

A portion of the marine terminal’s berth approach area was recently dredged by the COE

as part of an extension of the La Quinta Channel. The two marine berths associated with

Terminal would be designed to accommodate a broad range of present and future LNG carrier

size and type classes, including the largest presently existing (Q-max class)LNG carriers with

cargo capacities of up to approximately 267,000 m3

.
Environmental Impact Statement 2-7 Corpus Christi LNG

Figure 2.1-1 Proposed Dredge Material Placement Areas
Environmental Impact Statement 2-8 Corpus Christi LNG

2.1.5 Flare Facilities

All liquefaction plant hydrocarbon emergency relief loads would go to a closed flare

system. The flares are the control technology for volatile organic compounds (VOCs)and

organic hazardous air pollutants (HAPs), and achieve 98 percent combustion efficiency over all

conditions including plant start-up, shut-down, continuous operation and emergency flaring at all

rates.

The Project would include flares to protect the process and the LNG loading and

unloading system during upset or emergency cases. Five flares consisting of three types would

be installed for the Project, including two wet gas flares, two dry gas flares, and one marine flare.

Two identical wet/dry flare systems would be provided, with each system size, for loads

from two LNG trains. The first wet/dry system would be exclusively for Train 1 with the second

for Train 3. Relief from Train 2 would be routed to either of the two flare systems, allowing

both systems to provide relief for two trains. The marine flare would be utilized for both docks

and the three LNG storage tanks. The wet and dry flares would be located on the common

derrick structure approximately 500 feet tall. This arrangement would incorporate demountable

flares to facilitate ease of flare tip maintenance. Critical Project structures and equipment,

including ships at the marine berths would be outside the high heat flux zones.

Each flare would be ignited by a pilot and the flame would be monitored by dual

thermocouples. The flare pilot would be operated in a continuous mode and is re-lit

automatically if the flame goes out for the wet and dry flares. The marine flare pilot would only

be operated during ship loading.

2.1.6 Other Terminal Infrastructure

In addition to the facilities described above, the Terminal would also require additional

facilities and infrastructure including:

 miscellaneous buildings and other structures to accommodate equipment, utilities, and

support services infrastructure;

 warehouse to store spare parts and consumables for the liquefaction, regasification, and

utility facilities;

 storage area for chemicals, lubricants, and hazardous substances;

 operation and maintenance building, including the control room;

 remote input/output buildings and substations;

 storage vessels for propane and ethylene refrigerants;

 storage tanks for amine make up;

 storage tanks for heavy hydrocarbons removed from the feed gas;

 spill containment facilities;

 emergency shutdown (ESD)systems;

 firewater system, including diesel driven pumps and storage tank;

 instrument air compressor packages;
Environmental Impact Statement 2-9 Corpus Christi LNG

 security and perimeter control systems, telecoms, information technology, closed-circuit

television, and other systems;

 storage tanks for condensate, liquid nitrogen, diesel, and gasoline;

 potable water, service water, and demineralized water systems;

 pipeline interconnect for the receipt of natural gas from and export to the Pipeline;and

 electric facilities, switchgear, transformers, and other electrical accessories.

2.2 PIPELINE FACILITIES

2.2.1 Pipeline

The Pipeline operating facilities would be designed for a maximum allowable operating

pressure (MAOP)of 1,440 psig and a capacity of 2.25 Bcf/d. The Pipeline facilities would be

located entirely within San Patricio County, Texas. A summary of facilities associated with the

Pipeline are discussed below.

Cheniere would construct approximately 23 miles of new 48-inch-diameter natural gas

pipeline, originating at the Terminal and routed primarily along an existing collocated electric

transmission and gas pipeline in San Patricio County, Texas. The Pipeline would terminate north

of Sinton at an interconnect with Tennessee Gas Pipeline Company, LLC (Tennessee Gas).

Six meter and regulator (M&R)stations would be installed at interconnects along the

Pipeline. The Liquefaction M&R Station would be located at milepost (MP)0.0 and would be

remotely operated to feed gas to/from the Terminal. This station would include one

bi-directional M&R system with a 2.6 Bcf/d capacity, filter separators, liquid handling tanks, gas

chromatograph building, one pig trap on the 48-inch mainline, and pressure/flow control. The

Texas Eastern Transmission, L.P. (Texas Eastern)M&R Station would be located at approximate

MP 7.5 and would be located on the Taft Compressor Station parcel. This station would include

one bi-directional M&R system with a 0.5 Bcf/d capacity, filter separator, and liquid handling

tank. The Tejas Pipeline LLC (Tejas)M&R Station would be located at approximate MP 21.5

and would have taps on both existing Tejas pipelines (30-inch-diameter and 36-inch-diameter).

This station would include a 48-inch by 36-inch ‘T’and valve on the Pipeline, one bi-directional

M&R system with a 1.0 Bcf/d capacity, filter separator, and liquid handling tank.

The Natural Gas Pipeline Company, LLC (NGPL)M&R Station would be located at

approximate MP 22.4 and would have taps on both existing NGPL pipelines (26-inch-diameter

and 30-inch-diameter). This station would include a 48-inch by 36-inch ‘T’and valve on the

Pipeline, one bi-directional M&R system with a 0.5 Bcf/d capacity, filter separator, and liquid

handling tank. The Transcontinental Gas Pipe Line Company, LLC (Transco)M&R Station

would be located at approximate MP 22.8 and would include a 48-inch by 24-inch ‘T’and valve

on the Pipeline, one bi-directional M&R system with a 0.25 Bcf/d capacity, filter separator, and

liquid handling tank. The Tennessee Gas M&R Station would be located at approximate MP

23.0 and would have taps on both existing Tennessee Gas pipelines (24-inch-diameter and

30-inch-diameter). This station would include a 48-inch by 36-inch ‘T’and valve on the

Pipeline, one bi-directional M&R system with a 1.0 Bcf/d capacity, one pig trap on the 48-inch

mainline, filter separator, and liquid handling tank.
Environmental Impact Statement 2-10 Corpus Christi LNG

In addition to the facilities listed above, Cheniere would also install five mainline valves

(MLV), as well as a pig launcher and receiver.8 MLVs would be installed at the Liquefaction

M&R Station, Taft Compressor Station, MP 14.5, Sinton Compressor Station, and the Tennessee

Gas M&R Station. A pig launcher would be installed at the Liquefaction M&R Station with a

pig receiver installed at the Tennessee Gas M&R Station.

2.2.2 Compressor Stations

Cheniere would construct two new compressor stations associated with the Pipeline. The

Taft Compressor Station would be constructed at approximate MP 7.5 and would be remotely

operated. The station would be located at an interconnect with a Texas Eastern and would

include two Solar Centaur 50 turbine/compressor units (6,387 horsepower [hp]each);one

compressor building to house both turbine/compressor units and to include suitable noise

abatement and overhead hoists;one auxiliary building with office space, bathrooms, and storage

for incidental spare parts for the compressor station;emergency power generator capabilities for

operation of the entire station;two suction headers (one mainline header and one for connection

to the Texas Eastern pipeline);filter separators;liquid handling tanks;and discharge gas coolers

associated with the Centaur 50 units.

The Sinton Compressor Station would be constructed at approximate MP 21.5. The

Sinton Compressor Station would be remotely operated and would include two Solar Titan 130

turbine/compressor units (20,387 hp each), one compressor building to house both

turbine/compressor units and to include suitable noise abatement and overhead hoists, one

auxiliary building with office space and storage for incidental spare parts for the station,

emergency power generator capabilities for operation of the entire station, two suction headers

(one mainline header and one for connection to the Tejas system), filter separators, liquid

handling tanks, and discharge gas coolers associated with the Titan 130 units.

2.3 LAND AND WATER REQUIREMENTS

2.3.1 Terminal Facilities

Cheniere estimates that approximately 991 acres would be affected by construction of the

Terminal including the marine basin and berths. Following construction, 349 acres would

continue to be impacted by operation and maintenance dredging and another 120 acres would be

part of an exclusion zone. Table 2.3-1 lists the land and water requirements for the Terminal

facilities. The majority of the land at the Terminal site is previously disturbed and includes areas

that were used for stockpiling bauxite. Water requirements associated with the Terminal include

part of the marine berths and basin, a tug dock, a boat launch, and part of the exclusion zone.

8 A pipeline “pig”is a device used to clean or inspect the pipeline. A pig launcher/receiver is an aboveground

facility where pigs are inserted or retrieved from the pipeline.
Environmental Impact Statement 2-11 Corpus Christi LNG

Table 2.3-1

Land and Water Requirements for the Terminal

Facility

Land

Impacted by

Construction

(acres)

Land

Impacted

During

Operation

(acres)

Water

Impacted by

Construction

(acres)

Water

Impacted

During

Operation

(acres)

Total Area

Impacted by

Construction

(acres) a/

Total Area

Impacted

During

Operation

(acres) b/

Terminal Site c/, d/ 225 225 0 0 225 225

Marine Basin and Berth 5 5 121 119 126 124

Dredged Material

Placement e/ 437 0 0 0 437 0

Temporary Laydown

Areas f/ 160 0 0 0 160 0

Temporary Parking

Area f/ 26 0 0 0 26 0

Temporary Access

Roads f/ 8 0 0 0 8 0

Tool and Lunch Area f/ 9 0 0 0 9 0

Exclusion Zones 0 91 0 29 0 120

Total 870 321 121 148 991 469

_______________________

a/ Construction area includes entire construction footprint, including all temporary and permanent construction areas.

b/ Operation area includes the permanent Terminal site, marine basin and berth, permanent easement, and exclusion zone.

c/ Acreage excludes the marine basin and berths and the capped Bauxite Disposal Bed 22 (52 acres). The Bauxite Disposal Bed

22 is within Project boundary but would not be disturbed by construction or operation.

d/ Bed 24 acreage is included in Terminal site (area would be filled with structural fill material and become part of the operating

area).

e/ DMPA 2 and the Clay Pit Disposal Area would be used during construction.

f/ Area used during construction only and located outside of the Terminal Site.
Environmental Impact Statement 2-12 Corpus Christi LNG

2.3.2 Pipeline Facilities

Table 2.3-2 summarizes the land requirements for the Pipeline and associated facilities.

Additional information regarding land requirements for the Pipeline facilities is provided in the

following sections.

Table 2.3-2

Land Requirements for the Pipeline and Associated Facilities

Facility Land Impacted by

Construction (acres)

Land Impacted During

Operation (acres)

Pipeline Right-of-Way

Pipeline 321.1 142.3

Additional Temporary Workspace 27.0 0.0

Compressor Stations

Taft Compressor Station (MP 7.5) 6.9 5.8

Sinton Compressor Station (MP 21.5) 17.2 7.3

M&R Stations

Liquefaction M&R Station (MP 0.0) 2.0 1.6

Texas Eastern M&R Station (MP 7.5) 2.1 2.1

Tejas M&R Station (MP 21.5) 2.4 2.4

NGPLM&R Station (MP 22.4) 1.3 1.0

Transco M&R Station (MP 22.8) 1.0 0.9

Tennessee Gas M&R Station (MP 23.0) 2.0 2.0

Launchers/MLVs

Terminal Pig Launcher and MLV (MP 0.0)a/ 0.0 0.0

MLV at Taft Compressor Station (MP 7.5)b/ 0.0 0.0

MLV (MP 14.5) 0.2 0.2

MLV at Sinton Compressor Station (MP 21.5)c/ 0.0 0.0

Pig Receiver and MLV (MP 23.0)d/ 0.0 0.0

Access Roads/Yards

Access Roads 20.1 12.7

Contractor and Pipe Yard 17.4 0.0

Total: 420.7 178.3

__________________________

a/ Included with the Liquefaction M&R Station.

b/ Included within the Taft Compressor Station.

c/ Included within the Sinton Compressor Station.

d/ Included within the Tennessee Gas M&R Station.

The 48-inch-diameter Pipeline would be installed adjacent to a high voltage overhead

powerline and existing natural gas pipelines along approximately 86 percent of the route.

Construction of the Pipeline would require the use of a 120-foot-wide construction right-of-way

consisting of 50 feet of permanent and 70 feet of temporary right-of-way in uplands. In

wetlands, the construction right-of-way would be 75 feet (consisting of 50 feet permanent and
Environmental Impact Statement 2-13 Corpus Christi LNG

25 feet temporary right-of-way). The construction right-of-way would be collocated in some

areas and may overlap with other existing rights-of-way.

The 120-foot-wide construction right-of-way would be necessary to accommodate both

the increased trench depth and width necessary to install a 48-inch-diameter pipe. Due to the

depth of the soils in the area, additional space would be required to store trench spoil and

segregated topsoil. The right-of-way would also provide heavy equipment operators the

necessary area to maintain safe and efficient separation distances between the potentially

unstable trench sidewalls and their equipment. The increased construction right-of-way would

also ensure adequate separation between adjacent foreign pipelines or high voltage overhead

power lines and the construction activities.

Although Cheniere has routed its pipeline to be adjacent to existing utility or road

rights-of-way for about 86 percent of the proposed route, it has not provided site-specific

configurations for its construction right-of-way by milepost since the pipeline design has not

been finalized. Cheniere would provide this information once the pipeline easement negotiation

process is complete. Cheniere indicates that it may be able to collocate or overlap its

construction right-of-way with other utility or road rights-of-way. Collocation of the pipeline

and/or overlapping construction right-of-way would further minimize the construction footprint

on properties crossed, thus minimizing impacts on affected resources. Table 2.3-3 below

provides the milepost locations where pipeline construction may be adjacent to existing utilities

or road rights-of-way, and the direction. Because the final pipeline design has not been

provided, and to further reduce construction footprint of the pipeline construction workspace, we

recommend that:

 Prior to construction of the pipeline,Cheniere should update table 2.3-3of the draft

EISto identifythe existing utilities/road locations and the milepost ranges of where

its construction right-of-waywould overlap or collocate other utility/road rights-ofway; and revise its final alignment sheets to reflect the actual right-of-way

configurations and workspace needs at these locations.
Environmental Impact Statement 2-14 Corpus Christi LNG

Table 2.3-3

Locations Where the Pipeline may be adjacent to Existing Rights-of-Way

Mileposts

Segment

Length

(miles)

Existing Easement Direction from

Existing Right-of-Way

0.0 –0.64 0.64 La Quinta Road Adjacent to the west side of the road.

0.80 –2.16 1.36 Equistar Pipeline, Koch Pipeline, Tejas

Pipeline, and El Paso Pipeline Adjacent to the north side of the Koch Pipeline.

2.36 –2.90 0.54 Overhead power line and water line Adjacent to north side of the water line.

2.90 –7.90 5.00 County Road 78, overhead electric

power line and water line

Adjacent to north side of the water line. County

Road 78 is about 300 feet south to about MP

5.0 and about 100 feet south thereafter.

7.90 –8.94 1.04 County Road 78 Pipeline will be about 500 feet south of County

Road 78 (not adjacent).

11.05 –13.22 2.17 Koch Pipeline Adjacent to the north side of the Koch pipeline.

13.22 –13.78 0.56 Koch Pipeline, private road, & water line Adjacent to the north side of the water line.

The private road is about 50 feet south.

13.79 –14.45 0.66 El Paso Pipeline Adjacent to the north side of pipeline.

14.45 –16.04 1.59 County Road 2921, El Paso Pipeline,

Valero Pipeline

Adjacent to the east side of Valero Pipeline.

County Road 2921 is about 1,000 feet west.

16.04 –17.80 1.76 Valero Pipeline, (2)El Paso Pipelines Adjacent to the east side of Valero Pipeline.

18.31 –22.72 4.41 Valero Pipeline, (2)El Paso Pipelines Adjacent to the east side of Valero Pipeline.

Total 19.73

Typical pipeline right-of-way configurations for overlapping construction rights-of-way

and abutting rights-of-way are depicted in figure 2.3-1 and figure 2.3-2, respectively.
Environmental Impact Statement 2-15 Corpus Christi LNG

Figure 2.3-1 Typical pipeline right-of-way configuration with overlapping rights-of-way
Environmental Impact Statement 2-16 Corpus Christi LNG

Figure 2.3-2 Typical pipeline right-of-way configuration with abutting rights-of-way
Environmental Impact Statement 2-17 Corpus Christi LNG

Additional temporary workspace (ATWS)would also be utilized in areas requiring

specialized construction techniques such as road and waterbody crossings. Following the

completion of construction, the temporary construction right-of-way and ATWS areas would be

restored to preconstruction conditions and a 50-foot permanent easement would be required for

operation and maintenance of the Pipeline.

The Taft Compressor Station would require approximately 6.9 acres of land for

construction and 5.8 acres of land for operation. The Sinton Compressor Station would require

approximately 17.2 acres of land for construction and 7.3 acres for operation. Construction of all

of the M&R stations would require less than 2.5 acres for construction and operation. The

specific land requirements associated with each M&R station is provided in table 2.3-2.

Cheniere would also install a permanent pig launcher within the Liquefaction M&R Station and a

permanent pig receiver within the Tennessee Gas M&R Station. The launcher and receiver

would be entirely contained within the respective M&R station and would not require additional

land.

A total of five MLVs would be placed along the Pipeline including one at MP 0.0, one at

the Taft Compressor Station (MP 7.5), one at MP 14.5, one at the Sinton Compressor Station

(MP 21.5), and one at MP 23.0. All of the MLVs would be contained within a proposed M&R

facility or compressor station and would not require any additional temporary or permanent

workspace, with the exception of the MLV at MP 14.5. This MLV would be located within the

permanent easement of the Pipeline and would require a construction and operation area of 0.2

acre.

The majority of the access roads that would be used during construction and operation of

the Project are existing roads that would require minor improvements, including maintenance

and adding rock. Two new permanent roads would be constructed comprising approximately 0.2

acre. In total, access roads used during construction would utilize approximately 20.1 acres of

land, including the approximately 12.7 acres that would be utilized during operation.

2.4 CONSTRUCTION PROCEDURES

The Project facilities would be designed, constructed, operated, and maintained in

accordance with federal standards which are intended to adequately protect the public by

preventing or mitigating LNG and natural gas pipeline failures or accidents, and ensure safe

operation of the facilities. The Terminal would be constructed according to the standards

outlined by the DOT Federal Safety Standards for Liquefied Natural Gas Facilities at

49CFR 193, and the NFPA’s Standards for the Production, Storage, and Handling of LNG

(NFPA 59A). The marine areas associated with the Terminal would comply with the applicable

sections of the Coast Guard regulations for Waterfront Facilities Handling LNG at 33 CFR 127

and Executive Order 10173.

The Pipeline facilities would comply with DOT regulations at 49 CFR 192,

Transportation of Natural or Other Gas by Pipeline: Minimum Federal Safety Standards. These

regulations specify material selection, design criteria, corrosion protection, and qualifications for

welders and operation personnel. Additionally, Cheniere would comply with the Commission’s

regulations at 18 CFR 380.15, regarding the siting and maintenance of pipeline rights-of-way.

Cheniere indicated that the Project would implement and adhere to our Upland Erosion

Control, Revegetation, and Maintenance Plan (Plan)and Wetland and Waterbody Construction
Environmental Impact Statement 2-18 Corpus Christi LNG

and Mitigation Procedures (Procedures) 2013 version with no alternative measures.

Additionally, Cheniere has developed a Spill Prevention, Control, and Countermeasure (SPCC)

Plan for both the Terminal and the Pipeline. We have reviewed this plan and find it acceptable.

Prior to the commencement of construction, affected landowners would be notified of the

start of construction and would be provided with the contact information for Cheniere in the

event that they have a construction‐related concern (see section 2.5.1 for additional information

on Cheniere’s complaint resolution procedures).

2.4.1 Construction Schedule

On September 16, 2013, Cheniere filed a revised construction schedule stating that

Cheniere anticipates construction of the Terminal would take approximately 60 months (5 years)

from the onset of site preparation activities until the startup of Train 3, with substantial

completion of Train 1 planned for late 2017. Construction of the Pipeline and aboveground

facilities is anticipated to take approximately one year to complete. The Pipeline is currently

planned for construction in 2016.

2.4.2 Terminal Facilities

2.4.2.1 Construction of Liquefaction Facilities

During the site-works phase of construction, Cheniere would cut necessary drainage

ditches in laydown areas to allow proper surface water runoff, place gravel surfaces for

temporary construction facilities (i.e., parking lots, office areas, and laydown areas), install

temporary construction fencing, and construct roads within the Terminal site boundaries.

Activities associated with the site-works phase of construction may occur concurrently with

other construction activities at the Terminal.

Cheniere would install the foundations for equipment, buildings, and pipe racks on spread

footings. Following installation of the pipe racks, the pipe would be installed from multiple

directions. Fabrication of pipe spools would be conducted in a covered area and structural steel

members would be prefabricated off-site and erected upon arrival. The majority of the straight

run pipe would be fabricated on or near the site prior to placement on the pipe racks. Pipe

expansion loops would be prefabricated, transported to the site, and erected with the straight run

piping. Pipe would be painted to the maximum extent practicable at the fabrication shops

off-site, after all welds have been tested in accordance with applicable codes.

When practicable, large equipment would arrive at site in preassembled packages to

facilitate final hook-up and testing. All equipment would be designed, fabricated, and tested by

highly qualified specialist suppliers at their respective facilities. Equipment would only be

shipped to the site after the necessary inspections and testing are complete. Larger equipment,

such as cold boxes, acid gas absorber, and the refrigerant compressors, would be offloaded at the

roll on/roll off construction dock on a multi-wheel transport crawler, and transported to their

foundations. Other materials and equipment would be delivered to the site by truck.

Installation of the equipment would occur concurrently with the installation of the pipe

on the pipe rack to allow for a more seamless tie-in at the main process areas. Construction of

other buildings, including warehouse and control buildings, would also occur concurrently with

pipe rack installation. Cheniere would coordinate the arrival of the major equipment with the

completion and curing of the respective foundation so that the equipment can be placed on its
Environmental Impact Statement 2-19 Corpus Christi LNG

foundation when it arrives, minimizing handling and the potential for intermediate storage on

site.

Painting and insulation work would be completed as the piping installation, hydrostatic

testing, pneumatic testing, and equipment erection is completed. After all equipment and piping

has been installed, Cheniere would begin the final road paving, site grading, landscaping, and

cleanup. The temporary construction facilities would be demobilized on a progressive basis as

they are no longer necessary

2.4.2.2 Construction of LNG Vaporization Facilities

LNG vaporization and natural gas send-out facilities would be constructed in the same

manner as the liquefaction facilities described above.

2.4.2.3 Construction of Marine Terminal and LNG Transfer Lines

The LNG berths would be dredged to a depth of -46 feet North American Vertical Datum

of 1988 (NAVD 88)with an additional 2 feet for advanced maintenance and 2 feet paid allowed

overdredge to ensure minimum depth and 3:1 side slopes are met. Hydraulically dredged

materials would be used to fill a portion of a former clay borrow pit and to assist in the

facilitation of capping bauxite residue beds.

The primary materials that would be used in the marine berth construction are steel-pipe

pilings, concrete, and reinforcing steel for concrete. Cheniere anticipates that the steel-pipe piles

would be fabricated offsite and delivered to the site by barge. The concrete would either be

produced in a batch at the main Terminal site or purchased from a local supplier.

Each of the two LNG carrier berths would contain at least four breasting dolphins and six

mooring structures that would be constructed to provide flexibility in berthing the full size range

of design vessels. One jetty platform would be constructed in each berthing area and would

consist of a single level, pile-supported concrete platform with a design elevation of 37 feet. The

surface of the platforms would slope towards the shore in order to drain rainwater and potential

LNG discharges. Curbs would also be constructed to separate the LNG areas from the remainder

of the jetty surfaces and at the perimeter of the jetty platform, where necessary, to adhere to

Occupational Safety and Health Administration requirements.

The jetty platforms would each support fixed equipment including a jetty substation

building, marine cryogenic liquid cargo transfer and vapor return arms, gangway tower/crane,

LNG and utility piping, fire suppression equipment, elevated access platforms, elected firewater

monitors, and a jetty control building. The approach and pipe trestles would link the rear of the

jetty platforms and the shore. Additionally, 4-foot catwalks would be installed to provide access

to mooring and breasting dolphins and to the shore.

Work on the marine berth platforms, approach, and pipe trestles would begin first to

allow installation of equipment and piping. All steel pilings would be coated with coal tar epoxy

from a point 15 feet below the mudline or groundline, to the soffit of the pile cap. Pile driving

would last approximately 4 to 6 months. Concrete filled high-density polyethylene pipe sleeves

would be required for all piling under the pipe trestle to provide splash zone corrosion resistance.

During construction, the dredging operations around the Terminal berth that would occur

over a period of months would accommodate passing commercial vessel traffic. A moving

exclusion zone around the LNG carrier would be expected to limit the movements of other
Environmental Impact Statement 2-20 Corpus Christi LNG

vessels for the relatively brief period while an LNG carrier is transiting to or from the Terminal’s

berth. In other ports with LNG terminals and comparable levels of vessel traffic, such moving

exclusion zones have caused inconvenience at times but have not had sustained significant

impacts on other commercial users of the channel. A stationary exclusion zone around the berth,

likely up to the edge of the La Quinta Channel, would limit the ability of other vessels to

approach the LNG carrier but would not restrict their ability to proceed past the Terminal within

the La Quinta Channel.

2.4.2.4 TemporaryConstruction Facilities

Main construction offices would be located on-site or in a nearby construction laydown

or parking area. This area would provide common office areas for all contractors and parking

areas outside the boundaries of the main construction areas. Other temporary construction

facilities that would be constructed as needed include support/satellite offices, warehousing,

lunchrooms, temporary access roads, parking lots, and material laydown storage. These facilities

can be mobilized without significant preparation work. Additional temporary facilities, primary

laydown areas, parking, and dredge disposal would be located on site or in close proximity to the

site.

The permanent site grading for drainage would be directed to an outfall on the western

perimeter of the Terminal site to ensure proper drainage during construction and operation. To

facilitate this, a system of drainage ditches would be constructed and would connect to a larger

existing drainage ditch that runs along the western edge of the site and flows into the La Quinta

Ship Channel. A Stormwater Pollution Prevention Plan (SWPPP)to control sediment and silt

would be implemented during construction. Site preparation and laydown areas would be

located in an area northwest of the Terminal and would include the installation of construction

power, communications, and water. The primary employee parking area for construction

personnel would be located north of the Terminal site.

Cheniere would have major construction equipment delivered primarily by barge. To

accommodate these deliveries, Cheniere would construct a new roll-on/roll-off area for

unloading equipment from barges to the west of the LNG carrier berths.

2.4.3 Pipeline Facilities

Prior to the start of construction, Cheniere would complete all surveys, locate the

centerline and construction workspaces, and complete land or easement acquisition as needed. If

the necessary easements cannot be obtained through good faith negotiations with property

owners, and the Commission has issued a Certificate for the Project, Cheniere may use the right

of eminent domain granted under Section 7(h)of the NGA and the Rules of Civil Procedure to

obtain easements. Cheniere would site, construct, operate, and maintain all Pipeline facilities in

accordance with all applicable federal and state regulations and industry standards. Figure 2.4-1

shows the typical construction sequence used for an overland pipeline construction spread as

summarized below.
Environmental Impact Statement 2-21 Corpus Christi LNG

Figure 2.4-1 Typical Pipeline Construction Sequence
Environmental Impact Statement 2-22 Corpus Christi LNG

2.4.3.1 Standard Construction and Restoration Techniques

Clearing and Grading

Clearing operations would include removal of vegetation within the construction right-ofway and the temporary construction workspace either by mechanical means or by hand-cutting.

The right-of-way limits would be identified and flagged in the field prior to clearing. Following

clearing, the construction right-of-way and ATWS would be graded as necessary to allow for

safe passage of equipment and to prepare a relatively level work surface for pipeline

construction. Bulldozers would typically perform grading activities.

Trenching

The pipeline ditch would be excavated to the appropriate depth to allow for burial of the

pipe with at least 3 feet of cover as required by 49CFR Part 192 of the DOT regulations. The

trench would be dug with an excavator or ditching machine and the excavated material would be

placed on the spoil side of the trench within the construction right-of-way. Based on available

data, shallow bedrock would not be encountered within the trench depth and blasting would not

be necessary. If water needs to be removed from the trench, the water would be pumped to a

well-vegetated upland area off the right-of-way and/or filtered through a filter bag or siltation

barrier.

Pipe Stringing, Coating, Bending, and Welding

Following excavation of the trench, the pipe would be strung along the trench. The pipe

would be hauled in sections to the right-of-way via a truck from the pipe storage yard. The pipe

would be off loaded and placed next to the trench using a side-boom tractor or vacuum hoe.

Following stringing the pipe sections would be bent as necessary to fit the vertical and

horizontal contours of the trench. A bending engineer would survey the trench to determine the

location and extent of each field bend. Appropriate bends would be made with a hydraulic pipebending machine. The pipe joints would then be lined up end-to-end to allow for welding into

continuous lengths (strings).

All welding would be performed in accordance with API Standard No. 1104. Individual

pipe sections would be welded in two steps. A front-end welding crew would perform the first

step, which would be to clean and align the pipe bevels in preparation for welding and to place at

least the first two passes in the welding process. Back-end welders would perform the section

step, which would be to complete the welds started by the front-end crew. The pipe would be

welded into long strings to minimize the number of welds that have to be made in the trench (tiein welds). Gaps in the welding process would often be left at waterbody/wetland crossings, road

crossings, and other locations where access across the work area is required.

The pipe lengths would be coated (typically with a heat applied epoxy)at a coating mill

prior to being delivered to the Project site. The ends of each pipe section would be left bare to

allow for welding. After welds have been inspected and approved, the weld areas would be field

coated by a coating crew. The pipe coating would be inspected using equipment that emits an

electrical charge, since pipeline coatings are electrically insulating.

Following welding, each weld would be inspected to ensure the structural integrity is

consistent with 49 CFR Part 192 of the DOT regulations. Radiographs or ultrasonic images
Environmental Impact Statement 2-23 Corpus Christi LNG

would be taken and processed on site for real-time results. Those welds that do not meet the

requirements established by the API Standard 1104 would be marked for repair or replacement.

Lowering-In and Backfilling

The trench would be dewatered and cleared of any debris, as necessary before the pipe is

lowered into the trench by side-boom tractors. Once the pipe strings have been lowered in, a tiein crew would make the final welds in the trench. The final welds would then be inspected and

coated. All suitable material excavated from the trench would be replaced during backfilling. In

areas where excavated material is unsuitable for backfilling, additional fill may be brought in

from offsite. In areas where topsoil was separated, the subsoil would be placed into the trench

first and the topsoil would be spread over top. In non-wetland areas the top of the trench may be

slightly crowned to compensate for potential settling. The soil would be inspected for

compaction and scarified as necessary. After backfilling is complete, the pipe would be cleaned

of any internal dirt, water, or debris by pipeline pigs that are propelled through the pipeline by air

pressure.

Hydrostatic Testing

Following the completion of backfilling and cleaning, the pipeline would be pressure

tested to ensure its integrity for the intended service and operating pressure. Water would be

used to hydrostatically test the pipe and the water is normally obtained from water sources

crossed by the pipeline, including available municipal supply lines. The water would be pumped

from the water source into the pipe and would propel a pig through the pipe in a manner that fills

it with water. A high pressure pump would be used to add water to the test section and to

increase the test pressure. At the completion of the hydrostatic test, the pressure would be

removed from the test section by propelling the pig with air and dewatering the pipe. Additional

“drying”pig runs would be made, as necessary, to remove any residual water from the pipe.

Hydrostatic testing is also addressed in section 4.3 of this EIS.

Cleanup and Restoration

All work areas would be final-graded and restored as closely to preconstruction

conditions as possible. Prior to final grading, all construction debris would be picked up along

the right-of-way. Permanent erosion control structures, such as slope breakers, would be

installed during final grading in accordance with our Plan. Our Plan requires that restoration be

completed within 20 days of backfilling, unless prevented by inclement weather conditions.

Private property such as fences, field roads, and driveways would be restored or repaired as

necessary.

Revegetation would be accomplished by seeding disturbed areas in accordance with the

recommendations of the local office of the U.S. Department of Agriculture (USDA), Natural

Resource Conservation Service (NRCS)or as requested by the landowner. Seeding would not be

required in actively cultivated croplands, unless specifically requested by the landowner.

Revegetation is further discussed in section 4.5 of this EIS.

2.4.3.2 Specialized Construction Techniques

Waterbody Construction Methods

To minimize potential impacts, waterbodies would be crossed in accordance with our

Procedures and the crossings would be implemented as quickly and safely as possible. With the
Environmental Impact Statement 2-24 Corpus Christi LNG

exception of the waterbodies that would be crossed by horizontal directional drill (HDD),

waterbodies would be crossed using conventional excavator-type equipment and wet-crossing

techniques, or by horizontal bore. Upland and agricultural swales, ditches, or other such

conveyances would be crossed using either a wet-crossing technique if water is flowing at the

time of crossing, or best management practices (BMPs)as determined by the Environmental

Inspector (EI)if there is no flow at the time of crossing. Additional information regarding

waterbody crossing methods is provided in section 4.3 of this EIS.

Except where reasonable alternative access is available, temporary construction

equipment crossings would be installed across waterbodies to gain access along the right-of-way

for construction. After equipment crossings are established, construction equipment would not

be permitted to drive through a waterbody for access and the equipment crossing would be

removed once access in the area is no longer needed. Only the equipment necessary to construct

the crossing and install the pipe would be allowed to work in the waterbody.

To facilitate pipeline construction across waterbodies, ATWS may be needed adjacent to

waterbodies to assemble and fabricate the pipe as necessary to complete the crossings. The

ATWS would be located at least 50 feet away from the waterbody, except in actively cultivated

croplands or other disturbed areas, as required by our Procedures. In areas where ATWS is

required to be set back from the waterbody, vegetation would not be cleared between the ATWS

and the waterbody.

Following installation, a minimum of 3 feet of cover would be placed over the pipe.

Waterbody bed and bank contours would be restored to preconstruction conditions and the banks

would be stabilized as soon as possible following construction activities. Permanent erosion

control structures would be maintained to minimize erosion. Following construction,

waterbodies would be inspected regularly to ensure that temporary erosion controls are

functioning properly and that revegetation is progressing satisfactorily.

Horizontal Directional Drill

HDD is a pipeline construction method that minimizes surface impacts by drilling a hole

and pulling the pipe through it rather than digging a trench. HDD requires drilling of a small

diameter hole, or pilot hole, along a predetermined design path that originates and terminates on

the surface. The pilot hole is then enlarged sufficiently to accommodate the pipe to be installed.

The pipe may or may not be installed concurrently with the hole enlargement depending upon

the final diameter of the enlarged hole and the soil conditions encountered.

Active Croplands

In accordance with our Plan, topsoil would be segregated in actively cultivated or rotated

agricultural lands, pastures, and hayfields, unless otherwise approved in writing by the

landowner prior to the commencement of grading activities. After the pipe has been lowered

into the trench, the subsoil would be used for backfilling and the topsoil would be spread across

the graded right-of-way. In active croplands, the depth of cover would be 4 feet unless otherwise

specified. Soil compaction would be treated, as necessary, in accordance with our Plan.

Prior to construction, Cheniere would work with affected landowners to identify any

drain tiles within the construction workspace. Any drain tiles damaged during construction

would be repaired to landowner specifications or to preconstruction conditions. At this time

Cheniere has not identified any existing drain tiles along the route.
Environmental Impact Statement 2-25 Corpus Christi LNG

Road Crossings

The crossing method used for a particular road would be dependent upon site-specific

conditions and state and local statutes. Prior to construction, Cheniere would contact the “One

Call”or “Call Before You Dig”system to verify and mark all utilities along the construction

workspaces. Generally, Cheniere would bore under paved roadways. Boring entails drilling a

hole below the roadway through which the pipe would pass. First, a bore pit is dug on one side

of the roadway and a receiving pit is dug on the other side. The bore pit is excavated to a depth

equal to the depth of the trench and is graded such that the bore would follow the grade of the

pipe. A boring machine is lowered into the bore pit and placed on supports. The machine cuts a

shaft under the roadway using a cutting head mounted on an auger. The auger rotates in a

casing, both of which are pushed forward as the hole is cut. The pipe is then pushed through the

casing.

During the open cut method of crossing a roadway, at least one lane of traffic would be

kept open when constructing on or across residential streets. During the brief period when the

road is completely cut, steel plates would be available on-site to cover the trench to permit travel

by emergency vehicles. Traffic lanes and home access would be maintained except for the

temporary periods necessary for installing the pipe.

2.4.3.3 Aboveground Facilities

Aboveground facilities associated with the Project would include M&R stations, MLVs,

pig launchers and receivers, and compressor stations. Sites for the aboveground facilities would

be cleared and graded as described above for the pipeline installation. The area would be cleared

of trees, brush, and debris, and would be graded and compacted to surveyed elevations.

Where foundations are required for the aboveground facilities, the ground would be

excavated and improved as needed for the installation of building foundations and pipe supports.

Forms and reinforcing bars would be installed in the excavated areas, as necessary, and high

strength concrete would be poured to the appropriate levels for the major equipment. Concrete

pours would be randomly sampled and tested to verify compliance with specifications. All

concrete would then be properly cured to the desired strength.

After the foundations have sufficiently cured, installation of buildings and machinery

would begin. At compressor station sites, installation of the machinery, buildings, and piping

would be concurrent. The steel frames of the buildings would be erected first, followed by

interior walls, insulation, exterior walls, and the roof. Cut-outs that allow for protrusion for inlet

and exhaust vents through the siding would be flashed to ensure that the buildings are weather

tight. Each building would be acoustically insulated and silencers would be installed on the

engine exhaust stacks and the air intakes to abate noise.

Installation of aboveground piping systems would begin concurrently with the foundation

work. Piping would require welding except where the piping is connected to flanged or threaded

components. Aboveground piping would be installed on concrete or metal pipe supports and

would be painted. Electrical conduit systems would also be installed. Once the structures and

equipment are set on foundations, they would be connected to the piping and electrical conduit

systems. Electrical wiring would be installed to provide power and connect instrumentation to

control systems.
Environmental Impact Statement 2-26 Corpus Christi LNG

As each system is completed, they would be tested and calibrated to ensure proper

operation. Aboveground piping would be hydrostatically tested. Controls and safety devices

such as the emergency shutdown system, relief valves, gas and fire detection facilities, and other

safety devices would be checked and tested. The compressor units would be operated on a trial

basis following completion of the piping and mechanical work to ensure proper operation of the

safety and protective devices. The trial operation would involve several short duration runs

conducted over the course of several days. Start-up of the compressor units would commence

once all testing is complete.

2.5 OPERATION AND MAINTENANCE

The Terminal would employ approximately 175 full-time staff. All permanent personnel

would be trained in LNG safety, cryogenic operations, and proper operation of all equipment.

Operators would meet all of the training requirements of the DOT minimum federal safety

standards specified in 49CFR Parts 192 and 193. The standards imposed are in accordance with

the Natural Gas Pipeline Safety Act of 1969, as amended.

The Terminal would be a bidirectional facility capable of loading and unloading LNG

cargoes to/from the LNG carriers, liquefying natural gas from the Pipeline to produce LNG, and

vaporizing stored LNG and sending the resultant natural gas into the Pipeline. Once Cheniere

decides on its customers, it would be determined whether the facility would be in liquefaction or

vaporization mode.

Operating procedures would be developed for the facilities, and extensive training would

be provided for operational personnel to ensure that they are familiar with and understand the

importance of adherence to safety procedures. These procedures would provide functional

requirements for the control and safeguarding systems, to include addressing safe start-up,

normal shutdowns, emergency shutdowns, fire, gas, and spills, as well as routine operation and

monitoring.

The LNG carriers would enter Corpus Christi Bay from the Gulf and transit between the

Terminal and the Gulf under the command of the ship’s master with local pilots to provide

specialized navigational-related advice. Together, they would decide whether the existing and

anticipated environmental conditions allow safe entry and transit between the Gulf and the

Terminal via the Aransas Pass Channel, Corpus Christi Channel, and the La Quinta Channel.

The pilots would be assigned by the ship’s master to direct the maneuvering of the LNG carrier

in the harbor with the assistance of accompanying tugboats as necessary. The pilots would

continue to advise the ship’s master during the berthing and securing of the ship’s mooring lines

until the LNG carrier is securely moored at the Terminal’s berth.

The cargo transfer arms would be coupled to the LNG carrier’s manifold by the

Terminal’s personnel. A communications and linked ESD system umbilical cable deployed

between the ship and the Terminal would connect these critical functions between cargo control

systems during the period that the cargo transfer arms remain connected. The emergency

shutdown system would be tested from both the ship and Terminal control rooms before cargo

transfer operations begin.

The ship and Terminal operators would prepare and align their respective side’s cargo

systems and valves after performing the required safety checks and procedures so that LNG

cargo transfer between the ship and the Terminal can begin. During all cargo transfer operations,
Environmental Impact Statement 2-27 Corpus Christi LNG

the LNG carrier’s manifold would be continuously visually monitored by the ship duty personnel

and also remotely by video cameras mounted on the jetty platform which transmit real-time

video to display monitors located in both the jetty and main control rooms. Additionally, a

security guard would be located at the facility entrance and continuously staffed 24 hours a day,

seven days a week.

Facility maintenance would be conducted in accordance with 49 CFR 193 Subpart G.

The full-time maintenance staff would conduct routine maintenance and minor overhauls. Major

overhauls and other major maintenance would be handled by soliciting the services of trained

contract personnel to perform the maintenance. All scheduled and unscheduled maintenance

would be entered into a computerized maintenance management system. All personnel would be

trained on the use of this system.

Scheduled maintenance, such as preventive and predictive maintenance of equipment

would be input into the system to automatically print out work orders either on a time basis or on

hours of operation, depending on the requirement. Scheduled maintenance would be performed

on safety and environmental equipment, instrumentation, and any other equipment that requires

maintenance on a routine basis. When a problem is detected that requires unscheduled

maintenance attention, the person that detects the problem would enter it into the computerized

maintenance management system. If a problem requires immediate attention, the appropriate

person would be notified.

The Pipeline would be patrolled on a routine basis and personnel qualified to perform

both emergency and routine maintenance on interstate natural gas pipeline facilities would

handle all maintenance.

The Pipeline and associated facilities would be operated and maintained in a manner such

that pipeline integrity is maintained in the interest of assuring that a safe, continuous supply of

natural gas reaches its ultimate destination. Maintenance activities would include regularly

scheduled gas leak surveys and measures necessary to repair any potential leaks. The latter may

include repair or replacement of pipe segments. All fence posts, signs, marker posts, aerial

markers, and decals would be painted or replaced to ensure that the pipeline locations would be

visible from the air and ground. All valves would be periodically inspected and greased.

Additionally, the Pipeline would be patrolled from the air periodically which would

provide information on possible leaks, construction activities, erosion, exposed pipe, population

density, possible encroachment, and other potential problems that may affect the safety or

integrity of the Pipeline. Cathodic protection units installed along the Pipeline would be

regularly maintained.

Other maintenance functions would include periodic seasonal mowing of the permanent

easement in accordance with our Plan and Procedures, terrace repair, backfill replacement, and

periodic inspection of water crossings. During pipeline easement maintenance, Cheniere would

not use herbicides or pesticides within 100 feet of a wetland or waterbody unless approved by the

appropriate state and local agencies.

2.5.1 Environmental Compliance and Monitoring

Cheniere would implement environmental compliance and monitoring requirements from

our Plan and Procedures during construction of the Terminal and Pipeline. They would also

incorporate compliance and monitoring requirements from federal, state, and local permits
Environmental Impact Statement 2-28 Corpus Christi LNG

obtained for the Project. To ensure environmental compliance, Cheniere would provide all

contractors with copies of all construction procedures, plans and specifications, a construction

drawing package, and all environmental permits, certificates, and/or clearances associated with

the Project prior to construction.

Additionally, Cheniere would conduct environmental training for its field personnel and

contractors. This training would focus on the implementation of Cheniere’s construction

procedures, techniques and plans, other Project-specific permit conditions, and impact

minimization measures. Cheniere would ensure that training personnel provide thorough

training sessions regarding the environmental requirements, all individuals receive

environmental training prior to starting work, adequate training records are kept, and refresher

training is provided as needed to maintain high awareness of environmental requirements.

Cheniere would employ one or more EI(s)to ensure that environmental conditions

associated with permits or authorizations are satisfied. The EI(s)would be onsite daily to

monitor and document environmental compliance and report to the Commission on a weekly

basis regarding Project activities. The EI(s)duties would include, but not be limited to, ensuring

compliance with all environmental commitments, construction procedures, techniques and plans,

and all permit conditions and requirements. The EI(s) would also verify construction

workspaces prior to use, confirm that all sensitive resources are properly marked, and ensure

proper installation and maintenance of all erosion control devices. The EI(s)would have peer

status with all other inspectors, would have the authority to enforce permit and FERC

environmental conditions, to issue stop-activity orders, and impose corrective actions to maintain

environmental compliance.

In addition to the EI(s), contractors and construction work areas would be subject to

periodic inspections throughout construction and restoration phases of the Project, by federal,

state, and local agencies including the Commission. Representatives of these agencies could

require the implementation of additional and/or corrective environmental measures. These

representatives could also issue work stoppages, impose fines, and recommend additional actions

in response to environmental compliance failures. Inspection reports prepared by us would be

entered into the Commission’s public record. Inspection reports prepared by other agencies

would be made available per their respective policies and guidelines.

Cheniere has developed protocols, in complaint resolution procedures, to handle

complaints received from landowners. Cheniere would designate one Issues Resolution

Coordinator, who would be responsible for making sure that all reported complaints and issues

are communicated internally and that timely responses are provided to the callers. In addition,

right‐of‐way agents or other staff of Cheniere receiving phone calls from landowners identifying

complaints or other issues would log the calls into a file that contains the specific information

about the complaint. The Project personnel would notify the Issues Resolution Coordinator with

the details of the call. The Issues Resolution Coordinator would then contact the construction

field office and discuss the issue with the appropriate individual, (e.g., Right‐of‐Way

Representative, Chief Inspector, or Lead EI)and determine the necessary steps and timeframe to

resolve the issue. In addition, landowners would be supplied with a copy of the FERC’s helpline

information in the event they need to contact FERC. The Issues Resolution Coordinator would

then contact the original caller as soon as practicable, but no later than 48 hours after the initial

call, to explain how the issue is to be resolved and the expected timeframe for the resolution to

occur. The Issues Resolution Coordinator would then follow up with the appropriate
Environmental Impact Statement 2-29 Corpus Christi LNG

construction representative to ensure that the resolution has been or is scheduled to be

implemented as indicated to the caller. The Issues Resolution Coordinator would notify the

Project Director, Right‐of‐Way Manager, and Environmental Manager of the issue and the

agreed upon resolution and anticipated timeframe. The Issues Resolution Coordinator would

record the resolution plan and would track and report all calls received and the resolution plans

on a regular basis to coincide with the construction reporting schedule for the FERC. A final

phone call would be made to the caller within 24 hours after completion of the resolution plan.

Parties concerned with environmental compliance may contact the Commission’s Dispute

Resolution Service (DRS). The DRS is a professional team that promotes timely and high

quality resolution of disputes. DRS specialists are highly trained in mediation, negotiation, and

facilitation and are able to assist parties with the resolution of environmental compliance matters.

2.6 FUTURE PLANSAND ABANDONMENT

There are no plans for future abandonment or expansion of facilities.

ALTERNATIVES

SECTION 3

Environmental Impact Statement 3-1 Corpus Christi LNG

3.0 ALTERNATIVES

As required by NEPA and Commission policy, we evaluated a number of alternatives to

the Project to determine if any would be reasonable and environmentally preferable to the

proposed action. Below, we discuss alternative actions for the Terminal facilities and Pipeline

facilities. The alternative actions include the no-action alternative, energy alternatives, systems

alternatives, and alternatives sites and pipeline routes for the Project.

The evaluation criteria for selecting potentially reasonable and environmentally

preferable alternatives include the following:

 technical and economic feasibility;

 significant environmental advantages over the proposed Project or segments of it;and

 ability to meet the Project objectives for providing facilities necessary to import and

export LNG and deliver natural gas into the existing interstate and intrastate natural gas

pipeline system in the Corpus Christi, Texas area.

With respect to the first criterion, it is important to recognize that not all conceivable

alternatives are technically and economically feasible. Some alternatives may be impracticable

because of the cost, existing technologies, constraints of existing system capacities, and logistics

in light of the overall project objectives. In conducting an alternatives analysis, it is also

important to consider the environmental advantages and disadvantages of the proposed action

and to focus the analysis on those alternatives that reduce impacts or offer a significant

environmental advantage.

Through the application of the evaluation criteria and subsequent environmental

comparisons, each alternative was considered until it was clear that the alternative was not

preferable to the proposed action because it would result in significantly greater environmental

or social impacts that could not be readily mitigated. Alternatives that appear to be the most

reasonable with similar levels of environmental impact are reviewed below.

3.1 TERMINAL FACILITIES

3.1.1 No-Action Alternative

Under the No-Action Alternative, the objectives of the Project would not be met and

Cheniere would not provide the proposed natural gas transportation capacity for import or

export. In addition, the potential adverse and beneficial environmental impacts identified in

section 4.0 of this EIS would not occur.

Development of and production from conventional and unconventional gas formations

are occurring throughout many of areas of the U.S. and are projected to continue for many years.

Cheniere indicated it could provide LNG to foreign countries at a competitive price and,

therefore, replace higher-cost shipments from other sources. Additionally, should market

demands shift in the future, the Project would have vaporization capabilities to allow LNG to be

imported, vaporized, and sent out for delivery to U.S. customers.

With or without the No-Action Alternative, other LNG export/import projects could also

be developed elsewhere in the Gulf Coast region or in other areas of the U.S. resulting in both

adverse and beneficial environmental impacts to those of the proposed Project. Development of
Environmental Impact Statement 3-2 Corpus Christi LNG

any new LNG export terminals on previously undeveloped sites would likely result in similar or

greater environmental impacts, in both magnitude and duration, than those of the proposed

Project.

The No-Action Alternative could also require that potential end users make other

arrangements to obtain natural gas service, make use of alternative fossil fuel energy sources

(e.g., coal or fuel oil), or possibly make use of other traditional long-term fuel source alternatives

(e.g., nuclear power)and/or renewable energy sources (e.g., solar power)to compensate for the

reduced availability of natural gas that would otherwise be supplied by the proposed Project.

Although international energy conservation could also result from the No-Action Alternative,

that option is beyond the scope of this analysis.

3.1.2 Alternative EnergySources

It is important to consider alternative energy sources as part of the alternative selection

process. As noted above, implementing the No-Action Alternative could force potential natural

gas customers to seek other forms of energy. Traditional energy alternatives to natural gas

include coal, oil, hydroelectric, and nuclear power. Renewable energy resources such as solar,

ocean energy, biomass, wind, landfill gas, and municipal solid waste represent new, advanced

energy alternatives. Conceivably, each of these energy alternatives could support the generation

of new electric power, which is a major consumer of natural gas along with residential heating,

commercial, and industrial uses.

The International Energy Agency (IEA)(2012b)reported that coal exports are increasing

and in the United States several new coal export projects were recently proposed, suggesting that

in many international markets coal will remain competitive with natural gas in spite of coal’s

greater air emissions. EPA (2013)stated that compared to the average air emissions from coalfired generation, natural gas produces half as much CO2, less than a third as much nitrogen

oxides, and 1 percent as much sulfur oxides at power plants. Similarly, fuel oil is commonly

used for power generation in many countries and will continue to compete with natural gas as a

fuel source in spite of greater emissions. As a result, if the No-Action Alternative is selected, it

could result in a greater use of other fossil fuels and a potentially substantial increase of

environmental impacts as compared to the use of natural gas. However, many countries are

cognizant of the greater environmental impact of coal and fuel oil and prefer to use natural gas as

a fuel source.

There has been a recent renewed interest in electric power generation by nuclear energy.

However, because of the increasing demand in electricity consumption worldwide, the U.S.

Energy Information Administration (2012)estimates that the proportion of electricity generated

by nuclear power will decrease from 19percent to 15 percent. In addition, regulatory hurdles,

public concern over nuclear power and nuclear waste disposal, construction costs, and plant

construction lead times make it unlikely that nuclear generating capacity could be available to

serve all the markets targeted by the Project on a similar timeline. Further, plans for nuclear

power generation have been scaled back as countries reconsidered policies after the accident at

the Fukushima Daiichi nuclear power plant near Fukushima, Japan, but capacity is still projected

to rise, led by China, Korea, India, and Russia (IEA, 2012a).

Renewable energy may become an increasingly significant factor in meeting future

energy demands worldwide. As reported by IEA (2012a;2012b), renewables are projected to

become the world’s second largest source of power generation by 2015, and are expected to
Environmental Impact Statement 3-3 Corpus Christi LNG

close in on coal as the primary source by 2035. However, this rapid increase hinges critically on

continued subsidies. In 2011, these subsidies (including for biofuels)amounted to $88 billion,

but to reach the projection noted above, the subsidies would need to increase to $4.8 trillion by

2035 (IEA 2012a).

Hydropower is currently the largest source of renewable electric power generation

worldwide, and IEA expects this trend to continue through 2030. However, as with nuclear

power generation, there are high costs associated with developing substantial hydropower

projects and long time periods between project conception and the production of electric power.

Other compromising renewable energy resources include solar, ocean energy, and

biomass. However, the cost of these types of renewable energy projects is currently high per

energy output unit in comparison to natural gas-fired power generation. Photovoltaic production

in support of solar energy is increasing, and the cost of photovoltaic systems is decreasing, with

photovoltaic cells potentially able to greatly supplement electrical generation resources.

Ocean energy is a largely unexplored renewable resource. Technologies to capture ocean

energy are in their infancy, and environmental and engineering considerations are being studied

to better understand the implications of placement of power generating facilities in the ocean.

Entrepreneurs and scientists are exploring the emerging use of algae for biofuels and

other renewable energy applications, and are working to accelerate the development of

applications to use algal biomass. IEA (2012b)projected electric power generation from

biomass technology to increase four-fold through 2035, but that time frame is well beyond the

planned startup and the currently requested authorization lifetime of proposed Project.

Further generation of electrical power by wind would require construction of new wind

turbines and additional electric transmission lines. Although this is likely to occur in many parts

of the world, it is also likely that such development will be slow-paced in most countries due to

the high cost of construction. In addition, wind power cannot be used for constant and reliable

energy production because of the variability in winds, and other power generation facilities are

commonly in place as backup facilities.

Electric generation from municipal waste and landfill methane are growing trends in

developed countries. Again, the cost of these facilities, including operating costs, is beyond the

means of many countries.

With regard to these renewable sources of energy, natural gas is often considered a

“bridge fuel”;a fuel that bridges the time between the dominant use of fossil fuels today and the

greater use of renewable energy sources in the future. Natural gas is cleaner burning than other

fossil fuels and can also reliably serve as backup fuel to renewable energy facilities, which often

provide power intermittently.

There is currently considerable momentum behind advancing renewable energy

technologies and moving toward more diversified energy sources. These advanced technologies,

either individually or in combination, will likely be important in addressing future energy

demands. Presumably, new energy technologies will continue to offset an increasing amount of

fossil fuels to meet growing energy demands, and that situation is not expected to change in the

next decade.

Although it is speculative and beyond the scope of this analysis to predict what action

might be taken by policy makers or end users in response to the No-Action Alternative, it is
Environmental Impact Statement 3-4 Corpus Christi LNG

possible that without the proposed Project, the energy needs may be met by alternative energy

sources, likely resulting in impacts on the environment. Alternative energy forms such as coal

and oil are available and could be used to meet increased demands for energy;however, natural

gas is a much cleaner-burning fuel. These other fossil fuels emit greater amounts of particulate

matter, sulfur dioxide (SO2), carbon monoxide (CO), CO2, hydrocarbons, and non-criteria

pollutants. The use of nuclear energy as replacement of other fuel sources also carries

undesirable consequences, such as negative public perception of the safety of electric generation

through nuclear plants and the disposal of waste products created. Renewable energies, such as

solar, hydroelectric, and wind are not always reliable or available in sufficient quantities to

support most market requirements and would not necessarily be an appropriate substitute for

natural gas in all applications. Therefore, we have dismissed alternative energy sources as a

reasonable alternative to meet the Project objectives.

3.1.3 System Alternatives

System alternatives are alternatives to the proposed action which would make use of

other existing, modified, or proposed facilities that would meet the stated purpose and need of

the proposed action. By definition, implementation of a system alternative would make it

unnecessary to construct part or all of the proposed action. However, additions or modifications

to the system alternatives may be required to increase capacity or provide receipt and delivery

capability consistent with that of the proposed Project. These additions or modifications could

result in environmental impacts that are less than, similar to, or greater than the environmental

impacts of the proposed facility.

Our analysis of system alternatives considers existing, or recently authorized or

proposed9LNG import, export, and storage facilities located in the continental U.S. to replace all

or part of the Project. We considered whether any of the existing, recently authorized, proposed,

or planned LNG import and export terminal projects could be viable system alternatives to the

Project. To be considered a viable system alternative, the existing or proposed project would

need to provide LNG carrier unloading, storage, and send-out capacities similar to Cheniere’s

proposal, in addition to current or planned expansion capacities for the terminals. Facilities

outside of the Gulf Region were not considered, because they do not meet the purpose and need

of the Terminal (due to the geographic region from which they are sourced).

For a system alternative to be viable, it must be technically and economically feasible. It

must also be compatible with any contractual agreements Cheniere may have relating to the

export of LNG. In addition, a viable system alternative would offer a significant environmental

advantage over the Project. The system alternatives considered in this analysis are depicted on

figure 3.1-1 and described below. Although we have considered each of the planned, proposed,

or recently authorized projects below as potential system alternatives, the market would

ultimately decide which and how many of these facilities are built.

9

Proposed projects are projects for which the proponent has submitted a formal application with the FERC;planned

projects are projects that have been announced but for which no formal application has been submitted.
Environmental Impact Statement 3-5 Corpus Christi LNG

Figure 3.1-1 System alternatives for the Terminal
Environmental Impact Statement 3-6 Corpus Christi LNG

3.1.3.1 Existing LNG Import Terminals with Planned, Proposed, or Authorized

Liquefaction Projects

There are six existing LNG import terminals in the southeastern United States along the

Gulf of Mexico:

 Cameron LNG, LLC (Cameron LNG)Terminal;

 Freeport LNG Development, LP (Freeport LNG)Terminal;

 Golden Pass Products, LLC (Golden Pass)Terminal

 Gulf LNG Energy, LLC (Gulf LNG)Terminal;

 Sabine Pass LNG, LP (Sabine Pass LNG)Terminal;and

 Trunkline LNG Company, LLC (Trunkline LNG)Lake Charles LNG Terminal.

The Sabine Pass Liquefaction Project is under construction and the other import terminals

are in regulatory review and permitting process for adding liquefaction and export capabilities.

Each of these facilities was considered as a system alternative to Cheniere’s proposed Project.

Cameron LNG Terminal

Cameron LNG is proposing to construct and operate a LNG liquefaction and export

facility adjacent to the existing Cameron LNG Import Terminal in Cameron Parish, Louisiana

approximately 240 miles northeast of the proposed Terminal site (see figure 3.1-1). The

Cameron LNG Liquefaction Project would include three liquefaction trains and related facilities

and would be capable of exporting 12 million metric tons per year (mtpy)of LNG. Cameron

LNG entered the pre-filing process on May 9, 201210 and filed an application with the FERC on

December 7, 201211 (Docket No. CP13-25). Cameron LNG expects to begin delivering LNG to

international markets in 2017. A final EIS was issued for the Cameron LNG Liquefaction

Project on April 30, 2014.

Although the Cameron LNG Liquefaction Project is estimated to start operations around

the same time as Cheniere’s Project, it would require additional capacity to meet Cheniere’s

objectives and any customer commitments. Cameron has not requested authorization for the

increased capacity and receipt of permits and approvals for the additional facilities that would be

needed to meet Cheniere’s objectives. The increased time to acquire the necessary permits

would not meet Cheniere’s timeline of initial export in 2017. Cameron LNG’s application states

that Cameron LNG has executed long-term agreements for all of the proposed facility capacity,

which would make it a nonviable alternative for the planned capacity at the Terminal. In

addition, as proposed, the natural gas feedstock for the Project would be sourced from the south

Texas region and transporting this gas to Cameron LNG would require far greater transportation

costs, potential additional facilities, and the associated additional environmental impacts.

Therefore, the Cameron LNG Liquefaction Project was not considered to be a reasonable

alternative to the proposed Project and was removed from further consideration.

10 Docket No. PF12-12

11 Docket No. CP13-25
Environmental Impact Statement 3-7 Corpus Christi LNG

Freeport LNG Terminal

The Freeport LNG Terminal is on Quintana Island in Brazoria County, Texas. The

import terminal, which started operations in 2008, includes two 160,000 m3LNG storage tanks

and a single berth capable of handling LNG carriers in excess of 200,000 m3. It has a peak send

out capability of approximately 1.5 Bcf of natural gas.

Freeport LNG Expansion, LP and FLNG Liquefaction, LLC (collectively, FLEX)

propose to add liquefaction facilities to its existing terminal to provide export capacity of

approximately 13.2 mtpy of LNG. The existing Freeport LNG Terminal is about 150 miles

northeast of the proposed Terminal site (see figure 3.1-1). This project would require

approximately 86 acres for three proposed trains, each with a capacity of 4.4 mtpy. FLEX filed

two separate applications to the DOE/FE to export LNG to Free Trade Agreement countries,

each for export of 511 Bcf per year. The DOE/FE approved the applications in February 2011

and 2012. On December 17 2010, FLEX submitted an application to the DOE/FE to export LNG

to non-Free Trade Agreement nations, and the DOE/FE authorized such export on May 17, 2013.

FLEX filed its application with the FERC in August 201212. A draft EIS for the Freeport LNG

Expansion Project was issued on March 14, 2014.

On July 31, 2012, Freeport LNG Expansion signed a 20-year agreement with Osaka Gas

and Chubu Electric for 100 percent of the first train (4.4 mtpy), and in February 2013 signed a

20-year agreement with BP for all of the second train (4.4 mtpy). In September 2013, FLEX

signed separate liquefaction tolling contracts with Japan’s Toshiba Corp and South Korea’s SK

E&S for all of the third train (4.4 mtpy).

FLEX anticipates start-up for the first liquefaction train in November 2016, with full

service anticipated 48 to 54 months after initiation of construction, or 2020 to 2021. Although

the Freeport LNG Expansion is estimated to start operations prior to Cheniere’s Project, it would

not produce at full capacity until after the planned full capacity date of the Terminal. In addition,

the full capacity of the Freeport LNG Expansion is contracted and use of the Freeport LNG

Terminal as a system alternative to meet Cheniere’s objectives and any customer commitments

would require that FLEX construct and operate three additional liquefaction trains and associated

facilities, as well as additional import facilities, similar to those of the Project which would likely

result in similar environmental impacts. However, FLEX has not requested authorization for the

increased capacity and receipt of permits and approvals for the additional facilities that would be

needed to meet Cheniere’s objectives. The increased time to acquire the necessary permits

would not meet Cheniere’s timeline of initial export in 2017. Therefore, the Freeport

Liquefaction Project was not considered to be significantly environmentally preferable or a

reasonable alternative to the proposed Project and was removed from further consideration.

Golden Pass Terminal

The Golden Pass Terminal is near the town of Sabine Pass, Texas, on the western shore

of Sabine Pass Channel, about 240 miles northeast of the proposed Terminal site (see

figure 3.1-1). Operations started in 2010 on the approximately 477-acre site. The import

terminal includes five 155,000 m3LNG storage tanks and two LNG carrier berths. It has a

maximum send-out capacity of 2.5 Bcf/d of natural gas. The planned export facility would use

12 Docket Nos. CP12-509and CP12-29
Environmental Impact Statement 3-8 Corpus Christi LNG

the existing storage tanks, berthing facilities, and pipeline infrastructure of the import terminal

and would have a send-out capacity of 15.6 mtpy of LNG.

Golden Pass received approval from DOE/FE to export LNG to Free Trade Agreement

countries on October 7, 2012. On October 26, 2012, Golden Pass submitted an application to

export LNG to non-Free Trade Agreement nations.

On May 16, 2013, Golden Pass requested that the FERC initiate the pre-filing process for

the project13. At the time this EIS was prepared, Golden Pass was still early in our pre-filing

process. As a result, the Golden Pass LNG Terminal is substantially behind Cheniere in the

permitting and review schedule and therefore, would likely not be permitted for service in time

to meet any customer commitments of the Project, beginning in 2017. In addition, the

environmental impacts of constructing and operating the facilities needed to expand beyond the

planned capacity would likely be similar to those of the Project. Therefore, this project would

not provide a significant environmental advantage to the proposed Project and was not

considered further.

Gulf LNG Terminal

The Gulf LNG Terminal is on a 40-acre site in Pascagoula, Mississippi, about 550 miles

northeast of the proposed Terminal site (see figure 3.1-1). The terminal started operations in

October 2011 and has a send-out capacity of 1.3 Bcf/d of natural gas. The import terminal

includes two 160,000 m3LNG storage tanks and a single LNG carrier berth designed to receive

LNG carriers up to 250,000 m3in capacity. On June 15, 2012, Gulf LNG received authorization

from DOE/FE to export to Free Trade Agreement countries.

Gulf LNG would construct its export facilities at its existing terminal to export up to 11.5

mtpy of LNG. On May 9, 2014, Gulf LNG requested to use the FERC pre-filing process14, and

on May 21, 2014, the FERC approved the request and initiated the pre-filing process.

The Gulf LNG Terminal is substantially behind the Project in the permitting and review

schedule and therefore, could not be permitted for service in time to meet any customer

commitments of the Project beginning in 2017. As a result, the planned Gulf LNG Liquefaction

Project does not meet the Project objective and was not further evaluated.

Sabine Pass LNG Terminal

The Sabine Pass LNG Terminal is in Cameron Parish, Louisiana, on the eastern shore of

the Sabine Pass Channel, approximately 240 miles northeast of the proposed Terminal site (see

figure 3.1-1). The terminal is on approximately 853 acres and includes five LNG storage tanks

with a total storage capacity of 16.9Bcf and two LNG carrier berths. The facility has a send-out

capacity of 4 Bcf/d of natural gas.

On April 16, 2012, the FERC authorized Sabine Pass LNG to receive, process, and export

16 mtpy of domestically produced natural gas as part of its liquefaction project15. The Sabine

Pass Liquefaction Project is permitted for up to four liquefaction trains, each with an average

liquefaction capacity of approximately 4 mtpy, and in August 2013, Sabine Pass LNG applied to

the FERC to construct and operate two additional trains. The project is under construction and

13 Docket No. PF13-14

14 Docket No. PF13-4

15 Docket No. CP11-72
Environmental Impact Statement 3-9 Corpus Christi LNG

will involve the permanent use of about 191 acres as well as temporary disturbance of about 97

acres within the existing Sabine Pass LNG Terminal site. All 16 mtpy of LNG of the first four

trains is fully committed to Sabine Pass LNG customers. In early 2013, Sabine Pass LNG

announced that Total Gas and Power North America had signed up to take gas volumes

equivalent to 2 mtpy from the fifth train and United Kingdom-based Centrica had contracted for

an additional 1.75 mtpy. Therefore, additional import and export facilities would be needed to

meet Cheniere’s objectives, likely resulting in similar environmental impacts to the proposed

Project. The permitting and authorization processes from constructing these additional facilities

would preclude Sabine Pass LNG from meeting Cheniere’s schedule, including any customer

commitments. As a result, the Sabine Pass Liquefaction Project was not considered to provide a

significant environmental advantage or be a reasonable system alternative to the Project and was

not evaluated further.

Lake Charles LNG Terminal

The Lake Charles LNG Terminal is in Lake Charles, Louisiana, and started operations in

1977. The import terminal is situated on approximately 125 acres about 280 miles northeast of

the proposed Terminal site (see figure 3.1-1)and has a peak send-out capacity of 2.1 Bcf/d of

natural gas. Two LNG carrier berths provide loading and unloading capacity.

On July 22, 2011, Lake Charles Exports, LLC received authorization from DOE/FE to

export LNG to Free Trade Agreement countries from the Lake Charles LNG Terminal. On

March 25, 2014, Trunkline LNG filed an application with the FERC for authorization to

construct and operate the Lake Charles Liquefaction Project16. Trunkline LNG would construct

the project on an approximately 400-acre parcel, about 0.5 mile west of the existing Lake

Charles LNG Terminal. The facility would include three liquefaction trains, each capable of

producing 5 mtpy for a total output capacity of 15 mtpy. Trunkline LNG anticipates an inservice date of August 2018.

Although the Lake Charles Liquefaction Project would provide approximately 1.5 mtpy

more LNG send-out capacity than the Project, its export capacity is solely contracted to one

customer, BG LNG. Additional import and export facilities would be necessary to meet

Cheniere’s objectives. Trunkline LNG has not requested authorization for the increased

capacity, and receipt of permits and approvals for the additional facilities required to meet

Cheniere’s schedule, including any customer commitments. Therefore, this alternative was not

further evaluated.

3.1.3.2 Proposed and Planned Stand-Alone LNG Export Terminals

In addition to the six existing LNG import facilities described above, are six planned or

proposed stand-alone liquefaction projects along the Texas Gulf Coast:

 planned Gulf Coast LNG Exports, LLC (Gulf Coast)Liquefaction Project;

 proposed Excelerate Liquefaction Solutions, LLC (ELS)Lavaca Bay LNG Project;

 proposed Magnolia LNG Project;

 planned Gasfin Development USA, LLC (Gasfin)LNG Project;

16 Docket No. CP14-120
Environmental Impact Statement 3-10 Corpus Christi LNG

 planned Waller Point LNG (Waller Point)Project;and

 planned CE FLNG, LLC (CE FLNG)LNG Project.

These projects are new or “greenfield”projects that are not associated with existing LNG

Import terminals that were considered as potential system alternatives.

Gulf Coast Liquefaction Project

The Gulf Coast Liquefaction Project would export LNG from a planned export terminal

at the Port of Brownsville in Brownsville, Texas, about 130 miles south of the proposed

Terminal site (see figure 3.1-1). On October 16, 2012, Gulf Coast received authorization from

DOE/FE to export LNG to Free Trade Agreement countries. At the time this EIS was prepared,

Gulf Coast had not requested that the FERC initiate the pre-filing process.

The project, as proposed to the DOE/FE, would include a new terminal on about

500 acres, four liquefaction trains capable of liquefying a total of 2.8 Bcf/d of natural gas, an

unspecified number of LNG storage tanks, a marine berth, and a pipeline connecting the terminal

to existing natural gas transportation lines. Rather than enter into long-term natural gas supply or

LNG export contracts, Gulf Coast would set up liquefaction tolling agreements allowing

individual gas customers to deliver gas and receive LNG from the terminal. Gulf Coast

anticipates in service in 2018.

As a greenfield facility, the environmental impacts associated with development on an

undisturbed site would likely be comparable in both magnitude and duration to the proposed

Project. Therefore, the Gulf Coast Liquefaction Project would not provide a significant

environmental advantage over the proposed Terminal. In addition, the Gulf Coast Liquefaction

Project would not be completed in Cheniere’s schedule, including any customer commitments.

Therefore, this system alternative was not considered further.

Lavaca BayLNG Project

The proposed Lavaca Bay LNG Project includes two floating liquefaction, storage, and

offloading (FLSO)units that produce LNG from North American natural gas. The project would

also include onshore pre-treatment facilities and infrastructure associated with the FLSOs. LNG

would be stored, as needed, prior to transferring the LNG to carriers for export. The FLSOs

would be permanently moored at a proposed shore-side dock in Port Lavaca in Calhoun County,

Texas, approximately 60 miles north of the proposed Terminal site (see figure 3.1-1).

The Lavaca Bay LNG Project would include a total of eight liquefaction trains, storage of

up to 500,000 m3of LNG, and a send-out capacity of 10 mtpy of LNG. On October 23, 2012,

ELS submitted a Letter of Intent and a preliminary WSA to the Coast Guard for consideration in

its assessment of the waterway and issuance of a LOR regarding the suitability of the waterway

for LNG carrier marine traffic. On February 6, 2014, ELS filed an application with the FERC,

with a planned in service date of December 31, 201717. Additional facilities would be needed to

meet Cheniere’s export objectives, including the creation of two new berthing areas and turning

basins as well as additional other onshore facilities, resulting in similar or greater environmental

impacts. Therefore, the Lavaca Bay LNG Project would not provide a significant environmental

advantage to the Project. Additionally, receipt of permits and approvals for the additional

17 Docket Nos. CP14-71, CP14-72, and CP14-73
Environmental Impact Statement 3-11 Corpus Christi LNG

facilities necessary to meet Cheniere’s objectives, which ELS has not requested, would likely not

meet Cheniere’s schedule. Therefore, this system alternative was not considered further.

Magnolia LNG Project

Magnolia LNG would construct its liquefaction and LNG export project at the Port of

Lake Charles in Calcasieu Parish, Louisiana, at the port’s Industrial Canal, off the Calcasieu Ship

Channel, about 280 miles northeast of the proposed Terminal site (see figure 3.1-1). The

Magnolia LNG Project would be a stand-alone LNG export facility, not associated with an

existing LNG terminal, and constructed on a 90-acre site. At full capacity, the project would

export 8 mtpy of LNG using four liquefaction trains, each with a capacity of 2 mtpy of LNG.

In December 2012, Magnolia LNG filed an application with DOE/FE requesting longterm authorization to export LNG to foreign countries with which the U.S. has existing Free

Trade Agreements. On April 30, 2014, Magnolia LNG filed its application at FERC with

planned commercial operations beginning with the first train in 2017 and the second train in

2018. The third and fourth trains would be constructed and operated if market conditions are

favorable.18

To meet Cheniere’s objectives, Magnolia LNG would need to commit all of the capacity

of the four trains to Cheniere and construct additional trains. Magnolia LNG has not requested

authorization for the increased capacity and receipt of permits and approvals for the additional

facilities that would be needed to meet Cheniere’s objectives, and would likely not meet

Cheniere’s schedule, including any customer commitments. Additionally, as proposed, the

natural gas feedstock for Cheniere’s Terminal would be sourced from the south Texas region.

Transporting gas to the Magnolia LNG terminal, located significantly further from the south

Texas region, would require greater transportation costs, potential facilities, and associated

additional environmental impacts, as compared to the Cheniere Terminal. Therefore, this system

alternative was not considered further.

Gasfin LNG Project

The planned Gasfin LNG Project is a liquefaction and LNG export project in Cameron

Parish, Louisiana on the east side of the Calcasieu Ship Channel, approximately 280 miles

northeast of the proposed Terminal site (see figure 3.1-1). The project would be a stand-alone

LNG export facility that is not associated with an existing LNG terminal and would have an

export capacity of 1.5 mtpy.

On March 7, 2013, DOE/FE granted Gasfin long-term authorization to export LNG to

countries with which the U.S. has existing Free Trade Agreements. The Gasfin LNG Project is

in the initial development phase and an anticipated schedule has not yet been released. At the

time this EIS was prepared, Gasfin had not requested that the FERC initiate the pre-filing

process. We do not consider the Gasfin LNG Project to be a reasonable alternative to the Project

because it would not be completed in time to meet Cheniere’s schedule, including any customer

commitments, and as a greenfield project, would likely not provide a significant environmental

advantage to the Project. Therefore, this system alternative was not considered further.

18 Docket No. CP14-347
Environmental Impact Statement 3-12 Corpus Christi LNG

Waller Point LNG Project

The planned Waller Point LNG Project is a stand-alone liquefaction and LNG export

facility in Cameron Parish, Louisiana on the western shore of the Calcasieu Ship Channel from

the Gulf of Mexico, approximately 280 miles northeast of the proposed Terminal site (see figure

3.1-1). The project would have an LNG export capacity of about 1.25 mtpy. On December 20,

2012, DOE/FE granted long-term authorization to Waller Point LNG for LNG export to

countries with which the U.S. has existing Free Trade Agreements.

The project is in the initial development phase and Waller Point LNG has not announced

a planned schedule. Further, at the time this EIS was prepared, Waller Point LNG has not

requested that the FERC initiate the pre-filing process. We do not consider the Waller Point

LNG Project to be a reasonable system alternative to the Project because it would not be

completed in time to meet Cheniere’s schedule, including any customer commitments, and as a

greenfield project, would likely not provide a significant environmental advantage to the Project.

Therefore, this system alternative was not considered further.

CE FLNG LNG Project

CE FLNG announced plans for developing a floating LNG liquefaction and export

terminal on the east bank of the Mississippi River north of the confluence of Baptiste Collette

Bayou in Plaquemines Parish, Louisiana, approximately 490 miles east of the proposed Terminal

site. Project facilities include two FLSO vessels, each capable of producing up to 4 mtpy of

LNG. The FLSOs would have an LNG storage capacity of 250,000 m3. LNG carriers would

berth next to the units to load LNG. The project would include a 45-mile-long pipeline to

connect the terminal with two sources of natural gas: (1)the existing Enterprise Products natural

gas processing plant in Bernard Parish, (2)and the existing Targa Venice natural gas processing

plant in Plaquemines Parish. CE Pipeline, LLC plans to construct and operate the pipeline.

The project would be a stand-alone liquefaction and LNG export facility that is not

associated with an existing terminal. On November 21, 2012, DOE/FE granted long-term export

authorization to CE FLNG for LNG export to countries with which the U.S. has existing Free

Trade Agreements. At the time this EIS was prepared, CE FLNG was in the early phases of the

FERC pre-filing process19. CE FLNG anticipates that the first FLSO vessel would be in service

in March 2018, with the second FLSO starting up in October 2018.

To meet Cheniere’s objectives, CE FLNG would need to commit its entire capacity of the

project to Cheniere and install two additional FLSO vessels which would require establishing

additional berthing facilities, turning basins, and associated onshore facilities. We do not

consider the CE FLNG LNG Project to be a reasonable system alternative to the Project because

would not be completed in time or have the send out capacity to meet Cheniere’s schedule,

including any customer commitments, and as a greenfield project, would likely not provide a

significant environmental advantage to the Project. Therefore, this system alternative was not

considered further.

3.1.4 Alternative Terminal Sites

Alternative aboveground facility sites considered for the Terminal are described below.

The proposed Terminal would occupy an industrial area with access to a deep water channel.

19Docket No. PF13-11
Environmental Impact Statement 3-13 Corpus Christi LNG

We performed a thorough site alternative evaluation for the Terminal facilities. An analysis and

conclusion of the alternative sites is presented below.

A large number of alternative sites were evaluated along the Gulf Coast. A total of 17

potential port alternative sites were evaluated for channel depth (greater than 40 feet)and

proximity to existing natural gas pipeline systems, which are the primary criteria applicable to

the Terminal. Three sites were selected for further evaluation based on access to a channel

greater than 40 feet deep, access to major natural gas pipelines, industrial zoning, and availability

of sufficient open land for construction and operation of the facility. These sites were previously

proposed or planned for three LNG import projects that have not been built: Vista del Sol LNG,

Eos FLNG, and Ingleside Energy Center LNG projects. Figure 3.1-2 shows the sites which are

further discussed below.
Environmental Impact Statement 3-14 Corpus Christi LNG

Figure 3.1-2 Terminal Site Alternatives
Environmental Impact Statement 3-15 Corpus Christi LNG

In order to assess the suitability of each site, we developed a set of four major objectives

including site-specific criteria, marine operations, access to existing pipeline systems, and

permitting, which were then subdivided into site selection criteria.

1. The site-specific criteria are as follows:

 the ease of acquisition, with preference given to parcels of land in industrial areas or

dredge disposal areas;

 sufficient space for the land-based and marine components of the Terminal, including

the required spacing between equipment and tanks, as specified by the NFPA 59A;

and

 existing infrastructures capable of providing reliable sources of power as well as

suitable roads and barge access for delivery of materials during construction.

2. The criteria of the marine operations objective include:

 vessel traffic volume must comply with potential restrictions that a LNG carrier in

transit may pose on traffic in conjunction with other vessels;

 ease and efficiency of channel access, as the more expeditiously a vessel is able to

reach the terminal, unload, and depart on its ballast voyage, the better the economics

of the terminal;

 availability of a channel with sufficient depth, width, and air draft for the operation of

a typical LNG carrier is essential;and

 adequate maneuvering area amplitude and proximity (a minimum diameter of 1,200

feet and greater than 40 foot depth is required for a typical LNG carrier maneuvering

area.).

3. The criteria for access to existing pipeline systems include:

 proximity of existing pipeline systems for importation (it is assumed that the routing

issues and construction techniques would be similar for all onshore sites.);and

 adequate supply/send-out capacity with sufficient available capacity, and ability to

maintain consistent demand for the pipeline system.

4. Criteria of the permitting objective include:

 avoidance of impacts on residential areas including noise and light impacts;

 environmental consequences, including maximizing the use of previously disturbed

areas in order to reduce potential impacts;

 compatibility with region/port development plans and those of adjacent properties;

 land use zoning to support the above two criteria (zoning does not preclude industrial

development);and

 avoidance of populated areas to ensure compliance with the siting requirements of

NFPA 59A and 49CFR Part 193. The sites were evaluated by comparison of their

distance to populated areas. Scores are relative to these distances.
Environmental Impact Statement 3-16 Corpus Christi LNG

Refer to table 3.1-1 below for a summary of the investigation results.

Table 3.1-1

Alternate Site Location Comparisons

Criteria Proposed Site Eos FLNG Vista del Sol LNG Ingleside Energy

Center LNG

Site Specific

Ease of Acquisition

Owned by Corpus

Christi Liquefaction,

LLC

Unknown

Owned by

Occidental

Petroleum Corp

Owned by Occidental

Petroleum Corp

Area Available (acres) 600+ Unknown 430 82

Infrastructure

Minimal

improvement

required

Minimal

improvement

required

Minimal

improvement

required

Minimal improvement

required

Marine Operations

Vessel traffic volume Acceptable Acceptable Acceptable Acceptable

Channel Access Acceptable Acceptable Acceptable Acceptable

Maneuvering Dredging required Dredging required Dredging required Dredging required

Access to Pipeline

Distance to pipeline ~23 miles 40+ miles ~23 miles ~26 miles

Pipeline capacity Intrastate &

interstate available Limited Intrastate &interstate available

Intrastate & interstate

available

Permitting

Compatibility with region/port

development plans

Development of

adjacent Port

property

Port Authority is

promoting growth

Development of

adjacent Port

property

Development of

adjacent Port property

Land Use Zoning None Industrial None None

Distance to populated areas >1 mile 5 miles >1 mile >1 mile

Environmental Factors a

Wetland Impacts (acres) 25.7 Unknown 24.5 5.5

Open Water Impacts 150 Unknown 62.4 40

Land Impacts (acres) 321 Unknown 247.1 74

_______________________

a/ Environmental factors were determined based on information provided in Vista del Sol LNG and Ingleside

Energy Center LNG EISs, that were issued on April 15, 2005 and June 10, 2005, respectively. These acreages are

based on constructing import facilities only, not taking into consideration liquefaction facilities required for export.

No acreages are calculated for the Eos FLNG as no data is available.

The Vista del Sol LNG and the Ingleside Energy Center LNG site locations are both on

the La Quinta Ship Channel and are nearby to the proposed Terminal site. Infrastructure and

environmental impacts at these sites would be similar to the proposed Terminal site but would

require additional investigation as to whether liquefaction facilities can be accommodated at the

site. Environmental impacts associated with developing either alternative site would likely result

in impacts either similar or greater than those of the proposed site. In addition, the properties are

now owned by Occidental Petroleum Corporation and are no longer available to Cheniere.

Occidental Petroleum Corporation has also recently acquired the Naval Station Ingleside site

from the Port of Corpus Christi Authority (POCCA)and thus, it is no longer available.

Therefore, these alternative sites were dismissed and not considered further.
Environmental Impact Statement 3-17 Corpus Christi LNG

The Eos FLNG site is more than 40 miles from an existing pipeline system which has

limited available capacity and lacks access to interstate pipeline networks. Construction of

additional pipeline to reach the Eos site would likely result in greater environmental impacts than

those of the proposed project. Therefore, this alternative was dismissed and not considered

further.

The proposed site for the Terminal is selected because it offered the following advantages

over the other alternative sites:

 the Terminal is compatible with the existing industrial land use;

 the channel has a history of accommodating international vessels delivering liquid

products;

 the site has potential for barge access for the delivery of construction materials;

 the site is isolated from residential communities;

 the distance from the Terminal required to reach open water is short;

 existing pipeline systems with available take-away capacity are proximal to the site;and

 the property is owned/leased and available for development by Cheniere.

Significant site preparation earthwork was conducted at the Terminal site from 2006 to

2008 to prepare the proposed site for construction of the previously approved Import Terminal.

Furthermore, some environmental permits, such as the COE Section 404/10 Permit, are valid for

the Terminal but are being amended to include additional impacts from the proposed layout.

There has been industrial development in the vicinity surrounding the Terminal site. Two

wind power projects as well as the Copano Pipeline Project occur within the vicinity of the

Terminal;however, they do not impact the site. The ongoing construction of the La Quinta

Channel Extension Project, being conducted by the COE and the POCCA, could potentially

impact the Terminal site or surrounding resources. This project involves an extension of the La

Quinta Channel by approximately 7,400 feet to the area directly south of the POCCA’s property,

located west of the Terminal. The collective effects from construction of these projects in

conjunction with the Terminal could be significant;however, it is anticipated that cumulative

impacts would be temporary or minor, as the listed projects would not be constructed

concurrently with the Terminal. Cumulative impacts associated with the proposed Project and

projects in the regional geographic area are further discussed in section 4.13.

The proposed Terminal site is the most environmentally preferable and practical

alternative, as it is the only considered site that fully satisfies the Project’s purpose and need,

while minimizing impacts on agricultural land and would not adversely impact other existing

land uses or protected resources (see sections 4.0 and 5.0).

3.1.5 Alternative Dredge Disposal Locations

As currently proposed, dredged materials would be utilized to fill a portion of a former

90-acre clay borrow pit northeast of the Terminal site. The remainder of the dredged material

would be deposited in a 385-acre area, known as DMPA 2 (old bauxite disposal beds), located

immediately north of the Terminal site in order to assist in the capping of those beds (see

figure 2.1-1). The dredge material would be transported by a slurry pipe approximately
Environmental Impact Statement 3-18 Corpus Christi LNG

11,000 feet long and would be evenly distributed across the large bauxite beds north of the

Terminal. The water would be decanted and monitored as it leaves the DMPA to permitted

outfalls. The resulting soil would provide a cap over the old bauxite beds, which would allow

vegetation to occur and reduce the red dust in the area.

There are two alternative locations for the placement of dredged materials from the

marine facilities that were evaluated. These locations, referred to as DMPA 13 and DMPA 14,

(see figure 3.1-3)are located on property owned by the POCCA to the west and south of the

Terminal. DMPA 13 is located south of the Terminal and La Quinta Channel and is an existing

spoil island created from dredging and maintenance activities along the Channel. Environmental

impacts from the placement of additional dredge material on DMPA 13 would be minimal.

DMPA 14 is located to the west of the Terminal at an area where the POCCA has created a berm

for dredge material placement;therefore, environmental impacts from placement of dredge

material within DMPA 14 would be minimal. However, DMPAs 13 and 14 would not allow

capping of former bauxite disposal beds or revegetation in the area. Therefore, the proposed

location of DMPA 2 would be preferred, because it provides minimal environmental impact as

well as providing minor beneficial environmental restoration.
Environmental Impact Statement 3-19 Corpus Christi LNG

Figure 3.1-3 Alternative Dredge Disposal Areas
Environmental Impact Statement 3-20 Corpus Christi LNG

3.2 PIPELINE FACILITIES

3.2.1 No-Action Alternative

Under the No-Action Alternative, the objectives of the Project would not be met and

Cheniere would not provide the proposed natural gas transportation capacity for import or

export. In addition, the potential adverse and beneficial environmental impacts identified in

section 4.0 of this EIS would not occur.

3.2.2 System Alternatives

We considered whether any of the existing, recently authorized, or currently proposed

pipeline routes in the U.S. could be reasonable system alternatives to the proposed Pipeline. To

be considered a viable system alternative, the existing or approved pipeline facilities would need

to: 1)transport all or part of the volume of gas required for liquefaction at the Terminal;and 2)

cause significantly less impact on the environment than the proposed Pipeline.

3.2.2.1 Pipeline System Alternatives

Numerous natural gas pipelines operate in San Patricio County, Texas. The pipeline

infrastructure in the county dates to the mid-20th century and is comprised of gathering and

midstream pipelines, upstream processing, and transmission or distribution pipelines downstream

of processing. Several interstate pipelines transport south Texas production to the east, feeding

long-haul transmission systems that serve the Midwest and Northeast U.S. Alternatively,

intrastate pipelines aggregate and deliver supplies for local consumption within Texas. Over the

years, certain pipelines have switched from transmission and distribution to gathering or

midstream service. Many have done so recently, given high production volumes. Regardless,

only processed, pipeline quality gas is considered for liquefaction.

Our analysis of pipeline system alternatives includes evaluation of existing interstate

pipeline systems to meet the objectives of the proposed Pipeline. Table 3.2-1 lists the natural gas

pipelines identified in San Patricio County and their relative distances from the Terminal. The

table also indicates which pipelines, to date, have been considered commercially for connection

to the proposed Pipeline and the character of service. Five pipelines in table 3.2-1 have planned

connections to the proposed Cheniere Pipeline. However, these pipelines would not serve as

suitable alternatives to the Cheniere Pipeline, as additional construction of pipeline to connect to

the Terminal would be required, resulting in similar or greater environmental impacts than the

proposal. In addition, interconnections would also be required and it is not known whether

additional pipeline length would be required by those companies at proposed pipeline

interconnects.
Environmental Impact Statement 3-21 Corpus Christi LNG

Table 3.2-1

Natural Gas Pipelines Identified in San Patricio County, Texas

Pipeline

Miles from

Cheniere

Terminal

Planned

Connection to

Cheniere

Pipeline

Description of Pipeline Service

Houston Pipeline a/ Adjacent No Intrastate, low pressure distribution line

Gulf South Pipeline b/ On site No Interstate, in gathering or midstream service

Crosstex Energy c/ On site No Gathering or midstream service

KM Tejas Adjacent No Intrastate distribution line

Texas Eastern 7.5 Yes Interstate, high pressure line

Gulf South Pipeline 11.6 No Interstate, in gathering or midstream service

Channel Industries d/ 14.6 No Intrastate, distribution line

Florida Gas e/ 16.7 No Interstate, high pressure line

KM Tejas 21.0 Yes Intrastate, high pressure line

NGPL 22.4 Yes Interstate, high pressure line

Transco 22.8 Yes Interstate, high pressure line

Tennessee Gas 23.0 Yes Interstate, high pressure line

________________________

a/ Houston Pipeline Company, LP

b/ Gulf South Pipeline Company, LP

c/ Crosstex Corpus Christi Natural Gas Transmission

d/ Channel Industries Gas Pipeline Company

e/ Florida Gas Transmission Company, LLC

The overall purpose of the Project is to provide facilities that would allow imported LNG

to be vaporized and transferred to U.S. markets via existing interstate and intrastate natural gas

pipeline systems. The Project would also liquefy natural gas and deliver the resulting product

either into existing interstate and intrastate natural gas pipelines in the Corpus Christi area, or

export LNG elsewhere. Under present conditions, no existing pipelines would satisfy the

purpose and need of the Project because these lines have gas volumes committed to existing

customers. Any additional volumes would require construction of additional loop, compression,

or new greenfield facilities. The closest interstate pipeline that would connect with the proposed

pipeline is Texas Eastern at 7.5 miles away, as depicted in table 3.2-1. Therefore, expansion of

an existing interstate or intrastate pipeline to connect with the proposed Terminal would result in

environmental impacts similar to or greater than those associated with the proposed Pipeline.

Because a pipeline alternative using another system would provide no environmental advantage

over the proposed Pipeline, we have dismissed these from consideration.
Environmental Impact Statement 3-22 Corpus Christi LNG

3.2.3 Pipeline Route Alternatives

In evaluating Pipeline route alternatives, we examined variations that could minimize or

avoid impacts on environmentally sensitive resources such as population centers, special use

areas, waterbodies, wetlands, existing or planned residences, or specific landowner concerns.

We looked for a suitable Pipeline route that would result in minimal environmental and social

impacts.

Paramount in the development of the alternative pipeline route analysis was the presence

of existing infrastructure (utility rights-of-way, corridors, or previously developed areas).

Significant emphasis was placed on the incorporation of guidelines set forth in 18 CFR Part

380.15.

The routing criteria used to develop the proposed Pipeline route included:

 utilization of existing corridors;

 minimal creation of new corridors;

 potential impacts on sensitive resources;

 land use issues;

 proximity to residential/congested areas;

 engineering/construction issues;

 operation and maintenance considerations;and

 supporting infrastructure.

Existing utility corridors generally provide opportunities to minimize impacts on the

environment. Constructing new pipelines along existing corridors reduces the need for

establishment of new corridors and thus, the involvement of additional landowners, clearing of

new rights-of-way, and potential environmental impacts.

When establishing the final proposed route, the only substantial development has been

the construction of the Papalote Creek Wind Farm, located in agricultural lands east of Taft,

Texas. There are several wind turbines that have been constructed and would operate in close

proximity to the Pipeline route;however, none these turbines are expected to directly impact the

Pipeline or associated aboveground facilities.

3.2.3.1 Major Route Alternative

The proposed Pipeline route was primarily based on the approved route of Cheniere’s

initial filing, which received an Order (FERC Docket No. CP04-37-000) but was never

constructed. Three major alternative routes as well as the proposed Pipeline route were

evaluated to determine which would produce minimal environmental impacts while meeting the

Pipeline’s objective. The proposed Pipeline route, at a length of approximately 23.0 miles,

provides the shortest distance from the proposed Terminal to existing high pressure natural gas

pipeline systems in the South Texas region. The Pipeline would be installed adjacent to a high

voltage overhead power line as well as existing natural gas pipelines along portions of the

proposed route. As such, the proposed route minimizes environmental impacts by maximizing

the use of existing corridors in the area. The evaluations of the three major route alternatives are
Environmental Impact Statement 3-23 Corpus Christi LNG

discussed below. Table 3.2-2 compares significant environmental factors of each of the route

alternatives with the proposed route.

Table 3.2-2

Environmental Comparison of the Proposed Pipeline Route with Route Alternatives

Environmental Factor Proposed Route Route

Alternative A

Route

Alternative B

Route

Alternative C

Total Length of Mainline Pipeline (miles) 23.0 24.0 27.4 26.4

Length Adjacent to Existing Right-of-Way (miles) 19.73 16.5 23.6 22.9

Construction Disturbance (acres) 321.1 a/ 350.6 a/ 332.1 b/ 320.0 b/

Waterbodies Crossed 9 7 9 9

Wetland Impacts (acres) <0.01 4.5 2.8 <0.01

Railroad Crossings 3 3 2 2

Road Crossings 18 14 33 22

Residences within 50 feet of Construction Work

Area 0 23 0 0

________________________

a/ Construction disturbance based on nominal right-of-way width of 120 feet

b/ Construction disturbance based on nominal right-of-way width of 100 feet

Route Alternative A

Route Alternative A (see figure 3.2-1)would begin at the proposed Terminal and proceed

west for approximately 1 mile across open land owned by the POCCA. It would then turn

northwest, cross the Southern Pacific Railroad and SH 35, skirt the west side of the city of

Gregory, and cross CR 2986. Alternative A would then parallel Boykin Road between MPs 4.0

and 11.0, skirting the west of the city of Taft. It would follow local farm roads between MPs

14.0 and 15.0, then turn northeast, parallel to CR 1074, crossing U.S. Highway (US)181, to MP

17.0, where it would turn northwest again. Following an existing pipeline corridor, Alternative

Route A would cross Oliver Creek at MP 18.0, Chiltipin Creek at MP 19.0, and US 77 at MP 21,

before terminating at MP 24.0.

This route would be 1.0 mile longer than the proposed route, and would be 4.5 miles less

collocated with existing rights-of-way. It would affect 29.5 acres more land including 4.5 acres

more wetlands and would be within 50 feet of 23 residences. The proposed route does not

impact residential lands. The primary disadvantage of the alternative is that it would cross a

greater portion of the POCCA property located west of La Quinta Road. The POCCA property

is the proposed site for both the La Quinta Trade Gateway Terminal as well as the Voestalpine

DRI Plant, both of which are further discussed in section 4.13. Alternative Route A also crosses

a residential area that had not been constructed when the route alternative was originally

proposed and evaluated under FERC Docket No. CP04-37-000.

Therefore, Route Alternative A would not offer an environmental advantage over the

proposed route and we do not recommend the use of this alternative.

Route Alternative B

Route Alternative B (see figure 3.2-1) would begin at ExxonMobil’s previously

approved, but never constructed, Vista del Sol LNG terminal, located south of the DuPont
Environmental Impact Statement 3-24 Corpus Christi LNG

chemical plant approximately 2 miles southeast of the proposed Terminal. It would then proceed

northward past the DuPont plant, crossing Edwards Road and a railroad, avoiding an existing

pond, and crossing SH 361 and the Southern Pacific Railroad at MP 2.3. It would then follow

existing ExxonMobil and Koch pipelines heading northwest across agricultural land, crossing

SH 35 at MP 5.5. At MP 17.7 Route Alternative B would leave the existing pipeline corridor

and become a greenfield route, crossing Chiltipin Creek at MP 19.0 and proceeding over open

scrubland to MP 20.8, where it would follow another existing pipeline. It would cross US 77 at

MP 24.8 and terminate at MP 27.4.

This route would be 4.4 miles longer than the proposed route, would impact 2.8 acres

more wetlands, and would cross 15 more roadways than the proposed route. Thus, Route

Alternative B would not offer a significant environmental advantage over the proposed route and

therefore we do not recommend the use of this alternative.

Route Alternative C

Route Alternative C (see figure 3.2-1)would begin at the previously approved, but never

constructed, Ingleside Energy Center LNG terminal and would proceed northward, past the

Occidental chemical plant, crossing SH 361 and the Southern Pacific Railroad at MP 1.5. It

would continue northwesterly, crossing SH 35 at about MP 4.0, skirting the east side of the city

of Gregory near MP 6.5, and the east side of the city of Taft near MP 14.5. This route would

cross Chiltipin Creek at MP 21.5, and terminate at MP 26.4.

Route Alternative C would be 3.4 miles longer than the proposed route and would

include four more road crossings thus resulting in greater land impacts. All other environmental

factors evaluated would be similar to the proposed route, thus, Route Alternative C would not

offer an environmental advantage over the proposed route and therefore we do not recommend

the use of this alternative.
Environmental Impact Statement 3-25 Corpus Christi LNG

Figure 3.2-1 Pipeline Route Alternatives
Environmental Impact Statement 3-26 Corpus Christi LNG

3.2.3.2 Other Appurtenant Aboveground Facilities

Proposed aboveground facilities for the Pipeline would include MLVs, one pig launcher

and receiver, and six M&R stations. These facilities all occur on agricultural land along the

Pipeline right-of-way. These facilities are small, would not impact environmentally sensitive

areas, are not located near residences, and their locations are tied to the locations of other foreign

pipeline facilities, with the exception of the MLV at MP 14.5. As noted throughout section 4.0,

the potential impacts of construction and operation of the aboveground facilities would be

adequately minimized, and therefore we did not identify alternative sites that would provide a

significant environmental advantage to the proposed aboveground facility sites.

3.2.3.3 Compressor Stations Site Alternatives

The Pipeline would require compression at two locations along the proposed route. In

order to meet the natural gas supply throughput requirements for the Pipeline, compressor

stations would be required at locations southeast of the city of Taft and northeast of the city of

Sinton. Additional information on the location of the proposed compressor stations and

alternative sites, are provided in the following sections.

Taft Compressor Station

The proposed Taft Compressor Station would be located on an approximately 30-acre

land parcel along the north side of County Road 78 at approximate MP 7.5. An alternative 30-

acre parcel is located on an adjacent tract to the southeast of the proposed site. Cheniere owns

the land of the proposed location of the Taft Compressor Station. Both sites are located on

agricultural land and neither site would have impacts on environmentally-sensitive resources

such as waterbodies, wetlands, public roads, and utility crosses (see table 3.2-3). However, the

proposed site is 474 feet further away from noise sensitive areas (NSAs)than the alternative site.

Additionally, the existing Texas Eastern pipeline crosses the property of the proposed site

obviating the need for construction of a lateral pipeline thus eliminating associated

environmental impacts. Therefore, the alternative site is not recommended since it has no

environmental advantage over the proposed site. The proposed and alternative Taft Compressor

Station sites are depicted in figure 3.2-2.

Table 3.2-3

Environmental Comparison of Cheniere’s Proposed and Alternative Taft Compressor Station Sites

Environmental Factor Proposed Site Alternative Site

Total Area (acres) 30 30

Distance to Nearest NSA (feet) 3,099 2,625

________________________

The proposed and alternative Taft compressor station sites would not have an impact on public road and utility crossings,

waterbodies, and wetlands.
Environmental Impact Statement 3-27 Corpus Christi LNG

Figure 3.2-2 Taft Compressor Station Site Alternative
Environmental Impact Statement 3-28 Corpus Christi LNG

Sinton Compressor Station

The proposed Sinton Compressor Station is located on an approximately 30-acre parcel

north of US 77 and northeast of the City of Sinton at approximate MP 21.5. Cheniere is in

negotiations with the landowner to acquire the land for the proposed Sinton Compressor Station.

The proposed site provides easy access to US 77 and the site is located in scrub/shrub habitat that

is devoid of sensitive environmental resources, such as waterbodies, wetlands, public roads, and

utility crossings. Table 3.2-4 compares significant environmental factors of the proposed Sinton

Compressor Station site as well as the evaluated alternative sites.

All four alternative sites would be located in scrub/shrub habitat and would have the

same acreages as the proposed site. Three alternative sites east of US 77 (Alternative Sites 1, 2,

and 3)would require a new access road that crosses a railroad track along US 77, resulting in a

potential safety concern for vehicular traffic. Alternative Sites 1, 2, and 3 were eliminated from

further consideration for the Sinton Compressor Station since they provided no environmental

advantage over the proposed site.

Alternative 4 is located west of US 77 on property owned by the same landowner who

owns the property of the proposed site. Alternative 4 was not selected because it is closer to the

nearest NSA by 828 feet, and also offers no environmental advantages. The proposed and

alternative Sinton Compressor Station sites are depicted in figure 3.2-3.

Table 3.2-4

Environmental Comparison of Cheniere’s Proposed and Alternative Sinton Compressor Station Sites

Environmental Factor Proposed

Site

Alternative

Site 1

Alternative

Site 2

Alternative

Site 3

Alternative

Site 4

Total Area (acres) 30 30 30 30 30

Distance to Nearest NSA (feet) 2,367 3,871 5,192 6,354 1,539

Public Road/Utility Crossings a/ 0 1 1 1 0

________________________

a/ Public road and utility crossings include those crossed by new permanent access roads. The proposed and alternative Sinton

compressor station sites would not have an impact on waterbodies and wetlands.
Environmental Impact Statement 3-29 Corpus Christi LNG

Figure 3.2-3 Sinton Compressor Station Site Alternatives
Environmental Impact Statement 3-30 Corpus Christi LNG

3.2.4 Pipeline and Compressor Alternatives Conclusions

Evaluation of the Pipeline route and compressor station alternatives determined that the

proposed Pipeline would fully satisfy the Project’s objective with minimal or temporary impacts,

with implementation of appropriate mitigation, as presented in section 4.0. None of the

alternative pipeline routes or compressor station alternatives offer a significant advantage over

Cheniere’s proposal.
ENVIRONMENTAL IMPACT ANALYSIS

SECTION 4

Environmental Impact Statement 4-1 Corpus Christi LNG

4.0 ENVIRONMENTAL ANALYSIS

This section describes the affected environment as it currently exists and discusses the

environmental consequences of the Project. The discussion is organized by the following major

resource topics: geology, including foundation conditions, and natural hazards;soils;water

resources;vegetation;wetlands;fisheries and wildlife resources;threatened, endangered, and

other special status species;land use, recreation, and visual resources;socioeconomics;cultural

resources;air and noise;safety and reliability;and cumulative impacts.

The environmental consequences of constructing and operating the Project would vary in

duration and significance. Four levels of impact duration were considered: temporary, shortterm, long-term, and permanent. Temporary impacts generally occur during construction with

the resource returning to preconstruction condition almost immediately afterward. Short-term

impacts could continue for up to 3 years following construction. Impacts were considered longterm if the resource would require more than 3 years to recover. A permanent impact could

occur as a result of any activity that modifies a resource to the extent that it would not return to

preconstruction conditions during the life of the Project. We considered an impact to be

significant if it would result in a substantial adverse change in the physical environment and the

relationship of people with the environment.

As part of its proposal, Cheniere developed certain mitigation measures to reduce the

impact of the Project. In some cases, we determined that additional mitigation

measures/recommendations could further reduce the Project’s impacts. Our additional

mitigation measures/recommendations appear as bulleted, boldfaced paragraphs in the text of

this section and are also included in section 5.0. We will recommend to the Commission that

these measures be included as specific conditions in any Authorization the Commission may

issue to Cheniere for this Project.

The conclusions in the EIS are based on our analysis of the environmental impact and the

following assumptions:

 Cheniere would comply with all applicable laws and regulations;

 the proposed facilities would be constructed as described in section 2.0 of this EIS;and

 Cheniere would implement the mitigation measures/conditions included in its application

and supplemental submittals to the FERC and cooperating agencies, and in other

applicable permits and approvals.

4.1 GEOLOGIC RESOURCES

4.1.1 Terminal Facilities

4.1.1.1 Geologic Setting

The Terminal would be located within the Coastal Prairie region of the Gulf Coastal Plain

physiographic province. Holocene-aged deposits are characteristic of this region and primarily

consist of alluvial, deltaic, beach, bay-estuary, and marsh deposits. These deposits are underlain

by deep Pleistocene-aged deltaic and alluvial deposits interlayered with clays and sands. The

topography in the area is nearly flat, with subsurface sediments gently dipping toward the Gulf,

and is dissected by highly sinuous streams. The minimum elevation at the Terminal is sea level,

and the maximum elevation is approximately 36 feet above mean sea level (AMSL).
Environmental Impact Statement 4-2 Corpus Christi LNG

The Terminal would be located within a modern bay-estuary system that formed upon the

Nueces River fluvial-deltaic system. The depositional environment in the Terminal area has

been significantly impacted by Pleistocene–aged glacial and interglacial events which resulted in

sea level changes. Broad deltas with meandering distributary channels of fluvial sands and

interdistributary floodplains with overbank mud deposits were formed during interglacial periods

when rivers carried large sediment loads towards the coast. The modern estuary system was

formed approximately 2,500 years before present, when sea levels rose and filled the Nueces

River valley with fluvial sediments and tidally transported Gulf sediments as the shoreline

receded to its current position. The upper Corpus Christi Bay is a shallow estuarine delta

characterized by prodelta muds and sandy channel-mouth bars.

The Terminal would be located within Holocene-aged alluvial and floodplain deposits

underlain by the Pleistocene-aged Beaumont Formation. The Beaumont Formation consists of

sands, silty sands, and clayey sands deposited in a tidally influenced back-bay environment in the

upper layers and interbedded sands and clays deposited in a barrier bar setting in the lower

section. The Beaumont Formation is underlain by the Pleistocene-aged Lissie Formation

consisting of alluvial clay and lenticular sandstone deposits.

4.1.1.2 Mineral Resources

There are five abandoned oil and gas wells located on or within the Terminal site. The

La Prade well, located in the northwest section of the site was a non-producing well that was

abandoned in 1945. The Reynolds, Green, and State Tract No. 1 wells are located in the southsoutheast section of the site and were all abandoned in 1972. The State Tract No. 15 well, also

located in the south-southeast section, was abandoned in 2011. All five abandoned wells were

plugged with cement and mud.

A review of the U.S. Geological Survey (USGS) Mineral Resource Data System

indicated that there are no active or potential surface mines located within the vicinity of the

Terminal. According to the oil and gas well database maintained by the RRC, the five

abandoned oil and gas wells located on or near the Terminal site are wells that were plugged and

abandoned in accordance with applicable RRC requirements. There is no surface evidence to

visually verify locations of the well casings, and there is no indication of the presence of other oil

and gas wells at the Terminal site.

In the event an unidentified oil and gas well is unexpectedly encountered during

construction, Cheniere would stop all work in the area, contain any spillage of product, secure

the area, and notify the EI, the RRC, and the FERC. Cheniere would consult with the RRC to

determine the operator or owner on record for the subject well. RRC Statewide Rule 14 (TAC

Title 16, Part 1, Chapter 3)requires operators of record to plug abandoned oil and gas wells in

accordance with specifications set forth within. If the well operator cannot be identified, the

RRC maintains and administers an Oil Field Cleanup Fund which may be utilized to properly

plug wells. Cheniere would likely request a variance from the FERC, if necessary, and adjust

equipment location to avoid the well.

Although the Project is not anticipated to affect any active or abandoned oil or gas wells

and active or potential surface mines, if an unidentified well is encountered, Cheniere would

implement the measures outlined above. Therefore, construction and operation of the Terminal

facilities would not significantly affect mineral resources.
Environmental Impact Statement 4-3 Corpus Christi LNG

4.1.1.3 Paleontological Resources

No sensitive paleontological resources have been identified within the Terminal area.

Therefore, no impacts are anticipated by constructing and operating the Terminal facilities.

4.1.1.4 Foundation Conditions

Cheniere has performed a geotechnical investigation of the site. The soils profiles at the

LNG tank locations reveal a layered stratigraphy of sands and clays extending to a depth of

approximately 180 feet. Below this lies a massive sand layer reaching a depth of approximately

300 feet. The sand and clay layers above the massive sand layer vary in thickness from

approximately 10 to 30 feet. Consistency of the clay layers was generally very stiff to hard,

while the upper most sand stratum had a variable density but was mostly medium dense. The

eastern half of the proposed liquefaction facility process area has a similar layer soil profile as

the proposed LNG tank locations, but the massive sand layer underlying the western facilities

occurs at elevations of approximately -40 to -80 feet. The clay layers in this process area above

elevation -40 feet are generally thicker than the sand layers, ranging between 10 to 40 feet for the

clay layers and 10 to 20 feet for the sand layers. As in the proposed LNG tank locations, the

upper sand is medium dense and the lower sands are very dense. The groundwater table ranges

between elevation 6 and 12 feet.

Site preparation would result in the high point of finished surface at an elevation of

approximately 25 feet AMSL. The foundations are planned to be reinforced concrete spread

footing and mats. The net allowable recommended soil bearing ranges between 4,000 and 6,000

pounds per square foot (psf).

During the period between 1965 and 2000, most of the liquefaction plant site was

covered with bauxite up to a depth of 60 feet and imposing area loads of as much as 7,500 psf.

Removal of this overburden started in 2000 and was completed in 2005. In areas of the proposed

liquefaction plant site covered by the bauxite stockpile, the shapes of the stockpile and the

current condition of the soils generally would have a beneficial effect on foundation conditions.

The LNG tanks, however, would be located in areas within and outside the previously stockpiled

area causing concerns of differential surcharge conditions on the middle tank foundation, which

could result in detrimental differential foundation settlements. Therefore, the tank design will

include settlement analyses of the LNG tank foundation for three bounding conditions: tank area

full preloaded, partially loaded, and outside of preload. Cheniere may also elect to remove and

re-compact the low blow count layer near the bottom of the LNG storage tank foundations as

part of the site grading and compaction.

Terminal must be constructed to satisfy the design requirements of 49CFR 193, NFPA

59A-2001, 2006 International Building Code, and ASCE 7-05. For seismic design, the facility

would also be designed to satisfy the requirements of NFPA 59A-2006 and ASCE 7-05.

The design of the facility is currently at the Front End Engineering Design (FEED)level

of completion. Cheniere has proposed a feasible design and it has committed to conducting a

significant amount of detailed design work for the Terminal if the Project is authorized by the

Commission. Information regarding the development of the final design, as detailed below

would need to be reviewed by FERC staff in order to ensure that the final design addresses the

requirements identified in the FEED. Further, the timing of the production of this information
Environmental Impact Statement 4-4 Corpus Christi LNG

should occur prior to the stage Cheniere has indicated in its application and subsequent filings.

Therefore, we are recommending that:

 Cheniere should file the following information,stamped and sealed bythe

professional engineer-of-record,with the Secretaryof the Commission

(Secretary):

a. site preparation drawings and specifications;

b. LNG tankand foundation design drawings and calculations based on the

seismic design ground motions in Cheniere’s Resource Report 13,

Appendix I(URS Report –Seismic and Tsunami Evaluation for the LNG

Export Facility dated August 7,2012)and settlement analyses indicated in

the TWEIresponse to question 4f provided in the Supplemental Responses

filed byCheniere on September 23,2013;

c. LNG Liquefaction facilitystructures and foundation design drawings and

calculations;and

d. quality control procedures to be used for civil/structural design and

construction.

In addition,Cheniere should file,in its Implementation Plan,the schedule for

producing this information.

4.1.1.5 Natural Hazards

Geologic hazards that can potentially affect the Terminal facility include earthquake

ground motions and faulting, soil liquefaction and subsidence, and slope stability. Other natural

hazards of concern include hurricane winds as well as storm surge-related flooding.

Earthquake Ground Motions and Faulting

The Gulf Plains physiographic province is characterized by low seismic hazard potential.

Cheniere conducted a site-specific hazard evaluation to address this effect. The evaluation

determined that the peak ground acceleration, with consideration of site amplification effects,

would be 0.013 gravity (g)for a 10 percent probability of exceedance in 50 years and 0.052 g for

a 2 percent probability in 50 years. Results of this evaluation indicate very low level of ground

motion predicted at the Terminal area;therefore, earthquake hazards were not considered a

controlling factor in facility design.

Several hundred faults exist in the Gulf Coast region and are primarily Gulf-facing listric

normal faults that developed in thick sedimentary sequences over a rifted margin. These faults

developed as growth faults underlying thick sediment loads and in relation to salt movement. In

modern times, movement along these faults is primarily the result of petroleum production and

groundwater pumping. Although numerous Quaternary surface faults are present in the Gulf

Coast region, earthquakes with epicenters within the coastal areas of Texas are rare and typically

of low magnitude. Subsurface salt movement can also influence faulting;however, the Terminal

would not be located near any salt domes. The closest salt dome is located approximately 70

miles west of the Terminal. Stratigraphic units over 40,000 years old are found at relatively
Environmental Impact Statement 4-5 Corpus Christi LNG

common elevations in several soil borings. There was no identified evidence that the site occurs

within the zone of influence or within 0.5 mile of an active (Holocene-aged)fault. A low risk of

seismic activity and faulting effects can be reasonably anticipated for the Terminal area.

Therefore, the potential for large-magnitude seismic activity in the vicinity of the Terminal is

low and is not considered a significant hazard.

Soil Liquefaction

Soil liquefaction is the transformation of loosely packed sediment, or cohesionless soil,

from a solid to a liquid state as a result of increased pore pressure and reduced effective stress,

such as intense and prolonged ground shaking from seismic events. The Terminal area would

have underlying water-saturated sediments and could be susceptible to liquefaction under

sufficiently strong ground motion. However, due to the relatively low levels of seismic activity

and potential ground motion anticipated at the Terminal site, there is little risk for liquefaction of

soils to occur. Therefore, it is not anticipated that soil liquefaction would present a significant

hazard at the Terminal site.

Subsidence

Subsidence is the sudden sinking or gradual downward settling of land with little or no

horizontal motion, caused by movements on surface faults or by subsurface mining or pumping

of oil, natural gas, or groundwater. Subsidence in the Gulf Coast region primarily results from

groundwater extraction, oil and gas extraction, and slumping along growth faults. Various

degrees of subsidence have been documented along the Texas coast, with the greatest incidences

occurring in the Houston-Galveston area.

Groundwater extraction in San Patricio County is primarily for irrigation and the amount

pumped varies by season and year. There are no water wells in the vicinity of the Terminal, and

while there are several oil and gas fields in San Patricio County, there is no significant petroleum

extraction near the proposed Terminal. Compaction of soft sediments under load can also lead to

subsidence;however, the Terminal would be underlain by consolidated stiff to hard clays and

medium to dense sands, minimizing the risk of subsidence. The only incidence of significant

subsidence is located more than 20 miles southwest of the site. Therefore, it is not anticipated

that subsidence would present a significant hazard to the Terminal site.

Slope Stability

Cheniere analyzed slope stability at the Terminal site to evaluate the erosion potential of

sand layers which would be exposed after dredging in the berth areas. The analysis revealed that

although there is little wave action in the La Quinta Channel, scour from tugboat propeller wash

could cause eventual slumping or slope failure. To minimize potential scour from tugboat

propeller wash, Cheniere would require that tugboats pull LNG carriers off the dock from the

offshore side rather than push from the inshore side. This would minimize the potential for

sustained propeller wash directed towards the shoreline.

Cheniere would further protect the shoreline by installing articulated block revetments.

To prevent scouring of sand layers exposed during dredging of the marine berths, Cheniere

would stabilize the berth slopes using articulated mats or other suitable means of stabilization.

Upland slopes within the Terminal would be seeded and maintained in a grassy condition as a

part of regular facility operations.
Environmental Impact Statement 4-6 Corpus Christi LNG

Cheniere would implement several preventative measures in order to avoid or minimize

the potential for slumping and slope failure. Therefore, adverse impacts on the slope stability at

the Terminal site after dredging would not be anticipated as a result of tugboat propeller wash.

Hurricane Winds

The Terminal site would be subject to hurricane winds. The LNG tanks and associated

safety systems would be designed for a sustained wind speed of 150 mph.

The Terminal would be susceptible to hurricanes and tropical storms which could

produce storm surges, high winds, and flooding. The most recent FEMA Flood Insurance Rate

Map indicate that the majority of the Terminal would be located within Zone C, while shoreline

areas would be located in Zones V22, A16, and B. The marine berth and LNG transfer lines

would be constructed within Zones V, A, or B. Table 4.1-1 includes definitions of FEMA flood

hazard zones for the Project area.

Table 4.1-1

Federal Emergency Management Agency Flood Hazard Zone Designations Within the Terminal

Zone Designation Description

Zone A

Zone A is the flood insurance rate zone that corresponds to the 100-year floodplains that are determined

in the Flood Insurance Study by approximate methods. Because detailed hydraulic analyses are not

performed for such areas, no Base Flood (100-year flood)Elevations (the computed elevation to which

floodwater is anticipated to rise during the base flood)or depths are shown within this zone. Mandatory

flood insurance purchase requirements apply.

Zone A1 to A30

Zones A1 to A30 are the flood insurance rate zones that correspond to the 100-year floodplains that are

determined in the Flood Insurance Study by detailed methods. In most instances, Base Flood Elevations

derived from the detailed hydraulic analyses are shown at selected intervals within this zone. Mandatory

flood insurance purchase requirements apply.

Zones B and C

Zones B and C are the flood insurance rate zones that correspond to areas outside the 100-year

floodplains, including areas of 100-year sheet flow flooding where average depths are less than 1 foot,

areas of 100-year stream flooding where the contributing drainage area is less than 1 square mile, or

areas protected from the 100-year flood by levees. No Base Flood Elevations or depths are shown

within this zone.

Zone V

Zone V is the flood insurance rate zone that corresponds to the 100-year coastal floodplains that have

additional hazards associated with storm waves. Base Flood Elevations derived from the detailed

hydraulic analyses are shown at selected intervals within this zone. Mandatory flood insurance purchase

requirements apply.

The Digital Storm Atlas of Texas predicts that a Category 5 hurricane striking Corpus

Christi Bay area could produce a storm surge of up to 21 feet AMSL. As a result, Cheniere

would construct the main processing equipment, storage tanks, and administration buildings in

upland areas at elevations greater than 25 feet AMSL. Additionally, the jetty platforms would be

at a design elevation of 36 feet AMSL, and Cheniere would install all critical and LNGcontaining equipment at or above 25 feet AMSL. The shoreline would be protected through the

installation of articulated block revetments.

In the event of a Category 5 or lower hurricane, significant impacts on the Terminal

facilities would not be anticipated. Cheniere would implement design measures during

construction that would minimize or avoid potential damages that could occur during a

hurricane.
Environmental Impact Statement 4-7 Corpus Christi LNG

The Project is located in an area that could present potential challenges relative to natural

hazards;however, these conditions can be effectively managed through sound engineering

design or shown to be minimal through additional evaluation. The overall effect of construction

and operation of the Terminal on topography and geology would be minor. The

recommendation included in this section ensures that impacts on geologic resources would be

adequately minimized.

4.1.2 Pipeline Facilities

4.1.2.1 Geologic Setting

The Pipeline would be located in the same physiographic province as the Terminal,

described above in section 4.1.1. The topography crossed by the Pipeline increases in elevation

from 25 feet AMSL at MP 0.0 to 80 feet AMSL near MP 23.0. The Pipeline would also cross

recent Holocene-aged alluvial deposits that are underlain by deep Pleistocene-aged deltaic and

alluvial deposits. The Pipeline would be underlain by the Beaumont Formation from MP 0.0 to

MP 18.9, and the Lissie Formation from MP 18.9to MP 23.0.

4.1.2.2 Mineral Resources

Four known oil and gas fields and one sand and clay pit would be located within 0.25

mile of the Pipeline. An unnamed oil field would be crossed between MP 5.5 and MP 6.5, the

Midway Oil Field would be crossed between MP 7.5 and MP 8.5, the Taft Oil and Gas Field

would be crossed between MP 15.9and MP 19.0, and the Portilla Oil and Gas Field would be

crossed between MP 19.0 and MP 23.0. Oil and gas deposits contained within these fields would

be significantly below the proposed depth of the Pipeline trench, at approximately 5,350 to

14,000 feet below the ground surface, and should not be disturbed during the construction and

operations of the Pipeline.

The sand and clay pit is intermittently active and would be located approximately 200

feet from the Pipeline construction right-of-way between MP 1.7 and MP 1.8. Cheniere would

avoid impacts from mining operations in this parcel through pit mining monitoring and terms of

agreement resulting from discussions with the operator to allow an adequate easement for the

Pipeline.

A total of 43 foreign pipelines would be crossed by, or in close proximity to the Pipeline

or associated facilities. In order to ensure foreign pipeline integrity, Cheniere indicated that it

would: 1)use databases and line locaters to identify and mark foreign pipeline locations and

burial depth;2)notify foreign pipeline operators of crossing and execute any mandatory crossing

agreements;3)obtain as-built drawings from the foreign pipeline operators where available;4)

perform a “One Call”before excavating;5)employ best operating practices to both Cheniere’s

and the foreign pipeline operator’s standards when excavating near an existing line, which may

include prohibition of mechanical equipment within a specified distance of the line;6)require

hand digging to expose a foreign pipeline at certain critical locations;and 7)have foreign

pipeline operators provide an on-site field representative as oversight to the Pipeline construction

activities.

Cheniere also identified seven oil and gas wells that would be located within 150 feet of

the Pipeline. One of these wells would be located within the construction right-of-way and four

would be located within 50 feet of the construction right-of-way. Cheniere indicated that it
Environmental Impact Statement 4-8 Corpus Christi LNG

would consult with the RRC prior to Pipeline construction to obtain additional information

regarding oil and gas wells within 150 feet of the construction right-of-way. Additionally, field

verification surveys would be conducted to confirm the location of each well prior to Pipeline

construction. If an oil and gas well is unexpectedly encountered during construction Cheniere

would stop work immediately, contain any spillage of product, secure the area, and notify the EI,

RRC, and the FERC. The owner or operator of the well would be notified and Cheniere would

route around the well if necessary. Cheniere would request a route variance from the FERC, if

necessary, and adjust the centerline to avoid the well.

Although some mineral resources have been identified within close proximity to the

Pipeline or may be crossed by the Pipeline, Cheniere would implement the appropriate

preventative measures or mitigation to minimize or avoid impacts on these resources. Therefore,

the Pipeline would not significantly impact extractive resources in the form of oil and gas fields,

sand and clay pits, buried foreign pipelines, or oil and gas wells.

4.1.2.3 Paleontological Resources

No identified sensitive paleontological resources would be crossed by the Pipeline.

Therefore, no impacts are anticipated by constructing and operating the Pipeline.

4.1.2.4 Natural Hazards

Geologic hazards that could potentially affect the Pipeline facilities include earthquake

ground motions and faulting, soil liquefaction, subsidence, slope stability, and flooding.

Earthquake Ground Motion and Faulting

As previously discussed in section 4.1.1, impacts on the Pipeline from seismic activity

and faulting are not anticipated. The nearest mapped fault is 42 miles from the northern terminus

of the Pipeline and thus, the potential for large-magnitude seismic activity in the vicinity of the

Pipeline is low.

Soil Liquefaction

Due to the low levels of seismic activity and potential for ground motion in the Pipeline

area, there is little risk for liquefaction of soils to occur. Soil liquefaction would not be a

significant hazard for the Pipeline.

Subsidence

As discussed in section 4.1.1 above, subsidence in the Gulf Coast region is primarily

caused by groundwater extraction, oil and gas extraction, and slumping along growth faults. In

addition, soft sediments under load can also result in subsidence. Groundwater extraction in San

Patricio County is primarily for irrigation, and the amount varies by season and year. Although

the nearest significant subsidence event occurred more than 20 miles southwest of the Project

area, typically potential for subsidence is greatest to the northeast. San Patricio County does not

experience the degree of subsidence found elsewhere along the Gulf Coast. Subsidence would

not be a significant hazard for the Pipeline.
Environmental Impact Statement 4-9 Corpus Christi LNG

Slope Stability

The Pipeline route crosses topography that is relatively flat, with elevations gradually

increasing from 25 feet AMSL to 80 feet AMSL over 23 miles. Slope stability would not be a

significant hazard for the Pipeline.

Flooding

The Pipeline would be susceptible to hurricanes and tropical storms which could produce

storm surges, high winds, and flooding. The most recent FEMA Flood Insurance Rate Map

indicates that the Pipeline would be located within Zones A, B, and C, with both of the

compressor stations located within Zone C (outside of the 100-year floodplain). Table 4.1-1

includes definitions of FEMA flood hazard zones for the Project area.

The segments of Pipeline that would be located in Zone A (100-year floodplain)would

have a higher susceptibility to flooding. To offset this risk Cheniere would use concrete coated

pipe at waterbody crossings and areas subject to flooding to compensate for negative buoyancy.

Flooding would not be a significant hazard for the Pipeline, as Cheniere would implement

measures to combat buoyancy in the event of flood or storm surge.

Overall, impacts on geologic resources resulting from the installation of the Pipeline

would be minor. While flooding is a potential hazard for the area, Cheniere has adequately

mitigated for this through the implementation of measures to combat pipe buoyancy in floodprone areas. With the implementation of BMPs and our Plan and Procedures, impacts on

geological resources would be adequately minimized for constructing and operating the Pipeline.

4.2 SOILSAND SEDIMENTS

4.2.1 Terminal Facilities

4.2.1.1 Soils Types and Limitations

Soil types that occur within the proposed Project area and general limitations of these

soils were compiled from information presented in the USDA soil survey of San Patricio and

Aransas Counties, Texas (USDA, 1979)and USDA NRCS Soil Survey Geographic Database

(USDA, 2003). Soil types, general limitations, and the potential impacts on these soils from the

proposed Project, are presented in this section.

4.2.1.2 Terminal Facility

Construction of the Terminal would impact each of the nine soil types mapped by the

NRCS (including wasteland and urban land soil types). In total, approximately 646 acres would

be temporarily impacted by construction workspace and approximately 281 acres would be

permanently impacted by aboveground facility placement and operation. Table 4.2-1

summarizes the acreage impacts for each soil type.
Environmental Impact Statement 4-10 Corpus Christi LNG

Table 4.2-1

Soil Series Impacted by the Terminal

Soil Series Terminal Component Area Impacted by

Construction (acres)

Area Impacted by

Operation (acres) Total

Edroy clay

Terminal, Clay Pit Disposal Area,

Temporary Laydown Access,

Temporary Parking

38 27 65

Monteola clay

5 to 8 percent slopes Terminal, Marine Basin and Berth 0 37 37

Orelia sandy clay loam

Terminal, Clay Pit Disposal Area,

Substation Lease Area, Temporary

Laydown Access, Temporary

Laydown Area, Temporary Parking

185 18 203

Papalote fine sandy loam,

0 to 1 percent slopes a/ Terminal, Temporary Laydown Area <1 17 18

Papalote fine sandy loam,

1 to 3 percent slopes a/

Temporary Laydown Access,

Temporary Laydown Area,

Temporary Parking

2 0 2

Raymondville clay loam,

0 to 1 percent slopes a/

Clay Pit Disposal Area, Substation

Lease Area, Temporary Laydown

Access, Temporary Laydown Area

2 0 2

Urban land Clay Pit Disposal Area 19 0 19

Victoria Clay,

0 to 1 percent slopes a/

Temporary Laydown Access,

Temporary Laydown Area <1 0 <1

Wasteland Terminal, DMPA 2, Substation

Lease Area, Tool and Lunch Area 399 182 581

Total b/ 646 281 927

_________________________

a/ Soils are designated as prime farmland.

b/ Impact acreages do not include open water impacts and are not comparable to table 2.3-1 and table 4.8-1 because the NRCS

does not map soils in tidally influenced areas. NRCS soils mapping does not accurately follow the current shoreline where as

impacts in table 2.3-1 and table 4.8-1were calculated based on a more precise, current shoreline.

Publically available information was evaluated to identify and evaluate the soils that

would be most susceptible to impacts from construction of the Terminal. Major soil limitations

within the Terminal are discussed below.

Hydric Soils

Hydric soils are defined as soils that formed under conditions of saturation, flooding, or

ponding long enough during the growing season to develop anaerobic conditions in the upper

part. Soils that are artificially drained or protected from flooding (e.g., by levees)are still

considered hydric if the soil in its undistributed state would meet the definition of a hydric soil.

Cheniere would construct the Terminal in accordance with our Plan and Procedures. The
Environmental Impact Statement 4-11 Corpus Christi LNG

Procedures include provisions for wetland crossings and special construction measures in areas

of saturated soils. Cheniere’s implementation of these measures, as well as use of other BMPs

during construction, would minimize impacts on hydric soils and would not result in significant

long-term adverse impacts.

Compaction Potential

Soil compaction reduces the porosity and moisture-holding capability of soil. The degree

of compaction is dependent on moisture content and soil texture. Fine-textured soils with poor

internal drainage are most susceptible to compaction. Construction equipment travelling over

wet soils can disrupt soil structure, reduce pore space, increase runoff potential, and cause

rutting.

Approximately 288 acres of soils that would be impacted during construction and

operation of the Terminal have a high potential for severe compaction (Edroy clay;Orelia sandy

clay loam;Papalote fine sandy loam, 0 to 1 percent slopes;Raymondville clay loam, 0 to 1

percent slopes;and Victoria clay, 0 to 1 percent slopes)(see table 4.2-1). The potential impacts

on soils from compaction would be minimal due to the existing disturbed conditions at the

Terminal site. Cheniere would test soils for compaction and mitigate per our Plan in areas

temporarily impacted during construction of the Terminal.

Compacted soils have the potential to increase stormwater runoff at the site. Cheniere

would minimize the potential for stormwater runoff by developing and constructing systems

designed to manage stormwater runoff at the Terminal. Environmental impacts resulting from

compacted soils would be minimal and temporary or short-term through site design and the

implementation of mitigation measures outlined in our Plan and Procedures. Potential impacts

associated with stormwater runoff are further discussed in section 4.3.

Revegetation Potential

Physical properties and characteristics of soils contribute to the likelihood and duration of

successful revegetation in disturbed areas. Edroy clay and Monteola clay, 5 to 8 percent slopes

were identified as having low revegetation potential. Permanent aboveground facilities

associated with the Terminal would not be permitted to revegetate;however, areas temporarily

impacted during construction would be restored to preconstruction conditions. In order to ensure

successful revegetation in these areas, Cheniere would implement measures in our Plan as well

as recommendations of the local NRCS. Significant short- or long-term impacts on the

revegetation potential of soils are not anticipated given the implementation of these mitigation

measures.

Erosion Potential

Factors that influence soil erosion include soil texture, structure, length and percent of

slope, vegetative cover, and rainfall or wind intensity. Soils most susceptible to erosion by water

are typified by bare or sparse vegetative cover, noncohesive soil particles with low infiltration

rates, and moderate to steep slopes. Wind erosion processes are less affected by slope angles.

Clearing, grading, and equipment movement could accelerate the erosion process and, without

adequate protection, could result in discharge of sediment to waterbodies and wetlands. Soil loss

due to erosion could also reduce soil fertility and impair revegetation.

Soils within the Terminal site with high erosion potential are limited to Monteola clay, 5

to 8 percent slopes and those within the area labeled by the NRCS as “wasteland”, which have
Environmental Impact Statement 4-12 Corpus Christi LNG

been disturbed due to previous industrial activity. Impacts on these soils would result from

constructing the LNG storage tanks, marine basin and berth, as well as vaporization and related

processing equipment.

While the remaining soil types that would be impacted by constructing the Terminal are

designated as having low erosion potential, areas such as stream banks and the banks of drainage

ditches could also be susceptible to erosion resulting from construction activities. Cheniere

would implement our Procedures and incorporate the erosion and sediment control practices

specified in our Plan. Implementation of these erosion control measures while constructing and

operating the Terminal would minimize the potential for soil erosion and associated impacts.

The shoreline between Aransas Pass and the north boundary of the Padre Island National

Seashore changes at variable rates due to engineering modifications, which impact sediment

deposits by trapping sand in the littoral drift system. The shoreline at the Terminal site has been

stable from about 1937 to 1982, with no net change from erosion. However, wave action has

caused the shoreline west and east of the Terminal to retreat at an average rate of 1 to 3 feet per

year. Dredging of the marine basin, loading dock, and maneuvering area would modify a portion

of the shoreline within the Terminal site. Articulated block mats or rock breakwaters would

protect the shoreline within the maneuvering area from erosion.

The soils on the 20-foot high bluff overlooking the Corpus Christi Bay shoreline could

experience some erosion and slumping, but only minimal construction activities would occur in

this area;therefore, significant erosion of the bluff soils is not anticipated.

All ships passing through the Corpus Christi and La Quinta channels have the potential to

contribute to shoreline erosion. The severity of potential shoreline erosion bordering ship

channels is dependent on the number of ships;ship size, hull shape, speed, and draft;propeller

action;and channel proximity to shore, shoreline shape, and the type of material of the shoreline.

LNG carriers tend to have relatively shallower drafts than some other ships that currently use the

channels and are likely to have less wash effect than those other ships. For a variety of safety

reasons, LNG carriers calling on the Terminal would travel at slow speeds, with the

accompaniment of ship-assist tug boats, thereby minimizing the generated wave energy.

Additionally, the tugs would pull the LNG carriers off the dock to avoid scour from tugboat

propeller wash against the shore.

Historical shore stability at the Terminal site, use of articulated block mats or rock

breakwaters along the shoreline, as well as operation practices designed to minimize shoreline

scour would effectively mitigate for shoreline erosion, thus minimizing impacts.

Prime Farmland Soils

Prime farmland is land that has the best combination of physical and chemical

characteristics for producing food, feed, forage, fiber, oilseed, and other agricultural crops with

minimum inputs of fuel, fertilizer, pesticides, and labor, and without intolerable soil erosion, as

determined by the U.S. Secretary of Agriculture. In addition, prime farmland includes land that

possesses the above characteristics but is being used currently to produce livestock and timber.

Urbanized land and open water are excluded from prime farmland. Prime farmland typically

contains few or no rocks, is permeable to water and air, is not excessively erodible or saturated

with water for long periods, and is not subject to frequent, prolonged flooding during the
Environmental Impact Statement 4-13 Corpus Christi LNG

growing season. Soils that do not meet the above criteria may be considered prime farmland if

the limiting factor is mitigated (e.g., artificial drainage).

Construction and operation of the Terminal would impact approximately 22 acres of soils

classified as prime farmland soil. Approximately 5 acres would be restored to preconstruction

conditions, and operation of the Terminal would permanently impact 17 acres (see table 4.2-1).

These soils were previously in industrial use and are already impacted;therefore, loss of this

acreage would not significantly impact prime farmland in the local area.

4.2.1.3 Sediments

Sediments that would be impacted by construction of the Terminal are located within the

proposed marine berth, loading dock, and maneuvering area. Dredging to an elevation of -46

feet with an additional 2 feet paid allowed overdredge and 2 feet advanced maintenance dredge

would remove approximately 4.4 mcy of sediments. The sediment types that would be dredged

are described as stiff clays with interbedded sand and silt layers.

Soils located in tidally influenced areas of Corpus Christi Bay have not been mapped by

the NRCS. However, in 2003, four borings were drilled near the proposed ship berths (CB-47,

CB-48, CB-52, and CB-54). The sediment types observed in the borings are summarized below:

 CB-47. Lean Clay or Fat Clay from the mudline at elevation -6 feet (National Geodetic

Vertical Datum of 1929[NGVD 29])to the depth of dredging at elevation -42 feet.

 CB-48. Predominantly Lean Clay or Fat Clay from the mudline at elevation -7 feet to the

depth of dredging at elevation -42 feet;3-foot-thick layer of silty sand at elevation -23

feet;and a 4-foot-thick layer of clayey sand at elevation -36 feet.

 CB-52. Predominantly Silty Clay or Fat Clay from elevation -7 feet to the depth of

dredging at elevation -42 feet;a 5-foot-thick layer of silty sand layer at the ground

surface at elevation -2 feet;and a 4-foot-thick silty sand layer at elevation -30 feet.

 CB-54. Predominantly Lean Clay, Fat Clay, or Sandy Lean Clay from elevation -6 feet to

the depth of dredging at elevation -42 feet;a 5-foot-thick layer of silty sand at the ground

surface at elevation -1 foot;and a 3-foot-thick clayey sand layer at elevation -18 feet.

4.2.1.4 Contaminated Soils and Sediments

The Terminal site has been used to store bauxite ore since the 1950s. From 1957 to 1984,

the U.S. government arranged to have approximately 5,685,195 tons of bauxite ore from British

Guyana and Jamaica stockpiled on the northern portion of the Terminal site. In addition,

Sherwin and its predecessor, the Reynolds Metal Company, deposited approximately 1.6 mcy of

alumina processing waste materials into two former solid waste management units designated as

Beds 22 and 24 from 1954 to 1969. The EPA has determined that bauxite residue, or red mud,

does not exhibit any of the characteristics of hazardous waste, and that these deposits have a low

potential for danger to health and the environment. Three constituents of concern were identified

in red mud (arsenic, chromium, and radium-226), but at soil concentrations which were not

designated by TCEQ to be a risk. Arsenic concentrations were, however, found to exceed the

TCEQ Protective Concentration Level (PCL)in groundwater within and downgradient of Bed 22

(section 4.3). A clay cap was constructed over Bed 22 in 2007 to 2008 to prevent the further

infiltration of stormwater and leaching of contaminants into groundwater.
Environmental Impact Statement 4-14 Corpus Christi LNG

Contamination from spills or leaks of fuels, lubricants, and coolant from construction

equipment can have an adverse impact on soils. The effects of contamination would typically be

minor because of the low frequency and volumes of potential spills and leaks. Cheniere has

developed an acceptable SPCC Plan for construction that specifies cleanup procedures in the

event of soil contamination from spills or leaks of fuel, lubricants, coolants, or solvents.

Implementation of the measures in the SPCC Plan, revised to include certain Project-specific

measures, would adequately minimize the potential for soil contamination. Therefore, any

impacts resulting from soil contamination would be minor and temporary.

Sediments near the surface in urban environments may be contaminated by release of

various chemicals from human activities along the shoreline. In 2003, the COE reported the

results for the analysis of sediments that were sampled in 2000 as part of the Corpus Christi Ship

Channel Improvement Project. Three samples were analyzed for organic and metallic chemicals,

as well as metals, and then compared to the Effects Range Low (ERL)values, which are used by

the National Oceanic and Atmospheric Administration (NOAA)as screening levels for assessing

sediment quality. These are conservative levels used to identify sediment that may require

additional evaluations before decisions on disposal or beneficial re-use are made. The samples

were all identified as below the ERL levels.

Three samples were also compared to the TCEQ PCL for Tier 1 commercial/industrial

soil protective of Class 3 groundwater for metals. All concentrations were below the PCL levels.

Samples were also collected from the La Quinta Channel in 2000 and analyzed for

polychlorinated biphenyls, pesticides, and polycyclic aromatic hydrocarbons. All detections

were below ERL levels. We are not aware of more recent data than that presented in the 2003

COE report.

Additional impacts on soils as a result of the Terminal would include historic soil

contamination at the site, as discussed above, as well as the potential for import of contaminated

soils. In order to minimize the potential for the import of contaminated soils, Cheniere would

follow the guidelines outlined in Specification for Site Preparation and Earthwork (Document

No. 25744-200-3PS-CG00-F0001)to fulfill the requirements for soils imported to the site.

Specification for Site Preparation and Earthwork describes the measures that would be

implemented to ensure these soils are not contaminated. See below for an excerpt of the fill

material requirements.

General fill shall be an inorganic, non-expansive cohesive material meeting the following

requirements:

 Liquid Limit 30% to 60%

 Plasticity Index 40% Maximum, 20% Minimum

 Maximum Size 2 inch

 % Passing #200 Sieve 80% Maximum, 40% Minimum

Unless otherwise noted on design drawings, general fill shall be compacted to no less

than 95 percent Maximum Dry Density as determined by American Society for Testing and

Materials D698.

Granular structural fill shall not contain any significant amount of organics or debris,

and shall conform to the following criteria:
Environmental Impact Statement 4-15 Corpus Christi LNG

 Gradation (see table 4.2-2)

 Liquid Limit =25% maximum

 Plasticity Index =10% maximum

Table 4.2-2

Gradation Criteria for Granular Structural Fill

U.S. Standard Sieve Size Percent Passing (By Weight)

2 inch 100

0.75 inch 70-100

No. 4 30-100

No.20 15-90

No. 50 5-30

No. 200 0-5

Structural clayfill shall be low plasticity, inorganic, non-expansive cohesive material

meeting the following requirements:

 Liquid Limit =40% maximum

 Plasticity Index =20% maximum, 10% minimum

 Maximum Size =1 Inch

 % Passing #200 Sieve =80% maximum, 40% minimum

Bedding material shall be well-graded granular soils. It shall not contain any significant

amounts of organics or debris, and shall conform to the gradation presented in table 4.2-3.

Table 4.2-3

Gradation Criteria for Bedding Material

U.S. Standard Sieve Size Percent Passing (By Weight)

2 inch 100

No. 4 72-100

No. 16 26-80

No. 50 5-25

No. 200 0-7

Adherence to the guidelines described above would ensure that no contaminated soils are

imported to the site for use as structural fill. As a result, we determined that impacts from the

importation of contaminated soils would be negligible.
Environmental Impact Statement 4-16 Corpus Christi LNG

4.2.2 Pipeline Facilities

4.2.2.1 Soils

The Pipeline would cross two soil associations (Victoria-Raymondville-Orelia and

Orelia-Papalote)including five soil types: Orelia sandy clay loam, Papalote fine sandy loam

(0 to 1 percent slopes), Papalote fine sandy loam (1 to 3 percent slopes), Raymondville clay loam

(0 to 1 percent slopes), and Victoria clay (0 to 1 percent slopes). Characteristics of these soil

associations are provided in table 4.2-4.

Table 4.2-4

Characteristics of Soil Types Crossed by the Pipeline Facilities

Milepost Soil Association Name Hydric Prime

Farmland

Erosion

Potential

Revegetation

Potential

Compaction

Potential

0.0-18.9 Victoria-Raymondville-Orelia No Yes Low High High

18.9-23.0 Orelia-Papalote No Yes Low Moderate Low

4.2.2.2 Soil Limitations

Publicly available data was evaluated to determine the most susceptible soils crossed by

the Pipeline. Limitations for soils crossed by the Pipeline are summarized in table 4.2-4.

Hydric Soils

No hydric soils have been identified along the Pipeline route, except where wetlands are

crossed and in isolated areas where soils with high clay content have been subjected to periods of

heavy saturation. As described above, Cheniere would construct the Pipeline in accordance with

the measures contained in our Procedures to minimize impacts on hydric soils. Therefore, any

impacts on hydric soils would be minor and temporary.

Compaction Potential

The Victoria-Raymondville-Orelia soil association has a high potential for compaction.

Mitigation for soil compaction in agricultural areas would include topsoil segregation,

postponing soil disturbances when soils are wet, and using deep tillage prior to replacement of

the topsoil. Therefore, impacts on soils from compaction would be temporary and minor given

the implementation of these mitigation measures and those described in our Plan.

Revegetation Potential

The aboveground facilities along the Pipeline would cover approximately 21.5 acres of

land and would be permanently maintained as fenced and graveled sites. Additionally,

approximately 4.1 acres of soils crossed by the Pipeline (MP 18.9to MP 23)were identified as

having a low potential for revegetation. Cheniere would implement measures in our Plan as well

as recommendations of the local NRCS to ensure successful revegetation in these areas. Some of

these measures include the addition of soil additives, and seeding requirements. Therefore, shortor long-term impacts on the revegetation potential of soils are not anticipated given the

implementation of these mitigation measures, which includes monitoring of the right-of-way.
Environmental Impact Statement 4-17 Corpus Christi LNG

Prime Farmland

There are seven aboveground facilities associated with the proposed pipeline that would

be located on prime farmland (see table 4.2-5)which would result in the removal of 21.5 acres of

prime farmland. The impact would be permanent since each site would be graveled and fenced.

However, given the amount of available prime farmland in the area, the impact is not considered

significant.

Construction of the Pipeline could also impact prime farmland. These impacts could

include interference with agricultural drainage, mixing of topsoil and subsoil, and soil rutting and

compaction. These impacts would result primarily from excavating and backfilling the pipeline

trench and vehicular traffic along the construction right-of-way.

Impacts on soils from the Pipeline would be minor. Most impacts during construction

would be short-term and would not impact the potential use of prime farmland for agricultural

purposes. Cheniere has consulted with the NRCS regarding potential impacts on prime farmland

soils and has agreed to segregate topsoil to a depth of 12 inches. The NRCS indicated in a letter

dated December 9, 2003 (regarding the previously proposed pipeline under Docket Nos. CP04-

37-000 and CP04-44-000)that it did not consider the construction of the Pipeline to represent a

permanent conversion of Important Farmland, because the land could still be used for

agricultural production after the Pipeline is installed and the right-of-way reclaimed. We concur

with the NRCS letter.

Table 4.2-5

Aboveground Facilities Along the Pipeline Located on Prime Farmland

Facility Milepost Soil Classification Land Required for

Operation (Acres)

Taft Compressor Station 7.5 Victoria Clay, 0-1% slopes 5.8

Texas Eastern M&R Station 7.5 Victoria Clay, 0-1% slopes 2.1

Sinton Compressor Station 21.5 Papalote fine sandy loam, 0-1% slopes 7.3

Tejas Pipeline M&R Station 21.5 Papalote fine sandy loam, 0-1% slopes 2.4

NGPLM&R Station 22.4 Victoria Clay, 0-1% slopes 1.0

Transco M&R Station 22.8 Victoria Clay, 0-1% slopes 0.9

Tennessee Gas M&R Station and

MLV 23.0 Victoria Clay, 0-1% slopes 2.0

Total 21.5

Overall, adhering to the measures in our Plan would minimize impact on agricultural

soils, including prime farmland. Therefore, we conclude that construction and operation of the

Pipeline would not significantly impact soils.
Environmental Impact Statement 4-18 Corpus Christi LNG

4.2.2.3 Contaminated Soils

The Pipeline would not cross any areas with known contaminated sediments. Cheniere

performed a search of environmental databases to determine if contaminated soils were present

along the proposed Pipeline. No known areas of contamination were identified along the

Pipeline route.

Contamination from spills or leaks of fuels, lubricants, and coolant from construction

equipment can adversely impact soils. The effects of contamination would typically be minor

because of the low frequency and volumes of potential spills and leaks. Cheniere has developed

an acceptable SPCC Plan for construction that specifies cleanup procedures in the event of soil

contamination from spills or leaks of fuel, lubricants, coolants, or solvents. Implementation of

the measures in the SPCC Plan, revised to include certain Project-specific measures, would

adequately minimize the potential for soil contamination.

4.2.2.4 Erosion Control

During construction of the pipeline, Cheniere would implement some of the erosion

control measures presented in our Plan such as installing temporary slope breakers, such as silt

fence or staked hay or straw bales to reduce the runoff velocity and divert water off the

construction right-of-way. In addition, Cheniere would use sediment barriers to stop the flow of

sediments and prevent the deposition of sediments beyond approved workspaces or into sensitive

resources.

None of the soils crossed by the Pipeline would have high erosion potential;therefore,

impacts on soils resulting from erosion would be negligible.

4.3 WATER RESOURCES

4.3.1 Terminal Facilities

4.3.1.1 Groundwater

The proposed Terminal is located in the Coastal Lowlands aquifer system within San

Patricio and Nueces Counties. In Texas, the Coastal Lowlands aquifer system underlies about

35,000 square miles of level, low-lying coastal plain and is comprised of Miocene-age and

younger unconsolidated sediments of sand, silt, and clay. These sediments were deposited in

three depositional environments: continental (alluvial plain), transitional (delta, lagoon, and

beach), and marine (continental shelf)(Ryder, 1996). In San Patricio and Nueces Counties, the

primary water-bearing stratigraphic units are Pliocene-age Goliad sand, Pleistocene-age Lissie

and Beaumont formations, and Holocene-age alluvial and beach sands in the Nueces River valley

(Shafer, 1968). Within Texas, the coastal lowlands aquifer system is commonly referred to as

the Gulf Coast aquifer which is separated into five permeable zones and two confining units

(Ryder, 1996).

Along the Gulf Coast, the upper part of the aquifer system is unconfined. The Chicot and

Evangeline aquifers are commonly used hydrogeologic-unit designations for subdivisions of the

upper, mostly sandy part of the aquifer system. Water supply wells in southeastern San Patricio

County are screened in the Chicot aquifer at depths typically less than 50 feet. Groundwater in

the county is primarily used for irrigation;however, its use is limited by high concentrations of

chloride, salinity, and alkalinity. There are no fresh-water bearing sands within the Terminal
Environmental Impact Statement 4-19 Corpus Christi LNG

site. Saltwater intrusion in the permeable sands extends further inland along the northern shore

of Corpus Christi Bay. The nearest freshwater sands are located east of the Terminal site, in the

vicinity of Aransas Pass and Ingleside.

The Terminal site is not underlain by a sole-source aquifer, as designated by the EPA,

and there are no locally zoned aquifer protection areas within the Terminal site. There is very

little groundwater use in the county and almost no pumping in the area. Most municipal water

systems in San Patricio and Nueces Counties obtain water from Lake Corpus Christi, Lake

Texana, or the Nueces River.

According to Texas Water Development Board data there are no public or private water

supply wells located within 150 feet of the Terminal and thus, there are no wellhead protection

areas (also known as source water protection areas)crossed by the Terminal. The nearest public

and private supply wells are located about 3.2 miles and 2.3 miles from the Terminal site,

respectively.

As discussed in section 4.2, groundwater monitoring showed that arsenic concentrations

in shallow groundwater exceeded the TCEQ PCL, within and slightly downgradient of Bed 22.

Groundwater quality monitoring is the responsibility of the Reynolds Metals Company under a

TCEQ-approved Remedial Action Plan which established a plume management zone for the

natural attenuation monitoring of arsenic concentrations in groundwater downgradient of Bed 22.

The depth to groundwater over the majority of the Terminal site is approximately 11 feet

and most excavations for construction would generally be in the range of 3 to 5 feet below

ground surface. It may be necessary to dewater trenches during construction if shallow

groundwater is encountered during excavations. Because of the relatively small amount of water

removed, the short duration of the activity, and the local discharge of the water, groundwater

levels would quickly recover after pumping stops. Cheniere would follow the measures in our

Procedures, which require that dewatering structures be located so that there would be no

discharge of sediments into wetlands and waterbodies.

Hammer-driven pilings would be used during the construction of the berthing docks. A

potential impact associated with driven pilings is the cross contamination of lower permeable

aquifer zones through downward vertical seepage from one layer to another. The anticipated

maximum depth of pilings is at an elevation of approximately -80 feet. At this depth, the pilings

would stay within the upper (shallow)permeable zone of the Chicot aquifer. Keeping the pilings

within one layer of the Chicot aquifer system and not crossing aquifer confining layers reduces

the potential for cross-contamination.

The greatest potential for an impact on groundwater would be an accidental release of

hazardous substances, such as fuels, lubricants, and coolants, while constructing and operating

the Terminal facilities. Cheniere has agreed to implement our Procedures, including the

preparation and implementation of Spill Prevention and Response Procedures that meet state and

federal requirements. Cheniere filed a SPCC Plan that provides measures to minimize the

potential impacts of spills of hazardous materials. Cheniere’s SPCC Plan describes general

preventative BMPs, including personnel training, equipment inspection, and refueling procedures

to reduce the likelihood of a spill. It also describes the mitigation measures, including

containment and cleanup, to minimize potential impacts should a spill occur.
Environmental Impact Statement 4-20 Corpus Christi LNG

Substantial impacts on the groundwater resources underlying the Terminal facilities are

not anticipated due to: the non-potable saline groundwater conditions that naturally occurs at the

site, lack of water supply wells in the area, depth of groundwater below land surface in relation

to anticipated excavation depths, construction of the proposed pilings within the permeable zone

of the Chicot aquifer and not crossing aquifer confining layers, and surficial mitigation measures

that would be implemented by Cheniere in the event of a hazardous material spill.

4.3.1.2 Surface Water

The Terminal would be located on the north shore of Corpus Christi Bay, situated at the

northwestern end of the La Quinta Channel. Corpus Christi Bay is designated in the National

Estuary Program as an estuary of “national significance”. Corpus Christi Bay is typically

shallow, with an average depth of 8 feet;however, there are two shipping channels through the

bay that are dredged to -45 feet mean low tide to allow passage of large cargo and tanker ships.

As described previously, Cheniere would dredge a maneuvering area to a depth of -46 feet (plus

two feet overdredge and 2 feet advanced maintenance dredge)to allow LNG carriers access to

the Terminal. These activities were previously permitted by the COE. Following construction,

dredged material would be disposed of in the designated DMPAs. Specifically, dredged material

would be put to beneficial use as fill for a portion of a former 90-acre clay borrow pit and to

facilitate the capping of 385 acres of bauxite residue beds that have laid open since 1968 (DMPA

2). Post-construction maintenance dredging would be conducted on an as-needed basis;

however, is not anticipated to be more than once every three years. A portion of the marine

facilities approach was recently dredged by the COE as part of an extension of the La Quinta

Channel.

Based on the TCEQ Draft 305(b)Water Quality Inventory, designated uses for Corpus

Christi Bay are Contact Recreation, Aquatic Life, Fish Consumption, Oyster Waters, and

General Use. All designated uses that were assessed in the 305(b)inventory are fully supported

(TCEQ, 2010a). Corpus Christi Bay is considered a warmwater, saline fishery.

Water quality issues currently affecting Corpus Christi Bay include reduced inflow of

fresh water;wetland habitat loss;chemical, heavy metal, and nutrient increases;brown tide;and

floating debris (American Oceans Campaign, 1996). Freshwater inflow to the bay has been

reduced by increasing demands from upstream communities that rely on surface water for their

water supply. The Corpus Christi Bay watershed supports the petrochemical, agriculture, and

shipping industries, which have the potential to degrade water quality through chemical and oil

spills, pesticide and fertilizer runoff, and heavy metal contamination. Corpus Christi Bay is

generally considered turbid, with a long-term average of total suspended solids ranging from 20

to 100 milligrams per liter (mg/L)or higher (Corpus Christi Bay National Estuary Program,

1997). This turbidity can be attributed to the natural characteristics of the bay as well as ongoing

shipping and periodic dredging activities.

As described below, construction and operation of the Terminal facilities would

temporarily and permanently impact Corpus Christi Bay.

Turbidity and Sedimentation

To facilitate the construction of the terminal facilities, marine basin, and maneuvering

area, Cheniere would use mechanical and hydraulic cutterhead-suction dredges to excavate

nearshore waters. These dredging activities would require approximately six months to
Environmental Impact Statement 4-21 Corpus Christi LNG

complete. Hydraulic suction dredges cut and pull dredged material into the dredge device

minimizing turbidity in the water column. Although hydraulic cutterhead dredges capture the

majority of sediment loosened, some sediment would become suspended in the water. Studies of

cutterhead dredges indicate that elevated turbidity is limited to the lower portion of the water

column and turbidity levels are at background within several hundred feet of the cutterhead.

Therefore, the dispersion of sediments that would occur during dredging would be minimal. To

further minimize turbidity and sedimentation impacts, Cheniere would adjust cutterhead speeds.

In addition to the use of a hydraulic cutterhead dredge to minimize turbidity and

sedimentation impacts, the natural characteristics of Corpus Christi Bay would also work to

minimize these impacts. Ward (1997)describes the tidal flushing in Corpus Christi Bay as a

restricted flow, tidal regime switching from semi-diurnal to diurnal. The tides are wind

dominated which results in relatively higher tides in summer and spring with lower tides in

winter and fall because of the prevailing wind. Because of the change in the width to depth ratio

of the La Quinta Channel, overall currents would be expected to be relatively low, particularly at

or near the bottom where dredging would occur.

We have determined that dredging activities would result in levels of turbidity consistent

with ambient total suspended solids concentrations, up to the approximately 80 mg/L that TCEQ

has reported as normal within 1 foot of the water surface. Therefore, based on the general

hydrologic characteristics of the site and the proposed dredging activities, we expect that most of

the turbidity and sedimentation would be localized, would return to background levels a short

distance from the point of disturbance, and would not significantly affect surface water quality.

In addition, proper disposal of dredged materials and implementation of the measures outlined in

our Plan and Procedures would further reduce or avoid significant increases in background

turbidity levels in the La Quinta Channel.

Dredging activities would also result in and potential runoff from the

construction/dredging equipment. Runoff impacts would be minimized through use of BMPs

and active maintenance of equipment.

Maintenance dredging would only occur in areas that have been previously dredged

during the initial construction of the Terminal. Maintenance dredging is presently expected to

occur no more frequently than once every three years and each event is anticipated to last for no

more than 30 days. Hydraulic cutterhead dredges would also be used to limit resuspension, and

sediments would be sampled and tested for priority pollutants prior to each maintenance

dredging event according to the methodology described in the Inland Testing Manual

(EPA/COE, 1998).

Cheniere is required to obtain several permits that would address dredging and dredged

material management, including permits from the COE under Section 404 of the CWA and

Section 10 of the RHA. Permits for water discharges into the bay from the Terminal would be

obtained from the EPA and/or the TCEQ under Section 401 of the CWA. A NPDES permit

under Section 402 of the CWA issued by the RRC would be necessary to regulate return water

flowing from the DMPA. The issuance of these permits takes into consideration impacts on

environmental resources;therefore, the permits may contain operational limitations designed to

minimize or avoid environmental impacts.

Several permit applications were submitted to the COE including the Section 404/10

Individual Permit application, as well as a Request for State Water Quality Certification and
Environmental Impact Statement 4-22 Corpus Christi LNG

Request for Coastal Zone Management Consistency Determination submitted to the RRC. At the

time of this EIS, the COE has not yet issued the Section 404/10 Individual Permit.

Ship and Boat Traffic

Ship and boat traffic associated with constructing and operating the Terminal could

impact surface water resources as a result of ship movements, including propeller use, and ballast

water exchanges. Increased wave action from ship and boat movements could increase turbidity

and sedimentation. Additional impacts on surface water resources would result from LNG

carrier operations requiring ballast water discharge at the Terminal. Discharge of ballast water at

the Terminal site could also increase turbidity in the immediate area, as well as alter the salinity

levels and water temperature. Impacts on water resources resulting from ballast water would be

temporary and minor, only affecting a relatively small area. Additional information regarding

impacts associated with ballast water is provided in section 4.6.2.

Ship and boat traffic has the potential to adversely impact water quality in the event of an

accidental release of a hazardous substance such as fuel, lubricants, coolants, or other materials

on board the vessel. Cheniere would implement the measures outlined in their SPCC in the

event of a spill, as well as measures outlined in our Procedures. Cheniere would minimize the

risk of a spill by implementing general preventative BMPs, including personnel training,

equipment inspection, and refueling procedures.

Stormwater Runoff

Stormwater run-off collecting at the Terminal would be discharged into Corpus Christi

Bay directly or, via the La Quinta Ditch which runs alongside La Quinta Road. Stormwater

removal from within the LNG storage tank dikes must conform to 49CFR 193.2173, requiring

water to be pumped out at 25 percent of the maximum predictable collection rate from a storm of

ten-year frequency and one-hour duration. Cheniere would follow our Procedures which require

that prior to construction Cheniere must prepare a SWPPP that complies with the EPA’s National

Stormwater Program General Permit requirements.

Water Use

The potable water supply for the Terminal facilities would be obtained from a San

Patricio Municipal Water District 24-inch-diameter main water line at the junction of SH 35 and

SH 361. The San Patricio Municipal Water District obtains its water from the Nueces River and

Lake Texana (TCEQ, 2010b). The water supply for the compressor stations would also be

procured from the San Patricio Municipal Water District. The volumes of water required to

construct and operate the Terminal are provided in tables 4.3-1 and 4.3-2.
Environmental Impact Statement 4-23 Corpus Christi LNG

Table 4.3-1

Water Requirements to Construct the Terminal

Activity Quantity (millions of gallons)

Craft and Subcontractor Use 20

Line Hydrostatic Test 5

LNG Tank Hydrostatic Test 127

Site Preparation 15

Total 167

Table 4.3-2

Water Requirements to Operate the Terminal

Activity Gallons per Minute Quantity (millions of

gallons per day)

Demineralized Water for Injection to Turbines for Nitrogen

Oxides and Amine System 1,171 1.69

Service Water for LNG Trains 50 0.07

Potable Water for Turbine Inlet Air Humidification 306 0.44

Potable Water for Remote Building 13 0.02

Reject Water from Treatment and Design Margins 1,086 1.56

Total 2,626 3.78

Hydrostatic Testing

Prior to being placed into service, the LNG storage tanks would be tested to ensure

structural integrity. The LNG piping would be pneumatically tested and therefore, would not

require hydrostatic testing. Other piping and equipment associated with the Terminal would

require hydrostatic testing. The total cumulative volume of water required for construction and

hydrostatic testing of this equipment would be approximately 167 million gallons.

Upon completion of construction, the inner tank of each of the LNG storage tanks would

be tested hydrostatically, in accordance with API Standard 620, Q.8.3. Hydrostatic testing would

involve filling each of the inner tanks with approximately 42,270,000 gallons of fresh water.

Test water would be purchased from the San Patricio Municipal Water District, and discharged

to a drainage ditch that flows into Corpus Christi Bay or the Sherwin Alumina raw water

reservoir (just north of the Terminal)for use in their facilities.

Pumps in each tank would control the discharge rate of the test water from the LNG

storage tanks while discharge structures, such as a splash plate or hay bale structures, would be

used to dissipate energy during discharge of the hydrostatic test water. These energy dissipation

devices aid in preventing scouring and erosion. No chemicals would be added to the hydrostatic
Environmental Impact Statement 4-24 Corpus Christi LNG

test water before or after testing. All test waters would be analyzed for chemical composition

prior to discharge.

Conclusion

Construction and operation of the Terminal would temporarily decrease water quality

within the vicinity of the site as a result of dredging, maintenance dredging, and stormwater

runoff. As described previously, impacts on water quality from dredging activities would be

short-term and localized to within a few hundred feet of the activity. Through implementation of

Cheniere’s BMPs, NPDES permitting, our Procedures, and Cheniere’s SPCC Plan, potential

impacts resulting from stormwater runoff or the discharge of hydrostatic test water would be

adequately minimized or avoided.

4.3.2 Pipeline

4.3.2.1 Groundwater

As discussed above for the Terminal, the Pipeline area is underlain by the Gulf Coast

aquifer, characterized as an unconfined aquifer with unconsolidated sand, silt, and clay (Ryder,

1996). There are no locally protected aquifers, public or private water supplies, or wellheads in

the vicinity of the Pipeline.

The greatest potential for impacts on groundwater would be an accidental release of a

hazardous substance, such as fuels, lubricants, and coolants while constructing and operating the

Pipeline. Cheniere would implement the measures contained in our Procedures, as well as its

SPCC Plan which provides measures to minimize the potential impacts associated with spills of

hazardous materials.

4.3.2.2 Surface Water

The Pipeline would cross nine waterbodies. There are no potable water intakes within

3 miles downstream of any waterbody crossing. No waterbody segments crossed by the Pipeline

are included on the list of impaired waterbodies under Section 303(d)of the CWA nor do they

contain contaminated sediments. Table 4.3-3 provides a list of the waterbodies that would be

crossed by the Pipeline, including location by MP, waterbody name, type, crossing width, water

quality classification, fishery type, and proposed crossing method. The pipeline would cross

only two natural, permanently flowing waterbodies;Oliver Creek (MP 16.6)and Chiltipin Creek

(MP 17.9).
Environmental Impact Statement 4-25 Corpus Christi LNG

Table 4.3-3

Waterbodies Crossed by the Pipeline

Waterbody Milepost a/ Stream

Type b/

Stream

Designation c/

State Water

Quality

Classification

Fishery

Type

Crossing

Method d/

Drainage Ditch 0.5 C Intermediate N/A Warmwater Open Cut

Drainage Ditch 1.2 C Intermediate N/A Warmwater Open Cut

Drainage Ditch 2.3 I Intermediate N/A Warmwater Open Cut

Drainage Ditch 4.7 I Intermediate N/A Warmwater Open Cut

Drainage Ditch 12.5 I Intermediate N/A Warmwater Open Cut

Oliver Creek 16.6 P Intermediate N/A Warmwater HDD

Chiltipin Creek 17.9 P Intermediate N/A Warmwater HDD

Tributary to Chiltipin Creek 18.0 I N/A N/A Warmwater Open Cut

Drainage Ditch 18.5 I N/A N/A Warmwater Open Cut

_________________________

a/ Milepost at canal/creek centerline.

b/ P =Perennial, I =Intermittent, C =Canal

c/ Stream designations includes minor, intermediate, and major. Minor waterbodies are less than or equal to 10 feet wide at the

water's edge at the time of crossing;intermediate waterbodies are greater than 10 feet wide but less than or equal to 100 feet wide

at the water's edge at the time of crossing;and major waterbodies are greater than 100 feet wide at the water's edge at the time of

crossing.

d/ HDD=horizontal directional drill

Cheniere would use the HDD method to cross Oliver and Chiltipin Creeks. Crossing

these waterbodies via HDD would avoid direct impacts on them as the Pipeline would be

installed underneath the stream bed. With the exception of one drainage ditch, the remaining

waterbodies are typically dry with little or no flow.

Waterbodies crossed via the open cut method could experience a decrease in water

quality due to increased turbidity and sedimentation. However, due to the duration of

disturbance, these impacts would be short-term. In addition, we anticipate that most drainage

ditches would not be flowing during construction of the Pipeline and thus a decrease in water

quality due to excess turbidity would not occur. Furthermore, impacts on the water quality of

crossed waterbodies as a result of increased turbidity or sedimentation during Pipeline

construction and operation would short-term and minor because in stream construction activities

would occur within 48 hours.

To minimize impacts on waterbodies, Cheniere would implement measures described in

our Procedures. These measures would include:

 restoring stream banks and natural contours to preconstruction conditions to the

maximum extent practicable using the measures contained in our Plan and Procedures;

 stabilizing banks and installing temporary erosion sediment barriers within 24 hours;and
Environmental Impact Statement 4-26 Corpus Christi LNG

 vegetating disturbed riparian areas with conservation grasses and legumes or native plant

species.

Additionally, lubricant, hydraulic fluid, and fuel spills from refueling construction

equipment, fuel storage, or equipment failure in or near a waterbody could flow or migrate to the

waterbody and impact water quality and other aquatic resources. Cheniere would implement the

measures outlined in its SPCC Plan to minimize the potential impacts of spills and hazardous

materials in waterbodies.

An adverse impact on waterbodies as a result of a hazardous materials spill would not be

anticipated, as Cheniere would implement preventative and mitigation measures as outlined in its

SPCC Plan and our Procedures.

Prior to being placed into service, the Pipeline would be hydrostatically tested to ensure

structural integrity. The Pipeline would be filled with approximately 11,400,000 gallons of

water for hydrostatic testing. Cheniere would likely obtain the water from an existing 30-inchdiameter raw water line owned and operated by the San Patricio Municipal Water District.

After testing is complete, water would be discharged at an average rate of approximately

4,000 gallons per minute into the Sherwin Alumina raw water reservoir located approximately

400 feet north of the south end of the Pipeline. Alternatively, the water may be discharged into

the drainage ditch along La Quinta Road where it would flow into the La Quinta Channel.

Cheniere would use appropriate energy dissipation and erosion control measures to prevent

scouring during dewatering. No chemicals would be added to the test water. As described for the

Terminal in Section 4.3.1 the raw water reservoir would have enough volume to accommodate

the one time discharge of hydrostatic test water from the Pipeline.

Conclusion

Waterbodies crossed by the Pipeline via the open cut method would experience shortterm decreases in water quality resulting from increased turbidity, sedimentation, and overall

stream bed and bank disturbance. However, we have determined that implementation of

Cheniere’s SPCC Plan as well as use of the measures outlined in our Procedures would

adequately minimize impacts on surface water resources.

4.4 WETLANDS

As defined by the COE, wetlands are areas inundated or saturated by surface water or

groundwater. Under normal circumstances these areas support a prevalence of vegetation

typically adapted for life in saturated soil conditions.

Cheniere identified wetlands within the Project area by field delineation. Delineations

followed the Routine On-Site Determination Methodology presented in the COE Wetland

Delineation Manual (Technical Report Y-B7-1)and the Regional Supplement to the Corps of

Engineers Wetland Delineation Manual: Atlantic Gulf Coastal Plain, Version 2.0 released in

November 2010 (ERDC/EL TR-10-20).

4.4.1 Terminal Facilities

Five wetland types were identified at the Terminal site;cordgrass salt marsh (estuarine

intertidal emergent [E2EM]wetland), black mangrove (estuarine intertidal scrub/shrub [E2SS]

wetland), unvegetated sand flat (estuarine intertidal flat [E2FL]), vegetated sand flat/high marsh
Environmental Impact Statement 4-27 Corpus Christi LNG

(E2FL), and seagrass (estuarine submerged aquatic bed [E1AB]). Table 4.4-1 provides the

approximate acreages of each wetland type located at the Terminal site. Typically, smooth

cordgrass (Spartina alterniflora)is the only species found within this wetland type, however in

the low marshes other species often include: saltmarsh bulrush (Scirpus maritimes var.

macrostachyus), perennial glasswort (Salicornia virginica), and sea lavender (Limonium

carolinianum). Black mangrove (Avicennia germinans)is the dominant species in the black

mangrove wetland type, but buttonwood (Conocarpus erectus), leather fern (Acrostichum

aureum), perennial glasswort, and bay marigold (Borrichia arborescens)may also be found.

The dominant species among sparsely vegetated sand flat often includes various glasswort

species (Salicornia spp.), saltwort (Batis maritima), mud plantain (Heteranthera reniformis), and

false pimpernel (Lindernia dubia). Seagrass consists predominantly of shoal grass (Halodule

wrightii), manatee grass (Syringodium filiforme), turtle grass (Thalassia testudinum), clover

grass (Halophila engelmanni), and widgeon grass (Ruppia maritima).

Table 4.4-1

Approximate Acreages of Wetland Vegetation Communities that would be Impacted by the Terminal

Vegetation Community Wetland Classification a/ Construction Impact

Acreage Operation Impact Acreage

Cordgrass Salt Marsh E2EM 6.19 5.91

Black Mangrove E2SS 7.35 6.72

Unvegetated Sand Flat E2FL 3.25 2.87

Vegetated Sand Flat / High

Marsh E2FL 1.37 1.00

Seagrass E1AB 9.29 9.17

Total 27.45 25.67

Construction and operation of the Terminal facilities would temporarily and permanently

impact wetlands. As identified in table 4.4-1, approximately 6.19and 5.91 acres of cordgrass

salt marsh, 7.35 and 6.72 acres of black mangrove, 4.62 and 3.87 acres of unvegetated and

vegetated sand flats, and 9.29and 9.17 acres of seagrass would be impacted by construction and

operation, respectively. A total of approximately 27.45 and 25.67 acres of wetlands would be

temporarily and permanently impacted by the construction and operation of the Terminal

facilities, respectively.

Temporary wetland impacts would be those associated exclusively with construction

activities. Once construction is complete, wetlands which were temporarily disturbed by

construction activities would be restored to preconstruction contours and allowed to naturally

revegetate. Unlike temporary impacts, permanently impacted wetlands would not be restored to

preconstruction conditions following the completion of construction activities, but would be

maintained as part of the Project.

To avoid and minimize impacts on wetlands, the Terminal facilities were sited in a

manner that would result in less wetland impact. To mitigate unavoidable impacts on wetlands,

Cheniere submitted an Aquatic Resources Mitigation Plan (ARMP)for the Project to the COE.

This plan was submitted to the COE as part of the CWA Section 404 permitting process and
Environmental Impact Statement 4-28 Corpus Christi LNG

approved in 2005 (DA Permit 23561). Since 2005, Cheniere has continued to work with the

COE to finalize the ARMP to account for additional wetland impacts associated with the

proposed Project.

Cheniere’s proposed conceptual wetland mitigation plan at Shamrock Island was

approved by the COE in 2005 to mitigate for impacts to waters of the U.S. associated with the

previous proposal to construct an LNG import terminal and associated pipeline (Docket Nos.

CP04-37-000, CP04-44-000, CP04-45-000, and CP04-46-000). Mitigation measures for the

previously permitted 12.88 acres of wetland impacts were completed in 2013 and included the

installation of 16 breakwaters bordering the north-western end of Shamrock Island. Construction

of these breakwaters would assist in the preservation of existing habitats including cordgrass,

mangroves, unvegetated sand flats, vegetated sand flats, hard substrates, and uplands.

The EPA expressed concern regarding Cheniere’s ARMP. The COE addressed this

concern and determined that 50 years to achieve an 8.9:1 preservation ratio, as proposed in

Cheniere’s ARMP, is not an appropriate period to evaluate preservation values. The COE

recommends evaluating the preservation values during a 10-year period, during which time,

conditions affecting the site would be relatively consistent and less likely to be influenced by

sudden episodic events, such as hurricanes. Use of a shorter time period would lower Cheniere’s

estimated preservation ratio and potentially change the habitat types preserved by the proposed

ARMP.

The COE determined that in order to quantitatively evaluate Project impacts on wetland

habitats, it is in the public’s best interest to perform a functional assessment of the Project. A

functional assessment would quantify, in a scientifically sound, reproducible and reasonably

rapid manner, the wetland functions lost and those that would be mitigated for by the Project.

This would allow the COE to verify if the Project is consistent with the COE-EPA Memorandum

of Understanding of Mitigation under the CWA Section 404(b)(1)Guidelines and 33 CFR

332.3(f)(1), and determine if the anticipated impacts would be adequately compensated by the

proposed mitigation. Pending the results of the functional assessment, increased compensation

in the mitigation area could be required.

Following construction, Cheniere would monitor all temporarily impacted wetlands and

adjacent wetlands, in accordance with our Procedures. Post-construction monitoring would

include photographing, measuring and reporting the extent of aerial vegetative cover at six

months, one year, two years, and three years following their initial restoration attempt. At the

end of each yearly interval, if wetlands are not reestablishing as planned, monitoring would also

include notification of the COE and other appropriate resource agencies in order to develop

alternative mitigation or restoration plans.

Construction and operation of the Terminal would result in the loss of approximately

25.67 acres of wetland and would temporarily disturb 1.78 acres. Because Cheniere’s ARMP is

still under development, we recommend that:

 Prior to construction,Cheniere should file the ARMP developed in consultation

with the COE. The plan should include:

a. details regarding the amount,location,and types of mitigation proposed;and

b. specific performance standards to measure the success of the mitigation;and

remedial measures,as necessary,to ensure that mitigation is successful.
Environmental Impact Statement 4-29 Corpus Christi LNG

Based on Cheniere’s proposed impact mitigation measures as well as preparation of the

functional assessment and ARMP to be approved by the COE, we have determined that

constructing and operating the Terminal would not have a significant impact on wetlands.

4.4.2 Pipeline Facilities

The Pipeline would cross three palustrine emergent wetlands (PEM)as identified in table

4.4-2. PEM wetlands are characterized by a dominance of rooted herbaceous (non-woody)

emergent wetland plants such as grasses and short, shrubby vegetation. Typical herbaceous

species which occur in the PEM wetlands crossed by the Pipeline include: river birch (Betula

nigra), mesquite (Prosopis glandulosa), deciduous holly (Ilex decidua), locust (Gleditsia

triacanthos), sedges (Carex spp.), softstem bulrush (Schoenoplectus tabernaemontani), curly

dock (Rumex crispus), common cattail (Typha latifolia), spikerushes (Eleocharis spp.), and red

fescue (Festuca rubra). Table 4.4-2 also provides the milepost location, wetland ID, temporary

and permanent areas of impact, and wetland classification for each wetland crossed by the

Pipeline facilities.

Table 4.4-2

Approximate Acreages of Wetland Vegetation Communities that would be Impacted by the Pipeline

Wetland ID Milepost Wetland Classification a/ Temporary Area of

Impact (Acres) b/

Permanent Area of

Impact (Acres) c/

MP-18-2 d/ 18.03 PEM 0.00 0.00

MP-20-1 d/ 20.13 PEM 0.00 0.00

MP-21-1 21.34 PEM <0.01 <0.01

_______________________

a/ PEM =Palustrine emergent wetland

b/ Temporary impacts based on 75-foot construction right-of-way

c/ Permanent impacts based on 50-foot wide permanent right-of-way

d/ Areas where no impacts would occur because area would be crossed via bore or HDD

Impacts on wetlands would include the temporary disturbance of wetland vegetation,

soils, and hydrology. Additionally, soil disturbance and removal of wetland vegetation would

temporarily impact wetland functions. Failure to properly segregate topsoil over the Pipeline

trenchline would result in the mixing of topsoil with subsoil. This mixing can affect the success

of post-construction reestablishment and the natural recruitment of native, wetland vegetation.

To avoid and minimize impacts on wetlands crossed by the Pipeline, Cheniere has reduced

workspaces wherever possible. Cheniere has also routed the proposed Pipeline in several

locations to avoid crossing wetlands entirely. Additionally, two of the three wetlands crossed by

the Pipeline would be bored or crossed via HDD, thus avoiding or minimizing impacts. Though

there is one PEM wetland that is located within the proposed permanent right-of-way, this

wetland would be restored following completion of construction activities. Cheniere would also

implement impact minimization measures identified in our Procedures. Major components of

our Procedures which are applicable to wetland construction include:

 limiting construction equipment operating within the right-of-way to the equipment

necessary for clearing, excavating, pipe installation, backfilling, and restoration activities;
Environmental Impact Statement 4-30 Corpus Christi LNG

 using upland access roads for all non-essential equipment to the maximum extent

practicable;

 operating low-ground-weight equipment or operating from prefabricated construction

mats in saturated wetlands;

 installing temporary erosion and sediment control measures immediately after the initial

disturbance of wetland soils, and inspecting and maintaining the temporary erosion and

sediment control measures until final stabilization;

 refueling and parking equipment at least 100 feet from a wetland boundary;

 installing sediment controls across the construction right-of-way, as needed, to contain

trench spoil within wetlands;and

 segregating the uppermost foot of wetland topsoil from the underlying subsoil in areas

disturbed by trenching, except in areas with standing water or saturated soils, or where no

topsoil layer is evident.

Following construction, Cheniere would also monitor all temporarily impacted wetlands

and adjacent wetlands, in accordance with the ARMP and our Procedures. Based on the amount

and type of wetlands impacted along the Pipeline route and Cheniere's proposed impact

minimization measures, we have determined that constructing and operating the Pipeline would

not significantly impact wetlands.

4.5 VEGETATION

4.5.1 Terminal Facilities

The Terminal would be located within the southeastern portion of the Gulf Prairies and

Marshes Ecoregion (Gould, 1975). The TPWD has defined area-specific vegetation types that

characterize the state by vegetative cover and habitat types (McMahan et al., 1984). The

Terminal would be located within an area TPWD has characterized as crops (McMahan et al.,

1984). However, due to past disturbances, we have characterized the vegetation at the Terminal

site as industrial/disturbed (grasslands and scrub/shrub). The marine component of the Terminal

site also contains submerged aquatic vegetation (SAV).

4.5.1.1 Industrial/Disturbed Vegetation

Much of the Terminal site would be located on highly disturbed land that supports little

or no vegetation. A significant portion of the site has been previously graveled, paved,

compacted or used for storage of bauxite and bauxite tailings. Grasslands and scrub/shrub

uplands have been identified along the edges of the disturbed industrial areas. Coastal grasses

and forbs exist as a narrow band between the tidal flats and the scrub/shrub communities within

the Terminal site. Grass and forb species in these areas include: marshhay cordgrass (Spartina

patens), saltgrass (Distichlis spicata), Bermuda grass (Cynodon dactylon), camphor daisy

(Machaeranthera phyllocephalla), sea ox-eye (Borrichia frutescens), coastal dropseed

(Sporoblous virginicus), and sea oats (Uniola paniculata). Both woody and herbaceous

vegetation also exist within the minimal scrub/shrub communities at the Terminal site. Typical

species of the herbaceous undergrowth at the Terminal site include: western ragweed (Ambrosia

psilostachya), common sunflower (Helianthus annus), prickly pear (Optunis spp.), scarlet sage
Environmental Impact Statement 4-31 Corpus Christi LNG

(Salvia coccinca), silver-leaf night-shade (Solanum elegnifolium), Indian blanket-flower

(Gaillardia grandiflora), and various grasses. Species of the woody overstory include mesquite

(Prospis juliflora), saltcedar (Tamarix ramosissima), sugarberry (Celtis laevigata), Carolina

holly (Ilex ambigua), Georgia holly (Ilex longipes), and various palm species.

4.5.1.2 Submerged Aquatic Vegetation

As identified in section 4.4.1, submerged seagrasses occur as discontinuous patchy

seagrass beds in shallow water at the Terminal site. Specifically, these seagrass beds are found

along the margin of Corpus Christi Bay and consist predominantly of shoal grass, manatee grass,

turtle grass, clover grass, and widgeon grass.

Construction and operation of the Terminal facilities would temporarily and permanently

impact industrial/disturbed vegetation and SAV. The construction and operation of Terminal

buildings and facilities would result in the permanent loss of vegetation. Additionally, the

construction of the marine facilities would result in the temporary and permanent loss of SAV

(see table 4.4-1). Additionally, SAV that occurs near the proposed marine facilities could be

impacted by turbidity and sedimentation resulting from dredging activities. We expect that

dredging turbidity and sedimentation impacts would be within several hundred feet of the

Terminal site.

To avoid and minimize impacts on vegetation at the Terminal, Cheniere would

implement measures described in our Plan and Procedures and its ARMP as described in section

4.4.1. Cheniere would also comply with all Project-specific recommendations and mitigation

requirements associated with their Section 10 permit when issued from the COE.

Based on the disturbed nature of the Terminal site, the amounts and types of vegetation

impacted, and Cheniere’s proposed impact minimization and mitigation measures, we have

determined that constructing and operating the Terminal facilities would not significantly impact

vegetation.

4.5.2 Pipeline Facilities

The Pipeline associated with the Terminal would also be located within the Gulf Prairies

and Marshes Ecoregion (Gould, 1975). It would be located within two distinct vegetation types

as characterized by TPWD; agricultural crops and Mesquite-Live Oak-Bluewood Parks

(McMahan et al., 1984). These vegetation types have been further characterized as agricultural,

herbaceous and scrub/shrub vegetation. Crops grown in the area that would be crossed by the

Pipeline include: cotton, sorghum, soybeans, and corn. Herbaceous vegetation includes: western

ragweed (Ambrosia psilostachya), common sunflower (Helianthus annuus), Indian blanketflower (Gaillardia pulchella), prickly pear (Opuntia spp.), scarlet sage (Salvia splendens), silverleaf night-shade (Solanum elaeagnifolium), and a variety of grasses such as king ranch bluestem

(Bothriochloa ischaemum), Texas windmill grass (Chloris texensis), Bermuda grass (Cynodon

dactylon), Johnson grass (Sorghum halepense), and buffelgrass (Pennisetum ciliare). Scattered

scrub/shrub species such as huisache (Acacia smallii), retama (Parkinsonia aculeata), bluewood

condalia (Condalia hookeri), and honey mesquite (Prosopis glandulosa)also occur scattered

throughout the herbaceous vegetation.

Construction and operation of the pipeline would temporarily impact vegetation,

specifically, resulting in the temporary loss of vegetation. The right-of-way would be seeded in
Environmental Impact Statement 4-32 Corpus Christi LNG

accordance with local NRCS requirements and therefore, vegetation would be allowed to revert

to preconstruction conditions following construction.

To minimize impacts on vegetation, Cheniere would implement measures described in

our Plan which specifically addresses reseeding, revegetation, and monitoring of vegetation.

Vegetation would be considered successful if the right-of-way surface condition is similar to

adjacent undisturbed land, and damage has been properly restored. Additionally, in order to

restore vegetative cover quickly in non-crop areas, Cheniere would reseed using the seed

mixtures identified in table 4.5-1

Table 4.5-1

Seed Mixtures for Terrestrial Vegetation Restoration Following Construction

Seed Mixture Application Rate (pounds per acre)

Temporary Seed Mixture

Oats 64

Hairy vetch 16

Foxtail millet 25

Rye 25

Permanent Seed Mixture

Green sprangletop 8

Little bluestem 15

Indiangrass 20

Switchgrass 16

Based on the amounts and types of vegetation impacted along the pipeline route, the

temporary nature of the impacts, and Cheniere’s proposed impact minimization measures, we

have determined that constructing and operating the Pipeline would not significantly affect

vegetation.

4.6 WILDLIFE AND AQUATIC RESOURCES

4.6.1 Wildlife Resources

4.6.1.1 Terminal Facilities

Marine Mammals

As identified in table 4.6-1, 27 species of marine mammals are commonly found in the

Gulf of Mexico, seven of which are also protected by the federal and/or state governments.

Additionally, five of the world’s seven sea turtle species have been recorded in the Gulf of

Mexico including: green (Chelonia mydas), hawksbill (Eretmochelys imbricate), Kemp’s ridley

(Lepidochelys kempii), leatherback (Dermochelys coriacea), and loggerhead (Caretta caretta).
Environmental Impact Statement 4-33 Corpus Christi LNG

All five species are listed as threatened or endangered under the ESA and are managed jointly by

the FWS and NOAA Fisheries. These species are also listed as threatened or endangered by

TPWD. Threatened and endangered species are addressed in section 4.7.

Table 4.6-1

Marine Mammals Observed in the Gulf of Mexico

Common Name Scientific Name

Humpback whale Megaptera novaeangliae

Fin whale Balaenoptera physalus

Sei whale Balaenoptera borealis

Minke whale Balaenoptera acutorostrata

Blue whale Balaenoptera musculus

Sperm whale Physeter macrocephalus

Dwarf Sperm whale Kogia simus

Pygmy Sperm whale Kogia breviceps

Killer whale Orcinus orca

Pygmy Killer whale Feresa attenuate

Cuvier's Beaked whale Ziphius cavirostris

Gervais' Beaked whale Mesoplodon europaeus

Blainville's Beaked whale Mesoplodon densirostris

Bryde's whale Balaenoptera edeni

Short-finned Pilot whale Globicephala macrorhynchus

False Killer whale Pseudorca crassidens

Melon-headed whale Peponocephala electra

Atlantic Spotted dolphin Stenella frontalis

Pantropical Spotted dolphin Stenella attenuate

Striped dolphin Stenella coeruleoalba

Clymene dolphin Stenella clymene

Spinner dolphin Stenella longirostris

Bottlenose dolphin Tursiops truncates

Risso's dolphin Grampus griseus

Fraser's dolphin Lagenodelphis hosei

Rough-toothed dolphin Steno bredanensis

West Indian manatee Trichechus manatus
Environmental Impact Statement 4-34 Corpus Christi LNG

Construction of the Terminal on an upland site would not impact marine mammals.

However, operation of the Terminal, specifically the dredging and LNG carrier’s calling on the

Terminal, could impact marine mammals and reptiles. LNG carriers could strike marine

mammals and reptiles resulting in an increase in stress, injury and/or mortality. The measures

that Cheniere would implement to minimize impacts on marine mammals are described in

section 4.7.1.

Based on the modest increase in LNG carrier traffic over current conditions resulting

from operation of the Terminal, the current commonality of such activities in the vicinity of the

Terminal, and vessel strike avoidance measures that would be communicated by Cheniere to

LNG carriers, we have determined that impacts on marine mammals would not be significant.

Aquatic Wildlife

The Terminal site contains open bay, seagrass, coastal marsh, sand flats, and black

mangrove habitats, as well as coastal grasses and forbs, and scrub/shrub habitats. Open Bay and

other aquatic habitat species are described in section 4.6.2.

Seagrass beds are inhabited by a variety of birds. Representative families include waders

(Ardeidae), sandpipers (Scolopacidae), plovers and allies (Charadriidae), gulls and terns

(Laridae), pelicans (Pelecanidae), cormorants (Phalacrocoracidae), grebes (Podicipedidae),

loons (Gaviidae), rails and allies (Rallidae), eagles and ospreys (Accipitridae), and waterfowl

(Anatidae)(Tunnell et al., 1996).

Due to salinity stress, few species of reptiles and amphibians are likely to occur in the

coastal marshes at the Terminal site (Tunnell et al. 1996). However, some species, such as the

diamondback terrapin (Malaclemys terrapin littoralis)and Gulf salt marsh snake (Nerodia

fasciata clarki), are known to inhabit brackish marshes along the Gulf Coast (Carr, 1952;Garrett

and Barker, 1987). The American alligator (Alligator mississipiensis)utilizes low-salinity

coastal marshes as both feeding and nesting areas (Garrett and Barker, 1987). Many species of

wading and aquatic shorebirds feed on the emergent plants, benthic invertebrates, and small

fishes found in coastal marshes (Bellrose, 1976). Some of the common bird species likely to

inhabit coastal marshes near the Terminal include mottled ducks (Anas fulvigula), lesser snow

geese (Chen caerulescens), willets (Cataptrophorus semipalmatus), clapper rails (Rallus

longirostris), great blue herons (Ardea herodias), tricolored herons (Egretta tricolor), blackcrowned night herons (Nycticorax nycticorax), great egrets (Casmerodius albus), snowy egrets

(Egretta caerulea), lesser scaups (Aythya affinis), buffleheads (Bucephala albeola), white

pelicans (Pelecanus erythrorhynchos), and cormorants (Bent, 1929;Daiber, 1982;Stutzenbaker,

1988;Ruth, 1990;Tunnell et al., 1996). Herbivorous mammals, such as nutria (Coypus coypu)

and white-tailed deer (Odocoileus virginianus)feed on marsh vegetation (White, 1973;Tunnell

et al., 1996). Few carnivorous rodents actually reside within coastal marshes. However, the rice

rat (Oryzomys palustris)is considered a predominantly carnivorous wetland species (Hamilton,

1976;Shard, 1967)that is common within the vicinity of the Terminal site. Other mammals that

occasionally forage in coastal marshes include the cotton rat (Sigmodon hispidus), fulvous

harvest mouse (Reithrodonomys fulvescens), house mouse (Mus musculus), and raccoon

(Procyon lotor)(Linscombe and Kinler, 1985).

Sand flats provide excellent habitat for numerous invertebrate species, including benthic

invertebrates, brown shrimp (Penaeus aztecus), and grass shrimp (Paleaemonetes spp.).

Vertebrates include a variety of birds such as gulls, terns, herons, shorebirds, and wading birds.
Environmental Impact Statement 4-35 Corpus Christi LNG

Some common species known to occur in the vicinity of the Terminal site include the laughing

gull (Larus atnicilla), ring-billed gull (Larus delawarensis), royal tern (Sterna maxima),

sandwich tern (Sterna sandvicensis), great blue heron, snowy egret, sanderlings (Calidnis alba),

least sandpiper (Calidnis minutilla), roseate spoonbill (Ajaia ajaja), and white ibis (Eudocimus

albus)(Tunnell et al. 1996).

Species likely to occur within the areas characterized by coastal grasses, forbs, and

scrub/shrub at the Terminal site include the gray fox (Urocyon cineroargentatus), raccoon,

coyote (Canis latrans), white tailed deer, and eastern cottontail (Sylvilagus floridanus)(Tunnell

et al. 1996).

The Terminal would be located on a site that was used for industrial purposes for

50 years and has since been reclaimed. As described previously, the north shore of Corpus

Christi Bay is highly industrial and the properties adjacent to the site are commercial and

industrial in nature. Construction and operation of the Terminal would result in the permanent

loss and conversion of disturbed coastal grasses and scrub/shrub habitats which would result in

the permanent relocation of wildlife and an increase in stress, injury, and/or mortality. To avoid

and minimize impacts on wildlife, Cheniere has reduced the size of construction areas to the

maximum extent practicable and would implement measures described in our Plan and

Procedures.

Based on the disturbed nature of the Terminal site as well as the characteristics of the

wildlife known to occur or potentially occur in the Project area, and Cheniere’s implementation

of its proposed mitigation measures, we have determined that construction and operation of the

Terminal would not significantly impact wildlife.

4.6.1.2 Pipeline Facilities

The Pipeline route would cross four different general habitat types: industrial,

agricultural, open, and wetland. The Pipeline would not cross any areas that have been identified

as sensitive habitats. Most of the Pipeline-related construction activities would occur in

previously disturbed agricultural areas.

Industrial land consists of highly disturbed and modified areas at the south end of the

Pipeline near the Terminal and at road crossings. These areas do not support much vegetation,

and most wildlife would only occasionally be expected to use or traverse these areas.

Agricultural land consists of active cropland. Agricultural fields planted with a variety of

legumes and row crops provide food and cover for several species of commonly observed

wildlife. These areas provide an important food source in the form of seeds, foliage, and insects

for a variety of songbirds, waterfowl, and game birds. The northern mockingbird (Mimus

polyglottos)and mourning dove (Zenaida macroura)are common birds found in agricultural

habitats (Tveten, 1993;Kaufman, 2000). Small mammals such as the hispid cotton rat are

common in this agricultural habitat as well (Davis and Schmidly, 1994). Reptiles such as the

Great Plains rat snake (Elaphe guttata emoryi)can also be found in this cover type (Dixon,

2000).

Wildlife species found within open land habitats include reptiles such as the western

glass lizard (Ophisaurus atenuatus), six-lined racerunner (Cnemidophorus sexlineatus), keeled

earless lizard (Holbrookia propinqua), Texas spotted whiptail (Cnemidophonus gulanis), western

coachwhip (Masticophis flagellum tesaceus), ground snake (Sonora semiannulata), and western
Environmental Impact Statement 4-36 Corpus Christi LNG

diamondback rattlesnake (Crotalus atrox)(Dixon, 2000). Bird species associated with this

habitat type would include Nelson’s sharp-tailed sparrow (Ammodramus nelsoni), prairie warbler

(Dendroica discolor), buff-breasted sandpiper (Tryngites subruficollis), loggerhead shrike

(Lanius ludovicianus), and short-eared owl (Asio flammeus). Mammals likely to occur within

this habitat type include the black-tailed jackrabbit (Lepus californicus), Gulf Coast kangaroo rat

(Dipodomys compactus), marsh rice rat (Orozomys palustris), fulvous harvest mouse

(Reithrodontomys fulvescens), raccoon, striped skunk (Mephitis mephitis), and coyote (Davis and

Schmidly, 1994).

As described previously, the Pipeline would cross PEM wetlands at three locations.

Typical wildlife species found within PEM wetlands include the Woodhouse’s toad (Bufo

woodhousii), eastern narrow-mouth toad (Gastrophryne carolinensis), bronze frog (Rana

clamitans), Missouri slider (Chrysemys floridana), speckled king snake (Lampropeltis getulus),

diamondback water snake (Nerodia rhombifer), red-winged blackbird (Agelaius phoeniceus),

American widgeon (Anas americana), American bittern (Botaurus lentiginosus), common snipe

(Capella gallinago), great egret (Casmerodius albus), marsh hawk (Circus cyaneus), North

American mink (Mustela vison), rice rat, and swamp rabbit (Sylvilagus aquaticus)(Gosselink et

al., 1979).

Construction and operation of the Pipeline facilities would result in minimal and shortterm impacts on wildlife because no sensitive habitats would be impacted, and much of the area

affected by construction would be allowed to revert to preconstruction conditions following

construction. Some smaller, less mobile wildlife, such as small mammals, amphibians and

reptiles, would likely be taken during clearing and grading activities. Other wildlife, such as

birds and larger mammals, would leave the immediate construction area when construction

activities approach, and would move to similar habitats nearby. Areas adjacent to the Pipeline

area provide similar and ample habitats for wildlife displaced temporarily during construction of

the Pipeline. Wildlife would return to the majority of the Project area following construction and

restoration. To minimize construction related impacts from Pipeline installation on wildlife

habitats, Cheniere would implement measures contained in our Plan and Procedures, including

the use of temporary erosion controls, restoration of all disturbed areas, and restricting vegetation

clearing between March 1 and August 31, as further discussed in section 4.6.3.

Based on the types of available habitat within the Project area and with the

implementation of the described mitigation measures, the Project would not have a significant

impact on terrestrial wildlife, and impacts would be short-term and minor.

4.6.2 Fisheries Resources

4.6.2.1 Terminal

The Terminal facilities would be located adjacent to and in Corpus Christi Bay. The

following sections describe the fisheries resources potentially impacted by construction and

operation of the Project.
Environmental Impact Statement 4-37 Corpus Christi LNG

Open Water and Intertidal Habitats

Corpus Christi Bay was designated as an “estuary of national significance”by the EPA in

1992 and it contains over 200 fish species. The Terminal would be located across five

aquatic/intertidal habitats: open bay, seagrass, coastal marsh, sand flats, and black mangroves.

Open Bay

Open bay communities provide habitat for a variety of benthic (living on or in bottom

substrate) invertebrates, including, but not limited to, nematodes, harpacticoid copepods,

gastrotrichs, clams, snails, polychaete worms, amphipods, and crabs. Epibenthos which typically

prefer protected areas such as seagrass beds and salt marshes also occur in the open bay

communities. Penaeid shrimp, roughback shrimp (Trachypenaeus similis), mantis shrimp

(Squilla empusa), and blue crabs (Callinectes sapidus and C. similis)are the most abundant

epifauna in these areas (Murray and Jinnette, 1976;Armstrong, 1987). Other epifaunal

crustaceans that occur in open bay habitats include amphipods (Gammarus mucronatus), mud

crabs (Rhithropanopeus spp.), hermit crabs (Pagurus annulipes), and grass shrimp

(Palaemonetes pugio)(Tunnell et al., 1996;Armstrong, 1987). The nektonic community

(occupying the water column above the substrate) of open bays includes a variety of

invertebrates and fishes. Common nektonic invertebrates include: zooplankton, a variety of

cnidarians (jellyfish, coral, and hydra)and the bay squid (Lolliguncula brevis)(Britton and

Morton, 1989). Fish species common in open bay habitats include the Atlantic croaker

(Micropogonias undulatus), spot (Leiostomus xanthurus), bay anchovy (Anchoa mitchilli),

hardhead catfish (Arius felis), pinfish (Lagodon rhomboides), sand seatrout (Cynoscion

arenarius), star drum (Stellifer lanceolatus), spotted seatrout (Cynoscion nebulosus), red drum

(Sciaenops ocellatus), black drum (Pogonias cromis), southern flounder (Paralichthys

lethostigma), gafftopsail catfish (Bagre marinus), and striped mullet (Mugil cephalus).

Seagrass

Seagrasses provide habitat for a variety of invertebrates, including various annelids,

polychaetes, crustaceans, gastropods and bivalves. Seagrass habitats also support a number of

fish species including seatrout and red drum. Additionally, seagrasses provide habitat for

tidewater silversides (Menidia peninsulae), rainwater killifish (Lucania parva), pinfish, bay

anchovy, striped mullet, menhaden (Brevoortia spp.), silver perch (Bairdiella chrysura), dusky

pipefish (Syngnathus floridae), speckled worm eel (Myrophis punctatus), and other associated

species. Seagrass beds also serve as important feeding grounds for larger invertebrates and

predatory fish that are attracted to these areas in pursuit of smaller prey species (Gulf of Mexico

Fishery Management Council, 1998). Such predatory species include: hardhead catfish, spotted

seatrout, red drum, southern flounder, spot, and various sharks and rays.

Coastal Marsh and Vegetated Flats

Coastal marshes provide habitat for a variety of filter-feeding mollusks, oligochaetes,

polychaetes, nematodes, fiddler crabs (Uca spp.), mud crabs, grass shrimp, penaeid shrimp, and

amphipods (Orchestia spp.). The abundance of emergent and epiphytic vegetation (plants that

grow on other vegetation)found in coastal marshes supports a variety of grazing invertebrates,

such as snails and various insects. Invertebrate predators, including crustacean larvae, adult

copepods (Marshall and Orr, 1960), odonates, coleopterans, dipterans, and blue crabs (Tunnell et

al. 1996)also are common inhabitants of coastal marshes. Similar to seagrass, coastal marshes
Environmental Impact Statement 4-38 Corpus Christi LNG

provide nursery habitat for a variety of marine and estuarine fishes. Additionally, coastal

marshes support several small, resident fish, including killifishes, menhaden, bay anchovy,

striped mullet, and mosquito fish (Gambusia affinis), and a variety of larger predatory fishes,

such as tarpon (Megalops atlanticus).

Tidal Flat

Tidal flats provide habitat for a variety of benthic invertebrates. Representative

organisms include polychaetes, gastropods, and crustaceans such as blue crabs (Withers, 1994).

Small fish often move into these areas to feed;common fish species include sheepshead minnow

(Cyprinodon variegatus), Gulf killifish (Fundulus grandis), rough silversides (Membras

martinica), larval inshore lizard fish (Synodus foetens), southern flounder, red drum, and spotted

sea trout (Harrington and Harrington, 1972;Pfeifer and Wiegert, 1981;Pulich et al., 1982).

BlackMangrove

Black mangroves provide habitat to wildlife along protected shorelines, intertidal salt

marshes, and marshy barrier islands. Black mangrove also effectively stabilizes interior tidal

mudflats, dredge-fill, and other artificial sites commonly associated with wetland restoration

(NRCS, 2005). Species found in black mangroves include goliath grouper (Epinephelus itajara),

lane snapper (Lutjanus sunagris), and yellowmouth grouper (Mycteroperca interstitialis)(Gulf

of Mexico Fishery Management Council, 2004).

Fisheries of Special Concern

Fisheries of special concern in Corpus Christi Bay include federal and state listed

threatened and endangered species, fish with designated EFH, and those of commercial and

recreational value. Corpus Christi Bay is designated in the National Estuary Program as an

estuary of “national significance”.

Essential Fish Habitat

In the MSA, Congress defines EFH as consisting of “waters and substrate necessary to

fish for spawning, breeding, feeding or growth to maturity” (16 USC 1802[10]). Specific

habitats include all estuarine water and substrate (mud, sand, shell, and rock), and all associated

biological communities, such as sub-tidal vegetation (seagrasses and algae), and the adjacent

inter-tidal vegetation (marshes and mangroves). In addition to ecological significance, EFH

represents areas of high economic importance due to the dependence of recreational and

commercial fisheries that are directly and indirectly associated with them.

The fish species known to occur in Corpus Christi Bay, most of which are temperate in

biogeographic distribution with a few tropical species (Tunnell et al., 1996), can be classified as

warmwater marine or estuarine.

Construction and operation of the Terminal would impact EFH for juvenile white and

brown shrimp;larval, post-larval, juvenile, and adult red drum;adult gray snapper (Lutjanus

griseus);post-larval and juvenile Goliath grouper;post-larval and juvenile lane snapper;and

juvenile yellowmouth grouper. These habitats have also been designated as EFH for highly

migratory species including neonate, juvenile, and adult blacktip (Carcharhinus limbatus), bull

(Carcharhinus leucas), bonnethead (Sphyrna tiburo), and Atlantic sharpnose (Rhizoprionodon

terranovae)sharks;neonate and juvenile scalloped hammerhead (Sphyrna lewini)and lemon
Environmental Impact Statement 4-39 Corpus Christi LNG

(Negaprion brevirostris)sharks;and neonate fine tooth (Carcharhinus isodon)sharks (NOAA

Fisheries, 2009a;Gulf of Mexico Fisheries Management Council, 2004).

A full EFH assessment has been performed for the Terminal site which outlines life

history information, and relative abundance of all species with EFH identified in the Terminal

area of impact. Potential impacts and conservation measures, as determined through

correspondence with NOAA Fisheries, to avoid and/or minimize impacts are also included in the

assessment. The EFH assessment has been included as appendix B of this EIS.

Recreational and Commercial Fisheries

Table 4.6-2 identifies the recreational and commercial fisheries known to occur in Corpus

Christi Bay.

Table 4.6-2

Recreational and Commercial Fisheries in Corpus Christi Bay

Common Name Scientific Name Fishery Classification

Brown shrimp Farfantepenaeus aztecus Warmwater marine/estuarine

Pink shrimp Farfantepenaeus duorarum Warmwater marine/estuarine

White shrimp Litopenaeus setiferus Warmwater marine/estuarine

Red drum Sciaenops ocellatus Warmwater marine/estuarine

Spanish mackerel Scomberomorus maculatus Warmwater marine

Atlantic croaker Micropogonias undulatus Warmwater marine/estuarine

Black drum Pogonias cromis Warmwater marine/estuarine

Gafftopsail catfish Barge marinus Warmwater marine/estuarine

Sand seatrout Cynoscion arenarius Warmwater estuarine

Sheepshead Archosargus probatocephalus Warmwater marine/estuarine

Southern flounder Paralichthys lethostigma Warmwater marine/estuarine

Spotted seatrout Cynoscion nebulosus Warmwater estuarine

Striped mullet Mugil cephalus Warmwater marine/estuarine

Impacts and Mitigation

Constructing and operating the Terminal would impact fisheries resources including EFH

and recreation and commercial fisheries. Specifically;dredging, dredge disposal, and pile

driving activities would impact fish and other aquatic organisms. These activities would also

impact recreational and commercial fisheries in a similar manner. Additionally, LNG carriers

calling on the Terminal and other ship-related marine traffic and operations could also impact

fisheries resources. Impacts on EFH resulting from construction and operation of the Project are

described in more detail in appendix B, and further described below in the appropriate impact

headings.
Environmental Impact Statement 4-40 Corpus Christi LNG

Dredge and Dredge Disposal

Dredging activities necessary for the construction of the Terminal would permanently

impact open bay, seagrass, salt marsh, sand flat, and black mangrove habitats. Maintenance

dredging required for operation of these facilities could periodically impact fisheries. As

described in section 2.3.1, a total of 124 acres of open water habitat would be impacted by

operation of the Terminal, including approximately 95.4 acres of aquatic/intertidal habitat that

would be permanently converted into deep water habitat (23.8 acres of the site is currently

classified as deep water and 5 acres of open land will be converted to deep water). Of the 95.4

acres of shallow, open water habitat that would be dredged, approximately 9.17 acres are

currently submerged aquatic seagrass beds, 5.91 acres are cordgrass salt marsh, 1.0 acre is

coastal marsh and vegetated sand flats, 2.9acres are unvegetated sand flats, 6.72 acres are black

mangrove, and the remaining 67.9acres are unvegetated shallow open water.

Dredging activities during construction of the Terminal, including the disturbance and

resuspension of sediments, would temporarily increase turbidity which could impact water

quality, fish, and other aquatic organisms. Turbidity resulting from dredging activities could

further be impacted by wind influenced tides. Increased turbidity could clog fish gills and irritate

epithelia tissue. Increased turbidity could also impact seagrasses and other aquatic vegetation

which could also impact fish and other aquatic organisms. Impacting fish habitat could impact

fish behavior (avoidance), foraging, breeding, and migration. Increased stress, injury, and

mortality could result from dredging activities. Additionally, dredging equipment could also

entrain fish and other aquatic organisms.

Maintenance dredging would periodically increase turbidity;however, this impact would

be temporary. Impacts on fisheries would be similar to those described above, but the intensity

of these impacts would be significantly less. Additionally, the Project area is already subject to

maintenance dredging and, as a result, fish in the area have become accustomed to this type of

disturbance.

Despite other highly variable physiochemical parameters (e.g., salinity, temperature,

oxygen)marine, coastal pelagic, and estuarine finfish and shellfish species are abundant in the

Project area and are well adapted to highly turbid conditions. Overall, motile organisms would

be capable of avoiding highly turbid areas (Hirsch et al., 1978). Under most conditions, fish and

other motile organisms are only exposed to localized suspended-sediment plumes for short

durations (minutes to hours)(Clarke and Wilber, 2000). COE studies have also demonstrated

that benthic organisms actively repopulate dredged areas quickly after completion of dredging

activities. Studies also show that many benthic organisms have capabilities to vertically migrate

through substantial overburdens caused by sedimentation and turbidity (Wilber et al., 2005;

Maurer et al., 1978, 1986).

As described previously, Cheniere proposes to dispose of all dredged material in an

upland DMPA immediately north of the Terminal site. Run-off and return water from the

DPMA would flow into an existing drainage canal along the western boundary of the Terminal

and back into Corpus Christi Bay. This run-off and return water would increase turbidity at the

point of entry into Corpus Christi Bay. Increased turbidity could impact fish and other aquatic

organisms as described above.

To minimize impacts on fish including EFH and other aquatic organisms, Cheniere

would adhere to measures outlined in our Plan and Procedures and implement its ARMP.
Environmental Impact Statement 4-41 Corpus Christi LNG

Cheniere would further minimize impacts from stormwater runoff through implementation of its

SPCC Plan, construction of drainage ditches on site, and adherence to measures contained in the

NPDES requirements.

In addition to the above measures, Cheniere would obtain state water quality certification

under Section 401 of the CWA from the RRC, and a Section 404 permit from the COE. The

certification and permit would contain measures to avoid, minimize, and mitigate impacts on

fisheries and aquatic resources.

Pile Driving

Pile driving activities would generate sound pressure waves and underwater noise levels

that could impact fish and other aquatic organisms. These impacts include stress, injury,

avoidance, and/or other behavior changes.

Although the impacts of pile driving are poorly studied and there is substantial variation

in species response to sound, intense sound pressure waves can change fish behavior or

injure/kill fish through rupturing swim bladders or causing internal hemorrhaging. The intensity

of the sound pressure levels produced during pile driving depends on a variety of factors

including, but not limited to, the type and size of the pile, the firmness of the substrate into which

the pile is being driven, the depth of water, and the type and size of the pile-driving hammer.

The degree to which an individual fish exposed to sound waves would be affected is dependent

upon variables such as the peak sound pressure level and frequency as well as the species, size,

and condition of the fish (e.g., small fish are more prone to injury by intense sound waves than

are larger fish of the same species).

Depending on the specific conditions at the site, pile driving activities could generate

underwater sound levels great enough to injure some fish or cause them to be more susceptible to

predation. Underwater noise levels are commonly referred to as a ratio of the underwater sound

pressure to a common reference pressure of 1 micropascal (μPa)root mean-square pressure,

which is expressed in decibels (dB)of sound intensity as dB re: 1 μPa. There are insufficient

peer reviewed reliable data available for the onset of behavior disturbance in fish;however, as a

conservative measure, NOAA Fisheries generally uses 150 dB re: 1 μPa as the threshold for

behavior effects to fish species of particular concern, citing that noise levels in excess of 150 dB

re: 1 μPa can cause temporary behavior changes (startle and stress)that could decrease a fish’s

ability to avoid predators. The current interim thresholds protective of injury to fish are 206 dB

re: 1 μPa (peak)and 187 dB re: 1 μPa (cumulative)sound exposure level for fish 2 grams or

greater and 183 dB re: 1 μPa (cumulative)sound exposure level for fish of less than 2 grams

(ICF Jones and Stokes and Illingworth and Rodkin, Inc., 2009).

Driving tubular steel piles has been known to generate sound levels from 192 to 194 dB,

above the level that is thought to injure some fish. Depending on the specific conditions at the

Terminal, these sounds can have a transmission loss rate of 0.021 to 0.046 dB per foot (Nedwell

and Edwards, 2002;Nedwell et al., 2003). Based on these values, the use of an impact hammer

at the Terminal could generate underwater sound levels great enough to injure some fish and

otherwise affect some fish as far as 1,860 feet from a steel pile (i.e., 155 dB). Although the

sound waves of the greatest intensity would be limited to the immediate vicinity of the piles

within the slip, sound levels of 155 dB could extend to the far shore of the La Quinta Channel

while piles for some of the mooring dolphins are being driven. In a review of studies

documenting fish kills associated with pile driving, NOAA Fisheries (2003)reported that all
Environmental Impact Statement 4-42 Corpus Christi LNG

have occurred during use of an impact hammer on hollow steel piles. The type of hammer that

would be used to drive piles during construction of the Project has not yet been identified.

Measures implemented to minimize impacts on aquatic organisms from pile driving

activities are further discussed in section 4.7.1.

Ship and Boat Traffic

Ship and boat traffic associated with constructing and operating the Terminal would also

impact fish and other aquatic organisms. Specifically, ship movements, noise and resulting wave

actions could impact fisheries resources. Ship movements could directly impact fisheries and

other aquatic organisms. These movements could result in strikes and cause avoidance which

could result in increased rates of stress, injury and/or mortality experienced. Although ship noise

would not generally be of the intensity produced from driving steel piles, vessels operating in the

La Quinta Channel could cause sounds that elicit responses in fish. Some research suggests that

fish exhibit avoidance behavior in response to engine noise (International Council for

Exploration of the Sea, 1995). At the same time, research conclusions tend to suggest that since

the impacts are transient (i.e., once the ship passes, behavior returns to normal), that the longterm impacts on fish populations are negligible (Stocker, 2001). Increased wave action resulting

from ship and boat traffic could increase turbidity which could impact fish and other aquatic

organisms.

Ship Operations –Ballast Water

LNG carrier operations at the Terminal site would require the discharge of ballast water.

As described previously in section 2.1.4, the Terminal has been designed to load approximately

200 to 300 LNG carriers per year. LNG carriers arriving at the Terminal could include the

largest presently existing LNG carriers with the capacity to discharge approximately 9million to

30 million gallons of ballast water at a rate up to 1.7 million gallons per hour. A 138,000 m3

capacity LNG carrier would discharge approximately 50,000 m3of ballast water at the berth

during each LNG cargo loading operation. Approximately 12,000,000 m3of ballast water would

be discharged at the Terminal per year.

Ballast discharge could impact water quality, fish, and other aquatic organisms. The

general characteristics of the discharged ballast water would be very similar to that of the water

pumped aboard each LNG carrier during the mandatory ballast water exchange operation. The

location, weather, and existing tidal/current conditions where this ballast water exchange would

take place would determine the unique characteristics of the ballast seawater aboard each LNG

carrier upon its arrival at the Terminal. Discharge of ballast water could result in temporary and

localized changes in salinity and temperature which could have minor impacts on aquatic species

in the vicinity. Ballast discharge could also result in the introduction of non-indigenous aquatic

species which could also impact fish and other aquatic organisms.

To minimize and avoid impacts on fish and other aquatic organisms resulting from ballast

water discharges, the Coast Guard, which has jurisdiction over inspection and regulatory

enforcement for all shipping in U.S. waters, would require all LNG carriers calling on the

Terminal to adhere to all applicable ballast water management rules and regulations. Coast

Guard regulations require that all vessels equipped with ballast water tanks which enter or

operate in U.S. waters maintain a ballast water management plan that is specific for that vessel

and assigns responsibility to the master or appropriate official to understand and execute the
Environmental Impact Statement 4-43 Corpus Christi LNG

ballast water management strategy for that vessel. Under these requirements, vessels must

implement strategies to prevent the spread of exotic aquatic nuisance species in U.S. waters.

Examples of these strategies include retaining ballast water on board, minimizing discharge or

uptake at certain times and locations, and exchanging ballast water with mid-ocean seawater.

Ships that have operated outside of the U.S. Exclusive Economic Zone (EEZ)must either retain

their ballast water on board or undergo a mid-ocean (greater than 200 nm from shore/water depth

greater than 2,000 meters)ballast water exchange in accordance with applicable regulations.

Applicable U.S. laws, regulations, and policy documents related to ballast water include the

following:

 Nonindigenous Aquatic Nuisance Prevention and Control Act of 1990 (NANPCA)that

established a broad federal program “to prevent introduction of and to control the spread

of introduced aquatic nuisance species... ”FWS, Coast Guard, EPA, COE, and NOAA

Fisheries all were assigned responsibilities.

 National Invasive Species Act of 1996 that reauthorized and amended the NANPCA

because “Nonindigenous invasive species have become established throughout the waters

of the U.S. and are causing economic and ecological degradation to the affected near

shore regions.” The Secretary of Transportation was charged with developing national

guidelines to prevent import of invasive species from ballast water of commercial

vessels, primarily through mid-ocean ballast water exchange, unless the exchange

threatens the safety or stability of the vessel, its crew, or its passengers.

 National Aquatic Invasive Species Act of 2003 (NAISA), amended in 2005 and again in

2007, established a mandatory National Ballast Water Management Program. The

primary requirements established under NAISA are: 1)all ships operating in U.S. waters

are required to have on board an Aquatic Invasive Species Management Plan;2)the

Coast Guard was made responsible for the development of standards for mid-ocean

ballast water exchange and ballast water treatment for vessels operating outside of the

EEZ;and 3)implementing the BMPs and available technology related to ballast water

treatment.

 National Ballast Water Management Program, originally established by NANPCA and

further amended by NISA 1996 and NAISA 2003, made the ballast water management

program mandatory, including ballast water exchange, with reporting to the Coast Guard.

 Shipboard Technology Evaluation Program, a program authorized under the Coast Guard

Ballast Water Management Program and designed to facilitate the development of

“effective ballast water treatment technologies, through experimental systems, thus

creating more options for vessel owners seeking alternatives to ballast water exchange.”

 Navigation and Vessel Inspection Circular 07-04, Change 1, a program developed by the

Coast Guard for the management and enforcement of ballast water discharge into U.S.

ports and harbors.

 Vessels Carrying Oil, Noxious Liquid Substances, Garbage, Municipal or Commercial

Waste, and Ballast Water, implementing regulations for the Act to Prevent of Pollution

from Ships of 1980, which applies to all U.S.-flagged ships anywhere in the world and to

all foreign-flagged vessels operating in navigable waters of the U.S. or while at port

under U.S. jurisdiction.
Environmental Impact Statement 4-44 Corpus Christi LNG

In addition to discharging ballast water, LNG carriers would require the intake of water

in order to operate the ship and cool the ship’s engines. Operation of the Terminal would also

require a water intake. Ship cooling water would be withdrawn and discharged below the water

line on the sides of the ship through screened water ports, known as “sea chests”. Water intakes

could result in the impingement and entrainment of fish. These actions could impact the rates of

stress, injury and/or mortality experienced by fish. To minimize these impacts, water intakes

would be outfitted with screened sea chests that withdraw and discharge water at a relatively

slow velocity.

To address the potential impacts on fisheries associated with offshore spills of fuel,

lubricants, or other hazardous materials, Cheniere would implement measures contained in its

SPCC Plan.

Conclusion

Based on the characteristics of the Terminal site and the adjacent waters, the fish and

other aquatic organisms including their habitats that would be impacted by the Project;the

dredging, dredge disposal, pile driving and shipping activities that would impact these resources;

and Cheniere’s implementation of measures to avoid, minimize and mitigate these impacts;we

have determined that construction and operation of the Terminal would impact fisheries,

including EFH resources, but that these impacts have been sufficiently minimized.

4.6.2.2 Pipeline Facilities

As identified in section 4.3.2, the pipeline facilities would cross nine waterbodies. Of the

nine waterbodies, two (Oliver Creek and Chiltipin Creek) are characterized as perennial,

freshwater, and containing warmwater fisheries. The remaining seven crossings have been

characterized as intermittent drainages, ditches, or canals that do not support sustainable fish

species. No EFH, fisheries of special concern, state or federally listed threatened and

endangered fish species, or fish of significant commercial and recreational value have been

identified as being crossed by the pipeline facilities. Representative freshwater fish species that

could occur in Oliver and Chiltipin Creeks include: central stoneroller (Campostoma anomalum),

cypress minnow (Hybognathus hayi), spotted sucker (Minytrema melanops), yellow bullhead

catfish (Ameiurus natalis), starhead minnow (Fundulus excambiaei), and green sunfish (Lepomis

cyanellus)(Garret and Klym, 2012). Additionally, table 4.6-3 provides a list of representative

game and commercial fish species with the potential to occur within Oliver and Chiltipin Creeks

(Texas Natural History Collections, 2003;TPWD, 2003).
Environmental Impact Statement 4-45 Corpus Christi LNG

Table 4.6-3

Representative Commercial and Game Fish Species with Potential to Occur in Waterbodies Crossed by the Pipeline

Common Name Scientific Name Fishery Classification

Largemouth bass Micropterus salmoides Warmwater

Blue catfish Ictalurus furcatus Warmwater

Channel catfish Ictalurus punctatus Warmwater

Flathead catfish Pylodictis olivaris Warmwater

Bluegill Lepomis macrochirus Warmwater

Red ear sunfish Lepomis microlophus Warmwater

Longear sunfish Lepomis megalotis Warmwater

Green sunfish Lepomis cyanellus Warmwater

Golden shiner Notemigonus crysoleucas Warmwater

Black-tail shiner Cyprinella venusta Warmwater

Bullhead minnow Pimephales vigilax Warmwater

Construction of the Pipeline would result in the temporary loss of aquatic habitat, disturb

the stream bed, and increase turbidity and sedimentation. The loss of habitat and localized

changes to water quality could increase the amount of stress, injury and mortality experienced by

fish in Oliver and Chiltipin Creeks. To minimize impacts on fish, Cheniere would cross Oliver

and Chiltipin Creeks using HDDs. Because the remaining seven waterbodies do not support

sustainable fisheries, constructing the Pipeline across these waterbodies would not impact fish.

Additionally, Cheniere would complete all waterbody crossings in accordance with the

construction and mitigation measures described in our Procedures.

The use of HDDs to cross Oliver and Chiltipin Creeks would significantly minimize

impacts on fish. Therefore, based on the characteristics of the fisheries contained within the nine

waterbodies that would be crossed, Cheniere’s use of HDDs, and its implementation of impact

minimization measures as described in our Procedures, we have determined that constructing and

operating the Pipeline facilities would not significantly impact fisheries.

4.6.3 MigratoryBirds

Migratory birds are protected under the MBTA, originally passed in 1918. The MBTA

states that it is unlawful to pursue, hunt, take, capture, kill, possess, sell, purchase, barter, import,

export, or transport any migratory bird, or any part, nest, or egg of any such bird, unless

authorized under a permit issued by the Secretary of the Interior. “Take”is defined in the

regulations as to “pursue, hunt, shoot, wound, kill, trap, capture, or collect, or attempt any of the

above”(50 CFR 10).

Executive Order 13186 (January 2001)was issued, in part, to ensure that environmental

analyses of federal actions assess the impacts on migratory birds. It also states that emphasis
Environmental Impact Statement 4-46 Corpus Christi LNG

should be placed on species of concern, priority habitats, and key risk factors and it prohibits the

take of any migratory bird without authorization from the FWS. On March 30, 2011, the FWS

and the Commission entered into a Memorandum of Understanding that focuses on avoiding or

minimizing the adverse impacts on migratory birds and strengthening migratory bird

conservation through enhanced collaboration between the Commission and the FWS by

identifying areas of cooperation. This voluntary Memorandum of Understanding does not waive

legal requirements under any other statutes and does not authorize the take of migratory birds.

Migratory birds follow broad routes called “flyways” between breeding grounds in

Canada and the U.S. and wintering grounds in Central and South America. The Terminal site is

within the Central Flyway. The Central Flyway runs through the central portion of the U.S. and

includes the states of Montana, Wyoming, Colorado, New Mexico, Texas, Oklahoma, Kansas,

Nebraska, South Dakota, and North Dakota, and the Canadian provinces of Alberta,

Saskatchewan and the Northwest Territories. Most birds that move along the Central Flyway

travel from Canada through the central states, eventually reaching the tropics of South America

via the Gulf of Mexico (FWS, 2011).

The FWS published the Birds of Conservation Concern 2008 to assess and prioritize bird

species for conservation purposes. The document identifies migratory and non-migratory birds

that are of conservation concern in order to stimulate conservation actions among government

agencies and private partners. According to the document, the Project lies within Bird

Conservation Region 37, the Gulf Coastal Prairie Region. Table 4.6-4 (see appendix C)provides

a list of the species of birds of conservation concern within region 37.

4.6.3.1 Terminal Facilities

A number of migratory birds, including shore and sea birds, have the potential to fly over

the Terminal. The Terminal would be located in a highly industrialized area, although several

locations on the site as well as the DMPA north of the Terminal, would provide some marginal

habitat. The highly industrial nature of the Terminal site and surrounding area make it an

unlikely stopover area for migrants. The high amounts of activity on the properties adjacent to

the Terminal likely deter migratory birds from utilizing the marginal habitat within the site.

There are proposed structures within the Terminal that could pose a risk to migratory bird

species that may fly through the area. These structures include the LNG tanks, the process flare

tower, and the marine flare. The LNG tanks are large structures and would likely be avoided by

avian species. The process flare tower would be a self-supported structure, approximately 500

feet tall, and would have aircraft warning lights installed. The marine flare would be a guy wiresupported structure, and would have visual markers affixed to the wires to prevent collisions by

bird species. Though there is potential for minor impacts on migratory bird species, constructing

and operating the Terminal is not expected to an impact on the population-levels of the birds.

Moreover, there are several areas in the vicinity of the Terminal, including the Aransas National

Wildlife Refuge, Mustang Island State Park, Lake Corpus Christi State Park, and Padre Island

National Seashore that provide suitable, high quality habitat for a variety of species.

As a measure to protect any migratory birds that could be found within the Terminal site,

Cheniere would avoid clearing woody vegetation during the peak nesting period between

March 1 and August 31 of any year. If vegetation clearing must be conducted during this time,

Cheniere would survey for migratory bird nests no more than three weeks prior to commencing
Environmental Impact Statement 4-47 Corpus Christi LNG

work. If an active migratory bird nest is found, Cheniere would consult with the FWS to identify

the most appropriate measure to be taken to avoid or minimize impacts.

In addition, Cheniere would implement BMPs as described in consultation received from

the FWS on September 12, 2012. Some practices outlined by the FWS include:

 using lighting systems with minimum intensity;

 using maximum off-phased white strobe lighting as per FAA regulations;

 down-shielding lights on the Terminal site as appropriate, and

 marking guy wires with visual markers and bird diverters.

Cheniere would continue to consult with the FWS prior to constructing the facilities

regarding implementation of further avoidance or minimization measures to protect migratory

bird species. Because of the measures described above to reduce impacts on migratory birds,

including timing of activities, impacts on migratory birds would not be significant.

4.6.3.2 Pipeline Facilities

The largest impact on migratory birds from the Pipeline would be from construction

activities, primarily right-of-way clearing. Impacts would be the greatest if right-of-way clearing

occurred during the breeding season;however, because most habitats that would be crossed by

the Pipeline are active agricultural lands, these impacts are expected to be minor. If adult birds

must move from the right-of-way to avoid temporary construction, this impact would be of

limited duration and would not result in a substantial or long-term impact on migratory birds.

This would not constitute a population-level impact given the stability of local populations and

the abundance of available habitat outside of the Pipeline right-of-way.

The linear nature of the Pipeline and the use of previously and continually disturbed areas

would minimize impacts on migratory bird species. Construction noise and activities could

result in the temporary displacement of migratory birds. Due to the relatively short duration of

construction activities and the current use of the area, the Pipeline would not have a significant

impact on migratory birds. As discussed above for the Terminal, as a measure to protect any

migratory birds that may be found along the Pipeline route, Cheniere would avoid clearing

woody vegetation during the peak nesting period between March 1 and August 31 of any year. If

vegetation clearing must be conducted during this time, Cheniere would survey for migratory

bird nests no more than three weeks prior to commencing work.

If an active migratory bird nest is found, Cheniere would consult with the FWS to

identify the most appropriate measures to be taken to avoid or minimize impacts on migratory

birds. Because of the measures described above to reduce impacts on migratory birds, including

timing of pipeline construction activities, impacts on migratory birds would not be significant.

4.7 THREATENED,ENDANGERED,AND OTHER SPECIAL STATUSSPECIES

4.7.1 FederallyListed Threatened and Endangered Species

Federal agencies are required by Section 7 of the ESA to ensure that any actions

authorized, funded, or carried out by the agency do not jeopardize the continued existence of a

federally listed threatened or endangered species, or result in the destruction or adverse

modification of designated critical habitat of a federally listed species. The FERC is required to
Environmental Impact Statement 4-48 Corpus Christi LNG

consult with the FWS and NOAA Fisheries to determine whether any federally listed endangered

or threatened species or designated critical habitat are within the vicinity of the proposed Project,

and to determine the proposed action’s potential effects on those species or critical habitats. If

the project would affect a listed species, the agency must report its findings to the FWS and

NOAA Fisheries in a BA. If FERC determines that the proposed action may adversely affect a

listed species, the agency must submit a request for formal consultation to comply with Section 7

of the ESA. In response, the FWS and/or NOAA Fisheries would issue a Biological Opinion as

to whether or not the federal action would likely jeopardize the continued existence of a listed

species, or result in the destruction or adverse modification of designated critical habitat.

In order to comply with Section 7 of the ESA, Cheniere, acting as the FERC’s nonfederal representative for purposes of complying with the ESA, consulted with the FWS and

NOAA Fisheries regarding the presence of federally listed and proposed threatened and

endangered species and their critical or proposed critical habitats within the Project area. On

October 29, 2012 NOAA Fisheries notified Cheniere that it has determined that project impacts

are similar to the original project and reinitiating of ESA Section 7 consultation is not required.

The FWS provided concurrence with Cheniere’s “not likely to adversely affect”determinations

in letters dated August 8, 2013 and November 5, 2013.

Since construction of the proposed facilities may occur over several years, we and

Cheniere would be responsible to ensure that any additional surveys resulting from the

observation or listing of species would be conducted as appropriate and if necessary reinitiate

consultation prior to allowing construction activities to commence.

The FWS and NOAA Fisheries identified 17 federally listed species that occur or

potentially occur within the Project area. As identified in table 4.7-1 (see appendix C), these

species include two plants (south Texas ambrosia [Ambrosia cheiranthifolia]and slender rushpea [Hoffsmanseggia tenelle]), eight mammals (blue whale [Balaenoptera musculus], fin whale

[Balaenoptera physalus], humpback whale [Megaptera novaeangliae], sei whale [Balaenoptera

borealis], sperm whale [Physeter macrocephalus], ocelot [Leopardus pardalis], gulf coast

jaguarundi [Herpailurus yagouaroundi], and West Indian manatee), two birds (whooping crane

[Grus americana]and piping plover [Charadrius melodus]), and five reptiles (loggerhead sea

turtle, green sea turtle, leatherback sea turtle, Atlantic hawksbill sea turtle, and Kemp’s ridley sea

turtle).

Cheniere conducted field surveys for marine and terrestrial threatened and endangered

species in June 2011 and March 2012.

Four species have been eliminated from further discussion in this EIS because suitable

habitat was not identified in the vicinity of the Project based on current or protected ranges. Gulf

Coast jaguarundi and ocelot are not known to occur in the Project area. Slender rush pea and

south Texas ambrosia are both terrestrial species listed in Nueces County only, and terrestrial

impacts associated with the Project would be outside of their known ranges. Therefore, we have

determined that the Project would have no effect on these species and they are not further

discussed.
Environmental Impact Statement 4-49 Corpus Christi LNG

4.7.1.1 Marine Mammals

Whales

Blue whales occur in all oceans of the world. They inhabit sub-polar to sub-tropical

oceans and rarely occur in the Gulf of Mexico off the coast of Texas. There are only two records

of blue whales from the Gulf;one stranded near Sabine Pass, Louisiana in 1926 and one stranded

near Freeport, Texas in 1940 (Texas Tech University, 1997). Both identifications have been

questioned. The approximate worldwide population of blue whales is 11,000-12,000, with the

current North Atlantic population between 100-1,500 individuals.

Fin whales are found in the deep, off-shore waters of all major oceans but primarily at

temperate to polar latitudes (NOAA Fisheries, 2011). While rare in Texas one young individual

was stranded on the beach at Gilchrist in Chambers County on February 21, 1951 (Texas Tech

University, 1997). A highly migratory species, these whales move to high latitude feeding

grounds during the spring and summer and return to southerly temperate waters for mating and

calving during fall and winter.

Humpback whales occur in all oceans of the world and are distributed in the western

north Atlantic from north of Iceland, Disko Bay and west of Greenland, south to Venezuela, and

the tropical islands of the West Indies (Texas Tech University, 1997). The worldwide population

estimate is between 5,200-5,600 individuals with approximately 800-1,000 individuals in the

western North Atlantic. Humpback whales have been captured in the Florida Keys and northern

Cuba with sightings occurring off the west coast of Florida and Alabama. There is only one

documented observation along the Texas Coast, occurring near the Bolivar Jetty near Galveston

on February 19, 1992 (Texas Tech University, 1997).

The sei whale is a medium sized baleen whale occurring primarily in offshore waters

from the Gulf and Caribbean Sea northward to Nova Scotia and Newfoundland. Sei whales, like

many other whales, are a migratory species that tend to occur in groups of two to five

individuals. There are no known occurrences of sei whales in Texas (Schmidly, 2004).

Sperm whales typically inhabit waters 600 meters or greater in depth, and are uncommon

in waters less than 300 meters deep (NOAA Fisheries, 2011). Sperm whales are found in all

oceans of the world in deep waters between approximately 60 degrees north and 60 degrees

south latitudes. Sperm whales are the most numerous of whales in the Gulf and sightings in

Texas near the coast are relatively common (Texas Tech University, 1997). Sightings of sperm

whales in the Gulf are common at depths of 655 feet or greater, along submarine canyons on the

edge of the continental shelf.

Although the whale species listed do not occur in relatively shallow waters such as those

found near the Project, they could potentially be impacted by collisions with LNG carriers that

are transiting to and from the Terminal in the open Gulf of Mexico. The probability of these

species encountering LNG carriers in the open ocean would be inherently low given their ability

to avoid on coming vessels coupled with their overall rarity.

Mitigation to minimize vessel strikes would be accomplished by maintaining a watch for,

and taking prudent measures to avoid, impacting listed species as described in NOAA Fisheries’

most recent Vessel Strike Avoidance Measures and Reporting for Mariners (revised

February 2008).
Environmental Impact Statement 4-50 Corpus Christi LNG

Due to the tendency for these species to remain far off-shore in very deep water, we have

determined that construction and operation of the Project is not likely to adversely affect these

species. NOAA Fisheries affirmed its previous concurrence with this determination in a letter

dated October 29, 2012.

West Indian Manatee

Manatees are found in rivers, estuaries, and coastal areas of the tropical and subtropical

New World. They may be found from the southeastern United States coast along Central

America and the West Indies to the northern coastline of South America. They occur mainly in

larger rivers and brackish water bays. Manatees are extremely rare in Texas and have been

sighted in Corpus Christi Bay, Laguna Madre, Cow Bayou near Sabine Lake, Copano Bay,

Bolivar Peninsula, and the mouth of the Rio Grande (Texas Tech University, 1997). Initial

decline of manatee populations was a result of over hunting;however, today population declines

may be attributed to collisions with power boats, entrapment in floodgates, navigation locks,

fishing nets, and water pipes. Loss of warm water habitat along with ingestion of marine debris

is also a threat to the continued survival of the West Indian Manatee.

Cheniere would further minimize the impact on the manatee by implementing additional

conservation measures recommended by the FWS which would include providing training on the

manatee to all personnel associated with constructing and operating the Project. Manatee

training information would advise contractors and staff that manatees may be found in the La

Quinta Channel and include a poster to assist in identifying the mammal and instruct personnel

not to feed or water the animal. Manatee training materials would include instruction to call the

FWS Corpus Christi Ecological Services Field Office in the event a manatee is sighted in or near

the Project area.

While manatees have been observed in the Project vicinity, sightings are very rare and

typically involve only a single animal that vacates the region relatively quickly. With Cheniere’s

implementation of additional conservation measures, we have determined that construction and

operation of the Project is not likely to adversely affect this species. The FWS concurred with

the proposed conservation measures and the may affect, not likely to adversely affect

determination in a letter dated November 5, 2013.

4.7.1.2 Sea Turtles

Five species of sea turtles inhabit the Gulf, nesting on beaches and occupying inlets and

shallow bays. However, nesting sea turtles are unlikely to occur in the Project area thus, impacts

on nesting turtles are unlikely. With this in mind, we determine that the Project would not

adversely affect sea turtles. The most likely impact on sea turtles would be LNG carrier strikes

with swimming turtles, although it would also be a rare event. Potential impacts are discussed

further below.

Loggerhead Sea Turtle

In the Atlantic, the loggerhead’s range extends from Newfoundland to as far south as

Argentina. The primary Atlantic nesting sites are along the east coast of Florida but additional

sites occur in Georgia, the Carolinas, and along the Gulf Coast of Florida. In the eastern Pacific,

loggerheads are reported from Alaska to Chile (NOAA Fisheries, 2004;COE, 2003). The

greatest threats to this sea turtle species are coastal development, commercial fisheries, and
Environmental Impact Statement 4-51 Corpus Christi LNG

pollution. Loggerhead sea turtles inhabit continental shelves, bays, estuaries, and lagoons in

temperate, subtropical, and tropical waters.

Mating takes place from late March to early June, and eggs are laid throughout the

summer. After hatching, loggerhead hatchlings move to the sea and often float on sargassum

masses for three to five years. Subadults occupy near-shore and estuarine habitats, whereas

adults occupy a variety of habitats that range from turbid bays to clear water. The young feed on

prey such as gastropods, crustacean fragments, and sargassum, while adults mainly forage on the

bottom, though they may also feed on jellyfish from the surface. Loggerhead sea turtles nest on

open, sandy beaches above the high tide mark and seaward of well-developed dunes. They

prefer steeply sloped beaches with gradually sloped offshore approaches (NOAA Fisheries,

2004;COE, 2003).

In Texas, loggerheads are considered to be the most abundant sea turtle, favoring

shallow, inner continental shelf waters and have been recorded in Corpus Christi Bay. They may

be present in Texas marine waters year-round;however, they are most noticeable during the

spring when Portuguese-Man-of-War are abundant (COE, 2003). Most loggerhead sightings

have been in the northern Gulf of Mexico near jettied passes and in open water and suitable

nesting habitat for this species is not available at the Project site.

Green Sea Turtle

Green sea turtles inhabit shallow waters with an abundance of marine algae and

seagrasses. They prefer lagoons, bays, inlets, shoals, and estuaries. They use coral reefs and

rocky outcrops near feeding areas to rest, and they feed on marine plants, mollusks, sponges,

crustaceans, and jellyfish. They tend to nest on their natal beach (NOAA Fisheries, 2004;

COE, 2003). Commercial harvest of eggs as food, collection of body parts to be used for leather

and jewelry, and stuffing of whole small turtles are the greatest threats to this species.

Population recovery is hindered further by the incidental take of green sea turtles during shrimp

harvests, and outbreaks of epidemic tumor infections have introduced a severe threat to the

population.

Green sea turtles are a circumtropical species occurring both in tropical and subtropical

waters. In the western Atlantic, they range from Massachusetts to the Virgin Islands and Puerto

Rico. Known nesting sites for the green sea turtle in the continental U.S. include North Carolina,

South Carolina, Georgia, and Florida. In Texas, small numbers of green sea turtles can been

found in Matagorda Bay, Aransas Bay, and the lower Laguna Madre. Preferred nesting and

foraging areas for this species are not found near the Project site.

Adult green sea turtles forage in bays that have extensive seagrass beds and could be

impacted by dredging activities when constructing the Terminal. With the exclusive use of

mechanical methods and hydraulic dredges (which are not known to take sea turtles), the

likelihood of a take would be significantly reduced (NOAA Fisheries, 2003).

Leatherback Sea Turtle

Leatherback sea turtles spend most of their time in the open ocean and come to land only

to nest. They may be found in coastal waters when nesting or following jellyfish concentrations.

They feed mainly on jellyfish and sea squirts as well as sea urchins, crustaceans, fish, and

floating seaweed. They prefer sandy beaches with a deepwater approach for nesting (NOAA

Fisheries, 2004;COE, 2003). Overexploitation by humans and incidental mortality due to
Environmental Impact Statement 4-52 Corpus Christi LNG

shrimping and fishing activities have contributed to a decline in the population, as has

degradation and disruption of nesting habitat and egg collection.

Leatherbacks are one of the widest-ranging sea turtles and are found in both the Pacific

and Atlantic oceans. To optimize foraging and nesting opportunities, they migrate between

boreal, temperate, and tropical waters. In the western Atlantic their range extends from Nova

Scotia to South America, and into the Gulf. While important nesting sites in the western Atlantic

include French Guiana and Columbia, they are also known to nest along the U.S. Virgin Islands,

Puerto Rico, and Florida. Although leatherback sea turtle sightings have been recorded in

Corpus Christi Bay, this species is rare along the Texas coast and no nest sites have been

recorded in over 60 years (NOAA Fisheries, 2004;COE, 2003). Suitable nesting habitat for this

species does not exist at the Project site. Of the five sea turtle species that occur in Texas waters,

the leatherback is the species least likely to occur in the Project area.

Atlantic Hawksbill Sea Turtle

This species inhabits coastal reefs, bays, rocky areas, estuaries, and lagoons at depths up

to 70 feet. Hatchlings may be found in the open sea floating on masses of marine plants while

juveniles, subadults, and adults may be found near coral reefs, their primary foraging area. They

prefer to feed on invertebrates such as sponges, mollusks, and sea urchins, although they are

omnivorous. Atlantic hawksbills come ashore to nest and prefer undisturbed, deep sand beaches.

Preferred beaches may range from high-energy to small pocket beaches bounded by crevices of

cliff walls with woody vegetation near the waterline (NOAA Fisheries, 2004;COE, 2003). The

greatest threat to this population has been the harvest of turtles to supply the tortoise shell market

and stuffed turtle curios. It is also used to manufacture leather, oil, perfume, and cosmetics.

Atlantic hawksbill sea turtles are circumtropical and occur in the tropical and subtropical

areas of the Atlantic, Pacific, and Indian Oceans. Nesting sites are known along the Yucatan

Peninsula of Mexico, the U.S. Virgin Islands, Puerto Rico, and the Florida Keys. Post-hatchlings

and juveniles are seen with some regularity in Texas and Florida, in areas primarily associated

with stone jetties (NOAA Fisheries, 2004). Although Atlantic hawksbill sightings have been

recorded in Corpus Christi Bay, they are unlikely to occur in the Project area because this species

prefers rocky outcroppings, coral reefs, and hard bottom areas.

The risk to hawksbill sea turtles in the Project area, while possible, would be considered

unlikely due to the lack of preferred habitat (rocky shores, reefs and passes)and preferred food.

With the exclusive use of mechanical methods and hydraulic dredges (which are not known to

take sea turtles), the likelihood of a take would be significantly reduced (NOAA Fisheries,

2003).

Kemp’s Ridley Sea Turtle

Kemp's ridley sea turtles inhabit shallow coastal and estuarine waters over sand or mud

bottoms. Juveniles feed on sargassum while adults are largely shallow water benthic feeders.

Food items include shrimp, snails, bivalves, jellyfish, and marine plants (NOAA Fisheries, 2004;

COE, 2003). Collection of eggs, capture for meat and other products, direct take for indigenous

use, ingestion of man-made materials, collision with boats, and disturbance or destruction of

nesting areas are all factors that have contributed to the decline of this species. Despite these

factors, the population appears to be in the early stages of recovery.
Environmental Impact Statement 4-53 Corpus Christi LNG

Kemp's ridley sea turtles inhabit primarily coastal waters in the northwestern Atlantic and

the Gulf. The majority of this species nests at beaches near Rancho Nuevo, Tamanlipas, Mexico,

about 315 miles south of the Project area, with a secondary nesting area at Tuxpan, Vera Cruz.

This species could be a transient to the Project area between crustacean-rich feeding areas in the

northern Gulf and breeding grounds in Mexico (NOAA Fisheries, 2004;COE, 2003). Preferred

nesting and foraging areas for this species are not found at the Project site.

The risk to a Kemp’s ridley sea turtle in the Project area would be very limited. While

Kemp’s ridley sea turtles are present in the bays and could potentially be in the Terminal area,

the exclusive use of mechanical methods and hydraulic dredges (which are not known to take sea

turtles), would reduce the likelihood of a take significantly (NOAA Fisheries, 2003).

Sea Turtle Impacts

Due to the specific nesting habitat requirements, sea turtles would not be likely to be

present onshore within the Project area. In general, sea turtles would be a rare visitor to the

Project area. Many of the sea turtles discussed have feeding, swimming, or resting behaviors

that keep them near the surface, where they may be vulnerable to vessel strikes. To help reduce

the risk of strikes or other potential disturbances associated with the presence of LNG carriers,

Cheniere would adhere to the measures outlined in the NOAA Fisheries Vessel Strike Avoidance

Measures and Reporting for Mariners (revised February 2008).

NOAA Fisheries identified pile driving as having the potential to affect sea turtles.

Studies have shown that the sound waves from pile driving may result in injury or trauma to fish,

sea turtles, or other animals with gas-filled cavities such as swim bladders, lungs, sinuses, and

hearing structures (Abbott et al., 2002). Although sea turtles would be expected to largely avoid

the Project area during pile driving activities, a potential exists for sea turtles to be injured during

the first several strikes of the pile driving hammer. Cheniere would reduce impacts on listed

species from pile driving by implementing the following pile driving protocols:

 An observer would be dedicated to sea turtle and marine mammal observations,

responsible for monitoring species presence prior to pile driving activities;

 A 250-meter radius zone would be established and monitored for 60 minutes prior to

engaging the pile driver hammer during construction. If a sea turtle or marine mammal is

observed within the zone, pile driving would be delayed until the animal is observed to

have left or is heading away from the established zone. If an animal dives and cannot be

re-sighted, pile driving may not begin until 20 minutes after the last sighting, or until the

60-minute observation is complete, whichever is longer;

 If pile driving activity ceases for any reason, observations for sea turtles and marine

mammals would resume until pile driving begins, or the 60-minute survey would be

repeated;

 All animals must be allowed to exit the established zone of their own free will;

 Pile driving would not be started during nighttime hours;but if started prior to sunset, it

may continue until the hammer activity ceases;and
Environmental Impact Statement 4-54 Corpus Christi LNG

 Cheniere would keep records of all observations and pile driving protocols, and make

these records available upon request.

If the rare occurrence of the species were to overlap with the rare incidence of a spill, a

turtle could be at risk due to effects on respiration, skin, blood chemistry, and salt gland function.

To address the potential impacts associated with offshore spills of fuel, lubricants, or other

hazardous materials, Cheniere would implement its SPCC Plan.

Dredging activities could temporarily disrupt potential foraging grounds for turtles.

Cheniere proposes to dredge the marine basin and berth area using a hydraulic cutterhead dredge.

Hydraulic cutterhead dredging is not known to take sea turtles by direct mortality, as with hopper

dredging. Dredging activities during construction would be temporary and local in nature

because dredging would be confined to the proposed turning basin and marine berth and

maintenance dredging would only occur about once every three years. Dredging actions that

could potentially result in injury to any sea turtles directly in the Project area would be

incidental. Activities at dredge spoil placement areas would similarly not affect sea turtles since

suitable nesting areas are not present in the placement areas.

With adherence to the mitigation measures identified above, we have determined that the

Project is not likely to adversely affect sea turtles. The FWS concurred with this determination

in a letter dated November 5, 2013 and NOAA Fisheries affirmed its previous concurrence with

this determination in a letter dated October 29, 2012.

4.7.1.3 Birds

Whooping Crane

The whooping crane winters in coastal Texas. Designated critical habitat for this species

is located within the Aransas National Wildlife Refuge in Aransas, Calhoun, and Refugio

Counties, approximately 25 miles north of the Project area. Some whooping cranes also winter

on Matagorda Island, which at its closest point is approximately 13 miles from the Project area.

Winter habitat consists of brackish bays, marshes, and salt flats that provide a variety of plant

and animal foods such as blue crabs, clams, and berries. Whooping cranes may also occasionally

use grassland swales and ponds that provide foods such as snails, crayfish, and insects. The

central and eastern Panhandle also provides a major stopover area for birds migrating between

summer and winter habitats.

The whooping crane has been recorded in San Patricio County, and could potentially

access waters on the bay side and interior of Mustang and Padre Islands, which would be outside

the Project area. While the whooping crane has been recently sighted in San Patricio County,

such occurrences are rare. Given its rarity and suitable habitat in waters on the leeward side of

the nearby barrier islands, we have determined that the Project is not likely to adversely affect

the whooping crane. The FWS concurred with this determination in a letter dated November 5,

2013.

Piping Plover

Piping plovers inhabit shorelines along oceans, rivers, and inland lakes and nest on sandy

beaches, sandbars, dunes, and silty flats. During the winter, they utilize beaches, mud and sand

flats, and offshore spoil islands. The piping plover breeds on the northern Great Plains, in the

Great Lakes, and along the mid- to north-Atlantic coast, and winters on the Atlantic and Gulf
Environmental Impact Statement 4-55 Corpus Christi LNG

coasts from North Carolina to Mexico. They arrive at their Texas wintering grounds during midto late-July and spend a majority of their time on sand and mud flats near sandy beaches. They

feed on tidal flats during low tide and Gulf beaches during high tide (COE, 2003). Decline in the

piping plover population has resulted from over-hunting during the early part of the twentieth

century, habitat loss or modification due to human development, alteration of river and wetland

systems, and predation.

San Patricio County is one of 12 counties in Texas where concentrations of piping plover

occur. Four sites in Corpus Christi Bay have been found to harbor wintering piping plover

populations: Port Aransas (15 miles east of the Project area), Fish Pass (13 miles southeast of the

Project area), Oso Bay (13 miles southwest of the Project area), and sites along the Gulf

Intracoastal Waterway (GIWW)(COE, 2003). Several areas along the Texas coast have been

identified by the FWS as essential wintering habitat for the piping plover. Essential wintering

habitat for the piping plover provides the space and requisite resources necessary for the

continued existence and growth of piping plover populations and consist of coastal beach, sand

flat, and mud flat habitats. Critical Habitat for the wintering grounds (as opposed to breeding

population Critical Habitat)has also been designated in Texas by the FWS (66 FR 36074—

36078). The closest critical habitat to the Project area is Unit TX13 Sunset Lake, located

approximately 4 miles southwest of the Project site.

This unit is triangle shaped, with SH 181 as the northwest boundary, and the limits of the

City of Portland as the northeast boundary. The shore on Corpus Christi Bay is the third side of

the triangle, with the actual boundary being mean lower low water off this shore. This unit is a

large basin with a series of tidal ponds, sand spits and wind tidal flats. This unit is owned and

managed by the City of Portland within a system of city parks. Some of the described area falls

within the jurisdiction of the TGLO.

The piping plover habitat at the Project site would be relatively small when compared to

the abundance of suitable habitat adjacent to the Terminal. Currently, piping plovers are not

known to inhabit the proposed Project area and construction activities would likely result in

piping plovers seeking refuge in nearby suitable habitats. To minimize impacts to piping

plovers, the FWS recommended that Cheniere have a qualified biologist survey the tidal flats

(piping plover habitat) at the Terminal before and after construction, submit photo

documentation to the FWS that the temporarily affected tidal flats were properly restored, and

have a biologist on site during construction in tidal flats to assist employees in avoiding impacts

to piping plovers during construction. Cheniere would comply with these measures and would

train workers through the use of a species “fact sheet” that would describe life history

information, habitat characteristics, and include a photograph to help with identification.

Due to Cheniere’s implementation of the above conservation measures, we have

determined that the Project is not likely to adversely affect the piping plover. The FWS

concurred with the proposed conservation measures and our determination in a letter dated

November 5, 2013.

4.7.2 State Listed Threatened and Endangered Species

The TPWD annotated county lists of rare species for San Patricio and Nueces Counties

include 24 state listed endangered or threatened species, in addition to those species that are also

federally listed and discussed above. Table 4.7-2 (see appendix C)identifies the state listed

species for San Patricio and Nueces Counties.
Environmental Impact Statement 4-56 Corpus Christi LNG

We have determined that 14 of these species would not be impacted by the Project

because the Project is not within the known range of the species, the species has been extirpated

in the Project area, there is no suitable habitat in the Project area, or the species would only occur

in the Project area as an occasional transient. These species are not discussed further in the EIS.

The remaining 10 state listed species could potentially occur in the vicinity of the Project. These

species are discussed in the following sections.

4.7.2.1 Mammals

Southern Yellow Bat

The southern yellow bat (Lasiurus ega)is a neotropical bat that has been recorded in

southern California, southern Arizona, and southern Texas in Cameron, Kleberg, and Nueces

Counties. Its range may be increasing in Texas due to the rising number of ornamental palm tree

plantings. This species utilizes palm trees as roosting sites and feeds on insects captured in

flight. In south Texas, the southern yellow bat breeds during late winter (Davis and Schmidly,

1997).

There is potential for southern yellow bats to roost in palm trees in the Project area and

forage for insects over the grasslands and coastal wetlands at night. However, due to the lack of

contiguous habitat and the mobility of this species, construction and operation of the Project

would not significantly impact this species.

4.7.2.2 Birds

Reddish Egret

The reddish egret (Egretta rufescens)is a common, permanent resident along the Texas

central lower coast and is uncommon along the upper coast. It breeds along Gulf State coasts

and it inhabits shallow tidal pools, saltwater bays, and marshes. Red egrets wade in shallow

waters and forages for small fishes and crustaceans and commonly nests in colonies with other

herons, egrets, and cormorants. Reddish egrets nest in brushy thickets of yucca and prickly pear

on dry coastal islands in Texas and among mangroves in Florida (TGLO, 2004).

The Project area would be located within the reddish egret's breeding range and, potential

nesting habitat does exist in the Project area. Additionally, the wetlands located in the Project

area could be used for foraging;however, other abundant foraging grounds near the Project area

could also be used by the species while constructing the Project. Reddish egrets were not

observed in the Project area during surveys in 2011 and 2012 and their mobility would allow

them to temporarily relocate to similar adjacent habitats during construction. Therefore, the

Project would not significantly impact this species.

White-tailed Hawk

In Texas, population declines of white-tailed hawk (Buteo albicaudatus)are primarily

due to grassland habitat conversion to agriculture and an increase in brushy cover within

remaining open grasslands. Over the past four decades, brush removal efforts have produced

more favorable habitats for this species. In the southern and central counties of Texas, and north

towards Galveston, white-tailed hawk inhabit coastal grasslands. They prefer saltgrass flats near

the Gulf and dry grassy mesquite-live oak savannas inland (USGS, 2004). They perch on

bushes, dead trees, fence posts, and utility structures and prey on small mammals, lizards, and
Environmental Impact Statement 4-57 Corpus Christi LNG

insects. Their breeding season is from March to May, and their nest consists of grass-lined sticks

in low bushes, small trees, or cacti (National Wildlife Federation, 2004).

The white-tailed hawk is uncommon in the Project area and was not observed during field

surveys in 2011 and 2012. There is potential for this species to occur in the Project vicinity;

however, construction and operation of the Project would not significantly impact this species.

Wood Stork

Wood storks (Mycteria americana)are the largest wading birds that breed in North

America. This species prefers freshwater and brackish wetlands, and nests in cypress or

mangrove swamps. In Texas, the wood stork forages in prairie ponds, flooded pastures or fields,

ditches and other shallow standing water including saltwater. The birds move into the Gulf States

in search of mudflats and other wetlands. They formerly nested in Texas but there have been no

breeding records since 1960 (TPWD, 2005). The decline of wood storks is attributed to loss of

cypress swamps and also associated with a reduction in the food base (primarily small fish)

necessary to support breeding colonies (FWS, 2010).

While wood storks could occur in the Project vicinity, they were not observed during

field surveys conducted in 2011 and 2012. Therefore, the Project would not significantly impact

this species.

4.7.2.3 Reptiles and Amphibians

Texas Tortoise

The Texas tortoise (Gopherus berlandieri)is a primarily vegetarian reptile that relies

heavily on the fruit of the common prickly pear and other succulent plants. Its range extends

from south-central Texas southward into the Mexican states of Coahuila, Nuevo Leon, and

Tamaulipas. Collection of tortoises for pets led to its listing in 1977 as a protected non-game

species (TPWD, 2012). This species breeds from April to September and lays its eggs deep in a

hollow on the ground.

While there is marginal habitat for this species within the Project footprint, the

probability of occurrence is very low due to past land disturbance including industrial and

agricultural practices. Therefore, the Project would not significantly impact the Texas tortoise.

Texas Horned Lizard

The Texas horned lizard (Phrynosoma cornutum)or “horny toad”is found in arid and

semiarid habitats in open areas with sparse vegetative cover. The horned lizard is common

among loose sands or loamy soils. They range from the south-central U.S. to northern Mexico,

and throughout most of Texas, Oklahoma, Kansas and New Mexico (TPWD, 2012c). They feed

primarily on harvest (red)ants. The decline of the Texas horned lizard is due to multiple factors

including collection for the pet trade, spread of invasive, red fire ants, changes in land use, and

environmental contaminants.

The Texas horned lizard could occur in the Project area;however, due to the small

amount of suitable habitat found in the Project vicinity and the large expanses of high quality

habitat in adjacent areas, that the Project would not significantly impact this species.

Texas Indigo Snake
Environmental Impact Statement 4-58 Corpus Christi LNG

The Texas indigo snake (Drymarchon melanurus erebennus)is a large non-venomous

snake found from southern Texas to Mexico. This species prefers sparsely vegetated areas close

to permanent water sources, but is also found in mesquite savanna, open grassland area, and

coastal sand dunes. They den in burrows abandoned by other animals and will eat a wide range

of animals including mammals, birds, lizards, frogs, turtles, eggs, and other snakes

(NatureServe, 2012). The decline of the Texas indigo snake is due primarily to habitat loss

resulting from land development.

The Project area would be within the far northern range of the Texas indigo snake;

however, indigo snake sightings in San Patricio County are rare. The probability of an

occurrence onsite is very low and additionally, the snake is mobile, allowing it to temporarily

displace to similar, adjacent habitat during Project construction. Therefore, the Project would

not significantly impact this species.

Black Spotted Newt

Black-spotted newts (Notophthalmus meridionalis)are found along the coastal plains of

south Texas and Mexico. They reside in the quiet waters of streams with abundant SAV, ponds,

and ditches. Breeding habits are dependent on the amount of water available. If a water source

dries up, young and adult black-spotted newts will seek shelter on land under rocks or rocky

ledges (National Wildlife Federation, 2004).

In general, amphibians are sensitive to climatic factors (such as drought), habitat changes,

and environmental pollutants including pesticides, petroleum hydrocarbons, and heavy metals.

These factors combined with the predatory influences of non-native fish species and bullfrogs

have contributed to population declines (TPWD, 2004).

The black spotted newt could occur in the Project area;however, due to the small amount

of suitable habitat found in the Project vicinity and with the implementation of best management

practices, as recommended by TPWD in a letter dated August 22, 2012, the Project would not

significantly impact this species.

South Texas Sirens

South Texas sirens (Siren spp.)inhabit areas that are similar to the black-spotted newt,

but require a year-round source of open water for aestivation (a state of dormancy)to assist in

water regulation during the hottest parts of the day.

South Texas sirens could occur in the Project area;however, due to the small amount of

suitable habitat found in the Project vicinity and with the implementation of best management

practices, as recommended by TPWD in a letter dated August 22, 2012, the Project would not

significantly impact this species.

4.7.2.4 Fish and Mollusks

Opossum Pipefish

The opossum pipefish (Microphis brachyurus)is an anadromous species, spending the

majority of its time in the open ocean and returning to freshwater to spawn. The opossum

pipefish can be found in low gradient creeks and medium to large rivers with dense, emergent

vegetation (NatureServe, 2012). Causes of population decline include disease, poor water

quality, unnatural flow, and water control structures (NOAA Fisheries, 2009b). The only
Environmental Impact Statement 4-59 Corpus Christi LNG

drainage that could provide suitable spawning and/or feeding habitat (low gradient with

emergent vegetation within 30 miles of the coast)is Chiltipin Creek. However, Chiltipin Creek

supports a population of longnose gar and the gars ability to thrive in turbid, warm water would

be an indicator that the water quality/dissolved oxygen levels of the drainage are too poor or low

to support the opossum pipefish. Additionally, downstream channel constrictions would prohibit

an upstream migration. Due to this, and the fact that the Pipeline would cross Chiltipin Creek

via the HDD method (avoiding direct impacts on the creek), construction and operation of the

Pipeline would not significantly impact the opossum pipefish.

4.8 LAND USE,RECREATION,AND VISUAL RESOURCES

4.8.1 Terminal Facilities

4.8.1.1 Land Use

Facilities associated with the Terminal would be constructed on property located on the

northern shore of Corpus Christi Bay, at the north end of the La Quinta Channel, north and east

of the city of Corpus Christi in San Patricio (land-based facilities)and Nueces (marine facilities)

Counties, Texas. The Terminal would be located west of the Sherwin Alumina plant on land

previously used for industrial purposes.

The Terminal would be located on property owned by Cheniere that was previously an

industrial site, but has since been reclaimed. Existing land uses at the site are open water and

open land. Approximately 991 acres would be affected by constructing the Terminal facilities,

including the marine basin and berths. Approximately 469 acres would be affected by the

operation of the Terminal, Marine basin and berth, plus exclusion zones. From the total impact

acreage, Terminal operations would impact approximately 225 acres and maintenance dredging

would impact approximately 124 acres. Details regarding acreage impacts on land use are

provided in table 4.8-1.
Environmental Impact Statement 4-60 Corpus Christi LNG

Table 4.8-1

Land Use Required to Construct and Operate the Terminal

Facility

Open Land Open Water a/ Total

Construction

(acres)

Operation

(acres)

Construction

(acres)

Operation

(acres)

Construction b/

(acres)

Operation c/

(acres)

Terminal Site d/, e/ 225 225 0 0 225 225

Marine Basin and Berth 5 5 121 119 126 124

Dredged Material Placement 437 0 0 0 437 0

Temporary Laydown Area f/ 160 0 0 0 160 0

Temporary Parking Area f/ 26 0 0 0 26 0

Temporary Access Roads f/ 8 0 0 0 8 0

Tool and Lunch Area f/ 9 0 0 0 9 0

Exclusion Zone 0 91 0 29 0 120

Total 870 321 121 148 991 469

_______________________

a/ Wetland impacts associated with the Terminal are included in open water.

b/ Construction area includes entire construction footprint, including all temporary and permanent construction areas

c/ Operational area includes the permanent Terminal site, marine basing and berth, permanent easements and exclusion zone.

d/ Acreage excludes Bauxite Disposal Bed 22 (52 acres)which is within the Project property boundary but would not be disturbed

by construction or operation.

e/ Bed 24 acreage is included in the Terminal site (area would be filled with structural fill and become part of the operating area).

f/ Area used during construction only and located outside of the Terminal site.

The LNG storage tanks associated with the Terminal would be located in an area that was

used for storage of bauxite ore as part of the U.S. government stockpile until 2003. Two bauxite

residue beds used for the disposal of alumina processing wastes, are located on the north side of

La Quinta Road for which Cheniere would have easements and lease agreements. Bauxite

residues from Bed 24 were removed and placed into Bed 22. Bed 22 has been capped with clay

as part of an agreement with TCEQ. There would be no direct land use impacts on Bed 22 to

construct and operate the Terminal. Bed 24 would be filled with clean structural fill, purchased

off-site, to planned grade and would be used as part of the Terminal facilities. The

operations/maintenance building, warehouse, LNG transfer lines, and access roads to the docks

would be located in a vegetated open area. Construction and operation impacts on this land

would be confined to a corridor surrounding the buildings, LNG transfer piperack, and access

road. The remainder of this area would remain open land. Open lands include scrub lands or

unimproved lands not in use for agriculture, industry, or residences.

While constructing the Terminal, Cheniere would utilize the adjacent property to the west

of the Terminal site for laydown and staging of construction materials. Additionally, a

temporary employee parking area would be used to ease construction traffic congestion on La

Quinta Road.
Environmental Impact Statement 4-61 Corpus Christi LNG

Cheniere selected two DMPAs to dispose of materials dredged during construction of the

marine basin, as well as materials from maintenance dredging of the La Quinta Channel.

Cheniere has indicated that they selected a site known as DMPA 2 to beneficially utilize dredged

material to cap old bauxite beds which currently produce red dust under windy conditions.

Cheniere would also use dredge material to fill an existing excavation area on the Alcoa

property.

Construction of the Terminal would require 991 acres of land with 469acres permanently

impacted during operation. However, the majority of the Terminal facilities would be located on

open land previously used for industrial purposes. The open water in the La Quinta Channel that

would be utilized for the LNG marine basin would remain open water, though it would be

dredged to a greater depth. The construction of the marine basin and berthing facilities would

result in the conversion of approximately 5 acres of open land to open water. The mitigation of

impacts on coastal marshes and wetlands as a result of the construction of the marine basin and

berthing facilities is discussed in section 4.4 of this EIS. Construction of the Terminal would

result in a conversion of the existing land use (open land)to industrial use. However, due to the

industrial use of adjacent land and the previously disturbed nature of the area, impacts on land

use from the Terminal would be minor.

4.8.1.2 Existing and Planned Residences and Commercial Developments

The Terminal would be located in an industrialized area surrounded by industrial and

commercial development. There are currently no existing or planned residential developments

within 0.25 mile of the Terminal.

The LNG storage tanks would be surrounded by industrial properties, and there would be

no land within 0.25 mile of the Terminal site that would be available for residential development.

The site would be bounded by industrial land owned by the POCCA to the west, an operating

alumina facility owned by Sherwin Alumina to the east, and property owned by Alcoa to the

north. All property would be zoned as industrial.

The nearest residential areas to the Terminal site are in Portland (1.3 miles west),

Gregory (2.0 miles north), and Ingleside (2.9 miles east), all located in San Patricio County,

Texas. The land surrounding the Terminal to the north and east has been used for processing,

storage, and disposal of aluminum ore and related waste products for over 50 years. The nearest

residence to any temporary construction activities is located approximately 0.6 mile northwest of

the junction of La Quinta Road and SH 361. This junction is near the northwest corner of

DMPA 2 that would be filled using dredged material excavated during construction. This area is

not owned by Cheniere, and there would be no Project related activities at this location once the

initial dredging of the marine berths were completed. Construction traffic would also use La

Quinta Road to enter the Terminal site.

There are residences surrounding the Northshore Country Club in Portland,

approximately 1.3 miles west of the Terminal site. Voestalpine, an Austrian steel producer, is

planning to build a direct iron reduced (DRI)plant on the adjacent 1,100-acre property to the

west of the Terminal site, currently owned by POCCA. The DRI plant would lie between the

Terminal site and the residences near the Northshore Country Club. Due to the siting of the

Terminal within an existing industrialized area and the absence of significant residential

development, impacts would be consistent with the surrounding land use.
Environmental Impact Statement 4-62 Corpus Christi LNG

To facilitate this Project, POCCA and the COE have initiated construction work on the

extension of the La Quinta Channel and began constructing a 126-acre dredge material

placement area in 2010. Per website inquiry, the channel extension was completed in February

2014.

4.8.1.3 Recreation and Special Interest Areas

All of the land that would be used for the Project is privately owned. No public lands,

Indian reservations, scenic areas, developed recreational facilities, parks, forests, wildlife

management areas, wilderness areas, trails, or registered national landmarks have been identified

in the vicinity of the proposed Terminal.

Corpus Christi Bay supports abundant marine life that drives the tourism industry in the

Corpus Christi area. Recreational fishing and boating occurs in the Corpus Christi Bay and in

the La Quinta Channel, and fishing takes place off piers along the shoreline in the Ingleside and

Portland areas. Numerous charter fishing boats operate in Corpus Christi Bay, originating out of

the communities of Corpus Christi, Ingleside, Port Aransas, Aransas Pass, and Rockport. The

recreational boating marinas closest to the Terminal include the Bahia Marina in Ingleside-onthe-Bay approximately 3 miles southeast, and the Port Aransas Municipal Marina, more than 10

miles east of the Terminal site. Common species sought by recreational anglers in the bay

include redfish, speckled trout, drum, and flounder.

The Corpus Christi and La Quinta Ship Channels are actively used by commercial ship

traffic, as the Port of Corpus Christi is the fifth largest commercial port in the U.S. Though total

port traffic would increase (section 4.9.10), the LNG carriers would be restricted to the dredged

deep water Corpus Christi and La Quinta Ship Channels while most recreational boaters utilize

shallower channels of the GIWW within Corpus Christi Bay. We have determined the Project

would not have any adverse impacts on recreation, including boating and fishing in Corpus

Christi Bay.

4.8.1.4 Visual Resources

The degree of visual impact that may result from a Project is typically determined by

considering the general character of the existing landscape and the visually prominent features of

the proposed facilities. The Terminal would be constructed in a historically industrial area along

the northeastern shore of Corpus Christi Bay, west of the Sherwin Alumina plant. The most

prominent visual feature at the Terminal site would be three LNG storage tanks, each 181.9feet

in height from the finished grade to the top of the dome. The height from the tank floor to the

top of the dome would be 177.5 feet. The outside tank diameter would be 258.5 feet. The

heights of each of the three LNG storage tanks are less than the tallest structure on the adjacent

Sherwin plant, which measures at 197 feet above grade.

The flare stack would be visible when in use in both day and night conditions. When

flaring is not occurring, the 500-foot-high flare stack would be similar in appearance to a cell

tower. The flare would be installed to accommodate emergency reliefs and start-up flaring only

and would not be used during routine operation. Cheniere projects using the flare stack two to

three days per year.

The Terminal would be consistent with the industrial land use and visual resources of the

area. In addition, the POCCA has plans to construct the La Quinta Trade Gateway Terminal on
Environmental Impact Statement 4-63 Corpus Christi LNG

the property immediately west of the Terminal. The La Quinta Trade Gateway Terminal would

block much or all of the visibility of the Terminal and provide a closer industrial visual feature

from residences and other publicly‐accessible locations. Given the existing industrial nature of

this area, the limited visibility of the Terminal and the plans to develop the property west of the

Terminal site, Cheniere is not proposing to implement any specific measures to further limit the

visibility of the Terminal.

Impacts on visual resources resulting from the storage tanks and flare stack would be

moderate and permanent;however, due to the proximity of the Terminal to other industrial

structures, the storage tanks and flare stack would be consistent with the surrounding land use.

There are no residences, schools, community parks, or public areas that would be

considered visually sensitive areas within 1 mile of the Terminal. The three storage tanks and

elevated flare stacks would be visible on the horizon from the nearby residential subdivisions and

the Northshore Country Club golf course. The current viewshed from the nearest residence is

presented in figure 4.8-1. An artist rendering of the anticipated viewshed following construction

of the Terminal is presented in figures 4.8-2 and 4.8-3.

The Terminal would use the minimum lighting necessary to allow personnel to safely

work and inspect the equipment at the Terminal. There would be lighting along the perimeter

fence as required by security regulations. Lighting on the marine jetties would be the minimum

necessary for safe operation and positioned so as not to impede shipping in the channel. The

lighting at the Terminal would be consistent with lighting at other industrial facilities along the

La Quinta Channel and would not significantly increase light pollution in the area. Therefore,

lighting and nighttime flaring would not have a significant impact on the environment. The

majority of the Pipeline would be constructed within agricultural land and/or adjacent to existing

rights-of-way, which would not alter the landscape of the region. The Taft Compressor Station

would be located in an agricultural field with very few nearby residences. In addition, the Taft

Compressor Station would be located amongst the wind turbines associated with the Papalote

Creek Wind Farm and visual impacts from the station are expected to be minimal. The Sinton

Compressor Station would not be visible from residences or publicly-accessible locations and is

expected to have no visual impacts. Other aboveground facilities associated with the Pipeline,

such as valves and meter and regulation stations, would be fairly small and not expected to have

a significant impact on visual resources.
Environmental Impact Statement 4-64 Corpus Christi LNG

Figure 4.8-1 Current View of the Terminal Site from California Drive, Portland

Figure 4.8-2 Post-construction Visual Simulation View of the Terminal Site from California Drive, Portland
Environmental Impact Statement 4-65 Corpus Christi LNG

Figure 4.8-3 Visual Simulation View of the Terminal at Night from California Drive, Portland
Environmental Impact Statement 4-66 Corpus Christi LNG

4.8.1.5 Coastal Zone Management

The Terminal would be located within the Texas CZMP. All activities or developments

that affect Texas’s coastal resources and require a federal permit or license are evaluated for

compliance with the CZMA through the “federal consistency”process. In addition to the RRC,

Cheniere has consulted with the TGLO’s Coastal Coordination Council which determined that

the Project exceeds their threshold for CZMA consistency review and deferred review to the

RRC. Cheniere has requested a CZMA determination for the Project in conjunction with its

review and comments to the COE as part of the COE Section 10/404 permitting process (see

section 1.6.9).

Cheniere submitted its permit application to the COE on August 31, 2012. The

application is still undergoing review and a Section 10/404 permit has not been issued. As a

result, Cheniere has not received its consistency determination from the RRC. A determination

from the RRC that the Project is consistent with the Texas CZMP must be received before we

could issue a notice to proceed with constructing the Terminal or the Pipeline. Because Cheniere

has not yet obtained its authorization, we are recommending that:

 Prior to construction,Cheniere should file documentation of concurrence from the

RRC that the Project is consistent with the Texas CZMP.

The FERC would not approve construction until all federal authorizations, including a

consistency determination with the CZMA has been granted.

4.8.2 Pipeline Facilities

4.8.2.1 Land Use

The Pipeline would originate at the proposed Terminal and would run northwest for

approximately 23 miles towards the city of Sinton and would terminate at the Tennessee Gas

M&R Station. The entire Pipeline would be located within San Patricio County, Texas. The

Pipeline would be collocated, overlapped, or paralleled with existing rights-of-way for

approximately 19.73 miles, or 86 percent of the total route. Locations where the Pipeline would

be collocated with existing rights-of-way are provided in table 4.8-2.
Environmental Impact Statement 4-67 Corpus Christi LNG

Table 4.8-2

Locations Where the Pipeline Would be Collocated, Overlap, or Parallel with Existing Rights-of-Way

Mileposts Existing Easement Direction from Existing

Right-of-Way

Segment Length

(miles)

0.0 –0.64 La Quinta Road Adjacent to the west side of the road. 0.64

0.80 –2.16 Equistar Pipeline, Koch Pipeline,

Tejas Pipeline, and El Paso Pipeline

Adjacent to the north side of the Koch

Pipeline. 1.36

2.36 –2.90 Overhead power line and water line Adjacent to north side of the water line. 0.54

2.90 –7.90 County Road 78, overhead electric

power line and water line

Adjacent to north side of the water line.

County Road 78 is about 300 feet south to

about MP 5.0 and about 100 feet south

thereafter.

5.00

7.90 –8.94 County Road 78 Pipeline would be about 500 feet south of

County Road 78 (not adjacent). 1.04

11.05 –13.22 Koch Pipeline Adjacent to the north side of the Koch

pipeline. 2.17

13.22 –13.78 Koch Pipeline, private road, & water

line

Adjacent to the north side of the water line.

The private road is about 50 feet south. 0.56

13.79 –14.45 El Paso Pipeline Adjacent to the north side of pipeline. 0.66

14.45 –16.04 County Road 2921, El Paso Pipeline,

Valero Pipeline

Adjacent to the east side of Valero Pipeline.

County Road 2921 is about 1,000 feet

west.

1.59

16.04 –17.80 Valero Pipeline, (2)El Paso Pipelines Adjacent to the east side of Valero Pipeline. 1.76

18.31 –22.72 Valero Pipeline, (2)El Paso Pipelines Adjacent to the east side of Valero Pipeline. 4.41

Total 19.73

There are no existing residences or buildings within 50 feet of the Pipeline construction

work area. A Southwestern Bell fenced facility lies within 60 feet outside the proposed Pipeline,

and a building within the Southwestern Bell facility lies within 75 feet of the proposed Pipeline.

This building does not house permanent employees.

Constructing the Pipeline and associated aboveground facilities would impact a total of

approximately 420.7 acres of land. Land use impacts associated with the Pipeline facilities

would include disturbance of existing land use, the creation of new easements, and the

conversion of some land to a different land use type. Construction of the Pipeline would require

a 120-foot-wide construction work area, which would be comprised of a 50-foot-wide permanent

easement for operation and a 70-foot-wide temporary easement for construction. ATWS would

be necessary in certain locations along the Pipeline route for setup and construction across

roadways, waterbodies, wetlands, and other features that require specialized construction

procedures (section 2.4.3.2). Pipeline construction and operational impacts on land use are listed

in table 4.8-3.

Construction of the Pipeline, including only the construction right-of-way and ATWS,

would impact 348.1 acres of land. Approximately 20.1 acres of access roads would be used

during construction. Details on temporary and permanent access roads to be used for the

Pipeline are listed in table 4.8-4. Constructing the two compressor stations would impact
Environmental Impact Statement 4-68 Corpus Christi LNG

approximately 24.1 acres (6.9acres for the Taft Compressor Station and 17.2 acres for the Sinton

Compressor Station). Constructing the six proposed M&R stations would impact approximately

10.8 acres of land. Cheniere would also utilize a 17.4-acre parcel of land previously used for

temporary construction support as a temporary pipe storage and contractor yard. This yard

would be located on the Pipeline route southeast of the City of Taft on County Road 78.

Agricultural lands would be the primary land use impacted by construction of the

Pipeline and associated facilities. To accommodate deep tilling in agricultural fields, Cheniere

would bury the approximately 18 miles of Pipeline that cross actively cultivated agricultural

fields to a minimum depth of 4 feet. In all other areas Cheniere would bury the Pipeline to a

minimum depth of 3 feet. Additional depth of cover would be provided where requested by

landowners during right-of-way negotiations. Final designed burial depth would be determined

during the detailed design phase based on land usage anticipated at the time of construction. The

remaining land uses that would be impacted by the Pipeline consist of open lands and industrial

lands.

Cheniere would obtain easements from landowners prior to constructing the Pipeline.

Easements would give Cheniere access to properties and the rights to construct, operate, and

maintain the Pipeline and establish a permanent right-of-way. Cheniere would compensate

landowners for use of their land. The easement agreements would specify compensation for the

loss of use during construction, loss of nonrenewable or other resources, and allowable uses and

restrictions on the permanent right-of-way after construction. These restrictions could include

prohibition of construction of aboveground structures including house additions, garages, patios,

pools, or any other objects not easily removable;roads or driveways over the pipeline;or the

planting and cultivating of trees or orchards within the permanent easement. The areas used as

temporary construction right-of-way and ATWS would be allowed to revert to preconstruction

uses with no restrictions. Land uses, including agricultural and open land, would be allowed to

continue within the permanent easement and would not be permanently impacted. As discussed

in the Environmental Compliance and Monitoring Section landowners would typically be

notified three to five days prior to the start of construction activities, unless earlier notice is

requested during easement negotiations. Landowners would be provided with written

notification that would include information regarding how landowners can contact Cheniere in

the event that there are complaints or incidences that need to be addressed during construction.

The written notification to landowners would also provide the number for the FERC Hotline if

landowners do not get an adequate response from Cheniere.

Cheniere would construct and maintain the Pipeline according to measures contained in

our Plan and Procedures. Vegetation on the permanent right-of-way in non-agricultural areas

would be maintained by mowing, cutting, or trimming as necessary. Agricultural areas would

return to a preconstruction cultivated state, and would thus not result in a change in land use.

The Pipeline right-of-way would be allowed to revegetate;however, in wetlands and in the

required 25-foot vegetation maintenance buffer adjacent to waterbodies, a 10-foot strip centered

on the Pipeline would be mowed. Additionally, trees within 15 feet of the pipeline with root

systems that could compromise the integrity of the pipe would be selectively removed. The

frequency of vegetation maintenance would depend upon the vegetative growth rate;however, it

would not exceed that prescribed in our Plan and Procedures.
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Table 4.8-3

Land Use Affected by Construction and Operation of the Pipeline and Associated Facilities

Facility

Agricultural Open Industrial 

Construction

(acres)

Operation

(acres)

Construction

(acres)

Operation

(acres)

Construction

(acres)

Operation

(acres)

Con

Pipeline a/ 244.6 107.0 65.1 28.7 11.4 6.6 

Additional Pipeline Temporary Workspace 21.6 0.0 4.3 0.0 1.1 0.0 

Liquefaction M&R Station, Pig Receiver and

MLV (MP 0.0)

2.0 1.6 0.0 0.0 0.0 0.0 

MLV (MP 14.5)b/ 0.2 0.2 0.0 0.0 0.0 0.0 

Pig Launcher and MLV (MP 23.0)c/ 0.0 0.0 0.0 0.0 0.0 0.0 

Taft Compressor Station 6.9 5.8 0.0 0.0 0.0 0.0 

Sinton Compressor Station 0.0 0.0 17.2 7.3 0.0 0.0 

Texas Eastern M&R Station 2.1 2.1 0.0 0.0 0.0 0.0 

Tejas Pipeline M&R Station 0.0 0.0 2.4 2.4 0.0 0.0 

NGPLM&R Station 1.3 1.0 0.0 0.0 0.0 0.0 

Transco M&R Station 1.0 0.9 0.0 0.0 0.0 0.0 

Tennessee Gas M&R Station 2.0 2.0 0.0 0.0 0.0 0.0 

Access Roads 14.3 12.7 4.0 0.0 1.8 0.0 

Contractor and Pipe Yards

4

0.0 0.0 0.0 0.0 17.4 0.0 

Project Total 296.0 133.3 93.0 38.4 31.7 6.6 

__________________________

a/ Construction impacts include construction right-of-way and temporary workspace. Operational impacts include new permanent right-of-way and aboveg

b/ MLV would be within the construction right-of-way for the Pipeline and is already accounted for above, with a portion outside of the permanent pipeline 

c/ Pig launcher and MLV at MP 23.0 would be within the Tennessee Gas M&R station.

d/ The contractor and pipe yard would be located partially on the Pipeline right-of-way, and therefore this portion of the acreage is accounted for in the Pip
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Table 4.8-4

Access Roads to be Used for Construction and Operation of the Pipeline and Associated Facilities

Access

Road ID

Milepost

Temp /

Perm

Existing /

New

Existing Surface

Type

Improvements Needed Land Use

Length

(feet)

W

(f

TAR #1 0.4 Temporary Existing Gravel Add Rock and Maintain Open 180 

TAR #2 1.3 Temporary Existing Gravel Add Rock and Maintain Industrial 3,200 

TAR #3 11.0 Temporary Existing Clay Add Rock and Maintain Agricultural 2,750 

TAR #4 19.8 Temporary Existing Gravel Add Rock and Maintain Open 6,780 

PAR #1 0.0 Permanent New N/A Add Rock and Maintain Agricultural 180 

PAR #2 14.5 Permanent Existing Clay Add Rock and Maintain Agricultural 1,200 

PAR #3 21.5 Permanent Existing Clay Add Rock and Maintain Agricultural 5,050 

PAR #4 22.3 Permanent Existing Clay Add Rock and Maintain Agricultural 15,450 

PAR #5 7.6 Permanent New N/A Add Rock and Maintain Agricultural 110 

Total 

______________________

N/A =Not Applicable.
Environmental Impact Statement 4-71 Corpus Christi LNG

4.8.2.2 Existing and Planned Residences and Commercial Developments

The Pipeline would be located primarily in agricultural areas. There are currently no

existing or planned residential developments within 0.25 mile of the Pipeline. Additionally,

there are no existing residences or occupied buildings within 50 feet of the Pipeline construction

work area. Therefore, the Pipeline would not adversely impact existing residences or planned

developments.

4.8.2.3 Recreation and Special Interest Areas

All of the land that would be used for the Pipeline is privately owned. No public lands,

Indian reservations, scenic areas, developed recreational facilities, parks, forests, wildlife

management areas, wilderness areas, trails, or registered national landmarks have been identified

in the vicinity of the proposed Pipeline;and would therefore, not be impacted.

4.8.2.4 Visual Resources

Constructing and operating the Pipeline may impact visual resources by altering the

terrain and vegetation patterns during construction or right-of-way maintenance and from the

presence of new aboveground facilities. The landscape setting along the proposed Pipeline route

is generally flat. No designated viewing locations are present in areas overlooking the route.

The majority of the Pipeline would be located within agricultural land and/or adjacent to existing

rights-of-way, which would not alter the landscape of the region.

Impacts on visual resources due to the Pipeline would be primarily temporary and shortterm, occurring during construction. The terrain over the majority of the Project area is flat;

therefore, during construction, the cleared and graded right-of-way, as well as construction

equipment would be visible from surrounding residences and local roads. Following the

completion of construction activities, areas disturbed for construction would be restored and

agricultural activities that previously occurred in the area would be able to resume. Therefore,

the construction and operation of the Pipeline would not result in long-term visual impacts.

Cheniere would also install several aboveground facilities including M&R stations, as

well as two compressor stations. M&R stations are typically small and would be expected to

have only minor visual impacts. No sensitive visual resources such as schools, residential

subdivisions, or public land were identified within the Project area or in the vicinity of the

proposed aboveground facilities. Therefore, the visual impact of the aboveground facilities

would not have a significant impact on the aesthetics of the landscape along the Pipeline route.

Taft Compressor Station

The Taft Compressor Station would be located southeast of Taft, Texas, in a rural

agricultural area northwest of the intersection of County Road 78 and County Road 77. The

nearest residence to the Taft Compressor Station would be located about 0.7 mile away. The

compressor station would be located within the Papalote Creek Wind Farm, and the nearest wind

turbine would be approximately 200 feet east of the proposed compressor station. There are

several other wind turbines within 0.25 mile of the station. The wind turbines are visible from

several miles away. Other man‐made features on the landscape include high‐tension power lines

along County Road 78, grain silos, and both operating and abandoned oil and gas facility

structures. The Taft Compressor Station would be consistent with other infrastructure in the area

and would be less visible and noticeable than the nearby wind turbines. The compressor station
Environmental Impact Statement 4-72 Corpus Christi LNG

would be enclosed with chain link fencing. Because the station is sited within the windfarm,

visual screening measures would not be necessary.

Sinton Compressor Station

The Sinton Compressor Station would be located more than 1 mile from the nearest

public access point and would not be visible to the public. Therefore, no plans are proposed to

implement measures to visually screen the Sinton Compressor Station.

The majority of the land impacted by the Pipeline would be allowed to revert back to

preconstruction conditions following completion of construction. Some areas, including those

used for aboveground facilities, would be permanently converted to an industrial use. The

implementation of the measures discussed above, including collocation of the majority of the

Pipeline, would result in minimization of impacts on land use. Most impacts on visual resources

would be temporary and associated with the construction phase of the Pipeline.

Construction and operation of aboveground facilities would have a minor impact on

visual resources. The Taft Compressor Station would be sited in an area dominated by wind

turbines and the Sinton Compressor Station would not be visible from the nearest residence or

public access point. Overall, land use, recreation, and visual resource impacts associated with

the Pipeline would be minor.

4.8.2.5 Coastal Zone Management

The Pipeline would be located within the Texas CZMP. Details regarding permit

applications and jurisdiction over construction activities in this zone are discussed in section

4.8.1.5 above.

4.9 SOCIOECONOMICS

Due to the regional extent of socioeconomic impacts, this section will discuss impacts in

regards to the Project as a whole, rather than Terminal and Pipeline facilities individually. If the

proposed Project was constructed, several potential socioeconomic impacts could occur as a

result. Potential impacts from construction activities would include increased local population

levels, and increased demands on public services and housing, increased local expenditures for

materials during construction, increased payroll and sales tax revenues, local job opportunities,

and increased property values. Socioeconomic impacts are detailed below.

4.9.1 Population

Both major Project components, the Terminal and the Pipeline, would be within the

Corpus Christi Metropolitan Statistical Area (CCMSA), which includes Nueces and San Patricio

Counties. Nearby towns and cities include Gregory, Portland, Corpus Christi, Taft, Sinton,

Ingleside, Ingleside-on-the-Bay, and Aransas Pass.

Table 4.9-1 below provides a summary of selected population and socioeconomic

statistics for the State of Texas. Nueces County had population growth from 2000 to 2010 of 8.5

percent, and the population of San Patricio County declined by 3.5 percent during the same time

period.
Environmental Impact Statement 4-73 Corpus Christi LNG

Table 4.9-1

Existing Population in the Project Area

Demographic San Patricio County Nueces County

2010 Population 64,804 340,223

2000 Population 67,138 313,645

Percent Population Change (2000 to 2010) -3.5 8.5

_________________________

Source: U.S. Bureau of the Census 2012.

The total Project-related population change would equal the total number of non-local

workers, plus any family members accompanying them. During peak construction periods

(approximately 60 months), Terminal and Pipeline construction workforces, combined would

include a total of approximately 2,100 workers;peaking at approximately 3,300 workers. As

discussed further in sections 4.9.2 and 4.9.6, Cheniere would utilize predominantly local workers

during construction, and employ a relatively small full-time operational staff at the Terminal.

We determined Project-related impacts on the regional population would be short-term and

negligible;however, more localized impacts on the nearby community of Portland could be

significant when the workforce is at its peak.

Representatives from Cheniere met with area of Chambers of Commerce on three

occasions: March 22, 2012, October 17, 2012, and December 4, 2012 to address the potential

impacts of construction and operation of the Project. In addition, Cheniere representatives have

met regularly since 2010 with local community officials, specifically all of the area mayors and

councils (Ingleside, Port Aransas, Aransas Pass, Corpus Christi, Portland, and Gregory), the

regional Economic Development Corporations, and non-governmental organizations such as

environmental groups, civic organizations, and educational facilities.

Constructing the Project would result in a short-term, moderate increase to the local

population and operating would result in a negligible long-term increase. Therefore, we

determined the Project, as a whole, would not significantly impact local population size.

4.9.2 Economyand Employment

In 2012, the government (19 percent), trade/transportation/utility (19 percent),

education/health services (17 percent), and the leisure and hospitality (12 percent)service sectors

were the largest economic sectors in the CCMSA. The largest employers in the CCMSA were

the petrochemical industries, health care industry, government and military, and agriculture.

The nearest municipality to the Terminal is Portland (pop. 15,099). With a civilian

employed population of 7,196, Portland has no heavy industry and little commercial or retail

business within the town limits;however, there are several industrial facilities located within

10 miles. The largest industries in Portland are educational services, and health care and social

assistance (U.S. Census Bureau, 2012).

The 2012 American Community Survey 5-year estimate for per capita income in San

Patricio County was $22,958 and the unemployment rate was 8.0 percent. According to the

same 5-year estimate, the per capita income in Nueces County was $23,660 and the
Environmental Impact Statement 4-74 Corpus Christi LNG

unemployment rate was also 8.0 percent (see table 4.9-2). The 2012 American Community

Survey 5-year estimate for unemployment rate in the CCMSA was 7.9percent, comparable to

the State of Texas rate of 7.7 percent (U.S. Census, 2012). Constructing the Project would

positively impact employment opportunities in both San Patricio and Nueces Counties. The

Project would not have an adverse impact on the unemployment rate, and could decrease the

unemployment rate due to hiring a predominantly local workforce where feasible.

Table 4.9-2

Existing Income and Employment Conditions in the Project Area

Income Characteristic Nueces

County

Corpus

Christi

San Patricio

County Portland Ingleside Gregory

2008-2012 Per Capita

Income (dollars) $23,660 $23,692 $22,958 $27,907 $22,773 $13,545

2008-2012 Population Below

Poverty Level (percent) 18.4 18.1 16.6 11.6 11.4 30.9

2008-2012 Unemployment

Rate (percent) 8.0 7.9 8.0 4.3 7.7 10.1

Wholesale Trade Receipts

2010 ($1,000) $23,402 N/A $1,824 N/A N/A N/A

Retail Receipts

2010 ($1,000) $65,139 N/A $11,864 N/A N/A N/A

Accommodation and Food

Service Receipts 2010

($1,000)

$20,018 N/A $3,347 N/A N/A N/A

____________________________

N/A =Not Available

Sources

Census 2008 –2012 American Community 5-Year Estimates, American Fact Finder, http://factfinder2.census.gov/.

U.S. Department of Labor, Bureau of Labor Statistics (unemployment rate at time of filing), http://www.bls.gov/data

Construction of the Terminal would require an estimated 1,800 workers over a duration

of approximately 60 months. Construction of the Pipeline and associated facilities, including

compressor stations, would require an estimated 300 workers over approximately 9months. A

large national or regional pipeline construction firm would likely be selected to construct the

Pipeline. However, there is a substantial local pipeline construction capability that could be

employed through the Pipeline contractor.

Construction schedules for the Terminal and Pipeline are planned to overlap in 2016 for a

period of approximately 9months to 1 year (the length of time that it would take to construct the

Pipeline facilities). The total number of workers on the Project when the two phases overlap

would be approximately 2,100;peaking at approximately 3,300 workers. Pipe and equipment for

the Pipeline would be staged several miles from the Terminal and construction activities

associated with the Pipeline immediately adjacent to the Terminal would be limited to the time

necessary to install the Pipeline and would not encroach directly on the Terminal facility.

During operation, Cheniere anticipates adding approximately 175 full-time positions,

split into three daily shifts, to operate the Terminal facilities, and approximately six full-time

employees to operate the Pipeline and associated compressor stations. Cheniere estimates that
Environmental Impact Statement 4-75 Corpus Christi LNG

staffing for operating the Terminal would result in very little relocation due to the local

availability of a large, skilled workforce. This is due primarily to the local refining and

petrochemical sectors as well as training programs at local colleges. Operating the Pipeline and

compressor stations would also draw primarily from the local workforce. A few management

level employees could relocate to the area for the operations phase. The Project workforce and

anticipated construction schedules for the Terminal and Pipeline facilities are summarized in

table 4.9-3.

Table 4.9-3

Number of Workers During Project Construction and Operation

Facility Number of Workers

During Construction

Number of Workers at

Peak Construction

Total Duration

(months)

Number of Permanent

Workers During

Operation

Terminal 1,800 3,000 60 175

Pipeline 300 300 9-12 6

Total 2,100 3,300 60 181

Cheniere estimates that construction and other pre-operational activities associated with

the Project would result in beneficial cumulative impacts on business activity ranging from $7.4

to $10.0 billion to the local economy, $22.9to $31.0 billion to the Texas economy, and $34.4 to

$46.4 billion to the U.S. economy. Over the first 25 years of Project operation, the cumulative

impacts of operations of the Project on business activity and tax receipts is estimated to

contribute $27.6 billion to the local economy, $35.0 billion to the Texas economy, and $38.0

billion to the U.S. economy.

Additionally, according to Cheniere the Project is estimated to contribute indirectly to the

creation of approximately 50,000 new jobs annually across the U.S. through increased natural

gas exploration, drilling and production. These secondary effects are expected to result in total

economic benefits of approximately $327 billion over 25 years for the U.S. economy.

4.9.3 PropertyValues

Construction and operation of the Project would not require the relocation or involuntary

displacement of any residences or businesses. The Terminal would be constructed on property

owned by Cheniere that was previously an industrial site, but has since been reclaimed. The

Pipeline and compressor station facilities would be primarily on agricultural lands, and no

existing residences or buildings are located within 50 feet of the Pipeline construction work area.

Cheniere owns that land of the proposed location of the Taft Compressor Station. Cheniere is in

negotiations to acquire the land for the proposed Sinton Compressor Station.

No significant impacts on property values are anticipated from construction and operation

of the Project. The Terminal would be located in an industrialized area surrounded by industrial

and commercial development, and there are currently no existing or planned residential

developments within 0.25 mile of the Terminal. The LNG storage tanks would be surrounded by

industrial/commercial properties, and there would be no land within 0.25 mile of the Terminal

site that would be available for residential development. The Pipeline would be located

primarily in agricultural areas, and there are no existing residences or buildings within 50 feet of
Environmental Impact Statement 4-76 Corpus Christi LNG

the Pipeline construction work area. Additionally, there are currently no existing or planned

residential developments within 0.25 mile of the Pipeline (see section 4.8). The proposed

pipeline may have an impact on the property values of the surrounding area;however, valuation

depends on many factors, including the size of the parcel, the values of adjacent properties, the

presence of other utilities, the current value of the land, and the current land use. Similar

pipeline rights-of-way are present in the surrounding areas;therefore, the property values in the

general area of the proposed pipeline would already reflect the presence of underground

facilities.

Property taxes are generally based on the actual size of the land. Construction of the

pipeline would not change the general use of the land, but would preclude construction of

aboveground structures on the permanent right-of-way. If landowner feels that the presence of a

pipeline easement reduces the values of his or her land, resulting in an overpayment of property

taxes, he/she may appeal the issue of the assessment and subsequent property taxation to the

local property tax agency. This issue is beyond the scope of this EIS.

We received a comment regarding the potential for insurance premium adjustments or

loss of coverage associated with the proposed Project. This landowner didn’t explicitly specify

if they would be directly affected by the Pipeline, or if they reside near the Terminal. If they

reside near the Terminal, no potential loss or coverage of insurance is expected. Assuming the

landowner may be affected by the pipeline, we cannot assess how their property and or any

insurance they hold may be affected. Research conducted and included in the Constitution

Pipeline Project draft EIS20, which consisted of the FERC staff calling insurance agents,

suggested that potential for a residential action would depend on several factors, including terms

of the individual landowners policy and terms of the applicant’s policy (in this case Cheniere).

As indicated in the Constitution EIS, we were unable to confirm exclusively under what

conditions a landowner’s insurance policy could change.

4.9.4 Construction Payroll and Material Purchases

The Project would have an estimated total construction payroll of approximately $1.0 to

$1.5 billion over the 60-month construction period. The expenditures of Project personnel on

local goods, services, and labor would create several cycles of income as wages are spent and respent by succeeding recipients. The average monthly payroll impact of the Project on local

communities would be an estimated $1.4 million. Because the region supports an extensive

manufacturing and processing infrastructure for the chemical and petro-chemical industries,

many construction materials and equipment supplies are locally available, and Cheniere

anticipates that purchases of local construction materials would range from approximately $785

million to $1.06 billion.

4.9.5 Tax Revenues

The overall sales tax on goods and services in the CCMSA is 8.25 percent. No state

income tax is levied in the State of Texas. Construction of the Project would result in increased

sales tax revenues for the State of Texas, San Patricio and Nueces Counties, Gregory-Portland

Independent School District , Taft Independent School District, and Sinton Independent School

District. The Project is estimated to contribute approximately $1.6 to $2.8 million per month in

20 Docket No. CP13-499
Environmental Impact Statement 4-77 Corpus Christi LNG

local tax revenues. Additionally, the total tax revenues from construction and other preoperational activities associated with the Project is estimated to contribute $96.8 million for

Corpus Christi, $578.4 million for the State of Texas, and $1.4 billion for the U.S. New

revenues would provide direct and indirect benefits to local residents throughout the life of the

Project.

4.9.6 Housing

A sufficient supply of temporary housing units is available in San Patricio and Nueces

Counties. However, due to the size of Portland non-local workers would likely have to disperse

to the surrounding communities to meet all of the housing needs during construction. The

number of temporary and permanent housing units available is provided in table 4.9-4 below.

The Corpus Christi area is a popular tourist destination in south Texas and there are many hotels,

campgrounds, and recreational vehicle (RV)parks in the area.

Table 4.9-4

Temporary Housing Units Available in the Project Area

Housing Characteristics a/ Nueces

County

Corpus

Christi

San Patricio

County Portland Ingleside Gregory

2006-2010 Number of Vacant

Housing Units b/ 17,233 13,192 4,652 251 398 22

2006-2010 Vacancy Rate (percent) 12.5 10.8 17.5 8.1 11.9 17.5

2010 Number of Vacant Housing

Units for Seasonal, Recreational, or

Occasional Use (percent)c/

5,431 3,844 1,237 19 44 2

2006-2010 Number of Renter

Occupied Housing Units 49,790 46,689 7,791 2,186 1,118 190

2012 Number of Hotels/Motels 184 126 38 8 8 0

2012 Number of Campgrounds and

RV Parks 24 11 17 1 1 0

________________________

a/ Housing Unit: According to the U.S. Census Bureau’s website glossary, a housing unit may be a house, apartment, mobile home

or trailer, group of rooms, or a single room occupied as separate living quarters or vacant, intended for occupancy as separate

living quarters. Separate living quarters are those in which the occupants live separately from other individuals in the building and

which have direct access from outside the building or through a common hall.

b/ Vacant Housing Unit: According to the U.S. Census Bureau’s website glossary, a housing unit is vacant if no one is living in it at

the time of enumeration, unless its occupants are only temporarily absent. Units temporarily occupied at the time of enumeration

entirely by people who have a usual residence elsewhere are also classified as vacant.

c/ Seasonal, Recreational, or Occasional Use Housing Unit: According to the U.S. Census Bureau’s American Community Survey

2008 Subject Definitions, seasonal, recreational, or occasional use housing units include vacant units used or intended for use

only in certain seasons or for weekends or other occasional use throughout the year. Seasonal units include those used for

summer or winter sports or recreation, such as beach cottages and hunting cabins. Seasonal units also may include quarters for

such workers as herders and loggers. Interval ownership units, sometimes called shared ownership or time-sharing

condominiums, are included in this category.

Sources

U.S. Census Bureau, Census 2010, http://factfinder.census.gov (vacant housing units and vacancy rate).

U.S. Census Bureau. 2000. Profiles of General Demographic Characteristics: 2000 Census of Population and Housing.

YellowBook 2012: Number of “Hotels and Motels”and “Campgrounds and RV Parks”as advertised on www.yellowbook.com.

Actual numbers may vary.
Environmental Impact Statement 4-78 Corpus Christi LNG

Seasonal tourism, recreation, and port activity are major components of the local

economy in the Corpus Christi metropolitan area. Because of the importance of these economic

sectors, businesses, local governments, and economic development agencies have worked to

ensure adequate availability of housing to accommodate these activities. Projected increases in

tourism for the area are already being addressed by growth in local temporary housing capacity.

The Project is not expected to require construction of new residences. However, because

of the creation of high paying direct and indirect jobs, the value of local housing is likely to

increase markedly due to the demand for higher-quality, owner-occupied and rental housing.

The majority of workers associated with the Project is anticipated to come from within 50 miles

of the Project area and would not require temporary housing. Therefore, constructing the Project

is not expected to significantly impact local market conditions.

4.9.7 Removal of Agricultural,Pasture,or Timberland from Production

Construction and operation of the Terminal would not require the removal of agricultural

land, pasture, or timberland from production;therefore, no adverse impacts would occur.

Although construction of the Pipeline would temporarily impact agricultural land, these lands

would be allowed to revegetate and return to preconstruction conditions and uses. Therefore, no

significant impact on potential revenue from agricultural lands is anticipated, as overall

production should not be affected.

Some areas, including those used for the Taft Compressor Station as well as other

aboveground facilities, would be permanently converted to industrial land and thus, would

require the removal of agricultural land from pasture. However, these impacts would be minor,

and Cheniere would compensate landowners for the use of their land and for production loss.

4.9.8 Public Services

San Patricio and Nueces Counties have well-developed infrastructure that would provide

health, police, fire, emergency, and social services near the Project site. Public health

infrastructure in San Patricio County includes one community hospital, five health centers, and

10 private clinics. Nueces County has seven hospitals: Care Regional Medical Center in Aransas

Pass, Texas, is located approximately 7 miles from the proposed Terminal;and Christus Spohn

Hospital, Corpus Christi Medical Center, Driscoll Children's Hospital, Kindred Hospital,

Northwest Regional Hospital, and Doctors Regional Medical Center, are all in Corpus Christi,

Texas, approximately 13 to 16 miles from the proposed Terminal.

The cities of Corpus Christi, Portland, Gregory, Ingleside, Sinton, and Taft each have a

police department and fire department near the Project area. The nearest hospital, Care Regional

Medical Center, is equipped with a trauma center and has 75 beds. Additional hospitals with

trauma centers are located nearby in Corpus Christi. The nearest police station, located

approximately 2.4 miles from the proposed Terminal, is the Portland City Police Department.

Other law enforcement and emergency services are provided by the Nueces County Sheriff’s

Department and San Patricio County Sheriff's Office in Sinton, Texas. The Portland City Fire

Department is the nearest fire service. Emergency services, including medical, fire, and law

enforcement, are available through the “911”service and can address large scale emergency

responses, as needed.
Environmental Impact Statement 4-79 Corpus Christi LNG

The Terminal facility is located in an unincorporated area that is not served by a

municipal fire department;therefore, Cheniere is exploring contracting with the Refinery

Terminal Fire Company to provide firefighting and emergency services in the area.

The Terminal site lies within the Gregory-Portland Independent School District and the

Pipeline crosses through Gregory-Portland Independent School District, Taft Independent School

District, and Sinton Independent School District. Table 4.9-5 below provides information on the

school districts and school enrollment in the Project area. For the 2010-2011 school year there

were 74,517 students enrolled in 130 schools in the Project area. Most of the Project

construction personnel would not be expected to relocate their entire families to the Project area;

therefore, the Project would not have a significant impact on local schools.
Environmental Impact Statement 4-80 Corpus Christi LNG

Table 4.9-5

School Districts and School Enrollment in the Project Area

School District

Number of Schools Enrollment

Total Elementary Middle /

Jr. High

High

School Other Total

% Change

(2008/2009 to

2010/2011)

San Patricio County

Aransas Pass ISD 5 3 1 1 0 1,784 -10.9%

Gregory-Portland ISD 7 4 2 1 0 4,291 -0.6%

Ingleside ISD 5 3 1 1 0 2,152 -3.2%

Mathis ISD 4 1 2 1 0 1,799 -0.3%

Odem-Edroy ISD 3 1 1 1 0 1,085 -6.0%

Sinton ISD 4 1 1 1 1 2,150 -0.6%

Taft ISD 3 1 1 1 0 1,136 -5.8%

Nueces County

Agua Dulce ISD 2 1 0 1 0 342 -7.6%

Banquete ISD 3 1 1 1 0 795 -5.2%

Bishop Cons. ISD 4 2 1 1 0 1,234 +3.4%

Calallen ISD 4 2 1 1 0 3,836 -0.1%

Corpus Christi ISD 58 37 11 6 4 38,242 -0.6%

Driscoll ISD 2 1 1 1 0 294 +8.1%

Flour Bluff ISD 6 3 2 1 0 5,526 -1.3%

London ISD 2 1 0 1 0 394 +48.1%

Port Aransas ISD 3 1 1 1 0 568 +5.6%

Robstown ISD 6 3 2 1 0 3,301 -2.2%

Tuloso-Midway ISD 5 2 1 1 1 3,550 +4.6%

West Oso ISD 4 2 1 1 0 2,038 -2.3%

________________________

ISD =Independent School District

Public services and municipal programs are readily available in the Project vicinity. In

addition to the emergency services described above, the area has several public libraries,

museums, parks and recreation facilities. There are abundant recreational opportunities at the

many national, state, and local parks in the Corpus Christi area.
Environmental Impact Statement 4-81 Corpus Christi LNG

The Corpus Christi area is home to several academic institutions of higher learning.

Texas A&M University - Corpus Christi and Del Mar College are located in Corpus Christi. Del

Mar College is a community college offering associate level and technical courses, while Texas

A&M University - Corpus Christi is an institution offering both undergraduate and graduate

degrees. Port Aransas hosts the University of Texas at Austin Marine Science Institute, an

institution fostering both undergraduate and postgraduate oceanographic studies.

Impacts on public services would be greatest while constructing the Project, as the

greatest number of workers would be present. City of Portland public services, as those closest

to the Terminal, would be in highest demand during construction. While public services in

Portland may not be sufficient to accommodate the increased demand when the workforce is at

its peak, public services in the surrounding areas would be sufficient. Through cooperation and

coordination with local law enforcement and health care providers, the Project would not

significantly burden local public services.

4.9.9 Environmental Justice

Environmental justice considers disproportionately high and adverse impacts on minority

or low-income populations in the surrounding community resulting from the programs, policies,

or activities of federal agencies. Items considered in the evaluation of environmental justice

include human health or environmental hazards, the natural physical environment, and associated

social, economic, and cultural factors. Environmental justice analysis is conducted in

compliance with Executive Order 12898, Federal Actions to Address Environmental Justice in

Minority Populations and Low Income Populations.

Under Executive Order 12898, each federal agency must ensure that public documents,

notices, and hearings are readily available to the public. The mailing list for the Project was

initiated when the FERC’s NOI was issued, and has been continually updated during the EIS

process. All property owners affected by the Project, as identified by Cheniere, received the

notices about the Project without any distinction based on minority or income status. The

distribution list for the draft EIS included local newspapers and libraries;and all landowners,

miscellaneous individuals, and environmental groups who provided scoping comments or asked

to remain on the mailing list.

The majority of impacts associated with the Project would result from construction and

operation of the Terminal facilities, as presented throughout this EIS. The nearest residential

area is located more than 1 mile from the Terminal and consists of a golf course community

(Northshore Country Club). Impacts associated with the Pipeline facilities are primarily

associated with construction and operation of the compressor stations. There are no residences

located within 0.5 mile of either the Sinton or Taft Compressor Stations, and the closest

residential areas are more than 3 miles and 1.4 miles, respectively.

Table 4.9-6 presents the general ethnic mix and economic status of San Patricio County,

and Nueces County, Texas based on data from the U.S. Census Bureau (2012). Nueces and San

Patricio Counties have a lower percentage of Black and Asian populations than the State of

Texas as a whole. However, both Counties have a higher percentage of people of Hispanic or

Latino origin than the rest of the state.
Environmental Impact Statement 4-82 Corpus Christi LNG

In order to evaluate information more specific to the area affected by the Terminal and

Pipeline, FERC assessed environmental justice statistics at the U.S. Census tract level, which is

the smallest geographic census unit for which information was available.

Table 4.9-6

Minority Populations in Census Tracts within 0.5 mile of the Project

State/County/Census Tract White (nonHispanic) Hispanic Black Asian Native

American Other Two ormore races

TEXAS 45.3 37.6 11.5 3.8 0.3 0.1 0.6

NUECES COUNTY a/ 32.8 60.7 3.7 1.6 0.2 0.1 0.9

SAN PATRICIO COUNTY 42.2 54.2 1.8 0.9 0.1 0.1 0.6

Census Tract 105 b/ 6.0 93.3 0.0 0.0 0.0 0.0 0.7

Census Tract 107 52.6 41.5 2.1 3.4 0.0 0.0 0.5

Census Tract 108 b/ 16.7 82.7 0.3 0.0 0.1 0.0 0.2

Census Tract 109 43.9 55.3 0.0 0.0 0.0 0.0 0.7

Census Tract 110 22.1 73.0 4.6 0.0 0.0 0.0 0.3

______________________

Source: U.S. Bureau of the Census 2012

a/ No tract information is presented for Nueces County, as all Project facilities would be located within Corpus Christ Bay, greater

than 0.5 mile from the nearest inhabited census tract

b/ Project would be within 0.5 mile of the tract, but would not be located directly within the tract

The communities in the immediate vicinity of the Project area do not show any

fundamental characteristics that would differentiate them from Nueces or San Patricio Counties,

or the State of Texas as a whole (see table 4.9-7). While a relatively high percentage of the

population lives below the poverty level in Census Tracts 105 and 108, these tracts would not be

directly crossed by the Project. Additionally, there are no aboveground facilities within 0.5 mile

of these tracts. All of the other census tracts within which the Project would be located have

fewer people below the poverty level than the State of Texas or the county;therefore, low

income populations would not be disproportionately impacted. Similarly, the percentage of

minority populations within some of the census tracts (Census Tracts 105, 108, and 110)are

higher than that for the Project counties. As stated, Census Tracts 105 and 108 are not directly

crossed by the Project, and only a small portion of the Pipeline would cross Census Tract 110.

All of the other tracts in which the Project would be located have fewer minority populations

than the county;therefore, minority populations are not disproportionately impacted. The

location of the Terminal and compressor stations in relation to the low income and minority

populations in the Project area are provided in table 4.9-7.
Environmental Impact Statement 4-83 Corpus Christi LNG

Table 4.9-7

Poverty and Minority Populations in Census Tracts within 0.5 mile of the Project

State/County/Census Tract Facility Percent Below

Poverty Percent Minority

TEXAS Terminal, Pipeline, Taft Compressor

Station, Sinton Compressor Station 17.4 54.7

NUECES COUNTY a/ Terminal 18.4 67.2

SAN PATRICIO COUNTY Terminal, Pipeline, Taft Compressor

Station, Sinton Compressor Station 16.6 57.8

Census Tract 105 b/ Pipeline 30.8 94.0

Census Tract 107 Terminal, Pipeline, Taft Compressor

Station 10.0 47.4

Census Tract 108 b/ Pipeline 21.6 83.3

Census Tract 109 Pipeline, Sinton Compressor Station 14.9 56.1

Census Tract 110 Pipeline 15.8 77.9

______________________

Source: U.S. Bureau of the Census 2012

a/ No tract information is presented for Nueces County, as all Project facilities would be located within Corpus Christ Bay, greater

than 0.5 mile from the nearest inhabited census tract

b/ Project would be within 0.5 mile of the tract, but would not be located directly within the tract

Contractors working on the Project would be required to comply with applicable equal

opportunity and non-discrimination laws and policies. The criteria for all positions would be

based upon qualifications without regard to age, race, creed, or sex, and in accordance with

applicable, federal, state, and local employment laws and policies. Disproportionate, adverse

impacts on minority or low-income populations would not occur as a result of constructing or

operating the Project. Furthermore, the Project is expected to provide a beneficial economic

impact on local communities through employment opportunities, construction payroll

expenditures, purchases of construction goods and materials, local expenditures by workers, and

increased tax revenues, regardless of race or income group.

The FERC staff held one public scoping meeting in the Project area to provide residents,

municipalities, special interest groups, and federal and state regulatory agencies an opportunity

to comment on the Project. The date and location of the meeting was included in the NOI.

Throughout this document we identify impacts on environmental resources that potentially may

have a direct or indirect effect on the local population, including air quality (see section 4.11.1),

water resources (see section 4.3), and hazardous materials (see section 4.2). We have not

identified any disproportionately high or adverse human health or environmental effects on

minority and low-income communities or Native American groups.

With the implementation of Cheniere’s construction plans, we have determined that the

construction and operation of the Project would not have a significant adverse impact on the

local population including low-income and minority populations.
Environmental Impact Statement 4-84 Corpus Christi LNG

4.9.10 Transportation and Traffic

4.9.10.1 Terminal Facilities

Land Transportation

The Terminal site is accessible via public roadways. It would be located on La Quinta

Road, which intersects SH 35 and SH 361 in Gregory. From Gregory, US 181 provides southern

access to Portland, Corpus Christi, and Interstate 37 (I-37), and northern access to Sinton and US

77. The city of San Antonio is 150 miles northwest of Gregory via I-37 and Houston is

210 miles north via US 77/59.

South of Gregory, existing roads would provide land access to the Terminal site via

SH 35, SH 361, and La Quinta Road. La Quinta Road, which is a private road currently used as

access to the adjacent Sherwin Alumina facility, would provide primary access to the Terminal

during both construction and operation. All Terminal traffic must access La Quinta Road via the

SH 35 eastbound frontage road, which requires all traffic entering the site to turn right from the

SH 35 eastbound frontage road onto La Quinta Road. All traffic exiting the site would turn right

from La Quinta Road onto the SH 35 eastbound frontage road. Personnel and deliveries driving

from Aransas Pass would travel west on SH 35 to Portland, exit Broadway, perform a U-turn and

proceed east on the SH 35 frontage road, which is the same direction as traffic from Corpus

Christi. Vehicles leaving the site and traveling to Aransas Pass would proceed easterly on the

SH 35 frontage road, and vehicles traveling to Corpus Christi would also travel easterly on the

SH 35 frontage road, but would U-turn under SH 35 at the SH 361 intersection and travel west

on SH 35.

Based on 2010 traffic data from the Texas Department of Transportation (TxDOT),

approximately 32,000 vehicles per day traveled SH 35 near the exit for La Quinta Road. No

official level of service ratings have been assigned to the roads in the Project vicinity.

There would be an increase in heavy truck traffic and workforce traffic to the Terminal

site during the Terminal construction phase. Cheniere estimates an average of 26 to 36 deliveries

of construction materials per day, with a peak of 44 to 59trips per day. The estimated daily

construction traffic would equate to approximately 1,620 to 2,268 trips to and from the Terminal

during an average month of construction, including all worker vehicles, deliveries, and other

construction traffic. During peak construction, Cheniere would anticipate approximately 2,700

to 3,645 vehicle trips per month to and from the site. Based on available traffic count data,

constructing the Terminal would not be expected to significantly impact traffic flow on SH 35, as

this volume represents a temporary daily increase in traffic of 2 to 3 percent. To help mitigate

increases in traffic, a parking area for construction workers is planned near SH 361 at the

Sherwin Alumina exit, from which the construction workers would be carried by a bus through

the Sherwin Alumina property to the rear entrance of the Terminal site. This arrangement would

reduce traffic on La Quinta Road during peak hours.

Vehicles entering the site could have an impact on traffic at the intersection of SH 35 and

Broadway (in Portland). A southbound SH 35 frontage road to northbound SH 35 frontage road

U-turn exists at the Broadway intersection which should minimize construction traffic from

passing through the intersection. Vehicles exiting the site would increase traffic at the

intersection of SH 35 and State Loop 202. However, a U-turn that connects the northbound SH

35 frontage road to the SH 35 southbound main lanes is located just west of State Loop 202.
Environmental Impact Statement 4-85 Corpus Christi LNG

This connector provides vehicles leaving the Terminal site an additional route, which would

minimize impacts at the intersection.

Cheniere would consult with the TxDOT and other local entities responsible for

transportation planning, including San Patricio and Nueces Counties and the cities of Gregory

and Portland, to determine if a Project-specific construction transportation plan is necessary.

Operating the Terminal would require an estimated 175 employees, split between 3 daily

shifts. The additional traffic generated by operational employees would not result in a

significant increase in traffic volume on area roadways because the increase would be less than 1

percent of the daily traffic volumes in the area.

Overall, impacts on land transportation would primarily occur during construction of the

Terminal. During construction, Cheniere would minimize impacts on traffic via the use of

busses to transport workers to the site. Additionally, the increase in traffic while constructing the

Terminal would be temporary and would only slightly increase traffic in the area. During

operation of the Terminal, the increase in traffic volume would be negligible and would not

result in a perceptible overall increase in area traffic.

Marine Transportation

The Port of Corpus Christi is the fifth largest port in the U.S. in tonnage. In 2009, the

volume of ship and barge activities (total of 5,160 ship calls)declined approximately 14 percent

from 2008. In 2010, the Port of Corpus Christi handled 5,768 ship calls, including 416 ships

carrying dry cargo, 992 tankers, and 4,360 barges. The top three inbound commodities in 2010

were crude oil, fuel oil, and gas oil, while the top outbound commodities were gasoline, fuel oil,

and diesel.

The La Quinta Channel is the site of the Kiewit Offshore Industries marine fabrication

yard, DuPont Chemical Company, Occidental Chemical Company, and the Sherwin Alumina

Company. Traffic consists of rigs and platforms, tank ships and barges carrying chemicals and

products to and from the chemical plants, and ore and alumina carriers (ships and barges)to and

from Sherwin Alumina.

The ferries at Port Aransas operate 24 hours a day, 365 days a year, typically departing

every 10 to 20 minutes. Additionally, Corpus Christi Bay is utilized by commercial fishing and

shrimping boats, and recreational boaters;however, the majority of recreational boaters use the

GIWW channels (see section4.8.1.3).

Commercial vessel traffic (less than 18-foot draft)traverses the ship channel between

Harbor Island and the Gulf of Mexico. On average, this traffic volume is less than six vessels

per day. Several fishing boats and other small crafts dock at Harbor Island and use either the

ship channel or Aransas Channel, and the Aransas Pass Outer Bar Channel to access the Gulf of

Mexico. Although this is a significant fleet of small boats, they typically do not use the Corpus

Christi Channel and would only be affected by LNG carrier traffic for the period of time the

LNG carrier is in the 4 nm along Outer Bar Channel. Aransas Pass also has a shipyard, but

traffic related to this facility would not be significant as compared to the normal volume of

fishing boats and other small crafts in the area.

The distance from the sea buoy off Aransas Pass to the Terminal’s marine berths would

be about 19.7 nm. The LNG carrier total U.S. territorial water route consists of an approximately

7.0 nm Safety Fairway transit from the U.S. Territorial Sea Boundary to the Aransas Pass Sea
Environmental Impact Statement 4-86 Corpus Christi LNG

Buoy, thence approximately 4.6 nm to the entrance of the Jetty Channel, thence approximately

1.5 nm to the Corpus Christi Channel, thence approximately 9.0 nm to the La Quinta Channel,

and thence approximately 4.6 nm up the La Quinta Channel to the proposed Terminal LNG

carrier marine berths.

Cheniere estimates piloted channel transit times in each direction for an LNG carrier

would be between three and four hours, including docking and undocking operations, between

the sea buoy of Aransas Pass and the Terminal. Actual underway time would be approximately

1.25 hours in the Corpus Christi Ship Channel and approximately 45 minutes to 1 hour in the La

Quinta Channel. A moving safety and security zone would be established that would essentially

limit deep draft traffic to a one-way pattern when LNG carriers are in the channel, though it

would not be expected to adversely impact overall traffic patterns.

The majority of vessel traffic that enters Corpus Christi Bay, via either the ship channel

or the GIWW, is bound for the Port of Corpus Christi. With the ship channel entrance and the

intersection with the GIWW both located east of the entrance to the La Quinta Channel,

transiting LNG carriers could have a transient effect on vessel traffic flow in Corpus Christi Bay

within that section of the channel. The majority of other vessel traffic consists of tug and barge

tows utilizing the GIWW. Their potential to intersect with the LNG carrier route would be for a

relatively short distance as the tug and barge tow route and the LNG carrier route would overlap

for approximately 1.5 nm between the GIWW intersection with the ship channel and the branch

to the La Quinta Channel. Ship traffic, although subject to the restrictions of the moving safety

and security zone around the transiting LNG carrier, would generally share the Corpus Christi

Channel between the Aransas Pass Sea Buoy and the entrance of the La Quinta Channel, a

distance of approximately 15 nm.

The Port Aransas ferry system crosses the Corpus Christi Ship Channel within

approximately 0.6 nm of the cut between San Jose Island and Mustang Island. Typically, four to

six ferryboats operate during daylight hours. However, when LNG carriers would be transiting;

one LNG carrier entering the Corpus Christi Ship Channel once every one to two days would not

be anticipated to have a significant effect on the Port Aransas ferry operations. Cheniere has

estimated that a single ferry trip may be potentially delayed up to a maximum of 20 minutes due

to the passage of an LNG carrier. According to TxDOT, ferry operators in the area are

accustomed to navigating around large vessels with safety zones and do not anticipate significant

impacts on ferry operations from LNG carriers under normal conditions.

4.9.10.2 Pipeline Facilities

Land Transportation

The Pipeline would cross 18 roadways;including SH 35, US 181, SH 188, and US 77;as

well as a number of local roadways. Roads crossed by the pipeline and the proposed crossing

method for each road are listed in table 4.9-8. The two pipeline compressor stations would be

located approximately 3 miles north of Sinton and 2 miles southeast of Taft. The Sinton

Compressor Station would be accessible from a private access road off of US 77 and the Taft

Compressor Station would be accessible via County Road 78.

Constructing the pipeline would require approximately 300 workers. An additional six

employees would be necessary to operate the Pipeline and associated compressor stations.

Construction traffic in and out of compressor station sites and yards would result in localized
Environmental Impact Statement 4-87 Corpus Christi LNG

increases in traffic volumes but existing traffic in the area is generally limited and the increased

traffic from construction is expected to be minor.

Table 4.9-8

Roadways Crossed by the Pipeline

Roadway Name Milepost Roadway Type Jurisdiction Construction

Crossing Method

La Quinta Road 0.0 Paved County Bore

US 181 / SH 35 1.9 Paved Federal / State HDD

CR 2986 2.9 Paved County Bore

CR 3667 5.0 Unpaved County Bore

CR 3567 6.2 Paved County Bore

CR 1612 7.5 Paved County Bore

CR 77 7.9 Paved County Bore

CR 3365 8.5 Unpaved County Bore

SH 893 9.6 Paved State Bore

SH 631 10.0 Paved State Bore

CR 1944 10.4 Paved County Bore

CR 2965 13.2 Unpaved County Bore

US 181 15.1 Paved Federal Bore

CR 1210 16.1 Unpaved County Bore

CR 2921 16.9 Unpaved County Bore

SH 188 17.0 Paved State Bore

Marathon Road 18.8 Paved City Bore

US 77 20.2 Paved Federal Bore

Constructing the Pipeline would result in some minor, short-term impacts on area

roadways along the 23-mile route. Short-term impacts on traffic flow could occur where the

Pipeline would be installed beneath roads due to safety precautions for workers crossing and

working in the vicinity of the road crossings. However, these crossings would be constructed via

bore and would have no long-term impacts on traffic patterns or road conditions.

Construction traffic in and out of the compressor station sites and ware yards would result

in localized increases in traffic but existing traffic in the area is generally limited and the

increased traffic from construction is expected to be minor. If necessary, traffic control

personnel would be utilized to manage traffic in areas of active construction, but this would

typically only be required for large trucks entering or exiting the Pipeline workspaces and the

traffic impacts would be of short duration. Cheniere would repair any damage to public

roadways caused by construction equipment. Operation of the Pipeline and associated facilities

would require an additional workforce of six people which would not have an impact on traffic

in the area.
Environmental Impact Statement 4-88 Corpus Christi LNG

4.10 CULTURAL RESOURCES

Section 106 of the NHPA, as amended, requires that the FERC take into account the

effects of its undertakings on historic properties, and afford the ACHP an opportunity to

comment. The steps in the process to comply with Section 106, outlined in the ACHP’s

implementing regulations at 36 CFR 800, include consultations, identification of historic

properties, assessment of effects, and resolution of adverse effects. Activities related to

consultation and/or Project coordination for both the Terminal and Pipeline facilities are

presented for the Project as a whole, below. Field survey activities and the results of

investigations to identify and evaluate cultural resources that are completed to date are discussed

separately below.

4.10.1 Consultations

We sent copies of our NOI for this Project to a wide range of stakeholders, including the

ACHP, U.S. Department of the Interior (DOI)National Park Service, DOI Bureau of Indian

Affairs (BIA), the Texas SHPO, and Indian tribes which may have an interest in the Project area.

The NOI contained a paragraph about Section 106 of the NHPA, and stated that we use the

notice to initiate consultations with the SHPO, and to solicit their views, and those of other

government agencies, interested Indian tribes, and the public on the Project’s potential effects on

historic properties. No comments on cultural resources issues were received in response to our

NOI.

Through a review of Cheniere’s application, and independent research, we identified

Indian tribes that historically used or occupied the Project area, and may attach religious or

cultural significance to historic properties in the APE, in accordance with Section 101(d)(6)(B)

of the NHPA. In addition to sending our NOI to potentially interested Indian tribes, we wrote

letters to the 12 tribes listed on table 4.10-1 on January 9, 2013, describing the Project and

requesting comments.
Environmental Impact Statement 4-89 Corpus Christi LNG

Table 4.10-1

Indian Tribes Contacted

Tribes Contacted by the FERC Through the NOI

and January 9, 2013 Letters

Tribes Contacted by Cheniere by

January 13, 2012 Letters Responses

Alabama Coushatta Tribe of Texas,

c/o Carlos Bullock, Chair No responses filed to date.

Apache Tribe of Oklahoma,

c/o Louis Maynahonah, Chair No responses filed to date.

Caddo Nation of Oklahoma,

c/o Brenda Edwards, Chair

Caddo Nation,

c/o Robert Cast, THPO a/ No responses filed to date.

Comanche Nation of Oklahoma,

c/o Michael Burgess, Chair No responses filed to date.

Jicarilla Apache Tribe of New Mexico,

c/o Levi Pesata, President No responses filed to date.

Kickapoo Traditional Tribe of Texas,

c/o Juan Garza, Chair No responses filed to date.

Kiowa Tribe of Oklahoma,

c/o Ron Twohatchet, Chair No responses filed to date.

Lipan Apache Tribe of Texas,

c/o Bernard Barcema. Chair No responses filed to date.

Mescalero Apache Tribe of New Mexico,

c/o Mark Chino, President No responses filed to date.

Tonkawa Tribe of Oklahoma,

c/o Donald Patterson, President

Tonkawa Tribe,

c/o Miranda Nax’ce Allen, Museum

and NAGPRA Assistant b/

No responses filed to date.

Wichita and Affiliated Tribes of Oklahoma,

c/o Stratford Williams, President

Wichita and Affiliated Tribes,

c/o Leslie Standing, President No responses filed to date.

Ysleta Del Sur Pueblo of Texas,

c/o Frank Paiz, Governor No responses filed to date.

___________________________

a/ THPO =Tribal Historic Preservation Officer

b/ NAGPRA =Native American Graves Protection and Repatriation Act

In addition to our consultation program, Cheniere also communicated with Indian tribes it

thought may have an interest in the Project area. On January 13, 2012, Cheniere sent a letter to

the Southern Plains Regional Office of the BIA requesting information about Indian tribes that

should be contacted about the Project. The BIA confirmed that the appropriate tribes that should

be contacted included the Alabama-Coushatta Tribe, Caddo Nation, Tonkawa Tribe, and Wichita

and Affiliated Tribes. Cheniere contends that it contacted the Alabama-Coushatta Tribe

concerning its proposed LNG import terminal in 2003, at the same location as the current

Project, and the tribe indicated that the Project area was outside of their ceded lands. Cheniere

sent letters dated January 13, 2012 to the Caddo Nation, Tonkawa Tribe of Oklahoma, and

Wichita and Affiliated Tribes requesting information about effects the Project may have on

traditional cultural properties. Cheniere has not filed any responses to its communications with

Indian tribes.

Cheniere also consulted with the THC, representing the SHPO. Cheniere had been

communicating with the SHPO since 2003, regarding its original LNG import terminal proposal.
Environmental Impact Statement 4-90 Corpus Christi LNG

4.10.2 Overview and SurveyResults

4.10.2.1 Terminal Facilities

On August 10, 2004, the SHPO indicated that the State Marine Archaeologist had

reviewed the submerged area where Cheniere proposed to excavate and construct its marine

berth for the originally proposed LNG import terminal and determined that much of the area had

been previously surveyed and the rest was very shallow, therefore, “the project may proceed

without further underwater archaeological survey.” Cheniere’s consultant, Tetra Tech, wrote a

letter to the SHPO on May 21, 2012, requesting concurrence that the previous cultural review

was still valid for the newly proposed LNG export proposal, because the basic location and

design of the marine berth had not greatly changed. The SHPO concurred on May 25, 2012.

Upland portions of the proposed Terminal site were first surveyed by Historic

Preservation Associates (Cheniere contractor), and reported in 2004. That survey identified 11

archaeological sites along the bluff edge (Klinger, 2004). A second survey report in 2004 by

PBS&J (Cheniere Contractor)inventoried about 79acres within the Terminal site. Nine of the

sites originally recorded by Historic Preservation Associates were relocated by PBS&J, plus

three new archaeological sites and an isolated find were identified (Turner, 2004b). PBS&J

tested six of the sites originally recorded by Historic Preservation Associates (Turner, 2004a).

The prehistoric sites were shell middens, usually found eroding from the bluffs, with limited

faunal materials and chipped stone artifacts.

One site (41SP35), however, contained an historic component, identified as the

archaeological remains of the so-called Taft Ranch Mansion. The Taft Ranch began as the

Fulton Cattle Company in 1871, and was controlled after 1900 by Charles Taft, half-brother to

future U.S. President William Taft. In 1907, Joseph Green, the Taft Ranch foreman, oversaw the

construction of a mansion and ranch headquarters, known as La Quinta, at the location of

41SP35. The mansion burned down in 1938.

PBS&J was of the opinion that none of the sites within the Terminal tract were eligible

for the NRHP. The SHPO agreed on August 24, 2004.

In May 2012, Tetra Tech inventoried about 4.2 acres at the proposed Terminal, relocated

10 of the previously recorded sites, and found three new sites. Again, all of the sites were

evaluated as not eligible for the NRHP (Tetra Tech, 2012). Tetra Tech submitted the report of

these investigations to the SHPO on August 8, 2012, who accepted it and agreed with the

recommendations, in a letter dated August 15, 2012.

On August 8, 2012, Tetra Tech wrote a letter to the SHPO, requesting permission not to

conduct archaeological surveys at the proposed DMPA 2 covering 385 acres and the borrow pit

covering 90 acres. It was Tetra Tech’s opinion that those areas were previously disturbed and

had a low potential to contain cultural resources. The SHPO agreed on August 15, 2012 that no

historic properties would be affected in those areas;and work at the DMPA 2 and borrow pit

could proceed as planned.

4.10.2.2 Pipeline Facilities

The original pipeline route proposed by Cheniere for its LNG import project, and

analyzed in our March 2005 EIS in Docket Nos. CP04-37-000 and CP04-44-000, was 23-mileslong, with eight proposed M&R stations at interconnections for other existing natural gas
Environmental Impact Statement 4-91 Corpus Christi LNG

pipeline systems. Within two reports filed in 2004, PBS&J documented surveys that covered all

but 2.1 miles of that original route (Perkins and Latham 2004;Perkins 2004). No archaeological

or historic sites were recorded during those surveys. The SHPO accepted those reports in letters

dated March 25 and July 8, 2004 and agreed that no historic properties were identified in the

areas inventoried. On May 21, 2012, Tetra Tech wrote the SHPO a letter to confirm that the

previous surveys were still valid for the current Project proposed by Cheniere in Docket No.

CP12-508-000, and the SHPO concurred on May 25, 2012.

The newly proposed pipeline route in Docket No. CP12-508-000 differs from the

originally proposed route at about six locations, totaling approximately 3.5 miles. In May 2012,

Tetra Tech conducted a cultural resources inventory of various segments along the newly

proposed pipeline route from approximately MP 3.0 to 5.0, MP 9.0 to 11.0, MP 18.1 to 18.3, and

MP 22.9 to 23.3;the location of the newly proposed Taft Compressor Station;and four

alternative locations for the Sinton Compressor Station. No cultural resources were recorded.

Tetra Tech conveyed the report to the SHPO on August 8, 2012, who accepted it and agreed with

the recommendations in a letter dated August 15, 2012.

The only segment of the newly proposed pipeline route that was not surveyed by PBS&J

in 2004 or by Tetra Tech in 2012 was from MP 0.0 to 0.5. However, this segment is within the

tract proposed for the La Quinta Trade Gateway Terminal.

On June 20, 2012, Tetra Tech wrote a letter to the SHPO requesting permission not to

conduct archaeological surveys at the proposed temporary construction laydown area within the

proposed La Quinta Trade Gateway Terminal tract, a temporary construction worker parking

area within the industrial area associated with the Sherwin aluminum plant, and the proposed

Sinton Compressor Station at approximately MP 22.5 on the proposed pipeline route. Reasoning

for this request was either because these areas were previously surveyed, were previously

disturbed, or have a low potential to contain cultural resources. The SHPO concurred on July 3,

2012, that no historic properties would be affected within those areas, and the Project could

proceed as planned.

4.10.3 Unanticipated Discoveries

On August 7, 2012, Tetra Tech submitted an updated Plan and Procedures for

Addressing Unanticipated Discoveries of Cultural Resources and Human Remains. Cheniere

also filed a copy of this plan with its application to the FERC. The SHPO concurred that this

plan was acceptable on August 15, 2012, and we agree.

4.10.4 Compliance with NHPA

No traditional cultural resources, burials, or sites of religious significance to Indian tribes

were identified in the APE by the National Park Service, BIA, SHPO, Cheniere, Tetra Tech, or

the Indian tribes contacted by the FERC. We agree with the SHPO that no historic properties

would be affected in areas that have been inventoried. The only segment that was not

documented by Cheniere as covered by a cultural resources survey was the newly proposed

pipeline route approximately between MP 0.0 and 0.5.
Environmental Impact Statement 4-92 Corpus Christi LNG

To ensure our responsibilities under Section 106 of the NHPA and its implementing

regulations are met, we recommend:

 Cheniere should not begin construction of facilities and use of all staging,storage,

and temporaryworkareas,and new or to-be-improved access roads,until:

a. Cheniere files with the Secretary:

1. anyadditional inventoryreports,including documentation of surveyof the

proposed pipeline route between about MP 0.0 and 0.5;

2. anyrequired evaluation reports,and anynecessarytreatment plans;and

3. comments on the reports and plans from the Texas SHPO.

b. the ACHP is afforded an opportunity to comment if any historic properties

would be adverselyaffected;and

c. the FERC staff reviews,and the Director of the Office of EnergyProjects (OEP)

approves,all cultural resources reports,documentation,and plans and notifies

Cheniere in writing that it mayproceed with treatment or construction.

All materials filed with the Commission containing location, character, and

ownership information regarding cultural resources must have the cover and any

relevant pages therein clearlylabeled in bold lettering: “CONTAINSPRIVILEGED

INFORMATION -DO NOT RELEASE.”

4.11 AIR QUALITY AND NOISE

4.11.1 Air Quality

Air quality would be affected by construction and operation of the Project. Though air

emissions would be generated by operation of equipment during construction of the Project

facilities, most air emissions associated with the Project would result from the long-term

operation of the Terminal and compressor stations. This section of the EIS addresses the

construction- and operation-based emissions from the Project, as well as projected impacts to air

quality and applicable regulatory requirements.

4.11.1.1 Regional Climate

The Project area climate (humid subtropical)is significantly influenced by its location in

the Texas Coastal Zone (i.e., proximity to the Gulf of Mexico). In general, Corpus Christi has

very short mild winters and long hot summers, although the sea breeze can help moderate peak

temperatures. Climate data obtained from NOAA for the period 1981 to 2010 show that daily

average high temperatures range from 67°F during January to 94°F during August. Daily

average low temperatures range from 47°F during January to 75°F during August. The record

minimum and maximum temperatures are 11°F and 109°F, respectively. The annual average

precipitation amounts to approximately 32 inches, with a monthly maximum of 5 inches in

September. At least a trace of precipitation occurs on 77 days during the year, on average

(NOAA, 2013a).

Two principal wind patterns dominate the Texas Coastal Zone: frequent, strong

southeasterly winds (essentially at any time of the year, but most pronounced in the spring

through mid-summer)and north-northeasterly winds associated with cold fronts from October
Environmental Impact Statement 4-93 Corpus Christi LNG

through March. The prevailing wind for the region is from the southeast and has an annual

average velocity of 12 mph (NOAA, 2013b). The prevailing southeast wind is further

strengthened by the thermal winds which develop when the air over the heated land in west

Texas is warmer than the air over the relatively cooler waters of the Gulf of Mexico. This effect

is most pronounced in the spring and summer (Corpus Christi Windsurfing Association, 2013).

4.11.1.2 Existing Air Quality

Ambient Air Quality Standards

The EPA has established National Ambient Air Quality Standards (NAAQS)for six

pollutants: SO2, CO, ozone (O3), nitrogen dioxide (NO2), particulate matter (PM)including PM

less than 10 microns in diameter (PM10)and PM less than 2.5 microns in diameter (PM2.5), and

lead. There are two classifications of NAAQS, primary and secondary standards. Primary

standards set limits the EPA believes are necessary to protect human health including sensitive

populations such as children, the elderly, and asthmatics. Secondary standards are set to protect

public welfare from detriments such as reduced visibility and damage to crops, vegetation,

animals, and buildings.

Individual state air quality standards cannot be less stringent than the NAAQS. The

federal NAAQS for criteria pollutants are the same as the state standards established by the

TCEQ in accordance with Section 30 of the TAC, Rule §101.21. The TCEQ has also established

30-minute average property line standards for SO2 and H2S in 30 TAC §112. The federal

NAAQS and Texas-specific standards (referenced as net ground-level concentrations) are

summarized in table 4.11-1.
Environmental Impact Statement 4-94 Corpus Christi LNG

Table 4.11-1

Ambient Air Quality Standards

Pollutant Averaging

Period

Primary

NAAQS

Secondary

NAAQS

Texas

NGLC

O3 8-Hour (2008) a/ 0.075 ppm 0.075 ppm -

CO 1-Hour b/ 35 ppm - -

8-Hour b/ 9 ppm - -

NO2 1-hour c/ 100 ppb - -

Annual d/ 53 ppb 53 ppb -

PM2.5 24-Hour e/ 35 μg/m3

35 μg/m3 -

Annual f/ 12 μg/m315 μg/m3 -

PM10 24-Hour g/ 150 μg/m3

150 μg/m3 -

Lead 3-Month h/ 0.15 μg/m3

0.15 μg/m3 -

SO2 1-Hour i/, j/ 75 ppb - -

3-Hour b/ - 0.5 ppm -

30-minute - - 0.4 ppm k/

H2S 30-minute - - 0.08/0.12 ppm l/

______________________

μg/m3 =micrograms per cubic meter;ppm =parts per million;ppb =parts per billion

NGLC =net ground-level concentration

a/ Annual fourth-highest daily maximum 8-hour concentration, averaged over 3 years.

b/ Not to be exceeded more than once per year.

c/ The 98th percentile of daily maximum 1-hour average concentrations, averaged over 3 years.

d/ Annual arithmetic mean.

e/ The 98th percentile of 24-hour concentrations, averaged over 3 years.

f/ Annual arithmetic mean, averaged over 3 years.

g/ Not be exceeded more than once per year on average over 3 years.

h/ Not to be exceeded.

i/ The 99th percentile of daily maximum 1-hour concentrations, averaged over 3 years.

j/ 24-hr and annual SO2 NAAQS revoked in 2010 (75 FR 35520);however, standards remains in effect until one year after an

area is designated attainment or nonattainment for the 1-hour standard, except in areas designated nonattainment for the

1971 standard, where the 1971 standards remains in effect until implementation plans to attain or maintain the 2010

standard are approved.

k/ Net ground-level concentration not to be exceeded at the property boundary.

l/ Net ground-level concentration of 0.08 ppm not to be exceeded on property normally occupied by people and net groundlevel concentration of 0.12 ppm not to be exceeded on property that are not normally occupied by people.

GHGs occur in the atmosphere both naturally and as a result of human activities, such as

the burning of fossil fuels. These gases are the integral components of the atmosphere’s

greenhouse effect that warms the earth’s surface and moderates day/night temperature variation.

In general, the most abundant GHGs are water vapor, CO2, methane (CH4), nitrous oxide (N2O),

and O3. On December 7, 2009, the EPA defined air pollution to include the mix of six long-lived
Environmental Impact Statement 4-95 Corpus Christi LNG

and directly-emitted GHGs, finding that the presence of the following GHGs in the atmosphere

may endanger public health and welfare through climate change: CO2, CH4, N2O,

hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride.

As with any fossil fuel-fired project or activity, the Project would contribute GHG

emissions. The principle GHGs that would be produced by the Project are CO2, CH4, and N2O.

Emissions of GHGs are quantified and regulated in units of carbon dioxide equivalents (CO2e).

The CO2e unit of measure takes into account the global warming potential (GWP)of each GHG.

The GWP is a ratio relative to CO2 that is based on the particular GHG’s ability to absorb solar

radiation as well its residence time within the atmosphere. Thus, CO2 has a GWP of 1, CH4 has

a GWP of 25, and N2O has a GWP of 29821. To obtain the CO2e quantity, the mass of the

particular compound is multiplied by the corresponding GWP, the product of which is the CO2e

for that compound. The CO2e value for each of the GHG compounds is summed to obtain the

total CO2e GHG emissions.

Air Quality Control Regions and Attainment Status

Air Quality Control Regions (AQCRs)are areas established for air quality planning

purposes in which implementation plans describe how ambient air quality standards will be

achieved and maintained. AQCRs were established by the EPA and local agencies, in

accordance with Section 107 of the CAA and its amendments, as a means to implement the CAA

and comply with the NAAQS through SIPs. The AQCRs are intrastate and interstate regions

such as large metropolitan areas where the improvement of the air quality in one portion of the

AQCR requires emission reductions throughout the AQCR. The entire Project area (including

the Terminal and Pipeline)is located in the Corpus Christi-Victoria Intrastate AQCR. Likewise,

ship transit would impact the same AQCR.

An AQCR, or portion thereof, is designated based on compliance with the NAAQS.

AQCR designations fall under three general categories as follows: attainment (areas in

compliance with the NAAQS);nonattainment (areas not in compliance with the NAAQS);or

unclassifiable. AQCRs that were previously designated nonattainment, but have since met the

requirements to be classified as attainment are classified as maintenance areas. The Corpus

Christi-Victoria Intrastate AQCR is designated as unclassifiable and/or attainment for all criteria

pollutants.

Air Quality Monitoring and Existing Air Quality

Air quality monitors are located throughout the state to determine existing levels of

various air pollutants. Air quality monitoring data obtained from the EPA AirData and the

TCEQ Air Quality Data databases for the period 2009-2011 were reviewed by Cheniere to

characterize ambient air quality for regulated criteria pollutants in the vicinity of the Project area.

The assessment included the following pollutants: O3, CO, NO2, PM2.5, PM10, and SO2. Data for

the three-year period from representative Project area monitors are summarized in table 4.11-2.

This table shows representative concentrations for the 3-year period and/or short-term averaging

periods.

21 On November 29, 2013, EPA revised the GWPs as part of amendments made to the Greenhouse Gas Reporting

Rule (78 FR 71904). When Resource Report No. 9was prepared by Cheniere, the EPA-stated GWPs for CO2, CH4,

and N2O were 1, 21, and 310, respectively. Because the GHG emissions for the Project are primarily CO2,

associated CO2e emissions will not change significantly as a result of EPA’s revisions.
Environmental Impact Statement 4-96 Corpus Christi LNG

Table 4.11-2

Existing Ambient Air Concentrations for the Project Area

Pollutant Averaging

Period

Measured

Concentration Units

Monitor Information

Air Quality Control

Region (AQCR) a/

Location -

County Site ID No.

CO 1-hr b/ 2 ppm AQCR 213 Cameron 480610006

8-hr b/ 2 ppm AQCR 213 Cameron 480610006

NO2 1-hr b/ 26 ppb AQCR 216 Brazoria 480391016

Annual c/ 3 ppb AQCR 216 Brazoria 480391016

Ozone 8-hr d/ 0.071 ppm AQCR 214 Nueces 483550025

PM2.5 24-hr e/ 26 μg/m3AQCR 214 Nueces 483550034

Annual c/ 9.4 μg/m3AQCR 214 Nueces 483550034

PM10 24-hr b/ 67 μg/m3AQCR 214 Nueces 483550034

SO2 1-hr b/ 52 ppb AQCR 214 Nueces 483550032

3-hr b/ NA NA AQCR 214 Nueces NA

______________________

μg/m3 =micrograms per cubic meter;ppm =parts per million;ppb =parts per billion

NA =Data not available

a/ AQCRs:

AQCR 213: Brownsville-Laredo Intrastate

AQCR 216: Metropolitan Houston-Galveston Intrastate

AQCR 214: Corpus Christi-Victoria Intrastate

b/ Maximum of the 2nd highest measurements recorded in 2009, 2010, and 2011

c/ Maximum annual average measurement recorded for 2009, 2010, and 2011

d/ Average of the annual 4th highest 8-hour average measurements recorded during the years 2009, 2010, and 2011

e/ Maximum of the 98th percentile measurements recorded during the years 2009, 2010, and 2011

A review of the 2012 ambient monitoring data in the TCEQ Air Quality Data database

(TCEQ, 2013)shows that, except for PM2.5 (annual average), the measured concentrations for all

pollutants for the various averaging periods are either at or below the values shown in

table 4.11-2. For PM2.5, the annual average concentration for 2012 was 9.6 μg/m3, which was

slightly higher than the annual average concentration (for 2009and 2010)shown in table 4.11-2.

4.11.1.3 RegulatoryRequirements for Air Quality

The Project would be potentially subject to a variety of federal and state regulations

pertaining to the construction or operation of air emission sources. The TCEQ has the primary

jurisdiction over air emissions produced by stationary sources associated with the Project. The

TCEQ is delegated by the EPA to implement Federal air programs, with the exception of issuing

permits for GHG emissions. However, on February 18, 2014, EPA issued a proposed

rulemaking approving Texas' GHG permitting program. In anticipation of a final rulemaking,

EPA has offered applicants who are currently in the permitting process with EPA the choice of

continuing the permitting process with EPA, or moving their applications to the TCEQ. For

those applicants who transition to the TCEQ, the process will restart with a new public notice

period. Although Texas' GHG permitting program is not finalized, TCEQ has begun accepting
Environmental Impact Statement 4-97 Corpus Christi LNG

applications. If a final rulemaking fails to occur, applicants would have the opportunity to return

back to EPA for federal permitting at the point in the application process where EPA left off.

The following sections summarize the applicability of various state and federal regulations.

Federal Air Quality Requirements

The CAA, 42 USC 7401 et seq., as amended in 1977 and 1990, and 40 CFR Parts 50

through 99are the basic federal statutes and regulations governing air pollution in the U.S. The

following federal requirements have been reviewed for applicability to the Project.

 New Source Review (NSR)/ Prevention of Significant Deterioration;

 Title V Operating Permits;

 New Source Performance Standards (NSPS);

 National Emission Standards for Hazardous Air Pollutants (NESHAP);

 Greenhouse Gas Reporting;

 Chemical Accident Prevention Provisions;and

 General Conformity.

New Source Review/Prevention of Significant Deterioration

Separate preconstruction review procedures for major new sources of air pollution (and

major modifications of major sources)have been established for projects that are proposed to be

built in attainment areas versus nonattainment areas. The preconstruction permit program for

new or modified major sources located in attainment areas is called PSD. This review process is

intended to keep new air emission sources from causing existing air quality to deteriorate beyond

acceptable levels codified in the federal regulations. Construction of major new stationary

sources in nonattainment areas must be reviewed in accordance with the nonattainment NSR

regulations, which contain stricter thresholds and requirements. Because all of the stationary

emission sources at the Project facilities (the Terminal, the Sinton Compressor Station, and the

Taft Compressor Station)are all located within an attainment area, nonattainment NSR does not

apply. Rather, each facility must be reviewed to determine applicability with the PSD program.

The PSD rule defines a major stationary source as any source with a potential to emit

(PTE)100 tons per year (tpy)or more of any criteria pollutant for source categories listed in

40 CFR §52.21(b)(1)(i)or 250 tpy or more of any criteria pollutant for source categories that are

not listed. In addition, with respect to GHG, the major source threshold CO2e is 100,000 tpy. If

a new source is determined to be a major source for any PSD pollutant, then other remaining

criteria pollutants would be subject to PSD review if those pollutants are emitted at rates that

exceed significant emission thresholds (100 tpy for CO;40 tpy for nitrogen oxides [NOx], VOC,

and SO2 each;25 tpy for total suspended particulate, 15 tpy for PM10, and 10 tpy for [direct]

PM2.5). Sources which exceed the major source threshold are then subject to a PSD review.

The three facilities associated with the Project are all evaluated separately for purposes of

PSD applicability. As shown in table 4.11-7, the Terminal is subject to PSD review for NOx,

VOC, CO, PM10, PM2.5, and CO2e. As shown in table 4.11-13, the Sinton Compressor Station is

subject to PSD review for NOx, CO, PM10, PM2.5, and CO2e. The Taft Compressor Station is not

subject to PSD review.

The PSD GHG Tailoring Rule intends to account for facilities that represent an estimated

70 percent of GHG emissions. This rule applies to all industrial sources that are major sources of
Environmental Impact Statement 4-98 Corpus Christi LNG

any NSR-regulated pollutant other than GHGs and emit or have the potential to emit 75,000 tpy

or more of CO2e.

Major new stationary sources applying for a PSD construction permit must include a Best

Available Control Technology (BACT)analysis and a detailed air quality impacts analysis in its

permit application. As part of the air quality impacts analysis, the applicant must demonstrate

that the proposed facilities would comply with applicable NAAQS.

One additional factor considered in the PSD permit review process is the potential

impacts on protected Class I areas. Class I areas were designated specifically as pristine natural

areas or areas of natural significance and have the lowest increment of permissible deterioration,

which precludes development near these areas. Class I areas are given special protection under

the PSD program. However, as described in section 4.11.1.4, because of the distance to the

nearest Class I area, and the quantity of emissions predicted from the Project, a Class I analysis

is not required for the Project.

The TCEQ issued a draft PSD permit for the Terminal's criteria pollutants on July 8,

2013. The TCEQ issued a final PSD permit for the Sinton Compressor Station's criteria

pollutants on December 20, 2013. The Terminal and Sinton Compressor Station began GHG

permitting with the EPA prior to the February 18, 2014 rulemaking. The EPA issued a draft

GHG permit for the Sinton Compressor Station on February 6, 2014, and the Terminal on

February 27, 2014. On April 14, 2014, Cheniere notified EPA and TCEQ that it was selecting

TCEQ as its GHG permitting authority for the Terminal and would be transitioning its GHG

permit application. Cheniere also filed additional information indicating that it made no changes

to the Terminal or BACT analysis upon submission to the TCEQ.

Title V Operating Permits

Title V of the CAA requires states to establish an air quality operating permit program.

The requirements of Title V are outlined in the federal regulations in 40 CFR Part 70 and in

30 TAC §122. The operating permits required by these regulations are often referred to as

Title V or Part 70 permits.

Major sources (i.e., sources with a PTE greater than a major source threshold level)are

required to obtain a Title V operating permit. Title V major source threshold levels are 100 tpy

for CO, SO2, PM10, or PM2.5, 10 tpy for an individual hazardous air pollutant (HAP), or 25 tpy

for any combination of HAPs. The recent Title V GHG Tailoring Rule also requires facilities

that have the potential to emit GHGs at a threshold level of 100,000 tpy CO2e be subject to Title

V permitting requirements.

Both the Terminal and Sinton Compressor Station would be subject to the Title V

program. The Terminal exceeds the major source thresholds for NOx, CO, VOC, HAPs and

GHGs. For the Sinton Compressor Station, emissions of NOx, CO and GHGs are greater than

the major source thresholds. Therefore, the Terminal and Sinton Compressor Station would need

to apply for and obtain Title V operating permits. The Taft Compressor Station does not qualify

as a major source under Part 70.

Cheniere submitted Title V operating permit applications for the Terminal and Sinton

Compressor Station to the TCEQ in November 2012, which are still under review.
Environmental Impact Statement 4-99 Corpus Christi LNG

New Source Performance Standards

NSPS regulations (40 CFR Part 60)establish pollutant emission limits and monitoring,

reporting, and recordkeeping requirements for various emission sources based on source type

and size. These regulations apply to new, modified, or reconstructed sources. The following

NSPS requirements were identified as potentially applicable to the specified sources at the

Terminal and Sinton and Taft compressor stations.

Subpart KKKK of 40 CFR Part 60, Standards of Performance for Stationary Combustion

Turbines, applies to stationary combustion turbines that are modified, constructed, or

reconstructed after February 18, 2005 and have maximum heat input rates greater than 10

MMBtu per hour. Turbines subject to this subpart are exempt from 40 CFR Part 60, Subpart GG

emission standards for turbines. Subpart KKKK applies to the 18 natural gas-fuel turbines used

to drive refrigeration compressors at the Terminal. Subpart KKKK also applies to the two

natural gas-fired turbines at both the Sinton Compressor Station and the Taft Compressor

Station, which are used to compress natural gas for onward transport through the pipeline.

Subpart KKKK regulates emissions of SO2 and NOx. One method of complying with the SO2

emission limit is to not burn any fuel in the turbine which contains total potential sulfur

emissions in excess of 26 nanograms (ng)SO2 per joule (/J)(0.060 pounds [lb]SO2 /MMBtu)

heat input. The turbines would be fueled by natural gas or boil-off gas and therefore would

comply with the fuel sulfur content requirement. Based on the size of the turbines, NOx

emissions must be limited to 25 ppm by volume at 15 percent oxygen (O2)or 1.2 lb per

megawatt-hour (lb/MWh). Refrigeration turbines located at the Terminal would utilize water

injection for NOx emission control. The turbines located at the compressor stations would not

employ water or steam injection to control NOx emission, and therefore annual performance

testing would be conducted to demonstrate continuous compliance. As an alternative to

performance testing, continuous parameter monitoring for each turbine may be conducted to

demonstrate that the units are operating in low-NOx mode.

Subpart Kb of 40 CFR Part 60, Standards of Performance for Volatile Organic Liquid

Storage Vessels, applies to storage vessels containing volatile organic liquids. Regulatory

applicability is dependent on the construction date, size, vapor pressure, and contents of the

storage vessel. Subpart Kb applies to new tanks, unless otherwise exempted, that have a storage

capacity between 75 m3 (19,813 gallons)and 151 m3 (39,890 gallons)and contain VOCs with a

maximum true vapor pressure greater than or equal to 15.0 kilopascals (kPa). Subpart Kb also

applies to tanks that have a storage capacity greater than or equal to 151 m3and contain VOCs

with a maximum true vapor pressure greater than or equal to 3.5 kPa. Pressure tanks are exempt

from the requirements of Subpart Kb.

There are storage tanks for propane and ethylene refrigerants located at the Terminal;

however, these storage tanks are exempt because they qualify as pressure vessels designed to

operate in excess of 204.9kPa and without emissions to the atmosphere. The three LNG storage

tanks would have a capacity of 160,000 m3, which would meet the volume criteria for Subpart

Kb. The LNG is considered a volatile organic liquid because a small portion of the LNG would

consist of VOCs. The LNG storage tank would operate at approximately -260°F and the true

vapor pressure of the VOC (assumed to be propane)at this temperature is 0.0007 kPa. This

would be well below the applicability threshold of 3.5 kPa;therefore, Subpart Kb would not

apply to the LNG storage tanks. There is one condensate storage tank at the Terminal that stores

VOCs and has a capacity greater than 75 m3. However, this tank is subject to the requirements
Environmental Impact Statement 4-100 Corpus Christi LNG

of 40 CFR Part 63, Subpart EEEE and therefore is not subject to Subpart Kb. Additionally, there

are eight diesel fixed-roof storage tanks and one gasoline fixed-roof storage tank located at the

Terminal. The tanks each have a capacity less than 75 m3, and therefore are exempt from

Subpart Kb based on size. Both the Sinton and Taft compressor stations have condensate tanks

with volumes less than 75 m3, thus exempting the tanks from Subpart Kb.

Subpart JJJJ of 40 CFR Part 60, Standards of Performance for Stationary Spark Ignition

Internal Combustion Engines, applies to spark ignition engines with a maximum engine power

greater than 25 hp for which construction commenced by July 12, 2006 and was manufactured

after January 1, 2009. The 1,328-brake-hp natural gas-fired generator at the Sinton Compressor

Station and the 838-brake-hp natural gas-fired generator at the Taft Compressor Station, to be

used for standby electricity generation to power the facilities, meet these applicability criteria

and are therefore subject to the requirements of Subpart JJJJ. In order to demonstrate

compliance with the emission limits found in the rule, owners and operators may either operate a

manufacturer-certified engine according to manufacturer’s operation and maintenance

procedures or conduct performance testing. Owners/operators of emergency engines are

required to keep records of their hours of operation. Additionally, maintenance records must be

kept for all engines.

Subpart IIII of 40 CFR Part 60, Standards of Performance for Stationary Compression

Ignition Internal Combustion Engines, applies to diesel-fueled stationary compression ignition

internal combustion engines of any size that are constructed, modified, or reconstructed after

July 11, 2005. The rule requires manufacturers of these engines to meet emission standards

based on engine size, model year, and end use. The rule also requires owners and operators to

configure, operate, and maintain the engines according to specifications and instructions

provided by the engine manufacturer. These requirements of Subpart IIII would apply to the

three 422-brake-hp diesel-fired fire water pump engines and the four 2,220-brake-hp diesel-fired

standby generators located at the Terminal. The recordkeeping and reporting requirements

would also apply.

Subpart OOOO of 40 CFR Part 60, Standards of Performance for Crude Oil and Natural

Gas Production, Transmissions and Distributions, applies in part to compressors that are located

between the wellhead and point of custody transfer. The Sinton and Taft compressor stations are

not located between the wellhead and the point of custody transfer and therefore are not subject

to Subpart OOOO.

National Emission Standards for Hazardous Air Pollutants

The NESHAP codified in 40 CFR Parts 61 and 63, regulate HAP emissions. Part 61 was

promulgated prior to the 1990 Clean Air Act Amendments (CAAA)and regulates specific HAPs,

such as asbestos, benzene, beryllium, coke oven emissions, inorganic arsenic, mercury,

radionuclides, and vinyl chloride.

The 1990 CAAA established a list of 189 HAPs, while directing EPA to publish

categories of major sources and area sources of these HAPs, for which emission standards were

to be promulgated according to a schedule outlined in the CAAA. These standards, also known

as the Maximum Achievable Control Technology (MACT)standards, were promulgated under

Part 63. The 1990 CAAA defines a major source of HAPs as any source that has a PTE of

10 tpy for any single HAP or 25 tpy for all HAPs in aggregate. Area sources are stationary
Environmental Impact Statement 4-101 Corpus Christi LNG

sources that do not exceed the thresholds for major source designation. Federal NESHAP

requirements are incorporated by reference in 30 TAC §113.55 and §113.00.

The annual PTE HAP emissions from the Terminal would be 24.2 tpy in aggregate and

16 tpy for formaldehyde (the individual HAP with the greatest PTE)(see section 4.11.1.4);

therefore, the Terminal would be a major source of HAPs. Although an LNG storage and

process facility is not one of the source categories regulated under Part 63, NESHAP/MACT

standards could still apply for specific types of sources (i.e., stationary combustion turbines)that

support facility operations. The annual PTE all-HAP emissions from the Sinton Compressor

Station and Taft Compressor Station are 4.1 tpy and 1.5 tpy, respectively (see section 4.11.1.4);

therefore, each station is classified as an area source of HAPs. The NESHAP described in the

following paragraphs have been identified as being potentially applicable to specific sources at

the Terminal and Sinton and Taft Compressor Stations.

Subpart Y of 40 CFR Part 63, National Emission Standards for Marine Tank Vessel

Loading Operations, applies to marine vessel loading operations at facilities that are considered

major sources of HAPs. Because the marine tank vessel loading operations at the Terminal

would occur at loading berths that only transfer liquids containing organic HAPs as impurities,

as that term is defined in 40 CFR §63.561, the Terminal is exempt from Subpart Y [40 CFR

§63.560(d)(5)].

Subpart EEEE of 40 CFR Part 63, NESHAP for Organic Liquids Distribution (NonGasoline), applies to owners and operators of organic liquid distribution operations located at a

major source of HAP emissions. The condensate storage tank and condensate loading operation

at the Terminal are subject to the requirements of this rule. The Terminal would need to comply

with the operating limitations, requirements for initial compliance demonstrations, and other

applicable requirements under Subpart EEEE.

Subpart YYYY of 40 CFR Part 63, NESHAP for Stationary Combustion Turbines,

applies to owners and operators of stationary combustion turbines located at a major source of

HAP emissions. The GE LM2500+G4 combustion turbines at the Terminal meet the definition

of a lean premix gas-fired stationary combustion turbine as defined under this subpart, and

therefore would potentially be subject to an emission limitation for formaldehyde of 91 parts per

billion (ppb)by volume, at 15 percent O2. The Terminal is a major source of HAPs and would

be required to comply with the operating limitations, requirements for performance test and

initial compliance demonstrations, and reporting requirements under Subpart YYYY.

Subpart CCCCCC of 40 CFR Part 63, NESHAP for Gasoline Dispensing Facilities,

applies to the loading of gasoline storage tanks at an area source of HAP emissions. The

Terminal is a major source of HAPs;therefore, Subpart CCCCCC would not apply to the loading

of the gasoline storage tank at the Terminal. The Sinton and Taft Compressor Stations would not

be equipped with gasoline storage tanks.

Subpart ZZZZ of 40 CFR Part 63, NESHAP for Stationary Reciprocating Internal

Combustion Engines, applies to reciprocating internal combustion engines of all sizes located at

major and area sources of HAPs. The Terminal is a major source of HAPs and would have four

diesel-fired standby generators each rated at 2,220 brake-hp;therefore, these generators (each of

which would operate less than 100 hours per year)are subject only to the initial notification

requirement of Subpart ZZZZ. As discussed previously, the three 422-brake-hp diesel-fired fire

water pumps at the Terminal would be required to comply with the requirements of 40 CFR Part
Environmental Impact Statement 4-102 Corpus Christi LNG

60, Subpart IIII. These engines satisfy the requirements of Subpart ZZZZ by meeting the

requirements of 40 CFR Part 60, Subpart IIII, per 40 CFR §63.6590(c)(6).

The Sinton and Taft compressor stations are classified as area sources of HAPs. The

standby generators at these facilities are considered a new emergency reciprocating internal

combustion engine at an area source and, as discussed previously, would be required to comply

with the requirements of 40 CFR Part 60 Subpart JJJJ. These engines satisfy the requirements of

Subpart ZZZZ by meeting the requirements of 40 CFR Part 60, Subpart JJJJ, per 40 CFR

§63.6590(c)(1).

Greenhouse Gas Reporting Rule

Subpart W under 40 CFR Part 98, the Mandatory Greenhouse Gas Reporting Rule,

requires petroleum and natural gas systems that emit 25,000 metric tons or more of CO2e per

year to report annual emissions of GHG to the EPA. “LNG storage”and “LNG import and

export equipment”’are industry segments specially included in the source category definition of

petroleum and natural gas systems. Equipment subject to reporting includes storage of LNG,

regasification of LNG and liquefaction of natural gas.

Emissions of GHGs associated with the construction and operation of the Project,

including all direct and indirect emission sources were calculated. In addition, GHG emissions

were converted to total CO2e emissions based on the GWP of each pollutant. The reporting rule

does not apply to construction emissions;however, we have included the construction emissions

for accounting and disclosure purposes. GHG emissions from operation of the Terminal, the

Sinton Compressor Station and the Taft Compressor Station are each anticipated to exceed the

25,000 metric ton threshold and therefore may be subject to the reporting rule. If actual GHG

emissions from the Terminal or compressor stations are equal to or greater than the reporting

threshold, Cheniere would need to comply with all applicable requirements of 40 CFR Part 98.

Chemical Accident Prevention Provisions

The chemical accident prevention provisions, codified in 40 CFR Part 68, are federal

regulations designed to prevent the release of hazardous materials in the event of an accident and

minimize potential impacts if a release does occur. The regulations contain a list of substances

(including methane, propane, and ethylene)and threshold quantities for determining applicability

to stationary sources. If a stationary source stores, handles, or processes one or more substances

on this list in a quantity equal to or greater than specified in the regulation, the facility must

prepare and submit a risk management plan. A risk management plan is not required to be

submitted to the EPA until the chemicals are stored onsite at the facility.

If a facility does not have a listed substance on-site, or the quantity of a listed substance is

below the applicability threshold, the facility does not have to prepare an RMP. However, if

there is any regulated substance or other extremely hazardous substance onsite, the facility still

must comply with the requirements of the General Duty Clause in Section 112(r)(1)of the 1990

CAAA. The General Duty Clause is as follows:

“The owners and operators of stationary sources producing, processing, handling

and storing such substances have a general duty to identify hazards which may result from

such releases using appropriate hazard assessment techniques, to design and maintain a

safe facility, taking such steps as are necessary to prevent releases, and to minimize the

consequences of accidental releases which do occur.”
Environmental Impact Statement 4-103 Corpus Christi LNG

Stationary sources are defined in 40 CFR Part 68 as any buildings, structures, equipment,

installations, or substance-emitting stationary activities which belong to the same industrial

group, that are located on one or more contiguous properties, are under control of the same

person (or persons under common control), and are from which an accidental release may occur.

The Terminal would store about 514,037,299pounds of methane as LNG, 1,956,793 pounds of

propane, and 1,007,181 pounds of ethylene on site. However, the definition also states that the

term stationary source does not apply to transportation, including storage incidental to

transportation, of any regulated substance or any other extremely hazardous substance. The term

transportation includes transportation subject to oversight or regulation under 49CFR Parts 192,

193, or 195. Based on these definitions, the Terminal, which is subject to 49CFR Part 193,

would not be required to prepare an risk management plan. We have included an analysis of the

proposed design’s compliance with Part 193, including overpressure modeling, in section 4.12 of

this EIS.

General Conformity

A conformity analysis must be conducted by the lead federal agency if a federal action

would result in the generation of emissions that would exceed the conformity threshold levels (de

minimis) of the pollutants(s) for which an AQCR is in nonattainment. According to

Section 176(c)(1)of the CAA (40 CFR §51.853), a federal agency cannot approve or support any

activity that does not conform to an approved SIP. Conforming activities or actions should not,

through additional air pollutant emissions:

 Cause or contribute to new violations of the NAAQS in any area;

 Increase the frequency or severity of an existing violation of any NAAQS;or

 Delay timely attainment of any NAAQS or interim emission reductions.

General Conformity assessments must be completed when the total direct and indirect

emissions of a planned project would equal or exceed the specified pollutant conformity

emission thresholds per year in each nonattainment area.

A General Conformity Determination must show that the emissions would conform to the

applicable SIP and would not degrade air quality in the nonattainment area. This can be

demonstrated through acquisition of emission offsets, SIP revisions, or dispersion modeling.

On-site mitigation of emissions, (i.e., controls above and beyond what is required by regulation),

can also be used to demonstrate conformity. According to 40 CFR §51.853, emissions from

sources subject to NSR or PSD requirements are exempt and are deemed to have conformed.

As discussed in a previous section of this report, the Project facilities (Terminal and

Sinton and Taft Compressor Stations)are located in an area currently designated by EPA as

better than national standards or unclassifiable or in attainment for all criteria pollutants.

Operating emissions for these facilities would be located entirely within designated

unclassifiable/attainment areas for all criteria air pollutants and would be subject to evaluation

under the PSD permitting program;therefore, these emissions are not subject to General

Conformity regulations. However, during the construction phase of the Project, barges carrying

equipment and materials would travel periodically from the Port of Houston to the Project

construction dock via the GIWW during the 2014 to 2017 period. Specifically, one barge in

2014 and approximately six barges per year in 2015, 2016, and 2017 would travel from the Port

of Houston to the construction dock. The Port of Houston is located in the Houston-GalvestonBrazoria (HGB)“severe”ozone nonattainment area (1997 8-hr NAAQS);therefore, each barge
Environmental Impact Statement 4-104 Corpus Christi LNG

would spend part of its trip within the HGB ozone nonattainment area. The construction barge

traffic emissions associated with travel in the HGB ozone nonattainment area would be subject to

evaluation under General Conformity regulations.

The relevant general conformity pollutant thresholds for the HGB ozone nonattainment

area are 25 tpy of NOx and VOC (ozone precursors)for the portions of the Project located in the

nonattainment area.

Cheniere estimated emissions from tug vessels that push the barges using the

methodology and emission factors described in EPA’s Current Methodologies in Preparing

Mobile Source Port-Related Emission Inventories (ICF International, 2009). The emissions were

apportioned between the HGB ozone nonattainment area and the adjacent

unclassifiable/attainment areas based on the emissions generated during the time spent traveling

through each of these areas.

Cheniere estimated that the total potential direct and indirect emissions of NOx and VOC

from the Project construction-related activity (i.e., construction barge travel in HGB ozone

nonattainment area)would be less than 25 tpy for each year of the construction period (2014 to

2017), as shown in table 4.11-3. Based on these emissions, a General Conformity Determination

is not required for the Project.

Table 4.11-3

Construction Barge NOx and VOC Emissions Subject to Evaluation for General Conformity

Pollutant

Annual Emissions (tpy)

2014 2015 2016 2017

NOx 0.64 3.85 3.85 3.85

VOC 0.02 0.14 0.14 0.14

Applicable State Air Quality Requirements

In addition to the federal regulations identified above, the TCEQ has its own air quality

regulations, codified in 30 TAC. The state requirements potentially applicable to the Project are

discussed below.

 30 TAC Chapter 101, Subchapter A –General Rules. This chapter includes provisions

related to circumvention, nuisance, traffic hazards, sampling and sampling ports,

emissions inventory requirements, sampling procedures and terminology, compliance

with EPA standards, inspection and emission fees, and emission events and scheduled

maintenance, startup, and shutdown activities.

 30 TAC Chapter 111 –Control of Air Pollution from Visible Emissions and Particulate

Matter. This chapter outlines the allowable visible emission (i.e., opacity)requirements

and total suspended particulate emission limits based on calculated emission rates.

 30 TAC Chapter 112 –Control of Air Pollution from Sulfur Compounds. This chapter

outlines emission limits and monitoring, reporting, and recordkeeping requirements. This

chapter also lists net ground-level concentration standards at the property line for certain

sulfur compounds.
Environmental Impact Statement 4-105 Corpus Christi LNG

 30 TAC Chapter 113 – Control of Air Pollution from Toxic Materials. Chapter 113

incorporates by reference the NESHAP source categories (40 CFR Part 63).

 30 TAC Chapter 114 – Control of Air Pollution from Motor Vehicles. This chapter

addresses inspection requirements and maintenance and operation of air pollution control

systems/devices for motor vehicles owned and/or operated at the Project facilities. This

chapter applies to use of construction- and operations-related vehicles.

 30 TAC Chapter 115 –Control of Air Pollution from Volatile Organic Compounds. This

chapter outlines applicable requirements for storage tanks, process vents, and loading

operations, including the standards and recordkeeping and reporting requirements.

 30 TAC Chapter 116, Subchapter B – Control of Air Pollution by Permits for New

Construction or Modification. This chapter outlines the permitting requirements for the

construction of new sources. Unlike the Terminal and Sinton Compressor Station, the

Taft Compressor Station construction and operation would be authorized by the TCEQ

Standard Permit for Installation and/or Modification of Oil and Gas Facilities, per 30

TAC §116.620. Cheniere intends to apply for the Standard Permit at a date closer in time

to the anticipated construction date for the Taft Compressor Station.

 30 TAC Chapter 118 –Control of Air Pollution Episodes. This chapter outlines the

requirements relating to generalized and localized air pollution episodes.

 30 TAC Chapter 122 – Federal Operating Permits. This chapter outlines the

requirements for complying with the Federal operating permits program.

4.11.1.4 Construction Emissions and Mitigation

Construction of the Terminal, Sinton and Taft Compressor Stations, and Pipeline

facilities would result in short-term increases in emissions of some air pollutants due to the use

of equipment powered by diesel fuel or gasoline engines and the generation of fugitive dust due

to the disturbance of soil and other dust-generating activities. More specifically, the construction

activities that would generate air emissions include:

 Site preparation (vegetation clearing, trenching, land contouring, foundation preparation,

etc.);

 Installation of Terminal equipment;

 Installation of compressor stations equipment;

 Installation of pipeline and pipeline interconnection equipment;

 Operation of off-road vehicles and trucks during construction;

 Operation of marine vessels (e.g., equipment barges)during construction;

 Offshore dredging;and

 Workers’vehicles used for commuting to and from the construction site (i.e., on-road

vehicles).

The total period of construction for the Terminal is estimated by Cheniere to be

60 months. The emission increases associated with the Project construction activities would

have short-term, localized impacts on air quality. These emissions are not subject to the air

quality permitting requirements that apply to emissions from operation of stationary sources at

the Terminal and compressor stations. We note that there are no residential or sensitive
Environmental Impact Statement 4-106 Corpus Christi LNG

populations within 1 mile of the Terminal site. Nevertheless, the construction-related emission

rates are discussed in this section as a means of identifying potential air quality concerns

associated with the construction phase of the Project and to assist in developing mitigation.

The amount of fugitive dust for an area under construction would depend on numerous

factors including: degree of vehicular traffic;size of area disturbed, amount of exposed soil, soil

properties (silt and moisture content);and wind speed. Construction of the Project would also

result in fuel combustion emissions from a variety of sources, including off-road sources (e.g.,

bulldozers, cranes, front-end loaders, pile drivers), on-road sources (e.g., construction worker

vehicles), and marine vessels (e.g., tugs, barges).

Site preparation activities for the Terminal, compressor stations, and M&R stations

would include grading, cutting of drainage ditches, placement of gravel surfaces (e.g., lay-down

areas), and construction of access roads within the Project site boundaries. Site preparation

activities would generate fugitive dust from earthmoving and movement of construction

equipment over unpaved surfaces and tailpipe emissions from construction equipment and

vehicle engines. The construction equipment and vehicles would be powered by internal

combustion engines that would generate PM10, PM2.5, SO2, NOx, VOC, and CO emissions. Site

preparation equipment would include bulldozers, front-end loaders, backhoes, compactors,

scrapers, dump trucks, and other mobile construction equipment.

The construction of the Terminal would include installation of three liquefaction trains,

three LNG storage tanks, LNG vaporization and natural gas send-out facilities, LNG carrier

berths and LNG transfer lines, major mechanical equipment, and piping and instrumentation, as

well as construction of foundations, pipe racks, miscellaneous storage tanks, and buildings. The

Terminal construction equipment would include cranes, forklifts, pile drivers, welders, concrete

pump trucks, and generators (for various duties, such as pumping, lighting, etc.), which would

result in fuel combustion and fugitive dust emissions.

The Project would include off-shore dredging of the LNG carrier berthing area at the

Terminal. The emissions generated by these activities would be predominantly combustion

emissions from the construction equipment and marine vessel engines. The construction

equipment would include a clam shell dredge, tugboats, survey/workboats, crew boats,

inspection vessels, and trucks.

Air emissions would also be generated during construction of the Pipeline. Pipeline site

preparation and construction activities would generate fugitive dust from clearing, trenching,

backfilling, grading, and traffic on paved and unpaved areas, as well as fuel combustion

emissions from the construction equipment. The internal combustion engines powering most of

the Pipeline construction equipment and vehicles would burn ultra-low-sulfur diesel fuel and the

remaining vehicles would burn gasoline. Equipment that would be used for the Pipeline

construction activities would include various earthmoving equipment (bulldozers, backhoes,

trenchers, graders, and compactors), cranes, forklifts, compressors, pumps, trenchers, stringing

trucks, welding rigs, generators, and miscellaneous trucks.

The construction of the Sinton and Taft Compressor Stations would include installation

of two compressor turbines at each station, major mechanical equipment, and piping and

instrumentation, as well as construction of foundations, miscellaneous storage tanks, and

buildings. The construction equipment would include cranes, forklifts, welders, pumps, and

generators, which would result in fuel combustion and fugitive dust emissions.
Environmental Impact Statement 4-107 Corpus Christi LNG

Site truck traffic (e.g., supply trucks)and worker commuter vehicles would generate

fugitive dust from travel on paved and unpaved surfaces as well as tailpipe emissions. The

Terminal construction would require an average of approximately 1,800 workers over a period of

approximately 60 months. The Pipeline construction would require approximately 300 workers

over a period of approximately nine months. Most of the commuter vehicles would likely burn

gasoline, although supply trucks and some worker pickup trucks would burn ultra-low-sulfur

diesel fuel.

Fuel combustion emissions from off-road construction equipment and on-road vehicles

(e.g., for commuter workers)were based on EPA emission factors. SO2 emissions would be

further mitigated by the use of ultra-low-sulfur diesel. In addition, vehicle emissions would be

minimized through compliance with 30 TAC Chapter 114 –Control of Air Pollution from Motor

Vehicles. Fugitive dust emissions generated by on-site construction equipment were based on

emission factors developed by the Western Regional Air Partnership (WRAP Fugitive Dust

Handbook). Fugitive dust emission estimates associated with construction activities for the

Project assume a dust suppressant control efficiency of 50 percent. The total criteria air pollutant

and GHG (as CO2e)emissions associated with construction-related activities for the Terminal are

summarized in table 4.11-4. The total criteria air pollutant and GHG (as CO2e)emissions

associated with construction-related activities for the Pipeline, compressor stations, and M&R

facilities are summarized in table 4.11-5. These totals include fuel combustion emissions as well

as fugitive PM emissions. For fuel combustion emissions from non-road and on-road engines,

nearly all emitted PM is assumed to be PM2.5.

Table 4.11-4

Total Construction Emissions by Year Associated with the Terminal

Year

Annual Emissions (tpy)

NOx VOC CO SO2 PM10 PM2.5 CO2e a/

2014 1,341.0 144.0 1,186.0 38.7 67.8 67.8 119,728

2015 2,588.3 235.3 1,557.3 66.7 116.5 116.4 148,341

2016 1,271.4 138.7 1,156.4 35.0 64.6 64.6 115,264

2017 793.9 106.2 974.3 23.9 39.2 39.1 91,924

2018 669.8 98.0 929.2 15.4 32.2 32.2 86,046

2019 61.2 4.2 23.4 1.4 3.3 3.3 2,993.1

Total Emissions from Fuel

Combustion b/ 6,726 726 5,827 181 324 323 564,296

Total Fugitive Dust Emissions 2,993 318

Total PM Emissions for Construction Period 3,317 641

______________________

a/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

b/ Emissions from dredge transfer pump included in Year 2015 emissions
Environmental Impact Statement 4-108 Corpus Christi LNG

Table 4.11-5

Total Construction Emissions Associated with the Pipeline and M&R Facility Areas a/, b/

Sub-Project

Annual Emissions (tpy) c/

NOx VOC CO SO2 PM10 PM2.5 CO2e d/

Pipeline 64.7 8.5 90.7 0.22 178.1 e/ 22.1 e/ 19,201

M&R Facility Areas 28.0 6.7 132.0 0.18 28.0 f/ 4.4 f/ 8,597

______________________

a/ M&R facility areas include the Sinton and Taft Compressor Stations

b/ Includes emissions from fuel combustion in non-road construction equipment and on-road worker commuter vehicles

c/ Emissions are projected by Cheniere to occur in calendar year 2016

d/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

e/ Includes fugitive dust emissions of 174.1 tpy PM10 and 18.2 tpy PM2.5

f/ Includes fugitive dust emissions of 26.4 tpy PM10 and 2.8 tpy PM2.5

As shown in table 4.11-4, the fugitive dust accounts for the majority of PM emissions

during the construction period for the Terminal. Cheniere developed a Fugitive Dust Control

Plan (FDCP)to mitigate these emissions (see appendix D). Measures outlined in the FDCP

include the following:

 use of a dedicated water truck to apply water to heavily used unpaved areas, as needed;

 ensure that dump trucks and other open-bodied trucks hauling soil or other dusty

materials to or from the Project site are covered, as needed;

 use of signage to direct construction vehicle traffic to designated (paved or gravel)roads

when practical;and

 enforcing a 15-mph speed limit on unsurfaced roads.

We, and the EPA, have reviewed the FDCP and believe it does not adequately address

track-out onto paved roads. Therefore, we recommend that:

 Prior to construction,Cheniere should file a revised FDCP with the Secretaryfor

review and written approval from the Director of OEP. The revised FDCP should

include the following:

a. the use of gravel at construction entrance and exit locations;and

b. measures to clean paved roads upon mud or dirt trackout.

Emissions over the 60-month construction period would increase pollutant concentrations

in the vicinity of the Project;however, their effect on ambient air quality would vary with time

due to the construction schedule, the mobility of the sources, and the variety of emission sources.

Construction emissions associated with the Pipeline are considered temporary and would cease at

completion of construction. Construction emissions associated with the compressor stations are

considered temporary, but would transition to permanent operational-phase emissions.

Construction emissions at the Terminal would occur over a five-year period in one location;

therefore, the associated air quality impacts are considered short-term. In addition, following

construction, air quality would not revert back to previous conditions, but would transition to

operational-phase emissions after commissioning and initial start-up.
Environmental Impact Statement 4-109 Corpus Christi LNG

4.11.1.5 Operating Emissions and Mitigation

Operation of the Terminal would result in air emissions from stationary equipment (e.g.,

refrigerant compressor turbines, flares, oxidizers, and emergency generators)and mobile sources

(e.g., LNG carriers and tugs). Also, operation of the Sinton and Taft Compressor Stations would

result in air emissions from stationary equipment (e.g., gas compressor turbines and emergency

generators). Operational-phase emissions from a variety of sources/equipment would be

permanent. These various sources and associated criteria pollutant, GHG, and HAP emission

rates are discussed in detail in the following sections.

Terminal

As discussed earlier, in addition to liquefaction operations, the Terminal would be

equipped to receive LNG and conduct vaporization of stored LNG using two trains of AAV and

pumps, with send-out to customers through the Pipeline. The AAVs provide regasification of the

LNG without requiring combustion, eliminating associated air emissions. This section focuses

on the Terminal emission sources associated with the operating liquefaction process.

The Terminal would operate up to three natural gas liquefaction trains continuously.

Sources of air emissions associated with operation of the Terminal include:

 18 GE LM2500+G4 natural gas-fired combustion turbines or equivalent (43,013 hp each;

six per train);

 Seven diesel-fired engines for emergency use (four standby power generators and three

fire water pumps);

 Five flares (for control of vented organic compound emissions);

 Three thermal oxidizers (for control of acid gas emissions);

 Miscellaneous storage tanks (condensate, gasoline, amine, and distillate/no. 2 oil);

 Maneuvering and hoteling LNG carriers;and

 Fugitive VOC and GHG emission sources (e.g., valves, flanges, connectors, and marine

vessel offloading equipment).

Criteria pollutant emissions of NOx, VOC, CO, PM10, PM2.5, and SO2 would be generated

primarily by the fuel combustion sources at the Terminal. The main emission sources at the

Terminal, the 18 combustion turbines, would be fueled with boil-off (natural)gas.

Table 4.11-6 provides a summary of the estimated annual criteria air pollutant, GHG (as

CO2e), and HAP emission rates for operating stationary sources associated with the Terminal.

The annual emissions are based on continuous operation (8,760 hours per year), except for

standby generators and fire water pumps, which are based on no more than 27 and 52 hours per

year, respectively. As discussed above, the Terminal is a major source under the PSD program

and a major source of HAPs.
Environmental Impact Statement 4-110 Corpus Christi LNG

Table 4.11-6

Annual Emissions Associated with Operation of On-Shore Emission Sources at the Terminal

Emission Source

Annual Emissions (tpy)

NOx VOC CO SO2 PM10 PM2.5 CO2e a/

HAPs

Total

HAPs

Single

HAP

Refgn. Comp. Turbines (18) 2,261 47.4 1,658 24.2 56.4 56.4 2,640,000 23.2 16.0 b/

Flares (5)c/ 28.5 7.4 244.7 0.42 - - 32,700 0.60 0.35 d/

Thermal Oxidizers (3) 18.2 0.43 19.7 8.85 2.71 2.71 589,000 0.36 0.30 d/

Standby Diesel Generators (4) 0.46 0.03 0.07 0.02 0.007 0.007 140 0.002 0.001 e/

Fire Water Pump Engines (3) 0.21 0.005 0.05 0.0004 0.007 0.007 37.7 0.001 0.0006 e/

Storage Tanks - 1.09 - - - - - - -

Fugitives - 29.7 - - - - 19,800 - -

Total Emissions: 2,308 86.1 1,923 33.5 59.1 59.1 3,280,000 24.2 16.0 a/

PSD Signif. Emission Rate f/ 40 40 100 40 15 10 g/ 100,000

Subject to PSD Review Yes Yes Yes No Yes Yes Yes

______________________

a/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

b/ Worst-case individual HAP emissions from the Project are presented for formaldehyde

c/ One marine flare, two wet gas flares, and two dry gas flares (normal operation, including planned MSS activities and ship inert

gas venting)

d/ Worst-case individual HAP emissions from the Project are presented for benzene

e/ Worst-case individual HAP emissions from the Project are presented for propylene

f/ Emissions of other PSD-regulated air pollutants –lead, fluorides, sulfuric acid mist, H2S, total reduced sulfur, and reduced sulfur

compounds –are negligible

g/ 10 tpy of direct PM2.5 emissions;40 tpy of SO2 emissions;40 tpy of NOx emissions unless demonstrated not to be a PM2.5

precursor

Short-term emission rates are considered a separate operating scenario for the Terminal

and are the basis of short-term impact analyses presented in section 4.11.1.6. Table 4.11-7

provides a summary of the estimated short-term (pounds per hour [lb/hr])controlled criteria air

pollutant and HAP emission rates for operating stationary sources associated with the Terminal.
Environmental Impact Statement 4-111 Corpus Christi LNG

Table 4.11-7

Short-Term Emissions Associated with Operation of On-Shore Emission Sources at the Terminal

Emission Source

Short-Term Emissions (lb/hr)

NOx VOC CO SO2 PM10 PM2.5

HAPs

Total

HAPs

Single

HAP

Refgn. Comp. Turbines (18) 516.2 10.8 378.5 5.53 12.9 12.9 5.29 3.66 a/

Flares (5)b/ 401.3 110.4 3,441 4.52 --c/ --c/ 7.74 4.67 d/

Thermal Oxidizers (3) 4.15 0.10 4.50 2.22 0.62 0.62 0.08 0.07 d/

Standby Diesel Generators (4) 37.7 2.05 5.92 1.29 0.54 0.54 0.15 0.10 e/

Fire Water Pump Engines (3) 8.70 0.23 2.06 0.02 0.30 0.29 0.04 0.03 e/

Storage Tanks -- 18.0 -- -- -- -- 0.015 0.010 f/

Fugitives -- 6.78 -- -- -- -- 0.022 0.019 f/

Total Emissions 968 148 3,832 13.6 14.4 14.4

______________________

a/ Highest individual HAP emission rate for this source is for formaldehyde

b/ One marine flare, 2 wet gas flares, and 2 dry gas flares (normal operation, including planned MSS)

c/ Assumed to be zero or negligible based on EPA’s AP-42 emission factor for non-smoking flares of 0 μg/l in exhaust

d/ Highest individual HAP emission rate for this source is for benzene

e/ Highest individual HAP emission rate for this source is for propylene

f/ Highest individual HAP emission rate for this source is for hexane

The TCEQ reviewed and approved Cheniere’s PSD BACT analysis for the Terminal,

including the refrigeration compressor turbines, internal combustion engines (standby

generators), flares, and thermal oxidizers. Methods for reducing emissions of NOx, CO, and

VOCs for each of these sources were evaluated based on technical feasibility. Cheniere would

reduce emissions of NOx from the refrigeration compressor turbines through use of waterinjection and good combustion practices;CO and VOC emissions would be controlled through

the use of good combustion practices. The limited-use standby generators/engines would utilize

good combustion practices and ultra-low-sulfur diesel fuel to reduce emissions, especially PM

and SO2 emissions. Emissions from the flares and thermal oxidizers would be reduced through

good combustion practices. The resulting BACT-based emission rates are equal to or better than

any NSPS, NESHAP, and/or Reasonably Available Control Technology (RACT)emission

standards applicable to the Terminal emission sources.

Once constructed, the Terminal would undergo an initial start-up process before it could

be fully operational. This process would result in larger emissions than under normal operating

conditions and would last approximately one to two months. After initial startup, Cheniere plans

to continuously operate the liquefaction facility, thus limiting start-up/shutdown events to those

associated with periodic routine maintenance or the need to shut down due to equipment

malfunction. Table 4.11-8 summarizes the criteria pollutants, GHGs, and HAP emissions for

initial startup activities.
Environmental Impact Statement 4-112 Corpus Christi LNG

Table 4.11-8

Annual Emissions Associated with Initial Start-Up of the Terminal

Emission Source

Annual Emissions (tpy)

NOx VOC CO SO2 PM10 PM2.5 CO2e a/

HAPs

Total

HAPs

Single

HAP

Terminal Start-Up –

All Sources 574.9 137.7 4,929 6.01 --b/ --b/ 32,900 4.12 c/ 2.35 d/

______________________

a/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

b/ Assumed to be zero or negligible based on EPA’s AP-42 emission factor for non-smoking flares of 0 μg/l in exhaust

c/ Flares emissions

d/ Highest individual HAP emission rate for flares is for benzene

Outside of scheduled routine maintenance events, complete shutdown of the refrigeration

compressors is not anticipated. A routine maintenance shutdown of each LNG train would occur

every three years for turbine engine replacement, amine vessel inspection, and molecular sieve

replacement. The maintenance schedule would be staggered such that one of the three trains per

year would undergo the maintenance activities. When the refrigerant compressors are shut down

for these maintenance events, there would be no need to vent or flare the refrigerants stored in

the equipment;therefore, no additional emissions are anticipated. Higher turbine emissions

during start-up and shutdown are not expected during these infrequent maintenance events.

Flaring emissions would occur during the regularly scheduled maintenance event on an

LNG train. Shutdown of the LNG train would require depressurization of the acid gas removal

unit and dehydration unit. The encompassed feed gas within the system would be pressure

purged to the process flare stack (526,000 lb per 12-hour period). After the maintenance event,

the LNG train would be purged, with a total of approximately 18,343,000 lb of feed gas vented

to the process flare stack over a 72-hour period.

During operation of the Terminal, LNG carriers and supporting marine vessels, namely

tugboats and security vessels, would routinely generate air emissions. Cheniere assessed the

emissions associated with various potential LNG carrier operating scenarios, in terms of engine

duty and fuel type, in determining the highest emissions-generating scenario. All scenarios

assumed a main engine size rating of 30,000 kilowatt, based on available engine data on the

existing fleet of LNG carriers.

Air pollutant emissions from LNG carriers would occur along the entire route from the

open seas to the ships’berth. Air emissions generated during ship transit in offshore areas would

be temporary, transient, and occurring at distances allowing for considerable dispersion before

reaching any sensitive receptors. Therefore, air emissions from ship transit outside the point

where the pilot boards the vessel (which is within state territorial waters)would not be expected

to result in a significant impact on air quality.

Ship emissions are quantified along the entire length of the reduced speed zone (RSZ).

Cheniere’s emission calculations for the LNG carriers transiting through the RSZ are based on

the use of residual oil with a sulfur content of 2.7 percent in the ship’s main engine. This

calculation is conservative in that International Maritime Organization Marine Pollution
Environmental Impact Statement 4-113 Corpus Christi LNG

standards will require the use of oil with a maximum sulfur content of 0.10 percent, effective

January 1, 2015. Therefore, we re-calculated the RSZ emissions based on the use of oil with a

sulfur content of 0.10 percent to more accurately represent main engine emissions.

LNG carrier maneuvering for each LNG carrier call would take place within the security

zone over a four-hour time period (two hours arriving and two hours departing). Cheniere

assumed that three tugboats and one security vessel would be deployed for each ship call. While

the LNG carrier is docked and LNG is being loaded to the ship, emissions would be generated by

hoteling operations on the ship for a 20-hour period. Cheniere examined various on-board power

generating scenarios for the maneuvering and hoteling phase of LNG carrier calls at the

Terminal. Based on projections for the type/class of LNG carriers calling at the Terminal in the

future, Cheniere selected a set of emission rates representative of the anticipated fleet profile.

Emissions may also be generated in the case of the potential future operating scenario whereby

LNG is being offloaded from a docked LNG carrier to the Terminal (i.e., LNG import

operations).

Table 4.11-9presents a summary of the estimated highest annual criteria air pollutant and

GHG (as CO2e)emissions associated with the operation of marine vessels within the security

zone at the Terminal. Marine vessel operations within the security zone would result in

emissions associated with maneuvering and hoteling LNG carriers, and could include emissions

from offloading operations on LNG carriers (under a potential future LNG import operating

scenario). Table 4.11-10 presents a summary of the estimated highest annual criteria air

pollutant and GHG (as CO2e)emissions associated with the operation of marine vessels outside

the security zone. Marine vessel operations outside the security zone would include LNG

carriers traversing the RSZ (i.e., the route between the security zone and pilot boarding zone).

These emissions, which are not subject to review under the PSD program, are based on 300 LNG

carrier calls per year.

Table 4.11-9

Annual Emissions Associated with Operation of Marine Vessels within the Security Zone at the Terminal

Emission Source

Annual Emissions (tpy)

NOx VOC CO SO2 PM10 PM2.5 CO2e a/

Maneuvering and Hoteling by LNG carriers

b/ 20.44 8.06 28.30 3.48 0.19 0.19 1,319

Offloading LNG carriers 36.90 1.07 12.52 0.77 0.44 0.42 1,939

Tug Boat Support 3.49 0.37 9.70 0.082 0.08 0.08 1,380

Security Vessel Support 2.11 0.22 5.85 0.049 0.05 0.05 831.8

Total Emissions (LNG Export) 26.0 8.7 43.9 3.6 0.32 0.32 5,470

Total Emissions (LNG Import) c/ 62.9 9.7 56.4 4.4 0.76 0.74 3,531

______________________

a/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

b/ Includes emissions from operation of main engine (for maneuvering)and auxiliary engines (for maneuvering and hoteling)

c/ LNG import scenario conservatively assumes on-board generator(s)operation for both hoteling and LNG offloading purposes
Environmental Impact Statement 4-114 Corpus Christi LNG

Table 4.11-10

Annual Emissions Associated with Operation of Marine Vessels Outside the Security Zone

Emission Source

Annual Emissions (tpy)

NOx VOC CO SO2 PM10 PM2.5 CO2e a/

RSZTravel by LNG carriers 79.76 7.33 12.79 2.48 1.42 1.27 3,958

Tug Boat Support 46.19 4.88 128.3 0.12 1.03 1.03 18,253

Security Vessel Support 3.01 0.32 8.35 0.07 0.07 0.07 1,188

Total Emissions 129 12.5 149 2.7 2.5 2.4 23,399

______________________

a/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

The marine vessel short-term emission rates are considered a separate operating scenario

for the impact analyses in section 4.11.1.6. Table 4.11-11 presents a summary of the estimated

short-term (lb/hr)criteria air pollutant emissions associated with the operation of marine vessels

within the security zone at the Terminal.

The air quality impacts that could occur during normal Terminal operation and ship

maneuvering within the security zone, ship hoteling, ship LNG loading, and ship LNG cargo

offloading are assessed as part of the air quality impacts analysis presented below.

Table 4.11-11

Short-Term Emissions Associated with Operation of Marine Vessels within the Security Zone

Emission Source

Short-Term Emissions (lb/hr)

NOx VOC CO SO2 PM10 PM2.5

Maneuvering and Hoteling by LNG carriers a/ 9.17 3.07 11.01 1.37 0.09 0.09

Offloading LNG carriers 27.06 0.78 11.21 0.82 0.35 0.33

Tug Boat Support 6.37 0.67 17.69 0.15 0.14 0.14

Security Vessel Support 6.01 0.63 16.71 0.14 0.13 0.13

a/ Includes emissions from operation of main engine (for maneuvering)and auxiliary engines (for maneuvering and hoteling)

Pipeline Facilities: Sinton and Taft Compressor Stations

Sources of air emissions associated with operation of the Sinton and Taft Compressor

Stations would include:

 Combustion turbines for gas compression:

a. Sinton: two Solar Titan 130-2050S turbine/compressor units (20,794 hp each);

b. Taft: two Solar Centaur 50 turbine/compressor units (6,387 hp each);
Environmental Impact Statement 4-115 Corpus Christi LNG

 Emergency generators for standby power (one generator at each station);

 Condensate storage and truck loading (one tank at each station);

 Fugitive VOC and GHG emission sources (e.g., valves, flanges, and connectors);and

 VOC and GHG emissions associated with limited blowdown events.

Criteria pollutant emissions of NOx, VOC, CO, PM10, PM2.5, and SO2 would be generated

primarily by the fuel (natural gas)combustion sources at the terminal. The main emission

sources at the compressor stations are the natural gas-fired combustion turbines.

Table 4.11-12 provides a summary of the estimated annual criteria air pollutant, GHG (as

CO2e), and HAP emissions for the Sinton and Taft Compressor Stations. For the combustion

turbines at each station, the annual emissions are based on continuous operation (i.e., 8,760 hours

per year). For the standby generators, annual emissions are based on operation of 100 and 500

hours per year for the Sinton and Taft Compressor Stations, respectively. As discussed in

section 4.11.1.3, the Sinton Compressor Station is a new major source under the PSD program

and the Taft Compressor Station is not a major source. Neither compressor station is a major

source of HAP emissions. Fugitive emissions associated with the M&R Stations would be

negligible, and no air emissions would be directly generated by the Pipeline during normal

operation. Rare situations (e.g., Pipeline maintenance/inspections)may require blowing down a

segment of the Pipeline;the air pollutant emissions of concern for such limited events are VOC

and GHG. Emissions associated with “blow-down” events at the compressor stations are

included in the fugitive emissions category in table 4.11-12 and table 4.11-13.
Environmental Impact Statement 4-116 Corpus Christi LNG

Table 4.11-12

Annual Emissions Associated with Operation of the Sinton and Taft Compressor Stations

Emission Source

Annual Emissions (tpy)

NOx VOC CO SO2 PM10 PM2.5 CO2e a/

HAPs

Total

HAPs

Single

HAP b/

Sinton Compressor Station

Compressor Turbines (2)c/ 128.6 9.41 194.9 17.5 26.9 26.9 150,254

Standby Diesel Generator 0.29 0.06 0.26 0.01 0.005 0.005 57.1

Fugitives - 2.69 - - - - 4,970

Storage Tank - 0.37 - - - - -

Total Emissions 128.9 12.5 195.1 17.5 26.9 26.9 155,281 4.06 3.12

PSD Signif. Emission Rate d/ 40 40 100 40 15 10e100,000

Subject to PSD Review Yes No Yes No Yes Yes Yes

Taft Compressor Station

Compressor Turbines (2)c/ 46.2 3.34 66.6 6.28 9.68 9.67 53,950

Standby Diesel Generator 0.92 0.17 0.60 0.02 0.01 0.01 167.8

Fugitives - 0.97 - - - - 3,604

Storage Tank - 0.37 - - - -

Total Emissions 47.1 4.9 67.2 6.3 9.7 9.7 57,722 1.47 1.19

______________________

a/ CO2e emissions based on GWPs of 1 for CO2, 21 for CH4, and 310 for N2O

b/ Worst-case individual annual HAP emissions from each station are formaldehyde emissions from fuel combustion

c/ Includes MSS (start-up and shutdown)emissions

d/ Emissions of other PSD-regulated air pollutants –lead, fluorides, sulfuric acid mist, HsS, total reduced sulfur, and reduced sulfur

compounds –are negligible

e/ 10 tpy of direct PM2.5 emissions;40 tpy of SO2 emissions;40 tpy of NOx emissions unless demonstrated not to be a PM2.5 precursor

Short-term emission rates are considered a separate operating scenario for the Sinton

Compressor Station and are the basis of the impacts analysis presented in section 4.11.1.6.

Table 4.11-13 provides a summary of the estimated short-term (lb/hr)criteria air pollutant and

HAP emissions for the Sinton Compressor Station.
Environmental Impact Statement 4-117 Corpus Christi LNG

Table 4.11-13

Short-Term Emissions Associated with Operation of the Sinton Compressor Station

Emission Source

Short-Term Emissions (lb/hr)

NOx VOC CO SO2 PM10 PM2.5 HAP a/

Compressor Turbines (2) 29.3 28.6 b/ 2,491 b/ 4.0 6.14 6.14

Standby Diesel Generator 5.85 1.15 5.27 0.13 0.10 0.10

Fugitives - 0.02 - - - -

Storage Tank - 28.4 - - - -

Total Emissions 35.2 58.2 2,496 4.1 6.2 6.2 150

______________________

a/ Worst-case individual short-term HAP emissions from each station are fugitive hexane emissions associated with blow-down

processes

b/ Emissions associated with turbine shutdown

The TCEQ reviewed and approved Cheniere’s PSD BACT analysis for the Sinton

Compressor Station, including the compressor turbines and the standby generator. Methods for

reducing emissions of NOx, CO, and VOCs for each of these sources were evaluated based on

technical feasibility. Cheniere would reduce emissions of NOx and CO from the compressor

turbines through use of dry low-NOx combustors and good combustion practices;VOC

emissions would be controlled through use of good combustion practices. The natural gas-fired,

limited-use standby generator would be equipped with a turbocharger and use good combustion

practices to reduce emissions. The resulting BACT-based emission rates are equal to or better

than any NSPS, NESHAP, and/or RACT emission standards applicable to the compressor station

emission sources.

Emissions from the Taft Compressor Station would be below PSD and Title V permitting

thresholds;therefore, the facility is classified as a minor source. As a result of triggering PSD

review, the air quality impacts that could occur during normal operation of the Sinton

Compressor Station are assessed below.

4.11.1.6 Operational Impact Assessment

To provide a more thorough evaluation of the potential impacts on air quality in the

vicinity of the Project, Cheniere conducted a quantitative assessment of air emissions from

operation of both the Terminal and the Sinton Compressor Station. The assessment included air

dispersion modeling to predict off-site (i.e., ambient)concentrations in the vicinity of the Project.

We considered five separate air quality impacts analyses in our review for the Terminal

and Sinton Compressor Station.

Air quality impact analyses for the Terminal include:

 Analysis 1: NAAQS modeling analysis, including associated marine activities;

 Analysis 2: PSD increment consumption and additional impacts analyses;
Environmental Impact Statement 4-118 Corpus Christi LNG

 Analysis 3: Ozone impacts analysis;and

 Analysis 4: Additional state-specific modeling.

Air quality impact analysis for the Sinton Compressor Station includes:

 Analysis 5: PSD permitting analyses.

Overall Modeling Methodology

With the exception of Analysis 3, all modeling was conducted using the American

Meteorological Society/EPA Regulatory Model. This model is the preferred guideline model for

predicting impacts from new and modified stationary sources. Analysis 3 was conducted using

the EPA-approved Comprehensive Air Quality Model with Extensions (CAMx). Data sets input

to these models include emission source parameter values (e.g., stack height and diameter, stack

exhaust temperature and gas flow, and pollutant emission rate), building/structure dimensions for

determining the effects of the buildings/structure on dispersion of emissions, receptor locations,

terrain elevation data, and meteorological data, as appropriate. Emission rates for stationary and

marine vessel sources are shown above. No receptors were placed within the facility fence line,

because these are not considered “ambient air”locations in accordance with modeling guidance.

Background concentrations and NAAQS were converted to units of μg/m3to be consistent with

the model-predicted units of concentration.

Analysis 1: Terminal - NAAQS Modeling Analysis

Cheniere conducted a cumulative NAAQS analysis addressing emissions from the

Terminal, marine activities associated with Terminal (including LNG carrier maneuvering,

hoteling and unloading, tugboat maneuvering and standby, and security vessel standby), existing

off-site emission sources (e.g., TCEQ-provided inventory of industrial/commercial facilities),

and representative background concentrations.

For the emissions from marine vessel activities, Cheniere considered two representative

operating scenarios: 1)one LNG carrier hoteling and offloading while a tug is on standby within

the security zone;and 2)one LNG carrier hoteling and offloading, a second LNG carrier being

maneuvered by two tugs, a third tug on standby nearby, and one security vessel on standby

nearby, all within the security zone. For these operating scenarios, Cheniere examined three

different combustion fuel options for the main and auxiliary engines used for the maneuvering

and hoteling phases. One of these options included main engine operation on oil with a 0.1

percent sulfur content maximum. Cheniere established LNG carrier emission rates for modeling

based on the anticipated future LNG carrier fleet mix profile for the three options.

Cheniere initially modeled the Terminal alone (with the marine activities included)and

compared the maximum concentrations against the Significant Impact Levels (SILs), which are

defined as a de minimis impact level below which a source is presumed not to cause or contribute

to an exceedance of a NAAQS. Table 4.11-14 shows the SIL analysis modeling results,

demonstrating that only the 1-hr NO2 and SO2 and annual NO2 impacts would be greater than the

SILs. Therefore, a cumulative NAAQS analysis was conducted only for NO2 and SO2.
Environmental Impact Statement 4-119 Corpus Christi LNG

Table 4.11-14

Terminal - SIL Analysis Modeling Results

Pollutant Averaging Period Modeled Concentration

(μg/m3)

SIL

(μg/m3)

NO2 1-hr 130.84 7.5

Annual 8.33 1

CO 1-hr 334.69 2,000

8-hr 166.10 500

PM10 24-hr 1.10 5

PM2.5 24-hr 1.01 1.2

Annual 0.29 0.3

SO2 1-hr 19.06 7.8 a/

3-hr 11.61 25

24-hr 3.76 5

Annual 0.49 1

______________________

a/ Interim SIL

For the cumulative NAAQS analysis, the Terminal (including associated marine

activities)and other off-site sources were modeled. To account for additional sources not

explicitly modeled but that contribute to background pollutant levels in the vicinity of the

Terminal, monitoring data from TCEQ-approved representative monitoring sites also were added

to the modeling results prior to comparison to the NAAQS. The monitoring site for NO2 was the

Lake Jackson Monitor (EPA Monitor 48-039-1016), located in the southern part of Brazoria

County. The monitoring site for SO2 was in Corpus Christi, Texas (EPA Monitor 48-355-0032).

Table 4.11-15 shows the results for the cumulative NAAQS analysis.

Table 4.11-15

Terminal - Cumulative NAAQS Analysis Results

Pollutant Averaging

Period

Modeled Concentration

(μg/m3)

Background

Concentration

(μg/m3)

Total

(μg/m3)

NAAQS

(μg/m3)

NO2 1-hr 543.34 39.55 582.89 188

Annual 23.35 6.32 29.67 100

SO2 1-hr 21.80 114.50 136.30 196

The modeled concentrations for annual NO2 and 1-hr SO2, when combined with

representative background concentrations, were predicted to be below the corresponding

NAAQS. However, modeled impacts of 1-hr NO2, when combined with representative

background concentrations, were predicted to be greater than their applicable NAAQS. Further
Environmental Impact Statement 4-120 Corpus Christi LNG

review of these results indicated that only one receptor, at another industrial site, is predicted to

have a concentration greater than the 1-hr NO2 NAAQS. A source culpability analysis

demonstrated that the Terminal’s contribution to this predicted industrial-site exceedance is

below the SIL;therefore, the Terminal would not cause or significantly contribute to this

exceedance.

Analysis 2: Terminal - PSD Increment Consumption and Additional Impacts Analyses

In addition to the cumulative NAAQS analysis discussed above, Cheniere submitted to

the TCEQ a PSD increment consumption analysis and an Additional Impacts Analysis to satisfy

PSD permitting requirements for the Terminal. The results of these analyses are provided below

to disclose further impacts associated with the Terminal.

PSD increment is the amount of pollution an area is allowed to increase. PSD increments

are intended to prevent the air quality in attainment areas from deteriorating to the level set by

the NAAQS. The PSD increment analysis is used to determine whether a proposed project

would cause or contribute to an exceedance of the allowable decrease in air quality in

conjunction with other existing sources. Federal PSD guidelines specify allowable changes in air

pollutant concentrations due to industrial expansion in an area.

The PSD SIL modeling results submitted to the TCEQ showed that the predicted

maximum 1-hr and annual NO2 concentrations exceed the respective SILs. There is no 1-hr NO2

PSD increment;however, a comprehensive PSD increment analysis was required for annual NO2

emissions as part of the PSD permit application submitted to the TCEQ.

For the NO2 PSD increment consumption analysis, the analysis considered Terminal

sources as well as off-site emission sources. Off-site sources within an area defined by the

Radius of Influence (the maximum distance in kilometers at which a modeled concentration is

predicted to be above a SIL) plus 50 kilometers were included. Emission rates/release

parameters for the off-site sources were obtained from the TCEQ Point Source Database. The

modeled annual NO2 concentration of 9.88 μg/m3is below the PSD increment of 25 μg/m3.

Cheniere also submitted to the TCEQ an Additional Impact Analysis as required by the

PSD regulations. For the growth analysis, no significant commercial, residential, or industrial

growth is expected as a result of construction/operation of the Terminal.

Secondary air quality standards are set under the CAA for the protection of public

welfare, including protection against decreased visibility and damage to animals and vegetation,

including crops. The NAAQS analysis demonstrated that the Terminal would comply with

applicable secondary NAAQS;therefore, any impacts on vegetation, animals, and other public

welfare concerns would not be significant.

In Texas, if a facility complies with visibility and opacity requirements specified in 30

TAC Chapter 111, no additional visibility impact analyses are required. Cheniere would comply

with visibility and opacity requirements specified in 30 TAC Chapter 111. Because the main

combustion units at the Terminal would use only natural gas as fuel, we do not anticipate

significant impacts to regional visibility.
Environmental Impact Statement 4-121 Corpus Christi LNG

Analysis 3: Terminal - Ozone Modeling

The TCEQ and FERC staff requested an assessment of the Terminal’s impact on local

ozone concentrations. Cheniere conducted this analysis using both the two-step screening

process established by the TCEQ as well as the refined photochemical model CAMx.

The two-step TCEQ screening process begins by first identifying a representative ozone

background concentration from a nearby ambient monitor. Step 2 of the screening procedure

involves calculating the ratio of annual VOC to NOx emissions. The results of this screening

process demonstrated that Cheniere’s emissions were considered ozone neutral, and therefore are

not expected to have a meaningful impact on local ozone levels.

Based on discussions with EPA and the TCEQ, Cheniere conducted refined modeling

using CAMx to further support the conclusion drawn from the two-step TCEQ screening

process. Unlike air quality analyses conducted for other criteria pollutants, there is not specific

guidance from EPA or the TCEQ concerning how to conduct ozone modeling. However, there is

precedent from recent permitting actions as to how to determine whether or not a permitting

action will have a meaningful impact on ozone levels.

The CAMx modeling was conducted for the May 31, 2006 through July 1, 2006 ozone

episode, because this episode has been used for local air quality planning. The use of CAMx and

this ozone episode was based on discussions with both EPA and the TCEQ. CAMx was run

using a “base case”scenario of emissions as well as an emissions scenario that included the

Project (added to the base case), thus allowing for a comparison of ozone levels before and after

the Project is permitted.

The results of the CAMx modeling analysis were evaluated in the same manner as has

been done for other recent permitting projects in Texas. This evaluation demonstrates that the

Terminal is not expected to cause or contribute to an exceedance of an ozone NAAQS violation.

Analysis 4: Terminal - Additional State-Specific Modeling

Although the Terminal’s SO2 emissions increase did not trigger PSD review, the TCEQ

requested an air dispersion modeling analysis for SO2 emissions to assess compliance with the

SO2 NAAQS as well as the State Property Line Standards for SO2 and H2S as specified in

30 TAC §112.3(a). The modeling conducted by Cheniere considered stationary sources

associated with the Terminal.

Table 4.11-16 shows the modeling results for the SO2 NAAQS analyses. All modeled

concentrations of SO2 were predicted to be less than the applicable SILs. Therefore, this

modeling analysis demonstrates compliance with the SO2 NAAQS.
Environmental Impact Statement 4-122 Corpus Christi LNG

Table 4.11-16

Terminal - SO2 NAAQS Analysis Modeling Results

Averaging Period Maximum Concentration

(μg/m3)

SIL

(μg/m3)

1-hr 4.14 7.8 a/

3-hr 2.44 25

24-hr 1.49 5

Annual 0.22 1

______________________

a/ Interim SIL

Table 4.11-17 shows the modeling results for the State Property Line Standards analysis.

The modeled concentrations were predicted to be less than the State Property Line Standards for

SO2 and H2S. Therefore, this modeling analysis demonstrates compliance with the State

Property Line Standards.

Table 4.11-17

Terminal - State Property Line Standards Modeling Results

Pollutant Maximum Concentration

(μg/m3) a/

Chapter 112 Standard

(μg/m3)

SO2 16.17 1,021

H2S 0.02 162

______________________

a/ 1-hr average concentration

Cheniere submitted to the TCEQ a State Effects Evaluation assessing emitted

compounds’potential to cause adverse health effects, odor nuisances, vegetation effects, or

materials damage. Following TCEQ procedures, a comparison against Effects Screening Levels

(ESLs)was required for only three compounds: benzene, gasoline, and ethylene.

The modeling conducted by Cheniere considered stationary sources associated with the

Terminal. Table 4.11-18 shows the modeling results of the State Effects Evaluation analysis.

Because the maximum predicted concentrations for ethylene were found to be less than their

corresponding ESLs, no further analysis of ethylene emissions was necessary. Although

predicted concentrations of benzene and gasoline were found to be greater than their respective

ESLs, TCEQ’s guidance deems the benzene and gasoline modeling results acceptable.

Therefore, no further State Effects Evaluation modeling is necessary.
Environmental Impact Statement 4-123 Corpus Christi LNG

Table 4.11-18

Terminal - State Effects Evaluation Modeling Results

Pollutant Averaging Period Maximum Concentration

(μg/m3)

ESL

(μg/m3)

Benzene 1-hr 184.35 170

Annual 2.41 4.5

Ethylene 1-hr 11.54 1,400

Annual 0.96 34

Gasoline 1-hr 6,769.33 3,500

Annual 54.93 350

Analysis 5: Sinton Compressor Station - PSD Permitting Analyses

Cheniere submitted to the TCEQ a PSD modeling analysis for the Sinton Compressor

Station, including a SIL analysis, cumulative NAAQS analysis, and PSD increment consumption

analysis. Tables 4.11-19through 4.11-21 show the results of these analyses.

Table 4.11-19

Sinton Compressor Station – SIL Analysis Modeling Results

Pollutant Averaging Period Maximum Concentration

(μg/m3)

SIL

(μg/m3)

NO2 1-hr 59.1 7.5

Annual 1.5 1

CO 1-hr 6,341.0 2,000

8-hr 5,543.5 500

PM10 24-hr 9.2 5

Annual 0.4 1

PM2.5 24-hr 7.6 1.2

Annual 0.4 0.3

As shown in table 4.11-19, the maximum predicted concentrations for all pollutants and

averaging times were found to be greater than the SILs, except for the annual PM10

concentration. Therefore, cumulative NAAQS and PSD increment consumption modeling

analyses were conducted for 1-hr and annual NO2, 1-hr and 8-hr CO, 24-hr PM10, and 24-hr and

annual PM2.5.

For the cumulative NAAQS analysis, the Sinton Compressor Station and off-site

emission sources were modeled. To account for additional sources not explicitly modeled but

that contribute to background pollutant levels in the vicinity of the station, monitoring data from

a representative monitoring site was added to the modeled results prior to comparison to the
Environmental Impact Statement 4-124 Corpus Christi LNG

NAAQS. The representative monitoring site for NO2 was the Lake Jackson Monitor (EPA

Monitor 48-039-1016), located in the southern part of Brazoria County. The representative

monitoring site for CO was located in Brownsville, Texas (EPA Monitor 48-061-0006). The

representative monitoring site for PM10 and PM2.5 was the Dona Park monitor (EPA Monitor 48-

355-0034), located in Nueces County. Table 4.11-20 shows the results for the cumulative

NAAQS analysis. The modeled concentrations for NO2, CO, PM10, and PM2.5, when combined

with representative background concentrations, were predicted to be below their corresponding

NAAQS.

Table 4.11-20

Sinton Compressor Station - Cumulative NAAQS Analysis Results

Pollutant Averaging

Period

Modeled Concentration

(μg/m3)

Background

Concentration

(μg/m3)

Total

(μg/m3)

NAAQS

(μg/m3)

NO2 1-hr 102.02 42.45 144.47 188

Annual 3.77 6.78 10.55 100

CO 1-hr 6,325.14 2,125.48 8,450.62 40,000

8-hr 4,836.42 1,125.26 5,961.68 10,000

PM10 24-hr 12.81 67.0 79.81 150

PM2.5 24-hr 13.35 20.67 34.02 35

Annual 1.38 9.37 10.75 15

For the PSD increment consumption analysis, the Sinton Compressor Station sources as

well as off-site emission sources were modeled. Per the request of TCEQ, only increment

consuming sources were included (i.e., reductions in emissions from shut down sources could

not be accounted for in the modeling). As shown in table 4.11-21, the modeled impacts for NO2,

PM10, and PM2.5 were predicted to be below their corresponding PSD increments.

Table 4.11-21

Sinton Compressor Station - PSD Increment Consumption Modeling Results

Pollutant Averaging Period Modeled Concentration

(μg/m3)

PSD Increment

(μg/m3)

NO2 Annual 3.77 25

PM10 24-hr 19.72 30

PM2.5 24-hr 8.72 9

Annual 0.55 4

An Additional Impact Analysis was conducted, as required by the PSD regulations. For

the growth analysis, no significant commercial, residential, or industrial growth is expected as a

result of construction/operation of the Sinton Compressor Station.
Environmental Impact Statement 4-125 Corpus Christi LNG

In Texas, if a facility complies with visibility and opacity requirements specified in 30

TAC Chapter 111, no additional visibility impact analyses are required. Cheniere would comply

with visibility and opacity requirements specified in 30 TAC Chapter 111. Because the

combustion units at the Sinton Compressor Station would use only natural gas as fuel, we do not

anticipate significant impacts to regional visibility.

4.11.2 Noise

Noise would affect the local environment during both the construction of the Project

facilities and operation of each of the proposed compressor stations associated with the Project.

At any location, both the magnitude and frequency of environmental noise may vary

considerably over the course of the day and throughout the week. This variation is caused in

part by changing weather conditions, the effects of seasonal vegetative cover, and man-made

activities.

Two measures used by federal agencies to relate the time-varying quality of

environmental noise to its known effect on people are the equivalent sound level (Leq)and the

day-night average sound level (Ldn). The Leq is the level of steady sound with the same total

(equivalent)energy as the time-varying sound of interest, averaged over a 24-hour period. The

Ldn is the Leq with 10 decibels on the A-weighted scale (dBA)added to nighttime sound levels

between the hours of 10:00 PM and 7:00 AM to account for people's greater sensitivity to sound

during nighttime hours. The A-weighted scale is used because human hearing is less sensitive to

low and high frequencies than mid-range frequencies. A person’s threshold of perception for a

perceivable change in loudness on the A-weighted sound level is on average 3 dBA, whereas

a 5 dBA change is clearly noticeable and a 10 dBA change is perceived as twice or half as loud.

4.11.2.1 RegulatoryRequirements

In 1974, the EPA published Information on Levels of Environmental Noise Requisite to

Protect Public Health and Welfare with an Adequate Margin of Safety (EPA, 1974). This

document provides information for state and local governments to use in developing their own

ambient noise standards. The EPA has determined that, to protect the public from activity

interference and annoyance outdoors in residential areas, noise levels should not exceed an Ldn of

55 dBA. We have adopted this criterion and use it to evaluate the potential noise impacts from

the Project at NSAs, such as residences, schools, or hospitals. Due to the 10 dBA nighttime

penalty added prior to calculation of the Ldn, for a facility to meet the Ldn 55 dBA limit, it must

be designed such that actual constant noise levels on a 24-hour basis do not exceed 48.6 dBA Leq

at any NSA.

Based on a review of state regulations, there are no noise quality regulations or

ordinances at the state or county level that are applicable to the Project. At the local level,

ordinances were identified for the City of Corpus Christi and the City of Portland. However, due

to the separation distance of the Project from the nearest point in the City of Corpus Christi, the

City of Corpus Christi ordinance requirements are not applicable to the Project. The City of

Portland’s Municipal Code of Ordinances provides a noise limit of 63 dBA at the residential

property line:

The ordinance listed above is generally less stringent for residences than the FERC limit.

However, in the unusual situation of a house set back on a very large parcel of land, the FERC

sound level limit could be satisfied at the house and the Portland City Ordinance limit exceeded
Environmental Impact Statement 4-126 Corpus Christi LNG

at the property line. Upon review of the site and existing NSAs for the Project, this unusual

condition is not expected to occur.

4.11.2.2 Existing Noise Levels

Impacts at the Terminal, two compressor stations, and three HDD crossings have been

evaluated for adjacent NSAs and surrounding ambient noise levels.

Terminal

There are no NSAs within a 1-mile radius of the proposed Terminal. For the purposes of

studying noise impacts for the proposed Terminal and dredging activities, the nearest five NSAs

were identified. These NSAs are shown on figure 4.11-1 and are located about 1.6 to 3.2 miles

from the noise-producing equipment at the Terminal. The NSAs include residential

communities, Ingleside High School, two churches, and a hotel.

Cheniere’s consultant, Tetra Tech, conducted a noise survey from February 16 to

February 17, 2012 to characterize the existing acoustic environment in the vicinity of the

Terminal site. Principal contributors to the acoustic environment include existing industrial

facilities, motor vehicle traffic on local roadways, periodic aircraft flyovers and rail movements,

and natural sounds such as birds, insects, and leaf or vegetation rustle during elevated wind

conditions. Table 4.11-23 summarizes the results of the baseline sound measurements for the

Terminal. The measured Ldn sound levels ranged from 51 to 54 dBA, indicating a relative

acoustic consistency across the area in the vicinity of the Terminal site, with NSAs exposed to

both similar sound sources and overall background sound levels.

Table 4.11-22

Terminal - Baseline Measurement Results

NSA Distance from site to

NSA (miles)

Direction from site to

NSA

Monitoring Location

ID

Sound Level

Ldn dBA

1 1.6 SW ST-1 53

2 2.1 W ST-2 54

3 2 NW ST-3 53

4 2.5 NW ST-4 54

5 3.2 E ST-5 51
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Figure 4.11-1 Terminal and Dredging NSA Locations and Distances
Environmental Impact Statement 4-128 Corpus Christi LNG

Pipeline

Baseline sound measurements were conducted in the vicinity of the two proposed

compressor station sites near the towns of Taft and Sinton from May 22 to May 24, 2012. The

NSAs identified for the compressor station sound surveys are shown in figure 4.11-2 and figure

4.11-3. Table 4.11-24 summarizes the results of the baseline sound measurements for the Sinton

and Taft Compressor Stations. The measured Ldn sound levels ranged from 55 to 64 dBA.
E

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Figure 4.11-2 Sinton Compressor Station NSA Locations and Distances
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Figure 4.11-3 Taft Compressor Station NSA Locations and Distances
Environmental Impact Statement 4-131 Corpus Christi LNG

Table 4.11-23

Compressor Stations - Baseline Measurement Results

Site NSA Distance from site

to NSA (miles)

Direction from site

to NSA

Monitoring

Location ID

Sound Level

Ldn dBA

Sinton CS 1 0.6 SE S-1 55

Taft CS 1 0.7 E T-2 59

2 0.9 NW T-2 59

3 1.4 N T-1 64

4 1.0 NE T-1 64

At the Sinton Compressor Station site, one NSA was identified, representative of a

grouping of privately owned cabins approximately 3,300 feet southeast of the proposed Sinton

Compressor Station site. A representative monitoring location was selected approximately 0.5-

mile from the intersection of Edwards Road and US 77. The ambient acoustic environment

included sounds from distant highway traffic on US 77, birds, distant air conditioning units at

one of the cabins, insects, and a night-time train pass-by and horn.

At the Taft Compressor Station site, four NSAs were identified within 1.5 miles;all were

residences. Two monitoring locations were selected to represent the ambient sound level

environment. The T-1 monitoring location was positioned northeast of the intersection of

US 181 and County Road 3465. The T-2 monitoring location was positioned southwest of the

intersection of US 181 and County Road 79(Midway Road). The acoustic environment included

sounds from roadway traffic on US 181, wind turbine generators, wind during both daytime and

nighttime monitoring, and insect and rodent noise only at night.

Horizontal Directional Drills

Cheniere conducted baseline sound measurements at NSAs in the vicinity of the three

proposed HDD crossings. The NSAs identified for the HDD site baseline sound surveys are

shown in figures 4.11-4 and 4.11-5. Cheniere has not finalized the entry and exit sides of the

crossing points, so the two sites associated with each crossing are labeled as (a)and (b).

Measurements were conducted during the same time period as those conducted for the

compressor stations. Table 4.11-25 summarizes the results of the baseline sound measurements

for the HDD sites. The results of the baseline sound survey show varying ambient sound levels

throughout the HDD areas. The measured daytime sound levels (Ld)ranged from 42 to 58 dBA.
E

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Figure 4.11-4 US 181/SH 35 HDD (HDD-1) and Oliver Creek HDD (HDD-2) NSA Locations and Distances
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Figure 4.11-5 Chiltipin Creek HDD (HDD-3) NSA Locations and Distances
Environmental Impact Statement 4-134 Corpus Christi LNG

The ambient acoustic environments of the Chiltipin Creek HDD crossing and the Oliver

Creek HDD crossing sites have similar sound source contributors, including traffic noise on

SH 188, birds, insects, and distant traffic noise on U.S. Highway 181.22 The NSAs at these two

HDDs are all residential. The ambient acoustic environment of the US 181/SH 35 HDD crossing

sites were influenced by traffic on US 181, SH 35, and local roads;birds, insects, wind, and

aircraft fly-overs. The nearest NSAs included residential communities, a hotel and a church.

Table 4.11-24

HDD Locations - Baseline Measurement Results

Crossing Site NSA

Distance from

site to NSA

(miles)

Direction from

site to NSA

Monitoring

Location ID Ld

Chiltipin Creek HDD-1(a) 1 0.4 S HN-2 57

HDD-1(b) 1 0.2 SW HN-2 57

Oliver Creek HDD-2(a) 3 0.1 SE HN-2 57

2 0.3 W HN-2 57

HDD-2(b) 3 0.2 N HN-2 57

4 0.8 SE HN-5 42

5 0.8 SW HN-5 42

US 181/SH 35 HDD-3(a) 6 0.4 NE HS-1 58

7 0.5 S HS-2 52

8 0.9 SW HS-3 53

9 0.8 NW HS-4 57

HDD-3(b) 10 0.4 NE HS-1 58

7 0.4 SW HS-2 52

22 The NSAs for the Chiltipin Creek HDD are located farther from both SH 188 and US 181 than the NSAs for the

Oliver Creek HDD. It is possible that the measured sound levels at the NSAs for the Chiltipin Creek HDD (HDD 1)

are less than the reported values.
Environmental Impact Statement 4-135 Corpus Christi LNG

4.11.2.3 Noise QualityImpacts and Mitigation

Construction Noise

Construction noise would be generated over an extended period at the Terminal and for a

short-term period along the pipeline, compressor stations, and HDD work areas.

Terminal Facilities

The four-year construction activities at the Terminal site would generate increases in

sound levels. Standard construction equipment would be used, and most construction would take

place during normal working hours of 7:00 a.m. until 7:00 p.m. Emergencies, weather

conditions or other unusual circumstances may necessitate nighttime work. Construction noise is

highly variable, as the types of equipment in use at a construction site change with the

construction phase and the type of activities. The first phase of Terminal construction

(consisting of excavation, filling and grading using heavy earth-moving equipment, pile driving

for docks, and dredging), would generate the highest sound levels. In general, heavy equipment

would be used during this phase of construction. Sound levels at the nearest NSA for each

construction phase were calculated. The results ranged from 43 to 48 dBA Leq.

Noise generated during pile-driving for installation of the LNG carrier docks was

considered as a separate case of construction noise because activities could occur 24 hours per

day. There may be two pile driving machines working simultaneously during construction. One

pile driving machine would be located at the west jetty and the other would be located at the east

jetty. Assuming two pile drivers in simultaneous 24-hour operation, the predicted Ldn value at

the nearest NSA (NSA 1)is 47.7 dBA, which is less than the existing ambient sound level.

Dredging noise is not expected to cause a significant environmental noise impact. There

are no NSAs located within 0.5 miles of the dredge proposed area, as shown on figure 4.11-1.

NSAs and the ambient acoustic environment closest to Project dredging activities are the same at

those NSAs identified near the Terminal site. The noise will vary as the activities move nearer

or farther from the NSAs, but even at the closest approach using the noisiest dredge option, the

temporary dredging contributions are not expected to exceed the FERC noise level criterion.

Dredging activities would require approximately six months to complete. Total daily activity

work time would vary from 16 to 20 hours, and may occur at any time of day or night, 7 days per

week.

Construction noise levels for the Terminal (including pile driving of the LNG carrier

docks and dredging activities)are projected below the FERC criterion at the closest NSAs and

are not expected to cause a significant impact.

Pipeline Facilities

Compressor Stations

Construction of the Pipeline would result in short-term noise impacts, primarily due to

heavy equipment used in clearing and grading, pipe trenching, pipe welding, trench backfill, and

right-of-way restoration activities. These activities are temporary and of short duration at any

given point along the linear pipeline route.

Noise levels from compressor station construction were conservatively evaluated

considering equipment usage factors and construction hours. The estimated noise level from the

Sinton Compressor Station would be 50 dBA Leq at the nearest NSA (NSA-1)at 0.6 miles. The
Environmental Impact Statement 4-136 Corpus Christi LNG

estimated noise level from the Taft Compressor Station is projected to be 47 dBA Leq at the

nearest NSA (NSA-1)at 0.7 miles. Actual received sound levels will fluctuate, depending on the

construction activity, equipment type, and separation distances between source and receiver.

Construction noise may be periodically audible at several residential receptor locations.

In order to minimize noise levels associated with compressor station construction, Cheniere

identified the following mitigation measures may be implemented to the extent practical:

 Construction site and access road speed limits may be established and enforced during

the construction period;

 Electrically-powered equipment may be used instead of pneumatic or internal combustion

powered equipment, where feasible;

 Material stockpiles and mobile equipment staging, parking, and maintenance areas may

be located as far as practicable from noise-sensitive receptors;

 The use of noise-producing signals, including horns, whistles, alarms, and bells, will be

for safety warning purposes only.

Additionally, all noise-producing construction equipment and vehicles using internal

combustion engines should be equipped with mufflers, air-inlet silencers where appropriate, and

any other shrouds, shields, or other noise-reducing features in good operating condition that meet

or exceed original factory specification.

Horizontal Directional Drills

Cheniere proposes three HDD crossings on the Project. Each HDD would require eight

days or more to complete. Cheniere has also committed to performing all HDD activities, except

potentially the pipe pullback, during daylight hours. HDD operations will occur at one site at a

time.

HDD equipment consists of an HDD drilling rig and auxiliary support equipment

including electric mud pumps, portable generators, a crane, mud mixing and cleaning equipment,

forklifts, loaders, trucks, and portable light sets. Sound levels at NSAs resulting from HDD

entry and exit operations were calculated using sound power levels of typical equipment. The

calculation also assumes the worst case condition that the entry would be nearest the NSA. The

results of this analysis are presented in table 4.11-25.

Noise levels from the Chiltipin Creek and US 181/SH 35 HDDs would be below existing

noise levels at the nearest NSAs. Potential noise impacts may occur at the Oliver Creek HDD

where noise levels would be at or above existing noise levels for several NSAs and would be

perceived as twice as loud as existing noise levels at a residence located 300 feet from one site.

However, noise levels during daytime hours would not be any louder than other typical

construction noise and would not impact night-time sound levels.
Environmental Impact Statement 4-137 Corpus Christi LNG

Table 4.11-25

Summary of HDD Acoustic Modeling Results

Crossing Site NSA

Distance from

site to NSA

(feet)

Direction

from site to

NSA

Existing

Ld (dBA)

HDD

Contribution Ld

(dBA)

Combined

Ld (dBA)

Net

Increase

(dBA)

Chiltipin

Creek

HDD-1(a) 1 2200 S 57 54.5 59 2

HDD-1(b) 1 1100 SW 57 54.5 59 2

Oliver

Creek

HDD-2(a) 1 300 SE 57 65.7 66 9

2 1800 W 57 50.2 58 1

HDD-2(b) 1 1300 N 57 53.2 59 2

2 4000 SE 42 43.3 46 4

3 4000 SW 42 43.3 46 4

US 181/

SH 35 HDD-3(a) 1 2400 NE 58 47.8 58 0

2 2600 S 52 48.6 54 2

3 4700 SW 53 42.0 53 0

4 4400 NW 57 42.5 57 0

HDD-3(b) 1 2200 NE 58 48.6 58 0

2 2200 SW 52 48.6 54 2

Operational Noise

Terminal Facilities

The Terminal would include the following major noise-producing sources:

 LM2500+G4 gas turbine driven refrigerant compressors;

 Gas treatment facilities;

 Waste heat recovery systems;

 Induced draft air coolers;

 Piping;

 Recycle boil-off gas compressors;and

 Instrument air compressor packages.

Noise contributions for the Terminal were calculated using environmental noise

prediction software Cadna/A version 4. The model calculates the total sound pressure level at a

specified receiver location or over a grid from all sources.

The following equipment noise mitigation measures are included in this study:
Environmental Impact Statement 4-138 Corpus Christi LNG

 large air-cooled heat exchangers with a sound power level limit of 99dBA and a sound

pressure level limit of 85 dBA at 1 meter;

 Each gas turbine for refrigerant compression requires a silencer for the gas turbine inlet,

gas turbine enclosure, inlet duct, inlet intake, filter house, gas turbine ventilation and

auxiliaries, resulting in an average 85 dBA sound pressure level at 1 meter;

 noise hood on gearboxes;and

 compressor suction, discharge and recycle piping are assumed to have 4 inch acoustic

insulation.

Predicted Ldn values from the Terminal are shown in table 4.11-26 for the five noise

sensitive areas identified on figure 4.11-1. Based on results of the noise model summarized

above, the Terminal (with the aforementioned noise control measures) would result in a

maximum sound level contribution of 51.3 dBA Ldn at the nearest NSA. Based on these results,

operation of the Terminal would comply with the FERC 55 Ldn criterion and City of Portland

noise requirements. Therefore, we do not believe that noise impacts due to operation of the

Terminal would be significant. However, to ensure that the actual noise resulting from operation

of the Terminal facilities is not significant, we recommend that:

 Cheniere should file a noise surveywith the Secretaryno later than 60 days after

placing each liquefaction train and the entire Terminal in service. If a full load

condition noise surveyis not possible,Cheniere should provide an interim surveyat

the maximum possible load and provide the full load surveywithin six months. If

the noise attributable to the operation of all of the equipment for a liquefaction train

or at the Terminal,under interim or full load conditions,exceeds an Ldn of 55dBA

at anynearbyNSAs,Cheniere should file a report on what changes are needed and

should install the additional noise controls to meet the level within one year of the

in-service date. Cheniere shall confirm compliance with the above requirement by

filing a second noise surveywith the Secretaryno later than 60 days after it installs

the additional noise controls.

Table 4.11-26

Terminal Operational Noise Impact Results

NSA

Distance (miles)

and Direction to

NSA from CCL

Terminal

Existing Ambient

Ldn (dBA)

Calculated Ldn of

Proposed Noise

Sources (dBA)

Combined Ldn

(dBA)

Expected

Increase (dBA)

NSA-1 1.6 53 50.8 55.0 2.0

NSA-2 2.1 54 49.0 55.2 1.2

NSA-3 2.0 53 49.9 54.7 1.7

NSA-4 2.5 54 50.8 55.7 1.7

NSA-5 3.2 51 48.0 52.8 1.8
Environmental Impact Statement 4-139 Corpus Christi LNG

Pipeline Facilities

Compressor Stations

Operation of the Sinton and Taft Compressor Stations has the potential to result in noise

impacts at nearby NSAs. The facilities for both compressor stations are similar but the Taft

Compressor Station would utilize two Solar Centaur 50 turbine/compressor units (6,387 hp each)

whereas the Sinton Compressor Station would utilize two Solar Titan 130 turbine/compressor

units (20,794 hp each). The following noise sources would be present at the compressor stations:

 Two Solar Centaur 50 turbine/compressor units (6,387 hp each)at the Taft Compressor

Station;

 Two Solar Titan 130 turbine/compressor units (20,794 hp each)at the Sinton Compressor

Station;

 Discharge gas coolers;

 Lube oil coolers;

 Air compressor;

 Electrical transformer;and

 Aboveground compressor station piping.

Similar to the modeling methodology of the Terminal, Cadna/A was used to model noise

generated during Compressor Station operation. Site-specific topography was imported into the

model and ground absorption characteristics within the Project area were also considered. Sound

attenuation through foliage and diffraction was ignored. Octave band sound power data from the

equipment manufacturer were used as inputs to the model wherever possible. In the absence of

manufacturer data, reasonable and appropriate assumptions were derived from engineering

guidelines and literature.

Cheniere is in the initial engineering phases for each compressor station and has not

finalized specific noise mitigation measures. Common vendor information has been applied to

each compressor station’s acoustic model when available. Final design would be inclusive of a

number of noise mitigation measures which may include acoustical enclosures, barriers,

silencers, and lagging, in addition to low noise equipment. The principal noise mitigation

measures which have been included in the noise analysis are as follows:

 Acoustically insulated compressor station buildings;

 Combustion air inlet silencers;

 Combustion turbines equipped with exhaust silencers;and

 Aboveground piping outside the compressor station building covered with acoustic pipe

insulation.

The modeled operational sound from the Taft and Sinton Compressor Stations considers

simultaneous operation of all sound sources at their maximum rated loads under normal

operating conditions. Results are presented in table 4.11-28, which contains a comparison of the

calculated levels with existing levels, the combined future levels, and the expected net increase.

The modeling results indicate that the calculated sound levels resulting from compressor station
Environmental Impact Statement 4-140 Corpus Christi LNG

operation at the NSAs are all below the FERC criterion of Ldn of 55 dBA. Also, the expected

increases in noise levels at the NSAs around both compressor station sites are shown to be

negligible. However, to ensure that the actual noise levels resulting from operation of the Sinton

and Taft Compressor Stations are not significant, we recommend that:

 Cheniere should file noise surveys with the Secretaryno later than 60 days after

placing the Sinton and Taft Compressor Stations in service. If a full load condition

noise survey is not possible,Cheniere should provide an interim survey at the

maximum possible horsepower load and provide the full load survey within six

months. If the noise attributable to the operation of all of the equipment at the

Sinton or Taft Compressor Station, under interim or full horsepower load

conditions,exceeds an Ldn of 55dBA at anynearbyNSAs,Cheniere should file a

report on what changes are needed and should install the additional noise controls

to meet the level within one year of the in-service date. Cheniere should confirm

compliance with the above requirement by filing a second noise survey with the

Secretaryno later than 60 days after it installs the additional noise controls.

Table 4.11-27

Operational Noise Impact Results - Compressor Stations

Compressor

Station NSA

Distance (feet) and

Direction to NSA from

Compressor Station

Existing

Ambient Ldn

(dBA)

Calculated Ldn of

Proposed Noise

Sources (dBA)

Combined

Ldn (dBA)

Increase

Over Existing

(dBA)

Sinton NSA-1 3200 -SE 55 44 55 <1

Taft NSA-1 3800 -ENE 59 39 59 <1

NSA-2 4400 -WNW 59 38 59 <1

NSA-3 7200 -NW 64 33 64 <1

NSA-4 5300 -NE 64 37 64 <1

Blowdowns

The sound levels associated with high pressure gas venting vary based on initial

blowdown pressure, the diameter and type of blowdown valve, and the diameter and

arrangement of the downstream vent piping. Blowdown sound levels are loudest at the

beginning of the blowdown event and they decrease as the blowdown pressure decreases. There

are typically two types of gas blowdown events at compressor stations:

 unit blowdown: a routine gas blowdown that can occur when a compressor is stopped and

gas between the suction/discharge valves and compressor(s)is vented to the atmosphere

through a blowdown silencer;and

 station blowdown: a gas blowdown, vented via a silencer that occurs when all of the

station piping is depressurized.
Environmental Impact Statement 4-141 Corpus Christi LNG

The blowdown silencers at the stations have been designed to produce no more than

60 dBA at 300 feet, during standard blowdown events in order to reduce the potential for adverse

noise impacts. Due to the short duration and infrequent timing of station blowdowns, these

events would not influence the 24-hour Ldn values projected for these facilities.

Meter and Regulator Stations

Six M&R stations would be installed at interconnects along the Pipeline. Facilities at the

M&R stations generally consist of filter separators, liquid handling tank, one bi-directional M&R

system, and a 48-inch by 36-inch “T”and valve on the Pipeline. Sound generated from M&R

stations is expected to be low level resulting in minimal impacts at NSAs.

4.12 RELIABILITY AND SAFETY

4.12.1 LNG FacilityRegulatoryOversight

Three federal agencies share regulatory authority over the siting, design, construction and

operation of LNG import and export terminals: the Coast Guard, the DOT, and the FERC. The

Coast Guard has authority over the safety of an LNG facility’s marine transfer area and LNG

marine traffic, as well as over security plans for the entire LNG facility and LNG marine traffic.

Those standards are codified in 33 CFR parts 105 and 127. The DOT establishes federal safety

standards for siting, construction, operation, and maintenance of onshore LNG facilities, as well

as for the siting of marine cargo transfer systems at waterfront LNG plants. Those standards are

codified in 49CFR 193. Under the NGA and delegated authority from the DOE, the FERC

authorizes the siting and construction of LNG import and export facilities.

In 1985, the FERC and DOT entered into a memorandum of understanding regarding the

execution of each agency’s respective statutory responsibilities to ensure the safe siting and

operation of LNG facilities. In addition to FERC’s existing ability to impose requirements to

ensure or enhance the operational reliability of LNG facilities, the memorandum of

understanding specified that FERC may, with appropriate consultation with DOT, impose more

stringent safety requirements than those in Part 193.

In February 2004, the Coast Guard, DOT, and FERC entered into an Interagency

Agreement to ensure greater coordination among these three agencies in addressing the full

range of safety and security issues at LNG terminals, including terminal facilities and tanker

operations, and maximizing the exchange of information related to the safety and security

aspects of the LNG facilities and related marine operations. Under the Interagency Agreement,

the FERC is the lead federal agency responsible for the preparation of the analysis required

under NEPA for impacts associated with terminal construction and operation. The DOT and

Coast Guard participate as cooperating agencies.

As part of the review required for a FERC authorization, Commission staff must ensure

that all proposed facilities would operate safely and securely. The design information that must

be filed in the application to the Commission is specified by 18 CFR 380.12 (m)and (o). The

level of detail necessary for this submittal requires the Project sponsor to perform substantial

front-end engineering of the complete facility. The design information is required to be sitespecific and developed to the extent that further detailed design would not result in changes to

the siting considerations, basis of design, operating conditions, major equipment selections,
Environmental Impact Statement 4-142 Corpus Christi LNG

equipment design conditions, or safety system designs which we considered during our review

process.

The FERC’s filing regulations also require each applicant to identify how its proposed

design would comply with DOT’s siting requirements in 49CFR 193, Subpart B. As part of our

NEPA review, we use this information from the applicant to assess whether or not a facility

would have a public safety impact. As a cooperating agency, DOT assists FERC staff in

evaluating whether an applicant’s proposed siting meets the DOT requirements. If a facility is

constructed and becomes operational, the facility would be subject to DOT’s inspection program.

Final determination of whether a facility is in compliance with the requirements of 49CFR 193

would be made by DOT staff.

Section 4.12.2 discusses the principal properties and hazards of the materials stored,

processed, and handled at the LNG Facility;section 4.12.3 discusses our technical review of the

preliminary design of the LNG Facility;section 4.12.4 discusses siting requirements for the LNG

Facility;section 4.12.5 discusses the siting analysis of the LNG Facility;section 4.12.6 discusses

the safety and security requirements of the LNG carriers associated with the LNG Facility.

section 4.12.7 discusses emergency response and evacuation planning for the LNG Facility and

along the LNG Carrier Route;and section 4.12.9discusses the safety of the Pipeline associated

with the Project.

4.12.2 LNG FacilityHazards

With the exception of the October 20, 1944, failure at an LNG facility in Cleveland,

Ohio, the operating history of the U.S. LNG industry has been free of safety-related incidents

resulting in adverse effects on the public or the environment. The 1944 incident in Cleveland led

to a fire that killed 128 people and injured 200 to 400 more people23. The failure of the LNG

storage tank was due to the use of materials inadequately suited for cryogenic temperatures.

LNG migrating through streets and into underground sewers due to the lack of adequate spill

impoundments at the site was also a contributing factor. Current regulatory requirements ensure

that proper materials suited for cryogenic temperatures are used and that spill impoundments are

designed and constructed properly to contain a spill at the site.

Another operational accident occurred in 1979at the Cove Point LNG facility in Lusby,

Maryland. A pump seal failure resulted in gas vapors entering an electrical conduit and settling

in a confined space. When a worker switched off a circuit breaker, the gas ignited, causing

heavy damage to the building and a worker fatality. With the participation of the FERC, lessons

learned from the 1979Cove Point accident resulted in changing the national fire codes to better

ensure that the situation would not occur again.

On January 19, 2004, a blast occurred at Sonatrach’s Skikda, Algeria, LNG liquefaction

facility, which killed 27 and injured 56 workers. No members of the public were injured.

Findings of the accident investigation suggested that a cold hydrocarbon leak occurred at

Liquefaction Train 40 and was introduced to the high-pressure steam boiler by the combustion

air fan. An explosion developed inside the boiler firebox, which subsequently triggered a larger

explosion of the hydrocarbon vapors in the immediate vicinity. The resulting fire damaged the

23 For a description of the incident and the findings of the investigation, see “U.S. Bureau of Mines, Report on the

Investigation of the Fire at the Liquefaction, Storage, and Regasification Plant of the East Ohio Gas Co., Cleveland,

Ohio, October 20, 1944,”dated February 1946.
Environmental Impact Statement 4-143 Corpus Christi LNG

adjacent liquefaction process and liquid petroleum gas (LPG)separation equipment of Train 40,

and spread to Trains 20 and 30. Although Trains 10, 20, and 30 had been modernized in 1998

and 1999, Train 40 had been operating with its original equipment since start-up in 1981. To

ensure that this potential hazard would be addressed at the proposed Project, Cheniere would

install hazard detection devices at all combustion and ventilation air intake equipment to enable

isolation and deactivation of any combustion equipment whose continued operation could add to,

or sustain, an emergency.

On March 31, 2014, an explosion and fire occurred at Northwest Pipeline Corporation’s

LNG peak-shaving facility in Plymouth, Washington. The facility was immediately shut down,

and emergency procedures were activated, which included notifying local authorities and

evacuating all plant personnel. No members of the public were injured. The accident

investigation is still in progress. Once developed, measures to address any causal factors which

led to this incident will be applied to all facilities under Commission jurisdiction.

4.12.2.1 Hazards Associated with the Proposed Equipment

Before liquefaction, Cheniere would pre-treat the feed gas for removal of mercury, H2S,

and CO2. The removal of these substances from the feed gas stream can be hazardous as a result

from the physical, chemical, flammability, and/or toxicity properties of the substances used or

produced during the pretreatment process.

The CO2 and H2S would be removed using an activated methyldiethanolamine (a-MDEA

or amine)system. Amine is commonly used to remove CO2 and H2S in natural gas. The amine

solution would be clear or pale yellow with an ammonia odor and is completely soluble in water.

The amine solution could result in eye and skin irritation or burns if contacted, upper respiratory

tract irritation or death if inhaled, and can be toxic if swallowed. Amine vapor is also flammable

in concentrations between approximately 1.4 and 8.8 percent, but would be handled at

temperatures below the point at which it could produce enough vapors to form a flammable

mixture. The piping and equipment containing amine would be contained if spilled, as discussed

under “Impoundment Sizing” in section 4.12.5. Due to its low vapor pressure, the amine

solution would not pose a significant hazard to the public, which would have no access to the onsite areas.

Carbon dioxide is a common component of natural gas. The CO2 would be in its gaseous

state and would be colorless and odorless. Carbon dioxide could result in eye and skin irritation

if contacted, and respiratory irritation or death if inhaled. Carbon dioxide is non-flammable.

Cheniere proposes a design capacity to handle up to 2 percent by volume (% vol)CO2, in the

natural gas stream. The CO2 would be removed from the natural gas stream to prevent fouling in

the liquefaction process and would be accumulated to concentrations exceeding 93% vol during

regeneration of the amine. After regeneration, the CO2 would eventually be vented to the

atmosphere after passing through scavenger beds and a thermal oxidizer. Due to the limited

amount of CO2 processed and high concentrations needed to cause asphyxiation, safety hazards

associated with the release of CO2 would be localized at the exit of the thermal oxidizer stack,

and therefore, the CO2 would not pose a significant safety hazard to the public, which would

have no access to the on-site areas.

Hydrogen sulfide may also exist in the natural gas stream. Hydrogen sulfide would be in

its gaseous state and would be colorless with a rotten egg odor. Hydrogen sulfide could result in

eye and skin irritation if contacted, and is toxic and can result in death if inhaled. Cheniere
Environmental Impact Statement 4-144 Corpus Christi LNG

proposes a design capacity to handle up to 4 parts per million by volume (ppm-v)H2S, however

lower concentrations would be expected in the natural gas stream. The H2S would be removed

from the natural gas stream from the amine system to prevent downstream corrosion and fouling

in the liquefaction process. During this process, H2S may accumulate to concentrations up to

approximately 0.016% vol during regeneration of the amine. After regeneration, the H2S would

be sent through scavenger beds to be removed. The spent scavenger would be disposed of offsite

at a licensed facility and would not pose a significant safety hazard to the public. In the case of a

release of H2S prior to reaching the scavenger beds, Cheniere has provided hazard modeling, as

described in section 4.12.5.

Mercury may exist in the natural gas stream, but is not expected to be present. Mercury

would be in a liquid state and would be a metallic silver color and is odorless. Mercury could

result in toxic effects, including death, if contacted, ingested, or inhaled in certain doses.

Cheniere proposes a design capacity to handle up to 20 micrograms per standard cubic meter

(μg/Sm3)of mercury. Mercury would be removed to prevent corrosion and potential liquid

metal embrittlement of downstream aluminum heat exchangers through the use of

sulfur-impregnated activated carbon beds to form mercuric sulfide, which is stable and insoluble.

The sulfur impregnated carbon beds would have enough capacity to last at least four years before

the beds would need to be replaced. Maintenance and safety procedures would cover the proper

replacement and disposal of the mercuric sulfide within the carbon beds and would not pose a

safety hazard to the public, which would have no access to the on-site areas.

In addition to the removal of H2S, CO2, and mercury, Cheniere would also install a heavy

hydrocarbon removal system to remove hydrocarbons that may be present in the natural gas

stream and could freeze and foul the liquefaction process. The hydrocarbons heavier than

methane would be separated out through a series of distillation columns. The lighter

hydrocarbons that exist as liquids under elevated pressures often present in a natural gas

transmission pipeline, such as ethane, propane, and butane, are often referred to as natural gas

liquids (NGLs). The NGLs would not freeze during the liquefaction process and would be

recycled back into the natural gas stream before liquefaction. The NGLs are not toxic, but are

flammable and can present overpressure hazards if ignited. The heavier hydrocarbons that exist

as liquids near atmospheric pressure, such as pentane, hexane, benzene, toluene, ethylbenzene,

and xylene, are referred to as condensates. These components would freeze during the

liquefaction process and damage or foul equipment. Therefore, these components would be

removed from the natural gas stream as liquids and sent to floating roof storage tanks where they

would be either pumped into an existing condensate pipeline or transferred to tanker trucks for

removal in the event that the stabilized condensate does not meet the applicable quality

specifications of the pipeline. Most of the stabilized condensate components are flammable and

some are toxic. Any liquid spill would be contained in impoundments, as discussed under

“Impoundment Sizing”in section 4.12.5. Cheniere has provided modeling in the case of an

accidental release of NGLs and stabilized condensate, also described in section 4.12.5.

After pre-treatment, the treated natural gas would then be liquefied into LNG through a

series of heat exchangers utilizing ethylene, propane, and methane as refrigerants. The LNG

would then be stored on-site in atmospheric storage tanks before being transferred to LNG

carriers for export. The refrigerants would also be stored on-site and periodically re-filled as

needed. The LNG and refrigerants are not toxic, but are flammable and some can present

overpressure hazards if ignited. Any liquid spill would be contained in impoundments, as
Environmental Impact Statement 4-145 Corpus Christi LNG

discussed under “Impoundment Sizing”in section 4.12.5. Cheniere has provided modeling in

the case of an accidental release of LNG and refrigerants, also described in section 4.12.5.

Loss of Containment

A loss of the containment is the initial event that results in all other potential hazards.

The initial loss of containment can result in a liquid and/or gaseous release with the formation of

vapor at the release location, as well as from any liquid that pooled. The fluid released may

present low or high temperature hazards, and may result in the formation of toxic and flammable

vapors. The extent of the hazard will depend on the material released, the storage and process

conditions, and the volumes released.

Cheniere would store LNG at atmospheric pressure and at a cryogenic temperature of

approximately -260°F;liquid ethylene at approximately 45 psig and a cryogenic temperature of

approximately -110°F;and liquid propane at ambient temperature and elevated pressures of

approximately 125 psig, similar to the conditions typically used in propane storage and

distribution. However, lower temperatures of propane would exist during the refrigeration

process and upon a release the rapidly expanding gas may further cool. The NGLs would vary

from approximately -88°F to 316°F and at approximately 40 psig to 620 psig. Condensate

storage would be at near atmospheric pressure and temperature.

Due to the temperature and pressure conditions under which these liquids would be

handled onsite, loss of containment of these liquids could lead to the release of both liquid and

vapor into the immediate area. Contact with either cold liquid or vapor could cause freeze burns

or frostbite for personnel in the immediate area or more serious injury or death depending on the

length of exposure. However, spills would be contained to on-site areas and the cold state of

these releases would be greatly limited due to the continuous mixing with the warmer air. The

cold temperatures from the release would not present a safety hazard to the public, which would

not have access to on-site areas.

These releases may also quickly cool any materials contacted by the liquid on release,

causing extreme thermal stress in materials not specifically designed for such conditions. These

thermal stresses could subsequently subject the material to brittleness, fracture, or other loss of

tensile strength. These temperatures, however, would be accounted for in the design of

equipment and structural supports, and would not be substantially different from the hazards

associated with the storage and transportation of liquid oxygen (-296oF)or several other

cryogenic liquids that have been routinely produced and transported in the United States.

A rapid phase transition (RPT)can occur when a cryogenic liquid is spilled onto water

and changes from liquid to gas, virtually instantaneously. Unlike an explosion that releases

energy and combustion products from a chemical reaction, an RPT is the result of heat

transferred to the liquid inducing a change to the vapor state. RPTs have been observed during

LNG test spills onto water. In some test cases, the overpressures generated were strong enough

to damage test equipment in the immediate vicinity of the LNG release point. The sizes of the

overpressure events have been generally small and are not expected to cause significant damage.

The average overpressures recorded at the source of the RPTs during the Coyote tests have

ranged from 0.2 pounds per square inch (psi)to 11 psi24. These events are typically limited to

24 The Lawrence Livermore National Laboratory conducted seven tests (the Coyote series)on vapor cloud

dispersion, vapor cloud ignition, and RPTs at the Naval Weapons Center in China Lake, California in 1981.
Environmental Impact Statement 4-146 Corpus Christi LNG

the area within the spill and are not expected to cause damage outside of the area engulfed by the

LNG pool. However, a RPT may affect the rate of pool spreading and the rate of vaporization

for a spill on water.

Vapor Dispersion

In the event of a loss of containment, LNG, ethylene, propane, and NGLs would vaporize

on release from any storage or process facilities. Depending on the size of the release, they may

also form a liquid pool and vaporize. Additional vaporization would result from exposure to

ambient heat sources, such as water or soil. When released from a containment vessel or transfer

system, LNG will generally produce 620 to 630 standard cubic feet (ft3)of natural gas for each

cubic foot of liquid. Ethylene will produce approximately 375 ft3of gas for each cubic foot of

liquid. Propane will produce approximately 250 ft3of gas for each cubic foot of liquid. The

composition of NGL would vary throughout the heavy hydrocarbon removal process and may

produce up to 380 ft3of gas for each cubic foot of liquid. In the event of a loss of containment of

stabilized condensate, the stabilized condensate would spill primarily as a liquid and form a pool,

but would vaporize much more slowly than NGL.

The vapor may form a toxic or flammable cloud depending on the material released. The

dispersion of the vapor cloud will depend on the physical properties of the cloud, the ambient

conditions, and the surrounding terrain and structures. Generally, a denser-than-air vapor cloud

would sink to the ground due to the relative density of the vapor to the air and would travel with

the prevailing wind, while a lighter-than-air vapor cloud would rise and travel with the prevailing

wind. The density will depend on the material releases and the temperature of the material. For

example, a LNG release would initially form a denser-than-air vapor cloud and transition to

lighter-than-air vapor cloud as the vapor disperses downwind and mixes with the warm

surrounding air;a liquid ethylene release would form a denser-than-air vapor cloud and

transition to a neutrally buoyant vapor cloud as it mixes with the warm surrounding air;and a

propane, NGL, or condensate release would form a denser-than-air vapor cloud and would

remain denser than the surrounding air, even after warming to ambient temperatures. However,

experimental observations and vapor dispersion modeling indicate a LNG vapor cloud would not

typically be warm, or buoyant, enough to lift off from the ground before the LNG vapor cloud

disperses below its lower flammable limit (LFL).

The vapor cloud would continue to be hazardous until it dispersed below toxic levels

and/or flammable limits. Toxicity is primarily dependent on the concentration of the vapor cloud

in the air and the exposure duration, while flammability of the vapor cloud is primarily

dependent just on the concentration of the vapor when mixed with the surrounding air. In

general, higher concentrations within the vapor cloud would exist near the spill, and lower

concentrations would exist near the edge of the cloud as it disperses downwind.

Toxicity is defined by a number of different agencies for different purposes. Acute

Exposure Guideline Levels (AEGLs)and Emergency Response Planning Guidelines (ERPGs)

are recommended for use by federal, state, and local agencies, as well as the private sector for

emergency planning, prevention, and response activities related to the accidental release of
Environmental Impact Statement 4-147 Corpus Christi LNG

hazardous substances25. Other federal agencies, such as the Department of Energy, EPA, and

NOAA, use AEGLs and ERPGs as the primary measure of toxicity26,27,28.

There are three AEGLs and ERPGs which are distinguished by varying degrees of

severity of toxic effects with AEGL-1 and ERPG-1 (level 1)being the least severe to AEGL-3

and ERPG-3 (level 3)being the most severe. AEGL-1 is the airborne concentration of a

substance that the general population, including susceptible individuals, could experience notable

discomfort, irritation, or certain asymptomatic non-sensory effects. However, these effects are

not disabling and are transient and reversible upon cessation of the exposure. AEGL-2 is the

airborne concentration of a substance above which it is predicted that the general population,

including susceptible individuals, could experience irreversible or other serious, long-lasting

adverse health effects or an impaired ability to escape. AEGL-3 is the airborne concentration of

a substance above which it is predicted that the general population, including susceptible

individuals, could experience life-threatening health effects or death. ERPG levels have similar

definitions, but are based on the maximum airborne concentration below which it is believed

nearly all individuals could be exposed for up to 1 hour without experiencing similar effects

defined in each of the AEGLs. The EPA provides ERPGs (1 hour)and AEGLs at varying

exposure times (10 minutes, 30 minutes, 1 hour, 4 hours, and 8 hours)for a list of chemicals.

AEGLs are used preferentially as they are more inclusive and provide toxicity levels at various

exposure times. The preferential use of AEGLs is also done by DOE and NOAA. The toxic

properties for the various material components stored and processed on-site are tabulated in

table 4.12-1.

25 U.S. Environmental Protection Agency, Sources of Acute Dose Response Information,

http://www.epa.gov/ttn/atw/toxsource/acutesources.html, December 3, 2013.

26 U.S. Department of Energy, Temporary Emergency Exposure Limits for Chemicals: Methods and Practice, DOE

Handbook, DOE-HDBK-1046-2008, August 2008.

27 U.S. Environmental Protection Agency, 40 CFR 68 Final Rule: Accidental Release Prevention Requirements:

Risk Management Programs Under Clean Air Act Section 112(r)(7), 61 Federal Register 31667-31732, Vol. 61, No.

120, Thursday, June 20, 1996.

28 U.S. National Oceanic and Atmospheric Administration, Public Exposure Guidelines,

http://response.restoration.noaa.gov/oil-and-chemical-spills/chemical-spills/resources/public-exposureguidelines.html, December 3, 2013.
Environmental Impact Statement 4-148 Corpus Christi LNG

Table 4.12-1

Toxicity Levels (in ppm) 29,30

Compound AEGL Level 10 min 30 min 60 min 4 hr 8 hr

H2S AEGL1 0.75 0.60 0.51 0.36 0.33

AEGL2 41 32 27 20 17

AEGL3 76 59 50 37 31

n-Hexane AEGL1 - - - - -

AEGL2 4,000 a/ 2,900 a/ 2,900 a/ 2,900 a/ 2,900 a/

AEGL3 12,000 c/ 8,600 b/ 8,600 b/ 8,600 b/ 8,600 b/

Benzene AEGL1 130 73 52 18 9

AEGL2 2,000 a/ 1,100 800 b/ 200

AEGL3 9,700 b/ 5,600 a/ 4,000 a/ 2,000 a/ 990

Toluene AEGL1 200 200 200 200 200

AEGL2 3,100 a/ 1,600 1,200 790 650

AEGL3 13,000 b/ 6,100 a/ 4,500 a/ 3,000 a/ 2,500 a/

EthylBenzene AEGL1 33 33 33 33 33

AEGL2 2,900 1,600 1,100 660 580

AEGL3 4,700 2,600 1,800 1,000 910

Xylenes AEGL1 130 130 130 130 130

AEGL2 2,500 a/ 1,300 a/ 920 a/ 500 400

AEGL3 7,200 b/ 3,600 a/ 2,500 a/ 1,300 a/ 1,000 a/

______________________

a/ =≥10% LFL

b/ =≥50% LFL

c/ =≥100% LFL

In addition, methane and heavier hydrocarbons are classified as simple asphyxiants and

may pose extreme health hazards, including death, if inhaled in significant quantities within a

limited time. Very cold methane and heavier hydrocarbons vapors may also cause freeze burns.

However, the locations of concentrations where cold temperatures and oxygen-deprivation

effects could occur are greatly limited due to the continuous mixing with the warmer air

29 U.S. Environmental Protection Agency, Acute Exposure Guideline Levels,

http://www.epa.gov/oppt/aegl/pubs/chemlist.htm, December 3, 2013.

30 American Industrial Hygiene Association, 2013 ERPG/WEEL Handbook, http://www.aiha.org/getinvolved/AIHAGuidelineFoundation/EmergencyResponsePlanningGuidelines, 2013.
Environmental Impact Statement 4-149 Corpus Christi LNG

surrounding the spill site. For that reason, exposure injuries from contact with releases of

methane and heavier hydrocarbons normally represent negligible risks to the public.

Flammable vapors can develop when a flammable material is above its flash point and

concentrations are between the LFL and the upper flammable limit (UFL). Concentrations

between the LFL and UFL can be ignited, and concentrations above the UFL or below the LFL

would not ignite. The flammable properties for the various material components stored and

processed on-site are tabulated in table 4.12-2.
Environmental Impact Statement 4-150 Corpus Christi LNG

Table 4.12-2

Flammable Properties31

Material Component Flash Point LFL

(% vol)

UFL

(% vol)

Methane -283°F 5.0 15.0

Ethylene -250°F 2.7 36

Ethane -211°F 3.0 12.5

Propane -155°F 2.1 9.5

n-Butane -76°F 1.8 8.5

i-Butane -105°F 1.8 8.4

n-Pentane -56°F 1.4 7.8

i-Pentane -60°F 1.4 7.6

CycloPentane -35°F 1.35 9.4

n-Hexane -7.6°F 1.2 7.5

i-Hexane -20°F 1.2 7.0

CycloHexane -20°F 1.3 8.0

n-Heptane 30°F 1.05 7.0

i-Heptane 0°F 1.05 7.0

n-Octane 63°F 0.80 6.5

i-Octane 10°F 1.0 5.6

n-Nonane 99°F 0.70 5.6

n-Decane 126°F 0.75 5.4

n-Undecane 149°F 0.70 4.8

n-Dodecane 162°F 0.60 4.7

Benzene 11°F 1.4 7.1

Toluene 45°F 1.2 7.1

EthylBenzene 75°F 1.0 6.7

m-Xylene 77°F 1.1 7.0

o-Xylene 75°F 1.1 6.0

p-Xylene 77°F 1.1 7.0

H2S -116°F 4.0 44

31 Society of Fire Protection Engineers, The SFPE Handbook of Fire Protection Engineering, Fourth Edition, 2008.
Environmental Impact Statement 4-151 Corpus Christi LNG

The extent of the affected area and the severity of the impacts on objects within a vapor

cloud would primarily be dependent on the material, quantity, and duration of the initial release,

the surrounding terrain, and the environmental conditions present during the dispersion of the

cloud. Cheniere has modeled the extent of the potential vapor dispersion hazards for the Project,

which is discussed in section 4.12.5.

Flammable Vapor Ignition

If the flammable portion of a vapor cloud encounters an ignition source, a flame would

propagate through the flammable portions of the cloud. In most circumstances, the flame would

be driven by the heat it generates. This process is known as a deflagration, or a flash fire

because of its relatively short duration. However, exposure to a deflagration, or flash fire, can

cause severe burns and death, and can ignite combustible materials within the cloud. Cheniere

has modeled the extent of the potential flammable vapor dispersion hazards for the Project,

which is discussed in section 4.12.5.

If the deflagration in a flammable vapor cloud accelerates to a sufficiently high rate of

speed, pressure waves that can cause damage would be generated. As a deflagration accelerates

to super-sonic speeds, the large shock waves produced, rather than the heat, would begin to drive

the flame, resulting in a detonation. The flame speeds are primarily dependent on the reactivity

of the fuel, the ignition strength and location, the degree of congestion and confinement of the

area occupied by the vapor cloud, and the flame travel distance. Cheniere has modeled the

extent of the potential overpressure hazards for the Project, which is discussed in section 4.12.5.

Once a vapor cloud is ignited, the flame front may propagate back to the spill site if the

vapor concentration along this path is sufficiently high to support the combustion process. When

the flame reaches vapor concentrations above the UFL, the deflagration could transition to a

fireball and result in a pool or jet fire back at the source. A fireball would occur near the source

of the release and would be of a relatively short duration compared to an ensuing jet or pool fire.

The extent of the affected area and the severity of the impacts on objects in the vicinity of a fire

would primarily be dependent on the material, quantity, and duration of the fire, the surrounding

terrain, and the environmental conditions present during the fire. Cheniere has modeled the

extent of the potential radiant heat hazards for the Project, which is discussed in section 4.12.5.

Cascading Events

Fires and overpressures may also cause failures of nearby storage vessels, piping, and

equipment if not properly mitigated. These failures are often termed cascading events or domino

effects and can exceed the consequences of the initial hazard.

The failure of a pressurized vessel could cause fragments of material to fly through the

air at high velocities, posing damage to surrounding structures and a hazard for operating staff,

emergency personnel, or other individuals in proximity to the event. In addition, failure of a

pressurized vessel when the liquid is at a temperature significantly above its normal boiling point

could result in a boiling-liquid-expanding-vapor explosion (BLEVE). BLEVEs can produce

overpressures when the superheated liquid rapidly changes from a liquid to a vapor upon the

release from the vessel. BLEVEs of flammable fluids may also ignite upon its release and cause

a subsequent fireball.
Environmental Impact Statement 4-152 Corpus Christi LNG

Failures of nearby storage vessels, piping, and equipment and the potential for cascading

events are discussed in this section 4.12.5. Cheniere has mitigated the risk for cascading event

hazards for the Project, which is also discussed in section 4.12.5.

4.12.3 Technical Review of the FacilityPreliminaryEngineering Design

Operation of the proposed facility poses a potential hazard that could affect the public

safety if strict design and operational measures to control potential accidents are not applied.

The primary concerns are those events that could lead to an LNG spill of sufficient magnitude to

create an off-site hazard as discussed in section 4.12.2. However, it is important to recognize the

stringent requirements in place for the design, construction, operation, and maintenance of the

facility, as well as the extensive safety systems proposed to detect and control potential hazards.

In general, we consider an acceptable design to include various layers of protection or

safeguards in the facility design to reduce the risk of a potentially hazardous scenario from

developing into an event that could impact the off-site public. These layers of protection are

independent of one another so that any one layer would perform its function regardless of the

action or failure of any other protection layer or initiating event. Such design features and

safeguards typically include:

 A facility design that prevents hazardous events through the use of inherently safer

designs;suitable materials of construction;operating and design limits for process piping,

process vessels, and storage tanks;adequate design for wind, flood, seismic, and other

outside hazards;

 Control systems, including monitoring systems and process alarms, remotely-operated

control and isolation valves, and operating procedures to ensure the facility stays within

the established operating and design limits;

 Safety-instrumented prevention systems, such as safety control valves and emergency

shutdown systems, to prevent a release if operating and design limits are exceeded;

 Physical protection systems, such as appropriate electrical area classification, proper

equipment and building spacing, pressure relief valves, spill containment, and structural

fire protection, to prevent escalation to a more severe event;

Site security measures for controlling access to the facility, including security inspections

and patrols;response procedures to any breach of security and liaison with local law enforcement

officials;and

On-site and off-site emergency response, including hazard detection and control

equipment, firewater systems, and coordination with local first responders to mitigate the

consequences of a release and prevent it from escalating to an event that could impact the public.

The inclusion of such protection systems or safeguards in a facility design can minimize

the potential for an initiating event to develop into an incident that could impact the safety of the

off-site public. In addition, siting of the facility with regard to potential off-site consequences

can be further used to minimize impacts to public safety. As discussed in section 4.12.4, DOT’s

regulations in 49CFR 193, Subpart B require a siting analysis be performed by Cheniere.

As part of the application, Cheniere provided a FEED for the Project. In developing the

FEED, Cheniere conducted a hazard identification study of the process flow diagram (PFD)to
Environmental Impact Statement 4-153 Corpus Christi LNG

identify potential risk scenarios. This helped to establish the required safety control levels and

identify whether additional process and safety instrumentation, mitigation, and/or administrative

controls would be needed. We have analyzed the information filed by Cheniere to determine the

extent that layers of protection or safeguards to enhance the safety, operability, and reliability of

the facility are included in the FEED.

The objectives of our FEED review focused on the engineering design and safety

concepts of the various protection layers, as well as the projected operational reliability of the

proposed facilities. The design would use materials of construction suited to the pressure and

temperature conditions of the process design. Piping would be designed in accordance with

ASME B31.3. Pressure vessels would be designed in accordance with ASME Section VIII and

the storage tanks would be designed in accordance with American Petroleum Institute (API)

Standard 620, per 49 CFR 193 and the National Fire Protection Association’s Standard 59A

(NFPA 59A). All LNG storage tanks would also include boil-off gas compression or reliquefaction to prevent the release of boil-off to the atmosphere in accordance with NFPA 59A

for an inherently safer design. Valves and other equipment would be designed to recommended

and generally accepted good engineering practices. Cheniere states that its facility would be

designed to withstand a sustained wind of 150 mph in accordance with

49CFR 193.2067(b)(2)(i), which would also exceed the 10,000 year mean return interval or 0.5

percent probability of exceedance in a 50-year period requirement in federal regulations of

49CFR 193.2067(b)(2)(ii)32. The base plant elevation would be at a height of 25 feet or greater

NAVD 88 or 25.59feet NGVD 29to minimize the risk of flooding. This elevation would be

able to withstand surge and tide equivalent to 10,000 year mean return interval hurricanes, which

would exceed the 100 year mean return interval Base Flood Elevation of 13 feet NVGD 29as

well as a potential storm surge elevation defined by NOAA for a Category 5 hurricane of 20.3

feet NGVD 2933. As discussed in Section 4.1.4, we also examined the seismic and structural

design of the facility and provided recommendations to deal with the issues identified. In

addition, FAA issued Aeronautical Study 2012-ASW-5296-OE34, indicating there is no

substantial adverse effect on the safe and efficient utilization of the navigable airspace. The

report concluded that there would be no substantial adverse impact for heights of 529feet above

ground level or 550 feet AMSL. No facilities or equipment would exceed this height. The

tallest structures that would be installed would be the flare stacks, LNG storage tanks, and the

gas turbine stacks. The LNG storage tanks would be outfitted with lighting and aircraft warning

lights and the flare stacks and gas turbine stacks would be marked and lighted in accordance with

the FAA Advisory Circular 70/7460-1K, “Obstruction Marking and Lighting.” Cheniere would

need to extend the FAA determination before the expiration date of July 29, 2014.

32 A 150 mph sustained wind speed would correspond to a 183 mph 3-second gust using the Durst Curve in ASCE

7-05 and a 185 mph 3-second gust using a 1.23 gust factor for onshore winds at a coast line recommended in World

Meteorological Organization, Guidelines for Converting Between Various Wind Averaging Periods in Tropical

Cyclone Conditions. These wind speeds are equivalent to approximately a 14,000 year mean return interval or

0.36 percent probability of exceedance in a 50-year period for the site based on ASCE 7-05 wind speed return period

conversions,

33 Surge and tide of 1 in 10,000 year hurricane (21 feet)and sudden hurricane (14 feet)based on a 30 ft mean lower

low water depth in Figure 4.5.1-4and Figure 7-4B, respectively, in API-2INT, Interim Guidance on Hurricane

Conditions in the Gulf of Mexico. A sudden hurricane may not allow for evacuation.

34 Federal Aviation Administration, Determination of no Hazard to Air Navigation,

https://oeaaa.faa.gov/oeaaa/external/letterViewer.jsp?letterID=182024301, Aeronautical Study No. 2012-ASW5296-OE, January 29, 2013.
Environmental Impact Statement 4-154 Corpus Christi LNG

Cheniere would install process control valves and instrumentation to safely operate and

monitor the facility. Alarms would have visual and audible notification in the control room to

warn operators that process conditions may be approaching design limits. Operators would have

the capability to take action from the control room to mitigate an upset.

Cheniere would develop facility operation procedures after completion of the final

design;this timing is fully consistent with accepted industry practice. We have made

recommendations for Cheniere to provide more information on the operating and maintenance

procedures as they are developed, including safety procedures, hot work procedures and permits,

abnormal operating conditions procedures, and personnel training. In addition, we have

recommended measures such as labeling of instrumentation and valves, piping, and equipment

and car-seals/locks, to address human factor considerations and improve facility safety. An

alarm management program would also be in place to ensure effectiveness of the alarms.

Safety valves and instrumentation would be installed to monitor, alarm, shutdown, and

isolate equipment and piping during process upsets or emergency conditions. Safety

instrumented systems would comply with International Society for Automation (ISA)Standard

84.01 and other recommended and generally accepted good engineering practices. We also

made recommendations on the design, installation, and commissioning of instrumentation and

emergency shutdown equipment to ensure appropriate cause and effect alarm or shutdown logic

and enhanced representation of the emergency shutdown valves in the facility control system.

Safety relief valves and flares would be installed to protect the process equipment and

piping. The safety relief valves would be designed to handle process upsets and thermal

expansion within piping, per NFPA 59A and ASME Section VIII, and would be designed based

on API 520, 521, 527, and other recommended and generally accepted good engineering

practices. In addition, we made recommendations to ensure the design and installation of

pressure and vacuum relief devices are adequate.

The security requirements for the Project are governed by 49 CFR 193, Subpart J -

Security. This subpart includes requirements for conducting security inspections and patrols,

liaison with local law enforcement officials, design and construction of protective enclosures,

lighting, monitoring, alternative power sources, and warning signs. Requirements for

maintaining safety of the liquefaction facility are in the Coast Guard regulations in 33 CFR 127.

Requirements for maintaining security of the terminal are in 33 CFR 105.

Title 49, CFR, Part 193, Subpart J – Security, specifies security requirements for the

onshore component of LNG facilities. This subpart includes requirements for conducting

security inspections and patrols, liaison with local law enforcement officials, design and

construction of protective enclosures, lighting, monitoring, alternative power sources, and

warning signs. Security at the facility would be provided by both active and passive systems.

The site would be surrounded by a protective enclosure (i.e., a fence or natural barrier). The

enclosure would be illuminated with not less than 2.2 lux between sunset and sunrise. Title 33

CFR 127 would require even higher intensity lighting at any loading flange and at each work

area. Intrusion detection systems and day/night camera coverage would identify unauthorized

access. A separate security staff would conduct periodic patrols of the plant, and screen visitors

and contractors. The security staff may also assist in maintaining security of the marine terminal

during cargo unloading.
Environmental Impact Statement 4-155 Corpus Christi LNG

In addition to the requirements of Part 193, there are also requirements for maintaining

security of a marine terminal contained in Coast Guard regulations. Title 33, CFR, Part 105, as

authorized by the MTSA, requires all terminal owners and operators to submit a Facility Security

Assessment and a Facility Security Plan to the Coast Guard for review and approval. Some of

the responsibilities of the applicant include, but are not limited to:

 designating a Facility Security Officer with a general knowledge of current security

threats and patterns, risk assessment methodology, and the responsibility for

implementing the Facility Security Assessment and Facility Security Plan and performing

an annual audit for the life of the project;

 conducting a Facility Security Assessment to identify site vulnerabilities, possible

security threats and consequences of an attack, and facility protective measures;

 developing a Facility Security Plan based on the Facility Security Assessment, with

procedures for: responding to transportation security incidents; notification and

coordination with local, state, and federal authorities;prevention of unauthorized access;

measures and equipment to prevent or deter dangerous substances and devices;training;

and evacuation;

 implementing scalable security measures to provide increasing levels of security at

increasing maritime security levels for facility access control, restricted areas, cargo

handling, vessel stores and bunkers, and monitoring;

 ensuring the Transportation Worker Identification Credential program is properly

implemented;and

 reporting all breaches of security and security incidents to the National Response Center.

Under 33 CFR 105, Cheniere would be required to submit a Facility Security Plan to the

Coast Guard for review and approval before commencement of operations.

In the event of a release, drainage systems from LNG storage and liquefaction process

facilities would direct a spill away from equipment in order to minimize flammable vapors from

dispersing to confined, occupied, or public areas and to minimize heat from impacting adjacent

equipment and public areas if ignition occurs. Spacing of vessels and equipment between each

other, from ignition sources, and to the property line would comply with NFPA 59A and

NFPA 30. We also made recommendations to ensure the spacing and designs of impoundments

reduce the thermal radiation distances and reduce the risk of cascading failure of future

condensate tanks. Impoundment systems are further discussed in section 4.12.5.

Cheniere performed a preliminary fire protection evaluation to ensure that adequate

hazard detection, hazard control, and firewater coverage would be installed to detect and address

any upset conditions. Structural fire protection, proposed to prevent failure of structural supports

of equipment and pipe racks, would comply with NFPA 59A and other recommended and

generally accepted good engineering practices. Cheniere would also install hazard detection

systems to detect, alarm, and alert personnel in the area and control room to initiate an

emergency shutdown and/or initiate appropriate procedures, and would meet NFPA 72,

ISA 12.13, and other recommended and generally accepted good engineering practices. Hazard

control devices would be installed to extinguish or control incipient fires and releases, and would

meet NFPA 59A and NFPA 10, 12, 15, 17, and other recommended and generally accepted good
Environmental Impact Statement 4-156 Corpus Christi LNG

engineering practices. Cheniere would provide automatic firewater systems and monitors for use

during an emergency to cool the surface of storage vessels, piping, and equipment exposed to

heat from a fire, and would meet NFPA 59A, 20, 22, and 24 requirements. We have made

recommendations for Cheniere to provide more information on the design, installation, and

commissioning of hazard detection, hazard control, and firewater systems as Cheniere would

further develop this information during the final design phase.

Cheniere would also have emergency procedures in accordance with 49CFR 193 and

33 CFR 127. The emergency procedures would provide for protection of personnel and the

public as well as the prevention of property damage that may occur as a result of incidents at the

facility. Cheniere would also be required to develop an emergency response plan (ERP)in

accordance with the Energy Policy Act of 2005 (EPAct 2005), as discussed further in section

4.12.7.

The use of these protection layers would minimize the potential for an initiating event to

develop into an incident that could impact the safety of the off-site public. As a result of the

technical review of the information provided by Cheniere in the submittal documents, we

identified a number of concerns in information data requests issued on April 8, April 22, and

August 16, 2013 relating to the reliability, operability, and safety of the proposed design.

Cheniere provided written responses on April 26, May 9, May 30, June 5, June 19, September

23, 2013 in response to staff’s questions. However, some of these responses indicated that

Cheniere would correct or modify its design in order to address issues raised in the information

request. As a result, we recommend that:

 Prior to construction of the final design,Cheniere should file with the Secretary,for

review and written approval by the Director of the OEP,information/revisions

pertaining to Cheniere’s responses,as listed in Table 4.12-3 of the EIS,which

indicated features to be included in the final design and documentation.

Table 4.12-3

Cheniere Responses Indicating Features to be Included in the Final Design of the Projects

FERC Data Request Filing Date Cheniere Response Filing Date Data Request Response Number(s)

February 1, 2013 February 21, 2013 60, 73, 77, 78, 80, 81, 82, and 85

February 1, 2013 May 3, 2013 60, 78, and 79

April 8, 2013 April 26, 2013 1, 2, 3, 10, 14, 15, 18, 20, 21, 22, 23,

24, 26, 28, 30, 50, 51, 52, 53, 54, 55,

57, 63, and 79

April 22, 2013 May 9, 2013 5

August 16, 2013 September 5, 2013 2 and 3

August 16, 2013 September 23, 2013 4
Environmental Impact Statement 4-157 Corpus Christi LNG

The FEED and specifications submitted for the proposed facilities to date are

preliminary, but would serve as the basis for any detailed design to follow. If authorization is

granted by the Commission, the next phase of the Project would include development of the final

design, including final selection of equipment manufacturers, process conditions, and resolution

of some safety-related issues. We do not expect that the detailed design information to be

developed would result in changes to the basis of design, operating conditions, major equipment

selections, equipment design conditions, or safety system designs that were presented as part of

the FEED.

A more detailed and thorough hazard and operability review (HAZOP)analysis would be

performed by Cheniere during the final design phase to identify the major hazards that may be

encountered during the operation of facilities. The HAZOP study would be intended to address

hazards of the process, engineering and administrative controls, and would provide a qualitative

evaluation of a range of possible safety, health, and environmental effects which may result from

the design or operation of the facility. Recommendations to prevent or minimize these hazards

would be generated from the results of the HAZOP review.

Once the design has been subjected to a HAZOP review, the design development team

tracks changes in the facility design, operations, documentation, and personnel. Cheniere would

evaluate these changes to ensure that the safety, health, and environmental risks arising from

these changes are addressed and controlled. Resolutions of the recommendations generated by

the HAZOP review would be monitored by FERC staff. We have included a recommendation

that Cheniere should file a HAZOP study on the completed final design.

Information regarding the development of the final design, as detailed below, would need

to be filed with the Secretary for review and written approval by the Director of the OEP before

equipment construction at the site would be authorized. To ensure that the concerns we’ve

identified relating to the reliability, operability, and safety of the proposed design are addressed

by Cheniere, and to ensure that the facility is subject to the Commission’s construction and

operational inspection program, we recommend that the following measures should applyto

the Cheniere Project. Information pertaining to these specific recommendations should be

filed with the Secretaryfor review and written approval bythe Director of OEP either:

prior to initial site preparation; prior to construction of final design; prior to

commissioning;prior to introduction of hazardous fluids;or prior to commencement of

service,as indicated by each specific condition. Specific engineering,vulnerability,or

detailed design information meeting the criteria specified in Order No. 683 (Docket

No. RM06-24-000),including securityinformation,should be submitted as critical energy

infrastructure information pursuant to 18 CFR 388.112. See Critical Energy

Infrastructure Information,Order No. 683,71 Fed. Reg. 58,273(October 3,2006),FERC

Stats. & Regs. 31,228(2006). Information pertaining to items such as: offsite emergency

response; procedures for public notification and evacuation; and construction and

operating reporting requirements,would be subject to public disclosure. All information

should be filed a minimum of 30 days before approval to proceed is requested.

 Prior to initial site preparation,Cheniere should provide quality assurance and

qualitycontrol procedures for construction activities.

 Prior to initial site preparation,Cheniere should file an overall project schedule,

which includes the proposed stages of the commissioning plan.
Environmental Impact Statement 4-158 Corpus Christi LNG

 Prior to initial site preparation,Cheniere should provide procedures for controlling

access during construction.

 Prior to initial site preparation,Cheniere should provide a plot plan of the final

design showing all major equipment,structures,buildings,and impoundment

systems.

 Prior to initial site preparation,Cheniere should file a complete specification of the

proposed LNG tankdesign and installation.

 Prior to initial site preparation,Cheniere should file drawings of the storage tank

piping support structure and support of horizontal piping at grade including pump

columns,relief valves,pipe penetrations,instrumentation,and appurtenances.

 The final design should include change logs that list and explain anychanges made

from the FEED provided in Cheniere’s application and filings. A list of all changes

with an explanation for the design alteration should be provided and all changes

should be clearlyindicated on all diagrams and drawings.

 The final design should provide an up-to-date equipment list, process and

mechanical data sheets,and specifications.

 The final design should include three-dimensional plant drawings to confirm plant

layout for maintenance,access,egress,and congestion.

 The final design should include up-to-date PFDs and Piping and Instrument

Diagrams (P&IDs). The PFDs should include heat and material balances. The

P&IDs should include the following information:

a. equipment tag number,name,size,duty,capacity,and design conditions;

b. equipment insulation type and thickness;

c. storage tankpipe penetration size or nozzle schedule;

d. piping with line number,piping class specification,size,and insulation type

and thickness;

e. piping specification breaks and insulation limits;

f. all control and manual valves numbered;

g. valve high pressure sides and cryogenic ball valve external and internal vent

locations;

h. relief valves with set points;and

i. drawing revision number and date.

 The final design should include a list of all car-sealed and locked valves consistent

with the P&IDs.

 The final design should include a hazard and operabilityreview prior to issuing the

P&IDs for construction. A copyof the review,a list of the recommendations,

and actions taken on the recommendations should be filed.

 The final design should include spill containment system drawings with dimensions

and slopes of curbing,trenches,and impoundments.
Environmental Impact Statement 4-159 Corpus Christi LNG

 The final design should provide electrical area classification drawings.

 The final design should include details of how process seals or isolations installed at

the interface between a flammable fluid system and an electrical conduit or wiring

system meet the requirements of NFPA 59A.

 The final design should provide an air gap or vent installed downstream of process

seals or isolations installed at the interface between a flammable fluid system and an

electrical conduit or wiring system. Each air gap should vent to a safe location and

be equipped with a leakdetection device that: should continuouslymonitor for the

presence of a flammable fluid;should alarm the hazardous condition;and should

shutdown the appropriate systems.

 The final design should include layout and design specifications of the pig trap,inlet

separation and liquid disposal,inlet/send-out meter station,and pressure control.

 The final design should specify fire protection systems,uninterruptable power

supply,emergency power generators,emergency lighting,radio communications

system, control valves, instrumentation, and shutdown systems as Seismic

Category1.

 The final design should specifythat for hazardous fluids,piping and piping nipples

2 inches or less in diameter are to be no less than schedule 160.

 The final design should include a plan for clean-out,dry-out,purging,and tightness

testing. This plan should address the requirements of the American Gas

Association’s Purging Principles and Practice required by49 CFR 193and should

provide justification if not using an inert or non-flammable gas for cleanout,dryout,purging,and tightness testing.

 The final design should specifythat piping and equipment that maybe cooled with

liquid nitrogen is to be designed for liquid nitrogen temperatures,with regard to

allowable movement and stresses.

 The final design should include operating procedures specifying that the Heavies

Removal Column (HRC) and the HRC Reboiler would be drained prior to

restarting the equipment when cryogenic temperatures exist in the HRC or in the

HRC Reboiler.

 The final design should include LNG tank fill flow measurement with high flow

alarm.

 The final design should include boil-off gas (BOG) flow and temperature

measurement for each tank.

 The final design should include an analysis of the structural integrityof the outer

containment of the full containment storage tanks when exposed to a roof tanktop

fire or adjacent tanktop fire.

 The final design should specifythat the minimum flow recycle line from the high

pressure LNG pumps to downstream of the isolation valve to the BOG Recondenser
Environmental Impact Statement 4-160 Corpus Christi LNG

should be the same pressure and temperature rating as the piping at the discharge

of the LNG Send-out pumps.

 The final design should specifythat a checkvalve is provided in the LNG send-out

pump minimum flow recycle piping.

 The final design should specify discharge valving to allow the pumps to be

recirculated without flowing LNG to the vaporizer control valve during initial

startup and provide a cooldown bypass valve to pressurize and cool the vaporizer

inlet piping.

 The final design of the LNG vaporization system should specifythat a checkvalve,

vent valve,and manual isolation valve are to be provided downstream of the outlet

shut-off valve 00XV-56015.

 The final design should specify that the LNG loading arms are equipped with a

manual isolation valve at the base of each arm.

 The final design should specify the minimum distance required for valve

maintenance,between the LNG loading header and the first valve in the discharge

piping to the loading arm.

 The final design should specifythat all drains from high pressure hazardous fluid

systems are to be equipped with double isolation and bleed valves.

 The final design should specifythat the C5+ Condensate Storage Tankfill connection

is located above the maximum liquid level.

 The final design of the wet gas flare should include a drain or should justifywhya

drain is not included.

 The final design should provide the procedures for pressure/leak tests which

address the requirements of ASME VIIIand ASME B31.3,as required by49 CFR

193.

 The final design should include the sizing basis and capacityfor the final design of

pressure and vacuum relief valves for major process equipment,vessels,storage

tanks,and vent stacks.

 The final design should specifythat a pressure relief valve is to be provided on the

upstream side of the vaporizer outlet shutoff valve. The valve should be sized in

accordance with the requirements of NFPA 59A (2001 ed.)Section 5.4.1.

 The final design of the LNG vaporization system should include a relief valve or

operated vent valve sized for thermal relief at the discharge of each vaporizer,

upstream of the isolation valves. This relief valve is in addition to the relief valve

specified in NFPA 59A (2001 ed.)Section 5.4.1 and should be set at a lower pressure.

 The final design should specify that ethylene storage vessels be equipped with

redundant full capacityrelief valves.

 The final design should specify that propane storage vessels be equipped with

redundant full capacityrelief valves.
Environmental Impact Statement 4-161 Corpus Christi LNG

 The final design should specifythat LNG relief valves and LNG drains should not

discharge into the vapor system.

 The final design should include pressure relieving protection for flammable liquid

piping (i.e.,condensate products)which can be isolated byvalves.

 The final design should specify that LNG from relief valves and drains is to be

returned to storage.

 The final design should specifythat all ESD valves are to be equipped with open and

closed position switches connected to the Distributed Control System (DCS)/Safety

Instrumented Systems (SIS).

 The final design should include complete plan drawings of the securityfencing and

of facilityaccess and egress.

 The final design should include the cause-and-effect matrices for the process

instrumentation,fire and gas detection system,and emergency shutdown system.

The cause-and-effect matrices should include alarms and shutdown functions,

details of the voting and shutdown logic,and setpoints.

 The final design should include a plant-wide ESD button with proper sequencing.

 The final design should include automatic shutoff valves at the inlet of the boil-off

compressors.

 The final design should specifythat the truckfill line be equipped with an automatic

shutoff valve.

 The final design should include an updated fire protection evaluation of the

proposed facilities carried out in accordance with the requirements of NFPA 59A

2001,chapter 9.1.2 as required by49 CFR 193. A copyof the evaluation,a list of

recommendations,and actions taken on the recommendations and supporting

justifications should be filed.

 The final design of the hazard detectors should account for the calibration gas when

determining the LFL set points for methane, propane, and ethylene, and

condensate.

 The final design should include complete plan drawings and a list of the hazard

detection equipment. Plan drawings should clearlyshow the location and elevation

of all detection equipment. The list should include the instrument tag number,type

and location,alarm indication locations,and shutdown functions of the proposed

hazard detection equipment.

 The final design should provide a technical review of its proposed facility design

that:

a. identifies all combustion/ventilation air intake equipment and the distances to

anypossible hazardous fluid release (LNG,flammable refrigerants,flammable

liquids and flammable gases);and

b. demonstrates that these areas are adequately covered by hazard detection

devices and indicates how these devices would isolate or shutdown any
Environmental Impact Statement 4-162 Corpus Christi LNG

combustion equipment whose continued operation could add to or sustain an

emergency.

 The final design should include smoke detection in occupied buildings.

 The final design should include hazard detection suitable to detect high

temperatures and smoldering combustion in electrical buildings and control room

buildings.

 The final design should include emergency shutdown of equipment and systems

activated byhazard detection devices for flammable gas,fire,and cryogenic spills,

when applicable.

 The final design should include clean agent systems in the electrical switchgear

and instrumentation buildings.

 The final design should provide complete plan drawings and a list of the fixed and

wheeled dry-chemical,hand-held fire extinguishers,and other hazard control

equipment. Drawings should clearlyshow the location bytag number of all fixed,

wheeled,and hand-held extinguishers. The list should include the equipment tag

number,type,capacity,equipment covered,discharge rate,and automatic and

manual remote signals initiating discharge of the units.

 The final design should include facilityplans and drawings showing the proposed

location of the firewater and anyfoam systems. Plan drawings should clearlyshow

the planned location of firewater and foam piping,post indicator valves,and the

location and area covered by,each monitor,hydrant,hose,water curtain,deluge

system,foam generator,and sprinkler. The drawings should also include piping

and instrumentation diagrams of the firewater and foam systems.

 The final design should specifythat the firewater pump shelter is designed with a

removable roof for maintenance access to the firewater pumps.

 The final design should specifythat the firewater flow test meter is equipped with a

transmitter and that a pressure transmitter is installed upstream of the flow

transmitter. The flow transmitter and pressure transmitter should be connected to

the DCS and recorded. The firewater main header pressure transmitter,00PT33091,should also be connected to the DCSand recorded.

 Prior to commissioning,Cheniere should file plans and detailed procedures for:

testing the integrityof onsite mechanical installation;functional tests;introduction

of hazardous fluids;operational tests;and placing the equipment into service.

 Prior to commissioning, Cheniere should provide a detailed schedule for

commissioning through equipment startup. The schedule should include milestones

for all procedures and tests to be completed: prior to introduction of hazardous

fluids;and during commissioning and startup. Cheniere should file documentation

certifying that each of these milestones has been completed before authorization to

commence the next phase of commissioning and startup will be issued.
Environmental Impact Statement 4-163 Corpus Christi LNG

 Prior to commissioning,Cheniere should tag all instrumentation and valves in the

field,including drain valves,vent valves,main valves,and car-sealed or locked

valves.

 Prior to commissioning,Cheniere should label equipment with equipment tag

number and piping with fluid service and direction of flow in the field in addition to

the pipe labeling requirements of NFPA 59A.

 Prior to commissioning, Cheniere should file Operation and Maintenance

procedures and manuals,including safety procedures,hot work procedures and

permits,abnormal operating conditions reporting procedures,and management of

change procedures and forms.

 Prior to commissioning,Cheniere should maintain a detailed training log to

demonstrate that operating staff has completed the required training.

 Prior to commissioning,Cheniere should file a tabulated list and drawings of the

proposed hand-held fire extinguishers. The list should include the equipment tag

number,extinguishing agent type,capacity,number,and location. The drawings

should show the extinguishing agent type,capacity,and tag number of all hand-held

fire extinguishers.

 Prior to commissioning,Cheniere should file results of the LNG storage tank

hydrostatic test and foundation settlement results.

 Prior to introduction of hazardous fluids,Cheniere should complete all pertinent

tests (Factory Acceptance Tests,Site Acceptance Tests,Site Integration Tests)

associated with the DCS and SIS that demonstrates full functionality and

operabilityof the system.

 Prior to introduction of hazardous fluids,Cheniere should complete a firewater

pump acceptance test and firewater monitor and hydrant coverage test. The actual

coverage area from each monitor and hydrant should be shown on facility plot

plan(s).

 Prior to commencement of service,Cheniere should develop procedures for offsite

contractors’responsibilities,restrictions,and limitations and for supervision of

these contractors byCheniere staff.

 Prior to commencement of service,Cheniere should notify FERC staff of any

proposed revisions to the securityplan and physical securityof the facility.

 Prior to commencement of service,Cheniere should file progress on construction of

the Terminal in monthly reports. Details should include a summary of activities,

problems encountered, contractor nonconformance/ deficiency logs, remedial

actions taken,and current project schedule. Problems of significant magnitude

should be reported to the FERC within 24 hours.

In addition,we recommend that the following measures should applythroughout

the life of the facility:
Environmental Impact Statement 4-164 Corpus Christi LNG

 The facility should be subject to regular FERC staff technical reviews and site

inspections on at least an annual basis or more frequentlyas circumstances indicate.

Prior to each FERC staff technical review and site inspection,Cheniere should

respond to a specific data request including information relating to possible design

and operating conditions that may have been imposed by other agencies or

organizations. Up-to-date detailed piping and instrumentation diagrams reflecting

facilitymodifications and provision of other pertinent information not included in

the semi-annual reports described below,including facilityevents that have taken

place since the previouslysubmitted annual report,should be submitted.

 Semi-annual operational reports should be filed with the Secretary to identify

changes in facilitydesign and operating conditions,abnormal operating experiences,

activities (including ship arrivals/departures,quantityand composition of imported

and exported LNG,liquefied and vaporized quantities,boil-off/flash gas,etc.),and

plant modifications including future plans and progress thereof. Abnormalities

should include, but not be limited to: unloading/loading shipping problems,

potential hazardous conditions caused byoff-site vessels,storage tankstratification

or rollover,geysering,storage tank pressure excursions,cold spots on the storage

tanks,storage tank vibrations and/or vibrations in associated cryogenic piping,

storage tank settlement,significant equipment or instrumentation malfunctions or

failures,nonscheduled maintenance or repair (and reasons therefore),relative

movement of storage tank inner vessels,hazardous fluids releases,fires involving

natural gas and/or from other sources,negative pressure (vacuum)within a storage

tankand higher than predicted boil-off rates. Adverse weather conditions and the

effect on the facilityshould also be reported. Reports should be submitted within 45

days after each period ending June 30 and December 31. In addition to the above

items,a section entitled "Significant Plant Modifications Proposed for the Next 12

Months (dates)" should also be included in the semiannual operational reports.

Such information would provide the FERC staff with early notice of anticipated

future construction/maintenance projects at the LNG facility.

 In the event the temperature of anyregion of anysecondarycontainment,including

imbedded pipe supports,becomes less than the minimum specified operating

temperature for the material,the Commission should be notified within 24 hours

and procedures for corrective action should be specified.

 Significant non-scheduled events,including safety-related incidents (e.g.,hazardous

fluid releases,fires,explosions,mechanical failures,unusual over pressurization,

and major injuries)and security related incidents (i.e.,attempts to enter site,

suspicious activities)should be reported to FERC staff. In the event an abnormality

is of significant magnitude to threaten public or employee safety,cause significant

property damage,or interrupt service,notification should be made immediately,

without unduly interfering with any necessary or appropriate emergency repair,

alarm,or other emergencyprocedure. In all instances,notification should be made

to FERC staff within 24 hours. This notification practice should be incorporated

into the LNG facility's emergencyplan. Examples of reportable hazardous fluids

related incidents include:
Environmental Impact Statement 4-165 Corpus Christi LNG

a. fire;

b. explosion;

c. estimated propertydamage of $50,000 or more;

d. death or personal injurynecessitating in-patient hospitalization;

e. release of hazardous fluid for five minutes or more;

f. unintended movement or abnormal loading byenvironmental causes,such as an

earthquake, landslide, or flood, that impairs the serviceability, structural

integrity,or reliabilityof an LNG facilitythat contains,controls,or processes

hazardous fluids;

g. any crack or other material defect that impairs the structural integrity or

reliabilityof an facilitythat contains,controls,or processes a hazardous fluid;

h. any malfunction or operating error that causes the pressure of a pipeline or

facilitythat contains or processes a hazardous fluid to rise above its maximum

allowable operating pressure (or working pressure for LNG facilities)plus the

build-up allowed for operation of pressure limiting or control devices;

i. a leakin a facilitythat contains or processes a hazardous fluid that constitutes

an emergency;

j. inner tank leakage,ineffective insulation,or frost heave that impairs the

structural integrityof an LNG storage tank;

k. anysafety-related condition that could lead to an imminent hazard and cause

(either directlyor indirectlybyremedial action of the operator),for purposes

other than abandonment,a 20 percent reduction in operation of a pipeline or a

facilitythat contains or processes a hazardous fluid;

l. safety-related incidents to hazardous material transportation occurring at or en

route to and from the LNG facility;or

m. an event that is significant in the judgment of the operator and/or management

even though it did not meet the above criteria or the guidelines set forth in an

LNG facility’s incident management plan.

In the event of an incident,the Director of OEP has delegated authority to take

whatever steps are necessaryto ensure operational reliabilityand to protect human

life,health,property or the environment,including authority to direct the LNG

facilityto cease operations. Following the initial companynotification,FERC staff

would determine the need for a separate follow-up report or follow-up in the

upcoming semi-annual operational report. All company follow-up reports should

include investigations results and recommendations to minimize a reoccurrence of

the incident.

In addition to the final design review, we would conduct inspections during construction

and would review additional materials, including quality assurance and quality control plans,

nonconformance reports, and cooldown and commissioning plans, to ensure that the installed

design is consistent with the safety and operability characteristics of the FEED. We would also

conduct inspections during operation to ensure that the facility is operated and maintained in

accordance with the filed design throughout the life of the facility. Based on our analysis and

recommendations presented above, the FEED presented by Cheniere would include acceptable
Environmental Impact Statement 4-166 Corpus Christi LNG

layers of protection or safeguards which would reduce the risk of a potentially hazardous

scenario from developing into an event that could impact the off-site public.

4.12.4 LNG FacilitySiting Requirements

The principal hazards associated with the substances involved in the liquefaction, storage

and vaporization of LNG result from cryogenic and flashing liquid releases, flammable and toxic

vapor dispersion, vapor cloud ignition, pool fires, BLEVEs, and overpressures. As discussed in

section 4.12.3, our FEED review indicates that sufficient layers of protection would be

incorporated into the facility design to mitigate the potential for an initiating event to develop

into an incident that could impact the safety of the off-site public. Siting of the facility with

regard to potential off-site consequences is also required by DOT’s regulations in 49CFR 193,

Subpart B as to ensure that impact to the public would be minimized. The Commission’s

regulations under 18 CFR 380.12(o)(14)require Cheniere to identify how the proposed design

complies with the siting requirements of DOT’s regulations in 49CFR 193, Subpart B. As part

of our review, we used Cheniere’s information, developed to comply with DOT’s regulations, to

assess whether or not the facility would have a public safety impact. The Part 193 requirements

state that an operator or government agency must exercise control over the activities that can

occur within an “exclusion zone,”defined as the area around an LNG facility that could be

exposed to specified levels of thermal radiation or flammable vapor in the event of a release.

Approved mathematical models must be used to calculate the dimensions of these exclusion

zones. The 2001 edition of NFPA 59A, an industry consensus safety standard for the siting,

design, construction, operation, maintenance, and security of LNG facilities, is incorporated into

Part 193 by reference, with regulatory preemption in the event of conflict. The following

sections of Part 193 specifically address the siting requirements applicable to each LNG

container and LNG transfer system:

 Part 193.2001, Scope of part, excludes any matter other than siting provisions

pertaining to marine cargo transfer systems between the marine vessel and the last

manifold or valve immediately before a storage tank.

 Part 193.2051, Scope, states that each LNG facility designed, replaced, relocated

or significantly altered after March 31, 2000, must be provided with siting

requirements in accordance with Subpart B and NFPA 59A (2001). In the event

of a conflict with NFPA 59A (2001), the regulatory requirements in Part 193

prevail.

 Part 193.2057, Thermal radiation protection, requires that each LNG container

and LNG transfer system have thermal exclusion zones in accordance with

Section 2.2.3.2 of NFPA 59A (2001).

 Part 193.2059, Flammable vapor-gas dispersion protection, requires that each

LNG container and LNG transfer system have a dispersion exclusion zone in

accordance with Sections 2.2.3.3 and 2.2.3.4 of NFPA 59A (2001).

For the LNG facilities proposed for the Project, these Part 193 siting requirements would

be applicable to the following equipment:

 Three 47,000,000 gallon (160,000 m3)nominal full containment LNG storage

tanks and associated piping and appurtenances - Parts 193.2057 and 2059require

the establishment of thermal and flammable vapor exclusion zones for LNG
Environmental Impact Statement 4-167 Corpus Christi LNG

tanks. NFPA 59A (2001), Section 2.2.3.2 specifies four thermal exclusion zones

based on the design spill and the impounding area. NFPA 59A (2001), Sections

2.2.3.3 and 2.2.3.4 specify a flammable vapor exclusion zone for the design spill

which is determined with Section 2.2.3.5.

 Two 30-inch-diameter and three 20-inch-diameter LNG transfer lines for the

proposed ship (un)loading docks – Parts 193.2001, 2057, and 2059 require

thermal and flammable vapor exclusion zones for the marine cargo transfer

system. NFPA 59A (2001)does not address LNG transfer systems.

 Twelve in-tank pumps (three 8,806-gallon-per-minute (gpm)pumps and one

4,403-gpm pump for each of the LNG storage tanks)and associated piping and

appurtenances;six 6,569-gpm LNG transfer pumps (one operating and one spare

for each liquefaction train)and associated piping and appurtenances;and two

1,834-gpm LNG sendout pumps (both operating, no spare common to the facility)

and associated piping and appurtenances - Parts 193.2057 and 2059 require

thermal and flammable vapor exclusion zones. NFPA 59A (2001)Section 2.2.3.2

specifies the thermal exclusion zone and Sections 2.2.3.3 and 2.2.3.4 specify the

flammable vapor exclusion zone based on the design spills for containers and

process areas.

 Two 200 million standard cubic feet per day trains of AAVs (both operating, no

spare)with eighteen to twenty fan assisted fin-fan heat exchangers and associated

piping and appurtenances common to the facility - Parts 193.2057 and 2059

require thermal and flammable vapor exclusion zones. NFPA 59A (2001)Section

2.2.3.2 specifies the thermal exclusion zone and Sections 2.2.3.3 and 2.2.3.4

specify the flammable vapor exclusion zone based on the design spills for

containers and process areas.

 Three liquefaction heat exchangers and associated piping and appurtenances,

including a telescoping 16-inch, 24-inch, 30-inch-diameter LNG rundown line,

for each of the proposed 4.5 million tons per annum (mtpa)(approximately 1.9

billion standard cubic feet per day)liquefaction trains - Parts 193.2057 and 2059

require thermal and flammable vapor exclusion zones. NFPA 59A (2001)Section

2.2.3.2 specifies the thermal exclusion zone and Sections 2.2.3.3 and 2.2.3.4

specify the flammable vapor exclusion zone based on the design spills for

containers and process areas.

Previous FERC environmental assessments/impact statements for past projects have

identified inconsistencies and areas of potential conflict between the requirements in Part 193

and NFPA 59A (2001). Sections 193.2057 and 193.2059require exclusion zones for each LNG

container and LNG transfer system, and an LNG transfer system is defined in Section 193.2007

to include cargo transfer system and transfer piping (whether permanent or temporary).

However, NFPA 59A (2001)requires exclusion zones only for “transfer areas,”which is defined

as the part of the plant where the facility introduces or removes the liquids, such as truck loading

or ship-unloading areas. The NFPA 59A (2001)definition does not include permanent plant

piping, such as cargo transfer lines. Section 2.2.3.1 of NFPA 59A (2001)also states that transfer

areas at the water edge of marine terminals are not subject to the siting requirements in that

standard.
Environmental Impact Statement 4-168 Corpus Christi LNG

The DOT has addressed some of these issues in a March 2010 letter of interpretation.35

In that letter, DOT stated that: (1)the requirements in the NFPA 59A (2001)for transfer areas

for LNG apply to the marine cargo transfer system at a proposed waterfront LNG facility, except

where preempted by the regulations in Part 193;(2)the regulations in Part 193 for LNG transfer

systems conflict with NFPA 59A (2001)on whether an exclusion zone analysis is required for

transfer piping or permanent plant piping;and (3)the regulations in Part 193 prevailed as a result

of that conflict. The DOT has determined that an exclusion zone analysis of the marine cargo

transfer system is required.

In FERC environmental assessments/impact statements for past projects, we have also

noted that when the DOT incorporated NFPA 59A into its regulations, it removed the regulation

that required impounding systems around transfer piping. As a result of that change, it is unclear

whether Part 193 or the adopted sections of NFPA 59A (2001)require impoundments for LNG

transfer systems. We note that Part 193 requires exclusion zones for LNG transfer systems, and

that those zones were historically calculated based on impoundment systems. We also note that

the omission of containment for transfer piping is not a sound engineering practice. For these

reasons, we generally recommend containment for all LNG transfer piping within a plant’s

property lines.

Federal regulations issued by the Occupational Safety and Health Administration

(OSHA)under 29CFR 1910.119(Process Safety Management of Highly Hazardous Chemicals;

Explosives and Blasting Agents (PSM)), and the EPA under 40 CFR 68 (Risk Management

Plans)cover hazardous substances, such as methane, propane, and ethylene at many facilities in

the U.S. However, OSHA and EPA regulations are not applicable to facilities regulated under 49

CFR 193. On October 30, 1992, shortly after the promulgation of the OSHA Process Safety

Management regulations, OSHA issued a letter of interpretation that precluded the enforcement

of PSM regulations over gas transmission and distribution facilities. In a subsequent letter on

December 9, 1998, OSHA further clarified that this letter of interpretation applies to LNG

distribution and transmission facilities.

In addition, EPA’s preamble to its final rule in Federal Register, Volume 63, Number 3,

639-645, clarified that exemption from the requirements in 40 CFR 68 for regulated substances

in transportation, including storage incident to transportation, is not limited to pipelines. The

preamble further clarified that the transportation exemption applies to LNG facilities subject to

oversight or regulation under 49CFR 193, including facilities used to liquefy natural gas or used

to transfer, store, or vaporize LNG in conjunction with pipeline transportation. Therefore, the

above OSHA and EPA regulations are not applicable to facilities regulated under 49CFR 193.

As stated in Section 193.2051, LNG facilities must be provided with the siting requirements of

NFPA 59A (2001 edition). The siting requirements for flammable liquids within an LNG

facility are contained in NFPA 59A, Chapter 2:

 NFPA 59A, Section 2.1.1 requires consideration of clearances between flammable

refrigerant storage tanks, flammable liquid storage tanks, structures and plant

equipment, both with respect to plant property lines and each other. This section

also requires that other factors applicable to the specific site that have a bearing

on the safety of plant personnel and surrounding public be considered, including

35 PHMSA Interpretation “Re: Application of the Siting Requirements in Subpart B of 49 CFR Part 193 to the

Mount Hope Bay Liquefied Natural Gas Transfer System”(March 25, 2010).
Environmental Impact Statement 4-169 Corpus Christi LNG

an evaluation of potential incidents and safety measures incorporated in the

design or operation of the facility.

 NFPA 59A Section 2.2.2.2 requires impoundments serving flammable

refrigerants or flammable liquids to contain a 10-minute spill of a single

accidental leakage source or during a shorter time period based upon

demonstrable surveillance and shutdown provisions acceptable to the DOT. In

addition, NFPA Section 2.2.2.5 requires impoundments and drainage channels for

flammable liquid containment to conform to NFPA 30, Flammable and

Combustible Liquids Code.

 NFPA 59A Section 2.2.3.2 requires provisions to minimize the damaging effects

of fire from reaching beyond a property line, and requires provisions to prevent a

radiant heat flux level of 1,600 British thermal units per cubic foot per hour

(Btu/ft2-hr)from reaching beyond a property line that can be built upon. The

distance to this flux level is to be calculated with LNGFIRE or using models that

have been validated by experimental test data appropriate for the hazard to be

evaluated and that are acceptable to DOT.

 NFPA 59A Section 2.2.3.4 requires provisions to minimize the possibility of any

flammable mixture of vapors from a design spill from reaching a property line

that can be built upon and that would result in a distinct hazard. Determination of

the distance that the flammable vapors extend is to be determined with DEGADIS

or alternative models that take into account physical factors influencing LNG

vapor dispersion. Alternative models must have been validated by experimental

test data appropriate for the hazard to be evaluated and must be acceptable to

DOT. Section 2.2.3.5 requires the design spill for impounding areas serving

vaporization and process areas to be based on the flow from any single accidental

leakage source.

For the following liquefaction facilities that are proposed for the Project, FERC staff

identified that the siting requirements from Part 193 and NFPA 59A would be applicable to the

following equipment:

 Three liquefaction heat exchangers and associated piping and appurtenances for

each of the proposed 4.5 mtpa (approximately 1.9billion standard cubic feet per

day)liquefaction trains;

 Three 75,961-gallon ethylene storage vessels and associated piping and

appurtenances common to the facility;

 Two 235,597-gallon propane storage vessels and associated piping and

appurtenances common to the facility;

 One 144,000-gallon stabilized condensate storage tank and associated piping and

appurtenances common to the facility;

 Three 65-gpm ethylene pump (one per liquefaction train)and associated piping

and appurtenances;

 Three 200-gpm propane pump (one per liquefaction train)and associated piping

and appurtenances;
Environmental Impact Statement 4-170 Corpus Christi LNG

 Two 100-gpm condensate send-out pumps and associated piping and

appurtenances;

 Twenty-seven reflux pumps (nine per liquefaction train), ranging from 152- to

358-gpm, and associated piping and appurtenances;

 Three 2,340-gpm hot oil pumps and associated piping and appurtenances;and

 Six 53-gpm pentane charge pump (two per liquefaction train)and associated

piping and appurtenances.

4.12.5 LNG FacilitySiting Analysis

Suitable sizing of impoundment systems and selection of design spills on which to base

hazard analyses are critical for establishing an appropriate siting analysis. Although

impoundment capacity and design spill scenarios for storage tank impoundments are well

described by Part 193, a clear definition for other impoundments is not provided either directly

by the regulations or by the adopted sections of NFPA 59A (2001). Under NFPA 59A (2001)

Section 2.2.2.2, the capacity of impounding areas for vaporization, process, or LNG transfer

areas must equal the greatest volume that can be discharged from any single accidental leakage

source during a 10-minute period or during a shorter time period based upon demonstrable

surveillance and shutdown provisions acceptable to the DOT. However, no definition of single

accidental leakage source is provided in the regulations.

We recommend impoundments to be sized based on the greatest flow capacity from a

single transfer pipe for 10 minutes, while recognizing that different spill scenarios may be used

for the single accidental leakage sources for the hazard calculations required by Part 193. A

similar approach is used with impoundments for process vessels. We recommend these to be

able to contain the contents of the largest process vessel served, while recognizing that smaller

design spills may be appropriate for Part 193 calculations.

4.12.5.1 Impoundment Sizing

Part 193.2181 references NFPA 59A (2001)for siting, which specifies each impounding

system serving an LNG storage tank must have a minimum volumetric liquid capacity of 110

percent of the LNG tank’s maximum design liquid capacity for an impoundment serving a single

tank. We also consider it prudent design practice to provide a barrier to prevent liquid from

flowing to an unintended area (i.e., outside the plant property)in the event that the full

containment storage tank primary and secondary containers have a common cause failure. The

purpose of the barrier is to prevent liquid from flowing off the plant property, and does not

define containment or an impounding area for thermal radiation or flammable vapor exclusion

zone calculations or other code requirements already met by sumps and impoundments

throughout the site.

Table 4.12-4 shows the spill volumes and their corresponding impoundment systems.

Cheniere proposes three full containment LNG storage tanks where the outer tank wall would

serve as the impoundment system. The proposed LNG storage tanks would have a design

maximum volume of 47,463,327 gallons with a maximum potential capacity of 48,030,856

gallons. As shown in Table 4.12-4, the outer tank would have a volumetric capacity of

56,444,124 gallons, which exceeds the 110 percent requirement by 4,234,465 gallons. The outer

tank would contain 119 percent of the design maximum volume and 112 percent of the
Environmental Impact Statement 4-171 Corpus Christi LNG

maximum potential capacity of the inner tank, meeting the Part 193 requirements. Cheniere

would install a raised access road around the perimeter of the facility, which also serves to limit

liquid from flowing off the plant property in the case of a common cause failure of the existing

full containment storage tank primary and secondary containers. The raised access road

surrounding the proposed LNG storage tanks would meet our recommendation that a barrier be

provided to prevent liquid from flowing off plant property.

Potential spills occurring from the LNG Tank withdrawal lines, liquefaction trains, LNG

vaporization, and associated pumps, vessels, equipment, piping and appurtenances would drain

toward trenches and would be directed to the outside battery limit (OSBL)Impoundment. The

trenches would have a rectangular cross-sectional area with a minimum slope of 0.1 percent, and

were confirmed to handle the maximum volumetric flow from any single line. The OSBL

Impoundment would be a cylindrical impoundment, 70 feet in diameter by 19feet deep, with a

usable capacity of approximately 547,000 gallons. The largest spill to the OSBL Impoundment

would be a 10 minute spill volume of 528,340 gallons from a guillotine rupture of the 30-inchdiameter ship transfer (un)loading line. The OSBL Impoundment would also contain spills from

the in-tank pump withdrawal header and the LNG rundown line. The proposed LNG storage

tank would be equipped with four in-tank pumps, three rated at 8,806 gpm and one at 4,403 gpm.

With all four in-tank pumps operating at full rated capacity, the volume for a 10-minute spill

from the in-tank pump withdrawal header would be 308,210 gallons. Any spills from the LNG

rundown line of the liquefaction trains would include two 6,569gpm LNG transfer pumps (one

operating and one spare) and would be sloped toward trenches leading to the OSBL

Impoundment. A 10 minute spill volume from the LNG rundown line assuming three pumps

running (one operational per train)would be approximately 197,070 gallons. The OSBL

Impoundment would also contain spills from the send-out pump header to the vaporizers. Sendout equipment would include two trains utilizing 1,834-gpm send-out pumps. A 10-minute spill

from one of the send-out trains would be 18,340 gallons. These spills would all be contained in

the OSBL Impoundment. The proposed OSBL Impoundment would also be able to contain

spills from the largest vessels in these areas, including three 75,961-gallon ethylene storage

vessels, two 235,597-gallon propane storage vessels, two approximately 176,000-gallon capacity

dry gas flare knockout vessels.

Potential spills occurring from the ship transfer line and associated vessels, equipment,

piping and appurtenances would drain toward troughs, trenches, and swales and would be

directed to the Jetty Impoundment. The swales would have trapezoidal cross-sectional areas

with a minimum slope of 0.1 percent, and were confirmed to handle the maximum volumetric

flow of 52,384 gpm from the transfer line. The Jetty Impoundment would also be a cylindrical

impoundment, 70 feet in diameter by 19 feet deep, with a usable capacity of approximately

547,000 gallons. The largest spill to the Jetty Impoundment would be a 10-minute spill volume

of 528,340 gallons from a guillotine rupture of the 30-inch-diameter ship transfer (un)loading

line.

Cheniere proposes to install a stabilized condensate product storage tanks with a

maximum design volumetric capacity of 237,945 gallons. Containment for the stabilized

condensate storage tank would be provided by a concrete pad and wall with dimensions of

150 feet-long by 90 feet-wide by 4 feet-high, and a usable volume of approximately

403,948 gallons.
Environmental Impact Statement 4-172 Corpus Christi LNG

Cheniere proposes to install a 30,551-gallon amine storage tank within a 50-foot-long by

48-foot-wide by 4-foot-high diked area and a 149,905-gallon amine surge tank within a 70-footlong by 50-foot-wide by 6-foot, 6-inch-high diked area. The diked areas would have usable

volumetric capacities of 71,813 gallons and 170,812 gallons, respectively. The Solvent

Regenerator, Solvent Flash Drum, Scavenger Tank, Spent Scavenger Tank, Thermal Oxidizer

KO Drum, and Hot Oil Surge Drum would also have separate containment, as shown in table

4.12-4.

Table 4.12-4

Impoundment Area Sizing

Source Spill Size

(gallons) Impoundment System

Impoundment

Size

(gallons)

LNG Storage Tank 48,030,856 Outer Tank Concrete Wall 56,444,124

Ship Transfer line (north) 528,340 OSBLImpoundment 547,000

In-Tank Pump Withdrawal Header 308,210 OSBLImpoundment 547,000

LNG Rundown Line 197,070 OSBLImpoundment 547,000

Sendout Pump

Discharge/Vaporizer Inlet 18,340 OSBLImpoundment 547,000

Ethylene Storage Tank 75,961 OSBLImpoundment 547,000

Propane Storage Tank 235,597 OSBLImpoundment 547,000

Dry Gas Flare Knockout Drum 304,581 OSBLImpoundment 547,000

Ship Transfer line (south) 528,340 Jetty Impoundment 547,000

Condensate Storage Tank 237,945 Condensate Containment 403,948

Amine Storage Tank 30,551 Amine Storage Diked Area 71,813

Amine Surge Tank 149,905 Amine Surge Diked Area 170,812

Solvent Regenerator and Solvent

Flash Drum 120,400 Solvent Diked Area 205,714

Scavenger Tank 25,814 Scavenger Tanks and Waste Water Dike 161,908

Spent Scavenger Tank 31,412 Scavenger Tanks and Waste Water Dike 161,908

Waste Water Tank 81,694 Scavenger Tanks and Waste Water Dike 161,908

Thermal Oxidizer KO Drum 3,470 Thermal Oxidizer Curbed Area 22,255

Hot Oil Surge Drum 105,983 Hot Oil Surge Drum Dike 158,210

4.12.5.2 Design Spills

Design spills are used in the determination of the hazard calculations required by

Part 193. Prior to the incorporation of NFPA 59A in 2000, the design spill in Part 193 assumed
Environmental Impact Statement 4-173 Corpus Christi LNG

the full rupture of “a single transfer pipe which has the greatest overall flow capacity”for not

less than 10 minutes (old Part 193.2059(d)). With the adoption of NFPA 59A, the basis for the

design spill for impounding areas serving only vaporization, process, or LNG transfer areas

became the flow from any single accidental leakage source. Neither Part 193 nor NFPA 59A

(2001)defines “single accidental leakage source.”

In a letter to FERC staff, dated August 6, 2013, DOT requested that LNG facility

applicants contact the Office of Pipeline Safety's Engineering and Research Division regarding

the Part 193 siting requirements36. Specifically, the letter stated that DOT required a technical

review of the applicant’s design spill criteria for single accidental leakage sources on a case-bycase basis to determine compliance with Part 193.

In response, Cheniere provided DOT with its design spill criteria and identified leakage

scenarios for the proposed equipment. DOT reviewed the data and methodology Cheniere used

to determine the single accidental leakage sources for the design spills based on the flow from

various leakage sources including piping, containers, and equipment containing LNG,

refrigerants, and other hazardous fluids. On February 10, 2014, DOT provided a letter to FERC

staff stating that DOT had no objection to Cheniere's methodology for determining the single

accidental leakage sources for candidate design spills to be used in establishing the Part 193

siting requirements for the proposed LNG liquefaction facilities37,38. The design spills produced

by this method were identified in the documents reviewed by DOT and have been filed in the

FERC docket for this project. These are the same design spills described in the following

sections.

DOT’s conclusions on the candidate design spills used in the siting calculations required

by Part 193 was based on preliminary design information which may be revised as the

engineering design progresses. If Cheniere’s design or operation of the proposed facility differs

from the details provided in the documents on which DOT based its review, then the facility may

not comply with the siting requirements of Part 193. As a result, we recommend that:

 Prior to the construction of the final design,Cheniere should file with the Secretary

for review and approval bythe Director of OEP,certification that the final design is

consistent with the information provided to DOT as described in the design spill

determination letter dated February10,2014 (Accession Number 20140210-4008).

In the event that anymodifications to the design alters the candidate design spills on

which the Title 49 CFR Part 193siting analysis was based,Cheniere should consult

with DOT on anyactions necessaryto complywith Part 193.

36 August 6, 2013 Letter from Kenneth Lee, Director of Engineering and Research Division, Office of Pipeline

Safety to Terry Turpin, LNG Engineering and Compliance Branch, Office of Energy Projects. Filed in Docket

Number CP12-507 on August 13, 2013. Accession Number 20130813-4005

37 February 10, 2014 Letter “Re: Corpus Christi Liquefaction, LLC, A Subsidiary of Cheniere Energy, Inc., Docket

No. CP12-507-000, Design Spill Determination” from Kenneth Lee to Lauren H. O'Donnell. Filed in Docket

Number CP12-507 on February 10, 2014. Accession Number 20140210-4008

38 PHMSA based this decision on the following documents: (1)DOT letter to FERC notifying applicants to contact

PHMSA for siting requirements, FERC Docket Accession Number 20130813-4005;(2)Corpus Christi Liquefaction

response to FERC/PHMSA Data Request, FERC Docket Accession Numbers 20140128-5154 and 20140128-5155;

(3)Corpus Christi Liquefaction supplemental response to PHMSA, FERC Docket Accession Numbers 20140207-

5085 and 20140207-5086;and (4)Corpus Christi Liquefaction supplemental response to PHMSA, FERC Docket

Accession Numbers 20140210-5100 and 20140210-5101 .
Environmental Impact Statement 4-174 Corpus Christi LNG

As design spills vary depending on the hazard (vapor dispersion, overpressure or radiant

heat), the specific design spills used for the Cheniere siting analysis are discussed under “Vapor

Dispersion Analyses”, “Overpressure Analysis”, and “Thermal Radiation Analysis”.

4.12.5.3 Vapor Dispersion Analyses

As discussed in section 4.12.2, a release may form a toxic or flammable cloud depending

on the material released. A large quantity of flammable material released without ignition would

form a flammable vapor cloud that would travel with the prevailing wind until it either dispersed

below the flammable limit or encountered an ignition source. In order to address these hazards,

49CFR §193.2051 and 193.2059require vapor dispersion evaluation of potential incidents and

exclusion zones in accordance with applicable sections of NFPA 59A (2001). NFPA 59A,

Section 2.1.1 requires consideration of clearances between flammable refrigerant storage tanks,

flammable liquid storage tanks, structures and plant equipment, both with respect to plant

property lines and each other. This section also requires that other factors applicable to the

specific site that have a bearing on the safety of plant personnel and surrounding public be

considered, including an evaluation of potential incidents and safety measures incorporated in

the design or operation of the facility. NFPA 59A, Section 2.2.3.4 also requires provisions to

minimize the possibility of any flammable mixture of vapors from a design spill from reaching a

property line that can be built upon and that would result in a distinct hazard. Taken together,

Part 193 and NFPA 59A (2001)require that flammable vapors either from an LNG tank

impoundment or a single accidental leakage source do not extend beyond a facility property line

that can be built upon and that other potential incidents (e.g., toxic releases)must also be

considered.

Title 49CFR §193.2059requires that dispersion distances be calculated for a 2.5 percent

average gas concentration (one-half the LFL of LNG vapor)under meteorological conditions

which result in the longest downwind distances at least 90 percent of the time. Alternatively,

maximum downwind distances may be estimated for stability Class F, a wind speed of 4.5 mph,

50 percent relative humidity, and the average regional temperature. Similar safety factors (i.e.,

one half the LFL of other flammable materials and one half the AEGL of toxic materials)and

similar parameters (i.e., F stability, 2 meters per second wind speed, 50 percent relative

humidity, average regional temperature, and 0.03 meter surface roughness)have also been

specified for other hazardous fluids.

The regulations in Part 193 specifically approve the use of two models for performing

these dispersion calculations, DEGADIS and FEM3A. The use of alternative models is also

allowed, but must be specifically approved by the DOT. Although Part 193 does not require the

use of a particular source term model, modeling of the spill and resulting vapor production is

necessary prior to the use of vapor dispersion models. In August 2010, the DOT issued Advisory

Bulletin ADB-10-07 to provide guidance on obtaining approval of alternative vapor-gas

dispersion models under Subpart B of 49CFR 193. In October 2011, two dispersion models

were approved by DOT for use in vapor dispersion exclusion zone calculations: PHAST-UDM

Version 6.6 and Version 6.7 (submitted by Det Norske Veritas)and FLACS Version 9.1 Release

2 (submitted by GexCon). PHAST 6.7 and FLACS 9.1, with their built-in source term models,

were used to calculate dispersion distances.

As discussed under “Design Spills”in section 4.12.5, failure scenarios must be selected

as the basis for the Part 193 dispersion analyses. Process conditions at the failure location would
Environmental Impact Statement 4-175 Corpus Christi LNG

affect the resulting vapor dispersion distances. In determining the spill conditions for these

leakage sources, process flow diagrams for the proposed design, used in conjunction with the

heat and material balance information (i.e., flow, temperature, and pressure), can be used to

estimate the flow rates and process conditions at the location of the spill. In general, higher flow

rates would result in larger spills and longer dispersion distances;higher temperatures would

result in higher rates of flashing;and higher pressures would result in higher rates of jetting and

aerosol formation. Therefore, two scenarios may be considered for each design spill:

1. The pressure in the line is assumed to be maintained by pumps and/or hydrostatic

head to produce the highest rate of flashing and jetting (i.e., flashing and jetting

scenario);and

2. The pressure in the line is assumed to be depressurized by the breach and/or

emergency shutdowns to produce the highest rate of liquid flow within a curbed,

trenched, or impounded area (i.e., liquid scenario).

Alternatively, a single scenario for each design spill could be selected if adequately

supported with an assessment of the depressurization calculations and/or an analysis of process

instrumentation and shutdown logic acceptable to DOT.

In addition, the location and orientation of the leakage source must be considered. The

closer a leakage source is to the property line, the higher the likelihood that the vapor cloud

would extend off-site. As most flashing and jetting scenarios would not have appreciable liquid

rainout and accumulation, the siting of impoundment systems would be driven by liquid

scenarios, while siting of piping and other remaining portions of the plant would be driven by

flashing and jetting scenarios.

Cheniere reviewed multiple releases for the liquid scenarios and for the flashing and

jetting scenarios. Cheniere used the following conditions, corresponding to 49CFR §193.2059,

for the vapor dispersion calculations: ambient temperature of 72°F, relative humidity of

50 percent, wind speeds of 1 to 2 meters per second in various directions, atmospheric stability

class of F and a ground surface roughness of 0.03 meter. In addition, a sensitivity analysis to the

wind speed and direction was provided to demonstrate the longest predicted downwind

dispersion distance in accordance with the PHAST and FLACS Final Decisions.

Cheniere accounted for the facility geometry, including the impoundment and trench

geometry details as established by available plant layout drawings. The plant geometry accounts

for any on-site wind channeling that could occur. The releases were initiated after sufficient time

had passed in the model simulations to allow the wind profile to stabilize from effects due to the

presence of buildings and other on-site obstructions.

Vapor Dispersion Design Spill Analyses for LNG

According to table 2.2.3.5 of NFPA 59A, design spills from containers with over the top

withdrawal lines and no bottom penetrations should be the largest flow from the container (i.e.,

storage tank)withdrawal pumps for a 10-minute duration at full-rated capacity. Design spills

from process areas should be single accidental leakage sources for a 10-minute duration.

Cheniere evaluated more than 440 different piping segments, vessels, valves, and other

equipment. Based on the failure frequency, total vapor flow rate, and location of the release,

Cheniere considered different LNG releases with varying release conditions, orientations, wind

speeds, and wind directions as described below. In order to address the highest rate of LNG flow
Environmental Impact Statement 4-176 Corpus Christi LNG

(i.e., liquid scenario), Cheniere evaluated multiple scenarios, including: a)full guillotine ruptures

of the 30-inch withdrawal lines of LNG Storage Tanks 1 and 2, b)a hole equivalent to 10-inchdiameter (1⁄3-diameter)and a full guillotine rupture at various locations in the 30-inch transfer

line from the LNG storage tanks to the Jetty Areas, c)a hole equivalent to 10-inch-diameter

(1⁄3-diameter)in the 30-inch transfer line from Liquefaction Train 1 to the LNG storage tanks,

and d)a hole equivalent to 5.33-inch-diameter (1⁄3-diameter)in the 16-inch transfer line from the

LNG storage tanks to Liquefaction Train 3.

The full guillotine rupture of the withdrawal line from the LNG storage tanks was

assumed to be at the maximum sendout flow rate of 52,834 gpm for a 10-minute duration based

on two of the three tanks operating three of its four pumps at the rated capacities of 8,806 gpm

(or three tanks operating two of its four pumps). This exceeds the maximum flow rate from a

withdrawal line from a single tank with all four pumps running at their maximum pump runout.

This design spill was evaluated at LNG Storage Tank 1 (closest LNG storage tank to the property

line)and at LNG Storage Tank 2 prior to its change in dimensions and relocation farther away

from the property line. LNG Storage Tank 3 would be the farthest from the property line and

LNG vapors would be expected to disperse no farther than LNG Storage Tank 1 or 2. The spills

were assumed to be completely liquid.

The 10-inch-diameter (1⁄3-diameter)equivalent hole in the 30-inch transfer line from the

storage tanks to the Jetty Areas was calculated to produce a 17,119gpm flow rate based on the

orifice equation and process conditions. This spill was evaluated at the send-out equipment

nearest to the property line, at the transition in the direction of the trenchway nearest to the

occupied buildings, and at the West and East Jetty Areas. A full guillotine rupture in the 30-inch

transfer line was also modeled and assumed to be at the be at the maximum sendout flow rate of

52,834 gpm for a 10-minute duration based on two of the three tanks operating three of its four

pumps at the rated capacities of 8,806 gpm (3 pumps for export)and 4,403gpm (1 pump for

sendout). This spill was evaluated at various locations along the transfer line, including at the

OSBL Impoundment, at the send-out equipment nearest to the property line, at the transition in

direction of the spillway nearest to the occupied buildings, and at the Jetty Sump. All spills were

assumed to be completely liquid.

The 10-inch-diameter (1⁄3-diameter)equivalent hole in the 30-inch transfer line from

Liquefaction Train 1 to the LNG storage tanks was assumed to be at a maximum flow rate of

19,677 gpm for a 10-minute duration based on three trains running one of their two pumps at full

rated capacity of 6,569gpm. The spill was evaluated at Liquefaction Train 1 and was assumed

to be completely liquid.

The 5.33-inch-diameter (1⁄3-diameter)equivalent hole in the 16-inch transfer line from

Liquefaction Train 3 to the storage tanks was calculated to produce a 6,374 gpm flow rate based

on the orifice equation and process conditions. The spill was evaluated at Liquefaction Train 3

and was assumed to be completely liquid.

Cheniere used PHAST Version 6.7 to perform diameter, wind, and elevation sensitivity

studies in order to address the highest rate of LNG vapor flow (i.e., flashing and jetting scenario).

The sensitivity analysis led Cheniere to evaluate multiple scenarios, including: a)a full guillotine

rupture of a 3-inch-diameter cooldown line attached to a 16-inch transfer pump discharge, b)a

full guillotine rupture of a 4-inch-diameter line attached to a 16-inch transfer pump discharge, c)

a full guillotine rupture of a 4-inch-diameter line attached to a 10-inch-diameter high pressure
Environmental Impact Statement 4-177 Corpus Christi LNG

sendout pump discharge, d)a hole equivalent to 8-inch-diameter in the 20-inch transfer line from

the shoreline to the East Jetty, and e)a hole equivalent to 2.23-inch-diameter in the LNG storage

tank withdrawal line.

The full guillotine of a 3-inch diameter line was calculated to produce 2,209gpm flow

rate based on the orifice equation and process conditions. The spill was evaluated at

Liquefaction Train 1 and was determined to produce no liquid rainout (i.e., all vapor).

The full guillotine of a 4-inch-diameter cooldown line was calculated to produce

3,927 gpm flow rate based on the orifice equation and process conditions. The spill was

evaluated at Liquefaction Train 3 and was determined to produce no liquid rainout (i.e., all

vapor).

The full guillotine of a 4-inch-diameter line was assumed to produce 2,180 gpm flow rate

for a 10-minute duration based on the pump operating at the maximum flow of 2,180 gpm. The

spill was evaluated at the send-out pump area and was determined to produce no liquid rainout

(i.e., all vapor).

The 8-inch-diameter equivalent hole in the 20-inch transfer line from the shoreline to the

East Jetty was calculated to produce 10,955 gpm based on the design flow rate of the line. The

release was evaluated at the East Jetty and was determine to produce. Shrouds were installed to

minimize jetting effects and resulted in 97 percent rainout.

The 2.23-inch-diameter equivalent hole in the LNG storage tank withdrawal line

representative of a gasket failure was calculated to produce 1,226 gpm based on the orifice

equation. The release was evaluated at the top of the northern most LNG storage tank.

The LNG releases are summarized in table 4.12-5. DOT staff reviewed the methodology

used to select these design spills and had no objection at the time of its review.
Environmental Impact Statement 4-178 Corpus Christi LNG

Table 4.12-5

LNG Design Spills

Scenario Hole Diameter Release location

Pressure

(psig)

Temperature

(

o

F)

Total

Flow

Rate

(gpm)

Liquid

Fraction

(%)

1 30-inch Storage Tank 1 5 -250 52,834 100

2 30-inch Storage Tank 2* 5 -250 52,834 100

3 30-inch OSBLImpoundment 5 -250 52,834 100

4

30-inch,

10-inch Sendout Pump Area 5,35 -250 52,834,17,119 100

5

30-inch,

10-inch Spillway Transition Near Buildings 5,35 -250 52,834,17,119 100

6 30-inch Jetty Impoundment 5 -250 52,834 100

7 10-inch West Jetty 35 -250 17,119 100

8 10-inch East Jetty 35 -250 17,119 100

9 10-inch Liquefaction Train 1 50 -245 19,677 100

10 5.33-inch Liquefaction Train 3 60 -245 6,374 100

11 3-inch Liquefaction Train 1 72 -245 2,209 0

12 4-inch Liquefaction Train 3 72 -245 3,927 0

13 4-inch Sendout Pump Area 1,530 -206 2,180 0

14 8-inch East Jetty 35 -250 10,995 97

15 2.23-inch Storage Tank 1 80 -250 1,226 0

Vapor Dispersion Design Spill Analyses for Other Hazardous Fluids

In addition to the 13 LNG releases evaluated, Cheniere considered 14 other hazardous

fluid releases after using PHAST Version 6.7 to perform diameter sensitivity, wind sensitivity,

and elevation sensitivity studies. The sensitivity analysis led Cheniere to evaluate multiple

scenarios, including: a)a full guillotine rupture of a 3-inch-diameter line attached to a 24-inchdiameter ethylene line from the Ethylene Surge Drum to the Ethylene Economizer at the

Ethylene Cold Box b)a full guillotine rupture of the 2-inch-diameter line attached to a 36-inch

propane line from the Propane Condensers to the Propane Accumulator c)a hole equivalent to

1-inch-diameter in the 4-inch-diameter discharge of the Heavy Reflux Pumps, d)a hole

equivalent to 1-inch-diameter in a 24-inch acid gas line from the Solvent Regenerator Reflux

Drum to the Hydrogen Sulfide Removal Skids at the Acid Gas Removal Unit, e)a hole

equivalent to 1-inch-diameter in the 4-inch-diameter discharge of the Condensate Pumps at the

Condensate Storage Area, f)a full guillotine rupture of the 2-inch-diameter ethylene transfer

hose at the Refrigerant Storage Area, g)a full guillotine rupture of the 2-inch-diameter propane
Environmental Impact Statement 4-179 Corpus Christi LNG

transfer hose at the Refrigerant Storage Area, and h)a full guillotine rupture of the 2-inchdiameter valve on the condensate transfer line at the Condensate Storage Area.

The full guillotine rupture of the 3-inch-diameter line at the Ethylene Cold Box was

calculated to produce 4,571 gpm for a 10-minute duration based on the orifice equation and

process conditions. The spill was evaluated at Liquefaction Trains 1, 2, and 3, and was

determined to produce no liquid rainout (i.e., all vapor).

The full guillotine rupture of the 2-inch-diameter line at the Propane Accumulator was

calculated to produce 1,520 gpm for a 10-minute duration based on the orifice equation and

process conditions. The spill was evaluated at Liquefaction Trains 1, 2, and 3, and was

determined to produce no liquid rainout (i.e., all vapor).

The 1-inch-diameter equivalent hole at the discharge of the Heavy Reflux Pumps was

determined to be at a flow rate of 199gpm for a 10-minute duration based on one of two pumps

operating at maximum flow rate of 199gpm. The spill was evaluated at Liquefaction Train 3,

and was determined to produce the largest amount of vapor.

The 1-inch-diameter equivalent hole at the Acid Gas Removal Unit was calculated to

produce a flow rate of 1,221 gpm based on the orifice equation and process conditions. The spill

was evaluated at Liquefaction Trains 1, 2, and 3, and would produce all vapor.

The 1-inch-diameter equivalent hole at the discharge of the Condensate Pumps was

determined to be at a flow rate of 100 gpm for a 10-minute duration based on one of two pumps

running at rated capacity of 100 gpm. The spill was evaluated at the Condensate Storage Area,

and was determined to produce the largest amount of vapor.

The full guillotine rupture of the 2-inch-diameter ethylene transfer hose was determined

to be at a flow rate of 50 gpm for a 10-minute duration based on the design flow rate from a

delivery truck. The spill was evaluated at the Refrigerant Storage Area, and was determined to

produce no liquid rainout (i.e., all vapor).

The full guillotine rupture of the 2-inch-diameter propane transfer hose was determined

to be at the maximum pump flow rate of 50 gpm for a 10-minute duration based on the design

flow rate from a delivery truck. The spill was evaluated at the Refrigerant Storage Area, and was

determined to produce no liquid rainout (i.e., all vapor).

The full guillotine rupture of the 2-inch-diameter valve on the condensate transfer line

was determined to be at the maximum pump flow rate of 100 gpm for a 10-minute duration

based on the design flow rate from a delivery truck. The spill was evaluated at the Condensate

Storage Area, and was determined to produce no liquid rainout (i.e., all vapor). The LNG

releases are summarized in table 4.12-6. DOT staff reviewed the methodology used to select

these design spills and had no objection at the time of its review.
Environmental Impact Statement 4-180 Corpus Christi LNG

Table 4.12-6

Other Hazardous Design Spills

Scenario Hole

Diameter Release location

Pressure

(psig)

Temperature

(

o

F)

Total

Flow

Rate

(gpm)

Liquid

Fraction

(%)

1 3-inch Ethylene Cold Box of Liquefaction Train 1 323 -18 4,571 0

2 3-inch Ethylene Cold Box of Liquefaction Train 2 323 -18 4,571 0

3 3-inch Ethylene Cold Box of Liquefaction Train 3 323 -18 4,571 0

4 2-inch Propane Accumulator of Liquefaction Train 1 190 105 1,520 0

5 2-inch Propane Accumulator of Liquefaction Train 2 190 105 1,520 0

6 2-inch Propane Accumulator of Liquefaction Train 3 190 105 1,520 0

7 1-inch Heavy Reflux Pumps at Liquefaction Train 3 643 -23 199 94

8 1-inch Acid Gas Removal Unit of Liquefaction Train 1 12.9 122 1,221 0

9 1-inch Acid Gas Removal Unit of Liquefaction Train 2 12.9 122 1,221 0

10 1-inch Acid Gas Removal Unit of Liquefaction Train 3 12.9 122 1,221 0

11 1-inch Condensate Storage Pumps of Condensate

Storage Area 128 116 100 62

12 2-inch Ethylene Transfer Hose of Refrigerant Storage

Area 45 -109 50 0

13 2-inch Propane Transfer Hose of Refrigerant Storage

Area 115 71 50 0

14 2-inch Condensate Transfer Valve of Condensate

Storage Area 125 119 100 0

FLACS was used to predict the extent of the 1⁄2 LFL vapor cloud. Since the acid gas

would contain the toxic component, H2S, and the stabilized condensate would contain toxic

components of benzene, toluene, ethylebenzene, and xylene, Cheniere also calculated the

dispersion distances to toxic threshold exposure limits based on the toxicity levels that were at or

below 1⁄2 AEGLs.

Vapor Dispersion Analyses for LNG and Other Hazardous Fluids

Cheniere proposes to install a series of 20-foot, 12-foot, and 10-foot-high vapor fences, as

shown in figure 4.12-1, as well as a shroud surrounding a portion of their transfer lines near their

East and West Docks to limit the vapor cloud dispersion distances.
Environmental Impact Statement 4-181 Corpus Christi LNG

Figure 4.12-1 Vapor Fences (20 feet high in green; 12 feet high in yellow; 10 feet high in purple)

Cheniere stated that the vapor fences would be routinely inspected by personnel and

repaired as necessary. The design of the vapor fences would be completed during detailed

engineering. In order to ensure that the vapor barriers are maintained throughout the life of the

facility, we recommend that:

 Prior to construction of the final design,Cheniere should file with the Secretaryfor

review and written approval bythe Director of OEP,the details of the vapor fences

as well as procedures to maintain and inspect the vapor barriers provided to meet

the siting provisions of 49 CFR § 193.2059. This information should be filed a

minimum of 30 days before approval to proceed is requested.

As shown in figure 4.12-2, the FLACS results indicated that the vapor dispersion hazards

would primarily remain within the Cheniere property line with the exception of limited areas that

would still remain within areas of legal control by Cheniere through exclusion zone agreements

with Alcoa, Sherwin, and the Port. These exclusion zone agreements have been reviewed by

DOT staff, who raised no objections at the time of review.
Environmental Impact Statement 4-182 Corpus Christi LNG

Figure 4.12-2 Flammable and Toxic Vapor Cloud Dispersion Contours

As a result, we conclude that the siting of the proposed Project would not have a

significant impact on public safety. If the facility is constructed and operated, compliance with

the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and

enforcement program.

All vapor fences would be required to meet 49CFR 193 regulations. However, the

10-foot-high vapor fence along the transfer line was not included in later model submittals.

Therefore, we recommend that:

 Prior to the end of the draft environmental impact statement comment period,

Cheniere should file with the Secretary for review and written approval by the

Director of OEP,clarification if a 10-foot vapor fence would be provided to mitigate

vapor dispersion from releases when the ambient air vaporizers are operational.

4.12.5.4 Overpressure Analysis

As discussed in section 4.12.2, the propensity of a vapor cloud to detonate or produce

damaging overpressures is influenced by the reactivity of the material, the level of confinement

and congestion surrounding and within the vapor cloud, and the flame travel distance. It is

possible that the prevailing wind direction may cause the vapor cloud to travel into a partially

confined or congested area.
Environmental Impact Statement 4-183 Corpus Christi LNG

LNG Vapor Clouds

As adopted by Part 193, Section 2.1.1 of NFPA 59A (2001)requires an evaluation of

potential incidents and safety measures incorporated in the design or operation of the facility be

considered. As discussed under “Flammable Vapor Ignition”in section 4.12.2, unconfined LNG

vapor clouds would not be expected to produce damaging overpressures.

The potential for unconfined LNG vapor cloud detonations was investigated by the Coast

Guard in the late 1970s at the Naval Weapons Center in China Lake, California. Using methane,

the primary component of natural gas, several experiments were conducted to determine whether

unconfined LNG vapor clouds would detonate. Unconfined methane vapor clouds ignited with

low-energy ignition sources (13.5 joules), produced flame speeds ranging from 12 to 20 mph.

These flame speeds are much lower than the flame speeds associated with a deflagration with

damaging overpressures or a detonation.

To examine the potential for detonation of an unconfined natural gas cloud containing

heavier hydrocarbons that are more reactive, such as ethane and propane, the Coast Guard

conducted further tests on ambient-temperature fuel mixtures of methane-ethane and methanepropane. The tests indicated that the addition of heavier hydrocarbons influenced the tendency

of an unconfined natural gas vapor cloud to detonate. Less processed natural gas with greater

amounts of heavier hydrocarbons would be more sensitive to detonation.

The Coast Guard indicated overpressures of 4 bar and flame speeds of 78 mph were

produced from vapor clouds of 86 percent to 96 percent methane in near stoichiometric

proportions using exploding charges as the ignition source. The 4 bar overpressure was the same

overpressure produced during the calibration test involving exploding the charge ignition source

alone, so it remains unclear that the overpressure was attributable to the vapor deflagration.

Additional tests were conducted to study the influence of confinement and congestion on

the propensity of a vapor cloud to detonate or produce damaging overpressures. The tests used

obstacles to create a partially confined and turbulent scenario, but found that flame speeds

developed for methane were not significantly higher than the unconfined case and were not in

the range associated with detonations.

Although it has been possible to produce damaging overpressures and detonations of

unconfined LNG vapor clouds, the Project would be designed to receive feed gas with methane

concentrations as low as 90 percent, which are not in the range shown to exhibit overpressures

and flame speeds associated with high-order explosions and detonations. Although Cheniere did

not identify any specific LNG imports with methane concentrations below 89percent, Cheniere

had stated that the Project may receive LNG from various foreign sources, and has considered

methane concentrations as low as 84 percent in the design of the facility. These concentrations

could provide a higher propensity to produce damaging overpressures if ignited, but would be

less reactive than propane or ethylene stored onsite and handled in areas with less congestion and

confinement. In addition, the substantial amount of initiating explosives needed to create the

shock initiation during the limited range of vapor-air concentrations also renders the possibility

of detonation of these vapors at an LNG plant as unrealistic.

Ignition of a confined LNG vapor cloud could result in higher overpressures. In order to

prevent such an occurrence, Cheniere would take measures to mitigate the vapor dispersion and

ignition into confined areas, such as buildings. Building would be located away from process
Environmental Impact Statement 4-184 Corpus Christi LNG

areas and combustion and ventilation air intake equipment would be required to have hazard

detection devices that enable isolation of the air dampers. Hazard detection with shutdown

capability would also be installed at air intakes of combustion equipment whose continued

operation could add to, or sustain, an emergency. In general, the primary hazards to the public

from an LNG spill that disperses to an unconfined area, either on land or water, would be from

dispersion of the flammable vapors or from radiant heat generated by a pool fire.

Vapor Clouds from Other Hazardous Fluids

In comparison with LNG vapor clouds, there is a higher potential for unconfined propane

clouds to produce damaging overpressures, and an even higher potential for unconfined ethylene

vapor clouds to produce damaging overpressures. Unconfined ethylene vapor clouds also have

the potential to transition to a detonation much more readily than propane. This has been shown

by multiple experiments conducted by the Explosion Research Cooperative to develop predictive

blast wave models for low, medium, and high reactivity fuels and varying degrees of congestion

and confinement39. The experiments used methane, propane, and ethylene, as the respective low,

medium, and high reactivity fuels. In addition, the tests showed that if methane, propane, or

ethylene is ignited within a confined space, such as in a building, they all have the potential to

produce damaging overpressures. The refrigerant streams would contain all three of these

components (i.e., methane, propane, and ethylene). Therefore, a potential exists for unconfined

vapor clouds that could produce damaging overpressures in the event of a release of propane or

ethylene.

In order to evaluate this hazard, Cheniere used FLACS to perform an overpressure

analysis. Cheniere used the vapor dispersion results, previously discussed in “Vapor Dispersion

Analyses”. Due to the highest reactivity, releases of ethylene from the liquefaction process area

dispersing to the most confined and congested regions of the plant were evaluated in the

overpressure analyses. Various ignition locations and times were evaluated to predict the worst

case overpressure distances. Releases of methane and propane and subsequent ignition would be

less severe due to their lower reactivity. The overpressure scenarios evaluated are summarized

in table 4.12-7.

Table 4.12-7

Overpressure Scenarios

Scenario Material Release Locations Ignition Location

1 Ethylene Ethylene Cold Box of Liquefaction

Train 1

SE Corner underneath Compressor

Building Deck

2 Ethylene Ethylene Cold Box of Liquefaction

Train 1

NE Corner underneath Compressor

Building Deck

3 Ethylene Ethylene Cold Box of Liquefaction

Train 3

SW Corner underneath Compressor

Building Deck

4 Ethylene Ethylene Cold Box of Liquefaction

Train 3

NW Corner underneath Compressor

Building Deck

39Pierorazio, A.J., Thomas, J.K., Baker, Q.A., Kethcum, D.E, "An Update to the Baker-Strehlow-Tang Vapor Cloud

Explosion Prediction Methodology Flame Speed Table", American Institute of Chemical Engineers, Process Safety

Progress, Vol. 24., No. 1, March 2005.
Environmental Impact Statement 4-185 Corpus Christi LNG

As shown in Figure 4.12-3, the FLACS results indicated that the maximum extent of

1 psi overpressures with a safety factor of 2 (i.e., 1⁄2 psi overpressure)would remain within the

Cheniere property line.

Figure 4.12-3 Vapor Cloud Explosion Overpressure Contours

Overpressures were also evaluated at the proposed LNG storage tanks, which would be as

high as 9psi. Cheniere indicated that the LNG storage tank would be designed for this external

blast loading. Cheniere indicated that the LNG storage tanks would be designed to withstand

this overpressure. Project specifications have been included that reflect this. In order to ensure

that the LNG storage tanks can withstand this overpressure, we recommend:

 Prior to construction of the final design,Cheniere should file with the Secretaryfor

review and approval bythe Director of OEP,the details of the LNG storage tank

structural design that demonstrates the tanks can withstand overpressures from

ignition of design spills. This information should be filed a minimum of 30 days

before approval to proceed is requested.

As a result, we conclude that the siting of the proposed Project would not have a

significant impact on public safety. If the facility is constructed and operated, compliance with
Environmental Impact Statement 4-186 Corpus Christi LNG

the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and

enforcement program.

4.12.5.5 Thermal Radiation Analysis

As discussed in section 4.12.2, if flammable vapors are ignited, the deflagration could

propagate back to the spill source and result in a pool fire causing high levels of thermal

radiation (i.e., heat from a fire). In order to address this, 49CFR §193.2051 and §193.2057

require evaluation of thermal radiation hazards of potential incidents and exclusion zones in

accordance with applicable sections of NFPA 59A (2001). Together, Part 193 and NFPA 59A

(2001)specify different hazard endpoints for spills into LNG storage tank containment and spills

into impoundments for process or transfer areas. For LNG storage tank spills, there are three

radiant heat flux levels which must be considered:

 1,600 Btu/ft2-hr - This level can extend beyond the facility’s property line that can

be built upon but cannot include areas that, at the time of facility siting, are used

for outdoor assembly by groups of 50 or more persons;

 3,000 Btu/ft2-hr - This level can extend beyond the facility’s property line that can

be built upon but cannot include areas that, at the time of facility siting, contain

assembly, educational, health care, detention or residential buildings or structures;

and

 10,000 Btu/ft2-hr - This level cannot extend beyond the facility’s property line

that can be built upon.

The requirements for spills from process or transfer areas are more stringent. For these

impoundments, the 1,600 Btu/ft2-hr flux level cannot extend beyond the facility’s property line

that can be built upon. Other potential incidents that could have a bearing on the safety of plant

personnel or surrounding public are also required to be evaluated under NFPA 59A, Section

2.1.1.

Part 193 requires the use of the LNGFIRE3 computer program model developed by the

Gas Research Institute to determine the extent of the thermal radiation distances. Part 193

stipulates that the wind speed, ambient temperature, and relative humidity that produce the

maximum exclusion distances must be used, except for conditions that occur less than 5 percent

of the time based on recorded data for the area. Cheniere selected the following ambient

conditions to produce the maximum exclusion distances: wind speeds of 15 to 28 mph, ambient

temperature of 34°F, and 40 percent relative humidity. We agree with Cheniere’s selection of

atmospheric conditions.

For its LNG storage tank analysis, Cheniere calculated thermal radiation distances using

LNGFIRE3 for the 1,600-, 3,000-, and 10,000-Btu/ft2-hr incident radiant heat levels using an

inner tank concrete wall inner diameter (261 feet)as the pool diameter. This diameter was based

on the initial LNG storage tank design, which is larger than the updated outer concrete wall outer

diameter (258.5 feet)and therefore would be conservative. The flame base was set equal to an

approximate height of the concrete wall (150 feet)above the surrounding terrain. This flame

height was based on the initial LNG storage tank design, which is lower than the updated outer

concrete container height (169.5 feet)and therefore would be conservative. Target heights were

set at the ground level.
Environmental Impact Statement 4-187 Corpus Christi LNG

For its Impoundment analysis, Cheniere calculated thermal radiation distances using

LNGFIRE3 for the 1,600-Btu/ft2-hr incident radiant heat level centered on the OSBL and Jetty

Impoundments. The OSBL and Jetty Impoundments are both 70 feet in diameter. The fire base

is conservatively assumed to be at ground elevation.

For other potential incidents, such as ethylene, propane, or NGL spills or a pool fire

within the condensate storage tank impoundment, Cheniere also calculated thermal radiation

distances using LNGFIRE3 for the 1,600-, 3,000-, and 10,000-Btu/ft2-hr incident radiant heat

levels. Although LNGFIRE3 is specifically designed to calculate thermal radiation flux levels

for LNG pool fires, LNGFIRE3 could also be used to conservatively calculate the thermal

radiation flux levels for flammable hydrocarbons such as ethylene, propane, NGL, and

condensate. Two of the parameters used by LNGFIRE3 to calculate the thermal radiation flux

are the mass burning rate of the fuel and the surface emissive power (SEP)of the flame, which is

an average value of the thermal radiation flux emitted by the fire. The mass burning rate and

SEP of an ethylene, propane, NGL, or condensate fire would be less than an equally sized LNG

fire. Since the thermal radiation from a pool fire is dependent on the mass burning rate and SEP,

the thermal radiation distances required for ethylene, propane, NGL, and condensate fires would

not extend as far as the exclusion zone distance previously calculated for an LNG fire in the

same sump. For condensate spills into the condensate impoundment, Cheniere modeled a pool

fire within the impoundment, which measures 150ft by 90ft. The flame base was conservatively

assumed to be at ground level.

As shown in table 4.12-8 and figure 4.12-4, the 10,000-, 3,000-, and 1,600-Btu/ft2-hr heat

fluxes from the LNG storage tank, OSBL Impoundment, Jetty Impoundment, and condensate

storage impoundment would remain within the facility property lines. In addition, as shown in

figure 4.12-1, radiant heat flux from the flares would not impact personnel or the public.

Table 4.12-8

Thermal Radiation Exclusion Zones for Impoundment Basins

Flux Level

(Btu/ft2-hr )

LNG Storage Tank Outer

Containment (ft) a/

OSBL

Impoundment (ft) a/

Jetty Impoundment

(ft) a/

Condensate Storage Tank

Dike

(ft) a/

Front Side

10,000 358 200 200 335 338

3,000 748 269 269 457 440

1,600 955 317 317 530 501

______________________

a/ from center of impoundment
Environmental Impact Statement 4-188 Corpus Christi LNG

Figure 4.12-4 Thermal Radiation Exclusion Zones 1,600-BTU for Storage Tank and Impoundments

Fires from trenches would not be expected to extend beyond the vapor dispersion

distances from the trenches and would not be expected to be of sufficient duration to warrant a

hazard to the public. FERC staff also evaluated jet fires from various piping and found that the

jet fires radiant heat to 5 kiloWatts per square meter (kW/m2)would extend a limited extent

beyond the property line, and not onto any structures. In addition, it is possible that the vapor

fences may in fact block the radiant heat from extending beyond the property line.

As a result, we conclude that the siting of the proposed Project would not have a

significant impact on public safety. If the facility is constructed and operated, compliance with

the requirements of 49 CFR 193 would be addressed as part of DOT’s inspection and

enforcement program.

4.12.5.6 Cascading Events

Although Cheniere proposes to install the propane and ethylene storage vessels away

from other equipment, the propane and ethylene storage vessels could be subject to radiant heat

exposure from a LNG storage tank roof top fire. In order to mitigate this potential, Cheniere

proposes to install radiant heat shields to protect the ethylene and propane storage vessels. The

radiant heat shields would result in negligible risk of a BLEVE occurring at the refrigerant

storage area from a LNG storage tank roof top fire.
Environmental Impact Statement 4-189 Corpus Christi LNG

In addition, Cheniere would have pressure and level instrumentation, fire detection,

emergency isolation and depressurization valves, passive fire protection, fire suppression units,

and remotely activated firewater monitors to mitigate the potential of a BLEVE from an adjacent

jet fire. As a result, we conclude that the siting of the proposed Project would not have a

significant impact on public safety.

4.12.6 LNG Carrier Hazards

Since 1959, ships have transported LNG without a major release of cargo or a major

accident involving an LNG carrier. There are more than 370 LNG carriers in operation routinely

transporting LNG between more than 100 import/export terminals currently in operation

worldwide. Since U.S. LNG terminals first began operating under FERC jurisdiction in the

1970s, there have been more than 2,600 individual LNG carrier arrivals at terminals in the U.S.

For more than 40 years, LNG shipping operations have been safely conducted in U.S. ports and

waterways.

Cheniere has not identified specific source(s)for LNG import or export destinations for

the proposed Project. LNG could be obtained from terminals throughout the world and delivered

by LNG carriers to the proposed Terminal. There are 19 countries which provide LNG for

export: Algeria; Angola, Australia, Brunei, Egypt, Equatorial Guinea, Indonesia, Libya,

Malaysia, Nigeria, Norway, Oman, Peru, Qatar, Russia, Trinidad & Tobago, United Arab

Emirates, United States, and Yemen with another 5 countries intending to develop export

facilities: Columbia, Canada, Iran, Papua New Guinea, and Venezuela. Cheniere has stated that

the proposed Terminal would be for a wide range of LNG import compositions, including from

Trinidad & Tobago (lean LNG)and Nigeria (rich LNG)

LNG from the Terminal may also be exported to any importing terminal throughout the

world for which Cheniere has authorization to export.40 There are 29 countries which have

facilities to receive LNG: Argentina, Belgium, Brazil, Canada, Chile, China, Dominican

Republic, England, France, Greece, India, Indonesia, Italy, Japan, Kuwait, Malaysia, Mexico,

Netherlands, Portugal, Singapore, South Korea, Spain, Sweden, Taiwan, Thailand, Turkey,

United Arab Emirates, United States, and Wales with another 9planned or under construction:

Albania, Croatia, Cyprus, Germany, Ireland, Lithuania, Pakistan, Philippines, and Poland.

Although LNG could be sent to any of these, Cheniere has stated that its export would likely be

to Latin America, Asia, and Europe.

4.12.6.1 Past LNG Carrier Incidents

A review of the history of LNG maritime transportation indicates that there has not been

a serious accident at sea or in a port which resulted in a spill due to rupturing of the cargo tanks.

However, insurance records, industry sources, and public websites identify a number of incidents

involving LNG carriers, including minor collisions with other vessels of all sizes, groundings,

minor LNG releases during cargo unloading operations, and mechanical/equipment failures

typical of large vessels. Some of the more significant occurrences, representing the range of

incidents experienced by the worldwide LNG carrier fleet, are described below:

40 Cheniere has authorization to export LNG to Free-Trade Agreements. Authorization to export LNG to Non-FreeTrade Agreement nations are subjected to DOE approval.
Environmental Impact Statement 4-190 Corpus Christi LNG

 El Paso Paul Kayser grounded on a rock in June 1979in the Straits of Gibraltar

during a loaded voyage from Algeria to the United States. Extensive bottom

damage to the ballast tanks resulted;however, no cargo was released because no

damage was done to the cargo tanks. The entire cargo of LNG was subsequently

transferred to another LNG carrier and delivered to its U.S. destination.

 Tellier was blown by severe winds from its docking berth at Skikda, Algeria in

February 1989 causing damage to the loading arms and the vessel and shore

piping. The cargo loading had been secured just before the wind struck, but the

loading arms had not been drained. Consequently, the LNG remaining in the

loading arms spilled onto the deck, causing fracture of some plating.

 Mostefa Ben Boulaid had an electrical fire in the engine control room during

unloading at Everett, Massachusetts. The ship crew extinguished the fire and the

ship completed unloading.

 Khannur had a cargo tank overfill into the vessel’s vapor handling system on

September 10, 2001, during unloading at Everett, Massachusetts. Approximately

100 gallons of LNG were vented and sprayed onto the protective decking over the

cargo tank dome, resulting in several cracks. After inspection by the Coast

Guard, the Khannur was allowed to discharge its LNG cargo.

 Mostefa Ben Boulaid had LNG spill onto its deck during loading operations in

Algeria in 2002. The spill, which is believed to have been caused by overflow

rather than a mechanical failure, caused significant brittle fracturing of the

steelwork. The vessel was required to discharge its cargo, after which it

proceeded to dock for repair.

 Norman Ladywas struck by the USS Oklahoma City nuclear submarine while

the submarine was rising to periscope depth near the Strait of Gibraltar in

November 2002. The 87,000 m3LNG carrier, which had just unloaded its cargo

at Barcelona, Spain, sustained only minor damage to the outer layer of its double

hull but no damage to its cargo tanks.

 Tenaga Lima grounded on rocks while proceeding to open sea east of Mopko,

South Korea due to strong current in November 2004. The shell plating was torn

open and fractured over an approximate area of 20 by 80 feet, and internal

breaches allowed water to enter the insulation space between the primary and

secondary membranes. The vessel was refloated, repaired, and returned to

service.

 Golar Freeze moved away from its docking berth during unloading on

March 14, 2006, in Savannah, Georgia. The powered emergency release

couplings on the unloading arms activated as designed, and transfer operations

were shut down.

 Catalunya Spirit lost propulsion and became adrift 35 miles east of Chatham,

Massachusetts on February 11, 2008. Four tugs towed the vessel to a safe

anchorage for repairs. The Catalunya Spirit was repaired and taken to port to

discharge its cargo.
Environmental Impact Statement 4-191 Corpus Christi LNG

 Al Gharrafa collided with a container ship, Hanjin Italy, in the Malacca Strait

off Singapore on December 19, 2013. The bow of the Al Gharrafa and the

middle of the starboard side of the Hanjin were damaged. Both ships were safely

anchored after the incident. No losses of LNG, fatalities, or injuries were

reported.

4.12.6.2 LNG Carrier RegulatoryOversight

The Coast Guard exercises regulatory authority over LNG carriers under 46 CFR 154,

which contains the United States safety standards for vessels carrying LNG in bulk. The LNG

carriers visiting the proposed facility would also be constructed and operated in accordance with

the International Maritime Organization (IMO)Code for the Construction and Equipment of

Ships Carrying Liquefied Gases in Bulk and the International Convention for the Safety of Life at

Sea. All LNG carriers entering U.S. waters are required to possess a valid IMO Certificate of

Fitness and either a Coast Guard Certificate of Inspection (for U.S. flag vessels)or a Coast

Guard Certificate of Compliance (for foreign flag vessels). These documents certify that the

vessel is designed and operating in accordance with both international standards and the U.S.

regulations for bulk LNG carriers under Title 46 CFR Part 154.

The LNG carriers which would deliver or receive LNG to or from the proposed facility

would also need to comply with various U.S. and international security requirements. The IMO

adopted the International Ship and Port Facility Security Code in 2003. This code requires both

ships and ports to conduct vulnerability assessments and to develop security plans. The purpose

of the code is to prevent and suppress terrorism against ships;improve security aboard ships and

ashore;and reduce the risk to passengers, crew, and port personnel on board ships and in port

areas. All LNG carriers, as well as other cargo vessels 500 gross tons and larger, and ports

servicing those regulated vessels, must adhere to the IMO standards. Some of the IMO

requirements for ships are as follows:

 ships must develop security plans and have a Vessel Security Officer;

 ships must have a ship security alert system. These alarms transmit ship-to-shore

security alerts identifying the ship, its location, and indication that the security of

the ship is under threat or has been compromised;

 ships must have a comprehensive security plan for international port facilities,

focusing on areas having direct contact with ships;and

 ships may have equipment onboard to help maintain or enhance the physical

security of the ship.

In 2002, the MTSA was enacted by the U.S. Congress and aligned domestic regulations

with the maritime security standards of the International Ship and Port Facility Security Code

and the Code for the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk and

the International Convention for the Safety of Life at Sea. The resulting Coast Guard

regulations, contained in 33 CFR 104, require vessels to conduct vulnerability assessments and

develop corresponding security plans. All LNG carriers servicing the facility would have to

comply with the MTSA requirements and associated regulations while in U.S. waters.

The Coast Guard also exercises regulatory authority over LNG facilities that affect the

safety and security of port areas and navigable waterways under Executive Order 10173;the
Environmental Impact Statement 4-192 Corpus Christi LNG

Magnuson Act (50 USC Section 191);the Ports and Waterways Safety Act of 1972, as amended

(33 USC Section 1221, et seq.);and the MTSA of 2002 (46 USC Section 701). The Coast Guard

is responsible for matters related to navigation safety, carrier engineering and safety standards,

and all matters pertaining to the safety of facilities or equipment located in or adjacent to

navigable waters up to the last valve immediately before the receiving tanks. The Coast Guard

also has authority for LNG facility security plan review, approval, and compliance verification as

provided in Title 33 CFR Part 105.

The Coast Guard regulations in 33 CFR 127 apply to the marine transfer area of

waterfront facilities between the LNG carrier and the first manifold or valve located inside the

containment. Title 33 CFR 127 regulates the design, construction, equipment, operations,

inspections, maintenance, testing, personnel training, firefighting, and security of LNG

waterfront facilities. The safety systems, including communications, emergency shutdown, gas

detection, and fire protection, must comply with the regulations in 33 CFR 127. Under §

127.019, Cheniere would be required to submit two copies of its Operations and Emergency

Manuals to the Coast Guard Captain of the Port (COTP)for examination.

Both the Coast Guard regulations under 33 CFR 127 and FERC regulations under

18 CFR 157.21, require an applicant who intends to build an LNG import facility to submit a

Letter of Intent to the Coast Guard at the same time the pre-filing process is initiated with the

Commission.

In addition to the Letter of Intent, 33 CFR 127 and FERC regulations require each LNG

project applicant to submit a WSA to the cognizant COTP no later than the start of the FERC

pre-filing process. Until a facility begins operation, applicants must annually review their WSAs

and submit a report to the COTP as to whether changes are required. The WSA must include the

following information:

 port characterization;

 risk assessment for maritime safety and security;

 risk management strategies;and

 resource needs for maritime safety, security, and response.

In order to provide the Coast Guard COTPs/Federal Maritime Security Coordinators,

members of the LNG industry, and port stakeholders with guidance on assessing the suitability

of a waterway for LNG marine traffic, the Coast Guard has published a Navigation and Vessel

Inspection Circular –Guidance on Assessing the Suitability of a Waterway for Liquefied Natural

Gas (LNG) Marine Traffic (NVIC 01-11).

As described in 33 CFR 127 and in NVIC 01-11, the applicant develops the WSA in two

phases. The first phase is the submittal of the Preliminary WSA, which begins the Coast Guard’s

review process to determine the suitability of the waterway for LNG marine traffic. The second

phase is the submittal of the Follow-On WSA. This document is reviewed and validated by the

Coast Guard and forms the basis for the agency’s recommendation to the FERC.

The Preliminary WSA provides an outline which characterizes the port community and

the proposed facility and transit routes. It provides an overview of the expected major impacts

LNG operations may have on the port, but does not contain detailed studies or conclusions. This
Environmental Impact Statement 4-193 Corpus Christi LNG

document is used to start the Coast Guard’s scoping process for evaluating the suitability of the

waterway for LNG marine traffic.

The Follow-On WSA must provide a detailed and accurate characterization of the LNG

facility, the LNG tanker route, and the port area. The assessment should identify appropriate risk

mitigation measures for credible security threats and safety hazards. The Follow-on WSA

provides a complete analysis of the topics outlined in the Preliminary WSA. It should identify

credible security threats and navigational safety hazards for the LNG marine traffic, along with

appropriate risk management measures and the resources (federal, state, local, and private sector)

needed to carry out those measures.

NVIC 01-11 directs the use of the three concentric Zones of Concern, based on LNG

carriers with a cargo carrying capacity up to 265,000 m3, used to assess the maritime safety and

security risks of LNG marine traffic. The Zones of Concern are:

 Zone 1 – impacts on structures and organisms are expected to be significant

within 500 meters (1,640 feet). The outer perimeter of Zone 1 is approximately

the distance to thermal hazards of 37.5 kW/m2 (12,000 Btu/ft2-hr)from a pool

fire.

 Zone 2 –impacts would be significant but reduced, and damage from radiant heat

levels are expected to transition from severe to minimal between 500 and

1,600 meters (1,640 and 5,250 feet). The outer perimeter of Zone 2 is

approximately the distance to thermal hazards of 5 kW/m2 (1,600 Btu/ft2-hr)from

a pool fire.

 Zone 3 –impacts on people and property from a pool fire or an un-ignited LNG

spill are expected to be minimal between 1,600 meters (5,250 feet) and a

conservative maximum distance of 3,500 meters (11,500 feet or 2.2 miles). The

outer perimeter of Zone 3 should be considered the vapor cloud dispersion

distance to the LFL from a worst case un-ignited release. Impacts to people and

property could be significant if the vapor cloud reaches an ignition source and

burns back to the source.

Once the applicant submits a complete Follow-On WSA, the Coast Guard reviews the

document to determine if it presents a realistic and credible analysis of the public safety and

security implications from LNG marine traffic in the port.

As required by its regulations (33 CFR 127.009), the Coast Guard is responsible for

issuing a LOR to the FERC regarding the suitability of the waterway for LNG marine traffic with

respect to the following items:

 physical location and description of the facility;

 the LNG carrier’s characteristics and the frequency of LNG shipments to or from

the facility;

 waterway channels and commercial, industrial, environmentally sensitive, and

residential areas in and adjacent to the waterway used by LNG carriers en route to

the facility, within 25 kilometers (15.5 miles)of the facility;

 density and character of marine traffic in the waterway;
Environmental Impact Statement 4-194 Corpus Christi LNG

 locks, bridges, or other manmade obstructions in the waterway;

 depth of water;

 tidal range;

 protection from high seas;

 natural hazards, including reefs, rocks, and sandbars;

 underwater pipes and cables;and

 distance of berthed vessels from the channel and the width of the channel.

The Coast Guard may also prepare an LOR Analysis, which serves as a record of review

of the LOR and contains detailed information along with the rationale used in assessing the

suitability of the waterway for LNG marine traffic.

4.12.6.3 Cheniere’s WaterwaySuitabilityAssessment

In a letter to the Coast Guard dated December 13, 2011, Cheniere submitted a Letter of

Intent and a Preliminary WSA to the COTP, Sector Corpus Christi to notify the Coast Guard that

it proposed to construct an LNG terminal. In the development of the Follow-On WSA, Cheniere

consulted with the Coast Guard, the Area Maritime Security Committee, and other port

stakeholders. As part of its assessment of the safety and security aspects of this project, the

COTP Sector Corpus Christi consulted various safety and security working groups, including the

Area Maritime Security Committee, Harbor Safety Committee, and Corpus Christi Port Security

Working Group. In addition, the Coast Guard participated in meetings with the Port of Corpus

Christi Authority, the Aransas-Corpus Christi Pilots, a focused La Quinta user group, and other

federal, state, and local agencies.

Cheniere submitted the Follow-On WSA to the Coast Guard on August 30, 2012 with an

Addendum submitted on January 28, 2013.

LNG Carrier Routes and Hazard Analysis

An LNG carrier’s transit to and from the Terminal would enter/exit at Port Aransas and

pass by Harbor Island and Pelican Island, before turning at Ingleside at the Bay near Cooks

Island. The LNG carrier would head north by Quinta Island before reaching its final destination

at the Cheniere Project. Pilotage is compulsory for foreign vessels and U.S. vessels under

registry in foreign trade when in U.S. waters. All deep draft ships currently entering the shared

waterway would employ a U.S. pilot. The National Vessel Movement Center in the U.S. would

require a 96-hour advance notice of arrival for deep draft vessels calling on U.S. ports. A LNG

carrier port time with pilotage would be approximately three to four hours for inbound and

outbound transits with transit speeds of approximately 5 to 20 knots depending on the location,

weather, sea state, and vessel traffic in the area. During transit, vessels would be required to

maintain voice contact with controllers and check in on designated frequencies at established

way points.

NVIC 01-11 references the “Zones of Concern”for assisting in a risk assessment of the

waterway. As LNG carriers proceed along the intended track line, Hazard Zone 1 would

encompass coastal areas along Port Aransas, including University of Texas Marine Science

Institute, US Coast Guard Port Aransas Station, and Roberts Point Park. Hazard Zone 1 would
Environmental Impact Statement 4-195 Corpus Christi LNG

also encircle coastal areas along Ingleside consisting primarily of industrial facilities. Portions of

Pelican Island, Cooks Island, and La Quinta Island would also be within Zone 1. Commercial

vessels, recreational and fishing vessels may also fall within Zone 1, depending on their course.

Transit of such vessels through a Zone 1 area of concern can be avoided by timing and course

changes, if conditions permit.

Zone 2 would cover a wider swath of coastal areas along Port Aransas and Ingleside,

including Port Aransas Fire Department and Police Department, and multiple residential,

commercial, industrial, and institutional (e.g., church, school, etc.)buildings. Pelican Island,

Cooks Island, and La Quinta Island would also be entirely within Zone 2.

Zone 3 would span Port Aransas in almost its entirety and larger portions of Ingleside,

including multiple residential, commercial, industrial, and institutional (e.g., church, school, etc.)

buildings.

The areas impacted by the three different hazard zones are illustrated for both accidental

and intentional events in figures 4.12-6 and 4.12-7.

Accidental Sandia Hazard Zone 1 (0-250m)

Accidental Sandia Hazard Zone 2 (250-750m)

Accidental Sandia Hazard Zone 3 (750-1700m)

Figure 4.12-5 Accidental Hazard Zones Along LNG Carrier Route
Environmental Impact Statement 4-196 Corpus Christi LNG

Intentional Sandia Hazard Zone 1 (0-500m)

Intentional Sandia Hazard Zone 2 (500-1600m)

Intentional Sandia Hazard Zone 3 (1600-3500m)

Figure 4.12-6 Intentional Hazard Zones Along LNG Carrier Route

4.12.6.4 Coast Guard Letter of Recommendation and Analysis

In a letter dated March 21, 2013, the Coast Guard issued a LOR and LOR Analysis to

FERC stating that the Corpus Christi Ship Channel from the entrance approach at Port Aransas

to the La Quinta Junction, and the entire length of the La Quinta Channel be considered suitable

for accommodating the type and frequency of LNG marine traffic associated with this Project.

The recommendation was based on full implementation of the strategies and risk management

measures identified to the Coast Guard by Cheniere in its WSA.

Although Cheniere has suggested mitigation measures for responsibly managing the

maritime safety and security risks associated with LNG marine traffic, the necessary vessel

traffic and/or facility control measures may change depending on changes in conditions along the

waterway. The Coast Guard regulations in 33 CFR 127 require that applicants annually review

WSAs until a facility begins operation. Accordingly, Cheniere is required to submit a report to

the Coast Guard identifying any changes in conditions, such as changes to the port environment,

the LNG facility, or the tanker route, that would affect the suitability of the waterway. The Coast

Guard has indicated that Cheniere has provided its annual update, which is currently under

review of the Coast Guard.

The Coast Guard’s LOR is a recommendation on the current status of the waterway to the

FERC, the lead agency responsible for siting the on-shore LNG facility. Neither the Coast

Guard nor the FERC has authority to require waterway resources of anyone other than the
Environmental Impact Statement 4-197 Corpus Christi LNG

applicant under any statutory authority or under the ERP or the Cost Sharing Plan (see

section 4.12.7). As stated in the LOR, the Coast Guard would assess each transit on a case by

case basis to identify what, if any, safety and security measures are necessary to safeguard the

public health and welfare, critical infrastructure and key resources, the port, the marine

environment, and the vessel.

Under the Ports and Waterways Safety Act, the Magnuson Act, the MTSA, and the

Safety and Accountability For Every Port Act, the COTP has the authority to prohibit LNG

transfer or LNG carrier movements within his or her area of responsibility if he or she

determines that such action is necessary to protect the waterway, port or marine environment. If

this Project is approved and if appropriate resources are not in place prior to LNG carrier

movement along the waterway, then the COTP would consider at that time what, if any, vessel

traffic and/or facility control measures would be appropriate to adequately address navigational

safety and maritime security considerations. Therefore, we recommend that:

 Cheniere should receive written authorization from the Director of OEP before

commencement of service at the Terminal. Such authorization would only be

granted following a determination bythe Coast Guard,under its authorities under

the Ports and Waterways SafetyAct,the Magnuson Act,the MTSA,and the Safety

and Accountability For Every Port Act,that appropriate measures to ensure the

safety and security of the facility and the waterway have been put into place by

Cheniere or other appropriate parties.

4.12.7 LNG Facilityand LNG Carrier EmergencyResponse

As required by 49 CFR §193.2059, Cheniere would need to prepare emergency

procedures manuals that provide for: a)responding to controllable emergencies and recognizing

an uncontrollable emergency;b)taking action to minimize harm to the public including the

possible need to evacuate the public;and c)coordination and cooperation with appropriate local

officials. Specifically, §193.2509(b)(3)requires “Coordinating with appropriate local officials in

preparation of an emergency evacuation plan... ”

Section 3A(e)of the NGA, added by Section 311 of the EPAct 2005, stipulates that in

any order authorizing an LNG terminal, the Commission must require the LNG terminal operator

to develop an ERP in consultation with the Coast Guard and state and local agencies. The FERC

must approve the ERP prior to any final approval to begin construction. Therefore, we

recommend that:

 Cheniere should develop an ERP (including evacuation)and coordinate procedures

with the Coast Guard;state,county,and local emergency planning groups;fire

departments;state and local law enforcement;and appropriate federal agencies.

This plan should include at a minimum:

a. designated contacts with state and local emergencyresponse agencies;

b. scalable procedures for the prompt notification of appropriate local officials and

emergency response agencies based on the level and severity of potential

incidents;

c. procedures for notifying residents and recreational users within areas of

potential hazard;
Environmental Impact Statement 4-198 Corpus Christi LNG

d. evacuation routes/methods for residents and public use areas that are within any

transient hazard areas along the route of the LNG marine transit;

e. locations of permanent sirens and other warning devices;and

f. an “emergencycoordinator”on each LNG carrier to activate sirens and other

warning devices.

The ERP should be filed with the Secretary for review and written approval bythe

Director of OEP prior to initial site preparation. Cheniere should notify the FERC

staff of all planning meetings in advance and should report progress on the

development of its ERP at 3-month intervals.

A number of organizations and individuals have expressed concern that the local

community would have to bear some of the cost of ensuring the security and emergency

management of the LNG facility and the LNG carriers while in transit and unloading at the berth.

Section 3A(e)of the Natural Gas Act (as amended by EPAct 2005)specifies that the ERP must

include a Cost-Sharing Plan that contains a description of any direct cost reimbursements the

applicants agree to provide to any state and local agencies with responsibility for security and

safety at the LNG terminal and in proximity to LNG carriers that serve the facility. Therefore,

we recommend that:

 The ERP should include a Cost-Sharing Plan identifying the mechanisms for

funding all Project-specific security/emergency management costs that would be

imposed on state and local agencies. In addition to the funding of direct transitrelated security/emergency management costs,this comprehensive plan should

include funding mechanisms for the capital costs associated with any necessary

security/emergencymanagement equipment and personnel base. Cheniere should

file the Cost-Sharing Plan for review and written approval bythe Director of OEP

prior to initial site preparation.

The Cost-Sharing Plan must specify what the LNG terminal operator would provide to

cover the cost of the state and local resources required to manage the security of the LNG

terminal and LNG carrier, and the state and local resources required for safety and emergency

management, including:

 direct reimbursement for any per-transit security and/or emergency management

costs (for example, overtime for police or fire department personnel);

 capital costs associated with security/emergency management equipment and

personnel base (for example, patrol boats, firefighting equipment);and

 annual costs for providing specialized training for local fire departments, mutual

aid departments, and emergency response personnel; and for conducting

exercises.

The cost-sharing plan must include the LNG terminal operator’s letter of commitment

with agency acknowledgement for each state and local agency designated to receive resources.

4.12.8 Conclusions on FacilityReliabilityand Safety

As part of the NEPA review, Commission staff must assess whether the proposed

facilities would be able to operate safely and securely to minimize potential public impact. Based
Environmental Impact Statement 4-199 Corpus Christi LNG

on our technical review of the preliminary engineering designs, we have made a number of

recommendations to be implemented prior to initial site preparation, prior to construction of final

design, prior to commissioning, prior to introduction of hazardous fluids, prior to

commencement of service, and throughout the life of the facility to enhance the reliability and

safety of the facility and to mitigate the risk of impact to the public.

In addition, we analyzed whether Cheniere would be sited consistently with federal

regulations promulgated by DOT in 49CFR 193. As a cooperating agency, DOT assisted FERC

staff in evaluating whether an applicant’s proposed siting meets the DOT requirements. DOT

reviewed the data and methodology Cheniere used to determine the design spills from various

leakage sources, including piping, containers, and equipment containing hazardous liquids.

Cheniere used those design spills to model hazardous releases, which extended beyond their

property line, but under their legal control through covenants with the adjacent property owners.

On February 10, 2014, DOT provided a letter to FERC staff stating that DOT had no objection to

Cheniere’s methodology for determining the single accidental leakage sources for candidate

design spills to be used in establishing the Part 193 siting requirements for the proposed LNG

liquefaction facilities. In a letter to FERC dated February 10, 2014, DOT stated it has no

objection to Cheniere’s methodology for determining the candidate design spills used to establish

the required siting for its proposed LNG import facility. If a facility is constructed and becomes

operational, the facility would be subject to DOT’s inspection and enforcement program. Final

determination of whether a facility is in compliance with the requirements of 49CFR 193 would

be made by DOT staff.

We also analyzed the potential impacts along the waterway from LNG marine traffic. As

a cooperating agency, the Coast Guard analyzed the suitability of the waterway for LNG marine

traffic. In a letter dated March 21, 2013, the Coast Guard issued a LOR and LOR Analysis to

FERC stating that the Corpus Christi Ship Channel from the entrance approach at Port Aransas

to the La Quinta Junction, and the entire length of the La Quinta Channel be considered suitable

for accommodating the type and frequency of LNG marine traffic associated with this Project.

The recommendation was based on full implementation of the strategies and risk management

measures identified to the Coast Guard by Cheniere in its WSA. Under the Ports and Waterways

Safety Act, the Magnuson Act, the MTSA, and the Safety and Accountability For Every Port

Act, the COTP has the authority to prohibit LNG transfer or LNG carrier movements within his

or her area of responsibility if he or she determines that such action is necessary to protect the

waterway, port or marine environment. If appropriate resources are not in place prior to LNG

carrier movement along the waterway, then the COTP would consider at that time what, if any,

vessel traffic and/or facility control measures would be appropriate to adequately address

navigational safety and maritime security considerations. FERC staff recommends Cheniere

receive written authorization from the Director of OEP before commencement of service at the

Terminal to ensure the Coast Guard has determined that appropriate measures to ensure the

safety and security of the facility and the waterway have been put into place by Cheniere or other

appropriate parties.

Based on our engineering design analysis and recommendations presented in section 4.12

for the Terminal, the no objection by DOT to the design spill methodology and our subsequent

review of the siting analysis for the Terminal, the LOR issued by the Coast Guard concluding the

LNG vessel transit is suitable for LNG marine traffic, and the regulatory requirements for the
Environmental Impact Statement 4-200 Corpus Christi LNG

design, construction, and operation of the Pipeline and Terminal, we conclude that the Project

would not result in significantly increased public safety risks.

4.12.9 Pipeline SafetyStandards

The transportation of natural gas by pipeline involves some incremental risk to the public

due to the potential for accidental release of natural gas. The greatest hazard is a fire or

explosion following a major pipeline rupture.

Methane, the primary component of natural gas, is colorless, odorless, and tasteless. It is

not toxic, but is classified as a simple asphyxiate, possessing an inhalation hazard. If breathed in

high concentration, oxygen deficiency can result in serious injury or death.

Methane has an auto-ignition temperature of 1,000°F and is flammable at concentrations

between 5.0 percent and 15.0 percent in air. An unconfined mixture of methane and air is not

explosive;however, it may ignite and burn if there is an ignition source. A flammable

concentration within an enclosed space in the presence of an ignition source can explode. It is

buoyant at atmospheric temperatures and disperses rapidly in air.

The DOT is mandated to provide adequate protection against risks to life and property

posed by pipeline transportation under Title 49, USC Chapter 601. The DOT’s Pipeline and

Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety administers the

national regulatory program to ensure the safe transportation of natural gas and other hazardous

materials by pipeline. It develops safety regulations and other approaches to risk management

that ensure safety in the design, construction, testing, operation, maintenance, and emergency

response of pipeline facilities. Many of the regulations are written as performance standards

which set the level of safety to be attained and allow the pipeline operator to use various

technologies to achieve safety. PHMSA ensures that people and the environment are protected

from the risk of pipeline incidents. This work is shared with state agency partners and others at

the federal, state, and local level.

The DOT provides for a state agency to assume all aspects of the safety program for

intrastate facilities by adopting and enforcing the federal standards. A state may also act as

DOT's agent to inspect interstate facilities within its boundaries; however, the DOT is

responsible for enforcement actions. Federal inspectors from the DOT Office of Pipeline Safety

perform inspections on interstate natural gas pipeline facilities in Texas.

The DOT pipeline standards are published in Parts 190-199of Title 49of the CFR. Part

192 specifically addresses natural gas pipeline safety issues.

Under a Memorandum of Understanding on Natural Gas Transportation Facilities

(Memorandum)dated January 15, 1993, between the DOT and the FERC, the DOT has the

exclusive authority to promulgate federal safety standards used in the transportation of natural

gas. Section 157.14(a)(9)(vi)of our regulations require that an applicant certify that it will

design, install, inspect, test, construct, operate, replace, and maintain the facility for which a

Certificate is requested in accordance with federal safety standards and plans for maintenance

and inspection. Alternatively, an applicant must certify that it has been granted a waiver of the

requirements of the safety standards by the DOT in accordance with Section 3(e)of the Natural

Gas Pipeline Safety Act. The FERC accepts this certification and does not impose additional

safety standards. If the Commission becomes aware of an existing or potential safety problem,

there is a provision in the Memorandum to promptly alert DOT. The Memorandum also
Environmental Impact Statement 4-201 Corpus Christi LNG

provides for referring complaints and inquiries made by state and local governments and the

general public involving safety matters related to pipelines under the Commission's jurisdiction.

The FERC also participates as a member of the DOT's Technical Pipeline Safety

Standards Committee which determines if proposed safety regulations are reasonable, feasible,

and practicable.

The facilities associated with the Pipeline must be designed, constructed, operated, and

maintained in accordance with the DOT Minimum Federal Safety Standards in 49CFR 192. The

regulations are intended to ensure adequate protection for the public and to prevent natural gas

facility accidents and failures. The DOT specifies material selection and qualification;minimum

design requirements;and protection from internal, external, and atmospheric corrosion.

The DOT also defines area classifications, based on population density in the vicinity of

the pipeline, and specifies more rigorous safety requirements for populated areas. The class

location unit is an area that extends 220 yards on either side of the centerline of any continuous

1-mile length of pipeline. The four area classifications are defined below:

Class 1 Location with 10 or fewer buildings intended for human occupancy.

Class 2 Location with more than 10 but less than 46 buildings intended for human

occupancy.

Class 3 Location with 46 or more buildings intended for human occupancy or

where the pipeline lies within 100 yards of any building, or small welldefined outside area occupied by 20 or more people on at least 5 days a

week for 10 weeks in any 12-month period.

Class 4 Location where buildings with four or more stories aboveground are

prevalent.

Class locations representing more populated areas require higher safety factors in

pipeline design, testing, and operation. For instance, pipelines constructed on land in Class 1

locations must be installed with a minimum depth of cover of 30 inches in normal soil and 18

inches in consolidated rock. Class 2, 3, and 4 locations, as well as drainage ditches of public

roads and railroad crossings, require a minimum cover of 36 inches in normal soil and 24 inches

in consolidated rock.

Class locations also specify the maximum distance to a sectionalizing block valve

(e.g., 10.0 miles in Class 1, 7.5 miles in Class 2, 4.0 miles in Class 3, and 2.5 miles in Class 4).

Pipe wall thickness and pipeline design pressures;hydrostatic test pressures;MAOP;inspection

and testing of welds;and frequency of pipeline patrols and leak surveys must also conform to

higher standards in more populated areas. Once the pipeline route has been finalized, Cheniere

would identify the pipeline centerline with respect to other structures or manmade features and

determine the class locations along the Pipeline.

If a subsequent increase in population density adjacent to the right-of-way results in a

change in class location for the pipeline, Cheniere would reduce the MAOP or replace the

segment with pipe of sufficient grade and wall thickness, if required to comply with the DOT

requirements for the new class location.

The DOT Pipeline Safety Regulations require operators to develop and follow a written

integrity management program that contain all the elements described in 49CFR 192.911 and
Environmental Impact Statement 4-202 Corpus Christi LNG

address the risks on each transmission pipeline segment. The rule establishes an integrity

management program which applies to all high consequence areas (HCA).

The DOT has published rules that define HCAs where a gas pipeline accident could do

considerable harm to people and their property and requires an integrity management program to

minimize the potential for an accident. This definition satisfies, in part, the Congressional

mandate for DOT to prescribe standards that establish criteria for identifying each gas pipeline

facility in a high-density population area.

The HCAs may be defined in one of two ways. In the first method an HCA includes:

 current Class 3 and 4 locations,

 any area in Class 1 or 2 where the potential impact radius41 is greater than 660 feet and

there are 20 or more buildings intended for human occupancy within the potential impact

circle42, or

 any area in Class 1 or 2 where the potential impact circle includes an identified site.

An identified site is an outside area or open structure that is occupied by 20 or more

persons on at least 50 days in any 12-month period;a building that is occupied by 20 or more

persons on at least 5 days a week for any 10 weeks in any 12-month period;or a facility that is

occupied by persons who are confined, are of impaired mobility, or would be difficult to

evacuate.

In the second method, an HCA includes any area within a potential impact circle which

contains:

 20 or more buildings intended for human occupancy;or

 an identified site.

Once a pipeline operator has determined the HCAs along its pipeline, it must apply the

elements of its integrity management program to those segments of the pipeline within HCAs.

The DOT regulations specify the requirements for the integrity management plan at

Section 192.911. Of the 23 miles of proposed pipeline route, Cheniere has identified

approximately 2.9miles that would be classified as an HCA. The pipeline integrity management

rule for HCAs requires inspection of the pipeline HCAs at intervals specified in §192.939, but at

least every seven years.

The DOT prescribes the minimum standards for operating and maintaining pipeline

facilities, including the requirement to establish a written plan governing these activities. Each

pipeline operator is required to establish an emergency plan that includes procedures to minimize

the hazards of a natural gas pipeline emergency. Key elements of the plan include procedures

for:

 receiving, identifying, and classifying emergency events, gas leakage, fires, explosions,

and natural disasters;

 establishing and maintaining communications with local fire, police, and public officials,

and coordinating emergency response;

 emergency system shutdown and safe restoration of service;

41 The potential impact radius is calculated as the product of 0.69and the square root of: the MAOP of the pipeline

in psig multiplied by the square of the pipeline diameter in inches.

42 The potential impact circle is a circle of radius equal to the potential impact radius.
Environmental Impact Statement 4-203 Corpus Christi LNG

 making personnel, equipment, tools, and materials available at the scene of an

emergency;and

 protecting people first and then property, and making them safe from actual or potential

hazards.

The DOT requires that each operator establish and maintain liaison with appropriate fire,

police, and public officials to learn the resources and responsibilities of each organization that

may respond to a natural gas pipeline emergency, and to coordinate mutual assistance. The

operator must also establish a continuing education program to enable customers, the public,

government officials, and those engaged in excavation activities to recognize a gas pipeline

emergency and report it to appropriate public officials. Cheniere would provide the appropriate

training to local emergency service personnel before the pipeline is placed in service.

4.12.9.1 Pipeline Accident Data

The DOT requires all operators of natural gas transmission pipelines to notify the DOT of

any significant incident and to submit a report within 20 days. Significant incidents are defined

as any leaks that:

 caused a death or personal injury requiring hospitalization;or

 involve property damage of more than $50,000 (1984 dollars)43.

During the 20 year period from 1994 through 2013, a total of 1,237 significant incidents

were reported on the more than 300,000 total miles of natural gas transmission pipelines

nationwide.

Additional insight into the nature of service incidents may be found by examining the

primary factors that caused the failures. Table 4.12-8 provides a distribution of the causal factors

as well as the number of each incident by cause.

The dominant causes of pipeline incidents are corrosion and pipeline material, weld or

equipment failure constituting 48.2 percent of all significant incidents. The pipelines included in

the data set in table 4.12-8 vary widely in terms of age, diameter, and level of corrosion control.

Each variable influences the incident frequency that may be expected for a specific segment of

pipeline.

The frequency of significant incidents is strongly dependent on pipeline age. Older

pipelines have a higher frequency of corrosion incidents and material failure, since corrosion and

pipeline stress/strain is a time-dependent process.

43 $50,000 in 1984 dollars is approximately $115,000 as of March, 2014 (CPI, Bureau of Labor Statistics,

February 2014)
Environmental Impact Statement 4-204 Corpus Christi LNG

Table 4.12-9

Natural Gas Transmission Pipeline Significant Incidents by Cause

1994-2013 a/

Cause No. of Incidents Percentage e/

Corrosion 292 23.6

Excavation b/ 211 17.0

Pipeline material, weld or equipment

failure 304 24.6

Natural force damage 142 11.5

Outside force c/ 74 6.0

Incorrect operation 33 2.7

All other causes d/ 181 14.6

TOTAL 1,237 -

______________________

a/ All data gathered from PHMSA Significant incident files, March 25, 2014. http://primis.phmsa.dot.gov/comm/reports/safety/

b/ Includes third party damage

c/ Fire, explosion, vehicle damage, previous damage, intentional damage

d/ Miscellaneous causes or unknown causes

e/ Due to rounding, column does not total 100%

The use of both an external protective coating and a cathodic protection system44,

required on all pipelines installed after July 1971, significantly reduces the corrosion rate

compared to unprotected or partially protected pipe.

Outside force, excavation, and natural forces are the cause in 34.5 percent of significant

pipeline incidents. These result from the encroachment of mechanical equipment such as

bulldozers and backhoes;earth movements due to soil settlement, washouts, or geologic hazards;

weather effects such as winds, storms, and thermal strains;and willful damage. Table 4.12-9

provides a breakdown of outside force incidents by cause.

Older pipelines have a higher frequency of outside forces incidents partly because their

location may be less well known and less well marked than newer lines. In addition, the older

pipelines contain a disproportionate number of smaller-diameter pipelines;which have a greater

rate of outside forces incidents. Small diameter pipelines are more easily crushed or broken by

mechanical equipment or earth movement.

Since 1982, operators have been required to participate in "One Call" public utility

programs in populated areas to minimize unauthorized excavation activities in the vicinity of

pipelines. The "One Call" program is a service used by public utilities and some private sector

companies (e.g., oil pipelines and cable television)to provide preconstruction information to

contractors or other maintenance workers on the underground location of pipes, cables, and

culverts.

44 Cathodic protection is a technique to reduce corrosion (rust)of the natural gas pipeline through the use of an

induced current or a sacrificial anode (like zinc)that corrodes at faster rate to reduce corrosion.
Environmental Impact Statement 4-205 Corpus Christi LNG

Table 4.12-10

Outside Forces Incidents by Cause

(1994-2013) a/

Cause No. of Incidents Percent of all Incidents

Third party excavation damage 176 41.2

Operator excavation damage 25 2.0

Unspecified excavation damage/previous damage 10 0.8

Heavy rain/floods 72 5.8

Earth movement 35 2.8

Lightning/temperature/high winds 21 1.7

Natural force (other) 14 1.1

Vehicle (not engaged with excavation) 45 3.6

Fire/explosion 8 0.6

Previous mechanical damage 5 0.4

Fishing or maritime activity 7 0.6

Intentional damage 1 0.1

Electrical arcing from other equipment/facility 1 0.1

Unspecified/other outside force 7 0.6

TOTAL 427 --

______________________

a/ Excavation, Outside Force, and Natural Force from table 4.12-8

4.12.9.2 Impact on Public Safety

The service incidents data summarized in table 4.12-8 include pipeline failures of all

magnitudes with widely varying consequences.

Table 4.12-10 presents the average annual injuries and fatalities that occurred on natural

gas transmission lines for the 5-year period between 2009and 2013. The majority of fatalities

from pipelines are due to local distribution pipelines not regulated by FERC. These are natural

gas pipelines that distribute natural gas to homes and businesses after transportation through

interstate natural gas transmission pipelines. In general, these distribution lines are smaller

diameter pipes and/or plastic pipes which are more susceptible to damage. Local distribution

systems do not have large right-of-ways and pipeline markers common to the FERC regulated

natural gas transmission pipelines.
Environmental Impact Statement 4-206 Corpus Christi LNG

Table 4.12-11

Injuries and Fatalities - Natural Gas Transmission Pipelines

Year Injuries Fatalities

2009 11 0

2010 a/ 61 10

2011 1 0

2012 7 0

2013 2 0

______________________

a/ All of the public injuries and fatalities in 2010 were due to the Pacific Gas and Electric pipeline rupture and fire in San Bruno,

California on September 9, 2010.

The nationwide totals of accidental fatalities from various anthropogenic and natural

hazards are listed in table 4.12-11 in order to provide a relative measure of the industry-wide

safety of natural gas transmission pipelines. Direct comparisons between accident categories

should be made cautiously, however, because individual exposures to hazards are not uniform

among all categories. The data nonetheless indicate a low risk of death due to incidents

involving natural gas transmission pipelines compared to the other categories. Furthermore, the

fatality rate is much lower than the fatalities from natural hazards such as lightning, tornados, or

floods.
Environmental Impact Statement 4-207 Corpus Christi LNG

Table 4.12-12

Nationwide Accidental Deaths a/

Type of Accident Annual No. of Deaths

All accidents 117,809

Motor Vehicle 45,343

Poisoning 23,618

Falls 19,656

Injury at work 5,113

Drowning 3,582

Fire, smoke inhalation, burns 3,197

Floods b/ 89

Lightning b/ 52

Tornado b/ 74

Natural gas distribution lines c/ 14

Natural gas transmission pipelines c/ 2

______________________

a/ All data, unless otherwise noted, reflects 2005 statistics from U.S. Census Bureau, Statistical Abstract of the United States: 2010

(129th Edition)Washington, DC, 2009;http://www.census.gov/statab.

b/ NOAA National Weather Service, Office of Climate, Water and Weather Services, 30 year average (1983-2012)

http://www.weather.gov/om/hazstats.shtml

c/ PHMSA significant incident files, March 25, 2014. http://primis.phmsa.dot.gov/comm/reports/safety/, 20 year average.

The available data show that natural gas transmission pipelines continue to be a safe,

reliable means of energy transportation. From 1994 to 2013, there were an average of 62

significant incidents, 10 injuries and 2 fatalities per year. The number of significant incidents

over the more than 300,000 miles of natural gas transmission lines indicates the risk is low for an

incident at any given location. The operation of the Pipeline would represent a slight increase in

risk to the nearby public.

4.13 CUMULATIVE IMPACTSANALYSIS

NEPA requires the lead federal agency to consider the potential cumulative impacts of

proposals under review. Cumulative impacts may result when the environmental effects

associated with the proposed action are superimposed on or added to impacts associated with

past, present, and reasonably foreseeable future projects. Cumulative impacts can result from

individually minor, but collectively significant, actions taking place over a period of time.

Generally, cumulative impacts could result only from the construction of other projects in the

same vicinity and impacting the same resource areas as the proposed facilities. In such a

situation, although the impact associated with each project might be minor, the cumulative

impact resulting from all projects being constructed in the same general area could be greater.
Environmental Impact Statement 4-208 Corpus Christi LNG

Our analysis includes other projects in the vicinity of the proposed Project that affect the

same resources as the proposed Project in the same approximate time frame. Specifically,

actions included in the cumulative impact analysis must:

 impact a resource area potentially affected by the proposed Project

 cause the impact within all or part of the same area affected by the proposed Project for

that resource;and

 cause the impact within all or part of the time span as that of the potential impact from

the proposed Project.

Using this approach, the potential for cumulative impacts was assessed by combining the

potential environmental impacts of the proposed Project with the impacts of identified projects.

The cumulative impact area for each resource is defined in section 4.13.2.

4.13.1 Projects PotentiallyContributing to Cumulative Impacts

While Cheniere states its purpose and need would support increased shale gas production,

no specific shale gas play is identified. The Pipeline would receive and deliver domestic natural

gas via interconnections with a number of existing intrastate and interstate pipeline systems.

These interconnecting pipeline systems (Texas Eastern, Tejas, NGPL, Transco, and Tennessee

Gas)span states from Texas to Illinois to Tennessee and Pennsylvania and cross multiple shale

gas plays, as well as conventional gas plays. In addition, each of these interconnecting pipeline

systems has a developed network of additional interconnects with other gas transmission pipeline

companies that may cross additional gas plays.

Further, Cheniere states that the export of natural gas as LNG would allow the further

development of shale gas. However, Cheniere does not, and cannot, estimate how much of the

export volumes would come from current shale gas production and how much, if any, would be

new production or development attributable to the Project. The Project does not depend on

additional shale gas production which may occur for reasons unrelated to the Project and over

which the Commission has no control, such as state permitting for additional gas wells. An

overall increase in nationwide production of shale gas may occur for a variety of reasons, but the

location and subsequent activity is unknown and is too speculative to assume based on the

interconnected interstate natural gas pipeline system. Additionally, the factors necessary for a

meaningful analysis of when, where, and how the development of shale gas would occur are

unknown at this time.

Wells which could produce gas that might ultimately flow to this Project might be

developed in any of the shale plays that exist in nearly the entire eastern half of the United

States. Accordingly, it is simply impractical for the Commission to consider impacts associated

with additional shale gas development as cumulative indirect impacts resulting from the Project

which must, under CEQ regulations, be meaningfully analyzed by the Commission. For

purposes of this cumulative impact analysis, impacts which may result from additional shale gas

production is not considered reasonably foreseeable, as defined by CEQ regulations, nor is such

an additional production or any correlative potential impacts, an effect of the Project. Therefore,

we find that the EIS appropriately considers cumulative impacts on the areas surrounding the

Project and appropriately focuses on potential impacts associated with the Project. The analysis

of the potential impacts of the Project on geology and soils, water resources, fisheries,
Environmental Impact Statement 4-209 Corpus Christi LNG

vegetation, wildlife, land use, recreation, visual resources, socioeconomics, cultural resources,

air quality, and noise, indicates that the Project would result in little to no incremental

contribution to impacts on resources in the Project area;therefore, the Project’s incremental

contribution to impacts on resources well beyond the Project area would likewise be negligible.

Table 4.13-1 (see appendix C)provides a list of projects considered in our cumulative

impacts analysis, including the proposed Project, and a general summary of potential impacts

associated with each project. Included in our analysis are those known projects with potential

impacts on the same resources for which some impact has been evaluated for the Project. Figure

4.13-1 shows the general locations of the projects included in our cumulative impacts analysis.
Environmental Impact Statement 4-210 Corpus Christi LNG

Figure 4.13-1 General Locations of Projects Potentially Contributing to Cumulative Impacts
Environmental Impact Statement 4-211 Corpus Christi LNG

4.13.1.1 U.S. ArmyCorps of Engineers La Quinta Channel Extension

The COE, Galveston District, awarded a contract on September 22, 2011 in the amount

of $33,537,027 to King Fisher Marine Service, LP for dredging of the Corpus Christi Ship

Channel’s La Quinta extension located less than 1 mile southeast of the Terminal in Nueces

County, Texas. Commencement of dredging began in December 2011, and will be completed by

the summer of 2014. Construction activities have included dredging of approximately 7,400 feet

of the La Quinta Channel extension to a depth of -39feet mean low tide (equivalent to -40 feet

NAVD 88)(plus 2 feet paid overdredge, plus 2 feet advanced maintenance dredge).

The project, for navigation and ecosystem restoration, is part of the Corpus Christi Ship

Channel - Channel Improvement Project as authorized by Section 1001(40)of the Water

Resources Development Act of 2007. Funding for the construction contracts was approved on

May 17, 2011 by the COE as part of its 2011 work plan for the Army Civil Works program. The

projects include the following navigation and ecosystem restoration elements:

 extend the La Quinta Ship Channel approximately 7,400 feet;

 construct an ecosystem restoration feature;and

 create a beneficial use site.

4.13.1.2 Port of Corpus Christi AuthorityLa Quinta Trade GatewayTerminal

The proposed La Quinta Trade Gateway Terminal comprises a major component of the

POCCA’s proposed long-term development plan and would be located immediately west of the

Terminal on a 1,100-acre site on the north side of Corpus Christi Bay. Once complete, this fully

permitted project would provide a state-of-the-art multi-purpose dock and container facility.

Project features consist of the extension of the La Quinta Channel (see description for COE La

Quinta Channel Extension), construction of a 3,800-foot-long, 3-berth ship dock with nine shipto-shore cranes, utilizing 250 acres of container/cargo storage yards, an intermodal rail yard, and

over 400 acres for on-site distribution and warehouse centers. The facility would have the

capacity to handle approximately 1 million 20-foot equivalent units annually. The La Quinta

Trade Gateway Terminal would be located adjacent to US 181/SH 35 and immediately to the

west of the proposed Project site.

The federal authorization to construct the extension of the La Quinta Ship Channel has

been a key factor for moving forward with the construction of the La Quinta Trade Gateway

Terminal. With the authorization and initial appropriation to construct the channel extension, the

Port Commission signed a Project Partnership Agreement with the COE in October 2009in order

to authorize and construct the extension. The COE began work at the site in 2010 through

construction of a 126-acre dredge material placement area as well as the dredging of the La

Quinta Channel extension as discussed above. The completion of the La Quinta Channel

extension by the summer of 2014 would facilitate the initiation of construction of the La Quinta

Trade Gateway Terminal, beginning with additional dredging of the Ship Channel. A start date

has not yet been set for construction of the cargo terminal.

4.13.1.3 Revolution EnergyHarbor Wind Project

Revolution Energy, LLC has developed and constructed the Harbor Sunrise wind farm on

the north side of the Inner Harbor along Nueces Bay. Feasibility study results have indicated
Environmental Impact Statement 4-212 Corpus Christi LNG

that a wind power project located within the inner harbor is viable. Under a lease agreement,

additional scoping studies have been conducted to determine the exact number and size of the

wind turbines that would be installed.

Project development commenced in the 2006 and began transmitting power to the grid in

February 2012. The project consists of six, 1.5-megawatt offshore wind turbines that can supply

up to 30 million kilowatt-hours a year to the local grid, supplying enough energy to power about

2,500 homes. The turbines have been installed along the perimeter of the port, out of the way of

cargo operation areas.

4.13.1.4 Offshore Wind Power Systems of Texas Foundation Test Site

Offshore Wind Power Systems of Texas, LLC (Offshore Wind), is a privately owned

Texas corporation that has developed an offshore platform (the Titan Wind Turbine Platform)for

use by wind turbines installed along off-shore wind farms. In September 2011 Offshore Wind

solicited turbine manufacturers/suppliers to utilize the “Titan 200” foundation at the fully

permitted test site located approximately 10 miles off the shore of the former Naval Station

Ingleside site, and approximately 26 miles east of the Terminal.

4.13.1.5 Tianjin Pipe Corporation America Corporation Minimill

Tianjin Pipe Corporation (TPCO)America Corporation began construction on its Texas

Mill Project in Gregory, Texas in September, 2011. Phase I of the project was completed in

early 2013 and the entire facility is scheduled to be operational in late 2014.

The Texas Mill Project is a seamless steel pipe manufacturing facility on a 253-acre site,

which will be located between SH 35 and SH 361, approximately 1.5 miles north of the proposed

Project site. The 1.6 million square-foot facility would produce 500,000 metric tons per year of

pipe principally for use in the energy industry. The seamless pipe would be used in both the U.S.

and abroad, utilizing an electric arc furnace to convert recycled scrap steel and pig iron. Once

fully operational, the TPCO America facility would be the largest single investment by TPCO, a

Chinese company, in a U.S. manufacturing facility.

4.13.1.6 OxyIngleside EnergyCenter Propane Export Facility

Oxy Ingleside Energy Center purchased the former Naval Station at Ingleside property

from the POCCA in 2012. The property is located along the Corpus Christi Ship Channel,

approximately 6 miles southeast of the Project site. The Naval station property encompasses

approximately 483 acres and contains more than 70 state-of-the-art buildings, such as warehouse

facilities, office and administrative facilities, barracks, fitness and recreation facilities, a capitalclass pier and wharf area, and several others.

Oxy Ingleside Energy Center has recently announced plans to construct a propane export

facility within this property and anticipates the facility to be operational by January 2015. The

company has also indicated that it could potentially export other fuels from the proposed facility,

such as butanes, natural gas, and condensate. Construction and operation plans for this project

have not been made available to the public;therefore, reasonable approximations of potential

impacts were used in the cumulative impacts analysis.
Environmental Impact Statement 4-213 Corpus Christi LNG

4.13.1.7 Papalote CreekWind Farm

The Papalote Creek Wind Farm is located on actively cultivated agricultural land near the

communities of Taft and Gregory. Portions of the wind farm would be crossed by the Cheniere

Pipeline between approximate MPs 7 to 10. Papalote Creek Wind Farm complex is a two-phase

project consisting of 87 Siemens 2.3 megawatt (MW)turbines and 109Vestas V82 1.65 MW

turbines capable of generating nearly 380 MW. The first phase of the wind farm went into

service in fall 2009and the second phase began operations in 2011.

4.13.1.8 Occidental Chemical Corporation Natural Gas Liquids Fractionation Facility

Occidental Chemical Corporation (OxyChem)proposes to construct and operate a new

87,000 barrel per day NGL Fractionation Facility within its existing site along the La Quinta

Channel, located 2 miles west of Ingleside, Texas and approximately 1.2 miles east of the

Terminal. The proposed project also includes the installation of four hydrocarbon pipelines,

which would be constructed within the existing 18.5-mile-long and 100-foot-wide San Patricio

Pipeline Corridor. These pipelines would serve to transport NGL to the proposed 470-acre

facility where they would be fractionated into ethane, propane, butane, and natural gasoline. The

products would then be stored on-site before being transferred via pipeline, tank truck, rail car, or

barge to various markets or the proposed OxyChem Ethylene Plant located immediately adjacent

to the fractionation facility.

In May 2012, OxyChem submitted a GHG PSD permit application to the EPA for their

proposed fractionation facility. OxyChem identified two thermal oxidizers, one flare, one

cooling tower, fugitive sources for five operating areas, one emergency generator, and four

firewater pump engines as new sources of GHG emissions. The public comment period for the

GHG PSD permit closed as of August 9, 2013.

OxyChem recently released an anticipated construction schedule, with project activities

estimated to be completed by December 2014. However, this schedule is currently under review

and a final in-service date has not yet been determined.

4.13.1.9 OxyChem Ethylene Plant

OxyChem proposes to construct and operate a new 1.2 billion pounds per year (lb/y)

ethylene plant within its existing site along the La Quinta Channel, located approximately

2 miles west of Ingleside, Texas and approximately 1.2 miles east of the Terminal. The plant

would receive ethane feed via pipeline or from the proposed NGL Fractionation Facility to be

constructed on adjacent property. Once fully operational, the plant would produce 1.2 billion

lb/y of market grade ethylene. Construction on this project is expected to commence in 2014,

with the facility becoming fully operational in early 2017.

In December 2012, OxyChem submitted a GHG PSD permit application to the EPA for

their proposed ethylene plant. OxyChem identified five cracking furnaces, two thermal

oxidizers, one high pressure ground flare, one emergency generator engine, one low pressure

enclosed flare, one cooling tower, and fugitive sources for six operating areas as new sources of

GHG emissions. OxyChem is currently in the early development and permitting stages for the

project, and an updated construction schedule has not been released.
Environmental Impact Statement 4-214 Corpus Christi LNG

4.13.1.10 Voestalpine DRIPlant

Voestalpine proposes to construct and operate a DRI plant on land adjacent to the west

side of the Project in San Patricio County, Texas. The proposed DRI plant would be constructed

on approximately 475 acres of upland property and approximately 11 acres of submerged land

owned by the POCCA. Additionally, the facility would also include the construction of a

1,060-foot-long high performance dock.

Project features consist of a reformer and reactor necessary for the conversion of

Canadian or Brazilian ore into highly metallized iron, either in the form of DRI or hot briquetted

iron. The DRI Plant is expected to require approximately 150 people for the annual production

of 2 million metric tons of iron, which would be distributed to Austrian steel mills as well as

other international and domestic markets. It is anticipated that the project would begin

operations in late 2015 and would be in full production by early 2016. Voestalpine submitted a

GHG PSD permit application to the EPA for their proposed DRI Plant in January 2013.

4.13.1.11 Flint Hills West RefineryExpansion

Flint Hills Resources Corpus Christi, LLC (FHR)proposes to expand their existing crude

oil refinery located on the north eastern shore of Nueces Bay, approximately 15 miles east of the

Terminal. The expansion of their currently operating West Refinery would allow the refinery to

process a larger percentage of domestic crude oil and increase the total crude processing

capacity.

Construction of new facilities for this project would include a process unit called the

Saturates Gas Plant No. 3, one cooling tower, and equipment piping fugitive components in

several existing process units. The existing equipment affected by construction would include

increasing the firing duty of the CCR Hot Oil Heater, physical changes to the Mid Plant Cooling

Tower, and conversion of the current Gas Oil Hydrotreating Unit to a Distillate Hydrotreating

Unit.

In December 2012, FHR submitted a GHG PSD permit application to the EPA, as the

proposed refinery expansion will increase emissions at the site. The application was incomplete

and FHR has since submitted updated information;however, the application has not been

deemed complete to date.

4.13.2 Existing LNG Terminals and Projects

We identified one existing LNG terminal in the general Project vicinity (Freeport

Liquefaction Project)that could contribute to cumulative impacts with those of the proposed

Project. Other existing or proposed LNG terminals were identified but dismissed from this

analysis as they are located approximately 300 miles away. A brief description of the project is

provided below. This cumulative impacts analysis considered the impacts of operation of the

existing terminal as well as the potential construction and operation impacts of the planned or

proposed projects.

4.13.2.1 Freeport Liquefaction Project

FLEX has proposed the Freeport Liquefaction Project in Brazoria County, Texas, which

includes the addition of liquefaction facilities to its existing terminal located on Quintana Island

to provide export capacity of approximately 13.2 mtpy of LNG. This project would require
Environmental Impact Statement 4-215 Corpus Christi LNG

approximately 86 acres for three proposed trains, each with a capacity of 4.4 mtpy, and

associated facilities. This project is located more than 150 miles from the proposed Project.

Therefore, we do not believe that cumulative impacts would have a cumulative effect on the

resources in the Project area, including air quality impacts as discussed in section 4.13.4.

4.13.3 CurrentlyOperating Oil and Gas Facilities

There are various oil and gas wells in the vicinity of the proposed Project site (see

section 4.1), primarily located near the Pipeline, and many of these are oil and gas gathering and

transmission pipelines and related facilities. Those facilities are in place and generally would not

contribute to the cumulative impacts associated with construction of the Project;however, the

operation of the wells permanently removed both wetlands and vegetation. There are no major

storage or processing facilities in the vicinity.

The Pipeline would be adjacent to portions of other rights-of-way including those with

which the proposed Pipeline would interconnect. These pipelines have been in service for a

number of years and the only impacts relating to the cumulative impact analysis include

maintenance for permanent rights-of-way in the vicinity of the interconnections and emissions

from compressor stations associated with the pipelines.

4.13.4 Other Projects and Activities Considered

4.13.4.1 Non-Jurisdictional Power Lines and Substations

As discussed in section 1.6.1, Cheniere identified an electrical power line extension and

substation that would be required for construction and operation of the Terminal. An overhead

powerline would extend from the junction of SH 35 and SH 361 to a new facilities substation

located at the Terminal site. The power line and electrical substation would be built, owned, and

operated by AEP. Cheniere would also build, own, and operate an underground power line that

would extend from the AEP substation to the facilities substation at the Terminal.

4.13.4.2 Non-Jurisdictional Waterline

As discussed in section 1.6.2, the construction and operation of the Terminal would

require a waterline connection to the San Patricio Municipal Water District potable water system

at the north end of La Quinta Road. The waterline would be constructed within the same

corridor as the power lines discussed above.

4.13.4.3 Removal of Non-Jurisdictional Natural Gas Pipelines

Three existing non-jurisdictional natural gas pipelines (Gulf South Pipeline Company, LP

[Gulf South], Crosstex Corpus Christi Natural Gas Transmission [Crosstex], and Royal

Production Company [Royal]were removed by their respective operators following Cheniere’s

receipt of the 2005 Order. Descriptions of the locations of the pipeline segments previously

present at the Terminal are provided below.

Gulf South Pipeline Company, LP -approximately 1.2 miles of 6-inch-diameter natural

gas pipeline owned and operated by Gulf South was located within the Terminal site boundary.

Crosstex Corpus Christi Natural Gas Transmission - approximately 0.3 mile of 10-inchdiameter natural gas pipeline owned and operated by Crosstex was located within the Terminal

site boundary. Portions of this pipe would have been impacted during dredging activities
Environmental Impact Statement 4-216 Corpus Christi LNG

associated with the marine berth, as well as the La Quinta Channel Extension, further discussed

in section 4.13.

Royal Production Company - approximately 0.6 mile of 6-inch-diameter offshore natural

gas pipeline extending from a well in Corpus Christi Bay, a 4-inch tie-in, and a tank battery, all

owned and operated by Royal, was located within the Terminal site boundary.

These three existing non-jurisdictional natural gas pipelines were abandoned, removed, or

relocated following Cheniere’s receipt of the Order issued by the Commission on April 18, 2005.

The exact nature of the abandonment, removal, or relocation activities is not known to Cheniere

or FERC, as each of the individual operators permitted and conducted these operations on their

own. Environmental impacts associated with the removal of those three pipelines are anticipated

to have occurred within previously disturbed areas and were not significant

4.13.5 Potential Cumulative Impacts byResource

The following sections address the potential cumulative impacts from Cheniere’s Project

on each environmental resource.

4.13.5.1 Geologic Resources

The cumulative impact area for geologic resources and natural hazards was considered to

be the area adjacent to the Terminal and the Pipeline construction areas. Although the

topography in the area is nearly flat, construction of the Terminal would require some

modification of existing contours to safely accommodate the facilities and maintain drainage in

the area. These modifications would not differ substantially from the existing topography in

adjacent areas. The LNG tanks would be located in areas that may be subject to differential

surcharge conditions, which could result in detrimental differential foundation settlements.

The projects in the cumulative impact area for geologic conditions at the Terminal would

include the COE La Quinta Channel Extension, the POCCA La Quinta Trade Gateway Terminal,

and the Voestalpine DRI Plant, all of which may require dredging activities. The three nonjurisdictional facilities associated with the proposed Project occur within the cumulative impact

area for geologic conditions at the Terminal;however, construction of these non-jurisdictional

facilities is not expected to result in noticeable changes in topography. Scouring of sand layers

exposed during dredging of the shoreline and La Quinta Channel could increase the erosion

potential of exposed sand layers and may cause eventual slumping or slope failure. Although the

Terminal is located in an area that may present challenges relative to slope stability, mitigation

plans and implementation of erosion controls would reduce or minimize any significant

cumulative impacts on these resources in the Corpus Christi Bay area.

Construction and operation of the Pipeline would primarily occur within previously

disturbed areas and would result in minimal impacts on geological resources. Cheniere would

restore topographic contours along the right-of-way to preconstruction conditions to the

maximum extent practicable.

4.13.5.2 Soils and Sediments

The cumulative impact area for soils was considered to be the area adjacent to the

Terminal and the Pipeline construction areas. Past impacts on soils resources in the vicinity of

the Project have resulted from agriculture and industrial developments as well as construction
Environmental Impact Statement 4-217 Corpus Christi LNG

and maintenance of existing roads, railroads, utility lines, and transmission lines. Clearing,

grading, and equipment movement associated with construction of the Terminal and the Pipeline

could result in soil loss due to erosion, which could reduce soil fertility and impair revegetation,

and discharge of sediment to waterbodies and wetlands. However, Cheniere would implement

mitigation measures outlined in our Plan and Procedures as well as recommendations of the local

NRCS to minimize erosion and aid in the reestablishment of vegetation in areas temporarily

impacted during construction.

The planned non-jurisdictional facilities, including the electrical power line extensions

and substations as well as the waterline, would be constructed within and adjacent to the

Terminal site. All of the non-jurisdictional facilities would be constructed within existing,

previously disturbed areas and would not contribute significantly to a cumulative impact on soils.

4.13.5.3 Water Resources

The cumulative impact area for groundwater was limited to the aquifers that Project is

located within. The cumulative impact area for surface water resources extends approximately 2

miles upstream and downstream of the Terminal site boundaries and the pipeline stream

crossings. Cumulative impacts on water resources at the Terminal site, when combined with

other projects in the area, would be limited primarily to the waters of the La Quinta Channel and

the Corpus Christi Ship Channel, as the majority of other identified projects are located along

those waterways. Although the non-jurisdictional waterline to the San Patricio Municipal Water

District potable water system would be installed at the Terminal site, the waterline would be

constructed entirely within previously disturbed areas and would not result in adverse impacts on

water resources or local water quality.

Some of the projects would require dredging in order to deepen, widen, or maintain

marine channels, turning basins, or to install pilings or footings. As a result of initial dredging

activities, construction of new channels and turning basins, and during future maintenance

dredging, increased turbidity and sedimentation would temporarily decrease water quality in the

vicinity of each project. Water resources may have been previously impacted during dredging

activities associated with the abandonment, removal, or relocation of the non-jurisdictional

natural gas pipelines located at the Terminal site. However, dredging and construction activities

associated with the abandonment, removal, or relocation of these pipelines would have been

similar to those discussed above but would have occurred on a much smaller scale.

If dredging associated with the Terminal could add to the cumulative impact on water

quality if it were to occur concurrently with dredging for the other projects identified in the area.

However, the negative impacts on water quality as a result of dredging in and adjacent to the

existing La Quinta and Corpus Christi Channels would be temporary, and water quality would be

expected to return to ambient conditions soon after completion of activities.

The design of the offshore platforms for the Offshore Wind Foundation Site offers a

relatively small area of impact using a reduced footprint on the sea floor. Although some

turbidity in the water column could occur as a result of installation of the platforms at the test

site, it is likely that this impact would be minor and temporary in nature. In addition, turbidity

would remain isolated to the area directly adjacent to the platform.

Installation of the Pipeline associated with the Project would not have a significant

impact on the freshwater waterbodies that would be crossed. Even if the other projects identified
Environmental Impact Statement 4-218 Corpus Christi LNG

in the area have concurrent impacts on the same waterbodies, significant cumulative impacts

would not be anticipated. Each company would implement crossing methods and erosion and

sediment control measures that would comply with local, state, and, federal permit requirements

for each crossing. The impacts on waterbodies that would occur as a result of the installation of

the Pipeline would be short-term, and full restoration of stream banks, pipeline right-of-ways,

and all other natural horizons would be restored to preconstruction contours to the maximum

extent practicable.

In the event of a spill of hazardous materials during construction or operation of any of

the projects identified, water resources could potentially be impacted. However, the Project is

not likely to contribute significantly to cumulative impacts on water resources due to spills. In

the event of a spill of hazardous materials, Cheniere would implement its SPCC Plan.

Additionally, the location of the Terminal site occurs on previously disturbed, highly

industrialized lands including old bauxite tailing storage areas. Best management practices

would be utilized during installation of the Pipeline in order to prevent contamination of

waterbodies being crossed in the event of a hazardous materials spill.

4.13.5.4 Wetlands and Submerged Aquatic Vegetation

The cumulative impact area for wetlands was considered to be the area adjacent to the

proposed Project construction area.

Several of the projects identified in table 4.13-1 (see appendix C)could have a significant

cumulative impact on wetlands and submerged aquatic vegetation. In the case of the Pipeline,

impacts on wetlands would be mostly temporary, as they would be restored after construction,

with less than 0.01 acre of anticipated permanent impacts. However, construction of the

Terminal is expected to contribute more significantly to cumulative impacts on wetlands in the

region. Each of the project proponents would be required by the terms and conditions of their

respective Section 404 permit to provide compensatory mitigation for these unavoidable wetland

impacts.

Additionally, the abandonment, removal, or relocation of the non-jurisdictional natural

gas pipelines would have impacted wetlands and SAV at the Terminal site. Although the exact

nature of the abandonment, removal, or relocation activities is not known to Cheniere or the

FERC, it is assumed that impacts associated with dredging activities as well as mitigation

measures would have been similar to those associated with the marine berth and the La Quinta

Channel Extension.

Both temporary and permanent impacts on SAV are expected as a result of dredging and

other construction activities from each of the identified projects, including the abandonment,

removal, or relocation of the non-jurisdictional natural gas pipelines. Additional mitigation plans

have been proposed by the POCCA to compensate for adverse impacts on SAV communities,

including the creation of nearly 200 acres of shallow-bottom habitat using dredged material from

the La Quinta Ship Channel Extension Project and construction of an Ecosystem Restoration

Feature to protect approximately 45 acres of existing SAV.

While impacts on wetlands and SAV are anticipated, mitigation plans and activities

would reduce or minimize cumulative impacts on these resources in Corpus Christi Bay area.

Therefore, the Project would not contribute significantly to cumulative impacts on wetlands and

SAV.
Environmental Impact Statement 4-219 Corpus Christi LNG

4.13.5.5 Vegetation,Wildlife,and Aquatic Resources

The cumulative impact area for vegetation and wildlife was considered to be the area

adjacent to and near the proposed Project construction zones. The cumulative impact area for

aquatic resources was considered to be the same as that for water resources.

When projects are constructed concurrently, the combination of construction activities

could have cumulative impact on vegetative, wildlife, or aquatic resources. All of the projects

considered in this cumulative impacts analysis would be within or adjacent to previously, highly

disturbed, industrial areas or developed sites. These areas do not typically offer high quality

habitat for diverse vegetation or wildlife species. In addition, while constructing these projects,

mobile wildlife species would be able to temporarily displace to similar adjacent habitats. These

species would later be able to return to the open project lands following restoration. Therefore,

we determined impacts on wildlife species would be short-term and not significant.

Dredging activities associated with several of the identified projects would impact a

significant amount of shallow-bottom habitat considered EFH. Deepening shipping channels,

maneuvering areas, and docks would result in a permanent conversion of shallow-bottom habitat

to deeper water habitat, maintained as such through periodic maintenance dredging. Dredging

associated with the abandonment, removal, or relocation of the non-jurisdictional natural gas

pipelines would have resulted in impacts on shallow-bottom habitat and other aquatic resources

similar to those associated with construction of the marine berth, but on a much smaller scale.

Therefore, cumulative impacts on vegetative, wildlife, or aquatic resources from the

abandonment, removal, or relocation of these non-jurisdictional pipelines would not be

significant. Most other impacts associated with dredging would be short-term, such as localized

turbidity resulting in reduced water quality and potential temporary impacts on local fish species.

Compensatory mitigation for loss of vegetated components of EFH (seagrass and coastal marsh

habitats)would be addressed through Section 404 permitting, and consultation with NOAA

Fisheries.

The construction and operation of large turbines associated with wind farm projects could

potentially affect bird and bat species through collision-related fatalities. However, a Phase I

Avian Risk Assessment conducted for the Revolution Energy Wind project determined that

fatalities among birds in the area are not likely to be biologically significant. Additionally, the

project has been constructed in a highly industrialized area which does not provide high quality

bird habitat. The Project would not be likely to contribute significantly to cumulative impacts on

flying species, as the tallest structures (storage tanks, marine flare, and process flare tower

located at the Terminal facilities)would have visual markers and aircraft warning lights installed

on guy-wires and tall, free-standing structures. Additionally, the heights of the tallest structures

associated with the Project would be similar or less than those located on neighboring properties.

Although some collisions with these structures could potentially occur it is not likely that these

fatalities would be of biological significance.

4.13.5.6 Threatened and Endangered Species

Of the projects listed in table 4.13-1 (see appendix C), only the La Quinta Channel

Extension, OxyChem NGL Fractionation Facility, FHR West Refinery Expansion, and Freeport

Liquefaction projects had results of threatened and endangered species impact assessments that

are publicly available. Seventeen federally listed species were identified as occurring or

potentially occurring within the Project area, including two plants (south Texas ambrosia and
Environmental Impact Statement 4-220 Corpus Christi LNG

slender rush-pea), nine mammals (five whales, ocelot, gulf coast jaguarundi, and West Indian

manatee), two birds (whooping crane and piping plover), and five reptiles (loggerhead sea turtle,

green sea turtle, leatherback sea turtle, Atlantic hawksbill sea turtle, and Kemp’s ridley sea

turtle). We have determined the Project would not be likely to adversely affect any of these

federally listed threatened and endangered species. An additional 24 state listed species were

identified in San Patricio and Nueces Counties, 14 of which would not be impacted and 10 which

would not likely be impacted by the Project.

According to the Environmental Assessment for the La Quinta Channel Extension, the

project would either have no effect or would not be likely to adversely affect the species listed in

Nueces and San Patricio Counties. Dredging of the Ship Channel may indirectly impact EFH

due to increased turbidity and suspended sediment load in the estuarine water column;however,

these impacts on EFH are expected to be temporary and minor. OxyChem developed a draft BA

to assess any potential impacts from its NGL Fractionation Facility on the listed threatened and

endangered species. The results of this BA determined that the project would have no effect on

four of these listed species and may affect, but would not be likely to adversely affect the

remaining listed species. Additionally, the BA states that the NGL Fractionation Facility would

have no adverse impacts on EFH. The GHG PSD permit application for FHR’s West Refinery

Expansion indicates that no listed threatened and endangered species or their critical habitats

occur within the project’s potential impact area and thus, no impacts on listed species are

expected. Freeport LNG indicated in its application to the FERC that the project will have no

effect, or will be not likely to adversely affect any threatened or endangered species in the area.

No adverse impacts on threatened and endangered species are expected occur as a result

of the Project and the projects identified in table 4.13-1 (see appendix C)(with publicly available

species impact assessments);therefore, no cumulative impacts are anticipated. However,

dredging associated with the Project;the abandonment, removal, or relocation of the nonjurisdictional natural gas pipelines;and the La Quinta Channel Extension could result in adverse

cumulative impacts on EFH. However, dredging activities for the La Quinta Channel Extension

and the abandonment, removal, or relocation of the non-jurisdictional natural gas pipelines

would not be performed in conjunction with the Project and thus, cumulative impacts on EFH

would not be significant.

4.13.5.7 Land Use,Recreation,and Visual Resources

The cumulative impact area for land use was considered to be the area adjacent to and in

the vicinity of the proposed Project. The cumulative impact area for recreation was considered

to be GIWW, the Corpus Christi and La Quinta Ship Channels, and Corpus Christi Bay. The

cumulative impact area for visual resources was considered to be the area within the viewsheds

of the Project facilities.

Almost all projects identified (on land)in the vicinity of the Project, including the nonjurisdictional electrical power line extensions and waterline, would be or have been, constructed

on, or adjacent to, highly disturbed industrial or agricultural lands. A significant, additional

cumulative loss of unique or special interest lands would not occur as a result of constructing or

operating the projects. The installation of the Pipeline and other pipelines across agricultural

lands would result only in short-term impacts on agricultural and open, herbaceous lands, as land

use would be restored following completion of construction activities.
Environmental Impact Statement 4-221 Corpus Christi LNG

The Corpus Christi Bay is actively utilized for recreation activities such as boating and

fishing;therefore, it is probable that the construction or operation of the identified projects could

have a significant, negative impact on the area’s recreational value. However, the Corpus Christi

and La Quinta Ship Channels are already actively used by commercial ship traffic, as the Port of

Corpus Christi is the fifth largest commercial port in the U.S. Though total port traffic would

increase, large ships would be restricted to the deep water-dredged Corpus Christi and La Quinta

Ship Channels, while most recreational boaters would utilize shallower channels of the GIWW

and many shallow water bays within the Corpus Christi Bay area.

The visual character of the existing landscape is defined by historic and current land uses

such as recreation, conservation, and development. The visual qualities of the landscape are

further influenced by existing installations such as highways, railroads, pipelines, and electrical

transmission and distribution lines and facilities. Cumulatively, the identified projects’

infrastructure facilities and their construction would have some visual impact on the immediate

surroundings. However, the identified projects would be consistent with ongoing industrial

activities and existing facilities along the Corpus Christi and La Quinta Ship channels.

The proposed non-jurisdictional underground power line and waterline would be buried

from the AEP substation to the Project substation at the Terminal site and would not affect the

visual character of the area after construction is complete. The overhead power line and

supporting structures would alter visual quality and expand the industrial character of the area to

the north of the Terminal site. However, the visual quality would be consistent with the

industrial character of the surrounding area and consistent with electrical transmission lines that

parallel many roadways in the area.

Impacts on visual resources resulting from the storage tanks and flare stack would be

moderate and permanent;however, due to the proximity of the Terminal to other industrial

structures, the storage tanks and flare stack would be consistent with the surrounding land use.

There are no residences, schools, community parks, or public areas that would be

considered visually sensitive areas within 1 mile of the Terminal. The Terminal would use the

minimum lighting necessary to allow personnel to safely work and inspect the equipment at the

Terminal. The lighting at the Terminal would be consistent with lighting at other industrial

facilities along the La Quinta Channel and would not significantly increase light pollution in the

area. Therefore, cumulative impacts from lighting and nighttime flaring on the environment

would not be significant.

4.13.5.8 Socioeconomics

The cumulative impact area for socioeconomics included San Patricio and Nueces

Counties. The construction period for the Project would likely be concurrent with those of

several of the major La Quinta Channel projects and the non-jurisdictional electrical power line

extensions and waterline. Combined, the projects identified would generate several thousand

temporary construction jobs and many permanent jobs associated with various operational duties.

Many of the workers would likely reside locally and would not require temporary housing.

However, if temporary housing would be required for multiple projects occurring concurrently,

Corpus Christi offers a relatively large number of temporary housing facilities such as hotels,

campgrounds, and RV parks.
Environmental Impact Statement 4-222 Corpus Christi LNG

Positive benefits of the new jobs and workers in the area would include lowering local

unemployment rates, increasing revenue for local business owners, and generating new tax

revenue to the Corpus Christi area. No identified minority or low-income populations would be

disproportionately impacted by the projects (see section 4.9.9);therefore, the Project would not

contribute to cumulative impacts on these populations.

A cumulative impact on land transportation would be dependent on the construction

schedules and amount of overlap between the construction phases for all of the identified

projects in the geographic region. Construction of the non-jurisdictional electric power lines and

substations and the non-jurisdictional waterline would contribute to cumulative impacts on

traffic along portions of US 361 and in the vicinity of the Terminal site, primarily at the

beginning and end of each construction shift. Although we recognize concurrent construction of

the proposed Project and other projects in the vicinity of the Terminal site would result in

increased workers in the area, periods of increased traffic, and impacts on public services, we are

not recommending additional mitigation at this time. Therefore, we have determined that with

the implementation of Cheniere’s mitigation measures, the impacts of the Project when added

with other projects’impacts would not result in significant cumulative impacts.

Currently, the Port accommodates more than 6,000 vessels and 80,000 tons of cargo

annually. The amount of vessel traffic in the Nueces Bay area would not significantly increase

as a result of construction and operation of the Cheniere Terminal and other identified projects.

However, it is not anticipated that the Corpus Christi and La Quinta Ship Channels Port would

be adversely impacted, as the Port has been maintained in such a way as to handle significant

increases in docking a maneuvering capacity.

4.13.5.9 Cultural Resources

Because no historic properties have been identified to date that would be adversely

effected by Cheniere’s proposal, that project would not be adding incrementally to cumulative

regional impacts on cultural resources which are listed or eligible for listing on the NRHP. Any

other projects with a federal nexus would have to adhere to section 106 of the NHPA, and follow

the regulatory requirements of 36 CFR 800. Under those regulations, the lead federal agency, in

consultation with the SHPO, would have to identify historic properties in the APE, assess

potential project effects, and resolve adverse effects through an agreement document that

outlines a treatment plan. The NHPA and its implementing regulations ensure that projects that

require a federal permit, license, or approval would not have significant cumulative impacts on

historic properties.

4.13.5.10 Air Qualityand Noise

The cumulative impact area for air quality during construction of the Project is the area

adjacent to and near the boundary of the Terminal site and along the Pipeline. The cumulative

impact area for air quality during operation of the project was established based on the Project’s

PSD Area of Impact, as described in section 4.11.1

Construction of the Project and many of the past, present, or future projects listed in

table 4.13-1 (see appendix C)would involve the use of construction equipment that generates air

pollution, including fugitive dust. Operation of construction equipment would be primarily

restricted to daylight hours and would be minimized through typical controls and practices, some

of which are required under TCEQ rules. The emissions from construction activities for the
Environmental Impact Statement 4-223 Corpus Christi LNG

Project and other projects in the region would result in short-term emissions that would be

localized to each project area;therefore, construction emissions are not expected to have a

significant cumulative impact on regional air quality.

Operation of the Project, including LNG carriers and associated support vessels in the

vicinity of the Terminal, would contribute cumulatively to air pollutant levels in combination

with some of the other projects identified as part of the cumulative impacts analysis. As

discussed in section 4.11.1.4, detailed air quality impact analyses were conducted by Cheniere to

quantitatively evaluate the combined impacts from operation of the Project and other emission

sources in the region, including pollutant background concentrations. Those combined impacts

were compared against the NAAQS, which are designed to be protective of human health and the

environment. The results of the NAAQS analyses demonstrated that there would be no

significant impact on regional air quality from operation of the Project.

Newly proposed (future) projects in the area (e.g., Voestalpine DRI Plant) would

contribute cumulatively to air quality through construction and operation activities. Each of

these projects would need to comply with federal, state, and local air quality regulations, which

may require controls to limit the emissions of certain criteria pollutants or HAPs. Although

outside the scope of our analysis, it is anticipated that these project activities would result in

increased permanent emissions of criteria pollutants, HAPs, and GHGs within the region. The

Project’s associated operating emissions would be mitigated by federal and state permits and

approvals. Thus, the Project is not anticipated to contribute to the cumulative impact on regional

air quality as a result of operation.

Noise levels typically attenuate quickly as the distance from the noise source increases.

Therefore, the cumulative impact area considered for noise is within about 1.5 miles of the

Terminal, 1 mile of the pipeline route, and a 1-mile radius of the Sinton and Taft Compressor

Stations. The only projects in the cumulative impact area that may be constructed at the same

time as the Terminal are the OxyChem NGL Fractionation Facility and Ethylene Plant, and

Voestalpine DRI Plant. Noise produced during the construction of these identified projects could

create some short-term impacts on nearby residences and could have short-term impacts on some

aquatic species. However, Noise impacts during construction of these projects would be

localized and would attenuate as the distance from the noise source increases. The nearest NSAs

in the vicinity of the Terminal site are over one mile away. Therefore, cumulative noise impacts

associated with construction would be unlikely to be noticeable, unless one or more of the

projects were constructed concurrently at the same location.

Operation of the identified projects with land-based facilities would also generate noise.

For the Project, the FERC would require that noise generated during operation would not exceed

the 55 decibel limit established by the EPA for protection of public health and welfare. The

combined operation of the identified projects, should they all be authorized, could result in the

raising of the average ambient noise level at the nearest NSAs but not by a significant measure.

Cumulative operational noise would be audible at the Terminal, but should not be significantly

greater than current measured ambient noise due to noise attenuation.

4.13.5.11 Climate Change

Climate change is the change in climate over an extended period of time, whether due to

natural variability, human activities, or a combination of both, and cannot be characterized by an

individual event or anomalous weather pattern. For example, a severe drought or abnormally hot
Environmental Impact Statement 4-224 Corpus Christi LNG

summer in a particular region is not an indication of climate change, while a series of severe

droughts or hot summers that statistically alter the trend in average precipitation or temperature

over decades may indicate climate change.

The Intergovernmental Panel on Climate Change (IPCC)is the leading international,

multi-governmental scientific body for the assessment of climate change. The U.S. is a member

of the IPCC and participates in the IPCC working groups studying various aspects of climate

change. The leading U.S. scientific body on climate change is the U.S. Global Change Research

Program (USGCRP). Thirteen federal departments and agencies45 participate in the USGCRP,

which began as a presidential initiative in 1989and was mandated by Congress in the Global

Change Research Act of 1990 (GCRA). The USGCRP coordinates and supports U.S.

participation in the IPCC assessments.

The IPCC and USGCRP have recognized that:

 globally, GHGs have been accumulating in the atmosphere since the beginning of the

industrial era (circa 1750);

 combustion of fossil fuels (coal, petroleum, and natural gas), combined with agriculture

and clearing of forests, is primarily responsible for the accumulation of GHG;

 anthropogenic GHG emissions are the primary contributing factor to climate change;and

 impacts extend beyond atmospheric climate change alone, and include changes to water

resources, transportation, agriculture, ecosystems, and human health.

The USGCRP issued the report, Global Climate Change Impacts in the United States, in

June 2009 summarizing the impacts climate change has already had on the U.S. and the

projected future impacts due to continued climate change (USGCRP, 2009). The report

describes the effects of global change on different regions of the U.S. (e.g., Southeast)and on

various societal and environmental sectors, such as water resources, agriculture, energy use, and

human health. Building on the findings presented in this report as well as other recent research,

the USGCRP issued the report, The National Global Change Research Plan 2012-2021: A

Strategic Plan for the U.S. Global Change Research Program, which outlines specific goals and

objectives for the Program to generate and disseminate scientific knowledge that is readily

available and directly useful to decision-makers and the general public (USGCRP, 2012). These

efforts are intended to fulfill the Congressional mandate of the GCRA. Although climate change

is a global concern, for this analysis, the focus is on the cumulative impacts of climate change in

the Project area.

The USGCRP’s report notes the following observations of environmental impacts that

may be attributed to climate change in the Southeast region:

 average temperatures have risen about 2°F since 1970 and are projected to increase

another 4.5 to 9°F during this century;

 increases in illness and death due to greater summer heat stress;

45 The USGCRP member agencies are: Department of Agriculture, Department of Commerce, Department of

Defense, Department of Energy, Department of Health and Human Services, Department of the Interior, Department

of State, Department of Transportation, Environmental Protection Agency, National Aeronautics and Space

Administration, National Science Foundation, Smithsonian Institution, and U.S. Agency for International

Development.
Environmental Impact Statement 4-225 Corpus Christi LNG

 the destructive potential of Atlantic hurricanes increased since 1970 and the intensity

(with higher peak wind speeds, rainfall intensity, and storm surge height and strength)is

likely to increase during this century;

 within the past century in the U.S., relative sea level changes ranged from falling several

inches to rising about 2 feet and are projected to increase another 3 to 4 feet this century;

 sea level rise and human alterations have caused coastal wetland loss during the past

century, reducing the capacity of those wetlands to protect against storm surge, and

projected sea level rise is anticipated to result in the loss of a large portion of the nation’s

remaining coastal wetlands;

 declines in dissolved oxygen in streams and lakes have caused fish kills and loss of

aquatic species diversity;

 moderate to severe spring and summer drought areas have increased 12 to 14 percent

(with frequency, duration and intensity also increasing and projected to increase);

 longer periods of time between rainfall events may lead to declines in recharge of

groundwater and decreased water availability;

 responses to decreased water availability, such as increased groundwater pumping, may

lead to stress or depletion of aquifers and a strain on surface water sources;

 increases in evaporation and plant water loss rates may alter the balance of runoff and

groundwater recharge, which would likely to lead to saltwater intrusion into shallow

aquifers;

 coastal waters temperature rose about 2°F in several regions and are likely to continue to

warm as much as 4 to 8°F this century;and

 coastal water warming may lead to the transport of invasive species through ballast water

exchange during ship transit.

Climate Change in the Project region would have two effects which may cause increased

storm surges;increase temperatures of Gulf Waters which would increase storm intensity, and a

rising sea level. Even with the increased sea levels due to climate change, and increased storm

surge, the critical structure elevations of 25-feet above mean sea level at the Liquefaction Plant

would provide a significant barrier to even a 100-year climate change-enhanced storm surge.

The GHG emissions associated with construction and operation of the Project were

identified and quantified in section 4.11.1.4. Based on the total annual potential emissions for

the constructed Terminal and Sinton and Taft Compressor Stations, Project operations would

increase CO2 emissions in Texas by approximately 0.5 percent (based on 2010 emissions for the

State [DOE, 2013]).

GHG emissions from sources located at Project facilities (Terminal and Sinton

Compressor Stations)would be minimized by application of EPA-approved BACT under the

PSD permitting program. Cheniere prepared a BACT analysis for the proposed refrigeration

compressor turbines, standby generators, flares, thermal oxidizers, and fugitive emissions at the

Terminal which was submitted to TCEQ for review. CO2 emissions from the turbines would be

minimized through use of natural gas as fuel, design energy efficiency, and operational energy
Environmental Impact Statement 4-226 Corpus Christi LNG

efficiency (i.e., good combustion practices) as BACT. The aeroderivative-class GE

LM2500+G4 SAC model turbines selected by Cheniere have a higher thermal efficiency than the

heavy-duty frame-class turbines. Also, natural gas for fuel yields the lowest CO2 emissions, on a

lb/MWh basis, of any fuel available for the turbines. Cheniere’s design also includes a waste

heat recovery system on the exhaust of two ethylene turbines for each liquefaction train to

provide the required heat for gas treatment, thus avoiding the need for new CO2-emitting gasfired heaters. Cheniere proposed a BACT emission limit for the turbines of 0.058 ton

CO2/MMBtu. BACT for the flares and thermal oxidizers is the implementation of design and

operational energy efficiency measures, along with a BACT emission limit for the oxidizers of

57.8 ton CO2 per million standard cubic feet. BACT for the limited-use standby generators and

fire water pump engines is the use of efficiently designed and operated generators with low

annual capacity factors (expected to be no more than 0.6 percent). BACT for fugitive emissions

from natural gas components is a gas leak detection and repair program, including a modified

form of the TCEQ 28M leak detection and repair program for fugitive emissions of methane.

Cheniere also prepared a BACT analysis for the proposed compressor turbines, standby

generator, and gas blowdowns at the Sinton Compressor Station, which was reviewed by EPA.

BACT for the turbines is the use of natural gas as fuel, with a proposed emission limit of 0.058

ton CO2/MMBtu. BACT for the standby generator is the use of efficiently designed and

operated generator using natural gas. BACT for the gas blowdowns is the use of an additional

seal gas booster system for the gas compressors and the capability to burn potential blowdown

gases as fuel, assuming at least one turbine is in operation.

Cheniere provided an assessment of the feasibility of a carbon capture and storage system

to TCEQ as part of the GHG permit application BACT analysis. Cheniere provided information

on the technical and economic feasibility of developing and using carbon capture and storage for

the Terminal and Sinton Compressor Stations. This technology involves deploying a method to

capture carbon from the exhaust stream of the combustion units and then finding a method for

permanent storage (injecting the recovered CO2 underground through various means, including

enhanced oil recovery, saline aquifers, and un-mineable coal seams). In the GHG BACT

analysis, Cheniere stated that there is no commercially available carbon capture system of the

scale that would be required to control the CO2 emissions from compressor turbines, thermal

oxidizers, and flares, such as those typically located at an LNG terminal or compressor station.

Also, Cheniere stated that no long-term CO2 storage facilities are located near the Project, as the

region does not have geological formations that support sequestration. Based on the magnitude

of the estimated capital and annualized costs, Cheniere demonstrated that CCS is not

economically feasible. Even if feasibility could be demonstrated, Cheniere noted that any CCS

system would cause significant adverse energy and environmental impacts due to the additional

water and energy needs for system operation, with the associated generation of additional GHGs

and other criteria pollutants from natural gas firing in combustion units. EPA and TCEQ are still

evaluating the GHG permit applications for the Terminal and Sinton Compressor Station.

Climate Change in the region would have two effects which may cause increased storm

surges;increase temperatures of Gulf Waters which would increase storm intensity, and a rising

sea level. Even with the increased sea levels due to climate change, and increased storm surge,

the critical structure elevations of 25-feet above mean sea level at the Liquefaction Plant would

provide a significant barrier to even a 100-year climate change-enhanced storm surge.
Environmental Impact Statement 4-227 Corpus Christi LNG

Currently, there is no standard methodology to determine how the Project’s incremental

contribution to GHGs would result in physical effects on the environment, either locally or

globally. However, estimated emissions associated with the Project would incrementally

increase the atmospheric concentrations of GHGs, in combination with GHG emissions from

other sources identified in the cumulative impacts analysis. Because we cannot determine the

Project’s incremental physical impacts due to climate change on the environment, we cannot

determine whether or not the Project’s contribution to cumulative impacts on climate change

would be significant.

4.13.5.12 Safety

For the proposed Terminal, we considered the cumulative impact area for marine vessel

traffic to include the water route from the Aransas Pass Sea Buoy, through the entrance of the

Jetty Channel, Corpus Christi Channel, and the La Quinta Channel, terminating at the Terminal

marine berths. The cumulative impact area for the Terminal is the area adjacent to and in the

vicinity of the Terminal site, and the cumulative impact area for the Pipeline was considered to

be within about 660 yards of the pipeline centerline. The cumulative impact area for emergency

services includes the area in the general vicinity of the Terminal and the Pipeline.

Cheniere would mitigate impacts on public safety through the implementation of

applicable federal, state, and local rules and regulations for the proposed Project as described in

section 4.12. Those rules and regulations would ensure that the applicable design and

engineering standards are implemented to protect the public and avoid or minimize the potential

for accidents and failures.

As noted in section 4.12, the risk associated with the Pipeline would be small. In

addition, the proposed Pipeline is adjacent to several pipelines and crosses several other

pipelines. Although operation of the proposed Pipeline would increase the risk of a pipeline

accident, the increase in risk would be small. As a result, cumulative impact on risk for the

Pipeline would not be significant.

Emergency response time is a key aspect of public health and safety. Key emergency

services would be provided by the existing services in San Patricio and Nueces Counties. In

accordance with our regulations, Cheniere would prepare a comprehensive plan that identifies

the cost sharing mechanisms for funding these emergency response costs. Therefore, the

cumulative impact of each project’s comprehensive plans would not result in a significant impact

on public safety.

4.13.6 Conclusions for Overall Cumulative Impacts

A thorough determination regarding the significance of cumulative impacts for specific

environmental resources is difficult due to a lack of access to the details of activities for many

identified projects. Additionally, distinct threshold values for most environmental resources are

typically undetermined. The most significant cumulative impacts would occur should all

identified projects in the area be constructed concurrently with the Project;however, this is not

anticipated. However, construction of the Terminal, in addition several of the identified projects,

would result in the permanent loss of various wildlife habitats and natural land use types. As a

result, construction of the Project would cumulatively contribute to the increasing

industrialization of agricultural and/or open lands in the area.
Environmental Impact Statement 4-228 Corpus Christi LNG

Most of the cumulative environmental impacts identified would be short-term and minor,

such as impacts on geology, soils, water, threatened and endangered species, and terrestrial

vegetation. The Project and several of the identified projects would increase vessel traffic within

the Port;however, the large port would more than likely be capable to adequately accommodate

such an increase and thus, would not contribute significantly to cumulative impacts on marine

traffic.

Wetlands and SAV within the region would sustain the most significant impacts, as

dredging and other activities associated with the Project and others would result in the

degradation and permanent loss of these resources. Compensatory and voluntary mitigation

plans and procedures for many of the projects would offset the severity of cumulative permanent

impacts on wetlands and SAV. Cheniere would comply with the terms and conditions of the

Section 404 permit by creating new wetland habitat and protect existing habitat, and would not

significantly contribute to the loss of wetlands.

Cumulative benefits would be realized from the creation of new wetlands, seagrass, and

marsh habitats through compensatory and voluntary mitigation programs. Additionally, the

Project and identified projects would enhance the local economy through jobs and wages,

purchases of goods and materials, and tax revenues.
CONCLUSIONS AND RECOMMENDATIONS

SECTION 5

Environmental Impact Statement 5-1 Corpus Christi LNG

5.0 CONCLUSIONSAND RECOMMENDATIONS

5.1 SUMMARY OFTHE ENVIRONMENTAL ANALYSIS

The conclusions and recommendations presented in this section are those of the FERC

environmental staff. Our conclusions and recommendations are based on input from the COE,

Coast Guard, DOE, DOT, and EPA as cooperating agencies in the preparation of this EIS.

However, the cooperating agencies will present their own conclusions and recommendations in

their respective Records of Decision and determinations, and can adopt this EIS consistent with

40 CFR 1501.3 if, after an independent review of the document, they conclude that their

requirements have been satisfied. Otherwise, they may elect to conduct their own supplemental

environmental analysis.

We conclude that construction and operation of the Corpus Christi LNG Project would

result in temporary and short-term impacts on numerous resources. However, the Project would

result in permanent impacts on wetlands, EFH, agricultural lands, and visual resources;and longterm impacts on air quality. As part of our analysis, we developed specific mitigation measures

that are practical, appropriate, and reasonable for construction and operation of the Project. We

are, therefore, recommending that these mitigation measures be attached as conditions to any

authorization issued by the Commission. Implementation of the mitigation proposed by

Cheniere and our recommended mitigation would ensure that impacts in the Project area would

be avoided or minimized and would not be significant. A summary of the Project impacts and

our conclusions are presented below by resource.

5.1.1 Geologic Resources

Construction and operation of the Project would not significantly alter the geologic

conditions of the Project area or affect mining of resources. Additional information is required

on the geology and seismology of the Terminal site to adequately design the facilities to prevent

any safety risks. Therefore, we are recommending that Cheniere file the Terminal and LNG tank

designs and construction details stamped and sealed by the professional engineer-of-record. The

Pipeline would not cross any significant geologic hazards, including areas of seismic activity or

subsidence. Cheniere is committed to conducting geotechnical investigations for the HDDs to

determine general subsurface conditions prior to constructing the Pipeline. Blasting is not

anticipated during construction of either the Terminal or the Pipeline. Based on Cheniere’s

proposal, including implementation of our Plan and Procedures and our recommended mitigation

measures, impacts on geological resources would be adequately minimized and would not be

significant, and that the potential for impacts on the Project from geologic hazards would also be

minimal.

5.1.2 Soils

Construction of the Project facilities would disturb soils, resulting in increased potential

for erosion, compaction, and mixing of topsoil. Soils within the Terminal site have high erosion

potential. Addition areas susceptible to erosion within the Project area include stream banks and

the banks of drainage ditches crossed by the Pipeline. Cheniere would implement the erosion

and sediment control measures outlined in our Plan and Procedures. Cheniere would further

minimize potential for shoreline erosion at the Terminal by installing articulated block mats or
Environmental Impact Statement 5-2 Corpus Christi LNG

rock breakwaters to protect the shoreline within the marine vessel maneuvering area from

erosion.

Construction of the Terminal would not significantly impact prime farmlands, as the area

was previously disturbed. However, construction of the Pipeline would result in the loss of 21.5

acres of prime farmland due to the installation of permanent aboveground facilities. Most

impacts during pipeline construction would be short-term and would not impact potential use of

prime farmland for agricultural purposes. Implementation of measures outlined in our Plan

would adequately minimize the impacts from the Project on prime farmland.

Due to the historic industrial use of the Terminal site and surrounding areas, there would

be potential for contaminated soils to be discovered during construction. However, no areas of

contamination have been identified at the Terminal site. In order to ensure that no contaminated

soils are imported to the site for use as structural fill, removed from the site, or discovered during

construction, Cheniere would follow guidelines outlined in its Specification for Site Preparation

and Earthwork to fulfill the requirements for soils imported to the site.

5.1.3 Water Resources

Due to the non-potable saline groundwater conditions that naturally occur at the

Terminal, lack of water supply wells in the area, depth of groundwater below land surface in

relation to anticipated excavation depths, construction of the proposed pilings within the

permeable zone of the Chicot aquifer rather than crossing the aquifer confining layers, and

surficial mitigation measures that would be implemented by Cheniere including those described

in its SPCC Plan and our Procedures, no significant impact on the groundwater resources

underlying the Terminal facilities is anticipated.

Impacts on groundwater as a result of the Pipeline would be similar to that discussed for

the Terminal. The greatest potential for impacts on groundwater would be an accidental release

of a hazardous substance, such as fuels, lubricants, and coolants while constructing and operating

the Pipeline. We have determined that the implementation of measures outlined in Cheniere’s

SPCC Plan and our Procedures would adequately minimize potential impacts on groundwater

resources resulting from construction and operation of the Pipeline.

Construction and operation of the Terminal would result in decreased water quality of

Corpus Christi Bay within the vicinity of the site as a result of initial dredging and maintenance

dredging, as well as stormwater runoff and dewatering. Impacts on water quality from dredging

activities would be short-term and localized to within a few hundred feet of the activity. Impacts

on water quality from dredging would be minimized by the use of a hydraulic cutterhead dredge

which effectively captures most sediment disturbed during dredging. Through implantation of

NPDES regulations, our Procedures, and Cheniere’s SPCC Plan, potential impacts resulting from

stormwater runoff or the discharge of hydrostatic test water would be adequately minimized or

avoided. We have determined that with implementation of the measures outlined above, impacts

on surface water resources as a result of the construction and operation of the Terminal would

not be significant.

Waterbodies crossed by the Pipeline via the open cut method would experience

short-term impacts on water quality including increased turbidity, sedimentation, and overall

stream bed and bank disturbance. Cheniere would avoid significantly impacting water quality in

two of the nine waterbodies crossed by the Pipeline, Chiltipin and Oliver Creeks, by utilizing
Environmental Impact Statement 5-3 Corpus Christi LNG

HDD crossing methods. We have determined that implementation of Cheniere’s SPCC Plan, the

HDD crossing method, and the measures outlined in our Procedures would adequately minimize

impacts on surface water resources associated with the construction and operation of the

Pipeline.

5.1.4 Wetlands

Construction and operation of the Terminal would result in the disturbance of 27.45 acres

of wetlands including 25.67 of permanent wetland loss. Wetlands within the Terminal consist of

cordgrass salt marsh, black mangrove, unvegetated sand flat, vegetated flats/high marsh, and

seagrass. To mitigate unavoidable impacts on wetlands at the Terminal, Cheniere submitted to

the COE an ARMP for the Project. As part of the 404 permit process, the COE will require that

Cheniere conduct a functional assessment to more adequately evaluate wetland impacts and

mitigation associated with the Project. Pending the results of the functional assessment, the COE

may require increased compensation as part of Cheniere’s final ARMP. We are recommending

that Cheniere file its final ARMP once complete prior to construction. Cheniere would monitor

all temporarily impacted wetlands in accordance with our Procedures until restoration is

complete.

The Pipeline would cross four PEM wetlands, three of which would be crossed by HDD

and would not result in any impacts. One small wetland (less than 0.01 acre)is located within

the proposed permanent pipeline easement and would be restored to preconstruction conditions

following the completion of construction activities.

Based on Cheniere’s proposed impact mitigation measures as well as preparation of the

functional assessment and ARMP to be approved by the COE, we have determined that

constructing and operating the Terminal and Pipeline would not have a significant impact on

wetlands.

5.1.5 Vegetation

Land-based facilities at the Terminal would not significantly impact vegetation, as the

site is highly disturbed and sparsely vegetated. Construction and operation of the marine berths

would permanently impact approximately 9.17 acres of SAV (seagrass beds). Mitigation for the

permanent conversion of SAV to deep water habitat would be mitigated by Cheniere through

implementation of its ARMP as discussed in section 4.4.1. Approximately 0.12 acre of SAV

will be temporarily impacted. Cheniere would adhere to our Procedures, including postconstruction monitoring, to ensure restoration of these areas following construction.

Based on the disturbed nature of the Terminal site, the amounts and types of vegetation

impacted, and Cheniere’s proposed impact minimization and mitigation measures, we have

determined that constructing and operating the Terminal facilities would not significantly impact

vegetation.

No sensitive vegetation would be impacted by the Pipeline. Vegetation impacted by the

Pipeline would be predominantly agricultural crops with some herbaceous and scrub-shrub

vegetation in open land. All areas impacted by installation of the Pipeline, with the exception of

the MLVs and two compressor stations, would be restored to preconstruction conditions. Due to

the abundance of similar vegetation in the area, permanent impacts on vegetation from the

aboveground facilities would not be significant.
Environmental Impact Statement 5-4 Corpus Christi LNG

5.1.6 Wildlife and Aquatic Resources

Construction and operation of the Terminal would result in the removal and/or

conversion of wildlife habitats at the site. Land-based facilities would result in the permanent

conversion of open land to industrial land. However, due to the previous industrial use of the

site and its proximity to other industrial areas, we conclude that this would not constitute a

significant impact on terrestrial wildlife habitat. To minimize impacts on wildlife, Cheniere

would restrict the size of construction areas to the maximum extent practicable and implement

measures described in our Plan and Procedures to avoid or minimize off-site impacts.

Construction and operation of the marine berths could impact aquatic reptiles and

mammals, as well as fisheries resources, as a result of dredging and pile driving during

construction and from LNG carrier traffic during operation. Impacts from pile driving and other

construction activities would be temporary. Operation impacts would be permanent;however,

because such activities are already common in the vicinity of the Terminal, and Cheniere would

inform LNG carriers about vessel strike avoidance measures, we have determined that impacts

on marine mammals and reptiles would not be significant.

Impacts on fisheries and other aquatic resources, including EFH would primarily result

from dredging, dredge disposal, and pile driving activities. These activities would also similarly

impact recreational and commercial fisheries. Additionally, LNG carriers calling on the

Terminal and other ship-related marine traffic and operations could also impact fisheries

resources. Impacts on EFH are further discussed in the EFH Assessment in appendix B.

Cheniere would adhere to measures outlined in our Plan and Procedures as well as its

ARMP to minimize and mitigate for impacts on fish and other aquatic resources. Potential

impacts associated with stormwater runoff would be minimized or avoided through

implementation of Cheniere’s SPCC Plan, construction of drainage ditches at the Terminal, and

adherence to NPDES regulations. Cheniere would also obtain state water quality certification

under Section 401 of the CWA from the RRC, and a Section 10/404 permit from the COE. We

have determined that construction and operation of the Terminal would impact fisheries and

other aquatic resources;however, based on Cheniere’s implementation of the measures outlined

above and in its ARMP, these impacts have been sufficiently minimized.

No sensitive wildlife habitats would be impacted by construction or operation of the

Pipeline. The majority of the area disturbed during construction would be agricultural land and

open land that would revert back to preconstruction condition and use following the completion

of construction activities. Areas adjacent to the Pipeline area provide similar and ample habitats

for wildlife displaced temporarily during construction of the Pipeline. Wildlife would return to

the majority of the Project area following construction and restoration. Impacts on wildlife

during construction and operation of the Pipeline would be minimized by the implementation of

our Plan and Procedures as well as restriction of vegetation clearing between March 1 and

August 31 to avoid impacts on migratory birds. If vegetation clearing must be conducted during

this time, Cheniere would survey for migratory bird nests no more than three weeks prior to

commencing work. If an active migratory bird nest is found, Cheniere would consult with the

FWS to identify the most appropriate measure to be taken to avoid or minimize impacts.

Impacts on aquatic resources associated with construction and operation of the Pipeline

would consist of loss of aquatic habitat, disturbance of the stream bed, and increased turbidity

and sedimentation. Two of the nine waterbodies crossed by the Pipeline support sustainable
Environmental Impact Statement 5-5 Corpus Christi LNG

fisheries (Oliver and Chiltipin Creeks); however, Cheniere would cross both of these

waterbodies via HDD, avoiding direct impacts to fisheries and other aquatic resources.

Additionally, Cheniere would complete all waterbody crossings in accordance with the

construction and mitigation measures described in our Procedures.

Based on the characteristics of the fisheries contained within the nine waterbodies that

would be crossed and Cheniere’s use of HDDs and its implementation of impact minimization

measures as described in our Procedures, we have determined that constructing and operating the

Pipeline facilities would not significantly impact aquatic resources.

5.1.7 Threatened,Endangered,and Other Sensitive Species

Based on consultations with the FWS and NOAA Fisheries, as well as Cheniere’s habitat

surveys, 13 federally listed species potentially occur in the general Project area. We have

determined that construction and operation of the Project is not likely to adversely affect the blue

whale, fin whale, humpback whale, sei whale, sperm whale, West Indian manatee, whooping

crane, piping plover, loggerhead sea turtle, green sea turtle, leatherback sea turtle, Atlantic

hawksbill sea turtle, and Kemp’s ridley sea turtle at the Terminal, and that the Pipeline would

have no effect on federally listed species. Regarding federally listed threatened and endangered

species, NOAA Fisheries notified Cheniere on October 29, 2012 that initiation of Section 7

consultation would not be required;and in letters dated August 8, 2013 and November 5, 2013,

the FWS concurred with determinations that the Project is not likely to adversely affect species

under its jurisdiction.

Ten state listed species were identified as potentially occurring within the Project area.

Based on the presence of potential habitat, we conclude that Cheniere’s collocation with existing

utility corridors and constructing primarily within previously disturbed areas would avoid or

minimize potential impacts on state listed species by reducing the overall extent of new land

disturbance.

In summary, implementation of Cheniere’s mitigation measures and use of our Plan and

Procedures during construction and operation of the Project would adequately minimize impacts

on federally and state listed species.

5.1.8 Land Use,Recreation,and Visual Resources

Construction of the Terminal would occur within a previous industrial site that has since

been reclaimed and would result in permanent impacts on 321 acres of open land and 148 acres

of open water. The majority of the open land area used for operation would be permanently

converted to industrial land (approximately 5 acres would be converted to open water). Open

water areas impacted by operation would remain open water, but would be dredged to a greater

depth. To ensure compliance with the CZMA, we are recommending that Cheniere file RRC

concurrence that the Project is consistent with the Texas CZMP.

Construction and operation of the Pipeline, including permanent access roads, would

result in approximately 133.3 acres of permanent operation impacts on agricultural land

(including areas impacted by the permanent pipeline easement that would return to agricultural

use), 38.4 acres of permanent operation impacts on open land (including areas impacted by the

permanent pipeline easement that would return to open land), and 6.6 acres of industrial land for

operation.
Environmental Impact Statement 5-6 Corpus Christi LNG

Impacts on visual resources near the Terminal resulting from the storage tanks and

elevated flare stack would be permanent. However, due to the proximity of the Terminal to other

industrial structures, the storage tanks and elevated flare stack would be consistent with the

surrounding viewshed. Visual impacts from facility lighting at the Terminal would be

permanent, but would be the minimum amount necessary to allow personnel to safely work and

inspect the equipment at the Terminal.

The construction of the Pipeline would temporarily impact visual resources along the

route due to the presence of construction personnel and equipment. Construction and operation

of the Taft and Sinton Compressor Stations would permanently impact the viewshed in the area.

However, Taft Compressor Station would be located in a rural area near a wind farm and the

Sinton Compressor Station would not be visible from the nearest public area minimizing and

avoiding impacts on the surrounding viewshed.

5.1.9 Socioeconomics

Construction of the Project would require a workforce of 2,100 workers, peaking at

approximately 3,300 workers. Cheniere would utilize predominantly local workers during

construction and employ a relatively small full-time operations staff at the Terminal. Projectrelated construction impacts on the regional population would result in a short-term, moderate

increase to the local population, and Project operation would result in a negligible, long-term

increase.

Construction and operation of the Project would increase local and state tax revenues

from sales taxes, payroll taxes, and would likely increase local employment. Additionally, the

Project would not impact any urban or residential areas, and no disproportionately high and

adverse human health or environmental effects on minority, low-income communities, or Indian

tribes have been identified.

Impacts on traffic in the Project area would primarily occur during construction of the

Terminal. During construction, Cheniere would minimize impacts on traffic via the use of

busses to transport workers to the site. Additionally traffic during construction would only

slightly increase overall traffic in the area. During operation, the increase in traffic would be

negligible and would not result in a perceptible increase in area traffic.

Construction and operation of the Terminal would result in an increase in marine traffic

in the area. During operation, Cheniere anticipates receiving approximately 300 LNG carriers

annually. Although LNG carriers would require a moving safety and security zone that would

limit deep draft traffic while LNG carriers are in the channel, the LNG carriers would only be in

the channel for about 1.25 hours and are not anticipated to adversely impact overall vessel traffic

patterns.

5.1.10 Cultural Resources

Cultural resource surveys were conducted for the entire Project area with the exception of

the area along the Pipeline between MP 0.0 and 0.5. No traditional cultural resources, burials, or

sites of religious significance to Indian tribes were identified in the APE by the National Park

Service, BIA, SHPO, Cheniere, or the Indian tribes contacted by the FERC. We agree with the

SHPO’s determination in a letter dated July 3, 2012, that no historic properties would be affected

in areas that have been inventoried. However, we are recommending that prior to the start of
Environmental Impact Statement 5-7 Corpus Christi LNG

construction Cheniere file with the Secretary the remaining evaluation reports or treatment plans,

and comments on the reports and plans from the Texas SHPO

5.1.11 Air Qualityand Noise

Air quality impacts associated with construction of the Project would include emissions

from fossil-fueled construction equipment and fugitive dust. Construction emissions associated

with the Pipeline and compressor stations would be temporary and localized; however,

compressor station emissions would transition to operational-phase emissions. The five-year

construction period at the Terminal would result in short-term air quality impacts which would

transition to permanent operational-phase emissions after commissioning and initial start-up.

Cheniere would incorporate fugitive dust control measures during construction to minimize

emissions. However, we and the EPA find that Cheniere has not adequately addressed track-out

onto paved roads as part of its fugitive dust controls. Therefore, we are recommending that

Cheniere file a revised FDCP that incorporates additional mitigation measures to address trackout, prior to the start of construction.

Operation of the Terminal and the Sinton and Taft Compressor Stations would result in

permanent air quality impacts. Cheniere would minimize operation emissions through

implementation of Best Available Control Technology, as required by Cheniere’s operating air

permits. Cheniere has applied for all applicable air permits and would comply with all air permit

requirements for those facilities. The Taft Compressor Station would be below PSD and Title V

permit thresholds and would be classified as a minor source. In addition, air dispersion

modeling, which included LNG carriers and other nearby emission sources, demonstrated that

operation of the Terminal would not result in an exceedance of the NAAQS at any location, with

the exception of NO2. An expanded analysis determined that operation of the Terminal would

not contribute significantly to exceedances of the 1-hour NO2 NAAQS. Air dispersion modeling

also demonstrated that the Sinton Compressor Station would not result in any exceedances of the

NAAQS at any location.

Impacts on noise levels associated with construction of the Project would generally be

temporary, minor, and limited to daylight hours. The highest noise levels would be generated

during the four to six months of pile driving activities, which are estimated to be well below

significant at all NSAs. Based on the detailed noise assessments for each of the proposed HDD

locations, noise levels from the Chiltipin Creek and US 181/SH 35 HDDs would be below the

existing noise levels at the nearest NSAs. Noise levels may be perceived as twice as loud as the

existing noise levels at one residence located near the Oliver Creek HDD. Cheniere has

committed to performing all HDD activities, except potentially the pipe pullback, during daylight

hours to mitigate significant noise impacts at NSAs.

The Terminal and Sinton and Taft Compressor Stations would generate noise on a

continuous basis during operation. However, the predicted noise levels attributable to operation

of these facilities should not result in significant impacts on the NSAs nearest to those facilities.

To ensure that actual noise levels resulting from Project operation would not exceed significant

levels, we are recommending that Cheniere file post-construction noise survey reports for each

facility.
Environmental Impact Statement 5-8 Corpus Christi LNG

5.1.12 Safety

We evaluated the safety of the proposed Terminal facility, the related LNG carrier transit,

and the sendout Pipeline. As part of our evaluation of the Terminal, we performed a technical

review of the preliminary engineering design to ensure sufficient layers of protection would be

included in the facility designs to mitigate the potential for an incident that could impact the

safety of the public. The DOT reviewed the data and methodology Cheniere used to determine

the design spills from various leakage sources, including piping, containers, and equipment

containing hazardous liquids, and stated it has no objection to Cheniere’s methodology for

determining the candidate design spills used to establish the required siting for its proposed

Terminal. The Coast Guard reviewed the suitability of the Corpus Christi Ship Channel from the

entrance approach at Port Aransas to the La Quinta Junction and the entire length of La Quinta

Channel, and issued a LOR indicating the waterway would be suitable for the type and frequency

of the marine traffic associated with the proposed Project. In addition, Cheniere would be

required to comply with all regulations in 49CFR 192 for its Pipeline and 33 CFR 105, 33 CFR

127, and 49CFR 193 for its Terminal facilities. Based on our engineering design analysis and

recommendations presented in section 4.12 for the Terminal, the design spill methodology

reviewed by DOT for the Terminal, the LOR issued by the Coast Guard for the LNG carrier

transit, and the regulatory requirements for the Pipeline and Terminal, we conclude that the

Project would not result in significantly increased public safety risks.

5.1.13 Cumulative Impacts

We considered the contributions of the proposed Project in conjunction with other

projects in the Project area to determine the potential for cumulative impact on the resources

affected by the Project. As a part of that assessment, we identified existing projects, projects

under construction, projects that are proposed or planned, and reasonably foreseeable projects

including existing and proposed LNG import and export terminals, other development projects,

and non-jurisdictional facilities associated with the Project. Our assessment considered the

impacts of the proposed Project combined with the impacts of the other projects on resources

within all or part of the same area and time. We conclude that although cumulative impacts on

some resources would occur, those impacts would not be significant.

Most of the identified cumulative impacts would be temporary and minor. However,

construction of the Terminal, in addition to several of the identified projects, would result in the

permanent loss of various wildlife habitats and natural land use types. As a result, construction

of the Project would contribute to the increasing industrialization of agricultural and/or open

lands in the area. Additionally, several of the identified projects, as well as the proposed Project

would contribute to an increase in vessel traffic in the Port. This would be a long-term impact;

however, due to the size of the Port, this would not contribute significantly to cumulative

impacts on marine traffic.

Other temporary and minor cumulative environmental impacts identified include impacts

on water and air quality, threatened and endangered species, and terrestrial vegetation.

Additionally, several of the identified projects, as well as the proposed Project would contribute

to an increase in vessel traffic in the Port;however, due to the size of the Port, this would not

contribute significantly to cumulative impacts on marine traffic.

Additionally the Project would result in cumulative impacts on wetlands and SAV within

the region when combined with dredging and degradation from other projects in the area.
Environmental Impact Statement 5-9 Corpus Christi LNG

Compensatory and voluntary mitigation plans for many of the projects would offset the severity

of permanent cumulative impacts on wetlands and SAV. Alternatively, there would also be

beneficial cumulative impacts from the creation of new wetlands, seagrass, and marsh habitats

through the compensatory and voluntary mitigation programs as well as beneficial use of

dredged material. Other beneficial cumulative impacts would be enhancement of the local

economy from increased tax revenues, jobs and wages, and purchases of goods and materials.

5.2 ALTERNATIVES

As alternatives for the Terminal and the Pipeline, alternative Terminal sites, alternative

dredge disposal locations, alternative Pipeline aboveground facility sites, and major and minor

route variation alternatives for the Pipeline. While the No-Action Alternative would avoid the

environmental impacts identified in this EIS, the objectives of the Project would not be met.

However, any need for the import and export of natural gas could potentially be met by LNG

export and import projects developed elsewhere, which would result in similar or greater impacts

at other locations. Potential end users could make other arrangements to obtain natural gas

service, or use alternative fossil fuel energy sources, other traditional long-term fuel source

alternatives, and/or renewable energy sources to compensate for the reduced availability of

natural gas that would otherwise be supplied by the Project. Similarly, natural gas capacity

holders on the Pipeline would have to find other outlets for getting natural gas to market, which

could include other pipelines or LNG terminals, each with their own environmental impacts.

We evaluated 12 Terminal system alternatives including 6 existing LNG import terminals

with planned, proposed, or authorized LNG export projects and 6 planned, proposed, or

authorized LNG terminals dedicated solely to export of LNG. All of the systems would require

the need for substantial construction beyond that currently proposed, production volume

limitations, in-service dates scheduled significantly beyond Cheniere’s schedule, including any

customer commitments, and environmental impacts that were considered comparable to or

greater than those of the proposed Project. As a result, we eliminated them from further

consideration.

We evaluated 17 alternative Terminal sites at existing ports along the Gulf Coast. Three

of these sites were selected for further evaluation based on access to a channel greater than 40

feet deep, access to major natural gas pipelines, industrial zoning, and availability of sufficient

open land for construction and operation of the Terminal. Each of these three evaluated sites

was previously proposed as a site for an LNG project, but the projects were never built. We

conclude the use of two of those areas would no longer be feasible, as the properties are now

owned by Occidental Petroleum Corporation and are no longer available to Cheniere. The third

site was removed from consideration as a viable alternative, as it did not meet the Project’s

criteria for access to an existing pipeline system. In addition, the location of the Terminal site

was selected because it is compatible with the existing industrial land use, would minimize

impacts on agricultural land, and would not adversely impact protected resources. As a result,

we conclude that development of the Terminal on the alternative sites would not be

environmentally preferable or fully satisfy the Project’s purpose and need. We considered two

alternative dredge disposal locations, but found that neither of these locations were

environmentally preferable to the proposed site

We evaluated 12 existing pipeline systems as system alternatives to the proposed

Pipeline, including five pipelines that have planned connections to the Cheniere Pipeline. We
Environmental Impact Statement 5-10 Corpus Christi LNG

determined that those system alternatives would not have sufficient capacity to meet the natural

gas requirements of the Terminal without substantial expansion. Construction impacts of

expanding those pipeline systems would be similar to or greater than those of the proposed

Pipeline. Consequently, we conclude that none of the pipeline system alternatives would be

environmentally preferable to the proposed Pipeline.

We evaluated three major pipeline route alternatives in addition to the proposed Pipeline

route to determine which would produce minimal environmental impacts while meeting the

Pipeline’s objective. The proposed Pipeline route would provide the shortest distance from the

Terminal to existing high pressure natural gas pipeline systems in the South Texas region. In

addition, the proposed route minimizes environmental impacts by maximizing the use of existing

corridors in the area. We determined that the major route alternatives would not offer a

significant environmental advantage over the proposed route. Consequently, we conclude that

none of the major pipeline route alternatives would be environmentally preferable to the

proposed Pipeline route.

We evaluated one site alternative to the proposed Taft Compressor Station site. Although

both sites are located on agricultural land that lack environmentally-sensitive resources, the

proposed site is further away from NSAs than the alternative site. Consequently, we conclude

that the alternative site would not provide a significant environmental advantage to the proposed

Taft Compressor Station site.

We evaluated four site alternatives to the proposed Sinton Compressor Station site.

Three of these alternative sites would require crossing an existing railroad track along US

Highway 77, resulting in a safety concern for vehicle traffic. The remaining alternative site is

closer to the nearest NSA than the proposed site, which was also preferred by the landowner.

Therefore, we conclude that the alternative sites would not provide a significant environmental

advantage to the proposed Sinton Compressor Station site. No alternative sites were identified

that would be environmentally preferable to the other proposed aboveground facilities associated

with the Pipeline.

5.3 FERC STAFF’SRECOMMENDED MITIGATION

If the Commission authorizes the Project, we are recommending that the following

measures be included as specific conditions in the Commission’s Order. These measures would

further mitigate the environmental impacts associated with the construction and operation of the

proposed Project. The section number in parentheses at the end of a condition corresponds to the

section number in which the measure and related resource impact analysis appears in the EIS.

1. Cheniere shall follow the construction procedures and mitigation measures described in

its applications and supplemental filings (including responses to staff data requests), and

as identified in the EIS, unless modified by the Order. Cheniere must:

a. request any modification to these procedures, measures, or conditions in a filing

with the Secretary;

b. justify each modification relative to site-specific conditions;

c. explain how that modification provides an equal or greater level of environmental

protection than the original measure;and
Environmental Impact Statement 5-11 Corpus Christi LNG

d. receive approval in writing from the Director of OEP before using that

modification.

2. For LNG facilities, the Director of the OEP has delegated authority to take all steps

necessary to ensure the protection of life, health, property, and the environment during

construction and operation of the Terminal. This authority shall include:

a. stop-work authority and authority to cease operation;and

b. the design and implementation of any additional measures deemed necessary to

ensure compliance with the intent of the Order.

3. The Director of OEP has delegated authority to take whatever steps are necessary to

ensure the protection of all environmental resources during construction and operation of

the Pipeline. This authority shall allow:

a. the modification of conditions of the Order;and

b. the design and implementation of any additional measures deemed necessary

(including stop-work authority)to assure continued compliance with the intent of

the environmental conditions as well as the avoidance of mitigation of adverse

environmental impact resulting from the Project construction and operation.

4. Prior to anyconstruction,Cheniere shall file affirmative statements with the Secretary,

certified by senior company officials, that all company personnel, EI’s, and contractor

personnel will be informed of the EI’s authority and have been or will be trained on the

implementation of the environmental mitigation measures appropriate to their jobs before

becoming involved with construction and restoration activities.

5. The authorized facility locations shall be as depicted in the EIS, as supplemented by filed

alignment sheets. As soon as theyare available and before the start of construction,

Cheniere shall file with the Secretary any revised detailed survey alignment maps/sheets

at a scale not smaller than 1:6,000 with station positions for all facilities approved by the

Order. All requests for modifications of environmental conditions of the Order or sitespecific clearances must be written and must reference locations designated on these

alignment maps/sheets.

Cheniere’s exercise of eminent domain authority granted under NGA Section 7(h)in any

condemnation proceedings related to the Order must be consistent with these authorized

facilities and locations. Cheniere’s right of eminent domain granted under NGA Section

7(h)does not authorize it to increase the size of its natural gas pipeline to accommodate

future needs or to acquire a right-of-way for a pipeline to transport a commodity other

than natural gas.

6. Cheniere shall file detailed alignment maps/sheets and aerial photographs at a scale not

smaller than 1:6,000 identifying all route realignments or facility relocations, and staging

areas, pipe storage yards, new access roads, and other areas that would be used or

disturbed and have not been previously identified in filings with the Secretary. Approval

for each of these areas must be explicitly requested in writing. For each area, the request

must include a description of the existing land use/cover type, documentation of

landowner approval, whether any cultural resources or federally listed threatened or
Environmental Impact Statement 5-12 Corpus Christi LNG

-15

endangered species would be affected, and whether any other environmentally sensitive

areas are within or abutting the area. All areas shall be clearly identified on the

maps/sheets/aerial photographs. Each area must be approved in writing by the Director

of OEP before construction in or near that area.

This requirement does not apply to extra workspaces allowed by FERC’s Plan or minor

field realignments per landowner needs and requirements that do not affect other

landowners or sensitive environmental areas such as wetlands.

Examples of alterations requiring approval include all route realignments and facility

location changes resulting from:

a. implementation of cultural resources mitigation measures;

b. implementation of endangered, threatened, or special concern species mitigation

measures;

c. recommendations by state regulatory authorities;and

d. agreements with individual landowners that affect other landowners or could

affect sensitive environmental areas.

7. Within 60 days of the acceptance of the Authorization and before construction

begins, Cheniere shall file a single Implementation Plan for the review and written

approval by the Director of OEP. Cheniere must file revisions to their plan as schedules

change. The plan shall identify:

a. how Cheniere will implement the construction procedures and mitigation

measures described in its respective application and supplements (including

responses to staff data requests), identified in the EIS, and required by the Order;

b. how Cheniere will incorporate these requirements into the contract bid

documents, construction contracts (especially penalty clauses and specifications),

and construction drawings so that the mitigation required at each site is clear to

onsite construction and inspection personnel;

c. the number of EIs assigned per spread and aboveground facility sites, and how the

company will ensure that sufficient personnel are available to implement the

environmental mitigation;

d. company personnel, including EIs and contractors, who will receive copies of the

appropriate materials;

e. the location and dates of the environmental compliance training and instructions

Cheniere will give to all personnel involved with construction and restoration

(initial and refresher training as the Project progresses and personnel change),

with the opportunity for OEP staff to participate in the training session(s);

f. the company personnel (if known)and specific portion of Cheniere’s organization

having responsibility for compliance;

g. the procedures (including use of contract penalties)Cheniere will follow if

noncompliance occurs;and
Environmental Impact Statement 5-13 Corpus Christi LNG

-17

h. for each discrete facility, a Gantt or PERT chart (or similar Project scheduling

diagram), and dates for:

1. the completion of all required surveys and reports;

2. the environmental compliance training of onsite personnel;

3. the start of construction;and

4. the start and completion of restoration.

8. Cheniere shall employ at least one EI for the Terminal and at least one EI per

construction spread for the Pipeline. Each EI shall be:

a. responsible for monitoring and ensuring compliance with all mitigation measures

required by the Order and other grants, permits, certificates, or authorizing

documents;

b. responsible for evaluating the construction contractor’s implementation of the

environmental mitigation measures required in the contract (see condition 7

above)and any other authorizing document;

c. empowered to order correction of acts that violate the environmental conditions of

the Order, and any other authorizing document;

d. a full-time position separate from all other activity inspectors;

e. responsible for documenting compliance with the environmental conditions of the

Order, as well as any environmental conditions/permit requirements imposed by

other federal, state, or local agencies;and

f. responsible for maintaining status reports.

9. Beginning with the filing of its Implementation Plan, Cheniere shall file updated

status reports on a monthlybasis for the Terminal and on a weeklybasis for the Pipeline

until all construction and restoration activities are complete. On request, these status

reports will also be provided to other federal and state agencies with permitting

responsibilities. Status reports shall include:

a. an update on Cheniere’s efforts to obtain the necessary federal authorizations;

b. the construction status at the Terminal site and of each spread of the Pipeline,

work planned for the following reporting period, and any schedule changes for

stream crossings or work in other environmentally sensitive areas;

c. a listing of all problems encountered and each instance of noncompliance

observed by each EI during the reporting period (both for the conditions imposed

by the Commission and any environmental conditions/permit requirements

imposed by other federal, state, or local agencies);

d. a description of the corrective actions implemented in response to all instances of

noncompliance, and their cost;

e. the effectiveness of all corrective actions implemented;
Environmental Impact Statement 5-14 Corpus Christi LNG

-18

f. a description of any landowner/resident complaints which may relate to

compliance with the requirements of the Order, and the measures taken to satisfy

their concerns;and

g. copies of any correspondence received by Cheniere from other federal, state or

local permitting agencies concerning instances of noncompliance, and Cheniere’s

response.

10. Prior to receiving written authorization from the Director of OEP to commence

construction of any Project facilities, Cheniere shall file with the Secretary

documentation that each has received all applicable authorizations required under federal

law (or evidence of waiver thereof).

11. Cheniere must receive written authorization from the Director of OEP prior to

introducing hazardous fluids into the Terminal facilities. Instrumentation and

controls, hazard detection, hazard control, and security components/systems necessary for

the safe introduction of such fluids shall be installed and functional.

12. Cheniere must receive written authorization from the Director of OEP before placing the

Terminal facilities into service. Such authorization will only be granted following a

determination that the facilities have been constructed in accordance with FERC approval

and applicable standards, can be expected to operate safely as designed, and the

rehabilitation and restoration of the areas affected by the Terminal are proceeding

satisfactorily.

13. Cheniere must receive written authorization from the Director of OEP before placing the

Pipeline into service. Such authorization will only be granted following a determination

that rehabilitation and restoration of the right-of-way and other areas affected by the

Pipeline are proceeding satisfactorily.

14. Within 30 days of placing the Authorized facilities in service, Cheniere shall file an

affirmative statement with the Secretary, certified by a senior company official:

a. that the facilities have been constructed in compliance with all applicable

conditions, and that continuing activities will be consistent with all applicable

conditions;or

b. identifying which of the authorization conditions Cheniere has complied with or

will comply with. This statement shall also identify any areas affected by the

Project where compliance measures were not properly implemented, if not

previously identified in filed status reports, and the reason for noncompliance.

15. Prior to construction of the Pipeline, Cheniere shall update table 2.3-3 of the draft

EIS to identify the existing utilities/road locations and the milepost ranges of where its

construction right-of-way would overlap or collocate other utility/road rights-of-way;

and revise its final alignment sheets to reflect the actual right-of-way configurations

and workspace needs at these locations. (section 2.3.2)
Environmental Impact Statement 5-15 Corpus Christi LNG

16. Cheniere shall file the following information, stamped and sealed by the professional

engineer-of-record, with the Secretary:

a. site preparation drawings and specifications;

b. LNG tank and foundation design drawings and calculations based on the seismic

design ground motions in Cheniere’s Resource Report 13, Appendix I (URS

Report – Seismic and Tsunami Evaluation for the LNG Export Facility dated

August 7, 2012)and settlement analyses indicated in the TWEI response to

question 4f provided in the Supplemental Responses filed by Cheniere on

September 23, 2013;

c. LNG liquefaction facility structures and foundation design drawings and

calculations;and

d. quality control procedures to be used for civil/structural design and construction.

(section 4.1.1.4)

In addition, Cheniere shall file, in its Implementation Plan, the schedule for producing

this information.

17. Prior to construction, Cheniere shall file the ARMP developed in consultation with the

COE. The plan shall include:

a. details regarding the amount, location, and types of mitigation proposed;and

b. specific performance standards to measure the success of the mitigation;and

remedial measures, as necessary, to ensure that mitigation is successful.

(section 4.4.1)

18. Prior to construction,Cheniere shall file documentation of concurrence from the RRC

that the Project is consistent with the Texas CZMP. (section 4.8.1.5)

19. Cheniere shall not begin construction or use of any staging, storage, and temporary

work areas, and new or to-be-improved roads, until:

a. Cheniere files with the Secretary:

1. any additional inventory reports, including documentation of survey of the

proposed pipeline route between approximate MP 0.0 and 0.5;

2. any required evaluation reports and any necessary treatment plans;and

3. comments on the reports and plans from the Texas SHPO.

b. the ACHP is afforded an opportunity to comment if any historic properties would

be adversely affected;and

c. the FERC staff reviews, and the Director of OEP approves, all cultural resource

reports, documentation, and plans and notifies Cheniere in writing that it may

proceed with treatment or construction. (section 4.10.4)

All materials filed with the Commission containing location, character, and

ownership information regarding cultural resources must have the cover and any
Environmental Impact Statement 5-16 Corpus Christi LNG

relevant pages therein clearlylabeled in bold lettering: “CONTAINSPRIVILEGED

INFORMATION -DO NOT RELEASE.”

20. Prior to construction,Cheniere shall file a revised FDCP with the Secretary for review

and written approval from the Director of OEP. The revised FDCP shall include the

following:

a. the use of gravel at construction entrance and exit locations;and

b. measures to clean paved roads upon mud or dirt track out. (section 4.l1.1.4)

21. Cheniere shall file a noise survey with the Secretary no later than 60 days after placing

each liquefaction train and the entire Terminal in service. If a full load condition noise

survey is not possible, Cheniere shall provide an interim survey at the maximum possible

load and provide the full load survey within six months. If the noise attributable to the

operation of all of the equipment for a liquefaction train or at the Terminal, under interim

or full load conditions, exceeds an Ldn of 55 dBA at any nearby NSAs, Cheniere shall file

a report on what changes are needed and shall install the additional noise controls to meet

the level within one year of the in-service date. Cheniere shall confirm compliance with

the above requirement by filing a second noise survey with the Secretary no later than

60 days after it installs the additional noise controls. (section 4.11.2.3)

22. Cheniere shall file noise surveys with the Secretary no later than 60 days after placing

the Sinton and Taft Compressor Stations in service. If a full load condition noise survey

is not possible, Cheniere shall provide an interim survey at the maximum possible

horsepower load and provide the full load survey within six months. If the noise

attributable to the operation of all of the equipment at the Sinton or Taft Compressor

Station, under interim or full horsepower load conditions, exceeds an Ldn of 55 dBA at

any nearby NSAs, Cheniere shall file a report on what changes are needed and shall

install the additional noise controls to meet the level within one year of the in-service

date. Cheniere shall confirm compliance with the above requirement by filing a second

noise survey with the Secretary no later than 60 days after it installs the additional noise

controls. (section 4.11.2.3)

23. Prior to the end of the draft environmental impact statement comment period,

Cheniere shall file with the Secretary for review and written approval by the Director of

OEP, clarification if a 10-foot vapor fence would be provided to mitigate vapor

dispersion from releases when the ambient air vaporizers are operational.

(section 4.12.5)

Recommendations 24 through 104 shall apply to the Cheniere Terminal. Information pertaining

to the specific recommendations shall be filed with the Secretary for review and written approval

by the Director of OEP either: prior to initial site preparation;prior to construction of final

design;prior to commissioning;prior to introduction of hazardous fluids;or prior to

commencement of service, as indicated by each specific condition. Specific engineering,

vulnerability, or detailed design information meeting the criteria specified in Order No. 683

(Docket No. RM06-24-000), including security information, shall be submitted as critical energy

infrastructure information pursuant to 18 CFR 388.112. See Critical Energy Infrastructure

Information, Order No. 683, 71 Fed. Reg. 58,273 (October 3, 2006), FERC Stats. & Regs.
Environmental Impact Statement 5-17 Corpus Christi LNG

31,228 (2006). Information pertaining to items such as: offsite emergency response;procedures

for public notification and evacuation;and construction and operating reporting requirements,

would be subject to public disclosure. All information shall be filed a minimum of 30 days

before approval to proceed is requested. (section 4.12.3)

24. Prior to initial site preparation, Cheniere shall provide quality assurance and quality

control procedures for construction activities. (section 4.12.3)

25. Prior to initial site preparation, Cheniere shall file an overall project schedule, which

includes the proposed stages of the commissioning plan. (section 4.12.3)

26. Prior to initial site preparation, Cheniere shall provide procedures for controlling

access during construction. (section 4.12.3)

27. Prior to initial site preparation, Cheniere shall provide a plot plan of the final design

showing all major equipment, structures, buildings, and impoundment systems.

(section 4.12.3)

28. Prior to initial site preparation, Cheniere shall file a complete specification of the

proposed LNG tank design and installation. (section 4.12.3)

29. Prior to initial site preparation, Cheniere shall file drawings of the storage tank piping

support structure and support of horizontal piping at grade including pump columns,

relief valves, pipe penetrations, instrumentation, and appurtenances. (section 4.12.3)

30. Prior to initial site preparation, Cheniere shall develop an ERP (including evacuation)

and coordinate procedures with the Coast Guard;state, county, and local emergency

planning groups;fire departments;state and local law enforcement;and appropriate

federal agencies. This plan shall include at a minimum:

a. designated contacts with state and local emergency response agencies;

b. scalable procedures for the prompt notification of appropriate local

officials and emergency response agencies based on the level and severity

of potential incidents;

c. procedures for notifying residents and recreational users within areas of

potential hazard;

d. evacuation routes/methods for residents and public use areas that are

within any transient hazard areas along the route of the LNG marine

transit;

e. locations of permanent sirens and other warning devices;and

f. an “emergency coordinator”on each LNG carrier to activate sirens and

other warning devices.

Cheniere shall notify the FERC staff of all planning meetings in advance and shall

report progress on the development of its ERP at 3-month intervals.

(section 4.12.7)

31. Prior to initial site preparation, Cheniere shall file a Cost-Sharing Plan identifying the

mechanisms for funding all Project-specific security/emergency management costs that
Environmental Impact Statement 5-18 Corpus Christi LNG

would be imposed on state and local agencies. In addition to the funding of direct transitrelated security/emergency management costs, this comprehensive plan shall include

funding mechanisms for the capital costs associated with any necessary

security/emergency management equipment and personnel base. (section 4.12.7)

32. The final design shall include change logs that list and explain any changes made from

the FEED provided in Cheniere’s application and filings. A list of all changes with an

explanation for the design alteration shall be provided and all changes shall be clearly

indicated on all diagrams and drawings. (section 4.12.3)

33. The final design shall provide information/revisions pertaining to Cheniere’s responses,

as listed in Table 4.12.3-1 of the EIS, which indicated features to be included in the final

design and documentation. (section 4.12.3)

34. The final design shall provide an up-to-date equipment list, process and mechanical data

sheets, and specifications. (section 4.12.3)

35. The final design shall include three-dimensional plant drawings to confirm plant layout

for maintenance, access, egress, and congestion. (section 4.12.3)

36. The final design shall include up-to-date PFDs and P&IDs. The PFDs shall include heat

and material balances. The P&IDs shall include the following information:

a. equipment tag number, name, size, duty, capacity, and design conditions;

b. equipment insulation type and thickness;

c. storage tank pipe penetration size or nozzle schedule;

d. piping with line number, piping class specification, size, and insulation

type and thickness;

e. piping specification breaks and insulation limits;

f. all control and manual valves numbered;

g. valve high pressure sides and cryogenic ball valve external and internal

vent locations;

h. relief valves with set points;and

i. drawing revision number and date. (section 4.12.3)

37. The final design shall include a list of all car-sealed and locked valves consistent with

the P&IDs. (section 4.12.3)

38. The final design shall include a hazard and operability review prior to issuing the P&IDs

for construction. A copy of the review, a list of the recommendations, and actions

taken on the recommendations shall be filed. (section 4.12.3)

39. The final design shall include spill containment system drawings with dimensions and

slopes of curbing, trenches, and impoundments. (section 4.12.3)

40. The final design shall provide electrical area classification drawings. (section 4.12.3)
Environmental Impact Statement 5-19 Corpus Christi LNG

41. The final design shall include details of how process seals or isolations installed at the

interface between a flammable fluid system and an electrical conduit or wiring system

meet the requirements of NFPA 59A. (section 4.12.3)

42. The final design shall provide an air gap or vent installed downstream of process seals or

isolations installed at the interface between a flammable fluid system and an electrical

conduit or wiring system. Each air gap shall vent to a safe location and be equipped with

a leak detection device that: shall continuously monitor for the presence of a flammable

fluid;shall alarm the hazardous condition;and shall shutdown the appropriate systems.

(section 4.12.3)

43. The final design shall include layout and design specifications of the pig trap, inlet

separation and liquid disposal, inlet/send-out meter station, and pressure control.

(section 4.12.3)

44. The final design shall specify fire protection systems, uninterruptable power supply,

emergency power generators, emergency lighting, radio communications system, control

valves, instrumentation, and shutdown systems as Seismic Category 1. (section 4.12.3)

45. The final design shall specify that for hazardous fluids, piping and piping nipples 2

inches or less in diameter are to be no less than schedule 160. (section 4.12.3)

46. The final design shall include a plan for clean-out, dry-out, purging, and tightness

testing. This plan shall address the requirements of the American Gas Association’s

Purging Principles and Practice required by 49CFR 193 and shall provide justification if

not using an inert or non-flammable gas for cleanout, dry-out, purging, and tightness

testing. (section 4.12.3)

47. The final design shall specify that piping and equipment that may be cooled with liquid

nitrogen is to be designed for liquid nitrogen temperatures, with regard to allowable

movement and stresses. (section 4.12.3)

48. The final design shall include operating procedures specifying that the Heavies Removal

Column (HRC)and the HRC Reboiler would be drained prior to restarting the equipment

when cryogenic temperatures exist in the HRC or in the HRC Reboiler. (section 4.12.3)

49. The final design shall include LNG tank fill flow measurement with high flow alarm.

(section 4.12.3)

50. The final design shall include BOG flow and temperature measurement for each tank.

(section 4.12.3)

51. The final design shall include an analysis of the structural integrity of the outer

containment of the full containment storage tanks when exposed to a roof tank top fire or

adjacent tank top fire. (section 4.12.3)

52. The final design shall include the details of the LNG storage tank structural design that

demonstrates the tanks can withstand overpressures from ignition of design spills.

(section 4.12.5)
Environmental Impact Statement 5-20 Corpus Christi LNG

53. The final design shall specify that the minimum flow recycle line from the high pressure

LNG pumps to downstream of the isolation valve to the BOG Recondenser shall be the

same pressure and temperature rating as the piping at the discharge of the LNG Send-out

pumps. (section 4.12.3)

54. The final design shall specify that a check valve is provided in the LNG send-out pump

minimum flow recycle piping. (section 4.12.3)

55. The final design shall specify discharge valving to allow the pumps to be recirculated

without flowing LNG to the vaporizer control valve during initial startup and provide a

cooldown bypass valve to pressurize and cool the vaporizer inlet piping. (section 4.12.3)

56. The final design of the LNG vaporization system shall specify that a check valve, vent

valve, and manual isolation valve are to be provided downstream of the outlet shut-off

valve 00XV-56015. (section 4.12.3)

57. The final design shall specify that the LNG loading arms are equipped with a manual

isolation valve at the base of each arm. (section 4.12.3)

58. The final design shall specify the minimum distance required for valve maintenance,

between the LNG loading header and the first valve in the discharge piping to the loading

arm. (section 4.12.3)

59. The final design shall specify that all drains from high pressure hazardous fluid systems

are to be equipped with double isolation and bleed valves. (section 4.12.3)

60. The final design shall specify that the C5+ Condensate Storage Tank fill connection is

located above the maximum liquid level. (section 4.12.3)

61. The final design of the wet gas flare shall include a drain or shall justify why a drain is

not included. (section 4.12.3)

62. The final design shall provide the procedures for pressure/leak tests which address the

requirements of ASME VIII and ASME B31.3, as required by 49 CFR 193.

(section 4.12.3)

63. The final design shall include the sizing basis and capacity for the final design of

pressure and vacuum relief valves for major process equipment, vessels, storage tanks,

and vent stacks. (section 4.12.3)

64. The final design shall specify that a pressure relief valve is to be provided on the

upstream side of the vaporizer outlet shutoff valve. The valve shall be sized in

accordance with the requirements of NFPA 59A (2001 ed.)Section 5.4.1. (section 4.12.3)

65. The final design of the LNG vaporization system shall include a relief valve or operated

vent valve sized for thermal relief at the discharge of each vaporizer, upstream of the

isolation valves. This relief valve is in addition to the relief valve specified in NFPA 59A

(2001 ed.)Section 5.4.1 and shall be set at a lower pressure. (section 4.12.3)
Environmental Impact Statement 5-21 Corpus Christi LNG

66. The final design shall specify that ethylene storage vessels be equipped with redundant

full capacity relief valves. (section 4.12.3)

67. The final design shall specify that propane storage vessels be equipped with redundant

full capacity relief valves. (section 4.12.3)

68. The final design shall specify that LNG relief valves and LNG drains shall not discharge

into the vapor system. (section 4.12.3)

69. The final design shall include pressure relieving protection for flammable liquid piping

(i.e., condensate products)which can be isolated by valves. (section 4.12.3)

70. The final design shall specify that LNG from relief valves and drains is to be returned to

storage. (section 4.12.3)

71. The final design shall specify that all ESD valves are to be equipped with open and

closed position switches connected to the DCS/SIS. (section 4.12.3)

72. The final design shall include complete plan drawings of the security fencing and of

facility access and egress. (section 4.12.3)

73. The final design shall include the cause-and-effect matrices for the process

instrumentation, fire and gas detection system, and emergency shutdown system. The

cause-and-effect matrices shall include alarms and shutdown functions, details of the

voting and shutdown logic, and setpoints. (section 4.12.3)

74. The final design shall include a plant-wide ESD button with proper sequencing.

(section 4.12.3)

75. The final design shall include automatic shutoff valves at the inlet of the boil-off

compressors. (section 4.12.3)

76. The final design shall specify that the truck fill line be equipped with an automatic

shutoff valve. (section 4.12.3)

77. The final design shall include an updated fire protection evaluation of the proposed

facilities carried out in accordance with the requirements of NFPA 59A 2001,

chapter 9.1.2 as required by 49 CFR 193. A copy of the evaluation, a list of

recommendations and supporting justifications, and actions taken on the

recommendations shall be filed. (section 4.12.3)

78. The final design of the hazard detectors shall account for the calibration gas when

determining the LFL set points for methane, propane, and ethylene, and condensate.

(section 4.12.3)

79. The final design shall include complete plan drawings and a list of the hazard detection

equipment. Plan drawings shall clearly show the location and elevation of all detection

equipment. The list shall include the instrument tag number, type and location, alarm

indication locations, and shutdown functions of the proposed hazard detection equipment.

(section 4.12.3)
Environmental Impact Statement 5-22 Corpus Christi LNG

80. The final design shall provide a technical review of its proposed facility design

that:

a. identifies all combustion/ventilation air intake equipment and the distances to any

possible hazardous fluid release (LNG, flammable refrigerants, flammable liquids

and flammable gases);and

b. demonstrates that these areas are adequately covered by hazard detection devices

and indicates how these devices would isolate or shutdown any combustion

equipment whose continued operation could add to or sustain an emergency.

(section 4.12.3)

81. The final design shall include smoke detection in occupied buildings. (section 4.12.3)

82. The final design shall include hazard detection suitable to detect high temperatures and

smoldering combustion in electrical buildings and control room buildings.

(section 4.12.3)

83. The final design shall include emergency shutdown of equipment and systems activated

by hazard detection devices for flammable gas, fire, and cryogenic spills, when

applicable. (section 4.12.3)

84. The final design shall include clean agent systems in the electrical switchgear and

instrumentation buildings. (section 4.12.3)

85. The final design shall provide complete plan drawings and a list of the fixed and wheeled

dry-chemical, hand-held fire extinguishers, and other hazard control equipment.

Drawings shall clearly show the location by tag number of all fixed, wheeled, and handheld extinguishers. The list shall include the equipment tag number, type, capacity,

equipment covered, discharge rate, and automatic and manual remote signals initiating

discharge of the units. (section 4.12.3)

86. The final design shall include facility plans and drawings showing the proposed location

of the firewater and any foam systems. Plan drawings shall clearly show the planned

location of firewater and foam piping, post indicator valves, and the location and area

covered by, each monitor, hydrant, hose, water curtain, deluge system, foam generator,

and sprinkler. The drawings shall also include piping and instrumentation diagrams of

the firewater and foam systems. (section 4.12.3)

87. The final design shall specify that the firewater pump shelter is designed with a

removable roof for maintenance access to the firewater pumps. (section 4.12.3)

88. The final design shall specify that the firewater flow test meter is equipped with a

transmitter and that a pressure transmitter is installed upstream of the flow transmitter.

The flow transmitter and pressure transmitter shall be connected to the DCS and

recorded. The firewater main header pressure transmitter, 00PT-33091, shall also be

connected to the DCS and recorded. (section 4.12.3)

89. The final design shall include certification that the final design is consistent with the

information provided to DOT as described in the design spill determination letter dated
Environmental Impact Statement 5-23 Corpus Christi LNG

February 10, 2014 (Accession Number 20140210-4008). In the event that any

modifications to the design alters the candidate design spills on which the Title 49CFR

Part 193 siting analysis was based, Cheniere shall consult with DOT on any actions

necessary to comply with Part 193. (section 4.12.5)

90. The final design shall include the details of the vapor fences as well as procedures to

maintain and inspect the vapor barriers provided to meet the siting provisions of 49CFR

§193.2059. (section 4.12.5)

91. Prior to commissioning, Cheniere shall file plans and detailed procedures for: testing the

integrity of onsite mechanical installation;functional tests;introduction of hazardous

fluids;operational tests;and placing the equipment into service. (section 4.12.3)

92. Prior to commissioning, Cheniere shall provide a detailed schedule for commissioning

through equipment startup. The schedule shall include milestones for all procedures and

tests to be completed: prior to introduction of hazardous fluids; and during

commissioning and startup. Cheniere shall file documentation certifying that each of

these milestones has been completed before authorization to commence the next phase of

commissioning and startup will be issued. (section 4.12.3)

93. Prior to commissioning, Cheniere shall tag all instrumentation and valves in the field,

including drain valves, vent valves, main valves, and car-sealed or locked valves.

(section 4.12.3)

94. Prior to commissioning, Cheniere shall label equipment with equipment tag number and

piping with fluid service and direction of flow in the field in addition to the pipe labeling

requirements of NFPA 59A. (section 4.12.3)

95. Prior to commissioning, Cheniere shall file Operation and Maintenance procedures and

manuals, including safety procedures, hot work procedures and permits, abnormal

operating conditions reporting procedures, and management of change procedures and

forms. (section 4.12.3)

96. Prior to commissioning, Cheniere shall maintain a detailed training log to demonstrate

that operating staff has completed the required training. (section 4.12.3)

97. Prior to commissioning, Cheniere shall file a tabulated list and drawings of the proposed

hand-held fire extinguishers. The list shall include the equipment tag number,

extinguishing agent type, capacity, number, and location. The drawings shall show the

extinguishing agent type, capacity, and tag number of all hand-held fire extinguishers.

(section 4.12.3)

98. Prior to commissioning, Cheniere shall file results of the LNG storage tank hydrostatic

test and foundation settlement results. (section 4.12.3)

99. Prior to introduction of hazardous fluids, Cheniere shall complete all pertinent tests

(Factory Acceptance Tests, Site Acceptance Tests, Site Integration Tests)associated with

the DCS and SIS that demonstrates full functionality and operability of the system.

(section 4.12.3)
Environmental Impact Statement 5-24 Corpus Christi LNG

100. Prior to introduction of hazardous fluids, Cheniere shall complete a firewater pump

acceptance test and firewater monitor and hydrant coverage test. The actual coverage area

from each monitor and hydrant shall be shown on facility plot plan(s). (section 4.12.3)

101. Prior to commencement of service, Cheniere shall develop procedures for offsite

contractors’responsibilities, restrictions, and limitations and for supervision of these

contractors by Cheniere staff. (section 4.12.3)

102. Prior to commencement of service, Cheniere shall notify FERC staff of any proposed

revisions to the security plan and physical security of the facility. (section 4.12.3)

103. Prior to commencement of service, Cheniere shall file progress on construction of the

Terminal in monthlyreports. Details shall include a summary of activities, problems

encountered, contractor non-conformance/ deficiency logs, remedial actions taken, and

current project schedule. Problems of significant magnitude shall be reported to the

FERC within 24 hours. (section 4.12.3)

104. Prior to commencement of service, Cheniere shall receive written authorization from

the Director of OEP. Such authorization would only be granted following a

determination by the Coast Guard, under its authorities under the Ports and Waterways

Safety Act, the Magnuson Act, the MTSA, and the Safety and Accountability For Every

Port Act, that appropriate measures to ensure the safety and security of the facility and

the waterway have been put into place by Cheniere or other appropriate parties. (section

4.12.6)

In addition, recommendations 105 through 108 shall apply throughout the life of the

facility:

105. The facility shall be subject to regular FERC staff technical reviews and site inspections

on at least an annual basis or more frequently as circumstances indicate. Prior to each

FERC staff technical review and site inspection, Cheniere shall respond to a specific data

request including information relating to possible design and operating conditions that

may have been imposed by other agencies or organizations. Up-to-date detailed piping

and instrumentation diagrams reflecting facility modifications and provision of other

pertinent information not included in the semi-annual reports described below, including

facility events that have taken place since the previously submitted annual report, shall be

submitted. (section 4.12.3)

106. Semi-annual operational reports shall be filed with the Secretary to identify changes in

facility design and operating conditions, abnormal operating experiences, activities

(including ship arrivals/departures, quantity and composition of imported and exported

LNG, liquefied and vaporized quantities, boil-off/flash gas, etc.), and plant modifications

including future plans and progress thereof. Abnormalities shall include, but not be

limited to: unloading/loading shipping problems, potential hazardous conditions caused

by off-site vessels, storage tank stratification or rollover, geysering, storage tank pressure

excursions, cold spots on the storage tanks, storage tank vibrations and/or vibrations in

associated cryogenic piping, storage tank settlement, significant equipment or

instrumentation malfunctions or failures, nonscheduled maintenance or repair (and
Environmental Impact Statement 5-25 Corpus Christi LNG

reasons therefore), relative movement of storage tank inner vessels, hazardous fluids

releases, fires involving natural gas and/or from other sources, negative pressure

(vacuum)within a storage tank and higher than predicted boil-off rates. Adverse weather

conditions and the effect on the facility shall also be reported. Reports shall be submitted

within 45days after each period ending June 30 and December 31. In addition to the

above items, a section entitled "Significant Plant Modifications Proposed for the Next 12

Months (dates)" shall also be included in the semiannual operational reports. Such

information would provide the FERC staff with early notice of anticipated future

construction/maintenance projects at the LNG facility. (section 4.12.3)

107. In the event the temperature of any region of any secondary containment, including

imbedded pipe supports, becomes less than the minimum specified operating temperature

for the material, the Commission shall be notified within 24 hours and procedures for

corrective action shall be specified. (section 4.12.3)

108. Significant non-scheduled events, including safety-related incidents (e.g., hazardous fluid

releases, fires, explosions, mechanical failures, unusual over pressurization, and major

injuries)and security related incidents (i.e., attempts to enter site, suspicious activities)

shall be reported to FERC staff. In the event an abnormality is of significant magnitude to

threaten public or employee safety, cause significant property damage, or interrupt

service, notification shall be made immediately, without unduly interfering with any

necessary or appropriate emergency repair, alarm, or other emergency procedure. In all

instances, notification shall be made to FERC staff within 24 hours. This notification

practice shall be incorporated into the LNG facility's emergency plan. Examples of

reportable hazardous fluids related incidents include:

a. fire;

b. explosion;

c. estimated property damage of $50,000 or more;

d. death or personal injury necessitating in-patient hospitalization;

e. release of hazardous fluid for five minutes or more;

f. unintended movement or abnormal loading by environmental causes, such

as an earthquake, landslide, or flood, that impairs the serviceability,

structural integrity, or reliability of an LNG facility that contains, controls,

or processes hazardous fluids;

g. any crack or other material defect that impairs the structural integrity or

reliability of an facility that contains, controls, or processes a hazardous

fluid;

h. any malfunction or operating error that causes the pressure of a pipeline or

facility that contains or processes a hazardous fluid to rise above its

maximum allowable operating pressure (or working pressure for LNG

facilities)plus the build-up allowed for operation of pressure limiting or

control devices;

i. a leak in a facility that contains or processes a hazardous fluid that

constitutes an emergency;
Environmental Impact Statement 5-26 Corpus Christi LNG

j. inner tank leakage, ineffective insulation, or frost heave that impairs the

structural integrity of an LNG storage tank;

k. any safety-related condition that could lead to an imminent hazard and

cause (either directly or indirectly by remedial action of the operator), for

purposes other than abandonment, a 20 percent reduction in operation of a

pipeline or a facility that contains or processes a hazardous fluid;

l. safety-related incidents to hazardous material transportation occurring at

or en route to and from the LNG facility;or

m. an event that is significant in the judgment of the operator and/or

management even though it did not meet the above criteria or the

guidelines set forth in an LNG facility’s incident management plan.

In the event of an incident, the Director of OEP has delegated authority to take whatever

steps are necessary to ensure operational reliability and to protect human life, health,

property or the environment, including authority to direct the LNG facility to cease

operations. Following the initial company notification, FERC staff would determine the

need for a separate follow-up report or follow-up in the upcoming semi-annual

operational report. All company follow-up reports shall include investigations results and

recommendations to minimize a reoccurrence of the incident. (section 4.12.3)
Appendix A

ALIGNMENT SHEETS

/ OO=H?

-$0&.# 1.)/*% *' %' ,.$+ ) -$

A-1
?H=OO /

-$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$-

A-2
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A-3
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A-4
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A-5
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A-6
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A-7
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A-8
?H=OO /

-$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$-

A-9
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-$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- -$) +$.,'%'* %*/).1# .&0$- 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A-10
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A-22
Appendix B

ESSENTIAL FISH HABITAT 

ASSESSMENT

APPENDIX B

ESSENTIAL FISH HABITAT ASSESSMENT

1.0 INTRODUCTION

In 1976, the Magnuson-Stevens Act (MSA) was passed in order to promote fish 

conservation and management. The MSA granted the National Oceanic and Atmospheric 

Administration, National Marine Fisheries Service (NOAA Fisheries) legislative authority for 

fisheries regulation in the United States within a jurisdictional area located between 3 miles to 

200 miles offshore, depending on geographical location. NOAA Fisheries established eight 

regional fishery management councils, each responsible for the proper management and harvest 

of finfish and shellfish resources within their respective geographic regions. These fishery 

management councils have developed Fisheries Management Plans (FMP), which outline 

measures to ensure the proper management and harvest of the finfish and shellfish within these 

waters.

Recognizing that many marine fisheries are dependent on nearshore and estuarine 

environments for at least part of their life cycles, new habitat conservation provisions to the 

MSA (Public Law [PL] 94-265, as amended in 1996 and PL 104-297, as amended in 1998) were 

added, along with other goals, to promote more effective habitat management and protection of 

marine fisheries. The protection of the marine environments important to marine fisheries, 

referred to as essential fish habitat (EFH), is required in the review of projects conducted under 

federal permits, licenses, or other authorities that affect or have the potential to affect such 

habitat. EFH is defined as “those waters and substrate necessary to fish for spawning, breeding, 

feeding, or growth to maturity” (16 United States Code [U.S.C.] 1802(10)). 

Federal agencies that authorize, fund, or undertake activities that may adversely impact 

EFH must consult with the NOAA Fisheries. Although absolute criteria have not been 

established for conducting EFH consultations, NOAA Fisheries recommends consolidated EFH 

consultations with interagency coordination procedures required by other statutes such as the 

National Environmental Policy Act (NEPA) and Endangered Species Act (ESA), in order to 

reduce duplication and improve efficiency. Generally, the EFH consultation process includes the 

following steps:

1) Notification – The action agency should clearly state the process being used for EFH 

consultations (e.g., incorporating EFH consultation into the Environmental Impact 

Statement (EIS) or Rivers and Harbors Act Section 10 Permit).

2) EFH Assessment – The action agency should prepare an EFH Assessment that 

includes both identification of affected EFH and an assessment of impacts. 

Specifically, the EFH should include: 1) a description of the proposed action; 2) an 

analysis of the effects (including cumulative effects) of the proposed action on EFH, 

the managed fish species, and major prey species; 3) the federal agency’s views 

regarding the effects of the action on EFH; and 4) proposed mitigation, if applicable.

3) EFH Conservation Recommendations – After reviewing the EFH Assessment, 

NOAA Fisheries would provide recommendations to the action agency regarding 

measures that can be taken by that agency to conserve EFH. 

B-1
4) Agency Response – The action agency must respond to NOAA Fisheries within 30 

days of receiving NOAA Fisheries’ recommendations to conserve EFH. The action 

agency may notify NOAA Fisheries that a full response to conservation 

recommendations will be provided by a specified completion date agreeable to all 

parties. The response must include a description of measures proposed by the agency 

for avoiding, mitigating, or offsetting the impact activity on EFH. 

CONSULTATION PROCESS

Our1consultations with NOAA Fisheries regarding the potential impacts on EFH 

resulting from construction and operation of the proposed Corpus Christi LNG Project (Project) 

have been conducted in coordination with our NEPA review. 

EFH ASSESSMENT OVERVIEW

A description of the proposed action is provided in section 2.0 of the Project draft EIS. 

Our analysis of the effects, including cumulative effects, of the proposed action and associated 

mitigation on EFH, managed fish species, and major prey species, and our views regarding the 

effects of the proposed action on EFH are provided in the following sections.

Based on our review of the proposed Project, including LNG marine traffic through the 

La Quinta Channel, and in consultation with NOAA Fisheries, we have identified EFH for 

various life stages of 14 species (Table 1): juvenile white (Litopenaeus setiferus) and brown

(Farfantepenaeus aztecus) shrimp; larval, post-larval, juvenile, and adult red drum (Sciaenops 

ocellatus); adult gray snapper (Lutjanus griseus); post-larval and juvenile Goliath grouper 

(Epinephelus itajara); post-larval and juvenile lane snapper (Lutjanus synagris); juvenile 

yellowmouth grouper (Mycteroperca interstitialis); neonate, juvenile, and adult blacktip 

(Carcharhinus limbatus), bull (Carcharhinus leucas), Atlantic sharpnose (Rhizoprionodon 

terranovae), and bonnethead sharks (Sphyrna tiburo); neonate and juvenile scalloped 

hammerhead sharks (Sphyrna lewini) and lemon sharks (Negaprion brevirostris) within Corpus 

Christi Bay (NOAA Fisheries, 2014; Gulf of Mexico Fishery Management Council [GMFMC], 

2004). 

In addition to being designated as EFH for a variety of federally managed species, the 

Project area provides nursery, foraging, and refuge habitats that support various recreationally 

and economically important marine fishery species such as spotted sea trout, southern flounder, 

Atlantic croaker, black drum, Gulf menhaden, striped mullet, and blue crab. Such estuarinedependent species serve as prey for other fisheries managed by GMFMC and highly migratory 

species managed by NOAA Fisheries (NOAA Fisheries, 2013).

 

1

“We,” “us,” and “our” refer to the environmental staff of the FERC’s Office of Energy Projects.

B-2
Table 1.

EFH Present in Project Area

Nueces and San Patricio Counties, Texas

Species

Life Stage

Larval Post-larval Neonate Juveniles Adults

Invertebrates

Brown Shrimp

(Farfantepenaeus aztecus)

N/A a/ X

White Shrimp

(Litopenaeus setiferus)

N/A a/ X

Reef Fish/Snapper-Grouper

Red Drum

(Sciaenops ocellatus)

X X N/A a/ X X

Gray Snapper

(Lutjanus griseus)

N/A a/ X

Lane Snapper 

(Lutjanus sunagris)

X N/A a/ X

Goliath Grouper

(Epinephelus itajara)

X N/A a/ X

Yellowmouth Grouper

(Mycteroperca interstitialis)

N/A a/ X

Highly Migratory Species

Bull Shark

(Carcharhinus leucas)

N/A b/ N/A b/ X X X

Scalloped Hammerhead Shark

(Sphyrna lewini)

N/A b/ N/A b/ X X

Bonnethead Shark

(Sphyrna tiburo)

N/A b/ N/A b/ X X X

Blacktip Shark

(Carcharhinus limbatus)

N/A b/ N/A b/ X X X

Finetooth Shark

(Carcharhinus isodon)

N/A b/ N/A b/ X

Lemon Shark

(Negaprion brevirostris)

N/A b/ N/A b/ X X

Atlantic Sharpnose Shark

(Rhizoprionodon terraenovae)

N/A b/ N/A b/ X X X

Source: NOAA Fisheries, 2014; GMFMC, 2004

a/ Species does not have a neonate life stage

b/ Species does not have a larval or post larval life stage

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2.0 ESSENTIAL FISH HABITAT

All estuarine systems of the Gulf of Mexico (Gulf) are considered essential habitat for 

fish species managed by the GMFMC. In 2005 the GMFMC amended seven FMPs in 

accordance with Subpart J of 50 CFR Part 600. In 2004, the GMFMC completed a Final EIS for 

the Generic Essential Fish Habitat Amendment addressing all required EFH components 

included in the amendment to the MSA. The 2005 EFH Amendment delineated EFH as areas of 

higher species density, based on the NOAA Atlas and functional relationships analysis for the

following FMPs: Red Drum, Reef Fish, Coastal Migratory Pelagics, Shrimp, Stone Crab, and 

Spiny Lobster, and Coral. 

The FMPs managed by the GMFMC, include: all estuaries; the U.S. – Mexico border to 

the boundary between the areas covered by the GMFMC and the South Atlantic Fishery 

Management Council from estuarine waters out to depths of 100 fathoms. Additionally, sharks 

are managed through Amendment 1 to the Final Consolidated Highly Mobile Species FMP. 

EFH is characterized as occurring within three zones: estuarine (inside barrier islands and 

estuaries), nearshore (60 feet or less in depth), and offshore (greater than 60 feet in depth). The 

GMFMC defines 12 standard habitat types, based on a combination of substrate and biogenic 

structure descriptions, which are present with the Gulf. These 12 standard habitat types include: 

submerged aquatic vegetation (e.g., seagrasses, benthic algae), mangroves, drifting algae, 

emergent marshes (e.g., tidal wetlands, salt marshes, tidal creeks, rivers/streams), sand/shell 

bottoms, soft bottoms (e.g., mud, clay bottoms, silt), hard bottoms (e.g., live hard bottoms, lowrelief irregular bottoms, high-relief irregular bottoms), oyster reefs, banks/shoals, reefs (e.g., reef 

halos, patch reefs, deep reefs), shelf edge/slope, and pelagic (GMFMC, 2004). 

All impacts associated with the Project are located within the estuarine zone. Habitat 

types identified within the Project area include emergent marshes, submerged aquatic vegetation, 

mangroves, soft bottoms (unvegetated shallow water), and sand/shell bottoms (unvegetated 

shallow water). In addition to providing EFH, mangroves and vegetated wetlands also provide 

other essential estuarine support functions, including: providing a physically recognizable 

structure and substrate for refuge and attachment above and below the sediment surface, binding 

sediments, preventing erosion, collecting organic and inorganic material by slowing currents, and 

providing nutrients and detrital matter to the estuary. 

A detailed description of these habitats as well as the life history characteristics and 

habitat preferences of each federally managed species in the Project area is provided below and 

is based primarily on the research referenced in Cheniere’s application to FERC, both Cheniere’s 

and our consultation with NOAA Fisheries, and a review of the applicable FMPs, as amended. 

3.0 FEDERALLY MANAGED SPECIES WITH EFH IN CORPUS CHRISTI BAY

Corpus Christi Bay is characterized as estuarine and provides habitat to a variety of 

animal species across several taxa including, birds, reptiles, fish, macro invertebrates, and 

mammals. Habitat types present within Corpus Christi Bay include, but are not limited to, 

submerged aquatic vegetation, mangroves, emergent marshes, oyster reefs, sand/shell bottoms, 

and soft bottoms (Coastal Bend Bays and Estuaries Program, 2012).

The GMFMC final EIS for EFH for the Gulf FMPs (GFMFC, 2004) and the 

Consolidated Atlantic Highly Migratory Species FMP (NOAA Fisheries, 2010) provide detailed 

information on life history and relative abundance for species identified as having potential EFH 

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in the Project area. All species with EFH as identified by NOAA Fisheries are considered to be 

at least classified as “common” in the Project area (NOAA Fisheries, 2014). The habitat types 

utilized by each of the species for which EFH is present within the Project area are presented in 

Table 2 and further discussed below.

Table 2

EFH Present in Corpus Christi Bay 

Nueces and San Patricio Counties, Texas

Habitat Type Species Life Stage

Estuarine Emergent Marsh

Gray snapper Adult

Red drum Post larval, juvenile, adult

Brown shrimp Juvenile

White shrimp Juvenile

Estuarine Mangrove

Goliath grouper Post larval, juvenile

Lane snapper Juvenile

Yellowmouth snapper Juvenile

Estuarine Sand/Shell Bottom 

Brown shrimp Juvenile

Gray snapper Adult

Lane snapper Juvenile

Red drum Post larval, juvenile, adult

Estuarine Mud/Soft Bottom

Gray snapper Adult

Lane snapper Juvenile

Red drum Larval, juvenile, adult

Brown shrimp Juvenile

White shrimp Juvenile

Estuarine Submerged Aquatic Vegetation

Brown shrimp Juvenile

Goliath grouper Juvenile

Lane snapper Post larval, juvenile

Red drum Larval, post larval, juvenile, adult

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Table 2

EFH Present in Corpus Christi Bay 

Nueces and San Patricio Counties, Texas

Habitat Type Species Life Stage

Estuarine a/

Bull shark Neonate, juvenile, adult

Scalloped hammerhead shark Neonate, juvenile

Bonnethead shark Neonate, juvenile, adult

Blacktip shark Neonate, juvenile, adult

Finetooth shark Neonate

Lemon shark Neonate, juvenile

Atlantic sharpnose shark Neonate, juvenile, adult

Source: NOAA Fisheries, 2014; GMFMC, 2004

a/ Information regarding specific estuarine habitats utilized by highly migratory species (sharks) is not 

available; therefore, the habitat type is not further refined.

Shrimp Fishery of the Gulf of Mexico

Shrimp species within the Gulf use a variety of habitats as they grow from planktonic 

larvae to spawning adults. Habitat throughout all life stages range from estuarine to open ocean. 

Larvae are primarily found in the open ocean. As larvae progress into the post larval life stage, 

they begin to move into the benthic estuarine habitats. Adult habitat use varies between species 

and season but typically ranges from nearshore to offshore (GMFMC, 1981). Specific life 

history and habitat use descriptions for species with EFH in the Project area are provided below.

White Shrimp (Litopenaeus setiferus)

White shrimp are found in estuaries and out to depths of approximately 40 meters (m) 

offshore in the coastal waters extending from Florida to Texas and are most abundant in the 

central and western Gulf. Non-spawning adult white shrimp inhabit offshore waters in the 

winter and move inshore in the spring. Spawning generally occurs offshore in water depths of 

less than 27 m from spring to late fall, peaking during June and July. Eggs are demersal and 

share the same distribution as spawning adults. Larval white shrimp hatch within 12 hours of 

spawning and begin to migrate through passes toward estuaries as they develop into post-larvae. 

Estuarine migration peaks between June and September. 

Juvenile white shrimp are most abundant in turbid estuaries along the western coast of the 

Gulf and, within these estuarine nurseries, reach their greatest densities in marsh edge habitats 

and in areas with submerged aquatic vegetation. However, juvenile white shrimp are also 

common in marsh ponds, channels, inner marshes, shallow subtidal areas, and oyster reefs. In 

non-vegetated areas, post-larvae and juveniles inhabit mostly muddy substrates with large 

quantities of detritus. Sub-adult white shrimp move from the estuaries to coastal areas in late 

August and September (GMFMC, 2004). 

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Brown Shrimp (Farfantepenaeus aztecus)

Adult brown shrimp inhabit neritic waters (over the continental shelf from low tide to a 

depth of approximately 110 m) throughout the Gulf, but are more abundant off the coasts of 

Texas, Louisiana, and Mississippi. Non-spawning adults prefer turbid waters to soft sediments 

(e.g., mud and sand). In the spring and fall, adult brown shrimp move to slightly deeper water 

(46 to 91 m) to spawn. Brown shrimp eggs are demersal and usually hatch when temperatures 

are greater than 24 degrees Celsius (C). Larval brown shrimp are most abundant offshore but do 

occur in waters that range from 0 to 82 m deep. Post-larval brown shrimp migrate toward 

estuaries in the spring, typically reaching their destination between February and April. Late 

post-larval and juvenile brown shrimp are most abundant in shallow (less than 1 m) estuarine 

habitats in the spring and early summer but typically are present through the fall. 

Juvenile brown shrimp reach their greatest abundances in turbid estuaries but tolerate 

waters with less suspended material. Within the estuarine environment, juvenile brown shrimp 

prefer marsh edges and areas with submerged vegetation, but occur throughout the vegetated and 

non-vegetated portions of the estuary and in the lower reaches of its tributaries. Sub-adults are 

most abundant in slightly deeper waters from 1 to 18 m and prefer sand, mud, and shell 

substrates to the vegetated bottoms preferred by juveniles. As they develop, sub-adult brown 

shrimp continue to migrate toward deeper waters, eventually leaving the estuarine nurseries in 

mid-summer.

Red Drum Fishery of the Gulf of Mexico

Red Drum (Sciaenops ocellatus)

Red drum occur in a variety of habitats over different substrates throughout the Gulf. 

Habitats range in depth from about 40 m offshore to very shallow in estuarine wetlands with 

substrates that include sand, mud, and oyster reefs. Adult red drum are roving predators that 

opportunistically feed on a variety of invertebrate and vertebrate prey including crab, shrimp, 

and other fishes. Spawning occurs from September through November over deeper waters 

protected from currents such as the mouths of bays and inlets, and on the Gulf side of barrier 

islands. Eggs typically hatch between late summer and early fall in the open waters of the Gulf 

and are subsequently transported on tides and currents into estuarine nursery areas. 

Larval red drum are most abundant in estuaries from mid-August through late November. 

Within these estuarine nurseries, larvae, post-larvae, and juveniles prefer habitats protected from 

currents with submerged and emergent vegetation and muddy substrates, but also tolerate nonvegetated hard and soft-bottomed areas. Larval and post-larval red drum feed primarily on 

copepods whereas juveniles feed on a wide variety of small invertebrates. Juvenile red drum 

become most abundant in early winter. Much like the adult red drum, late juveniles utilize a 

wide variety of habitats. However, they still prefer protected waters and do not become 

abundant in open waters until mid-September to early October. Estuarine wetlands are very 

important to larval and juvenile red drum and while adult red drum use estuaries they tend to 

spend more time offshore as they age (GMFMC, 2004). 

Reef Fishery of the Gulf of Mexico

Estuarine dependent and nearshore reef fish and snapper-grouper species utilize areas 

inshore of the 100-foot contour, such as attached macroalgae; submerged rooted vascular plants 

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(seagrasses); estuarine emergent vegetated wetlands (salt marshes, brackish marsh); tidal creeks; 

estuarine scrub/shrub (mangrove fringe); oyster reefs and shell banks; unconsolidated bottom 

(soft sediments); artificial and coral reefs; and live/hard bottom for all life stages. Snappers are 

common in all warm marine waters. Most are inshore dwellers although some occur in openwater. Some species enter estuaries and mangroves, with the latter functioning as nursery 

grounds. The serranids (grouper) are primarily carnivorous bottom dwellers, associated (as 

adults) with hard-bottomed substrates and rocky reefs (GMFMC, 2004). Specific life history and 

habitat use descriptions for species with EFH in the Project area are provided below.

Gray Snapper (Lutjanus griseus)

Gray snapper range from North Carolina to Brazil, including Bermuda, the Caribbean, 

and northern Gulf (GMFMC, 1998). Juveniles can occasionally be found as far north as 

Massachusetts (Manooch, 1988). Gray snapper are capable of inhabiting a wide variety of 

habitats. Offshore benthic habitats include shipwrecks, ledges, hard bottom, coral reefs, and 

rocky outcroppings to depths of 180 m, while inshore habitats consist of seagrasses, mangroves, 

and rock piles (Bortone and Williams, 1986; Manooch, 1988; Florida Museum, 2013). Smaller, 

younger fish are typically found utilizing more inshore habitats, such as seagrass beds and areas 

of soft sediments, compared to larger, older adults (Manooch, 1988; Florida Museum, 2013). 

Adults and juveniles are euryhaline and can tolerate a salinity range from 0 to 37 practical 

salinity units and have even been recorded in freshwater lakes and rivers of southern Florida 

(GMFMC, 1998; 2004; Florida Museum, 2013). They are also found utilizing waters with 

temperatures between 13 and 32.5 degrees C (Bortone and Williams, 1986). Eggs and larvae are 

pelagic until larvae settle at inshore nurseries consisting of seagrass beds, mangroves, jetties, or 

pilings, approximately three weeks after hatching, typically from July through September 

(Bortone and Williams, 1986; Domeier et al., 1996; GMFMC, 1998; 2004; Florida Museum, 

2013). 

This species does not exhibit extensive movements and remains in the same area for 

extended periods of time, except during spawning season (GMFMC, 1998; Florida Museum 

2013). Gray snapper do demonstrate daily movement associated with feeding and schooling. 

Gray snapper migrate from inshore waters to offshore waters to spawn between April and 

November, with spawning correlated with lunar cycles (Manooch, 1988; Domeier et al., 1996; 

Florida Museum, 2013). Spawning locations have not been identified but are believed to be 

associated with reefs and shipwrecks (Domeier et al., 1996). Individuals are capable of 

spawning multiple times during a season (Florida Museum, 2013). This species is an 

opportunistic predator. Crustaceans are a primary component of the adult gray snapper’s diet 

(Starck and Schroeder, 1971). Adult gray snapper prey nocturnally on fish, shrimp, and crab 

(Manooch, 1988; Florida Museum, 2013). 

Lane Snapper (Lutjanus synagris)

Lane snapper are distributed from North Carolina to southern Brazil, including the Gulf 

and the Caribbean Sea. Lane snapper are abundant in the Antilles, off Panama, and the northern 

coast of South America (Florida Museum, 2013). These fish prefer clear nearshore water over 

rocky bottoms near coral reefs and in sandy areas or seagrass with abundant shrimp. Juveniles 

use inshore waters as nurseries. Lane snapper occur up to 400 m deep (Florida Museum, 2013). 

Lane snapper spawn from March to September throughout their range, and both sexes are able to 

B-8
spawn after the first year (GMFMC, 2004). Lane snapper are opportunistic predators feeding on 

a variety of prey, such as small bottom fishes as well as shrimp, crabs, and cephalopods (Florida 

Museum, 2013). 

Goliath Grouper (Epinephelus itajara)

Goliath grouper are distributed from Florida to Brazil, including Bermuda, Caribbean 

Sea, and Gulf (Florida Museum, 2013). They are most abundant off eastern Florida south to the 

Florida Keys (GMFMC, 1998; 2004). This species is also found in the eastern Atlantic from 

Senegal to Congo, Africa and in the eastern Pacific from the Gulf of California to Peru (Florida 

Museum, 2013). Rocks, corals, caves, shipwrecks, ledges, and muddy substrates, in waters with 

depths less than 46 m, are the preferred habitat of territorial adults, while juveniles are found in 

estuarine areas associated with mangroves and oyster bars (Sadovy and Eklund, 1999; Florida 

Museum, 2013). Eggs and larvae are pelagic with larvae becoming benthic approximately 25 

days after hatching (Florida Museum, 2013). Spawning events occur around shipwrecks, rock 

ledges, and reefs from July through September and are correlated with lunar events. Spawning 

aggregations containing over 100 goliath groupers have been observed with all recorded 

aggregations (except Bermuda) occurring between 15 degrees north and 26 degrees north 

latitudes (Sadovy and Eklund, 1999; Florida Museum, 2013). These aggregations primarily 

consist of the largest and oldest individuals of the population (Coleman et al., 2000). Goliath 

grouper are considered sedentary and typically do not move among reefs, except to form 

aggregations (Sadovy and Eklund, 1999). Goliath groupers are opportunistic feeders that prey 

mainly on crustaceans (spiny lobsters, shrimp, and crabs) and fishes (stingrays and parrotfishes),

but also consume cephalopods and young sea turtles (Florida Museum, 2013). 

Yellowmouth Grouper (Mycteroperca interstitialis)

Yellowmouth grouper are native to the western Atlantic from Florida to southern Brazil, 

including the Gulf, Florida Keys, Bahamas, Cuba, and throughout the Caribbean Sea (IUCN, 

2013). In the Gulf, yellowmouth grouper occur off of the Campeche Banks, the west coast of 

Florida, Texas Flower Garden Banks, and the northwest coast of Cuba (GMFMC, 2004). 

Yellowmouth grouper prefer rocky and coral bottoms from shoreline to at least 55 m deep. 

Smaller yellowmouth grouper are common in mangrove areas (IUCN, 2013). Little information 

is available on yellowmouth grouper life history, however, yellowmouth grouper are pelagic 

spawners and sex-reversal is possible for this species (IUCN, 2013). Spawning occurs primarily 

in spring and summer, with peaks in April and May off the west coast of Florida (GMFMC, 

2004). Juveniles commonly occur in mangrove-lined lagoons and move into deeper water as 

they grow (GMFMC, 2004). Yellowmouth grouper feed primarily on other fishes (IUCN, 2013). 

Atlantic Highly Migratory Species 

Highly migratory species (sharks) may utilize a variety of coastal and ocean habitats. 

Shark habitat can be described in four broad categories: coastal, pelagic, coastal-pelagic, and 

deep-dwelling. Coastal species inhabit estuaries, nearshore areas, continental slope, and 

continental shelf. Bull, scalloped hammerhead, bonnethead, blacktip, finetooth, lemon, and 

Atlantic sharpnose sharks are all considered coastal sharks (NOAA Fisheries, 2009; 1999). 

Adult sharks are broadly distributed as adults, but often utilize estuaries as pupping and nursery 

areas during pupping season and through their neonate and young-of-the-year life stages. 

B-9
Specific life history and habitat use descriptions for species with EFH in the Project area are 

provided below.

Bull Shark (Carcharhinus leucas)

The bull shark is managed under the Large Coastal Shark MU through the Final Atlantic 

Consolidated FMP for Highly Migratory Species (NOAA Fisheries, 2006). Bull sharks are a 

circumglobal species and in the Atlantic are distributed from Massachusetts to Florida, including 

the Gulf. The bull shark is considered most common off southern Florida and within the Gulf

(Castro, 1983; Compagno, 1984b). This shallow-water species is common in both tropical and 

subtropical regions and in marine, estuarine, and freshwater habitats and can journey long 

distances up large rivers (NOAA Fisheries, 1999). The bull shark typically occupies shallow 

coastal waters less than 30 m deep, but has been observed at depths of 152m. Adults occupy 

deeper waters than juveniles. Bull sharks typically stay near the bottom, rarely utilizing surface 

waters (Compagno, 1984b). Bull shark nurseries have been recorded in low salinity estuaries 

extending from North Carolina to the Gulf (McCandless et al., 2002). Bull sharks migrate north 

as far as Massachusetts, along the coast during the summer and then return south as waters cool

(Compagno, 1984b). Mating occurs in late spring or early summer (June or July), with birth to 

live young occurring in estuaries and river mouths the following year, from April to June

(Compagno, 1984b; Castro, 1983). Bull sharks are opportunistic feeders that prey on a wide 

variety of bony fishes, shark species, and invertebrates. Additionally, stomach contents have 

revealed that this species also consumes sea turtles, sea birds, and marine mammals (Compagno, 

1984b).

NOAA Fisheries (2009) has designated EFH for neonates, juveniles, and adult bull sharks 

within the Project area. Neonate bull shark EFH is designated as shallow coastal waters, 

including inlets and estuaries in the Gulf between Texas and the west coast of Florida, with 

localized areas off of Mississippi and the Florida Panhandle. The mid-east coast of Florida to 

South Carolina is also EFH for bull sharks (NOAA Fisheries, 2009). Juvenile bull shark EFH is 

designated as shallow coastal waters, inlets, and estuaries in waters less than 25 m off western 

Florida in the Gulf from Texas through the Florida Keys (NOAA Fisheries, 2009). Adult bull 

shark EFH is in western Florida through the Florida Keys as well as the Texas coast and eastern 

Louisiana. 

Scalloped Hammerhead Shark (Sphyrna lewini)

The scalloped hammerhead shark is managed under the Large Coastal Shark MU through 

the Final Consolidated Atlantic Highly Migratory Species FMP (NOAA Fisheries, 2006). 

Scalloped hammerhead sharks are found in warm-temperate to tropical waters worldwide over 

the continental shelf and slope. In the Atlantic, the scalloped hammerhead shark ranges from 

New Jersey to Brazil, including the Gulf and the Caribbean Sea (Florida Museum, 2013). This 

species inhabits waters from the surface to depths of 275 m and is found close to shore, in bays 

and estuaries, preferring water temperatures of at least 22 degrees C (Castro, 1983; Compagno, 

1984a). Typically, scalloped hammerhead sharks spend the day close to shore and move to 

deeper waters at night to feed (Florida Museum, 2013). Scalloped hammerhead sharks birth 

once a year in the summer starting around June in shallow coastal nurseries found from Virginia 

to the Gulf (Castro, 1993; McCandless et al., 2002). This species forms large schools when it 

migrates seasonally north to south along the eastern U.S. coast (NOAA Fisheries, 1999). 

B-10
Scalloped hammerhead sharks consume a wide variety of fishes, as well as invertebrates, and 

have been reported feeding only at night (Compagno, 1984a). 

NOAA Fisheries (2009) has designated EFH for neonate and juvenile scalloped 

hammerhead sharks within the Project area. Neonate and juvenile scalloped hammerhead shark 

EFH is designated as shallow coastal areas such as bays and estuaries out to a 25 m isobath in the 

Gulf from Texas to the southern west coast of Florida (NOAA Fisheries, 2009). 

Bonnethead Shark (Sphyrna tiburo)

The bonnethead shark is managed under the Small Coastal Shark Management Unit

through the Final Atlantic Consolidated Highly Migratory Species FMP (NOAA Fisheries, 

2006). The bonnethead shark is limited to warm waters in the Atlantic Ocean ranging from 

coastal southern New England south to the Gulf and Brazil, and is most common in the 

Caribbean Sea, including Cuba and the Bahamas. In the Pacific Ocean, the bonnethead shark 

ranges from southern California to Ecuador (Castro, 1983). Bonnethead sharks inhabit shallow 

coastal waters where they are typically associated with sandy or muddy substrates (Castro et al., 

1999). This species inhabits continental and insular shelves, over reefs, estuaries, seagrass beds, 

and shallow bays from depths of 10 m to 80 m (Campagno, 1984b). Bonnethead shark nurseries 

have been identified in estuaries from South Carolina south along the Atlantic coast into the Gulf

(McCandless et al., 2002). Bonnethead sharks prefer water temperatures warmer than 21 degrees 

C and migrate accordingly back and forth to the equator throughout the year. This species 

migrates to inshore areas of North Carolina, South Carolina, and Georgia during the summer and 

off Florida and the Gulf during spring and fall. During the winter, it moves southward to deeper 

waters. This species mates late summer through early fall in shallow waters (Castro, 1983; 

Branstetter, 2002; Lombardi-Carlson et al., 2003). Bonnethead sharks prey primarily upon 

benthic species, including shrimp, crab, cephalopods, and fish during the daytime (Castro, 1983; 

Branstetter, 2002). 

NOAA Fisheries (2009) has designated EFH for neonate, juvenile, and adult bonnethead 

sharks within the Project area. Neonate, juvenile, and adult bonnethead shark EFH is designated 

as shallow coastal waters, inlets, and estuaries in the Gulf along Texas and from eastern 

Mississippi through the Florida Keys (NOAA Fisheries, 2009). 

Blacktip Shark (Carcharhinus limbatus)

The blacktip shark is managed under the Large Coastal Shark Management Unit through 

the Final Atlantic Consolidated Highly Migratory Species FMP (NOAA Fisheries, 2006). This 

shark is found worldwide in predominantly tropical seas but occurs seasonally in warmtemperate coastal waters. In the Atlantic, it ranges from southern New England to southern 

Brazil, encompassing the Gulf and Caribbean Sea (Garrick, 1982). The blacktip shark is most 

abundant off South Carolina, Georgia, and Florida in the summer (Castro, 1983). The blacktip 

shark ranges from inshore estuarine waters, including bays and mangrove swamps, to offshore 

habitats, but is rarely found at depths greater than 30 m. This species often stays near the 

surface. Although often recorded offshore, it is not considered a true oceanic shark species. It 

has a wide salinity tolerance but generally does not move far into riverine systems (Compagno, 

1984a). Neonate and juvenile blacktip sharks utilize nursery areas and can remain there for up to 

a year. Blacktip shark nurseries have been identified in nearshore and estuarine waters from 

North Carolina through the Gulf (Castro, 1993; NOAA Fisheries, 1999; McCandless et al., 

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2002). Recent analysis has determined that blacktip sharks in the Gulf and Atlantic nurseries are 

genetically distinct and separate from one another. Large schools of blacktip sharks off the coast 

of Florida seasonally migrate north to south along the coast up to 1,159 nautical miles. This 

species migrates to deeper waters during the winter and utilizes coastal waters of the 

southeastern U.S. during the summer. Blacktip sharks give birth to live young in inshore nursery 

grounds during late spring to early summer after a 10 to 11 month gestation period. Blacktip 

sharks are active mid-water hunters, feeding on benthic and pelagic fishes, cephalopods, and 

other invertebrates. 

Finetooth Shark (Carcharhinus isodon)

The finetooth shark is managed under the Small Coastal Shark Management Unit through 

the Final Consolidated Atlantic Highly Migratory Species FMP (NOAA Fisheries, 2006). In the 

Atlantic, the finetooth shark is distributed from North Carolina to Cuba and southern Brazil, 

including the Gulf (Compagno, 1984a). Not a lot is known about habitat associations of this 

species. Finetooth sharks form large schools and are located in waters close to shore to depths of 

10 m (Compagno, 1984a). Finetooth shark estuarine nursery areas have been documented from 

South Carolina to the Gulf (Castro, 1993; McCandless et al., 2002). Finetooth sharks give birth 

to live young from May to June. This species feeds on bony fishes, crustaceans, and 

cephalopods (Campagno, 1984a; Florida Museum, 2013). 

NOAA Fisheries (2009) has designated EFH for neonates within the Project area. 

Neonate finetooth shark EFH is designated as shallow coastal areas such as bays and estuaries 

out to a 25 m isobath in the Gulf off of Texas, eastern Louisiana, Mississippi, Alabama, and the 

Florida Panhandle (NOAA Fisheries, 2009).

Lemon Shark (Negaprion brevirostris)

The lemon shark is managed under the Large Coastal Shark Management Unit (MU) 

through the Final Atlantic Consolidated Highly Migratory Species FMP (NOAA Fisheries, 

2010). The species is found in the temperate/tropical regions of the Atlantic and Pacific oceans, 

as well as the Caribbean Sea. In the Atlantic, its distribution ranges from New Jersey to southern 

Brazil, including the Gulf (Compagno, 1984b; Florida Museum, 2013). Utilization of diverse 

habitat is characteristic of the species and includes oceanic waters, coral reefs, mangroves, bays, 

sounds, estuaries, and river mouths. The lemon shark is found from surface waters to depths of 

90 m (Florida Museum, 2013). Young sharks are typically found utilizing habitats closer to 

shore than adults (Campagno, 1984b). Lemon shark nurseries have been recorded in the Florida 

Keys, Tampa Bay, Florida, and along the Gulf coast of Texas (McCandless et al., 2002). Lemon 

sharks typically inhabit deeper waters during the daytime and move to shallower waters at night 

(Florida Museum, 2013). Off Florida, this species also migrates south into deeper water during 

the winter (Compagno, 1984b). Lemon sharks mate and give birth to live young during the 

spring and summer, from May to September (Compagno, 1984b). Lemon sharks consume a 

variety of crustaceans, mollusks, and fishes located over sandy or muddy substrates (Compagno, 

1984b; Florida Museum, 2013). 

NOAA Fisheries (2009) has designated EFH for adult and neonate lemon sharks within 

the Project area. Neonate lemon shark EFH is designated as shallow coastal areas such as bays 

and estuaries out to a 25 m isobath in the Gulf between Texas mid-coast and the Florida Keys. 

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Juvenile lemon shark EFH is designated as shallow coastal areas such as bays and estuaries out 

to a 25 m isobath in areas along Texas and eastern Louisiana (NOAA Fisheries, 2009).

Atlantic Sharpnose Shark (Rhizoprionodon terraenovae)

The Atlantic sharpnose shark is managed under the Small Coastal Shark Management 

Unit through the Final Consolidated Atlantic Highly Migratory Species FMP (NOAA Fisheries, 

2009). This shark is a subtropical-tropical species found throughout the Atlantic Ocean. The 

Atlantic sharpnose shark inhabits the waters of the coast of North America from New Brunswick 

to Florida, extending to the Yucatan area in the Gulf (Castro, 1983; Florida Museum, 2013). 

This species is a common year-round coastal inhabitant from South Carolina to the Gulf and is a 

seasonally abundant migrant off Virginia (NOAA Fisheries, 1999). The Atlantic sharpnose 

shark is most abundant in warm-temperate to subtropical waters of the continental shelf, from 

inshore areas such as estuaries to the surf zone and out over the shelf in water as deep as 280 m, 

but it mostly remains in waters less than 10 m deep (Florida Museum, 2013). This demersal 

shark has a broad salinity tolerance and has been found up rivers, such as the Pascagoula River in 

Mississippi (Florida Museum, 2013). This species and its nursery areas can also be found in 

estuarine habitats (Castro, 1993). The Atlantic sharpnose shark performs inshore-offshore 

movements seasonally, moving into deeper offshore waters during winter as water temperatures 

fall (Compagno, 1984a; Florida Museum, 2013). Atlantic sharpnose sharks typically mate in late 

spring and early summer with females migrating offshore during their pregnancy (Florida 

Museum, 2013). This species moves back inshore to give birth to live young in shallow, 

protected areas during the late spring to early summer of the following year, from North Carolina 

to central Florida (Castro, 1983; 1993). This species feeds on fishes, worms, shrimp, crabs, and 

mollusks (Florida Museum, 2013; Branstetter, 2002). 

NOAA Fisheries (2009) has designated EFH for neonate, juvenile, and adult Atlantic 

sharpnose sharks within the Project area. Neonate, juvenile, and adult Atlantic sharpnose shark 

EFH is designated as shallow coastal areas such as bays and estuaries out to a 25 m isobath 

within the Gulf between Texas and the Florida Keys (NOAA Fisheries, 2009). 

4.0 POTENTIAL EFFECTS ON EFH

Potential effects on EFH associated with the construction and operation of the Project 

would primarily consist of increased turbidity; decreased water quality; and increased sediment 

disturbance, suspension, and deposition in the area. 

Approximately 124.0 acres of open water habitat would be impacted by operation of the 

Terminal. Of the 124.0 acres, approximately 95.4 acres is currently aquatic/intertidal habitat 

(shallow water) that would be permanently converted to deep water habitat (23.8 acres of the site 

is currently classified as deep water and 5.0 acres of open land will be converted to deep water). 

Impact on EFH species would depend on the species’ use of deep water habitats. Many of the 

species that occupy shallow water habitats may also inhabit the deep water habitats that currently 

exist in the adjacent La Quinta Channel and Turning Basin sometime during their life cycle. 

Many species reside or migrate through both inshore and offshore areas at different life stages 

and during different seasons throughout the year. 

Of the 95.4 acres of shallow water habitat that would be dredged, approximately 9.2 acres 

are currently submerged aquatic seagrass beds, 5.9 acres are cordgrass salt marsh, 1.0 acre is 

emergent marsh and vegetated sand flats, 2.9 acres are unvegetated sand flats, and 6.7 acres are 

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black mangrove. The remaining 67.9 acres are unvegetated shallow water. Portions of these 

habitats would be permanently converted to open water habitat. These habitats are valuable 

habitat types relative to fish and EFH as they provide a food rich environment for productive 

foraging and refuge from predators for juveniles and prey species. Alteration of these habitats 

can cause a reduction or loss of juvenile or prey species rearing habitats and an alteration in the 

timing of life history stages. The primary activities associated with the Project that would result 

in alteration and degradation of EFH include dredging, pile driving, increased ship traffic, and 

ballast water intake and discharge.

Dredging

As described in section 4.3 of the EIS, Cheniere proposes to use a hydraulic cutterhead 

dredging system to remove approximately 4.4 million cubic yards of mostly stiff clays with 

interbedded sand and silt layers to create the berthing area and maneuvering basin at the 

Terminal. Dredging with a hydraulic cutterhead dredge generally creates less turbidity than 

other types of dredges (i.e., mechanical bucket or hopper dredges). With a cutterhead dredge, the 

cutter speed can be adjusted to match the sediment properties, thus minimizing turbidity 

(Herbich and Brahme, 1984). During operation of the Project, maintenance dredging may be 

required every three years. Cheniere estimates that 200,000 cubic yards of material would be 

dredged for each occurrence. During the dredging operation, water quality would be affected by 

the temporary increase in turbidity surrounding the hydraulic cutterhead of the dredge as well as 

around the mixing zone. Disturbance of bottom sediments during dredging can significantly 

increase turbidity and down-current deposition of sediments. Very high levels of turbidity can 

result in the physical impairment of estuarine species (e.g., turbidity induced clogged gills 

resulting in suffocation, or abrasion of sensitive epithelial tissue). 

However, the turbidity and the deposition of sediments would be reduced by the tidal

flushing action of Corpus Christi Bay. Tidal flushing in Corpus Christi Bay has been described 

as a restricted flow, tidal regime switching from semi-diurnal to diurnal (Ward, 1997). The tides 

are wind dominated which results in relatively higher tides in summer and spring with lower 

tides in winter and fall because of the prevailing wind. Because of the change in the width to 

depth ratio of the La Quinta Channel, overall currents would be expected to be relatively low, 

particularly at or near the bottom where dredging would occur.

Based on the general hydraulic characteristics of the site and the proposed depth of 

dredging, most of the sediment that would become suspended during the dredging process is 

expected to be short term and the water quality would return to background levels a short 

distance from the point of disturbance. Therefore, impacts to EFH due to water quality impacts 

from dredging are not expected to be significant. 

Entrainment of aquatic organisms by dredging machinery can impact EFH species 

directly or indirectly through the removal of prey species (e.g., benthic invertebrates) or food 

species (e.g., macroalgae), disrupting energy flow and biotic interactions. Entrainment of 

benthic organisms during the dredging of the berthing and maneuvering areas is expected, 

however, entrainment would not be extensive enough to have a significant impact on the fishery 

resources of Corpus Christi Bay. In addition, benthic organisms typically have rapid 

recolonization rates that would limit impacts on the biota of these areas.

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Dredging and the direct removal of suitable benthic substrates can impact EFH by 

removing suitable cover or settlement structure. Dredging typically homogenizes bottom 

substrates, reducing the structural complexity of habitats. Field surveys of the Project area 

revealed that the open bay habitats that would be dredged already consist of a homogenous bed 

of fine substrates. Dredging of these areas would, therefore, not significantly alter the existing 

bottom type, with the exception of vegetated areas, as discussed below.

Dredging can also result in the chemical impairment of the water column due to the 

suspension of contaminated sediments. The Final EIS for the Corpus Christi Ship Channel 

Improvement Project reported the results of sediments that were sampled and analyzed for 

organic and metallic chemicals (COE, 2003). The U.S. Army Corps of Engineers (COE) EIS 

included samples from the La Quinta Channel extension that would overlap the area of the 

proposed dredging. In addition, Cheniere collected three sediment cores from the proposed 

dredging area and had them analyzed for metals. In the COE final EIS, the results were 

compared to the Effects Range Low (ERL), which are used by NOAA as screening levels for 

assessing sediment quality. These are conservative concentration levels and are considered the 

lowest concentrations where effects on the marine ecology have been observed. These levels are 

used to identify sediment that may require additional evaluations before decisions on disposal or 

beneficial re-use are made.

In 1985 samples from the La Quinta Channel, arsenic ranged from 12 to 15 milligrams 

per kilogram (mg/kg) in all six samples, which is above the ERL of 8.2 mg/kg. Six samples 

were taken from the same stations in 1990 and again in 2000, and all metals were below the ERL 

levels. Three samples were taken in 2000 from the La Quinta extension and analyzed for metals 

and all metals were below the ERLs. The samples taken in 1985 were analyzed for 

polychlorinated biphenyls (PCBs) and pesticides and all detections were below ERL levels. The 

samples taken in 1990 and 2000 were analyzed for PCBs, pesticides, and polycyclic aromatic 

hydrocarbons, and all detections were below ERL levels. The COE concluded that, overall, there 

is no indication of current water quality problems in the La Quinta Channel (COE, 2003). 

The results of the analysis of Cheniere’s core samples were compared to the Protective 

Concentration Levels (PCL) for Tier 1 commercial/industrial soil protective of Class 3 

groundwater. All concentrations were below the PCL.

While the existing functions of the permanently impacted seagrass, coastal marsh, 

cordgrass salt marsh, vegetated and unvegetated sand flats, black mangrove, and unvegetated 

shallow water habitats would be lost, this area would function as open water habitat. Impacts on 

EFH resulting from increased turbidity, decreased water quality, and increased sedimentation as 

a result of dredging would be short term and limited to the immediate area surrounding the 

activity. 

Pile Driving

In addition to impacts from dredging during construction of the Project, sound pressure 

waves produced during pile driving activities to construct the marine terminal may result in 

impacts on nearby fish species with EFH designations, and their prey. Intense sound pressure 

waves can affect fish behavior and/or result in the rupturing of swim bladders and internal 

hemorrhaging. The intensity of the sound pressure levels produced during pile driving depends 

on a variety of factors including, but not limited to, the type and size of the pile, the firmness of 

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the substrate into which the pile is being driven, the depth of water, and the type and size of the 

pile-driving hammer. The degree to which an individual fish exposed to sound waves would be 

affected is dependent upon variables such as the peak sound pressure level and frequency as well 

as the species, size, and condition of a fish (e.g., small fish are more prone to injury by intense 

sound waves than are larger fish of the same species). Depending on the specific conditions at 

the site, pile driving activities could generate underwater sound levels great enough to injure 

some fish or cause them to be more susceptible to predation. However, in order to reduce 

impacts on fish and other aquatic species from pile driving, Cheniere would perform a soft start 

in which they would ramp-up pile driving activities to allow mobile species in the area to 

relocate to adjacent habitats prior to the primary pile driving activities. 

Marine Traffic

Ship and boat traffic associated with construction and operation of the Project would also 

generate underwater sounds. Although vessel sounds would not generally be of the intensity 

produced from driving steel piles, Project vessels (e.g., LNG carrier ships [LNGCs’], tugs, 

construction barges) operating in the La Quinta Channel could result in sounds that illicit 

responses in fish. Most research suggests that fish exhibit avoidance behavior in response to 

engine noises (International Council for Exploration of the Sea, 1995). At the same time, 

research conclusions tend to suggest that since the effects are transient (i.e., once the ship passes, 

behavior returns to normal), then the long-term effects on populations are negligible (Stocker, 

2001). 

Ballast Water

It is expected that any LNGC at the Terminal would be in full compliance with the 

domestic requirements for ballast water management as specified in the National Invasive 

Species Act of 1996 and international standards that were adopted on February 13, 2004. 

Additionally, the Terminal would comply with Port of Corpus Christi Authority (POCCA) 

general and specific discharge prohibitions (regulations) currently in place. While taking on 

LNG cargo at the Terminal, LNGCs will discharge seawater ballast to maintain stability. In 

accordance with International Maritime Organization regulations, LNGCs are required to 

undergo mid-ocean ballast water exchange during transit so that the source of the ballast water 

discharged at the Terminal would not be from a foreign port but would be from open ocean. 

Ballast water is exchanged through seachests and it is estimated to take between 25 and 72 hours 

to complete ballast water discharge while at dock depending on the rate of LNG cargo loading. 

Ballast discharge is necessary to maintain a constant draft at the berth. Adverse effects on 

marine life would be minimized by a number of factors. First, temporary spikes in salinity are 

not anticipated to adversely affect fish and other marine organisms. Second, ballast water would 

be discharged near the bottom of the waterway, where salinity levels are naturally higher and the 

ballast water can enter the saltwater wedge and move toward the open Gulf. Third, as the 

LNGCs move in and out of the marine berth, the amount of water displaced by the LNGC (on 

average 110,000 tons per vessel) would be circulated into, around, and out of the berth and 

would facilitate rapid mixing of any ballast water and flushing of the marine berth on a per ship 

basis. The net effect is enhanced and rapid dilution of any ballast water upon departure of the 

LNGC. Finally, the amount of freshwater flowing into the Corpus Christi Bay from the Nueces 

River, as well as other freshwater sources along the La Quinta Channel, exceeds anticipated 

ballast discharge. Thus, the ballast water would be quickly diluted to ambient salinity. 

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Therefore, any effects on salinity are expected to be temporary and localized, and are not 

expected to have any negative effects on the marine life in and around the Terminal.

If it is necessary for ballast water to be taken on at the Terminal, during cargo delivery, 

each LNGC would discharge its entire cargo to LNG storage tanks on shore. As with LNG 

export, LNGCs discharging LNG cargo would take on seawater ballast to maintain a constant 

draft at the berth. Aquatic species in the immediate vicinity of the ship berths could therefore be 

impacted by entrainment during ballast water intake. 

Cumulative Impacts

Cumulative impacts result when impacts associated with a proposed project is 

superimposed on or added to impact associated with past, present, or reasonably foreseeable 

future projects within the area affected by the Project. Although individual impacts of the 

separate projects might be minor, the additive effects from all the projects could be significant. 

Additional discussion of cumulative impacts is provided in section 4.13 of the Project EIS.

Existing environmental conditions in the Project area reflect extensive changes based on 

past projects and activities. For example, substantial impacts have occurred and continue to 

occur because of water quality degradation from point and non-point source pollution within 

Corpus Christi Bay. Point source discharges from industry, combined with septic tank leachates, 

stormwater runoff, and oil and chemical spills contribute to lower water quality and degraded 

fishery habitats. 

Cumulative effects on marine resources in the area could occur from several planned and 

currently in progress projects including the proposed COE La Quinta Ship Channel Extension,

POCCA La Quinta Trade Gateway Terminal, Offshore Wind Power Systems of Texas, LLC 

Foundation Test Site, and Voestalpine DRI Plant. All of these projects would involve dredging 

activities, which if conducted concurrently with the Project, could result in cumulative impacts 

on EFH in the area. The primary short-term impact of dredging is an increase in turbidity. 

Turbidity impacts are primarily restricted to the area surrounding the dredging activity and are 

temporary. The La Quinta Ship Channel Extension is located directly across from the Terminal 

site, and the POCCA La Quinta Trade Gateway Terminal and Voestalpine DRI Plant are located 

immediately adjacent to the Terminal site. If dredging for the Terminal is conducted 

concurrently with these other projects, short-term impacts to EFH from increased turbidity would 

be significant. However, based on the projected schedules of these projects, dredging would

likely not occur concurrently, minimizing the potential for cumulative effects from dredgeassociated turbidity. 

Construction of each of these projects, including dredging, would result in long-term 

impacts to EFH in the form of habitat loss or conversion. However, the COE requires mitigation 

for all permanent impacts to waters of the United States; therefore, similar to the proposed 

Project, these other projects would be required to compensate for loss of these habitats through 

mitigation as well. For example, the La Quinta Ship Channel Extension is beneficially utilizing

dredge material by creating shallow water habitat partially planted with submerged aquatic 

vegetation to compensate for similar habitat lost as a result of dredging. 

Although required mitigation would lessen the impacts from these projects to EFH and 

aquatic resources as a whole, gradual and cumulative impacts that could result from the 

construction and operation of the Project and other projects in the area and within the near future 

B-17
would result in some unavoidable adverse effects on the existing environment. For example, 

future projects such as the La Quinta Trade Gateway Terminal and the Voestalpine DRI Plant 

could potentially contribute to impacts on EFH both from dredging and the potential for 

increased ship traffic. However, specific impacts on EFH as a whole would be addressed for 

each individual project, and impacts on vegetated components of EFH would be addressed 

through compensatory mitigation during Section 404 permitting. 

5.0 EFH MITIGATION

Cheniere has attempted to avoid or minimize impacts on coastal resources, including 

EFH, by identifying a site for the Terminal that is previously disturbed, adjacent to an existing 

deep water shipping channel, and near industrial activity. Because the proposed site is 

immediately adjacent to the existing La Quinta Turning Basin and Channel, the need for 

dredging would be limited to that required for the Terminal maneuvering basin and berths.

The permanent conversion of wetlands (EFH) as a result of the proposed dredging will 

require compensatory mitigation to comply with the COE Section 404(b)1 guidelines. Cheniere 

submitted an Aquatic Resources Mitigation Plan (ARMP) for the Project to the COE. This plan 

was submitted to the COE as part of the CWA Section 404 permitting process and approved in 

2005 (DA Permit 23561). Since 2005, Cheniere has continued to work with the COE to finalize 

the ARMP to account for additional wetland impacts associated with the proposed Project.

Cheniere’s proposed conceptual wetland mitigation plan at Shamrock Island was 

approved by the COE in 2005 to mitigate for impacts to waters of the U.S. associated with the 

previous proposal to construct an LNG import terminal and associated pipeline (Docket Nos. 

CP04-37-000, CP04-44-000, CP04-45-000, and CP04-46-000). Mitigation measures for the 

previously permitted 12.88 acres of wetland impacts were completed in 2013 and included the 

installation of 16 breakwaters bordering the north-western end of Shamrock Island. Construction 

of these breakwaters would assist in the preservation of existing habitats including cordgrass, 

mangroves, unvegetated sand flats, vegetated sand flats, hard substrates, and uplands.

In response to the COE public notice for Cheniere’s permit application (Permit No. 

SWG-2007-01637), several agencies, including NOAA Fisheries, expressed concern regarding 

the length of time (50 years) it would take for complete compensatory mitigation to be complete. 

The COE addressed these concerns and determined that 50 years to achieve an 8.9:1 preservation 

ratio, as proposed in Cheniere’s ARMP, is not an appropriate period to evaluate preservation 

values. The COE recommends evaluating the preservation values during a 10-year period, 

during which time, conditions affecting the site would be relatively consistent and less likely to 

be influenced by sudden episodic events, such as hurricanes. Use of a shorter time period would 

lower Cheniere’s estimated preservation ratio and potentially change the habitat types preserved 

by the proposed ARMP. 

The COE determined that in order to quantitatively evaluate Project impacts on wetland 

habitats, it is in the public’s best interest to perform a functional assessment of the Project. A 

functional assessment would quantify, in a scientifically sound, reproducible and reasonably 

rapid manner, the wetland functions lost and those that would be mitigated for by the Project. 

This would allow the COE to verify if the Project is consistent with the COE-EPA Memorandum 

of Understanding of Mitigation under the CWA Section 404(b)(1) Guidelines and 33 CFR 

332.3(f)(1), and determine if the anticipated impacts would be adequately compensated by the 

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proposed mitigation. We expect the COE recommendations to be included in any permit that it 

may issue. Pending the results of the functional assessment, increased compensation in the 

mitigation area could be required. 

6.0 FERC’S VIEW REGARDING EFH 

Construction and operation of the Project would have temporary and long-term impacts

on EFH. In general, temporary impacts are not expected to be significant considering the 

proposed dredging method and the localized impact of the actions. Dredging of the berthing and 

maneuvering basin would temporarily affect EFH by disturbing bottom sediments and increasing 

turbidity, which can have adverse physiological effects on finfish and shellfish species. 

Hydraulic dredging would also directly affect some benthic species that would be entrained 

during dredging. However, considering the nature of the sediments that would be dredged, the 

use of hydraulic cutterhead dredging, and the temporary nature of the dredging, these impacts 

would not be significant. 

Impacts on EFH from the deposition of sediments re-suspended by dredging activities are

expected to be minimal. Considering the hydrologic characteristics of the site and the depth of 

excavation, most of the sediment that does become suspended during the dredging process is 

expected to settle within or near the dredging footprint as opposed to migrating to adjacent areas. 

Field studies of cutterhead dredges indicate that elevated turbidity is limited to the lower portion 

of the water column and turbidity levels are at background within several hundred feet of the 

cutterhead dredging operation (Herbich and Brahme, 1984). Because of the design of the 

channel, suspended sediments would be expected to stay within the confines of the dredged 

channel.

With the exception of areas of coastal wetland, dredging of open bay habitat is not 

expected to result in a significant alteration of habitat structure, as the area of the bay near the 

Terminal generally lacks habitat structure/cover. Also, considering recolonization rates of 

potentially affected benthic species and the relatively limited area affected by dredging, these 

losses would not be extensive enough to have a significant impact on the fishery resources of 

Corpus Christi Bay. 

The primary impact on EFH would be the permanent loss of approximately 95.90 acres 

of shallow open water habitat, of which 25.67 acres consist of seagrass, coastal marsh, cordgrass 

salt marsh, vegetated and unvegetated tidal flats, and black mangrove. This habitat is valuable to 

EFH managed species as they provide a food-rich environment for foraging and refuge for 

juveniles and prey species. To compensate for this permanent loss of habitat, Cheniere would 

implement wetland mitigation designed to avoid a net loss of wetlands as necessary to comply 

with the COE’s Section 404(b)1 guidelines. 

Based on Cheniere’s proposed impact mitigation measures as well as preparation of the 

functional assessment and ARMP to be approved by the COE, we have determined that 

constructing and operating the Terminal would not have a significant impact on EFH.

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7.0 REFERENCES

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requirements of coastal fishes and invertebrates (south Florida): gray, lane, mutton, and 

yellowtail snappers. Washington, DC: Fish and Wildlife Service, U.S. Department of the 

Interior; Vicksburg, Mississippi. Biological Report 82(11.52). Coastal Ecology Group, 

Waterways Experiment Station, U.S. Army Corps of Engineers, TR EL-82-4, 18p.

Branstetter, S. 2002. Mackerel sharks, Family Lamnidae. In: Bigelow and Schroeder’s Fishes 

of the Gulf of Main. 3rd Edition. Collette, B.B., and G. Kein-Macphee editors, p. 30-32. 

Washington: Smithsonian Institution Press.

Castro, J.I. 1983. The Sharks of North American Waters. Texas A and M University Press, 

College Station, Texas. 

Castro, J.I. 1993. The shark nursery of Bulls Bay, South Carolina, with a review of the shark 

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Castro, J.I., C.M. Woodley, and R.L. Brudek. 1999. A Preliminary Evaluation of Status of 

Shark Species. FAO Fisheries Technical Paper 380. Food and Agriculture Organization 

of the United Nations, Rome. 

Coleman, F.C., C.C. Koening, G.R. Huntsman, J.A. Musick, A.M. Eklund, J.C. McGovern, R.W. 

Chapman, G.R. Sedberry, and C.B. Grimes. 2000. Long-lived reef fishes: The groupersnapper complex. Fisheries 25:14-20.

Coastal Bend Bays and Estuaries Program. 2012. Habitat Atlas. Publication CBBEP – 83 

Project Number – 1227, 87p. 

Compagno, L.J.V. 1984a. Sharks of the World: Hexanchiformes to Lamniformes. Fishery 

Synopsis no. 125, Vol. 4 Part 1. Food and Agriculture Organization of the United 

Nations, Rome.

Compagno, L.J.V. 1984b. Sharks of the World: An annotated and illustrated catalogue of shark 

species to date. Part II (Carcharhiniformes). Fishery Synopsis. Food and Agriculture 

Organization of the United Nations, Rome.

Domeier, M.L., C. Koenig, and F. Coleman. 1996. Reproductive biology of gray snapper 

(Lutjanus griseus) with notes on spawning for other western Atlantic snappers 

(Lutjanidae). In Biology and culture of tropical groupers and snappers. F. ArreguinSanchez, J.L. Munro, M.C. Balgos, and D. Pauly editors, p. 189-201. International 

Center for Living Aquatic Resources Management Conference Proceedings 48, 

ICLARM, Makati City, Philippines. 

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http://www.flmnh.ufl.edu/fish/Education/bioprofile.htm. Accessed October 2013.

Garrick, J.A.F. 1982. Sharks of the genus Carcharhinus. NOAA Tech. Rep. NMFS Circ. 

(445):194 p.

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Gulf of Mexico Fishery Management Council. 1981. Fishery Management Plan for the Shrimp 

Fishery of the Gulf of Mexico, United States Waters (includes Amendments 1 and 2). 

Tampa, Florida: Gulf of Mexico Fishery Management Council.

Gulf of Mexico Fishery Management Council. 1998. Generic amendment for addressing 

essential fish habitat requirements in the following Fishery Management Plans of the 

Gulf of Mexico: shrimp fishery, red drum fishery, reef fish fishery, costal migratory 

pelagic resources (mackerels), stone crab fishery, spiny lobster, and coral and coral reefs.

Prepared by the BMFMC, October 1998.

Gulf of Mexico Fishery Management Council. 2004. Final Environmental Impact Statement for 

the Generic Essential Fish habitat Amendment to the following fishery management 

plans of the Gulf of Mexico: Shrimp Fishery of the Gulf of Mexico, Red Drum Fishery of 

the Gulf of Mexico, Reef Fish Fishery of the Gulf of Mexico, Coral and Coral Reef 

Fishery of the Gulf of Mexico, Spiny Lobster Fishery of the Gulf of Mexico, and South 

Atlantic, Coastal Migratory Pelagic Resources of the Gulf of Mexico and South Atlantic. 

Volume 1. Gulf of Mexico Fishery Management Council pursuant to National Oceanic 

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Herbich, J.B., and S.B. Brahme. 1984. Turbidity generated by a model cutterhead dredge. In: 

R.L. Montgomery and J.W. Leach editors, Dredging and dredge material disposal, p. 47-

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Vessels: Review and Recommendations. ICES-Cooperative Research Report No. 209.

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life-history traits of bonnethead sharks, Sphyrna tiburo, (Carcharhiniformes: Sphyrnidae) 

from the eastern Gulf of Mexico. Marine and Freshwater Research 54:875-883.

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McCandless, C.T., N.E. Kohler, and H.L. Pratt, Jr. 2002. Editors Shark Nursery Grounds of the 

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Fisheries Society. Symposium 50, 402 p.

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Volumes 1 and 2. Silver Spring, Maryland: National Marine Fisheries Service.

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NOAA Fisheries. 2009. Amendment 1 to the Final Consolidated Atlantic Highly Migratory 

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NOAA Fisheries. 2010. Amendment 3 to the Final Consolidated Atlantic Highly Migratory 

Species Fishery Management Plan. National Marine Fisheries Service, Office of 

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Personal communication with Amy Williams (Biologist), Perennial Environmental 

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Sadovy, Y. and A.M. Eklund. 1999. Synopsis of biological data on the Nassau grouper, 

Epinephelus striatus, and the Jewfish, E. itajara. NOAA Technical Report 146, 65 p.

Starck, W.A., II, and R.E. Schroeder. 1971. Investigations of the gray snapper, Lutjanus

griseus. Studies in Tropical Oceanography (Miami) 10,224 p.

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Anthropogenic Noise in the Marine Acoustic Environment. http://www.msadesign.com/FishEars.html. Accessed October 2013.

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Impact Statement, April 2003.

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Appendix C

TABLES

Table 4.6-4

Birds of Conservation Concern – Gulf Coastal Prairie Region (BCR 37)

Common Name Scientific Name

Audubon’s shearwater Puffinus lherminieri

Band-rumped storm petral Oceanodroma castro

American bittern Botaurus lentiginosus

Least bittern Ixobrychus exilis

Reddish egret Egretta rufescens

Swallow-tailed kite Elanoides forficatus

Bald eagle Haliaeetus leucocephalus

White-tailed hawk Buteo albicaudatus

Peregrine falcon Falco peregrinus

Yellow rail Coturnicops noveboracensis

Black rail Laterallus jamaicensis

Snowy plover Charadrius alexandrinus

Wilson’s plover Charadrius wilsonia

Mountain plover Charadrius montanus

American oystercatcher Haematopus palliatus

Solitary sandpiper Tringa solitaria

Lesser yellowlegs Tringa flavipes

Upland sandpiper Bartramia longicauda

Whimbrel Numenius phaeopus

Long-billed curlew Numenius americanus

Hudsonian godwit Limosa haemastica

Marbled godwit Limosa fedoa

Red knot Calidris canutus

Buff-breasted sandpiper Tryngites subruficollis

Short-billed dowitcher Limnodromus griseus

Least tern Sternula antillarum

Gull-billed tern Gelochelidon nilotica

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Table 4.6-4

Birds of Conservation Concern – Gulf Coastal Prairie Region (BCR 37)

Common Name Scientific Name

Sandwich tern Thalasseus sandvicensis

Black skimmer Rynchops niger

Short-eared owl Asio flammeus

Loggerhead shrike Lanius ludovicianus

Sedge wren Cistothorus platensis

Sprague’s pipit Anthus spragueii

Prothonotary warbler Protonotaria citrea

Swainson’s warbler Limnothlypis swainsonii

Botteri’s sparrow Aimophila botterii

Grasshopper sparrow Ammodramus savannarum

Henslow’s sparrow Ammodramus henslowii

LeConte’s sparrow Ammodramus leconteii

Nelson’s sharp-tailed sparrow Ammodramus nelsoni

Seaside sparrow Ammodramus maritimus

Painted bunting Passerina ciris

Dickcissel Spiza americana

C-2
Table 4.7-1

Federally Threatened and Endangered Species in the Project Area

Species Scientific Name

Federal

Status a/

State

Status a/

Project

Component

Preferred Habitat 

MAMMALS

Gulf Coast Jaguarundi

Herpailurus

yagouaroundi

E E

The 2012 survey of the Project area found

semi-suitable habitat for the jaguarundi.

However, San Patricio County is out of this

species known range.

Ocelot Leopardus pardalis E E

The 2012 survey of the Project area found

semi-suitable habitat for the ocelot, however

the habitat is small and isolated. The ocelot

is not known to inhabit this part of San

Patricio County.

Blue whale Balaenoptera musculus E -- Terminal

Inhabits deep waters of the continental shelf.

Suitable habitat is not present in the Project

area, but is present in the open Gulf of

Mexico in the vicinity of transiting LNGCs.

Fin whale Balaenoptera physalus E -- Terminal

Inhabits deep waters of the continental shelf.

Suitable habitat is not present in the Project

area, but is present in the open Gulf of

Mexico in the vicinity of transiting LNGCs.

Humpback whale Megapetra novaeangliae E -- Terminal

Inhabits deep waters of the continental shelf.

Suitable habitat is not present in the Project

area, but is present in the open Gulf of

Mexico in the vicinity of transiting LNGCs.

Sei whale Balaenoptera borealis E -- Terminal

Inhabits deep waters of the continental shelf.

Suitable habitat is not present in the Project

area, but is present in the open Gulf of

Mexico in the vicinity of transiting LNGCs.

Sperm whale Physeter macrocephalus E -- Terminal

Inhabits deep waters of the continental shelf.

Suitable habitat is not present in the Project

area, but is present in the open Gulf of

Mexico in the vicinity of transiting LNGCs.

West Indian manatee Trichechus manatus E E Terminal

Occasional visitor to Texas waters. Inhabits

warm, shallow coastal waters, estuaries,

bays, rivers, and lakes. Suitable habitat is

present within the Project area.

C-3
Table 4.7-1

Federally Threatened and Endangered Species in the Project Area

Species Scientific Name

Federal

Status a/

State

Status a/

Project

Component

Preferred Habitat 

BIRDS

Whooping crane Grus americana E E Terminal

Winter habitat in Texas comprises brackish

marshes, bays, and flats. Suitable habitat

may be present near the Project area.

Piping plover Charadrius melodus T T Terminal

Beaches, mudflats, and sand flats. Suitable

habitat is present in the Project area.

REPTILES

Loggerhead sea turtle Caretta caretta T T Terminal

Juveniles are found in Gulf and bay systems.

Adults are mostly pelagic. Suitable habitat is

present in the Project area.

Green sea turtle Chelonia mydas T T Terminal

Gulf and bay systems, shallow water

seagrass beds, open water. Suitable habitat

is present in the Project area.

Leatherback sea turtle Dermochelys coriacea E E Terminal

Gulf and bay systems. Widest ranging open

water reptile. Suitable habitat is present in

the Project area.

Atlantic hawksbill sea turtle Eretmochelys imbricata E E Terminal

Gulf and bay systems, warm, shallow waters

especially in rocky marine environments,

jetties and coral reefs. Suitable habitat may

be present in the Project area.

Kemp’s ridley sea turtle Lepidochelys kempii E E Terminal

Gulf and bay systems. Adults stay within the

shallow waters of the Gulf of Mexico.

Suitable habitat is present in the Project

area.

PLANTS

Slender rush pea Hoffsmanseggia tenelle E E Terminal Project is outside of known range 

South Texas ambrosia Ambrosia cheiranthifolia E E Terminal Project is outside of known range 

_________________________

a/ E=Endangered, T=Threatened

C-4
Table 4.7-2

State Threatened and Endangered Species in the Project Area

Species Scientific Name State

Status a/ Preferred Habitat Determination

MAMMALS

Red wolf Canus rufus E

Brushy or forested areas

and coastal prairies.

Species has been

extirpated in the Project

area.

No impact

White-nosed coati Nasua narica T

Woodlands, riparian

corridors and canyons.

Suitable habitat is not

present in the Project area.

No impact

Southern yellow bat Lasiurus ega T

Roosts in trees of far south

Texas. Suitable habitat is

present in the Project area.

Impacts would not

be significant

BIRDS

Eskimo curlew Numenius borealis E

Grasslands, pastures,

plowed fields, marshes,

and mudflats. Species has

likely been extirpated in the

Project area.

No impact

Texas Botteri’s Sparrow Aimophila botterii texana T

Grassland and short-grass

plains with scattered

bushes or shrubs. Suitable

habitat is present within the

Project area; however, the

Project area is outside the

species’ known range.

No impact

Peregrine falcon Falco peregrinus T

Urban, concentrations

along coast and barrier

islands. Suitable habitat is

present within the Project

area; however, the species

only occurs within the

Project area as an

occasional transient.

No impact

American peregrine falcon Falco peregrinus anatum T

Urban, concentrations

along coast and barrier

islands. Suitable habitat is

present within the Project

area; however, the species

only occurs within the

Project area as an

occasional transient.

No impact

Northern Aplomado falcon Falco femoralis septentrionalis E

Savanna, open woodland,

grass plains, plowed fields,

coastal prairies, and

marshes. Suitable habitat

is present within the

Project area; however, the

Project area is outside the

species’ known range.

No impact

C-5
Table 4.7-2

State Threatened and Endangered Species in the Project Area

Species Scientific Name State

Status a/ Preferred Habitat Determination

Sooty tern Sterna fuscata T

Islands and coastal

beaches. Suitable habitat

is present in the Project

area; however the species

is very uncommon in

coastal Texas.

No impact

White-faced ibis Plegadis chihi T

Freshwater marshes,

swamps, and ponds.

Suitable habitat is not

present in the Project area.

No impact

Reddish egret Egretta rufescens T

Coastal marshes, shell

beaches, sand flats, and

mudflats. Suitable habitat

is present in the Project

area.

Impacts would not

be significant

White-tailed hawk Buteo albicaudatus T

Coastal grasslands.

Suitable habitat is present

in the Project area.

Impacts would not

be significant

Wood stork Mycteria americana T

Prairie ponds, flooded

pastures, and fields.

Suitable habitat is present

in the Project area.

Impacts would not

be significant

REPTILES / AMPHIBIANS

Sheep frog Hypopachus variolosus T

Tropical humid forests.

Suitable habitat is not

present in the Project area.

No impact

Black-spotted newt Notophthalmus meridionalis T

Freshwater ponds, canals,

and ditches. Suitable is

present within the Project

area.

Impacts would not

be significant

South Texas siren Siren spp. T

Freshwater ponds, ditches,

and swamps. Suitable is

present within the Project

area.

Impacts would not

be significant

Texas tortoise Gopherus berlandieri T

Cactus rich areas of south

Texas. Suitable habitat is

present in the Project area.

Impacts would not

be significant

Timber/canebrake rattlesnake Crotalus horridus T

Hilly woodlands and

thickets near freshwater.

Suitable habitat is not

present in the Project area.

No impact

Texas horned lizard Phrynosoma cornutum T

Loose sand and loamy

soils throughout Texas.

Suitable habitat is present

in the Project area.

Impacts would not

be significant

C-6
Table 4.7-2

State Threatened and Endangered Species in the Project Area

Species Scientific Name State

Status a/ Preferred Habitat Determination

Texas scarlet snake Cemophora coccinea lineri T

Sandy thickets of the

Texas Coastal Bend.

Suitable habitat is not

present in the Project area.

No

Texas indigo snake Drymarchon melanurus

erebennus T

Sparsely vegetated areas

of south Texas. Suitable

habitat is present in the

Project area.

Impacts would not

be significant

FISH

Smalltooth sawfish Pristis pecinata E

Sheltered bays, shallow

banks, and in estuaries or

river mouths for young and

mangrove, reef, seagrass,

and coral for adults.

Species has likely been

extirpated in the Project

area.

No impact

Opossum pipefish Microphis brachyurus T

Anadromous and breeds in

freshwater. Spends

majority of its time in open

ocean. Suitable habitat is

present in the Project area.

Impacts would not

be significant

MOLLUSKS

Golden orb Quadrula aurea T

Habitat is restricted to

lentic and lotic areas of

river basins. Suitable

habitat is not present in the

Project area.

No impact

_____________________________

a/ E=Endangered, T=Threatened

C-7
Table 4.13-1

Cumulative Impacts of the Corpus Christi LNG Project and Other Projects in the Project Area

Project

Land

Disturbance

Wetlands/

Surface

Waterbodies

Water

Use /

Discharge

T&E

Species/

EFH

Coastal

Marine

Disturbance

(Dredging)

a/

Marine

Transportation

Socioeconomics

Air

Quality

Noise V

Cheniere

Terminal

and Pipeline

Yes Yes Yes Yes Yes Yes Yes Yes Yes 

COE La

Quinta

Channel

Extension

Yes Yes No Yes Yes Yes Yes IU No 

POCCA La

Quinta

Trade

Gateway

Terminal

Yes Yes IU IU Yes Yes Yes IU No 

Revolution

Energy

Harbor Wind

Project

Yes Yes IU IU No Yes IU No No 

Offshore

Wind Power

Systems of

Texas, LLC

Foundation

Test Site

Yes Yes No IU Yes Yes IU No No 

TPCO

America

Corporation

Minimill

Yes IU Yes IU No IU Yes Yes No 

OIEC

Propane

Export

Facility

Yes IU Yes IU IU Yes Yes Yes No 

Papalote

Creek Wind

Farm

Yes No No IU No No Yes No No 

C-8
Table 4.13-1

Cumulative Impacts of the Corpus Christi LNG Project and Other Projects in the Project Area

Project

Land

Disturbance

Wetlands/

Surface

Waterbodies

Water

Use /

Discharge

T&E

Species/

EFH

Coastal

Marine

Disturbance

(Dredging)

a/

Marine

Transportation

Socioeconomics

Air

Quality

Noise V

OxyChem

NGL

Fractionation

Facility

Yes IU Yes No IU Yes Yes Yes Yes 

OxyChem

Ethylene

Plant

Yes IU Yes IU IU Yes Yes Yes Yes 

Voestalpine

DRI Plant

Yes Yes Yes Yes Yes Yes Yes Yes Yes 

Flint Hills

West

Refinery

Expansion

No No IU No No Yes Yes Yes No 

Freeport

Liquefaction

Yes Yes Yes Yes Yes Yes Yes No No 

NonJurisdictional

electrical

power lines

and

substations

Yes No No No No No No No No 

NonJurisdictional

waterline

Yes No No No No No No No No 

Removal of

NonJurisdictional

Natural Gas

Pipelines

Yes Yes No Yes Yes No No No No 

_________________________

a/ IU = Information Unavailable

C-9

Appendix D

CHENIERE’S FUGITIVE DUST 

CONTROL PLAN

Corpus Christi Liquefaction Project 

San Patricio and Nueces Counties, Texas 

FERC Docket Nos. PF12-3-000 

1

Fugitive Dust Control Plan 

1 Objective

The objective of this fugitive dust control plan is to identify potential dust emission sources and 

provide guidance to construction and field personnel on measures to avoid the generation of 

fugitive dust and control any generated fugitive dust during construction activities associated 

with the Corpus Christi Liquefaction Project. It will be the responsibility of Project Contractors 

and the Environmental Inspectors to identify all activities generating fugitive dust, implement 

feasible dust control measures, and ensure compliance with regulatory requirements. 

2 Fugitive Dust Sources

Dust is generated by the mechanical disturbance of granular material exposed to the air. Dust 

from open sources is termed “fugitive” because it is not discharged to the atmosphere in a 

confined flow stream. The following activities are identified as having potential for generating 

fugitive dust. 

 Vehicle and motorized equipment movement on paved and unpaved surfaces; 

 Vegetation Removal; 

 Clearing and Grading; 

 Soil Stabilization; 

 Bulk/Piles material loading, unloading, hauling, etc.; and 

 Abrasive Blasting. 

3 Dust Control Measures

3.1 Water Truck

Project Contractors will make all practicable efforts to minimize fugitive dust emissions from 

construction activities. The Project will have a water tank and will purchase water from the local 

municipality from which the Project’s 80 barrel water truck on site that will load water to spray 

areas for dust control. 

Areas to be sprayed include most areas within the Project Boundary; for example, but not limited 

to: 

 Designated access roads; 

 Construction Dock and staging areas; 

 All designated Staging and Laydown areas; and 

 All designated parking areas. 

D-1
Corpus Christi Liquefaction Project 

San Patricio and Nueces Counties, Texas 

FERC Docket No. PF12-3-000 

2

The frequency at which the water truck will spray the Project areas will vary based on weather 

and site conditions. For example, in dry conditions, construction traffic may increase the amount 

of dust generated on access roads, thus the water truck would be instructed to spray continuously 

throughout the workday. 

In contrast, if there is light traffic, minimal dust generating activities, and/or wet weather, the 

water truck may not be necessary. It will be at the discretion of the Environmental Inspector and 

Site Managers to engage water spraying of the site. Corpus Christi will ensure that a water truck 

be available at all times during construction. Please refer to Section 4 below for Project 

Authority. 

3.2 Other dust control measures within and outside of the soil

improvement areas:

3.2.1 Limiting vehicles from tracking “off‐road”, and keeping traffic to

designated roads

Corpus Christi will install proper signage to direct traffic to designated roads. Any traffic 

that deviates from designated roads will be redirected to the designated road and the 

activity will be reported to the appropriate supervisor for corrective action. 

3.2.2 Enforcing a speed‐limit of 15 mph on unsurfaced roads

Corpus Christi will install speed limit signs on all designated access roads. Any 

observances of excessive speeds will be reported to the appropriate supervisors for 

corrective action, and removal from the Project if necessary. Speeding on the Project Site 

will not be tolerated. 

3.2.3 Covering open‐bodied haul trucks		

The Environmental Inspector, Contractor Supervisors and Project Management will 

continuously be observing activities on-site. If there are observances of excessive dust 

being generated from open bodied trucks, they will be stopped and asked to reduce 

speeds or cover the truck beds as necessary. 

3.2.4 Enclosing the work area

For discreet activities such as abrasive blasting, the contractors will be instructed to 

enclose the work area to contain any fugitive dust and emissions as per Corpus Christi’s 

standard operation procedures. 

4 Project Authority

During all phases of Site Preparation and Construction, Corpus Christi will ensure the 

appropriate authorities are on site at all times. 

D-2
Corpus Christi Liquefaction Project 

San Patricio and Nueces Counties, Texas 

FERC Docket No. PF12-3-000 

3

The following individuals have the equal authority to: 

1. determine if/when water needs to be reapplied for dust control: 

2. determine if/when a palliative action should be used; and 

3. Stop the dust-producing work if the contractor does not comply with the dust control 

measures. 

Title Name Cell Phone Number 

Environmental Inspector 

Corpus Christi Construction Director 

Corpus Christi Project Director 

Contractor ES&H Manager 

Corpus Christi HSE Manager 

D-3

Appendix E

DISTRIBUTION LIST FOR DRAFT 

ENVIRONMENTAL IMPACT 

STATEMENT

Federal Government Agencies

United States Environmental Protection Agency

Lisa Jackson, Administrator

Jerome Blackman, Natural Gas STAR

Office of Federal Activities

Robert Hargrove, NEPA Compliance

Susan E. Bromm, Acting Director

Office Enforcement and Compliance Assurance

Cynthia Giles, Assistant Administrator

Region 6

Jeff Robinson

Al Almendariz, Regional Administrator

Alfred Dumaual, GHG Cross - Cutting Issues

Barbara Keeler, Coastal Issues

Jim Herrington, Wetland Issues

Larry Giglio, NPDES Permits

Melanie Magee, GHG Air Permits

Michael Jansky, NEPA Compliance

Patrick Rankin, Legal Cross - Cutting Issues

Rhonda Smith, Chief - Office of Planning and Coordination

Rob Lawrence, Energy Policy Advisor

Tina Arnold, Legal Cross - Cutting Issues

United States Fish and Wildlife Service

Frank Weaver

Daniel Ashe, Director

Division of Conservation and Classification

Nicole Alt, Chief

Pat Clements, Federal Project Coordinator

Allan Strand, Field Supervisor

Corpus Christi Ecological Services Field Office

Dawn Whitehead, Deputy Field Office Supervisor

Southwest Regional Office

Benjamin Tuggle, Regional Director

United States Department of Energy

Office of Environmental Compliance

Office of Environmental Management

Ed LeDuc, Deputy Assistant General Counsel

Office of Intergovernmental Affairs

Carol M. Borgstrom, Director

E-1
Office of Import/Export Activities

Bob Corbin, Director

Office of Natural Gas Regulatory Activities

John Anderson, Manager

Lisa Tracy, NEPA Document Manager

International Activities Team

Sally Kornfeld, Team Leader

United States Department of Agriculture

Jonathan Adelstein, Administrator

Natural Resources Conservation Service

Texas State Office

Bob Stobaugh, Public Affairs Specialist

National Environmental Coordinator

John Matt Harrington

Andree Duvarney

Forest Service

Director of Lands

Deputy Chief, National Forest System

Ecosystem Management Coordination

Joe Carbone, Assistant Director, NEPA

United States Army Corps of Engineers

John Furry, Senior Policy Advisor

Meredith Temple, Acting Chief of Engineers

Lloyd Mullins, Permitting Agent

Galveston District

Supervisor, Corpus Christi Field Office

Regulatory Branch Chief

Christopher Sallese, District Commander

Casey Cutler, Compliance Section Chief

Advisory Council on Historic Preservation

Charlene D. Vaughn, Assistant Director for Federal Program

John Fowler, Executive Director

United States Department of Transportation

Environmental Policies Team Leader

Federal Aviation Administration 

Michael Huerta, Acting Administrator

Research and Special Programs Administration

William H. Gute, Eastern Region

John Pepper, Southwest Region

Pipeline and Hazardous Materials Safety Administration

E-2
Jeffrey Wiese, Associate Administrator

Magdy El-Sibaie, Associate Administrator

Office of Pipeline Safety

Mike Israni, Program Manager

Community Assistance/Technical Services

Tom Fortner, Director

Research and Special Programs Administration

Administrator

Western Region

Michael J. Khayata, Sr. Compliance Investigator

Ross Reineke, Comm. Assistance/Tech. Services

Central Region

Harold Winnie, Comm. Assistance/Tech. Services

Joseph Mataich, Comm. Assistance/Tech Services

Eastern Region

Alex Dankanich, DPS-14

Southwest Region

Charles Helm

Enforcement/Research and Special Programs

Office of Drug Abuse, Compliance and Investigations and Compliance

Stanley T. Kastanas, Director

Office of Deputy Assistant Secretary of the Army

Environmental Safety and Occupational Health

Cheryl Antosh, Assistant for Sustainability, Safety and Occupational Health

Bureau of Indian Affairs

Southern Plains Regional Office

Dan Deerinwater, Regional Director

Branch of Fish, Wildlife and Recreation

Gary Rankel, Director

Michael Black, Director

Council on Environmental Quality

Ellen Athas, Senior Counsel

Horst G. Greczmiel, Director for NEPA Oversight

United States Coast Guard

Peter Gooding, Commander

Kathy Moore, Captain

George Leshner

LCDR Justin Jacobs

Office of Operating and Environmental Standards

Commandant

E-3
Marine Safety Office

DeWayne R. Penberthy

Brian Salerno, Captain of the Port

Port Arthur

G.W. Anderson, Captain

Michael Hunt

Boston

LT Antonellis

Providence

Mary E. Landry, Commanding Officer

Texas City

Ricardo M. Alonso, Commanding Officer

Los Angeles-Long Beach

Ryan Manning

Portsmouth

William Lee, Commander 

Sector Corpus Christi

Erich Stein

Erik Heithaus

8th District

Roy Nash, Commander 

Center for Disease Control and Prevention 

Building and Facilities Office

George Chandler, Director

National Marine Fisheries Service

Office of Habitat Protection

Marine Resource Habitat Specialist

Heather Young, Biologist

Rusty Swafford, Supervisor Fishery Biologist

Southeast Region

Dr. Roy Crabtee, Regional Administrator

Federal Energy Management Agency

Region VI

Heidi Carlin, Regional Director

Department of Justice

Land and Natural Resources Division

Ignacia Moreno, Assistant Attorney General

Department of the Air Force

Basing and Units 

Jack Bush, Senior Planner/NEPA Program Manager

E-4
Jeffrey Blevins, Real Property Agency

United States Department of Housing and Urban Development

Environmental Planning Division

James M. Potter, Community Planner

Department of State

Bureau of Oceans and International Environmental and Scientific Affairs

John Matuszak

United States Department of the Interior

Bureau of Land Management

Deputy Assistant Secretary

Minerals Management Service

Marci Todd, Division of Decision Support, Planning, and NEPA

Environmental Policy and Compliance

Natural Resource Management

Vijai N. Rai, Team Leader

National Park Service

Jonathan Jarvis, Director

Intermountain Region

John Wessels, Director

Environmental Planning and Compliance Branch

Patrick Walsh, Chief

Operations Division (DAIM-ODO)

Ravin L. Howell, ACSIM, Operations Directorate - Army

Gulf of Mexico Fishery Management Council

Robert Shipp, Chairman

Office of the Deputy Under Secretary of Defense

Installations and Environment

Terry Bowers, Director of Environmental Security

Surface Transportation Board

Office of Environmental Analysis

Victoria Rutson, Director

Committee on Energy and Natural Gas

National Oceanic and Atmospheric Administration

NEPA Coordinator

Program Planning and Integration

Department of Commerce

Office of the Secretary

Senior Policy Advisor

Department of Labor

Office of Regulatory Economics

E-5
Federal Representatives and Senators

Senator John Cornyn

Speaker John Boehner

Energy Policy Advisor Mike Catanzaro

Representative Blake Farenthold

Representative Ruben Hinojosa

Representative Jeff Morehouse

Representative Kay Granger

Representative Henry Cuellar

Representative Lloyd Doggett

Representative Charles Boustany

State Representatives and Senators

Governor Rick Perry

Lieutenant Governor David Dewhurst

Texas Secretary of State

Speaker Joe Straus

Senator Juan Hinojosa

Senator Judith Zaffirini

Representative Jim Keffer

Representative Todd Hunter

E-6
Texas State Agencies

Texas Commission on Environmental 

Quality

Mark Vickery, Executive Director

Zak Covar, Executive Director

Erik Hendrickson, Team Leader

Air Permits Division

Mike Wilson, Director

Rebecca Partee, Manager

Office of Compliance and Enforcement

Richard Hyde, Deputy Director

Office of Air

Steve Hagle, Deputy Director

Region 14

Susan Clewis, Director

Railroad Commission of Texas

Michael Williams, Commissioner

Pipeline Safety Division

Polly McDonald, Director

Corpus Christi - District 4

Fermin Munoz, Jr., Director

Oil and Gas Division

Gil Bujano, Deputy Director

Leslie Savage, Chief Geologist- Oil 

and Gas Permits

Intergovernmental Relations

Stacie Fowler, Director

Texas Department of Transportation

Environmental Affairs

Mark A. Marek, Interim Director

Howard Gillespie, Port Aransas 

Ferry Operations Manager

Texas Historical Commission

Mark Wolfe, Executive Director

Jeff Durst, Project Reviewer 

(Archaeological)

Texas General Land Office

Jerry Patterson, Texas Land 

Commissioner

Texas Coastal Coordination Council 

Lower Coast

Jesse Solis

Federal Consistency Review

Kate Zultner

Environmental Review

Tony Williams

Public Utilities Commission of Texas

Kenneth W. Anderson, Jr., 

Commissioner

Texas Parks and Wildlife Department

Mary Ellen Vega

Leslie Williams, Lower Coast Team 

Leader

Texas Bureau of Economic Geology

Scott W. Tinker, Director

Texas Department of Agriculture

Todd Staples, Commissioner

Texas Natural Resource Conservation 

Service

Soils Section

Texas Association of Regional Councils

Texas Department of Public Safety

Texas Department of State Health Services

Texas Economic Development Council

Texas Forest Service

Texas Soil and Water Conservation Board

E-7
Local and County Government

Nueces County

Lloyd Neal, County Judge

San Patricio County

Terry Simpson, County Judge

Gracie Alaniz-Gonzales, County 

Clerk

Precinct 1

Nina Teveno, County Commissioner

Precinct 2

Fred Nardini, County Commissioner

Precinct 4

Jim Price, County Commissioner

Lucia Rodriguez, Floodplain 

Program Manager

Port of Corpus Christi Authority

John LaRue, Executive Director

Frank Brogan, Deputy Director

Greg Brubeck, Director of 

Engineering Services

Judy Hawley, Port Commissioner 

(San Jacinto County)

Mike Carrell, Port Commission 

Chairman

Paul Carangelo, Coastal 

Environmental Planner

City of Corpus Christi

Angel Escobar, City Manager

Joe Adame, Mayor

Ron Olson, City Manager

Mark Scott, Councilman at Large

Gas Department

John M. Alexander, 

Planner/Scheduler

City of Taft

Jerry King, Mayor

Bob Gorson, City Manager

City of Portland

David Krebs, Mayor

Ron Jorgensen, Mayor Pro Tem

John Green, Mayor Pro Tem

Randy Wright, Chief of Police and 

Assistant City Manager

Cathy Skurow, City Council

Mike Tanner, City Manager

City of Port Aransas

Keith McMullin, Mayor

David Parsons, Interim City 

Manager

City of Ingleside

Pete Perkins, Mayor

Jim Gray, City Manager

City of Ingleside on the Bay

Howard Gillespie, Mayor

City of Sinton

Pete Gonzales, Mayor

Jackie Knox, City Manager

City of Gregory

Victor Lara, Mayor

John Valls, City Consultant

Norma Garcia, City Secretary

Gregory-Portland Independent School 

District

Paul Clore, Superintendent

City of Aransas Pass

Tommy Knight, Mayor

Native American Tribes

Comecrudo Nation

Kickapoo Traditional Tribe of Texas

Kiowa Tribe

Lipan Apache Band of Texas

Mescalero Apache Tribe

People of LaJunta

Tonkawa Tribe of Oklahoma

Ysleta de Sur Pueblo

E-8
Libraries

Del Mar College Libraries

Texas A&M University, Mary and Jeff Bell 

Library

Bell/Whittington Public Library

Ed and Hazel Richmond Public Library

Ingleside Public Library

La Retama Central Library

Sinton Public Library

Taft Public Library

Media

The Aransas Pass Progress

Corpus Christi Caller-Times

The Coastal Bend Herald

San Patricio County News

Portland News

Kiii 3 News

Organizations

Soil & Water Conservation Society

Craig Cox, Executive Director

Coastal Bend Audubon Society

David Newstead, President

Texas League of Conservation Voters

David Weinberg, Executive Director

American Fisheries Society

Gus Rassam, Executive Director

Coastal Bend Bays Foundation

John Adams, President Board of 

Directors

Ismael Nava, Executive Director

Coastal Bend Bays and Estuaries Program

Ray Allen, Executive Director

Leo Trevino, Deputy Director

Clean Economy Coalition

James Klein, Chairperson

Ducks Unlimited, Inc.

Southern Regional Office

Ken Babcock, Director of Operations

Sierra Club

Lone Star Chapter 

Ken Kramer, Chapter Director

Gulf of Mexico Foundation

Richard Gonzales, Science and 

Spanish Club

Nature Conservancy

TX Chapter

Robert Potts, State Director

National Wildlife Federation

Susan Kaderka, Director, Gulf States

Wildlife Society

Terry Blankenship, Texas Chapter 

President

Texas State Aquarium

Tom Schmidt, Chief Executive 

Officer

Texas Bass Chapter Federation

The Wilderness Society

Resource Economist

Air Alliance Houston

Adrian Shelley, Executive Director

Ima Hogg Foundation

University of Texas Real Estate

Allan Prickett

Pipeline Contractors Association

J. Patrick Tielborg

Rocky Mountain Pipeline Contractors 

Association

J.D. Lormand, Executive Director

Rocky Mountain Pipeline Contractors 

Association

Executive Director

Association of Texas Soil and Water 

Conservation Districts

Jose Dodier, Jr., President and 

NACD Board Member

Ingleside Chamber of Commerce

E-9
Organizations (continued)

Michael Ladewig, Chairman

Portland Chamber of Commerce

Patti Cass-Strain, President

Sue Zimmermann, Executive 

Director

Aransas Pass Chamber of Commerce

Rincon Water Supply District

San Patricio Water District

Companies

ConocoPhillips Company

Bruce Connell, Director

Pete Frost

American Gas Association

Dave Parker, President

Exxon Mobil Corporation

Douglas Rasch, Attorney

National Association of Conservation 

Districts

Eugene Lamb, Director of Programs

BP America, Inc.

Frederick Kolb, Attorney

Total Gas and Power North America

J. Mark Ingram, Chairman and CEO

Jones Day

Jason Leif

Occidental Energy Ventures Corporation

Jeff Hanig, Director

Thomas Feeney, Senior Vice 

President

Tetra Tech EC, Inc.

John Scott, Project Manager

Crosstex Energy Services, L.P.

Leslie Wylie, Vice President

King and Spalding, LLP

Lisa Tonery

Baker Botts

Mark Cook, Attorney

Alcoa Inc.

Alcoa Corporate Center

Max Laun, Vice President and 

General Counsel

Paul Myron

Transcontinental Gas Pipe Line Corporation

Scott Turkington, Director

Weaver's Cove Energy, LLC

Ted Gehrig, President

Trunkline LNG Company, LLC

William Grygar, Vice President

Bell Rachel Partnership

Berryman Properties, Ltd.

Bracewell & Patterson, LLP

Gregory Power Partners, LP

Lackey Partnership

Sherwin Alumina Company, L.P.

Corpus Christi Regional Economic 

Development Corporation

Roland Mower, President and CEO

John Plotnik, Executive Vice 

President

San Patricio Economic Development 

Corporation 

Josephine Miller, Executive Director

American Electric Power

Vince Deases, Commercial Manager

Bell South Telephone Building

Landowners

Alexandra E. Zafiriou

Magnuson Protection Trust

April F.

Nancy Fleming Shelton Trust

Ben and Nancy F. Shelton

Betty McGregor Pamplin

Betty Ann Pamplin

Betty Jo Pyron

E-10
Landowners (continued)

Brad M. Floerke

Mary Madeline O'Connor Family Exempt 

Trust

Carter Lynn O’Connor

Charles A. and Linda D. Brown

Cheri P. Collier

Christopher H. Cable

Corinne McKamey

Cornelia Ann Moore Phillis

Danny Windland

Daryl Hass

David Edwards

David and Marion Trees

Diane DeCou

GJW Partnership

Don Cable

Estate of Donald Frank

Donald F. Swann

Dora Faye and Otto Schuster

Dorothy Tutt Asbury

Douglas Ray Hart

E.C. Pustejovsky

Welder Heirs

Earl Shouse

Edwin Danford

Estate of Clestine M. Schubert

Frank and Linda Decker Erhard

Gary Schubert

Gilbert and Elvia Hernandez

Harry B. Fessler

Hart Douglas

James and Lynn Lackey

Jason Floerke

Jean Ivy

Jeff McKamey

Estate of A.H. Moore

Jerry Lea Moore

Kathleen Young Moore

Jimmy Mauch

GJW Partnership

Joe Garrett

Joseph Cable

Joseph D. Cable

Julia and Robert Driscoll

Katherine S. Cable

Estate of Donald Frank

Kay H. Swann

Kay P. Hart Swann

Alcoa, Inc.

Keith Schmidt, Project Manager 

Remediation

Kenneth G. McKamey, Jr.

Kenny Mutchler

Kim Elaine Hunt

Larry Baker

Leon Boils

Leslie Jo Ann Owen

Lydia Schmalstieg

Bell Family Farms, Ltd.

M. and J. Bell

Margie Shelborne

Margie M. Shelburne

Martha McKamey Decou

Mary Donna Smothers

Mary Madeline O'Connor Family Exempt 

Trust

Mary Madeline O'Connor

Mary Willeen Schmidt

Floerke Family Limited Partnership, L.P.

Max M. Floerke

Mayo Toyce

Melissa Mires

Mildred M. Robinson

c/o John Robinson

Neal L. Floerke

Nikolaos T. Zafiriou

Norman Telschik

E-11
Landowners (continued)

Estate of G.H. McCann

Ola McCann

Ora Marie Floerke

P. H. Welder

Pablo Garza

Patrick Raymond

BDJ Properties, LLC

Phil Berryman

R.H. Welder Heirs, Ltd.

Rachel Randolph

Rafael Q. Garza Estate

c/o Pablo Garza Sr.

Randy Rachal

Richard Thomas

Robert Weagley Jr. and Rev. Trust

Robert F. Barlow

Roy J. Floerke

Sanford Shelburne

Portilla Ranch Holdings, Ltd.

Scott Galloway

Estate of A.H. Moore

Scott Moore

DeCou Family Partnership, Ltd.

Susan DeCou Lamb

T. Michael O'Conner

Terry Reed Smith

Thomas and Joyce Houser

Tim Pyron

Sherwin Alumina Company

Tom Ballou Legal and External 

Affairs Coordinator

Tom Russell, President and CEO

Velma Cantu

Alcoa & Reynolds

Property Tax Department

CCC Properties, Ltd.

E. H. Partnership, Ltd.

Midway Gin and Grain Co Op 

Olle Farm, Ltd.

c/o Susan M. Anderson

Port of Corpus Christi

San Patricio Municipal Water District

San Patricio Municipal Water District

E-12
Appendix F

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F-6
Appendix G

LIST OF PREPARERS AND 

REVIEWERS

LIST OF PREPARES AND REVIEWERS

This EIS was prepared by Perennial Environmental Service, LLC, a third-party contractor, under 

the direction of the FERC Staff. Representatives from the COE, Coast Guard, DOE, and DOT 

also contributed to or participated in the preparation of this document and the NEPA review 

process. The following presents the names of individuals who prepared and/or reviewed this 

Administrative Draft EIS and their area of areas of responsibility.

TABLE G-1

Prepares/Reviewers for FERC

Name Education Responsibility

Kandilarya Barakat

M.E., Environmental 

Engineering/Project Management, 

2006, University of Maryland, College 

Park

B.S., Chemical Engineering, 2003, 

University of Maryland, College Park.

Project Manager

John Peconom B.S., Biology and Management, 2000, 

University of California, Davis Deputy Project Manager

James Glaze B.S., Geology, 1975, California 

Lutheran University

Geologic Conditions, Resources, and 

Hazards

John Wisniewski B.S., Mineral Economics, 1975, The 

Pennsylvania State University Alternatives 

Joanne Wachholder

M.S., Crop and Soil 

Sciences/Environmental Toxicology, 

1997, Michigan State University

B.S., Biology, 1994, University of 

Wisconsin – Stevens Point

Wildlife and Aquatic Resources; 

Vegetation; Threatened, Endangered, 

and Other Special Status Species

Paul Friedman

M.A., 1980, History, University of 

California, Santa Barbara

B.A., 1976, Anthropology and History, 

University of California, Santa Barbara

Cultural Resources

Magdalene Suter

B.S., Environmental Systems 

Engineering, 2004, The Pennsylvania 

State University

Air Quality and Noise; Pipeline Reliability 

and Safety

Andrew Kohut

M.S., Fire Protection Engineering, 

2011, University of Maryland

B.S., Fire Protection Engineering, 

2006, University of Maryland

B.S., Mechanical Engineering, 2006, 

University of Maryland

LNG Reliability and Safety

Sentho White

M.S., Environmental Engineering, 

2001, Johns Hopkins University

B.S., Civil Engineering, 2000, Georgia 

Institute of Technology

LNG Reliability and Safety

G-1
TABLE G-2

Prepares/Reviewers for Perennial Environmental Services

Name Education Responsibility

Dennis Woods

M.S., Environmental Management, 

2006, University of Houston – Clear 

Lake

M.B.A., 2006, University of Houston 

– Clear Lake

B.S., Biology, 1997, University of 

Texas at Austin

Project Manger. Alternatives; Cumulative 

Impacts, Conclusions and 

Recommendations, Executive Summary

Leslie Yoo

M.S., Zoology, 2001, Oklahoma 

State University

B.S., Biology, 1995, Randolph 

Macon Woman’s College

Deputy Project Manager, Project 

Coordination. Executive Summary; 

Conclusions and Recommendations;

Jennifer Seinfeld B.S., Chemical Engineering, 1982, 

University of Tennessee Air Quality

Lou Corio

M.S., Meteorology, 1983, University 

of Maryland

B.S., Meteorology, 1980, Rutgers 

University – Cook College

Air Quality

Tim Simmons

Ph.D., Physics, 2003, University of 

Mississippi

M.S., Physics, 1998, University of 

Mississippi

B.S., Engineering Physics, 1996, 

University of Tennessee

Noise

Amy Williams

M.S., Wildlife Ecology, 2011, 

University of Nebraska – Lincoln

B.S., Natural Resource Sciences, 

2008, Washington State University

Geology and Soils; Aquatic Resources; 

Vegetation; Threatened, Endangered, and 

Other Special Status Species; Water 

resources; Wetlands; and Wildlife

Megan Rathwell B.S., Environmental Science, 2013, 

Texas A&M University

Land Use, Recreation, and Visual 

Resources; Socioeconomics

Abby Peyton

M.A., Archaeology, 2005, Texas 

State University

B.A., Anthropology, 2001, Baylor 

University

Cultural Resources

Jeremiah Bowling

M.S., Water Resource 

Management, 2012, Texas A&M 

University

B.S., Spatial Science, 2009, Texas 

A&M University

GIS; Graphics

G-2