Federal Energy Regulato

Office of Energy Projects Washington, DC 20426

Lake Charles Li

Final Environmen

Trunkline Gas Company, LLC, L

and Lake Charles LNG 

FERC Docket Nos. CP14-119-000

DOE Docket Nos. 11-5

FERC/EIS-0258

Cooperating Agencies:

U.S. Coast Guard

U.S. Department 

of Energy 

Final Environmental Impact Statement 

Lake Charles Liquefaction Project 

FERC/EIS-0258F

Docket Nos. 

CP14-119-000, CP14-120-000, 

and CP14-122-000 

August 

2015

U.

Wil

FEDERAL ENERGY REGULATORY COMMISSION

WASHINGTON, D.C. 20426

OFFICE OF ENERGY PROJECTS In Reply Refer To:

OEP/DG2E/Gas Branch 1

Trunkline Gas Company, LLC;

Lake Charles LNG Company, LLC; and 

Lake Charles LNG Export Company, LLC 

Docket Nos. CP14-119-000, CP14-120-000, 

and CP14-122-000

FERC/EIS-0258F

TO THE PARTY ADDRESSED:

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

has prepared a final environmental impact statement (EIS) for the Lake Charles 

Liquefaction Project, proposed by Trunkline Gas Company, LLC (Trunkline), Lake 

Charles LNG Company, LLC, and Lake Charles LNG Export Company, LLC in the 

above-referenced dockets. Trunkline requests authorization to construct, install, and 

operate new natural gas pipeline facilities; modify certain existing pipeline facilities; and 

abandon one compressor unit in the states of Arkansas, Mississippi, and Louisiana

(collectively referred to as the Non-Liquefaction Facilities). Lake Charles LNG 

Company, LLC and Lake Charles LNG Export Company, LLC (collectively referred to 

as Lake Charles LNG) request authorization to site, construct, and operate new 

liquefaction facilities adjacent to an existing liquefied natural gas (LNG) terminal located 

in Calcasieu Parish, Louisiana, and to construct and operate certain facility modifications 

at the existing LNG terminal. The new liquefaction facilities would have a design 

production capacity of 16.45 million metric tons of LNG per annum, which would 

provide an LNG export capacity equivalent to about 2 billion cubic feet per day of natural 

gas. 

Lake Charles LNG also requests authorization to abandon certain terminal 

facilities previously certificated under the Natural Gas Act (NGA) section 7; abandon 

services provided under its existing FERC Gas Tariff and Certificates of Public 

Convenience and Necessity; cancel its FERC Gas Tariff, including all rate schedules 

therein; and convert such certificated facilities and operation under NGA section 3, so 

that the entirety of the company’s facilities and operations are authorized solely under 

NGA section 3.

The final EIS assesses the potential environmental effects of construction and 

operation of the Lake Charles Liquefaction Project in accordance with the requirements 

of the National Environmental Policy Act. The FERC staff concludes that approval of 

the proposed project would have some adverse environmental impacts; however, most of 

these impacts would be reduced to less-than-significant levels with the implementation of 
- 2 -

Lake Charles LNG’s and Trunkline’s proposed mitigation and the additional measures 

recommended in the final EIS. 

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

Energy, U.S. Fish and Wildlife Service, and U.S. Department of Transportation 

participated as cooperating agencies in the preparation of the final EIS. Cooperating 

agencies have jurisdiction by law or special expertise with respect to resources potentially 

affected by a proposal and participate in the National Environmental Policy Act analysis. 

Although the cooperating agencies provided input on the conclusions and 

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

conclusions and recommendations in their respective records of decision or 

determinations for the project. 

The Lake Charles Liquefaction Project includes:

 three liquefaction trains, each with a production capacity sufficient to 

produce 5.48 million metric tons per annum of LNG for export (each train

would contain metering and gas treatment facilities, liquefaction and

refrigerant units, safety and control systems, and associated infrastructure);

 modifications and upgrades at the existing LNG terminal; 

 about 0.5 mile of 48-inch-diameter feed gas line to supply natural gas to the 

liquefaction facility from existing gas transmission pipelines;

 approximately 17.9 miles of 24- and 42-inch-diameter natural gas pipeline;

 a new compressor station with a manufacturer’s rating of 103,175 

horsepower (hp), which equates to a site-specific rating of 98,685 hp (based 

on relative humidity and elevation);

 abandonment of a 3,000-hp compressor unit, installation of a unit with a 

manufacturer’s rating of 15,900 hp and site-specific rating of 15,002-hp 

unit, and piping modifications at one existing compressor station;

 modification of station piping at three other existing compressor stations;

 five new meter stations and modifications and upgrades of five existing 

meter stations; 

 modification of certain existing pipeline facilities; and

 construction of miscellaneous auxiliary and appurtenant facilities.

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

government representatives and agencies; elected officials; environmental and public 
- 3 -

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

individuals and non-governmental organizations; newspapers and libraries in the project 

area; and parties to this proceeding. Paper copy versions of this EIS were mailed to those 

specifically requesting them; all others received a compact disk version. In addition, the 

final EIS is available for public viewing on the FERC’s website (www.ferc.gov) using 

the eLibrary link. A limited number of hardcopies 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

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(s) excluding the last three digits in the Docket Number field 

(i.e., CP14-119, CP14-120, and CP14-122). Be sure you have selected an appropriate 

date range. For assistance, please contact FERC Online Support at FercOnlineSupport

@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 www.ferc.gov/docs-filing/esubscription.asp.

TABLE OF CONTENTS

i

Trunkline Gas Company, LLC, Lake Charles LNG Company, LLC,

and Lake Charles LNG Export, LLC

Lake Charles Liquefaction Project

Final Environmental Impact Statement

Page

TABLE OF CONTENTS............................................................................................................................... i

LIST OF TABLES.....................................................................................................................................viii

LIST OF FIGURES ..................................................................................................................................... xi

LIST OF APPENDICES.............................................................................................................................xii

TECHNICAL ACRONYMS AND ABBREVIATIONS...........................................................................xiii

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

INTRODUCTION .....................................................................................................................ES-1

PROPOSED ACTION...............................................................................................................ES-2

PUBLIC INVOLVEMENT .......................................................................................................ES-2

ENVIRONMENTAL IMPACTS AND MITIGATION............................................................ES-3

ALTERNATIVES CONSIDERED .........................................................................................ES-11

CONCLUSIONS .....................................................................................................................ES-12

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

1.1 PROJECT PURPOSE AND NEED.................................................................................1-3

1.2 PURPOSE AND SCOPE OF THIS STATEMENT ........................................................1-4

1.2.1 Federal Energy Regulatory Commission............................................................1-4

1.2.2 U.S. Army Corps of Engineers...........................................................................1-5

1.2.3 U.S. Coast Guard ................................................................................................1-5

1.2.4 U.S. Department of Energy.................................................................................1-6

1.2.5 U.S. Fish and Wildlife Service ...........................................................................1-7

1.2.6 U.S. Department of Transportation.....................................................................1-8

1.3 PUBLIC REVIEW AND COMMENT............................................................................1-8

1.3.1 Pre-filing Process and Scoping ...........................................................................1-8

1.3.2 Public Review of the Draft EIS ........................................................................1-12

1.3.3 Final EIS ...........................................................................................................1-12

1.4 NON-JURISDICTIONAL FACILITIES.......................................................................1-12

1.5 PERMITS, APPROVALS, AND REGULATORY REVIEWS....................................1-13

2.0 PROPOSED ACTION................................................................................................................2-1

2.1 EXISTING FACILITIES.................................................................................................2-1

2.1.1 Trunkline LNG Terminal....................................................................................2-1

2.1.2 Non-Liquefaction Facilities................................................................................2-6

2.2 PROPOSED FACILITIES...............................................................................................2-6

2.2.1 Liquefaction Facility, LNG Terminal Modifications, and Additional

Construction Workspaces...................................................................................2-6

2.2.1.1 Liquefaction Facility ...........................................................................2-6

2.2.1.2 Modifications to the Existing Trunkline LNG Terminal...................2-10

2.2.1.3 Additional Construction Workspaces................................................2-10
TABLE OF CONTENTS (cont’d)

Page

ii

2.2.2 Non-Liquefaction Facilities..............................................................................2-10

2.2.2.1 Proposed New Pipelines....................................................................2-11

2.2.2.2 Proposed Pipeline Modifications.......................................................2-11

2.2.2.3 Aboveground Facilities .....................................................................2-11

2.3 LAND REQUIREMENTS.............................................................................................2-13

2.3.1 Liquefaction Facility, LNG Terminal, and Additional Construction

Workspaces.......................................................................................................2-13

2.3.2 Non-Liquefaction Facilities..............................................................................2-13

2.3.2.1 New and Modified Pipeline Facilities...............................................2-13

2.3.2.2 Aboveground Facilities .....................................................................2-16

2.4 CONSTRUCTION SCHEDULE...................................................................................2-17

2.5 ENVIRONMENTAL COMPLIANCE..........................................................................2-17

2.5.1 Compliance Monitoring....................................................................................2-17

2.6 CONSTRUCTION PROCEDURES..............................................................................2-18

2.6.1 Liquefaction Facility and LNG Terminal Modifications..................................2-19

2.6.1.1 Site Preparation .................................................................................2-19

2.6.1.2 Marine Construction – Temporary Construction Docks ...................2-19

2.6.1.3 Facility Foundations..........................................................................2-20

2.6.1.4 Piping and Equipment Installation and Testing.................................2-20

2.6.1.5 Restoration.........................................................................................2-20

2.6.2 Non-Liquefaction Facilities..............................................................................2-21

2.6.2.1 Surveying and Easement Clearance ..................................................2-21

2.6.2.2 Clearing and Grading ........................................................................2-21

2.6.2.3 Pipe Stringing, Bending, and Welding ..............................................2-21

2.6.2.4 Trenching...........................................................................................2-25

2.6.2.5 Lowering-In and Backfilling .............................................................2-25

2.6.2.6 Hydrostatic Testing ...........................................................................2-26

2.6.2.7 Cleanup and Restoration....................................................................2-26

2.6.3 Special Construction Procedures......................................................................2-26

2.6.3.1 Road, Railroad, and Existing Pipeline Crossings..............................2-26

2.6.3.2 Wetland Crossings.............................................................................2-27

2.6.3.3 Waterbody Crossings.........................................................................2-28

2.6.3.4 Residential Areas...............................................................................2-29

2.6.3.5 Agricultural Areas.............................................................................2-29

2.6.4 Aboveground Facilities Construction Procedures ............................................2-30

2.7 OPERATION, MAINTENANCE, AND SAFETY PROCEDURES............................2-31

2.7.1 Liquefaction Facility and LNG Terminal .........................................................2-31

2.7.1.1 Spill Containment System.................................................................2-31

2.7.1.2 Hazard and Fire Detection System....................................................2-31

2.7.1.3 Firewater and High Expansion Foam System ...................................2-32

2.7.1.4 Emergency Shutdown System...........................................................2-32

2.7.2 Pipelines............................................................................................................2-32

2.7.2.1 Corrosion Protection and Detection System......................................2-33

2.7.2.2 Pipeline Emergency Response Procedures........................................2-33
TABLE OF CONTENTS (cont’d)

Page

iii

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

3.1 NO-ACTION ALTERNATIVE.......................................................................................3-2

3.2 SYSTEM ALTERNATIVES...........................................................................................3-5

3.2.1 Liquefaction Facility Alternatives ......................................................................3-5

3.2.1.1 Existing LNG Import Terminals with Planned, Proposed, or

Authorized Liquefaction Projects........................................................3-6

3.2.1.2 Approved, Proposed, and Planned Stand-Alone Liquefaction

Projects..............................................................................................3-13

3.2.2 Pipeline System Alternatives............................................................................3-26

3.2.2.1 Creole Trail Pipeline..........................................................................3-27

3.2.2.2 Gulf South Pipeline ...........................................................................3-27

3.2.2.3 Cameron Interstate Pipeline...............................................................3-28

3.3 ALTERNATIVE LIQUEFACTION FACILITY SITES...............................................3-28

3.3.1 Site Descriptions...............................................................................................3-29

3.3.2 Site Selection Analysis .....................................................................................3-31

3.4 ALTERNATIVE TERMINAL CONFIGURATIONS ..................................................3-33

3.5 ALTERNATIVE PIPELINE ROUTES.........................................................................3-33

3.5.1 Mainline Connector ..........................................................................................3-34

3.5.2 Mainline 200-3 Loop ........................................................................................3-34

3.6 ALTERNATIVE ABOVEGROUND FACILITY SITES FOR PIPELINE

EXPANSION.................................................................................................................3-35

3.6.1 Compressor Station Sites..................................................................................3-35

3.6.2 Meter Stations...................................................................................................3-37

3.7 ALTERNATIVE POWER SOURCES..........................................................................3-38

3.7.1 Liquefaction Facilities ......................................................................................3-38

3.7.2 Compressor Station 203-A................................................................................3-39

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

4.1 GEOLOGY ......................................................................................................................4-1

4.1.1 Geologic Setting .................................................................................................4-1

4.1.2 Mineral Resources..............................................................................................4-2

4.1.3 Geologic Hazards................................................................................................4-4

4.1.3.1 Seismicity ............................................................................................4-4

4.1.3.2 Landslides............................................................................................4-5

4.1.3.3 Land Subsidence and Sea Level Rise ..................................................4-6

4.1.3.4 Flooding/Storm Damage/Tsunamis.....................................................4-7

4.1.4 Design and Construction of the Project Facilities...............................................4-8

4.1.4.1 Liquefaction Facility ...........................................................................4-8

4.1.4.2 Compressor Station 203-A ..................................................................4-9

4.1.5 General Impacts and Mitigation..........................................................................4-9

4.2 SOILS ............................................................................................................................4-10

4.2.1 Existing Soil Resources....................................................................................4-10

4.2.1.1 Prime Farmland .................................................................................4-12

4.2.1.2 Erosion...............................................................................................4-13

4.2.1.3 Compaction Potential ........................................................................4-13

4.2.1.4 Revegetation Potential.......................................................................4-13

4.2.2 Soil Contamination ...........................................................................................4-13

4.2.3 General Impacts and Mitigation........................................................................4-14
TABLE OF CONTENTS (cont’d)

Page

iv

4.3 WATER RESOURCES .................................................................................................4-16

4.3.1 Groundwater Resources....................................................................................4-16

4.3.1.1 Sole Source Aquifers.........................................................................4-16

4.3.1.2 Water Supply Wells...........................................................................4-17

4.3.1.3 Contaminated Groundwater...............................................................4-18

4.3.1.4 Groundwater Impacts and Mitigation................................................4-18

4.3.2 Surface Water ...................................................................................................4-20

4.3.2.1 Existing Surface Water Resources ....................................................4-20

4.3.2.2 Surface Water Impacts and Mitigation..............................................4-23

4.4 WETLANDS .................................................................................................................4-32

4.4.1 Affected Wetlands ............................................................................................4-33

4.4.2 Wetland Impacts and Mitigation.......................................................................4-34

4.4.2.1 Liquefaction Facility .........................................................................4-34

4.4.2.2 Non-Liquefaction Facilities...............................................................4-34

4.4.3 Alternative Measures to FERC’s Procedures ...................................................4-37

4.4.3.1 Liquefaction Facility .........................................................................4-37

4.4.3.2 Non-Liquefaction Facilities...............................................................4-38

4.4.4 Compensatory Mitigation .................................................................................4-42

4.5 VEGETATION..............................................................................................................4-42

4.5.1 Existing Vegetation Resources.........................................................................4-43

4.5.1.1 Liquefaction Facility .........................................................................4-43

4.5.1.2 Non-Liquefaction Facilities...............................................................4-43

4.5.2 Construction and Operation Impacts and Mitigation........................................4-44

4.5.2.1 Liquefaction Facility .........................................................................4-44

4.5.2.2 Non-Liquefaction Facilities...............................................................4-46

4.5.3 Exotic or Invasive Plant Communities and Noxious Weeds ............................4-48

4.5.4 Vegetative Communities of Special Concern ...................................................4-49

4.5.4.1 Natural Communities of Louisiana....................................................4-49

4.5.4.2 Kisatchie National Forest ..................................................................4-50

4.6 WILDLIFE AND AQUATIC RESOURCES................................................................4-50

4.6.1 Wildlife Resources............................................................................................4-50

4.6.1.1 Existing Wildlife Habitat...................................................................4-50

4.6.1.2 Impacts and Mitigation......................................................................4-51

4.6.1.3 Unique and Sensitive Wildlife Resources.........................................4-55

4.6.2 Aquatic Resources............................................................................................4-59

4.6.2.1 Liquefaction Facility .........................................................................4-59

4.6.2.2 Non-Liquefaction Facilities...............................................................4-64

4.6.3 Essential Fish Habitat .......................................................................................4-66

4.6.3.1 Regulatory Background.....................................................................4-66

4.6.3.2 Essential Fish Habitat within the Project Area..................................4-67

4.6.3.3 Impacts and Mitigation......................................................................4-67

4.7 THREATENED, ENDANGERED, AND OTHER SPECIAL STATUS SPECIES .....4-68

4.7.1 Federally Listed Threatened and Endangered Species .....................................4-74

4.7.2 State-Listed and Special Status Species............................................................4-75
TABLE OF CONTENTS (cont’d)

Page

v

4.8 LAND USE, RECREATION, AND VISUAL RESOURCES ......................................4-75

4.8.1 Land Use...........................................................................................................4-75

4.8.1.1 Liquefaction Facility .........................................................................4-76

4.8.1.2 Non-Liquefaction Facilities...............................................................4-76

4.8.1.3 Land Use Impacts and Mitigation .....................................................4-83

4.8.2 Landowner and Easement Requirements..........................................................4-87

4.8.2.1 Liquefaction Facility .........................................................................4-87

4.8.2.2 Non-Liquefaction Facilities...............................................................4-87

4.8.3 Planned Developments .....................................................................................4-88

4.8.4 Recreation and Special Interest Areas ..............................................................4-88

4.8.4.1 Liquefaction Facility .........................................................................4-88

4.8.4.2 Non-Liquefaction Facilities...............................................................4-89

4.8.5 Hazardous Waste Sites......................................................................................4-90

4.8.6 Visual Resources...............................................................................................4-91

4.8.6.1 Liquefaction Facility .........................................................................4-91

4.8.6.2 Non-Liquefaction Facilities...............................................................4-92

4.8.7 Coastal Zone Management ...............................................................................4-94

4.9 SOCIOECONOMICS....................................................................................................4-94

4.9.1 Population.........................................................................................................4-95

4.9.1.1 Liquefaction Facility .........................................................................4-95

4.9.1.2 Non-Liquefaction Facilities...............................................................4-96

4.9.2 Economy and Employment...............................................................................4-96

4.9.2.1 Liquefaction Facility .........................................................................4-96

4.9.2.2 Non-Liquefaction Facilities...............................................................4-97

4.9.3 Local Taxes and Government Revenue ............................................................4-97

4.9.3.1 Liquefaction Facility .........................................................................4-97

4.9.3.2 Non-Liquefaction Facilities...............................................................4-98

4.9.4 Housing.............................................................................................................4-98

4.9.4.1 Liquefaction Facility .........................................................................4-99

4.9.4.2 Non-Liquefaction Facilities...............................................................4-99

4.9.5 Public Services................................................................................................4-100

4.9.5.1 Liquefaction Facility .......................................................................4-100

4.9.5.2 Non-Liquefaction Facilities.............................................................4-101

4.9.6 Transportation.................................................................................................4-101

4.9.6.1 Liquefaction Facility .......................................................................4-101

4.9.6.2 Non-Liquefaction Facilities.............................................................4-102

4.9.7 Property Values...............................................................................................4-103

4.9.7.1 Liquefaction Facility .......................................................................4-103

4.9.7.2 Non-Liquefaction Facilities.............................................................4-103

4.9.8 Environmental Justice.....................................................................................4-104

4.10 CULTURAL RESOURCES........................................................................................4-105

4.10.1 Liquefaction Facility.......................................................................................4-105

4.10.1.1 Cultural Resources Survey ..............................................................4-105

4.10.1.2 Compliance with the National Historic Preservation Act................4-106

4.10.2 Non-Liquefaction Facilities............................................................................4-106

4.10.2.1 Cultural Resources Survey ..............................................................4-106

4.10.2.2 Compliance with the National Historic Preservation Act................4-108
TABLE OF CONTENTS (cont’d)

Page

vi

4.10.3 Unanticipated Discovery Plan ........................................................................4-108

4.10.4 Native American Consultation........................................................................4-108

4.11 AIR QUALITY AND NOISE .....................................................................................4-109

4.11.1 Air Quality ......................................................................................................4-109

4.11.1.1 Regional Climate .............................................................................4-109

4.11.1.2 Existing Air Quality ........................................................................4-110

4.11.1.3 Regulatory Requirements for Air Quality .......................................4-113

4.11.1.4 Construction Air Emissions Impacts and Mitigation.......................4-125

4.11.1.5 Operational Air Emissions Impacts and Mitigation ........................4-128

4.11.2 Noise ...............................................................................................................4-134

4.11.2.1 Noise Regulations............................................................................4-135

4.11.2.2 Existing Sound Levels and Noise-Sensitive Areas..........................4-136

4.11.2.3 Construction Noise Impacts and Mitigation....................................4-141

4.11.2.4 Operational Noise Impacts and Mitigation......................................4-146

4.12 RELIABILITY AND SAFETY...................................................................................4-151

4.12.1 Regulatory Agencies.......................................................................................4-151

4.12.2 LNG Facility Hazards.....................................................................................4-152

4.12.2.1 Hazards Associated with the Proposed Equipment .........................4-153

4.12.3 Technical Review of the Facility Preliminary Engineering Design................4-160

4.12.4 LNG Facility Siting Requirements .................................................................4-172

4.12.5 LNG Facility Siting Analysis .........................................................................4-175

4.12.5.1 Impoundment Sizing .......................................................................4-175

4.12.5.2 Design Spills....................................................................................4-177

4.12.5.3 Vapor Dispersion Analysis..............................................................4-178

4.12.5.4 Overpressure Analysis.....................................................................4-188

4.12.5.5 Thermal Radiation Analysis............................................................4-191

4.12.5.6 Cascading Events.............................................................................4-194

4.12.6 Emergency Response......................................................................................4-194

4.12.7 LNG Vessel Safety .........................................................................................4-194

4.12.8 Conclusions on Facility Reliability and Safety...............................................4-195

4.12.9 Pipeline Safety Standards ...............................................................................4-195

4.12.9.1 Pipeline Accident Data ....................................................................4-200

4.12.9.2 Impacts on Public Safety.................................................................4-202

4.13 CUMULATIVE IMPACTS.........................................................................................4-203

4.13.1 Projects and Activities Considered .................................................................4-204

4.13.1.1 LNG Liquefaction and Export Projects..........................................4-215

4.13.1.2 Pipeline System Projects ................................................................4-218

4.13.1.3 Other Industrial Facilities...............................................................4-218

4.13.1.4 Utilities and Transportation Projects..............................................4-220

4.13.1.5 Commercial and Residential Developments...................................4-221

4.13.1.6 Government Activities....................................................................4-223

4.13.2 Potential Cumulative Impacts by Resource ....................................................4-224

4.13.2.1 Geologic Conditions.......................................................................4-224

4.13.2.2 Soils................................................................................................4-224

4.13.2.3 Water Resources.............................................................................4-225

4.13.2.4 Wetlands.........................................................................................4-228

4.13.2.5 Vegetation and Wildlife .................................................................4-228

4.13.2.6 Aquatic Resources..........................................................................4-230
TABLE OF CONTENTS (cont’d)

Page

vii

4.13.2.7 Threatened and Endangered Species..............................................4-230

4.13.2.8 Land Use, Recreation, and Visual Resources.................................4-231

4.13.2.9 Socioeconomics..............................................................................4-233

4.13.2.10 Cultural Resources..........................................................................4-235

4.13.2.11 Air Quality and Noise.....................................................................4-236

4.13.2.12 Safety..............................................................................................4-241

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

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

5.1.1 Geology Resources.............................................................................................5-1

5.1.2 Soils ....................................................................................................................5-2

5.1.3 Water Resources.................................................................................................5-3

5.1.4 Wetlands.............................................................................................................5-6

5.1.5 Vegetation...........................................................................................................5-7

5.1.6 Wildlife and Aquatic Resources .........................................................................5-8

5.1.7 Threatened, Endangered, and Other Special Status Species.............................5-11

5.1.8 Land Use, Recreation, and Visual Resources...................................................5-12

5.1.9 Socioeconomics................................................................................................5-15

5.1.10 Cultural Resources............................................................................................5-16

5.1.11 Air Quality and Noise .......................................................................................5-17

5.1.12 Safety ................................................................................................................5-19

5.1.13 Cumulative Impacts..........................................................................................5-20

5.1.14 Alternatives.......................................................................................................5-22

5.2 FERC STAFF’S RECOMMENDED MITIGATION....................................................5-25
LIST OF TABLES

Number Title Page

viii

Table 1.3-1 Key Environmental Concerns Identified During the Scoping Process....................1-10

Table 1.3-2 Issues Identified and Comments Received That Are Outside the Scope of the

EIS Process..............................................................................................................1-11

Table 1.5-1 Major Permits, Approvals, and Consultations for the Lake Charles Liquefaction

Project......................................................................................................................1-14

Table 2.3-1 Land and Open Water Requirements for the Proposed Lake Charles

Liquefaction Project ................................................................................................2-14

Table 3.2.1-1 Existing LNG Import Terminals with Planned, Proposed, or Approved Liquefaction 

Projects Along the Gulf Coast – Summary Profile as System Alternatives..............3-7

Table 3.2.1-2 Stand-Alone Proposed and Planned Liquefaction Projects Along the Gulf Coast –

Summary Profile as System Alternatives................................................................3-15

Table 3.6.1-1 Site Alternatives Comparison for Compressor Station 203-A for the Lake Charles 

Liquefaction Project ................................................................................................3-37

Table 4.1.1-1 Geologic Formations Impacted by the Lake Charles Liquefaction Project...............4-3

Table 4.2.1-1 Characteristics of Soils in the Lake Charles Liquefaction Project Area .................4-11

Table 4.3.1-1 Water Wells Within 150 Feet of the Lake Charles Liquefaction Project................4-17

Table 4.3.2-1 Surface Waters Affected by the Lake Charles Liquefaction Project.......................4-22

Table 4.3.2-2 Waterbodies Proposed to be Crossed Using the Horizontal Directional

Drill Method............................................................................................................4-29

Table 4.3.2-3 Surface Water Requirements Associated with Proposed Horizontal Directional Drill

Operations ...............................................................................................................4-29

Table 4.3.2-4 Surface Water Requirements Associated with Hydrostatic Testing the Proposed

Non-Liquefaction Facilities.....................................................................................4-31

Table 4.4.2-1 Wetlands Affected by Construction and Operation of the Liquefaction Facility....4-34

Table 4.4.2-2 Wetlands Affected by Construction and Operation of the Non-Liquefaction

Facilities..................................................................................................................4-35

Table 4.4.3-1 Proposed Locations of Additional Temporary Workspace or Aboveground Facilities 

Within Wetlands for the Non-Liquefaction Facilities Associated With the Lake 

Charles Liquefaction Project...................................................................................4-40

Table 4.5.2-1 Vegetation Communities Affected by the Lake Charles Liquefaction Project .......4-45

Table 4.6.2-1 Representative Fish Species Potentially Occurring in the Vicinity of the Lake

Charles Liquefaction Project...................................................................................4-60

Table 4.7-1 Federally and State-Listed Species Potentially Occurring in the Vicinity of the

Lake Charles Liquefaction Project..........................................................................4-69

Table 4.8.1-1 Land Use Types and Acres Affected by Construction and Operation of the Lake 

Charles Liquefaction Project...................................................................................4-77

Table 4.8.1-2 New Permanent Access Roads Associated with the Lake Charles Liquefaction 

Project......................................................................................................................4-82

Table 4.9.1-1 Existing Socioeconomic Conditions in the Project Area ........................................4-95

Table 4.9.3-1 Estimated Property Taxes (Year 1 In-Service)........................................................4-98

Table 4.9.4-1 Housing Characteristics in the Project Area............................................................4-98

Table 4.9.5-1 Public Services in the Project Area .......................................................................4-100

Table 4.9.8-1 Demographics in the Lake Charles Liquefaction Project Area .............................4-104

Table 4.11.1-1 National Ambient Air Quality Standards..............................................................4-111

Table 4.11.1-2 Ambient Air Quality Concentrations for Areas Near the Lake Charles

Liquefaction Project ..............................................................................................4-113

Table 4.11.1-3 Major Stationary Source/Major Modification Emission Thresholds ....................4-114
TABLES (cont’d)

Number Title Page

ix

Table 4.11.1-4 Prevention of Significant Deterioration Applicability Analysis for the

Liquefaction Facility at the Existing LNG Terminal ............................................4-116

Table 4.11.1-5 Best Available Control Technology Analysis Summary for Criteria Pollutants

for the Lake Charles Liquefaction Project Liquefaction Facility..........................4-117

Table 4.11.1-6 Best Available Control Technology Analysis Summary for Greenhouse Gas 

Pollutants...............................................................................................................4-118

Table 4.11.1-7 Liquefaction Facility Construction Emissions ......................................................4-125

Table 4.11.1-8 Compressor Station 203-A Construction Emissions (2017–2018)........................4-126

Table 4.11.1-9 Longville Station Construction Emissions (2017–2018) ......................................4-126

Table 4.11.1-10 Mainline Connector Pipeline Construction Emissions (2017–2018) ....................4-127

Table 4.11.1-11 Mainline 200-3 Loop Pipeline Construction Emissions (2017–2018)..................4-127

Table 4.11.1-12 Liquefaction Facility Summary of Emissions.......................................................4-128

Table 4.11.1-13 Applicable PSD Increment and NAAQS Air Quality Levels................................4-129

Table 4.11.1-14 Significance Modeling Analysis Results...............................................................4-129

Table 4.11.1-15 NAAQS Modeling Analysis Results.....................................................................4-130

Table 4.11.1-16 PM2.5 24-hour PSD Increment Analysis Results ...................................................4-131

Table 4.11.1-17 Compressor Station 203-A Operational Emissions Summary ..............................4-132

Table 4.11.1-18 Compressor Station 203-A AERSCREEN Modeling Results...............................4-132

Table 4.11.1-19 Longville Compressor Station Operational Emissions Summary .........................4-133

Table 4.11.1-20 Longville Compressor Station Modifications AERSCREEN Modeling

Results...................................................................................................................4-133

Table 4.11.2-1 Sound Levels and Relative Loudness....................................................................4-135

Table 4.11.2-2 Ambient Noise Study Results for the Lake Charles Liquefaction Facility ...........4-136

Table 4.11.2-3 Ambient Noise Study Results for Compressor Station 203-A ..............................4-138

Table 4.11.2-4 Ambient Noise Study Results for the Longville Compressor Station ...................4-138

Table 4.11.2-5 Construction Equipment Noise Summary for the Lake Charles Liquefaction

Facility...................................................................................................................4-141

Table 4.11.2-6 Noise-Generating Construction Equipment for Compressor Station 203-A.........4-142

Table 4.11.2-7 Noise-Generating Construction Equipment for the Longville Compressor

Station....................................................................................................................4-143

Table 4.11.2-8 HDD Noise Quality Analysis for the Lake Charles Liquefaction Project.............4-145

Table 4.11.2-9 Estimated Noise Levels at Noise Sensitive Areas During Operation of the

Lake Charles Liquefaction Facility .......................................................................4-146

Table 4.11.2-10 Estimated Noise Levels at Noise Sensitive Areas During Operation of

Compressor Station 203-A ....................................................................................4-148

Table 4.11.2-11 Estimated Noise Levels at Noise Sensitive Areas During Operation of the

Longville Compressor Station...............................................................................4-150

Table 4.12.2-1 Toxicity Levels of Various Material Components................................................4-157

Table 4.12.2-2 Flammable Properties............................................................................................4-158

Table 4.12.3-1 Lake Charles LNG Responses Indicating Corrections or Modifications to the

FEED Design.........................................................................................................4-164

Table 4.12.5-1 Impoundment Area Sizing.....................................................................................4-176

Table 4.12.5-2 LNG Design Spills................................................................................................4-181

Table 4.12.5-3 Other Hazardous Fluid Design Spills....................................................................4-187

Table 4.12.5-4 Vapor Dispersion Scenarios from MRL, NGL, Refrigerant, and Condensate

Releases.................................................................................................................4-187

Table 4.12.5-5 Distance (in feet) to the 1⁄2-AEGL 1 ......................................................................4-188
TABLES (cont’d)

Number Title Page

x

Table 4.12.5-6 Thermal Radiation Exclusion Zone for Impoundment Basins..............................4-192

Table 4.12.8-1 Natural Gas Transmission Pipeline Significant Incidents by Cause

(1994 to 2013).......................................................................................................4-201

Table 4.12.8-2 Outside Force Incidents by Cause (1994 to 2013) ................................................4-201

Table 4.12.8-3 Annual Average Injuries and Fatalities – Natural Gas Transmission Pipelines

(2009 to 2013).......................................................................................................4-202

Table 4.12.8-4 Nationwide Accidental Deaths..............................................................................4-203

Table 4.13.1-1 Reasonably Foreseeable Activities and Projects Considered in the Cumulative

Impact Analysis.....................................................................................................4-205

Table 4.13.2-1 Total Support Vessel Emissions............................................................................4-237
LIST OF FIGURES

Number Title Page

xi

Figure 2-1 Project Location Map ................................................................................................2-2

Figure 2-2 Proposed Liquefaction Facility, Existing LNG Terminal, and Additional

Construction Workspace Areas.................................................................................2-3

Figure 2-3a Mainline Connector and Compressor Station 203-A ................................................2-4

Figure 2-3b Mainline 200-3 Loop.................................................................................................2-5

Figure 2.2.1-1 Proposed Liquefaction Facility Layout .....................................................................2-8

Figure 2.6.2-1 Typical Pipeline Construction Sequence.................................................................2-22

Figure 2.6.2-2 Typical Right-of-Way Configuration for the Mainline Connector Pipeline ...........2-23

Figure 2.6.2-3 Typical Right-of-Way Configuration for the Mainline 200-3 Loop Pipeline .........2-24

Figure 3.3.1-1 Alternative Liquefaction Facility Sites....................................................................3-30

Figure 3.6.1-1 Alternative Compressor Station 203-A Sites ..........................................................3-36

Figure 4.3.2-1 Waterways in the Vicinity of the Liquefaction Facility ..........................................4-21

Figure 4.11.2-1 Liquefaction Facility Noise Sensitive Areas.........................................................4-137

Figure 4.11.2-2 Compressor Station 203-A Noise Sensitive Areas................................................4-139

Figure 4.11.2-3 Longville Compressor Station Noise Sensitive Areas...........................................4-140

Figure 4.12.5-1 Vapor Fences at Lake Charles LNG’s Facility......................................................4-182

Figure 4.12.5-2 LNG Release From a Guillotine Rupture of the In-Tank Pump Header...............4-183

Figure 4.12.5-3 Jetting and Flashing Scenario From the In-tank Pump Header.............................4-183

Figure 4.12.5-4 Release From LNG Product Pump Header at the Liquefaction Area....................4-184

Figure 4.12.5-5 Release From the LNG Rundown Lines ...............................................................4-185

Figure 4.12.5-6 Release From the LNG Rundown Header at the LNG Storage Tank Area...........4-186

Figure 4.12.5-7 Propane Overpressure Scenario at Train 1 ............................................................4-190

Figure 4.12.5-8 Propane Overpressure Scenario at Train 3 ............................................................4-191

Figure 4.12.5-9 Thermal Radiation Zones from the Proposed Impoundment Sumps ....................4-193

Figure 4.12.5-10 Thermal Radiation Zones From the Condensate Containment .............................4-193

Figure 4.13.1-1 Lake Charles Area Projects...................................................................................4-213
LIST OF APPENDICES

xii

Appendix A Distribution List

Appendix B Non-Jurisdictional Facilities Maps

Appendix C Proposed Project Facilities Maps

Appendix D Draft Horizontal Directional Drill Plan and Profile Drawings, and Horizontal 

Directional Drill Contingency Plan

Appendix E Plan for Unanticipated Discovery of Contaminated Soils or Groundwater

Appendix F Waterbodies Affected by the Lake Charles Liquefaction Project

Appendix G Wetlands Affected by the Lake Charles Liquefaction Project

Appendix H Birds of Conservation Concern Likely to Occur in the Project Area

Appendix I Access Roads Identified for the Lake Charles Liquefaction Project

Appendix J References and Contacts

Appendix K List of Preparers

Appendix L Responses to Comments on the Draft Environmental Impact Statement

Appendix M Index
TECHNICAL ACRONYMS AND ABBREVIATIONS

xiii

AAE Approval of Emissions

ACHP Advisory Council on Historic Preservation

ACW additional construction workspace

AEGL Acute Exposure Guideline Level

Alturas Alturas LLC

AMSL above mean sea level

Annova Annova LNG Common Infrastructure, LLC, Annova LNG Brownsville 

A, LLC, Annova LNG Brownsville B, LLC, and Annova LNG 

Brownsville C, LLC

AOI area of impact

API American Petroleum Institute

AQCR air quality control region

ASCE American Society of Civil Engineers 

ASME American Society of Mechanical Engineers

ATWS additional temporary workspace

BA Biological Assessment

BACT Best Available Control Technology

Barca Barca LNG LLC

BCC Birds of Conservation Concern

Bcf/d billion cubic feet per day

BCR Bird Conservation Region

BG LNG BG LNG Services LLC

BGEPA Bald and Golden Eagle Protection Act

BLEVE boiling-liquid expanding vapor explosion

Boardwalk Boardwalk Pipeline Partners, L.P.

CAA Clean Air Act

Cameron LNG Cameron LNG, LLC

CE FLNG CE FLNG, LLC

CEII critical energy infrastructure information

CEQ Council on Environmental Quality

Certificate Certificate of Public Convenience and Necessity

CFR Code of Federal Regulations

CH4 methane

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

Christi Pipeline, LP

CI ICE compression ignition internal combustion engines

CO carbon monoxide

CO2 carbon dioxide

CO2e carbon dioxide equivalent

Coast Guard U.S. Coast Guard

COE U.S. Army Corps of Engineers

Columbia Gulf Columbia Gulf Transmission, LLC 

Commission Federal Energy Regulatory Commission

Corpus Christi Corpus Christi Liquefaction, LLC

CSA Compressor Station Alternative site

CUP Coastal Use Permit

CWA Clean Water Act

CZMA Coastal Zone Management Act
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xiv

CZMP Coastal Zone Management Program

dB decibels

dBA decibels on the A-weighted scale

Delfin Delfin LNG LLC

DOD U.S. Department of Defense

DOE U.S. Department of Energy

DOT U.S. Department of Transportation

DOTD Louisiana Department of Transportation and Development

EFH essential fish habitat

EI environmental inspector

EIS environmental impact statement

ELS Excelerate Liquefaction Solutions, LLC

Entergy Entergy Gulf States Louisiana, LLC

Eos Eos LNG, LLC

EPA U.S. Environmental Protection Agency

EPAct 2005 Energy Policy Act of 2005

ERP emergency response plan

ERPG Emergency Response Planning Guidelines

ESA Endangered Species Act of 1973

ESD emergency shutdown

FAA Federal Aviation Administration

FEED front-end engineering design

FEMA Federal Emergency Management Agency

FERC Federal Energy Regulatory Commission

FGT Florida Gas Transmission Company, LLC

First Flight First Flight Holdings, LLC

FLEX FLNG Expansion and FLNG Liquefaction, LLC

FLSO floating liquefaction storage and offloading unit

FME Freeport – McMoRan Energy LLC 

FMP fishery management plans

Freeport LNG Freeport LNG Development, LP

ft3cubic feet

FTA Free Trade Agreement

FWS U.S. Fish and Wildlife Service

G2 LNG G2 LNG LLC

Gasfin Gasfin Development USA, LLC

GHG greenhouse gas

GIS geographic information systems

GMFMC Gulf of Mexico Fishery Management Council 

Golden Pass LNG Golden Pass LNG, LLC

gpm gallons per minute

GPP Golden Pass Products, LLC

Greenfield Greenfield Logistical Solutions of Louisiana LLC 

Gulf Coast Gulf Coast LNG Exports, LLC

Gulf LNG Gulf LNG Liquefaction Company, LLC

Gulf South Gulf South Pipeline Company

GWP global warming potential

H&K Hoover & Keith, Inc.
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xv

H2O water

H2S hydrogen sulfide

HAP Hazardous Air Pollutants

HAZOP hazard and operability review 

HCA high consequence area

HDD horizontal directional drill

HDD Contingency Plan Horizontal Directional Drill Contingency Plan

HFC hydrofluorocarbons

Hg mercury

hp horsepower

IEA International Energy Agency

INGAA Interstate Natural Gas Association of America

IPCC Intergovernmental Panel on Climate Change 

ISA International Society for Automation

Juniper GTL Juniper GTL, LLC

KMLP Kinder Morgan Louisiana Pipeline LLC

kV kilovolt

kW kilowatt

LAC Louisiana Administrative Code

Lake Charles LNG Lake Charles LNG Export Company, LLC and Lake Charles LNG 

Company, LLC

LCE Lake Charles Exports, LLC

LCLNG Export Meter Station Lake Charles LNG Export Meter Station

LDAR leak detection and repair

LDEQ Louisiana Department of Environmental Quality

Ldn day-night sound level

LDNR Louisiana Department of Natural Resources

LDWF Louisiana Department of Wildlife and Fisheries

Leq equivalent sound level

LFL lower flammable limit

LFS Liquefaction Facility Site

Liberty Liberty Natural Gas, LLC

Live Oak Live Oak LNG, LLC

LLNG Louisiana LNG Energy LLC

LNG liquefied natural gas

LNHP Louisiana Natural Heritage Program

LOI Letter of Intent

LOR Letter of Recommendation

LPDES Louisiana Pollutant Discharge Elimination System

LPG liquid petroleum gas

m

3

cubic meters

MACT Maximum Achievable Control Technology 

Magnolia Magnolia LNG

MAOP maximum allowable operating pressure

MARAD U.S. Maritime Administration

Marine Center Louisiana Marine Fisheries Enhancement, Research, and Science Center

MARPOL International Convention for the Prevention of Pollution from Ships

MBTA Migratory Bird Treaty Act
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xvi

MCL Maximum Contaminant Level

MDEQ Mississippi Department of Environmental Quality

MEP Midcontinent Express Pipeline

MLV mainline valve

MOU Memorandum of Understanding

MP milepost

mph miles per hour

MRL mixed refrigerant liquid

MSA Magnuson-Stevens Fishery Conservation and Management Act

MTPA million metric tons per annum

MTSA Maritime Transportation Security Act 

MW megawatt

N2O nitrous oxide

NAAQS national ambient air quality standards 

NEPA National Environmental Policy Act of 1969

NESHAP National Emissions Standards for Hazardous Air Pollutants 

NFPA National Fire Protection Association

NGA Natural Gas Act

NGL natural gas liquid

NGPL Natural Gas Pipeline Company of America

NHPA National Historic Preservation Act

NO2 nitrogen dioxide

NOA notice of availability

NOAA National Oceanic and Atmospheric Administration

NOAA Fisheries National Oceanic and Atmospheric Administration, National Marine 

Fisheries Service

NOI Notice of Intent to Prepare an Environmental Impact Statement for the 

Planned Lake Charles Liquefaction Project, Request for Comments on 

Environmental Issues, and Notice of Public Scoping Meeting

Non-Liquefaction Facilities Two new pipelines, a new compressor station, five new meter stations, 

and modifications to existing pipeline facilities, compressor stations, 

and meter stations in Louisiana, Arkansas, and Mississippi

NOx nitrogen oxide

NPDES National Pollutant Discharge Elimination System

NRCS Natural Resources Conservation Service

NRHP National Register of Historic Places

NSA noise-sensitive area

NSPS New Source Performance Standards

NSR New Source Review

NWI National Wetlands Inventory

NWR National Wildlife Refuge

OEP Office of Energy Projects

OPS Office of Pipeline Safety

OSHA Occupational Safety and Health Administration

P&ID piping and instrumentation diagrams 

PAH polycyclic aromatic hydrocarbons

Pangea Pangea LNG (North American) Holdings, LLC

Pb lead
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xvii

PCB polychlorinated biphenyl

PFC perfluorocarbons

Phase III ERP/PEIS Phase III Early Restoration Plan and Early Restoration Programmatic 

Environmental Impact Statement 

PHMSA Pipeline and Hazardous Materials Safety Administration

Plan Upland Erosion Control, Revegetation, and Maintenance Plan

PM10 particulate matter less than 10 microns in aerodynamic diameter

PM2.5 particulate matter less than 2.5 microns in aerodynamic diameter

Port Arthur Port Arthur LNG, LLC and Port Arthur Pipeline, LLC

Procedures Wetland and Waterbody Construction and Mitigation Procedures 

PSD Prevention of Significant Deterioration

psi pounds per square inch

psig pounds per square inch gauge

PSM Process Safety Management

RECAP Risk Evaluation/Corrective Action Program

Rio Bravo Rio Grande LNG, LLC and Rio Bravo Pipeline Company, LLC

RPT rapid phase transition

Sabine Pass LNG Sabine Pass LNG, LP

Sasol Sasol North America, Inc.

SCT&E LNG Southern California Telephone and Energy LNG, LLC

SEP surface emissive power

SER significant emission rate

SF6 sulfur hexafluoride

SHPO State Historic Preservation Office

SI ICE stationary spark ignition internal combustion engines

SIL significant impact levels

SIP State Implementation Plan

SO2 sulfur dioxide

SONRIS Strategic Online Natural Resources Information System Database

SOWELA Southwest Louisiana Technical Community College

SOX sulfur oxide

SPAR Spill Prevention and Response

SPCC Spill Prevention, Control, and Countermeasure

SSA sole source aquifer

SSURGO Soil Survey Geographic database

SWLA Southwest Louisiana

SWPPP Stormwater Pollution Prevention Plan

TCD temporary construction dock

TETCO Texas Eastern Gas Transmission 

Texas LNG Texas LNG Brownsville LLC

TGP Tennessee Gas Pipeline Company

tpy tons per year

Transco Transcontinental Gas Pipeline Company, LLC

Trunkline Trunkline Gas Company, LLC

UFL upper flammable material

USC United States Code

USDA U.S. Department of Agriculture

USGCRP U.S. Global Change Research Program 
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xviii

USGS U.S. Geological Survey

Venture Global Venture Global Calcasieu Pass, LLC

VFD Variable Frequency Drives

VOC volatile organic compound

Waller Point Waller Point LNG

WesPac WesPac Midstream LLC

Westlake Chemical Westlake Chemical Corporation

WSA Waterway Suitability Assessment

μPa microPascal
ES-1

EXECUTIVE SUMMARY

INTRODUCTION

On March 25, 2014, the companies then known as Trunkline LNG Export, LLC and Trunkline 

LNG Company, LLC jointly filed an application with the Federal Energy Regulatory Commission 

(Commission or FERC) pursuant to section 3(a) of the Natural Gas Act (NGA) and part 153 of the 

Commission’s regulations. On September 19, 2014, both companies amended their names to Lake 

Charles LNG Export Company, LLC and Lake Charles LNG Company, LLC, respectively. The amended 

names are used in this final environmental impact statement (EIS), and the two entities are often referred 

to collectively as “Lake Charles LNG.” 

In Docket No. CP14-120-000, Lake Charles LNG requests authorization to site, construct, and 

operate new liquefaction facilities adjacent to the existing liquefied natural gas (LNG) terminal 

(Trunkline LNG Terminal) located in Calcasieu Parish, Louisiana, and to construct and operate certain 

facility modifications at the existing LNG terminal to facilitate the storage and subsequent export of LNG. 

Additionally, Lake Charles LNG Company, LLC filed in Docket No. CP14-122-000 an application 

pursuant to sections 3 and 7(b) of the NGA for authorization to abandon certain facilities at the existing 

LNG terminal; abandon services provided under its FERC Gas Tariff and its previous Certificates of 

Public Convenience and Necessity (Certificate); cancel its FERC Gas Tariff; and convert the previously 

certificated facilities and operation under NGA section 3 so that the entirety of the company’s facilities 

and operations are authorized solely under NGA section 3.

Also on March 25, 2014, Trunkline Gas Company, LLC (Trunkline), filed an application with the 

FERC for a Certificate pursuant to sections 7(b) and 7(c) of the NGA and part 157 of the Commission’s 

regulations. In Docket No. CP14-119-000, Trunkline requests authorization to construct, install, and 

operate new natural gas pipeline, compression, meter station, and appurtenant facilities; modify certain 

existing pipeline facilities; modify station piping at four existing compressor stations; modify various 

meter stations; and abandon one existing compressor unit, all within the states of Louisiana, Arkansas, 

and Mississippi. These facilities are collectively referred to as the Non-Liquefaction Facilities; Lake 

Charles LNG’s and Trunkline’s proposed projects are collectively referred to as the Lake Charles 

Liquefaction Project. 

The purpose of the EIS is to inform 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. We1 prepared this EIS to assess the environmental impacts associated with construction and 

operation of the project as required under the National Environmental Policy Act of 1969, as amended. 

Our analysis was based on information provided by Lake Charles LNG and Trunkline, and further 

developed from data requests, field investigations, scoping, literature research, and contacts with or 

comments from federal, state, and local agencies, and individual members of the public. 

The FERC is the lead agency for the preparation of the EIS. The U.S. Army Corps of Engineers, 

U.S. Coast Guard, U.S. Department of Energy, U.S. Fish and Wildlife Service (FWS), and U.S. 

Department of Transportation (DOT) are participating in the National Environmental Policy Act review 

as cooperating agencies.

2

 

 

1

“We,” “us,” and “our” refer to the environmental staff of the FERC’s Office of Energy Projects.

2 A cooperating agency is an agency that has jurisdiction over all or part of a project area and must make a decision on a project, and/or an 

agency that provides special expertise with regard to environmental or other resources.
ES-2

PROPOSED ACTION

The Lake Charles Liquefaction Project consists of two main components: 1) the development of 

natural gas liquefaction and LNG export capabilities through construction of a new liquefaction facility 

and modifications to the existing Trunkline LNG Terminal in Calcasieu Parish, Louisiana; and 2) the 

construction of facilities necessary to provide natural gas supplies to the proposed liquefaction facility, 

including two new pipelines (Mainline Connector and Mainline 200-3 Loop), a new compressor station

(Compressor Station 203-A), five new meter stations, and modifications to existing pipeline facilities. 

The project would be able to produce 16.45 million metric tons per annum of LNG for export. Capacity 

for the proposed project is contracted by BG LNG. 

Subject to the receipt of FERC authorization and all other applicable permits, authorizations, and 

approvals, Lake Charles LNG anticipates starting construction of the liquefaction facility and 

modifications to the existing LNG terminal in 2015, and placing the first new liquefaction train into 

service in 2019. The three proposed liquefaction trains would be placed into service 6 months apart. 

Trunkline would begin construction of the proposed Non-Liquefaction Facilities in 2017 and initiate 

service in late 2018, prior to startup of the first liquefaction train. 

PUBLIC INVOLVEMENT

On April 6, 2012, the FERC began its pre-filing review of the Lake Charles Liquefaction Project 

and established pre-filing Docket No. PF12-8-000 to place information related to the project into the 

public record. The cooperating agencies agreed to conduct their environmental reviews of the project in 

conjunction with the Commission’s environmental review process.

On September 14, 2012, the FERC issued a Notice of Intent to Prepare an Environmental Impact 

Statement for the Planned Lake Charles Liquefaction Project, Request for Comments on Environmental 

Issues, and Notice of Public Scoping Meeting (NOI). This notice was sent to about 315 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 

planned project facilities. Publication of the NOI established a 30-day public comment period for the 

submission of comments, concerns, and issues related to the environmental aspects of the proposed 

project. On March 21, 2013, the FERC issued a supplemental NOI for the project to describe additional 

non-liquefaction facilities that were added after the initial NOI was issued. This notice was sent to about 

340 interested parties. Publication of the supplemental NOI established an additional 30-day public 

comment period for these newly proposed facilities.

On October 3, 2012, the FERC conducted a public scoping meeting in Sulphur, Louisiana and an 

interagency meeting in Baton Rouge, Louisiana to provide an opportunity for the public and federal, state, 

and local agencies to learn more about the project and provide comments on environmental issues to be 

addressed in the EIS. Substantive environmental issues 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 pre-filing docket 

number.

The draft EIS for the proposed project was issued for public review on April 10, 2015 and the 

notice of availability for the draft EIS was published in the Federal Register on April 16, 2015. The 

notice of availability included notice of a public comment meeting on May 7, 2015 in Sulphur, Louisiana. 

Copies of the draft EIS were sent to agencies, elected officials, media organizations, Native American 

tribes, private landowners, and other interested parties. In accordance with the Council on Environmental 

Quality’s regulations implementing the National Environmental Policy Act, a 45-day public comment 
ES-3

period was established, ending on June 1, 2015. No individuals elected to present oral comments at the 

comment meeting. The FERC received written comments from federal and state agencies and other 

interested parties. Written comments directly pertaining to the draft EIS and responses to those comments 

are provided in appendix L.

ENVIRONMENTAL IMPACTS AND MITIGATION

We evaluated the potential impacts of construction and operation of the project on geology; soils; 

water resources; wetlands; vegetation; wildlife and aquatic resources; 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 measures to minimize or avoid these impacts. Sections 5.1 and 5.2 of the EIS 

contain our conclusions and a compilation of our recommended mitigation measures, respectively. 

Construction of the project would disturb 1,516.3 acres, including extra temporary workspaces, a 

contractor yard, and access roads. During operation, 841.9 acres would be required for operation of the 

new, expanded, and modified project facilities including 439.5 acres of new permanent right-of-way or 

new aboveground facility area, and 402.4 acres of existing facilities and right-of-way. Of the remaining 

674.4 acres, 349.2 acres would be allowed to revert to preconstruction land use type. The other 

325.2 acres consist of the additional construction workspaces (ACW) that would be used during 

construction of the proposed liquefaction facility. Lake Charles LNG would clear and elevate these areas 

to create suitable workspace for the proposed construction activities. Lake Charles LNG would not retain 

the ACWs following construction, but the modified condition of this land would make it suitable for 

potential future development. Therefore, in accordance with landowner conditions, Lake Charles LNG 

would not restore the ACWs to preconstruction condition. The permanent filling of the ACWs would 

result in permanent impacts on forest, wetlands, open land, industrial/commercial land, and open water.

Construction of the liquefaction facility and modifications to the existing LNG terminal would 

result in permanent impacts on about 285.9 acres of forest, industrial/commercial land, open land, and 

open water. All affected acres would be permanently converted to industrial land. The proposed 

11.4-mile-long Mainline Connector pipeline would require greenfield construction; however, all 6.5 miles 

of the Mainline 200-3 Loop pipeline would be collocated with an existing Trunkline pipeline, and the 

permanent easement would overlap the existing easement by 25 feet. Construction of the NonLiquefaction Facilities would affect agricultural, forest, open land, industrial/commercial, open water, 

pine plantation, and residential land uses. 

Important issues identified as a result of our analyses, scoping comments, and agency 

consultations include impacts on water quality, wetlands, vegetation, wildlife and aquatic resources,

threatened and endangered species, land use, traffic and housing, air quality and noise, safety, and the 

cumulative impacts of projects in the vicinity of the proposed Lake Charles Liquefaction Project. 

Water Resources

The Industrial Canal/Turning Basin is designated as essential fish habitat and a Navigable 

Waterway under section 10 of the Rivers and Harbors Act. The primary impacts on water quality within 

this area would be from dredging and the suspension of sediments in the water column. These effects 

would be minor because they would be temporary and limited to the immediate area. Lake Charles 

LNG’s proposed use of a hydraulic dredge with a suction cutter head would also minimize turbidity and 

water quality impacts. Information in recent sampling plans prepared by Tetra Tech, Inc. on behalf of 

Alcoa indicates that sediments within the Industrial Canal/Turning Basin contain contaminants, but that 

the underlying clay is not affected. Sediment samples were collected and analyzed, and affected
ES-4

sediments were fully delineated for contamination associated with historical operations of the Reynolds’ 

Lake Charles Carbon Company (owned by Alcoa). Reynolds is in the process of dredging and disposing

of affected sediments at certain locations in the proposed project dock work area as part of a remediation 

effort approved by the Louisiana Department of Environmental Quality (LDEQ). Removal of the 

affected sediment was initiated in March 2015 and is anticipated to be completed prior to any project

construction activities. Therefore, contaminated sediments that might otherwise have been disturbed 

during project activities will have been removed by the time construction of the project begins. 

Fourteen waterbodies would be filled during construction of the liquefaction facility, and one 

waterbody would be armored and realigned. Impacts on these surface waters would be mitigated through 

implementation of Lake Charles LNG’s Compensatory Mitigation Plan. Impacts from stormwater runoff 

would not be significant because stormwater would be managed in accordance with the LDEQ and the 

U.S. Environmental Protection Agency requirements. 

Lake Charles LNG is not proposing to change the frequency or size of LNG carriers that currently

call on the existing LNG terminal. To ensure compliance with U.S. laws and regulations governing

ballast water discharges, Lake Charles LNG would review applicable documentation that the visiting 

LNG carrier’s operation is in accordance with the federal standards and practices. Therefore, we 

conclude that significant impacts on surface waters would not occur as a result of ballast water discharge.

A total of 104 waterbodies would be crossed or otherwise affected (e.g., matted or filled) by 

construction of the Non-Liquefaction Facilities. The Calcasieu River, which would be crossed as part of 

the Mainline 200-1 modifications, is designated as an Outstanding Natural Resource Water by the LDEQ, 

a Louisiana Natural and Scenic River by the Louisiana Department of Wildlife and Fisheries (LDWF), 

and a Navigable Waterway under section 10 of the Rivers and Harbors Act. None of the waterbodies 

impacted by the Non-Liquefaction Facilities are listed as National Wild and Scenic Rivers, designated as 

essential fish habitat, or contain federally or state-listed species. 

Trunkline proposes to conduct six horizontal direction drill (HDD) operations that would 

encompass 22 waterbodies, including the Calcasieu River. Use of the HDD method would avoid

disturbance of the stream beds, banks, and riparian vegetation. In the event of an inadvertent release of 

drilling mud during an HDD crossing, Trunkline would implement its HDD Contingency Plan. The 

remaining waterbodies would be crossed by the open-cut method. To minimize surface water impacts, 

Trunkline would implement the measures in the FERC’s Wetland and Waterbody Construction and 

Mitigation Procedures (Procedures) except where we found site-specific alternative measures justified.

With implementation of the HDD method, Compensatory Mitigation Plan, FERC Procedures,

project-specific plans, Lake Charles LNG’s and Trunkline’s proposed additional mitigation measures

included in the EIS, and our recommendations, we conclude that impacts on water resources would be 

adequately minimized.

Wetlands

Construction of the liquefaction facility would result in the permanent loss of 215.4 acres of 

wetlands within the liquefaction facility site and ACWs. The majority of the wetlands affected would be 

forested wetlands or forested wetland mosaics (pimple-mounds). Construction of the Non-Liquefaction 

Facilities would affect 37.9 acres of wetlands, the majority of which (35.6 acres) would be a result of 

pipeline construction. The remainder would be associated with construction or modification of six meter 

stations. About 6.5 acres of wetland would be affected during operation of the pipeline and meter 

stations, including 6.0 acres located within the permanent pipeline easement that would not be 

permanently filled or drained, and 0.5 acre that would be permanently converted to upland industrial land 
ES-5

during meter station site preparation activities. Trunkline would minimize impacts by collocating the 

Mainline 200-3 Loop and using the HDD method as described above. Additionally, Trunkline revised its 

plans for the Mainline Connector to reduce wetland impacts and reconfigured the layout of Compressor 

Station 203-A to avoid a wetland within the site. Trunkline would further reduce impacts on wetlands by 

implementing the Procedures, except where we found alternative measures are warranted. In addition, 

Lake Charles LNG and Trunkline would mitigate wetland impacts associated with construction and 

operation of the project as part of their project-specific Compensatory Mitigation Plan. We are 

recommending that Lake Charles LNG and Trunkline file a copy of the final Compensatory Mitigation 

Plan and documentation of U.S. Army Corps of Engineers approval of the plan prior to construction. 

With the implementation of the FERC Procedures, proposed mitigation measures, and our 

recommendations, we conclude that impacts on wetlands due to construction and operation of the NonLiquefaction Facilities would be minor. Construction of the liquefaction facility would result in the loss 

of a relatively large portion of the forested wetlands in the immediate area, but would be mitigated 

through the project-specific Compensatory Mitigation Plan.

Vegetation Resources

Construction and operation of the liquefaction facility (including use of the ACWs) would require 

the clearing of 568.3 acres of vegetation, resulting in the loss or conversion of 261.7 acres of forested 

uplands, 158.6 acres of forested wetlands, 56.9 acres of non-forested wetlands, and 91.1 acres of 

herbaceous upland. Impacts on herbaceous upland vegetation would be permanent; however, they would 

not be significant because similar vegetative communities occur within the surrounding area. 

Construction of the liquefaction facility would result in the unmitigated loss of 261.7 acres of upland 

forest. Additional forested communities are also located in the project vicinity; however, construction of 

the project would result in the loss of a relatively large portion of forested communities in the immediate 

area. Impacts on wetland vegetation would be mitigated to less than significant levels through the 

implementation of Lake Charles LNG’s Compensatory Mitigation Plan. 

Construction of the Non-Liquefaction Facilities would affect about 375.8 acres of vegetation, 

including agricultural vegetation, pine plantation, forested wetland, non-forested wetland, herbaceous 

upland, and upland forest. The primary impacts on vegetation from construction would be the cutting and

clearing of existing vegetation within the construction work areas. Impacts resulting from operation of 

the facilities would include conversion of some forested or scrub-shrub vegetation to herbaceous 

vegetation due to maintenance of the pipeline rights-of-way, and conversion of vegetation within new or 

expanded aboveground facilities to non-vegetated industrial land. Impacts on agricultural, scrub-shrub, 

and herbaceous vegetation within the pipeline rights-of-way and additional temporary workspaces would 

be temporary and short term because these areas would revegetate within one to two growing seasons. 

Additionally, we are recommending that Lake Charles LNG and Trunkline coordinate with the Natural 

Resources Conservation Service and LDWF to develop a project-specific noxious weed control plan. 

The project would affect two vegetation communities of special concern in Louisiana, Bayhead 

Swamp and Bottomland Hardwood Forest. Of the 4.5 acres of Bayhead Swamp located within the 

proposed pipeline easements, 2.7 acres would be permanently converted to emergent wetland to facilitate 

pipeline inspections and maintenance, and 1.8 acres would be allowed to naturally revegetate. Trunkline

would minimize impacts on Bayhead Swamp communities by using the HDD method to install the 

pipelines beneath the potential communities adjacent to Bayou Lacassine and Arceneaux Bayou. 

Bottomland Hardwood Forest communities occupy a total of 29.6 acres within the liquefaction facility 

site, along the Mainline Connector, and at three meter stations. Of this, 22.8 acres would be permanently 

converted to industrial use, 1.7 acres would be converted to emergent wetland due to routine maintenance 
ES-6

of the pipeline right-of-way, and the remaining 5.1 acres would be allowed to revegetate to pre-existing 

conditions.

To minimize impacts of the Non-Liquefaction Facilities on vegetative communities, Trunkline

would conduct much of the work within or adjacent to existing maintained rights-of-way and facility 

sites, and would construct and operate the facilities in accordance with our Upland Erosion Control, 

Revegetation, and Maintenance Plan (Plan) and Procedures. With the implementation of the proposed 

mitigation measures and our recommendations, we conclude that construction and operation of the NonLiquefaction Facilities would not have a significant impact on vegetation communities in the project area. 

Wildlife and Aquatic Resources

The greatest impact on wildlife habitat would result from the permanent conversion of forested 

land within the liquefaction facility site and ACWs. Lake Charles LNG would provide compensatory 

mitigation for permanent impacts on forested wetland that would be permanently converted to upland.

Although this and other proposed mitigation measures would lessen impacts on wildlife, we have 

determined that construction and operation of the liquefaction facility would have long-term impacts on 

wildlife species due to the loss of forested habitat.

We expect impacts due to noise, light, and human activity during operation of the liquefaction 

facility to be negligible because wildlife in the area are acclimated to similar effects from activities at the 

existing LNG terminal and other nearby industrial facilities. Birds could also be affected by flaring at the 

liquefaction facility. Startup flares would be used during the startup of each liquefaction train. Use of the 

marine and emergency flares would only occur occasionally. The FWS has not raised flaring as an issue 

of concern and we are not aware of any reported significant impacts of flaring on migratory birds in the 

project area. As a result, we conclude that the temporary flaring at the liquefaction facility would not 

have a significant impact on migratory birds passing through the area.

During construction and operation of the Non-Liquefaction Facilities, most impacts on wildlife 

would be short-term and limited to the construction period. With the implementation of our Plan and 

Procedures, and due to the fact that abundant similar habitat is available for wildlife adjacent to the 

affected areas, we conclude that construction and operation of the Non-Liquefaction Facilities would not 

have a significant impact on local wildlife populations or habitat.

The vegetative communities in the project area provide potential habitat for migratory bird 

species. According to the FWS, the liquefaction facility site is expected to provide nesting habitat for 

bird species of concern. Lake Charles LNG’s compensatory mitigation would offset some of this habitat 

loss. Additionally, the FWS recommended that no habitat alteration work be performed during the 

migratory bird nesting period. Lake Charles LNG and Trunkline have affirmed that they would not 

conduct any forest clearing between March 1 and July 31 unless approved in writing by the FWS. If 

clearing during the nesting season is necessary in non-forested areas, we are recommending that Lake 

Charles LNG and Trunkline consult with the FWS and file with the Secretary written documentation of 

FWS approval prior to construction in those areas.

The LDWF identified records of two colonial waterbird rookeries within 1 mile of the project. 

The LDWF provided guidelines for preconstruction site visits and, if warranted, distance and timing 

restrictions. The FWS recommended that Lake Charles LNG and Trunkline contact the FWS and LDWF 

if surveys identify undocumented rookeries during nesting season and provided guidelines for spatial 

buffers. No rookeries were identified within the project area during environmental field surveys 

conducted to date. We are recommending that Lake Charles LNG and Trunkline provide documentation 

that the FWS and LDWF are in agreement with Trunkline’s proposed approach for addressing colonial 
ES-7

waterbirds, including a description of the final agreed-upon mitigation measures that Trunkline would 

implement if construction of the Mainline 200-3 Loop or the Natural Gas Pipeline Company of America–

Lakeside Meter Station would occur during the colonial waterbird nesting seasons identified by the FWS 

and LDWF. With our recommendations and the implementation of the measures recommended by the 

FWS and LDWF, we conclude that impacts on migratory birds, including colonial waterbirds, would be 

avoided or sufficiently minimized.

Construction of the two temporary construction docks and berthing dock modifications would 

require dredging a 22.1-acre area in the Industrial Canal/Turning Basin, driving sheet piles, and installing 

the docks and berthing structure modifications. Potential impacts from these activities include increased 

sedimentation, turbidity, and noise levels, which could adversely affect aquatic resources. The aquatic 

resources present within the project area are likely accustomed to regular fluctuations in noise and 

turbidity levels from industrial activity and maintenance dredging within the Industrial Canal/Turning 

Basin. Lake Charles LNG’s use of a cutter head suction dredge would minimize resuspension of 

sediments. Due to the small volume of materials to be dredged (approximately 26,000 cubic yards), short 

duration of dredging activities (30 days), and limited deepening of the existing open water habitat, we 

have determined that dredging impacts on aquatic resources would be localized, temporary, and minor. 

However, to minimize potential impacts from sound waves during pile driving, we are recommending

that, prior to construction, Lake Charles LNG file a description of the proposed in-water pile installation 

process and anticipated underwater sound pressure levels. If the peak or cumulative noise levels would 

exceed the thresholds for injury to fish identified in the National Oceanic and Atmospheric 

Administration, National Marine Fisheries Service (NOAA Fisheries) interim guidelines, we are 

recommending that Lake Charles LNG file proposed measures to minimize impacts on aquatic resources 

in the vicinity of pile driving activities for our review and approval, prior to construction.

During construction of the proposed pipelines, use of the HDD method to cross several

waterbodies would avoid or minimize impacts on fisheries, fish habitat, and other aquatic resources. Use 

of the open-cut crossing method for the remaining waterbodies would result in temporary loss or 

modification of aquatic habitat and would temporarily affect water quality. However, due to the 

relatively small number of crossings, limited construction workspace and duration, and implementation of 

the proposed mitigation measures, we anticipate that construction of the pipelines would have only 

temporary, localized impacts on aquatic resources. Operation of the pipeline facilities would not affect 

aquatic resources. 

Based on the largely temporary nature of project-related impacts and NOAA Fisheries’ response 

to communications from Lake Charles LNG, we have determined that the project would not have a 

significant adverse impact on essential fish habitat. We requested in the draft EIS that NOAA Fisheries

consider the EIS as our Essential Fish Habitat Assessment. In a letter dated May 21, 2015, NOAA 

Fisheries concurred with our determination and confirmed that no further essential fish habitat

consultation is required.

Threatened and Endangered Species

Twenty-three federally listed threatened and endangered species, two species that are candidates 

for listing under the Endangered Species Act, one species proposed for listing, and designated critical 

habitat for one species may occur within the parishes and/or counties affected by the project. The FWS 

confirmed that project activities within Trunkline’s existing facilities and easements in Louisiana would 

be covered under Trunkline’s existing Blanket Clearance, which, with certain conditions, authorizes 

Trunkline to perform minor and routine pipeline construction and maintenance activities under the 

FERC’s jurisdiction within Louisiana.
ES-8

We determined that the project would have no effect on 22 of the 23 federally listed species or 

critical habitat, is not likely to cause the jeopardy of the 1 proposed species, and would not contribute to 

the trend toward federal listing for the 2 candidate species. One federally listed endangered species, the 

red-cockaded woodpecker, has the potential to be located in the Kisatchie National Forest, 0.1 mile 

southwest of the Pollock Compressor Station. The FWS concurred that by adhering to the stipulations in 

Trunkline’s Blanket Clearance for proposed work at the Pollock Compressor Station, the project is not 

likely to adversely affect the red-cockaded woodpecker. Therefore, we have determined that the project 

may affect, but is not likely to adversely affect, the red-cockaded woodpecker. However, because the 

Blanket Clearance only covers activities conducted in 2014, we are recommending that, prior to 

construction, Trunkline file an updated Blanket Clearance and/or updated documentation from the FWS 

that the previous determinations of effect are still current.

As required by section 7 of the Endangered Species Act, we requested that the FWS accept the 

information provided in the draft EIS as the Biological Assessment for the project. On July 16, 2015, the 

FWS concurred with our findings. The project would have no effect on listed species under the 

jurisdiction of NOAA Fisheries; therefore, no formal section 7 consultation between the FERC and 

NOAA Fisheries is required. 

Land Use

The new liquefaction facility would be constructed immediately adjacent to the existing LNG 

terminal. Lake Charles LNG currently leases 46 acres within the proposed liquefaction facility site from

the Lake Charles Port Authority, and plans to acquire 80 acres within the site from Alcoa. The remainder 

of the land required for the liquefaction facility and ACWs would be leased from the Lake Charles Port 

Authority. Aside from the Lake Charles Port Authority properties, no federal, state, or local agency 

owned or managed lands would be affected by the liquefaction facility. Construction activities, 

particularly at ACWs A and D, might be visible from nearby residences; therefore, we are recommending 

that Lake Charles LNG file visual screening plans prior to construction for ACWs A and D to minimize 

visual impacts on these residences. The lands necessary for construction and operation of the NonLiquefaction Facilities would be composed of both land currently owned or leased by Lake Charles LNG

or Trunkline and other private land. A residence within the liquefaction facility site has been purchased 

by Lake Charles LNG; no other residential lands would be directly affected during construction or 

operation of the liquefaction facility. No residential structures or buildings are located within 50 feet of 

any of the Non-Liquefaction Facilities. 

Construction and operation of the liquefaction facility would result in minor, temporary impacts 

on recreational boating and fishing. Construction-related dust and noise could also be a nuisance to the 

recreational users of two nearby golf courses, but these impacts would be temporary, and Lake Charles 

LNG would implement mitigation measures to minimize them. Construction of the Non-Liquefaction 

Facilities could potentially be noticeable to users of the Lacassine National Wildlife Refuge, which is 

about 0.4 mile from the Natural Gas Pipeline Company of America–Lakeside Meter Station, or the 

Kisatchie National Forest, which surround areas near the Pollock Compressor Station. However, 

construction at these locations would be temporary and would occur within or immediately adjacent to 

existing industrial facilities. We conclude that visitors to the National Wildlife Refuge or the national 

forest would not be adversely affected. 

Socioeconomics

Construction of the project would not have a significant adverse impact on local populations, 

employment, provision of community services, or property values. There would not be any 

disproportionately high or adverse environmental and human health impacts on low-income and minority 
ES-9

populations from construction or operation of the project. Construction of the project would result in 

minor positive impacts due to increases in construction jobs, payroll taxes, purchases made by the 

workforce, and expenses associated with the acquisition of material goods and equipment. Operation of 

the project would have a positive effect on the local governments’ tax revenues due to the increase in 

property taxes that would be collected. 

Construction of the liquefaction facility would increase the local population for the 5-year 

construction period. The currently available transient housing in Calcasieu Parish may not be sufficient

to accommodate the maximum peak non-resident workforce, which would result in a temporary impact

on housing availability in the project area during peak construction. Outside of the time when the 

workforce peaks, the impact on transient housing would be minor. Lake Charles LNG would require its

contractor to develop a plan for addressing worker housing and monitoring availability of housing from 

the start of construction through the workforce peak. During operation of the liquefaction facility, an 

additional 176 permanent staff would be required, which would have a minor permanent impact on 

the local housing market. Nearly all of the workers required to construct the Non-Liquefaction Facilities 

are anticipated to be local hires. Adequate housing exists to accommodate non-resident workers and

their families. Overall, construction of the proposed Non-Liquefaction Facilities would not result in 

significant impacts on transient housing in the area. Operation of the Non-Liquefaction Facilities would

require eight new permanent employees, which would have a negligible impact on the local housing 

market.

Traffic is anticipated to increase substantially during construction of the liquefaction facility due 

to worker vehicles, construction vehicles, and trucks taking materials and equipment to and from the site. 

Lake Charles LNG would consider bussing construction workers to and from the site and expects truck 

deliveries to occur during off-peak traffic period. A majority of the large deliveries are anticipated to be 

via barge, reducing the number of truck trips. To reduce potential cumulative impacts of the proposed 

project and other developments in the project area, we are recommending that Lake Charles LNG file a 

traffic management plan for our review and approval detailing specific measures that would be 

implemented to minimize impacts on traffic. Construction of the Non-Liquefaction Facilities would 

result in only minor, temporary impacts on traffic in the project area. Operation of the Non-Liquefaction

Facilities would not result in any significant impacts on traffic or roadways.

Air Quality and Noise

Air quality impacts due to construction would generally be temporary and localized, and are not 

expected to cause or contribute to a violation of applicable air quality standards. To minimize fugitive 

dust emissions, we are recommending that Lake Charles LNG and Trunkline file a Fugitive Dust Control 

Plan for our review and approval, including, as appropriate, recommended measures provided by the 

U.S. Environmental Protection Agency in its comments filed on the draft EIS. With this 

recommendation, we find that construction-related impacts on local air quality would not be significant.

Lake Charles LNG would minimize operational impacts on air quality by adhering to applicable 

federal and state regulations and installing Best Available Control Technology as described in their air

permit application and required by the air permit issued by the LDEQ on May 1, 2015. Trunkline’s

AERSCREEN model results demonstrate that the emissions from Compressor Station 203-A and from the 

modifications at the Longville Compressor Station would not significantly impact the air quality in the 

surrounding area. However, Trunkline’s AERSCREEN analysis only included the proposed 

modifications, and not the existing facilities. Therefore, we are recommending that Trunkline provide 

further analysis of the incremental increase in emissions of criteria pollutants from the modifications prior 

to construction. 
ES-10

The increases in noise levels during construction of the liquefaction facility and LNG terminal 

modifications would be intermittent, would generally occur during daylight hours, and would vary over 

the course of the 5-year construction period. The noise modeling conducted by Lake Charles LNG found 

that the estimated noise impact at the nearest noise-sensitive areas (NSA) would have a day-night sound 

level (Ldn) less than the FERC’s guideline of 55 decibels on the A-weighted scale (dBA).

The acoustical analyses Trunkline conducted for construction of Compressor Station 203-A and 

the Longville Compressor Station modifications indicate that the noise levels at the NSAs nearest to these 

compressor stations could exceed the 55-dBA Ldn threshold when equipment is operating simultaneously. 

However, construction would occur during daytime hours, would be temporary and localized, and would 

not cause a significant long-term impact on ambient noise levels at any of the identified NSAs. Trunkline

also conducted an acoustical assessment to estimate the sound contribution of the HDDs for NSAs within 

0.5 mile of each HDD entry or exit point. The results of this assessment demonstrate that HDD noise at 

the Indian Bayou Canal is estimated to exceed the FERC guidelines at eight NSAs. Trunkline would 

implement noise mitigation measures to bring HDD noise levels into compliance with the FERC 

guidelines, and we are recommending that Trunkline file in its biweekly construction status reports 

information for the Indian Bayou Canal HDD entry and exit points, including noise measurements from 

the nearest NSA, the noise mitigation that Trunkline implemented, and any additional mitigation 

measures Trunkline would implement if the initial noise measurements exceed the FERC guidelines. An 

acoustical assessment has not yet been completed for the revised Calcasieu River HDD alignment; 

therefore, we are recommending that Trunkline file an acoustical assessment for this crossing prior to 

construction. Noise associated with construction of the other pipeline facilities would be short-term and 

temporary at any one location because of the assembly-line method of pipeline construction. Because 

Trunkline would primarily limit construction to daytime hours and implement noise mitigation measures 

at HDD sites, we conclude that construction noise would not have a significant impact on landowners and 

residents.

Modeling results indicate that, with the incorporation of proposed noise mitigation measures, the 

noise from operation of the liquefaction facility would not exceed the 55-dBA Ldn threshold at any of the 

NSAs. Although not part of day-to-day operations, Lake Charles LNG would use flares during startup 

procedures and, if necessary, during emergency situations. Based on a noise assessment conducted for 

both planned flaring events and unplanned emergency flaring events, noise from certain flaring events 

would exceed the 55-dBA Ldn threshold at some or all of the NSAs. These particular types of flaring 

events are expected to occur infrequently, and with the exception of the startup flares (which could last up 

to 24 hours), are expected to be limited to about 0.5 to 2 hours in duration. To minimize impacts on local 

residents, Lake Charles LNG would post details of planned flaring events in advance on the project 

website, and landowners in the vicinity would be notified of planned flaring events by information leaflets 

delivered to their properties. Due to the infrequent occurrence of flaring, these activities would not result 

in significant noise impacts.

The modeling analysis for operation of Compressor Station 203-A indicates that with the 

incorporation of the proposed mitigation measures, operational noise at Compressor Station 203-A would 

not exceed the 55-dBA noise threshold at any of the NSAs. The noise levels from the existing equipment 

at the Longville Compressor Station, which were placed in service before the Commission adopted the 

current noise standards, are currently above an Ldn of 55 dBA at three of the four nearby NSAs. 

However, the noise contribution from the proposed compressor unit replacement at the Longville 

Compressor Station would not exceed the 55-dBA Ldn noise threshold at any of the nearby NSAs. We are 

recommending that Lake Charles LNG and Trunkline conduct post-construction noise surveys for the 

liquefaction facilities and compressor stations to ensure noise impacts resulting from the project would 

not be significant and, in the case of the Longville Compressor Station, would not increase above existing 

levels. 
ES-11

Based on the analyses conducted, mitigation measures proposed, and with our additional 

recommendations, we believe that the project would not result in significant air or noise impacts on 

residents and the surrounding communities during construction and operation of the project. 

Safety and Reliability

The proposed project facilities would be designed, constructed, operated, and maintained to meet 

or exceed the U.S. Coast Guard Safety Standards in 33 Code of Federal Regulations (CFR) Parts 105 and 

127, the DOT Minimum Federal Safety Standards in 49 CFR 192 and 193, and other applicable federal 

and state regulations. Based on our technical review of the preliminary engineering design, we conclude 

that, with the incorporation of our recommendations, the Front End Engineering Design presented by 

Lake Charles LNG would include acceptable layers of protection or safeguards to reduce the risk of a 

potentially hazardous scenario from developing into an event that could impact the off-site public.

In a September 19, 2014 letter to FERC staff, the DOT stated that it had no objection to Lake 

Charles LNG’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 liquefaction facilities. 

Additionally, on January 30, 2015, the DOT indicated that it has no objection to the use of the proposed 

vacuum insulated piping in the methodology for determining single accidental leakage sources. We 

conclude that the siting of the proposed project would not have a significant impact on public safety. In a 

March 5, 2012 letter, the U.S. Coast Guard stated that the existing Waterway Suitability Assessment and 

Letter of Recommendation are adequate because the proposed modifications for the liquefaction facilities 

would lie outside of the Marine Transfer Area and because Lake Charles LNG is not proposing to 

increase the size or frequency of LNG carrier traffic at the Trunkline LNG Terminal. Lake Charles LNG

would amend the Operations Manual, Emergency Manual, and Facility Security Plan to capture changes 

associated with the project. 

Cumulative Impacts

Our analysis of cumulative impacts includes other projects in the vicinity of the proposed Lake 

Charles Liquefaction Project that could affect the same resources as the proposed project in the same 

approximate time frame. We conclude that, for most resources, the project’s contribution to cumulative 

impacts on resources affected by the project would not be significant, or that the potential cumulative 

impacts of the Lake Charles Liquefaction Project and the other projects considered would be minor or 

insignificant. However, concurrent construction of the proposed projects and other projects in the area 

would result in increased workers in the area, which could exceed available housing and result in impacts 

on public services. Concurrent construction and operation of the project would also increase traffic, 

which could result in deficiencies in area roadway capacities. We conclude that the implementation of 

the proposed mitigation measures and our recommended mitigation measures would adequately reduce 

these impacts. 

Concurrent construction and operation of the Lake Charles Liquefaction Project and the other 

projects in the area would have a beneficial cumulative effect on revenues for the state and the local 

parishes due to expenditures for services and materials for the projects, increased expenditures by local 

workers, and expenditures by the non-local workforce and any family members accompanying the nonlocal workers. The parishes would also receive a substantial increase in property taxes from the projects. 

ALTERNATIVES CONSIDERED

We evaluated the No-Action Alternative, system alternatives for the proposed liquefaction facility 

and the proposed pipelines, alternatives sites for the liquefaction facility, alternative configurations for the 
ES-12

liquefaction facility, alternative pipeline routes, alternative aboveground facility sites for the NonLiquefaction Facilities, and alternative power sources for the liquefaction facility and Compressor Station 

203-A. While the No-Action Alternative would eliminate the short- and long-term environmental impacts 

identified in the EIS, the stated objectives of the proposed action would not be met. 

System alternatives evaluated for the liquefaction facility included 6 operating LNG import 

terminals with approved, proposed, or planned expansions to provide liquefaction capabilities and 

20 approved, proposed, or planned stand-alone liquefaction projects. All of these were eliminated from 

further consideration as viable alternatives for reasons that include incompatible timeframes and 

environmental impacts that were considered comparable to or greater than those of the proposed project. 

We evaluated three system alternatives to the proposed pipelines. All three systems were eliminated from 

further consideration because they would require construction of additional facilities to provide the 2.6 

billion cubic feet per day required by the project and/or would not provide a significant environmental 

advantage over the proposed project.

We evaluated the proposed site and four alternative sites for the liquefaction facility. We 

concluded that the currently proposed site represents the preferred site because it is sufficiently sized to 

allow optimal facility layout design and contiguity with the existing LNG terminal, avoids the need for 

off-site LNG piping, and is geographically well separated from area residences. We did not identify any 

alternative configurations for the liquefaction facility that would meet the design and configuration 

requirements of 49 CFR 193 and other industry or engineering standards while avoiding or reducing the 

impacts associated with the proposed terminal configuration. 

We did not identify any environmental concerns that indicate a need to identify and evaluate 

alternative routes for the Mainline Connector. The Mainline 200-3 Loop would be collocated with and 

overlap an existing pipeline, precluding the need for an alternatives analysis. We evaluated one

alternative to the proposed Compressor Station 203-A site. In addition to offering no environmental 

advantage, the alternative site is also in a more densely populated area. Therefore, we conclude that the 

alternative site would not be environmentally preferable to the proposed location. 

Lake Charles LNG evaluated and ruled out the use of electrically driven motors as an alternative 

to gas-fired turbines at the proposed liquefaction facility due to the excessive amount of electrical power

required. Trunkline reviewed the potential use of electric motor-driven compressors at Compressor 

Station 203-A and concluded that the electric load for this design would require a high-voltage 

transmission system for which the nearest potential interconnect is more than 2 miles away. Trunkline 

eliminated this option from initial consideration, but requested that Entergy Gulf States Louisiana, LLC

(service provider) provide a high-level feasibility of service analysis, which Trunkline filed during the 

draft EIS comment period along with a comparison of capital and operating costs for electric motordriven versus gas-fired compressor units. Taking into account the environmental impacts associated with 

additional infrastructure that would be required to support the use of electric-driven compressor units as 

well as the relative costs, we conclude that Trunkline’s proposed use of gas-fired compressor units at 

Compressor Station 203-A is reasonable and justified, and that electric compression would not provide a 

significant advantage over the proposed facility design. 

CONCLUSIONS

We determined that construction and operation of the project would result in adverse 

environmental impacts but most impacts would be reduced to less-than-significant levels. This 

determination is based on a review of the information provided by Lake Charles LNG and Trunkline and

further developed from data requests; field investigations; scoping; literature research; alternatives 
ES-13

analysis; and contacts with federal, state, and local agencies as well as Indian tribes and individual 

members of the public.

Although many factors were considered in this determination, the principal reasons are:

 Construction and operation of the proposed liquefaction facility would not result in 

increased LNG vessel traffic (i.e., LNG vessel traffic would not exceed 225 vessels per 

year considered by the U.S. Coast Guard in its waterway suitability reviews).

 About 6.5 miles (36 percent) of the proposed new pipelines would be looped and would 

overlap with the adjacent existing pipeline right-of-way, which would minimize new 

disturbance.

 Much of the work at aboveground facilities would be located at existing facilities (four 

existing compressor stations and five existing metering and regulating stations), which 

would minimize new disturbance.

 The HDD method would be used to cross 22 waterbodies, including the Calcasieu River, 

which would avoid direct impacts on these resources.

 Lake Charles LNG would mitigate wetland impacts associated with the construction and

operation of the proposed liquefaction facility in accordance with the project-specific 

Compensatory Mitigation Plan.

 The FERC staff has completed the process of complying with section 7 of the 

Endangered Species Act.

 The FERC staff has completed consultation under section 106 of the National Historic 

Preservation Act and implementing regulations at 36 CFR 800 prior and determined that 

no historic properties would be affected by the project.

 Lake Charles LNG and Trunkline would comply with all applicable air and noise 

regulatory requirements during construction and operation of the project.

 Lake Charles LNG and Trunkline would minimize impacts on environmental resources 

during construction and operation of the project by implementing, as applicable, their 

Spill Prevention and Response Plan; Spill Prevention, Control, and Countermeasure 

Plans; Plan for Unanticipated Discovery of Contaminated Soils or Groundwater; 

Horizontal Directional Drill Contingency Plan; Compensatory Mitigation Plan; 

Unanticipated Discovery Plans (for cultural resources); traffic management plan; Fugitive 

Dust Control Plan; and by implementing the FERC’s Plan and Procedures.

 An environmental inspection program would be implemented to ensure compliance with 

the mitigation measures that become conditions of the FERC authorization.

In addition, we developed 96 mitigation measures that Lake Charles LNG and Trunkline should 

implement to further reduce the environmental impacts that would otherwise result from construction and 

operation of the project. We determined that these measures are necessary to reduce adverse impacts 

associated with the project and, in part, are basing our conclusions on implementation of these measures. 

Therefore, we are recommending that these mitigation measures be attached as conditions to any 

authorization issued by the Commission. These recommended mitigation measures are presented in 

section 5.2 of the final EIS.

1-1

1.0 INTRODUCTION

On March 25, 2014, the companies then known as Trunkline LNG Export, LLC and Trunkline 

LNG Company, LLC jointly filed an application with the Federal Energy Regulatory Commission 

(Commission or FERC) pursuant to section 3(a) of the Natural Gas Act (NGA) and part 153 of the 

Commission’s regulations. On September 19, 2014, both companies amended their Certificates of 

Formation with the state of Delaware, amending their names to Lake Charles LNG Export Company, 

LLC and Lake Charles LNG Company, LLC, respectively. The amended names are used in this final 

environmental impact statement (EIS), and the two entities are often referred to collectively as “Lake 

Charles LNG.” 

In Docket No. CP14-120-000, Lake Charles LNG requests authorization to site, construct, and 

operate new liquefaction facilities adjacent to Lake Charles LNG Company, LLC’s existing liquefied 

natural gas (LNG) terminal (Trunkline LNG Terminal) located in Calcasieu Parish, Louisiana, and to 

construct and operate certain facility modifications at the existing LNG terminal to facilitate the storage 

and subsequent export of LNG. Additionally, Lake Charles LNG Company, LLC filed in Docket 

No. CP14-122-000 an application pursuant to sections 3 and 7(b) of the NGA for authorization to 

abandon certain facilities at the existing LNG terminal; abandon services provided under its FERC Gas 

Tariff and its previous certificates of public convenience and necessity; cancel its FERC Gas Tariff; and 

convert the previously certificated facilities and operation under NGA section 3 so that the entirety of the 

company’s facilities and operations are authorized solely under NGA section 3.

Also on March 25, 2014, Trunkline Gas Company, LLC (Trunkline), filed an application with the 

FERC for a Certificate of Public Convenience and Necessity (Certificate) pursuant to sections 7(b) 

and 7(c) of the NGA and Part 157 of the Commission’s regulations. In Docket No. CP14-119-000, 

Trunkline requests authorization to construct, install, and operate new natural gas pipeline, compression, 

meter station, and appurtenant facilities; modify certain existing pipeline facilities; modify station piping 

at four existing compressor stations; modify various meter stations; and abandon one existing compressor 

unit, all within the states of Louisiana, Arkansas, and Mississippi. These facilities are collectively 

referred to as the Non-Liquefaction Facilities. 

The actions and facilities proposed by Lake Charles LNG and Trunkline are referred to 

collectively in this draft EIS as the Lake Charles Liquefaction Project. As part of the Commission’s 

consideration of these applications, we1prepared this final EIS to assess the potential environmental 

impacts resulting from construction and operation of the proposed project in accordance with the 

requirements of the National Environmental Policy Act of 1969 (NEPA).

The vertical line in the margin identifies text that is new or modified in the final EIS and differs 

materially from corresponding text in the draft EIS. Changes were made to address comments from 

cooperating agencies and other stakeholders on the draft EIS; incorporate modifications to the project 

after publication of the draft EIS; update information included in the draft EIS; and incorporate

information filed by Lake Charles LNG and Trunkline in response to our recommendations in the draft 

EIS. As a result of the changes, 10 of the recommendations identified in the draft EIS are no longer 

applicable to the project and do not appear in the final EIS. Additionally, seven recommendations 

identified in the draft EIS have been substantively modified in the final EIS, and six new 

recommendations have been added in the final EIS.

 

1

“We,” “us,” and “our” refer to the environmental staff of the FERC’s Office of Energy Projects.
1-2

The existing Trunkline LNG Terminal is located in Calcasieu Parish, Louisiana about 9 miles 

southwest of the city of Lake Charles, Louisiana on the east side of the Calcasieu Ship Channel. The new

liquefaction facility, which would include three liquefaction trains with a design production capacity of 

16.45 million metric tons per annum (MTPA) of LNG, would be located on an approximately 286-acre 

site immediately north of and directly adjacent to the existing Trunkline LNG Terminal. Natural gas 

would be delivered to the Trunkline LNG Terminal via the existing Trunkline pipeline facilities that 

connect the terminal with various existing interstate pipeline systems, and/or by the proposed Trunkline

Non-Liquefaction Facilities that would interconnect with the new liquefaction facilities. More detailed 

information regarding the proposed facility components is provided in section 2.2.

Subject to the receipt of FERC authorization and all other applicable permits, authorizations, and 

approvals, Lake Charles LNG anticipates it would commence construction of the proposed liquefaction 

facility and associated modifications at the Trunkline LNG Terminal in 2015 and initiate service of the 

first liquefaction train in 2019. The three liquefaction trains would be placed into service 6 months apart. 

The existing regasification facilities at the LNG terminal would remain in place. Lake Charles 

LNG would isolate the existing revaporization equipment while constructing the liquefaction facilities

and exporting LNG. Lake Charles LNG does not anticipate resuming operation of the revaporization 

equipment until BG LNG Services LLC (BG LNG), its sole regasification service customer, requests 

resumption of regasification services. With some adjustments, the LNG facilities would be able to import 

or export gas in accordance with customer contracts and economic demand. 

The proposed Non-Liquefaction Facilities would be developed to provide increased capacity on 

the Trunkline pipeline system to meet the demand for additional transportation capacity to deliver natural 

gas to certain liquefaction facilities, including the liquefaction facility proposed by Lake Charles LNG. 

The proposed Non-Liquefaction Facilities would provide for 3,100,000 dekatherms per day of firm 

transportation service.

Subject to the receipt of a FERC Certificate and all other applicable permits, authorizations, and 

approvals, Trunkline anticipates it would begin construction of the proposed Non-Liquefaction Facilities

in 2017 and initiate service in late 2018. The Non-Liquefaction Facilities would consist of the following 

key facilities as described in more detail in section 2.0:

 construction, installation, and operation of an approximately 11.4-mile-long, 42-inchdiameter pipeline and an approximately 6.5-mile-long, 24-inch-diameter pipeline loop;

 construction and operation of a new compressor station with a manufacturer’s rating of 

103,175 horsepower (hp), which equates to a site-specific rating of 98,685 hp (based on 

relative humidity and elevation);

 abandonment of a 3,000-hp compressor unit, installation of a unit with a manufacturer’s 

rating of 15,900 hp and site-specific rating of 15,002 hp, and piping modifications at one

existing compressor station; 

 modification of station piping at three other existing compressor stations;

 construction and operation of five new meter stations and modifications and upgrades of 

five existing meter stations;

 modification of certain existing pipeline facilities; and

 construction of miscellaneous auxiliary and appurtenant facilities.
1-3

1.1 PROJECT PURPOSE AND NEED

The project purpose as stated by Lake Charles LNG and Trunkline is to transport and liquefy 

domestic natural gas into LNG for export to foreign markets. Export would occur consistent with 

authorizations from the U.S. Department of Energy (DOE), which has approved Lake Charles LNG 

Export Company, LLC to export 15 MTPA of LNG by vessel to any country with which the U.S. 

currently has, or in the future will have, a free trade agreement. Lake Charles LNG and Trunkline

identify the following project benefits: 

 help stimulate the local, regional, and national economies by allowing for the liquefaction 

of domestically produced natural gas for export to foreign countries;

 enable producers of domestic natural gas to access world markets for LNG and, thus, 

encourage further domestic natural gas production;

 help to provide a market solution to producers of LNG and further allow for development 

of domestic natural gas resources;

 stimulate the local, state, regional, and national economies through the numerous 

construction jobs required for the project, as well as a number of permanent jobs required 

to operate the facility;

 create an increase in economic activity and tax revenues;

 contribute to a rising job market as a direct result of continued domestic natural gas 

development and production;

 provide environmental benefits resulting from the use of natural gas by displacing less 

desirable fuels abroad, such as fuel oil and coal; and

 increase economic trade with foreign nations receiving LNG from the Trunkline LNG 

Terminal.

Lake Charles LNG and Trunkline state that the project is consistent with President Obama’s 

National Export Initiative signed in 2010. BG LNG is the sole holder of capacity at the Trunkline LNG 

Terminal.

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 used for importation or exportation, the FERC shall authorize the proposal unless it finds that the 

proposed facilities would not be consistent with the public interest.

Section 7(b) of the NGA specifies that no natural gas company shall abandon any portion of its 

facilities subject to the Commission’s jurisdiction without the Commission first finding that the 

abandonment will not negatively affect the present or future public convenience and necessity. 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 a proposed 

project.
1-4

1.2 PURPOSE AND SCOPE OF THIS STATEMENT

The principal purposes in preparing an EIS are to:

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

implementation of the proposed action;

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

minimize adverse effects on the human environment; 

 facilitate public involvement in identifying significant environmental impacts; and 

 identify and recommend specific mitigation measures to avoid or minimize 

environmental impacts.

This EIS focuses on the facilities that are under the FERC’s jurisdiction (that is, the new proposed

liquefaction facility and modifications to the existing LNG terminal, and the Non-Liquefaction Facilities). 

The topics addressed in this EIS include geology; soils; water use and quality; wetlands; vegetation; 

wildlife; fisheries and essential fish habitat (EFH); threatened, endangered, and special status species; 

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

reliability and safety; cumulative impacts; and alternatives. This EIS describes the affected environment 

as it currently exists, discusses the potential environmental consequences of the proposed project, and 

compares the project’s potential impact to that of alternatives. This EIS also presents our conclusions and 

recommended mitigation measures.

The Energy Policy Act of 2005 (EPAct 2005) provides that the FERC shall act as the lead agency 

for coordinating all applicable authorizations related to jurisdictional natural gas facilities and for 

purposes of complying with NEPA. The FERC, as the “lead federal agency,” is responsible for 

preparation of this EIS. This effort was undertaken with the participation and assistance of the U.S. Army 

Corps of Engineers (COE), U.S. Coast Guard (Coast Guard), DOE, U.S. Fish and Wildlife Service

(FWS), and U.S. Department of Transportation (DOT) as “cooperating agencies” under NEPA. 

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

involved with a proposal. The roles of the FERC, COE, Coast Guard, DOE, FWS, and DOT in the 

project review process are described below. The EIS provides a basis for coordinated federal decision 

making in a single document, avoiding duplication among federal agencies in the NEPA environmental 

review processes. In addition to the lead and cooperating agencies, other federal, state, and local agencies 

may use this EIS in approving or issuing permits for all or part of the proposed project. Federal, state, 

and local permits, approvals, and consultations for the proposed project are discussed in section 1.5.

1.2.1 Federal Energy Regulatory Commission

Based on its authority under the NGA, the FERC is the lead agency for preparation of this EIS in 

compliance with the requirements of NEPA, the Council on Environmental Quality’s (CEQ) regulations 

for implementing NEPA (Title 40 of the Code of Federal Regulations [CFR], Parts 1500–1508 [40 CFR 

1500-1508]), and FERC regulations implementing NEPA (18 CFR 380). 

As the lead federal agency for the Lake Charles Liquefaction Project, the FERC is required to 

comply with section 7 of the Endangered Species Act of 1973 (ESA), as amended; the Magnuson-Stevens 

Fishery Conservation and Management Act (MSA); section 106 of the National Historic Preservation Act 

(NHPA); and section 307 of the Coastal Zone Management Act (CZMA). Each of these statutes has been 

taken into account in the preparation of this EIS. The FERC will use this document to consider the 
1-5

environmental impacts that could result if it issues an authorization to Lake Charles LNG under section 

3(a) of the NGA and a Certificate to Trunkline under section 7(c) of the NGA. 

1.2.2 U.S. Army Corps of Engineers

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 United States, and section 10 of the Rivers and Harbors Act 

(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 could adopt the EIS in 

compliance with 40 CFR 1506.3 if, after an independent review of the document, it concludes that the EIS 

satisfies the COE’s comments and suggestions. The project occurs within the New Orleans and 

Vicksburg Districts of the COE Mississippi Valley Division. Staff from the New Orleans District 

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

The primary decisions to be addressed by the COE include:

 issuance of section 404 permits for wetland impacts associated with construction of the 

proposed liquefaction facility and Non-Liquefaction Facilities; and 

 issuance of a section 10 permit for construction activities within navigable waters of the 

United States.

The COE will consider information contained in this EIS to help reach decisions on these issues. 

Through the coordination of this document and its own permitting process, the COE will obtain the views 

of the public and natural resource agencies prior to reaching its 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. The COE would issue a Record of Decision 

to formally document its decisions on the proposed action, including section 404(b)(1) analyses and 

required environmental mitigation commitments.

1.2.3 U.S. Coast Guard

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 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 (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 

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). The process of preparing the LOR begins when an applicant 
1-6

submits a Letter of Intent (LOI) to the local Captain of the Port. In a letter dated March 5, 2012, the 

Coast Guard stated that the LOI requirements apply only to “new construction” that impacts the Marine 

Transfer Area, and that a new LOI would not be required for the Lake Charles Liquefaction Project 

because the proposed modifications for the liquefaction facilities would lie outside of the Marine Transfer 

Area. Additionally, because Lake Charles LNG is not proposing to increase the size or frequency of LNG 

carrier traffic at the Trunkline LNG Terminal, the most recent existing WSA remains valid and no further 

modifications would be required. However, the Coast Guard would require Lake Charles LNG to make 

applicable amendments to the existing Operations Manual, Emergency Manual, and Facility Security Plan 

to capture changes to the operations and increased facility footprint associated with the project.

1.2.4 U.S. Department of Energy

The DOE 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 proposed import or export will not be consistent 

with the public interest. On May 6, 2011, Lake Charles Exports, LLC (LCE, an affiliate of Lake Charles 

LNG) filed an application with the DOE (FE Docket No. 11-59-LNG), as subsequently amended. The 

application sought authorization for LCE to export up to 15 million metric tons per year of domestic 

natural gas as LNG, the equivalent of about 2 billion cubic feet per day (Bcf/d) of natural gas, for a 

25-year period, commencing on the earlier of the date of first export or 10 years from the date of issuance 

of the requested authorization. 

On January 10, 2013, Lake Charles LNG Export Company, LLC (then Trunkline LNG Export, 

LLC) filed a similar application with the DOE (FE Docket No. 13-04-LNG) seeking authorization to 

export up to 15 million metric tons per year2of domestic natural gas as LNG, the equivalent of about 

2 Bcf/d of natural gas, 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. The application indicated that it was 

non-additive with respect to the May 2011 LCE application, and that the applicant was not seeking to 

export additional volumes of LNG, but was seeking broader authority than that sought by LCE in order to 

expand the potential customer base. On October 10, 2014, the DOE was notified that Trunkline LNG 

Export, LLC’s name had been amended as described in section 1.0 above.

As set forth in their applications, LCE and Lake Charles LNG Export Company, LLC each seek

to export LNG by vessel from the Trunkline LNG Terminal (referred to as the Lake Charles LNG 

Terminal in the DOE applications) to any country with which the United States:

1. has, or in the future may have, a Free Trade Agreement (FTA) requiring national 

treatment for trade in natural gas (FTA countries); and

2. does not have a free trade agreement requiring national treatment for trade in natural gas 

and with which trade is not prohibited by U.S. law or policy (non-FTA countries).

Section 3(c) of the NGA, as amended by section 201 of the Energy Policy Act of 1992 (Public 

Law 102–486), requires that applications to the DOE requesting authorization of the import and export of 

natural gas, including LNG, from and to a nation with which there is in effect a free trade agreement 

requiring national treatment for trade in natural gas, be deemed consistent with the public interest and 

granted without modification or delay. Accordingly, on July 22, 2011 and March 7, 2013, the DOE 

issued orders granting authorization to LCE and Lake Charles LNG Export Company, LLC, respectively, 

 

2 Although the design production capacity of Lake Charles LNG’s proposed liquefaction facility is 16.45 MTPA of LNG, 

authorization has been secured from the DOE’s Office of Fuel Energy to export 15 MTPA, reflecting allowances for design 

margins, maintenance, and outages.
1-7

to export LNG by vessel from the Trunkline LNG Terminal to FTA countries. On March 18, 2015, the 

DOE issued an order amending the authorization holder of the March 7, 2013 order and the applicant in 

FE Docket No. 13-04-LNG to the Lake Charles LNG Export Company, LLC.

In the case of LNG export applications to non-FTA countries, section 3(a) of the NGA requires 

the DOE to conduct a public interest review and to grant the applications unless the DOE finds that the 

proposed exports will not be consistent with the public interest. Additionally, NEPA requires the DOE to 

consider the environmental impacts of its decisions on non-FTA export applications. On August 7, 2013, 

the DOE issued an order conditionally authorizing LCE (in FE Docket No. 11-59-LNG) to export LNG 

by vessel to non-FTA countries for a term of 20 years to commence on the date of first export.3 This

authorization is conditioned on the satisfactory completion of this environmental review of the proposed 

modifications to the Trunkline LNG Terminal under NEPA and on issuance by the DOE of a finding of 

no significant impact or a Record of Decision pursuant to NEPA. In accordance with 40 CFR 1506.3, 

after an independent review of the EIS, the DOE may adopt the EIS prior to issuing a Record of Decision 

on LCE’s application for authority to export LNG. The DOE will not issue a final order granting LCE’s 

application until these environmental conditions have been met. 

The separate application of Lake Charles LNG Export Company, LLC to export LNG by vessel 

to non-FTA countries is currently pending before the DOE in FE Docket No. 13-04-LNG. No conditional 

or final non-FTA authorization has been issued in that proceeding. 

1.2.5 U.S. Fish and Wildlife Service

The FWS is responsible for ensuring compliance with the ESA. Section 7 of the ESA, as 

amended, states that any project authorized, funded, or conducted by any federal agencies 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 1536(a)(2)). The FWS also reviews project plans and provides comments regarding protection 

of fish and wildlife resources under the provisions of the Fish and Wildlife Coordination Act (16 USC 

661 et seq.). The FWS is responsible for the implementation of the provisions of the Migratory Bird 

Treaty Act (MBTA) (16 USC 703) and the Bald and Golden Eagle Protection Act (BGEPA) (16 USC 

688).

Section 7 of the ESA requires identification of and consultation on aspects of any federal action 

that may have effects on federally listed species, species proposed for federal listing, and their habitat. 

The ultimate responsibility for compliance with section 7 remains with the lead federal agency (i.e., the 

FERC for this project).

As the lead federal agency for the project, the FERC consulted with the FWS pursuant to 

section 7 of the ESA to determine whether federally listed endangered or threatened species or designated 

critical habitat are found in the vicinity of the project, and to evaluate the proposed action’s potential 

effects on those species or critical habitats. The FERC coordinated with the FWS regarding other federal 

trust wildlife resources, such as migratory birds. The FWS elected to cooperate in preparing this EIS 

because it has special expertise with respect to environmental impacts associated with the project. We 

consulted with the FWS regarding the MBTA, the BGEPA, the Fish and Wildlife Coordination Act, and 

NEPA.

 

3

See Lake Charles Exports, LLC, DOE/FE Order No. 3324, FE Docket No. 11-59-LNG, Order Conditionally Granting LongTerm Multi-Contract Authorization to Export Liquefied Natural Gas by Vessel from the Lake Charles Terminal to Non-Free 

Trade Agreement Nations (Aug. 7, 2013).
1-8

1.2.6 U.S. Department of Transportation

The DOT is a cooperating agency in the development of this EIS. The DOT has authority to 

enforce safety regulations and design standards for the LNG terminal (see section 4.13.10 of this EIS), as 

well as safety regulations and standards related to the design, construction, and operation of natural gas

pipelines, under the Natural Gas Pipeline Safety Act (49 U.S.C. 1671 et seq.). In a September 19, 2014, 

letter to the FERC, the DOT Pipeline and Hazardous Materials Safety Administration stated that it had 

reviewed the criteria used by Lake Charles LNG in identifying credible leakage scenarios and establishing 

the siting for the LNG terminal to confirm compliance with 49 CFR 193, and had no objections to Lake 

Charles LNG’s methodologies.

4

 The DOT would also monitor the construction and operation of the 

natural gas facilities to determine compliance with its design and safety standards.

1.3 PUBLIC REVIEW AND COMMENT

1.3.1 Pre-filing Process and Scoping

On March 30, 2012, Lake Charles LNG and Trunkline filed a request with the FERC to use our 

pre-filing review process. At that time, the companies were in the preliminary design stage of the project 

and no formal applications had been filed with the FERC. The request to use our pre-filing review 

process was approved on April 6, 2012. Pre-filing Docket No. PF12-8-000 was established for the project 

to place information filed by Lake Charles LNG and Trunkline, and related documents issued by the 

FERC, into the public record. The pre-filing review process provides opportunities for interested 

stakeholders to become involved early in project planning, facilitates interagency cooperation, and assists 

in the identification and resolution of issues prior to a formal application being filed with the FERC.

Lake Charles LNG held a public open house for the liquefaction facility and LNG terminal 

modifications in Lake Charles, Louisiana on July 19, 2012. The FERC staff participated in the meeting to 

describe the FERC process and provide those attending with information on how to file comments with 

the FERC.

On September 14, 2012, the FERC issued a Notice of Intent to Prepare an Environmental Impact 

Statement for the Planned Lake Charles Liquefaction Project, Request for Comments on Environmental 

Issues, and Notice of Public Scoping Meeting (NOI). This notice was sent to about 315 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 

planned project facilities. Publication of the NOI established a 30-day public comment period for the 

submission of comments, concerns, and issues related to the environmental aspects of the proposed 

project.

On October 3, 2012, the FERC conducted a public scoping meeting in Sulphur, Louisiana, to 

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

environmental issues to be addressed in the EIS. No individuals elected to present oral comments at the 

scoping meeting.

We received comments from two federal agencies, the FWS and the U.S. Environmental 

Protection Agency (EPA), in response to the NOI; a statement of no comment from the U.S. National 

Park Service; and a letter from the Southwest Louisiana Economic Development Alliance in support of 

the project. Following the scoping period, letters were received from the Choctaw Nation of Oklahoma 

 

4 This letter was filed in the FERC public record under Docket Number CP14-120-000 on September 19, 2014. Accession 

Number 20140919-4005.
1-9

requesting copies of correspondence from the Mississippi State Historic Preservation Office (SHPO), and 

from the Jena Band of Choctaw Indians referring the Commission to the Coushatta Tribe of Louisiana.

Also on October 3, 2012, we held a joint interagency meeting for the project and Cameron LNG, 

LLC’s Cameron LNG Liquefaction Project and met with representatives of the COE, Coast Guard, 

Louisiana Department of Environmental Quality (LDEQ), Louisiana Department of Natural Resources 

(LDNR), Louisiana Department of Wildlife and Fisheries (LDWF), National Oceanic and Atmospheric 

Administration’s (NOAA) National Marine Fisheries Service (NOAA Fisheries), FWS, and Cameron

LNG, LLC and Lake Charles LNG’s representatives to discuss the planned projects, coordination of 

agency review, permit requirements and status, and each agency’s interest in participating in our 

environmental review as a cooperating agency.

On February 4 and 5, 2013, Trunkline held two additional open houses for the Non-Liquefaction 

Facilities in Iowa and Jennings, Louisiana, respectively. The FERC staff again participated in those 

meetings to describe the FERC process and provide those attending with information on how to file 

comments with the FERC.

On March 21, 2013, the FERC issued a supplemental NOI for the project to describe additional 

Non-Liquefaction Facilities that were added after the initial NOI was issued. This notice was sent to 

about 340 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 planned project facilities. Publication of the supplemental NOI 

established an additional 30-day public comment period for the submission of comments, concerns, and 

issues related to these newly proposed facilities. 

In total, three letters from federal agencies (FWS, EPA, and NOAA Fisheries) and one letter from 

a state agency (LDWF) were received in response to the supplemental NOI. In addition, the 

U.S. Department of Defense (DOD) Siting Clearinghouse provided a letter after the scoping period stating 

no opposition to the project; the U.S. National Park Service provided a statement of no comment; and the 

Choctaw Nation of Oklahoma acknowledged receipt and requested copies of SHPO correspondence and 

survey reports. The Commission also received a letter from the Sierra Club, which included comments on 

air quality, water impacts, wildlife impacts, traffic and safety, and impacts on local communities.

In June 2013, we mailed a project update newsletter to 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 planned project 

facilities. This update provided information on the proposed project, a list of the primary concerns that 

were raised during scoping, information on the status of the environmental review process and the next 

steps in the process, and information on how to stay informed about the progress of the review process. 

In October 2013, we mailed a project post card, which provided updated information on the status of the 

project.

Issues identified after the initial open houses and during and after the public comment process are 

summarized in table 1.3-1 along with a listing of the EIS sections that address the comments. Issues 

identified that are not considered environmental considerations or are outside the scope of the EIS process 

are summarized in table 1.3-2, and are not addressed further in this EIS.
1-10

TABLE 1.3-1

Key Environmental Concerns Identified During the Scoping Process for the Lake Charles Liquefaction Project

Issue/Specific Comment

EIS Section

Addressing Comment

General

Project purpose and need 1.1

Project design 2.0

Construction methods 2.6

Coordination of NEPA reviews with cooperating agencies 1.2

Compliance with environmental permits 1.5

Right-of-way requirements and configurations 2.3

Measures to avoid, minimize, and mitigate adverse impacts on the environment 4.0, 5.0

Alternatives

Evaluation of alternatives 3.0

Geology

Disposition of active oil/gas well at liquefaction facility site 4.1.2

Soils

Erosion and sediment control 4.2.3

Water Quality and Aquatic Resources

Storage of hazardous materials and reporting requirements/procedures 4.3.2

Floodplain identification 4.3.1

Impacts on groundwater, existing hydrology and drainage patterns, and drinking water supply

and mitigation measures

4.3

Water emission impacts on public health, wildlife, threatened and endangered species, and 

ecosystems

4.3

Tanker traffic impacts on water quality, especially in the Lake Charles area 4.3.2.2

Beneficial uses of affected water 4.3

Impacts on impaired waters, existing restoration and enhancement efforts, and mitigation 

measures to avoid further degradation

4.3.2.2

Wetlands

Impacts on wetlands and waters of the United States 4.3.2.2, 4.4.2

Wetland crossing methods 2.6.3.2

Implementation of Stormwater and Pollution Prevention Plan to protect adjacent wetlands 4.3.2.2

Vegetation

Compliance with Executive Order 13112, Invasive Species 4.5.3

Plans for invasive species control 4.5.3

Fish and Wildlife Resources

Compliance with the MBTA and BGEPA 4.6.1.3

Impacts on aquatic and terrestrial wildlife and habitat 4.6

Impacts on fishery resources 4.6.2, 4.6.3

Special Status Species

Agency coordination and requirements 4.7

Potential impacts on threatened or endangered species and suitable habitat 4.7

Land Use

Construction impacts on existing land uses 4.8.1.3

Agricultural operations 4.8.1

Impacts on aesthetics and recreational opportunities 4.8.4, 4.8.6

Socioeconomics

Employment opportunities for local contractors and laborers 4.9.2

Traffic impacts associated with the project, including off-site staging areas 4.9.6

Impacts on Environmental Justice communities 4.9.8

Impacts on homes, businesses, and local communities 4.9

Cultural Resources

Tribal consultation and impacts on tribal lands and areas of cultural importance to Native 

American tribes

4.10.4

Impacts on culturally and historically significant properties 4.10

NHPA section 106 consultation and analysis, including correspondence/consultation with

State and Tribal Historic Preservation Offices

4.10
1-11

TABLE 1.3-1 (cont’d)

Key Environmental Concerns Identified During the Scoping Process for the Lake Charles Liquefaction Project

Issue/Specific Comment

EIS Section

Addressing Comment

Air Quality

Consistency with the emissions limits and standards 4.11.1

Impacts on air quality resulting from construction and maintenance activities 4.11.1

Air emission impacts on public health, wildlife, threatened and endangered species, and 

ecosystems

4.11.1

Effects of and impacts on climate change 4.11.1, 4.13.2

Reliability and Safety

Safety during construction and operation of the project 4.12

Safety impacts of off-site staging areas 4.12

Cumulative Impacts

Analysis of cumulative impacts associated with aquatic and biological resources, including 

threatened and endangered species, and their habitat

4.13.2

Cumulative and indirect impacts resulting from operation of the project, with a focus on 

natural gas production in the United States

4.13

TABLE 1.3-2

Issues Identified and Comments Received That Are Outside the Scope of the EIS Process

Issue/Specific Comment Explanation

Resolution of negotiations 

regarding compensation for 

royalty owners of affected oil and 

gas well 

As discussed in section 4.1.2, development of the proposed liquefaction facility would involve 

the abandonment of an active oil and gas well on the proposed facility site. While the EIS

acknowledges that the royalty owners could be adversely affected by the closure of this well, 

the negotiations among Lake Charles LNG, the well owner, and the affected royalty owners are 

beyond the scope of the EIS process and fall outside of the FERC's jurisdiction. If the parties 

cannot reach agreement, royalty owners may elect to pursue the matter through the 

appropriate legal process.

Environmental and economic 

consequences of any expansion 

or change in natural gas 

production, especially in shale 

gas plays, as a result of 

increased gas exports

Production and gathering activities, and the pipelines and facilities used for these activities, are 

not regulated by the FERC, but are overseen by the affected region’s state and local agencies 

with jurisdiction over the management and extraction of the shale gas resource. Determining 

the well and gathering line locations and their environmental impact is not feasible because the 

market and gas availability at any given time would determine the source of the natural gas. 

Therefore, it is outside of the scope of this EIS.

Effects on threatened and 

endangered species throughout 

the Gulf region

Effects on threatened and endangered species in the vicinity of the project area are discussed 

in section 4.7. Impacts beyond the general project area are not anticipated and are outside the 

scope of this EIS.

Effects of hydraulically fractured 

shale gas production

The development of natural gas in shale plays by hydraulic fracturing is not the subject of this 

EIS nor is the issue directly related to the proposed project.

Effects of LNG combustion in 

end-use/importing markets

Review of the project is limited to the economic and environmental impacts of the proposal 

before the Commission; therefore, the effects of LNG combustion in end-use/importing markets 

is outside of the scope of this EIS.

Consideration of other pending 

LNG export proposals before the 

DOE and FERC, beyond the 

alternatives analysis

Cumulative impacts from all proposed export terminals, including those pending or approved 

by the DOE, would necessitate a programmatic EIS. The Lake Charles Liquefaction Project 

does not meet the requirements of federal regulations requiring programmatic EISs and so the 

question is not properly before the Commission.

Delay a decision on the 

application until comments are 

received on the DOE Office of 

Fossil Energy’s economic study 

on impacts of LNG exports.

The comment and reply comment periods closed in January and February 2013 for the DOEcommissioned study into the potential U.S. economic impacts of natural gas exports in the 

form of LNG. The 2012 study, which was completed by NERA Economic Consulting, largely 

found that “LNG exports would be beneficial to the U.S. economy under the scenarios 

modeled.” The DOE elected to prepare two additional reports of the environmental impacts of 

increased LNG exports. However, the reports are beyond the requirements of NEPA and, 

therefore, are outside of the scope of this EIS.

Impose monitoring conditions for 

economic disruptions caused by 

natural gas extraction and 

domestic increases in gas and 

electricity prices and resulting 

shifts to more polluting fuels.

Review of the project is limited to the economic and environmental impacts of the proposal 

before the Commission; therefore, economic impacts caused by natural gas extraction and 

domestic increases in gas and electricity prices and resulting shifts to more polluting fuels is 

outside of the scope of this EIS.
1-12

1.3.2 Public Review of the Draft EIS

The draft EIS for the proposed project was issued for public review on April 10, 2015 and the 

notice of availability (NOA) for the draft EIS was published in the Federal Register on April 16, 2015 

(Volume 80, Number 73, Document No. 2015-08740, pages 20489 to 20490). The NOA included notice 

of a public comment meeting on May 7, 2015 in Sulphur, Louisiana. The NOA also provided summary 

information regarding the draft EIS and requested the submission of all comments by June 1, 2015. 

Copies of the draft EIS were sent to agencies, elected officials, media organizations, Native American 

tribes, private landowners, and other interested parties. An electronic version of the draft EIS is available 

for download on the FERC website under Docket Nos. CP14-119-000, CP14-120-000, and CP14-122-000

(see eLibrary accession no. 20150410-4000). 

The public comment meeting was held in Sulphur, Louisiana on May 7, 2015 to solicit both 

verbal and written comments on the draft EIS. The meeting was held in the vicinity of the proposed 

project at the same location as the scoping meeting held on October 3, 2012. No individuals elected to 

present oral comments at the comment meeting. The FERC received seven written comments, including 

four from federal and state agencies and three from other interested parties. Written comments directly 

pertaining to the draft EIS and responses to those comments are provided in appendix L.

1.3.3 Final EIS

The final EIS is being mailed to the agencies, individuals, and organizations on the distribution 

list in appendix A. In accordance with CEQ regulations implementing NEPA, no agency decision on the 

proposed action may be made until 30 days after the EPA publishes a NOA of the final EIS in the Federal 

Register. However, CEQ regulations provide an exception to this rule when an agency decision is subject 

to a formal internal appeal process that allows other agencies or the public to make their views known. 

This is the case at FERC, where any Commission decision on the proposed action would be subject to a 

30-day rehearing period. Therefore, the FERC decision may be made and recorded concurrently with the 

publication of the final EIS. 

1.4 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 “non-jurisdictional” facilities may be integral to the 

need for the proposed facilities, or they may be merely associated as minor components of the 

jurisdictional facilities that would be constructed and operated as a result of authorization of the proposed 

facilities. The non-jurisdictional facilities associated with the project are shown on the figures in 

appendix B.

The following non-jurisdictional actions were identified in association with the proposed project:

 removal of two existing 8- and 12-inch-diameter third-party liquid pipelines that cross the 

western third of the proposed liquefaction facility site;

 relocation of the Alcoa administration building on existing Alcoa property;
1-13

 abandonment of an active oil well currently located on the liquefaction facility site;

 construction of an approximately 19-mile-long, 230 kilovolt (kV) electric transmission 

line and a new substation by Entergy Gulf States Louisiana, LLC (Entergy) to provide 

power to the liquefaction facilities; and

 electrical power supply connections to Compressor Station 203-A, the new meter 

stations, and the Texas Eastern Gas Transmission (TETCO)–Allen Meter Station.

These facilities are described in more detail below and are also addressed in our cumulative 

impacts analysis in section 4.13 of this EIS.

Removal/Relocation/Abandonment of Non-jurisdictional Facilities

Two existing 8- and 12-inch-diameter liquid pipelines owned by Boardwalk Pipeline Partners, 

L.P. (Boardwalk), which currently cross the western third of the liquefaction facility site in one corridor at 

a slight pitch from northwest to southeast, would be removed after the pipelines are decommissioned and 

isolated by Boardwalk. Boardwalk would be responsible for obtaining all required permits for the 

removal of the pipelines. The Alcoa administration building would be relocated on the existing Alcoa 

property. Lake Charles LNG is also coordinating with Jordan Oil for the plugging and abandonment of 

an active oil well currently on the liquefaction facility site. Jordan Oil would be responsible for obtaining 

all required permits for the abandonment of the oil well. 

Power Supply Connections

Entergy would construct a new approximately 19-mile-long, 230 kV electric transmission line to 

provide power to the liquefaction facilities. This transmission line would originate at Entergy’s existing 

Nelson substation, travel generally south parallel to an existing Entergy line, and connect to a new 

Entergy substation to be constructed adjacent to and north of the Graywood substation (the existing 

substation for the LNG terminal). Entergy would conduct the necessary consultations and obtain 

applicable permits and approvals for the electric transmission line, including threatened and endangered 

species consultations, cultural resources consultation, submittal of a stormwater pollution prevention plan 

and Notice of Intent to the LDEQ, and COE authorization under section 404 (CWA) and section 10 of the 

Rivers and Harbors Act, if necessary.

Power would also need to be supplied to Compressor Station 203-A, the new meter stations, and 

the TETCO–Allen Meter Station. Electric poles would be installed inside the proposed Compressor 

Station 203-A footprint, along the proposed access road, and would tie-in to existing lines along Dennison 

Road. Power poles would also be required for the new meter stations and TETCO–Allen Meter Station. 

1.5 PERMITS, APPROVALS, AND REGULATORY REVIEWS

As federal agencies, the FERC and COE are required to comply with a number of regulatory 

statutes including, but not limited to NEPA, section 7 of the ESA, the MSA, the Clean Air Act (CAA), 

the CWA, the Rivers and Harbors Act, section 106 of the NHPA, and section 307 of the CZMA. Each of 

these statutes has been taken into account in the preparation of this EIS. The major permits, approvals, 

and consultations for the Lake Charles Liquefaction Project are identified in table 1.5-1.
1-14

TABLE 1.5-1

Major Permits, Approvals, and Consultations for the Lake Charles Liquefaction Project

Agency

Permit/Approval/ 

Consultation

Status

Liquefaction Facility and Modifications 

to Existing LNG Terminala

Non-Liquefaction

Facilities

FEDERAL

FERC Certification under 

section 7(c) of the NGA

Not applicable Application filed March 25, 2014

Authorization under 

section 3(a) of the NGA

Application filed March 25, 2014 Not Applicable

Federal 

Aviation 

Administration

Notification of Proposed 

Construction Possibly 

Affecting Navigable Air 

Space

 Determination of No Hazard to Air 

Navigation for marine and start-up 

flare received May 6, 2014

 Determination of No Hazard to Air 

Navigation for emergency flare 

received August 11, 2014

Not applicable

DOEb

Application for Long Term, 

Multi-Contract 

Authorization to Export 

Natural Gas to Free Trade 

Agreement Countries

 Authorization received July 22, 2011 

for LCE

 Authorization received 

March 18, 2015 for Lake Charles 

LNG Export Company, LLC

Not applicable

Application for Long-Term, 

Multi-Contract 

Authorization to Export 

Natural Gas to Non-Free 

Trade Agreement 

Countries

 Conditional authorization received 

August 7, 2013 for LCE

 Lake Charles LNG Export Company, 

LLC application pending

Not applicable

COE Section 404, CWA Permit Application submitted

August 6, 2014

Application submitted 

August 6, 2014

Section 10, Rivers and 

Harbors Act Permit

Application submitted

August 6, 2014

Application submitted

August 6, 2014

Coast Guard Amended Letter of Intent Consultation completed

March 2012

Not applicable

NOAA 

Fisheries

Section 7 ESA 

Consultation

No further consultation required due to 

no effect finding

Not applicable

MSA Essential Fish 

Habitat Consultation

Consultation completed; concurrence 

with draft EIS finding of no significant 

adverse impact on EFH received 

May 21, 2015

Not applicable`

FWS Section 7 ESA 

Consultation

Consultation completed; concurrence 

with findings in draft EIS issued 

July 16, 2015

 No effect concurrence received

by applicant March 11, 2014 

(Arkansas)

 No effect concurrence received

by applicant March 18, 2014 

(Mississippi)

 Consultation completed; 

concurrence with findings in draft 

EIS issued July 16, 2015

Migratory Bird Treaty Act Consultation completed; FWS provided 

comments and recommendations to 

Lake Charles LNG on November 27, 

2012 and March 31, 2014 

Consultation completed; FWS 

provided comments and 

recommendations to Trunkline on 

March 11, 2013 (Louisiana),

March 11, 2014 (Mississippi Barrel 

West), and March 18, 2014 

(Mississippi Barrel East)
1-15

TABLE 1.5-1 (cont’d)

Major Permits, Approvals, and Consultations the Lake Charles Liquefaction Project

Agency

Permit/Approval/ 

Consultation

Status

Liquefaction Facility and Modifications 

to Existing LNG Terminal a

Non-Liquefaction

Facilities

STATE – LOUISIANA

LDEQ – Air 

Quality Division

Air Permits Permit issued May 1, 2015  Compressor Station 203-A permit 

application filed December 2014

 Longville Compressor Station 

permit application filed 

December 2014

LDEQ – Water 

Quality Division

Hydrostatic Test Water 

Discharge General Permit

Lake Charles LNG to submit Notices of 

Intent at least 2 days prior to individual 

discharges

Trunkline to submit Notices of intent 

at least 2 days prior to individual 

discharges

Water Quality Certification Application submitted

August 6, 2014 with COE application

Application submitted

August 6, 2014 with COE

application

LDNR – Office 

of Coastal 

Management

Coastal Zone Consistency 

– Coastal Use Permit 

(CUP) application

Not applicable  CUP application for NGPL–

Lakeside Meter Station submitted 

April 21, 2014; (Kinder Morgan–

Lake Charles Meter Station is 

exempt from coastal zone 

jurisdiction)

 Letter of No Objection received 

from Cameron Parish Police Jury 

on June 13, 2014

 Determination from LDNR stating 

no CUP required for NGPLLakeside Meter Station received 

August 27, 2014.

LDWF Threatened and 

Endangered Species 

Consultation

 Consultation submitted 

January 2013

 Reinitiated consultation for ACWs on 

March 7, 2014; no response 

provided.

 Comments on draft EIS received 

June 2, 2015

 Initial response received April 18, 

2013

 Reinitiated consultation for 

additional project facilities on 

March 7, 2014; no response 

provided.

 Comments on draft EIS received 

June 2, 2015

Louisiana Natural and 

Scenic Rivers System

Not applicable  Anticipate filing application

second half of 2016

Louisiana 

SHPOc

Section 106 Consultation, 

NHPA

Consultation completed; clearance 

letters received August 28, 2013

(liquefaction facilities) and March 17, 

2014 (ACWs)

Consultation completed; clearances 

received September 20, 2013, 

March 17, 2014, May 13, 2014

(renewal of Categorical Clearance), 

and July 23, 2015

STATE –

ARKANSAS

Arkansas 

Natural 

Heritage 

Commission

Threatened and 

Endangered Species 

Consultation

Not applicable Consultation completed for the 

Mainline 100-3 modifications March 

24, 2014

Arkansas 

SHPOc

Section 106 Consultation Not applicable Consultation completed; final 

clearance for the Mainline 100-3 

modifications received on March 31, 

2014
1-16

TABLE 1.5-1 (cont’d)

Major Permits, Approvals, and Consultations the Lake Charles Liquefaction Project

Agency

Permit/Approval/ 

Consultation

Status

Liquefaction Facility and Modifications 

to Existing LNG Terminal a

Non-Liquefaction

Facilities

STATE – MISSISSIPPI

Mississippi 

Department of 

Environmental 

Quality

Notification of proposed 

change to Shaw 

Compressor Station

Not applicable To be submitted at least 7 days 

prior to commencing modifications

Mississippi 

Department of 

Wildlife, 

Fisheries, and 

Parks

Threatened and 

Endangered Species 

Consultation

Not applicable Consultation completed; clearance 

for Shaw Compressor Station 

received on February 19, 2013 and 

clearance for Mainline 100-3 

modifications received March 29, 

2014

Mississippi 

SHPOc

Section 106 Consultation, 

NHPA

Not applicable Consultation completed; clearance 

for Shaw Compressor Station 

received on May 16, 2013 and final 

clearance for Mainline 100-3 

modifications received April 14, 

2014

____________________

a

Includes the ACWs.

b Authorization granted by the DOE is conditioned on the satisfactory completion of the environmental review of the 

proposed modifications to the Trunkline LNG Terminal under NEPA and on issuance by the DOE of a finding of no 

significant impact or a Record of Decision pursuant to NEPA.

c Consultations with Native American tribes are discussed in section 4.10.3.

To comply with section 7 of the ESA, the FERC is required to determine whether any federally 

listed or proposed endangered or threatened species or their designated critical habitat occur in the 

vicinity of the proposed project and conduct consultations with the FWS and/or NOAA Fisheries, if 

necessary. If, upon review of existing data or data provided by Lake Charles LNG and Trunkline, the 

FERC determines that these species or habitats may be affected 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 that would avoid the habitat and/or species, or would reduce potential impact to 

acceptable levels. Section 4.7 provides information on the status of this review.

The MSA, as amended by the Sustainable Fisheries Act of 1996 (Public Law 104-267), 

established procedures designed to identify, conserve, and enhance 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 

affect EFH (MSA §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)), to reduce duplication and improve efficiency. As part of this 

consultation process, the FERC staff prepared an EFH assessment. This assessment and the status of the 

EFH consultation are provided in section 4.6.3. 

Section 106 of the NHPA requires that the FERC take into account the effects of its undertakings 

on properties listed, or eligible for listing, in the National Register of Historic Places (NRHP), including 

prehistoric or historic sites, districts, buildings, structures, objects, or properties of traditional religious or 

cultural importance, and to afford the Advisory Council on Historic Preservation (ACHP) an opportunity 

to comment on the undertaking. Lake Charles LNG and Trunkline, as non-federal parties, assisted the 
1-17

FERC in meeting its obligations under section 106 by preparing the necessary information, analyses, and 

recommendations under ACHP regulations in 36 CFR 800. Section 4.10 of this EIS provides information

on the status of this review.

Lake Charles LNG and Trunkline must comply with sections 401 and 404 of the CWA. Water 

quality certification (section 401) has been delegated to the state agencies, with review by the EPA. 

Water used for hydrostatic testing that is point-source discharged into waterbodies would require a 

National Pollutant Discharge Elimination System (NPDES) permit (section 402) issued by the LDEQ. 

The COE has responsibility for determining compliance with all regulatory requirements associated with 

section 404 of the CWA. The EPA also independently reviews section 404 applications for wetland 

dredge-and-fill applications for the COE and has section 404(c) veto power for wetland permits issued by 

the COE. The section 404 permitting process regulates the discharge of dredged and fill material 

associated with the construction of pipelines across streams and in wetlands. Before an individual section 

404 permit can be issued, the CWA requires completion of a section 404(b)(1) guideline analysis. The 

FERC, in the NEPA review represented by this EIS, has analyzed technical issues required for the section 

404(b)(1) guideline analyses, including analysis of natural resources and cultural resources that would be 

affected by the project, as well as analyses of alternatives. The results of our analysis of alternatives are 

provided in section 3.0, and a summary of wetland impacts are provided in section 4.4 of this EIS. In 

addition to CWA responsibilities, the COE has jurisdiction over section 10 permits, which would be 

required for all construction activities in navigable waterways under the Rivers and Harbors Act of 1899. 

Waterbody crossing methods and impacts are summarized in section 4.3 of this EIS. Section 404 and 

section 10 permits are required for both the proposed liquefaction facility and the Non-Liquefaction 

Facilities. Lake Charles LNG and Trunkline submitted an application to the COE on August 6, 2014. 

EPAct 2005 and section 3 of the NGA require us to consult with the DOD to determine if there 

would be any impacts associated with the project on military training or activities on any military 

installations. The FERC initiated consultation with a letter to the DOD on September 27, 2012. The 

DOD responded on December 6, 2012, concluding the project would have minimal impact on the military 

operations conducted in this area and would not oppose construction of the project.

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 those states will meet their obligations and responsibilities in managing their coastal 

areas. In Louisiana, the LDNR administers the Coastal Zone Management Program (CZMP). Trunkline

initiated consultation with the LDNR on March 7, 2014 for the Natural Gas Pipeline Company of 

America (NGPL)–Lakeside and Kinder Morgan–Lake Charles Meter Stations, and submitted an 

application for a Coastal Use Permit (CUP) for the NGPL–Lakeside Meter Station on April 21, 2014. In 

an August 27, 2014 letter, the LDNR stated that the proposed work at the NGPL–Lakeside Meter Station 

would have no direct and significant impact on coastal waters and that the Kinder Morgan–Lake Charles 

Meter Station is exempt; therefore, neither facility would require a CUP. The liquefaction facility is not 

within the CZMP. The CZMP is discussed further in section 4.8.6.

The CAA was enacted by the U.S. Congress to protect the health and welfare of the public from 

the adverse effects of air pollution. The CAA is the basic federal statute governing air pollution. Federal 

and state air quality regulations established as a result of the CAA include, but are not limited to, Title V 

operating permit requirements and Prevention of Significant Deterioration (PSD) Review. The EPA is 

the federal agency responsible for regulating stationary sources of air pollutant emissions; however, the 

federal permitting process has been delegated to the LDEQ in Louisiana. The initial air permit 

application for the liquefaction facility was filed in December 2013; a revised application was filed on 

July 31, 2014 incorporating updated project information and LDEQ comments. The LDEQ issued an air 
1-18

permit for the liquefaction facility on May 1, 2015. The air permit applications for Compressor Station 

203-A and the Longville Compressor Station were filed in December 2014. No amendment to the 

existing air permit for the Shaw Compressor Station would be required; a notification letter would be 

submitted at least 7 days prior to modifying the facility. Air quality impacts that could occur as a result of 

construction and operation of the project are evaluated in section 4.11.1 of this EIS.

Lake Charles LNG and Trunkline are responsible for all permits and approvals required to 

implement the Lake Charles Liquefaction Project, regardless of whether they appear in table 1.5-1. 

However, any state or local permits issued with respect to jurisdictional facilities must be consistent with 

the conditions of any authorization the Commission may issue. Although the FERC encourages 

cooperation between applicants and state and local authorities, this does not mean that state and local 

agencies, through application of state and local laws, may prohibit or unreasonably delay the construction 

or operation of facilities approved by the FERC.

5

 

5

See, e.g., Schneidewind v. ANR Pipeline Co., 485 U.S. 293 (1988); National Fuel Gas Supply v. Public Service 

Commission, 894 F.2d 571 (2d Cir. 1990); and Iroquois Gas Transmission System, L.P., et al., 52 FERC ¶ 61,091 (1990) 

and 59 FERC ¶ 61,094 (1992).
2-1

2.0 PROPOSED ACTION

The Lake Charles Liquefaction Project consists of two main components:

1. development of natural gas liquefaction and LNG export capabilities through 

construction of a new liquefaction facility and modifications to the existing Trunkline

LNG Terminal in Calcasieu Parish, Louisiana; and

2. the construction of facilities necessary to provide natural gas supplies to the proposed 

liquefaction facility, including two new pipelines, a new compressor station, five new 

meter stations, and modifications to existing pipeline facilities, compressor stations, and 

meter stations (collectively, Non-Liquefaction Facilities).

Figure 2-1 depicts the general location of the Lake Charles Liquefaction Project. Figure 2-2

depicts the locations of the proposed liquefaction facility and existing LNG terminal. Figure 2-3 shows 

the locations of the Mainline Connector and Mainline 200-3 Loop Pipelines. Larger-scale route maps of 

the pipelines and maps of the other Non-Liquefaction Facilities are provided in appendix C.

2.1 EXISTING FACILITIES

2.1.1 Trunkline LNG Terminal

The existing Trunkline LNG Terminal is located about 9 miles southwest of Lake Charles,

Louisiana on the north side of the Industrial Canal, which is accessed via the Calcasieu Ship Channel. 

The terminal was authorized on April 29, 1977 to regasify and transport natural gas imported to the 

United States from foreign markets (Trunkline LNG Company, LLC, 2014). The terminal received the 

first LNG deliveries in 1982; however, deliveries were suspended in 1983 due to market conditions. LNG 

deliveries resumed in 1989. On December 18, 2002, the Commission authorized expansions of the 

Trunkline LNG Terminal to include a fourth storage tank, a second unloading dock, appurtenances, and 

support facilities to increase vaporization services and a peak sendout capacity of 2.1 Bcf/d. On April 5 

and July 8, 2006, these additional facilities were placed into service to bring the peak sendout capacity to 

2.1 Bcf/d as authorized. On December 26, 2006, the Commission authorized ambient air vaporization 

and natural gas liquids processing facilities (IEP Project), which were placed into service on March 11, 

2010, having no effect on the sendout capacity authorized for the terminal. 

A maximum of 225 LNG carriers per year are currently authorized to import or export LNG at 

the terminal’s two existing marine berths at a rate of up to 12,000 cubic meters (m3) per hour per carrier 

over an approximate 24-hour period. LNG carriers destined for the terminal are escorted from the pilot 

boarding area, about 30 miles offshore of Louisiana (CC Buoy), across the gulf to the terminal via the 

Calcasieu Ship Channel and Industrial Canal, and into the Turning Basin to complete berthing of the 

vessel. The average frequency of LNG carriers that could call on the terminal is about one carrier every 

1.5 days.
2-2

Insert figure 2-1 Project Location Map
2-3

Insert figure 2-2Proposed Liquefaction Facility, Existing LNG Terminal,

and Additional Construction Workspace Areas
2-4

3a Mainline Connector
2-5

Insert figure 2-3b Mainline 200-3 Loop
2-6

The existing Trunkline LNG Terminal includes the following major facilities:

 two shipping berths (east dock and west dock), each equipped with mooring and 

breasting dolphins. Each dock contains four liquid loading arms and one vapor return 

arm; one arm on each dock serves as a hybrid arm that can be used for liquid loading or 

vapor return;

 four LNG storage tanks: three with a capacity of 95,000 m3and one with a capacity of 

140,000 m3, for a total combined capacity of 425,000 m3;

 LNG sendout facilities, including 12 pumps, 14 vaporizers, and 2 boil-off gas

compressors;

 hazard detection, control, and prevention systems, cryogenic piping and insulation, and 

electrical and instrumentation systems;

 a firewater system;

 a natural gas liquids recovery system; and

 ancillary utilities, buildings, and service facilities.

2.1.2 Non-Liquefaction Facilities

Trunkline owns and operates a natural gas interstate transmission system that extends from its 

historical supply sources in Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, 

and Illinois to a terminus at the Indiana–Michigan state line near Elkhart, Indiana. Trunkline’s pipeline 

system includes a 30-inch-diameter pipeline and an adjacent 36-inch-diameter looping pipeline that

connect the existing LNG terminal to the mainline transmission system used for sendout capacity from 

the terminal (FERC, 2005). Trunkline’s pipeline system includes several appurtenant facilities including

compressor stations, meter stations, and interconnections with several other natural gas transmission 

pipelines. 

2.2 PROPOSED FACILITIES

2.2.1 Liquefaction Facility, LNG Terminal Modifications, and Additional Construction 

Workspaces 

2.2.1.1 Liquefaction Facility

The new liquefaction facility would be constructed immediately south of W. Tank Farm Road, 

west of Big Lake Road, and north of the existing LNG terminal in Calcasieu Parish, Louisiana. The new 

facility would include the following key components: 

 gas treatment units and heavy hydrocarbon removal units, one for each liquefaction train, 

each consisting of a fractionation unit, acid gas removal unit, gas dehydration unit, and a 

mercury removal unit;

 three liquefaction trains, each with a production capacity sufficient to produce 

5.48 MTPA of LNG for export;
2-7

 refrigerant storage and makeup system for all three liquefaction trains consisting of 

horizontal storage bullets holding refrigerants (ethane and propane);

 nitrogen generation and distribution system;

 boil-off gas system consisting of compressors to handle boil-off gas in the facility;

 fuel gas system to provide high-pressure gas to the refrigerant gas turbine drivers and 

low-pressure gas to the flare systems, heaters, and thermal oxidizers;

 hot oil system providing high-temperature oil for the regeneration gas heater and lowtemperature oil for all other services;

 flare system, including include seven flares on three derrick structures;

 hazard detection system;

 firewater and fire protection system;

 instrument and utility air system for supplying instrumentation and control systems and 

for powering tools and equipment used in the operation and maintenance of the 

liquefaction facilities;

 service water supply system providing service water to the utility station, demineralized 

water treatment package, glycol water system, chilled glycol water system, and firewater 

system;

 demineralized water supply system providing demineralized water for the operation of 

the amine unit;

 potable water service and supply system; and 

 emergency power systems consisting of diesel-fueled standby generators.

Figure 2.2.1-1 shows the layout of the proposed liquefaction facility. Additional information 

about some of the key facilities and processes is provided below. 

Trains, Utilities, and Systems

Trunkline’s existing pipelines, proposed new pipelines and facilities, and proposed modifications 

to the existing pipelines and facilities (see section 2.2.2) would transport natural gas (feed gas) to the 

liquefaction facility. Feed gas would be supplied to the liquefaction trains via a 48-inch-diameter feed 

gas pipeline from the Lake Charles LNG Export Meter Station (LCLNG Export Meter Station). The gas 

would be cooled into a liquid at the liquefaction facility, then conveyed to the existing storage tanks at the 

LNG terminal via an LNG rundown line and loaded onto LNG carriers at the existing terminal docks.
2-8

Insert figure 2.2.1-1 Liquefaction Facility Layout
2-9

The proposed liquefaction facility would consist of three liquefaction trains, with each train 

containing a natural gas pre-treatment system, including a heavy hydrocarbon removal unit, a 

fractionation unit, an acid gas removal unit, a gas dehydration unit, and a mercury removal unit. Before 

liquefaction, the feed gas would be pre-treated for removal of mercury to prevent corrosion of aluminum 

equipment, removal of carbon dioxide and sulfur compounds, and reduction of water to allow operation 

of the cryogenic heat exchanger. The fractionation unit would remove benzene and aromatics with heavy 

components from the feed gas to prevent freezing during the cryogenic processes. Ethane would be 

recovered for use as mixed refrigerant in the refrigerant storage and makeup systems. The stabilized 

condensate product, including extracted pentane and heavier hydrocarbons, would be air cooled and 

routed to the stabilized condensate storage tanks.

After the pre-treatment process, the liquefaction process would cool and condense the natural gas 

into a liquid at –260 degrees Fahrenheit. The primary components involved in the liquefaction process 

include the main cryogenic heat exchanger, refrigerant systems, and the end flash gas system. 

Liquefaction utility components would include a boil-off gas system, fuel gas system, hot oil system, 

flares, instrument and utility air systems, service water supply systems, a demineralization water supply 

system, hazard detection, and firewater protection systems, and emergency (backup) power systems. The 

liquefaction process would generate boil-off gas from the transfer of heat in system components that 

would be diverted to boil-off gas compressors. The fuel gas system would receive compressed boil-off 

gas, and excess boil-off gas would be recycled back through the liquefaction process.

Power Generation

To provide electrical power to the liquefaction facility, Entergy would build an approximately 

19-mile-long, 230-kV electric transmission line in Calcasieu Parish, Louisiana. The line would originate 

at Entergy’s existing Nelson Substation and would connect to a new Entergy substation to be constructed 

adjacent to and north of the existing Graywood Substation at the LNG terminal (see figure 2.2.1-1 and 

appendix B). The electric transmission line would be a non-jurisdictional facility, as discussed in sections

1.4 and 4.13 (cumulative impacts). Four 4,000-kilowatt (kW), stand-by diesel generators would provide 

emergency backup power to all systems.

LCLNG Export Meter Station

The proposed LCLNG Export Meter Station would be constructed in the southeast portion of the 

proposed liquefaction facility. The existing meter station at the LNG terminal, located in the northwest 

portion of the facility where the existing natural gas pipelines enter the terminal, would remain.

Associated Infrastructure

Existing roads would be used to access the proposed liquefaction facility site during construction; 

no new access roads would be required. Two roads within the existing LNG terminal would be 

installed/upgraded, including a heavy haul road leading from the west construction dock to the 

liquefaction facility and a medium haul road for transporting materials and equipment from the east 

construction dock to the liquefaction facility. Roads would be developed within the construction site

during site preparation/construction, which would later comprise the operational road network for the site.
2-10

2.2.1.2 Modifications to the Existing Trunkline LNG Terminal

The proposed modifications to facilities at the existing Trunkline LNG Terminal include:

 installation of larger in-tank LNG pumps;

 replacement of LNG loading arms at the west dock;

 modifications to boil-off compression and handling systems;

 expansion and integration of electrical systems;

 installation of LNG rundown lines from the liquefaction area to the LNG storage tanks;

 expansion and integration of security system;

 integration of control and emergency showdown systems;

 expansion and integration of telecommunication system;

 installation of larger vapor return pipeline from each dock to the LNG tanks;

 installation of a marine flare;

 addition of mooring dolphins and breasting dolphins at west dock and breasting dolphins 

at east dock; and

 construction of temporary construction docks (TCD), including dredging with disposal 

onshore.

Lake Charles LNG indicates that these modifications are required to facilitate the storage and 

subsequent export of LNG using the existing storage, piping, and docking facilities at the LNG terminal. 

The proposed modifications would also expand and integrate existing electrical, security, 

telecommunications, and emergency shutdown systems to accommodate the new and modified facilities. 

The modifications to the existing LNG terminal would occur within the existing fenced facility (see 

figure 2.2.1-1).

2.2.1.3 Additional Construction Workspaces

Construction of the liquefaction facility and LNG terminal modifications would require the use of 

four temporary additional construction workspaces (ACW) located north and east of the liquefaction

facility and LNG terminal. The ACWs would be used for a variety of purposes such as material and 

equipment storage, temporary field offices, parking, and fabrication and staging activities.

2.2.2 Non-Liquefaction Facilities

Trunkline proposes to construct and operate the Non-Liquefaction Facilities described below to 

increase the volume of natural gas able to be delivered to the liquefaction facility from 1.2 Bcf/d to the 

required 2.6 Bcf/d, enable bi-directional (north–south) flow capability in the pipeline system, and increase 

access to new natural gas supplies.
2-11

2.2.2.1 Proposed New Pipelines

Mainline Connector

Trunkline proposes to construct and operate a new 11.4-mile-long, 42-inch-diameter natural gas 

greenfield pipeline from mainline valve (MLV) 303-A in Jefferson Davis Parish, Louisiana on the Kaplan 

300 pipeline to MLV 203-A and proposed Compressor Station 203-A in Calcasieu Parish, Louisiana on 

the Kaplan 200 pipeline (see figure 2-3.a and appendix C). Bi-directional pigging facilities 

(launchers/receivers)1 would be installed at the origin and terminus of the proposed Mainline Connector.

Mainline 200-3 Loop

Trunkline proposes to construct and operate a new 6.5-mile-long, 24-inch-diameter natural gas 

looping pipeline from MLV 205 to MLV 204A on the Kaplan 200 pipeline (see figure 2-3.b and appendix 

C). The pipeline loop would start and end in Jefferson Parish, Louisiana, and cross a portion of Calcasieu 

Parish, Louisiana. The new loop line would be offset 25 feet from the adjacent existing pipeline. Bidirectional pigging facilities would be installed at the north end of the loop at MP 182.5 and at the 

NGPL–Lakeside Meter Station at MP 165.6.

2.2.2.2 Proposed Pipeline Modifications

Mainline 100-3 Modifications

Trunkline proposes to construct and modify launcher/receiver barrels at existing facilities on 

Trunkline’s 100 pipeline system in Washington County, Mississippi and Chicot County, Arkansas. These 

modifications would enable bi-directional flow on the pipeline system.

Mainline 200-1 Modifications

The proposed Mainline 200-1 modifications include the removal of a check meter at the existing 

U.S. 190 Meter Station and replacement of MLV 202 at the Transco Ragley Meter Station, both in 

Beauregard Parish, Louisiana, as well as replacement of a 100-foot section of overhead pipeline with a 

same-length section of underground pipeline installed via conventional methods at the Texas Gas–

Woodlawn Meter Station in Calcasieu Parish, Louisiana. These modifications would facilitate flow on 

the system and help meet the required throughput and demand for the project. 

In addition, the Mainline 200-1 modifications would include the replacement of a segment of the 

existing 200-1 pipeline at the Calcasieu River crossing in Calcasieu Parish. The approximately 

5,477-foot-long replacement segment would be constructed beneath the river using the horizontal 

directional drill (HDD) crossing method. The original river crossing segment would be abandoned in 

place and taken out of service.

2.2.2.3 Aboveground Facilities

Compressor Station 203-A 

Trunkline proposes to construct and operate a new compressor station near MLV 203-A on 

Trunkline’s Mainline 200 system in Calcasieu Parish, Louisiana (see figure 2-3.b and appendix C). 

Compressor Station 203-A would include 10 natural gas-driven compressor units, including 

 

1 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.
2-12

5 Mars 100 units, and 5 Caterpillar G3616 units, for a total site-specific rating of 98,685 hp

(manufacturer’s rating of 103,175 hp). The compressor station facility would include two compressor 

buildings, gas coolers, above- and belowground piping, auxiliary and control buildings, a backup power 

system (generator), and an office building and utilities.

Longville Compressor Station

Trunkline proposes to replace one Allison 500 Unit 4521 (3,000 hp) with a new Mars 100 natural 

gas-driven compressor unit (site-specific rating 15,002 hp, manufacturer’s rating of 15,900 hp) at the 

existing Longville Compressor Station in Beauregard Parish, Louisiana (see figure 2-1 and appendix C).2 

Modifications of piping and appurtenances at the facility would also be required to increase the flow 

capacity and enable bi-directional flow on the pipeline system. Trunkline would also install a 

4,200-gallon lube oil storage tank.

Pollock, Epps, and Shaw Compressor Stations

Trunkline proposes to install and modify piping and appurtenant facilities at the existing Pollock 

(Grant Parish, Louisiana), Epps (West Carroll Parish, Louisiana), and Shaw (Bolivar County, Mississippi) 

Compressor Stations (see figure 2-1 and appendix C). Modifications at these facilities would allow bidirectional flow on the pipeline system. Modifications at the Shaw Compressor Station would also 

include installation of a scrubber/separator with a 10,000-gallon storage tank.

Meter Stations

Trunkline proposes to construct the following five new meter stations in Louisiana:

 the LCLNG Export Meter Station in the southeast corner of the liquefaction facility in 

Calcasieu Parish;

 the Kinder Morgan–Lake Charles Meter Station at the intersection of the Trunkline

laterals and the Kinder Morgan pipeline in Calcasieu Parish;

 the Gulf Crossing–Perryville Meter Station at the intersection of Mainline 100-3 and the 

Gulf Crossing Pipeline in Richland Parish;

 the Midcontinent Express Pipeline (MEP)–Perryville Meter Station at the intersection of 

Mainline 100-3 and the MEP pipeline in Richland Parish; and 

 the Columbia Gulf–Egan Meter Station near the intersection of the Kaplan 300 Line and 

the Columbia Gulf Transmission Pipelines in Acadia Parish.

In addition to metering equipment, each meter station would include a remote terminal unit 

building and an emergency generator typically sized at about 25 kW. 

Additionally, Trunkline proposes to modify the NGPL–Lakeside, TETCO–Allen, Texas Gas–

Woodlawn, Tennessee Kaplan, and Transco Ragley Meter Stations. The proposed modifications include 

installing upgraded equipment, increasing receipt/delivery points, and enabling bidirectional flow.

 

2 The Longville Compressor Station currently has 11 compressor units with a total of 36,750 hp. With the proposed new 

horsepower, and the retirement of Unit No. 4521, the station would have a total of 49,650 certificated hp (manufacturer 

rating).
2-13

The new and modified meter stations would increase Lake Charles LNG’s and Trunkline’s access 

to natural gas supply by interconnecting with new supplies and increasing throughput capacity at existing 

interconnects.

2.3 LAND REQUIREMENTS

Lake Charles LNG and Trunkline would require about 1,516.3 acres of land and open water for 

construction of the project (see table 2.3-1). Operation of the project, including the modified existing 

facilities and the proposed new facilities, would require a total of about 841.9 acres, of which 439.5 acres 

would be maintained as new permanent right-of-way or new aboveground facility area, and 402.4 acres 

would consist of existing facilities and right-of-way. About 349.2 acres of temporary workspace would 

revert to preconstruction use and condition, while the 325.2 acres of temporary ACW to be used during 

construction of the liquefaction facility would be permanently affected as discussed in section 2.6.1.5. 

See section 4.8 for more detailed information regarding land uses affected by the project.

2.3.1 Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

Construction of the new liquefaction facility and modifications to the existing LNG terminal 

would require about 762.9 acres of land, including 285.9 acres for the new liquefaction facility; the 

existing 151.8-acre LNG terminal; and 325.2 acres of ACWs. Additionally, construction of the TCDs and 

berth modifications would require dredging of 22.1 acres within the Industrial Canal. During operation, 

the new liquefaction facility would permanently occupy the entire 285.9-acre site. Operations at the 

existing LNG terminal would continue to occur within the current facility boundaries (i.e., the project 

would not result in an increase in the existing terminal area). 

Lake Charles LNG indicated that the ACW property owners do not want the land returned to 

present conditions because the fact that these sites would be cleared and slightly elevated makes them 

more suitable for future use and development. Additionally, since compacted fill material would be 

distributed across the whole of each ACW and construction would continue for about 5 years, successful 

broad-scale restoration to previous conditions would be difficult, time consuming, and costly. Therefore, 

although Lake Charles LNG would not retain the ACWs for operation of the project facilities, in 

accordance with landowner agreements, these areas would not be restored to preconstruction conditions 

(see section 2.6.1.5). Due to the type and duration of disturbance required for project construction, 

impacts on the ACWs would likely be permanent.

2.3.2 Non-Liquefaction Facilities

Construction of the Non-Liquefaction Facilities would require a total of about 731.3 acres of land 

and open water. In addition to the 250.6 acres of land that are already within the operational boundaries 

of existing Trunkline facilities to be modified or used temporarily for construction, operation of the new 

and modified Non-Liquefaction Facilities would require 153.6 acres of newly affected land. 

2.3.2.1 New and Modified Pipeline Facilities

Construction and Permanent Right-of-Way 

Trunkline generally proposes to construct the 42-inch-diameter Mainline Connector within a 

125-foot-wide construction right-of-way, which would affect about 150.9 acres (the construction right-ofway width would be reduced within wetlands as discussed in section 2.6.3.2). Following construction of 

the Mainline Connector, a 50-foot-wide permanent easement would be retained during operation of the 

pipeline, encompassing 67.8 acres.
2-14

TABLE 2.3-1

Land and Open Water Requirements for the Proposed Lake Charles Liquefaction Project (in acres)a

Facility

Total

Construction

Land Requirementsb

Operational Land Requirements

Existing Facility 

Footprint/

Right-of-Way

New Facility 

Footprint/

Right-of-Wayc

LIQUEFACTION FACILITY, LNG TERMINAL, AND ACWs

LNG terminal 151.8 151.8 0

Dredge area 22.1 0.0 0.0

Liquefaction facility 285.9 0.0 285.9

ACWs 325.2 0.0 0.0

Liquefaction Facility, LNG 

Terminal, and ACWs Total

785.0 151.8 285.9

NON-LIQUEFACTION FACILITIES

New Pipelines 

Mainline Connector 

Right-of-way 150.9 0.0 67.8

Additional temporary workspace (ATWS) 43.3 0.0 0.0

Access Roads 49.9 0.0 0.0

Subtotal 244.1 0.0 67.8

200-3 Loop 

Right-of-way 54.4 16.6 22.7

ATWS 36.5 0.0 0.0

Access Roads 10.4 0.0 0.0

Subtotal 101.3 16.6 22.7

Pipeline Modifications

Mainline 100-3 Modifications

Mississippi Barrel East 2.0 2.0 0.0

Mississippi Barrel West 1.6 1.6 0.0

Subtotal 3.6 3.6 0.0

Mainline 200-1 Modifications 

Calcasieu River HDD 

Right-of-way and ATWS 30.3 0.0 6.0

Access Roads 27.5 0.0 0.0

U.S. 190 Meter Station 

Existing facility 0.3 0.3 0.0

ATWS 0.9 0.0 0.0

Access Roads <0.1 0.0 <0.1

100-foot overhead crossing replacementd0.0 0.0 0.0

MLV 202e0.0 0.0 0.0

Subtotal 59.0 0.3 6.0

Contractor Yard 20.8 0.0 0.0

Compressor Stations 

203-A

f

(new) 46.6 1.0 45.6

Longville (existing) 44.5 44.5 0.0

Pollock (existing) 78.4 78.4 0.0

Epps (existing) 41.9 41.9 0.0

Shaw (existing) 62.9 62.9 0.0

Subtotal 274.3 228.7 45.6
2-15

TABLE 2.3-1 (cont’d)

Land and Open Water Requirements for the Proposed Lake Charles Liquefaction Project (in acres) a

Facility

Total

Construction

Land Requirements b

Operational Land Requirements

Existing Facility 

Footprint/

Right-of-Way

New Facility 

Footprint/

Right-of-Way c

Meter Stations

LCLNG Exportg(new) 0.0 0.0 0.0

Kinder Morgan–Lake Charles (new) 2.4 0.0 1.5

Columbia Gulf–Eganf(new) 4.6 0.0 2.7

NGPL–Lakesidef(existing) 3.2 0.3 0.3

TETCO–Allenf (existing) 4.8 0.3 2.4

Gulf Crossing–Perryvillef(new) 3.2 0.0 1.4

MEP–Perryvillef(new) 5.5 0.0 3.2

Texas Gas–Woodlawnf(existing) 2.3 0.2 0.0

Tennessee–Kaplanh(existing) 0.0 0.0 0.0

Transco Ragleyf(existing) 2.1 0.7 0.1

Subtotal 28.1 1.5 11.5

Non-Liquefaction Facilities Total 731.3 250.6 153.6

PROJECT TOTAL 1,516.3 402.4 439.5

____________________

a

The totals shown in this table may not equal the sum of addends due to rounding.

b

Total construction land requirements include both temporary and permanent work areas.

c New operational land requirements include only new or additional facility areas or pipeline right-of-way resulting from the 

project.

d

Land required for the 100-foot overhead crossing replacement is accounted for in the requirements for the Texas Gas–

Woodlawn Meter Station.

e

Land required for the MLV 202 replacement is accounted for in the requirements for the Transco Ragley Meter Station.

f

Includes temporary and permanent access road impacts.

g

Land required for the LCLNG Export Meter Station, which would be located within the liquefaction facility site, is 

accounted for in the liquefaction facility requirements. 

h

Land required for the Tennessee–Kaplan Meter Station modifications, which would be located at the origin of the Mainline 

200-3 Loop, is accounted for with the Mainline 200-3 Loop requirements.

Construction of the 24-inch-diameter Mainline 200-3 Loop would require a 75-foot-wide 

construction right-of-way that would overlap the existing right-of-way by 25 feet and affect a total of 

54.4 acres. A 50-foot-wide permanent easement would be retained during operation of the 

Mainline 200-3 Loop; however, 25 feet of the easement would overlap the adjacent pipeline’s existing 

permanent easement. In total, 39.3 acres would be required for operation of the Mainline 200-3 Loop, of 

which 22.7 acres would be new permanent right-of-way and 16.6 acres would be existing right-of-way.

Construction and operation of the Mainline 100-3 modifications at the Mississippi River barrel 

sites would be conducted entirely within the existing facility footprints, consisting of a total of 3.6 acres. 

Construction of the Mainline 200-1 modifications would require a total of 59.0 acres. 

Construction of the Calcasieu River HDD crossing would require 30.3 acres of workspace, and would 

result in about 6.0 acres of new permanent right-of-way. Construction of the U.S. 190 Meter Station 

modifications would require 1.2 acres of land, including the 0.3-acre existing facility site and about 

0.9 acre of temporary workspace, as well as a less than 0.1-acre new, permanent access road. Following 

construction, the temporary workspace would revert to preconstruction condition and operation of the 

modified facility would occur within the existing 0.3-acre site. The 100-foot overhead crossing 

replacement and MLV 202 replacement would take place within the Texas Woodlawn and Transco 
2-16

Ragley Meter Station sites, respectively, and would not require additional temporary or permanent 

workspace. 

Additional Temporary Workspace

Trunkline proposes to use 79.8 acres of additional temporary workspace (ATWS) at road, 

wetland, and waterbody crossings to provide extra space for construction activities and storage of 

excavated materials during construction of the Mainline Connector and Mainline 200-3 Loop. 

Although Trunkline has identified areas where ATWS would be required, additional or 

alternative ATWS could be identified in the future due to site-specific construction requirements. 

Examples of locations where other ATWS could potentially be requested include:

 pipe stringing truck and other equipment turnaround areas;

 existing pipeline, utility line, drain tile, and irrigation system crossings;

 steep side slopes to create level working areas; and

 full right-of-way topsoil segregation areas.

Trunkline would be required to file information on each of these areas for our review and 

approval prior to use.

Access Roads

Trunkline would use 37 temporary access roads during construction of the new and modified 

pipeline facilities, including 17 for the Mainline Connector, 12 for the Mainline 200-3 Loop, and 8 for the 

Calcasieu River HDD, which together would total about 87.8 acres. Access roads would typically be no 

more than 30 feet wide. Three of the access roads would be new roads constructed in open or agricultural 

land; the remainder are existing dirt paths or roads. Grading, graveling, side vegetation trimming, and/or 

deployment of construction mats would possibly be required to improve the roads for project use based

on site-specific conditions at the time of construction. Access roads are discussed in more detail in 

section 4.8.1.2.

Contractor Yard

Trunkline would use one 20.8-acre site as a contractor yard during construction (see appendix C). 

This site was previously used for industrial/commercial purposes. Contractor yards are typically used 

during construction for storage of pipe, equipment, and other materials, as well as staging and other 

contractor activities. Following construction of the project, the contractor yard would be allowed to 

revert to preconstruction condition and use. 

2.3.2.2 Aboveground Facilities

Construction of the proposed aboveground facilities and facility modifications (compressor and 

meter stations) would affect a total of 302.4 acres of land and open water. About 57.2 acres of new land

would be required for operation of the new and expanded facilities. The remaining land includes about 

230.2 acres of existing facility sites and about 15.0 acres of temporary workspace and temporary access 

roads. The temporary construction areas would be restored and allowed to revert to preconstruction 

condition and use.
2-17

Construction of new permanent access roads would be required for Compressor Station 203-A 

and the TETCO–Allen, Columbia Gulf–Egan, Gulf Crossing–Perryville, MEP–Perryville, and Transco 

Ragley Meter Stations. Acreage for the permanent access roads is included in the construction and 

operation land requirements shown for the respective facilities in table 2.3-1. The existing road leading to 

the NGPL–Lakeside Meter Station would also be used during construction; however, no improvements to 

the road would be required.

Operation of Compressor Station 203-A would require all of the 46.6 acres used during 

construction. No additional land would be required for operation of the modified facilities at the 

Longville, Pollock, Epps, and Shaw Compressor Stations. The LCLNG Export Meter Station would be 

constructed and operated within the liquefaction facility site and would not require additional land. The 

combined new land requirements associated with operation of the Kinder Morgan–Lake Charles, 

Columbia Gulf–Egan, NGPL–Lakeside, TETCO–Allen, Gulf Crossing–Perryville, and MEP–Perryville 

Meter Stations would be 11.5 acres. No additional land would be required for operation of the modified 

facilities within the Texas Gas–Woodlawn and Transco Ragley Meter Stations except for a 0.1-acre new 

permanent access road at the latter. Land requirements for the Tennessee-Kaplan Meter Station are 

included in the Mainline 200-3 Loop.

2.4 CONSTRUCTION SCHEDULE

Assuming receipt of all certifications, authorizations, and necessary permits, Lake Charles LNG

anticipates starting construction of the liquefaction facility and modifications to the existing LNG 

terminal in 2015, and placing the first new liquefaction train into service in 2019. The three liquefaction 

trains would be placed into service 6 months apart.

Assuming receipt of all certifications, authorizations, and necessary permits, Trunkline would 

begin construction of the Non-Liquefaction Facilities in 2017 and initiate service in late 2018.

2.5 ENVIRONMENTAL COMPLIANCE

2.5.1 Compliance Monitoring

The FERC may impose conditions on any Certificate or authorization it grants for the project. 

These conditions include additional requirements and mitigation measures recommended in this EIS to 

minimize the environmental impact that would result from construction and operation of the Lake Charles 

Liquefaction Project (see sections 4 and 5). We will recommend that these additional requirements and 

mitigation measures (bold type in the text of the EIS) be included as specific conditions to any approving 

Certificate or authorization issued for the project. We will also recommend to the Commission that Lake 

Charles LNG and Trunkline be required to implement the mitigation measures proposed as part of the 

project unless specifically modified by other Certificate or authorization conditions. Lake Charles LNG

and Trunkline would be required to incorporate all environmental conditions and requirements of the 

FERC Certificate, authorization, and associated construction permits into the construction documents for 

the project.

Lake Charles LNG and Trunkline would employ environmental inspectors (EI) for the project, 

including one EI for the liquefaction facility and one EI for each of the pipeline spreads, one of which 

would also be responsible for Compressor Station 203-A. Additional EIs may be assigned as needed. At 

existing facilities, a qualified inspector may be assigned EI responsibilities and operational environmental 

personnel would likely assist in environmental compliance and inspection for the bi-directional 

modifications. For all other facilities (meter stations and mainline modifications) and depending on the 

final construction schedule, a dedicated EI may be assigned to roam between various project sites, the 

pipeline EIs may participate in inspection and oversight, and/or another qualified inspector may be 
2-18

assigned EI responsibilities with assistance from Trunkline operational staff. The responsibilities of the 

EIs are described in the 2013 FERC Upland Erosion Control, Revegetation, and Maintenance Plan (Plan) 

and Wetland and Waterbody Construction and Mitigation Procedures (Procedures).

3

 The FERC Plan and 

Procedures are a set of construction and mitigation measures developed by FERC staff with input from

other federal and state agencies, environmental consultants, inspectors, construction contractors, nongovernmental organizations, and the natural gas pipeline industry to minimize the potential environmental 

impacts of the construction of pipeline projects in general. 

The EIs’ responsibilities would include verifying that environmental obligations, conditions, and 

other requirements of permits and authorizations for the project are met. The EIs would inspect 

construction and mitigation activities to verify environmental compliance and, if applicable, may also 

oversee cultural resource and/or biological monitors that monitor and evaluate construction impacts on 

resources as specified in this EIS.

Lake Charles LNG and Trunkline would conduct environmental training for the EIs to familiarize 

them with project-specific issues and requirements, and would provide separate training for contractor 

personnel to make them aware of the environmental requirements of the project. Additionally, Lake 

Charles LNG and Trunkline would incorporate environmental requirements and specifications in 

contractor bid documents, and would provide the contractors with copies of environmental permits, 

certificates, and clearances.

In addition to Lake Charles LNG’s and Trunkline’s environmental compliance activities, the 

FERC staff would conduct field inspections during construction. Other federal and state agencies may 

also conduct oversight or inspections to the extent determined necessary by the individual agency. After 

construction is completed, the FERC staff would continue to monitor the project area during operation of 

the project to verify successful restoration. Additionally, the FERC staff would conduct bi-annual 

engineering safety inspections of the liquefaction facility operations.

2.6 CONSTRUCTION PROCEDURES

The project would be constructed in accordance with the DOT Federal Safety Standards for 

Liquefied Natural Gas Facilities, 49 CFR 193, and the National Fire Protection Association (NFPA) 59A 

LNG Standards. All pipeline facilities would be designed, constructed, tested, operated, and maintained 

in accordance with the DOT regulations in 49 CFR 192. Lake Charles LNG and Trunkline would 

implement the FERC Plan and Procedures (with the exception of alternative measures where sufficiently 

justified), as well as all conditions resulting from the Certificate and other project permits. Lake Charles 

LNG and Trunkline would also implement their proposed project-specific plans and measures developed 

to avoid or minimize environmental impacts during construction, which are discussed throughout this 

EIS. 

Lake Charles LNG and Trunkline requested several alternative measures to those specified in the 

FERC Procedures. The requested alternative measures and our evaluation and conclusions regarding

these requests are provided in sections 4.3.2.2 and 4.4.3. 

 

3 The FERC Plan and Procedures can be viewed on the FERC website at http://www.ferc.gov/industries/gas/enviro/plan.pdf

and http://www.ferc.gov/industries/gas/enviro/procedures.pdf, respectively.
2-19

2.6.1 Liquefaction Facility and LNG Terminal Modifications

2.6.1.1 Site Preparation

The proposed liquefaction facility site and any staging, laydown, and storage areas that are 

currently undeveloped would be cleared, grubbed, filled, and graded to accommodate construction of the 

new liquefaction facility. In accordance with the FERC Plan, Lake Charles LNG would install temporary 

erosion controls immediately after initial soil disturbance to minimize erosion; these erosion controls 

would be maintained throughout construction. Materials removed from developed areas would be 

salvaged and/or disposed of in accordance with applicable laws and regulations.

The existing grade at the liquefaction facility site varies between 6.4 and 7.6 feet above mean sea 

level (AMSL). The liquefaction facility site would be built up to an elevation of 11 feet AMSL in areas 

with buildings or critical equipment (e.g., transformers, substations, switchgears, propane, or boil-off gas 

compressors, cryogenic heat exchangers). This 11-foot grade elevation is based on the 100-year flood 

plain elevation of 9 feet AMSL as recommended by the Federal Emergency Management Agency 

(FEMA), plus an additional 2 feet to compensate for sea level rise and area subsidence for a 25-year 

lifespan. Other areas would be elevated to 8 feet AMSL.

Lake Charles LNG would import local fill material from commercial operators in the vicinity of 

the project area. 

2.6.1.2 Marine Construction – Temporary Construction Docks

Prior to installation of major facilities, Lake Charles LNG would construct two TCDs to facilitate 

delivery via barge of major equipment, plant pre-fabricated packages, main part of the bulks, 

commodities, and other materials necessary for the construction and commissioning of the liquefaction 

facility (see figure 2.2.1-1). The TCDs would consist of anchored steel sheetpile bulkheads that are 

backfilled to create a working platform for offloading materials and equipment. TCD 1, which would be 

located at the western limit of the facilities, would be a mixed-use dock with a quay width of 475 feet and 

a 250-foot clear linear distance behind the berth for package unloading. TCD 2, which would be located 

east of the last mooring dolphin at the existing east berth, would have a quay width of 200 feet and a 

165-foot clear linear distance behind the berth for shipment unloading. Mooring dolphins and breasting 

dolphins would be modified at the existing west dock, and breasting dolphins would be added to the 

existing east dock.

The TCDs would be constructed using conventional waterborne marine construction equipment 

(e.g., barges, cranes, pile driving equipment) and shore-based construction equipment (e.g., backhoes, 

bulldozers). It is anticipated that steel sheet piles would first be installed waterward of the bank to allow 

the inner space to be backfilled with select structural fill. The anchorage system would be installed to 

provide restraining force from the active earth pressures. The surface features of the TCDs would be 

installed with the conventional shore-based equipment and would include a gravel working surface, 

curbing, etc. The dredging of the TCD areas would most likely involve the use of a cutter suction 

hydraulic dredge that would hydraulically pump the material to the existing dredged material disposal site

northeast of the waterfront. Modification of the current banks of the Turning Basin would be disturbed by 

excavation and fill activities to assist with suitable anchoring and structural integrity of the TCDs.

Dredging volumes are estimated at 20,000 and 6,000 cubic yards for TCDs 1 and 2, respectively. 

The dredged material would be pumped through the dredge pipeline from the waterfront to the disposal 

area where it would be allowed to dewater through a conventional weir system that would then return the 

decanted water back to the Industrial Canal, meeting all water quality requirements. The dredged 
2-20

material would be tested prior to disposal. Best management practices would be employed during 

dredging and disposal activities.

The TCDs would have a design life of about 6 years. The procedures for demolition and removal 

of the TCDs would include removal of all surface features (curbing, gravel, etc.) and excavation of any 

backfill material to allow the anchor system to be removed prior to extraction of the steel sheetpiles. The 

shoreline would be restored by grading the slope to approximately the existing in-situ conditions. 

Shoreline protection would be reinstalled if needed. Impacts for removal would likely be minimal 

because most work would be completed from shore-based equipment.

2.6.1.3 Facility Foundations

For lightly loaded structures, Lake Charles LNG would use conventional spread footings/concrete 

slab and/or grade beam foundations bearing on properly compacted structural fill soils, which it would 

install at an elevation of 8 to 11 feet AMSL, matching the design of the existing LNG terminal. For flood 

risk purposes, the liquefaction facility site would be built up to an elevation of 11 feet AMSL in areas 

with buildings or critical equipment (e.g., transformers, substations, switchgears, propane or boil-off gas 

compressors, cryogenic heat exchangers). Some buildings and critical equipment may be placed on 

higher foundations to accommodate specific design requirements such as piping and utility connections. 

For example, top of concrete (operating level) of the control building would be at an elevation of 12 feet 

6 inches AMSL, which puts the 18-inch recessed areas of the building at the same 11-foot AMSL 

elevation as the surrounding grade elevation for flood risk purposes.

Lake Charles LNG would drive piles to a depth not expected to exceed about 70 feet below the 

ground surface. 

2.6.1.4 Piping and Equipment Installation and Testing

All pipe would be fabricated according to American Society of Mechanical Engineers (ASME) 

standards by ASME Section IX qualified welders. Once process equipment is set in place on the 

foundations, roughly aligned, and secured to the foundations, pipe installation would begin. Lake Charles 

LNG would coat all piping and equipment with a material that resists corrosion.

When all process equipment is installed and electrical, mechanical, and other instrumentation 

work completed, the key pre-commissioning activities would commence, which typically include the 

following:

 conformity checks on each part or piece of equipment to ensure proper installation;

 flushing and cleaning of equipment; and

 nitrogen leak testing of all hydrocarbon piping and associated equipment.

After all pre-commissioning activities are complete, Lake Charles LNG would clean and 

hydrostatically or pneumatically test piping in compliance with the applicable codes that govern pipe 

design, and purge the piping. In general, Lake Charles LNG would pneumatically test cryogenic piping

using dry air or nitrogen and hydrostatically test non-cryogenic piping using clean water (see 

section 4.3.2.2 for further information on hydrostatic test water). All testing would be performed in 

accordance with ASME B31.3.

2.6.1.5 Restoration

Following construction, the liquefaction facility site would be graded and surfaces would be 

finished as gravel- or asphalt-covered, concrete-paved, and grassy areas. Site restoration would be 
2-21

conducted in accordance with the FERC Plan and Procedures. In addition, a Stormwater Pollution 

Prevention Plan (SWPPP) would be implemented for facility operation. As noted previously, the ACWs 

would not be restored to preconstruction condition. Lake Charles LNG anticipates that these areas would

be graveled or converted to vegetated surfaces based on landowner agreements; temporary and/or 

permanent erosion control devices would be installed as needed to prevent off-site erosion and 

sedimentation.

2.6.2 Non-Liquefaction Facilities

Trunkline would construct the pipelines and associated facilities as described in this section and 

in accordance with 49 CFR 192. Figure 2.6.2-1 shows a depiction of the typical pipeline construction 

sequence. Figures 2.6.2-2 and 2.6.2-3 illustrate the typical right-of-way configurations Trunkline

proposes for the Mainline Connector and Mainline 200-3 Loop Pipelines, respectively. As indicated in 

figure 2.6.2-2, Trunkline proposes a 125-foot-wide construction right-of-way for the Mainline Connector, 

which is wider than the typical right-of-way identified in the FERC Plan (75 feet, with an additional 

25 feet allowed in specific circumstances). The wider construction right-of-way is necessary to 

accommodate the trench required for the 42-inch-diameter Mainline Connector pipeline and to allow for 

containment of spoil material within the approved right-of-way. The proposed construction right-of-way 

for the Mainline Loop is 75 feet wide, including a 25-foot overlap with an existing pipeline easement as 

shown in figure 2.6.2-3. 

2.6.2.1 Surveying and Easement Clearance

Prior to initiating construction-related activities, Trunkline would survey the route and secure 

right-of-way easements from the appropriate landowners. The limits of construction would be clearly 

marked in the field with various color-coded flagging to represent temporary easement, centerlines, 

workspaces, etc. Trunkline would notify landowners in advance of construction activities that could 

affect their property or business.

2.6.2.2 Clearing and Grading

Trunkline would clear and grade the construction right-of-way and extra workspaces (including 

brush, trees, and roots), where necessary, to provide a relatively level surface for trench excavating 

equipment, sufficient space to accommodate safe working and passage of heavy construction equipment, 

and to provide for the safety of the pipeline workers. In grassy areas where grading is not required, 

vegetation would be mowed to avoid damage to root systems and cleared to the edge of the work area. 

Temporary erosion controls would be installed after initial soil disturbance, where necessary, to minimize 

erosion and would be maintained throughout construction as needed.

2.6.2.3 Pipe Stringing, Bending, and Welding

Trunkline would string the pipe segments along the construction right-of-way on temporary 

supports, which involves positioning pipe sections parallel to the centerline of the trench so they are 

easily accessible to construction personnel. Field bends of the pipe would follow the natural grade and 

direction changes of the right-of-way. Following stringing and bending, the ends of the pipe sections 

would be aligned and welded together. Trunkline would x-ray welds to ensure structural integrity and 

compliance with applicable DOT regulations at 49 CFR 192. Trunkline would repair or replace any 

welds that do not meet the DOT’s safety standards. The welded joints would be externally coated and the 

assembled pipeline would be visually and electronically inspected for faults, scratches, or other damage, 

including coating defects. Any damage would be repaired prior to lowering the pipe into the trench.
2-22

Insert figure 2.6.2-1 Typical Pipeline Construction Sequence
2-23

Insert figure 2.6.2-2 Typical Right-of-Way Configuration for the Mainline Connector 

Pipeline
2-24

Insert figure 2.6.2-3 Typical Right-of-Way Configuration for the Mainline 200-3 Loop 

Pipeline
2-25

2.6.2.4 Trenching

Trunkline would install the majority of the pipeline in uplands using conventional open-cut 

methods, which typically include the steps described below. Trunkline’s proposed pipeline installation 

across waterbodies and wetlands, as well as other specialized construction procedures, are described in 

section 2.6.3.

Wheel ditching machines and/or backhoes would be used to excavate a trench to a depth 

sufficient to allow coverage of the pipeline to meet the DOT standards at 49 CFR 192.327. The typical 

depth of cover would be 36 inches.

For the 42-inch-diameter Mainline Connector, the trench depth would typically be about 8 feet to 

allow for 3 to 4 feet of cover over the pipe. The trench width would be about 15 feet in stable soils and

even wider in saturated or otherwise unstable soils. Additional trench width could be required to maintain 

stability of the trench walls for the safety of pipeline workers and equipment. For the 24-inch-diameter 

Mainline 200-3 Loop, the nominal trench depth would be 6 feet to allow for 3 to 4 feet of cover; the 

trench width would typically be about 12 feet. 

Trunkline would install the pipeline at least 36 inches below ground surface to the top of the pipe 

at drainage ditches and public roads, and 48 inches below ground surface in agricultural areas. In 

cultivated agricultural areas, Trunkline would strip and segregate up to 12 inches of topsoil. Topsoil 

segregation would also be conducted on residential land unless topsoil replacement is deemed more 

efficient. Trunkline would typically store excavated materials (including subsoil and segregated topsoil) 

on the non-working side of the trench, away from construction traffic and pipe assembly areas.

Trunkline would be required to employ the measures described in the FERC Plan and Procedures 

to minimize erosion during trenching operations and construction activities. To contain disturbed soils in 

upland areas and minimize the potential for sediment loss to wetlands and waterbodies, Trunkline would 

install temporary erosion controls immediately after initial soil disturbance and maintain them throughout 

construction.

2.6.2.5 Lowering-In and Backfilling

Prior to lowering the pipeline, Trunkline would dewater the trench as necessary. Trunkline would 

pump accumulated groundwater or rainwater from the trench to stable upland areas in accordance with 

applicable federal, state, and local permitting requirements, as well as the FERC Procedures. If 

necessary, dewatering effluent would be passed through sediment filters (e.g., hay bale structures, filter 

bags) to ensure compliance with water quality requirements. Trench breakers would be installed at 

regular intervals, where appropriate, to prevent subsurface erosion and flow of water between the trench 

and crossed waterbodies, wetlands, or near-surface groundwater.

After the pipeline is lowered into the trench and adequately protected, Trunkline would place 

previously excavated materials into the trench. If the excavated material has significant amounts of rock 

that could damage the pipe coating, Trunkline would install a rock shield, obtain commercial fill for 

padding, or separate rocks from suitable material from the excavated trench spoil. Trunkline would be 

required to dispose of excess rock deemed unsuitable for backfill in accordance with applicable 

regulations and landowner requests. In areas where topsoil has been segregated, Trunkline would place 

the excavated subsoil into the trench first and top it with the topsoil. No topsoil would be used for 

pipeline padding.
2-26

2.6.2.6 Hydrostatic Testing

Once installation and backfilling are completed, Trunkline would hydrostatically test the pipeline 

in accordance with DOT safety standards (49 CFR 192) and applicable permit conditions to verify its 

integrity and ensure its ability to withstand the maximum allowable operating pressure (MAOP). 

Hydrostatic testing consists of installing a hydrostatic test cap and manifold, filling the pipeline with 

water, pressurizing the pipeline to 125 percent of its MAOP, and maintaining that test pressure for a 

minimum of 8 hours. Section 4.3.2.2 provides additional information on hydrostatic testing and test water 

discharge.

2.6.2.7 Cleanup and Restoration

After the trench is backfilled, Trunkline would remove all remaining debris, surplus materials, 

and temporary structures and dispose of them in accordance with applicable federal, state, and local 

regulations. In accordance with the FERC Plan, Trunkline would finish grade and restore all disturbed 

areas as closely as practicable to preconstruction contours. The soil over the trench may be compacted or 

mounded as needed to minimize future settling. During this phase, Trunkline would also install 

permanent erosion control measures in accordance with the FERC Plan and Procedures.

Trunkline would be required to seed the right-of-way after pipeline installation and re-contouring 

in accordance with the FERC Plan and Procedures. Trunkline would inspect the right-of-way after the 

first and second growing seasons, at a minimum, to determine the success of revegetation. FERC staff 

would also continue inspections throughout revegetation, until such time as restoration is deemed 

successful. Trunkline would be required to implement additional restoration measures if deemed 

necessary by the FERC and/or other federal, state, or local agencies.

After completion of construction and hydrostatic testing, the new pipeline would be cleaned and 

dried, using pipeline pigs propelled through the pipeline with compressed air, and then packed with 

natural gas. Trunkline would install pipeline markers and/or warning signs along the pipeline centerline 

at line-of-sight intervals to identify the pipeline location, identify Trunkline as the pipeline operator, and 

provide telephone numbers for emergencies and inquiries. Trunkline would install a pipeline cathodic 

protection system in accordance with 49 CFR 192 (also see section 2.7.2.1).

2.6.3 Special Construction Procedures

2.6.3.1 Road, Railroad, and Existing Pipeline Crossings

The proposed pipeline routes would cross paved and unpaved roads, highways, railroads, and 

existing pipelines. Trunkline would construct across these features in accordance with the requirements 

of all applicable crossing permits and approvals. Trunkline would be required to use traffic warning 

signs, detour signs, and other traffic control devices as required by federal, state, and local departments of 

transportation.

Trunkline would cross most major roads and railroads via the conventional bore method, which 

would result in minimal or no disruption to traffic at road or railroad crossings. The conventional bore 

method involves excavating a pit on each side of the feature, boring a hole under the road or railroad at 

least equal to the diameter of the pipe, and pulling a prefabricated pipe section through the borehole. The 

bore pipe may or may not be cased depending on applicable permit conditions. Some highways and 

railroads may be crossed using the HDD method (see section 2.6.3.3 for more information regarding the 

HDD crossing method).

Trunkline would cross unpaved and smaller roads by traditional open-cut methods as allowed by 

respective landowners. Trunkline would schedule construction activities at road crossings to avoid or 
2-27

minimize interruptions in the flow of traffic. Detours may not be necessary, except for during brief 

periods, if one lane of traffic can be kept open during the crossing.

Trunkline would be required to maintain a minimum clearance of 12 inches between the proposed 

pipeline and the crossing of existing pipelines in accordance with 49 CFR 192 and in compliance with 

pipeline crossing agreements negotiated with the existing pipeline operators.

2.6.3.2 Wetland Crossings

Trunkline would construct the proposed facilities across wetlands (see section 4.4.2 for specific 

facilities located within wetlands) in accordance with applicable federal and state permits and the FERC

Procedures, except where alternatives to the standard FERC Procedures are warranted (see table 4.4.3-1). 

The wetland crossing methods and mitigation measures identified in the FERC Procedures are designed

to minimize the extent and duration of construction-related disturbance within wetlands. The FERC 

Procedures require a 75-foot-wide construction right-of-way through wetlands. Trunkline would comply 

with this requirement except in areas along the Mainline Connector where Trunkline has determined a 

wider right-of-way would be necessary to accommodate installation of the 42-inch-diameter pipeline in

saturated wetland soil conditions. Trunkline has requested a 100-foot-wide construction right-of-way in 

these areas to allow for sufficient trench slopes and enough space to contain excavated material within the 

approved construction area. Section 4.4.3 provides information on Trunkline’s requested deviations from

the FERC Procedures.

In wetlands, trees and brush would be removed from the construction workspace and vegetation 

would be cut just above ground level, leaving existing root systems intact. Stumps would be removed 

only directly over the trench line (minimum 10 feet), except in areas that would be permanently converted 

to upland or where it is determined that the stumps present a safety hazard for construction. Retaining the 

stumps and root systems where practicable helps to stabilize the soil and promote re-sprouting by some 

species. Debris would be removed from the wetland and stockpiled within an upland area of the right-ofway for proper disposal.

Immediately after initial ground disturbance, erosion control devices would be installed across the 

right-of-way at all wetlands and along the limits of the right-of-way directly upslope of the wetlands as 

needed. All sediment barriers would be maintained during construction and repaired/replaced as 

necessary until permanent erosion controls are installed or restoration of adjacent upland areas is 

complete.

A backhoe would be used to excavate a trench to the proper depth to allow for the burial of the 

pipe with a minimum of 3 feet of cover as required by the DOT regulations at 49 CFR 192. The top 

12 inches of topsoil over the trenchline would be segregated in unsaturated wetlands with firm substrates. 

Trench spoil would be temporarily stored in a ridge along the pipeline trench and segregated as required. 

Gaps in the spoil pile would be left at appropriate intervals to provide for natural drainage of water.

Where practicable, the pipeline would be assembled in an upland staging area during trench 

excavation. Pipe assembly would occur in the wetland only if site conditions are dry enough to support 

the skids and pipe. Either low ground weight bearing equipment would be used, or standard equipment 

would be operated from travel mats to minimize rutting and inadvertent mixing of topsoil with subsoil.

Trunkline may use the push/pull method to install the pipeline in inundated or excessively wet areas that 

cannot support the standard installation methods.

After the pipeline is lowered into the trench and backfilled, the disturbed areas would be graded 

to preconstruction contours, restored in accordance with the FERC Procedures, and monitored until 

revegetation is successful. 
2-28

2.6.3.3 Waterbody Crossings

The FERC defines a waterbody as any natural or artificial stream, river, or drainage with 

perceptible flow at the time of crossing, and other permanent waterbodies such as ponds and lakes. 

Trunkline would implement the measures in the FERC Procedures to minimize the extent and duration of 

construction disturbance on waterbodies. With the exception of the initial clearing equipment, only the 

equipment necessary for in-stream excavation and backfilling would be allowed in the stream channel. 

All other construction equipment would cross the waterbody on temporary equipment bridges, which 

would be constructed in accordance with the FERC Procedures. Trunkline would maintain water flow at 

waterbody crossings.

Trunkline proposes to use the open-cut or HDD methods to cross the waterbodies along the 

pipeline route. Dry crossing methods (flume or dam-and-pump) are sometimes used to cross waterbodies 

up to 30 feet wide (at the water’s edge at the time of construction) that are state-designated as either 

coldwater or significant coolwater or warmwater fisheries, or federally designated as critical habitat. 

Trunkline is not proposing to cross any waterbodies using the dry crossing method; therefore, this method

will not be further discussed in this EIS. Any modifications during construction to the methods described 

in this EIS and Trunkline’s filings would require review and approval by the FERC and other applicable 

agencies prior to their implementation.

Open-cut Crossing Method

The open-cut crossing technique is a “wet” crossing method that is completed while the 

waterbody continues to flow across the work area. The open-cut crossing method is typically used to

cross non-sensitive minor and intermediate waterbodies (width greater than 10 feet but less than or equal 

to 100 feet between the water’s edges). In general, an open-cut crossing is accomplished using methods 

similar to conventional upland open-cut trenching. The open-cut construction method involves 

excavation of the pipeline trench across the waterbody, installation of a pre-fabricated segment of 

pipeline, and backfilling of the trench with native material without affecting or diverting flow at the time 

of crossing. Trunkline would use a backhoe or other similar equipment operating from one or both 

waterbody banks to excavate the trench within the water. Material excavated from the trench would be 

stored at least 10 feet from the water’s edge in accordance with the FERC Procedures. Trunkline would 

minimize the introduction of sediment into waterbodies from disturbed upland areas by installing and 

maintaining sediment barriers (silt fences and/or straw bales) at stream crossings. Trunkline would 

complete construction activities at these stream crossings within the timeframes indicated in the FERC 

Procedures, typically within 24 hours of initiation of the crossing for minor waterbodies and within

48 hours for intermediate waterbodies, unless bedrock is encountered.

Horizontal Directional Drill

The HDD method is a trenchless crossing method used to avoid direct impacts on sensitive 

resources (such as waterbodies and wetlands) or infrastructure (major roads and railroads) by conducting 

a deep bore beneath them. This method requires specialized equipment and personnel and has four 

general steps:

1. placement of guide wires over the anticipated path of the drill;

2. drilling a pilot hole on an arc-shaped path that typically extends between 30 and 50 feet 

beneath the waterbody or other sensitive feature;
2-29

3. enlarging the pilot hole with a series of reamers to accommodate the pipeline; and

4. pulling a pre-fabricated section of pipe through the hole.

The HDD method involves an entry and exit pad on each side of the crossing. The initial step of 

placing HDD guide wires over the path of the drill may require minor hand clearing of woody vegetation 

and/or branches. A pilot hole is drilled under the waterbody and banks. The head of the pilot drill string 

contains a pivoting head that can be controlled by an operator as the drill progresses. Typically, the pilot 

hole would be directed downward at an angle until the proper depth is achieved, then turned and directed 

horizontally for the required distance, and finally angled upward back to the surface. Throughout the 

process of drilling and enlarging the hole, mud slurry, consisting of bentonite and water, would be 

pressurized and pumped through the drill stem to lubricate the drill bit, maintain the hole, and remove 

drill cuttings. Bentonite is the commercial name for a nontoxic mixture of nontoxic clays and rock 

particles consisting of about 85 percent montmorillonite clay, 10 percent quartz and feldspars, and 

5 percent accessory materials, such as calcite and gypsum. This slurry, referred to as drilling mud or 

drilling fluid, has the potential to be inadvertently released to the surface if fractures or fissures are 

encountered in the substrate during drilling.

The potential for an inadvertent release is generally greatest during drilling of the pilot hole when 

the pressurized drilling mud is seeking the path of least resistance and near the drill entry or exit pits 

where the drills are at their shallowest depths. The path of least resistance is typically back along the path 

of the drilled pilot hole. However, if the drill path becomes temporarily blocked or encounters areas such 

as large fractures or fissures that lead to the ground, then an inadvertent release could occur. Trunkline

developed a site-specific HDD plan for each drill site and a Horizontal Directional Drill Contingency 

Plan (HDD Contingency Plan) to monitor for, contain, and clean up any inadvertent releases of drilling 

fluid during HDD operations. The HDD Contingency Plan is included in appendix D. Additional

information on waterbody crossings, including the use of the HDD method, is presented in section

4.3.2.2.

2.6.3.4 Residential Areas

Lake Charles LNG identified one residence within the proposed liquefaction facility site on the 

west side of Big Lake Road; however, the tract has since been purchased for the liquefaction facility. No

residential structures or buildings are located within 50 feet of any of the proposed project facilities. 

Access to all rural residences in the project area would remain open throughout construction and 

operation of the project. 

2.6.3.5 Agricultural Areas

The project crosses several agricultural areas, including:

 pasture lands (liquefaction facility, Non-Liquefaction Facilities);

 land used for row and field crops, including soybean and rice, or alternately crayfish 

farming (Non-Liquefaction Facilities); and

 pine plantations (Mainline Connector and Mainline 200-3 Loop). 

Trunkline would implement the FERC Plan in these areas to minimize impacts on current 

agricultural uses. Prior to starting construction in agricultural areas, Trunkline would coordinate with 

landowners to determine the location of existing drainage structures and irrigation facilities. Irrigation 
2-30

system water flow would be maintained throughout construction if possible. Any required irrigation 

system shut off would be coordinated with the affected parties.

In accordance with the FERC Plan and in coordination with the landowner(s), topsoil would be 

removed to its actual depth, up to a maximum of 12 inches, and stockpiled separately from the subsoil 

excavated from the pipeline trench. During construction, Trunkline would maintain the natural flow 

patterns of all fields by providing breaks in the stockpiles of topsoil and subsoil. In addition, flow would

be maintained in drainage systems during construction to prevent ponding in adjacent non-disturbed 

areas.

After pipeline installation, Trunkline would follow the restoration and revegetation practices 

outlined in the FERC Plan. Any soil rutting or compaction would be repaired prior to revegetation of the 

disturbed areas. All stones at the surface larger and/or in higher densities than those in adjacent 

undisturbed areas would be collected and properly disposed of per the requirements described in the 

FERC Plan. 

Impacts on agricultural lands would be limited to the construction periods except where 

conversion to an industrial/commercial land use is proposed. Following construction, the agricultural

lands affected by the project would be restored to their previous use, except for limited clearing of the 

pipeline rights-of-way for maintenance. In addition, any drain tiles or systems damaged during 

construction would be returned to original or better condition.

No special construction techniques would be used within pine plantations unless requested by the 

landowners; the landowner would be allowed to replant the temporary construction right-of-way. For the 

areas alternately used for growing rice and raising crayfish, the landowner(s) would be compensated for 

crop loss due to construction activities. 

2.6.4 Aboveground Facilities Construction Procedures

Site preparation, including clearing, grading, and compacting, would be conducted where 

necessary. Excavations would be performed as necessary to accommodate the new reinforced concrete 

foundations for the new compressors, pigging facilities, metering equipment, and buildings. Subsurface 

piles could be required to support the foundations, depending upon the bearing capacity of the existing 

soils and the equipment loads. Forms would be set, rebar installed, and the concrete poured and cured in 

accordance with applicable industry standards. Concrete pours would be randomly sampled to verify 

compliance with minimum strength requirements. Backfill would be compacted in place, and excess soil 

would be used elsewhere or distributed around the site to improve grade.

Materials and equipment would be shipped to the site by truck and offloaded using cranes, frontend loaders, or both. The equipment would be positioned on the foundations, leveled, grouted where 

necessary, and secured with anchor bolts. All non-threaded piping associated with the aboveground 

facilities would be welded, except where connected to flanged components. All welders and welding 

procedures would be qualified in accordance with American Petroleum Institute standards. Welds in gas 

piping systems would be examined using non-destructive testing in accordance with applicable codes.

All components in high-pressure natural gas service would be pressure tested prior to arrival or 

on site, and all controls and safety equipment and systems, emergency shutdown, relief valves, and gas 

measurement and control equipment would be commissioned prior to being placed in service.

Disturbed surface areas would be restored, and stabilization measures installed in a timely manner 

in accordance with the FERC Plan and Procedures.
2-31

2.7 OPERATION, MAINTENANCE, AND SAFETY PROCEDURES

2.7.1 Liquefaction Facility and LNG Terminal

Lake Charles LNG would operate its liquefaction facility and LNG terminal in compliance with 

federal requirements for LNG facilities (see table 1.5-1), which include operation, emergency, and 

security procedures. The liquefaction facility and LNG terminal would meet NFPA 59A LNG Standards. 

Safety controls would be designed, constructed, operated, and maintained in accordance with DOT 

federal safety standards for LNG facilities at 49 CFR 193. In addition, Lake Charles LNG would update 

the existing LNG terminal’s operations manual(s) as needed to include the new liquefaction facility and

submit amendments to the agencies prior to commissioning the facility. The plans would include written 

procedures consistent with corporate policy and federal standards, including DOT regulations at 33 CFR 

127.401 and 49 CFR 193(G).

The liquefaction facility and LNG terminal would be operated from a central control room. The 

control room would be fully integrated with all facility hazard detection and control, security, and 

emergency shutdown systems. LNG storage tank systems and ship loading would also be monitored from 

the control room.

All facility operations and maintenance personnel would be trained to properly and safely 

perform their duties. The facility operators would be trained in the potential hazards associated with 

LNG, cryogenic operations, and the proper operations of all the equipment. The operators would meet all 

the training requirements of the Coast Guard, DOT, Louisiana State Fire Marshal, and other regulatory 

entities, as well as the requirements of Lake Charles LNG.

The facility full-time maintenance staff would conduct routine maintenance and minor overhauls. 

Major overhauls and other major maintenance would be handled by outside maintenance personnel 

specifically trained to perform the required activities. All scheduled and unscheduled maintenance would

be entered into a computerized maintenance management system.

2.7.1.1 Spill Containment System

There would be three liquefaction trains at the liquefaction process area. Each liquefaction train 

would include two insulated concrete impoundment sumps: 1) the Liquefaction Area Sump would be 

located south of the liquefaction train and contain LNG or refrigerant liquid spills from liquefaction 

facilities; and 2) the NGL Impoundment would be located north of the liquefaction train and serve 

hydrocarbon liquid spills from the NGL extraction facilities. Lake Charles LNG proposes to construct 

two other insulated concrete impoundment sumps to contain any spills along the rundown lines between 

the liquefaction area and the LNG storage tank area. Furthermore, any potential spills at the LNG storage 

tank area from the rundown lines during liquefaction operation or from the in-tank pump withdrawal 

header during export operation would drain toward the existing Tank Area Impoundment Sump. 

Lake Charles LNG also proposes to install a Refrigerant Storage Impoundment at the refrigerant 

storage area to contain any spills from the refrigerant make-up tanks and the refrigerant trucks. 

Additional information regarding spill containment system for the stabilized condensate product storage 

tank, Amine Storage Tank, and Aqueous Ammonia Storage Tank is presented in section 4.12.5.1.

2.7.1.2 Hazard and Fire Detection System

The liquefaction facility would have a variety of strategically located fire and gas monitoring 

systems that would provide detection of flammable gas releases or fires throughout all potentially affected 
2-32

areas of the facilities. The monitoring system would be hard-wired from the field devices to the new 

central control room. Any detection would provide an alarm at the control console. The fire and gas 

monitoring system would include detectors for:

 flammable gas; 

 low temperature;

 ultraviolet/infrared fire and flame to indicate ignition of flammable vapors;

 high temperature to detect a fire; and

 smoke.

Additional detail regarding the hazard detection system is provided in section 4.12.3.

2.7.1.3 Firewater and High Expansion Foam System

The existing LNG terminal has a fire protection system that would provide protection for the new 

equipment added in the LNG storage and loading areas. Lake Charles LNG would install a similar

firewater supply and distribution system for the new liquefaction facility, consisting of a looped firewater 

header, fire monitors, fire headers, hose reels, dry chemical, and high expansion foam systems. 

Additional detail regarding the fire protection system can be found in section 4.12.3.

2.7.1.4 Emergency Shutdown System

Lake Charles LNG would install an emergency shutdown system for the new liquefaction facility 

that would be integrated with the existing LNG terminal’s system. The emergency shutdown system

would consist of separate shutdown sequences that would result in total plant shutdown, shutdown of ship 

loading/unloading; shutdown of the sendout system; and/or shutdown of individual pieces of equipment, 

depending on the type of incident. Audible and visual alarms would be throughout the facility to alert 

personnel in affected locations (inside and outside) and in the control room.

2.7.2 Pipelines

Trunkline would operate and maintain all of its pipeline facilities in accordance with the DOT 

regulations in 49 CFR 192, other applicable federal and state regulations, and in accordance with industry 

standard procedures designed to ensure the integrity of the pipeline and minimize the potential for pipe 

failure. Trunkline would inspect the pipeline for leakage as part of scheduled operations and maintenance 

in accordance with 49 CFR 192.

Pipeline operational activity would be limited primarily to maintenance of the right-of-way and 

inspection, repair, and cleaning of the pipelines. Trunkline would maintain vegetation on the permanent 

right-of-way in upland areas by mowing, cutting, and trimming, except in areas of actively cultivated 

cropland and in accordance with the FERC Plan and Procedures. The entire construction right-of-way 

would be allowed to revegetate; however, large brush and trees would be periodically removed near the 

pipeline. In accordance with the FERC Procedures, Trunkline would not conduct vegetation maintenance 

over the full width of the permanent right-of-way in forested wetland areas. However, a corridor up to 

10 feet wide centered on the pipeline would be maintained in an herbaceous state to facilitate periodic 

pipeline corrosion/leak surveys. In addition, trees within 15 feet of the pipeline with roots that could 

compromise the integrity of the pipeline coating would be selectively cut and removed from the 

permanent right-of-way. No routine vegetation mowing or clearing would occur in wetlands over HDD 

easements where the pipeline is greater than 10 feet deep. Pipeline inspection would be accomplished by 

means identified in the pipeline integrity management program in accordance with applicable laws and 

regulations.
2-33

Trunkline would install pipeline identification markers at line-of-sight intervals and at crossings 

of roads, railroads, waterbodies, and other key points in accordance with DOT regulations. The markers 

would clearly indicate the presence of the pipeline, identify Trunkline as the pipeline operator, and 

provide telephone numbers where a Trunkline representative could be reached in the event of an 

emergency or prior to any excavation in the area by a third party. As part of its effort to prevent any 

third-party damage to the pipeline, Trunkline is also a member of the “One Call” system in all states 

where it currently has operational facilities.

2.7.2.1 Corrosion Protection and Detection System

During construction of the pipeline facilities, Trunkline would install a cathodic protection 

system to prevent or minimize corrosion of the buried pipelines and aboveground facilities. A cathodic 

protection system impresses a low-voltage current on a pipeline to offset natural soil and groundwater 

corrosion potential. The pipeline would be designed to allow the use of internal inspection technology. 

The condition of the pipe coating and the effectiveness of the cathodic protection system would be 

monitored in accordance with federal standards and regulations. If defects are detected during the 

monitoring, Trunkline would repair the pipe, pipe coating, or the cathodic protection system.

2.7.2.2 Pipeline Emergency Response Procedures

The DOT regulations at 49 CFR 192 (Transportation of Natural and Other Gas by Pipeline: 

Minimum Federal Safety Standards) are intended to ensure adequate protection for the public and prevent 

natural gas pipeline facility accidents and failures. Part 192 specifies material selection and qualification, 

minimum design requirements, and protection from internal, external, and atmospheric corrosion. Part 

192 also prescribes the minimum standards for operating and maintaining pipeline facilities, including the 

requirement to establish a written plan governing these activities. Under Section 192.615, each pipeline 

operator must also establish an emergency plan that includes procedures to minimize the hazards in a 

natural gas pipeline emergency. Key elements of the plan include the following:

 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;

 making personnel, equipment, tools, and materials available at the scene of an 

emergency;

 protecting people first and then property, and ensuring safety from actual or potential 

hazards; and

 emergency shutdown of the system and safe restoration of service.

Part 192 also requires that each operator establish and maintain a liaison with appropriate fire, 

police, regulatory, 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. Trunkline 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.

3-1

3.0 ALTERNATIVES

As required by NEPA and FERC policy, we evaluated alternatives to the Lake Charles 

Liquefaction Project and its various components to determine whether any such alternatives would be 

reasonable and have significant environmental advantages compared with the proposed action. The range 

of alternatives analyzed included the No-Action Alternative, system alternatives for both the proposed 

liquefaction facility and the Non-Liquefaction Facilities, alternative sites for the liquefaction facility, 

alternative configurations for the liquefaction facility, alternative pipeline routes, alternative aboveground 

facility sites for the Non-Liquefaction Facilities, and alternative power sources for the liquefaction facility

and Compressor Station 203-A. In some cases, our analysis concluded that consideration of alternatives 

was not feasible or required and this is indicated where applicable.

As part of the No-Action Alternative, we considered the effects and actions that could 

conceivably result if the proposed Lake Charles Liquefaction Project were not constructed. Under the 

analysis of system alternatives, we evaluated the ability of other existing, planned, or proposed (new or 

expanded) LNG export terminals and pipeline systems to meet Lake Charles LNG’s and Trunkline’s

project objectives. Our evaluation of alternative sites for the liquefaction facility focused on several 

locations, all close to the existing Trunkline LNG Terminal. For the aboveground facilities associated 

with the Non-Liquefaction Facilities, we focused on alternative sites for the proposed new compressor 

station in Calcasieu Parish. Our primary consideration of pipeline route alternatives related to the 

proposed Mainline Connector pipeline, an 11.4-mile-long greenfield facility. 

The principal criteria for considering and weighing the alternatives for the Lake Charles 

Liquefaction Project were:

 the technical and economic feasibility and practicality of each alternative;

 the significance of each alternative’s environmental advantages and disadvantages 

relative to the proposed undertaking; and

 the ability of each alternative to reasonably meet Lake Charles LNG’s and Trunkline’s 

primary objective of liquefying 15.0 MTPA of domestically produced natural gas for 

foreign export as competitively priced LNG within a timeframe that would allow 

contractual obligations to be met.

BG LNG is the sole holder of capacity at the Trunkline LNG Terminal.

Lake Charles LNG and Trunkline participated in our pre-filing process during the preliminary 

design stage of the Lake Charles Liquefaction Project (see section 1.3). This process emphasized 

identification of stakeholder issues, as well as identification and evaluation of alternatives that could 

reduce environmental impacts. We analyzed each alternative based on public comments and guidance 

received from federal, state, and local regulatory agencies. Additional sources of information included

Lake Charles LNG’s and Trunkline’s field surveys, aerial photography, U.S. Geological Survey (USGS)

topographic maps, National Wetlands Inventory (NWI) maps, pipeline system maps, agency 

consultations, and publicly accessible databases. To ensure equitable results, consistent data sources were 

used when comparing a feature across alternatives (e.g., NWI data were used for wetlands comparisons, 

rather than a combination of NWI and field survey data.) The scope, methodology, and results of our 

alternatives analyses are discussed in the following sections.
3-2

3.1 NO-ACTION ALTERNATIVE

Under the No-Action Alternative, the Lake Charles Liquefaction Project would not be developed 

and Lake Charles LNG’s and Trunkline’s objective of providing the proposed liquefaction and 

transportation capacity for LNG export would not be realized. In addition, the potential adverse and 

beneficial environmental impacts discussed in section 4.0 of this EIS would not occur.

The development and production of gas supplies from conventional and unconventional gas 

formations has increased in recent years throughout many areas of the United States and is projected to 

continue for decades. With or without the No-Action Alternative, other LNG export projects could be 

developed in the Gulf Coast region or elsewhere in the United States, resulting in both adverse and 

beneficial environmental impacts. Terminal and pipeline system expansions of similar scope and 

magnitude to the Lake Charles Liquefaction Project would likely result in environmental impacts of 

comparable significance, especially those projects in a similar regional setting. LNG export terminal 

developments on greenfield sites, without the attendant marine facilities, LNG storage, and pipeline 

infrastructure offered by an existing import terminal, would likely result in greater environmental impacts 

than projects at established sites, such as the Lake Charles Liquefaction Project.

The No-Action Alternative could require that potential end users make different arrangements to 

obtain natural gas service, use other fossil fuel energy sources (e.g., coal or fuel oil), or possibly use 

traditional long-term energy sources (e.g., nuclear power) and/or renewable energy sources (e.g., solar 

power) to compensate for the lack of natural gas that would otherwise be supplied by the Lake Charles 

Liquefaction Project. Although the No-Action Alternative could also be aligned with a drive to promote 

international energy conservation, this sphere of discussion lies beyond our analytical scope.

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 more recent, advanced energy alternatives. 

Conceivably, each of these energy alternatives could support the generation of electric power, which, 

along with residential heating, commercial, and industrial uses, is a major consumer of natural gas.

The International Energy Agency (IEA) (2014b) indicates that the global market for coal remains 

buoyant although it will increasingly be replaced by natural gas and low-carbon fuels in the energy mix. 

Demand for coal will decrease in China and all countries in the Organization for Economic Co-operation 

and Development, including the United States, due to new air pollution and climate policies. However, 

demand will continue to grow rapidly in India for an overall demand growth for coal of 0.5 percent per 

year. In the United States, several new coal export projects have been proposed recently, suggesting that 

coal will remain competitive with natural gas as an international commodity in the foreseeable future, 

despite coal’s greater air emissions. Similarly, fuel oil, which also produces greater emissions, is 

commonly used for power generation in many countries and will continue to compete with natural gas as 

a fuel source. The EPA (2013a) states that natural gas-fired electric generation, compared with the 

average air emissions from coal-fired electric generation, produces half as much carbon dioxide (CO2), 

less than a third as much nitrogen oxides (NOX), and 1 percent as much sulfur oxides (SOX). In addition, 

combustion of natural gas is not a significant source of mercury emissions (EPA, 2013a). In addition to 

power generation, fuel oil is used in the shipping industry. New legislation will limit sulfur content of 

marine fuels. Specifically, the International Convention for the Prevention of Pollution from Ships 

(MARPOL) is the main international convention covering prevention of pollution of the marine 

environment by ships from operational or accidental causes. Annex VI of MARPOL establishes limits on 

NOX emissions and the sulfur content of marine fuels. By 2020, Annex VI will require the reduction of 

sulfur content of marine fuels to 0.5 percent on a global basis. In order to comply with this requirement, 
3-3

ship operators will be required to install SOX emission reduction equipment or switch to low sulfur fuels, 

such as LNG. 

If the No-Action Alternative is selected, it could result in the continued use of less clean-burning 

fossil fuels at levels that might otherwise have been reduced through replacement with LNG; it could also 

result in the increased consumption of other fossil fuels to satisfy any future growth in demand that might 

otherwise be addressed in whole or part by LNG. Consequently, the more severe air emissions and other 

adverse environmental impacts associated with the use of less clean-burning fossil fuels would not be 

reduced and may increase if the No-Action Alternative were to be adopted, irrespective of the fact that 

many countries are cognizant of the environmental impacts of these fuels and prefer to use natural gas as 

an energy source.

There has been a recent renewed interest in nuclear fuel as a source of electric power generation, 

although the U.S. Energy Information Administration (2014a) estimates the proportion of electricity 

generated in the United States by nuclear power will decrease from 19 percent to 16 percent by 2040, 

with actual nuclear generating capacity remaining fairly static over the long term. Whereas global nuclear 

capacity is still projected to rise, led by China, Korea, India, and Russia (IEA, 2012a, 2014b), regulatory 

hurdles, public concerns over facility safety and nuclear waste disposal, project costs, and plant 

construction lead times make it unlikely that sufficient nuclear capacity could be available to serve all the 

markets targeted by the Lake Charles Liquefaction Project on a compatible timeline. Further, plans for 

nuclear power generation have been scaled back in some countries, reflecting policy reconsideration 

following the 2011 accident at the Fukushima Daiichi nuclear power plant near Fukushima, Japan (IEA, 

2012a).

Renewable sources may become an increasingly significant factor in meeting future energy 

demands worldwide. Hydropower is the predominant renewable source for electric power generation, 

which contributes to more than 16 percent of electricity generation worldwide and about 85 percent of 

global renewable electricity (IEA, 2014a). The IEA expects hydropower to remain as the predominant 

renewable energy source through 2035 (IEA, 2013). However, as with nuclear power generation, there 

are high costs associated with developing substantial hydropower projects and a long development time 

between project conception and operation. Other promising renewable energy resources include solar, 

ocean energy, biomass, and wind, as discussed in more detail below.

With respect to solar energy, photovoltaic production is increasing as the cost of photovoltaic 

systems decreases. Photovoltaic cells have the potential to supplement electric power generation 

resources. In 2012 solar energy accounted for 2.2 percent of global electricity production (Observ’ER, 

2013).

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 placing power-generating facilities in the ocean. In 2012, ocean energy 

accounted for 0.01 percent of global electricity production (Observ’ER, 2013). 

Biomass categories for electric power generation include solid biomass, liquid biomass, biogas, 

and renewable household waste. Like ocean energy, this is an emerging area of study and biomass 

research covers diverse applications. For example, researchers are working to accelerate the development 

of applications that use algal biomass as a fuel source. Burning of wood pellets in Europe for power 

generation is increasing, and wood pellet exports from the United States to Europe increased to over 

3 million short tons per year in 2013 (Energy Information Administration, 2014b). In 2012, biomass 
3-4

sources accounted for 1.4 percent of global electricity production (Observ’ER, 2013). The IEA (2012a) 

projects a four-fold increase in biomass consumption for electric power generation through 2035. 

Further growth of wind-generated electric power requires construction of new wind turbines and 

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 electricity production because of its inherent variability, 

and back-up modes of power generation are commonly required. In 2012, wind power accounted for 

2.4 percent of global electricity production (Observ’ER, 2013).

In 2012, renewable energy sources (solar, marine, biomass, wind, geothermal, and hydropower) 

accounted for 20 percent of global electricity production (Observ’ER, 2013). Renewables are projected to 

become the world’s second-largest source of power generation in the next couple of years, and are 

expected to challenge coal as the primary source by 2040, when they will fuel 33 percent of global 

electricity production (IEA, 2014b). However, compared with natural gas-fired power generation, the 

cost of renewable energy projects per energy output unit is currently high and any significant increase in 

their relative contribution to global electric power generation hinges critically on continued subsidies. 

In 2013, these subsidies amounted to $121 billion, but to reach the projection noted above, the subsidies 

would need to increase to $230 billion by 2030, before falling to $205 billion in 2040 due to support 

commitment and capacity schedules (IEA, 2014b).

Natural gas is often considered a “bridge fuel,” meaning a fuel that bridges the timespan 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 serve as a reliable backup fuel to 

renewable energy facilities, which characteristically provide power on an intermittent basis.

There is currently considerable momentum behind advancing renewable energy technologies and 

moving towards more diversified energy sources. These advanced technologies, either individually or in 

combination, will likely be important in addressing future energy demands. However, whereas 

renewables are forecast to gain increasing global prominence as energy sources for electric power 

generation over the next two decades, this trend does not reflect any corresponding decrease in natural gas 

demand; rather, an increase approaching 50 percent in worldwide gas demand is predicted over the same 

timespan (IEA, 2013). Based on this forecast, the increased use of renewable energy sources does not 

constitute a reasonable alternative to the Lake Charles Liquefaction Project.

Although it is speculative and beyond the scope of this analysis to predict what actions might be 

taken by policymakers or end users in response to the No-Action Alternative, it is possible that the energy 

needs to be satisfied by the Lake Charles Liquefaction Project would be met largely by other fossil fuel 

energy sources, such as coal and oil, resulting in more air emissions and greater environmental impacts. 

Renewable sources are not always reliable or available in sufficient quantities to support most market 

requirements and would not necessarily be appropriate substitutes for natural gas in all applications. 

Similarly, the use of nuclear power in lieu of natural gas would depend on geographic availability and 

could be especially problematic from the perspective of negative public perception. 

Based on our consideration of environmental impacts and the evident lack of viable energy source 

alternatives, we have dismissed the No-Action Alternative as a reasonable alternative to meet the 

objectives of the Lake Charles Liquefaction Project. Because the purpose of the project is to prepare 

natural gas for export to foreign markets, the development or use of renewable energy technology would 

not be a reasonable alternative to the proposed action.
3-5

3.2 SYSTEM ALTERNATIVES

We reviewed system alternatives to evaluate the ability of other existing, modified, approved, 

planned, or proposed facilities to meet the stated objectives of the Lake Charles Liquefaction Project and 

to determine if a system alternative exists that would have less significant adverse environmental impacts 

than those associated with the project.

1

 The status identified for each system alternative (e.g., planned, 

proposed, or approved) is current as of the time this EIS is being written, and is subject to change over 

time. Our analyses of system alternatives for the proposed liquefaction facility and Non-Liquefaction 

Facilities are presented in sections 3.2.1 and 3.2.2, respectively. By definition, implementation of a 

system alternative would make construction of all or some of the proposed facilities unnecessary; 

conversely, infrastructure additions or other modifications to the system alternative may be required to 

increase capacity or provide receipt and delivery capability consistent with that of the proposed facilities. 

Such modifications may result in environmental impacts that are less than, comparable to, or greater than 

those associated with construction and operation of the proposed facilities. 

3.2.1 Liquefaction Facility Alternatives

For a system alternative to be viable, it must be technically and economically feasible, as well as 

offer a significant environmental advantage over the proposed project. In the case of the Lake Charles 

Liquefaction Project, it must also be compatible with Lake Charles LNG’s contractual agreements for 

LNG export. 

Lake Charles LNG is proposing to export LNG to FTA and non-FTA countries. The volume of 

gas for FTA countries has already been approved by the DOE (and therefore is determined to be in the 

public interest). The DOE determination for non-FTA countries is pending. The other approved, 

planned, or proposed LNG export facilities have also either obtained or applied for DOE approval for the 

export of LNG associated with the production capacity in the respective project plans/proposals. 

Therefore, for Lake Charles LNG’s customers to obtain LNG from other facilities that have DOE approval 

for export, those facilities would need to construct additional liquefaction facilities to meet the export 

capacity proposed by Lake Charles LNG, and as approved by the DOE authorizations. We recognize that 

liquefaction capacity may not be fully subscribed at all facilities based on contracts executed as of the 

writing of this EIS. However, because the DOE’s export approval is a determination that the export is in 

the public interest, we will not speculate that any portion of other LNG terminals’ liquefaction capacity is 

in “excess” or available for use by Lake Charles LNG to meet its project objectives. 

An expansion of existing facilities would need a similar scope of pre-treatment and liquefaction 

facilities and possibly additional storage and marine transfer facilities, while any new facility would need 

a similar scope of pre-treatment, liquefaction, storage, and marine transfer facilities. These additional 

facilities would result in environmental impacts that are less than, equal to, or greater than the 

environmental impacts of the proposed facility and may not provide a significant environmental 

advantage over the proposed project. Each of the planned, proposed, or authorized projects described in 

sections 3.2.1.1 and 3.2.1.2 was considered as a potential system alternative (see section 4.13 for 

additional information on project locations). Our analysis was predicated on the assumption that each 

project has an equal chance of being constructed and would therefore be available as a potential 

alternative. However, future Commission review and market forces will ultimately decide which and how 

many of these facilities are built.

 

1

Proposed projects are projects for which the proponent has submitted a formal application to the FERC; planned projects are 

projects that are either in pre-filing or have been announced, but have not been proposed.
3-6

3.2.1.1 Existing LNG Import Terminals with Approved, Proposed, or Planned Liquefaction 

Projects

In addition to the Trunkline LNG Terminal, there are six operating LNG import terminals along 

the Gulf Coast in the southern United States, all of which are associated with approved, proposed, and/or 

planned expansions to provide liquefaction capabilities, as identified below. 

Approved

 Cameron LNG, LLC (Cameron LNG) Terminal 

 Freeport LNG Development, LP (Freeport LNG) Terminal

 Sabine Pass LNG, LP (Sabine Pass LNG) Terminal and Sabine Pass LNG Terminal –

Trains 5 and 6

Proposed

 Golden Pass LNG, LLC (Golden Pass LNG) Terminal

 Gulf LNG Liquefaction Company, LLC (Gulf LNG) Terminal 

Planned

 Main Pass Energy Hub Deepwater Port

 Cameron LNG Terminal – Trains 4 and 5

 Freeport LNG Terminal – Train 4

Liquefaction and export facilities are under construction at the Sabine Pass LNG, Cameron LNG, 

and Freeport LNG Terminals and may be constructed at each of the other import terminals pending 

completion of regulatory review and permitting. Each of the above terminals and, where applicable, their 

associated expansions was evaluated as a potential system alternative to the Lake Charles Liquefaction 

Project. Although it might be theoretically possible to move Lake Charles LNG’s total liquefaction 

capacity to any of the other six terminal locations by building additional infrastructure alongside 

previously announced expansion facilities, the commercial, technical, environmental, and schedule 

impediments to such an undertaking preclude further analysis. Although the design production capacity 

of Lake Charles LNG’s proposed liquefaction facility is 16.45 MTPA of LNG, authorization has been 

secured from the DOE’s Office of Fuel Energy to export 15.0 MTPA, reflecting allowances for design 

margins, maintenance, and outages. For the purposes of evaluating system alternatives, we have used the 

LNG volumes requested from or authorized by the DOE for export, including 15.0 MTPA for the Lake 

Charles Liquefaction Project. 

Table 3.2.1-1 provides a summary of the liquefaction projects listed above, the criteria used to 

evaluate their system alternatives status, and the results of the evaluation in each case. Further details for 

each project are provided in the text that follows the table.

Cameron LNG Terminal

The Cameron LNG Terminal is located on the Calcasieu Ship Channel, near Hackberry, 

Louisiana, about 5 miles south-southwest of the Trunkline LNG Terminal. It started operation as an LNG 

import terminal in 2009 and received authorization in 2010 to re-export foreign-sourced LNG. The 

existing facilities include vaporization units and three 160,000-m

3 LNG storage tanks with a sustained 

send-out capacity of 1.8 Bcf/d and maximum send-out capacity of 2.1 Bcf/d. There are two LNG carrier 

berths, each capable of loading/unloading vessels ranging from 125,000 to 217,000 m3in size. 
3-7

TABLE 3.2.1-1

Existing LNG Import Terminals with Planned, Proposed, or Approved Liquefaction

Projects Along the Gulf Coast – Summary Profile as System Alternatives

Project MTPA

MTPA

Differential

FERC

Status

In-Service 

Target Date

Compatible 

Timeline for 

Additional 

Expansion

Less Environmental ImpactReasonable

Alternative

Approved Projects

Cameron 

LNG

14.95 –0.05 Authorized

06-19-14

2017–2018 No Unlikely No

Freeport 

LNG

13.2 –1.8 Authorized

7-30-14

2018–2019 No Unlikely No

Sabine Pass 

LNG

20.0 +5.0 Authorized

04-16-12

2016–2017 No Unlikely No

Sabine Pass 

LNG 

Expansion 

(Trains 5 

and 6)

9.0 –6.0 Authorized

04-06-15

2019 No Unlikely No

Proposed Projects

Golden Pass 

LNG

15.6 +0.6 Application filed 

7-7-14

2019–2020 No Unlikely No

Gulf LNG 10.0 –5.0 Application filed 

6-19-15

2019–2020 No Unlikely No

Planned Projects

Main Pass

Energy Hub 

Deepwater 

Port

24.0 +9.0 Not applicablea2017 No Not 

comparable

No

Cameron 

LNG 

Expansion 

(Trains 4 and 

5)

9.97 -5.03 Pre-filing 

initiated

3-2-15

2019 No Unlikely No

Freeport 

LNG 

Expansion

(Train 4)

5.1 -9.9 Pre-filing 

initiated 

5-18-15

2020 No Unlikely No

____________________

a

The Main Pass Energy Hub Deepwater Port would require authorizing from the U.S. Maritime Administration and the 

Coast Guard. Applications have not been filed to date.

Approved

Cameron LNG will construct three liquefaction trains, each capable of producing 4.99 MTPA of 

LNG, a fourth 160,000-m

3 LNG storage tank, and additional facilities on 502 acres, consisting of 70 acres 

within the existing terminal fenceline and 432 contiguous acres adjacent to the terminal. Concurrent with 

the terminal expansion, Cameron Interstate Pipeline, LLC will construct a new 56,820 hp compressor 

station, 21 miles of 42-inch-diameter natural gas pipeline, and associated facilities, to supply the gas for 

liquefaction. On January 17, 2012, Cameron LNG was granted DOE authorization to export up to 

12.0 MTPA of LNG (equivalent to 1.7 Bcf/d of vaporized natural gas) over 20 years to FTA countries. 

On April 9, 2015, the DOE authorized Cameron LNG to export an additional 2.95 MTPA of LNG 

(equivalent to 0.4 Bcf/d) to FTA countries over the same period, resulting in a total approved export 

volume of 14.95 MTPA (equivalent to 2.1 Bcf/d) of LNG. On September 10, 2014, Cameron LNG 

received approval from the DOE to export LNG over 20 years to non-Free Trade Agreement (non-FTA) 
3-8

nations. On May 9, 2012, Cameron LNG received approval to enter our pre-filing process 2for adding 

liquefaction and export facilities to the existing terminal. The formal application for the LNG facilities 

was filed with the Commission on December 7, 2012 3and the for the pipeline facilities on December 14, 

2012.

4

 The final EIS was issued on April 30, 2014. The FERC issued an Order Granting Authorization 

Under Section 3 of the Natural Gas Act and Issuing Certificates for the project on June 19, 2014. 

Cameron LNG’s project is currently under construction and has an in-service target date of early 2018 for 

the first train, mid-2018 for the second train, and end of 2018 for the third train.

Planned

On February 23, 2015, Cameron LNG submitted applications to export an additional 10.0 MTPA 

of LNG to both FTA countries and non-FTA countries over a 20-year period. On July 10, 2015, Cameron 

LNG received approval from the DOE authorizing export of up to 10.0 MTPA of LNG to FTA countries. 

On May 28, 2015, Cameron LNG re-filed its application for DOE approval to export 10.0 MTPA of LNG 

to non-FTA countries; DOE review of the application is pending. Cameron LNG plans to construct two 

liquefaction trains (Trains 4 and 5) with a capacity of 4.985 MTPA and a fifth 160,000-m

3 LNG storage 

tank (Tank 5). On March 2, 2015, the FERC initiated its pre-filing process for this expansion.

5

The customer bases for the two facilities do not overlap. Cameron LNG’s capacity is contracted 

to multiple customers, whereas Lake Charles LNG’s capacity is contracted solely to one mutually 

exclusive customer, BG LNG. Given the different customer bases, Cameron LNG’s terminal expansion 

could not meet Lake Charles LNG’s market-based objectives. Also, in both cases, the environmental 

impacts of the proposed facilities would likely be similar, so Cameron LNG’s Project would not provide a 

significant environmental advantage over the Lake Charles Liquefaction Project. Therefore, this system 

alternative was not evaluated further.

Freeport LNG Terminal

The Freeport LNG Terminal is located on Quintana Island in Brazoria County, Texas, about 

146 miles southwest of the Trunkline LNG Terminal. The import terminal, which started operations in 

2008, includes two 160,000-m

3 LNG storage tanks, vaporization units, and a single berth capable of 

handling LNG carriers in excess of 200,000-m

3

. It has a peak natural gas send-out capability of about

1.5 Bcf/d. Authorization to re-export foreign-sourced LNG was received in 2009. 

Approved

Freeport LNG and FLNG Liquefaction, LLC (collectively, Freeport LNG) are currently 

constructing liquefaction, storage, and export facilities at the existing terminal to provide LNG export 

capacity of about 13.0 MTPA (equivalent to 1.8 Bscf/d of vaporized natural gas). This project requires 

approximately 105 acres for three liquefaction trains (each with a nominal capacity of 4.4 MTPA) and 

ancillary facilities; one 160,000-m

3 LNG storage tank; a marine berthing dock; transfer facility; and an 

access road system. An off-site pre-treatment plant and interconnecting pipeline/utility line system are

also under construction. 

FLNG Expansion and FLNG Liquefaction, LLC (collectively, FLEX) filed two separate 

applications with the DOE, each to export up to 9.0 MTPA of LNG (equivalent to 1.4 Bcf/d of vaporized 

natural gas) over 25 years to FTA countries. The DOE approved the applications in February 2011 and 

 

2 Docket Nos. PF12-12-000 and PF12-13-000

3 Docket No. CP13-25-000

4 Docket No. CP13-27-000

5 Docket No. PF15-13
3-9

February 2012. On December 17, 2010, FLEX submitted an application to the DOE to export 9.0 MTPA

of LNG (equivalent to 1.4 Bcf/d of vaporized natural gas) over 25 years to non-FTA countries. On 

December 19, 2011, FLEX submitted a second application to export an additional 9.0 MTPA to non-FTA 

countries. FLEX received final DOE approval to export a total of 13.0 MTPA to non-FTA countries on 

November 14, 2014. On January 5, 2011, Freeport LNG received authorization to use the FERC prefiling process and filed its formal application with the Commission on August 31, 2012.6

 The FERC 

issued an Order Granting Authorization Under Section 3 of the Natural Gas Act for the project on July 

30, 2014.7 

On July 31, 2012, Freeport LNG Expansion announced a 20-year agreement with Osaka Gas and 

Chubu Electric for the liquefaction capacity (4.4 MTPA) of the first train. On February 11, 2013, 

Freeport LNG Expansion announced a 20-year agreement with BP for the liquefaction capacity 

(4.4 MTPA) of the second train. On September 9, 2013, Freeport LNG Expansion announced separate 

20-year agreements with Toshiba and SK E&S for the liquefaction capacity (4.4 MTPA) of the third train, 

split equally between the two companies. The project, which began construction in early 2015, is 

expected to begin operation in 2018, when the first liquefaction train will enter service; the remaining two 

trains will enter service in 2019, 48 to 54 months after initiation of construction. 

Planned

On June 3, 2015, Freeport Development entered into the FERC’s pre-filing process for the 

proposed Freeport LNG Liquefaction Expansion Project.8 The project would include one additional 

liquefaction train (Train 4) with a capacity of about 5.1 MTPA and supporting utility and auxiliary 

facilities and infrastructure. If approved, Freeport Development anticipates the project would enter 

service in 2020, 38 months after initiation of construction.

Freeport LNG’s approved liquefaction facilities are currently under construction and projected to 

enter full service about 1 year ahead of the Lake Charles Liquefaction Project (which is not scheduled to 

enter full service until 2020). Freeport Development’s planned liquefaction facilities (Train 4) are 

projected to enter service in the same general timeframe as the Lake Charles Liquefaction Project 

(in 2020). As described previously, Freeport LNG’s capacity is subscribed to multiple customers (Osaka 

Gas, Chubu Electric, BP, Toshiba, and SK E&S), whereas Lake Charles LNG’s capacity is contracted 

solely to one different customer, BG LNG. Given the different customer bases, Freeport LNG’s terminal 

expansion could not meet Lake Charles LNG’s market-based objectives. Furthermore, Freeport LNG 

would need to further expand its facility similar to the proposed project to add the additional 15.0 MTPA 

liquefaction capacity proposed by Lake Charles LNG, which would likely result in substantially similar 

environmental impacts, and a permitting and review process that would begin substantially later than the 

process for the Lake Charles Liquefaction Project. Therefore, this system alternative was not evaluated 

further.

Sabine Pass LNG Terminal

The Sabine Pass LNG Terminal is located on the eastern shore of the Sabine Pass Channel in 

Cameron Parish, Louisiana, about 42 miles west of the Trunkline LNG Terminal. The existing terminal 

occupies an approximately 853-acre site and includes five LNG storage tanks with a total storage capacity 

of 16.9 billion cubic feet and two LNG carrier berths. The facility has a natural gas send-out capacity of 

 

6 Docket Nos. PF11-2 and CP12-509-000

7 Docket Nos. CP12-509-000 and CP12-29-000

8 Docket No. PF15-25-000
3-10

4.0 Bcf/d. The terminal became operational as an LNG import facility in 2008 and received authorization 

for the re-export of foreign-sourced LNG in 2009.

Approved

On September 7, 2010, Sabine Pass LNG received approval from DOE to export 16.0 MTPA of 

LNG (equivalent to 2.2 Bcf/d of vaporized natural gas) to FTA countries over 30 years; on August 7, 

2012, Sabine Pass LNG received approval from the DOE to export the same volume of LNG to non-FTA 

countries over the same period. On July 11, 2013 and July 12, 2013, Sabine Pass LNG received DOE

approval for LNG exports equating to 0.28 Bcf/d and 0.24 Bcf/d of vaporized natural gas, respectively. 

On January 22, 2014, Sabine Pass LNG received DOE approval to export surplus LNG equating to an 

additional 0.86 Bcf/d of vaporized natural gas. DOE approvals for comparable non-FTA applications in 

2013/2014 are pending.

On April 16, 2012, the FERC authorized Sabine Pass LNG to receive, process, and export 

16.0 MTPA of domestically originated LNG through its liquefaction project,9 which involves the addition 

of four 4.0 MTPA liquefaction trains (Trains 1 through 4). On February 20, 2014,10 the FERC authorized 

an increase in LNG production for Trains 1 through 4 from 16.0 to 20.0 MTPA to reflect a higher 

production capability due to certain approved design changes. The authorized project is currently under 

construction and will involve the permanent use of about 191 acres as well as the temporary disturbance 

of about 97 acres, all 288 acres being within the existing terminal site. Sabine Pass LNG anticipates that 

Trains 1 and 2 will be placed in service in 2016 and Trains 3 and 4 will be placed in service in 2017. 

Currently, two interstate natural gas pipelines, the Creole Trail Pipeline and the Kinder Morgan 

Louisiana Pipeline, interconnect with the Sabine Pass LNG terminal. A third pipeline, owned by NGPL, 

crosses the terminal site but does not directly interconnect. Sabine Pass LNG indicates that the 2.2 Bcf/d 

of natural gas needed for the liquefaction facilities would be supplied via the Creole Trail Pipeline. 

Creole Trail Pipeline filed an application and subsequently received FERC authorization on February 21, 

2013 to add a 53,125 hp compressor station to provide 1.5 Bcf/d of reverse flow capacity on its system.11 

The compressor station is currently under construction.

On April 6, 2015, the FERC authorized the Sabine Pass Liquefaction Expansion Project and 

Cheniere Creole Trail Pipeline Expansion Project, which will involve the addition of two more 

liquefaction trains (Trains 5 and 6) at the Sabine Pass LNG Terminal, about 104 miles of new pipeline, 

one new compressor station, and four new meter stations.12 Operation of Trains 5 and 6 will add 

9.0 MTPA (equivalent to 1.4 Bcf/d of vaporized natural gas) to the 20.0 MTPA previously authorized for 

Trains 1 through 4. Sabine Pass LNG anticipates that Train 5 will be placed into service in 2019 and 

Train 6 at a later date when commercially feasible.

All 20.0 MTPA of LNG from Sabine Pass LNG’s first four trains is fully committed and the 

customer base is wholly different from that of Lake Charles LNG. Both projects are fully subscribed to 

different customer bases and, therefore, further consideration of the four-train expansion as a system 

alternative is precluded.

Sabine Pass LNG announced in March 2013 that Total and UK-based Centrica had collectively 

committed to 3.75 MTPA of liquefaction capacity for the fifth train. Although some liquefaction capacity 

(5.25 MTPA) does remain unsubscribed on the two trains, we will not speculate that this capacity is 

 

9 Docket No. CP11-72-000

10

 Docket No. CP14-12-000

11 Docket No. CP12-351-000

12 Docket Nos. CP13-552-000 and CP13-553-000
3-11

available for use by Lake Charles LNG customers. To meet the project objectives, Sabine Pass LNG 

would have to construct a further expansion similar to the facilities proposed by Lake Charles LNG to 

meet a 15.0 MTPA liquefaction and export capacity. The environmental impacts of a further expansion 

would likely be similar to the proposed facilities and the permitting and review process would be 

substantially later than the process for the Lake Charles Liquefaction Project. As a result, the Sabine Pass 

Liquefaction Project was not considered to be environmentally advantageous or a reasonable system 

alternative to the Lake Charles Liquefaction Project and was not evaluated further.

Golden Pass LNG Terminal

The Golden Pass LNG Terminal is located near the town of Sabine Pass, Texas, on the western 

shore of the Sabine Pass Channel, about 44 miles southwest of the Trunkline LNG Terminal. The import 

terminal occupies an approximately 477-acre site and includes five 155,000-m

3 LNG storage tanks and 

two LNG carrier berths. It has a maximum send-out capacity of 2.5 Bcf/d and became operational in 

2010.

Proposed

Natural gas is sent out from the LNG terminal via the Golden Pass Pipeline, which connects to 

five interstate and four intrastate pipelines providing access to major markets on the Gulf Coast and 

across the mid-western and northeastern United States. The proposed export facility includes three 

5.2 MTPA liquefaction trains, providing a total LNG send-out capacity of 15.6 MTPA. It would also 

require about 2.6 miles of 24-inch-diameter pipeline, compression facilities totaling 121,750 hp at three 

new compressor stations, and modification of certain existing interconnect facilities to provide for bidirectional transportation to deliver 2.6 Bcf/d of natural gas for liquefaction.

On September 27, 2012, Golden Pass Products, LLC (GPP) received approval from the DOE to 

export 15.6 MTPA of LNG (equivalent to 2.03 Bcf/d of vaporized natural gas) over 25 years to FTA 

countries. On October 26, 2012, GPP submitted an application, for which authorization is currently 

pending, to export LNG over the same period to non-FTA countries. On May 30, 2013, GPP received 

authorization to use the FERC pre-filing process, and GPP filed its application with the Commission on 

July 7, 2014.

13 GPP anticipates the first liquefaction train would enter service in 2019, and the remaining 

two trains would enter service in 2020.

GPP established a commercial framework agreement with Qatar Petroleum International and 

ExxonMobil to sell up to the full 15.6 MTPA. GPP’s and Lake Charles LNG’s projects have similar total 

liquefaction capacities (15.0 and 15.6 MTPA, respectively), and GPP’s capacity may still be available for 

subscription; however, we will not speculate that the additional 15.0 MTPA proposed by Lake Charles 

LNG could be accommodated by the Golden Pass terminal expansion, because both terminals’ exports 

have been determined to be in the public interest by the DOE. To service the Lake Charles Liquefaction 

Project objectives, additional facilities would need to be constructed to meet an additional export capacity 

of 15.0 MTPA with substantially similar environmental impacts. In addition, the permitting and review 

process for an additional expansion at the Golden Pass terminal would begin substantially later than the 

process for the Lake Charles Liquefaction Project and would not be permitted in time to meet Lake 

Charles LNG’s customer commitments. We conclude the environmental impacts of constructing and 

operating an expansion at the Golden Pass terminal to accommodate the proposed export capacity of Lake 

Charles LNG would likely be similar, with no evidence of a clear environmental advantage. Therefore, 

the Golden Pass system alternative was not evaluated further.

 

13 Docket Nos. PF13-14, CP14-517, and CP14-518
3-12

Gulf LNG Terminal

The Gulf LNG Terminal is on a 40-acre site in Pascagoula, Mississippi, about 286 miles east of 

the Trunkline LNG Terminal. The terminal started import operations in October 2011 and has a natural 

gas send-out capacity of 1.3 Bcf/d. It includes two 160,000-m

3 LNG storage tanks and a single LNG 

carrier berth designed to receive vessels up to 250,000 m3in capacity. The terminal is connected to the 

Mobile Bay Lateral pipeline through a 15.5-mile-long, 26-inch-diameter pipeline. The Mobile Bay 

Lateral pipeline provides interconnects with Florida Gas Transmission Company, LLC (FGT) and 

Transcontinental Gas Pipeline Company, LLC (Transco) pipelines. 

Proposed

Gulf LNG is proposing to construct liquefaction facilities at its existing terminal, with plans to 

export up to 10.0 MTPA of LNG. The expansion would include two 5.0 MTPA liquefaction trains, 

providing a total liquefaction capacity of 10.0 MTPA. It would also include a new stabilized condensate

storage tank, a new truck loading/unloading facility, and a new dock designed to receive barges 

transporting large equipment during construction. Gulf LNG anticipates the first liquefaction train would 

enter service in the third quarter of 2019, and second train would enter service in 2020.

On June 15, 2012, Gulf LNG received DOE authorization to export 11.5 MTPA14 of LNG 

(equivalent to 1.5 Bcf/d of vaporized natural gas) to FTA countries over 25 years; on August 31, 2012, 

Gulf LNG filed an application with DOE to export the same volume of LNG to non-FTA countries over 

the same period. DOE approval of the non-FTA application is pending. The FERC approved the use of 

the pre-filing process on May 21, 2014, and Gulf LNG filed its application with the Commission on June 

19, 2015.

15 Gulf LNG would need to further expand its facility similar to the proposed project to add the 

additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG, which would likely result in 

substantially similar environmental impacts, and a permitting and review process that would begin 

substantially later than the process for the Lake Charles Liquefaction Project. Furthermore, an additional 

expansion at Gulf LNG could not be permitted for service in time to meet the customer commitments of 

the Lake Charles Liquefaction Project. As a result, the planned Gulf LNG Liquefaction Project does not 

meet the market-based objectives of Lake Charles LNG’s and Trunkline’s proposed development, 

presents no clear environmental advantages, and was not evaluated further as a system alternative.

Main Pass Energy Hub Deepwater Port

Freeport – McMoRan Energy LLC (FME) plans to export LNG from existing and new facilities 

at the Main Pass Energy Hub Deepwater Port, located in federal waters in Main Pass Block 299, 16 miles 

offshore from southeastern Louisiana and about 272 miles east-southeast of the Trunkline LNG Terminal. 

The existing infrastructure includes eight platforms.

Planned

The planned project includes delivery of natural gas to the port via pipeline, which would be 

stored in new underground salt dome storage caverns, liquefied on six new floating liquefaction, storage, 

and offloading (FLSO) units and transferred to LNG carriers for export. Each FLSO unit would have a 

liquefaction capacity of 4.0 MTPA and an LNG storage capacity of 200,000 m3, providing a collective 

liquefaction capacity of 24.0 MTPA and storage capacity of 1,200,000 m3. 

 

14 Current project design is based on 10.0 MTPA.

15 Docket Nos. PF13-4 and CP15-521-000
3-13

On May 24, 2013, FME received approval from the DOE to export 24.0 MTPA of LNG 

(equivalent to 3.22 Bcf/d of vaporized natural gas) to FTA countries over 30 years; a corresponding 

application for export to non-FTA countries is currently under DOE review. The facility would qualify as 

a “deepwater port” under the Deepwater Port Act and, as such, would require a license from the U.S. 

Maritime Administration (MARAD) and the Coast Guard. At the time of writing, FME has not filed an 

application with the MARAD and Coast Guard.

On April 24, 2013, it was announced that Petronet LNG Limited committed to 4.0 MTPA of the 

total LNG output of 24.0 MTPA from the Main Pass Energy Hub Deepwater Port. While the FME 

project would have remaining capacity, we will not speculate the capacity would be available for use by 

Lake Charles LNG customers. To meet Lake Charles LNG’s objectives, FME would have to expand or 

build additional storage caverns to accommodate an additional 15.0 MTPA, and the permitting and review 

process would begin substantially later than the process for the Lake Charles Liquefaction Project. As an 

offshore ocean facility, environmental impacts of the necessary expansion are not readily comparable 

with those of the Lake Charles Liquefaction Project but there is no clear evidence that they would 

necessarily be less significant. Therefore, this system alternative was not considered further.

3.2.1.2 Approved, Proposed, and Planned Stand-Alone Liquefaction Projects

In addition to the liquefaction projects proposed or planned at the six existing LNG import 

facilities described above, there are several approved, proposed, and planned stand-alone liquefaction 

projects located along the Gulf Coast in the southern United States, as identified below.

Approved

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

(collectively, Cheniere Corpus Christi) – Corpus Christi LNG Project

Proposed

 Excelerate Liquefaction Solutions, LLC (ELS) – Lavaca Bay LNG Project

 Magnolia LNG (Magnolia) – Magnolia LNG Project

Planned

 Louisiana LNG Energy LLC (LLNG) – Louisiana LNG Project

 CE FLNG, LLC (CE FLNG) – CE FLNG LNG Project

 Venture Global Calcasieu Pass, LLC (Venture Global) – Calcasieu Pass Project

 Texas LNG Brownsville LLC (Texas LNG) – Texas LNG Project

 Annova LNG Common Infrastructure, LLC, Annova LNG Brownsville A, LLC, Annova 

LNG Brownsville B, LLC, and Annova LNG Brownsville C, LLC (collectively, Annova)

– Annova LNG Project

 Port Arthur LNG, LLC and Port Arthur Pipeline, LLC (collectively, Port Arthur) – Port 

Arthur LNG Project

 Rio Grande LNG, LLC and Rio Bravo Pipeline Company, LLC (collectively, Rio Bravo)

– Rio Grande Project

 Cheniere Corpus Christi – Stage 3 Project
3-14

 Gasfin Development USA, LLC (Gasfin) – Gasfin LNG Project

 Waller Point LNG (Waller Point) – Waller Point LNG Project

 Delfin LNG LLC (Delfin) – Delfin LNG Project

 Gulf Coast LNG Exports, LLC (Gulf Coast) – Gulf Coast LNG Project

 Eos LNG LLC (Eos) Project/Barca LNG LLC (Barca) Project – Eos LNG Project16

 Southern California Telephone and Energy LNG, LLC (SCT&E LNG) – SCT&E LNG 

Project

 WesPac Midstream LLC (WesPac) – WesPac/Gulfgate Terminal Project

 G2 LNG LLC – G2 LNG Project

 Live Oak LNG, LLC (Live Oak) – Live Oak LNG Project

 Venture Global Plaquemines LNG, LLC (Plaquemines LNG) – Plaquemines LNG 

Project

These projects are new or “greenfield” projects that are not associated with existing LNG import 

terminals, but we considered them as potential system alternatives. Table 3.2.1-2 provides a summary of 

the liquefaction projects listed above, the criteria used to evaluate their system alternatives status, and the 

results of the evaluation in each case. Further details for each project are provided in the text that follows 

the table.

Approved

Corpus Christi LNG Project

The Corpus Christi LNG Project is located about 285 miles southwest of the Trunkline LNG 

Terminal, on the northeast side of Corpus Christi Bay in San Patricio County, Texas. The project site was 

originally authorized for the Corpus Christi LNG Import Terminal, which was not constructed due to 

market changes.17 The liquefaction and export terminal, which is under construction, will include three 

trains, each with a liquefaction capacity of 4.5 MTPA, for a total send-out capacity of 13.5 MTPA, three 

160,000-m

3 LNG storage tanks, and two LNG berthing docks. The project also includes an 

approximately 23-mile-long, 48-inch-diameter pipeline, which will connect the LNG terminal with five 

interstate and intrastate natural gas transmission pipelines in south Texas, and two new compressor 

stations. In total, about 1,000 acres of construction workspace will be required.

On October 16, 2012, Cheniere Corpus Christi (through Cheniere Marketing, LLC) received 

DOE authorization to export 13.5 MTPA of LNG (equivalent to 2.1 Bcf/d of vaporized natural gas) to 

FTA countries over 25 years; on August 31, 2012, Corpus Christi (through Cheniere Marketing, LLC) 

applied to the DOE to export the same volume of LNG to non-FTA countries over 22 years. On May 12, 

2015, the DOE authorized Cheniere Corpus Christi to export 2.1 Bcf/d of vaporized natural gas to nonFTA countries over a 20-year term.

 

16 The Eos and Barca Projects constitute the same planned development, for which separate DOE applications were filed. As 

such, to avoid unnecessary redundancy, only the Eos Project is discussed further in section 3.1.1.2.

17 Docket No. CP04-37
3-15

TABLE 3.2.1-2

Stand-Alone Approved, Proposed, and Planned Liquefaction Projects Along the Gulf Coast

Summary Profile as System Alternatives

Project MTPA

MTPA

Differential FERC Status

In-Service 

Target Date

Compatible 

Timeline for 

Additional 

Expansion

Less 

Environmental 

Impact

Reasonable

Alternative

Approved Project

Corpus Christi 

LNG

13.5 –1.5 Authorized 12-30-14 2017–2020 No No No

Proposed Projects

Lavaca Bay 10.0 –5.0 Application filed 

02-06-14 – on hold

2018 No No No

Magnolia LNG 8.0 –7.0 Application filed

04-30-14

2018–2019 No No No

Planned Projects

Louisiana LNG 2.0 –13.0 Pre-filing initiated

7-18-14

2018 No No No

CE FLNG 8.0 –7.0 Pre-filing initiated 

04-16-13

2019 No No No

Calcasieu 

Pass

10.0 –5.0 Pre-filing initiated

10-10-14

2019 No No No

Texas LNG 2.0 –13.0 Pre-filing requested

3-9-15

2020 No No No

Annova LNG 7.0 –8.0 Pre-filing requested

3-11-15

2019 No No No

Port Arthur 

LNG

10.0b-5.0 Pre-filing requested

3-20-2015

2021 No No No

Rio Grande 27.0b+12.0 Pre-filing requested 

3-20-15

2020 No No No

Corpus Christi

Stage 3

10.0a–5.0 Pre-filing requested

6-1-2015

2021 No No No

Gasfin LNG 1.5 –13.5 Pre-filing not initiated Not known No No No

Waller Point

LNG

1.5 –13.5 Pre-filing not initiated Not known No No No

Delfin LNG 9.2 –5.8 Not applicableb2019–2022 No No No

Gulf Coast 

LNG

18.0 +3.0 Pre-filing not initiated 2018 No No No

Eos LNG 12.0 –3.0 Pre-filing not initiated Not known No No No

SCT&E LNG 12.0 –1.0 Pre-filing not initiated Not known No No No

WesPac LNG 

Project

1.5 –13.5 Pre-filing not initiated Not known No No No

G2 LNG 

Project

14.0 -1.0 Pre-filing not initiated 2019 No No No

Live Oak LNG 

Project

5.0 -10.0 Pre-filing not initiated 2019 No No No

Plaquemines 

LNG

20.0 +5.0 Pre-filing initiated 

7-2-15

2019 No No No

____________________

a

The volumes of LNG listed are based on the information provided in the FERC pre-filing requests because the DOE 

applications were not available at the time of this writing.

b

The Delfin LNG Project, a deepwater port project, would require authorizing from the U.S. Maritime Administration

(MARAD) and the Coast Guard. Delfin LNG submitted its application to MARAD and the Coast Guard on May 8, 2015.
3-16

Corpus Christi received authorization to use the FERC pre-filing process on December 22, 201118

and submitted its application on August 31, 2012.19 Between December 2013 and July 2014, Corpus 

Christi entered in to eight LNG sale and purchase agreements with six different customers for export of a 

total of about 7.3 MTPA of LNG over 20 years. On December 30, 2014, the FERC issued an Order 

Granting Authorization Under Section 3 of the Natural Gas Act and Issuing Certificates authorizing the 

project. The project, which began construction in February 2015, is expected to commence operation in 

late 2017. 

The Corpus Christi LNG Project has 6.2 MTPA of unsubscribed liquefaction capacity, but we 

will not speculate that this unsubscribed capacity would be available for use by Lake Charles LNG 

customers. To meet the project objectives, Cheniere Corpus Christi would have to construct a further 

expansion similar to the facilities proposed by Lake Charles LNG to meet a 15.0 MTPA liquefaction and 

export capacity. In addition, with new berthing facilities and about 1,000 acres of land-based disturbance

(excluding the expansion that would be required to meet the Lake Charles Liquefaction Project 

objectives), this project would not provide a significant environmental advantage over the Lake Charles 

Liquefaction Project. Also see discussion of the planned Stage 3 Project below.

Proposed

Lavaca Bay LNG Project

ELS’s proposed Lavaca Bay LNG Project is located in Port Lavaca in Calhoun County, Texas, 

about 222 miles southwest of the Trunkline LNG Terminal. The proposed terminal development includes 

two FLSO units that would manufacture LNG from domestically produced natural gas, two marine 

berths, and onshore pretreatment facilities and infrastructure associated with the FLSO units, which 

would be permanently moored. The project would include a total of eight liquefaction trains, four on 

each of the two FLSO units. It would have an LNG storage capacity of up to 502,000 m3, and a peak 

LNG send-out capacity of 10.0 MTPA. LNG would be stored, as needed, prior to transfer to marine 

carriers for export. 

The project would require improvement dredging of the existing Matagorda Ship Channel to 

accommodate the delivery of the FLSO units, new dredging to create a berth for the FLSOs, and new 

dredging to create a berth and turning basin for the LNG carriers. The project would also include a 29.5-

mile-long, 42-inch-diameter natural gas delivery pipeline and compression, metering, and appurtenant 

facilities. The pipeline would connect with nine interstate and intrastate pipelines. 

On August 9, 2012, ELS received DOE authorization to export 10.0 MTPA of LNG (equivalent 

to 1.38 Bcf/d of vaporized natural gas) to FTA countries over 20 years; an application to export 

1.38 Bcf/d to non-FTA countries over the same period is pending approval. On November 12, 2012, ELS 

received authorization to use the FERC pre-filing process20 and filed its formal application with the

Commission on February 6, 2014.

21

 In a letter December 23, 2014, ELS requested that the FERC place 

the project on hold until September 1, 2015 while it reevaluates the economics of the Lavaca Bay LNG 

Project. 

Because the Lavaca Bay LNG Project is on hold, the timelines for permitting, construction, and 

operational start-up are uncertain. In addition, ELS would need to expand its proposed facilities to add 

 

18 Docket No. PF12-3-000

19 Docket No. CP12-507

20 Docket No. PF13-1-000

21 Docket Nos. CP14-71-000, CP14-72-000, and CP14-73-000
3-17

the additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG. The addition of a third 

FLSO is technically infeasible. Also, we anticipate that the environmental impacts associated with 

construction and operation of two new berthing areas and turning basins, onshore terminal infrastructure, 

and an extensive pipeline delivery system would be no less than those of the Lake Charles Liquefaction 

Project. Therefore, the Lavaca Bay LNG Project would not provide a significant environmental 

advantage over the Lake Charles Liquefaction Project and this system alternative was not evaluated 

further.

Magnolia LNG Project

Magnolia’s proposed liquefaction project site is located about 250 yards southwest of the existing 

Trunkline LNG Terminal, on the opposite side of the Port of Lake Charles’ Industrial Canal, off the 

Calcasieu Ship Channel, in Calcasieu Parish, Louisiana. The Magnolia LNG Project would be 

constructed on a 115-acre site that partially overlaps Liquefaction Facility Site 1, one of the terminal 

expansion site alternatives considered by Lake Charles LNG (see section 3.3.1). At full capacity, the 

project would export 8.0 MTPA of LNG through four liquefaction trains, each with a nominal capacity of 

2.0 MTPA. The project would also include two vessel loading facilities and two 160,000-m

3 LNG 

storage tanks. Natural gas would be supplied from an existing transmission pipeline (Kinder Morgan 

Louisiana Pipeline) that crosses the site. 

On February 26, 2013, Magnolia received DOE authorization to export 4.0 MTPA of LNG 

(equivalent to 0.54 Bcf/d of vaporized natural gas) to FTA countries over 25 years. On March 5, 2014, 

the DOE authorized export of an additional 4.0 MTPA of LNG to FTA countries over the same period, 

bringing the total authorized export volume to FTA countries to 8.0 MTPA (equivalent to 1.08 Bcf/d of 

vaporized natural gas). On October 11, 2013, Magnolia filed an application with the DOE to export the 

same volume of LNG to non-FTA countries for a 25-year term. DOE approval of the non-FTA 

application is pending. On March 20, 2013, the FERC initiated its pre-filing process for the project and 

Magnolia filed an application on April 30, 2014.

22 Subject to the receipt of necessary approvals, 

construction is proposed to begin in early 2016, with operational start-up of the first train scheduled for 

the end of 2018. 

Magnolia would need to expand its proposed facility similar to the proposed project to add the 

additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG, which would likely result in 

substantially similar environmental impacts, and a permitting and review process that would begin 

substantially later than the process for the Lake Charles Liquefaction Project. Therefore, this system 

alternative was not evaluated further. 

Planned

Louisiana LNG Project

LLNG plans to construct and operate a liquefaction and LNG export facility on a 200-acre site on 

the east bank of the Mississippi River downstream from the Port of New Orleans in Plaquemines Parish, 

Louisiana, about 216 miles east-southeast of the Trunkline LNG Terminal. The project would include 

four liquefaction trains, each producing 0.5 MTPA of LNG for a total capacity of 2.0 MTPA, as well as 

two 100,000-m

3 LNG storage tanks, a marine berth accommodating an LNG vessel with cargo capacity of 

up to 175,000 m3, LNG truck loading facilities, electric power generation facilities, a compressor station, 

and two header pipelines connecting the facility to existing natural gas pipeline system infrastructure. 

 

22 PF13-9-000; CP14-347
3-18

On February 5, 2014, LLNG applied for DOE authorization to export 2.0 MTPA of LNG 

(equivalent to 0.27 Bcf/d of vaporized natural gas) to FTA countries over 25 years; a corresponding 

application for export of 2.0 MTPA of LNG to non-FTA countries over the same period was submitted on 

February 18, 2014. On August 28, 2014 LLNG received DOE authorization to export 2.0 MTPA of LNG 

to FTA countries over 25 years; its application to export to non-FTA countries over the same period is 

pending approval. LLNG received authorization to use the FERC pre-filing process on July 18, 2014.23

We do not consider the Louisiana LNG Project to be a reasonable alternative to the Lake Charles 

Liquefaction Project because it would not have the necessary send-out capacity to meet Lake Charles 

LNG’s customer commitments. LLNG would have to construct additional facilities to meet an additional 

export capacity of 15.0 MTPA with substantially similar environmental impacts, and the permitting and 

review process would be substantially later than the process for the Lake Charles Liquefaction Project. 

Also, based on the small scale of the Louisiana LNG Project, fundamental differences are anticipated in 

the type of market each project serves. Moreover, the Louisiana LNG Project offers no clear 

environmental advantage over the Lake Charles Liquefaction Project. Therefore, this system alternative 

was not considered further.

CE FLNG LNG Project

CE FLNG has announced the planned development of a floating LNG liquefaction and export 

facility on the east bank of the Mississippi River in Plaquemines Parish, Louisiana, about 250 miles eastsoutheast of the Trunkline LNG Terminal. Terminal facilities would include two marine berths, a turning 

basin, and two FLSO units, each capable of producing up to 4.0 MTPA of LNG, for an overall project 

output of 8.0 MTPA. The FLSO units would each have four liquefaction trains and LNG storage capacity 

of 250,000 m3, for an overall project storage capacity of 500,000 m3. LNG carriers would berth next to 

the FLSO units to receive LNG. An approximately 125-acre area fronting the Mississippi River would be 

dredged to install the berths and FLSO units. The project would also include a 37-mile-long 42-inchdiameter pipeline to connect the terminal with existing natural gas pipeline systems. Based on a recent 

status report filed with the Commission, the project has been revised to also include a 5-mile-long 36-

inch-diameter pipeline. CE Pipeline, LLC plans to construct and operate the pipeline.

On November 21, 2012, CE LNG received DOE approval to export 8.0 MTPA of LNG 

(equivalent to 1.07 Bcf/d of vaporized natural gas) to FTA countries over 30 years; a September 21, 2012 

application to export 8.0 MTPA of LNG to non-FTA countries over the same period is pending. On April 

16, 2013, FERC initiated the pre-filing process;24 at the time of writing, an application had not been filed. 

CE FLNG anticipates that the FLSO units would be placed in service during the third quarter of 2019.

To meet Lake Charles LNG’s 15.0 MTPA LNG delivery requirement, CE FLNG would need to 

install additional FLSO units and marine berths, along with attendant on-shore facilities. Irrespective of 

technical feasibility, the inherent schedule delays associated with the design, permitting, and construction 

of these additional facilities would preclude attainment of Lake Charles LNG’s timeline commitments. 

Moreover, the environmental impacts of constructing and operating these facilities and the necessary 

expansion would likely be no less than those associated with the Lake Charles Liquefaction Project. 

Therefore, the CE LNG Project was not evaluated further as a system alternative.

 

23 Docket No. PF14-17-000.

24 Docket No. PF13-11-000.
3-19

Calcasieu Pass Project

Venture Global is planning to construct and operate a liquefaction and LNG export facility on a 

203-acre site on the east side of the Calcasieu Ship Channel near the Gulf of Mexico, about 23 miles 

south of the Lake Charles Liquefaction Project, in Cameron Parish, Louisiana. The proposed greenfield 

development would use single mixed refrigerant technology and would consist of 10 LNG blocks capable 

of producing a total of 10.0 MTPA of LNG, two 200,000-m

3 LNG storage tanks, two LNG berthing 

docks that would accommodate vessels up to 185,000 m3in size. The project would also include 

construction of two new natural gas lateral pipelines, one 19 miles long and the other 24 miles long, that 

would connect to the existing natural gas pipeline grid in southern Louisiana.

The DOE has issued three authorizations to Venture Global for the export of up to 12.0 MTPA of 

domestically produced LNG to FTA countries. Up to 5.0 MTPA was authorized on September 27, 2013, 

another 5.0 MTPA was authorized on October 10, 2014, and 2.0 MTPA was authorized on June 17, 2015. 

Venture Global has filed three applications with the DOE requesting authorization to export up to a total 

of 12.0 MTPA of domestically produced LNG to non-FTA countries. Applications to export up to 

5.0 MTPA (DOE Docket No. 13-69-LNG), 5.0 MTPA (DOE Docket No. 14-88-LNG), and 2.0 MTPA 

(DOE Docket No 15-25-LNG) are under DOE review. The FERC approved Venture Global’s request to 

enter the FERC pre-filing process on October 10, 2014.25 According to its pre-filing request letter, 

Venture Global anticipates an in-service date of December 2019.

Venture Global would need to further expand its planned facility similar to the proposed project 

to add the additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG, which would 

likely result in substantially similar environmental impacts, and a permitting and review process that 

would begin substantially later than the process for the Lake Charles Liquefaction Project. Therefore, we 

do not consider the Calcasieu Pass Project to be a reasonable alternative to the Lake Charles Liquefaction 

Project, and this system alternative was not considered further.

Texas LNG Project

Texas LNG is planning a liquefaction and LNG export terminal on a 625-acre site on the 

Brownsville Ship Channel in Cameron County, Texas. The proposed project would be located about 

375 miles southwest of the Trunkline LNG Terminal and would include up to two liquefaction trains with 

an overall LNG capacity of approximately 4.0 MTPA, two 210,000-m

3 LNG storage tanks, and a marine 

berth for one LNG carrier. The planned terminal would receive domestic feed gas from the Agua Dulce 

natural gas hub through a new, 150-mile-long intrastate natural gas header pipeline. If approved, Texas 

LNG anticipates commencing operation in 2020.

On June 11, 2014, Texas LNG received DOE authorization to export 2.0 MTPA of LNG 

(equivalent to 0.27 Bcf/d of vaporized natural gas) to FTA countries over 25 years; an application to 

export the same volume to non-FTA countries over the same period is pending approval. Texas LNG 

indicates that it plans on placing the facilities in service in early 2020. On March 9, 2015, Texas LNG 

requested that the FERC initiate the pre-filing process.26 The FERC approved Texas LNG’s request on 

April 14, 2015.

We do not consider the Texas LNG Project to be a reasonable alternative to the Lake Charles 

Liquefaction Project because Texas LNG would need to expand its planned facility similar to the 

proposed project to add the additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG,

 

25 Docket No. PF15-2

26 Docket No. PF15-14
3-20

which would likely result in substantially similar environmental impacts, and a permitting and review 

process that would begin substantially later than the process for the Lake Charles Liquefaction 

Project. Also, based on the small scale of the Texas LNG Project, fundamental differences are anticipated 

in the type of market each project serves. Therefore, this system alternative was not considered further.

Annova LNG Project

Annova is planning a liquefaction and LNG export terminal on a 650-acre site on the Brownsville 

Ship Channel in Cameron County, Texas, about 375 miles southwest of the Trunkline LNG 

Terminal. Annova’s facility would include six liquefaction trains with an overall LNG capacity of 

approximately 7.0 MTPA, two 160,000-m

3 LNG storage tanks, and a marine berth for one LNG 

carrier. The planned terminal would receive domestic feed gas from the Isla Grande Pipeline through a 

new, intrastate natural gas header pipeline. 

On February 20, 2014, Annova received DOE authorization27 to export 7.0 MTPA of LNG 

(equivalent to 0.94 Bscf/d of vaporized natural gas) to FTA countries over 30 years; a corresponding 

application for LNG export to non-FTA countries is not anticipated. On March 11, 2015, Annova LNG 

requested that the FERC initiate the pre-filing process.28 The FERC approved Annova LNG’s request on 

March 27, 2015. If approved, Annova anticipates an in-service date of December 2019.

We do not consider the Annova LNG Project to be a reasonable alternative to the Lake Charles 

Liquefaction Project because Annova would need to expand its planned facility similar to the proposed 

project to add the additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG, which 

would likely result in substantially similar environmental impacts, and a permitting and review process 

that would begin substantially later than the process for the Lake Charles Liquefaction Project. 

Therefore, this system alternative was not considered further.

Port Arthur LNG Project

Port Arthur is planning a liquefaction and LNG export facility on the west side of the SabineNeches Waterway near Port Arthur, Texas, about 45 miles southwest of the Trunkline LNG Terminal. 

Port Arthur’s facility would include two 5.0 MTPA liquefaction trains (providing a total liquefaction 

capacity of 10.0 MTPA), two 160,000-m

3

capacity LNG storage tanks, a natural gas liquids and 

refrigerant storage area, a truck loading/unloading facility, two LNG carrier berths. To supply natural gas 

required for the terminal, construction of two 42-inch-diameter natural gas pipelines (one 7 miles in 

length and one 27 miles in length), two compressor stations, metering stations, and appurtenant facilities 

would be required. If approved, the Port Arthur LNG Project would begin operations in the first quarter 

of 2021. 

On March 20, 2015, Port Arthur submitted an application to the DOE for authorization to export 

LNG to FTA countries. Also on March 20, 2015, Texas LNG requested that the FERC initiate the prefiling process.29 The FERC approved Port Arthur’s request on March 31, 2015.

We do not consider the Port Arthur LNG Project to be a reasonable alternative to the Lake 

Charles Liquefaction Project because Port Arthur would need to expand its planned facility similar to the 

proposed project to add the additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG,

 

27 On July 17, 2014, the DOE authorized the transfer of Annova LNG, LLC’s FTA authorization to Annova LNG Common 

Infrastructure, LLC.

28 Docket No. PF15-15.

29 Docket Nos. PF15-18-000 and PF15-19-000
3-21

which would likely result in substantially similar environmental impacts, and a permitting and review 

process that would begin substantially later than the process for the Lake Charles Liquefaction Project. 

Therefore, this system alternative was not evaluated further. 

Rio Grande Project

Rio Bravo is planning a liquefaction and LNG export terminal on a 1,000-acre site on the 

northern shore of the Brownsville Ship Channel in Cameron County, Texas, about 375 miles southwest of 

the Trunkline LNG Terminal. The proposed project would include six liquefaction trains with an overall 

LNG capacity of approximately 27.0 MTPA, four 180,000-m

3 LNG storage tanks, two marine berths, and 

on-site power generation. To supply natural gas required for the terminal, construction of two parallel, 

130-mile-long, 42-inch-diameter natural gas pipelines, three compressor stations, and appurtenant 

facilities would be required. If approved, Rio Bravo anticipates commencing operation during the fourth 

quarter of 2020. 

On March 20, 2015, Texas LNG requested that the FERC initiate the pre-filing process.30 The 

FERC approved Rio Bravo’s request to enter the FERC pre-filing process on April 13, 2015. Rio Bravo 

anticipates filing an application with the DOE for authorization to export LNG to FTA countries in 

January 2016. 

We do not consider the Rio Grande Project to be a reasonable alternative to the Lake Charles 

Liquefaction Project because it would not be completed in a compatible timeframe to meet Lake Charles 

LNG’s customer commitments. Therefore, this system alternative was not considered further.

Corpus Christi Stage 3 Project

On June 9, 2015, Cheniere Corpus Christi entered into the FERC’s pre-filing process for the 

proposed Stage 3 Project.31 The project would be located immediately north of the Corpus Christi LNG 

Project site. The Stage 3 Project would include two additional liquefaction trains (Trains 4 and 5) capable 

of producing a total of 10.0 MTPA of LNG, one additional LNG storage tank (Tank 4) with a capacity of 

160,000 m

3

, a new 22-mile-long natural gas pipeline, additional compression at one compressor station, 

and appurtenant facilities. If approved, Cheniere Corpus Christi anticipates the Stage 3 Project would 

enter service in 2021. With the additional 10.0 MTPA of LNG capacity that the Stage 3 Project would 

provide, the Corpus Christi liquefaction facility could potentially supply the volumes of LNG required 

under Lake Charles LNG’s customer agreements. However, we will not speculate that this capacity 

would be available for use by Lake Charles LNG customers. To meet the project objectives, Cheniere 

Corpus Christi would have to construct a further expansion similar to the facilities proposed by Lake 

Charles LNG to meet a 15.0 MTPA liquefaction and export capacity. The environmental impacts of a 

further expansion would likely be similar to the proposed Lake Charles LNG facilities. Moreover, the 

Stage 3 Project facilities, including any further expansion, would not be operational within a timeframe 

that would be compatible with Lake Charles LNG’s commitments. Therefore, even after consideration of 

the Stage 3 Project, the Corpus Christi facility would not be a viable system alternative to the Lake 

Charles Liquefaction Project.

Gasfin LNG Project

Gasfin is planning to develop a liquefaction and LNG export facility on the east side of the 

Calcasieu Ship Channel in Cameron Parish, Louisiana, about 23 miles south of the Trunkline LNG 

 

30 Docket No. PF15-20-000

31 Docket No. PF15-26-000
3-22

Terminal. This mid-scale project would have overall LNG storage capacity of 100,000 m3and LNG 

export capacity of 1.5 MTPA. Onshore facilities would be constructed on a 35-acre site and the project 

would also include a single marine berth, capable of handling LNG carriers with a capacity between 

10,000 and 35,000 m3. 

On March 7, 2013, Gasfin received DOE authorization to export 1.5 MTPA of LNG (equivalent 

to 0.2 Bcf/d of vaporized natural gas) to FTA countries over 25 years; a December 24, 2013 application to 

export 1.5 Bcf/d to non-FTA countries over 20 years is pending approval. The project is in the initial 

development phase and an anticipated schedule has not yet been released. At the time of writing, 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 Lake Charles 

Liquefaction Project because it would not be completed in a compatible timeframe or have the necessary 

send-out capacity to meet Lake Charles LNG’s customer commitments. Gasfin would need to expand its 

planned facility similar to the proposed project to add the additional 15.0 MTPA liquefaction capacity 

proposed by Lake Charles LNG, which would likely result in substantially similar environmental impacts, 

and a permitting and review process that would begin substantially later than the process for the Lake 

Charles Liquefaction Project. Also, based on the relatively small scale of the Gasfin LNG Project, 

including the LNG carrier size range it is designed to accommodate, fundamental differences are 

anticipated in the type of market each project serves. Therefore, this system alternative was not 

considered further.

Waller Point LNG Project

The Waller Point LNG Project is a planned liquefaction and LNG export facility on a 180-acre 

greenfield site near the mouth of the Calcasieu Ship Channel in Cameron Parish, Louisiana, about 

22 miles south of the Trunkline LNG Terminal. The project would include small-scale liquefaction trains 

with a total LNG export capacity of about 1.5 MTPA, LNG storage capacity of 30,000 m3, and berthing 

facilities for LNG barges.

On December 20, 2012, Waller Point received DOE authorization to export 1.25 MTPA of LNG 

(equivalent to 0.16 Bcf/d of vaporized natural gas) to FTA countries over 25 years; a November 26, 2013 

application to export 1.5 MTPA of LNG (equivalent to 0.19 Bcf/d of vaporized natural gas) to non-FTA 

countries over the same period is pending approval. The project is in the initial development phase and 

Waller Point LNG has not announced a planned schedule. Furthermore, at the time of writing, initiation 

of the FERC pre-filing process had not been requested.

We do not consider the Waller Point LNG Project to be a reasonable alternative to the Lake 

Charles Liquefaction Project because it would not be completed in a compatible timeframe or have the 

necessary send-out capacity to meet Lake Charles LNG’s customer commitments. Waller Point would 

need to expand its planned facility similar to the proposed project to add the additional 15.0 MTPA 

liquefaction capacity proposed by Lake Charles LNG, which would likely result in substantially similar 

environmental impacts, and a permitting and review process that would begin substantially later than the 

process for the Lake Charles Liquefaction Project. Also, based on the small scale of the Waller Point 

LNG Project and the use of LNG barges instead of ships, fundamental differences are anticipated in the 

type of market each project serves. Therefore, this system alternative was not considered further.

Delfin LNG Project

Delfin is planning to construct and operate a floating liquefaction and export terminal to be 

located in the West Cameron Block 167 in the Gulf of Mexico, about 30 miles offshore from Cameron 
3-23

Parish, Louisiana and 54 miles south of the Trunkline LNG Terminal. The facility would qualify as a 

“deepwater port” under the Deepwater Port Act and, as such, would require a license from the MARAD 

and the Coast Guard. The terminal would be located near an existing platform and would receive gas via 

an existing 30-mile-long, 42-inch-diameter Enbridge pipeline that was originally built to transport 

offshore gas production to onshore connections with ANR Pipeline Company, Transco, NGPL, and 

nearby gas processing plants. In 2011, based on changing market economics, the pipeline was taken out 

of service but maintained in an operable state. The on-shore connections would be reinstated and flow 

reserved to deliver gas to the new terminal.

Delfin indicates that gas would be liquefied by four trains located on FLSO units located close to 

the offshore terminus of the former Enbridge pipeline and loaded onto LNG carriers for export. Each 

LNG train would be capable of producing approximately 2.0 MTPA of LNG, for a total export capacity 

of 8.0 MTPA. Under peak operating conditions, Delfin anticipates the facility may be capable of 

achieving a maximum output of 9.2 MTPA. If authorized, the onshore project components would 

commence operation in 2018 and the deepwater port would begin operation in the third quarter of 2019.

On February 20, 2014, Delfin received DOE approval to export 13.0 MTPA of LNG (equivalent 

to 1.80 Bcf/d of vaporized natural gas) to FTA countries over 20 years; a November 12, 2013 application 

to export 13.0 MTPA of LNG to non-FTA countries over the same period is pending. On May 8, 2015, 

Delfin filed its deepwater port application with MARAD and the Coast Guard, as well as its abbreviated 

application for onshore facilities with the FERC.32

To meet Lake Charles LNG’s 15.0 MTPA LNG delivery requirement, Delfin would need to 

install additional FLSO units. Moreover, because Delfin only recently filed its applications with 

MARAD and the Coast Guard, it is unlikely that the planned facilities or any necessary expansion would 

be available in a timeframe compatible with Lake Charles LNG’s customer commitments. As an offshore

ocean facility, environmental impacts are not readily comparable with those of the Lake Charles 

Liquefaction Project but there is no clear evidence that they would necessarily be less significant. 

Therefore, the Delfin LNG Project was not evaluated further as a system alternative.

Gulf Coast Liquefaction Project

The Gulf Coast Liquefaction Project would export LNG from a planned liquefaction facility at 

the Port of Brownsville in Brownsville, Texas, about 374 miles southwest of the Trunkline LNG 

Terminal. The project would include a new terminal on about 500 acres, with four liquefaction trains 

each capable of producing 4.5 MTPA of LNG (18.0 MTPA total), an unspecified number of LNG storage 

tanks, a marine berth, and a pipeline interconnect with existing natural gas transmission lines. 

On October 16, 2012, Gulf Coast received DOE authorization to export 18.0 MTPA of LNG 

(equivalent to 2.8 Bcf/d of vaporized natural gas) to FTA countries over 25 years; an application to export 

2.8 Bcf/d to non-FTA countries over the same period is pending approval. At the time of writing, Gulf 

Coast had not requested that the FERC initiate the pre-filing process. 

Gulf Coast would potentially have the capacity to meet Lake Charles LNG’s 15.0 MTPA

requirement; however, we will not speculate that this capacity would be available for use by Lake Charles 

LNG customers. To meet the project objectives, Gulf Coast would have to construct an expansion of the 

planned facility similar to the facilities proposed by Lake Charles LNG to meet a 15.0 MTPA liquefaction 

and export capacity. Moreover, given that the project has not yet entered pre-filing, the project’s 

development schedule would not be compatible with Lake Charles LNG’s timeline for customer 

 

32 Docket No. CP15-490-000
3-24

commitments. In addition, as a greenfield facility, the Gulf Coast Liquefaction Project, including any 

necessary expansion, would be unlikely to provide a significant environmental advantage over the Lake 

Charles Liquefaction Project. Therefore, this system alternative was not considered further.

Eos LNG Project

Eos is planning to develop a liquefaction and LNG export facility at the Port of Brownsville in 

Brownsville, Texas, approximately 375 miles southwest of the Trunkline LNG Terminal. The facility is 

being designed and permitted for up to six modular floating liquefaction barges with aggregate peak 

capacity of up to 12.0 MTPA. It would include up to six 35,000-m

3

full containment storage tanks and up 

to six LNG carrier docks. Each floating liquefaction barge would be moored alongside an LNG carrier 

that would be utilized solely for storage. LNG would be transferred to and exported by a second carrier, 

moored alongside the barge and storage carrier. The project would not require land-based liquefaction or 

storage facilities. Feed gas would be sourced from local pipeline interconnects.

On November 26, 2013, Eos received DOE authorization to export 12.0 MTPA of LNG 

(equivalent to 1.6 Bcf/d of vaporized natural gas) to FTA countries over 25 years; an application filed on 

August 23, 2013 to export 12.0 MTPA to non-FTA countries over the same period is pending approval. 

At the time of writing, initiation of the FERC pre-filing process had not been requested. 

We do not consider the Eos LNG Project to be a reasonable alternative to the Lake Charles 

Liquefaction Project because it would not be completed in a compatible timeframe or have the necessary 

send-out capacity to meet Lake Charles LNG’s customer commitments. Eos would need to expand its 

planned facility similar to the proposed project to add the additional 15.0 MTPA liquefaction capacity 

proposed by Lake Charles LNG. Also, based on the small scale of the Eos LNG trains and LNG carriers, 

fundamental differences are anticipated in the type of market each project serves. Moreover, the Eos 

LNG Project offers no clear environmental advantage over the Lake Charles Liquefaction Project. 

Therefore, this system alternative was not considered further.

SCT&E LNG Project

SCT&E LNG is planning a liquefaction and LNG export facility on an about 246-acre site on 

Monkey Island in Cameron Parish, Louisiana, about 3 miles from the Gulf of Mexico and approximately 

22 miles south of the Trunkline LNG Terminal. SCT&E’s facility would include six LNG trains with an 

overall capacity of 12.0 MTPA of LNG. LNG produced by the trains would be stored in multiple on-site 

LNG storage tanks that may also be used for LNG bunkering and fueling of transportation ships for 

distribution of LNG.

On July 9, 2014, SCT&E LNG submitted an application to the DOE for authorization to export 

12.0 MTPA (equivalent of 1.62 Bcf/d of natural gas) of LNG to FTA countries over 30 years. On July 

24, 2014, SCT&E LNG also submitted an application to the DOE for authorization to export 12.0 MTPA

of LNG to non-FTA countries. SCT&E LNG received authorization to export to FTA countries on 

December 15, 2014; the application requesting authorization to export to non-FTA countries is currently 

pending. At the time of writing, SCT&E has not yet requested initiation of the FERC pre-filing process.

The SCT&E LNG Project would not be completed in a compatible timeframe or have the 

necessary send-out capacity to meet Lake Charles LNG’s customer commitments. SCT&E LNG would 

need to expand its planned facility similar to the proposed project to add the additional 15.0 MTPA 

liquefaction capacity proposed by Lake Charles LNG, which would likely result in substantially similar 

environmental impacts, and a permitting and review process that would begin substantially later than the 
3-25

process for the Lake Charles Liquefaction Project. Therefore, we do not consider it to be a viable system 

alternative. 

WesPac LNG Project

WesPac is planning a liquefaction and LNG export facility on 40 acres of land located on the 

Sabine-Neches Waterway near Port Arthur, Texas, which is approximately 45 miles southwest of the 

Trunkline LNG Terminal. On April 18, 2014, Alturas LLC (Alturas), a subsidiary of WesPac, submitted 

an application to the DOE for authorization to export 1.5 MTPA of LNG to FTA countries over 20 years. 

As of this writing, the application is still pending. At the time of writing, initiation of the FERC pre-filing 

process had not been requested. WesPac would need to expand its planned facility similar to the 

proposed project to add the additional 15.0 MTPA liquefaction capacity proposed by Lake Charles LNG, 

which would likely result in substantially similar environmental impacts. Because the WesPac LNG 

Project would not be completed in a compatible timeframe or have the necessary send-out capacity to 

meet Lake Charles LNG’s customer commitments, we do not consider it to be a viable system alternative. 

G2 LNG Project

G2 LNG LLC (G2 LNG) is planning to develop a liquefaction and LNG export facility within a 

500-acre site on the Calcasieu Ship Channel in Cameron Parish, Louisiana, about 20 miles south of the 

Trunkline LNG Terminal. G2 LNG’s project would be located on a 500-acre site and would include two 

liquefaction trains each capable of producing 7.0 MTPA of LNG (14.0 MTPA total), an unspecified 

number of LNG storage tanks, and a marine berth. G2 LNG has stated that, if approved, it anticipates that 

operation of the G2 LNG Project would begin in 2019. 

On July 17, 2015, G2 LNG received DOE approval to export 14.0 MTPA of LNG (equivalent to 

1.8 Bcf/d of vaporized natural gas) to FTA countries over 30 years; a March 19, 2015 application to 

export the same volume of LNG to non-FTA countries over the same period is pending. At the time of 

this writing, G2 LNG has not requested initiation of the FERC pre-filing process. 

G2 LNG would not have the capacity to meet Lake Charles LNG’s 15.0 MTPA requirement. 

G2 LNG would need to expand its planned facility similar to the proposed project to add the additional 

15.0 MTPA liquefaction capacity proposed by Lake Charles LNG. Also, given that the project has not 

yet entered pre-filing, it is unlikely that it would meet the planned 2019 in-service date or be compatible 

with Lake Charles LNG’s timeline for customer commitments. In addition, as a greenfield facility, the

G2 LNG Project, would be unlikely to provide a significant environmental advantage over the Lake 

Charles Liquefaction Project. Therefore, this system alternative was not considered further.

Live Oak LNG Project

Live Oak has announced plans for a liquefaction and LNG export facility in Calcasieu Parish,

approximately 2 miles west of the existing Trunkline LNG Terminal on the west side of the Calcasieu 

Ship Channel. Live Oak’s project would include eight liquefaction units capable of producing a nominal 

capacity of 5.2 MTPA of LNG, two 130,000-m

3 LNG storage tanks, a marine berth accommodating an 

LNG vessel with cargo capacity of up to 175,000 m3, and an interconnection with the Kinder Morgan 

Louisiana Pipeline LLC (KMLP) and the Creole Trail Pipeline systems. The project is in the initial

development phase and, if authorized, is expected to begin export of up to 5.0 MTPA of LNG at the end 

of 2019. 

At the time of this writing, Live Oak has not requested initiation of the FERC pre-filing process, 

nor has it submitted an application to the DOE for authorization to export LNG.
3-26

The Live Oak LNG Project would not have the capacity to meet Lake Charles LNG’s 15.0 MTPA 

requirement. Given that the project has not yet entered pre-filing or requested DOE approval to export 

LNG, it is unlikely that it would be completed and in service in a compatible timeline with Lake Charles 

LNG’s customer commitments. In addition, as a greenfield facility, the Live Oak LNG Project, would be 

unlikely to provide a significant environmental advantage over the Lake Charles Liquefaction Project. 

Therefore, this system alternative was not considered further.

Plaquemines LNG Project

Plaquemines LNG is planning a liquefaction and LNG export terminal on a 623-acre site on the 

west side of the Mississippi River and just south of Myrtle Grove, Louisiana. The project would be 

located about 206 miles east-southeast of the Trunkline LNG Terminal, in Plaquemines Parish, Louisiana. 

Plaquemines LNG’s proposed project would consist of 20 liquefaction trains capable of producing a total 

of 20.0 MTPA of LNG, four 200,000-m

3 LNG storage tanks, three LNG loading berths, and on-site 

power generation. The project would also include 43.9 miles of three new natural gas pipelines that 

would connect to the existing natural gas pipeline grid in southeastern Louisiana.

The FERC approved Plaquemines LNG’s request to enter the FERC pre-filing process on July 2, 

2015.33 According to its pre-filing request letter, Plaquemines LNG anticipates an in-service date of 

September 2019. As of the time this EIS is being prepared, Plaquemines LNG has not requested DOE 

approval to export LNG. 

The Plaquemines LNG Project would potentially have the capacity to meet Lake Charles LNG’s

15.0 MTPA requirement; however, we will not speculate that this capacity would be available for use by 

Lake Charles LNG customers. Moreover, given that the project has only recently entered pre-filing and 

has not yet requested DOE approval to export LNG, the project’s development schedule would not be 

compatible with Lake Charles LNG’s timeline for customer commitments. In addition, the Plaquemines

Project, including any necessary expansion, would be unlikely to provide a significant environmental 

advantage over the Lake Charles Liquefaction Project. Therefore, this system alternative was not 

considered further.

3.2.2 Pipeline System Alternatives

To serve as a viable system alternative to Trunkline’s proposed pipelines, the system would have 

to (1) transport all or a part of the volume of natural gas required for liquefaction at the proposed new 

facility, and (2) cause significantly less impact on the environment than the proposed pipeline expansion. 

System alternatives to serve Lake Charles LNG’s proposed liquefaction facility are those alternatives that 

could replace all or part of the proposed pipeline segments (Mainline Connector and Mainline 200-3 

Loop) by making use of existing natural gas pipeline infrastructure and/or other new pipeline 

infrastructure. To be considered a legitimate system alternative, the supply infrastructure must either 

connect directly to the proposed liquefaction facility or to the existing Trunkline pipelines that serve the 

existing LNG terminal, in the latter case, through new rather than existing connections. 

Trunkline’s south Louisiana pipeline system provides the only direct connection to the Trunkline 

LNG Terminal, via a 30-inch- and 36-inch-diameter lateral pipeline (LNG lateral) designed to send out 

over 2.0 Bcf/d of natural gas through regasification of LNG. Based on the high volumes that the lateral is 

designed to handle, looping would not be necessary to maintain adequate gas flow for the proposed 

liquefaction facility, although additional compression would still be required. Therefore, looping for this 

segment of the proposed pipeline delivery system was not considered a reasonable alternative.

 

33 Docket No. PF15-27-000
3-27

As currently proposed, Trunkline’s upstream pipeline systems would be cost effectively expanded 

to provide up to 2.6 Bcf/d of natural gas to the LNG terminal via the LNG lateral. The 2.6 

Bcf/d represents both fuel use and LNG production on a peak day. The DOE export authorization of up 

to 2.0 Bcf/d represents average LNG production. For a system alternative to be viable, similar supply 

rates would have to be possible and achieved with the same consideration of cost.

Trunkline’s south Louisiana pipeline system currently interconnects with eight major interstate 

natural gas pipelines in the west Louisiana area: Creole Trail Pipeline, FGT, Gulf South Pipeline 

Company (Gulf South), NGPL, Tennessee Gas Pipeline Company (TGP), TETCO, Texas Gas 

Transmission, and Transco. Two of these pipelines (Creole Trail Pipeline and Gulf South), together with 

a third pipeline (Cameron Interstate Pipeline), cross several of the others and offer actual interconnections 

or interconnection capability. However, none of these three pipelines is currently capable of transporting 

2.6 Bcf/d of gas to the LNG terminal; thus, they would need to undergo significant expansions through 

looping and compression to achieve this delivery capacity and new segments would have to be 

constructed to connect directly with the liquefaction facility. Using a straight line configuration, these 

new segments would measure about 2.5 miles for the Creole Trail Pipeline, 10 miles for the Gulf South 

Pipeline, and 6 miles for the Cameron Interstate Pipeline. The capacities of each of these three pipelines 

and their viability as system alternatives are described in the following sections.

3.2.2.1 Creole Trail Pipeline

The Creole Trail Pipeline is a 153-mile-long, 42-inch-diameter pipeline that was originally 

designed and constructed to transport vaporized LNG from the Sabine Pass LNG Terminal but is being 

modified to provide bi-directional flow of natural gas to the Sabine Pass Liquefaction Project for 

liquefaction and export. It extends from the Sabine Pass LNG Terminal in Cameron Parish, Louisiana to 

interconnections with Bridgeline Holdings, L.P., FGT, NGPL, TETCO, TGP, Transco, and Trunkline.

At a maximum flow rate of 2.6 Bcf/d, the Creole Trail Pipeline can transport sufficient natural 

gas to allow Sabine Pass LNG to export up to 16.0 MTPA of LNG (equivalent to 2.2 Bcf/d of vaporized 

natural gas). Because all 16.0 MTPA is committed to Sabine Pass LNG’s customers, the Creole Trail 

Pipeline would not have sufficient capacity to supply natural gas to the Lake Charles Liquefaction Project 

without substantial looping.

As indicated above, the Creole Trail Pipeline has interconnections with many of the same 

pipelines as Trunkline’s proposed pipelines and, at its closest point, is located about 2.5 miles west of the 

liquefaction facility site. From this location, a new route segment at least 2.5 miles long would have to be 

constructed through or around Alcoa’s adjacent industrial property to connect with the proposed 

liquefaction facility. Also, significant looping would be needed to provide the 2.6 Bcf/d required by the 

Lake Charles Liquefaction Project in addition to satisfying the requirements of the Sabine Pass 

Liquefaction Project. As a result, environmental impacts would likely be equal to or greater than those of 

the proposed pipelines. Therefore, the Creole Trail Pipeline would not provide a significant 

environmental advantage over the proposed pipelines and was not evaluated further as a system 

alternative.

3.2.2.2 Gulf South Pipeline

The Gulf South Pipeline system includes about 7,360 miles of pipeline and has a capacity of 

about 6.9 Bcf/d. Markets served in Louisiana include local distribution companies, municipalities, power 

plants, and industrial end-users; off-system markets are served in the northeastern, mid-western, and 

southeastern United States through interconnections with third-party pipelines.
3-28

Given the supply sources and delivery points of the Gulf South system, it is unlikely that the 

existing system could provide the 2.6 Bcf/d of natural gas required for operation of the proposed 

liquefaction facility without extensive looping. In addition, the nearest point on the system to the 

liquefaction facility site is about 10 miles away, which would require at least 10 miles of new greenfield 

pipeline to connect directly to the liquefaction facility. We do not expect that the required looping and 

greenfield pipeline developments would have any significant environmental advantage relative to 

Trunkline’s proposed pipelines. Therefore, the Gulf South Pipeline system alternative was not considered 

further.

3.2.2.3 Cameron Interstate Pipeline

The 36-mile-long, 42-inch-diameter Cameron Interstate Pipeline extends from the Cameron LNG 

Terminal in Cameron Parish, Louisiana, through Calcasieu Parish, to the Ragley Compressor Station in 

Beauregard Parish. The pipeline was constructed as a send-out pipeline for the Cameron LNG Terminal 

and provides interconnections with the FGT, TGP, TETCO, and Transco systems, through which gas is 

delivered to end-user markets. To allow the transport of natural gas to Cameron LNG’s terminal for 

liquefaction and export, new pipeline facilities would be installed to increase the flow volume in the 

Cameron Interstate Pipeline from 1.0 to 2.35 Bcf/d and enable bidirectional flow capability. The new 

facilities would include the 56,820 hp Holbrook Compressor Station and 20.9 miles of new 

42-inch-diameter pipeline extending from the existing interconnection with FGT in Cameron Parish to a 

proposed interconnect with Trunkline in Beauregard Parish.

At its closest point, the Cameron Interstate Pipeline is located about 6 miles from Lake Charles 

LNG’s liquefaction facility site. As such, at least 6 miles of new greenfield pipeline would need to be 

constructed to connect with the proposed liquefaction facility, which could involve a crossing of Moss 

Lake (on the Calcasieu River north of Lake Calcasieu) of up to 1 mile. Also, significant looping would 

be needed to provide the 2.6 Bcf/d required by the Lake Charles Liquefaction Project in addition to 

satisfying the requirements of the Cameron LNG Liquefaction Project. As a result, environmental 

impacts would likely be equal to or greater than those of Trunkline’s proposed pipelines. Therefore, the 

Cameron Interstate Pipeline would not provide a significant environmental advantage over the proposed 

pipelines and was not evaluated further as a system alternative.

3.3 ALTERNATIVE LIQUEFACTION FACILITY SITES

Based in part on information provided by Lake Charles LNG, we evaluated five alternative sites, 

including the currently proposed site, for the proposed liquefaction facility. The Trunkline LNG Terminal 

was established as the focal point of the site selection study area. Proximity to the existing terminal 

would allow Lake Charles LNG to readily integrate the new facilities with existing terminal infrastructure 

such as the LNG storage tanks, LNG carrier berths, and LNG transfer facilities. Use of this existing 

infrastructure would avoid the impacts of constructing and operating duplicate facilities elsewhere. The 

existing terminal is also connected to a natural gas pipeline system that could be readily modified to 

supply gas for liquefaction as well as transport gas from the terminal during import mode.

Lake Charles LNG indicated that cost and functionality constrain the length of the cryogenic 

piping that would be used to transport LNG from the liquefaction facilities to the existing LNG terminal. 

Two miles was defined as the maximum length of piping, a criterion that was used to define the general 

dimensions of the study area for identification of alternative sites. The north, south, and eastern 

boundaries of the study area were defined as about 1 mile from the center of the existing terminal. The 

study area boundary was arbitrarily extended west for about 3 miles to confer adjacency with the 

Calcasieu Ship Channel. The study area boundary encompassed about 8.6 square miles, within which the 

five site location options were identified.
3-29

3.3.1 Site Descriptions 

The locations of the Liquefaction Facility Sites (LFS) considered (hereinafter referred to as 

LFS-1 through 5) are depicted in figure 3.3.1-1 and descriptions are provided below.

LFS-1 

LFS-1 is located southwest of the existing LNG terminal, across the Industrial Canal. The 

164-acre site is bisected by Henry Pugh Boulevard. On the north side of Henry Pugh Boulevard, the site 

is characterized by a former dredged material placement area that supports extensive scrub and 

herbaceous cover with some wooded patches. To the west, adjacent facilities include a public 

recreational area with a boat ramp, fishing pier, store, and restrooms; to the east, adjacent facilities are 

represented by a construction yard. To the south of Henry Pugh Boulevard, the topography drops 

sharply; this area does not appear to have been used for dredged material placement in the past and 

supports more extensive wooded cover than the site’s northern section, with a mix of species such as 

water oak (Quercus nigra), loblolly pine (Pinus taeda), and Chinese tallow tree (Triadica sebifera). The 

southernmost extent of the site is emergent brackish marsh that borders a tidal bayou adjacent to 

Calcasieu Lake. LFS-1 is wholly within the FEMA 100-year floodplain. As noted previously, the 

proposed Magnolia LNG Project site includes a portion of LFS-1.

LFS-2

LFS-2 is located about 0.4 mile east of LFS-1 and southeast of the existing LNG terminal. The 

160-acre site is bounded by Joe Ledoux Road to the south. The majority of LFS-2 is taken up by a 

manufacturing facility currently owned and operated by Shaw Group, Inc. The remainder of this area has 

heavy soil disturbance from recent construction activities. Vegetation is characterized by maintained 

grasses with occasional early successional woody species, such as rattlebush (Sesbania drummondii). 

LFS-2 is wholly within the FEMA 100-year floodplain; however, the foundation pad for the 

manufacturing facility was likely raised above this level.

LFS-3

LFS-3 is located northeast of the existing LNG terminal. The 163-acre site is bordered to the 

west by Big Lake Road. The southern sector of the site contains a dredged material placement area that 

was utilized during development of the marine berthing area at the Trunkline LNG Terminal site; the 

northern sector is characterized by maintained pasture land. A rural residential community borders the 

northeastern corner of the site. LFS-3 is wholly within the FEMA 100-year floodplain.

LFS-4

LFS-4, the proposed 286-acre site for the liquefaction facility, is located north of and adjacent to 

the existing LNG terminal. The site is bordered to the north by West Tank Farm Road and bisected by 

Granger Road. A wastewater treatment plant operated by the City of Lake Charles is located on the 

opposite side of West Tank Farm Road. A carbon black facility (Lake Charles Carbon Company) 

operated by Alcoa is located west of and adjacent to the site. 

LFS-4 is heavily wooded with mixed pine and hardwoods (loblolly pine, water oak, and 

sweetgum [Liquidambar styraciflua]) with areas of intermixed wetlands within a mosaic pimple mound 

setting. LFS-4 is bisected by a drainage ditch that flows from east to west and ultimately into the 

Industrial Canal. LFS-4 is wholly within the FEMA 100-year floodplain.
3-30

Insert figure 3.3.1-1 Alternative Liquefaction Facility Sites
3-31

LFS-5

LFS-5 is located just beyond the Alcoa facility west of the existing Terminal. LFS-5 has no road 

access. It is bordered to the south by the Industrial Canal. The 571-acre site is bisected by a drainage 

ditch that flows from east to west and ultimately into the Industrial Canal. To the north of the drainage 

ditch, the site is outside of the FEMA 100-year floodplain; however, to the south of the drainage ditch, it 

is within the floodplain. North of the drainage ditch, LFS-5 supports mixed hardwoods and pines with 

areas of intermixed wetlands within a mosaic pimple mound setting, similar to LFS-4. South of the 

drainage ditch, the vegetation transitions to brackish emergent vegetation, such as Gulf cordgrass 

(Spartina spartinea). Brackish emergent vegetation is also located in areas of historic dredged material 

placement to the west of the site. 

3.3.2 Site Selection Analysis

Having identified the five sites based on (1) proximity to the LNG terminal and (2) property 

considerations (parcel size and contiguity, current ownership and potential availability, etc.), various 

environmental criteria were applied for site prioritization and selection of the preferred alternative. 

During project planning, Lake Charles LNG conducted a desktop analysis of all five sites and undertook a 

concurrent program of landowner outreach, during which time the potential availability of the sites for 

lease or ownership was investigated. It should be noted that, unlike an authorization granted for a 

pipeline under section 7 of the NGA, an authorization granted for facilities under section 3 of the NGA 

(including the currently proposed liquefaction facility) does not grant the applicant eminent domain; thus,

we have limited ability to ensure that a recommended alternative site would be available unless the 

landowner makes it available for purchase or lease.

From a natural resources perspective, there is no evidence to suggest that federally or state-listed 

species are present at, or reliant on, any of the five sites. Similarly, while there is noticeable inter-site 

variation in habitat quantity and composition, reflecting differences in both actual acreages and relative 

percentages of forested and herbaceous cover, disturbed land, wetlands, uplands, etc., there appear to be 

no strongly discriminating factors that would allow prioritization of sites based on habitat quality or 

suitability for wildlife or avian use, including use by migratory birds. 

With respect to wetlands, NWI information indicates that that there are about 54 acres on LFS-1, 

86 acres on LFS-2, 45 acres on LFS-3, 93 acres on LFS-4, and 273 acres on LFS-5. In the context of 

overall site acreage, the percentage of each site characterized as wetlands is about 33 for LFS-1, 54 for 

LFS-2, 28 for LFS-3, 33 for LFS-4, and 48 for LFS-5. From a wetlands preservation perspective, LFS-3 

represents the lowest acreage impact.

The degree of geographic separation from the nearest residential areas was a selection criterion 

afforded particular focus. The preclusion of potential adverse impacts (e.g., increased noise, traffic, and 

dust) associated with facility construction and operation favors a site with no residences in close 

proximity. The area in which all five sites are located primarily supports industrial facilities interspersed 

with vegetated, undeveloped, open land; residential development is characterized by isolated houses, 

small housing clusters concentrated along area highways, and peripheral residential subdivisions. LFS-2 

and LFS-3 are the only sites that have residences within the general vicinity: at LFS-2, several isolated 

residences are located within 0.25 mile of the site’s southern boundary; at LFS-3, a small subdivision 

abuts the northeastern boundary of the site. Therefore, consideration of residential proximity favors 

LFS-1, LFS-4, and LFS-5, which have no residences in close proximity.

While all five sites are in relatively close proximity to the existing LNG terminal, only one 

(LFS-4) directly borders the terminal. As such, pipeline routing between the LNG terminal and any of the 
3-32

other four sites would necessarily involve longer connections, crossing of public/and or private land 

outside of Lake Charles LNG’s direct control, and potential environmental or engineering constraints. 

The cryogenic piping used to transport LNG between the liquefaction facility and the LNG terminal 

would be installed aboveground, precluding a direct crossing under the Industrial Canal from LFS-1; 

therefore, pipeline routing from this site would be particularly circuitous. With respect to LFS-5, 

cryogenic piping would have to cross the intervening Alcoa facility, which could be problematic due to 

the physical and safety restrictions posed by the presence of existing plant infrastructure. Because of its 

adjacency to the LNG terminal, LFS-4 represents the most advantageous site from a pipeline routing 

perspective. The length of cryogenic and support piping would be minimized and all facilities would be 

on land under Lake Charles LNG’s direct control.

Land use and zoning was a selection criterion evaluated for each of the sites. All five sites are 

wholly or predominantly zoned as heavy industrial, although some on-site agricultural areas may fall 

outside this category and require rezoning. This industrial/agricultural profile, in itself, was not regarded 

as sufficiently variable to allow site prioritization. However, the continued presence and operation of 

existing industrial facilities on two of the sites - a natural gas processing facility on LFS-3 and the facility 

operated by Shaw Group, Inc. on LFS-2 - would compromise facility layout design, especially in the case 

of LFS-2, and render the sites unviable from a configuration and available space perspective. 

Similarly, the road (Henry Pugh Boulevard) that bisects LFS-1 provides public access to the 

recreational area west of the site and the continued use of this road would have a significant and 

potentially insurmountable impact on facility design, presenting serious safety and controllability 

concerns relating to public access though an industrial plant. Road access is also a significant concern for 

LFS-5, although in this case, the recognized disadvantage relates to the lack of any peripheral roads 

providing direct access on to the site.

As facility design evolved and plant acreage requirements were increased accordingly, the 

relative lack of space afforded by LFS-1, LFS-2, and LFS-3 became an increasingly significant site 

discriminator. These three sites cover about 164, 160, and 163 acres respectively, whereas revised facility

design plans suggested the need for more acreage within the property fenceline to accommodate plant 

infrastructure and to comply with vapor dispersion and noise limit requirements (see section 3.4). With 

respect to potential noise concerns, the close proximity of a residential subdivision was considered a 

significant disadvantage for LFS-3. In addition, ongoing interaction with property owners confirmed that 

the existing industrial operations at LFS-2 and LFS-3 would continue into the foreseeable future. Given 

the lack of sufficient property area to ensure compliance with vapor dispersion and/or noise requirements, 

the exacerbating space and design restrictions imposed by continued industrial operations on LFS-2 and 

LFS-3, and public road access through LFS-1, these three sites were eliminated from further 

consideration. 

LFS-4 and LFS-5 both have sufficient space to house the proposed facilities and, based solely on 

this selection criterion, are equally viable. However, as discussed previously, lack of direct road access 

and LNG pipeline routing constraints represent significant disadvantages for LFS-5. Also, modeling of 

the potential spill scenarios from the LNG transfer line identified more zonal safety restrictions on LFS-5 

site development than the property owners were willing to accept.

Our alternatives analysis concluded that LFS-4 represents the preferred site for the proposed 

liquefaction facility. It is sufficiently sized to allow optimal facility layout design and contiguity with the 

existing LNG terminal avoids the need for off-site LNG piping. It is also geographically well separated 

from area residences, the closest of which are more than 0.4 mile distant. While LFS-4 does contain 

wetlands and forested cover, the loss of habitat diversity and function resulting from facility development 

would be generally comparable with that anticipated at the other sites, with the advantage that no 
3-33

estuarine wetlands would be affected (unlike LFS-1 and LFS-5). Of the two sites deemed to be 

sufficiently sized to accommodate the proposed liquefaction facility, LFS-4 contains a much lower 

acreage of NWI-mapped wetlands than LFS-5: 93 acres compared with 273 acres. From a visual impact 

perspective, the new facilities would be integrated into and accord with the industrial backdrop provided 

by the existing LNG terminal. To further minimize visual impacts, we are recommending that Lake 

Charles LNG retain a strip of wooded cover on the east side of proposed ACW A to the north of LFS-4, 

and on the north side of ACW D (see section 4.8.6). This could provide an effective visual screen 

between the facilities/ACW sand the nearest residences.

3.4 ALTERNATIVE TERMINAL CONFIGURATIONS 

Facility design and configuration within the liquefaction facility site is subject to the siting 

requirements of 49 CFR 193 and other industry or engineering standards. Regulatory requirements 

stipulate that potential thermal exclusion and vapor dispersion zones remain on site, limiting the potential 

locations for specific pieces of liquefaction and pretreatment equipment. Similarly, thermal radiation 

zones for flares require that the flare be set back a minimum distance from other equipment and property 

lines. The selected location of each of the components of the expanded terminal was based on the 

relevant regulations, codes, and guidelines. We did not find any alternative configurations that would 

meet these regulations, codes, and guidelines and at the same time avoid or reduce the impacts associated 

with the proposed terminal configuration. 

The proposed location for the liquefaction trains and pretreatment units, for which most of the 

modeling for thermal exclusion and vapor dispersion zones was focused, represents the area on site that is 

farthest from publicly accessible land. This location also represents the area on site that is closest to the 

existing LNG terminal, thereby minimizing the length of interconnecting LNG transfer piping. While

other locations may satisfy regulatory siting requirements equally, these two factors confer a significant 

advantage for the currently proposed layout.

As part of our analysis of alternative terminal configurations, we considered whether Lake 

Charles LNG’s planned permanent conversion of all land to industrial use is necessary across the entire 

liquefaction facility site. According to Lake Charles LNG, the perimeter of the site cannot be reduced or

adjusted and still meet operational noise and vapor dispersion requirements. Within this perimeter, Lake 

Charles LNG’s grading plan calls for the import of suitable fill material and a significant elevation

increase across the whole site to meet safety requirements, within both the operational footprint of plant 

infrastructure and adjacent construction workspaces. The increased elevation would facilitate 

maneuverability, staging, fabrication, etc. during construction and would reduce the threat of flooding 

during both construction and operation. 

Since compacted fill material would be distributed across the whole site and construction would 

continue for about 5 years, successful broad-scale restoration to previous conditions would be difficult, 

time consuming, and costly. Further, the fill material brought in for construction would have to be 

removed to and returned to off-site locations. We concur with Lake Charles LNG that, in general,

wetland losses on site would be mitigated more effectively through the proposed purchase of mitigation 

bank credits (see section 4.4.4). 

3.5 ALTERNATIVE PIPELINE ROUTES

The Lake Charles Liquefaction Project would include two new pipeline segments: the Mainline 

Connector and the Mainline 200-3 Loop. The Mainline Connector would be a greenfield segment, 

defined as a pipeline segment that is constructed cross country and within new right-of-way that does not 

parallel an existing pipeline or other linear infrastructure. The Mainline 200-3 is a looping segment, 
3-34

defined as a pipeline segment that is laid parallel to another pipeline, and is often used as a way to 

increase the capacity of a system beyond that provided by the existing pipeline. Route alternative 

considerations for each of the two proposed pipeline segments are discussed below.

3.5.1 Mainline Connector

As described in section 2.2.2.1, the 11.4-mile-long Mainline Connector would connect 

Trunkline’s existing 300 Mainline and 200 Mainline system pipelines between MLVs 303-A and 203-A, 

allowing gas to be delivered to the liquefaction facility via the existing LNG lateral, which connects with 

the 200 Mainline system pipelines at MLV 203-A. Proposed Compressor Station 203-A would be located 

on the Mainline Connector, just east of MLV 203-A. The new pipeline would be located in Jefferson

Davis and Calcasieu Parishes, Louisiana.

The regional landscape between MLVs 203-A and 303-A is rural and there are no existing 

pipeline corridors or other linear features that offer suitable collocation opportunities for the Mainline 

Connector pipeline beyond the short section (0.3 mile) between MLV 203-A and Compressor Station 

203-A. Thus, Trunkline has indicated that the baseline route for the Mainline Connector was conceived 

as the shortest distance between existing valve stations that would provide access between the three 

existing pipeline systems: Mainline 300, Mainline 200, and LNG lateral. 

Generally, shorter route lengths are correlated with lower construction costs and fewer 

environmental impacts, although variables other than pipeline length (e.g., terrain, existing land 

development, and sensitive natural resources) may weaken these correlations. Starting with the baseline 

route, Trunkline implemented broad-scale adjustments to avoid or minimize crossings of wetlands, 

waterbodies, and forested land. This effort resulted in a proposed route running northwest of the baseline 

route, with a maximum separation of 0.75 mile. Two subsequent deviations were made, between 

milepost (MP) 0.26 and MP 2.71 to avoid two waterbody crossings and between MP 3.05 and MP 3.67 to 

allow for a perpendicular crossing of State Highway 383. Both deviations also reduce potential wetland 

crossing impacts. While the proposed route is about 890 feet longer than the baseline route, it was 

developed and selected on the basis of these engineering and environmental impact considerations. 

We have analyzed the regional setting of Trunkline’s proposed Mainline Connector pipeline route

and have determined that a different route (which would likely be longer) between other points of 

interconnection would not offer any environmental advantage, irrespective of engineering feasibility or 

cost. Also, the proposed pipeline interconnection between MLV 203-A and MLV 303-A is an integral 

part of a wider system plan involving the construction of new aboveground facilities and modifications to 

existing aboveground facilities (compressor stations, meter stations, and appurtenant aboveground 

facilities). We have identified minimal environmental impacts associated with the construction and 

operation of these facilities and, while selection of a longer route for the Mainline Connector may or may 

not affect the scope and locations of these planned developments, it would be unlikely to further reduce 

system-wide environmental impacts. In summary, we did not identify any environmental concerns that 

indicate a need to identify and evaluate alternative routes for the Mainline Connector, nor were any 

alternatives suggested during the scoping period. 

3.5.2 Mainline 200-3 Loop

The location of the proposed 6.5-mile-long Mainline 200-3 Loop was chosen to fulfill the Lake 

Charles Liquefaction Project’s requirements for gas delivery and to overcome engineering constraints 

along the existing Kaplan 300 and Kaplan 200 pipelines. By definition, the Mainline 200-3 Loop would 

be collocated with the existing pipeline to be looped, precluding the need for an alternatives analysis 

beyond determining the side of the existing pipeline on which to collocate. The entire loop segment 
3-35

parallels the existing pipeline on the western/southern side. Collocation on the northern/eastern side was 

ruled out early in the planning process because construction would require crossing two existing pipelines 

and would create a conflict with the Tennessee Kaplan meter station at the northern terminus. The 

proposed right-of-way for the Mainline 200-3 Loop would partially overlap the previously disturbed 

right-of-way of the looped pipeline, minimizing environmental impacts. 

3.6 ALTERNATIVE ABOVEGROUND FACILITY SITES FOR PIPELINE EXPANSION

We evaluated alternative sites for proposed Compressor Station 203-A and also considered the 

need to evaluate potential alternative sites for the other aboveground facilities associated with the NonLiquefaction Facilities. Our assessments were based on information derived from maps, aerial 

photography, and field observations.

3.6.1 Compressor Station Sites 

The proposed Lake Charles Liquefaction Project includes the construction and operation of one 

new compressor station (Compressor Station 203-A), piping modifications at four existing compressor 

stations (Longville, Pollock, Epps, and Shaw Compressor Stations) to allow bidirectional gas flow, and 

increased horsepower at the Longville Compressor Station through the replacement of one compressor 

unit with a larger unit. Feasible alternatives for the bidirectional piping modifications and the 

compression upgrade do not exist and, given that construction would take place within the fencelines of 

the existing facilities, environmental impacts would be minimized. 

The location of Compressor Station 203-A is dictated by the gas flow hydraulic properties of the 

existing Trunkline pipeline infrastructure and the proposed Mainline Connector pipeline. The only viable 

location for the new compressor station would be one located at or in the immediate vicinity of the 

southern junction of these facilities (i.e. at MLV 203A), in an area of largely open and undeveloped land. 

We evaluated two potential sites for Compressor Station 203-A: the proposed site and the 

Compressor Station Alternative site 1 (CSA-1), as depicted in figure 3.6.1-1. CSA-1 is located on the 

west side of Dennison Road and surrounds MLV 203-A; the proposed site lies 0.25 mile east of Dennison 

Road (see figure 3.6.1-1). Table 3.6.1-1 provides a quantitative comparison of land use and other 

environmental features for each of two sites.

CSA-1 has the advantage of immediate adjacency to MLV 203-A, which would allow the 

consolidation of aboveground facilities at one common location, without the need for an off-site pipeline 

segment to connect the compressor station with MLV 203-A. However, this advantage is over-ridden by 

the presence of a perennial stream and associated band of riparian forestland that bisects the site on the 

north/south axis, and the comparative number of residences in relatively close proximity to the site.

To provide sufficient space for aboveground facilities, site preparation at CSA-1 would 

necessitate the removal of most of the riparian woodland and rerouting of the perennial stream. The 

proposed site contains an agricultural ditch and a 2.6-acre scrub-shrub wetland located in the site’s 

southeast corner in a former agricultural field. Although this ditch would be permanently filled, 

Trunkline has revised the configuration of the station from the original design to avoid the wetland and 

the environmental impact would be significantly less than that associated with the riparian woodland 

removal and stream rerouting that would be required at CSA-1.
3-36

Insert Figure 3.6.1-1 Alternative Compressor Station 203-A Sites
3-37

TABLE 3.6.1-1

Site Alternatives Comparison for Compressor Station 203-A for the Lake Charles Liquefaction Project

Environmental Features Units Proposed Site CSA-1

Land Use

Agriculture Acre 45.6 54.8

Forest land Acre 0.0 15.0

Industrial/commercial Acre 1.0 1.1

Total land usea Acre 46.6 70.9

NWI wetlands affected within construction footprintb Acre 0.0 0.0

Field delineated wetlands within construction footprint Acre 2.6 Not surveyed

Perennial streams with forested banks Number 0 1

Dry drainage/agricultural canals Number 1 0

Residences within 0.5 mile of fenceline Number 10 59

Distance to nearest residence from fenceline Feet 1,140 145

____________________

a

The total acreage for CSA-1 is larger than that for the proposed site due to the extra land needed for stream rerouting on 

the property. 

b Based on NWI data.

Table 3.6.1-1 indicates that the proposed site is located in a less populated area than CSA-1, with 

10 residences located within 0.5 mile of the site and the nearest residence being 1,140 feet away. In 

contrast, 59 residences are located within 0.5 mile of CSA-1 and several of these residences are within 

close proximity to the site, the closest being 145 feet away. From the perspective of environmental 

impacts associated with station construction and operation (e.g., increased noise, dust, and air emissions), 

the comparative lack of nearby residences is favorable.

Based on the above comparison between the two sites, we conclude that CSA-1 would not be 

environmentally preferable to the proposed location.

3.6.2 Meter Stations

The Lake Charles Liquefaction Project would require modifications to five existing meter stations 

to provide bidirectional flow capabilities and other upgrades, and the construction of five new meter 

stations in greenfield locations. Construction activities at four of the five existing meter stations (NGPL–

Lakeside, Texas Gas–Woodlawn, Tennessee–Kaplan, and Transco-Ragley) would occur within the 

existing facility footprints and in ATWS immediately adjacent to the existing facilities, as the proposed 

activities relate. Following construction at three of these meter stations, the ATWS, which predominantly 

consists of agricultural and open land, would be allowed to revert to pre-construction condition. At the 

NGPL–Lakeside Meter Station, about 0.3 acre of the ATWS immediately adjacent to the existing facility 

boundary would be retained as an addition to the permanent footprint. The proposed upgrades at the 

TETCO–Allen Meter Station would also require an increase in the permanent facility size, with the new 

portion located about 0.2 mile from the existing facility. ATWS to be used during construction would be

immediately adjacent to the new permanent facility. Because these upgrades would take place at existing 

facilities, there are no feasible alternatives for these project components.

The new LCLNG Export Meter Station, which would serve as the new meter station for the 

Trunkline LNG Terminal, would be constructed at the liquefaction facility site. Alternative sites for the 

LCLNG Export Meter Station are all within either the existing LNG terminal or the liquefaction facility

site. Since these two areas are either fully developed or would be fully developed under the proposed 

action, there is no net difference in anticipated environmental impacts between alternative site locations.
3-38

The other four new meter stations are located at existing Trunkline pipeline crossings with Gulf 

Crossing, Midcontinent Express, Kinder Morgan, and Columbia Gulf Transmission. By necessity of 

system function and design, the proposed meter stations must be located at or in the immediate vicinity of 

the intersections between Trunkline and these other suppliers; therefore, materially different alternative 

sites were not identified for evaluation. The potential impacts of construction and operation of the meter 

stations would be minimal and we conclude that there are no alternative sites that would provide a 

significant environmental advantage over the proposed sites.

The locations of the remaining Non-Liquefaction Facilities, including the Mainline 100-3 

Modifications and the Mainline 200-1 Modifications, would be located at existing facilities and, as such, 

there are no feasible alternatives to these locations.

3.7 ALTERNATIVE POWER SOURCES

3.7.1 Liquefaction Facilities

According to Lake Charles LNG, the use of electrically driven motors as an alternative to gasfired turbines was studied during pre-Front End Engineering Design, with this option being ruled out at 

the time due to the excessive amount of electrical power required (above 800 megawatts [MW]). If 

electric-powered motors were to be utilized, power would either have to be generated on site or imported

from the municipal power grid, neither of which is a feasible supply source for the reasons described 

below. 

On-site Power Generation

The construction of a single-cycle or a combined-cycle power plant would be required for on-site

power generation. Single-cycle power generation technology has no advantages over the base case 

configuration proposed for the liquefaction facility (gas turbine driven compressors) as both have similar 

efficiency ratings and both require selective catalytic reduction units to minimize air emissions that would 

impact ambient air quality. In fact, there would likely be more air emissions associated with a singlecycle power plant due to the requirement for a larger generation capacity to compensate for distribution 

and motor energy losses. By comparison, a combined-cycle power generation system would have a 

higher thermal efficiency but would require a larger plot area and would take longer to construct, which 

would impact the overall project schedule.

The noise levels associated with a power generation system located at the liquefaction facility 

would be similar to those from gas turbine driven compressors with mitigation measures, such as acoustic 

insulation, being required in both cases to meet thresholds for acceptable operational noise levels.

In summary, on-site power generation by both single- and combined-cycle plants was ruled out in 

the design of the Lake Charles Liquefaction Project as these systems would require a larger area to 

accommodate additional equipment (such as condensers and steam turbines in the case of combined 

cycle) than that currently available. Also, the introduction of steam generation would increase overall 

facility complexity and associated risks.

Imported Power

With respect to imported power, air emissions generated at the liquefaction facility itself (either 

through gas turbine drivers or on-site electrical generation) would be precluded, instead occurring in the

area where the power generation system is located. However, there would likely be no net benefit in
3-39

emissions as a result of using the grid efficiency of the regional electricity provider, Entergy. Operational 

noise associated with on-site gas turbine drivers or electrical generation would also be precluded.

When considering the imported power case, Lake Charles LNG noted that the power level needed 

to supply the refrigeration compressors would be significantly higher than the actual compressor 

requirement, as the voltage losses in transformers and power cables can account for up to 10 percent of 

the total power required. Therefore, an expansion of the existing power plants that supply the municipal 

grid could be required. With respect to the transmission lines that supply the existing terminal, the 

current infrastructure may be inadequate for such a high power demand, leading to further expansions that 

would have impacts on the environment and local communities. Additionally, the size of the electrical 

substation required to handle the imported power would be three to four times the size of the substation 

required for the proposed base case configuration, leading to further issues regarding space limitations.

One consideration that is applicable to both power supply options is the proven maximum size 

(45 MW) of electric motors for refrigeration compressors. As a result, more electric-driven compressors 

would be needed than gas turbine-driven compressors. The space requirement for these additional 

compressors would add more challenges to plant layout design.

Another factor to be considered with electric-driven refrigeration compressors is the need of 

Variable Frequency Drives (VFD). One VFD would be needed per motor so a large number of VFDs

would have to be installed near the compressors. It is expected that the plot area required for each VFD 

would be about 50 percent larger than the area required for each gas turbine. 

For the reasons above, using electric motors to drive the refrigerant compressors would increase 

the complexity and therefore the inherent risks associated with liquefaction facility operations. 

Furthermore, space limitations at the proposed site would make this alternative very challenging or 

potentially unfeasible.

3.7.2 Compressor Station 203-A

Trunkline performed a review of electric motor-driven compressors at Compressor Station 203-A. 

The electric load for this design would be of a magnitude serviceable only by a high-voltage transmission 

system for which the nearest potential interconnect is more than 2 miles away. Due to the required capital 

cost for the electric system expansion and the cost of electricity for facility operation, Trunkline

eliminated this option from initial consideration. However, Trunkline requested a high-level feasibility of 

service analysis from the providing utility (Entergy). The analysis was not available at the time the draft 

EIS was issued; therefore, we recommended that Trunkline file it prior to the end of the draft EIS 

comment period with an alternative analysis of electric motor-driven compressor units for this station. 

In its May 22, 2015 response, Trunkline provided a copy of Entergy’s facility study. The study 

addresses the additional infrastructure and modifications to existing electrical infrastructure that would be 

required to support the use of electric-driven compressor units at Compressor Station 203-A. Required 

new infrastructure would include a new switching station, which would be constructed at the compressor 

station with a separating fence, as well as two 138 kV transmission lines (two lines would be required for 

reliability). Subject to completion of a routing study, Entergy’s preliminary routing assumptions include 

a 3.2-mile-long transmission line and a 3.6-mile-long transmission line, each of which would be 

constructed within a 100-foot-wide right-of-way encompassing approximately 80 acres of land in total. 

The primary environmental benefit to electric compression at Station 203-A would be the 

elimination of local air emissions during routine operation of the station. However, generation of the 

electricity would likely result in similar (or increased) emissions at a power plant in the region. Noise 
3-40

levels could potentially remain unchanged. Entergy estimates that approximately 11 acres of wetlands 

would be affected. A total of about 57 steel structures would be required to support the transmission 

lines, which would range from 50 to 105 feet in height (Entergy, 2015). Construction of the new facilities 

would also require an approximately 3-acre laydown yard. Based on a review of aerial photography and 

information provided by Trunkline, affected land uses would likely include pasture land, agricultural land, 

mixed forest land, and rural residential land. Trunkline estimates that the capital costs for using electric 

motor-driven units rather than gas-fired equipment would be about $3 million higher, and the annual 

operating costs for electric motor-driven units would be about $10,600 higher than for gas-fired 

equipment. While there would be a reduction in local air emissions from the station using electric-driven 

compression, we note that the proposed station would be a minor source of air emissions under PSD 

regulations. Therefore, taking into account both the environmental impacts and cost implications 

associated with the use of electric motor-driven compressor units, we conclude that Trunkline’s proposed 

use of gas-fired compressor units at Compressor Station 203-A is reasonable and justified, and that 

electric compression would not provide a significant advantage over the proposed facility.
4-1

4.0 ENVIRONMENTAL IMPACT ANALYSIS

The environmental consequence of constructing and operating the Lake Charles Liquefaction 

Project would vary in duration and significance. Four levels of impact duration were considered: 

temporary, short term, long term, and permanent. A temporary impact would generally occur during 

construction, with the resource returning to preconstruction conditions almost immediately afterward. A 

short-term impact could continue for up to 3 years following construction. An impact was considered 

long term if the resource would require more than 3 years to recover. A permanent impact could occur as 

a result of an activity that modifies a resource to the extent that it would not return to preconstruction 

conditions during the life of the project, such as the construction and operational impact of a new 

aboveground facility. We considered an impact to be significant if it would result in a substantial 

beneficial or adverse change in the physical environment. 

In this section, we discuss the affected environment, general construction and operational 

impacts, and proposed mitigation measures for each resource. Lake Charles LNG and Trunkline, as part 

of their proposals, agreed to implement certain measures to reduce impacts on environmental resources. 

We evaluated the proposed mitigation measures to determine whether additional measures would be 

necessary to reduce impacts. Where we identified the need for additional mitigation, the measures appear 

as bulleted, boldfaced paragraphs in the text. We will recommend that these measures be included as 

specific conditions to authorizations that the Commission may issue to Lake Charles LNG and Trunkline. 

Conclusions in this EIS are based on our analysis of the environmental impact and the following 

assumptions:

 Lake Charles LNG and Trunkline would comply with all applicable federal laws and 

regulations;

 the proposed facilities would be constructed as described in section 2.0 of this 

document; and

 Lake Charles LNG and Trunkline would implement the mitigation measures included in 

their application and supplemental filings to the FERC.

4.1 GEOLOGY

4.1.1 Geologic Setting

The Lake Charles Liquefaction Project facilities would be located in two sections of the Coastal 

Plain physiographic province. The liquefaction facility and existing LNG terminal, and the majority of 

the Non-Liquefaction Facilities, would be within the West Gulf Coastal Plain, while the Shaw and Epps 

Compressor Stations, MEP–Perryville and Gulf Crossing–Perryville Meter Stations, and the East and

West Mississippi Barrel modifications would be located within the Mississippi Alluvial Plain (Fenneman 

and Johnson, 1946). The Coastal Plain lies along the Atlantic Seaboard and Gulf Coast, stretching 100 to 

200 miles inland and 100 to 200 miles offshore to the edge of the Continental Shelf. It comprises an 

elevated sea bottom with low topographic relief and extensive marsh lands, dipping gently seaward from 

its highest elevations of about 500 feet (Hunt, 1967). The surface materials of the region are mainly 

Quaternary-age unconsolidated sand and clay with scattered lignite deposits and small quantities of 

quartzite and limestone (Stroud and Hanson, 1981). The Mississippi Alluvial Plain intersects the East and 

West Gulf Coastal Plains and gently slopes seaward (Hunt, 1967). These Quaternary-age alluvial 

deposits cover the Gulf Coast Plains and form deep fertile soils along flood plains, terraces, and the 

Mississippi Delta (Hunt, 1967; Stroud and Hanson, 1981).
4-2

Geologic formations in the project area consist mainly of unconsolidated alluvial, coastal marsh, 

and terrace deposits that resulted from fluvial, tidal, littoral (beach or shoreline), and deltaic processes 

during the Pleistocene and Holocene epochs (see table 4.1.1-1). Elevations in the project area range from 

less than 10 feet AMSL at the liquefaction facility to more than 200 feet AMSL at the Pollock 

Compressor Station. Topography in the project area ranges from nearly level to gently sloping, with 

average slopes ranging from 0 to 3 percent within the liquefaction facility and 0 to 9 percent within the 

Non-Liquefaction Facilities (Soil Survey Staff, 2014).

Lake Charles LNG performed geotechnical studies to evaluate subsurface conditions within the 

proposed liquefaction facility site. These investigations included 83 soil borings that ranged in depth 

from 15 to 125 feet. The borings contained unconsolidated clays and silty sand in the upper 10 feet and 

clays with intermittent and discontinuous layers of silty and clayey sands from 10 to 125 feet deep. No 

significant gravel deposits or bedrock were encountered in any of the borings (Professional Service 

Industries, 2014). Groundwater was encountered between about 0 and 5 feet above sea level.

4.1.2 Mineral Resources

Nonfuel mineral resources in the project area consist mainly of salt and construction sand and 

gravel (USGS, 2009a, 2009b). Based on a review of the USGS topographical maps, recent aerial 

imagery, and available databases from the USGS, no active mining or nonfuel mineral resources are 

located within 1 mile of any of the project facilities (USGS, 2013b; 2013c).

Oil and gas production is prevalent throughout Louisiana and the surrounding region. The 

proposed project facilities would be located proximate to various oil and gas fields, including the East 

Moss Lake oil and gas field, which underlies the liquefaction facility site (LDNR, 2007a). Based on a 

review of LDNR mapping, 17 oil and gas wells are located within 0.25 mile of the liquefaction facility 

site and LNG terminal (7 of which are within the liquefaction facility site, and 3 of which are within the 

ACWs). Of these, 15 were listed as plugged and abandoned. One active gas and condensate producing 

well is located within the proposed liquefaction facility site, and one active producing well is located just 

east of the ACWs to be used for construction of the liquefaction facility and LNG terminal modifications

(LDNR, 2007b). 

In May and June 2014, we received comments by telephone and email from Margaret Kuttner, 

John Bergstedt, and Tom Bergstedt stating that they are royalty owners with an interest in the disposition 

of the active well within the liquefaction facility site. They expressed concern about how impacts on the 

well would affect their mineral rights and asked to be kept informed of discussions and decisions 

regarding the well. In July 2014, Lake Charles LNG stated that it was discussing a buyout of the well 

with the well owner (i.e., Jordan Oil) and indicated that the well would be plugged and abandoned by 

Jordan Oil prior to the start of construction. Lake Charles LNG also stated that it had met with 

Ms. Kuttner and the Bergstedts. However, in a January 2015 letter, Ms. Kuttner and the Bergstedts stated 

that the issue of their mineral rights had not yet been resolved. In order to clarify the disposition of the 

well and address the comments of Ms. Kuttner and the Bergstedts, we recommended in the draft EIS that 

Lake Charles LNG file updates on its discussions with Jordan Oil, the outcome of those discussions 

regarding the buyout and closure of the well (and potential drilling of a new well, if applicable), and 

communications with Ms. Kuttner and the Bergstedts regarding their mineral rights concerns. 

In a May 14, 2015 response to our recommendation, Lake Charles LNG indicated that discussions 

were ongoing with Jordan Oil regarding the terms and conditions of an agreement whereby Jordan Oil 

would relinquish its rights associated with the producing well within the liquefaction facility site in return 

for compensation to Jordan Oil and all associated royalty interest owners. Lake Charles LNG also stated 

that it has offered Jordan Oil access to land owned by Lake Charles LNG’s affiliate so that Jordan Oil 

may drill a new well from a nearby location outside of the liquefaction facility site. Lake Charles LNG 

stated that it would notify the Commission when such an agreement is reached. 
4-3

TABLE 4.1.1-1

Geologic Formations Affected by the Lake Charles Liquefaction Project

Facility Formation (Symbol) Unit Age Dominant Material

Liquefaction Facilities Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Pipelines

Mainline Connector Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Alluvium (Qal) Holocene Clay/Mud, Sand

Mainline 200-3 Loop Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Alluvium (Qal) Holocene Clay/Mud, Sand

Compressor Stations

203-A Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Longville Intermediate Terraces (Qti) Pleistocene Clay/Mud, Silt

Pollock Catahoula Formation (Oc) Oligocene Sandstone, Sand

High Terraces (Qth) Pleistocene Clay/Mud, Silt

Epps Braided Stream Terraces (Qbs) Pleistocene Sand, Clay/Mud

Shaw Alluvium (Qa) Holocene Clay/Mud, Sand

Meter Stations

LCLNG Export Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Kinder Morgan–Lake Charles Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Columbia Gulf–Egan Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

NGPL–Lakeside Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

TETCO–Allen Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Gulf Crossing–Perryville Braided Stream Terraces (Qbs) Pleistocene Sand, Clay/Mud

MEP–Perryville Braided Stream Terraces (Qbs) Pleistocene Sand, Clay/Mud

Texas Gas–Woodlawn Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Tennessee–Kaplan Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

Transco Ragley Intermediate Terraces (Qti) Pleistocene Clay/Mud, Silt

Mainline 100-3 Modifications

Mississippi Barrel East Alluvium (Qa) Holocene Clay/Mud, Sand

Mississippi Barrel West Alluvium (Qcm) Holocene Gravel, Sand, Clay/Mud

Mainline 200-1 Modifications

Calcasieu River HDD Alluvium (Qal) Holocene Clay/Mud, Sand

Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

US 190 Meter Station Intermediate Terraces (Qti) Pleistocene Clay/Mud, Silt

100’ Overhead Crossing Prairie Terraces (Qtp) Pleistocene Clay/Mud, Silt

MLV 202 Intermediate Terraces (Qti) Pleistocene Clay/Mud, Silt

____________________

Sources: Stoeser et al., 2005; Louisiana Geologic Survey, 2002 and 2003
4-4

Lake Charles LNG stated in its response that Jordan Oil remains responsible to any lessor, 

mineral owner, or royalty owner pursuant to the mineral leases associated with the active well and the 

Louisiana Mineral Code. However, in recognition that direct discussions with the royalty interest owners 

might facilitate fair compensation to the affected parties, Lake Charles LNG said it has met with several 

of the royalty interest owners, and that several of these parties have accepted proposals and received 

compensation for the purchase of their interests. As part of this effort, Lake Charles LNG stated that its 

representatives have had discussions with Ms. Kuttner and the Bergstedts, and that it plans to continue to 

work to reach agreement with respect to Jordan Oil and all royalty/mineral interest owners prior to taking 

a positive final investment decision and commencing work on the site. In May 18, 2015 comments on the 

draft EIS (see comment IND1 in appendix L), Ms. Kuttner and the Bergstedts provided a summary of 

their communications with representatives of Lake Charles LNG and Jordan Oil, including the status of 

their negotiations. As of the time they filed their comments, negotiations had not resulted in a resolution 

to this matter.

We acknowledge that royalty owners could be adversely affected by the closure of the currently 

active oil and gas well on the liquefaction facility site. However, the negotiations among Lake Charles 

LNG, Jordan Oil, and the affected royalty owners are beyond the scope of the EIS process and fall outside 

of the FERC's jurisdiction. If the parties cannot reach agreement, royalty owners may elect to pursue the 

matter through the appropriate legal process.

The LDNR mapping showed 66 oil and gas wells within 0.25 mile of the Non-Liquefaction 

Facilities, 64 of which were listed as plugged and abandoned, permit expired/no product, or shut-in 

production wells. One active gas and condensate producing well and one active oil producing well are 

located within 0.25 mile of the access roads proposed for the Mainline Connector. With the exception of 

a plugged and abandoned well within the proposed Compressor Station 203-A site, all of the wells are 

located outside of the proposed project workspace. 

Prior to construction, Lake Charles LNG and Trunkline would perform field investigations to 

verify the status of all of the plugged and abandoned wells within the proposed project workspace. Wells

determined to be unsatisfactorily abandoned would be properly abandoned prior to construction. 

4.1.3 Geologic Hazards

Geologic hazards are natural, physical conditions that can result in damage to land and structures 

or injury to people. Such hazards typically include seismicity (e.g., earthquakes, surface faults, and soil 

liquefaction), landslides, flash flooding, and ground subsidence. Conditions necessary for the 

development of other geologic hazards, including avalanches, volcanism, and karst terrain are not present 

in the project area. In general, the potential for geologic hazards to significantly affect construction or 

operation of the proposed project facilities is low.

4.1.3.1 Seismicity

Earthquakes and Surface Faults

The majority of significant earthquakes around the world are associated with tectonic subduction 

zones, where one crustal plate is overriding another (e.g., the Japanese islands), where tectonic plates are 

sliding past each other (such as in California), or where tectonic plates are converging (e.g., the Indian 

Sub-Continent). Relative to these highly active tectonic regions, Louisiana and the surrounding areas are 

seismically quiet.

A belt of hundreds of mostly seaward-facing faults, collectively known as the Gulf-margin 

normal faults, occur along the Gulf of Mexico. However, these faults exist in sediments and poorly 
4-5

lithified rocks; most of these materials are unable to support the extreme stresses required for the 

propagation of significant seismic events and ground motion (Crone and Wheeler, 2000). Lake Charles 

LNG completed a Seismic and Tsunami Hazard Evaluation for the proposed liquefaction facility, which 

identified an active growth fault about 1.1 miles north of the proposed liquefaction facility site. However, 

the evaluation did not identify any evidence of surface faulting, scarps, or lineaments within the 

liquefaction facility site and, therefore, determined that there was a low potential for a fault rupture hazard 

(URS Corporation, 2014).

The magnitude of an earthquake is measured using the Richter scale, which ranges from 0 to 9, 

though no real upper limit exists. Earthquakes with magnitude of about 2.0 or less are usually called 

microearthquakes, and are not commonly felt by people; large earthquakes generally have a magnitude of 

8.0 or greater (USGS, 2013a). Historically, there have only been sparse, low-magnitude seismic events 

recorded within the Gulf-margin normal faults. Only six damaging earthquakes have been reported 

through 2009, which were located in westernmost Florida (1780), southern Alabama (1993, 1997), 

southern Louisiana (1930), and eastern Texas (1891, 1932) (Crone and Wheeler, 2000; USGS, 2009c). 

The 1930 earthquake was the largest earthquake measured in Louisiana; its epicenter was about 60 miles 

west of New Orleans. The largest recorded earthquake in the vicinity of the Lake Charles Liquefaction 

Project (in 1983) was a magnitude of 3.8 on the Richter scale, located 10 miles west of Lake Charles, 

Louisiana (Stevenson and McCulloh, 2001). An event such as this today would cause considerable 

damage to poorly built structures but only negligible damage to buildings of good design and 

construction. The most significant seismic source site is the New Madrid Seismic Zone, which is located 

about 400 miles northeast of the liquefaction facility in the vicinity of New Madrid, Missouri. In 1811 

and 1812, the New Madrid Seismic Zone experienced three very large earthquakes with magnitudes 

estimated to range between 7.2 and 7.6.

The shaking during an earthquake can be expressed in terms of the acceleration due to gravity. 

Based on USGS seismic hazard mapping, the liquefaction facility, LNG terminal, and Non-Liquefaction 

Facilities in Louisiana are located in an area where peak horizontal ground accelerations, with 2 percent 

probability of exceedance in 50 years, are between 2 and 10 percent of gravity (USGS, 2008). In 

Mississippi and Arkansas where the proposed modifications to the Shaw Compressor Station and the East 

and West Mississippi Barrels would take place, peak horizontal ground accelerations are between 10 and

14 percent of gravity as they are closer to the New Madrid seismic zone. The USGS peak horizontal 

ground acceleration values are for rock sites and can be amplified by factors of 2 or more for soft soil 

sites such as those found at the liquefaction facility site. The newly constructed or modified facilities 

would be designed for earthquake ground motions; therefore, it is unlikely that they would be affected if 

an earthquake were to take place. 

Soil Liquefaction

Soil liquefaction is a phenomenon often associated with seismic activity in which saturated, noncohesive soils temporarily lose their strength and liquefy (i.e., behave like viscous liquid) when subjected 

to forces such as intense and prolonged ground shaking. Areas susceptible to liquefaction generally 

include sandy or silty soils located along rivers, streams, lakes, and shorelines or in areas with shallow 

groundwater. Soil conditions necessary for liquefaction to occur would likely be present in the project 

area. However, because of the low potential for strong and/or prolonged seismic ground shaking in the 

vicinity of the proposed facilities, the potential for soil liquefaction to occur is also low.

4.1.3.2 Landslides

Landslides involve the downslope movement of earth materials under a force of gravity due to 

natural or man-made causes. With the exception of the East and West Mississippi Barrels, the project 

facilities are located in an area considered to have a low incidence of landslides (Radbruch-Hall et al., 
4-6

1982). An analysis of the county soils data showed that the majority (98 percent) of the soils in the 

project area have average slopes less than 3 percent and would, therefore, have a low susceptibility to 

landslides (Soil Survey Staff, 2014). Based on Radbruch-Hall et al. (1982), the areas surrounding the

East and West Mississippi Barrels are considered to have a high susceptibility to slumps and earthflow 

along the river banks due to fine-grained materials underlain by coarse, easily eroded sand at depths

which the river can scour. However, the areas prone to slope failure appear to be immediately adjacent to 

the Mississippi River and outside of the workspace. Due to low topographic relief, there is a low risk for 

landslides, mudflows, or other mass wasting for any of the Lake Charles Liquefaction Project facilities. 

4.1.3.3 Land Subsidence and Sea Level Rise

Common causes of ground subsidence include the presence of karst terrain, underground mining, 

and significant groundwater or fluid withdrawal. Karst features such as sinkholes, caves, and caverns can 

form as a result of the long-term action of groundwater on soluble carbonate rocks (e.g., limestone and 

dolostone). Underground mining poses risks to engineered structures due to the potential for the 

overlying strata to collapse into the void formed by the extraction of minerals. Based on a review of 

available information, there are no underground mining activities or potential to encounter karst terrain in 

the project area (USGS, 2013b, 2013c; Epstein et al., 2002). Therefore, subsidence associated with these 

causes is not anticipated.

Subsidence could occur in the project area, particularly at the liquefaction facility and ACWs, due 

to oil and gas extraction and groundwater withdrawal. As discussed above, the liquefaction facility would 

be located within the East Moss Lake oil and gas field, which is actively producing oil and gas. In 

addition, the liquefaction facility would be located in the vicinity of (greater than 400 feet from) several 

water supply wells as discussed in section 4.2.1. Lake Charles LNG’s Marine Statistical Analysis 

(Moffatt & Nichol, 2014) estimated that regional subsidence proximate to the proposed liquefaction 

facility will be about 0.18 inch per year. This subsidence combined with an estimated sea level rise of 

0.12 inch per year would equate to a loss in elevation of about 7.5 inches (0.63 feet) over the 25-year life 

of the project. Lake Charles LNG stated that monitoring can be done through periodic topographic 

surveying of the site, but did not commit to conduct such monitoring because it does not anticipate that 

any mitigation would be required based on the estimated subsidence rate. However, we believe that 

periodic monitoring should be completed; therefore, we recommended in the draft EIS that Lake Charles 

LNG file a ground subsidence monitoring plan and possible mitigation measures prior to the end of the 

draft EIS comment period. 

In a May 14, 2015 response to this recommendation, Lake Charles LNG declined to provide a 

plan, noting that it complies with the federal safety standards for LNG facilities at 49 CFR Part 193,

Subpart G (Maintenance) (specifically citing parts 193.2609 and 193.2623), and that it would inspect 

tanks and support system foundations for evidence of subsidence or degradation of support system 

integrity. Lake Charles LNG stated that surveys would be evaluated against historical data to determine if 

abnormal or unanticipated subsidence were occurring, with deviations from baseline surveys conducted as 

part of the construction execution plan serving as lead indicators. Mitigation would be addressed on a 

case-by-case basis. While compliance with federal safety standards would require some inspection, we 

continue to believe that a plan for period monitoring and reporting is warranted. Therefore, we 

recommend that:

 Prior to construction, Lake Charles LNG should file with the Secretary a plan for 

periodic monitoring and reporting of ground subsidence and foundation settlement 

for the design life of the liquefaction facility.
4-7

4.1.3.4 Flooding/Storm Damage/Tsunamis

FEMA produces Flood Insurance Rate Maps for municipalities across the nation. The maps 

depict zones with assigned probabilities of experiencing a flood event during any 1-year period. The 

100-year flood represents a river channel water level that, based on an analysis of the historic record, is 

likely to be equaled or exceeded every 100 years, meaning that there is a 1 percent chance that the water 

level will be equaled or exceeded in any individual year during a flood event. The lowest mapped 

probability of flooding is 0.2 percent, which would have an average flooding recurrence interval of 

500 years. 

We evaluated the potential for flooding at the proposed project facilities using FEMA’s Map 

Service Center, the associated Flood Insurance Rate Maps, and the National Flood Hazard Layer. The 

liquefaction facility would be situated on a 100-year floodplain (FEMA, 2014). Some of the NonLiquefaction facilities, including the Kinder Morgan–Lake Charles, Columbia Gulf–Egan, and NGPL–

Lakeside Meter Stations, would also be located in the 100-year floodplain, and portions of the Mainline 

Connector and Mainline 200-3 Loop would be at risk of flooding because they cross 100- and 500-year 

floodplains near streams and rivers. The remaining project facilities would be located outside of the 

500-year floodplain. To mitigate the risk of flooding, Lake Charles LNG has committed to constructing 

critical liquefaction facilities at an elevation above the 500-year floodplain and sensitive aboveground 

facilities at the liquefaction facility and the compressor and meter stations at a final grade elevation that 

exceeds the 100-year floodplain.

The proposed liquefaction facility site is subject to periodic hurricanes. Hazards associated with 

hurricanes include storm surges, heavy rainfall, inland flooding, high winds, tornadoes, and rip currents.

Hurricane intensity is measured on the Saffir-Simpson Scale and ranges from a Category 1 storm with 

winds from 74 to 95 miles per hour (mph) that produce some damage, to a Category 5 storm with winds 

greater than 157 mph that produce catastrophic damage (National Weather Service, 2014). Lake Charles 

LNG has completed an investigation of storm surge for the Lake Charles Liquefaction Project. Based on 

historical data, it was found that the liquefaction facility site is located in an area where the return period 

for a hurricane to strike is about 13 to 14 years and the return period for a major hurricane (Category 3 or 

higher) strike is about 33 to 34 years. This means that in a given year there is about a 3 percent chance 

for a major hurricane to make landfall within the general vicinity of the proposed liquefaction facility

(HDR Engineering, 2012). FEMA has published probabilistic storm surge study maps which indicate that 

a storm surge still water elevation of +9.6 feet (NAVD 88) has a 1 percent annual probability of being 

exceeded while a storm surge still water elevation of +14.2 feet (NAVD 88) has a 0.2 percent annual 

probability of being exceeded (500-year flood level) at the liquefaction facility site. Therefore, because 

the liquefaction buildings and critical equipment would be constructed at an elevation of 15 feet, the 

facility would be able to withstand storm surges without damage from a Category 3 hurricane.

Lake Charles LNG’s Seismic and Tsunami Hazard Evaluation report described the potential for a 

tsunami or seiche (i.e., a condition in which a body of water is caused to rock, causing wave action) to 

impact the liquefaction facility. Because the liquefaction facility site is located 24 miles north of the Gulf 

of Mexico shoreline and given the low probability of strong seismic events in the Gulf, the report 

concluded that the potential for a seismically generated tsunami or seiche hazard to impact the 

liquefaction facility is non-existent (URS Corporation, 2014). We concur with this determination. 

Tsunamis could also be generated by offshore landslides; however, the maximum estimated run-up values 

are significantly less than those from storm surge and therefore the tsunami hazard is inherently 

considered since the facility is designed for storm surge. 
4-8

4.1.4 Design and Construction of the Project Facilities

4.1.4.1 Liquefaction Facility

Site Grading 

The liquefaction facility site would be cleared, grubbed, and prepared using standard earthmoving 

and compaction equipment. Existing site grade elevations range between +6.4 feet and +7.6 feet (NAVD 

88). The burning of brush, vegetation, and trees or burying of any these materials would not be permitted 

on site. Imported structural fill would be used to raise the site elevation to +11.0 feet in the process areas 

and +8.0 feet for the balance of the site. It is estimated the consolidation settlements of this fill material 

would range between 2 and 3 inches over the project life. The elevation of +11.0 feet is based upon a 

100-year floodplain elevation of +9.0 feet provided in the FEMA Flood Insurance Rate Maps for the site 

plus an additional 2 feet to compensate for sea level rise, surface soil layer consolidation, and regional 

area subsidence for a 25-year project design life. 

Foundations

Foundations used for this project would range from shallow foundations for lightly loaded 

structures to deep foundations for heavy equipment and settlement-sensitive equipment and structures. 

Deep foundations would either be driven precast concrete piles or auger cast-in-place concrete piles. The 

length of the piles would be determined during final design and would depend on pile type and size, 

downdrag loads, and allowable settlement of the structure. In the process areas of the liquefaction 

facility, the top of concrete (operating level) pedestals for structure and equipment supports would

generally be at an elevation of +12.0 feet (NAVD 88). However, the top of concrete elevation for all 

critical equipment (e.g., transformers, substations, switchgears, remote instrument enclosure units, mixed 

refrigerant and propane compressors, BOG compressors, cryogenic heat exchanges, propane vaporizers)

would be at an elevation of +15.0 feet. The top of the concrete elevations for critical equipment would be 

above the maximum elevations anticipated from a Category 3 hurricane strike. 

The control building floor slab would have two top of concrete elevations. The majority of the 

control building floor slab top of concrete elevation would be +12.5 feet while the recessed areas for 

computer access floors would have top of concrete elevation of +11.0 feet, which would be above the 

100-year floodplain elevation. 

Facility and Structure Design

The liquefaction facilities would be constructed to satisfy the design requirements of 49 CFR 193, 

NFPA 59A-2001, 2009 International Building Code, and American Society of Civil Engineers 

(ASCE) 7-05. For seismic design, the facility would be designed to satisfy the requirements of NFPA 

59A-2006 and ASCE 7-05.

Wind Design 

LNG facilities as defined in 49 CFR 193 would be designed for a sustained wind speed of 

150 mph. Other non-LNG facilities associated with the liquefaction facility would be designed for a 

110-mph, 3-second gust wind speed in accordance with ASCE 7-05.

Seismic Design Ground Motions

Geotechnical investigations of the liquefaction facility site determined that the site is classified 

as Site Class E (soft clay) in accordance with the International Building Code and standard ASCE 7-05 

based on a site average shear wave velocity that ranged between 163 and 181 meters per second
4-9

(URS, 2014). Sites with soil conditions of this type would experience significant amplifications of 

surface earthquake ground motions. 

URS performed a site-specific seismic hazard study for the site. The study concluded that 

earthquake ground motions at the ground surface of the site that have 2 percent probability of being 

exceeded in 50 years have a 0.2-second spectral acceleration value of 0.214 g, while the 1.0-second 

spectral acceleration at the site is 0.141 g (URS, 2014). These predicted spectral accelerations are 

relatively low compared to other locations in the United States.

Submittal of Final Design Documents

The design of the facility is currently at the front-end engineering design (FEED) level of 

completion. Lake Charles LNG has proposed a feasible design and committed to conducting a significant 

amount of detailed design work for the proposed liquefaction facility 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 should occur prior to the stage 

Lake Charles LNG has indicated in its application and subsequent filings. Therefore, we recommend 

that:

 Lake Charles LNG should file with the Secretary the following information, 

stamped and sealed by the professional engineer-of-record:

a. site preparation drawings and specifications;

b. LNG liquefaction facility structures and foundation design drawings and 

calculations; and

c. quality control procedures to be used for civil/structural design and 

construction.

In addition, Lake Charles LNG should file, in its Implementation Plan, the schedule 

for producing this information.

4.1.4.2 Compressor Station 203-A

Compressor Station 203-A would be a large, greenfield facility capable of producing 98,685 hp 

and would be located in an area underlain by clay or mud. Trunkline stated that it would conduct 

geotechnical investigations of the site; however, the results of these investigations were not yet available 

at the time the draft EIS was prepared. Accordingly, we recommended in the draft EIS that Trunkline file 

the results of its geotechnical investigation at the Compressor Station 203-A site, including any resulting 

foundation and site improvement recommendations. On May 14, 2015, Trunkline filed a report entitled, 

Geotechnical Investigation, 203A Compressor Station, Calcasieu Parish, LA, (Tolunay-Wong Engineers, 

Inc., 2015) describing geotechnical studies conducted to evaluate subsurface conditions at the site, the 

results of these studies, and recommendations. We find the geotechnical report to be acceptable.

4.1.5 General Impacts and Mitigation

The overall effect of the project on topography and geology would be minor. The primary 

impacts would be limited to construction activities and would include disturbance of slopes within the 

work areas. Such impacts resulting from grading and trenching operations along the pipeline rights-ofway would be temporary because Trunkline would restore these areas to preconstruction contours to the 

maximum extent practicable. However, impacts at the liquefaction facility and other aboveground 
4-10

facilities would be permanent where grading and filling is required to create a safe and stable land surface 

to support the facilities. Additionally, Lake Charles LNG does not plan to restore the ACWs to 

preconstruction contour, therefore, impacts within these areas would also be permanent (see section 

4.2.3).

Utilization of the HDD method would eliminate impacts on existing geologic conditions between 

the HDD entry and exit points at the locations where this method is used. Trunkline has not yet 

conducted geotechnical surveys for the proposed HDD crossings to evaluate the suitability of the geologic 

materials. Trunkline proposes to conduct these investigations within 1 year prior to construction of the 

proposed pipelines, and would provide the results of these studies and proposed mitigation measures, as 

necessary, when they become available. Therefore, we recommend that: 

 Prior to construction, Trunkline should file with the Secretary the geotechnical 

investigations, stamped and sealed by the professional engineer-of-record, which are 

necessary to evaluate the suitability of the proposed HDD crossings.

Based on the low probability of localized seismic ground shaking in the vicinity of the project, we 

do not anticipate any problems attributable to seismicity. Studies of earthquake performance of gas 

transmission pipelines in southern California indicate that modern, arc-welded, ductile steel pipelines 

have performed very well in earthquakes with magnitudes greater than or equal to 5.8 (O’Rourke and 

Palmer, 1996). These studies addressed the effects of 11 earthquakes between 1933 and 1994 with 

magnitudes ranging from 5.8 to 7.7. Pipelines and associated aboveground facilities are designed and 

installed in accordance with DOT standards, including those in 49 CFR 192, Transportation of Natural 

and Other Gas by Pipeline: Minimum Federal Safety Standards. Each facility would be designed and 

constructed to provide adequate protection from washouts, floods, unstable soils, or other hazards that 

could cause it to move or sustain abnormal loads.

 

Based on available soils and geologic maps and the geotechnical investigations conducted by 

Lake Charles LNG, we do not anticipate that any blasting would be required for the construction of the 

project facilities.

Based on the above discussion, and in consideration of Trunkline’s and Lake Charles LNG’s

proposed mitigation and design criteria, we conclude that the Lake Charles Liquefaction Project would 

not significantly impact or be impacted by geological conditions in the area.

4.2 SOILS

4.2.1 Existing Soil Resources

The soils affected by the proposed project were identified and assessed using various data sources 

including digital soils data (e.g., the Soil Survey Geographic [SSURGO] database) and published soil 

surveys for the applicable parishes and counties, where available (see table 4.2.1-1). The SSURGO 

database is a digital version of the original county soil surveys developed by the U.S. Department of 

Agriculture (USDA), Natural Resources Conservation Service (NRCS) for use with geographic 

information systems (GIS). It provides the most detailed level of soils information for natural resource 

planning and management. The attribute data within the SSURGO database provides the proportionate 

extent of the component soils and their properties for each soil map unit. 
4-11

TABLE 4.2.1-1

Characteristics of Soils in the Lake Charles Liquefaction Project Area (in acres)

Facility Totala

Prime 

Farmlandb

Highly Erodible Compaction 

Pronee

Revegetation 

Concernsf Waterc Windd

LIQUEFACTION FACILITIES

Liquefaction Facility 285.9 243.5 0.0 0.0 202.4 0.0

Additional Construction 

Workspaces

325.2 276.3 0.0 0.0 256.6 0.0

Subtotal 611.1 519.8 0.0 0.0 459.0 0.0

NON-LIQUEFACTION FACILITIES

Pipelines

Mainline Connector 244.1 232.7 0.0 0.0 209.6 0.0

Mainline 200-3 Loop 101.3 97.7 0.0 0.0 100.8 0.0

Compressor Stations

Compressor Station 203-A 46.6 46.6 0.0 0.0 46.6 0.0

Meter Stations g

Kinder Morgan–Lake Charles 2.4 2.4 0.0 0.0 2.4 0.0

Columbia Gulf–Egan 4.6 4.6 0.0 0.0 4.6 0.0

NGPL–Lakeside 2.9 2.9 0.0 0.0 2.9 0.0

TETCO–Allen 4.5 3.5 0.0 0.0 2.2 0.0

Gulf Crossing–Perryville 3.2 3.2 0.0 0.0 2.3 0.0

MEP–Perryville 5.5 5.5 0.0 0.0 5.5 0.0

Texas Gas–Woodlawn 2.1 2.1 0.0 0.0 2.1 0.0

Transco Ragley 1.4 1.4 0.0 0.0 1.3 0.0

Mainline 200-1 Modifications

Calcasieu River HDD 57.8 30.0 0.0 0.0 41.3 0.0

US 190 Meter Station 1.2 1.2 0.0 0.0 0.0 0.0

Subtotal 477.6 433.8 0.0 0.0 421.6 0.0

Project Total 1,088.7 953.6 0.0 0.0 880.6 0.0

_____________________

a Existing aboveground facilities and the proposed contractor yard, a currently graveled lot, are not included and should be 

considered as disturbed urban land (no limitations data available). 

b As designated by the NRCS. Includes soils that are considered prime if a limiting factor is mitigated (e.g., artificial 

drainage).

c

Includes land in capability subclasses IVe through VIIe, which have severe to extreme erosion limitations for agricultural 

use, and soils with an average slope greater than 8 percent.

d

Includes soils in wind erodibility groups 1 and 2, which includes soils with poor aggregation that are particularly susceptible 

to wind erosion.

e

Includes soils in somewhat poor, poor, and very poor drainage classes with surface textures of sandy clay loam or finer.

f

Includes coarse-textured soils (sandy loams and coarser) that are moderately well to excessively drained and soils with an 

average slope greater than 8 percent.

g Soil characteristics and associated acreage for the LCLNG Export Meter Station are included in those shown for the new 

liquefaction facility site. 

Source: Soil Survey Staff, 2014
4-12

Liquefaction Facility, Existing LNG Terminal, and Additional Construction Workspaces

The proposed liquefaction facility is located on a largely undeveloped 285.9-acre site just north of 

the existing LNG terminal. Construction of the liquefaction facility and LNG terminal modifications 

would also require the disturbance of about 325.2 acres of land encompassed by the ACWs. Soils within 

the liquefaction facility site and ACWs consist of very deep, fine to very fine textured, very poorly to 

somewhat poorly drained soils that formed in alluvial, eolian, and marine deposits (Soil Survey Staff, 

2014).

The soils within the existing LNG terminal site are predominantly mapped as urban land, which is 

defined as areas where more than 85 percent of the surface is covered by asphalt, concrete, buildings, or 

other impervious surfaces (Soil Survey Staff, 2014). The proposed modifications to the existing LNG 

terminal required for the project would occur almost entirely within previously disturbed areas of the 

terminal and would have minimal, if any, impacts on soil resources. Construction of the two TCDs would 

require dredging of about 26,000 cubic yards of sediment in the Industrial Canal/Turning Basin east of the 

Calcasieu Ship Channel. The overall extent of dredging is expected to be 22.1 acres, extending about 

2,800 feet along the waterfront and southward to the existing navigation channel. Lake Charles LNG 

anticipates using a cutter suction dredge to hydraulically pump the dredge materials through a temporary 

pipeline to an approved onshore disposal site located about 0.75 mile to the northeast. Impacts associated 

with sediment resuspension and turbidity during dredging activities are discussed in section 4.3.2.

Non-Liquefaction Facilities

The proposed Mainline Connector pipeline, Mainline 200-3 Loop, Compressor Station 203-A, 

and other new or modified aboveground facilities would be located on soils that consist of very deep, fine 

textured, poorly to moderately well drained soils that formed in alluvium, fluviomarine, and eolian 

deposits (Soil Survey Staff, 2014). The proposed modifications within the boundaries of existing 

aboveground facilities (i.e., where temporary construction workspace is not required outside of the 

previously disturbed areas) would have negligible impacts on soil resources.

4.2.1.1 Prime Farmland

The USDA defines prime farmland as “land that has the best combination of physical and 

chemical characteristics for producing food, feed, fiber, and oilseed crops” (Soil Survey Staff, 1993). 

This designation includes cultivated land, pasture, woodland, or other lands that are either used for food 

or fiber crops, or are available for these uses. Urbanized land, built-up land, and open water cannot be 

designated as 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 growing season. Soils that do not meet the above criteria may be 

considered prime farmland if the limiting factor is mitigated (e.g., by draining or irrigating). 

About 88 percent (953.6 acres) of soils that would be affected by the Lake Charles Liquefaction 

Project are designated as prime farmland. However, the majority of this soil (about 729.4 acres), 

including 519.8 acres within the liquefaction facility site and ACWs, is within land that is not classified as 

agricultural land use. Of the prime farmland affected, 243.5 acres would be permanently converted to 

urban land for operation of the liquefaction facility and 57.2 acres would be similarly converted due to 

operation of the other aboveground facilities. An additional 276.3 acres of prime farmland soils in the 

ACWs would be permanently impacted due to the deposition of fill within the workspaces, which Lake 

Charles LNG proposes not to restore to preconstruction condition. The remaining 376.6 acres of prime 

farmland soils would be restored to preconstruction conditions and are anticipated to retain their former 

productivity.
4-13

4.2.1.2 Erosion

Erosion is a continuing natural process that can be accelerated by human disturbance. Factors 

such as soil texture, structure, slope, vegetative cover, rainfall intensity, and wind intensity can influence 

the degree of erosion. Soils most susceptible to erosion by water are typified by bare or sparse vegetative 

cover, non-cohesive soil particles with low infiltration rates, and moderate to steep slopes. Soils typically 

more resistant to erosion by water include those that occupy low relief areas, are well vegetated, and have 

high infiltration capacity and internal permeability. Wind erosion processes are less affected by slope 

angles than water erosion processes. Wind-induced erosion often occurs on dry soils where vegetative 

cover is sparse and strong winds are prevalent.

Based on the soil properties reviewed, none of the soils in the Lake Charles Liquefaction Project 

area are considered highly susceptible to erosion by wind or water. 

4.2.1.3 Compaction Potential

Soil compaction modifies the structure and reduces the porosity and moisture-holding capacity of 

soils, which increase runoff potential. Construction equipment traveling over wet soils could disrupt soil 

structure, reduce pore space, and cause rutting. The degree of compaction depends on moisture content 

and soil texture. Fine-textured soils with poor internal drainage that are moist or saturated are the most 

susceptible to compaction and rutting.

About 75 percent (459.0 acres) of the soils within the liquefaction facility and ACWs and 

88 percent (421.6 acres) of the soils within the Non-Liquefaction Facilities are prone to compaction.

4.2.1.4 Revegetation Potential

Successful restoration and revegetation are important for maintaining soil productivity and 

protecting the underlying soil from potential damage, such as erosion. The revegetation potential of soils 

affected by the Lake Charles Liquefaction Project was evaluated based on the soil surface texture, slope, 

and drainage class. Droughty soils that have a coarse surface texture and are moderately well to 

excessively drained may be difficult to revegetate. Drier soils have less water to aid in the germination 

and eventual establishment of new vegetation. Coarser textured soils have a lower water holding capacity 

following precipitation, which could result in moisture deficiencies in the root zone and unfavorable 

growing conditions for many plants. 

Due to the fine textured soils and nearly level topography in the project area, no revegetation 

concerns were identified. 

4.2.2 Soil Contamination

Based on a review of the EPA’s Toxic Release Inventory Program sites in Louisiana, one 

hazardous waste site is located within 0.25 mile of the Lake Charles Liquefaction Project. The Lake 

Charles Carbon Company, located directly west of the proposed liquefaction facility, is listed as being in 

Significant Violation for releases of benzoperylene, hydrogen fluoride, lead, mercury, and polycyclic 

aromatic compounds (EPA, 2006). Lake Charles LNG conducted soil contamination investigations along 

the western border of the LNG terminal property (bordering the Lake Charles Carbon Company) to 

characterize the extent of polycyclic aromatic hydrocarbons (PAH) and polychlorinated biphenyls (PCB) 

contamination in soils within Lake Charles LNG’s property. The results of these investigations indicate 

that 29 percent of samples screened for PAHs and 6 percent of samples screened for PCBs were above the 

LDEQ’s industrial site standards (Tetra Tech, 2014). Ground disturbance from construction activities in 

this area has the potential to expose these contaminated soil materials. 
4-14

Lake Charles LNG stated that impacted media would be managed and disposed of in accordance 

with all applicable regulations and in coordination with Alcoa (the current owner of the Lake Charles 

Carbon Company) and the LDEQ. If previously unidentified contaminants are encountered during 

construction, Lake Charles LNG and Trunkline would follow the steps outlined in their Plan for 

Unanticipated Discovery of Contaminated Soils or Groundwater (see appendix E). This plan specifies 

that EIs and construction contractor personnel would be trained in hazard identification and worker 

protection, lists indicators of possible contamination, requires preconstruction inspections prior to 

beginning work in each area of the project, and identifies measures to be implemented in the event that 

suspected contamination is encountered. 

4.2.3 General Impacts and Mitigation

Construction activities such as clearing, grading, trench excavation, backfilling, and the 

movement of construction equipment may affect soil resources. Clearing removes protective vegetative 

cover and exposes the soil to the effects of wind and rain, which increases the potential for soil erosion 

and sedimentation of sensitive areas. Grading, spoil storage, and equipment traffic can compact soil, 

reducing porosity and increasing runoff potential.

To reduce the impacts of construction on soils, Lake Charles LNG and Trunkline would 

implement the FERC Plan and Procedures except where alternative measures are warranted. The Plan 

and Procedures include measures to control erosion and sedimentation during construction and to ensure 

proper restoration of disturbed areas following construction. Relevant mitigation measures specified in 

the Plan and Procedures include:

 sediment barriers, such as silt fencing and/or straw bales, would be installed before 

ground-disturbing activities to prevent sediment flow from construction areas into 

waterbodies, wetlands, and roads;

 temporary erosion control measures, such as temporary slope breakers and mulch, would 

be installed during construction;

 permanent erosion control measures, such as permanent slope breakers, trench breakers, 

and revegetation of the disturbed areas, would be maintained following construction;

 temporary and permanent trench plugs would be constructed to reduce runoff velocities 

in the trench during construction and reduce subsurface groundwater movement after the 

trench is backfilled;

 erosion control fabric would be placed at dike and drainage swale outlets, on steep slopes, 

and adjacent to roads and waterbodies as necessary; and

 dust suppression, via water application, would be used as necessary to control soil loss 

from wind erosion.

Rutting and compaction would be minimized by avoiding construction during periods of heavy 

rainfall or unusual soil saturation, to the extent practicable, and by utilizing low-ground weight 

construction equipment and/or timber mats. 

Construction debris (e.g., used filter bags, skids, trash) would be removed from the right-of-way 

unless the landowner or land management agency approves otherwise, and temporary work areas (except 

the ACWs) would be restored to preconstruction conditions. Post-construction monitoring of mitigation 

measures would be conducted to ensure their successful implementation. Disturbed areas would be 
4-15

monitored following construction for the first and second (as necessary) growing seasons in upland areas 

and at least 3 years in wetlands to ensure successful restoration (see section 2.6.2).

As agreed upon by the landowner, Lake Charles LNG anticipates that it would stabilize the 

ACWs with gravel or vegetation, and would install additional temporary or permanent erosion control 

devices to prevent off-site erosion and sedimentation. Lake Charles LNG also stated that final detail 

designs of these locations would be completed by the selected contractor and permitted as necessary prior 

to disturbance and use. To ensure that the ACWs are adequately stabilized and runoff accounted for to 

avoid impacts on surrounding areas, we recommend that: 

 Prior to construction, Lake Charles LNG should file with the Secretary, for review 

and written approval by the Director of the Office of Energy Projects (OEP), final 

design plans for the ACWs that detail how each ACW would be stabilized after 

construction is complete to prevent off-site erosion impacts on the surrounding 

areas, and any planned mitigation to address altered drainage patterns resulting 

from the modified elevation and clearing of these sites.

Soil contamination from non-EPA-regulated volumes of spills or leaks of fuels, lubricants, and 

coolant from construction vehicles would be avoided by following the Spill Prevention and Response 

(SPAR) Plan prepared by Lake Charles LNG and Trunkline and the measures in our Plan and 

Procedures. The SPAR plan identifies measures to be taken for spill preparedness and prevention, 

emergency response procedures, designated coordinators and duties, reporting procedures, and contact 

numbers for local emergency officials. The contractor(s) hired by Lake Charles LNG and Trunkline

would use the SPAR Plan for minimum guidelines to create a project-specific Spill Prevention, Control,

and Countermeasure (SPCC) Plan(s) for EPA-regulated volumes of fuels or hazardous materials. The 

contractor’s SPCC Plan(s) would also need to comply with section IV.A of our Procedures. Lake Charles 

LNG and Trunkline have also prepared a Plan for Unanticipated Discovery of Contaminated Soils or 

Groundwater. As described above, this plan outlines response measures to be taken by the EIs and 

contractors if previously unidentified hazardous materials are encountered during construction. We have 

reviewed the SPAR Plan and the Plan for Unanticipated Discovery of Contaminated Soils or 

Groundwater provided with Trunkline and Lake Charles LNG’s application and find them generally 

acceptable, but the SPAR plan has not yet been updated to include project-specific emergency 

contacts and local authorities. Additionally, the project-specific SPCC Plan(s) is not yet available 

because it would be prepared by the construction contractor(s). Therefore, we recommend that:

 Prior to construction, Lake Charles LNG and Trunkline should file with the 

Secretary an updated SPAR Plan that includes project-specific emergency contacts 

and local authorities, and the project-specific SPCC Plan(s) for review and written 

approval by the Director of OEP.

As discussed in section 2.5.1, Lake Charles LNG and Trunkline would employ EIs to verify 

compliance with the FERC Plan and Procedures, SPAR Plan, and other project-specific plans and 

specifications during construction and restoration. The EIs would have the authority to stop work and 

order corrective actions for activities that violate the environmental conditions of the FERC Certificate 

and other authorizations. 
4-16

4.3 WATER RESOURCES

4.3.1 Groundwater Resources

The majority of the Lake Charles Liquefaction Project facilities are located in the coastal 

lowlands aquifer system, while the Gulf Crossing–Perryville and MEP–Perryville Meter Stations, Epps 

and Shaw Compressor Stations and the Mississippi Barrel East and West are located in the Mississippi 

River Valley alluvial aquifer system (USGS, 2003).

The coastal lowlands aquifer system is a wedge-shaped, gulf-ward-thickening, semi-consolidated 

aquifer composed of discontinuous bands of sands, silts, and clays ranging in age from the Oligocene to 

Holocene epochs. This aquifer reaches depths of up to 14,000 feet in southern Louisiana; however,

depths associated with the project areas are generally between 6,000 and 10,000 feet (USGS, 1998). The 

Pollock Compressor Station is located at the landward edge of the coastal lowlands aquifer system where 

it borders the Mississippi embayment aquifer system and depths are generally less than 2,000 feet (USGS, 

1998; USGS 2003). The coastal lowlands aquifer system is capable of supplying large quantities of water 

from properly constructed wells. Maupin and Barber (2005) estimated that about 2,370 million gallons 

per day were withdrawn from the coastal lowlands aquifer system in 2000 (Maupin and Barber, 2005). 

Based on development in the region it is assumed that current withdrawals are significantly higher than 

those in 2000.

The Mississippi River Valley alluvial aquifer system is the largest surficial aquifer system (about

33,000 square miles) in Louisiana, Arkansas, and Mississippi (USGS, 1998). It formed from the 

deposition of glacial outwash in the river valley carved by the ancestral Mississippi River. This water 

bearing, braided sequence of gravels and coarse sands was then confined by fine, post-glacial alluvial 

deposits laid down by the meandering river system we know today. The thickness of this confining unit 

averages between 20 and 30 feet, but is missing in some places where the rate of erosion supersedes 

deposition (USGS, 1998). Below the confining layer, the aquifer extends to depths of 150 feet or more 

(USGS, 1998). This aquifer system is also capable of supplying large quantities of water from properly 

constructed wells. Total withdrawals from the Mississippi River Valley alluvial aquifer were estimated to 

be 9,290 million gallons per day in 2000 (Maupin and Barber, 2005). Based on development in the 

region it is assumed that current withdrawals are significantly higher than those in 2000.

4.3.1.1 Sole Source Aquifers

The EPA defines a sole or principal source aquifer (SSA) as one that supplies at least 50 percent 

of the drinking water consumed in the area overlying the aquifer. EPA guidelines require that SSAs can 

have no alternative drinking water source(s) that could physically, legally, and economically supply all 

those who depend upon the aquifer for drinking water (EPA, 2012). 

The Mississippi River Alluvial aquifer, in which the Gulf Crossing–Perryville and MEP–

Perryville Meter Stations, Epps and Shaw Compressor Stations, and the Mississippi Barrel East and West 

are or would be located, is not listed as an SSA. All of the remaining Lake Charles Liquefaction Project

facilities are or would be located in the Chicot SSA (EPA, 2008). The Chicot aquifer system is about

9,000 square miles and composed of productive, saturated coarse sands and gravels and the adjoining silt 

and clay deposits that confine them (Louisiana Department of Transportation and Development [DOTD] 

and USGS, 2004). In 2010, 648.5 million gallons per day were withdrawn from the Chicot aquifer, which 

accounted for 41 percent of Louisiana’s total groundwater usage (DOTD and USGS, 2011). Three units 

of the Chicot aquifer are present in Lake Charles: the 200-foot sand, the 500-foot sand, and the 700-foot 

sand. In some areas, groundwater withdrawals from the Chicot aquifer are causing lowered water levels 

and saltwater encroachment. In the Lake Charles industrial district, intense pumping of the 500-foot sand 
4-17

has lowered water levels and formed a deep cone of depression centered under the district. Chloride 

levels have remained relatively stable since the mid-1970s; however, elevated chloride levels (i.e., greater 

than 100 milligrams per liter) observed at public supply wells in eastern and southern Lake Charles 

suggest that additional upconing of salt water from the 700-foot sand to the 500-foot sand may occur in 

the future (DOTD and USGS, 1999; LDEQ, 2009a). 

4.3.1.2 Water Supply Wells

Louisiana’s Wellhead Protection Program is a component of the LDEQ’s Drinking Water 

Protection Program and is designed to protect the quality of public drinking water supplies obtained from 

community water wells. The LDEQ delineates a drinking water protection area around each well, ranging 

from a 1,000-foot-radius to a 1-mile-radius, depending on well screen depth, construction date, or aquifer 

source. A Management Plan is then created for each well to minimize the potential risks to public water 

supplies, which can include ordinances, source prohibitions, and/or education of the public. 

Based on consultation with the LDEQ, the liquefaction facility and the LCLNG Export Meter 

Station would be located within eight drinking water protection areas (LDEQ, 2013a). Each of the 

drinking water protection areas is centered on a wellhead and has a 1-mile radius because the protected 

well depths are less than 1,000 feet. Two of the wells supply water to the existing LNG terminal, three

industrial supply wells are located on the Alcoa property adjacent to and west of the liquefaction facility 

site, two public supply wells are located southwest of the existing LNG terminal across the Industrial 

Canal, and one public supply well is located east of the liquefaction facility. Additionally, the contractor 

yard and Kinder Morgan–Lake Charles Meter Station are each located within two public supply wellhead 

protection areas, and the Longville Compressor Station is within the limits of one additional public supply 

wellhead protection area (LDEQ, 2013a).

Based on review of USGS quadrangles, field surveys, the LDNR’s Strategic Online Natural 

Resources Information System (SONRIS) database (2014), and correspondence with the LDEQ, Lake 

Charles LNG and Trunkline identified seven active private water wells and one public supply well within 

150 feet of the Lake Charles Liquefaction Project (see table 4.3.1-1). 

TABLE 4.3.1-1

Water Wells Within 150 Feet of the Lake Charles Liquefaction Project

Water Well Number Use Facility Distance and Direction

019-5305Z Domestic Liquefaction facility Within footprint

019-12170Z Domestic Liquefaction facility 93 feet east

019-5596Z Domestic Liquefaction facility 116 feet west

019-14640Z Domestic ACW Area B Within footprint

019-715 Domestic ACW Area C Within footprint

019-7665Z Domestic ACW Area D 86 feet northeast

019-656 Domestic Contractor yard 21 feet north

043-182 Rural Public Supply Pollock Compressor Station Within footprint

Lake Charles LNG proposes to install two new water wells within the liquefaction facility 

footprint to provide water needed for construction and operation of the facility. During operation, the 

wells would supply the combination freshwater/firewater tank that would be used for utility service water 

and process water. In addition, Trunkline proposes to install a new water well at the Compressor Station 

203-A site to provide water for non-potable activities. 
4-18

4.3.1.3 Contaminated Groundwater

The LDEQ runs an Aquifer Sampling and Assessment Program to monitor the quality of 

groundwater produced in Louisiana’s major freshwater aquifers. The program samples about 200 wells 

across 14 aquifers every 3 years and presents the results in a triennial report. Under the Federal Safe 

Drinking Water Act, the EPA has established the Primary Maximum Contaminant Level (MCL) for 

pollutants that may pose a health risk in public drinking water. A Primary MCL is the highest level of a 

contaminant that the EPA allows in public drinking water. Secondary MCLs have also been set by the 

EPA, but are defined as non-enforceable guidelines for taste, odor, or appearance (LDEQ, 2009a, 2009b). 

The Chicot aquifer was shown to produce hard, but good quality water. There were no wells 

sampled by the LDEQ in 2008 that exceed the Primary MCL of any of the 90 contaminants regulated by 

the EPA. However, there were 4 wells that exceeded the Secondary MCL for pH, 3 wells for chloride, 

3 wells for color, 5 wells for total dissolved solids, and 17 wells for iron. Over the past 12 years, the 

Chicot aquifer has shown an average increase in six analytical parameters: pH, alkalinity, chloride, 

hardness, barium, and iron. The aquifer has exhibited an average decrease in temperature, total 

phosphorus, and nitrogen. The LDEQ currently does not recommend any course of corrective action, but 

rather to continue scheduled monitoring (LDEQ, 2009a). 

The Mississippi River Alluvial aquifer was found to be a source of very hard water. The Primary 

MCL for arsenic was exceeded in 6 of 23 wells sampled. The data also shows that the aquifer is of poor 

quality with 33 Secondary MCLs exceeded in 19 wells, including pH, chloride, sulfate, color, total 

dissolved solids, and iron. Over the past 12 years, pH, temperature, specific conductance, salinity, 

sulfate, hardness, and iron have increased in the Mississippi River Alluvial aquifer. Chloride, color, total 

dissolved solids, ammonia, nitrogen, barium, copper, zinc, and total phosphorus have decreased on 

average across the aquifer. The LDEQ provides owners of wells with Primary MCL violations with 

information about the compound, its health effects, and possible treatment methods (LDEQ, 2009b). 

4.3.1.4 Groundwater Impacts and Mitigation

The installation of piles for the liquefaction facilities, which are anticipated to be driven to a 

depth of 70 feet, is not expected to have direct impacts on the underlying aquifer, which is about 200 feet 

below the surface. Other construction activities are not likely to significantly affect groundwater 

resources because the majority of construction would involve shallow, temporary, and localized 

excavation. However, shallow aquifers could sustain minor, indirect impacts from changes in overland 

water flow and recharge caused by clearing and grading of the proposed work areas. In addition, nearsurface soil compaction caused by heavy construction vehicles could reduce the soil’s ability to absorb 

water in these areas. Lake Charles LNG and Trunkline would use specialized construction techniques 

such as sheet piling and earthen berms to control surficial water flow and infiltration. During 

construction, local water table elevations could be affected by trenching and backfilling. In areas where 

groundwater is near the surface, trench excavation may intersect the water table in low-lying areas. Lake 

Charles LNG and Trunkline would use well pointing, which consists of closely spaced small-diameter 

shallow wells to temporarily lower the water table in the immediate area, and/or pit-to-pit dewatering 

techniques to reduce impacts on groundwater in these circumstances. These minor, direct, and indirect 

impacts would be temporary and would not significantly affect groundwater resources. Lake Charles 

LNG and Trunkline would further minimize or avoid potential impacts on groundwater by implementing 

measures outlined in the FERC Plan and Procedures (e.g., temporary and permanent trench plugs and 

interceptor dikes). After installation of the proposed facilities, the ground surface in areas that would not 

be paved or graveled for aboveground facilities would be restored as closely as practicable to original 

contours and any exposed soils would be revegetated to ensure restoration of preconstruction overland 
4-19

flow and recharge patterns except within the ACWs. As noted previously, Lake Charles LNG anticipates

that the ACWs would be graveled or converted to vegetated surfaces based on landowner agreements. 

Unconfined aquifers and shallow groundwater areas could be vulnerable to contamination caused 

by inadvertent surface spills of hazardous materials used during construction. Accidental spills and leaks 

of hazardous materials associated with equipment trailers; the refueling or maintenance of vehicles; and 

the storage of fuel, oil, and other fluids pose the greatest risk to groundwater resources. If not cleaned up, 

contaminated soil could continue to leach and contaminate groundwater after a spill has occurred. 

Implementation of Lake Charles LNG’s and Trunkline’s SPAR and SPCC Plans would minimize the 

potential for groundwater impacts associated with an inadvertent spill of hazardous materials (see section 

4.2.3). In addition, these plans address the storage and transfer of hazardous materials and petroleum 

products. Therefore, we conclude that the potential for the Lake Charles Liquefaction Project to 

contaminate local aquifers or water supply wells would be minimal. 

Water required for construction and operation of the existing LNG terminal modifications and 

liquefaction facility would be provided from the two existing and two new on-site wells. Uses include 

hydrostatic testing of new piping systems, construction personnel sanitation, and other general utility 

uses. Lake Charles LNG estimates that about 45 million gallons of water would be withdrawn from the 

Chicot aquifer during construction. Typical flow rates would be 56 gallons per minute (gpm), with peak 

consumption of about 166 gpm. These withdrawal rates would be negligible relative to the more than 

10 million gpm that are currently withdrawn from the Chicot aquifer (DOTD and USGS, 2011). At the 

liquefaction facility, potable water during construction would be provided from the City of Lake Charles 

Department of Public Works for on-site concrete production, hydrostatic testing, and personnel 

consumption. The city obtains water from 17 wells that are drilled in the 500-foot and 700-foot sands of 

the Chicot aquifer. The wells supply residents with about 12 million gallons of water each day. Lake 

Charles LNG has received approval from the city for the use of about 20 million gallons of municipal 

water, which would be used at an average flow rate of 24 gpm, with a peak flow of 60 gpm. 

Water used during construction of the Non-Liquefaction Facilities would be obtained from 

municipal and surface water sources as discussed further in section 4.3.2.2. Non-potable water required 

at Compressor Station 203-A would be obtained from the new well to be installed on site. Trunkline

would not require any potable water sources at Compressor Station 203-A or the other non-liquefaction 

facilities.

Operational uses of water for the completed liquefaction facility would be supplied from the local 

municipal system and from the two new wells on the liquefaction facility property. These wells would be 

equipped with pumps capable of extracting 3,000 gpm to fill a tank that would be used for freshwater and 

for the plant’s fire suppression system. The average water consumption for plant operations would be 

14,400 gallons per day for potable water to serve the 247 on-site employees, 95,040 gallons per day for 

utility/service water, and 48,960 gallons per day for plant process water. Lake Charles LNG has

committed to coordinating with the city and other developers as needed to ensure that the local systems 

can provide an adequate supply of water. 

Lake Charles LNG and Trunkline have stated that they would continue to coordinate with the 

LDEQ and local agencies to ensure that construction and operation of the project facilities within the 

eight wellhead protection areas would be consistent with the applicable regulations.
4-20

Lake Charles LNG and Trunkline would conduct pre- and post-construction monitoring of well 

yield and water quality for all water supply wells located within 150 feet of construction activities. If the 

project results in adverse impacts, Lake Charles LNG or Trunkline would provide a temporary source of 

water to those affected and repair or replace the affected water wells. To document any project impacts 

on water wells and verify that they are appropriately addressed, we recommend that:

 Within 30 days of placing facilities in service, Lake Charles LNG and Trunkline

should file with the Secretary a report identifying all public or private water supply 

wells/systems damaged by construction and how they were repaired. The report 

should also include a discussion of any other complaints concerning well yield or 

water quality and how each problem was resolved.

4.3.2 Surface Water

4.3.2.1 Existing Surface Water Resources

Liquefaction Facility and LNG Terminal

The liquefaction facility would be located immediately north of the existing LNG terminal, 

adjacent to the Industrial Canal/Turning Basin, which discharges into Calcasieu Lake via the Calcasieu 

River (see figure 4.3.2-1). In addition to the Calcasieu River, numerous bayous, smaller rivers, and the 

surrounding marshlands discharge freshwater into Calcasieu Lake. Other sources of freshwater in the 

estuary system include streams and stormwater runoff; municipal, industrial, and agricultural return flow; 

and direct precipitation. Tidal exchange between the Gulf of Mexico and Calcasieu Lake occurs through 

the Calcasieu Ship Channel, which has been extensively modified for navigation purposes (e.g., the 

channel is generally maintained at a depth of 40 feet) (COE, 2015). 

The Industrial Canal/Turning Basin, located adjacent to the existing LNG terminal, has been 

designated as EFH, which is described in section 4.6.3. The Industrial Canal/Turning Basin has also been 

designated as a Navigable Waterway under section 10 of the Rivers and Harbors Act.

In addition to the Industrial Canal/Turning Basin, 15 unnamed waterbodies are present within the 

liquefaction facility site. These include 1 pond, 1 perennial waterbody, 2 intermittent waterbodies, and 

11 roadside drainages (see table 4.3.2-1). None of the waterbodies affected by the liquefaction facility are 

listed as Wild and Scenic Rivers, or contain federally or state-listed species. Designated uses of the 

Industrial Canal/Turning Basin, pond, perennial waterbody, and intermittent waterbodies include primary 

contact recreation, secondary contact recreation, propagation of fish and wildlife, and agriculture (LDEQ, 

2013c). However, because the Industrial Canal (located within LDEQ subsegment LA031101) does not 

support its designated use for primary contact recreation or fish and wildlife propagation, it is included on 

the State of Louisiana’s 2012 CWA §303(d) List of Impaired Waters (303(d) list) (LDEQ, 2013c). The 

causes of impairment include chloride, sulfates, total dissolved solids, and water temperature due to 

changes in tidal circulation/flushing, drought-related impacts, and impacts from hydrostructure flow 

regulation or modification. None of the other waterbodies that would be affected at the liquefaction 

facility site are included on the 303(d) list. Drainages do not have a state-designated uses. A full list of 

waterbodies affected by the project, including waterbody name, type, classification, crossing width, and 

crossing method is provided in appendix F.
4-21

Insert figure 4.3.2-1 Waterways in the Vicinity of the Liquefaction Facility
4-22

Non-Liquefaction Facilities

A total of 104 waterbodies, including 16 perennial, 12 intermittent, 8 ephemeral, 4 open water 

(pond), and 64 agricultural ditches and canals would be crossed or otherwise affected (e.g., matted) by 

construction of the Non-Liquefaction Facilities (see table 4.3.2-1). The agricultural drainages do not have 

state-designated uses. Designated uses of the remaining waterbodies include primary and secondary 

contact recreation, propagation of fish and wildlife, and agriculture. 

TABLE 4.3.2-1

Surface Waters Affected by the Lake Charles Liquefaction Project

Project Component Open Water Perennial Intermittent Ephemeral

Agricultural 

Ditches 

and Canals Total

LIQUEFACTION FACILITY AND LNG TERMINAL

LNG terminal 1 0 0 0 0 1

Liquefaction facility 1 1 2 0 11 15

SUBTOTAL 2 1 2 0 11 16

NON-LIQUEFACTION FACILITIES

Pipelines

Mainline Connector 4 7 9 7 29 56

Mainline 200-3 Loop 0 5 1 0 29 35

Mainline 200-1 modifications, 

Calcasieu River HDD

0 4 0 1 0 5

Aboveground Facilities

Compressor Station 203-A 0 0 1 0 4 5

Columbia Gulf–Egan Meter Station 0 0 1 0 2 3

SUBTOTAL 4 16 12 8 64 104

PROJECT TOTAL 6 17 14 8 75 120

At the proposed crossing location, the Calcasieu River is also designated as an Outstanding 

Natural Resource Water by the LDEQ, as a Louisiana Natural and Scenic River by the LDWF, and as a 

Navigable Waterway under section 10 of the Rivers and Harbors Act (LDEQ, 2013b; LDWF, 2012; COE, 

2013a). However, this segment of the river (located within LDEQ subsegment LA030201) is listed on 

the 303(d) list because it is not supporting its designated uses for primary contact recreation, fish and 

wildlife propagation, and Outstanding Nature Resource. Causes of impairment include chloride, lead, 

sulfates, total dissolved solids, turbidity, and fecal coliform due to drought-related impacts, agricultural 

activities, and runoff (LDEQ, 2013c). 

East Bayou Lacassine (MP 176.5 of Mainline 200-3 Loop, within LDEQ subsegment LA050601) 

is also included on the 303(d) list because it does not meet its designated use for fish and wildlife 

propagation. This waterbody is listed as impaired for chloride, sulfate, and total dissolved solids due to 

drought-related impacts and agricultural activities (LDEQ, 2013c). 

The Kinder Morgan–Lake Charles Meter Station in Calcasieu Parish and NGPL–Lakeside Meter 

Station in Cameron Parish are located within the 2012 Louisiana Coastal Zone (Louisiana Regular 

Session 49:214.24); however, no waterbodies occur within either meter station site (see additional 
4-23

discussion in section 4.8.7). None of the waterbodies impacted by the Non-Liquefaction Facilities are 

listed as National Wild and Scenic Rivers, designated as EFH, or contain federally or state-listed species.

4.3.2.2 Surface Water Impacts and Mitigation

Liquefaction Facility and LNG Terminal

Table 4.3.2-1 summarizes the surface waters that would be affected as a result of construction and 

operation of the liquefaction facility. Potential impacts on surface waters due to construction activities at 

the existing LNG terminal would occur within the Industrial Canal/Turning Basin and would be 

associated with the TCDs and berth modifications (i.e., dredging, pile installation, spills or leaks of 

hazardous materials, and removal of the TCDs) and vessel traffic (i.e., barge traffic and ballast water 

discharge). Potential impacts on surface waters at the liquefaction facility site include waterbody 

modification/fill, increased stormwater runoff, and spills or leaks of hazardous materials. The following 

sections describe these potential impacts as well as measures proposed by Lake Charles LNG to minimize 

impacts on surface waters.

LNG Terminal

Temporary Construction Docks and Berthing Dock Modifications

Construction of the two TCDs would require dredging a 22.1-acre area in the Industrial 

Canal/Turning Basin, driving sheet piles, and installing the TCD surface features. Modification of the 

existing berthing docks would include installation of berthing structures (e.g., addition of mooring 

dolphins, installation of larger vapor return arms from each dock to the LNG storage tanks).

The primary impacts on water quality resulting from these activities would be associated with 

dredging. As described in additional detail in section 2.6.1, about 26,000 cubic yards of material would 

be dredged from within the Industrial Canal/Turning Basin. Dredging activities would occur over a 

30-day period. Dredged material would be hydraulically pumped through a 0.5-mile-long temporary, 

aboveground dredge pipe into Lake Charles LNG’s existing dredged material disposal area located 

immediately east of ACW Area B. Once placed into the disposal area, dredged materials would be 

allowed to dewater through a conventional weir system that would return the decanted water back to the 

Industrial Canal/Turning Basin in accordance with LDEQ and EPA requirements.

Impacts on water quality resulting from dredging include temporary increases in suspended 

sediment and turbidity levels as well as potential resuspension of contaminated sediments. The COE and 

Lake Charles Harbor and Terminal District partner to conduct maintenance dredging within the Industrial 

Canal/Turning Basin; in order to maintain deep draft access, dredging is expected to occur every other 

year (COE, 2015). This routine dredging, combined with existing vessel traffic associated with operation 

of existing facilities, causes sustained high and variable turbidity levels within the Industrial 

Canal/Turning Basin. Lake Charles LNG proposes to conduct dredging activities using a hydraulic 

dredge with a suction cutter head. This dredging method minimizes turbidity from resuspension of the 

sediment in the water column and other water quality impacts. Additionally, any effects would be minor 

because they would be temporary (i.e., confined to the period of dredging activity and shortly thereafter) 

and limited to the area within and immediately around the Industrial Canal/Turning Basin. During 

dredging and other in-water activities, Lake Charles LNG would routinely measure water quality and 

would implement additional measures, such as the use of silt curtains, as needed to comply with 

applicable permit conditions. 
4-24

Lake Charles LNG stated that information in recent sampling plans conducted by Tetra Tech, Inc. 

on behalf of Alcoa indicated that sediments within the Industrial Canal/Turning Basin contain 

contaminants, but that the underlying clay is not impacted. Lake Charles LNG also stated that a surface 

water and sediment sampling study was being conducted within the Industrial Canal/Turning Basin; 

however, the study results were not yet available at the time we prepared the draft EIS. In order to better 

identify potential impacts and appropriate mitigation measures associated with the disturbance of 

contaminated sediments, we recommended in the draft EIS that Lake Charles LNG file the results of the 

contaminated sediment sampling study for the Industrial Canal/Turning Basin, as well as an interpretation 

of the results, prior to the end of the draft EIS comment period. 

In its May 14, 2015 response to this recommendation, Lake Charles LNG did not provide the 

results of the sampling study, but stated that sediments in the Industrial Canal/Turning basin have been 

evaluated by Reynolds Metals (Reynolds) for the presence of contaminants of concern associated with 

historical operations of Reynolds’ Lake Charles Carbon Company (owned by Alcoa). Sediment samples 

were collected and analyzed in accordance with the LDEQ Risk/Evaluation/Corrective Action Program 

(RECAP). Affected sediments were fully delineated and areas exhibiting concentrations of PCBs and 

PAHs above RECAP Corrective Action Standards were established. Lake Charles LNG explained that 

Reynolds has decided to dredge, transport, and dispose of affected sediment at certain locations where 

contaminants of concern were identified above LDEQ established action levels, and provided a copy of 

part of a dredging work plan developed by POWER Engineers Inc., which was submitted to the LDEQ on 

behalf of Reynolds in January 2015. The work plan was approved by the LDEQ in February 2015. 

According to the work plan, the LDEQ issued an Administrative Order in 2005 that identified areas of 

concern at the Lake Charles Carbon Company, including sediments within the Industrial Canal/Turning 

Basin. The work plan states that Reynolds is undertaking an Interim Measure action under the 

Administrative Order to remove selected affected sediments from areas that could be affected by the

project. The work plan identifies the applicable permits to be obtained by Reynolds, provides the 

dredging locations and estimated volumes, and describes the steps and sequence of the Interim Measure 

dredging operation from mobilization and site preparation through disposal of the affected material 

(including water quality monitoring and water quality best management practices). Lake Charles LNG 

reported that removal of the affected sediment was initiated on March 25, 2015 and is anticipated to be 

completed prior to any Lake Charles LNG Industrial Canal/Turning Basin construction activities. 

Due to Reynolds’ implementation of the LDEQ-approved work plan, contaminated sediments that 

might otherwise have been disturbed during project activities will be removed by the time construction of 

the proposed project begins. Therefore, the potential for adverse impacts on water quality during Lake 

Charles LNG’s in-water work is significantly reduced. Additionally, Lake Charles LNG has applied for 

authorization from the COE New Orleans District under section 404 of the CWA and section 10 of the 

Rivers and Harbors Act to dredge and/or fill waters of the United States (see discussion in section 4.4). 

Lake Charles LNG would be required to implement the measures incorporated into the COE permit, 

including any special requirements/procedures for handling contaminated sediments (e.g., silt curtains or 

other in-water controls that may be included as conditions of the permit), if such measures remain 

necessary. 

Construction of the two TCDs and modification of the existing berths would result in localized, 

temporary increases in turbidity and suspended sediment levels. A combination of conventional in-water 

marine construction equipment (e.g., barges, cranes, pile driving equipment) and shore-based construction 

equipment (e.g., backhoes, bulldozers) would be used to install steel sheet pilings, backfill the TCD 

footprint with structural fill, and install over-water structures. Removal of the TCDs following the 5-year 

construction period would be accomplished primarily using shore-based equipment. To minimize 

impacts on water quality, excavation of backfill material and removal of the anchor system would occur 

prior to the steel sheet piles being extracted. The shoreline would be restored to approximately the 
4-25

preconstruction grade and shoreline protection would be reinstalled, if needed. Therefore, the activities 

associated with the TCDs and berthing dock modifications would result in temporary and minor increases 

in turbidity and sediment levels in the immediate vicinity of construction activities, but no permanent or 

long-term water quality impacts. 

Spills, leaks, or other releases of hazardous materials during in- or over-water construction 

activities could adversely impact water quality. To protect surface water resources from inadvertent 

releases of fuel and other mechanical fluids, Lake Charles LNG would implement its SPAR and SPCC 

Plans (see section 4.2.3 for further discussion of these plans). Furthermore, Lake Charles LNG would 

enforce refueling restrictions, hazardous material storage, and equipment parking restrictions within 

100 feet of surface waters in accordance with our Procedures. With the implementation of the projectspecific spill plans and our Procedures, the expected impacts on water quality in the event of a spill or 

leak would be minor. 

Vessel Traffic

Throughout construction of the project, barges and support vessels would deliver large equipment 

and materials to the TCDs. Lake Charles LNG anticipates an average of five barge deliveries per day and 

less than one bulk carrier per week over the 5-year construction period. This traffic may increase 

shoreline erosion and resuspension of bottom sediments, resulting in temporary increases in turbidity 

levels within the Industrial Canal/Turning Basin and along vessel transit routes. The Calcasieu Ship 

Channel was specifically created to provide deepwater access for maritime commerce. It is managed by 

the Port of Lake Charles, a deepwater seaport, and is maintained by regular dredging (Port of Lake 

Charles, 2014). As such, use of the channel by barges and support vessels to deliver materials during 

construction of the liquefaction facility would be consistent with the planned purpose and use of this

active shipping channel, and associated impacts on water quality within the channel would be minor. 

Lake Charles LNG is not proposing to change the frequency or size of LNG carriers, and the 

impacts associated with the transit of these vessels to and from the terminal during operation of the 

project would not change. However, operation of the LNG terminal as an export facility rather than an 

import facility would require that LNG carriers discharge ballast water (for LNG loading) rather than take 

on ballast water (for offloading of LNG). Therefore, an analysis of potential impacts on water quality due 

to ballast water discharge is included below.

During operation of the project, up to 225 LNG carriers would call on the LNG terminal per year, 

each of which could discharge up to 16,907,250 gallons of water (depending on LNG carrier size) into the 

Industrial Canal/Turning Basin during LNG loading. As required by Coast Guard regulations (33 CFR 

151.2026), vessels equipped with ballast tanks must implement one of five options to control the 

introduction of nonindigenous species into waters of the United States. The International Maritime 

Organization has adopted this regulation, which requires each vessel to install and operate a ballast water 

management system (option 1 as currently defined). Compliance dates associated with this International 

Maritime Organization requirement will be phased, but will apply to all vessels beginning in 2016.

1

 Until 

this rule is fully implemented, Lake Charles LNG has stated that it would require LNG carriers to conduct 

a complete ballast water exchange at least 200 nautical miles from any shoreline (option 4 as currently 

defined), except in extraordinary circumstances causing safety or stability concerns that would require a

ballast exchange closer to the shoreline, which is authorized under 33 CFR 151.2040. Therefore, ballast 

water discharged into the Industrial Canal/Turning Basin would be composed of open ocean water, and 

 

1 This regulation (33 CFR 151.2026) currently applies to all new vessels as well as existing vessels with ballast water capacity 

between 1,500 and 5,000 m

3

 that have been drydocked since January 1, 2014. Compliance by existing vessels with ballast 

water capacity less than 1,500 m

3

or greater than 5,000 m

3 will be required as of the vessel’s first scheduled drydocking after 

January 1, 2016.
4-26

potential impacts on water quality would include changes in temperature, pH, dissolved oxygen, and 

salinity levels.

Depending on hydrologic conditions at the time of discharge, the physio-chemical composition of 

ballast water may be very similar to or different from the ambient water within the Industrial

Canal/Turning Basin. The primary potential impact on water quality due to ballast water discharge would 

be a temporary increase in salinity level. Because the Industrial Canal/Turning Basin is located within the 

Calcasieu River estuary (about 23 miles north of the Gulf of Mexico), these differences may not be 

measurable under normal tidal cycles. However, during periods of heavy rainfall, salinity levels may 

decrease in the Industrial Canal/Turning Basin. Ballast water would be discharged near the bottom of the 

marine berth where relatively dense saltwater from the Gulf of Mexico characteristically underlies 

freshwater from inland sources. Furthermore, the amount of ballast water discharged into the Industrial 

Canal/Turning Basin during each LNG carrier visit to the LNG terminal would represent a very minor 

influence on the overall system.

Another physio-chemical water quality parameter that may be influenced by ballast water 

discharges is dissolved oxygen level. As described above, ballast water would be discharged near the 

bottom of the marine berth and may contain lower levels of dissolved oxygen than the surrounding water. 

The LDWF collected water quality data from the top, middle, and bottom of the water column from July 

2013 through February 2014 at two stations within the Industrial Canal/Turning Basin (entrance and 

Turning Basin). Throughout the study period, dissolved oxygen levels near the bottom of the Turning 

Basin ranged from less than 0.1 to 8.7 milligrams per liter (LDWF, 2014a). Because oxygen levels are 

already suppressed, impacts on dissolved oxygen levels in the area would be minor. 

Ballast water is stored in the ship’s hull below the waterline; as a result, discharged water 

temperatures are not expected to deviate significantly from ambient water temperatures. The pH of the 

ballast water (reflective of sea water in open ocean conditions) is maintained in a fairly narrow range (8.1 

to 8.5), which can be substantially higher than water within estuaries (Knezovich, 1994). Water quality 

data collected by the LDWF from July 2013 through February 2014 documented pH within the Industrial 

Canal/Turning Basin ranging from 7.1 to 8.6 (LDWF, 2014a). Lake Charles LNG reports that 

background samples taken at 15 sites within the Turning Basin in March 2014 obtained pH readings 

ranging from 6.7 to 8.1. Although pH within the Industrial Canal/Turning Basin is generally lower than 

seawater, it varies over space and time. Due to discharged ballast water representing a relatively minor 

volume compared to the volume of the Industrial Canal/Turning Basin, this impact is expected to be 

temporary and minor.

To ensure compliance with U.S. laws and regulations governing ballast water discharges, Lake 

Charles LNG’s marine staff would review any applicable documentation that the visiting ship is or has 

operating(ed) the LNG carrier in accordance with the federal standards and practices. Therefore, we 

conclude that significant impacts on surface waters would not occur as a result of ballast water discharge.

Liquefaction Facility

Modification and Fill of Surface Waters

During site preparation activities at the liquefaction facility, the pond and two intermittent 

waterbodies within the site would be filled. The 11 roadside drainages would be filled, replaced, and/or 

realigned to accommodate the drainage system at the liquefaction facility. The perennial waterbody (an 

unnamed tributary to the Calcasieu River) present along the southern boundary of the liquefaction facility 

site would be armored and redirected as part of the facility’s stormwater system improvements, as 

discussed in additional detail below (see Stormwater Runoff). Impacts on these surface waters would be 
4-27

mitigated through implementation of Lake Charles LNG and Trunkline’s final Compensatory Mitigation 

Plan (see discussion in section 4.4.4).

About 84 million gallons of water would be used for dust control and as a soil additive during site 

preparation, if needed due to dry soil conditions at the time of construction. Water would be appropriated 

from two existing ponds adjacent to ACW Area B and from an existing drainage ditch within the 

liquefaction facility site. The smaller of the two ponds is located adjacent to, and southeast of ACW Area 

B. Appropriation of water from this pond during construction would result in a temporary reduction in 

water depth until replenished by rainfall or groundwater recharge, but is not likely to result in significant 

impacts on surface water quality. The pond located adjacent to and east of ACW Area B is an existing, 

COE-permitted dredged material disposal area that Lake Charles LNG proposes to use for dredged 

material placement associated with construction of the TCDs. As described above, the drainage ditch 

would be permanently modified as a result of the project. Therefore, we conclude that impacts on surface 

waters due to temporary water appropriation for these activities would not be significant.

Stormwater Runoff

During construction, land disturbance and vegetation removal could increase stormwater 

discharges to surface waters at and adjacent to the liquefaction facility, resulting in a temporary increase 

in suspended sediment levels. Land disturbing activities would be conducted in compliance with the 

Louisiana Pollutant Discharge Elimination System (LPDES), General Permit for stormwater discharges 

from construction activities 5 acres or more; the project-specific SWPPP (as required under the CWA). 

Lake Charles LNG anticipates that best management practices would include (but not be limited to) 

properly functioning and maintained erosion control devices, the use of contours to control and direct 

stormwater flow during clearing and grading, and the use of dissipation and filtering devices (e.g., 

vegetation, hay bales) to ensure that water quality criteria are met.

Operation of the liquefaction facility would increase the amount of impervious surface area at the 

site, which would result in an increased volume of stormwater runoff. Lake Charles LNG would amend 

the existing operational SWPPP for the LNG terminal to include the operation of the liquefaction facility. 

Stormwater would be managed in accordance with LDEQ and EPA requirements. Therefore, we 

conclude that impacts from stormwater runoff would not be significant. 

Spills or Leaks of Hazardous Materials

Spills, leaks, or other releases of hazardous materials during construction and operation of the 

liquefaction facility could adversely impact water quality. To protect surface water resources from 

inadvertent releases of fuel and other mechanical fluids, Lake Charles LNG would implement its SPAR 

and SPCC Plans and the measures specified in our Procedures (see section 4.3.2). With the 

implementation of these plans, impacts on water quality in the event of a spill or leak are expected to be 

minor.

Non-Liquefaction Facilities

The surface waters that would be impacted during construction and operation of the NonLiquefaction Facilities are summarized in table 4.3.2-1 and listed in appendix F. Potential impacts on 

these surface waters during construction and operation of the project are described in the following 

sections. 
4-28

Pipelines

Trunkline would use the open-cut method at 46 waterbody crossings along the Mainline 

Connector and at 25 waterbody crossings associated with the Mainline 200-3 Loop (see appendix F). The 

open-cut method of construction would involve clearing and grading stream banks, in-water trenching, 

trench dewatering, and backfilling. These activities could increase sedimentation, turbidity, and water 

temperature; decrease dissolved oxygen levels; and release chemical or nutrient pollutants from 

sediments. The primary impact on water quality due to in-stream trenching and backfilling would be 

suspension of sediments. The extent of the impact would depend on sediment loads, stream velocity, and 

sediment particle size at the time of construction. These factors would determine the density, downstream 

extent, and persistence of the sediment plume. As discussed in additional detail in section 4.6.2.2, 

impacts on the in-stream aquatic biota and the habitat value of the waterbody would be temporary. 

Through the transport of sediment and recruitment of aquatic biota from upstream sources, these 

resources would be expected to return to preconstruction conditions soon after the completion of instream work, backfilling, and restoration.

To minimize surface water impacts, Trunkline would implement the construction and mitigation 

measures described in our Procedures. Adherence to our Procedures would minimize short- and longterm impacts associated with these waterbody crossings.

Trunkline proposes to conduct six HDD operations. As some of the HDDs would encompass 

more than one waterbody, a total of 22 waterbodies would be crossed using the HDD method. Of these, 

10 crossings would be associated with construction of the Mainline Connector, 10 crossings would be 

associated with construction of the Mainline 200-3 Loop, and 2 crossings would be associated with the 

Mainline 200-1 modifications, where the portion of the pipeline crossing the Calcasieu River would be 

replaced (see additional discussion on the proposed Calcasieu River crossing below). Proposed HDD 

crossings are listed in table 4.3.2-2.

Trunkline provided site-specific plan and profile drawings for the proposed HDD crossings with 

its application; however, some of the HDD crossing designs were subsequently modified to reduce 

impacts on wetlands. Therefore, we recommend that:

 Prior to construction, Trunkline should file with the Secretary copies of the final 

HDD plan and profile drawings for review and written approval by the Director of 

OEP.

The HDD method involves the circulation of a drilling mud to remove cuttings, stabilize the 

borehole, and cool and lubricate the drill bit (see detailed description in section 2.6.3.3). Drilling mud is 

composed primarily of freshwater, bentonite clay, and a small percentage of other additives. Trunkline 

proposes to utilize both municipal and surface water sources for HDD operations; surface water sources, 

volume requirements, and intake and discharge locations are described in table 4.3.2-3. Trunkline would 

be required to obtain authorization from the LDWF for the proposed surface water withdrawal from the 

Calcasieu River because it is a state-designated Natural and Scenic River (see table 1.5-1).
4-29

TABLE 4.3.2-2

Waterbodies Proposed to be Crossed Using the Horizontal Directional Drill Method

Directional Drill 

Number

Drill Entry 

Milepost

Drill Exit 

Milepost

Length of Drill 

(feet)a Waterbodies Crossed (Feature ID number)

Mainline Connector

1 1.8 1.1 1,675 Unnamed Tributary to Arceneaux Bayou (S-T-115)

Arceneaux Bayou (S-T-117)

Unnamed Tributary to Arceneaux Bayou (S-B-139)

2 6.2 5.7 2,683 Unnamed Tributary to Little Bayou (S-B-119)

Little Bayou (S-B-109)

Unnamed Tributary to Little Bayou (S-B-108B)

Unnamed Tributary to Little Bayou (S-B-106)

Unnamed Tributary to Little Bayou (S-B-105)

3 9.7 9.1 1,756 Unnamed drainage (D-C-201)

Serpent Bayou (S-T-110)

Mainline 200-3 Loop

1 176.0 177.1 5,691 East Bayou Lacassine (S-A-100)

Unnamed drainage (D-T-120)

Unnamed drainage (D-T-119)

Unnamed drainage (D-T-118)

2 178.8 178.3 2,594 Unnamed drainage (D-B-100)

Unnamed drainage (D-T-116)

Unnamed drainage (D-C-117)

Indian Bayou Canal (S-C-116)

Unnamed drainage (D-T-114)

Unnamed drainage (D-T-113)

Mainline 200-1 Modifications

1 194.8 195.8 5,477 Calcasieu River (NHD-1)

Unnamed waterbody (WB-B-CA-621)

____________________

a

Length of drill obtained from the site-specific crossing plans filed by Trunkline. 

TABLE 4.3.2-3

Surface Water Requirements Associated with Proposed HDD Operations

Directional Drill Number Intake Milepost Discharge Milepost Volume Required (gallons)

Mainline Connector

Arceneaux Bayou 1.2 1.0 1,399,000

Little Bayou 5.9 5.7 2,225,000

Bayou Serpent 9.5 9.2 1,478,000

Mainline 200-3 Loopa

Lacassine Bayou 176.5 177.2 1,921,000

Mainline 200-1 Modifications

Calcasieu Riverb194.8 Not applicablec2,065,000

____________________

a

Trunkline proposes to use 877,000 gallons of municipal water for HDD operations at Indian Bayou.

b

Trunkline proposes to use water from the Calcasieu River; however, municipal water would be utilized in the event that 

appropriation from the Calcasieu River is not authorized by the LDWF.

c

Trunkline indicates the water used for the Calcasieu River HDD operations would not be discharged as it would all be

used for drilling mud.
4-30

The use of the HDD method would eliminate or significantly reduce the potential for 

construction-related impacts on water quality because the HDD method avoids disturbance of the stream 

beds, banks, and associated riparian vegetation. There is potential during the drilling process for drilling 

mud to enter waterbodies through coarse unconsolidated formations, such as sand or gravel, or through 

fractured rock formations. Because drilling mud is composed of primarily freshwater, a small release 

would likely dissipate and would not be expected to adversely affect water quality beyond a temporary 

increase in turbidity. In larger quantities, the release of drilling mud could negatively affect fisheries 

and/or vegetation, although impacts would generally be less than those associated with an open-cut 

crossing. To minimize potential impacts on water quality in the event of an inadvertent release of drilling 

mud, Trunkline has prepared a preliminary HDD Contingency Plan that describes measures Trunkline

would implement during drilling activities as well as in the event of an inadvertent release of drilling mud 

to uplands or surface waters. Trunkline has stated that it would finalize the HDD Contingency Plan with 

the selected contractor and the final plan would be incorporated into construction compliance documents. 

Therefore, we recommend that:

 Prior to construction, Trunkline should file its final HDD Contingency Plan with the 

Secretary for review and written approval by the Director of OEP.

Calcasieu River Crossing

The proposed Mainline 200-1 modifications include replacing the existing segment of pipeline 

crossing the Calcasieu River (MP 195.6). Trunkline proposes to complete the approximately 5,477-footlong crossing, which would connect the existing Mainline 200-1 to the existing Mainline 200-3, using the 

HDD method. Due to the Calcasieu River’s designation at the crossing location as both a section 10 

waterbody and a Louisiana Natural and Scenic River (COE, 2013a; LDWF, 2012), Trunkline would be 

required to obtain authorization from the COE New Orleans District and the LDWF, respectively, to 

install the pipeline beneath this waterbody (see additional discussion in section 4.8.4.2). As described 

above, Trunkline would also be required to obtain authorization from the LDWF to appropriate water 

from the Calcasieu River at this location for HDD operations. 

Compressor Station 203-A

Construction of Compressor Station 203-A would require filling a man-made agricultural canal 

and the installation of piping beneath four drainage canals. Temporary impacts on water quality 

associated with the installation of piping would be similar to those described above and would be 

minimized through Trunkline’s implementation of our Procedures (see Pipelines subsection, above).

Columbia Gulf–Egan Meter Station

Three waterbodies are located within the Columbia Gulf–Egan Meter Station site, including an 

intermittent waterbody and two drainage canals. Trunkline would place mats over these features to 

minimize potential impacts during construction at the meter station site. The mats would be removed at 

the end of construction. Impacts on water quality within these waterbodies would be temporary and 

insignificant. 

Alternative Measures to FERC Procedures

Section V.B.2.A of our Procedures requires that extra work areas be located at least 50 feet away 

from water’s edge except where the adjacent upland consists of cultivated or rotated cropland or other 

disturbed land. Trunkline proposed a large ATWS that encompasses a waterbody that runs along its 

existing right-of-way on the southeast side of the Calcasieu River. Based on the initial design of this 

HDD crossing, the ATWS was required for the HDD exit point, stringing of the HDD pipeline segment, 

and for removal of a drip. However, other than indicating it would mat the waterbody, Trunkline did not 

provide sufficient justification for this proposed deviation or how it would minimize impacts on the 
4-31

waterbody. In order for us to consider Trunkline’s proposed deviation from the Procedures at this 

location, we recommended in the draft EIS that Trunkline provide a detailed description of the proposed 

ATWS affecting waterbody WB-B-CA-621, whether Trunkline could limit the workspace or shift it to 

avoid all or part of the waterbody, and how Trunkline would minimize unavoidable impacts on the 

waterbody. 

In its May 14, 2015 response to this recommendation, Trunkline stated that it had redesigned the 

Calcasieu River HDD to use an alternate alignment that would avoid crossing the existing Gulf South 

pipelines west of the river. The alternative alignment significantly reduces the size of the ATWS 

affecting waterbody WB-B-CA-621 and the associated impact. Additionally, the alternative alignment 

encompasses much of this waterbody within the HDD path. Trunkline further stated that the ATWS on 

either side of the Calcasieu River would be required to excavate and disconnect the existing pipeline 

segment to be abandoned and to complete the tie-ins to the 200-1 pipeline. In order to complete the tieins, Trunkline stated that construction personnel would be required to work inside the excavations, 

necessitating wider excavations (and the associated increased spoil) to meet OSHA regulations. With the 

redesigned HDD alignment and the additional information provided by Trunkline regarding the need for 

this ATWS, we find that the location of the ATWS within waterbody WB-B-CA-621 is reasonable and 

adequately justified. Additionally, Trunkline would be required to comply with the conditions of its COE 

permit.

Hydrostatic Testing

Pipeline segments installed using the HDD method would be hydrostatically tested before 

installation (known as an HDD pre-test) to ensure structural integrity per DOT standards (49 CFR Part 

192). Before being placed into service, the entire Mainline Connector, Mainline 200-3 Loop, and noncryogenic piping associated with the Non-Liquefaction Facilities would be hydrostatically tested. 

Trunkline proposes to use both municipal sources and surface waters for hydrostatic testing of the NonLiquefaction Facilities. Surface water requirements as well as proposed intake and discharge locations 

are described in table 4.3.2-4. As described above (see Pipelines), Trunkline would be required to obtain 

water use (withdrawal) permits from the LDWF prior to conducting surface water withdrawals. A 

detailed description of the hydrostatic test process is provided in section 2.6.2.7.

TABLE 4.3.2-4

Surface Water Requirements Associated with Hydrostatic Testing the Proposed Non-Liquefaction Facilities

Water Source

Intake

Milepost

Discharge 

Milepost

Volume Required

(gallons) Proposed Use

Mainline Connector

Arceneaux Bayou 1.2 1.0 125,000 HDD pre-test

Arceneaux Bayou 1.2 1.0 4,100,000 Mainline hydrostatic test

Little Bayou 5.9 5.7 190,000 HDD pre-test

Bayou Serpent 9.5 9.2 125,000 HDD pre-test

Mainline 200-3 Loopa

Laccassine Bayou 176.5 177.2 140,000 HDD pre-test

Laccassine Bayou 176.5 182.5 775,000 Mainline hydrostatic test

Mainline 200-1 Modifications

Calcasieu River 195.6 196.3 130,000 HDD pre-test

____________________

a

Trunkline proposes to use 60,000 gallons of municipal water for the HDD pre-test at Indian Bayou.

After the hydrostatic test is successfully completed, each pipeline segment would be de-watered 

by pushing the water out with air. Trunkline would not add any chemicals to the hydrostatic test water, 
4-32

and the discharged water would be tested in accordance with the requirements of the LPDES Hydrostatic 

Test Water Discharge Permit. In addition, Trunkline would implement the measures outlined in our 

Procedures, which include: notifying state agencies prior to testing; screening intakes to avoid 

entrainment of fish; maintaining adequate stream flow rates to protect aquatic life and provide for all 

waterbody uses and downstream withdrawals of water by existing users; locating hydrostatic test 

manifolds outside of wetlands and riparian areas to the maximum extent practicable; regulating discharge 

rates; using energy dissipation devices; and installing sediment barriers as necessary to prevent erosion, 

streambed scour, suspension of sediments, or excessive streamflow. With the implementation of these 

measures, impacts on water quality due to hydrostatic testing would be short term and insignificant.

Spills or Leaks of Hazardous Materials

Spills, leaks, or other releases of hazardous materials during construction and operation of the 

Non-Liquefaction Facilities could adversely impact water quality. To protect surface water resources 

from inadvertent releases of fuel and other mechanical fluids, Trunkline would implement its projectspecific SPAR and SPCC Plans and the measures specified in our Procedures. With the implementation 

of these plans and our Procedures, impacts on water quality in the event of a spill or leak are expected to 

be minor. 

Operation

Operation of Compressor Station 203-A and the Columbia Gulf–Egan Meter Station are not 

expected to affect surface water resources. Impacts on surface waters are not expected during operation 

of the proposed Mainline Connector, Mainline 200-3 Loop, or Mainline 200-1 crossing of the Calcasieu 

River because no further in-stream activities would be expected. Because the pipelines would be installed 

at a sufficient depth below the beds of waterbodies, exposure of the pipe is not anticipated. In the event 

that a pipeline anomaly (i.e., corrosion, dent, rupture) is detected during routine inspections that could 

require pipeline excavation or replacement within a waterbody, impacts would be similar to those 

described above for construction.

4.4 WETLANDS

Wetlands are areas that are inundated or saturated by surface or groundwater at a frequency and 

duration sufficient to support, and under normal circumstances do support, a prevalence of vegetation 

typically adapted for life in saturated soil conditions, commonly known as hydrophytic vegetation 

(Environmental Laboratory, 1987). Wetlands can be a source of substantial biodiversity and serve a 

variety of functions that include providing wildlife habitat, recreational opportunities, flood control, and 

naturally improving water quality.

At the federal level, wetlands are protected under section 404 of the CWA, which establishes 

standards to evaluate and reduce total and net impacts on wetlands under the jurisdiction of the COE. In 

general, wetland impacts need to be avoided if possible; if avoidance is not possible, impacts are to be 

minimized, rectified, reduced, and mitigated in accordance with federal and state regulations, including 

our Procedures and the COE’s section 404(b)1 guidelines, which restrict discharges of dredged or fill 

material where a less environmentally damaging and practicable alternative exists. COE jurisdictional 

wetlands potentially affected by the project are subject to review by the COE to ensure that wetland 

impacts are fully identified and that appropriate wetland restoration and mitigation measures are 

identified. The proposed project is located in two COE regulatory districts, the New Orleans District and 

the Vicksburg District. Lake Charles LNG and Trunkline have submitted applications to both COE 

Districts.

Wetland impacts authorized under section 404 of the CWA also require state water quality 

certification under section 401 of the CWA and a state-issued CUP for impacts on coastal wetlands, if 
4-33

applicable. For the proposed project, water quality certification would be issued by the LDEQ. The State 

of Louisiana defines coastal wetlands as wetlands less than 5 feet AMSL that occur within the designated 

coastal zone (Louisiana Revised Statute 49:214.2). Coastal wetlands are under the jurisdiction of the 

LDNR Office of Coastal Management and the COE. According to the revised June 7, 2012 Coastal Zone 

Inland Boundary, project components within the designated coastal zone include the Kinder Morgan–

Lake Charles Meter Station in Calcasieu Parish and the NGPL–Lakeside Meter Station in Cameron 

Parish. However, in a letter dated August 27, 2014, the LDNR Office of Coastal Management determined 

that a CUP would not be required for the proposed activities at these stations.

Field surveys did not identify any wetlands within portions of the project area in Mississippi and 

Arkansas. Therefore, neither water quality certifications nor CUPs would be required in Mississippi or 

Arkansas.

4.4.1 Affected Wetlands

Lake Charles LNG and Trunkline conducted wetland delineations in accordance with the COE’s 

Wetlands Delineation Manual (Environmental Laboratory, 1987). Wetland delineations were performed 

within the liquefaction facility site in September 2012 and within other project areas (ACWs and NonLiquefaction Facilities) from March through May 2013, from September 2013 through January 2014, in 

June 2014, and in July 2014. Wetland types identified within the project area were classified as either 

palustrine emergent, palustrine scrub-shrub, or palustrine forested wetlands (Cowardin et al., 1979). A 

full list of wetlands affected by the project, including wetland identification number, wetland type, and 

type and acreage of impact is provided in appendix G. 

Forested wetlands and forested wetland mosaics are the most common wetland type within the 

project area and occupy large areas associated with the liquefaction facility and ACWs. The forested 

wetland mosaics that occur within the proposed ACWs are composed of what are frequently called 

pimple-mound mosaics. These mosaics have complex topography that is distinguished by repeated small 

changes in elevation occurring over short distances. The tops of ridges and hummocks within these 

mosaics are often classified as uplands, but are interspersed with wetlands having hydrophytic vegetation, 

hydric soils, and wetland hydrology (COE, 2010). The dominant canopy species observed in the pimplemound mosaics include Chinese tallow (Sapium sebiferum), live oak (Quercus virginiana), water oak 

(Quercus nigra), black willow (Salix nigra), slash pine (Pinus elliotti), and loblolly pine (Pinus taeda). 

The sub-canopy layer consists of younger individuals of these species, as well as saltbush (Baccharis 

halimifolia), American beautyberry (Callicarpa americana), and yaupon (Ilex vomitoria). Vines are 

prolific and include saw greenbrier (Smilax bona-nox), yellow jessamine (Gelsemium sempervirens), 

grape vine (Vitis spp.), and Virginia creeper (Parthenocissus quinquefolia). In herbaceous portions of the 

mosaics, dominant species include narrow leaf cattail (Typha angustifolia), pickerelweed (Pontederia 

cordata), smartweed (Polygonum hydropiperoides), slender arrowhead (Sagittaria graminea), and 

wingleaf primrose-willow (Ludwigia decurrens).

Forested wetlands are also located along the proposed pipeline routes (Mainline Connector, 

Mainline 200-3 Loop, and Calcasieu River HDD associated with Mainline 200-1 modifications) and 

within other aboveground facility sites. Species observed during the field surveys of these wetlands 

include willow oak (Quercus phellos), American hornbeam (Carpinus caroliniana), red maple (Acer 

rubrum), Chinese tallow, southern bayberry (Myrica cerifera), Alabama supple-jack (Berchemia 

scandens) and Virginia dayflower (Commelina virginica).

Small- to medium-sized emergent and scrub-shrub wetlands also occur within the project area. 

Typical species observed in emergent wetlands during field surveys include Timothy canary grass 

(Phalaris angusta), beach false-foxglove (Agalinis fasciculata), little quaking grass (Briza minor), vasey 
4-34

grass (Paspalum urvillei), bushy bluestem (Andropogon glomeratus), soft rush (Juncus effusus), 

American marsh pennywort (Hydrocotyle americana), southern blueflag (Iris shrevei), bushy seedbox 

(Ludwigia alternifolia), curly dock (Rumex crispus), small spikerush (Eleocharis parvula), and broom 

panic grass (Dichanthelium scoparium). Species observed in scrub-shrub wetlands during field surveys 

include eastern false-willow (Baccharis halimifolia), Chinese tallow, small spikerush, southern bayberry, 

bushy bluestem, and soft rush. 

4.4.2 Wetland Impacts and Mitigation

4.4.2.1 Liquefaction Facility

Construction of the liquefaction facility would result in the permanent loss of 215.4 acres of 

wetlands, as shown in table 4.4.2-1. Of this total, 105.3 acres of wetlands are located within the proposed 

liquefaction facility site, and 110.1 acres are located within ACWs associated with the construction of the 

liquefaction facility. During site preparation activities, wetlands within the liquefaction facility site 

would be permanently filled and converted to upland industrial land. Wetlands within ACW Areas A, B, 

C, and D would be filled, elevated, and converted to industrial use for the 5-year construction period. 

Lake Charles LNG would not restore the wetlands within the ACWs following construction. The 

landowners have requested that the fill in these wetlands not be removed to facilitate the potential future 

use and development of the ACW areas. 

TABLE 4.4.2-1

Wetlands Affected by Construction and Operation of the Liquefaction Facilitya,b

Wetland Classification

Liquefaction 

Facility ACW Area A ACW Area B ACW Area C ACW Area D Total

Emergent 8.0 2.6 0.6 0.0 0.0 11.1

Emergent mosaic 0.0 0.0 7.9 1.7 0.0 9.6

Scrub-shrub 23.6 3.9 4.9 0.0 0.0 32.4

Scrub-shrub mosaic 0.0 0.0 0.0 1.9 1.9 3.8

Forested 21.7 0.0 0.0 0.0 0.0 21.7

Forested mosaic 52.0 69.5 2.2 0.7 12.5 136.8

TOTAL 105.3 75.9 15.5 4.3 14.4 215.4

____________________

a All units of measurement represent acreage impacted.

b

The numbers in this table have been rounded for presentation purposes; therefore, the totals may not reflect the sum of 

the addends.

The majority of the wetlands impacted by the proposed liquefaction facility and ACWs are 

forested wetland mosaics (pimple-mounds), scrub-shrub wetlands, or forested wetlands. Additional 

forested wetlands and forested wetland mosaics are located in the project vicinity (generally within the 

floodplain of the Calcasieu River), but construction of the project would result in the loss of a relatively 

large portion of the forested wetlands in the immediate area. Lake Charles LNG would be required to 

mitigate wetland impacts associated with construction and operation of the project as part of its projectspecific Compensatory Mitigation Plan, which is discussed further in section 4.4.4.

4.4.2.2 Non-Liquefaction Facilities

Construction of the Non-Liquefaction Facilities would affect a total of 37.9 acres of wetlands (see 

table 4.4.2-2). The majority of wetland impacts associated with the Non-Liquefaction Facilities 

(35.6 acres) would be a result of pipeline construction; the remaining wetland impacts would be 

associated with construction and operation at six meter stations. A wetland present within the southeast 
4-35

corner of the Compressor Station 203-A site would be avoided during construction and operation of the 

proposed facility.

Pipelines

Based on wetland delineations conducted by Trunkline, construction of the proposed pipelines 

(Mainline Connector, Mainline 200-3 Loop, and Calcasieu River HDD associated with Mainline 200-1 

modifications) would impact an estimated 35.6 acres of wetlands as shown in table 4.4.2-2. Of this total, 

6.0 acres are located within the proposed 50-foot-wide permanent easements associated with the pipelines. 

TABLE 4.4.2-2

Wetlands Affected by Construction and Operation of the Non-Liquefaction Facilitiesa,b

Project Component

Emergent 

Wetland

Scrub-Shrub

Wetland

Forested

Wetland Total

Const.c Oper. Const.c Oper. Const.c Oper. Const.c Oper.

Pipelines

Mainline Connector 4.6 1.2 5.3 2.0 1.7 0.6 11.6 3.8

Mainline 200-3 Loop 1.1 0.1 4.3 2.1 0.3 <0.1 5.7 2.2

Mainline 200-1 Modifications –

Calcasieu River HDD

17.2 0.0 0.1 0.0 1.1 0.0 18.4 0.0

PIPELINES SUBTOTAL 22.9 1.3 9.7 4.1 3.1 0.6 35.6 6.0

Meter Stations

Kinder Morgan–Lake Charles 0.0 0.0 0.4 0.1 0.0 0.0 0.4 0.1

Columbia Gulf–Egan 0.0 0.0 0.0 0.0 0.3 0.2 0.3 0.2

NGPL–Lakeside 0.1 0.1 0.0 0.0 0.0 0.0 0.1 0.1

Gulf Crossing–Perryville 0.1 0.0 0.0 0.0 0.0 0.0 0.1 0.0

Texas Gas–Woodlawn 0.0 0.0 0.0 0.0 <0.1 0.0 <0.1 0.0

Transco Ragley 1.4 0.1 0.0 0.0 0.0 0.0 1.4 0.1

METER STATIONS SUBTOTAL 1.5 0.2 0.4 0.1 0.4 0.2 2.3 0.5

TOTAL 24.4 1.4 10.1 4.3 3.5 0.8 37.9 6.5

____________________

a All units of measurement represent acreage impacted.

b

The numbers in this table have been rounded for presentation purposes; therefore, the totals may not reflect the sum 

of the addends. 

c Construction impacts include impacts within the construction workspace limits, including temporary and permanent 

right-of-way, ATWSs, and access roads. Wetlands crossed by HDD are not included because they would not be 

affected outside of designated construction workspace areas.

The majority of the wetlands impacted by construction of the pipelines (64 percent) would be 

emergent, which is partly due to the Mainline 200-3 Loop and Calcasieu River HDD routes being 

constructed within or largely adjacent to existing rights-of-way. Small and medium sized scrub-shrub and 

forested wetlands would also be impacted as a result of pipeline construction, comprising 27 percent and 

9 percent, respectively, of the wetland impacts associated with pipeline construction.

Trunkline would typically construct the pipelines using a 75-foot-wide construction right-of-way 

in wetlands. The only exceptions would be where the use of a 100-foot-wide construction corridor is 

warranted due to site-specific conditions (see section 4.4.3). Excavation of the pipeline trench, 

stockpiling of the trench spoil, and backfilling of the trench would disturb soils and could temporarily 

affect the rate and direction of water movement within wetlands. If contours and elevations are not 

properly restored, these effects could adversely impact wetland hydrology and revegetation by creating 

soil conditions that may not support wetland communities and hydrophytic vegetation at preconstruction

levels. If soils are not properly segregated during construction, the resulting mixed soil layers could alter 
4-36

biological components of the wetland and affect the reestablishment of native wetland vegetation. The 

temporary stockpiling of soil and movement of heavy machinery across wetlands could also lead to 

inadvertent compaction and furrowing of soils, which could alter natural hydrologic patterns, inhibit seed 

germination, and increase seedling mortality. Equipment could also introduce non-native and invasive 

species to the disturbed soil. Altered surface drainage patterns, stormwater runoff, runoff from the trench, 

accidental spills, and discharge of hydrostatic test water could also negatively affect wetland regeneration. 

The effects of construction would be greatest during and immediately following construction. 

Generally, once the pipelines are in place, wetland vegetation communities would transition back to a 

community with a function similar to that of the wetland prior to construction. In emergent wetlands, the 

impact of construction would be relatively minor and short term, because the herbaceous vegetation 

would regenerate quickly (generally within 1 to 2 years). Scrub-shrub wetland impacts would also be 

minor and short term, but these wetlands could take 2 to 4 years to reach functionality similar to 

preconstruction conditions depending on the age and complexity of the wetland system. In forested 

wetlands, the impact of construction would be long term due to the long regeneration period of these 

vegetative types (30 years or more).

Within the 50-foot-wide permanent easement associated with the Mainline Connector and 

Mainline 200-3 Loop pipelines, Trunkline would maintain up to a 10-foot-wide corridor centered over 

each pipeline in an herbaceous state during operation to facilitate pipeline inspections and maintenance. 

In accordance with our Procedures, Trunkline may selectively remove trees within a 30-foot wide 

corridor centered over each pipeline with roots that could compromise the integrity of the pipeline 

coating. The remaining 20 feet within the permanent easement would be allowed to revegetate naturally. 

As a result, a 10-foot wide corridor through both scrub-shrub and forested wetlands would be 

permanently converted to emergent wetland. An additional 20-foot-wide corridor (extending 10 feet on 

either side of the 10-foot-wide corridor centered over each pipeline) through forested wetlands would be 

permanently converted to scrub-shrub wetlands. Wetland conversion within the permanent easement 

would convert about 6.0 acres of forested wetland to scrub-shrub or emergent wetlands. While the 

conversion would not constitute a wetland loss, it would represent a potential permanent change in 

wetland function. 

Trunkline would minimize wetland impacts by collocating the 6.5-mile Mainline 200-3 Loop 

with an existing pipeline and overlapping the rights-of-way, and by placing temporary workspaces 

associated with the Calcasieu River HDD within the existing permanent easement for Mainline 200-1, 

which would minimize impacts on previously undisturbed wetlands. Section 2.6.3 provides additional 

details and typical drawings of right-of-way cross-sections in both collocated and non-collocated areas. 

Additionally, several wetlands would be avoided by the use of the HDD method. With the exception of a 

minor cut line path that may be required along the HDD guide wire path, no clearing is proposed between 

the entry and exit points of the HDDs. Section 2.6.3 describes the specialized construction techniques 

that Trunkline would implement for construction through wetlands. 

Except where alternative measures are justified as discussed in section 4.4.3, Trunkline would 

implement our Procedures to minimize impacts on wetlands, which include: 

 limiting the operation of construction equipment within wetlands to equipment essential 

for clearing, excavation, pipe installation, backfilling, and restoration;

 limiting removal of stumps and grading in wetlands to directly over the trench, except 

where necessary to ensure safety;

 segregating topsoil in non-saturated wetlands;
4-37

 minimizing the length of time that the trench is open and the topsoil is segregated before 

it is restored;

 installing trench breakers at the boundaries of wetlands as needed to prevent draining of a 

wetland and maintain original wetland hydrology;

 prohibiting storage of hazardous materials, chemicals, fuels, and lubricating oils within a 

wetland or within 100 feet of a wetland boundary; and

 limiting post-construction maintenance of vegetation within herbaceous wetlands to a 

10-foot-wide strip of vegetation centered over the pipeline, and in forested areas, limiting 

tree removal to those that are within 15 feet of the pipeline centerline.

As discussed in additional detail in section 4.4.4, Trunkline would also be required to mitigate 

wetland impacts associated with construction and operation of the project through its project-specific 

Compensatory Mitigation Plan. With the implementation of the above measures and the Compensatory 

Mitigation Plan, we believe that construction and operation of the proposed pipeline facilities would have 

minimal impacts on wetlands.

Meter Stations 

Construction of the meter stations would affect a total of 2.3 acres of wetlands as shown in 

table 4.4.2-2. Of this, 1.4 acres of emergent wetlands are located within the Transco Ragley Meter 

Station site and small wetland areas totaling 0.9 acre are located within the Kinder Morgan–Lake Charles, 

Columbia Gulf–Egan, NGPL–Lakeside, Gulf Crossing–Perryville, and Texas Gas–Woodlawn Meter 

Station sites. 

During site preparation activities, 0.5 acre of wetland would be permanently filled and converted 

to upland industrial land. The remaining 1.8 acres of emergent, scrub-shrub, and forested wetlands would 

be temporarily modified for use as temporary workspace during construction of the meter stations. 

Impacts on these wetlands would be temporary and similar to, but smaller in scale than, the temporary 

wetland impacts associated with pipeline construction described above (see Pipelines). 

Following construction, temporary workspaces would be restored in accordance with our 

Procedures and allowed to naturally transition back into a community with a function similar to that of the 

wetland prior to construction. As described above, the impact of construction on emergent wetlands 

would be relatively short term since herbaceous vegetation would regenerate quickly. Impacts on scrubshrub wetlands would also be minor and short term, although these wetlands could take longer to fully 

recover. In forested wetlands, the impact would be extended due to the longer regeneration period 

associated with forested communities. Overall, construction and operation of the proposed meter stations 

would have only minor impacts on wetlands.

4.4.3 Alternative Measures to FERC’s Procedures

In several locations, Lake Charles LNG and Trunkline propose to use alternatives to the measures 

described in our Procedures that relate to the construction right-of-way width, the location of ATWS 

within wetlands, and the location of aboveground facilities within wetlands. The proposed alternative 

measures are discussed below. 

4.4.3.1 Liquefaction Facility

Section VI.A.6 of our Procedures states that aboveground facilities should be located outside of 

wetlands except where the location of such facilities outside of wetlands would prohibit compliance with 
4-38

DOT regulations. As described above, Lake Charles LNG proposes to construct the new liquefaction 

facility within a site that contains 105.3 acres of wetlands. Section 3.3 of this EIS provides an analysis of 

alternative liquefaction facility sites and concludes that, when multiple factors are considered, the 

proposed site is the environmentally preferable site. As such, we find that the placement of the 

liquefaction facility within wetlands is reasonable and adequately justified provided that Lake Charles 

LNG complies with the conditions of its COE permit, including the implementation of compensatory 

mitigation.

Section VI.B.1.a of our Procedures requires that all extra workspaces (e.g., staging areas and 

additional spoil storage areas) be at least 50 feet away from wetland boundaries, except where the 

adjacent upland consists of cultivated or rotated cropland or other disturbed land. Portions of each of the 

ACWs Lake Charles LNG proposes to use during construction of the liquefaction facility are within 

wetlands. Use of the ACWs would impact a total of 110.1 acres of wetlands, including 84.9 acres of 

forested wetland mosaics. 

In response to our inquiry about possible alternative locations for the ACWs, Lake Charles LNG

said it sought alternative ACW sites within a few miles of the proposed liquefaction facility and on either 

side of Lincoln, Big Lake, and Tank Farm Roads. An advantage of the proposed ACWs to the east of Big 

Lake Road is that Lake Charles LNG has existing leases on portions of those sites. Siting ACWs west of 

the liquefaction facility was not feasible due to the existing Alcoa facility. Lake Charles LNG indicated 

that a significant disadvantage of siting ACW A to the east of the proposed location was the potential to 

increase traffic congestion along two primary roads servicing the area, Lincoln Road and Big Lake Road. 

There is also a rail spur that runs toward the liquefaction facility site from the east. Tank Farm Road to 

the north of the liquefaction facility site is a less traveled road than Big Lake Road; therefore, utilizing the 

ACW to the north would reduce the potential risks and congestion associated with moving construction 

equipment, materials, and construction workers across the roads. Generally, sites in the vicinity of the 

Liquefaction Facility contain a large percentage of wetlands, and all tracts that Lake Charles LNG

reviewed north of Tank Farm Road and to the west were similar to each other. Given the lack of good 

alternatives in close proximity to the liquefaction facility site, we agree that use of the proposed ACW 

locations is justified provided that Lake Charles LNG complies with the requirements of its COE permit 

and implements its COE-approved Compensatory Mitigation Plan.

4.4.3.2 Non-Liquefaction Facilities

Section VI.A.3 of our Procedures states that the width of the construction right-of-way should be 

limited to 75 feet or less in wetlands. Trunkline has proposed a right-of-way width of 100 feet in the 

following nine wetlands that would be crossed by the Mainline Connector:

Beginning Milepost Wetland ID Number

2.5 W-C-137

3.2 WB-D-110

3.5 W-AT-11

3.6 A-AT-12

4.0 W-AT-7

5.0 W-AT-6

6.3 W-AT-15

8.3 W-C-121

10.4 W-AT-3
4-39

Trunkline stated that the extra right-of-way width at the above locations is necessary to maintain 

slope stability of the trench required for the 42-inch-diameter pipeline and to contain excavated spoil 

within the right-of-way. Based on our review, we determined in the draft EIS that these proposed 

alternative measures are reasonable and adequately justified at all except one of the requested locations. 

Wetland W-AT-15 is a forested wetland located immediately northeast of the HDD entry point for the 

Little Bayou HDD crossing. In order to ascertain whether impacts on this wetland could be avoided, we 

recommended in the draft EIS that Trunkline evaluate the feasibility of moving the Little Bayou HDD 

entry point to the northeast beyond the boundary of forested wetland W-AT-15. In its May 14, 2015 

response, Trunkline stated that it had reviewed our suggested reconfiguration of this HDD and determined 

that moving the entry point to avoid the wetland would increase the length of the HDD by approximately 

500 feet, bringing the total length to approximately 3,284 feet. Trunkline stated that the increased HDD 

length for this large-diameter (42-inch) pipeline would increase constructability challenges and increase 

the risk of inadvertent returns, which could affect the other resources to be avoided by this HDD, 

including a larger forested wetland (W-AT-5) as well as Little Bayou and several tributaries. Based on 

Trunkline’s assessment, we agree that the potential constructability issues and risks of increasing the 

length of this HDD outweigh the benefit of avoiding the relatively small (0.17 acre) disturbance of 

wetland W-AT-15. Therefore, we conclude that the deviation from the Procedures at this location under 

the revised HDD design is adequately justified. Trunkline would need to mitigate impacts on wetland 

W-AT-15 in accordance with its COE permit. 

Trunkline has also proposed alternative measures to sections VI.B.1.a and VI.A.6 of our 

Procedures to place certain ATWS and aboveground facilities within wetlands. Table 4.4.3-1 lists these 

locations and facilities, as well as the wetlands affected, Trunkline’s site-specific justifications, and our 

conclusions as to whether the justifications are adequate.

In its initial application, Trunkline proposed to place a number of ATWSs along the Mainline 

Connector within wetlands. However, Trunkline re-evaluated and subsequently modified certain 

workspace configurations, including the locations of some HDD entry and exit points, to reduce impacts 

on wetlands. The alternative measures in table 4.4.3-1 are those that are currently proposed. Trunkline

has also proposed the placement of ATWSs within wetlands at the origin and terminus of the Mainline 

200-3 Loop and at one bored crossing of an agricultural ditch. For the reasons shown in the table, we 

have determined that alternative measures at each of these ATWS locations are reasonable and adequately 

justified.

Trunkline proposes to place ATWSs in wetlands W-E-001 and W-E-003 for the HDD crossing of 

the Calcasieu River, which would be part of the Mainline 200-1 modifications. The proposed ATWS 

within wetland W-E-001, an emergent wetland, includes the HDD entry point, the location of which has 

changed due to the above-noted redesign of this crossing. The ATWS in wetland W-E-001 runs along 

and immediately adjacent to Trunkline’s existing permanent rights-of-way on the west side of the 

Calcasieu River, including an area that appears to consist of unmaintained land between two of 

Trunkline’s existing pipelines. Trunkline did not explain why this portion of the ATWS is necessary or 

provide justification for this additional wetland disturbance. We noted in the draft EIS the possibility that 

Trunkline might plan to use a portion of its existing right-of-way in this area to obtain water from the 

river during implementation of the HDD (i.e., for mixing drilling fluid and conducting hydrostatic testing 

of the HDD pipe segment); however, the amount of workspace depicted in the alignment sheet, which 

was not clearly quantified, appeared excessive for this purpose. Additionally, Trunkline proposes to place 

an ATWS within wetland W-E-003, a forested wetland also on the west side of the river. Although 

Trunkline’s table of wetland impacts indicated that impacts on this wetland would be small (less than 

0.1 acre), the location of the proposed ATWS within this wetland is not clearly depicted on the alignment 

sheet, and the justification provided was too general for us to evaluate.
4-40

TABLE 4.4.3-1

Proposed Locations of Additional Temporary Workspace or Aboveground Facilities Within Wetlands for

the Non-Liquefaction Facilities Associated With the Lake Charles Liquefaction Project

Facility/

Milepost

Wetland

I.D.

Procedures 

Section 

Reference

Deviation

Description Justification for Deviation FERC Staff Conclusiona

Mainline Connector

2.7 W-C-137 VI.B.1.a ATWS within

wetland

The point of inflection (PI) at this location 

could not be moved to avoid the wetland 

due to proximity of a roadway and 

residence; therefore, the ATWS 

associated with the PI could not be 

moved outside of the wetland.

Sufficiently justified. A 

suitable upland alternative 

location for the ATWS is not 

available.

11.3 W-D-125 VI.B.1.a ATWS within

wetland

ATWS at pipeline terminus required for 

staging area.

Sufficiently justified. A 

suitable upland alternative 

for the portion of the ATWS 

in a wetland is not available.

Mainline 200-3 Loop

176.0 W-B-200A VI.B.1.a ATWS within

wetland

This ATWS is at the terminus of the 

pipeline and includes the HDD entry 

point for the Bayou Lacassine HDD. The

ATWS is located in the middle of a >1.7-

mile-long stretch of wetlands and an 

upland alternative is not available. 

Erosion control devices would be used

and monitored throughout construction.

Sufficiently justified. A 

suitable upland alternative 

location for the ATWS is not 

available.

182.1 W-C-100 VI.B.1.a ATWS within

wetland

This ATWS is necessary to complete the

bore of the adjacent agricultural ditch.

Sufficiently justified. A 

suitable upland alternative 

location for the ATWS is not 

available.

182.5 W-C-100 VI.B.1.a ATWS within

wetland

The origin of the pipeline segment is 

located within this feature. There is no 

upland alternative for workspace.

Sufficiently justified. A 

suitable upland alternative 

location for the ATWS is not 

available.

Mainline 200-1 Modifications – Calcasieu River HDD

195.7 W-E-001 VI.B.1.a ATWS within

wetland

Required for completion of the Calcasieu 

River HDD, including the HDD entry point 

and excavations required to disconnect 

existing pipeline and tie into the existing 

200-1 pipeline.

Sufficiently justified. A 

suitable upland alternative 

for the ATWS is not 

available.

196.1 W-E-003 VI.B.1.a ATWS within

wetland

Required for completion of the Calcasieu 

River HDD, including excavations 

required to disconnect existing pipeline 

and tie into the existing 200-1pipeline.

Sufficiently justified. A 

suitable upland alternative 

for the ATWS is not 

available.

Meter Stations

Kinder Morgan–

Lake Charles

W-AV-039

W-AV-041

VI.A.6 Aboveground 

facility within 

a wetland

The meter station would be located at the 

intersection of the Trunkline and Kinder 

Morgan pipelines. The tract is within a 

pasture that contains closely intermingled 

uplands and wetlands throughout. 

Alternate configurations would not reduce 

wetland impacts.

Sufficiently justified. A 

suitable alternative location 

for the facility that would 

completely avoid wetlands is 

not available.
4-41

TABLE 4.4.3-1 (cont’d)

Proposed Locations of Additional Temporary Workspace or Aboveground Facilities within Wetlands for

the Non-Liquefaction Facilities Associated with the Lake Charles Liquefaction Project

Facility/

Milepost

Wetland

I.D.

Procedures 

Section 

Reference

Deviation

Description Justification for Deviation FERC Staff Conclusion a

NGPL–Lakeside W-C-108A VI.A.6 Aboveground 

facility within 

a wetland

The existing NGPL Meter Station is 

surrounded by wetlands to the north, 

south, and west, and a road (LA-3056) 

runs adjacent to the station to the east. 

Expanding the station in another direction 

would result in greater wetland impacts 

than the proposed expansion to the west.

Sufficiently justified. The 

proposed configuration 

minimizes wetland impacts 

as compared to expansion in 

a different direction.

Transco Ragley W-B-CA603VI.A.6 Aboveground 

facility within 

a wetland

The proposed modifications at this 

existing meter station would require a 

small amount of permanent wetland fill 

within the existing meter station site. 

Because the existing facility is 

surrounded by wetlands and the 

modification is at an existing facility, other 

possible configurations would not reduce 

the impact on this wetland.

Sufficiently justified. A 

suitable upland alternative 

location for the required 

modification is not available.

____________________

a Approval of these deviations does not relieve Trunkline from complying with other requirements of our Procedures. Erosion 

and sedimentation control devices should be monitored and maintained in these areas more frequently than the minimum 

time intervals required by our Procedures until final grading and revegetation has been completed.

In order for us to consider Trunkline’s proposed deviations from the Procedures at these two 

locations, we recommended in the draft EIS that Trunkline file maps or figures clarifying the location of 

the proposed ATWS in wetland W-E-003, and provide additional justification for this ATWS and the 

proposed ATWS in wetland W-E-001. As noted above, in its May 14, 2015 response, Trunkline stated 

that the ATWS on either side of the Calcasieu River would be required to excavate and disconnect the 

existing pipeline segment to be abandoned and to complete the tie-ins to the 200-1 pipeline, and explained 

why wider excavations would be required for these operations. Additionally, the ATWS would be used to 

obtain water for HDD operations and hydrostatic testing. Trunkline noted that the redesigned plan would 

reduce impacts on wetland W-E-001 by about 0.4 acre. The impacts on wetland W-E-003 would not be 

reduced; however, the figure provided with the response shows more clearly the location of the ATWS 

within the wetlands. The figure also shows that, based on NWI data, the wetlands in this area extend 

further to the west of the right-of-way (beyond the surveyed area), making avoidance of wetlands at this 

location impracticable. With the additional information provided by Trunkline, we find that the locations 

of these ATWSs are adequately justified.

Trunkline proposes to place portions of three aboveground facilities (the Kinder Morgan–Lake 

Charles, NGPL–Lakeside, and Transco Ragley Meter Stations) within wetlands, which would 

permanently affect a total of about 0.3 acre of wetlands. The proposed activities at the NGPL–Lakeside 

and Transco Ragley Meter Stations would involve modifications of existing facilities; therefore, potential 

alternative configurations are very limited. The wetlands affected at these two stations are emergent 

wetlands immediately adjacent to the existing facilities and likely do not provide high-quality habitat. 

The Kinder Morgan–Lake Charles Meter Station location is driven by the intersection of two existing 

pipelines, and an alternate configuration of the station would not avoid wetland impacts due to the 

interspersed presence of wetlands and uplands within the area. Therefore, as shown in table 4.4.3-1, we 

have determined that alternative measures at these locations are reasonable and adequately justified.
4-42

4.4.4 Compensatory Mitigation

The COE has a goal of “no net loss” of wetlands in the United States. This means that 

unavoidable wetland impacts must be offset by the creation, restoration, enhancement, or preservation of 

at least an equal amount of wetlands, which is referred to as compensatory mitigation. 

As required by 33 CFR 332.3, Lake Charles LNG and Trunkline are required to propose 

compensatory mitigation that is commensurate with the amount and type of impact resulting from 

construction and operation of the Lake Charles Liquefaction Project. There are three mechanisms for 

providing compensatory mitigation: permittee-responsible compensatory mitigation, mitigation banks, 

and in-lieu fee mitigation. Lake Charles LNG and Trunkline developed a mitigation plan that would 

include credit purchases from COE-approved mitigation banks and permittee-responsible compensatory 

mitigation, with the amount of compensatory mitigation determined based on the COE’s preliminary

jurisdictional determinations. The plan is subject to review and approval by the COE, New Orleans 

District as part of the section 404/10 permit process. Lake Charles LNG and Trunkline filed their section 

404 permit application with the COE, New Orleans District on August 6, 2014; however, the 

Compensatory Mitigation Plan was not included in the application as it was still in development. Because 

the project’s Compensatory Mitigation Plan was not finalized and approved by the COE at the time we 

prepared the draft EIS, we recommended that Lake Charles LNG and Trunkline file a copy of the final 

Compensatory Mitigation Plan and documentation of COE approval of the plan prior to the end of the 

draft EIS comment period. In their May 22, 2015 response, Lake Charles LNG and Trunkline stated that 

consultation with the COE was continuing. In a June 1, 2015 supplemental response, Lake Charles LNG 

and Trunkline provided a copy of the proposed Permittee Responsible Mitigation Plan that was submitted 

to the COE on that same day. The plan was designed to mitigate for impacts on 243.8 acres of wetlands

within the Lower Calcasieu and Upper Calcasieu Watersheds. Based on application of the COE’s 

mitigation ratios, Lake Charles LNG’s and Trunkline’s mitigation contractor, Resource Environmental 

Solutions, LLC calculated the required mitigation for this acreage as 427.3 acres (the proposed mitigation 

plan provides for additional mitigation that would be reserved for future use if necessary). The permittee 

responsible mitigation would be accomplished through the re-establishment and rehabilitation of coastal 

prairie and bottomland hardwood habitats. The cover letter accompanying the submittal of the plan to the 

COE stated that approved mitigation bank credits would be used to compensate for project-related 

impacts in the Mermentau and Mermentau Headwaters Watersheds. Lake Charles LNG and Trunkline 

stated that they would file documentation of the COE’s approval of the plan with the Secretary upon 

receipt. However, because the plan could potentially be revised based on the COE’s review, we 

recommend that:

 Prior to construction, Lake Charles LNG and Trunkline should file with the 

Secretary a copy of the final Compensatory Mitigation Plan and documentation of 

COE approval of the plan. 

4.5 VEGETATION

The Lake Charles Liquefaction Project spans portions of three plains’ ecoregions, all of which are 

generally topographically flat, yet slightly varied in climate and substrate. Each ecoregion has a unique 

geographical position, hydrological connection, and soil composition allowing for the development of 

distinctive biotic communities. 

The majority of the proposed project would be situated in the Western Gulf Coastal Plain 

ecoregion, including the liquefaction facility; the Mainline Connector; the Mainline 200-3 Loop; the 

Columbia Gulf–Egan, Kinder Morgan–Lake Charles, NGPL–Lakeside, Texas Gas–Woodlawn, and 

LCLNG Export Meter Stations; and Compressor Station 203-A. The Western Gulf Coastal Plain occurs 
4-43

along the coastal portions of Texas and Louisiana and is conducive to grasslands and croplands (EPA, 

2013c).

The Mainline 200-1 modifications at the Calcasieu River would be located in the transitional area 

from the Western Gulf Coastal Plain ecoregion into the South Central Plains. This ecoregion 

encompasses central and northwest Louisiana, east Texas, and southwest Arkansas and is known for its 

productive loblolly and shortleaf pine plantations, although historically, the South Central Plains 

comprised mixed pine and hardwood forests (EPA, 2013c). Other Non-Liquefaction Facilities in the 

South Central Plains ecoregion include the Tennessee–Kaplan, Transco Ragley, and TETCO–Allen Meter 

Stations; modifications to Mainline 200-1 at the US 190 Meter Station; and the Longville and Pollock 

Compressor Stations.

To the east of the South Central Plains ecoregion lies the Mississippi Alluvial Plain ecoregion. 

The northern Non-Liquefaction Facilities, including the Mainline 100-3 modifications, the Gulf 

Crossing–Perryville and MEP–Perryville Meter Stations, and the Epps and Shaw Compressor Stations, 

would be situated within the Mississippi Alluvial Plain, where broad flats and poorly drained soils were 

traditionally occupied by bottomland deciduous forest. Much of this region has been converted to 

cropland with soybean, cotton, and rice as the primary crops (EPA, 2013c).

4.5.1 Existing Vegetation Resources

4.5.1.1 Liquefaction Facility

Lake Charles LNG reported that the vast majority of the project area associated with the 

liquefaction facility, including the liquefaction facility site, LCLNG Export Meter Station, and ACWs, are 

composed of pimple-mound wetland/non-wetland “mosaics.” The mosaic areas within the project area 

are dominated by forest, but also include herbaceous zones. Pimple-mound mosaics, and typical 

vegetation present within mosaic wetland communities at the liquefaction facility, are described in detail 

in section 4.4.1.

Herbaceous upland communities are located in the southeast corner of proposed liquefaction 

facility and within ACW Areas B and C. Typical species within these areas include annual ragweed 

(Ambrosia artemisiifolia), dogfennel (Eupatorium capillifolium), sneezeweed (Helenium amarum), St. 

Augustine grass (Stenotaphrum secundatum), and swamp sunflower (Helianthus angustifolius).

Herbaceous wetland communities occur in the southeastern portion of the liquefaction facility 

site. Typical vegetation present within herbaceous wetland communities are described in section 4.4.1.

4.5.1.2 Non-Liquefaction Facilities

The proposed work at the existing meter stations and the mainline modifications would primarily 

be located within the existing facility sites and adjacent agricultural land. The proposed new Compressor 

Station 203-A and portions of some of the new meter stations would also be located in agricultural land. 

In addition, more than half of the land crossed by the Mainline Connector and Mainline 200-3 Loop is 

agricultural. Based on Trunkline’s field surveys, agricultural lands within the project area include pine 

plantations, pasture land, and crop lands. 

Pine plantations are located along the Mainline Connector and Mainline 200-3 Loop routes. Pine 

plantations are dominated by varying age stands of loblolly pine and used exclusively for timber 

production. Understory and ground cover within pine plantations varies depending on land management 

practices. Pasture lands in the area consist of maintained natural herbaceous vegetation for grazing 
4-44

animals or are planted in monocultures of perennial (e.g., Bermuda grass (Cynodon dactylon), Bahia grass 

(Paspalum notatum), and dallisgrass (Paspalum dilatum)) or annual (e.g., ryegrass (Lolium multiflorum), 

cereal rye (Secale cereal), and oats (Avena sativa)) grasses for hay production. Crops identified during 

Trunkline’s field surveys included rice, soybeans, and crawfish.

Upland forest communities along the Mainline 200-3 Loop route typically contain Chinese

tallow, longleaf pine (Pinus palustris), slash pine, southern red oak (Quercus falcata), and water oak. 

Sub-canopy upland species include American beautyberry, American holly (Ilex opaca), red maple (Acer 

rubrum), and yaupon. 

Forested wetlands are located along the Mainline Connector route and, to a lesser extent, the 

Mainline 200-3 Loop route. Small areas of herbaceous wetland communities are present along the 

Mainline Connector and Mainline 200-3 Loop routes, within and adjacent to meter station sites, at the 

Compressor Station 203-A site, and at the Mainline 200-1 modification sites. Typical species present 

within these wetland communities are described in section 4.4.1.

Herbaceous upland communities are present along the Mainline 200-3 Loop route, within and 

adjacent to meter station sites, and at the Mainline 200-1 modification sites. Typical species within these 

communities include black medick (Medicago lupulina), bluestem (Andropogon spp.), catchweed 

(Galium aparine), geranium (Geranium spp.), johnsongrass (Sorghum halepense), little quakinggrass 

(Briza minor), Louisiana vetch (Vicia ludoviciana), ragweed, red fescue (Festuca rubra), southern 

dewberry (Rubus trivialis), and Timothy canarygrass (Phalaris angusta). 

4.5.2 Construction and Operation Impacts and Mitigation

As summarized in table 4.5.2-1, a total of about 944.1 acres of vegetation would be cleared 

during construction of the project. Following construction, about 218.4 acres of vegetation would be 

allowed to return to vegetated conditions, 725.7 acres would not be restored but would be converted to 

developed land or stabilized with gravel or vegetation. Overall, the project would have the greatest 

impact on forest (upland forest and pine plantations [338.9 acres] and forested wetland/inundated forest

[167.8 acres]), followed by pasture and row crop agriculture (218.9 acres), herbaceous upland 

(127.0 acres), and non-forested wetland (91.5 acres) vegetation. Proposed activities within existing 

facility boundaries (i.e., LNG terminal; contractor yard; Longville, Pollock, Epps, and Shaw Compressor 

Stations; certain meter stations, and some of Mainline 100-3 modifications) would not affect vegetation 

because these areas have undergone previous disturbance and/or have been graded and graveled.

4.5.2.1 Liquefaction Facility

A total of 568.3 acres of vegetation would be cleared during construction of the liquefaction 

facility, including the ACWs. Of this, 245.4 acres would be permanently converted to industrial use 

associated with operation of the liquefaction facility, resulting in a permanent loss of 135.3 acres of 

forested uplands, 73.7 acres of forested wetlands (both palustrine forested wetlands and forested mosaics), 

31.6 acres of palustrine emergent and palustrine scrub-shrub wetlands/wetland mosaics, and 4.8 acres of 

herbaceous uplands. Lake Charles LNG has stated that in accordance with the respective landowners’ 

requests, the 322.9 acres of vegetated areas within the ACWs would not be restored to preconstruction 

elevations or contours, although they would be stabilized as described in section 4.2.3 to prevent off-site 

erosion and sedimentation. Therefore, although these areas are not within the operational footprint of the 

liquefaction facility, we consider these impacts on vegetation to be permanent, resulting in the loss or 

conversion of 86.3 acres of herbaceous upland, 25.3 acres of palustrine emergent and palustrine scrubshrub wetlands/wetland mosaics, 84.9 acres of forested wetlands, and 126.4 acres of forested uplands.
4-45

TABLE 4.5.2-1 

Vegetation Communities Affected by the Lake Charles Liquefaction Project (in acres)

Facilities

Agriculturea

Herbaceous 

Upland

Non-Forested 

Wetlandb

Forested 

Wetland or 

Inundated Forest Forested Upland Pine Plantation Total

Temp. Perm. Temp. Perm. Temp. Perm. Temp. Perm. Temp. Perm. Temp. Perm. Temp. Perm.

LIQUEFACTION FACILITY

Liquefaction Facility 0.0 0.0 0.0 4.8 0.0 31.6 0.0 73.7c0.0 135.3 0.0 0.0 0.0 245.4

Additional Construction 

Workspaces

0.0 0.0 0.0 86.3 0.0 25.3 0.0 84.9 c0.0 126.4 0.0 0.0 0.0 322.9

Subtotal 0.0 0.0 0.0 91.1 0.0 56.9 0.0 158.6

c

0.0 261.7 0.0 0.0 0.0 568.3

NON-LIQUEFACTION FACILITIES

Pipelines

Mainline Connector 76.5 31.3 0.0 0.0 6.8 3.2 1.1 0.6c12.3 12.3 25.4 18.0 122.1 65.4

Mainline 200-3 Loop 35.8 24.8 9.7 3.5 3.2 2.2 0.3 0.0c1.4 6.6 0.0 0.7 50.4 37.8

Access Roads 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.0 0.1 0.0

Compressor Stations

203-A 0.0 45.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 45.6

Meter Stationsd

Kinder Morgan–Lake Charles 0.0 0.0 0.7 1.4 0.3 0.1 0.0 0.0 0.0 0.0 0.0 0.0 1.0 1.5

Columbia Gulf–Egan 0.9 0.6 0.8 0.8 0.0 0.0 0.2 0.2 0.0 0.0 0.0 0.0 1.9 1.6

NGPL–Lakeside 2.6 0.3 0.0 0.0 0.0 0.1 0.0 0.0 0.0 0.0 0.0 0.0 2.6 0.4

TETCO–Allen 0.0 0.0 2.2 1.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.2 1.8

Gulf Crossing–Perryville 0.5 0.0 1.2 1.2 0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.8 1.2

MEP–Perryville 0.0 0.0 2.3 2.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.3 2.1

Texas Gas–Woodlawn 0.0 0.0 1.6 0.0 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.0 1.7 0.0

Transco Ragley 0.0 0.0 0.0 0.0 1.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.3 0.0

Mainline 200-1 Modificationse

Calcasieu River HDD 0.0 0.0 5.6 0.0 17.3 0.0 6.8f0.0 0.3 0.0 0.0 0.0 30.0 0.0

US 190 Meter Station 0.0 0.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 0.0

Subtotal 116.3 102.6 25.1 10.8 29.0 5.6 8.4 0.8 14.2 18.9 25.4 18.7 218.4 157.4

PROJECT TOTAL 116.3 102.6 25.1 101.9 29.0 62.5 8.4 159.4 14.2 280.6 25.4 18.7 218.4 725.7

___________________________

a

For vegetation impact calculations, agriculture includes pasture and row crops. Pine plantations are analyzed separately.

b

Includes areas delineated as palustrine emergent and palustrine scrub-shrub wetlands/wetland mosaics.

c

Includes areas delineated as forested wetlands and forested wetland mosaics.

d

Impacts associated with the LCLNG Export and Tennessee–Kaplan Meter Stations are included with the Liquefaction Facility site and the Mainline 200-3 Loop, respectively.

e Work required for the100-foot overhead crossing and the MLV 202 replacement would occur within the Texas Gas–Woodlawn and Transco Ragley Meter Stations, 

respectively.

f Consists of 1.1 acre of forested wetland and 5.7 acres of inundated forest that was delineated as a waterbody (WB-B-CA-621). 

Note: The numbers in this table have been rounded for presentation purposes. As a result, the totals may not reflect the sum of the addends.
4-46

Although impacts on herbaceous upland vegetation affected by the liquefaction facility would be 

permanent where converted to industrial land, similar vegetative communities occur within the 

surrounding area. Therefore, impacts from construction and operation of the liquefaction facility on 

herbaceous upland vegetation communities would not be significant. Additional forested communities 

are located in the project vicinity (generally within the floodplain of the Calcasieu River), but 

construction of the project would result in the loss of a relatively large portion of upland and wetland 

forested communities in the immediate area. Impacts on wetland vegetation (including forested wetlands 

and forested wetland mosaics) would be mitigated to less than significant levels through the 

implementation of Lake Charles LNG’s project-specific Compensatory Mitigation Plan, which would 

require review and approval by the COE, New Orleans District (see section 4.4.2.2). However, the 

construction of the liquefaction facility would result in the unmitigated loss of about 261.7 acres of 

upland forest. 

4.5.2.2 Non-Liquefaction Facilities 

Construction of the Non-Liquefaction Facilities would affect about 375.8 acres of vegetation, 

including 275.8 acres for the pipelines, and 100.0 acres for aboveground facilities and Mainline 200-1 

modifications (see table 4.5.2-1).

Construction of the Mainline Connector and Mainline 200-3 Loop, including access roads, would 

affect a total of 275.8 acres of vegetation, including 168.4 acres of agricultural vegetation (pasture and 

row crops), 44.1 acres of pine plantation, 2.0 acres of forested wetland, 15.4 acres of non-forested 

wetland, 13.2 acres of herbaceous upland, and 32.7 acres of upland forest (see section 4.4.2.2 for further 

discussion of wetland impacts). Following construction, vegetation within the permanent easements 

associated with the Mainline Connector and Mainline 200-3 Loop (65.4 and 37.8 acres, respectively), 

would be subject to routine maintenance.

Trunkline would construct the Mainline Connector within a 125-foot-wide construction right-ofway through upland areas. In accordance with our Procedures, the right-of-way width would be reduced 

to 75 feet through wetlands, with the exception of those wetland areas where Trunkline’s request to use a 

100-foot-wide construction right-of-way is justified due to site-specific soil conditions, as described in 

section 4.4.3. The Mainline 200-3 Loop, which would be installed adjacent to an existing pipeline, would

be constructed within a 75-foot-wide construction right-of-way that would overlap the existing 

maintained right-of-way by 25 feet. Construction of both pipelines would also require the use of ATWS

at locations such as road, waterbody, wetland, and foreign pipeline crossings. During construction of the 

pipelines, Trunkline would remove surface vegetation mechanically or by hand, and grade the 

construction right-of-way as necessary to facilitate pipeline installation and allow for safe operation of 

equipment. Tree stumps would be removed from the trench line and cut low to the ground or removed 

from the right-of-way. Following construction, a 50-foot-wide permanent easement would be maintained 

over both the Mainline Connector and Mainline 200-3 Loop. The permanent easement for the Mainline 

200-3 Loop would overlap the existing permanent easement by 25 feet. 

Following construction, Trunkline would restore areas impacted by pipeline construction (e.g., 

construction rights-of-way, ATWS, and temporary access roads) to preconstruction conditions and 

contours. Disturbed areas would be restored in accordance with our Plan and Procedures, NRCS 

recommendations, other agency requirements and permit conditions, and landowner requests. Typically, 

Trunkline would not reseed actively cultivated crop lands unless requested by the landowner. Within pine 

plantations, the landowners would be allowed to replant temporary work areas; however, the 50-foot-wide 

permanent easements would be maintained in an herbaceous state. Trunkline has stated that all disturbed 

areas would be routinely monitored until restoration and revegetation are successful. At a minimum, on 

the ground inspections would be performed for 3 years following construction.
4-47

The primary impacts on vegetation from construction of the pipelines would be the cutting, 

clearing, and/or removal of existing vegetation within the construction work areas. The duration and 

magnitude of impacts would depend on the type and amount of vegetation affected, the rate at which 

vegetation regenerates after construction, and the frequency of vegetation maintenance conducted on the 

right-of-way during pipeline operation. In addition, right-of-way revegetation would depend on factors 

such as local climate, soil types, right-of-way maintenance practices, and land use. There would be minor 

and short-term impacts on agricultural, scrub-shrub and emergent wetland, and herbaceous upland areas 

because we would expect these areas to revegetate to a cover similar to preconstruction conditions within 

one to two growing seasons. 

Upland forested areas within the permanent easement would be permanently converted to 

herbaceous cover. Of the 76.8 acres of upland forest and pine plantation that would be cleared during 

construction of the Mainline Connector and Mainline 200-3 Loop, Trunkline would permanently maintain 

37.6 acres in an herbaceous state. Within wetlands, Trunkline would maintain a 10-foot-wide strip over 

the pipeline in an herbaceous state, and would selectively remove trees located within 15 feet of the 

pipeline that have roots that could compromise the integrity of the pipeline coating. Of the 2.0 acres of 

forested wetland that Trunkline would clear during construction, about 0.6 acre would be permanently 

converted to herbaceous or scrub-shrub wetland within this 30-foot-wide permanently maintained 

corridor. In temporary work areas where upland forest and forested wetland would be allowed to regrow, 

impacts would be long term because re-establishment to preconstruction conditions could take 10 to 

30 years, depending on the species type. 

Trunkline would minimize impacts on vegetative communities affected by pipeline construction 

by collocating the Mainline 200-3 Loop with an existing pipeline and by overlapping the construction 

area and permanent right-of-way with the existing maintained right-of-way as described above. 

Additionally, Trunkline proposes to install the pipelines using the HDD method at six locations, which 

would avoid or minimize impacts on riparian vegetation and wetland communities, including forested 

wetlands. No vegetation clearing is proposed between HDD entry and exit locations during construction 

and operation of the project, with the possible exception of a minor hand-cut line path, which may be 

necessary to allow for the placement of a tracing wire to ensure HDD accuracy. Trunkline’s 

implementation of our Plan and Procedures, which require the use of temporary and permanent erosion 

control measures, topsoil segregation in select areas, testing and mitigation for soil compaction, postconstruction monitoring, and limited routine vegetation maintenance would further minimize impacts on 

vegetation. All disturbed areas would be routinely monitored until restoration and revegetation are 

successful.

Construction of Compressor Station 203-A, new and modified meter stations, and mainline 

modifications would affect 50.5 acres of agricultural vegetation, 22.7 acres of herbaceous upland, 

19.2 acres of non-forested wetland, and 0.4 acre of upland forest. Construction of these facilities would 

affect 1.5 acres of forested wetland and an additional 5.7 acres of inundated forest that was delineated as a 

waterbody within areas affected by the Calcasieu River HDD. A 2.6-acre forested wetland is present 

within the Compressor Station 203-A site but would be avoided. Following construction, 54.2 acres of 

vegetated land would be permanently converted to industrial land for the new aboveground facilities. The 

remaining 45.8 acres of vegetation within the ATWS would be allowed to revert to preconstruction 

condition. Similar to the other pipeline facilities, Trunkline would not conduct clearing between the 

Calcasieu River HDD entry and exit points during construction and operation. To minimize impacts on 

vegetative communities during and after construction of these facilities, Trunkline would conduct much 

of the work within or adjacent to existing maintained rights-of-way and facility sites. Additionally, 

Trunkline would install erosion control measures and revegetate temporary workspaces in accordance 

with our Plan and Procedures. All disturbed areas would be routinely monitored in accordance with our 

Plan and Procedures until restoration and revegetation are successful.
4-48

With the implementation of the mitigation measures described above, we conclude that 

construction and operation of the Non-Liquefaction Facilities would not have a significant impact on 

vegetation communities in the project area. 

4.5.3 Exotic or Invasive Plant Communities and Noxious Weeds

Exotic plant communities, invasive species, and noxious weeds can out-compete and displace 

native plant species, thereby negatively altering the appearance, composition, and habitat value of 

affected areas. In accordance with the Plant Protection Act of 2000 (7 USC 7701), 13 plants have been 

federally designated as noxious weeds that could occur in Louisiana (NRCS, 2012), and the State of 

Louisiana has designated one plant as a noxious weed, Chinese tallow (Louisiana Revised Statutes Title 3 

Part 1791). In addition to those species designated as noxious at the federal or state level, an email dated 

February 14, 2014 from the NRCS to TRC, Lake Charles LNG and Trunkline’s environmental consultant, 

identified the following nuisance species: Chinese privet (Liqustrum sinense), giant sylvania (Salvinia 

sp.), Japanese climbing fern (Lygodium japonicum), and purple loosestrife (Lythrum salicaria). 

Field surveys for the Lake Charles Liquefaction Project identified Chinese tallow, Chinese privet, 

and Japanese climbing fern within the project area. Lake Charles LNG and Trunkline identified Chinese 

tallow within project areas associated with both the liquefaction facility and Non-Liquefaction Facilities. 

This species was found to be one of the dominant canopy species observed within the pimple mound 

wetland/non-wetland mosaics. This nonnative tree grows quickly and spreads quickly. When cut, the 

trees produce multiple stump sprouts. Intensive herbicide application is necessary to control this species 

as fire and mechanical removal (chopping and root removal) fail to control the aggressive seedlings 

(USGS, 2000).

Chinese privet and Japanese climbing fern were identified along the Mainline Connector route. 

Chinese privet is a nonnative shrub and prolific seed producer that matures rapidly, displacing native 

vegetation. Manual removal, including roots, is an effective control measure (NRCS, 2005). Japanese 

climbing fern thrives in moist soils with potential for dense canopy cover which, in turn, suppresses 

understory plant growth and recruitment. Control measures for this species include manual removal 

followed by herbicide application (USFS, 2014).

Lake Charles LNG and Trunkline would implement our Plan and Procedures, which require postconstruction monitoring for the first and second growing seasons in uplands, and for 3 years in wetlands, 

to evaluate the success of revegetation. As part of this monitoring program, Lake Charles LNG and 

Trunkline would be required to examine the project area for the presence of invasive species. In nonagricultural upland areas, revegetation would be considered successful if the density and cover of nonnuisance species within the areas disturbed during construction are similar to the density and cover in 

adjacent undisturbed areas. Wetland revegetation would be considered successful if all of the following 

criteria are satisfied: 

a. the affected wetland satisfies the current federal definition for a wetland (i.e., soils, 

hydrology, and vegetation);

b. vegetation is at least 80 percent of either the cover documented for the wetland prior to 

construction, or at least 80 percent of the cover in adjacent wetland areas that were not 

disturbed by construction;

c. if natural rather than active revegetation was used, the plant species composition is 

consistent with early successional wetland plant communities in the affected ecoregion; 

and 
4-49

d. invasive species and noxious weeds are absent, unless they are abundant in adjacent areas 

that were not disturbed by construction. 

In addition, our Plan and Procedures require that Lake Charles LNG and Trunkline coordinate 

with the appropriate land management and/or state agencies to prevent the introduction or spread of 

invasive species, noxious weeds, and soil pests. In email correspondence with TRC dated January 15, 

2014, the NRCS provided typical suggestions for the removal and control of Chinese tallow and stated 

that control and prevention recommendations for nuisance and invasive species would come from the 

LDWF. Lake Charles LNG and Trunkline have not proposed measures to be implemented during 

construction and operation of the project to control the spread of noxious weeds; therefore, we 

recommend that:

 Prior to construction, Lake Charles LNG and Trunkline should coordinate with the 

NRCS and LDWF to develop a project-specific noxious weed control plan. The plan 

should be filed with the Secretary for review and approval by the Director of OEP.

4.5.4 Vegetative Communities of Special Concern

Vegetative communities of special concern may include ecologically important natural 

communities, threatened or endangered plant species, or other rare or imperiled plants in need of special 

protection or minimal disturbance. Potential impacts on such communities in Louisiana are discussed 

below. The proposed project activities in Mississippi and Arkansas would occur within existing industrial 

facilities; therefore, no impacts on vegetation communities of special concern are anticipated in those 

states. Federally and state-listed plant species potentially occurring within the project area are discussed 

in section 4.7.

4.5.4.1 Natural Communities of Louisiana

The LDWF, Louisiana Natural Heritage Program (LNHP) (2009) recognizes 68 natural 

vegetative communities across 6 ecoregions in Louisiana. During coordination with Lake Charles LNG

and Trunkline, the LNHP identified three of these natural communities, including Coastal Prairie, 

Flatwoods Pond, and Western Acidic Longleaf Pine Savannah, as being recorded in the vicinity of the 

proposed Non-Liquefaction Facilities. None of these natural communities were identified within the 

project work areas during field surveys. Therefore, we would not anticipate impacts on these 

communities during construction or operation of the Lake Charles Liquefaction Project.

Although not identified by the LNHP during project-related coordination, field surveys conducted 

by Trunkline and Lake Charles LNG identified two forested wetland communities within the project area 

that meet the description of recognized natural vegetative communities, Bayhead Swamp and Bottomland 

Hardwood Forest. Bayhead Swamp is associated with depressional areas, drainages, or headwaters with 

typical overstory species including bald cypress, laurel oak, longleaf pine, red maple, slash pine, swamp 

blackgum, sweet bay magnolia, and sweetgum (LNHP, 2014). Potential Bayhead Swamp communities 

occur adjacent to Arceneaux Bayou (MP 1.2) and at MP 5.3 along the Mainline Connector route (a total 

of 11.2 acres impacted) and adjacent to Bayou Lacassine (MP 178.5) along the Mainline 200-3 Loop 

(0.4 acre impacted). A total of 4.5 acres of Bayhead Swamp would be located within the pipeline 

easements; of this, 2.7 acres would be permanently converted to emergent wetland to facilitate pipeline 

inspections and maintenance, the remaining 1.8 acres would be allowed to naturally revegetate. 

Trunkline would minimize impacts on potential Bayhead Swamp communities by using the HDD method 

to install the Mainline 200-3 Loop beneath the potential communities adjacent to Bayou Lacassine and to 

install portions of the Mainline Connector beneath this community adjacent to Arceneaux Bayou. See 

additional discussion of forested wetland impacts and proposed mitigation measures in sections 4.4.2.2 

and 4.5.2.2. 
4-50

Bottomland Hardwood Forest occurs in floodplains of large river systems and contains a mix of 

broadleaf deciduous, needleleaf deciduous, and evergreen trees and shrubs (LNHP, 2014). Those forested 

wetlands systems impacted by the project that are not classified as forested mosaic wetlands or potential 

Bayhead Swamps meet the description of Bottomland Hardwood Forest. These natural communities 

occupy a total of 29.6 acres within the liquefaction facility site, along the Mainline Connector, and at 

three meter stations (Columbia Gulf–Egan, TETCO–Allen, and Texas Gas–Woodlawn). Of this, 

22.8 acres would be located within the liquefaction facility and meter station sites, which would be 

permanently converted to industrial use; 1.7 acres would be located within the permanent easement 

associated with the Mainline Connector and would be converted to emergent wetland due to routine 

maintenance associated with pipeline operation; the remaining 5.1 acres would be allowed to revegetate 

to pre-existing conditions. See additional discussion of forested wetland impacts and proposed mitigation 

measures in sections 4.4.2.2 and 4.5.2.2.

4.5.4.2 Kisatchie National Forest

The Kisatchie National Forest, which surrounds the Pollock Compressor Station, contains 

recovering populations of the longleaf pine as well as other pine (e.g., loblolly, slash, and shortleaf pine) 

and hardwood species (USDA, 2014). The proposed project would not affect vegetative communities 

within the Kisatchie National Forest; all activities at the Pollock Compressor Station would be conducted 

inside existing facility boundaries.

4.6 WILDLIFE AND AQUATIC RESOURCES

4.6.1 Wildlife Resources

Wildlife species inhabiting the project area are characteristic of the habitats provided by the plant 

communities that occur in the vicinity of the project. Detailed information on vegetation types present

within the project area is included in section 4.5. Habitat types were identified based on aerial 

photography and field surveys. Aquatic resources are discussed in section 4.6.2. Protected wildlife 

species are discussed in section 4.7.

4.6.1.1 Existing Wildlife Habitat

The wildlife habitat types present within the project area include wetlands, upland forest, open 

water, open land, and agricultural land. Typical wildlife occurring within these habitat types is 

described below.

Wetland habitats present within the project area include palustrine emergent, palustrine scrubshrub, palustrine forested wetlands, and palustrine forested wetland mosaics. Wetlands support a diverse 

ecosystem that provides nutrients, cover, shelter, and water for a variety of terrestrial and aquatic wildlife 

species, including waterfowl, wading birds, raptors, mammals, reptiles, and amphibians. Typical wildlife 

associated with palustrine forested and scrub-shrub wetlands include white-tailed deer (Odocoileus 

virginianus), raccoon (Procyon lotor), river otter (Lutra canadensis), armadillo (Dasypus novemcinctus), 

wood thrush (Hylocichla mustelina), common yellowthroat (Geothlypis trichas), wood duck (Aix sponsa), 

prothonotary warbler (Protonotaria citrea), wild turkey (Meleagris gallopava), red-shouldered hawk 

(Buteo lineatus), and cottonmouth (Agkistrodon piscivorus). Typical wildlife associated with palustrine 

emergent wetlands include the species listed above, as well as rice rat (Oryzomys palustris), least bittern 

(Ixobrychus exilis), green heron (Butorides striatus), red-winged blackbird (Agelains phoeniceus), 

southern leopard frog (Rana utricularia), bullfrog (Rana catesbeiana), mud turtle (Kinosteron sp.), 

chicken turtle (Deirochelys reticularia), and pygmy rattlesnake (Sistrurus miliarius) (Sutton and Sutton, 

1985; Burt and Grossenheider, 1976; Peterson, 1980).
4-51

Upland forest habitat present within the liquefaction facility site and ACWs is composed of large 

stands of mature, mixed hardwood forest. In addition, mixed pine-hardwood forest, natural pine stands, 

and managed pine plantations are present within areas that would be affected by the Non-Liquefaction 

Facilities. Tree and shrub layers provide shelter and foraging habitat for various bird species and larger 

mammals. Organic material on the forest floor provides habitat for various invertebrates, reptiles, smaller 

mammals, and amphibians. Mammals typically associated with upland forest habitat in the project area 

include the white-tailed deer, gray fox (Urocyon cinereoargenteus), gray squirrel (Sciurus carolinensis), 

cotton mouse (Sigmodon hispidus), and striped skunk (Mephitis mephitis). Typical bird species include 

the Carolina chickadee (Parus carolinensis), loggerhead shrike (Lanius ludovicianus), eastern kingbird 

(Tyrannus tyrannus), hairy woodpecker (Picoides villosus), brown-headed nuthatch (Sitta pusilla), pine 

warbler (Dendroica pinus), Northern bobwhite (Colinus virginianus), tufted titmouse (Parus bicolor), and 

wild turkey. Amphibians and reptiles include the rat snake (Elaphe obsolete), garter snake (Thamnophis 

sirtalis sirtalis), black racer (Coluber constrictor), pigmy rattlesnake (Sistrurus miliarius), and green tree 

frog (Hyla cinerea) (Sutton and Sutton, 1985; Burt and Grossenheider, 1976; Peterson, 1980).

Open water habitats present within the liquefaction facility site include the Industrial 

Canal/Turning Basin, 1 perennial stream, 2 intermittent streams, 1 pond, and 11 roadside drainages. Open 

water habitats associated with the Non-Liquefaction Facilities include 4 freshwater ponds, 16 perennial 

streams, 12 intermittent streams, 8 ephemeral streams, and 64 drainage ditches/canals. Typical wildlife 

associated with open water habitat includes wading birds, waterfowl, beavers, otters, nutria (Myocastor 

coypus), snakes, and other wildlife species dependent on an aquatic environment (see additional 

discussion in section 4.6.2). 

Open lands within the project area consist primarily of grasses, forbs, and shrubs. Mammals 

typically associated with open lands include white-tailed deer, striped skunk, eastern spotted skunk 

(Spilogale putorius), cotton mouse, armadillo, raccoon, and eastern harvest mouse (Reithrodontomys 

humulis). Bird species include northern bobwhite, eastern bluebird (Sialia sialis), dickcissel (Spiza 

americana), rusty blackbird (Euphagus carolinus), red-tailed hawk (Buteo jamaicensus), northern harrier 

(Circus cyaneus), American robin (Turdus migratorius), cattle egret (Bubulcus ibis), and red-winged 

black bird. Typical reptiles and amphibians include chorus frog (Pseudacris sp.), box turtle (Terrapene 

carolina carolina), rat snake, and garter snake (Sutton and Sutton, 1985; Burt and Grossenheider, 1976; 

Peterson, 1980).

Agricultural lands affected by the project include those used for the cultivation of crops such as 

rice, soybeans, and crawfish. Agricultural lands do not provide high quality habitat for cover or nesting, 

but do provide foraging opportunities for several species. Irrigation ditches, ponds, and flooded fields 

provide habitats for shorebirds, wading birds, and waterfowl. Many species capable of inhabiting open 

lands would also utilize agricultural lands. Typical mammal species observed foraging in agricultural 

lands in the project area include white-tail deer, striped skunk, eastern spotted skunk, cotton mouse, 

armadillo, raccoon, and eastern harvest mouse. Bird species observed on agricultural lands include redtailed hawk, northern harrier, American robin, cattle egret, red-winged black bird, and mourning dove. 

Typical amphibians and reptiles include rat snake, garter snake, and chorus frog (Sutton and Sutton, 1985; 

Burt and Grossenheider, 1976; Peterson 1980).

4.6.1.2 Impacts and Mitigation

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

Clearing of the liquefaction facility site and ACWs would affect a total of 574.7 acres of wildlife 

habitat, including 568.3 acres of vegetated habitat, as described in section 4.5.2.1 and summarized in 

table 4.5.2-1, and about 6.3 acres of open water habitat. Following construction, 251.6 acres of wildlife 

habitat would be permanently converted to industrial land for the new liquefaction facility, in which most 
4-52

of the vegetated and open water habitats would be replaced with surfacing materials such as concrete or 

gravel. The 322.9 acres of vegetated areas within the ACWs would not be restored to preconstruction 

elevations or contours and would be stabilized with graveled or vegetated surfaces. Therefore, although 

these areas are not within the operational footprint of the liquefaction facility, we anticipate that impacts 

on wildlife habitat within the ACWs would also be permanent. 

Impacts on wildlife from construction of the liquefaction facility would include displacement, 

stress, and direct mortality of some individuals. Potentially suitable cover, nesting, and foraging habitat 

for some wildlife species would be reduced due to clearing of vegetation. Individuals of smaller, less 

mobile wildlife such as reptiles and amphibians could be inadvertently injured or killed by construction 

equipment. More mobile wildlife such as birds and mammals may relocate to similar habitats nearby 

when construction activities commence. The permanent reduction in available habitat within the area as 

well as the influx of individuals to other nearby areas may increase population densities for certain 

species, resulting in increased inter- and intra-specific competition and reduced reproductive success of 

individuals. The greatest impact on wildlife habitat would result from the permanent conversion of about

420.3 acres of forested uplands and forested wetlands within the liquefaction facility site and ACWs, 

which would result in a permanent reduction in forested habitat in the general vicinity of the liquefaction 

facility, where the surrounding area is largely composed of developed, open, and agricultural lands. 

Based on final review and approval by the COE, Lake Charles LNG would provide compensatory 

mitigation for permanent impacts on the about 158.6 acres of forested wetland that would be permanently 

converted to upland; however, the loss of 261.7 acres of upland forest would not be mitigated.

Operation of the liquefaction facility would result in increased noise, lighting, and human activity 

that could disturb wildlife in the area. However, due to current industrial activities at the existing LNG 

terminal and other industrial facilities in the vicinity, most wildlife in the area are acclimated to the noise 

and artificial lighting associated with these activities. Therefore, we expect impacts due to noise, light, 

and human activity during operation of the liquefaction facility to be negligible. (See section 4.6.1.3 for 

further discussion of lighting at the liquefaction facility).

The proposed modifications at the existing LNG terminal would occur within the fenced 

industrial facility. The existing LNG terminal provides minimal wildlife habitat that would not be 

substantially affected by the proposed project activities with the exception of the work to be done in the 

Industrial Canal/Turning Basin as discussed in section 4.6.2.1.

To minimize project-related impacts on wildlife, Lake Charles LNG would implement our Plan 

and Procedures, as well as its SPAR Plan for volumes of materials not regulated by the EPA, and a SPCC 

Plan for materials regulated by the EPA (see additional discussion of these plans in section 4.3.2.2). In 

addition, the COE New Orleans District would require compensatory mitigation for wetland impacts that 

cannot be avoided (see section 4.4.4). Although the implementation of these mitigation measures would 

lessen impacts on wildlife species, we have determined that construction and operation of the proposed 

liquefaction facility would have long-term impacts on wildlife species due to the loss of forested habitat. 

Non-Liquefaction Facilities 

About 2.9 acres of open water wildlife habitat and 375.8 acres of vegetated wildlife habitat would 

be affected by construction of the Non-Liquefaction Facilities. The majority of the impacts on wildlife 

habitat would be associated with construction of the proposed pipeline facilities and construction and 

operation of the new and expanded aboveground facilities as discussed below. Proposed activities within 

existing facility boundaries (i.e., Longville, Pollock, Epps, and Shaw Compressor Stations; Mainline 100-

3 modifications, and some of the Mainline 200-1 modifications), as well as the use of the proposed 

contractor yard, would not affect wildlife habitat as these areas have undergone previous disturbance 

and/or have been graded and graveled. 
4-53

Pipelines and Calcasieu River HDD

Construction of the Mainline Connector and Mainline 200-3 Loop would result in both temporary 

and permanent impacts on wildlife and wildlife habitat. Construction would affect a total of 275.8 acres 

of vegetated wildlife habitat consisting of the vegetation communities described in section 4.5.2.1, and 

2.5 acres of open water habitat. Following construction, about 172.6 acres of temporary work areas 

would be allowed to revert to preconstruction condition, and about 103.2 acres would be retained as 

permanent, maintained right-of-way. The primary wildlife habitats affected by construction of the 

pipelines would be agricultural lands (61 percent), pine plantations (16 percent), and forested uplands 

(12 percent).

The impact of pipeline construction on terrestrial wildlife and wildlife habitats would vary 

depending on the type of habitat affected, the requirements of each species, the timing of construction, 

and types of construction techniques used. Noise and human disturbance during construction would 

cause most wildlife to avoid areas of active construction; however, this would be a short-term effect as 

construction activities proceed along the right-of-way. The greatest effect on wildlife habitat would result 

from cutting, clearing, and/or removal of existing vegetation, which would reduce the amount of available 

wildlife habitat in the project area and may result in direct mortality of less mobile wildlife such as small 

rodents and reptiles. Larger or more mobile wildlife, such as birds and large mammals, would relocate 

into adjacent similar habitats.

Following construction, disturbed areas would be restored, and the permanent right-of-way 

maintained, in accordance with our Plan and Procedures. The duration of impacts on terrestrial wildlife 

habitat would depend on the rate at which vegetation regenerates after construction. Agricultural lands 

would be available for replanting during the growing season immediately following pipeline construction. 

Open land and emergent wetland habitats would generally revegetate within 2 to 4 years after 

construction is completed. Open water habitats would revert to preconstruction condition shortly after the 

completion of in-water work (see section 4.6.2.2 for further discussion of impacts on aquatic resources). 

Therefore, impacts from construction and operation of the proposed pipelines on wildlife that use 

agricultural, open land, emergent wetland, and open water habitats would be short-term and minimal.

Impacts on affected forested habitat within temporary construction work areas would be long 

term because forested lands can take decades to regenerate. Species that use early successional 

communities may benefit from the clearing and revegetation process, as additional habitat of this type 

would be created during construction. Additionally, non-woody, early successional vegetation may 

provide seeds and foliage as food for small mammals and birds, as well as habitat for ground-nesting 

birds, mammals, and reptiles.

Within the permanent rights-of-way, upland forested habitat would be permanently converted to 

open land due to routine pipeline maintenance activities. The majority of forested wetland areas within 

the permanent rights-of-way would be permanently converted to either emergent or scrub-shrub wetlands 

because our Procedures do not allow routine vegetation clearing in wetlands. However, our Procedures 

do allow for the maintenance of a 10-foot-wide strip over the pipeline in an herbaceous state and selective 

cutting and removal of trees within 15 feet of the pipeline with roots that could compromise the integrity 

of the pipeline coating.

Impacts on forested habitat would be greatest along the greenfield Mainline Connector route, 

where the conversion of forested lands to open lands would result in some new forest fragmentation and 

create edge habitat. In the limited locations where the Mainline 200-3 Loop crosses forested land, the 

edge habitat would be shifted, but no new fragmentation would occur. Trees adjacent to the cleared areas 

would be exposed to windier conditions, which may increase the frequency of blowdowns.
4-54

Edge habitats are used by several wildlife species, such as white-tailed deer and various small 

mammals. Many species adapt well to this habitat shift and could take advantage of the edge habitats. 

Predatory species such as red-tailed hawk and coyote commonly use utility rights-of-way for hunting, and 

other species, such as eastern cottontail, northern bobwhite, mourning dove, eastern meadowlark, whiteeyed vireo, white-tailed deer, and American crow, would benefit from the transition to early successional 

habitat for foraging. Although the increase in edge habitat may be advantageous for some species, it 

could adversely affect interior forest species or species that prefer large tracts of unbroken forest. 

Additionally, nesting success may be denied or diminished for one annual breeding cycle for adult birds 

that normally breed in the area but would avoid it during construction activities. 

The slow regeneration of forested communities within temporary construction areas would result 

in the long-term reduction in forested habitat for species that use these communities. However, abundant 

similar habitats are available for wildlife adjacent to the proposed pipeline facilities. 

Land disturbing activities for the Calcasieu River HDD, which Trunkline would conduct as part 

of the Mainline 200-1 modifications, would occur within temporary workspace that is largely located 

within Trunkline’s existing pipeline easement and would affect about 30.0 acres including open land, 

inundated forest, and 0.3 acre of open water. Following construction, the temporary workspaces would 

revert to preconstruction condition. Impacts on wildlife habitat resulting from the Calcasieu River HDD 

would be largely similar to those described above. In particular, the noise and activity associated with 

HDD operations would cause wildlife to avoid the area during construction. 

Trunkline attempted to minimize crossing of forested land during routing and design of the 

Mainline Connector. In addition to the Calcasieu River HDD, Trunkline proposes to conduct five HDD 

crossings during construction of the pipelines (some of which would encompass more than one 

waterbody), which would minimize impacts on open water and adjacent riparian habitats. To further 

minimize impacts on wildlife and wildlife habitat, Trunkline would not maintain the rights-of-way 

between HDD entry and exit points. Additionally, the Mainline 200-3 Loop would be entirely collocated 

with an existing pipeline, and Trunkline would overlap the Mainline 200-3 Loop construction and 

permanent right-of-way with the existing pipeline right-of-way by 25 feet. With these measures and the 

implementation of the measures specified in our Plan and Procedures, we conclude that construction and 

operation of the proposed pipelines would not significantly affect wildlife. 

Aboveground Facilities and Modification of US 190 Meter 

Construction of the proposed aboveground facilities, including the work to be done at the existing 

US 190 meter station as part of the proposed Mainline 200-1 modifications, would affect a total of 

70.0 acres of vegetated wildlife habitat consisting of the communities described in section 4.5.2.1 and 

summarized in table 4.5.2-1. Impacts on wildlife and habitat during construction of the aboveground 

facilities would be similar to those described above for the pipelines. Following construction, about

54.2 acres of habitat would be permanently converted to industrial land for operation of the new and 

expanded facilities. 

Construction of Compressor Station 203-A would occur entirely within the permanent boundaries 

of this proposed new facility and would result in the permanent conversion of 45.6 acres of agricultural 

land to industrial use. Construction would require filling of a man-made agricultural canal; other 

drainages on the site would not be permanently affected because station piping would be installed beneath 

them, though availability of these features for use by wildlife would be limited during operation of the 

fenced facility. Although any habitat at the compressor station site would be permanently removed for 

most wildlife use due to the loss of vegetation and installation of security fencing, abundant agricultural 

habitat is available adjacent to the site. During operation, increased noise levels in the vicinity of the 
4-55

compressor station may result in avoidance of the area by wildlife until they become acclimated to the 

increase. 

Construction activities associated with new and modified meter stations, including the proposed 

modifications at the US 190 Meter Station, would impact a total of 24.4 acres of wildlife habitat. 

Following construction, 15.8 acres of temporary workspace would revert to preconstruction condition, 

and 8.6 acres at the new and expanded meter station sites would be permanently converted to industrial 

land. The majority of the impacts on wildlife habitat associated with these facilities would be on open 

and agricultural lands; however, construction activities at the Columbia Gulf–Egan Meter Station would 

also impact small amounts of forested habitat. Activities at each meter station site would affect relatively 

small amounts of wildlife habitat ranging from about 1.0 to 4.4 acres at any given site, would occur 

adjacent to existing maintained rights-of-way and facilities, and would be located in areas where 

surrounding habitat could accommodate the potential influx of displaced wildlife. 

Although individuals of some wildlife species would be affected by construction and operation of 

the proposed aboveground facilities, most impacts on wildlife would be short-term and limited 

predominantly to the construction period. With the implementation of our Plan and Procedures, and due 

to the fact that abundant similar habitat is available for wildlife adjacent to the affected areas, we 

conclude that construction and operation of the Non-Liquefaction Facilities would not have a significant 

impact on local wildlife populations or habitat.

4.6.1.3 Unique and Sensitive Wildlife Resources

Unique or sensitive wildlife resources, such as migratory birds, colonial waterbird nesting areas, 

and managed wildlife areas, may be present in the vicinity of the proposed project and are discussed 

below. Species protected under the ESA, BGEPA, and state endangered and threatened species 

regulations are discussed in section 4.7.

Migratory Birds

Migratory bird species nest in the United States and Canada during the summer months and then 

migrate south to the tropical regions of Mexico, Central and South America, and the Caribbean for the 

non-breeding season. Some species migrate from breeding areas in the north to the Gulf Coast for the 

non-breeding season. Migratory birds are protected under the MBTA and bald and golden eagles are 

additionally protected under the BGEPA. The MBTA prohibits the take or killing of individual migratory 

birds, their eggs and chicks, and active nests. The MBTA provides 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. Executive Order 13186 (January 2001) directs federal agencies to 

consider the effects of agency actions on migratory birds and determine where unintentional take is likely 

to have a measurable negative effect on migratory bird populations, and to avoid or minimize adverse 

impacts on migratory birds through enhanced collaboration with the FWS. Executive Order 13186 states 

that emphasis should be placed on species of concern, priority habitats, and key risk factors, and that 

particular focus should be given to addressing population-level impacts.

On March 30, 2011, the FWS and the Commission entered into a Memorandum of Understanding 

(MOU) that focuses on avoiding or minimizing adverse impacts on migratory birds and strengthening 

migratory bird conservation through enhanced collaboration between the two agencies. This voluntary 

MOU does not waive legal requirements under the MBTA, BGEPA, ESA, Federal Power Act, NGA, or 

any other statute and does not authorize the take of migratory birds.

In order to accurately identify bird species with the greatest conservation priority and stimulate 

action by federal/state agencies and private parties, the FWS Migratory Bird Office issued a report 
4-56

describing the Birds of Conservation Concern (BCC) (FWS, 2008a). The report identifies priority bird 

species at the national, regional, and Bird Conservation Region (BCR) levels. The Lake Charles 

Liquefaction Project is located within three BCRs, including BCR 37-Gulf Coastal Prairie, BCR 25-West 

Gulf Coastal Plain/Ouachitas, and BCR 26-Mississippi Alluvial Valley (FWS, 2008a). Appendix H 

identifies the BCC that have been documented or are cited as probable to occur in the vicinity of 

the project. 

Project Area in Relation to Migratory Bird Flyways

Migratory birds follow broad routes called flyways between breeding grounds in Canada and the 

United States and wintering grounds in Central and South America, and the Caribbean. Additionally, 

several species migrate from breeding areas in the north to winter along the Gulf Coast and remain 

throughout the non-breeding season. The proposed project is located within the Mississippi Flyway and 

along the eastern edge of the Central Flyway.

The Central and Mississippi Flyways both terminate at the Gulf Coast, making it one of the most 

important waterfowl areas in North America. Of the 650 species of birds known to occur in the United 

States, nearly 400 species occur along the Gulf Coast (Esslinger and Wilson, 2003). The Gulf Coast 

provides wintering and migration habitat for significant numbers of continental duck and goose 

populations that use both the Central and Mississippi Flyways. The coastal marshes of Louisiana, 

Alabama, and Mississippi regularly hold half of the wintering duck population of the Mississippi Flyway 

(Esslinger and Wilson 2003).

Impacts and Mitigation

The vegetative communities in the project area provide potential habitat for migratory bird 

species, including songbirds, waterbirds, and raptors. Mature mixed-pine forested habitats within the 

liquefaction facility and ACWs potentially provide large tracts of high quality nesting habitat for 

migratory birds. In an email dated November 27, 2012 regarding the proposed liquefaction facility site, 

the FWS commented that the site, which is mostly mature mixed pine hardwoods, is expected to provide 

nesting habitat for bird species of concern (i.e., brown-headed nuthatch (Sitta pusilla), Chuck-will’swidow (Antrostomus carolinensis), Kentucky warbler (Geothlypis formosa), and painted bunting 

(Passerina ciris)) (FWS, 2012). 

Construction of the liquefaction facility would result in the permanent loss of 420.3 acres of 

forested habitat, which would directly impact the available nesting and foraging habitat for migratory 

birds including the above-listed species of concern. Adjacent similar forested habitat is available north 

and west of the liquefaction facility site; however, the spatial extent of the habitat is limited. Lake 

Charles LNG would provide compensatory mitigation for impacts on forested wetlands, which would 

offset some of this habitat loss. Additionally, to minimize impacts from vegetation clearing on migratory 

birds, the FWS recommended that no habitat alteration work be performed during the nesting period 

(March 1 to July 31) (FWS, 2012). Lake Charles LNG and Trunkline stated that they would initiate 

clearing activities outside the nesting season. However, to further clarify their intent, we recommended in 

the draft EIS that Lake Charles LNG and Trunkline confirm they would not conduct any clearing during 

the migratory bird nesting period between March 1 and July 31 unless approved in writing by the FWS. 

In their May 14, 2015 response to this recommendation, Lake Charles LNG and Trunkline affirmed that 

all clearing of forested areas would be conducted outside of the specified migratory bird nesting season, 

and that if the construction schedule changes such that clearing during migratory bird nesting season is 

necessary, Lake Charles LNG and Trunkline would obtain written approval from FWS, prior to clearing.
4-57

Much of the vegetated land associated with the Non-Liquefaction Facilities is previously 

disturbed and/or currently maintained by mowing and other land management practices that reduce 

nesting habitat value. However, the undisturbed areas contain higher quality nesting habitat that would be 

more attractive to breeding bird species. Therefore, while the commitment to limit forest clearing to the 

non-nesting season would minimize impacts on migratory birds that nest in forested habitats, we also 

recommend that:

 If clearing during the migratory bird nesting season is necessary in non-forested 

vegetated habitat, Lake Charles LNG and Trunkline should consult with the FWS 

and file with the Secretary written documentation of FWS approval prior to 

construction in those areas.

During project operation, Trunkline would not conduct routine vegetation mowing or clearing 

over the full width of the permanent rights-of-way in uplands more frequently than every 3 years, and 

routine vegetation mowing or clearing would not occur during the majority of the migratory bird nesting 

season between April 15 and August 1 unless specifically approved in writing by the FWS. 

Other impacts on migratory birds and their habitat due to construction and operation of the 

project would be similar to impacts on general wildlife resources (see section 4.6.1.2). Additionally, birds 

could be affected by flaring and lights at the liquefaction terminal. Flaring would be required during 

startup of the liquefaction facility, which may require up to 1 month for each liquefaction train. During 

operation, use of the marine and emergency flares would only occur occasionally. The FWS has not 

raised flaring as an issue of concern in the area and we are not aware of any reported significant impacts 

of flaring on migratory birds in the project area. As a result, we believe that the temporary flaring during 

construction and the occasional flaring during operation would not represent a significant impact on 

migratory birds passing through the area. 

Many migratory birds use natural light from the sun, moon, and stars for navigation. Artificial 

lighting can hide natural light sources, having unknown effects on birds at the population level. Fatalities 

to avian species due to artificial light are well documented. Avian fatalities are associated with attraction 

to light sources, especially in low light, fog, and when there is a low cloud ceiling (Orr et al., 2013). The 

proposed liquefaction facility would require adequate lighting for operations and safety. Due to the 

presence of facility lighting at the existing LNG terminal, the overall increase in nighttime lighting during 

construction and operation of the liquefaction facility would be minor. Outdoor lighting at the 

compressor and meter stations would be limited and likely contain floodlights affixed to pole or building 

structures to facilitate operations work at night or during inclement weather. Security lighting for onground facilities and equipment would be down-shielded to keep light within the boundaries of the site, as 

recommended by the FWS, to minimize the effects of artificial lighting on migratory birds.

With the implementation of the mitigation measures described above, we conclude impacts on 

migratory birds would not be significant. 

Colonial Waterbird Nesting Areas

Colonial waterbirds, a subset of migratory birds, include a large variety of bird species that share 

two common characteristics: 1) they tend to gather in large assemblies, called colonies or rookeries, 

during the nesting season, and 2) they obtain all or most of their food from the water (FWS, 2002). 

Colonial waterbirds demonstrate nest fidelity, meaning that they return to the same rookery year after 

year. Rookeries are typically established in marshes or near the shores of ponds or streams. Although 

some colonial waterbirds will nest in developed areas (e.g., least terns), many waterbirds are wary of 

human activity (e.g., great blue heron and great egrets). 
4-58

During coordination with Trunkline in March 2013, the LDWF, LNHP identified records of two 

colonial waterbird nesting areas (or rookeries) within 1 mile of proposed workspaces associated with the 

Mainline 200-3 Loop and the NGPL–Lakeside Meter Station. As part of that communication, and again 

in its June 2, 2015 comments on the draft EIS, the LDWF stated that a field visit should be conducted no 

more than 2 weeks prior to commencing construction if construction would commence during nesting 

season. Based on the LDWF’s comments, the nesting period for colonies containing nesting wading birds 

(e.g., herons, egrets, night-herons, ibis, roseate spoonbills, anhingas, and cormorants) extends from

February 16 through August 31, and the nesting period for colonies containing gulls, terns, and/or black 

skimmers extends from April 2 through September 15. If the field visit identifies nesting colonies within 

400 meters (700 meters for brown pelicans) of the project, a survey should be performed to document the 

species present and the extent of the colonies, and further consultation with the LDWF should be 

conducted. The LDWF also stated that all project activity occurring within 300 meters of an active 

colony of any of the above-listed wading birds should be restricted to the non-nesting period 

(September 1 through February 15), and all project activity occurring within 400 meters (700 meters for 

brown pelicans) of an active colony of gulls, terns, or black skimmers should be restricted to the nonnesting period for those species (September 16 through April 1). 

In March 11, 2013 comments provided to Trunkline’s environmental consultant, the FWS also 

recommended that Lake Charles LNG and Trunkline contact the FWS and LDWF if surveys identify 

undocumented rookeries during nesting season. No rookeries were identified within the project area 

during environmental field surveys conducted during 2012, 2013, and 2014. To minimize disturbance of 

colonial nesting birds, the FWS stated that activities within 1,000 feet of a rookery should be restricted to 

non-nesting season (with the specific season depending on the species present). 

Trunkline and Lake Charles LNG stated that they would consult with the FWS and LDWF for 

guidance and recommendations in the event that an active rookery is observed within a distance expected 

to have a potential impact on the nesting species. To further clarify this commitment, we recommended 

in the draft EIS that the companies confirm that if construction would commence during the nesting 

season for colonial waterbirds, they would conduct field visits and consult with the FWS and LDWF as 

recommended by the agencies. In their May 22, 2015 response, Lake Charles LNG and Trunkline stated 

that the recorded waterbird colonies nearest to the project areas are approximately 1.2 miles northeast of 

MP 178.5 along the Mainline 200-3 Loop and approximately 1.7 miles from the NGPL–Lakeside Meter 

Station. Because these colonies are several miles inland, the companies stated that they are likely to 

contain wading birds. Therefore, Lake Charles LNG and Trunkline stated that if construction of the 

Mainline 200-3 Loop or the NGPL–Lakeside Meter Station would commence between February 16 and 

August 31, Trunkline would conduct a field visit within 2 weeks prior to starting construction and would 

consult with the FWS and LDWF if nesting colonies are found. To ensure that the FWS and LDWF 

recommendations are fully implemented, and further ensure that Trunkline implements appropriate 

mitigation if colonial waterbird nest surveys are required, we recommend that:

 Prior to construction of the Mainline 200-3 Loop and the NGPL–Lakeside Meter 

Station, Trunkline should file with the Secretary documentation that the FWS and 

LDWF are in agreement with Trunkline’s proposed approach for addressing 

colonial waterbirds, including a description of the final agreed-upon mitigation 

measures that Trunkline would implement if construction of these facilities would 

occur during the colonial waterbird nesting seasons identified by the FWS and 

LDWF. 

With this condition and the implementation of the measures recommended by the FWS and 

LDWF, we conclude that impacts on colonial waterbirds would be avoided. 
4-59

Managed Wildlife Areas 

No public or conservation lands have been identified within the proposed project area. Based on 

information from the LNHP, no wildlife management areas operated or managed by the LDWF are 

located within 0.25 mile of the project area. 

The closest National Wildlife Refuge (NWR) to the project is the Lacassine NWR, which is 

located 0.4 mile south of the NGPL–Lakeside meter station in Cameron Parish, Louisiana. The Lacassine 

NWR was established in 1937 as a refuge and breeding ground for migratory birds and other wildlife. 

Proposed activities at the NGPL–Lakeside meter station would occur within the existing facilities and in 

adjacent agricultural areas. Due to the distance between the meter station and the refuge, impacts on 

wildlife within the Lacassine NWR would be limited to increased noise during construction activities. 

Habitat between the two facilities is composed of forested wetland, which would likely buffer noise levels 

to less than significant levels. See section 4.8.4.2 for additional information on the Lacassine NWR. 

Although the Pollock Compressor Station is located on land owned by Trunkline, it is surrounded 

by the Kisatchie National Forest. Construction activities associated with the Pollock Compressor Station 

would be located entirely within the fenceline of the existing facility. In general, impacts on wildlife 

within the forest would be short term and similar to those described above (see section 4.6.1.2). Potential 

impacts on sensitive wildlife (e.g., red-cockaded woodpecker) within the Kisatchie National Forest are 

discussed further in section 4.7.1.1.

4.6.2 Aquatic Resources

4.6.2.1 Liquefaction Facility

Existing Aquatic Resources

All waterbodies within the project area support warmwater fisheries and, with the exception of 

the Industrial Canal/Turning Basin, which is estuarine, all waterbodies in the project area are freshwater. 

Of the waterbodies located within the liquefaction facility site, only the Industrial Canal/Turning Basin 

and the one perennial stream provide year-round habitat for aquatic resources; the remaining waterbodies 

(i.e., freshwater pond, intermittent streams, and drainage ditches) provide limited habitat value for aquatic 

resources due to restricted water flow regimes, which are likely dependent upon precipitation. 

In the vicinity of the proposed construction docks where dredging would occur, water depth 

within the Industrial Canal/Turning Basin is about 38 feet and substrates are composed mainly of 

estuarine subtidal unconsolidated bottom sediment. Unconsolidated sediments provide foraging habitat 

for benthic organisms and demersal fish and are designated as EFH for red drum, shrimp, reef fish, and 

coastal migratory pelagic species. EFH is discussed in section 4.6.3. Substrates within the Industrial 

Canal/Turning Basin are considered early successional due to frequent disturbance from maintenance 

dredging, propeller wash, and vessel traffic.

One perennial stream is located along the southern boundary of the proposed liquefaction facility 

site. This unnamed tributary to the Calcasieu River is about 6 feet deep and substrates are composed of 

freshwater unconsolidated bottom sediment. 

Representative fish species found in the project area are presented in table 4.6.2-1. Those species 

with a fishery classification of “estuarine” commonly occur in the Industrial Canal/Turning Basin, 

whereas those species with a fishery classification of “freshwater” are typical of perennial freshwater 

streams in the project area. 
4-60

TABLE 4.6.2-1

Representative Fish Species Potentially Occurring in the Vicinity of the Lake Charles Liquefaction Project

Common Name Scientific Name Estuarine/Freshwater

Shellfish

Blue crab Callinectes sapidus Estuarine

Brown shrimp Farfantepenaeus aztecus Estuarine

White shrimp Litopenaeus setiferus Estuarine

Finfish

Alligator gar Atractosteus spatula Freshwater

Black crappie Pomoxis nigromaculatus Freshwater

Blue catfish Ictalurus furcatus Freshwater

Channel catfish Ictalurus punctatus Freshwater

Common carp Cyprinus carpio Freshwater

Creek chubsucker Erimyzon oblongus Freshwater

Freshwater drum Aplodinotus grunniens Freshwater

Gafftopsail catfish Bagre marinus Estuarine

Golden shiner Notemigonus crysoleucas Freshwater

Green sunfish Lepomis cyanellus Freshwater

Largemouth bass Micropterus salmoides Freshwater

Mosquitofish Gambusia affinis Freshwater

Red drum Sciaenops ocellatus Estuarine

Redear sunfish Lepomis microlophus Freshwater

Redfin pickerel Esox americanus Freshwater

River carpsucker Carpiodes carpio Freshwater

Sheepshead Archosargus probatocephalus Estuarine

Spotted sucker Minytrema melanops Freshwater

Striped bass Morone saxatilis Freshwater

Striped mullet Mugil cephalus Estuarine

Warmouth Lepomis gulosus Freshwater

White bass Morone chrysops Freshwater

Yellow bullhead Ameiurus natalis Freshwater

No significant fisheries resources are located within the project area; however, recreational 

fishing occurs within the Industrial Canal/Turning Basin. Recreational fishing is discussed in additional 

detail in section 4.8.4.1. 

Impacts and Mitigation

Potential impacts on aquatic resources during construction and operation of the liquefaction 

facility include those associated with the two TCDs and berthing dock modifications, waterbody 

modifications and water withdrawals within the liquefaction facility area, ballast water exchanges, 

inadvertent spills, and barge traffic. 
4-61

Lake Charles LNG is not proposing to increase the authorized number or size of LNG carriers, 

and the associated impacts would not change. Therefore, these activities are not addressed in this EIS.

Temporary Construction Docks and Berthing Dock Modifications

Construction of the two TCDs and berthing dock modifications would require dredging a 

22.1-acre area in the Industrial Canal/Turning Basin, driving sheet piles, and installation of the docks’ 

surface features and berthing structure modifications. Potential impacts on aquatic resources due to these 

activities are described below.

Most fish species are highly mobile and would be expected to leave the vicinity of the project 

area during in- and over-water activities. However, dredging would result in direct mortality of benthic 

organisms such as mollusks and crustaceans within the dredge footprint. Slower, less mobile benthic 

invertebrates would also be directly affected, while larger, more mobile species, such as blue crab and 

redfish, would experience temporary displacement. Following construction activities, aquatic resources 

would be expected to return to the newly dredged area, which would be similar to the existing habitat, but 

would have an increased water depth of 43 feet (with an overdredge of 2 feet).

Dredging and pile driving activities would also temporarily increase noise, turbidity, and 

suspended solids within the water column, which can adversely affect fish eggs and juvenile fish survival, 

benthic community diversity and health, foraging success, and suitability of spawning habitat. 

Additionally, sediments in the water column could be deposited on nearby substrates, burying aquatic 

macroinvertebrates (an important food source for many species of fish). Impacts on aquatic resources due 

to increased turbidity and suspended solid levels would vary by species; however, the aquatic resources 

present within the project area are likely accustomed to regular fluctuations in noise and turbidity levels 

from industrial activity and regular maintenance dredging (every other year) within the existing Industrial 

Canal/Turning Basin. Further, Lake Charles LNG would use a cutter head suction dredge, which would 

minimize resuspension of sediments and the resulting increases in turbidity and suspended sediment 

levels. Due to the small volume of materials being dredged (about 26,000 cubic yards), short duration of 

dredging activities (30 days), and limited deepening of the existing open water habitat, we have 

determined impacts on aquatic resources from dredging would be localized, temporary, and minor. 

Studies have shown that the sound waves from pile driving may result in injury or trauma to fish, 

sea turtles, and other animals with gas-filled cavities, such as swim bladders, lungs, sinuses, and hearing 

structures (Abbott and Sawyer, 2002). The degree to which an individual fish exposed to sound waves 

would be affected depends on variables such as the peak sound pressure level and frequency as well as the 

species, size, and condition of the fish. Small fish are more prone to injury by intense sound waves then 

are larger fish of the same species.

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. NOAA Fisheries is currently developing guidelines for 

determining sound pressure level thresholds for fish and marine mammals. The agency’s interim 

guidelines use 150 dB re: 1 μPa as the threshold for behavioral effects on 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 

for the onset of injury to fish are a peak sound pressure of 206 dB re: 1 μPa regardless of fish size, a 

cumulative sound pressure level of 187 dB re: 1 μPa for fish 2 grams or greater, and a cumulative sound 

pressure level of 183 dB re: 1 μPa for fish of less than 2 grams (NOAA Fisheries, 2015; Stadlar and 

Woodbury, 2009; ICF Jones and Stokes, 2012). 
4-62

The intensity of the sound pressure levels produced during pile driving depends on a variety of 

factors such as the type and size of the pile, the substrate into which the pile is being driven, the depth of 

water, and the type of pile-driving equipment being used. Lake Charles LNG’s Construction Noise 

Assessment Report does not address anticipated underwater noise levels associated with pile driving 

within the liquefaction facility and with the installation of the steel sheet piling for the TCDs. In order to

allow for an accurate analysis of potential impacts on aquatic resources during pile driving, we 

recommended in the draft EIS that Lake Charles LNG file a description of the proposed in-water pile 

installation process, including the number and type of pile driver(s), duration of in-water pile driving 

activities, anticipated peak and cumulative underwater sound pressure levels, and measures proposed to 

minimize impacts on aquatic resources in the vicinity of on-land and in-water pile driving activities. In its

May 22, 2015 response, Lake Charles LNG indicated that this information is not yet available because it 

has not yet selected its construction contractors for the marine facilities and pile-installation techniques 

have not been finalized. Lake Charles LNG also noted that because the project is not expected to affect 

federally listed marine species and is not expected to result in significant adverse impact on EFH, it does 

not propose any measures to minimize impacts on aquatic resources in the vicinity of pile driving 

activities. 

While we agree that the project would not have a significant adverse impact on EFH and would 

not affect federally listed aquatic species (see sections 4.6.3 and 4.7, respectively), additional information 

is necessary to assess potential impacts of the project on aquatic species in the vicinity of the marine 

facilities. Therefore, we recommend that:

 Prior to construction, Lake Charles LNG should file with the Secretary, for review 

and written approval by the Director of OEP, a description of the proposed in-water 

pile installation process, including the number and type of pile driver(s) (e.g., impact

or vibratory hammer) and duration of in-water pile driving activities, and an 

analysis of anticipated peak and cumulative underwater sound pressure levels. If 

the analysis determines that pile driving activities would exceed a peak sound 

pressure of 206 dB re: 1 μPa or a cumulative sound pressure level of 

183 dB re: 1 μPa, Lake Charles LNG should provide a description of measures it 

would implement to minimize impacts on aquatic resources in the vicinity of on-land 

and in-water pile driving activities.

Over-water activities associated with installation of the Construction of the two TCDs and 

berthing dock modifications surfaces and modifications of the existing berthing docks may cause 

avoidance of the area by mobile species due to noise and movement, but this impact would be minor and 

temporary. During the 5-year project construction period, the two TCDs would create aquatic habitat in 

the form of additional hard substrate areas, allowing for the growth of attached organisms. Over-water 

dock structures may also provide a source of refuge for some aquatic species. Following construction of 

the liquefaction facility, the construction docks would be removed using shore-based equipment. Backfill 

material would be removed prior to extracting steel sheet piles, thereby minimizing impacts on aquatic 

resources associated with increased suspended sediment and turbidity levels in the water column. 

Although temporary avoidance of the area during dock removal activities is anticipated, this impact 

would be temporary and fisheries use of the area would revert to pre-project conditions upon completion 

of removal activities.

Waterbody Modifications and Water Withdrawals

Construction of the liquefaction facility would involve permanently filling 1 freshwater pond and 

2 intermittent waterbodies, armoring and realigning 1 perennial waterbody, and filling and replacing 

11 drainage ditches. Additionally, the perennial waterbody would be utilized as a water source for dust 
4-63

control and fill material additive during construction activities (see section 4.3.2.2). The perennial 

waterbody, an unnamed tributary to the Calcasieu River, is located along the southern boundary of the 

liquefaction facility and would be armored and realigned as part of the proposed stormwater system 

improvements. This waterbody has been historically altered and channelized and, therefore, offers 

minimal limnological or riparian function. Fish within the perennial waterbody and ponds at the time of 

water withdrawal could suffer from impingement or entrainment; those within the waterbodies during site 

preparation and dredged material placement are likely to suffer mortality. Following construction, 

fisheries use of the stream is expected to resume. 

As described above (see Existing Resources), only the perennial stream provides year-round 

habitat for aquatic resources; the remaining waterbodies provide limited habitat value due to restricted 

water flow regimes. Because these features offer limited resources for aquatic resources, project-related 

impacts would not be significant. 

Ballast Water

The effects of ballast water discharges on four ambient water quality parameters (temperature, 

pH, dissolved oxygen, and salinity) are described in section 4.3.2.2. Resident species within the 

Industrial Canal/Turning Basin are euryhaline (able to live in waters with a wide range of salinity) and are 

well adapted to natural spatiotemporal variation in salinity and oxygen levels. This adaptability and the 

ability to move over a short distance to more suitable conditions minimizes adverse impacts on aquatic 

resources associated with ballast water discharges.

U.S. regulations require that all vessels equipped with ballast water tanks that enter or operate in 

U.S. waters maintain a vessel-specific ballast water management plan and assign responsibility to the 

master or appropriate official to understand and execute the ballast water management strategy for that 

vessel (33 CFR 151.2026). Under these requirements, vessels must implement strategies to prevent the

spread of exotic aquatic nuisance species in U.S. waters. These strategies include retaining ballast water 

on board, minimizing uptake or discharge at certain times or locations, and exchanging ballast water from 

coastal sources with mid-ocean seawater. Vessels that have operated outside of the U.S. Exclusive 

Economic Zone must either retain their ballast water on board or undergo a mid-ocean (greater than 

200 nautical miles from shore and at a water depth greater than 6,562 feet) ballast water exchange in 

accordance with applicable regulations. Lake Charles LNG would discharge all ballast water under 

federal oversight and in accordance with federal regulations. 

With the implementation of the mandatory practices required by the Coast Guard, we conclude

that the impacts on aquatic resources from ballast water discharges associated with the project would not 

be significant.

Inadvertent Spills

Aquatic resources could be adversely affected by an accidental spill or leak of hazardous 

materials into or near a waterbody. To minimize potential impacts on aquatic resources, Lake Charles 

LNG would implement its SPAR and SPCC Plans (see section 4.2.3). Implementation of the SPAR and 

SPCC Plans would minimize the potential for releases to occur. Should a spill or leak occur, 

implementation of the response measures in the SPAR and SPCC Plans would reduce response time and 

ensure appropriate cleanup, thereby minimizing impacts on aquatic resources.
4-64

Barge Traffic 

Construction of the liquefaction facility would require an average of five barge deliveries per day 

over the 5-year construction period. Increases in barge traffic have the potential to increase shoreline 

erosion and suspended sediment concentrations due to increased wave activity. Because the barges would

transit existing, industrial channels and are typically slow moving vessels, project-related increases in 

shoreline erosion or suspended sediment concentrations within the Industrial Canal/Turning Basin would 

not be significant. 

4.6.2.2 Non-Liquefaction Facilities

Existing Aquatic Resources

Table F-2 in appendix F lists the waterbodies that would be crossed or affected by the NonLiquefaction Facilities as well as the proposed crossing method and water quality classification for each 

feature. All of the waterbodies affected by the Non-Liquefaction facilities are freshwater and classified as 

warmwater fisheries. Of the 104 waterbodies impacted, 84 are classified as intermittent, ephemeral, or 

drainages/canals, which typically provide limited value or marginal fishery habitat due to restricted water 

flow regimes. The remaining 20 waterbodies are classified as either perennial or open water and have the 

potential to provide suitable habitat for and support aquatic resources. Representative fish species found 

in these waterbodies are presented in table 4.6.2-1. No sensitive fish species, fisheries of concern, or EFH 

have been identified within the waterbodies affected by the Non-Liquefaction Facilities.

Impacts and Mitigation

Impacts on aquatic resources resulting from construction and operation of the Non-Liquefaction 

Facilities could include loss or modification of habitat, increased sedimentation and turbidity levels, and 

alteration of vegetative cover resulting from waterbody crossings; entrainment of small organisms during 

withdrawal of hydrostatic test water; and introduction of pollutants as a result of inadvertent spills or 

leaks of hazardous materials. These impacts are discussed in the following sections. 

Waterbody Crossings

As detailed in section 4.3.2.2, construction of the proposed new pipelines and the Calcasieu River 

HDD would require crossing 16 perennial streams and 4 ponds that provide suitable habitat for aquatic 

resources. Trunkline proposes to conduct six HDD operations that would cross 8 of these perennial 

waterbodies. The remaining perennial waterbodies and the ponds would be crossed using the open-cut 

method (see table 4.3-2). 

Installing the proposed pipelines using the HDD method would avoid or minimize impacts on 

fisheries, fish habitat, and other aquatic resources within and adjacent to waterbodies unless an 

inadvertent release of drilling mud were to occur. An inadvertent release of drilling mud into a stream 

would affect water quality and could impede fish movement, potentially resulting in stress, injury, and/or 

direct mortality of fish present in the vicinity of the release. If an inadvertent release occurs, Trunkline

would implement the corrective action and cleanup measures outlined in its HDD Contingency Plan to 

minimize potential impacts on aquatic resources (see appendix D), including the installation of berms, silt 

fence, and/or hay bales to prevent silt-laden water from flowing into waterbodies, or in the event of an inwater release, the use of temporary dams to isolate the drilling fluid and vacuum trucks to remove the 

released drilling mud.
4-65

Use of the open-cut crossing method would result in temporary loss or modification of aquatic 

habitat, increase in sedimentation and turbidity levels, and alteration of vegetative cover. The majority of 

fish present within the waterbody at the time of construction activities would likely be displaced to similar 

adjacent habitats up or down stream; however, stress, injury, or death of individual fish may occur. 

Increased suspended sediment and turbidity levels may cause degradation of benthic and spawning habitat 

and decreased dissolved oxygen levels within and downstream of the crossing location. This temporary 

increase in suspended solids would decrease rapidly following the completion of instream activities. The 

clearing of riparian vegetation during construction may reduce shade and cover until revegetation occurs, 

indirectly causing a temporary increase in water temperature in localized areas. Clearing would be 

adjacent to existing rights-of-way at the three open-cut perennial waterbody crossings along the Mainline 

200-3 Loop, which would minimize changes in water temperature because much of the vegetation is 

already maintained in a low-growing, herbaceous state and does not provide shade over the waterbodies.

Trunkline would implement the measures outlined in our Procedures to minimize impacts on 

waterbodies and aquatic resources during pipeline construction. These mitigation measures include 

reduced workspace areas near waterbodies, establishing buffers to prevent run-off from entering 

waterbodies, installing erosion control devices, and completion of instream construction activities within 

24 or 48 hours, depending on crossing length. Once construction is complete, streambeds and banks 

would be restored to their preconstruction conditions and contours to the maximum extent practicable, 

which would aid in preventing erosion and minimize long-term impacts on aquatic resources. 

Construction of Compressor Station 203-A would require the installation of piping beneath four 

drainage canals using the open-cut method and permanent filling of one 660-foot-long agricultural canal. 

Additionally, construction of the proposed new Columbia Gulf–Egan Meter Station would require 

installation of station piping beneath an intermittent waterbody using the open-cut method and installation 

of culverts within two drainage ditches to facilitate access to the meter station site. As noted above, these 

surface waters provide limited value for aquatic resources; therefore impacts would not be significant.

Due to the relatively small number of crossings, limited construction workspace and duration, and 

implementation of the mitigation measures described above, we anticipate that the project would have 

minimal and localized impacts on aquatic resources.

Hydrostatic Testing

Prior to placing the Non-Liquefaction Facilities into service, each component would be 

hydrostatically tested to ensure its integrity. Hydrostatic test water would be withdrawn from both 

surface waterbodies and municipal sources, as described in table 4.3.2-5. The water withdrawal process 

could entrain fish eggs and juvenile fish located near the intake hose. Trunkline would screen intake 

hoses at surface water intakes to eliminate or minimize the entrainment of fingerling and small fish during 

water withdrawal. Trunkline would regulate the timing, rate, and volume of hydrostatic test water 

withdrawals to maintain ambient downstream flow in the waterbodies from which hydrostatic test water 

would be withdrawn. 

Hydrostatic test water would contact only new pipe and Trunkline has stated that it does not plan 

to add chemicals to the water. After testing is completed, the hydrostatic test water would be discharged 

to well-vegetated uplands and/or using energy dissipation devices to regulate the discharge rate and 

minimize the potential for erosion, streambed scour, suspension of sediments, and excessive stream flow. 

Therefore, impacts on aquatic resources due to hydrostatic testing would be temporary and negligible. 
4-66

Accidental Spill or Leak of Hazardous Materials

Aquatic resources could be adversely affected by an accidental spill or leak of hazardous 

materials into or near a waterbody. As described in section 4.3.2.2, Trunkline would implement projectspecific SPAR and SPCC Plans to minimize the potential for releases to occur. Should a spill or leak 

occur, implementation of the response measures in the SPAR and SPCC Plans would reduce response 

time and ensure appropriate cleanup, thereby minimizing impacts on aquatic resources.

4.6.3 Essential Fish Habitat

4.6.3.1 Regulatory Background

The MSA (Public Law 94-265 as amended through October 11, 1996) was established, along 

with other goals, to promote the protection of EFH during the review of projects to be conducted under 

federal permits, licenses, or other authorities that affect or have the potential to affect such habitat. EFH 

is defined in the MSA as those waters and substrate necessary to fish for spawning, breeding, feeding, or 

growth to maturity. Federal agencies that authorize, fund, or undertake activities that may adversely 

impact EFH must consult with 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 NEPA, the Fish and Wildlife 

Coordination Act, and the ESA in order to reduce duplication and improve efficiency (50 CFR 

600.920(e)). 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 an EIS). 

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:

 a description of the proposed action; 

 an analysis of the effects (including cumulative effects) of the proposed action on 

EFH, managed fish species, and major prey species; 

 the federal agency’s views regarding the effects of the action on EFH; and

 proposed mitigation, if applicable.

3. EFH Conservation Recommendations – After reviewing the EFH Assessment, NOAA 

Fisheries should provide recommendations to the action agency regarding measures that 

can be taken by that agency to conserve EFH.

4. Agency Response – Within 30 days of receiving the recommendations, the action agency 

must respond to NOAA Fisheries. The action agency may notify NOAA Fisheries that a 

full response to the conservation recommendations would be provided by a specified 

completion date agreeable to all parties. The response must include a description of 

measures proposed by the agency to avoid, mitigate, or offset the impact of the activity 

on EFH.
4-67

The FERC proposes to incorporate EFH consultation for the Lake Charles Liquefaction Project 

with the interagency coordination procedures required under NEPA. As such, we requested that NOAA 

Fisheries consider the draft EIS as our EFH Assessment.

4.6.3.2 Essential Fish Habitat within the Project Area

Between 1979 and 1987, the Gulf of Mexico Fishery Management Council (GMFMC) prepared 

fishery management plans (FMP) for seven marine groups within the Gulf of Mexico: reef fish, migratory 

pelagic fish, red drum (Sciaenops ocellatus), shrimp, spiny lobster (Panulirus argus), stone crab 

(Menippe adina and Menippe mercenaria), and corals. Each FMP has been amended at least several 

times since then. One important amendment that applied to all seven FMPs occurred in 1998 and 

involved the identification of EFH for each group. All estuarine systems of the Gulf (e.g., Calcasieu 

River estuary) are considered EFH, which is managed by the GMFMC (GMFMC, 2010). 

The GMFMC (2005) designated the Calcasieu River estuary and surrounding waters as EFH for 

four groups of finfish and shellfish, namely red drum, shrimp, reef fish, and coastal migratory pelagics 

(NOAA Fisheries, 2013). The only area classified as EFH within the project area is the Industrial 

Canal/Turning Basin. Two categories of EFH are present within this area: mud substrates and estuarine 

water column.

The mud substrates in and near the Industrial Canal/Turning Basin are composed of sub-tidal 

unconsolidated sediments. This EFH type serves as important nursery and feeding habitat for many fish 

and the invertebrates they feed on (e.g., worms and mollusks living on and in the sediments). Estuarine 

water column habitat serves as EFH for several species and their prey at various life stages by providing 

suitable habitat for spawning, breeding, and foraging. The community composition of both the mud 

substrates and estuarine water column within the Industrial Canal/Turning Basin remain in an early 

successional stage due to maintenance dredging being conducted every other year, propeller wash from 

passing vessels, and natural sedimentation. 

4.6.3.3 Impacts and Mitigation

As described in section 4.6.1.2, construction of the TCDs and berthing dock modifications would 

require dredging an about 22.1-acre area, which would remove the existing benthic community within the 

dredge footprint. Construction of the TCDs and dredging activities would also temporarily increase 

noise, turbidity, and suspended solids within the water column, which can adversely affect fish eggs and 

juvenile fish survival, benthic community diversity and health, foraging success, and suitability of 

spawning habitat. Additionally, sediments in the water column could be deposited on nearby substrates, 

burying aquatic macroinvertebrates (an important food source for many species of fish). However, due to 

the small volume of materials being dredged (about 26,000 cubic yards), short duration of in-water 

disturbance, limited deepening of the existing estuarine water column, and ongoing maintenance 

dredging within the Industrial Canal/Turning Basin, these impacts are expected to be localized, 

temporary, and minor.

As non-federal parties assisting the FERC in meeting its obligations under the MSA, Lake 

Charles LNG coordinated with NOAA Fisheries’ Southeast Regional Office, and on March 7, 2014, 

requested concurrence that the project would have no effect on EFH and that further consultation under 

the MSA is not warranted. In a March 13, 2014 email, NOAA Fisheries concurred with the determination 

that the dock work and related activity in the vicinity of the Turning Basin would not result in significant 

adverse impact on EFH. Based on the largely temporary nature of project-related impacts and 

concurrence from NOAA Fisheries’ Southeast Regional Office, we have determined that the project 

would not have a significant adverse impact on EFH. In a letter dated May 21, 2015, NOAA Fisheries 

concurred with our determination and confirmed that no further EFH consultation is required.
4-68

4.7 THREATENED, ENDANGERED, AND OTHER SPECIAL STATUS SPECIES

Federal agencies are required under Section 7 of the ESA, as amended, to ensure that any actions 

authorized, funded, or carried out by the agency would not jeopardize the continued existence of a 

federally listed threatened or endangered species, or result in the destruction or adverse modification of 

the designated critical habitat of a federally listed species. As the lead federal agency, the FERC is 

required to coordinate with the FWS and NOAA Fisheries to determine whether federally listed 

threatened or endangered species or designated critical habitat are found in the vicinity of the project, and 

to determine the proposed action’s potential effects on those species or critical habitats. 

For actions involving major construction activities with the potential to affect listed species or 

designated critical habitat, the lead federal agency must prepare a BA and submit its BA to the FWS 

and/or NOAA Fisheries. If the action would adversely affect a listed species, the federal agency must 

also submit a request for formal consultation. 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. 

As required by Section 7 of the ESA, we requested that the FWS accept the information provided 

in the draft EIS as the BA for the project. Further, we requested concurrence with our findings of effect 

for the federally listed species in table 4.7-1. The FWS concurred with our findings on July 16, 2015 as 

discussed in section 4.7.1. Consequently, our consultation with the FWS under Section 7 of the ESA is 

concluded. As described below, we have determined that the project would have no effect on listed 

species under the jurisdiction of NOAA Fisheries; therefore, no formal section 7 consultation between the 

FERC and NOAA Fisheries is required.

Lake Charles LNG and Trunkline, acting as the FERC’s non-federal representatives, initiated 

informal consultation with the FWS Ecological Services Field Offices in Louisiana, Arkansas, and 

Mississippi and with NOAA Fisheries. As part of this effort, the FWS confirmed that the proposed 

project activities within Trunkline’s existing facilities and easements in Louisiana would be covered 

under Trunkline’s existing Blanket Clearance (dated January 9, 2014) (FWS, 2014a; FWS, 2014b). With 

certain conditions, the existing Blanket Clearance authorizes Trunkline to perform minor and routine 

pipeline construction and maintenance activities under the FERC’s jurisdiction within the State of 

Louisiana (FWS, 2014a). 

Lake Charles LNG and Trunkline also coordinated with the LNHP regarding state-listed or other 

special status species or habitat within 10 miles of the project area in Louisiana, and with the Mississippi 

Department of Wildlife, Fisheries, and Parks and Arkansas Natural Heritage Commission regarding the 

project components in Mississippi and Arkansas, respectively. Federally and state-listed species, as well 

as species that are candidates or proposed for listing, potentially occurring in the project area are 

identified in table 4.7-1.

Based on a review of publicly available information, agency correspondence, and field surveys, a 

total of 28 federally and state-listed threatened and endangered, candidate, and proposed species occur in 

parishes and/or counties impacted by the project. In addition, critical habitat has been designated for the 

Louisiana black bear in Richland and West Carroll Parishes, Louisiana. We have determined that the 

project would have no effect on 23 of the 28 federally and/or state-listed species, is not likely to cause the 

jeopardy of 1 proposed species, and would not contribute to the trend toward federal listing for 

2 candidate species. Table 4.7-1 summarizes the potential for the project to affect these species and the 

rationale for our determinations. Because the project would not affect these species, they are not 

discussed further in this EIS. Further discussion of one federally listed species and one state-listed 

species and our assessment of potential impacts are provided in sections 4.7.1 and 4.7.2.
4-69

TABLE 4.7-1 

Federally and State-listed Species Potentially Occurring in the Vicinity of the Lake Charles Liquefaction Project

Common Name

Scientific Name

Federal

Statusa

State 

Statusa

Parish/

Countyb Project Components Determination of Effect and Comments

Birds

Bald eagle

Haliaeetus 

leucocephalus

DL E BL

BD

CS

RL

Shaw Compressor Station

Longville Compressor Station, Transco Ragley Meter 

Station, US 190 Meter Station Mod., MLV 202

Liquefaction Facilities, Mainline Connector, Mainline 200-

3 Loop, 203-A Compressor Station, LCLNG Export Meter 

Station, Kinder Morgan–Lake Charles Meter Station, 

Texas Gas–Woodlawn Meter Station, Calcasieu River 

HDD, 100-foot Overhead Crossing

Gulf Crossing–Perryville Meter Station, MEP–Perryville 

Meter Station

Impacts would not be significant

Nesting typically occurs in mature trees (e.g., bald 

cypress, sycamore, willow) in or near cypress/tupelo 

swamps, fresh to intermediate marshes, or open water. 

Suitable habitat is present within the project area adjacent 

to major river crossings (e.g., Lacassine and Calcasieu 

Rivers). No bald eagles or their nests were identified 

during field surveys. In the event an active bald eagle 

nest is identified within 660 feet of a project area prior to 

construction, Trunkline would notify and consult with the 

FWS and LDWF with respect to the National Bald Eagle 

Management Guidelines.

Brown pelican

Pelecanus 

occidentalis

DL E CA NGPL–Lakeside Meter Station Impacts are not anticipated

The species is largely restricted to coastal waters for 

foraging and nesting. No suitable habitat is present in or 

adjacent to the project area.

Interior least tern 

Sterna antillarum 

athalassos

E E BL

CH

GA

WA

Shaw Compressor Station

Mississippi Barrel West 

Pollock Compressor Station

Mississippi Barrel East

No effect

Nesting occurs on barren or sparsely vegetated beaches, 

bays, estuaries, lagoons, lakes, and rivers. No suitable 

habitat is present in or adjacent to the project area.

Piping plover

Charadrius melodus

T - CA

CH

NGPL–Lakeside Meter Station

Mississippi Barrel West

No effect

Nesting occurs on wide, flat, open, sandy beaches. No 

suitable habitat is present in or adjacent to the project 

area.

Red-cockaded 

woodpecker

Picoides borealis

E E AL

BD

CS

GA

TETCO–Allen Meter Station

Longville Compressor Station, Transco Ragley Meter 

Station, US 190 Meter Station Mod., MLV 202

Liquefaction Facilities, Mainline Connector, Mainline 200-

3 Loop, 203-A Compressor Station, LCLNG Export Meter 

Station, Kinder Morgan–Lake Charles Meter Station, 

Texas Gas–Woodlawn Meter Station, Calcasieu River 

HDD, 100-foot Overhead Crossing

Pollock Compressor Station 

Not likely to adversely affect

Species occurs in open, park-like stands of mature pine 

forest. Suitable habitat is present adjacent to the project 

area near the Pollock Compressor Station. Forested

habitat within the fenced boundary of the station would 

not be cleared, and construction would be limited to 

previously disturbed areas of the site. Additionally, work 

in this area would be conducted in accordance with 

Trunkline’s existing Blanket Clearance for work in 

existing, previously disturbed workspaces; therefore, 

adverse impacts on the species are not anticipated. 

Suitable habitat is not present elsewhere within the 

project area.
4-70

TABLE 4.7-1 (cont’d)

Federally and State-listed Species Potentially Occurring in the Vicinity of the Lake Charles Liquefaction Project

Common Name

Scientific Name

Federal

Statusa

State 

Statusa

Parish/

County b Project Components Determination of Effect and Comments

Red knot

Calidris canutus

P - CA NGPL–Lakeside Meter Station Not likely to jeopardize the continued existence

The species breeds in Alaska and Canada and may 

overwinter on coastlines of the Gulf of Mexico. Wintering 

habitat occurs along seacoasts and consists of tidal flats 

and beaches. No suitable wintering habitat is present in 

or adjacent to the project area.

Sprague’s pipit

Anthus spragueii

C - AC

AL

CA

CS

JD

RL

Columbia Gulf–Egan Meter Station

TETCO–Allen Meter Station

NGPL–Lakeside Meter Station

Liquefaction Facilities, Mainline Connector, Mainline 200-

3 Loop, 203-A Compressor Station, LCLNG Export Meter 

Station, Kinder Morgan–Lake Charles Meter Station, 

Texas Gas–Woodlawn Meter Station, Calcasieu River 

HDD, 100-foot Overhead Crossing

Mainline Connector, Mainline 200-3 Loop, Tennessee–

Kaplan Meter Station

Gulf Crossing–Perryville Meter Station, MEP–Perryville 

Meter Station

Project would not contribute to a trend toward federal 

listing

The species breeds in native prairie of the Great Plains. 

Wintering habitat in southern Louisiana consists of native 

prairie; this community type does not occur within or 

adjacent to the project area.

Terrestrial Mammals

Louisiana black bear

Ursus americanus 

Iutelous

T

c

, CH - RL

WA

WC

Gulf Crossing–Perryville Meter Station, MEP–Perryville 

Meter Station

Mississippi Barrel East 

Epps Compressor Station

No effect

The species primarily inhabits large, undisturbed 

contiguous tracts of bottomland hardwood forest and 

utilizes a variety of habitat types including marshes and 

upland forests. Within the species’ range, neither suitable 

habitat nor designated critical habitat are present within or 

adjacent to the project area. The nearest designated 

critical habitat to the project area is about 5.9 miles 

southeast of the Epps Compressor Station. 

Northern long-eared 

bat

Myotis 

septentrionalis

T

d

- GA

RL

Pollock Compressor Station

Gulf Crossing–Perryville Meter Station, MEP–Perryville 

Meter Station

No effect

The species hibernates in caves and abandoned mines 

during the winter and roosts in trees during summer 

months. Within the species’ range, suitable habitat is not 

present in or adjacent to the project area.
4-71

TABLE 4.7-1 (cont’d)

Federally and State-listed Species Potentially Occurring in the Vicinity of the Lake Charles Liquefaction Project

Common Name

Scientific Name

Federal

Statusa

State 

Statusa

Parish/

County b

Project Components Determination of Effect and Comments

Terrestrial Reptiles

Louisiana pine snake

Pituophis ruthveni

C C BD

GA

Longville Compressor Station, Transco Ragley Meter 

Station, US 190 Meter Station Mod., MLV 202

Pollock Compressor Station

Project would not contribute to a trend toward state or 

federal listing 

The species inhabits fire-maintained, longleaf pine 

savannah with sandy, well-drained soils and herbaceous 

ground cover. This community type does not occur in the 

project area. 

Fish

Gulf sturgeon

Acipenser 

oxyrinchus desotoi

T T CA NGPL–Lakeside Meter Station No effect

This anadromous fish spawns in large, free-flowing 

freshwater rivers with hard substrates composed of sand, 

rock, or rubble in spring and forages in lower rivers during 

summer months before returning to coastal waters during 

the winter. No waterbodies with suitable habitat would be 

impacted by the project.

Pallid sturgeon

Scaphirhynchus 

albus

E E BL

CH

GA

WA

Shaw Compressor Station

Mississippi Barrel West 

Pollock Compressor Station

Mississippi Barrel East

No effect

The species is restricted to main channel habitats in the 

Mississippi River and its large tributaries, neither of which 

would be impacted by the project.

Mussels

Fat pocketbook

Potamilus capax

E - BL

WA

Shaw Compressor Station

Mississippi Barrel East

No effect

The species occurs in perennial rivers with sand, mud, 

and silt substrates. Within the species’ range, suitable 

habitat would not be impacted by the project. 

Louisiana pearlshell

Margaritifera 

hembeli

T - GA Pollock Compressor Station No effect

The species occurs in clear, moderately swift-flowing, 

perennial streams with stable substrate. Within the 

species’ range, suitable habitat would not be impacted by 

the project. 

Sheepnose Mussel

Plethobasus 

cyphyus

E - WA Mississippi Barrel East No effect

The species occurs in large streams with moderately swift 

currents and inhabits shallow waters with course sand 

and gravel substrates. Within the species’ range, suitable 

habitat would not be impacted by the project. This 

species is no longer included in the FWS Information, 

Planning, and Conservation system Trust Resources List 

for Washington County. 
4-72

TABLE 4.7-1 (cont’d)

Federally and State-listed Species Potentially Occurring in the Vicinity of the Lake Charles Liquefaction Project

Common Name

Scientific Name

Federal

Statusa

State 

Statusa

Parish/

County b

Project Components Determination of Effect and Comments

Plants

American chaffseed

Schwalbea 

americana

E E AL

BD

TETCO–Allen Meter Station

Longville Compressor Station, Transco Ragley Meter 

Station, US 190 Meter Station Mod., MLV 202

No effect

The species occurs in acidic, sandy or peaty soils within 

open pine flatwoods, pitch pine lowland forests, seepage 

bogs, palustrine pine savannahs, and other grass- and 

sedge-dominated plant communities. Within the species 

range, suitable habitat would not be impacted by the 

project.

Pondberry

Lindera melissifolia

E - BL

WA

Shaw Compressor Station

Mississippi Barrel East

No effect

The species occurs in seasonally flooded wetlands such 

as bottomland hardwood forests, forested swales, 

margins of shallow ponds, and bottoms of seasonal 

ponds. Within the species’ range, suitable habitat is not 

located in or adjacent to the project area.

Marine/Aquatic Mammals

West Indian manatee

Trichechus manatus

E - CA NGPL–Lakeside Meter Station No effect

Species inhabits in large, slow-moving rivers, river 

mouths, and shallow coastal areas such as coves and 

bays. No suitable habitat would be impacted by the 

project. 

Blue whale

Balaenoptera 

musculus

E - CA NGPL–Lakeside Meter Station No effect

The species inhabits the open ocean, which would not be 

impacted by the project.

Finback whale

Balaenoptera 

physalus

E - CA NGPL–Lakeside Meter Station No effect

The species inhabits the open ocean, which would not be 

impacted by the project.

Humpback whale

Megaptera 

novaeangliae

E - CA NGPL–Lakeside Meter Station No effect

The species inhabits the open ocean, coastal waters, and 

sometimes inshore areas such as bays. The project 

would not impact the species or its habitat.

Sei whale

Balaenoptera 

borealis

E - CA NGPL–Lakeside Meter Station No effect

The species inhabits the open ocean, which would not be 

impacted by the project.

Sperm whale

Physeter 

macrocephalus

E - CA NGPL–Lakeside Meter Station No effect

The species inhabits the open ocean, which would not be 

impacted by the project.
4-73

TABLE 4.7-1 (cont’d)

Federally and State-listed Species Potentially Occurring in the Vicinity of the Lake Charles Liquefaction Project

Common Name

Scientific Name

Federal

Statusa

State 

Statusa

Parish/

County b

Project Components Determination of Effect and Comments

Marine Reptiles

Green sea turtle

Chelonia mydas

T - CA NGPL–Lakeside Meter Station No effect

The species is restricted to coastal areas and the open 

ocean, which would not be impacted by the project.

Hawksbill sea turtle

Eretmochelys 

imbricate

E - CA NGPL–Lakeside Meter Station No effect

The species is restricted to coastal areas and the open 

ocean, which would not be impacted by the project.

Kemp’s Ridley sea 

turtle

Lepidochelys kempii

E - CA NGPL–Lakeside Meter Station No effect

The species is restricted to coastal areas and the open 

ocean, which would not be impacted by the project.

Leatherback sea turtle

Dermochelys 

coriacea

E - CA NGPL–Lakeside Meter Station No effect

The species is restricted to coastal areas and the open 

ocean, which would not be impacted by the project.

Loggerhead sea turtle

Caretta caretta

T - CA NGPL–Lakeside Meter Station No effect

The species is restricted to coastal areas and the open 

ocean, which would not be impacted by the project.

_____________________

a

Federal and state status includes: Endangered (E), Threatened (T), Proposed (P), Candidate (C), Delisted (DL), and Critical Habitat (CH). 

b Parishes/counties include Acadia (AC), Allen (AL), Beauregard (BD), Calcasieu (CS), Cameron (CA), Grant (GA), Jefferson Davis (JD), Richland (RL), and West Carroll 

(WC) Parishes, Louisiana; Bolivar (BL), and Washington (WA) Counties, Mississippi; and Chicot (CH) County, Arkansas.

C As noticed in Volume 80, No. 98 of the Federal Register (May 21, 2015), the FWS has proposed to remove the Louisiana black bear from the federal list of endangered and 

threatened wildlife species due to recovery. As of the development of this EIS, a public comment period is open (until July 20, 2015) for the draft post-delisting monitoring 

plan for this species.

d As of May 4, 2015, the federal status of the northern long-eared bat under the ESA was changed from Proposed to Threatened. 
4-74

4.7.1 Federally Listed Threatened and Endangered Species

Based on information obtained from the FWS and NOAA Fisheries, 23 federally listed threatened 

and endangered species, 1 species proposed for federal listing under the ESA, and 2 species that are 

candidates for listing under the ESA may occur within the parishes and/or counties affected by the 

project. Of these species, one federally listed endangered species (red-cockaded woodpecker) has the 

potential to be located in the vicinity of the project area and is discussed below. 

The red-cockaded woodpecker is a federally listed endangered bird that inhabits open, park-like 

stands of mature pine forests. Although the red-cockaded woodpecker nests in excavated cavities of 

mature pine trees, generally 70 years or older, they may also utilize pine or pine/hardwood stands of 

forest, woodland, or savannah 30 years or older for foraging habitat (FWS, 2003). They feed on a variety 

of insects and seasonal wild fruit. The decline of the red-cockaded woodpecker has been caused by the 

loss of old growth pine forest due to development, shorter rotation pine management, and the 

encroachment of hardwood mid-story in the pine forest due to fire suppression (FWS, 2008b). 

The red-cockaded woodpecker was identified as potentially occurring in Allen, Beauregard, 

Calcasieu, and Grant Parishes, Louisiana. Table 4.7-1 identifies the project components that could 

potentially impact affect this species. The LNHP (2013) indicated that suitable habitat may be present 

within the area and provided seven records of the red-cockaded woodpecker within 1 mile of the existing 

Pollock Compressor Station, which is located in Grant Parish. The closest record is located 0.1 mile 

southwest of the Pollock Compressor Station, within the Kisatchie National Forest. As described in 

section 4.6.1.3, the Pollock Compressor Station is located on land owned by Trunkline, but is surrounded 

by the Kisatchie National Forest. 

Although construction at the existing Pollock Compressor Station would be conducted within the 

existing fence lines where ground has been previously disturbed, any red-cockaded woodpeckers present 

in adjacent areas within the Kisatchie National Forest could be temporarily disturbed during construction 

activities. Trunkline has stated that work at the Pollock Compressor Station would be conducted in 

accordance with its existing Blanket Clearance, which includes stipulations for work conducted adjacent 

to habitat containing cavity trees used by red-cockaded woodpeckers (FWS, 2014a). 

Suitable habitat for the red-cockaded woodpecker was not identified during the field surveys in 

Allen, Beauregard, and Calcasieu Parishes. As part of Lake Charles LNG’s and Trunkline’s informal 

consultation with the FWS, the FWS confirmed in a November 27, 2012 email to TRC that activities at 

the liquefaction facility site would have no effect on federally listed species. In a March 31, 2014 

response to a subsequent letter from TRC, the FWS provided concurrence that by adhering to the Blanket 

Clearance’s stipulations for work at the Pollock Compressor Station, the project is not likely to adversely 

affect the red-cockaded woodpecker. Therefore, we have determined that the project may affect, but is 

not likely to adversely affect the red-cockaded woodpecker. As noted above, the FWS has concurred with 

this finding. However, because the Blanket Clearance only covers activities conducted in 2014, and to 

ensure that the stipulations do not materially change by the time the project goes to construction, we 

recommend that:

 Prior to construction, Trunkline should file with the Secretary an updated Blanket 

Clearance regarding federally listed species under the ESA and/or, if an updated 

Blanket Clearance is not issued or the stipulations of the Blanket Clearance change, 

updated documentation from the FWS that the previous determinations of effect are 

still current. Trunkline should not begin construction activities until it receives 

written notification from the Director of OEP that construction or use of mitigation 

may begin. 
4-75

4.7.2 State-Listed and Special Status Species

Based on information obtained from the LDWF and the Arkansas Game and Fish Commission, 

seven state-listed threatened or endangered species and one candidate species are listed within the 

parishes/counties impacted by the project (LDWF, 2014b; Arkansas Natural Heritage Commission, 

2010). Six of the state-listed species are also federally listed as threatened, endangered, or candidate 

species; these species are discussed in section 4.7.1 above. No state-listed species in Mississippi have 

been observed within counties that would be impacted by the project (Mississippi Museum of Natural 

Science, 2013). The project is expected to have no impact on one of the two non-federally listed species 

(brown pelican) due to the absence of suitable habitat within the project area. The remaining state-listed 

species, the bald eagle, is discussed below.

The bald eagle is state listed in Louisiana as endangered within several parishes crossed by the 

project. The bald eagle was federally delisted in 2007, but is still federally protected by the MBTA and 

by the BGEPA, which prohibits the “taking” of bald eagles, including their parts, nests, or eggs. The bald 

eagle winters and breeds throughout the United States near large waterbodies including rivers, lakes, and 

coastal areas. In Louisiana, bald eagles nest primarily in southeastern coastal areas but are also known to 

nest near large lakes in the northern and central portions of the state. Bald eagles forage on fish, 

waterfowl, carrion, nutria, and muskrats. Current threats to this species include loss of nesting habitat and 

disturbance to nesting pairs from humans during the nesting season (LDWF, 2014c).

No bald eagles or their nests were identified during field surveys conducted by Lake Charles 

LNG and Trunkline in September 2012 and March through May 2013. The LNHP (2013) has one record 

of a bald eagle within 10 miles of the project area, located about 2.5 miles southeast of MP 176.5 on the 

Mainline 200-3 Loop. The FWS (2013c) also indicated that floodplains associated with the Lacassine 

River may contain nesting bald eagles. Trunkline would utilize the HDD method to cross Lacassine 

Bayou and other large waterbodies, which would minimize the likelihood of project-related impacts on 

the bald eagle. Because no nesting sites were observed during field surveys, and the HDD method would 

be used to minimize potential impacts, we have determined the project would not significantly impact the 

bald eagle. In the event a bald eagle or its nest is identified within 660 feet of a project area prior to 

construction, Lake Charles LNG or Trunkline would notify the FWS and LDWF in accordance with the 

National Bald Eagle Management Guidelines.

4.8 LAND USE, RECREATION, AND VISUAL RESOURCES

4.8.1 Land Use

The Lake Charles Liquefaction Project would affect seven general land use types, including 

agricultural, industrial/commercial, open land, open water, forest, pine plantation, and residential. The 

definition of each land use type is as follows:

 Agricultural – includes active cropland, pasture, and/or hayfields;

 Industrial/Commercial – includes power or utility stations, manufacturing or industrial 

plants, paved areas, landfills, commercial or retail facilities, and roads; 

 Open Land – includes non-forested lands, maintained utility rights-of-way (including 

utility corridors), and herbaceous palustrine emergent or scrub-shrub wetlands; 

 Open Water – includes larger waterbody crossings such as lakes, ponds, and rivers, as 

well as the Industrial Canal/Turning Basin;

 Forest – includes upland or wetland forest including palustrine forested; 
4-76

 Pine Plantation – includes forested lands actively used for silviculture operations; and

 Residential – includes existing developed residential areas and planned residential 

developments. This may include large developments or residentially zoned areas that 

have been developed.

Table 4.8.1-1 shows the acreage impacts associated with construction and operation of the project 

components by land use type. As shown in the table, construction of the project would affect a total of 

about 1,516.3 acres, after which about 457.0 acres of land (for new aboveground facilities and pipeline 

easements) would be permanently required for operation of the project (as indicated in footnote c of 

table 4.8.1-1, this total includes 16.6 acres of the Mainline 200-3 Loop that would overlap an existing 

Trunkline pipeline easement, and 1.0 acre occupied by an existing mainline valve and access road that 

would be within the new Compressor Station 203-A facility boundary.) Of the remaining 1,059.3 acres, 

about 734.1 acres would be allowed to revert to preconstruction land use type. The other 325.2 acres 

consist of the ACWs that would be used during construction of the proposed liquefaction facility. Lake 

Charles LNG would not retain this land following construction; however, in accordance with landowner 

agreements, it would not restore the ACWs to preconstruction condition. These areas would be cleared 

and slightly elevated, making them more suitable for landowners’ future development plans.

4.8.1.1 Liquefaction Facility

Modifications to the existing LNG terminal would occur on industrial/commercial land within the 

existing 151.8-acre fenced facility. Additionally, Lake Charles LNG would dredge 22.1 acres of the 

Industrial Canal/Turning Basin during construction of the two TCDs (see section 4.3.2.2 for further 

discussion). The new liquefaction facility would be constructed on a 285.9-acre site located immediately 

to the north of and directly adjacent to the existing LNG terminal. The majority of the proposed 

liquefaction facility site (about 209.0 acres or 73 percent) is forest land, mostly classified as a 

wetland/upland mosaic or pimple-mound complex. The remainder of the site is mainly open land 

(36.4 acres or 13 percent) and industrial/commercial land (34.2 acres or 12 percent) consisting of existing 

office buildings and parking areas for the Alcoa-Lake Charles Facilities, and 6.3 acres (2 percent) of open 

water, most of which would be filled during site preparation. Lake Charles LNG would convert the entire 

liquefaction facility site to industrial use. About 211.2 acres (65 percent) of the ACWs required during 

construction is composed of forest land, followed by 111.6 acres (34 percent) of open land, 2.3 acres 

(about 1 percent) of industrial/commercial land, and 0.1 acre (less than 1 percent) of open water. 

Following construction of the liquefaction facilities, the ACWs would be stabilized as graveled or 

vegetated surfaces in accordance with landowner agreements. 

4.8.1.2 Non-Liquefaction Facilities

Proposed New Pipelines

Land use-related impacts associated with the Mainline Connector and Mainline 200-3 Loop 

pipelines would include the disturbance of existing uses within the construction rights-of-way and ATWS 

during construction and retention of an expanded or new permanent right-of-way for operation of 

the pipelines.
4-77

TABLE 4.8.1-1

Land Use Types and Acres Affected by Construction and Operation of the Lake Charles Liquefaction Projecta,b

Facility

Agricultural Residential

Industrial/

Commercial Open Water Open Land Forest

Pine

Plantation Total

Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper.

LIQUEFACTION FACILITY, LNG TERMINAL, AND ACW

Liquefaction Facility 0 0 0 0 34.2 34.2 6.3 6.3 36.4 36.4 209.0 209.0 0 0 285.9 285.9

LNG Terminal 0 0 0 0 151.8 0 22.1 0 0 0 0 0 0 0 173.9 0.0

ACW 0 0 0 0 2.3 0 0.1 0 111.6 0 211.2 0 0 0 325.2 0.0

Subtotal 0 0 0 0 188.3 34.2 28.5 6.3 148.0 36.4 420.2 209.0 0 0 785.0 285.9

NON-LIQUEFACTION FACILITIES

Pipelines

Mainline Connector

Right-of-way 78.7 32.0 0.9 0.3 2.7 1.3 1.9 1.1 4.6 2.2 22.6 12.9 39.6 18.0 150.9 67.8

ATWS 32.7 0.0 0.6 0.0 2.2 0.0 0.1 0.0 0.3 0.0 3.6 0.0 3.8 0.0 43.3 0.0

Subtotal 111.3 32.0 1.6 0.3 4.9 1.3 2.0 1.1 4.9 2.2 26.2 12.9 43.4 18.0 194.2 67.8

Mainline 200-3 Loopc

Right-of-way 36.9 24.8 0.0 0.0 1.3 1.0 0.5 0.4 7.9 5.7 7.1 6.6 0.7 0.7 54.4 39.3

ATWS 23.7 0.0 0.0 0.0 0.9 0.0 0.0 0.0 10.7 0.0 1.2 0.0 0.0 0.0 36.5 0.0

Subtotal 60.6 24.8 0.0 0.0 2.2 1.0 0.5 0.4 18.6 5.7 8.3 6.6 0.7 0.7 90.9 39.3

Mainline 100-3

Mississippi East 0.0 0.0 0.0 0.0 2.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.0 0.0

Mississippi West 0.0 0.0 0.0 0.0 1.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.6 0.0

Subtotal 0.0 0.0 0.0 0.0 3.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.6 0.0

Mainline 200-1

Calcasieu River HDD 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.3 22.9 0.0 7.1 5.7 0.0 0.0 30.3 6.0

U.S. 190 Meter 0.0 0.0 0.0 0.0 0.2 0.0 0.0 0.0 1.0 0.0 0.0 0.0 0.0 0.0 1.2 0.0

Subtotal 0.0 0.0 0.0 0.0 0.2 0.0 0.3 0.3 23.9 0.0 7.1 5.7 0.0 0.0 31.5 6.0
4-78

TABLE 4.8.1-1 (cont’d)

Land Use Types and Acres Affected by Construction and Operation of the Lake Charles Liquefaction Project a,b

Facility

Agricultural Residential

Industrial/

Commercial

Open

Water

Open

Land Forest

Pine

Plantation Total

Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper.

Contractor Yard

Right-of-way 0.0 0.0 0.0 0.0 20.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 20.8 0.0

Aboveground Facilities

New Compressor Station

203-A

c

45.6 45.6 0.0 0.0 1.0 1.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 46.6 46.6

Modifications to Existing Compressor Stations

Longville (existing) 0.0 0.0 0.0 0.0 44.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 44.5 0.0

Pollock (existing) 0.0 0.0 0.0 0.0 78.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 78.4 0.0

Epps (existing) 0.0 0.0 0.0 0.0 41.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 41.9 0.0

Shaw (existing) 0.0 0.0 0.0 0.0 62.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 62.9 0.0

Subtotal 0.0 0.0 0.0 0.0 227.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 227.8 0.0

New Meter Stations

LCLNG Exportd0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Kinder Morgan–Lake 

Charles

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.4 1.5 0.0 0.0 0.0 0.0 2.4 1.5

Columbia Gulf–Egan 1.5 0.6 0.0 0.0 0.0 0.0 0.0 0.0 1.6 0.8 0.4 0.2 0.0 0.0 3.5 1.6

Gulf Crossing–

Perryville

0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2.5 1.2 0.0 0.0 0.0 0.0 3.0 1.2

MEP–Perryville 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 4.4 2.1 0.0 0.0 0.0 0.0 4.4 2.1

Subtotal 2.0 0.6 0.0 0.0 0.0 0.0 0.0 0.0 10.9 5.6 0.4 0.2 0.0 0.0 13.3 6.4

Modifications to Existing Meter Stations

NGPL–Lakeside 2.9 0.3 0.0 0.0 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 3.2 0.3

TETCO–Allen 0.0 0.0 0.0 0.0 0.2 0.0 0.0 0.0 4.0 1.8 0.0 0.0 0.0 0.0 4.2 1.8

Texas Gas–

Woodlawn

0.0 0.0 0.0 0.0 0.3 0.0 0.0 0.0 1.6 0.0 0.1 0.0 0.0 0.0 1.9 0.0

Tennessee–Kapland0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0

Transco Ragley 0.0 0.0 0.0 0.0 0.7 0.0 0.0 0.0 1.3 0.0 0.0 0.0 0.0 0.0 2.0 0.0

Subtotal 2.9 0.3 0.0 0.0 1.5 0.0 0.0 0.0 6.9 1.8 0.1 0.0 0.0 0.0 11.4 2.1
4-79

TABLE 4.8.1-1 (cont’d)

Land Use Types and Acres Affected by Construction and Operation of the Lake Charles Liquefaction Project a,b

Facility

Agricultural Residential

Industrial/

Commercial

Open

Water

Open

Land Forest

Pine

Plantation Total

Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper.

Total for 

Aboveground 

Facilities

50.4 46.5 0.0 0.0 230.3 1.0 0.1 0.0 17.8 7.4 0.5 0.2 0.0 0.0 299.0 55.0

Access Roads

Mainline Connector <0.1 0.0 0.0 0.0 49.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.0 49.9 0.0

Mainline 200-3 Loop 1.8 0.0 0.0 0.0 8.5 0.0 0.0 0.0 0.0 0.0 0.1 0.0 0.0 0.0 10.4 0.0

Mainline 200-1 0.0 0.0 0.0 0.0 20.7 0.0 <0.1 0.0 6.7 0.0 0.1 0.0 0.0 0.0 27.5 <0.1

Meter Stations 0.0 0.0 0.0 0.0 1.8 1.7 0.0 0.0 1.7 1.4 0.0 0.0 0.0 0.0 3.5 3.0

Subtotal 1.8 0.0 0.0 0.0 80.8 1.7 0.0 0.0 8.5 1.4 0.2 0.0 0.1 0.0 91.3 3.1

Total for NonLiquefaction 

Facilities

224.2 103.3 1.6 0.3 342.7 4.9 2.8 1.8 73.6 16.7 42.2 25.3 44.2 18.8 731.3 171.1

PROJECT TOTALS 224.2 103.3 1.6 0.3 531.0 39.1 31.3 8.1 221.6 53.1 462.4 234.3 44.2 18.8 1,516.3 457.0

____________________

a

The numbers in this table have been rounded for presentation purposes. As a result, the totals may not reflect the sum of the addends. 

b Operational impacts shown for existing aboveground facilities to be modified, expanded, or affected during construction only include new operational impacts that would 

result from the proposed project (i.e., increases in existing operational footprint).

c Although included for completeness (to represent full acreage permanently encumbered by the new facilities), new operational impacts shown for the Mainline 200-3 Loop 

would actually be 16.6 acres less than those depicted in this table due to overlap with the existing pipeline right-of-way, and the new operation impacts shown for 

Compressor Station 203-A would be 1.0 acre less that those depicted because existing MLV 203-A and an associated access road would be within the new facility 

boundaries.

d

Impacts for the LCLNG Export and Tennessee–Kaplan Meter Stations are included in the impacts shown for the liquefaction facility and Mainline 200-3 Loop, respectively.
4-80

Mainline Connector

The proposed 11.4-mile-long, 42-inch-diameter Mainline Connector would be constructed on 

newly created right-of-way. During construction of the Mainline Connector, Trunkline would generally 

use a 125-foot-wide construction corridor, consisting of 50 feet of permanent right-of-way for operation 

of the pipeline and 75 feet of temporary construction workspace. The construction right-of-way would be 

reduced within wetlands as discussed in section 4.4.2.2. Construction would also require the use of 

ATWSs at road, wetland, and waterbody crossings to provide extra space for construction activities and 

excavated materials storage. The predominant land use types affected by construction of the pipeline, 

including the construction right-of-way and ATWS, would be agricultural (111.3 acres), pine plantation 

(43.4 acres), and forest land (26.2 acres), followed by open and industrial/commercial land (4.9 acres 

each), residential land (1.6 acres), and open water (2.0 acres). Land uses within the permanent right-ofway include 32.0 acres of agricultural land, 18.0 acres of pine plantation, 12.9 acres of forest land, 

2.2 acres of open land, 1.3 acres of industrial/commercial land, 1.1 acres of open water, and 0.3 acre of

residential land.

Mainline 200-3 Loop

The entire 6.5-mile-long, 24-inch-diameter Mainline 200-3 Loop would be collocated with an 

existing Trunkline pipeline right-of-way. During construction of the Mainline 200-3 Loop, Trunkline

would use a 75-foot-wide construction right-of-way, consisting of 50 feet of permanent right-of-way and 

25 feet of temporary construction workspace, as well as ATWS at road, wetland, and waterbody 

crossings. Twenty-five feet of the permanent right-of-way would overlap the existing permanent 

easement (16.6 acres). The predominant land use types affected by construction of the pipeline, including 

the construction right-of-way and ATWS, would be agricultural (60.6 acres) and open land (18.6 acres), 

followed by forest (8.3 acres), industrial/commercial land (2.2 acres), pine plantation (0.7 acre), and open 

water (0.5 acre). Land uses within the permanent right-of-way include 24.8 acres of agricultural land, 

6.6 acres of forest land, 5.7 acres of open land, 1.0 acre of industrial/commercial land, 0.7 acre of pine 

plantation, and 0.4 acre of open water.

Proposed Pipeline Modifications

Mainline 100-3

The Mainline 100-3 modifications would occur within the existing facility boundaries and require 

temporary disturbance of 3.6 acres of industrial/commercial land. No new permanent right-of-way would 

be required for operation of the modified facilities.

Mainline 200-1

Workspace for the Calcasieu River HDD would include 22.9 acres of open land, 7.1 acres of 

forest land, and 0.3 acre of open water, much of which would be within an existing Trunkline pipeline 

right-of-way. About 6.0 acres would comprise new permanent right-of-way, consisting of forest and open 

water. Impacts of the new permanent right-of-way between the HDD entry and exit points would be 

minimal, and would be limited to the cutting of a small path using non-mechanized equipment and foot 

traffic to lay the tracing wires during HDD construction if necessary. This area would not be maintained 

during operation of the pipeline. 

Construction of the U.S. 190 Meter Station modifications would require a total of 1.2 acres, 

including the existing facility and adjacent ATWSs. Construction would affect 0.2 acre of 

industrial/commercial land and 1.0 acre of open land. Following construction, the ATWSs would revert 
4-81

to preconstruction condition and use and the modified meter station would continue to operate within the 

facility’s existing 0.3-acre footprint. 

Aboveground Facilities

Compressor Stations

Construction and operation of proposed new Compressor Station 203-A would require a total of 

46.6 acres of land, including 45.6 acres of agricultural land and 1.0 acre of industrial/commercial land that 

includes existing MLV 203-A and an associated access road. All of the affected agricultural land would 

be converted to commercial/industrial land use during operation of the new facilities including the 

compressor station, permanent right-of-way for suction/discharge piping, and permanent access road. 

Modifications to the four existing compressor stations would occur within the fenced boundaries 

of the existing station sites, affecting a total of 227.8 acres of industrial/commercial land. Following 

construction, these facilities would continue to operate within the existing facility boundaries; no 

additional land would be acquired or permanently maintained for these modifications.

Meter Stations

Construction activities required for the proposed modifications to the five existing meter stations, 

excluding the modifications to the access roads, would disturb 11.4 acres including 6.9 acres of open land, 

2.9 acres of agricultural land, 1.5 acres of industrial/commercial lands, and 0.1 acre of forest land. After 

construction, operation of the Texas Gas–Woodlawn and Transco-Ragley Meter Stations would continue 

within the existing boundaries of those facilities, and the temporary workspace required for construction 

would revert to preconstruction condition and use. The Tennessee–Kaplan Meter Station would be 

operated within the Mainline 200-3 Loop right-of-way. The modifications at the NGPL–Lakeside and 

TETCO–Allen Meter Stations would increase those stations’ permanent operational footprints by 0.3 acre 

(agricultural land) and 1.8 acres (open land), respectively.

The new LCLNG Export Meter Station would be located in the southeast corner of the 

liquefaction facility and would not require additional land for construction or operation. Construction of 

the new Kinder Morgan–Lake Charles, Columbia Gulf–Egan, Gulf Crossing–Perryville, and MEP–

Perryville Meter Stations would affect 13.3 acres of land, including 10.9 acres of open land, 2.0 acres of 

agricultural land, and 0.4 acre of forest land. About 6.4 acres, including 5.6 acres of open land, 0.6 acre 

of agricultural land, and 0.2 acre of forest land would be permanently converted to industrial/commercial 

land use for operation of these new facilities. The temporary construction areas outside of the fenced 

facilities would be restored to preconstruction conditions in accordance with the FERC Plan and 

Procedures.

2

Contractor Yard

Trunkline would use one contractor yard, consisting largely of graveled surface with some grassy 

areas, to support construction activities. Use of this yard would temporarily affect 20.8 acres of 

industrial/commercial land and Trunkline’s activities would be consistent with previous uses. The yard 

would be allowed to revert to preconstruction condition and use after construction is complete.

 

2 The FERC Plan and Procedures can be viewed on the FERC website at http://www.ferc.gov/industries/gas/enviro/plan.pdf and 

http://www.ferc.gov/industries/gas/enviro/procedures.pdf, respectively.
4-82

Access Roads

Existing roads would be used to gain access to the proposed liquefaction facility site and the 

existing LNG terminal during construction and operation of the proposed liquefaction facilities; therefore, 

no new access roads would be required for these facilities. 

A total of 29 temporary access roads, including 17 for the Mainline Connector and 12 for the 

Mainline 200-3 Loop, would be required to provide access to construction workspaces during 

construction of the pipelines. These temporary access roads would affect 60.3 acres of land, primarily 

within existing dirt paths (characterized in table 4.8.1-1 as industrial/commercial land) and agricultural

land, followed by minor impacts on forested land and pine plantation. Depending on site-specific 

conditions, some or all of the existing dirt paths would require improvement in order to accommodate the 

movement of equipment and materials to the construction right-of-way such as widening, grading, 

addition of gravel, or side trimming of vegetation. Access roads would generally be no more than 30 feet 

wide. 

Trunkline proposes to use eight temporary access roads during construction of the Calcasieu 

River HDD crossing (which is part of the Mainline 200-1 modifications). These access roads would 

affect 27.5 acres consisting predominantly of existing dirt roads or paths and existing pipeline right-ofway categorized as industrial/commercial and open land, as well as a small amount of forest land. A 

temporary access road would also be required for the proposed modifications at the Texas Gas–

Woodlawn Meter Station, which would affect 0.3 acre of open land. Trunkline would utilize an existing 

access road at the Transco-Ragley Meter Station during construction of the proposed modifications at that 

facility, affecting 0.1 acre of industrial/commercial land.

Construction of four new permanent access roads would be required for the Columbia Gulf–Egan, 

TETCO–Allen, Gulf Crossing–Perryville, and MEP–Perryville Meter Stations (see table 4.8.1-2). These 

permanent access roads would be constructed within industrial/commercial and open lands, permanently 

disturbing 3.1 acres, and would be maintained by project personnel during construction to provide 

continued access to the facilities. Additionally, Trunkline would require a small permanent access road, 

affecting less than 0.1 acre of industrial/commercial (an existing dirt path), at the U.S. 190 Meter Station. 

A permanent access road would also be constructed for Compressor Station 203-A; however, land use 

impacts for this road are included in the facility footprint.

A list of permanent access roads required for the project is provided in table 4.8.1-2. A full list of 

all access roads required for the project is provided in appendix I. 

TABLE 4.8.1-2

New Permanent Access Roads Associated With the Lake Charles Liquefaction Project

Facility/Access Road Proposed Modifications

Length

(feet)

New 

Permanent 

Impacts

(acres)

Land Use 

Affected

Meter Stations

Columbia Gulf–Egan Board road, gravel, grading, or side trimming 1,687.0 1.2 Open land

TETCO–Allen Board road, gravel, grading, or side trimming 796.0 0.6 Existing dirt path

Gulf Crossing–Perryville Board road, gravel, grading, or side trimming 335.0 0.2 Existing dirt path

MEP–Perryville Board road, gravel, grading, or side trimming 1,594.0 1.1 Existing dirt path

Mainline 200-1 Modifications

U.S. 190 Meter Station Board road, gravel, grading, or side trimming 7.0 <0.1 Existing dirt path

TOTAL 3.1
4-83

4.8.1.3 Land Use Impacts and Mitigation

Impacts on agricultural, industrial/commercial, open land, forested, pine plantation, and 

residential land uses are discussed below. Surface waters (open water) and wetlands are discussed in 

sections 4.3 and 4.4, respectively. 

Agricultural

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

No currently cultivated agricultural lands would be disturbed during construction or operation of 

the proposed liquefaction facility, ACWs, and existing LNG terminal modifications. However, prime 

farmland soils are present at the liquefaction facility and ACWs and would be permanently converted as a 

result of the project (see section 4.2). 

Non-Liquefaction Facilities

The proposed Non-Liquefaction Facilities would cross agricultural lands currently used as pasture 

lands, row crops (e.g., rice and soybean), or crayfish farming. The pasture lands within the right-of-way 

are primarily managed for cattle. Soils classified as prime farmland would be affected by the project (see 

section 4.2). However, no specialty crops would be affected during construction or operation of the 

proposed project facilities.

Construction of the Mainline Connector and Mainline 200-3 Loop would affect 171.9 acres of 

agricultural land within the construction right-of-way and ATWS. Impacts on these areas would include 

the temporary loss of production during and shortly after construction is completed. Impacts could also 

include damage to existing irrigation systems and soil rutting or compaction due to construction 

equipment. Typical cropping and planting procedures in a given agricultural field could also be affected. 

Trunkline would implement the FERC Plan (see section 2.6.3.5) to minimize impacts on 

agricultural lands. In agricultural lands, the pipeline would be installed via conventional trenching 

methods along with topsoil segregation. Prior to starting construction in agricultural areas, Trunkline

would coordinate with landowners to determine the location of existing drainage structures and irrigation 

facilities. Trunkline would maintain the flow of water through irrigation systems throughout construction 

if possible and coordinate any shut off with the affected parties. During construction, Trunkline would 

maintain the natural surface water flow patterns of fields by providing breaks in the stockpiles of topsoil 

and subsoil. In addition, flow would be maintained in drainage systems to prevent ponding in adjacent 

undisturbed areas. For the areas alternately used for growing rice and raising crayfish, the landowner(s) 

would be compensated for crop loss due to construction activities.

The permanent pipeline right-of-way for the Mainline Connector and Mainline 200-3 Loop would 

encompass 56.8 acres of agricultural land. Following construction, Trunkline would follow the 

restoration and revegetation practices outlined in the FERC Plan. Any soil rutting or compaction would 

be repaired prior to revegetation of the disturbed areas. Agricultural lands within the permanent right-ofway would be allowed to revert to their previous use except for limited areas of the pipeline right-of-way 

that would be routinely maintained. The temporary workspace and ATWSs would be allowed to revert to 

their prior vegetated state following the completion of construction. 

Construction of the new and modified aboveground facilities would affect 50.4 acres of 

agricultural land, resulting in impacts similar to those described above for the pipelines. Following 
4-84

construction, the temporary workspaces would be restored in accordance with the FERC Plan and allowed 

to revert to preconstruction use. A total of 46.5 acres of agricultural land would be permanently 

converted to industrial/commercial use for operation of the new Compressor Station 203-A and the new 

and expanded meter stations. 

Overall, with the implementation of the FERC Plan and Procedures and the other measures 

identified above, we believe construction of the proposed project would have a minor, mostly temporary 

impact on agricultural land use. Although there would be permanent impacts on agricultural lands 

associated with some of the aboveground facilities, we do not believe this would represent a significant 

impact on agricultural uses in the area.

Industrial/Commercial

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

Construction of the liquefaction facility and LNG terminal modifications, including the use of the 

ACWs, would affect 188.3 acres of industrial/commercial lands. The majority of this land consists of the 

existing 151.8-acre LNG terminal, and 34.2 acres of buildings, roads, and parking areas at the Alcoa-Lake 

Charles facility that would be acquired by Lake Charles LNG. The remaining 2.3 acres are within the 

ACWs and consist predominantly of existing roads. Construction impacts on these industrial/commercial 

areas during construction would include increased dust from exposed soils, construction noise, and traffic 

congestion. Dust and noise levels would be minimized as described in sections 4.11.1 and 4.11.2, 

respectively. Impacts associated with construction traffic are discussed in section 4.9.6. Following 

construction, the existing LNG terminal would revert to preconstruction use, and the entire 285.9-acre 

liquefaction facility site would be converted to industrial/commercial land use. In accordance with 

landowner agreements, the ACWs would not be restored to preconstruction condition, and the future land 

use of these areas would be determined by the landowners.

Non-Liquefaction Facilities

Construction and operation of the Mainline Connector and the Mainline 200-3 Loop would affect 

7.1 and 2.3 acres of industrial/commercial land, respectively, consisting largely of roads. Construction 

and operation of the new Compressor Station 203-A would affect 1.0 acre of existing 

industrial/commercial land containing a mainline valve and associated access road. As detailed in table 

4.8.1-1, construction of the proposed modifications at the existing Longville, Pollock, Epps, and Shaw 

Compressor Stations; the five existing meter stations; the Mainline 100-3 facilities; and the U.S. 190 

Meter Station would affect a total of 233.1 acres of existing industrial/commercial land. Following 

construction, all of these facilities would continue to operate within their existing facility boundaries, 

without the need for any additional land. During construction of the project, Trunkline would also use a 

20.8-acre contractor yard that is existing industrial/commercial land. Following construction, the yard 

would revert to preconstruction industrial/commercial land use. 

Impacts on industrial/commercial land during construction of the Non-Liquefaction Facilities 

would be temporary and could include increased noise, dust, and impacts on traffic flow. In addition to 

the mitigation measures described above, Trunkline would install the pipelines using horizontal bores or 

HDDs to avoid impacts on several roadways and traffic. To minimize traffic congestion, Trunkline

would encourage construction workers to leave their personal vehicles at the contractor yards and carpool

to the construction areas, where possible. Other potential impacts on transportation and proposed 

mitigation measures are discussed in detail in section 4.9.6. 
4-85

Based on the above discussion, we conclude that impacts of the project on industrial/commercial 

land would be minor.

Open Land

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

Open land at the liquefaction facilities primarily include palustrine emergent and scrub-shrub 

wetland areas, non-forested upland areas, and pasture lands located in the southeastern corner of the site 

and within ACWs located east of Tank Farm Road. Construction and operation of the liquefaction 

facility would permanently convert 36.4 acres of open land within the liquefaction facility site to 

industrial/commercial land. Use of the ACWs during construction would affect 111.6 acres of open land. 

As noted previously, Lake Charles LNG would not retain the ACWs for operation of the project facilities, 

but as requested by the landowners, these areas would not be restored to preconstruction condition. Lake 

Charles LNG would stabilize the ACWs with temporary and/or permanent erosion control devices, and 

upon demobilization from each ACW, the land would be turned back over to the landowner. 

Non-Liquefaction Facilities

Similar to the liquefaction facility, the open land associated with the Non-Liquefaction Facilities 

includes palustrine emergent and scrub-shrub wetland areas and non-forested upland areas. Construction 

of the Mainline Connector and the Mainline 200-3 Loop would affect a total of 23.5 acres of open land. 

Construction-related impacts on open land would include the removal of vegetation and disturbance of 

soils. Trunkline would minimize impacts on open land by implementing the measures in our Plan and 

Procedures.

Following construction, 15.6 acres of temporary workspace and ATWS would be allowed to 

revert to preconstruction condition. The 7.9 acres of open land that would remain within the permanent 

right-of-way would also be restored and allowed revert to preconstruction condition except for limited 

areas of the right-of-way that would be routinely maintained (i.e., mowed). 

Construction of the Mainline 200-1 modifications would affect 22.9 acres of open land, most of 

which includes existing pipeline right-of-way Trunkline would use as temporary workspace and ATWS 

for the Calcasieu River HDD. No additional open land would be retained as new permanent right-of-way. 

Additionally, construction of the new and modified meter stations would affect a total of 17.8 acres of 

open land. Following construction of these facilities, 7.4 acres of open land would be converted to 

industrial/commercial land for operation of the meter stations, and the remaining 10.4 acres would be 

restored and allowed to revert to preconstruction condition. 

With the exception of the open land that would be permanently converted to 

industrial/commercial land for operation of the new and expanded meter stations, construction-related 

impacts on open land would be predominantly temporary and short term and would be minimized by 

implementation of the FERC’s Plan and Procedures. 

Forest

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

Construction and operation of the proposed liquefaction facility would affect a total of 

420.2 acres of forest land, including 209.0 acres within the liquefaction facility site and 211.2 acres within 

the ACWs. The existing forested areas include forested wetlands and upland wooded areas as described 
4-86

in detail in section 4.5.1.1. All of the forest land within the liquefaction site would be permanently 

converted to industrial/commercial land. Impacts on forest land within the ACWs is also considered 

permanent because, as discussed previously, these areas would not be restored. Trunkline would be 

required to conduct compensatory mitigation for forested wetlands in compliance with COE requirements 

as discussed in section 4.4.4.

Non-Liquefaction Facilities

Forested land affected by construction and operation of the Non-Liquefaction Facilities include 

forested wetlands and upland forests of mixed hardwoods and conifers as described in detail in 

section 4.5.1.1. 

Construction of the Mainline Connector and the Mainline 200-3 Loop would involve clearing of 

34.5 acres of forest land, including 19.5 acres within the permanent right-of-way and 15.0 acres within 

temporary workspace and ATWS. Following construction, the majority of the forest land within the 

permanent right-of-way would be converted to open land as a result of maintenance activities. Although 

the temporary workspace and ATWS would be allowed to revert to preconstruction condition, the impact 

on forest land in these areas would be long term due to the long regeneration period for this type of 

vegetation. 

Construction and operation of the Calcasieu River HDD would affect an additional 7.1 and 

5.7 acres of forest land, respectively. Construction of the new and modified meter stations would affect 

0.5 and 0.2 acre, respectively. Impacts would be similar to those described above for the new pipelines; 

the forest land within the permanent meter station boundaries would be permanently converted to 

industrial/commercial land.

Trunkline would minimize impacts on forest land by implementing the measures in our Plan and 

Procedures, and by avoiding clearing between the HDD entrance and exit points at the Calcasieu River 

HDD. Moreover, Trunkline would be required to conduct compensatory mitigation for forested wetlands 

in compliance with COE requirements as discussed in section 4.4.4.

Pine Plantation

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

No pine plantations would be affected during construction or operation of the proposed 

liquefaction facility. 

Non-Liquefaction Facilities

Pine plantations are located along the Mainline Connector route and, to a lesser extent, the 

Mainline 200-3 Loop route. The pine plantations in these areas are dominated by varying age stands of 

loblolly pine and are used exclusively for timber production. Construction of the two pipelines would 

affect a total of 43.4 acres of pine plantation. 

The impacts on pine plantations would be similar to those described for forest land. No special 

construction techniques would be used within pine plantations unless requested by the landowners. The 

landowners would be allowed to replant the temporary construction right-of-way and ATWS (25.4 acres); 

however, this would be a long-term impact due to the relatively long growth period required for 

marketable timber. Timber production would be prohibited within the permanent right-of-way, resulting 

in permanent removal of 18.7 acres of land from timber production. Trunkline would compensate the 
4-87

landowners for the loss of timber production in accordance with the terms of individual easement 

agreements.

Residential

Liquefaction Facility, LNG Terminal, and Additional Construction Workspaces

Residential areas in the vicinity of the liquefaction facility are characterized as rural residential 

but occur at a denser rate than those near the other project components. A single residence within the 

proposed liquefaction facility site on the west side of Big Lake Road has been purchased by Lake Charles 

LNG. No other residential land uses are located within or immediately adjacent to any of the other 

project facilities, and no residential lands would be affected during construction or operation of the 

proposed liquefaction facility. 

Non-Liquefaction Facilities

The residential areas identified in the general vicinity of the Non-Liquefaction Facilities are low 

intensity rural residential land use characterized by widely spaced homes on large parcels. No residential 

structures or buildings are located within 50 feet of any of the Non-Liquefaction Facilities. The Mainline 

Connector pipeline route would cross one parcel identified as residential land just south of Gordon 

Dennison Road near MP 2.9. The closest construction workspace on this parcel would be about 320 feet

from the residence. The majority of the right-of-way and workspaces on this parcel would be in fields 

used for hay production, but one ATWS would cross a private road leading to the residence and farm 

structures (i.e., barns). Access to the residence and other structures would remain open during 

construction. Following construction, land within the temporary right-of-way and ATWS would be 

allowed to revert to preconstruction conditions. Although certain activities (e.g., tree planting or 

construction of permanent structures) would not be allowed, land within the permanent right-of-way 

would also revert to preconstruction conditions and use. Therefore, impacts on this residential land would 

be temporary and short term. 

4.8.2 Landowner and Easement Requirements

4.8.2.1 Liquefaction Facility

Lake Charles LNG currently leases 46 acres within the proposed liquefaction facility site. The 

property, owned by the Lake Charles Port Authority (also known as the Lake Charles Harbor and 

Terminal District), is adjacent to and north of the railroad that separates the existing LNG Terminal from 

the proposed liquefaction facility and the Alcoa property at Granger Road west to Big Lake Road. 

Current use of the land is the liquids metering facility in the southwest portion of the property and 

undeveloped mosaic. Lake Charles LNG plans to acquire 80 acres of land within the proposed 

liquefaction facility site from Alcoa. The remainder of the land required for the liquefaction facility and 

ACWs would be leased from the Lake Charles Port Authority. All work at the existing LNG terminal 

would occur within the existing facility. Aside from the Lake Charles Port Authority properties, no 

federal, state, or local agency owned or managed lands would be affected by the liquefaction facility.

4.8.2.2 Non-Liquefaction Facilities

The lands necessary for construction and operation of the Non-Liquefaction Facilities would be 

composed of both land currently owned or leased by Lake Charles LNG or Trunkline and other private 

land. For privately owned lands along the pipeline routes, Trunkline would need to secure easements that 

convey temporary and permanent rights-of-way.
4-88

An easement agreement between a company and a landowner typically specifies compensation 

for losses resulting from construction, including losses of non-renewable and other resources, damages to 

property during construction, and restrictions on existing uses that would not be permitted on the 

permanent right-of-way. Compensation would be fully determined through negotiations between 

Trunkline and the landowner. 

If an easement cannot be negotiated with a landowner and the project has been certified by the 

FERC, Trunkline could use its right to eminent domain under section 7(h) of the NGA and the procedure 

set forth under the Federal Rules of Civil Procedure (Rule 71A) to obtain the right-of-way and ATWS 

areas. Trunkline would still be required to compensate the landowner for the right-of-way and any 

damages incurred during construction; however, the level of compensation would be determined by a 

court according to state or federal law.

4.8.3 Planned Developments

There are no planned residential or commercial developments within 0.25 mile of the project. 

However, four commercial/industrial facilities are planned within 1 mile of the proposed liquefaction 

facility, including the proposed Magnolia LNG Project and associated KMLP Lake Charles Expansion 

Project; the G2X Energy natural gas-to-gasoline facility; and the Louisiana Marine Fisheries 

Enhancement, Research, and Science Center. Certain non-jurisdictional facilities are also planned to 

provide utilities (i.e., electric power, water) to the Lake Charles Liquefaction and Magnolia LNG 

Projects. Each of these projects, as well as other planned residential and commercial/industrial 

development projects in the broader project area, are discussed in the cumulative impact analysis 

provided in section 4.13.1.

4.8.4 Recreation and Special Interest Areas

4.8.4.1 Liquefaction Facility

Construction and operation of the liquefaction facility would not directly affect designated 

recreational areas. However, portions of two NWRs (the Sabine NWR and the East Cove Unit of the 

Cameron Prairie NWR) are in the vicinity of the Calcasieu Ship Channel and offer a variety of 

recreational activities and recreational boating and fishing occurs in the project area. There are also two

golf courses located nearby. Potential impacts on these areas are discussed below.

Ship traffic accesses the existing terminal via the Gulf Intracoastal Waterway and Calcasieu Ship 

Channel. During construction, barges would deliver equipment and materials to the existing LNG 

terminal. Barge traffic during construction would consist of an average of five barge deliveries per day, 

and each barge would occupy the Calcasieu Ship Channel for about 15 minutes before turning at Devil’s 

Elbow (the turn off point for the Industrial Canal/Turning Basin). 

The Sabine NWR is 8 miles south of Hackberry, Louisiana, and extends to the ship channel 

between river miles 9 and 12 (for reference, the Industrial Canal is at about river mile 23). Users of the 

Sabine NWR adjacent to the ship channel may observe an increase in barge traffic during the construction

period. Users may also observe LNG carrier traffic through the channel during operation of the 

liquefaction facility; however, Lake Charles LNG has not requested a change to the currently authorized 

size, number, or transit route of the LNG carriers calling on the terminal. The East Cove Unit of the 

Cameron Prairie NWR extends along a portion of the southeastern shore of Calcasieu Lake. The 

Cameron Prairie NWR is about 1.4 miles from the Calcasieu Ship Channel at the nearest point, and there 

is land east of the ship channel that would blocks views from the refuge. As a result, we do not believe 

that East Cove Unit users would likely be affected by marine traffic a construction and operation of the 

project. 
4-89

Recreational boating and fishing occurring in the project area could be affected by construction 

activities. Calcasieu Landing, a public boat launch, is located on the south side of the Industrial Canal at 

the entrance to the canal from the Intracoastal Waterway. Additionally, recreational boat traffic uses the 

Calcasieu Ship Channel in transit to Calcasieu Lake. We believe the impacts of construction-related 

barge traffic within the Intracoastal Waterway and the ship channel on recreational boats would be minor 

because the ship channel is specifically maintained to provide deep draft access to the Port of Lake 

Charles and is routinely used for both recreational and industrial traffic. Similarly, the impacts of barge 

traffic on fishing in the channel would be minor. Restrictions on fishing in the immediate vicinity of the 

proposed TCDs and berth modifications would exist during construction of the facilities and when the 

facilities are in use, but there is extensive similar habitat in the Industrial Canal and the general project 

area. During operation, the potential impacts on recreational boating and fishing would not increase 

above the impacts addressed in the previous authorizations for the existing LNG terminal because Lake 

Charles LNG has not requested an increase in LNG carriers calling on the terminal. Overall, construction 

and operation of the project would result in minor, temporary impacts on recreational boating and fishing. 

Additional discussion of project-related impacts on marine traffic is provided in section 4.9.6.

Construction of the liquefaction facilities could temporarily affect two nearby golf courses. The 

Lake Charles Country Club Golf Course, a private country club on Prien Lake with an 18-hole golf 

course, is located 2.4 miles from ACW Area A. The Gray Plantation Golf Course, an 18-hole golf course 

and sports club, is located 0.3 mile from ACW A. Construction could generate dust and noise, which 

could be a nuisance to the recreational users. Construction could also interfere with or diminish the 

quality of the recreational experience by affecting public access during peak season due to constructionrelated increases in traffic. In general, impacts on the golf courses would be temporary and would be 

limited to the period of active construction. Dust and noise levels would be minimized as described in 

sections 4.11.1 and 4.11.2, respectively. To minimize impacts on traffic, we are recommending that Lake 

Charles LNG prepare and file a traffic management plan as discussed in section 4.9.6.1. With 

implementation of these measures, we do not believe that any significant impacts on the golf courses 

would occur during construction. Operation of the liquefaction facility is not expected to affect

recreational activities at the nearby golf courses. 

4.8.4.2 Non-Liquefaction Facilities

Construction and operation of the Non-Liquefaction Facilities would not directly affect 

designated special interest areas. However, several areas are located within 2.5 miles of the project.

The Lacassine NWR is located 0.4 mile south of the existing NGPL–Lakeside Meter Station 

facility. The Lacassine NWR is part of the Southwest Louisiana NWR Complex, which consists of three 

other federal wildlife refuges in southwest Louisiana: Cameron Prairie, Sabine, and Shell Keys. 

Lacassine NWR, located in Cameron and Evangeline Parishes, encompasses nearly 35,000 acres and 

serves as a refuge and breeding ground for migratory birds and other wildlife. The refuge is bisected by 

the Gulf Intracoastal Waterway and Bayou Lacassine and is bordered on the east by the Mermentau River 

and on the west by the Bell City Drainage Ditch. The southern border of the refuge is formed by Lake 

Misere, Bayou Misere, Mud Lake, and Grand Lake. The dominant feature of the refuge is the Lacassine 

Pool, where sport fishing is permitted at a level compatible for the environment. Hunting and bird 

watching are also popular recreational activities within the NWR. A nature drive, foot trails, and 

observation towers are available year-round (FWS, 2014c). The closest construction activities to the 

refuge would be the modifications at the NGPL–Lakeside Meter Station, which would occur within the 

existing facility and in adjacent agricultural areas. Due to the distance between the meter station and the 

NWR (0.4 mile), any impacts on recreational users within the Lacassine NWR would be limited to minor, 

short-term increases in noise and dust during construction activities and would not be significant. 

Operation of the modified facility would not affect the NWR.
4-90

The Kisatchie National Forest in Grant Parish surrounds the areas immediately adjacent to the 

Pollock Compressor Station. However, the Pollock Compressor Station is completely owned by 

Trunkline and all work to be performed at the Pollock Compressor Station would occur within 

Trunkline’s existing fence line. Because the construction activities proposed at the Pollock Compressor 

Station would be minor and within an existing industrial facility, we believe that visitors to this area of 

the national forest would not be adversely affected. 

The Calcasieu River is classified as a Louisiana Natural and Scenic River. The approximately 

200-mile-long river drains a largely rural area of forests and bayou country in Vernon Parish and then 

meanders southward through the Kisatchie National Forest, passing the towns of Oakdale and Lake 

Charles to enter Calcasieu Lake (or Big Lake), an estuary on the Gulf of Mexico. Trunkline proposes to 

replace an existing Calcasieu River crossing with a 5,477-foot-long segment of new pipeline via the HDD 

method to connect the Mainline 200-1 pipeline to Trunkline’s existing 200-3 Line. The HDD method, as 

described further in section 2.6.3.3, is a trenchless crossing method that can avoid direct surface impacts 

on sensitive resources like the Calcasieu River and its riparian area. By using the HDD method, 

Trunkline would eliminate the need for both clearing of the riparian area where the pipeline crosses the 

river, and for in-water work and any resultant disruption of boating. Additionally, Trunkline would 

implement the measures in the FERC Procedures and its HDD Contingency Plan (see appendix D) to 

further minimize the extent and duration of construction disturbance on this waterbody. With 

implementation of these measures, we do not believe the natural and scenic characteristics of the river 

would be affected by the project (see section 4.8.6).

4.8.5 Hazardous Waste Sites

Based on a review of several federal, state, and local government environmental databases, no 

listed NPL or “Superfund” sites were identified within 8 miles of any proposed project sites (EPA, 

2013d). Information on contaminated soil or groundwater near the proposed facilities is provided in 

sections 4.2 and 4.3, respectively.

Alcoa is currently working with the LDEQ regarding impacts on soil and sediment from historical 

uses of PCBs and other materials at the Alcoa facility east of the proposed liquefaction facility (also see 

section 4.3.2.2). Lake Charles LNG is working closely with Alcoa to determine what contaminants may 

be encountered during construction of the liquefaction facility. Lake Charles LNG would manage and 

dispose of impacted media in accordance with applicable regulations and in coordination with Alcoa and

the LDEQ.

Should contaminated soils, sediments, or groundwater be encountered unexpectedly during 

construction, Lake Charles LNG would implement its Plan for Unanticipated Discovery of Contaminated 

Soils or Groundwater (see section 4.2.2). If contamination is encountered, work would be stopped,

appropriate containment and cleanup measures would be employed, and applicable regulatory agencies 

would be consulted if warranted to develop a site-specific plan for removal, disposal, and treatment of the 

contaminated area. Identification/characterization, handling, labeling, storage, manifesting, 

transportation, record keeping, and disposal of potentially contaminated materials would be conducted in 

accordance with applicable federal, state, and local regulations and guidance. In addition, Lake Charles 

LNG and Trunkline would implement their SPAR and SPCC Plans to minimize potential contamination 

of soil and water resources from spills or releases of fuel, other mechanical fluids, or other hazardous 

materials. 
4-91

4.8.6 Visual Resources

“Visual resources” refers to the composite of basic terrain features, geologic features, hydrologic 

features, vegetation patterns, and anthropogenic features that influence the visual appeal of an area for 

residents or visitors. In general, impacts on visual resources may occur during construction when large 

equipment, excavation activities, spoil piles, and construction materials are visible to local residents and 

visitors and during operation to the extent facilities or portions of facilities and their lighting are visible to 

residents and visitors. The degree of visual impact resulting from the proposed project facilities is highly 

variable among individuals, and is typically determined by the general character of the existing landscape

and the visually prominent features of the proposed facilities.

4.8.6.1 Liquefaction Facility

The primary existing structures in the viewshed of the proposed new liquefaction facility include 

the existing Trunkline LNG Terminal, East Moss Lake Oil and Gas Field, Alcoa-Lake Charles facilities, 

and other industrial properties. The viewshed also includes the Industrial Canal and Calcasieu Ship 

Channel to the south and southwest, forest and wetlands to the north, and a mix of open and vegetated 

areas to the east. Because the topography of the surrounding area is fairly level, visibility would extend 

outward from the site except where buffered by vegetation or existing structures. 

Construction activities, particularly at ACW A, might be visible from residences along Jacob’s 

Way Road, Ford Road, Wilder Road, and north of Haymark Road; however, most of these residences 

would be visually shielded from the construction activity by forest land. Visual impacts would be more 

significant for the residences east of Big Lake Road where there is more open land and fewer forested 

buffers. Clearing and construction activities at ACW D would result in visual impacts on residences 

north of the ACW along West Lincoln Road. Visual impacts on residential areas south of the Industrial 

Canal along Airhart Road would be negligible due to distance and the presence of vegetation. There are 

no nearby residences west of the liquefaction facility site or the existing LNG terminal, but activities may 

be visible to recreationists using the Calcasieu Ship Channel. 

Construction of the liquefaction facility would also increase traffic on West Tank Farm Road (to 

the north of the site) and Big Lake Road (to the east of the site), which could impact motorists using those 

roads, who could observe increased equipment, vehicles, workers, and structures on the proposed site. 

However, the overall duration of views for passers-by would be short. 

The impact on visual resources during construction would be temporary due to the presence of 

workers and equipment for the approximately 5-year construction period, but the impacts resulting from 

operation of the facilities would be permanent. 

The permanent changes to the visual character of the area would include the clearing of forested 

vegetation within ACWs A and D, and within the liquefaction facility site. Additionally, the LNG 

terminal modifications and proposed new liquefaction facility would include many aboveground 

structures that could result in visual resource impacts. These include but are not necessarily limited to

three liquefaction trains, flare structures, mooring and breasting dolphins, and two TCDs. The new 

facilities would also require lighting for operations, safety, and to comply with Federal Aviation 

Administration (FAA) requirements. Lake Charles LNG has determined that it would not be feasible to 

leave a visual buffer along the liquefaction plant boundaries along Tank Farm Road or Big Lake Road for 

security and safety reasons. However, Lake Charles LNG is considering retaining a forested buffer along 

the east edge of ACW A along Big Lake Road, which could provide a visual screen between the facilities 

and the nearest residences to the east. Lake Charles LNG has not indicated whether it also considered a 

forested buffer along the north side of ACW D to reduce visual impacts on residences north of West 
4-92

Lincoln Road. To ensure that impacts on the surrounding visual landscape are minimized, we 

recommend that:

 Prior to construction, Lake Charles LNG should file with the Secretary, for review 

and written approval of the Director of OEP, visual screening plans for ACWs A

and D. At a minimum, each plan should include the retention of a forested buffer of 

sufficient width to provide an effective visual screen between the liquefaction 

facilities or ACW and the nearest residences located to the east (for ACW A) and to 

the north (for ACW D).

Another potential source of visual impacts is the flare system that would be constructed as part of 

the project, which would include seven flares on three derrick structures. Two of the derricks would be 

located within the liquefaction facility, one of which would support a single startup flare, and the other of 

which would support 4 emergency flares and a spare. Another derrick near the dock area would support a 

marine flare. Lake Charles LNG anticipates that the flare heights would range from 201 to 351 feet, with 

estimated diameters from 16 to 48 inches. When in use, the flares would be visible from varying 

distances. To the east of the proposed site, where trees do not offer vegetative screening, flares may be 

visible to neighborhoods along Big Lake Road and in the vicinity of Elliott Road. Neighborhoods to the 

south along Airhart Road would have limited visibility due to the distance from the site and the existing 

vegetative buffers. The upper parts of the flares might be visible at neighborhoods along Haymark Road 

and from varying points within the Gray Plantation Golf Club. However, flares would only operate on a 

limited basis. The startup flare would be in use throughout the initial start-up period prior to beginning 

operation of each liquefaction train. The duration of the flaring associated with the start-up period would 

depend on the specific commissioning schedule, but is expected to be up to 1 month for each train. The 

other flares would be used only on an emergency basis. Therefore, visual impacts resulting from the 

flares during operation of the facility would be temporary and infrequent.

Impacts on the visual landscape associated with the modified and new facilities at the LNG 

terminal and proposed liquefaction facility would be permanent, but because the liquefaction facility 

would be constructed immediately adjacent to the existing terminal, views of the facility would be 

consistent with the existing industrial area. Additionally, implementation of a visual screening plan as 

recommended above would minimize impacts. Overall, we believe that visual impacts of the proposed 

liquefaction facility and LNG terminal modifications would be minor and generally in character with the 

existing landscape.

4.8.6.2 Non-Liquefaction Facilities

Pipelines

During construction of the pipelines, visual impacts would result from the presence of personnel, 

large construction equipment, and vehicles, all of which could be visible in areas accessible to the public, 

such as roadways crossed by the route and nearby residences. However, no residences are located within 

50 feet of the construction right-of-way and the pipeline routes do not cross densely populated areas. 

Visual impacts due to the presence of construction equipment and personnel would be temporary and 

short term; therefore, we believe those visual impacts would not be significant.

The primary impact on visual resources during construction and operation of the Mainline 

Connector and Mainline 200-3 Loop would result from vegetation clearing in the construction rights-ofway and ATWS. Clearing of forest land within the construction right-of-way, and maintenance of the 

permanent right-of-way in an herbaceous or scrub-shrub state, would change the viewscape for viewers in 

the area. Trunkline would allow forest land in ATWSs to revert to preconstruction conditions, although it 
4-93

could take up to 50 years for forest vegetation to reach a mature stage, resulting in long-term visual 

impacts in those areas. The permanent visual impact would be most noticeable for the Mainline 

Connector, which would result in the creation of a new right-of-way. Operational impacts along the 

Mainline 200-3 Loop, where the new right-of-way would overlap an existing pipeline right-of-way, 

would be less evident. Once the disturbed areas are restored and revegetated in accordance with the 

FERC Plan and Procedures, operation of the pipeline would result in negligible impacts in open areas, 

where the permanent right-of-way would largely revert to preconstruction condition and use.

As noted above, the proposed Mainline 200-1 modifications would include installation of a new 

pipeline segment by HDD across the Calcasieu River, a Louisiana Natural and Scenic River. Drilling 

equipment and construction activities may be visible to passers-by at some locations along the river, but 

there are few residences in the area, with the closest about 0.5 mile away. Overall, visual impacts 

associated with the HDD operations would be minor and short term. Moreover, use of the HDD method 

would minimize visual impacts associated with operation of the new pipeline segment because it would 

eliminate the need to remove vegetation at the river banks, and Trunkline has indicated that it would not 

conduct maintenance clearing between the HDD entrance and exit points. Therefore, no additional visual 

impacts would occur during operation.

Compressor Stations

Construction at the existing compressor stations would result in negligible visual impacts. These 

would include the presence of equipment and workers, and short-term, localized disturbance of vegetation 

and soils within the fence line of these industrial facilities. After restoration, there would be no visual 

impacts associated with operation of the modified piping. 

Construction of Compressor Station 203-A would occur within a rural area of Calcasieu Parish 

off of Dennison Road and south of Billy Corbello Road, both of which are low-density, two-lane roads.

Construction related impacts including the presence of equipment and workers would be temporary and 

limited to the construction period. The areas that would be cleared and graded predominantly consist of 

agricultural land, which would be converted to industrial/commercial land. During both construction and 

operation, Compressor Station 203-A would be visible to motorists passing through the immediate rural 

area of Calcasieu Parish. Construction and operation of Compressor Station 203-A would not affect any 

designated visual resources; however, the station would be visible to the few nearby residences, the 

closest of which are about 790 feet east, 1,200 feet southwest, and 1,330 feet northwest of the station 

perimeter. Therefore, we recommended in the draft EIS that Trunkline file a plan to minimize visual 

impacts of Compressor Station 203-A on nearby residences. In its May 14, 2015 response, Trunkline 

committed to using materials and/or painting the structures at the station to be harmonious with the 

surrounding landscape and infrastructure. 

Meter Stations

Construction activities at the new and modified meter stations would result in short-term, 

localized visual impacts similar to those described above. There would be no permanent visual impacts at 

the existing meter stations that would not be expanded. The new and expanded meter stations would 

result in new, permanent impacts on visual resources. A fence would be erected around each of the new 

meter stations and the existing fencelines would be expanded at the existing stations where necessary to 

encompass the new facilities. However, the new meter and expanded meter stations would be in rural 

areas and would not affect any designated visual resources. Therefore, we believe the proposed new and 

modified meter stations would have a minimal impact on visual resources.
4-94

Contractor Yard

The contractor yard that would be used for the temporary storage of trailers, vehicles, pipe, and 

other construction-related material during construction consists of previously disturbed, graveled areas 

and some grassy areas. Minimal ground disturbance is anticipated during use of the yard for the project. 

There would be no permanent impacts on visual resources associated with the use of the yard. The only 

impacts at the yard would be temporary during construction. Moreover, the yard has been used for 

similar purposes in the past. 

Access Roads

Trunkline proposes to use 38 temporary access roads (in addition to permanent access roads at 

existing facilities) during construction of the Non-Liquefaction Facilities. Some of these roads would 

require minor improvements that would not have a significant impact on visual resources. After 

construction, the roads used for temporary access would be returned to preconstruction conditions unless 

another arrangement is mutually agreed upon with the landowner.

The permanent access roads to the new meter stations would be constructed on existing dirt paths

or open land. Use of these roads by construction equipment and project personnel would result in 

temporary impacts on visual resources during construction. Overall, we believe the permanent access 

roads to these new aboveground facilities would result in minor impacts on the viewshed during both 

construction and operation.

4.8.7 Coastal Zone Management

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 those states will meet their obligations and responsibilities in managing their coastal 

areas. In Louisiana, the LDNR’s Office of Coastal Management administers the CZMP. The LDNR 

evaluates activities or development affecting land within Louisiana’s coastal zone for compliance with the 

CZMA through a process called “federal consistency.”

The Gulf Intracoastal Waterway marks the inland extent of the coastal zone boundary. Project 

facilities that fall within this boundary include the proposed new Kinder Morgan–Lake Charles Meter 

Station and the modifications and expansion at the NGPL–Lakeside Meter Station. No other components 

of the project are located within the Coastal Zone. 

Trunkline initiated consultation with the LDNR for the NGPL–Lakeside and Kinder Morgan–

Lake Charles Meter Stations on March 7, 2014 requesting confirmation that the project would be 

consistent with the Louisiana Coastal Resources Program and clarification as to whether a CUP would be 

required for these facilities. In an August 27, 2014 letter, the LDNR Office of Coastal Management 

stated that the proposed work at the NGPL–Lakeside Meter Station would have no direct and significant 

impact on coastal waters and that the Kinder Morgan–Lake Charles Meter Station is exempt; therefore, 

neither facility would require a CUP.

4.9 SOCIOECONOMICS

Construction of the project could impact socioeconomic conditions, either adversely or positively, 

in the general vicinity of the project. These potential impacts include alteration of population levels or 
4-95

local demographics, increased employment opportunities, increased demand for housing and public 

services, transportation impacts, and an increase in government revenue associated with sales and payroll 

taxes. The potential socioeconomic impacts of project operation include employment opportunities, 

ongoing local expenditures by the operator, an increased tax base, and an increased demand for public 

services.

The socioeconomic analysis is limited to Calcasieu, Jefferson Davis, and Beauregard Parishes in 

Louisiana because they encompass the larger project components: the existing LNG terminal, proposed 

liquefaction facility, the Mainline Connector and the Mainline Loop 200-3, Compressor Station 203-A, 

and upgrades at the Longville Compressor Station. For the purposes of our socioeconomic analysis, these 

three parishes are defined as the “project area.” 

4.9.1 Population

Table 4.9.1-1 provides a summary of selected population and demographic information for the 

project area.

TABLE 4.9.1-1

Existing Socioeconomic Conditions in the Project Area for the Lake Charles Liquefaction Project

State/Parish

Population

Population 

Density (per 

square mile)

Per 

Capita 

Income

Civilian 

Labor 

Force

Unemployment RateTop Two Major 

Industries

Square 

Milesa

2010a

2012

(est.)a

2010a2012 2012a2012b2012b2013c

Louisiana 43,203.90 4,533,372 4,602,134 104.9 106.5 $24,264 2,083,710 6.4 1. Educational, 

health, and social 

services

2. Manufacturing

Calcasieu Parish 1,063.66 192,768 194,323 181.2 182.7 $24,255 92,084 5.9 1. Educational, 

health, and social 

services

2. Manufacturing

Jefferson Davis 

Parish

651.33 31,594 31,439 48.5 48.3 $21,142 14,587 5.3 1. Educational, 

health, and social 

services

2. Retail trade

Beauregard Parish 1,157.34 35,654 36,240 30.8 31.3 $22,428 14,403 7.0 1. Educational, 

health, and social 

services

2. Manufacturing

____________________

a U.S. Census Bureau, 2014a

b

Louisiana Workforce Commission, 2013

c City-Data, 2013

4.9.1.1 Liquefaction Facility

The U.S. Census Bureau (U.S. Census Bureau, 2014a) reported that in 2012, the population of 

Calcasieu Parish was 194,323, with a population density of 182.7 persons per square mile. The average 

population density for Louisiana in 2012 was 106.5 persons per square mile.
4-96

Construction of the liquefaction facility is expected to begin in 2015 and be completed with full 

service anticipated by 2020. Lake Charles LNG estimates a peak construction workforce of about 

5,600 workers, with an average workforce of about 2,100 workers over 5 years. Lake Charles LNG

anticipates that about 20 percent of these workers would be hired locally; the peak number of non-resident 

workers hired during construction is estimated to be 4,480. Should non-resident workers be accompanied 

by family members, and based on an average household size of 2.55 persons in Calcasieu Parish, up to 

11,424 non-local persons could potentially move to the project area during peak construction (U.S. 

Census Bureau, 2014a). Although it is not likely that all workers would bring families, this addition 

would constitute a 5.9 percent increase over the current Calcasieu Parish population of 194,323. The 

peak construction workforce would be required for less than 9 months. 

Lake Charles LNG anticipates hiring up to 176 additional permanent employees to operate the 

liquefaction facility. This workforce and their families would represent a minor but permanent population 

increase in the vicinity of the liquefaction facility.

4.9.1.2 Non-Liquefaction Facilities

The major Non-liquefaction Facilities would be constructed in three Parishes: Calcasieu, 

Jefferson Davis, and Beauregard. Calcasieu Parish is described above. The estimated 2012 population 

densities, an indication of the extent of development, for Jefferson Davis and Beauregard parishes were 

48.3 and 31.3 persons per square mile, respectively. The total population of Jefferson Davis Parish is 

31,439 and the total population of Beauregard Parish is 36,240 (U.S. Census Bureau, 2014a).

The construction workforce for the Non-liquefaction Facilities would consist of about 90 workers 

for the compressor stations and 260 workers for the pipelines. Based on previous construction 

experience in the project area, Trunkline estimates that about 20 percent of the workforce would reside 

in the project area, while 80 percent would commute to the work sites daily. Given that almost all the 

workforce is anticipated to live within daily commuting distance of the project areas, the construction 

workers associated with the Non-liquefaction Facilities would likely have a negligible effect on 

population in the project areas.

Trunkline anticipates hiring eight new permanent employees to operate the Non-liquefaction 

Facilities. This would represent a negligible increase in the local population in the vicinity of the project 

area.

4.9.2 Economy and Employment

Table 4.9.1-1 provides selected employment and income statistics for the p roject area. The 

main employment sectors in Calcasieu and Beauregard Parishes are education, health, and social services,

and manufacturing. In Jefferson Davis Parish, the main employment sectors are education, health, and 

social services, and retail trade (City-Data, 2013).

4.9.2.1 Liquefaction Facility

The civilian labor force is defined as the sum of employed persons and those searching for

work. The civilian labor force in Calcasieu Parish is 92,084 persons and per capita income is $24,255. 

Calcasieu Parish has an unemployment rate of 5.9 percent, and 16.8 percent of the population is below

the poverty line. The parish has a lower unemployment rate than the State of Louisiana, which has an

unemployment rate of 6.4 percent. In addition, Calcasieu Parish has a smaller percentage of the 

population that is below the poverty level compared to Louisiana’s 18.7 percent.

Expenditures in the liquefaction facility project area are estimated to be $1.68 billion for various 

goods and services throughout construction. Total wages during the entire construction period are 
4-97

expected to equal about $2.72 billion. Construction of the liquefaction facility would increase economic 

activity within the area in several ways:

 a direct effect – hiring of local construction workers and purchases of goods and 

services from local businesses;

 an indirect effect – the additional demand for goods and services, such as replacing 

inventory from the firms that sell goods and services directly to the project or to workers 

and their families; and

 an induced effect – the spending of disposable income by the construction workers at

local businesses, which in turn order new inventory from their suppliers.

The increase in economic activity resulting from the sum of these three effects would result 

in a temporary positive economic impact in the vicinity of the liquefaction facility.

Anticipated operational expenditures would include $65 million in annual regional taxable 

expenditures on goods and services, about $21 million per year in salaries, and an un-estimated amount in

indirect and induced expenditures as these dollars are spent and re-spent throughout the economy. We

conclude that the expenditures and permanent workforce associated with operation of the liquefaction 

facility would result in positive permanent impact on the local economy.

4.9.2.2 Non-Liquefaction Facilities

Employment and income information for Calcasieu Parish is described above. The civilian labor 

force numbered 14,587 in Jefferson Davis Parish and 14,403 in Beauregard Parish. Per capita income is 

roughly the same in both parishes ($21,142 in Jefferson Davis Parish and $22,428 in Beauregard Parish), 

and both are below the state’s average per capita income of $24,264. 

Jefferson Davis has an unemployment rate of 5.3 percent, with 18.1 percent of the population below 

the poverty line. Beauregard Parish has an unemployment rate of 7.0 percent, with 14.8 percent of the

population below the poverty line. Both parishes have a smaller percentage of their population below the

poverty line than Louisiana, but only Jefferson Davis has a lower unemployment rate as well.

Expenditures during construction of the non-liquefaction facilities are estimated to be about

$161.7 million for various goods and services. Total wages during the entire construction period are 

expected to equal about $137.2 million. As with the liquefaction facility, in addition to the direct

employment and payroll impacts generated by the Non-liquefaction Facilities, dollars spent on goods and

services would have positive direct, indirect, and induced economic impacts on the project area during 

the construction period.

Operation of the Non-Liquefaction Facilities would result in $1.6 million in annual regional 

expenditures on goods and service and about $1.3 million per year in salaries. These expenditures would 

result in a negligible positive impact on the local economy.

4.9.3 Local Taxes and Government Revenue

4.9.3.1 Liquefaction Facility

Lake Charles LNG estimates spending $325 million on construction materials and supplies in the 

liquefaction facility area during construction. This would generate increased local, state, and federal

sales tax revenue in the project area. The expenditures on goods and services by the construction 

workforce and the families of the workers would also generate increased tax revenues. In addition,
4-98

local, state, and federal governments would tax the $2.7 billion in total workforce payroll. This increase

in tax revenue would be a temporary, positive impact on the tax revenue in the liquefaction facility area.

After construction, Lake Charles LNG would pay parish property taxes on its liquefaction 

facility and equipment. Lake Charles LNG estimates that the total property tax paid in Calcasieu Parish 

for the initial year following completion of construction would be $5.8 million. There also would be

long-term increases in sales tax revenue from expenditures on materials, goods, and services by Lake 

Charles LNG and the operational workforce.

4.9.3.2 Non-Liquefaction Facilities

Trunkline estimates that the total construction payroll for the Non-Liquefaction Facilities would 

be about $137.2 million. It is also likely that some portion of construction materials and supplies 

(estimated at about $24.5 million) would be purchased locally. Additionally, expenditures by Trunkline,

workers, and the families of workers during construction would increase tax revenues in the region. The 

project would have a temporary, positive impact on the tax revenue in the project area.

Operation of the Non-liquefaction Facilities would also have a positive effect on local property 

tax revenue. Table 4.9.3-1 summarizes the anticipated property taxes by parish/county to be paid in the 

initial year after project completion. 

TABLE 4.9.3-1

Estimated Property Taxes (Year 1 In-Service) for the Lake Charles Liquefaction Project

Parish, State Estimated Property Taxes

Calcasieu Parish, LA $5,852,061

Jefferson Davis Parish, LA $1,272,084

Beauregard Parish, LA $1,289,212

Total $8,413,357

4.9.4 Housing

Table 4.9.4-1 provides data on the local rental and other temporary housing options in the project

area. 

TABLE 4.9.4-1

Housing Characteristics in the Project Area for the Lake Charles Liquefaction Project

State/Parish

Housing 

Unitsa

Vacant 

Housing 

Unitsa

Vacant 

Housing Units 

for Renta

For Seasonal, 

Recreational, or 

Occasional Usea

Rental 

Vacancy Rate 

(percent)a

Number of Hotels 

and Motelsb

Louisiana 1,964,981 236,621 66,857 42,253 10.5 538

Calcasieu Parish 82,058 8,062 3,015 724 11.8 120

Jefferson Davis Parish 13,306 1,535 320 260 9.9 78

Beauregard Parish 15,040 1,881 251 513 8.0 115

____________________

a U.S. Census Bureau, 2014b

b Yellowbook, 2013 (number of “Hotels and Motels” as advertised on www.yellowbook.com). Some of these hotels and 

motels may be located in adjacent parishes.

The number of housing units (permanent and temporary) varies across the project area, largely 

based on the parish population and presence or absence of a major city. In 2010, the fewest housing units 
4-99

were in Jefferson Davis Parish (13,306), which also had the lowest population for those parishes/counties 

evaluated, while the most housing units were in Calcasieu Parish (82,058), which had the highest 

population of the parishes and counties in the project area. Rental vacancy rates in the project area ranged 

from a low of 8.0 percent in Jefferson Davis Parish to a high of 11.8 percent in Calcasieu Parish.

According to the U.S. Census Bureau, vacant housing units in Calcasieu Parish in 2010 totaled

8,062 units; of these, 3,015 units were rentals and 724 were for seasonal, recreational, or occasional use. 

Vacant housing units in Jefferson Davis Parish totaled 1,535 units; of these, 320 units were rentals and 

260 were for seasonal, recreational, or occasional use. In Beauregard Parish, vacant housing units totaled 

1,881 units, with 251 rentals and 513 units for seasonal, recreational, or occasional use. There are about

313 hotels/motels across the three parishes that could be used by the short-term workforce. The project 

area also offers other temporary housing options such as campgrounds and RV parks. The Pelican Lodge 

industrial housing facility at the Port of Lake Charles (Southwestern Louisiana Economic Development 

Alliance, 2014) is under development; this facility will have the initial capacity to house 

4,000 construction personnel when complete.

4.9.4.1 Liquefaction Facility

As stated previously, Lake Charles LNG anticipates local residents would comprise a portion of 

the workers hired for construction of the liquefaction facility. Calcasieu Parish has the most vacant

transient housing units that would be available to the workforce, including vacant units for rent and those

for seasonal, recreational, and occasional use (3,739 units) as well as rooms at 120 hotels and motels (see 

section 4.9.5). The currently available transient housing in Calcasieu Parish may not be sufficient to

accommodate the maximum peak non-resident workforce; therefore, during the 9-month period that the 

peak workforce may be present, workers might need to find housing outside the local area and commute 

from further away, and/or make use of the Pelican Lodge housing facility if available. Outside of the 

time when the workforce peaks, sufficient housing is expected to be available to accommodate the 

average workforce required for the construction of the liquefaction facility. Overall, we believe 

construction of the proposed liquefaction facility would have a temporary impact on housing in the 

project area. However, as discussed in section 4.13.2.9, housing constraints would be more significant if 

several of the other planned projects in the area are constructed in the same timeframe. Lake Charles 

LNG and Trunkline have stated that the bid documents for the project would require prospective 

contractors to address this issue and to provide a plan worker housing in their proposals.

We believe the addition of 176 permanent staff required to operate the liquefaction facility 

would have a minor permanent impact on local housing markets.

One residence and one business would be displaced as a result of construction of the liquefaction 

facility. The residence was located near the northeast corner of the proposed liquefaction facility site and 

has already been purchased by Lake Charles LNG and the occupants have relocated. An office building 

and a parking area located in the southwest corner of the proposed liquefaction facility site has also been 

purchased, and would be vacated prior to construction. 

4.9.4.2 Non-Liquefaction Facilities

Trunkline anticipates local hires would comprise almost all of the peak 690 workers for

construction of the Non-Liquefaction Facilities. Those workers would commute daily from their homes 

to the construction right-of-way or the compressor station sites. Based on the number of available rental

housing units and hotels/motels in the three parishes as discussed above, adequate housing exists to

accommodate non-resident workers and their families. Overall, construction of the proposed NonLiquefaction Facilities would not result in significant impacts on transient housing in the area.
4-100

Operation of the Non-Liquefaction Facilities would require eight new permanent employees who

would relocate to the project area. These new employees would represent a negligible decrease in 

available permanent housing.

It is not anticipated that any residences or businesses would be displaced during the construction 

or operational phases of the Non-Liquefaction Facilities. Trunkline would minimize the impact on 

residential properties by locating the pipelines and compressor station in areas removed from residential 

uses, to the extent practicable.

4.9.5 Public Services

Table 4.9.5-1 summarizes local community public services in the project area.

TABLE 4.9.5-1

Public Services in the Project Area for the Lake Charles Liquefaction Project 

Parish, State

Number of Public 

Schoolsa

Number of Sheriff’s 

Departmentsb

Number of Police 

Departmentsb

Number of Fire and

Rescue Departmentsc

Number of 

Hospitalsd

Calcasieu Parish, LA 56 1 6 5 5

Jefferson Davis Parish, LA 10 1 5 4 1

Beauregard Parish, LA 8 1 2 1 1

____________________

a Public Schools K12, 2014

b USA Cops, 2013

c USA Fire & Rescue, 2013

d Hospitals Center, 2013

4.9.5.1 Liquefaction Facility

Calcasieu Parish has 56 public schools with an enrollment of 31,657 students in 2009 to 2010 

(Public Schools K12, 2014). There are five hospitals, one sheriff’s department, six police departments, 

and five fire departments within the parish. 

The peak number of 5,600 workers is anticipated to last less than 9 months. Lake Charles LNG

estimates local workers would account for about 20 percent of the workforce based on construction of the

existing LNG terminal. If all of the about 4,500 non-resident workers relocate to Calcasieu Parish with

two children each, local school system enrollment would increase by 9,000 students, or an increase of

28.4 percent. However, Lake Charles LNG would not employ many of the workers for the full duration

of construction, and it is unlikely that those workers would relocate with their children. For the

average workforce of 2,100 and assuming two children per worker, school enrollment could increase by 

4,400 students, or 13.9 percent. We believe this represents the worst-case scenario, resulting in moderate,

temporary impacts on the schools. However, many construction workers do not have families or would

not relocate their families while they work at the liquefaction facility. As a result, the impacts on schools

in the project area would likely be much less than estimated.

During operation of the liquefaction facility, the additional 176 permanent workers would not

likely cause any adverse impact on local schools. If all 176 permanent workers have 2 children, this 

would result in 352 additional children in local parish school systems. This addition would represent a 

1.1 percent increase in total enrollment, with students spread out over many grade levels. As a result,

we believe no adverse impacts from operation of the liquefaction facility would occur on the parish’s 

school systems.
4-101

Construction of the liquefaction facility would result in little or no short-term impact on the 

availability of local community facilities and services such as police, fire, and medical because the nonlocal workforces would be small relative to the current population. The proposed liquefaction facility 

would not materially change the emergency response requirements from those associated with operations 

at the existing LNG terminal. The local fire department is part of a regional mutual aid organization that 

provides emergency services to numerous petro-chemical facilities and is an experienced responder to 

industrial incidents. The LNG terminal has its own first responder group that supports the local services 

on an as needed basis. The local communities have adequate infrastructure and community services to 

meet the needs of the workers that would be required for construction and operation of the facility. 

Therefore, we believe impacts on public services during construction of the liquefaction facility would 

be temporary and minor.

4.9.5.2 Non-Liquefaction Facilities

We believe Trunkline’s construction workers would not likely bring family members to the area

due to the relatively short construction period required for the Non-Liquefaction Facilities. Further, the 

temporary increase in population due to construction would be negligible compared to the current

population in the project areas. As a result, we believe the Non-Liquefaction Facilities would minimally 

impact schools in the project area. Although it is likely that there would be some need for increased

police, fire, and medical services during construction, those public services would experience only minor

impacts during construction.

The eight new permanent positions would represent a negligible increase in the local population. 

Therefore, we believe local public services would not be impacted.

4.9.6 Transportation

4.9.6.1 Liquefaction Facility

Roadway Traffic

Access for transporting equipment, materials, and personnel to the liquefaction facility site would 

largely be provided by existing roads and barge traffic. The construction entrance to the liquefaction 

facility would be located on West Tank Farm Road, which intersects with Big Lake Road (LA 384). 

West Tank Farm Road is a two-lane asphalt roadway with 6-foot shoulders and a posted speed limit of 

55 miles per hour. Traffic count data provided by the Calcasieu Metropolitan Planning Organization 

indicated that LA 384, adjacent to the proposed site, currently experiences about 4,374 vehicles per day. 

Traffic would increase substantially during construction in the vicinity of the proposed

liquefaction facility due to the presence of worker vehicles, construction vehicles, and trucks taking 

materials and equipment to and from the site. During the peak of construction, about 5,600 employees

would travel to the worksite. This would result in up to 4,308 commuter vehicles entering or exiting the

site per shift. Lake Charles LNG may consider bussing the construction workers to and from the site 

using a remote location(s) to mitigate traffic impacts. 

Truck deliveries would not typically occur during the peak traffic periods and would not affect 

existing traffic. A majority of the large deliveries for rock fill materials are anticipated to be delivered by 

barge to the site. Barges would deliver large equipment and materials, such as soil and rock fill, to the

work dock during construction. This would reduce the number of truck trips to and from the

l iquefaction facility as well as the potential for damage to local roadways and traffic congestion. 

Material deliveries by truck would peak at about 7,000 per month with an average of 350 per day. Lake 
4-102

Charles LNG would attempt to schedule deliveries outside of peak traffic hours, when possible, to

reduce congestion. 

Lake Charles LNG commissioned a traffic assessment study to evaluate potential impacts of the 

project on traffic in the project area. The study conducted concluded that traffic generated by the 

construction and operation of the proposed project is not expected to impact the existing roadway network 

in terms of roadway capacity once a planned road improvement project, the Ham Reid Road Extension, is 

completed. The Ham Reid Road Extension would provide a connection between Elliot and Big Lake 

Roads, relieving current capacity deficiencies on Country Club Road. By itself, the project would not 

significantly impact the existing roadway network; however, the traffic study indicated that the 

cumulative impact of the proposed project and other anticipated or recently completed developments in 

the vicinity of the liquefaction facility may create roadway capacity deficiencies (Fenstermaker, 2014). 

The traffic study described a number of mitigation strategies to decrease or eliminate the potential traffic 

impact. Therefore, we recommend that:

 Prior to construction, Lake Charles LNG should file with the Secretary, for review 

and written approval by the Director of OEP, a traffic management plan that details 

specific measures that would be implemented to minimize impacts on traffic. The 

traffic management plan should identify off-site vehicle parking areas, alternative 

worker transportation methods, traffic control measures, infrastructure 

improvement, traffic control personnel, and construction and delivery areas.

Operation of the liquefaction facility would require a permanent workforce of 250 employees

(74 current and 176 new) who would commute to the site on a daily basis. Based on Lake Charles 

LNG’s 2014 traffic impact study (Fenstermaker, 2014), we believe this would not result in a significant

impact on the existing traffic conditions in the vicinity of the project. Additionally, operation of the

liquefaction facility would increase truck traffic; however, it is not likely that the increase in traffic

would be substantial. We believe there would be a minor impact on local roads for the life of the project.

Marine Traffic

During construction of the liquefaction facility, marine traffic would consist of bulk carriers, 

which would deliver aggregate from the Gulf of Mexico to a dump site near Devil’s Elbow (the point of 

the turn off for the Industrial Canal and Turning Basin), and barges would then deliver aggregate from the 

dump site to the liquefaction facility. Based on a marine traffic study conducted for the project (Ausenco, 

2013), existing vessel traffic in Calcasieu Channel is 18.8 vessels per week, or 2.7 vessels daily. Bulk 

carrier traffic would be less than one vessel per week, and the bulk carriers would not block other traffic 

in the channel during unloading. Barge traffic during construction would consist of an average of five 

barge deliveries per day, and each barge would occupy the main channel for about 15 minutes before 

turning at Devil’s Elbow. The marine traffic study (Ausenco, 2013) found that there was sufficient 

capacity in the channel for the increase in bulk carrier and barge traffic due to construction of the 

liquefaction facility, and the construction traffic would not impact existing users of Calcasieu Channel. 

Lake Charles LNG has not requested an increase in the currently authorized number of LNG 

carriers that would call on the existing LNG terminal during operation of the liquefaction facility. 

4.9.6.2 Non-Liquefaction Facilities

Trunkline would install the pipelines using horizontal bores or HDDs to prevent impacts on 

roadways and traffic. Trunkline proposes to open-cut dirt and gravel roads and would attempt to

schedule construction activities to minimize traffic flow interruptions. If an open-cut would require 
4-103

extensive construction time, steel plates would be used across the trench and/or provisions would be made 

for temporary detours or other measures to allow safe traffic flow during construction. 

The movement of construction equipment and materials and the daily commuting of employees to 

and from the construction work areas may also slightly increase traffic volumes. Construction work is 

typically scheduled to take advantage of daylight hours, 6 days per week; therefore, most workers would 

commute to and from the construction areas and contractor yards during off-peak hours. Along the 

pipeline routes, construction would move sequentially; therefore, traffic flow impacts that do arise would 

be temporary on any given section of roadway. To minimize traffic congestion, Trunkline would 

encourage construction workers to leave their personal vehicles at the contractor yards and carpool to the 

construction areas, where possible. As necessary, contractors may provide buses to move workers from 

common parking areas to the construction work areas. Therefore, we expect construction of the NonLiquefaction Facilities to result in minor, temporary impacts on traffic flow by the construction 

workforce.

Operation of the Non-liquefaction Facilities would not result in any significant impacts on traffic

or roadways within the project area.

4.9.7 Property Values

4.9.7.1 Liquefaction Facility

The proposed location for the liquefaction facility is adjacent to the existing LNG terminal and 

other industrial facilities in an area zoned for these types of uses. It is located in a sparsely populated 

rural residential area where some residences have existed during the operational period of the existing 

LNG terminal and some have been constructed since the terminal has been in operation. Therefore, it is 

unlikely that there would be any adverse effects on property values of nearby residences. 

Further, some long-term construction workers would likely purchase residences in the vicinity of 

the liquefaction facility. These housing purchases would have a net positive effect on property values in 

the vicinity of the project. 

4.9.7.2 Non-Liquefaction Facilities

Currently available information does not support any firm conclusion with respect to project 

impacts on property values (INGAA, 2001). The impact the Non-Liquefaction Facilities may have on the 

value of a tract of land depends on many factors, including size, the values of adjacent properties, 

presence of other pipelines, the current value of the land, and the extent of development and other aspects 

of current land use. A potential purchaser will make an offer to purchase based on his or her own values, 

which might or might not take the project’s presence into account. Data are insufficient to conclude that 

any significant impacts on property values would occur as a result of the project. 

The effect that an easement may have on property values is an issue that is negotiated between 

Trunkline and the landowners during the easement acquisition process. The easement acquisition process 

is designed to provide fair compensation to the landowner for the right to use the property for project 

construction and operation.

Trunkline would compensate landowners as appropriate for damage(s) to their property, including 

damage to crops, pasture, and timber. In the event that a landowner observes damage after restoration is 

complete, Trunkline would work with the landowner to correct the deficiency.
4-104

Property taxes are generally based on the actual use of the land. Construction of the pipelines 

would not typically change the general use of the land, but it would preclude the construction of 

aboveground structures within the permanent right-of-way. If a landowner feels that the presence of a 

pipeline easement reduces the value of his or her land, resulting in excessive property taxes, he/she may 

appeal the issue of the assessment and subsequent property taxation to the local property taxation agency. 

In any event, Trunkline would compensate landowners for negative impacts on their properties.

4.9.8 Environmental Justice

Executive Order 12898 on environmental justice recognizes the importance of using the NEPA 

process to identify and address, as appropriate, any disproportionately high and adverse health or 

environmental effects of federal programs, policies, or activities on minority populations and low-income 

groups. The provisions of Executive Order 12898 apply equally to Native American programs. 

Consistent with Executive Order 12898, the CEQ has called on federal agencies to actively scrutinize the 

following issues with respect to environmental justice (CEQ, 1997):

 the racial and economic composition of affected communities;

 health-related issues that may amplify project effects to minority or low-income 

individuals; and

 public participation strategies, including community or tribal participation in the NEPA 

process.

The EPA provides guidance on determining whether there is a minority or low-income 

community to be addressed in a NEPA analysis. According to this guidance, minority population issues 

must be addressed when they comprise over 50 percent of an affected area or when the minority 

population percentage of the affected area is substantially greater than the minority percentage in the 

larger area of the general population. Low-income populations are those that fall within the annual 

statistical poverty thresholds from the U.S. Department of Commerce, Bureau of the Census Population 

Reports, Series P-60 on Income and Poverty. 

In accordance with these guidelines, we prepared an environmental justice analysis for the 

project. Table 4.9.8-1 shows the racial composition and economic status of Calcasieu, Jefferson Davis, 

and Beauregard Parishes as well as the State of Louisiana.

TABLE 4.9.8-1

Demographics in the Lake Charles Liquefaction Project Areaa

State/Parish

Racial Composition of Population (percent)

Median Household 

Income 

(2008 to 2012)

Persons Below 

Poverty 

(percent)

White alone, not 

Hispanic or Latino

Black or African 

American Alone

Hispanic or

Latino Other

Louisiana 59.9 32.4 4.5 3.2 $44,673 18.7

Calcasieu Parish 69.2 25.1 2.8 2.9 $44.247 16.8

Jefferson Davis Parish 78.6 17.2 1.8 2.4 $41,777 18.1

Beauregard Parish 79.8 13.5 3.2 3.5 $46,762 14.8

____________________

a U.S. Census Bureau, 2014a
4-105

The liquefaction facility would be located adjacent to the existing LNG terminal site and would 

not be located near any low-income or minority population areas. Therefore, there would not be any 

disproportionately high or adverse environmental and human health impacts on low-income and minority 

populations.

Trunkline would collocate new pipeline facilities with existing linear and facility infrastructure 

where possible. The remaining pipeline routes would cross mostly rural areas and were developed to 

avoid a disproportionate effect on any population (minority, low-income, or otherwise). The new 

compressor station would be located in a rural agricultural area proximate to existing natural gas 

transmission infrastructure. There would not be any disproportionately high or adverse environmental 

and human health impacts on low-income and minority populations from construction or operation of the 

Non-liquefaction Facilities.

4.10 CULTURAL RESOURCES

Section 106 of the NHPA, as amended, requires the FERC to take into account the effect of its 

undertakings on properties listed, or eligible for listing, on the NRHP and to afford the ACHP an 

opportunity to comment on the undertaking. Lake Charles LNG and Trunkline, as non-federal parties, are 

assisting the FERC in meeting our obligations under section 106 and the implementing regulations in 

36 CFR 800 by preparing the necessary information, analyses, and recommendations, as authorized by 

36 CFR 800.2(a)(3).

Construction and operation of the Lake Charles Liquefaction Project could have the potential to 

affect historic properties (that is, cultural resources listed or eligible for listing on the NRHP). Historic 

properties include prehistoric or historic archaeological sites, districts, buildings, structures, and objects, 

as well as locations with traditional value to Native Americans or other groups. Historic properties 

generally must possess integrity of location, design, setting, materials, workmanship, feeling, and 

association, and must meet one or more of the criteria specified in 36 CFR 60.4.

4.10.1 Liquefaction Facility

4.10.1.1 Cultural Resources Survey

Lake Charles LNG completed a records review and Phase I cultural resources surveys of the 

proposed liquefaction facility and associated ACW. The investigations covered both archaeological and 

architectural resources. A Phase I report for the liquefaction facility (Grunden et al., 2013) and an 

Addendum Phase I report for the associated ACW (Laird, 2014a) were provided to the FERC and the 

Louisiana SHPO. Lake Charles LNG did not conduct cultural resources survey within the existing LNG 

terminal, providing a May 2014 agreement with the Louisiana SHPO that stated no consultation with the 

SHPO was necessary for construction or maintenance projects within existing rights-of-way, fenced 

aboveground facilities, or for use of existing access roads.

The records review identified two known resources (archaeological site 16CU37 and cemetery 

Cem-Cu-43-01) within the survey area for the liquefaction facility. Site 16CU37 consisted of the ruins of 

a mid-twentieth century structure originally recorded in 2005. Cem-Cu-43-01, the historic Black Bayou 

Cemetery, was originally recorded in 2003. Site 16CU37 had previously been recommended as not 

eligible for the NRHP, and the eligibility of Cem-Cu-43-01 for the NRHP had not been previously 

assessed. No known historic architectural resources were identified within or near the proposed 

liquefaction facility.

The Phase I cultural resources surveys examined a 739-acre area for the liquefaction facility and 

associated ACW. The survey consisted of pedestrian surface inspection of areas with greater than 

25 percent surface visibility, and systematic subsurface shovel testing of areas that were not inundated, 
4-106

composed of hydric soil, or covered with gravel or other obvious fill. A total of 1,479 shovel tests were 

excavated. A single new archaeological site, a house ruin (16CU79), was identified at the liquefaction 

facility and recommended as not eligible for the NRHP. The previously recorded Black Bayou Cemetery 

was relocated and not assessed; however, Lake Charles LNG plans to avoid the cemetery during 

construction and operation of the facility. To prevent inadvertent impacts during construction, Lake 

Charles LNG would install safety fencing around the cemetery and assign an inspector to oversee earth 

moving activities in proximity to the cemetery. During operation, the liquefaction facility vapor fence 

would be adjacent to the existing cemetery fence line. Previously recorded archaeological site 16CU37 

was not relocated and Lake Charles LNG recommended no additional investigation of the site’s recorded 

location. 

Lake Charles LNG also examined surrounding areas within line-of-sight (estimated to be 

0.25 mile) of proposed construction for historic architectural resources. No historic architectural 

resources were identified.

In letters dated May 21, 2013, March 17, 2014, and June 12, 2014, the Louisiana SHPO 

commented on the Phase I and Addendum Phase I reports and concurred that site 16CU79 was not 

eligible for the NRHP, and that no historic properties would be affected by construction of the

liquefaction facility. We concur also.

4.10.1.2 Compliance with the National Historic Preservation Act

Cultural resources surveys have been completed for the liquefaction facility and ACW. The 

Louisiana SHPO and FERC agree that no historic properties would be affected by these project 

components. Therefore, the process of complying with Section 106 of the NHPA has been completed for 

the liquefaction facility and ACW. 

4.10.2 Non-Liquefaction Facilities

4.10.2.1 Cultural Resources Survey

Louisiana

Trunkline completed a records review and Phase I cultural resources surveys of most of the 

proposed Non-Liquefaction Facilities. The investigations covered both archaeological and architectural 

resources. Phase I reports for the Mainline 200-3 Loop (Laird et al., 2013a), Mainline Connector (Laird 

et al., 2013b), aboveground facilities (including Compressor Station 203-A, the LCLNG Export, Kinder 

Morgan-Lake Charles, Columbia Gulf–Egan, MEP–Perryville, Gulf Crossing–Perryville, TETCO–Allen, 

a portion of Transco Ragley, NGPL–Lakeside, Tennessee–Kaplan Meter Stations, and a 20.8-acre 

contractor storage yard) (Laird et al., 2013c), and an Addendum Phase I report for the Texas Gas–

Woodlawn Meter Station (Laird, 2014b), were provided to the FERC and the Louisiana SHPO. Cultural 

resources surveys were not conducted for the existing Pollock, Longville, and Epps Compressor Stations, 

the US 190 Meter Station, and several access roads because they were exempt from survey in accordance 

with Trunkline’s May 2014 agreement with the Louisiana SHPO (see above). 

The records review did not identify any known archaeological resources within the survey areas 

or any known historic architectural resources within or near the proposed Non-Liquefaction Facilities.
4-107

The Phase I cultural resources surveys included examination of a 200- to 400-foot-wide corridor 

encompassing the proposed pipeline rights-of-way and associated ATWSs, 50-foot-wide corridors along 

the proposed access roads, as well as examination of parcels for the compressor station, contractor storage 

yard, and the new and modified meter stations. In total, about 1,011 acres were surveyed. The cultural 

resources survey consisted of pedestrian surface inspection of areas with greater than 25 percent surface 

visibility, and systematic subsurface shovel testing of areas that were not inundated or obviously 

disturbed past the depth of potential archaeological deposits. A total of 2,321 shovel tests were 

excavated. 

Trunkline did not identify any archaeological resources within the surveyed areas. Trunkline also 

examined the areas surrounding the pipelines, compressor station, new meter stations, meter station 

modifications, access roads, and contractor storage yard for architectural resources that could be visually 

impacted by those facilities. Trunkline defined the area of potential visual impact as the surrounding 

areas within the line of sight of each proposed facility. Trunkline did not identify any architectural 

resources within those areas.

In three separate letters (one for each Phase I report reviewed) dated September 4, 2013, as well 

as an additional letter dated March 17, 2014 (for the Addendum Phase I report), the Louisiana SHPO 

concurred that no historic properties would be affected by construction of the Mainline 200-3 Loop, 

Mainline Connector, aboveground facilities, and the Texas Gas–Woodlawn Meter Station. We concur 

also. 

Subsequently, Trunkline contacted the Louisiana SHPO regarding an additional 0.13-acre work 

area for the Transco Ragley Meter Station, and the proposed route of the HDD crossing of the Calcasieu 

River. On March 27, 2014, the Louisiana SHPO indicated that “no known historic properties will be 

affected” by Trunkline’s use of the additional Transco Ragley Meter Station work area or by Trunkline’s 

proposed route of the HDD crossing of the Calcasieu River. Following the issuance of the draft EIS, 

Trunkline redesigned the Calcasieu River HDD to use an alternate alignment and advised the Louisiana 

SHPO of this modification. On July 23, 2015, the Louisiana SHPO indicated that “no known historic 

properties will be affected” by the revised Calcasieu River HDD crossing. We concur also.

Mississippi

Trunkline contacted the Mississippi SHPO regarding the activities at the existing Shaw 

Compressor Station. In a letter dated May 16, 2013, the SHPO concluded that the proposed modifications 

at the Shaw Compressor Station would have no effect on cultural resources. We concur. 

Subsequently, Trunkline contacted the Mississippi SHPO regarding the proposed modifications to 

the existing launcher barrel facility situated on the east bank of the Mississippi River. In a letter dated 

April 14, 2014, the SHPO indicated that “no cultural resources are likely to be affected” by the 

modifications to this facility. We concur. 

Arkansas

Trunkline contacted the Arkansas SHPO regarding the proposed installation of a new bidirectional barrel at the existing facility situated on the west bank of the Mississippi River. On March 31, 

2014, the SHPO indicated that “no known historic properties will be affected” by the installation of this 

facility. We concur.
4-108

4.10.2.2 Compliance with the National Historic Preservation Act

Cultural resources surveys have been completed for the Non-Liquefaction Facilities. The 

Louisiana, Mississippi, and Arkansas SHPOs, as well as the FERC, agree that no historic properties 

would be affected by these facilities. Therefore, the process of complying with Section 106 of the NHPA 

has been completed for the Non-Liquefaction Facilities.

4.10.3 Unanticipated Discovery Plan

Lake Charles LNG and Trunkline prepared an Unanticipated Discovery Plan that they would 

implement in the event that cultural resources or human remains are encountered during construction of 

the proposed project components in Louisiana. We requested minor revisions to the plan, and Lake 

Charles LNG and Trunkline provided a revised plan that we find acceptable. Lake Charles LNG and 

Trunkline subsequently provided a copy of the plan to the Louisiana SHPO; on April 2, 2014, the 

Louisiana SHPO responded that it had reviewed and accepted the plan.

Trunkline prepared Unanticipated Discovery Plans for the Non-Liquefaction Facilities in 

Mississippi and Arkansas that it would implement in the event that cultural resources or human remains 

are encountered during construction of project components in those states. We requested minor revisions 

to the plans, and Trunkline provided revised plans that we find acceptable. 

Trunkline subsequently provided copies of the Mississippi and Arkansas Unanticipated Discovery 

Plans to the Mississippi and Arkansas SHPOs, respectively. The Mississippi SHPO responded that it 

found the plan to be acceptable, but suggested that the Oklahoma Band of Choctaw Indians Tribal 

Historic Preservation Officer be added to the list of tribes to be notified if an unanticipated discovery of 

prehistoric material is made during project construction. The Arkansas SHPO made several 

recommendations for revisions to the Arkansas plan. Trunkline submitted revised plans addressing the 

Mississippi and Arkansas SHPOs’ comments. We find the revised plans acceptable. 

4.10.4 Native American Consultation

We sent our NOI and supplemental NOI to the following federally recognized Native American 

tribes: the Caddo Nation; Chitimacha Tribe of Louisiana; Jena Band of Choctaw Indians; the Coushatta 

Tribe of Louisiana; the Mississippi Band of Choctaw Indians; the Choctaw Nation of Oklahoma; the 

Tunica-Biloxi Tribe of Louisiana; and the Alabama Coushatta Tribe of Texas. The NOI requested 

comments on the proposed project and encouraged attendance at the FERC’s public scoping meeting. We 

received a response to the initial NOI from the Choctaw Nation of Oklahoma requesting copies of 

correspondence received from the Mississippi SHPO, as well as copies of the cultural resources survey 

reports. The Choctaw Nation of Oklahoma reiterated this request in an April 9, 2013 letter to the FERC 

acknowledging receipt of the supplemental NOI. We directed Lake Charles LNG and Trunkline to 

provide copies of the requested information to the Choctaw Nation of Oklahoma, which they provided on 

May 12, 2014. In a June 20, 2014 response, the Choctaw Nation of Oklahoma indicated it was unaware 

of any cultural or sacred sites within the immediate project area and that work should proceed as planned, 

but requested to be contacted in the event that Native American cultural objects or human remains were 

encountered during construction. The Unanticipated Discovery Plans provide for notification of Native 

American tribes in the event of a discovery. We did not receive responses to the NOI or supplemental 

NOI from any of the other tribes.

We sent a follow-up letter to each of the tribes on September 28, 2012. The letters requested 

comments from the tribes and assistance in identifying properties of traditional, religious, or cultural 

importance that may be affected by the proposed project. We received a letter from the Jena Band of 
4-109

Choctaw Indians deferring to the Coushatta Tribe of Louisiana. To date, we have received no other 

responses.

Lake Charles LNG and Trunkline sent three letters (for the liquefaction facility, the NonLiquefaction Facilities, and an update on all project facilities) to the Caddo Nation, Chitimacha Tribe of 

Louisiana, Jena Band of Choctaw Indians, the Coushatta Tribe of Louisiana, the Tunica-Biloxi Tribe of 

Louisiana, and the Alabama Coushatta Tribe of Texas on August 13, 2012; February 5, 2013; and March 

3, 2014. The letters requested the tribes communicate any concerns about potential impacts the proposed 

project may have on archaeological sites, burials, or traditional cultural properties. In an April 8, 2013 

response, the Jena Band of Choctaw Indians requested that Lake Charles LNG and Trunkline provide 

additional information and the cultural resource survey reports for review. The Jena Band of Choctaw 

Indians reiterated these requests in an email to Lake Charles LNG and Trunkline dated March 13, 2014. 

Lake Charles LNG and Trunkline provided the reports and other requested information to the tribe on

May 9, 2014. To date, no comments have been received from the tribe. 

In a letter dated April 2, 2014, the Coushatta Tribe of Louisiana concurred with Lake Charles 

LNG’s and Trunkline’s recommendations that no historic properties would be affected by the proposed 

project. The tribe requested that it be notified if cultural resources or human remains are discovered 

during construction activities. The Unanticipated Discovery Plans provide for notification of Native 

American tribes in the event of a discovery. In a response dated April 4, 2014, the Chitimacha Tribe of 

Louisiana noted that it had no concerns or comments regarding the project. No other responses have been 

received to date to the letters sent by Lake Charles LNG and Trunkline.

4.11 AIR QUALITY AND NOISE

4.11.1 Air Quality

4.11.1.1 Regional Climate

Due to its location near the Gulf of Mexico, the Lake Charles Liquefaction Project area has a 

subtropical climate which is generally categorized as warm and wet, with mild and humid winters (EPA, 

2014a). A semi-permanent high-pressure system, known as the Bermuda High, is typically situated off of 

the Atlantic Coast. Depending on its position, it commonly draws moisture northward or westward from 

the Atlantic and Gulf of Mexico, especially during the warm season. As a result, summers in the project 

area are characteristically warm and moist with frequent thundershower activity in the afternoon and early 

evening hours. Day-to-day and week-to-week variations in the positions of the Bermuda High can have a 

strong influence on precipitation patterns. When the Bermuda High builds west over the region, hot and 

dry weather occurs, although humidity often remains relatively high. This pattern can cause heat waves 

and poor air quality (NOAA, 2013).

The Lake Charles area receives an annual average of 57.19 inches of rain. February is typically 

the driest month of the year with an annual mean of 3.28 inches, whereas June tends to be the wettest 

month with an annual mean of 6.07 inches. Snow events are rare with an annual mean of 0.3 inches of 

snow which is only likely to occur in January or February. Temperatures range from an average of 

60.6 degrees Fahrenheit in February to an average of 91.3 degrees Fahrenheit in August (NOAA, 2004). 

Wind direction in the Lake Charles area is primarily either north or south depending on the time 

of year. Spring and summer months experience winds coming from the south whereas wind direction is 

typically from the north or northeast during the fall and winter months. On average, wind speed varies

between 6 and 10 miles per hour (NOAA, 1998). 
4-110

4.11.1.2 Existing Air Quality

Ambient Air Quality Standards

Criteria Pollutants

The EPA, as required by the CAA, has established National Ambient Air Quality Standards 

(NAAQS) to protect public health (primary standards) and public welfare (secondary standards). 

Standards have been set for six principal pollutants that are called “criteria pollutants.” These criteria 

pollutants are ground-level ozone, carbon monoxide (CO), oxides of nitrogen (NOX), sulfur dioxide 

(SO2), respirable and fine particulate matter (inhalable particulate matter with an aerodynamic diameter 

less than or equal 10 microns [PM10] and less than or equal to 2.5 microns [PM2.5]), and airborne lead 

(Pb). Ozone is not directly emitted into the atmosphere from an emissions source. Ozone develops as a 

result of a chemical reaction between NOX and volatile organic compounds (VOC) in the presence of 

sunlight. Therefore, NOX and VOCs are often referred to as ozone precursors. Table 4.11.1-1 lists the 

NAAQS for the six criteria pollutants. Louisiana, Arkansas, and Mississippi have adopted the NAAQS.

Greenhouse Gases

In April 2007 the Supreme Court ruled that greenhouse gases (GHG) fell within the CAA’s 

definition of “air pollutant,” and required the EPA to conduct an endangerment finding for GHGs. On 

December 7, 2009 the EPA issued findings that current and projected concentrations of six key wellmixed GHGs in the atmosphere threaten the public health and welfare of current and future generations 

(EPA, 2014c). The six key GHGs are:

 carbon dioxide (CO2);

 methane (CH4);

 nitrous oxide (N2O);

 hydrofluorocarbons (HFC);

 perfluorocarbons (PFC); and

 sulfur hexafluoride (SF6).

These findings were based on emissions associated with new motor vehicles; however, regulation 

of GHGs has expanded to include major stationary sources of air pollutants. There are no NAAQS for 

GHGs.

GHGs are often represented by an aggregate number expressed in units of carbon dioxide 

equivalent (CO2e). A global warming potential (GWP) factor has been determined by the EPA for each 

GHG, which is a relative measure of a GHG’s ability to absorb solar radiation and its residence time in 

the atmosphere in comparison to that of CO2. For example, CO2 has a GWP of 1, whereas CH4 has a 

GWP of 25 and N2O has a GWP of 298.
4-111

TABLE 4.11.1-1

National Ambient Air Quality Standards

Criteria Pollutant

Primary/ 

Secondary Averaging Time Level Form

CO Primary 8-hour 9 ppm (10,000 μg/m3) Not to be exceeded more than 

once per year 1-hour 35 ppm (40.000 μg/m3

)

Pb Primary and 

secondary

Rolling 3-month 

average

0.15 μg/m3 a Not to be exceeded

Nitrogen dioxide (NO2) Primary 1-hour 100 ppb (189 μg/m3) 98th percentile, averaged over 3

years

Primary and 

secondary

Annual 53 ppbb(100 μg/m3) Annual mean

Ozone Primary and 

secondary

8-hour (2008) 0.075 ppmc(150 μg/m3) Annual fourth-highest daily 

maximum 8-hr concentration, 

averaged over 3 years

Primary and 

secondary

8-hour (1997) 0.08 ppm (157 μg/m3)

Primary and 

secondary

1-Hour 0.12 ppm (235 μg/m3)

Particle pollution

PM2.5 Primary Annual 12 μg/m3 Annual mean, averaged over 3 

years

Secondary Annual 15 μg/m3

Primary and 

secondary

24-hour 35 μg/m398th percentile, averaged over 3 

years

PM10 Primary and 

secondary

24-hour 150 μg/m3 Not to be exceeded more than 

once per year on average over 3 

years

SO2 Primary 1-hour 75 ppb (195 μg/m3)d 99th percentile of 1-hour daily 

maximum concentrations, 

averaged over 3 years

Secondary 3-hour 0.5 ppm (1,300 μg/m3) Not to be exceeded more than 

once per year

____________________

a

Final rule signed October 15, 2008. The 1978 lead standard (1.5 μg/m3as a quarterly average) remains in effect until 1 

year after an area is designated for the 2008 standard, except that in areas designated nonattainment for the 1978, the 

1978 standard remains in effect until implementation plans to attain or maintain the 2008 standard are approved.

b

The official level of the annual NO2 standard is 0.053 ppm, equal to 53 ppb, which is shown here for the purpose of clearer 

comparison to the 1-hour standard.

c

Final rule signed March 12, 2008. The 1997 ozone standard (0.08 ppm, annual fourth-highest daily maximum 8-hour 

concentration, averaged over 3 years) and related implementation rules remain in place. In 1997, EPA revoked the 1-

hour ozone standard (0.12 ppm, not to be exceeded more than once per year) in all areas, although some areas have 

continued obligations under that standard (“anti-backsliding”). The 1-hour ozone standard is attained when the expected 

number of days per calendar year with maximum hourly average concentrations above 0.12 ppm is less than or equal 

to 1.

d

Final rule signed June 2, 2010. The 1971 annual and 24-hour SO2 standards were revoked in that same rulemaking. 

However, these standards remain in effect until 1 year after an area is designated for the 2010 standard, except in areas 

designated nonattainment for the 1971 standards, where the 1971 standards remain in effect until implementation plans to 

attain or maintain the 2010 standard are approved.

Notes: ppm = parts per million; μg/m3= microgram per cubic meter; ppb = parts per billion

Source: EPA, 2014b
4-112

Air Quality Control Regions and Attainment Status

An air quality control region (AQCR) is defined under 42 USC §7407(c) as “...any interstate area 

or major intrastate area which [the Administrator of the EPA] deems necessary or appropriate for the 

attainment and maintenance of ambient air quality standards.” Each AQCR, or portion(s) of an AQCR, is 

classified as either attainment, non-attainment, or maintenance with respect to the NAAQS. 

Areas where ambient air concentrations of the criteria pollutants are below the levels listed in the 

NAAQS are considered in attainment; if ambient air concentrations of criteria pollutants are above the 

NAAQS levels then the area is considered to be non-attainment. Areas that have been designated 

nonattainment but have since demonstrated compliance with the NAAQS are designated maintenance for 

that pollutant. Maintenance areas are treated similar to attainment areas for the permitting of stationary 

sources; however, specific provisions may be incorporated through the state's approved maintenance plan 

to ensure that the air quality would remain in compliance with the NAAQS for that pollutant. 

Maintenance areas retain the classification for 20 years before being re-classified as attainment areas. 

Areas where air quality data is not available are considered to be unclassifiable and are treated as 

attainment areas. The entire Lake Charles Liquefaction Project area is classified as in attainment for all 

criteria pollutant standards.

Air Quality Monitoring and Background Concentrations

Ambient air monitoring operations in Louisiana are the responsibility of the LDEQ Air Quality 

Assessment Division, which has developed a statewide network of stationary monitoring stations to 

collect direct measurements of air pollutant concentrations. Data from these air monitoring sites is 

available through the EPA’s AIRDATA database which collects air monitoring data from all over the 

country. The majority of work associated with the Lake Charles Liquefaction Project would be in the 

Calcasieu Parish, Louisiana area. The nearest or most representative monitors for ambient air 

concentrations of PM2.5, SO2, nitrogen dioxide (NO2), and ozone are in Lake Charles, Calcasieu Parish, 

Louisiana. The nearest and most representative monitors for ambient air concentrations of PM10, CO, and 

Pb are in Galveston, Jefferson, and Harris Counties, Texas, respectively.

Ambient air quality monitoring data from the 3-year period 2011 to 2013 are summarized in 

table 4.11.1-2 for those monitors that were nearest or most representative of the Lake Charles 

Liquefaction Project area. For each monitor, table 4.11.1-2 lists the applicable concentrations such as 

annual mean concentration in each year and/or a near maximum short-term concentration. Second-high 

short-term concentrations are listed for most pollutants, but table 4.11.1-2 includes the fourth highest 

8-hour concentration for ozone, the 98th percentile 24-hour concentration for PM2.5, the 98th percentile 

1-hour concentration for NO2, and the 99th percentile 1-hour concentration for SO2.

The concentrations listed in table 4.11.1-2 are maximum or near maximum values for the 

identified monitors. As such, they are not necessarily representative of current actual air quality in the 

immediate vicinity of the project.
4-113

TABLE 4.11.1-2

Ambient Air Quality Concentrations for Areas Near the Lake Charles Liquefaction Project

Pollutant

Averaging 

Period Rank Location 2013 2012 2011 Units Monitor(s)

CO 1-hour 2

nd high Jefferson County, TX 0.7 0.7 0.9 ppm A

8-hour 2

nd high Jefferson County, TX 0.6 0.5 0.5 ppm A

NO2 Annual Mean Calcasieu Parish, LA N/A N/A 6 ppb B

1-hour 98th percentile Calcasieu Parish, LA 30 27 32 ppb B

Ozone 8-hour 4

th high Calcasieu Parish, LA 0.07 0.075 0.069 ppm B

PM2.5 24-hour 98th percentile Calcasieu Parish, LA 17 20 20 μg/m3 E

Annual Mean Calcasieu Parish, LA N/A N/A 8.9 μg/m3 E

PM10 24-hour 2

nd high Galveston County, TX 46 54 51 μg/m3 C

SO2 1-hour 99th percentile Calcasieu Parish, LA 31 42 37 ppb B

3-hour 2

nd high Calcasieu Parish, LA N/A N/A N/A ppb B

Lead Quarterly Maximum Harris County, TX N/A N/A N/A μg/m3 D

____________________

Monitor Key:

A = Seattle Street, Nederland, Jefferson County, Texas(monitor # 482451035)

B = 2646 John Stine Rd, Lake Charles, Calcasieu Parish, Louisiana (monitor # 220190008)

C = 2516 Texas Avenue, Texas City, Galveston County, Texas (monitor # 481670004)

D = 1262 1⁄2 Mae Drive, Houston, Harris County, Texas (monitor #482011034)

E = Common & E. McNeese, Lake Charles, Calcasieu Parish, Louisiana (monitor # 220190010)

Notes: 

μg/m3= micrograms per cubic meter

ppm = parts per million

ppb = parts per billion

N/A = data not yet available

Source: epa.gov/airdata

4.11.1.3 Regulatory Requirements for Air Quality

The LDEQ is the lead air permitting authority for the Lake Charles Liquefaction Project facilities 

in Louisiana. The LDEQ's air quality regulations are codified in Title 33 of the Louisiana Administrative 

Code (LAC) Part III Chapters 1 through 59. The regulations incorporate the federal program 

requirements listed in 40 CFR Parts 50-99 and establish permit review procedures for all facilities that can 

emit pollutants to the ambient air. New facilities are required to obtain an air quality permit prior to 

initiating construction. Facilities can trigger additional review by the EPA if the facility triggers PSD 

permitting requirements.

The Mississippi Department of Environmental Quality (MDEQ) Air Division is the air permitting 

authority for the project facilities in Mississippi. The MDEQ’s air quality regulations are codified in Title 

11 of the Mississippi Administrative Code, Part 2, Chapters 1-10.

The project components proposed to be constructed in Arkansas would not result in significant 

emissions and would not be subject to air quality regulations in that state. 

Federal Regulatory Requirements 

New Source Review – Prevention of Significant Deterioration 

Congress established the New Source Review (NSR) preconstruction permitting program as part 

of the 1977 CAA Amendments. Federal preconstruction review under NSR is conducted under separate 

procedures for sources in attainment areas and sources in nonattainment areas. Nonattainment New 
4-114

Source Review applies to sources in nonattainment areas. Since the project is not located in any 

nonattainment areas, this process does not apply and is not discussed further. PSD applies to new major 

sources or major modifications at existing sources located in attainment areas or in areas that are 

unclassifiable. PSD is intended to keep new air emission sources from causing the existing air quality to 

deteriorate beyond acceptable levels. Under PSD, any new major source or major modification of an 

existing source of air pollutants is required to obtain an air quality permit before beginning construction. 

The definition of a PSD major source of air pollutants as applicable to the project is any stationary source 

which emits, or has the potential to emit, 250 tons per year (tpy) of a regulated criteria pollutant (40 CFR 

Part §51.166(b)(1)(i)(b)). 

PSD can also apply to an existing major source when physical modifications are made to the 

source that result in increased emissions above the “major modification” or significant emission rate 

(SER) for the respective pollutant. The SERs for the pollutants applicable to the Lake Charles 

Liquefaction Project are listed in table 4.11.1-3. 

TABLE 4.11.1-3

Major Stationary Source/Major Modification Emission Thresholds

Pollutant

Major Stationary Source

Threshold Level (tpy)

Major Modification

Significant Net Increase (tpy)

Ozone /VOC/NOX 250 40

CO 250 100

SO2 250 40

PM 250 25

PM10 250 15

PM2.5 250 10

Pb 250 0.6

GHG N/A N/A

GHG Reporting Rule

In September 2009, the EPA issued the final Mandatory Reporting of Greenhouse Gases 

Rule, requiring reporting of GHG emissions from suppliers of fossil fuels and facilities that emit greater

than or equal to 25,000 metric tpy of GHG (reported as CO2). In November 2010, the EPA signed a

rule finalizing GHG reporting requirements for the petroleum and natural gas industry in 40 CFR Part 98

Subpart W. The industry separates LNG storage facilities from LNG import and export equipment

because the former are considered part of the source category regulated by Subpart W. The rule does not 

apply to construction emissions.

The new liquefaction facilities would potentially be subject to the GHG Mandatory Reporting Rule. 

The rule establishes reporting requirements based on actual emissions; however, it does not require emission 

controls. Lake Charles LNG would monitor emissions in accordance with the reporting rule. If actual 

emissions exceed the 25,000 tpy CO2e reporting threshold, Lake Charles LNG would be required to report 

its GHG emissions to the EPA.

GHG Tailoring Rule

On May 13, 2010, the EPA issued a PSD GHG Tailoring Rule. The rule tailored specific 

applicability thresholds for GHG stationary sources. However, on June 23, 2014, the Supreme Court ruled 

that the EPA cannot require PSD permitting based solely on GHG emissions, striking down a portion of 

the rule. 
4-115

The GHG Tailoring Rule specified that as of July 1, 2011, new sources would become subject to 

PSD with regard to GHGs if the source emits or has the potential to emit greater than 100,000 tpy of 

CO2e. An existing Title V facility was subject to a 75,000 tpy CO2e significance threshold for any 

modifications. However, based on the Supreme Court ruling, in order for PSD permitting requirements to 

apply, the new or modified source must be subject to PSD for a criteria pollutant in order to be considered 

a major PSD source for GHGs, and for such sources only Best Available Control Technology (BACT) 

would apply to the sources of GHG emissions.

PSD Requirements 

Once a facility is subject to PSD, the following requirements apply: 

 installation of BACT;

 air quality monitoring and modeling analyses to ensure that a project’s incremental 

increase of emissions will not cause or contribute to a violation of any NAAQS;

 notification to the federal land manager of nearby Class I areas and modeling if 

applicable; 

 a growth, soil and vegetation, and visibility analysis; and

 public comment on the permit.

BACT is an emissions limitation which is based on the maximum degree of control that can be 

achieved. It is a case-by-case decision that considers energy, environmental, and economic impact. 

BACT can be add-on control equipment or modification of the production processes or methods. This 

includes fuel cleaning or treatment and innovative fuel combustion techniques. BACT may be a design, 

equipment, work practice, or operational standard if imposition of an emissions standard is infeasible 

(EPA, 2014d).

The air quality monitoring and modeling analysis involves an assessment of existing air quality, 

which may include ambient monitoring data and air quality dispersion modeling results, and predictions, 

using dispersion modeling, of ambient concentrations that will result from the proposed project and future 

growth associated with the project (EPA, 2014d). 

Federal Class I areas are areas of special national or regional natural, scenic, recreational, or 

historic value for which the PSD regulations provide special protection. There are 156 Class I areas in the 

United States. If a new source or major modification of an existing source is subject to the PSD program 

requirements and is within 62 miles (100 kilometers) of a Class I area, the facility is required to notify the 

appropriate federal officials and assess the impacts of the proposed project on the Class I area. 

The proposed liquefaction facility would be subject to PSD permitting requirements as discussed 

in more detail below. Although the Longville Compressor Station is an existing major source, the 

expected increase in emissions due to the proposed modifications would not exceed the SERs listed in 

table 4.11.1-3; therefore, it would not be subject to PSD permitting requirements. Compressor Station 

203-A also would not be subject to the major source PSD requirements because it would not emit 

250 tons or more of any criteria pollutant, and it is not listed as belonging to one of 28 specifically listed 

industrial source categories under 40 CFR 52.21 (b) (1) which have a 100 tpy applicability threshold. All 

other facilities associated with the Lake Charles Liquefaction Project are not expected to exceed the 

emission thresholds that would trigger PSD requirements.
4-116

The results of the PSD applicability analysis for the liquefaction facility are summarized in table 

4.11.1-4. The proposed liquefaction facility would be permitted as a separate, stand-alone stationary 

source. However, as the liquefaction facility would be adjacent to the existing LNG terminal and both 

emission sources would be under common operational control, Lake Charles LNG anticipates that the two 

facilities would be addressed as a single source for PSD applicability and subject to the net emission 

increase thresholds shown above. The PSD applicability analysis for the liquefaction facility indicates 

that operational emission increases would exceed the significant net emission increase thresholds listed in 

table 4.11.1-4 for PM10, PM2.5, NOX, CO, and VOC.

TABLE 4.11.1-4

Prevention of Significant Deterioration Applicability Analysis

for the Liquefaction Facility at the Existing LNG Terminal

Pollutant

Significant

Emission Rate

(tpy)

Proposed New LNG 

Liquefaction Facility 

Emissions

(tpy)

Creditable 

Contemporaneous 

Emission Change (tpy)

Net Emission 

Increase

(tpy)

Significant Net 

Emission Increase 

(Yes/No)

PM10 15 202.47 0 202.47 Yes

PM2.5 10 202.47 0 202.47 Yes

NOX 40 750.41 0 750.41 Yes

SO2 40 39.89 0 39.89 No

CO 100 1,878.83 0 1,878.83 Yes

Total VOC 40 58.18 0 58.18 Yes

CO2e N/A 4,513,540 0 4,513,540 N/A

____________________

N/A = Not applicable.

Note: Ozone is assessed through two precursors: NOX and VOC, and is not specifically listed in the table. 

Lake Charles LNG conducted a BACT analysis for the liquefaction facility as required for its 

PSD permit application. The analysis uses a “top-down” approach developed by the EPA for determining 

the best type of control technology for the liquefaction facility. The approach includes five basic steps: 

1) identification of all available control options for the emission unit in question; 2) evaluation of the 

technical feasibility of the control options identified in step one; 3) ranking of remaining control 

technologies from step two based on control effectiveness for the pollutant under review; 4) consideration 

of the energy, environmental, and economic impacts of available and technically feasible control 

technology options; and 5) selection of the most effective control alternative not eliminated in step four 

and establishment of a corresponding emission limit.

Tables 4.11.1-5 and 4.11.1-6 summarize the findings of the BACT analysis for the liquefaction 

facility with respect to criteria and GHG pollutants, respectively. 

In accordance with 40 CFR Part 52.21, a demonstration of compliance with the NAAQS and PSD 

Increment standards is required for the construction of any new major stationary source or any project at 

an existing major stationary source in an area designated as attainment or unclassifiable under the CAA. 

The ambient air quality in Calcasieu Parish is designated as attainment for all criteria pollutants. Based 

on the PSD analysis for the proposed liquefaction facility, Lake Charles LNG conducted dispersion 

modeling for CO, NO2, PM10, and PM2.5. The procedures, assumptions, and results of the air dispersion 

analysis are documented in a detailed modeling report that was submitted to the LDEQ in September 

2014 (Trinity Consultants, 2014a).
4-117

TABLE 4.11.1-5

Best Available Control Technology Analysis Summary for Criteria Pollutants

for the Lake Charles Liquefaction Project Liquefaction Facility

Source Pollutant Proposed Emission Controls Proposed Emission Limits

Gas Turbines NOX Selective catalytic reduction (90 percent

control efficiency) and low Nox burners

5 ppm (volumetric dry) corrected to

15 percent O2 on a 3-hour average.

CO Post combustion catalytic oxidation

CO Turndown (COTD)

10 ppm (volumetric dry) corrected to 

15 percent O2 on a 3-hour average. 

Performance test will be used to 

demonstrate compliance.

VOC Good combustion practices

Post combustion catalytic oxidation

Work practice standards

PM Low PM-emitting gaseous fuels only, 

good combustion and maintenance 

practices

Work practice standards

Thermal Oxidizers NOX Low NOx burners and good combustion 

practices 

Work practice standards

CO Good combustion practices Work practice standards

PM Low PM-emitting gaseous fuels only, 

good combustion and maintenance 

practices

Work practice standards

AGRU Process Vents VOC Thermal Oxidizer 99.9 percent efficiency; Minimum

firebox temperature for ongoing

compliance and leakless components

Flares NOX 40 CFR Part 60.18 and good combustion 

practices

Minimum heating value (British 

thermal units per standard cubic foot)

and maximum tip velocity based on 

40 CFR 60.18

CO 40 CFR Part 60.18 and good combustion 

practices

NSPS standards

Hot Oil Heater NOX Low NOx burners and good combustion 

practices

Work practice standards

CO Good combustion practices Work practice standards

VOC Good combustion practices Work practice standards

PM Good combustion practices Work practice standards

Fugitives

Standby Generator

Diesel Engines

Firewater Pump 

Diesel Engines

Condensate Storage 

Tank

VOC

VOC, NOX, CO, PM

Leak detection & repair program

Good combustion practices

Good combustion practices

Internal floating roof with liquid mounted 

primary and rim mounted secondary 

seals

Monitoring on a monthly basis with a 

leak detection threshold of 500 parts 

per million by volume (ppmv)

Non-emergency maintenance and 

testing limited to 100 hours per year

Non-emergency maintenance and 

testing limited to 100 hours per year

Monitoring on a monthly basis with a 

leak detection threshold of 500 ppmv
4-118

TABLE 4.11.1-6

Best Available Control Technology Analysis Summary for Greenhouse Gas Pollutants

for the Lake Charles Liquefaction Project Liquefaction Facility

Source Pollutant Proposed Emission Controls Proposed Emission Limits

Gas Turbines CO2 Low carbon fuels, design and operational 

energy efficiency including:

Excess O2 analyzer

Preventative Maintenance

Tuning /Calibration

Fuel Gas Flow Meter

Oxygen control

Monthly calibration, check filters, etc.

Quarterly maintenance

Tune ups and calibration performed quarterly

Classify as environmentally critical instruments 

and thus receive an increased priority for 

preventative maintenance and repairs

Control O2based on O2 analyzer output to assure 

high efficiency combustion

Thermal Oxidizers Design and operational energy efficiency 

including:

Excess O2 analyzer

Preventative Maintenance

Tuning /Calibration

Fuel Gas Flow Meter

Oxygen control

Firebox temperature

Monthly calibration, check filters, etc.

Quarterly maintenance

Tune ups and calibration performed quarterly

Classify as environmentally critical instruments 

and thus receive an increased priority for 

preventative maintenance and repairs

Control O2based on O2 analyzer output to assure 

high efficiency combustion

Monitor Chamber exit temperature

Flares Design and operated in accordance with 40 

CFR Part 60.18 including:

Compliance with an annual CO2e emission 

limit 

Compliance with 40 CFR Part 98 Subpart W

Minimum heating value (British thermal units per 

standard cubic foot) and maximum tip velocity 

based on 40 CFR Part 60.18

Demonstrated on a rolling 12 month basis

Calculations performed monthly based upon fuel 

flow and heating value

Standby Generator 

Diesel Engines

Good combustion practice Non-emergency maintenance and testing limited 

to 100 hours per year

Firewater pump 

engines

Good combustion practice Non-emergency maintenance and testing limited 

to 100 hours per year

Fugitives Leak detection & repair program Monitoring on a monthly basis with a leak 

detection threshold of 500 parts per million by 

volume (ppmv)

Gas Turbines CH4 Low carbon fuels, design and operational 

energy efficiency including:

Excess O2 analyzer

Preventative Maintenance

Tuning /Calibration

Fuel Gas Flow Meter

Oxygen control

Monthly calibration, check filters, etc.

Quarterly maintenance

Tune ups and calibration performed quarterly

Classify as environmentally critical instruments 

and thus receive an increased priority for 

preventative maintenance and repairs

Control O2based on O2 analyzer output to assure 

high efficiency combustion

Thermal Oxidizers Low carbon fuels, design and operational 

energy efficiency including:

Excess O2 analyzer

Preventative Maintenance

Tuning /Calibration

Fuel Gas Flow Meter

Oxygen control

Monthly calibration, check filters, etc.

Quarterly maintenance

Tune ups and calibration performed quarterly

Classify as environmentally critical instruments 

and thus receive an increased priority for 

preventative maintenance and repairs

Control O2based on O2 analyzer output to assure 

high efficiency combustion

Flares Design and operated in accordance with 40 

CFR Part 60.18 including:

Compliance with an annual CO2e emission 

limit 

Compliance with 40 CFR Part 98 Subpart W

Minimum heating value (British thermal units per 

standard cubic foot) and maximum tip velocity 

based on 40 CFR Part 60.18

Demonstrated on a rolling 12 month basis

Calculations performed monthly based upon fuel 

flow and heating value
4-119

TABLE 4.11.1-6 (cont’d)

Best Available Control Technology Analysis Summary for Greenhouse Gas Pollutants

for the Lake Charles Liquefaction Project Liquefaction Facility

Source Pollutant Proposed Emission Controls Proposed Emission Limits

Standby generator 

diesel engines

Good combustion practice Non-emergency maintenance and testing limited 

to 100 hours per year

Firewater pump 

engines

Good combustion practice Non-emergency maintenance and testing limited 

to 100 hours per year

Fugitives Leak detection & repair program Monitoring on a monthly basis with a leak 

detection threshold of 10,000 ppmv for CH4

Gas Turbines N2O Design and operational energy efficiency 

including:

Excess O2 analyzer

Preventative Maintenance

Tuning /Calibration

Fuel Gas Flow Meter

Oxygen control

Monthly calibration, check filters, etc.

Quarterly maintenance

Tune ups and calibration performed quarterly

Classify as environmentally critical instruments 

and thus receive an increased priority for 

preventative maintenance and repairs

Control O2based on O2 analyzer output to assure 

high efficiency combustion

Thermal Oxidizers Design and operational energy efficiency Work practice standards

Flares Design and operational energy efficiency Design and operational energy efficiency

Standby generator 

diesel engines

Good combustion practice Non-emergency maintenance and testing limited 

to 100 hours per year

Firewater pump 

engines

Good combustion practice Non-emergency maintenance and testing limited 

to 100 hours per year

Lake Charles LNG’s analysis included:

 a description of all assumptions made for modeling purposes; 

 feasible “worst-case” operating scenarios (those that would produce the highest 

concentration of air emissions); 

 evaluation of the emissions from all of the stationary sources at the proposed liquefaction 

facility; 

 emissions from a marine flare and two emergency generators that would be installed at 

the existing LNG terminal as part of the proposed liquefaction facility (the emissions 

from these three sources are included in the liquefaction facility air permit application, as 

well as being included in the air dispersion modeling analysis for the liquefaction 

facility); and

 a PSD Screening Analysis, NAAQS Analysis, and PSD Increment Analysis

The results of this modeling analysis were compared to the significant impact levels, as well as 

added to the background levels and compared to the NAAQS. The results of this modeling analysis are 

detailed in section 4.11.1.5, Operational Air Emissions Impacts and Mitigation.

PSD requirements also include an analysis of the impacts from the proposed project on Class I 

areas, growth, soil and vegetation, and visibility. The following is a summary of the analyses performed 

for these impacts.

Class I Area Analysis: There are no Class I areas within 300 kilometers of the facility. 

Therefore, no Class I modeling analysis was necessary.
4-120

Growth Impact Analysis: The elements of the growth analysis include a projection of the 

associated industrial, commercial, and residential growth that would occur in the area of impact (AOI) 

due to the proposed project, including the potential impact on ambient air due to this growth. Lake 

Charles LNG anticipates that about 250 new employees would be hired as a result of the proposed project, 

and that all of these new employees would be existing residents of Calcasieu Parish and/or nearby 

parishes. Lake Charles LNG does not anticipate any associated industrial or commercial growth due to 

the proposed project. Therefore, negligible growth‐related ambient air impacts are expected.

Soil and Vegetation Impact Analysis: For most types of soil and vegetation, ambient 

concentrations of criteria pollutants below the secondary NAAQS will not result in harmful effects (EPA, 

1990). Lake Charles LNG’s modeling analysis demonstrates compliance with the NAAQS standards. 

Therefore it is presumed that emissions from the proposed project would not result in harmful effects on 

either soil or vegetation.

Visibility Analysis: Based on a conservative Level 1 visibility analysis (Trinity Consultants, 

2014a), visibility impacts from the proposed project would not be above the critical screening criteria; 

thus, an additional refined analysis is not necessary. As such, significant visibility or regional haze 

impacts from the project are not expected.

New Source Performance Standards

Section 111 of the CAA authorized the EPA to develop technology-based standards which apply 

to specific categories of stationary sources. These standards, referred to as New Source Performance 

Standards (NSPS), are found in 40 CFR Part 60. The NSPS apply to new, modified, and reconstructed 

affected facilities in specific source categories.

We have determined that the following NSPS would be applicable to one or more project 

components. 

Subpart A – General Provisions

The general provisions listed in Subpart A include broader definitions of applicability and various 

methods for maintaining compliance with requirements listed in subsequent subparts of 40 CFR Part 60. 

Subpart A also specifies the state agencies to which the EPA has delegated authority to implement and 

enforce standards of performance. The LDEQ has been delegated authority for all 40 CFR Part 60 

standards promulgated by the EPA, except for Subpart AAA – Standards of Performance for New 

Residential Wood Heaters, which is not applicable to the Lake Charles Liquefaction Project [40 CFR Part 

60.4(e)(2)]. Equipment at the LNG Terminal, the liquefaction facility, Compressor Station 203-A, the 

Longville Compressor Station, and the meter stations subject to any of the NSPS subparts listed below 

would all be subject to Subpart A. Lake Charles LNG and Trunkline have outlined the methods and 

measures by which they would comply with the specific requirements of each applicable NSPS subpart 

listed below in section 22 of the Approval of Emissions (AAE) form included in their respective permit 

applications submitted to the LDEQ (Trinity Consultants, 2014b, c, and d).

Subpart Kb – Standards of Performance for Volatile Organic Liquid Storage Vessels (Including 

Petroleum Liquid Storage Vessels) for Which Construction, Reconstruction, or Modification Commenced 

After July 23, 1984

This subpart regulates emissions of VOCs from various forms of volatile organic liquid storage 

tanks with a capacity greater than or equal to 75 m3for which construction, reconstruction, or 

modification is commenced after July 23, 1984. In addition to standards for reducing emissions of VOCs, 

this subpart also requires testing of emission control devices as well as monitoring, recordkeeping, and 

reporting requirements. One fixed-roof storage tank (Condensate Storage Tank EPN 8101F) that would 
4-121

be located at the proposed liquefaction facility would be subject to NSPS Subpart Kb. The condensate 

tank would comply with the emission limitations of NSPS Subpart Kb through the installation and

maintenance of an internal floating roof in accordance with 40 CFR Part 60.112b(a)(1). The remaining 

liquefaction facility storage tanks would not be subject to NSPS Subpart Kb because the tanks would not 

meet the applicability criteria for minimum storage capacity (gallons) and/or for minimum true vapor 

pressure for the stored volatile organic liquid. The 10,000-gallon storage tank proposed to be installed at 

the Shaw Compressor Station would be exempt from this subpart because its storage capacity would be 

below the applicability criteria.

Subpart IIII – Standards of Performance for Stationary Compression Ignition Internal Combustion 

Engines

Subpart IIII applies to owners and operators of stationary compression ignition internal 

combustion engines (CI ICE) that commence construction after July 11, 2005 where the stationary CI ICE 

are: 1) manufactured after April 1, 2006 and are not fire pump engines, or 2) are manufactured as a 

certified NFPA fire pump engine after July 1, 2006.

Subpart IIII specifies emission standards, fuel requirements, compliance requirements, and testing 

requirements for CI ICE, some of which vary by model year, engine power, and displacement, and also 

specifies notification, reporting, and recordkeeping requirements for owners and operators of CI ICE 

subject to this subpart. CI ICEs located at the liquefaction facility, Compressor Station 203-A, the 

Longville Compressor Station, and the emergency generators located at the meter stations would be 

subject to Subpart IIII. 

In accordance with 40 CFR Part 60.4205(b), Lake Charles LNG and Trunkline would comply with

the emission limitation requirements by installing emergency CI ICE that are certified by the engine

manufacturer to meet the required emission limits. In addition, Lake Charles LNG and Trunkline would 

maintain and operate the emergency CI ICE in accordance with the engine manufacturer’s specifications. 

Emergency engines would not be operated in excess of 100 hours per calendar year for any combination 

of purposes or in excess of 50 hours per years in non-emergency situations. In order to ensure 

compliance with hours of operation limits, Lake Charles LNG and Trunkline would install a nonresettable hour meter prior to startup of each of the engines.

Subpart KKKK – Standards of Performance for Stationary Combustion Turbines

Subpart KKKK applies to owners and operators of stationary combustion turbines with a heat 

input peak load equal to or greater than 10.7 gigajoules (10 million British thermal units, MMBtu) per 

hour that commenced construction, modification, or reconstruction after February 18, 2005. Subpart 

KKKK regulates emissions of NOX and SO2. Subject turbines must meet the applicable emission limits 

and operational requirements as well as recordkeeping and reporting requirements of this subpart.

All of the compressor turbines at the liquefaction facility and the Solar Mars turbines to be 

installed at Compressor Station 203-A and the Longville Compressor Station would be subject to NSPS 

Subpart KKKK. The turbines would meet the less than 25 ppm NOx emission limit specified in 40 CFR

Part 60.4320(a). Additionally, for the compressor turbines at the liquefaction facility, Lake Charles LNG

would implement Selective Catalytic Reduction control technology to reduce NOx emissions to less than

25 ppm. Lake Charles LNG and Trunkline would perform annual NOx testing to demonstrate compliance

with the NOx emission limit in accordance with 40 CFR Part 60.4340(a).

Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion Engines

Subpart JJJJ applies to stationary spark ignition internal combustion engines (SI ICE) with a 

maximum engine power greater than or equal to 75 kW (100 hp). The five natural gas-fired compressor 
4-122

engines proposed to be installed at Compressor Station 203-A would be subject to this subpart. Trunkline

would comply with the engine operations and maintenance requirements, recordkeeping and reporting, and 

performance testing as outlined in 40 CFR Parts 60.4243 and 4245. 

National Emission Standards for Hazardous Air Pollutants

The National Emissions Standards for Hazardous Air Pollutants (NESHAP), codified in 40 CFR 

Parts 61 and 63, regulate the emissions of Hazardous Air Pollutants (HAP) from new and existing 

sources. Part 61, promulgated before the 1990 CAA Amendments, regulates eight hazardous substances: 

asbestos, benzene, beryllium, coke oven emissions, inorganic arsenic, mercury, radionuclides, and vinyl 

chloride. 

The 1990 CAA Amendments established a list of 189 HAPs, resulting in the promulgation of Part 

63, also known as the Maximum Achievable Control Technology (MACT) standards. Part 63 regulates 

HAPs from major sources of HAPs and specific source categories emitting HAPs. Some NESHAPs may 

apply to non-major sources (area sources) of HAPs. Major source thresholds for NESHAPs are 10 tpy of 

any single HAP or 25 tpy of total HAPs. 

The proposed liquefaction facility would be a major source of HAPs due to a single HAP 

(formaldehyde from combustion emissions) being greater than 10 tpy. Compressor Station 203-A would 

not be a major source for HAPS. The existing Longville Compressor Station is a major source of HAPS 

due to a single HAP (formaldehyde from combustion emissions) being greater than 10 tpy. The proposed 

modifications at this facility would not alter this status.

Subpart A – General Provisions

The general provisions listed in Subpart A include broader definitions of applicability and various 

methods for maintaining compliance with requirements listed in subsequent subparts of 40 CFR Part 63. 

This subpart also addresses the delegation of NESHAP authority to the states. Though not all NESHAPs 

have been delegated to the state in Louisiana, the specific NESHAPs that are applicable to the Lake 

Charles Liquefaction Project have been delegated to LDEQ. Lake Charles LNG and Trunkline have 

outlined the methods and measures by which they would comply with the specific requirements of each 

applicable NESHAP subpart listed below in section 22 of the AAE forms included in their respective 

permit applications submitted to the LDEQ (Trinity Consultants, 2014b, c, and d).

Subpart YYYY – NESHAP for Stationary Combustion Turbines

Subpart YYYY establishes national emission limitations and operating limitations for emissions 

of HAPs from stationary combustion turbines located at major sources of HAP emissions, and 

requirements to demonstrate initial and continuous compliance with the emission and operating 

limitations. The compressor turbines and combustion turbines proposed to be installed at the liquefaction 

facility, Compressor Station 203-A, and the Longville Compressor Station would qualify as new 

stationary turbines under this subpart. However, the EPA has not taken final action to require 

compliance. Therefore, the proposed new gas-fired turbines are not required to meet compliance 

requirements, except for submission of the initial notification requirements under 40 CFR Part 63.6645(f).

Subpart DDDDD – NESHAP for Industrial, Commercial, and Institutional Boilers and Process Heaters

Subpart DDDDD applies to industrial, commercial, or institutional boiler or process heater that is 

located at, or is part of, a major source of HAPs. The new liquefaction facility would be a major source 

of HAPs, and the proposed hot oil fired heater at this facility would be subject to this subpart. To comply 

with this subpart, Lake Charles LNG would be required to operate and maintain the hot oil fired heater in 
4-123

a manner consistent with safety and good air pollution control combustion practices as specified by 

40 CFR 63.6.

Subpart ZZZZ – NESHAP for Stationary Reciprocating Internal Combustion Engines

Subpart ZZZZ applies to the new emergency internal combustion engines that would be located

at area sources of HAPs. Subpart ZZZZ applies to the new CI ICEs proposed to be installed at the new 

liquefaction facility, Compressor Station 203-A, the Longville Compressor Station, and the emergency CI 

ICE at the meter stations. All of the NESHAP Subpart ZZZZ compliance requirements would be met

through compliance with the corresponding NSPS, 40 CFR Part 60, Subpart IIII in accordance with

40 CFR Parts 63.6590(c) and (c)(1).

Title V Operating Permits

The Part 70 Operating Permit program, as described in 40 CFR Part 70, requires major stationary 

sources of air emissions to submit an operating permit application prior to initial facility startup. Part 70 

operating permits are more commonly referred to as “Title V” permits. In Louisiana, the EPA has 

delegated the authority to issue Title V permits to the LDEQ, which has incorporated the program in LAC 

33:III.507. The threshold levels for determining the applicability for a Title V permit are:

 100 tpy of any criteria air pollutant;

 10 tpy of any individual HAP; or

 25 tpy of any combination of HAPs.

The proposed liquefaction facility would be considered a part of the same stationary source as the 

existing LNG terminal; however, operations and emissions sources at the LNG terminal would remain 

authorized under the current Title V permit (No. 0520-00098-V8), while the operations and emissions 

sources at the liquefaction facility would be authorized under a new and separate Title V permit. Lake 

Charles LNG submitted its Title V permit application for the liquefaction facility to the LDEQ in 

December 2013, and submitted a revised Title V permit application to the LDEQ in July 2014. In 

September 2014, Lake Charles LNG submitted its air quality dispersion modeling report as an addendum 

to the application. As previously discussed, emissions from a marine flare and two emergency generators 

that would be installed at the existing LNG terminal as part of the proposed liquefaction facility are 

included in this liquefaction facility air permit application. On May 1, 2015, the LDEQ issued a Part 70 

Operating Permit for the proposed liquefaction facility.

Emissions associated with Compressor Station 203-A would surpass the Title V permitting 

thresholds for NOX, and CO. Therefore, Trunkline would be required to obtain a Title V permit for this 

facility. Trunkline submitted its Title V permit application for proposed Compressor Station 203-A to 

LDEQ in December 2014. 

The Longville Compressor Station is an existing Title V facility and would be required to make a 

minor modification to its Title V permit as estimated emissions resulting from the proposed modifications 

would be below the SER thresholds. Trunkline submitted a Title V modification application for the 

Longville Compressor Station to the LDEQ in December 2014.

The Shaw Compressor Station has an existing Title V Operating Permit issued by the MDEQ. 

The estimated emissions for the proposed modifications at this facility are less than 5 tpy of VOC. Based 

on its review of Section 502(b)(10) of the CAA and the general conditions of its permit, Trunkline

determined that it is authorized to make the proposed modifications at the Shaw Compressor Station 

without obtaining a Title V Operating permit revision, and that only a Section 502(b)(10) notification 

letter to the MDEQ will be required at least 7 days before the proposed change occurs. 
4-124

General Conformity

A General Conformity applicability analysis is required for any part of the project occurring in 

nonattainment or maintenance areas for criteria pollutants. Section 176(c) of the CAA requires federal 

agencies to ensure that federally approved or funded projects conform to the applicable approved State 

Implementation Plan (SIP). Such activities must not: 

1. cause or contribute to any new violation of any standard in any area;

2. increase the frequency or severity of any existing violation of any standard in any area; or

3. delay timely attainment of any standard or any required interim emission reductions or 

other milestones in any area.

The entire Lake Charles Liquefaction Project area is classified as in attainment for all criteria 

pollutant standards; therefore, General Conformity requirements would not apply.

Greenhouse Gas Reporting Rule

On November 8, 2010, the EPA signed a rule that finalizes reporting requirements for the 

petroleum and natural gas industry under 40 CFR Part 98. Subpart W of 40 CFR Part 98 requires 

petroleum and natural gas facilities that emit 25,000 metric tons or more of CO2e per year to report annual 

emissions of specified GHGs from various processes within the facility. LNG storage and LNG import 

and export equipment are considered part of the source category regulated by Subpart W. The proposed 

liquefaction facility, the Longville Compressor Station, and Compressor Station 203-A are estimated to 

exceed the 25,000 metric ton threshold of CO2e emissions; therefore, Lake Charles LNG and Trunkline

would be required to comply with all applicable requirements of the rule.

Chemical Accident Prevention Provisions

40 CFR Part 68, Chemical Accident Prevention Provisions, is a federal regulation designed to 

prevent the release of hazardous materials in the event of an accident and to minimize impacts when 

releases do occur. The regulation contains a list of substances and threshold quantities for determining 

applicability of the rule to a facility. If a facility stores, handles, or processes one or more substances on 

this list and at a quantity equal to or greater than that specified in the regulation, the facility must prepare 

and submit a risk management plan. Lake Charles LNG does not propose to store acutely hazardous 

materials at a quantity equal to or greater than that specified. Therefore 40 CFR Part 68 requirements 

would not be applicable to the proposed facilities.

Louisiana State Regulatory Requirements 

LAC Title 33, Part III details the air quality regulations for emission sources in Louisiana. In 

addition, LAC Title 33, Chapter 1, delegates authority to the LDEQ to maintain air quality resources in 

Louisiana and enforce LDEQ air quality regulations. The following Louisiana state air quality 

requirements would be applicable to emission sources proposed as part of the Lake Charles Liquefaction 

Project. 

 Chapter 9 – General Regulations on Control of Emissions and Emission Standards

 Chapter 11 – Control of Air Pollution from Smoke

 Chapter 13 – Emission Standards for Particulate Matter

 Chapter 15 – Emission Standards for Sulfur Dioxide

 Chapter 21 – Control of Emission of Organic Compounds
4-125

Lake Charles LNG and Trunkline have outlined the methods and measures by which they would

comply with the requirements of each applicable LDEQ air quality regulation in section 22 of the AAE 

form included in their permit applications (Trinity Consultants, 2014b, c, and d). The LDEQ permit 

issued on May 1, 2015 includes conditions to ensure compliance with these regulations. It is expected 

that the LDEQ would also include conditions in the permit it issues for proposed Compressor 

Station 203-A, and in the permit modifications issued for the Longville Compressor Station.

4.11.1.4 Construction Air Emissions Impacts and Mitigation

Air pollutant emissions during construction of the Lake Charles Liquefaction Project would result 

from the operation of construction vehicles, marine traffic, vehicles driven by construction workers 

commuting to and from project work sites, and the generation of fugitive dust during construction 

activities. Particulate emissions would result from fugitive dust generated by construction-related 

activities and from open burning for land clearance. The quantity of fugitive dust would depend on 

several factors, including the size of area disturbed; the nature and intensity of construction activity; 

surface properties (such as the silt and moisture content of the soil); the wind speed; and the speed, 

weight, and volume of vehicular traffic. 

Liquefaction Facility and Existing LNG Terminal

Construction of the liquefaction facility is expected to occur over a period of about 5 years. 

Construction emission estimates for the liquefaction facility, excluding those associated with marine 

traffic, are summarized in table 4.11.1-7.

TABLE 4.11.1-7

Liquefaction Facility Construction Emissions 

Construction 

Activity

NOX 

(tons)

SO2 

(tons)

CO

(tons)

PM10

(tons)

PM2.5

(tons)

TSP

(tons)

THC

(tons)

VOC

(tons)

CO2

(tons)

CH4

(tons)

N2O

(tons)

CO2e

(tons)

Worker 

commutinga

22.07 11.87 188.68 0.22 0.22 - - 15.58 5,290 1.9 0.2 5,401.9

Fugitive dustb2,831.40 424.71 6,482.30 - - - - - -

Construction 

dirt work

794 18 371 65 65 - 75 51,388 3 1 51,735.92

Construction 

plant work

3,515 130 1,437 295 295 - - 333 225,184 18 4 226,970

Open burning 1.2 - 42.3 - - 5.1 5.7 - - - - -

_________________

a Emissions from worker commuting are based on an estimated 44-month construction period, assuming an average of 1,500 

workers commute to the project site 30 days per month.

b

TSP emissions include construction of liquefaction facility and ACWS A, B, C, and D.

Notes:

TSP: Total suspended particulates

THC: Total Hydrocarbons
4-126

Estimated emissions from the barges and bulk carriers that would deliver materials to the 

liquefaction facility site during construction were not yet available during preparation of the draft EIS. 

Therefore, in order to provide for a more accurate analysis of construction emissions, we recommended in 

the draft EIS that Lake Charles LNG file these estimated emissions prior to the end of the draft EIS 

comment period. In its May 22, 2015 response, Lake Charles LNG provided the following total estimated 

emissions from vessels delivery materials to the facility site during the construction period: 

 3.0 tons of CO;

 32.1 tons of NOX;

 0.3 ton of VOC; and

 0.0 tons of SO2.

Non-Liquefaction Facilities

Compressor Stations

Construction emissions anticipated to occur for Compressor Station 203-A and the Longville 

Compressor Station are summarized in tables 4.11.1-8 and 4.11.1-9, respectively. Emissions shown for 

pipeline construction and dirt work include tailpipe emissions from construction equipment anticipated to 

operate over the course of the construction period. Emissions from workers commuting to and from the 

compressor stations sites would be minimal. Additionally, since work at the Longville Compressor 

Station would occur within the existing facility, emissions from fugitive dust or open burning would also 

be minimal.

TABLE 4.11.1-8

Compressor Station 203-A Construction Emissions (2017–2018)

Construction Activity

NOX 

(tons)

SO2 

(tons)

CO

(tons)

PM10

(tons)

PM2.5

(tons)

TSP

(tons)

THC

(tons)

VOC 

(tons)

Construction Plant and Dirt 

Work

119.13 1.24 61.15 9.03 9.03 - - 7.68

Open Burning 0.09 - 3.21 - - 5.1 0.39 -

Fugitive Dust - - - - - 34.6 - -

TABLE 4.11.1-9

Longville Station Construction Emissions (2017–2018)

Construction Activity

NOX 

(tons)

SO2 

(tons)

CO

(tons)

PM10

(tons)

PM2.5

(tons)

TSP

(tons)

THC

(tons)

VOC 

(tons)

Construction Plant and Dirt 

Work

119.13 1.24 61.15 9.03 9.03 - - 12.53

The only construction activity associated with the Shaw compressor station is the installation of a 

10,000-gallon storage tank and connection piping. Therefore, the construction emissions are expected to 

be insignificant.

Pipelines

Construction emissions for the Mainline Connector pipeline and the Mainline 200-3 Loop are 

summarized in tables 4.11.1-10 and 4.11.1-11, respectively. Emissions shown for pipeline construction 

and dirt work include tailpipe emissions from construction equipment anticipated to operate over the 

course of the construction period.
4-127

TABLE 4.11.1-10

Mainline Connector Pipeline Construction Emissions (2017–2018)

Construction Activity

NOX 

(tons)

SO2 

(tons)

CO

(tons)

PM10

(tons)

PM2.5

(tons)

TSP

(tons)

THC

(tons)

VOC 

(tons)

Pipeline Construction and Dirt Work 319.13 3.98 614.92 21.79 21.72 - - 45.41

Open Burning (Calcasieu Parish, LA) 0.05 - 1.63 - - 0.20 0.22 -

Open Burning (Jefferson Davis Parish, LA) 0.40 - 13.83 - - 1.68 1.88 -

Fugitive Dust (Calcasieu Parish, LA) - - - - - 7.8 - -

Fugitive Dust (Jefferson Davis Parish, LA) - - - - - 66.4 - -

TABLE 4.11.1-11

Mainline 200-3 Loop Pipeline Construction Emissions (2017–2018)

Construction Activity

NOX 

(tons)

SO2 

(tons)

CO

(tons)

PM10

(tons)

PM2.5

(tons)

TSP

(tons)

THC

(tons)

VOC 

(tons)

Pipeline Construction and Dirt Work 137.41 1.72 264.44 9.38 9.38 - - 19.59

Open Burning (Calcasieu Parish, LA) 0.05 - 1.70 - - 0.21 0.23 -

Open Burning (Jefferson Davis Parish, LA) 0.14 - 4.74 - - 0.58 0.64 -

Fugitive Dust (Calcasieu Parish, LA) - - - - - 5.1 - -

Fugitive Dust (Jefferson Davis Parish, LA) - - - - - 14.2 - -

Meter Stations, Mainline 100-3 and 200-1 Modifications

Construction emissions associated with the proposed new and modified meter stations, Mainline 

100-3 modifications, and Mainline 200-1 modifications would be minimal, localized to the construction 

area, and relatively short term. All of these facilities would be located in sparsely populated areas. 

Construction at each site would require a small workforce ranging from an average of 25 workers to an 

estimated peak workforce of 45 workers. 

Mitigation Measures

Lake Charles LNG and Trunkline would minimize vehicular exhaust and crankcase emissions 

from gasoline and diesel engines by complying with applicable EPA mobile source emission performance 

standards and by using equipment manufactured to meet these standards. Fugitive dust emissions would 

be limited or mitigated, if necessary, by spraying water to dampen dry work surfaces and/or by the 

application of calcium chloride or other dust suppressants. In its June 1, 2015 comments on the draft EIS, 

the EPA recommended that, in addition to complying with applicable local, state, or federal requirements,

Lake Charles LNG and Trunkline develop a Fugitive Dust Control Plan to reduce air quality impacts, 

including PM10 and PM2.5 emissions. While the measures described by Lake Charles LNG and Trunkline 

would help control fugitive dust during construction, we agree with the EPA that more detail is necessary, 

particularly in light of the other planned development activities in the project area as discussed in 

section 4.13, some of which may be in construction concurrently with the Lake Charles Liquefaction 

Project. Therefore, we recommend that:

 Prior to construction, Lake Charles LNG and Trunkline should file with the 

Secretary, for review and written approval by the Director of OEP, a Fugitive Dust 

Control Plan that includes a description of mitigation measures they would 

implement to minimize fugitive dust emissions from construction activities, 

including measures to reduce PM10 and PM2.5 emissions. The plan should clearly 

explain how Lake Charles LNG and Trunkline would implement such measures and 

specify the individuals that would have the authority to determine the need for 
4-128

implementation of dust control measures, and to stop work if the contractor does 

not comply. In developing the plan, Lake Charles LNG and Trunkline should 

consider and incorporate as appropriate the recommendations provided by the EPA 

in Attachment 1 of its June 1, 2015 comment letter.

Fugitive dust and construction emissions would occur during the construction period and would 

subside once construction activities for any given project component are complete. Additionally, 

construction emissions would be primarily limited to the construction area and would represent a small 

portion of the parishes’ and counties’ yearly emissions inventories. Construction emissions associated 

with pipeline construction would typically be intermittent and short term at any one location because 

pipeline construction moves though individual areas relatively quickly. In conclusion, we find that with 

implementation of the proposed mitigation measures and our recommended condition, constructionrelated impacts on local air quality would not be significant.

4.11.1.5 Operational Air Emissions Impacts and Mitigation

Liquefaction Facility

Emissions from the operation of the liquefaction facility are expected from the various 

combustion sources and storage tanks located on site. A summary of emissions for stationary sources at 

the liquefaction facility is provided in table 4.11.1-12; a detailed emission summary is included in 

Appendix B of Lake Charles LNG’s revised Title V/PSD permit application submitted to the LDEQ for 

the liquefaction facility (Trinity Consultants, 2014b). The estimated emissions reflect any applicable 

vendor guarantees and BACT limits.

TABLE 4.11.1-12

Liquefaction Facility Summary of Emissions

NOX 

(tpy)

SO2 

(tpy)

CO

(tpy)

PM10 

(tpy)

PM2.5 

(tpy)

VOC 

(tpy)

H2S 

(tpy)

NH3 

(tpy)

CO2

(tpy)

CH4

(tpy)

N2O

(tpy)

HAPs 

(tpy)

750.41 39.89 1,878.83 202.47 202.47 58.18 0.02 402.66 4,484,169 244.0 78.19 18.68

As discussed in the PSD applicability section in section 4.11.1.3, Lake Charles LNG’s analysis 

included a PSD Screening Analysis, NAAQS Analysis, and PSD Increment Analysis for stationary 

sources at the liquefaction facility (Trinity Consultants, September 2014a). The PSD Screening Analysis 

included a Significance Analysis, the AOI Analysis, and the Preconstruction Monitoring Analysis. The 

significance analysis considers the emissions associated only with the proposed project to determine if it 

would have a significant impact on the surrounding area. The modeled ground‐level concentrations are 

compared to the corresponding significant impact levels (SIL), also known as modeling significance 

levels, to determine if any predicted concentrations at any receptor locations are “significant.” If the 

significance analysis reveals that modeled ground‐level concentrations for a particular pollutant and 

averaging period are greater than the applicable SIL, a full impact analysis, which considers emissions 

from regional sources within the AOI, is performed at the significant receptors. If predicted significance 

analysis impacts for a particular pollutant are below the applicable SIL(s), then no further analyses (e.g., 

NAAQS and PSD increment analyses) are required for that pollutant. Results from the significance 

analysis also dictate if preconstruction ambient monitoring is required. Table 4.11.1-13 lists the 

applicable standards for the pollutants involved.
4-129

TABLE 4.11.1-13

Applicable PSD Increment and NAAQS Air Quality Levels

Pollutant

Averaging 

Period

SIL

(μg/m3)

Monitoring de Minimis 

Concentration (μg/m3)

PSD Class II Increment 

(μg/m3)

NAAQS

(μg/m3)

CO 8-hour 500 575 N/A 10,000

1-hour 2,000 N/A N/A 40,000

NO2 1-hour 7.5a N/A Not established 188b

Annual 1 14 25 100

PM2.5 24-hour 1.2c4

c

9 35

Annual 0.3 N/A 4 12

PM10 24-hour 5 10 30 150

____________________

a Based on U.S. EPA Memorandum from Stephen D. Page to Regional Air Division Directors titled “Guidance Concerning 

the Implementation of the 1-hour NO2 NAAQS for the Prevention of Significant Deterioration Program.” June 29, 2010.

b Based on the currently applicable 1-hour NO2 standard of 100 ppb.

c

The monitoring de minimis concentration and the SIL for PM2.5 24-hour averaging period were vacated in a court decision 

dated January 22, 2013. 

In accordance with the modeling requirements outlined above, Lake Charles LNG performed 

significance analyses for CO, NO2, PM10, and PM2.5. The results of these analyses are summarized in 

table 4.11.1-14.

TABLE 4.11.1-14

Significance Modeling Analysis Results

Pollutant Averaging Period

Maximum Modeled 

Concentration (μg/m3)

Significant Impact Level 

(μg/m3)

Monitoring de Minimis 

Level (μg/m3)

CO 1-hour 133.5 2,000 N/A

CO 8-hour 70.4 500 575

PM10 24-hour 4.5 5 10

PM2.5 24-hour 3.6 1.2 4

PM2.5 Annual 0.27 0.3 N/A

NO2 1-hour 18.4 7.5 N/A

NO2 Annual 0.76 1 14

____________________

Note: Meteorological data years: 5-year max.

CO, PM10 Significance Analysis Impacts: This analysis showed that SILs and the monitoring de 

minimis concentration for CO or PM10 were not exceeded by impacts from the proposed project. Since 

the modeled impacts do not exceed the SILs for CO and PM10, the project would not cause or 

significantly contribute to an exceedance of either the CO or PM10 NAAQS, and a full impact analysis is 

not required for either CO or PM10. Additionally, since the monitoring de minimis concentration for either 

CO or PM10 were not shown to be exceeded, pre‐construction monitoring is not required.

PM2.5 Significance Analysis Impacts: This analysis showed that the PM2.5 24‐hour SIL was 

exceeded by impacts from the proposed project. Since the 24‐hour SIL was exceeded, a NAAQS and 

PSD Increment analysis was required to be performed for the PM2.5 24‐hour averaging period. The 

24‐hour monitoring de minimis concentration and the Annual SIL were not exceeded by impacts from the 

proposed project. Therefore, pre‐construction monitoring and cumulative impacts for annual PM2.5 are 

not required.

NO2 Significance Analysis Impacts: This analysis showed that the NO2 1‐hour SIL was exceeded 

by impacts from the proposed project. Since the 1‐hour SIL was exceeded, a NAAQS analysis was 
4-130

required to be performed for the NO2 1‐hour averaging period. However, since the PSD Increment 

standard has not been established for NO2 1‐hour, a PSD Increment analysis was not performed. The NO2

annual monitoring de minimis concentration and SIL were not exceeded by impacts from the proposed 

project. Therefore, pre‐construction monitoring and cumulative impacts for annual NO2 are not required.

A NAAQS analysis is required for all criteria pollutants with modeled concentrations in excess of 

their respective SILs. As discussed above, PM2.5 and NO2 modeled concentrations exceeded their 24‐hour 

and 1‐hour SILs, respectively. Therefore, a NAAQS analysis was required for both of these pollutants 

and averaging periods. A source is not considered to have caused or contributed to the violation if its own 

impact from the modeling significance analysis is not significant (e.g., modeled impact is less than the 

SIL) at the violating receptor at the time of the predicted violation. If no simultaneous exceedance of the 

SIL and the NAAQS is found in this process, the modeling analysis demonstrates that the proposed 

project would not cause or contribute to the potential NAAQS exceedance. If this is the case, no further 

analysis is required. If a simultaneous exceedance is found at any receptor and the receptor is located on 

another facility’s property, the other facility’s contribution to the potential exceedance has been 

subtracted. If the revised concentration is less than the NAAQS standard, compliance is demonstrated 

and no further analysis is required. For any remaining potential NAAQS exceedance, a file review to 

update any emission sources that contribute to potential NAAQS exceedance(s) has been performed.

The results of the NAAQS modeling analyses are summarized in table 4.11.1-15.

PM2.5 and NO2 NAAQS Analysis Results: Although the modeled results in table 4.11.1-15 show 

exceedances of the NAAQS for both the PM2.5 24-hour and the NO2 1-hour standard, a culpability 

analysis for the project’s PM2.5 and NO2 emissions impacts demonstrate that none of the significance 

analysis contributions are significant at the same time and location of a NAAQS exceedance. Therefore, 

the PM2.5 24‐hour and NO2 model results demonstrated compliance with NAAQS modeling requirements 

based on the fact that the facility would not cause or contribute to the violation.

TABLE 4.11.1-15

NAAQS Modeling Analysis Results

Pollutant

Averaging 

Period

NAAQS 

(μg/m 3)

Background 

Concentration 

(μg/m 3)

NAAQS Minus 

Background 

Concentration 

(μg/m 3)

Modeled 

NAAQS 

Concentration 

(μg/m 3)

Modeled SIL 

Contribution 

(μg/m 3)

Pass 

Culpability?

PM2.5 24-hour 35 19 16 2314.08a0.24 Yes

PM2.5 24-hour 35 19 16 36.57 1.19b Yes

NO2 1-hour 188 30 158 1303.32a1.3E-04 Yes

NO2 1-hour 188 30 158 446.38 5.4b Yes

____________________

a Receptor chosen to demonstrate maximum modeled NAAQS concentration.

Notes:

Utilized the MAXCONDT function in AERMOD

Note: Meteorological data years: 5-year max.

For pollutants with a modeled concentration greater than the corresponding SIL, PSD regulations 

require a PSD Increment Analysis. The PSD Increment analysis demonstrates that the proposed project 

would neither cause nor contribute to an exceedance of federal ordinances on industrial expansion. As 

discussed above, the PM2.5 and NO2 modeled concentrations exceeded their 24‐hour and 1‐hour SILs, 

respectively. A PSD Increment analysis was performed for PM2.5 24‐hour standard, but no PSD 

Increment analysis was performed for NO2 1‐hour standard since a PSD Increment has not yet been 

established. 
4-131

The PSD Increment analysis for PM2.5 24‐hour standard implemented the same AOI and receptors 

as the NAAQS analysis. The inventory for the PM2.5 24‐hour PSD Increment was determined using the 

major and minor baseline years for PM2.5. Through coordination with the LDEQ, Lake Charles LNG

used May 2, 2013 as the minor baseline year date, as well as AOI plus 50 kilometers as the inventory 

radius. Lake Charles LNG gathered the actual, reported inventory for 2013 from the LDEQ. Those 

emissions represented the baseline emissions for the model. The potential PM2.5 emissions of the 

proposed project and the increment inventory emissions described above were modeled together for 

comparison to the PM2.5 24‐hour PSD Increment. 

Table 4.11.1-16 summarizes the results of the PSD Increment analysis for the PM2.5 24‐hour 

standard.

TABLE 4.11.1-16

PM2.5 24-hour PSD Increment Analysis Results

Meteorological 

Data Year

PM2.5 24-hour 

PSD Increment 

(μg/m 3)

UTM East 

(NAD 83) (m)

UTM North 

(NAD 83) (m)

Modeled PSD 

Increment 

Concentration (μg/m 3)

Modeled SIL 

Contribution 

(μg/m 3)

Pass 

Culpability?

2009 9 472,500 3,333,200 6.5 N/A N/A

2010 9 472,900 3,332,400 9.7 0.48 Yes

2011 9 472,600 3,333,200 7.0 N/A N/A

2012 9 471,000 3,333,400 8.6 N/A N/A

2013 9 471,000 3,332,900 9.1 0.15 Yes

Table 4.11.1-16 shows the yearly results for the PM2.5 24‐hour PSD Increment models. The years 

2009, 2011, and 2012 did not exceed the PSD Increment, therefore not requiring a culpability analysis. 

The years 2010 and 2013 had concentrations that exceeded the PSD Increment, therefore requiring a 

culpability analysis. The modeled SIL contributions to the 2010 and 2013 PSD Increment exceedances 

were under the PM2.5 24‐hour SIL threshold. The culpability analysis showed that the proposed project 

would not cause or contribute to the potential PSD Increment exceedance.

In addition to emissions from the stationary sources included in the PSD modeling analysis, Lake 

Charles LNG provided emissions for mobiles sources during operation of the liquefaction facility, 

including LNG carriers and tugboats. However, Lake Charles LNG is not proposing to increase the 

currently authorized number or size of LNG carriers that would potentially call on the proposed export 

facility. Therefore, emissions from these sources could occur independent of the proposed project and are 

not discussed here. Emissions from mobile sources are considered in section 4.13.2.11, Cumulative 

Impacts.

Lake Charles LNG would minimize potential impacts on air quality due to the operation of 

liquefaction facility by adhering to applicable federal and state regulations and installing BACT to 

minimize emissions. Section 4.11.1.3 describes measures for BACT as required for NOx, CO, VOC, 

PM10, PM2.5, and GHG emissions for the proposed equipment to be installed at the liquefaction facility.

Non-Liquefaction Facilities 

Compressor Station 203-A

Emissions from Compressor Station 203-A are expected from various combustion sources and 

storage tanks. Trunkline would install five Caterpillar 3616 engines, five Mars 100 turbines, two 

emergency generators, and a condensate storage tank at the station. Additionally, truck loading activities 

and fugitive emissions from components are expected to cause emissions of VOCs. A summary of the 

estimated emissions for the operation of Compressor Station 203-A is provided in table 4.11.1-17. 
4-132

TABLE 4.11.1-17

Compressor Station 203-A Operational Emissions Summary 

for the Lake Charles Liquefaction Project

NOX (tpy) SO2 (tpy) CO (tpy) PM10/2.5 (tpy) VOC (tpy) CH2O (tpy) Total HAPS (tpy) CO2e (tpy)

249.09 1.98 208.08 23.33 149.66 5.91 14.26 364,265

____________________

CH2O = Formaldehyde

As noted above, Compressor Station 203-A is not subject to PSD permitting requirements (major 

source permitting, modeling, or application of BACT requirements). However, to assist us in preparing 

this EIS, Trunkline performed an air dispersion screening analysis using the AERSCREEN model to 

assess the impact of the proposed Compressor Station 203-A on the NAAQS. The results of this analysis 

are summarized in table 4.11.1-18.

TABLE 4.11.1-18

Compressor Station 203-A AERSCREEN Modeling Results

Pollutant

Averaging 

Period

Maximum Combined Model 

Concentration (μg/m3)

Ambient Background 

(μg/m3)

Total Concentration 

(μg/m3)

NAAQS 

(μg/m3)

CO 1-Hour 22.62 798 820.62 40,000

CO 8-Hour 20.36 570 590.36 10,000

NO2 1-Hour 21.67 56.40 78.07 188

NO2 Annual 2.17 9.40 11.57 100

PM2.5 24-Hour 1.52 19 20.52 35

PM2.5 Annual 0.25 8.4 8.65 12

PM10 24-Hour 1.52 72 73.52 150

SO2 1-Hour 0.22 96.57 96.79 196

The AERSCREEN model results shown in table 4.11.1-18 demonstrate that the emissions from 

the proposed new Compressor Station 203-A would not significantly impact the air quality in the 

surrounding area.

Trunkline would minimize potential impacts on air quality due to the operation of Compressor 

Station 203-A by adhering to applicable federal and state regulations as discussed in section 4.11.1.3 and 

in section 22 of the AAE form included in its air permit application.

Longville Compressor Station

Modifications to the Longville Compressor Station would include the installation of one Mars 

turbine, the retirement of the single existing natural gas-fired turbine compressor, and the installation of 

one new diesel-fired emergency internal combustion engine generator. A summary of the existing facility 

emission totals as well as estimated emissions from the proposed new facility sources is provided in 

table 4.11.1-19. The proposed modifications to the Longville Compressor Station would not result in the 

exceedance of any criteria pollutant SER. Therefore, the proposed modifications at the Longville 

Compressor Station would not be subject to PSD permitting, modeling, or application of BACT 

requirements. However, to assist us in preparing this EIS, Trunkline performed an air dispersion 

screening analysis using the AERSCREEN model to assess the impact of the proposed modifications at 

the Longville Compressor Station on the NAAQS. The results of this analysis are summarized in 

table 4.11.1-20. 
4-133

TABLE 4.11.1-19

Longville Compressor Station Operational Emissions Summary

for the Lake Charles Liquefaction Project

Facility

NOX

(tpy)

SO2

(tpy)

CO

(tpy)

PM10/2.5

(tpy)

VOC

(tpy)

CH2O

(tpy)

CO2e

(tpy)

Existing Facility Emissions 3,982.65 3.57 384.67 20.23 190.42 40.29 102,575.07

Proposed Facility Sources -10.28 -0.10 20.52 2.51 17.53 0.27 55,824

New Facility Total 3,972.37 3.47 405.19 22.74 207.95 40.56 158,398.67

____________________

CH2O = Formaldehyde

TABLE 4.11.1-20

Longville Compressor Station Modifications AERSCREEN Modeling Results

Pollutant

Averaging 

Period

Maximum Combined Model 

Concentration (μg/m3)

Ambient 

Background 

(μg/m3)

Total Concentration 

(μg/m3)

NAAQS 

(μg/m3)

CO 1-Hour 3.17 798 801.17 40,000

CO 8-Hour 2.85 570 572.85 10,000

NO2 1-Hour 2.51 56.40 58.91 188

NO2 Annual 0.25 9.40 9.65 100

PM2.5 24-Hour 0.21 19 19.21 35

PM2.5 Annual 0.03 8.4 8.43 12

PM10 24-Hour 0.21 72 72.21 150

SO2 1-Hour 0.03 96.57 96.60 196

The AERSCREEN model results shown in table 4.11.1-20 demonstrate that the proposed 

modifications to the Longville Compressor Station would not significantly impact the air quality in the 

surrounding area. 

Trunkline would minimize potential impacts on air quality due to the operation of the Longville 

Compressor Stations by adhering to applicable federal and state regulations as discussed in section 

4.11.1.3 and in section 22 of the AAE form included in its air permit application. However, Trunkline’s 

AERSCREEN analysis only included the proposed modifications, and not the existing facilities. 

Therefore, we recommend that:

 Prior to construction of modifications to the Longville Compressor Station, 

Trunkline should file with the Secretary, for review and written approval by the 

Director of OEP, the results of an air quality screening (AERSCREEN) or refined 

modeling analysis (AERMOD or EPA-approved alternative). This modeling 

analysis should demonstrate that the incremental increase in emissions of criteria 

pollutants from the modifications either: results in local concentrations below the 

NAAQS where current concentrations are currently below the NAAQS; or does not 

cause or contribute to local concentrations above the NAAQS where the current 

concentrations are above the NAAQS. 

Shaw Compressor Station (Mississippi)

The Shaw Compressor Station operates under an existing Title V permit from the MDEQ. The 

only new equipment expected to be added to this facility is a 10,000-gallon storage tank for pipeline 

distillates, water, and compressor oils. VOC emissions from this tank are expected to be less than 5 tpy. 

The proposed piping modifications to make this station bi-directional would not be emission sources. 
4-134

Meter Stations

Trunkline proposes to install a 50 hp emergency generator engine at each metering station. The 

emissions from a single emergency engine are estimated at: 3.4 tpy NOx, 15.5 tpy CO, less than 1 tpy 

VOC, and 9,225 tpy GHG.

Mainline 100-3 and 200-1 Modifications

Based on the gas composition, the volumes of the respective launchers/receivers, and the 

assumption that pigs will be run one time per year, Trunkline estimates that fugitive emissions for the pig 

launchers and receivers to be installed/replaced on the Mainline 100-3 and the Mainline 200-1 facilities 

would be 0.92 pounds of VOC for the 36-inch barrel and 0.41 pounds of VOC for the 24-inch barrel. The 

annual emissions for these two facilities would be de minimis.

4.11.2 Noise

Sound is a sequence of waves of pressure that propagates through compressible media such as air 

or water. When sound becomes excessive, annoying, or unwanted, it is referred to as noise. The Lake 

Charles Liquefaction Project would affect noise levels in the vicinity of project components during 

construction and operation of the proposed facilities. Construction and operation of the project may affect 

overall noise levels in the immediate area. The ambient sound level of a region is defined by the total 

noise generated within the specific environment and usually comprises natural and man-made sounds. At 

any location, both the magnitude and frequency of environmental noise may vary considerably over the 

course of a day and throughout the week. This variation is caused in part by changing weather conditions 

and the effect of seasonal vegetative cover. 

Two measurements used by some federal agencies to relate the time-varying quality of 

environmental noise to its known effects on people are the equivalent sound level (Leq) and the day-night 

sound level (Ldn). The Leq is a sound level over a specific time period corresponding to the same sound 

energy as measured for an instantaneous sound level assuming it is a constant noise source. Sound levels, 

measured in decibels (dB), are perceived differently, depending on length of exposure and time of day. 

The Ldn takes into account the duration and time the noise is encountered. Specifically, in the calculation 

of the Ldn, late night and early morning (10:00 p.m. to 7:00 a.m.) noise exposures are increased by 

10 decibels to account for people’s greater sensitivity to sound during nighttime hours. To account for the 

human ear’s sensitivity to low-level noises, decibel levels are corrected using the A-weighted 

scale (dBA). The A-weighted scale is used because human hearing is less sensitive to low and high 

frequencies than mid-range frequencies.

Table 4.11.2-1 demonstrates the relative dBA noise levels of common sounds measured in the 

environment and industry. A 3 dB change of sound level is considered to be barely perceivable by the 

human ear. A 5 or 6 dB change of sound level is considered noticeable, and a 10 dB increase is perceived 

as if the sound intensity has doubled. 
4-135

TABLE 4.11.2-1

Sound Levels (dBA) and Relative Loudness 

Description of Sound Sound Level (dBA)

Threshold of pain 140

Jet taking off (200-foot distance) 130

Operating heavy equipment 120

Night club with music 110

Construction site 100

Boiler room 90

Freight train (100-foot distance) 80

Classroom chatter 70

Conversation (3-foot distance) 60

Urban residence 50

Soft whisper (5-foot distance) 40

North rim of Grand Canyon 30

Silent study room 20

Threshold of hearing (1,000 hertz) 0

____________________

Adapted from OSHA Technical Manual, 1999

4.11.2.1 Noise Regulations

Federal Regulations

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 publication evaluated 

the effects of environmental noise with respect to health and safety. The document provides information 

for state and local governments to use in developing their own ambient noise standards. The EPA has 

determined that in order 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 (18 

CFR 157.206(b)(5)) for new compression and associated pipeline facilities, and it is used here to evaluate 

the potential noise effects from operation of the proposed liquefaction facility, Compressor Station 203-A, 

the Longville Compressor Station, and HDD activities. An Ldn of 55 dBA is equivalent to a continuous 

noise level of 48.6 dBA for facilities that operate at a constant level of noise. 

State and Local Regulations

The State of Louisiana has no regulations that would limit noise generated from the construction 

and operation of the Lake Charles Liquefaction Project.

Calcasieu Parish has adopted a noise ordinance (Code of Ordinances, Chapter 18, Article VIII –

Disturbing the Peace) that does not set specific sound level limits, but restricts excessive noise as follows: 

“No person shall make, continue, or cause to be made or continued any loud, unnecessary or excessive 

noise which unreasonably interferes with the comfort and repose of others within the jurisdiction of the 

parish.” 
4-136

Applicable exemptions include:

 Sec 18–99, paragraph (3) “Noises made by persons having obtained a permit”; 

 Sec 18–99, paragraph (4) “Any noise resulting from activities of temporary duration, for 

which a permit has been granted pursuant to this article, and which conforms to the 

conditions and limits stated thereon”; and 

 Sec 18–100, paragraph (4) “Construction and demolition. The operating of any 

equipment used in construction work within 165 feet of any residential or noise sensitivearea (NSA) between sunset and sunrise on weekdays and Saturdays, and 9:00 p.m. and 

8:00 a.m. on Sundays and holidays, except for emergency work.”

No other Louisiana parishes in which the project is located have noise ordinances. 

There are no state or local regulations pertaining to the areas in Mississippi and Arkansas in 

which the proposed project facilities would be located. 

4.11.2.2 Existing Sound Levels and Noise-Sensitive Areas

Liquefaction Facility

Lake Charles LNG and Trunkline’s noise consultant (Hoover & Keith, Inc. (H&K)) measured 

ambient noise levels on June 26, 2013, at four NSAs representing the boundary of the nearest existing 

residential development within the vicinity of the proposed liquefaction facility (see figure 4.11.2-1). 

Measurements were not taken at a fifth NSA at which ambient noise was assumed to be equivalent to that 

at another NSA. The results of the ambient noise survey as well as the distance and direction of each 

identified NSA from the liquefaction facility are provided in table 4.11.2-2.

TABLE 4.11.2-2

Ambient Noise Study Results for the Lake Charles Liquefaction Facility

Location ID Distance (feet) Direction

Existing Ambient Ldn (dBA)

June 2013

NSA 1 4,200 North-northeast 54.8

NSA 2 5,100 East 50.9

NSA 3 5,600 West 45.1

NSA 4 7,100 Northwest 48.5

NSA 5 5,500a Northwest 48.5b

____________________

a

The distance shown for NSA 5 has been corrected from that shown in Trunkline’s noise analysis; however, the noise level 

is not affected.

b Measurements were not conducted near this NSA; it is assumed to be equivalent to NSA 4.
4-137
4-138

Non-Liquefaction Facilities

Compressor Station 203-A

H&K recorded ambient noise level measurements on June 27, 2013, at four NSAs in the vicinity 

of proposed Compressor Station 203-A (see figure 4.11.2-2). A fifth NSA was identified after the 

preconstruction noise survey had been completed. The results of the ambient noise survey as well as the 

distance and direction of each identified NSA are provided in table 4.11.2-3.

TABLE 4.11.2-3

Ambient Noise Study Results for Compressor Station 203-A

Location ID Distance (feet) Direction

Existing Ambient Ldn (dBA)

June 2013

NSA 1 1,650 West-southwest 53.2

NSA 2 1,805 Northwest 49.0

NSA 3 2,580 East-northeast 52.5

NSA 4 3,180 North 54.3

NSA 5a1,140 East 52.5

____________________

a NSA 5 was identified after the preconstruction survey was conducted. The existing ambient sounds level at this NSA is 

assumed to be the same as measured at NSA 3.

Longville Compressor Station

Ambient noise level measurements were recorded at the existing Longville Compressor Station in 

February 2008 after the installation of an additional compressor unit (Compressor Unit 4522) not 

associated with the Lake Charles Liquefaction Project. Based on the 2008 noise survey and pre-existing 

noise levels at the station, the estimated existing sound levels at the nearest NSAs due to the full operation 

of all existing compressor units are provided in table 4.11.2-4 (see also figure 4.11.2-3). Trunkline 

reviewed the area during other project-related noise surveys in 2013 and did not identify any new NSAs 

or additional projects that would increase ambient noise levels in the vicinity of this facility.

TABLE 4.11.2-4

Ambient Noise Study Results for the Longville Compressor Station

Location ID Distance (feet) Direction

Estimated Existing Ambient

Ldn (dBA) – February 2008

NSA 1 1,470 Southwest 68.6

NSA 2 1,120 North-northwest 66.8

NSA 3 880 North-northeast 60.6

NSA 4 1,360 Southeast 55.0

HDD Locations

Ambient noise measurements were not taken at the proposed HDD locations. For the purposes of 

this analysis and based on a review of aerial photography, estimated background noise levels at the HDD 

entry and exit locations are based on published EPA data for the Rural Residential Area category. 

Locations of NSAs for the HDD entry and exit locations and estimated background noise levels are 

provided in the next section.
4-139

Insert Figure 4.11.2-2
4-140

Insert Figure 4.11.2-3
4-141

4.11.2.3 Construction Noise Impacts and Mitigation

Liquefaction Facility and LNG Terminal

The most prevalent sound generating equipment and activity during construction of the 

liquefaction facility and LNG terminal modifications is anticipated to be internal combustion engines 

associated with construction equipment and pile driving. The sound levels experienced at the NSAs 

would depend on the type of equipment used, the mode of operation of the equipment, the length of time 

the equipment is in use, the amount of equipment used simultaneously, and the distance between the 

sound generation source and the receptor. Sheet and pile driving could produce peak sound levels that 

would be perceptible above the background sound levels during construction. H&K conducted an 

analysis of construction noise based on standard construction equipment, anticipated power levels, and 

estimated number of equipment units potentially operating at one time as shown in table 4.11.2-5.

TABLE 4.11.2-5

Construction Equipment Noise Summary for the Lake Charles Liquefaction Facility

Equipment Type Sound Power Level (dBA) Number of Units Operating

LNG Train 1

Crane 105 4

Backhoe 105 4

Bulldozer 111 4

Grader 115 4

Pile Drivers 123 5

LNG Train 2

Crane 105 4

Backhoe 105 4

Bulldozer 111 4

Grader 115 4

LNG Train 3

Crane 105 4

Backhoe 105 4

Bulldozer 111 4

Grader 115 4

Auxiliary Building

Crane 105 4

Backhoe 105 4

Bulldozer 111 4

Grader 115 4

Increases in noise levels during construction activities would be intermittent and would generally 

occur during daylight hours. However, certain activities may need to be conducted during nighttime 

hours to avoid construction schedule delays. The level of construction-related noise would also vary over 

the course of the about 5-year construction period depending on the phase of construction in progress. 

For the purposes of modeling potential construction noise, is was assumed that the equipment 

would operate 100 percent of the time during the day (7:00 am to 10:00 pm) and 50 percent of the time 

during the night (10:00 pm to 7:00 am) for power trains 1, 2, and 3, and only during the day for the 

auxiliary building. It was assumed that all pile driving activities would only occur during the day. Based 
4-142

on these assumptions, the modeling found that the estimated noise impact at the nearest NSAs would be 

less than 55 dBA Ldn.

Non-Liquefaction Facilities

Compressor Station 203-A

Construction activities at Compressor Station 203-A would include earthwork and construction of 

the site foundations and equipment. Construction is expected to last about 12 months. For this analysis it 

was assumed that earthwork activities would produce the most amount of noise during construction. 

Table 4.11.2-6 lists the construction equipment, horsepower, assumed maximum number of equipment 

units that may be operating at one time, and the estimated noise (dBA) associated with the equipment at a 

distance of 50 feet. 

TABLE 4.11.2-6

Noise-generating Construction Equipment for Compressor Station 203-A

Type of Equipment

Equipment Power

Rating/Capacity (hp)

Estimated Maximum Number

Operating at One Time

Estimated dBA

(at 50 feet)

Diesel generator 100 1 75

Bulldozer 250–700 1 82

40 TN RT crane 150–200 1 83

Side boom 130–210 1 80

Cherry picker 150–250 1 81

Welding trucks 200–300 7 74

Backhoe 130–210 1 80

Front-end loader 150–250 1 85

The nearest NSA to the construction activities for Compressor Station 203-A is NSA 5, which is 

located at a distance of 1,140 feet. The estimated noise impact at NSA 5 would be equal to or less than 

63 dBA or an Ldn of 61 dBA, since only daytime construction would be conducted. Although estimated 

noise levels during construction of Compressor Station 203-A would exceed the 55-dBA Ldn noise 

threshold, construction noise would be temporary and localized, and would not cause a significant longterm impact on ambient noise levels at any of the identified NSAs. 

Longville Compressor Station

Construction activities at the Longville Compressor Station would include earthwork and 

construction of the site foundations and equipment. Construction is expected to last about 12 months. 

For this analysis it was assumed that earthwork activities would produce the most noise during 

construction. Table 4.11.2-7 lists the construction equipment, horsepower, assumed maximum number of 

equipment units that may be operating at one time, and the estimated noise (dBA) associated with the 

equipment at a distance of 50 feet.

The nearest NSA to the construction activities for the Longville Compressor Station is NSA 3 

located at a distance of 880 feet. Estimated construction noise levels at NSA 3 would be equal to or less 

than 65 dBA or an Ldn of 63 dBA, since only daytime construction would occur. Because construction 

would take place during daytime hours, and would be temporary and localized, we conclude that 

construction activities would not cause a significant long-term impact on ambient noise levels at any of 

the identified NSAs.
4-143

TABLE 4.11.2-7

Noise-generating Construction Equipment for the Longville Compressor Station

Type of Equipment

Equipment Power

Rating/Capacity (hp)

Estimated Maximum Number

Operating at One Time

Estimated dBA

(at 50 feet)

Diesel generator 100 1 75

Bulldozer 250–700 1 82

Small crane 250–3,500 1 83

Cherry picker 150–250 1 81

Welding trucks 200–300 3 74

Backhoe 130–210 1 80

Front-end loader 150–250 1 85

HDD Locations

Trunkline proposes to conduct HDD crossings at three locations on the Mainline Connector 

(Arceneaux Bayou, Little Bayou, and Serpent Bayou), two locations on the Mainline 200-3 Loop (Bayou 

Lacassine and Indian Bayou Canal), and at the Calcasieu River as part of the Mainline 200-1 

modifications. HDD construction involves various equipment and activities including power generation, 

mobile equipment, and mixing pumps. Typical equipment used at the HDD entry side includes:

 drilling rig and engine-driven hydraulic power unit;

 engine-driven mud pump(s) and engine-driven generator set(s);

 mud mixing/cleaning equipment and associated fluid systems shale shakers;

 mobile equipment including a crane, backhoe, front loader, forklift and/or trucks(s); 

 frac tanks; and

 engine-driven lights.

Noise associated with the HDD exit side is typically lower but could result from use of the 

following equipment:

 backhoe, side boom and/or truck(s);

 engine-driven generator and pump; and

 engine-driven lights.

Of the above noise sources, Trunkline anticipates that the diesel engine power generation units 

would be the most significant noise generating sources. 

H&K conducted an acoustical assessment to estimate the sound contribution of the HDDs for 

NSAs within 0.5 mile of each HDD entry or exit point. No NSAs were identified within 0.5 mile of the 

entry or exit point for Little Bayou; therefore, that HDD is not discussed further in this section. 

Additionally, the Calcasieu River HDD crossing has been redesigned and Trunkline did not provide a 

revised acoustical assessment for the new alignment. In order to evaluate the potential noise impacts 

associated with the Calcasieu River HDD, we recommend that:

 Prior to construction of the Calcasieu River HDD, Trunkline should file an 

acoustical assessment identifying NSAs within 0.5 mile of the HDD entry and exit 

points and describing noise mitigation measures it would implement if the estimated 

sound contribution of the HDD would exceed an Ldn of 55 dBA and/or result in a 

greater than 10-dBA increase over noise ambient conditions at any NSA.
4-144

Table 4.11.2-8 shows the estimated the noise impact at the nearest NSAs to the other HDDs from 

the combined entrance and exit noise sources. As shown in table 4.11.2-8, HDD noise is estimated to 

exceed a 55 dBA noise level (Ldn) and/or result in a greater than 10 dBA increase over ambient conditions 

at the Indian Bayou Channel at NSAs 1, 2, 3, 4, 5, 7, 8 and 9. 

Trunkline anticipates that each HDD would take 3 to 8 weeks to complete depending on the sitespecific subsurface conditions. Although Trunkline anticipates that the majority of HDD operations 

would take place during daytime hours, overnight operations might be necessary if the drilling is at a 

critical point where stopping could result in a loss of the drill hole or an unsuccessful drill. If necessary, 

work performed during nighttime hours would be limited the amount necessary to prevent the failure. 

If drilling would exceed 55-dBA (Ldn), additional noise mitigation may be required. Potential 

noise mitigation measures that Trunkline would utilize at the HDD entry and exit sites include, but are not 

limited to, the following:

 construct a temporary noise barrier around the predominant noise-producing equipment 

which could include the use of acoustically-lined plywood panels or tents;

 utilize hospital-grade exhaust silencers on all engines;

 relocate equipment to utilize existing temporary and permanent barriers; and

 provide temporary relocation or monetary compensation to NSAs significantly impacted 

by the HDD drilling operations.

To ensure that HDD-related noise does not exceed an Ldn of 55 dBA or result in a greater than 

10 dBA increase over ambient noise levels, we recommend that:

 Trunkline should file in the biweekly construction status reports the following for 

the Indian Bayou Canal HDD entry and exit points:

a. the noise measurements from the nearest NSA, obtained at the start of 

drilling operations;

b. the noise mitigation that Trunkline implemented at the start of drilling 

operations; and 

c. any additional mitigation measures that Trunkline would implement if the 

initial noise measurements exceeded an Ldn of 55 dBA at the nearest NSA 

and/or increased noise more than 10 dBA over ambient conditions.

Other Pipeline Construction Noise

Noise associated with construction of the pipeline facilities would be short term and temporary at 

any one location because of the assembly-line method of pipeline construction. While the noise levels 

attributable to the construction equipment could noticeably increase ambient noise levels at the NSAs 

nearest the pipeline right-of-way and the other Non-Liquefaction sites, the noise increase during the 

construction phase would be temporary and localized. Because Trunkline would primarily limit 

construction to daytime hours and implement noise mitigation measures at HDD sites, we conclude that 

construction noise would not have a significant impact on landowners and residents near the NonLiquefaction Facilities.
4-145

TABLE 4.11.2-8

HDD Noise Quality Analysis for the Lake Charles Liquefaction Project

HDD Location and

Closest NSA(s) to 

Entry and Exit Points

Distance and 

Direction of NSA

Estimated 

Ambient 

Ldn (dBA)a

Unmitigated

HDD Operations 

From Entry and 

Exit Operations 

Leq (dBA)

Unmitigated

HDD Operations 

From Entry and 

Exit Operations 

Ldn (dBA)

Unmitigated

HDD 

Operations 

Plus Ambient 

Ldn (dBA)

Potential 

Increase 

Above 

Ambient

(dB) 

Arceneaux Bayou

NSA 1 – entry side 2,506 feet 

southwest

45.0 45.5 51.9 52.7 7.7

NSA 2 – entry side 2,277 feet 

southeast

45.0 46.6 53.0 53.6 8.6

No NSAs within 

0.5-mile radius of 

exit

- - - - -

Serpent Bayou

No NSAs within 

0.5-mile radius of 

entry

- 45.0 - - -

NSA 1 – exit side 1,892 feet 

southeast

45.0 21.5 27.9 45.1 0.1

NSA2 – exit side 2,231 feet 

southeast

45.0 18.3 24.7 45.0 0.0

Indian Bayou Canal

NSA 1 – entry side 213 feet 

southeast

45.0 70.4 76.8 76.8 31.8

NSA 2 – entry side 514 feet east 45.0 62.1 68.5 68.5 23.5

NSA 3 – entry side 812 feet 

northeast

45.0 57.6 64.0 64.1 19.1

NSA 4 – entry side 1,069 feet 

northwest

45.0 54.8 61.2 61.3 16.3

NSA 5 – entry side 1,228 feet west 45.0 53.3 59.7 59.8 14.8

NSA 6 – entry side 1,172 feet 

northeast

45.0 47.1 53.5 54.1 9.1

NSA7– entry side 1,006 feet 

southeast

45.0 55.4 61.8 61.9 16.9

NSA 8 – exit side 1,003 feet 

northwest

45.0 50.5 56.9 57.2 12.2

NSA 9 – exit side 632 feet 

southwest

45.0 50.3 56.7 57.0 12.0

NSA 10– exit side 1,632 feet 

southwest

45.0 42.9 49.3 50.7 5.7

Lacassine Bayou

NSA 1 – exit side 1,691 feet north 45.0 33.5 39.9 46.2 1.2

NSA 2 – exit side 2,152 feet south 45.0 35.5 41.9 46.7 1.7

NSA 3 – entry side 2,183 feet 

northwest

45.0 31.4 37.8 45.8 0.8

____________________

a Estimated from EPA, 1974 Information on Levels of Environmental Noise Requisite to Protect Public Health and Welfare 

With an Adequate Margin of Safety, based on Rural Residential Area category.
4-146

4.11.2.4 Operational Noise Impacts and Mitigation

Liquefaction Facility and LNG Terminal

Noise Assessment for Normal Operations of the Liquefaction Facility

Operation of the proposed liquefaction facility would produce noise on a continuous basis. The 

primary noise-generating sources during the operation of the liquefaction facility would be:

 air-cooled heat exchangers;

 LNG refrigerant compressor gas turbine drive units;

 gas compressor units;

 inlet and discharge piping; 

 expanders units; and

 packaged items. 

H&K modeled operational noise to evaluate the noise levels that would be generated by operation 

of the liquefaction facility and modified LNG terminal, assess the noise impacts on NSAs, and to identify 

appropriate noise mitigation measures. The results of this analysis are summarized in table 4.11.2-9. 

Modeling assumed that all compressor units and all expander units would operate in an acoustically 

treated shed structure with partial sidewalls; inlet and discharge piping would be acoustically treated with 

4-inch thick glass or mineral wool insulation covered with an outer solid acoustic liner; packaged items 

would have sufficient noise control to limit the sound pressure level to 75 dBA or less at a distance of 

3 feet; and all packaged item units would operate simultaneously except for one. 

TABLE 4.11.2-9

Estimated Noise Levels at Noise Sensitive Areas During Operation

of the Lake Charles Liquefaction Facility

Location ID

Existing Ambient 

Ldn (dBA)

June 2013

Liquefaction 

Project Impact Leq

(dBA) 

Estimated 

Liquefaction 

Project Ldn (dBA)

Combined Ldn 

(dBA) (Existing 

plus Estimated)

Potential Noise 

Increase, Ldn (dBA)

NSA 1 54.8 47.2 53.6 57.3 2.5

NSA 2 50.9 42.5 48.9 53.0 2.1

NSA 3 45.1 43.0 49.4 50.8 5.7

NSA 4 48.5 42.6 49.0 51.8 3.3

NSA 5a48.5 45.0 51.4 53.2 4.7

____________________

a Ambient noise measurements were not taken for NSA 5 and are assumed to be the same as NSA 4. 

The modeling results indicate that with the incorporation of the proposed mitigation measures, the 

noise attributable to operation of the liquefaction facility would not exceed the 55-dBA Ldn noise 

threshold at any of the NSAs. 

Operation of the liquefaction facility would occur in phases with the first and second liquefaction 

trains and associated facilities to be completed and in service in 2019, followed by the third liquefaction 

train in 2020. Therefore, to ensure that NSAs are not adversely impacted by the phased operation of the 

liquefaction facility, we recommend that:

 Lake Charles LNG should file a full load noise survey with the Secretary for the 

liquefaction facility no later than 60 days after each liquefaction train is placed into 

service for the first and second liquefaction train. If the noise attributable to the 
4-147

operation of the equipment at the liquefaction facility exceeds an Ldn of 55 dBA at 

the nearest NSA, Lake Charles LNG should reduce operation of the liquefaction 

facilities or install additional noise controls until a noise level below an Ldn of 

55 dBA at the nearest NSA is achieved. Lake Charles LNG should 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.

In compliance with the condition above, Lake Charles LNG would need to complete two noise 

surveys after the first and second liquefaction trains are placed in service to ensure that the phased-in 

liquefaction trains are below 55 dBA Ldn at the nearest NSA. If the noise levels reported in any of the 

noise surveys are over 55 dBA Ldn, Lake Charles LNG would need to implement the required mitigation 

to reduce the noise impacts on the nearest NSAs within the time specified in the condition. Once the third 

liquefaction train is installed and placed into service, we recommend that:

 Lake Charles LNG should file a noise survey with the Secretary no later than 

60 days after placing the entire liquefaction facility into service. If a full load noise 

survey is not possible, Lake Charles LNG should provide an interim survey at the 

maximum possible load and provide the full load survey within 6 months. If the 

noise attributable to the operation of all of the equipment at the liquefaction facility 

under interim or full load conditions exceeds an Ldn of 55 dBA at the nearest NSA, 

Lake Charles LNG should file a report on what changes are needed and should 

install the additional noise controls to meet the level within 1 year of the in-service 

date. Lake Charles LNG should 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.

Noise Assessment During Flaring

As described previously, the liquefaction facility would include a flare system consisting of 

startup flares and emergency flares. When in use, flares would be a source of noise. In order to evaluate 

the impacts of noise during flaring events, we recommended in the draft EIS that Lake Charles LNG file 

noise estimates for flaring activities at the liquefaction facility and modified LNG terminal, including 

supporting calculations and assumptions, as well as a description of how often flaring would occur, and 

Lake Charles LNG’s landowner notification procedures. 

Lake Charles LNG provided a noise assessment for flaring events in its May 22, 2015 response. 

The assessment, which was conducted by H&K, includes both planned flaring events and unplanned 

emergency flaring events based on assumptions detailed in the report. The results of the assessment 

indicate that the estimated noise levels at the NSAs from planned flaring events would range from 7.0 to 

61.5 dBA Ldn. Of the 15 types of planned flaring operations assessed, the only events that would exceed 

the 55-dBA Ldn noise threshold would be associated with operation of the startup flares, including sweet 

gas flaring and end flash gas, each of which is assumed in the assessment to occur once a year per LNG 

train. During these flaring events, five of the seven NSAs identified would experience noise levels 

ranging from 55.3 dBA Ldn to 61.5 dBA Ldn for a possible duration of 24 hours per event. For 

perspective, the high end of this range would be approximately comparable to conversation at close range 

as shown in table 4.11.2-1. 

The assessment found that estimated noise levels at the NSAs from seven types of unplanned 

emergency flaring operations (involving marine and emergency flares) would range from 29.1 to 

70.8 dBA Ldn. Operation of the marine flare was found not to exceed 55 dBA Ldn at any of the NSAs. 

The 55-dBA Ldn noise threshold would be exceeded at NSAs 1, 2, and 6, which would experience noise 
4-148

levels of 60.6, 59.1, and 57.5 dBA Ldn, respectively, due to operation of the emergency flares when used 

for a blocked outlet operation. These events are estimated to occur once per year per LNG train, with 

each event lasting about 0.5 hour. Noise levels would exceed the 55-dBA Ldn noise threshold at all seven 

NSAs during emergency blowdown events, with noise levels ranging from 56.1 to 70.8 dBA Ldn. These 

events are estimated to occur once a year for the entire facility, and are estimated to last for 2 hours per 

event. Noise levels would also exceed the 55-dBA Ldn noise threshold at six of the NSAs during mixed 

refrigerant blocked outlet flaring operations, with noise levels ranging from 56.6 to 65.8 dBA Ldn. These 

events are estimated to occur once per year per LNG train for a duration of 2 hours per event. The highest 

of the noise levels associated with these unplanned flaring events (i.e., 70.8 dBA Ldn during emergency 

blowdown events) would be approximately equivalent to then noise levels from chattering in a classroom 

as shown in table 4.11.2-1.

With the exception of the two startup flaring events identified above, which would last for 

24 hours each, the flaring events that would exceed the 55-dBA Ldn noise threshold would be of relatively 

short duration. Lake Charles LNG indicated in its response that details of planned flaring events would 

be posted in advance on the Lake Charles LNG project website. Additionally, landowners in the vicinity 

would be notified of planned flaring events by information leaflets that would be delivered to their 

properties. In summary, while flaring noise might be a nuisance for nearby residents during flaring 

events, these events would occur infrequently and, therefore, would not result in significant noise impacts.

Compressor Station 203-A

Noise Assessment for Operations at Full Load at Compressor Station 203-A

The noise impact evaluation for Compressor Station 203-A considers the noise produced by all 

significant sound sources associated with the proposed compressor station that could impact the sound 

contribution at the nearby NSAs. Significant sound sources include five Caterpillar G3616 compressor 

units, five Solar Mars 100 compressor units, and aboveground gas piping. The noise evaluation 

incorporates reductions from the proposed noise controls. Noise controls for the compressor building 

include acoustical specifications for wall, roof, and entry door materials; prohibition of windows, 

skylights, or open louvers; patching and sealing requirements; acoustical specifications for a double rollup door system for equipment access; and acoustical specification for the ventilation system. Noise 

controls for the compressor equipment include the use of specified silencers, mufflers, ductwork, and 

acoustic blankets. Table 4.11.2-10 shows the estimated noise impact due to the full load operation of 

Compressor Station 203-A. 

TABLE 4.11.2-10

Estimated Noise Levels at Noise Sensitive Areas During Operation of Compressor Station 203-A

Location ID

Existing Ambient Ldn (dBA)

June 2013

Estimated Compressor Station 

203-A Project Ldn (dBA) at 

Normal Full Load Operations

Combined Ldn (dBA) 

(Existing plus Estimated)

Potential Noise 

Increase, Ldn (dBA)

NSA 1 53.2 52.7 56.0 2.8

NSA 2 49.0 51.8 53.7 4.7

NSA 3 52.5 48.2 53.9 1.4

NSA 4 54.3 46.0 54.9 0.6

NSA 5a52.5 54.2 56.5 4.0

____________________

a NSA 5 was identified after the preconstruction survey was conducted. The existing ambient sounds level at this NSA is 

assumed to be the same as measured at NSA 3.
4-149

The modeling results indicate that with the incorporation of the proposed mitigation measures, 

operational noise at Compressor Station 203-A would not exceed the 55-dBA Ldn noise threshold at any 

of the NSAs. 

Based on the noise analysis above, noise levels attributable to operation of Compressor Station 

203-A would be less than 55 dBA Ldn at all nearby NSAs. To ensure that the noise from the compressor 

station does not exceed an Ldn of 55 dBA at the nearest NSAs, we recommend that:

 Trunkline should file a noise survey for Compressor Station 203-A no later than 

60 days after placing the station into service. If a full power load condition noise 

survey is not possible, Trunkline should file an interim survey at the maximum 

possible power load within 60 days of placing the station into service and file the full 

power load survey within 6 months. If the noise attributable to operation of all 

equipment at the station under interim or full power load conditions exceeds an Ldn

of 55 dBA at any nearby NSA, Trunkline should:

a. file a report with the Secretary, for review and written approval by the 

Director of OEP, on what changes are needed;

b. install additional noise controls to meet that level within 1 year of the inservice date; and

c. confirm compliance with this requirement by filing a second full power load 

noise survey with the Secretary for review and written approval by the 

Director of OEP no later than 60 days after it installs the additional noise 

controls.

Based on the noise analysis and our recommendation, we believe that operation of Compressor 

Station 203-A would have no significant impact on the noise environment in the vicinity of the station.

Noise Assessment for Normal Unit Blowdown Events at Compressor Station 203-A

The sound levels associated with high pressure gas venting are a function of 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.

Trunkline would install silencers on the gas blowdown equipment to limit the noise level to 

60 dBA at a distance of 300 feet. NSA 5, which is the nearest NSA to Compressor Station 203-A, is 

about1,140 feet from the facility; therefore, the estimated sound level at this NSA would be about 52 dBA 

or less during unit blowdown events. This estimate assumes a direct line of site between the silencer 

outlet and NSA 5 with no shielding from structures or foliage. As estimated noise levels are below the 

55-dBA threshold, blowdown events would be expected to have an insignificant impact on the nearest 

NSAs. To further minimize impacts of blowdown noise on nearby landowners, Trunkline would notify 

nearby landowner prior to performing blowdowns required for maintenance.
4-150

Longville Compressor Station

The primary sound sources associated with the proposed modifications at the Longville 

Compressor Station would include:

 turbine-compressor casing noise that penetrates the compressor building;

 noise from the turbine exhaust system;

 noise from the turbine air intake system;

 noise from the electric motor driven lube oil cooler; and

 noise radiated by any above ground piping.

Table 4.11.2-11 shows the estimated noise impact at normal full load operation of the Longville 

Compressor Station with the addition of the proposed modifications and associated proposed noise 

controls. 

TABLE 4.11.2-11

Estimated Noise Levels at Noise Sensitive Areas During Operation of the Longville Compressor Station

Location ID

Existing Ldn at Full Load 

Station Operation 

(dBA)

Estimated Longville Compressor 

Ldn (dBA) – Proposed Addition 

Only

Combined Ldn 

(dBA) 

Potential Noise 

Increase (dBA)

NSA 1 68.6 39.0 68.6 0.0

NSA 2 66.8 41.7 66.8 0.0

NSA 3 60.6 44.0 60.7 0.1

NSA 4 55.0 39.8 55.1 0.1

The Longville Compressor Station was authorized in 1950 and placed into service in 1951. At 

that time, the Commission’s regulations did not require the current noise level of an Ldn of 55 dBA. As 

shown in table 4.11.2-11, the noise levels from the existing equipment at the Longville Compressor 

Station are above an Ldn of 55 dBA at three of the four nearest NSAs. However, these existing facilities 

are not required to retroactively comply with noise standards that were later adopted by the Commission. 

The modeling results indicate that the noise contribution from the proposed compressor unit 

replacement itself at the Longville Compressor Station would not exceed the 55-dBA Ldn noise threshold 

at any of the nearby NSAs. To ensure that there is no perceptible increase in noise levels resulting from 

operation of the Longville Compressor Station, we recommend that:

 Trunkline should conduct noise surveys at the Longville Compressor Station to 

verify that the noise from all the equipment operated at full power load does not 

exceed the predicted noise levels above an Ldn of 55 dBA at any nearby NSAs. The 

results of the noise surveys should be filed with the Secretary no later than 60 days

after placing the new compressor unit in service. If a full load condition noise 

survey is not possible, Trunkline should provide an interim survey at the maximum 

possible horsepower load within 60 days of placing the new compressor unit into 

service and provide the full load survey within 6 months. If the noise attributable to 

the operation of the modified compressor station at full or interim power load 

conditions exceeds predicted noise levels at any nearby NSAs, Trunkline should file 

a report on what changes are needed and should install the additional noise controls 

to meet the level within 1 year of the in-service date. Trunkline should confirm 

compliance with this requirement by filing a second noise survey with the Secretary 

no later than 60 days after it installs the additional noise controls.
4-151

Based on the noise analysis and our recommendation, we conclude that operational noise impacts 

resulting from the proposed modifications at the Longville Compressor Station would be insignificant.

Noise Assessment for Normal Unit Blowdown Events at the Longville Compressor Station

The sound levels associated with high pressure gas venting are a function of 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.

Trunkline would install silencers on the gas blowdown equipment to limit the noise level to 

50 dBA at a distance of 300 feet. NSA 3, which is the nearest NSA to the Longville Compressor Station, 

is about 880 feet from the facility; therefore, the estimated sound level at this NSA would be about

51 dBA during unit blowdown events. This estimate assumes a direct line of site between the silencer 

outlet and NSA 3 with no shielding from structures or foliage. As estimated noise levels are below the 

55-dBA threshold, blowdown events would be expected to have an insignificant impact on the nearest 

NSAs. To further minimize impacts of blowdown noise on nearby landowners, Trunkline would notify 

nearby landowner prior to performing blowdowns required for maintenance.

4.12 RELIABILITY AND SAFETY

4.12.1 Regulatory Agencies

Three federal agencies share regulatory authority over the siting, design, construction, and 

operation of LNG import 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 49 CFR 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 an MOU 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 MOU 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, but remain responsible for 

enforcing their regulations covering LNG facility design, construction, and operation. All three agencies 

have some oversight and responsibility for inspection and compliance during the facility’s operation.
4-152

As part of the review required for a FERC authorization, Commission staff must evaluate whether

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 site-specific 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, 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 of 49 CFR 193, Subpart B. As part of our NEPA review, 

we use this information from the applicant, developed to comply with DOT’s regulations, 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 49 CFR 193 would be made 

by DOT staff.

In accordance with 33 CFR 127, the Coast Guard has reviewed the proposed liquefaction 

facilities and stated that the existing WSA and LOR are adequate for the service associated with the 

proposed modifications. A copy of the correspondence between Lake Charles LNG and the Coast Guard 

is included in Appendix 11-D of Resource Report 11.3

Section 4.12.2 provides a brief history on LNG incidents and discusses the principal properties 

and hazards associated with LNG, refrigerants, stabilized condensate products, and toxic components; 

section 4.12.3 discusses our technical review of the preliminary design; section 4.12.4 discusses siting 

requirements for Lake Charles LNG’s facilities; section 4.12.5 discusses the siting analysis of the LNG 

facility; section 4.12.6 discusses emergency response and evacuation planning; section 4.12.7 discusses 

LNG vessel safety; and section 4.13.8 provides conclusions regarding LNG facility reliability and safety. 

Section 4.13.9 discusses reliability and safety of the proposed pipeline facilities.

4.12.2 LNG Facility Hazards

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 people.4 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 1979 at 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 

 

3 Accession Number: 20140325-5137.

4

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.
4-153

the building and a worker fatality. With the participation of the FERC, lessons learned from the 1979 

Cove 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 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, 

Lake Charles LNG 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, Lake Charles LNG would pre-treat the feed gas for the removal of hydrogen 

sulfide (H2S), CO2, water (H2O), and mercury (Hg). 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 Hg and H2S. The process of removing H2S would require the use of an amine solution, a hazardous 

substance, which is discussed below. Additionally, the feed gas may contain pentane and heavier 

hydrocarbons, including aromatic hydrocarbons such as benzene, toluene, and xylene. Although a small 

amount is expected, they are still considered hazardous substances.

Lake Charles LNG proposes a design capacity to handle up to 15 micrograms per normal cubic 

meter (μg/Nm3) Hg, 3.3 parts per million by volume H2S, and 2 percent by volume CO2. However, lower 

quantities and concentrations of these substances would be expected in the natural gas feed stream and 

would not pose a hazard to the public. 

The CO2 and H2S would be removed from the feed gas by a closed-loop regenerative amine 

system which uses a Methyldiethanolamine (amine) solution. As the CO2 and H2S are removed by the 

amine solution, these substances would accumulate within the amine solution and reduce the effectiveness 

of the amine system. Therefore, the amine solution would be regenerated periodically, where an acid gas 

stream with concentrations up to 213 parts per million by mole H2S and 95 mole percent CO2 would be 

separated from the contaminated amine solution and routed to a Hydrogen Sulfide Removal Unit to 

remove the H2S content. The resulting waste gas stream would be sent to the Thermal Oxidizer for 

further treatment to reduce emission prior to discharging to the atmosphere. 
4-154

Mercury in the feed gas would be removed by absorption in mercury removal beds. Lake Charles 

LNG would replace the mercury removal beds by the end of their service life. Maintenance and safety 

procedures would cover the proper replacement and disposal of spent materials. The amine solution 

would be contained, as discussed under “Impoundment Sizing” in section 4.12.5.1. Therefore, the amine 

solution would not pose a significant hazard to the public, which would have no access to the on-site 

areas. 

In addition to the removal of CO2, H2O, H2S, and mercury, Lake Charles LNG would install a 

fractionation unit to condense pentane and heavier hydrocarbons that may be present in the feed gas. 

During this removal process, natural gas liquids (NGL) would be extracted and handled on site at 

temperature and pressure conditions under which a loss of containment would result primarily in a vapor 

release and the ability to produce damaging overpressures. The fractionation process would produce 

stabilized condensate, which includes pentane and heavier hydrocarbons, as well as a small trace of toxic 

components that include benzene, toluene, and xylene. The stabilized condensate would be stored on site 

at atmospheric pressure and temperature. Due to the temperature and pressure conditions under which the 

stabilized condensate would be stored and handled, a loss of containment would primarily result in a 

liquid release. 

Although not a part of the pretreatment process, an aqueous ammonia solution would be used in 

the utility system to control emission of nitrogen oxide. An aqueous ammonia solution (19 percent by 

weight) would be used in the Selective Catalytic Reduction (SCR) units on the mixed refrigerant and 

propane compressor gas turbine drivers as the reduction agent to convert nitrogen oxide into nitrogen 

before emission. The aqueous ammonia solution would be stored on-site at atmospheric conditions. A 

release of aqueous ammonia would form a liquid pool and may produce a flammable cloud. However, its 

impact would be smaller in comparison to other flammable products stored and handled on-site.

A loss of the containment from the storage tanks or process piping would result in the formation 

of flammable or toxic vapor at the release location, as well as from any LNG or liquid flammable 

refrigerant that pooled. Releases occurring in the presence of an ignition source would most likely result 

in a fire at the vapor source. A spill without ignition would form a vapor cloud that would travel with the 

prevailing wind until it either dispersed below the flammable limits or encountered an ignition source. In 

some instances, ignition of a vapor cloud may produce damaging overpressures. These hazards are 

described in more detail below.

Loss of Containment

Lake Charles LNG would store the following on site: LNG at atmospheric pressure and at a 

cryogenic temperature of about –260°F; liquid ethane at 46°F and 405 pounds per square in gauge (psig); 

liquid propane at ambient temperature and 153 psig (similar to the conditions typically used in propane 

storage and domestic distribution), stabilized condensate, and aqueous ammonia (19 percent by weight) at 

ambient conditions.

The mixed refrigerant process stream would consist of nitrogen, CH4, ethane, and propane. 

Cryogenic temperatures as low as –243°F would occur within the MR process stream used to liquefy the 

feed gas. The temperature of NGL in the heavy hydrocarbon removal process stream would be as low as 

–83°F. Loss of containment of LNG and mixed refrigerant liquid (MRL), and NGL could lead to the 

release of both liquid and vapor into the immediate area. Exposure to either cold liquid or vapor could 

cause freeze burns and, depending on the length of exposure, more serious injury or death. However, 

spills would be contained to on-site areas and the cold state of these releases would be greatly limited due 
4-155

to the continuous mixing with the warmer air. The cold temperatures from the release would not present 

a hazard to the public, which would not have access to on-site areas. 

LNG and portions of the MRL stream are cryogenic liquids that would 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 psi.5 These 

events are typically limited to 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, ethane, propane, and NGL would vaporize on release 

from any storage or process facilities. Depending on the size of the release, cryogenic liquids, such as 

LNG and MRL, may 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. Ethane will produce about 300 ft3of gas for each cubic foot of liquid. Propane will 

produce about 260 ft3of gas for each cubic foot of liquid. The composition of the extracted NGL would 

vary throughout the heavy hydrocarbon removal process and may produce up to about 260 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 

propane. 

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. 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). A 

 

5 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.
4-156

liquid ethane release would form a denser-than-air vapor cloud that would sink to the ground due to the 

cold temperature of the vapor. As the ethane vapor cloud disperses downwind and mixes with the warm 

surrounding air, the ethane vapor would become neutrally buoyant. A propane release would form a 

denser-than-air vapor cloud that would sink to the ground; however, propane would remain denser than 

the surrounding air, even after warming to ambient temperatures. Any NGL release would form a denserthan-air vapor cloud, even after warming to ambient temperatures. 

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 Level (AEGL) and Emergency Response Planning Guidelines (ERPG) can be used for 

emergency planning, prevention, and response activities related to the accidental release of hazardous 

substances.6 Other federal agencies, such as the DOE, EPA, and NOAA, use AEGLs and ERPGs as the 

primary measure of toxicity.7,8,9 

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 because

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 4.12.2-1.

 

6 U.S. Environmental Protection Agency, Dose-Response Assessment for Assessing Health Risks Associated With Exposure to 

Hazardous Air Pollutants, http://www2.epa.gov/fera/dose-response-assessment-assessing-health-risks-associated-exposurehazardous-air-pollutants, July 3, 2014.

7 U.S. Department of Energy, Temporary Emergency Exposure Limits for Chemicals: Methods and Practice, DOE Handbook, 

DOE-HDBK-1046-2008, August 2008.

8 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.

9 U.S. National Oceanic and Atmospheric Administration, Public Exposure Guidelines, http://response.restoration.noaa.gov/

oil-and-chemical-spills/chemical-spills/resources/public-exposure-guidelines.html, December 3, 2013.
4-157

TABLE 4.12.2-1

Toxicity Levels of Various Material Components (in ppm)a,b,

Material Components

Acute Exposure 

Guideline Level 10 min 30 min 60 min 4 hr 8 hr

Ammonia AEGL 1 30 30 30 30 30

AEGL 2 220 220 160 110 110

AEGL 3 2,700 1,600 1,100 550 390

Benzene AEGL 1 130 73 52 18 9

AEGL 2 2,000 c1,100 800 400 200

AEGL 3 9,700 d5,600 c4,000 c2,000 c990

Hydrogen Sulfide AEGL 1 0.75 0.60 0.51 0.36 0.33

AEGL 2 41 32 27 20 17

AEGL 3 76 59 50 37 31

Toluene AEGL 1 200 200 200 200 200

AEGL 2 3,100 c 1,600 1,200 790 650

AEGL 3 13,000 d6,100 c4,500 c3,000 c2,500 c

Xylenes AEGL 1 130 130 130 130 130

AEGL 2 2,500 c1,300 c920 c500 400

AEGL 3 7,200 d3,600 c2,500 c1,300 c1,000 c

____________________

a U.S. Environmental Protection Agency, Acute Exposure Guideline Levels, http://www.epa.gov/oppt/aegl/pubs/

chemlist.htm, December 3, 2013. 

b American Industrial Hygiene Association, 2013 ERPG/WEEL Handbook, http://www.aiha.org/get-involved/AIHAGuideline

Foundation/EmergencyResponsePlanningGuidelines, 2013.

c Greater than or equal to 10 percent LFL.

d Greater than or equal to 50 percent 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 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 4.12.2-2.

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. Lake Charles LNG 

has modeled the extent of the potential vapor dispersion hazards for the project, which is discussed in 

section 4.12.5.
4-158

TABLE 4.12.2-2

Flammable Propertiesa

Material Component Flash Point LFL (percent volume) UFL (percent volume)

Methane –283°F 5.0 15.0

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

n-Hexane –7.6°F 1.2 7.5

Benzene 11°F 1.4 7.1

Toluene 45°F 1.2 7.1

m-Xylene 77°F 1.1 7.0

o-Xylene 75°F 1.1 6.0

p-Xylene 77°F 1.1 7.0

Hydrogen sulfide –116°F 4.0 44

____________________

a Society of Fire Protection Engineers, The SFPE Handbook of Fire Protection Engineering, Fourth Edition, 2008.

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. Lake Charles LNG has modeled the extent of the potential 

flammable vapor dispersion hazards for the project, which is discussed in section 4.12.5.3.

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. Lake Charles LNG has modeled the extent of the potential overpressure hazards for 

the project, which is discussed in section 4.12.5.4. 

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. The potential radiant heat hazards for the project are discussed in section 4.12.5. 

Overpressures

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, large pressure waves are produced, and a shock wave is created. This shock wave, rather than the 
4-159

heat, would begin to drive the flame, resulting in a detonation. Deflagrations or detonations are generally 

characterized as “explosions” as the rapid movement of the flame and pressure waves associated with 

them cause additional damage beyond that from the heat. The amount of damage an explosion causes is 

dependent on the amount the produced pressure wave is above atmospheric pressure (i.e. an overpressure) 

and its duration (i.e., pulse). For example, a 1 psi overpressure, often cited as a safety limit in U.S. 

regulations, is associated with glass shattering and traveling with velocities high enough to lacerate skin.

Flame speeds and overpressures 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. 

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 methane-propane. 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. 

Although it has been possible to produce damaging overpressures and detonations of unconfined 

LNG vapor clouds, the feed gas stream proposed for the project would have lower ethane and propane 

concentrations than those that resulted in damaging overpressures and detonations. 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, Lake Charles LNG would take measures to mitigate the vapor dispersion and ignition into 

confined areas, such as buildings. Lake Charles LNG 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. 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. 

In comparison with LNG vapor clouds, there is a higher potential for unconfined propane clouds 

to produce damaging overpressures. 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 confinement (Pierorazio, 2005). 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 are ignited within a confined space, such 

as in a building, they all have the potential to produce damaging overpressures. The MRL and NGL 

process streams would contain a mixture of components such as the ones discussed above (i.e., propane). 

Therefore, a potential exists for these process streams to produce unconfined vapor clouds that could 

produce damaging overpressures in the event of a release.
4-160

Discussion of these hazards and potential mitigation are in section 4.12.5 for the project facilities. 

Lake Charles LNG has also mitigated the risk for cascading event hazards for the project, which is also 

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-liquidexpanding-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. 

Failures of nearby storage vessels, piping, and equipment and the potential for cascading events 

are discussed in section 4.12.5.6. 

4.12.3 Technical Review of the Facility Preliminary Engineering 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 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;
4-161

 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.

We believe 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 

49 CFR 193, Subpart B require a siting analysis be performed by Lake Charles LNG.

As part of the application, Lake Charles LNG provided a FEED for the project. In developing the 

FEED, Lake Charles LNG conducted a hazard identification study of the preliminary site layout, plot 

plans, and process flow diagrams to 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 Lake Charles 

LNG 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 NFPA’s Standard 59A 

(NFPA 59A). All LNG storage tanks would also include boil-off gas compression 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 generally accepted good engineering practices. LNG facilities

would be designed to withstand a sustained wind of 150 miles per hour (mph), which converts to 183 mph 

at a 3-second gust per 49 CFR §193.206710. The wind forces on shop fabricated containers of LNG or 

other hazardous fluids with a capacity of not more than 70,000 gallons would be based on applicable wind 

load data in ASCE/SEI/ 7-05. TLNG proposes to design all other facilities to 3-second gust wind speed 

of 110 mph.

The ground surface of the liquefaction facilities would be elevated to about +11.0 feet North 

American Vertical Datum 1988 (NAVD88) in order to be above the flood elevations. The Lake Charles 

LNG site would be located 24 miles north of the Gulf of Mexico shoreline. As mentioned in 

section 4.1.4, the top of concrete elevation for all critical equipment (e.g., transformers, substations, 

switchgears, remote instrument enclosure units, mixed refrigerant and propane compressors, BOG 

compressors, cryogenic heat exchanges, propane vaporizers) would be at an elevation of +15.0 feet. The 

 

10 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.
4-162

top of the concrete elevations for critical equipment would be above the maximum elevations anticipated 

from a Category 3 hurricane strike. 

The control building floor slab would have two top of concrete elevations. The majority of the 

control building floor slab top of concrete elevation would be +12.5 feet while the recessed areas for 

computer access floors would have top of concrete elevation of +11.0 feet, which would be above the 

100-year floodplain elevation.

The tallest structure would be the flares in the common derrick, which would be approximately 

350 feet tall per FAA regulations.

Lake Charles LNG 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. 

Lake Charles LNG 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 Lake Charles LNG 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 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 84.00.01 and other 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 

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 liquefaction facilities 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 USCG regulations in 33 CFR 127. Lake Charles LNG proposed to install access control 

system, intrusion detection system, and security cameras at plant entrances, security gates, perimeter 

fence, LNG loading/unloading docks, and buildings. Lake Charles LNG also indicated adherence to 

cyber security standards ISA 99.00.01, ISA 99.01.01, and ISA 99.02.01.

Requirements for maintaining security of the liquefaction facility can be found in 33 CFR 105. 

These security requirements were authorized by the Maritime Transportation Security Act (MTSA) of 

2002, which requires all terminal owners and operators to submit a Facility Security Assessment and a 
4-163

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 an 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.

The Trunkline LNG Terminal has an existing Facility Security Plan which has been approved by 

the USCG. Lake Charles LNG would update the Facility Security Plan to include the changes in 

operations and the increased facility footprint associated with the liquefaction project.

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 meet the requirements of NFPA 59A (2001 edition), as referenced in 49 CFR 

193.2401. 

Lake Charles LNG 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 generally accepted good engineering 

practices. Lake Charles LNG 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 and other 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, 11, 13, 14, 15, 17, and other generally accepted good engineering practices. 

Lake Charles LNG 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, 24, and 25 requirements. We have made recommendations for Lake Charles LNG to 

provide more information on the design, installation, and commissioning of hazard detection, hazard 
4-164

control, and firewater systems as Lake Charles LNG would further develop this information during the 

final design phase.

Lake Charles LNG would also have written emergency procedures in accordance with 49 CFR 

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. 

Lake Charles LNG would also be required to develop an emergency response plan (ERP) in accordance 

with EPAct 2005. As discussed further in section 4.13.6, an ERP has been in place since the Trunkline 

LNG Terminal re-commissioned the import of LNG in 1989; however, Lake Charles LNG would need to 

update the existing ERP to include the proposed liquefaction facilities and emergencies related to 

refrigerant handling.

As a result of the technical review of the information provided by Lake Charles LNG in the 

submittal documents, we identified a number of concerns in information data request letters issued on 

July 3, 2014 and November 18, 2014 relating to the reliability, operability, and safety of the proposed 

design. Lake Charles LNG provided written responses to the information data request on July 24, 2014 

and November 25, 2014. Some of these responses indicated that Lake Charles LNG would correct or 

modify its design in order to address issues raised in the information request. These responses are 

referenced in table 4.12.3-1. As a result, we recommend that:

 Prior to construction of the final design, Lake Charles LNG should file with the 

Secretary, for review and approval by the Director of OEP, information/revisions 

pertaining to Lake Charles LNG’s response to the Engineering Information 

Requests identified in table 4.12.3-1 of the EIS. 

TABLE 4.12.3-1

Lake Charles LNG Responses Indicating Corrections or Modifications to the Front-End Engineering Design

Date of FERC Engineering

Information Request

FERC Engineering

Information Request

Filing Date of

Lake Charles LNG Response

July 3, 2014 Resource Report 13: 1, 2(b), 6, 9, 11, 12, 13, 15(a), 15(e), 

19, 21, 23, 24, 25, 26, 27, 29, 30, 32, 39, 40, 42, 45, 48, 

53, 57, and 60

July 24, 2014

November 18, 2014 3, 4, and 5 November 25, 2014

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 Lake Charles LNG 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. 
4-165

Once the design has been subjected to a HAZOP review, Lake Charles LNG’s design 

development team would track changes in the facility design, operations, documentation, and personnel. 

Lake Charles LNG 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 

Lake Charles LNG 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 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 Lake Charles LNG, and to 

ensure that the facility is subject to the Commission’s construction and operational inspection program, 

we recommend that the following measures should apply to the Lake Charles Liquefaction Project 

LNG facilities. Information pertaining to these specific recommendations should 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, should be submitted as 

critical energy infrastructure information (CEII) 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, Lake Charles LNG should provide procedures for 

controlling access during construction.

 Prior to initial site preparation, Lake Charles LNG should file the quality assurance 

and quality control procedures for construction activities.

 Prior to initial site preparation, Lake Charles LNG should file a plot plan of the 

final design showing all major equipment, structures, buildings, and impoundment 

systems.

 The final design should include change logs that list and explain any changes made 

from the FEED provided in Lake Charles LNG’s application and filings. A list of 

all changes with an explanation for the design alteration should be provided and all 

changes should be clearly indicated on all diagrams and drawings.

 The final design should provide up-to-date Process Flow Diagrams with heat and 

material balances and piping and instrumentation diagrams (P&ID), which include 

the following information: 

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness; 

c. storage tank (i.e., condensate) pipe penetration size or nozzle schedule;

d. valve high pressure side and internal and external vent locations;
4-166

e. piping with line number, piping class specification, size, and insulation type 

and thickness; 

f. piping specification breaks and insulation limits; 

g. all control and manual valves numbered; 

h. relief valves with size and set points; and

i. drawing revision number and date. 

 The final design should provide P&IDs, specifications, and procedures that clearly 

show and specify the tie-in details required to safely connect the project to the 

existing facility.

 The final design should provide an up-to-date complete 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 provide complete drawings and a list of the hazard detection 

equipment. The drawings should clearly show 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 hazard detection 

equipment.

 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 clearly show the location by tag 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 provide facility plans and drawings that show the location of 

the firewater and foam systems. Drawings should clearly show: firewater and foam 

piping; post indicator valves; and the location, and area covered by, each monitor, 

hydrant, deluge system, foam system, water-mist system, and sprinkler. The 

drawings should also include P&IDs of the firewater and foam system.

 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 by 49 CFR Part 193. The evaluation should consider 

the need for clean agent fire suppression in the new switchgears and motor control 

centers. A copy of the evaluation, a list of recommendations and supporting 

justifications, and actions taken on the recommendations should be filed.

 The final design should specify that for hazardous fluids, piping and piping nipples 

2 inches or less in diameter are to be no less than schedule 160 for carbon steel and 

no less than schedule 80 for stainless steel, or are designed to withstand external 

loads, including vibrational loads in the vicinity of rotating equipment and live loads 

of operators in areas accessible by operators.
4-167

 The final design should include drawings and 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 leak detection device that: should continuously monitor for the 

presence of a flammable fluid; should alarm the hazardous condition; and should 

shutdown the appropriate systems.

 The final design should provide electrical area classification drawings.

 The final design should provide spill containment system drawings with dimensions 

and slopes of curbing, trenches, and impoundments.

 The final design of the hazard detectors should account for the calibration gas when 

determining the LFL set points for methane, propane, ethane, and condensate.

 The final design should include a hazard and operability review of the completed 

design prior to issuing the P&IDs for construction. A copy of the review, a list of 

recommendations, and actions taken on the recommendations, should be filed.

 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 drawing showing the location of the emergency 

shutdown buttons. Emergency shutdown buttons should be easily accessible, 

conspicuously labeled, and located in an area that would be accessible during an 

emergency.

 The final design should specify that all emergency shutdown valves are to be 

equipped with open and closed position switches connected to the Distributed 

Control System/Safety Instrumented System. 

 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 by 49 CFR 193, and should 

provide justification if not using an inert or non-flammable gas for cleanout, dryout, purging, and tightness testing.

 The final design should include the sizing basis and capacity for the final design of 

pressure and vacuum relief valves for major process equipment, vessels, and storage 

tanks.

 The final design should provide the procedures for pressure/leak tests that address 

the requirements of ASME VIII and ASME B31.3, as required by 49 CFR 193.
4-168

 The final design should include a structural evaluation of each LNG storage tank 

that accounts for the modifications to the tanks, internal pump columns, and piping 

systems. The evaluation should include the following: 

a. modification details; 

b. structural design loading and acceptance criteria used to evaluate the 

structural integrity of the LNG storage tanks, internal pump columns, piping 

and associated supports; 

c. effects of the modifications on the tanks’ structural design; and

d. review and approval by the tank manufacturer to verify the structural 

integrity of the tank is adequate to support the modifications and proposed 

operating conditions and other design loadings.

 The final design of the thermal relief valve PSV-880 discharge should not be 

directed downstream of emergency shutdown valve ESDV-510.

 The final design should specify that the design pressure of the Hot Oil Expansion 

Drum, A801-F, should be consistent with the design pressure of the hot oil system.

 The final design of the inlet and discharge piping to/from PSV-060A/B on the Rich 

Amine Flash Drum should be stainless steel and should discharge to the low 

pressure flare header to be consistent with the flare pressure design philosophy.

 The final design should include a piping specification that applies to the design 

conditions of the regeneration piping systems associated with the dehydrators.

 The final design of the discharge from pressure controlled vents PV-144 and PV-124 

on the mixed refrigerant system should be directed to the low pressure cold flare 

header.

 The final design should include a full evaluation and justification for the exclusion 

of suction drums for the medium pressure and high pressure stages of the medium 

and high pressure mixed refrigerant compressors. The evaluation should include 

consideration for settle out condensation under all conditions.

 The final design of the firewater pump testing system should include flow and 

pressure transmitters that connect to the distributed control system. The P&IDs 

should show the test piping from the discharge of each pump connecting to a 

common header upstream of the flow and pressure transmitters.

 The final design should provide details of the heating element for the Flare 

Knockout Drums and the method of insertion and removal.

 The final design should evaluate the installation of a forward pressure control valve 

with flow reset, rather than a flow control valve (i.e., FV-82127), on the regeneration 

stream to the Ethane Treatment Beds.

 The final design should demonstrate that the design pressure of the Propane 

Transfer Pump, 8202-J, and the set pressure of the discharge relief valve PSV-82087 

would be consistent with the propane transfer pump shutoff pressure conditions.
4-169

 The final design should provide procedures of how to prevent the flare system from 

overloading due to excessive intentional and inadvertent venting from the blowdown 

valves.

 The final design of the refrigerant storage system should allow the isolation of 

individual pressure relief valves while providing full relief capacity, during pressure 

relief valve maintenance or testing.

 Prior to commissioning, procedures should be developed for providing the facility 

with fire water coverage during such times as the fire water system would be out of 

service, in particular for removing and flushing brackish water from the system.

 Prior to commissioning, Lake Charles LNG should file plans and detailed 

procedures for: testing the integrity of on-site mechanical installation; functional 

tests; introduction of hazardous fluids; operational tests; and placing the equipment 

into service.

 Prior to commissioning, Lake Charles LNG 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. Lake Charles LNG should file 

documentation certifying that each of these milestones has been completed before 

authorization to commence the next phase of commissioning and startup would be 

issued.

 Prior to commissioning, Lake Charles LNG should tag all equipment, 

instrumentation, and valves in the field, including drain valves, vent valves, main 

valves, and car-sealed or locked valves.

 Prior to commissioning, Lake Charles LNG 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, Lake Charles LNG should file updates addressing the 

liquefaction facilities in the operation and maintenance procedures and manuals, as 

well as safety procedures.

 Prior to commissioning, Lake Charles LNG should maintain a detailed training log 

to demonstrate that operating staff has completed the required training.

 Prior to introduction of hazardous fluids, Lake Charles LNG 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 introduction of hazardous fluids, Lake Charles LNG should complete all 

pertinent tests (Factory Acceptance Tests, Site Acceptance Tests, Site Integration 

Tests) associated with the Distributed Control System and the Safety Instrumented 

System that demonstrates full functionality and operability of the system.
4-170

 Prior to commencement of service, Lake Charles LNG should label piping with fluid 

service and direction of flow in the field in addition to the pipe labeling 

requirements of NFPA 59A.

 Prior to commencement of service, Lake Charles LNG should notify FERC staff of 

any proposed revisions to the security plan and physical security of the facility. 

 Prior to commencement of service, progress on the construction of the proposed 

systems should be reported in monthly reports filed with the Secretary. Details 

should include a summary of activities, problems encountered, contractor 

non-conformance/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 the following measures should apply throughout the life of the 

facilities:

 The facility should 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, Lake Charles LNG 

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 P&IDs 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 semi-annual report, should be submitted.

 Semi-annual operational reports should be filed with the Secretary to identify 

changes in facility design and operating conditions, abnormal operating experiences, 

activities (including ship arrivals, quantity and composition of imported and 

exported LNG, liquefied and vaporized quantities, boil-off/flash gas, etc.), plant 

modifications, including future plans and progress thereof. Abnormalities should 

include, but not be limited to: unloading/loading/shipping problems, potential 

hazardous conditions from 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 reasons therefore), relative movement of 

storage tank inner vessels, hazardous fluids releases, fires involving hazardous 

fluids 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 also should 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)” also should be included in the semi-annual operational reports. Such 

information would provide FERC staff with early notice of anticipated future 

construction/maintenance projects at the LNG facility.

 Significant non-scheduled events, including safety-related incidents (e.g., LNG, 

condensate, refrigerant, or natural gas releases, fires, explosions, mechanical 

failures, unusual over pressurization, and major injuries) and security-related 

incidents (e.g., attempts to enter site, suspicious activities) should be reported to 
4-171

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 emergency procedure. 

In all instances, notification should be made to FERC staff within 24 hours. This 

notification practice should 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 fluids 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 LNG facility that contains, controls, or processes hazardous 

fluids; 

h. any malfunction or operating error that causes the pressure of a pipeline or 

LNG facility that contains or processes hazardous fluids to rise above its 

MAOP (or working pressure for LNG facilities) plus the build-up allowed for 

operation of pressure limiting or control devices; 

i. a leak in an LNG facility that contains or processes hazardous fluids that 

constitutes an emergency; 

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 operating pressure or 

shutdown of operation of a pipeline or an LNG facility that contains or 

processes hazardous fluids; 

l. safety-related incidents to hazardous fluids vessels 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 should 
4-172

include investigation 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, we believe that the 

FEED presented by Lake Charles LNG would include acceptable 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 Facility Siting Requirements

The principal hazards associated with the substances involved in the liquefaction 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 49 CFR 

193, Subpart B to ensure that impact to the public would be minimized. The Commission’s regulations 

under 18 CFR 380.12(o)(14) require Lake Charles LNG to identify how the proposed design complies 

with the siting requirements of DOT’s regulations in 49 CFR 193, Subpart B. As part of our review, we 

used Lake Charles LNG’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 (b)(3), 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); and

 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).
4-173

For the LNG facilities proposed for the project, these Part 193 siting requirements would be 

applicable to the following equipment:

 twelve 4,625 gpm in-tank pumps (three pumps per LNG storage tank) used for ship 

loading and associated piping and appurtenances; and six 6,962 gpm LNG product pumps 

(two pumps per liquefaction train) used for LNG storage tank loading 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; and

 three liquefaction heat exchangers (one per liquefaction train) and associated piping and 

appurtenances, including two 20-inch-diameter LNG rundown lines in parallel – 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 193.2059 require 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.

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 consider it prudent design practice to 

provide containment for all LNG transfer piping within a plant’s property lines.

Federal regulations issued by the Occupational Safety and Health Administration (OSHA) under 

29 CFR 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 
4-174

the transportation exemption applies to LNG facilities subject to oversight or regulation under 49 CFR 

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 49 CFR 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 (2001 edition) 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 (2001 edition) 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 (2001 edition) 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 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 (2001 edition) 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. NFPA 59A 

(2001 edition) 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, the refrigerant siting 

requirements from Part 193 and NFPA 59A (2001 edition) would be applicable to the following 

equipment:

 three liquefaction heat exchangers (one per liquefaction train) and associated piping and 

appurtenances;

 two mounded 155,940-gallon ethane storage bullets and associated piping;

 three mounded 260,000-gallon propane storage bullets and associated piping; 
4-175

 two 711,000-gallon stabilized condensate storage tanks and associated piping;

 one 700-gpm propane transfer pump and associated piping and appurtenances; 

 one 160-gpm ethane transfer pump and associated piping and appurtenances;

 two 115-gpm condensate transfer pumps and associated piping;

 nine 139-gpm NGL reinjection pumps (three pumps per liquefaction train) and associated 

piping and appurtenances; 

 nine 94-gpm LPG reinjection pumps (three pumps per liquefaction train) and associated 

piping and appurtenances; 

 six 348-gpm Debutanizer reflux pumps (two pumps per liquefaction train) and associated 

piping and appurtenances; and

 six 424-gpm Deethanizer reflux pumps (two pumps per liquefaction train) and associated 

piping and appurtenances.

4.12.5 LNG Facility Siting 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 consider it prudent design practice to size impoundments based on the greatest flow capacity 

from a single pipe for 10 minutes, 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, where the impoundments should be able to contain the contents 

of the largest process vessel served while smaller design spills may be appropriate for Part 193 

calculations.

4.12.5.1 Impoundment Sizing

Table 4.12.5-1 lists the spill volumes and their corresponding impoundment systems. There are 

four existing sub-impoundment sumps, called Tank Area Impoundment Sump, where each subimpoundment sump is located within one of the four LNG storage tank dikes. Potential spills at the LNG 

storage tank area occurring from the 20-inch-diameter in-tank pump withdrawal header during export 

operation or from the 24-inch-diameter LNG rundown line during liquefying operation would drain 

toward the existing Tank Area Impoundment Sump. The existing Tank Area Impoundment Sump is 

75-feet-long, 75-feet-wide, and 14-feet-deep, with a usable capacity of 550,560 gallons. Each existing 

LNG storage tank would be equipped with three larger LNG in-tank pumps, each rated at 4,625 gpm with 

a maximum runout flow rate of 5,509 gpm. With all three LNG in-tank pumps operating, the maximum 

volume for a 10-minute spill from the LNG in-tank pump withdrawal header would be 165,270 gallons. 
4-176

Any liquid volume remaining in the export piping after the 10-minute spill would be contained within the 

LNG storage tank dike. 

TABLE 4.12.5-1

Impoundment Area Sizing

Source

Spill Size

(gallons) Impoundment System

Impoundment Size

(gallons)

20-inch in-tank pump withdrawal header 162,270 Tank area impoundment sump 550,560

24-inch LNG rundown line (LNG tank area) 250,950 Tank area impoundment sump 550,560

24-inch LNG rundown line (liquefaction area) 250,950 Liquefaction area sump 261,820

18-inch chilled gas 18,750 NGL impoundment 35,900

24-inch LNG rundown line (between liquefaction 

area and LNG storage tank area)

250,950 Rundown line sumps 261,820

6-inch-diameter propane transfer pump 9,830 Refrigerant storage impoundment 73,310

Refrigerant truck 8,000 Refrigerant storage impoundment 73,310

Condensate storage tank 710,990 Condensate containment 852,780

Amine storage tank 144,390 Amine containment 554,300

Mixed amine storage tank 352,510 Amine containment 554,300

Aqueous ammonia tank 25,000 Ammonia containment 78,545

LNG produced from each liquefaction train would combine into a common 24-inch-diameter 

header located south of the liquefaction area. This common 24-inch-diameter header would feed into two 

20-inch-diameter LNG product lines in parallel, which would span about 2,000 feet between the 

liquefaction area and the LNG storage tank area to eventually merge into a 24-inch-diameter header at the 

LNG storage tank area. Any spills from the 24-inch-diameter LNG rundown header at the LNG storage 

tank area would be sloped toward the existing Tank Area Impoundment Sump. The maximum runout 

flow rate of each LNG product pump from the liquefaction area would be 8,365 gpm. With all three 

liquefaction trains operating in parallel, a 10-minute spill volume from the 24-inch-diameter LNG 

rundown line would be 250,950 gallons. These spills would be contained in the existing Tank Area 

Impoundment Sump.

At the liquefaction process area, there would be three liquefaction trains. Each liquefaction train 

would include two insulated concrete impoundment sumps: 1) the Liquefaction Area Sump would be 

located south of the liquefaction train and would contain LNG or refrigerant liquid spills from 

liquefaction facilities; and 2) the NGL Impoundment would be located north of the liquefaction train and 

would serve hydrocarbon liquid spills from the NGL extraction facilities. The Liquefaction Area Sump 

would be 50-feet-long by 50-feet-wide by 20-feet-deep with a usable volume of 261,820 gallons. The 

largest spill into the Liquefaction Area Sump would be from the 24-inch-diameter LNG rundown line 

header south of the liquefaction process area. With three LNG product pumps operating in parallel during 

liquefaction, a 10-minute spill volume from the 24-inch-diameter LNG rundown line would be 

250,950 gallons. This spill would be contained within the Liquefaction Area Sump. The containment 

system in the liquefaction area would be arranged such that any piping inventory remaining after 

10 minutes would continue to flow to the trench and contained within the adjacent Liquefaction Area 

Sump. The NGL Impoundment would be 20-feet-long by 20-feet-wide by 18-feet-deep with a usable 

volume of 35,900 gallons. The largest spill into the NGL Impoundment would be a 10-minute spill 

volume of 18,750 gallons from the 18-inch-diameter chilled gas line to the Demethanizer. Since the NGL 

Impoundment would be over 90-percent larger than the 10-minute spill volume, a spill from the 18-inchdiameter chilled gas line and any piping inventory in this piping segment remaining after 10 minutes 

would be contained within the NGL Impoundment.
4-177

Lake Charles LNG proposes to construct two other insulated concrete impoundment sumps to 

contain any spills along the rundown lines between the liquefaction area and the LNG storage tank area. 

These new sumps would measure 50-feet-long by 50-feet-wide by 20-feet-deep with a usable volume of 

261,820 gallons. As described above, a 10-minute maximum spill volume accounting for the effect of 

pump runout would be 250,950 gallons. This spill would be contained within the Rundown Line Sumps. 

Any piping inventory in this piping segment remaining after 10 minutes would be contained in the trench.

The refrigerant storage area would be located about 700 feet north of the liquefaction area. Lake 

Charles LNG proposes to install three propane storage bullets and two ethane storage bullets. These tanks 

would be mounded to prevent the risk of BLEVE. Lake Charles LNG proposes to install a Refrigerant 

Storage Impoundment with dimensions of 35-feet-long by 35-feet-wide by 14-feet-deep with a usable 

volume of 73,310 gallons, to contain any potential liquid spills during the refrigerant makeup and the 

truck loading/unloading operations. This impoundment sump would also be lined with insulated 

concrete. The largest spill into the Refrigerant Storage Impoundment would from the propane transfer 

pump. Accounting for the effect of pump runout, the 10-minute spill volume from the propane transfer 

pump 6-inch-diameter discharge header would be 9,830 gallons. The Refrigerant Storage Impoundment 

would also contain the entire contents of an 8,000-gallon refrigerant truck.

Lake Charles LNG proposes to install two stabilized condensate product storage tanks, each with 

a maximum volumetric capacity of 710,990 gallons, east of the refrigerant storage area. Each stabilized 

condensate storage tank would have its own secondary diked containment. Containment for a stabilized 

condensate product storage tank would be 190-feet-long by 100-feet-wide by 6-feet-high with a usable 

volume of 852,780 gallons, which would contain the entire contents of a stabilized condensate product 

storage tank.

Lake Charles LNG proposes to install a 144,390-gallon Amine Storage Tank and a 

352,510-gallon Mixed Amine Storage Tank within a 130-foot-long by 95-foot-wide by 6-foot-high diked 

area. The diked area would have a volumetric capacity of 554,300, gallons and would hold the entire 

contents of the Amine Storage Tank and Mixed Amine Storage Tank. Lake Charles LNG would also 

install a 25,000-gallon Aqueous Ammonia Tank within a 50-foot-long by 35-foot-wide by 6-foot-high 

diked area. This diked area would have a volumetric capacity of 78,545 gallons and would hold the entire 

contents of the Aqueous Ammonia Tank. 

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 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 

requirements.11 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-by-case basis to determine compliance 

with Part 193.

 

11 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 PF12-8 on August 

13, 2013. Accession Number 20130813-4009
4-178

In response, Lake Charles LNG provided DOT with its design spill criteria and identified leakage 

scenarios for the proposed equipment. DOT reviewed the data and methodology Lake Charles LNG 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 September 19, 2014, DOT provided a letter to FERC staff stating that DOT had no 

objection to Lake Charles LNG’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.12,13 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 Lake Charles LNG’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, Lake Charles LNG should file with the 

Secretary, for review and approval by the 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 September 19, 2014 (Accession Number 

20140919-4005). In the event that any modifications to the design alters the 

candidate design spills on which the Title 49 CFR Part 193 siting analysis was based, 

Lake Charles LNG should consult with DOT on any actions necessary to comply 

with Part 193.

As design spills vary depending on the hazard (vapor dispersion, overpressure, or radiant heat), 

the specific design spills used for Lake Charles LNG’s Liquefaction siting analyses are discussed under 

“Vapor Dispersion Analysis,” “Overpressure Analysis,” and “Thermal Radiation Analysis.”

4.12.5.3 Vapor Dispersion Analysis

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, 49 CFR §193.2051 

and 193.2059 require 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 

 

12 September 19, 2014 Letter “Re: Trunkline LNG, FERC Docket No. CP14-120-000, Design Spill Determination” from 

Kenneth Lee to Rich McGuire. Filed in Docket Number CP14-120-000 on September 19, 2014. Accession Number 

20140919-4005.

13 PHMSA based this decision on the following documents: (1) Resource Report 11 Reliability and Safety, FERC Docket 

Accession Number 20140325-5137; (2) Modeling Assumption and Hazard Analysis Report, FERC Docket Accession 

Number 20140421-5205; (3) Lake Charles LNG’s Response to FERC Data Request, FERC Docket Accession Number 

20140724-5008; (4) Supplemental Information to the Proceeding Record re PHMSA, FERC Docket Accession Numbers 

20140822-5137 and 20140822-5138; (5) Supplemental Information to the Proceeding Record re PHMSA, FERC Docket 

Accession Numbers 20140917-5153 and 20140917-5154.
4-179

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 49 CFR §193.2059 requires 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 factors to account for model uncertainty (i.e., one-half the LFL of 

other flammable materials and one half the AEGL of toxic materials) and parameters (i.e. F stability, 

2 m/s wind speed, 50-percent relative humidity, average regional temperature, and 0.03m 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 49 CFR 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 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.
4-180

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.

Lake Charles LNG reviewed multiple releases for the liquid scenarios and for the flashing and 

jetting scenarios. Lake Charles LNG used the following conditions, corresponding to 49 CFR §193.2059, 

for the vapor dispersion calculations: ambient temperature of 71.6°F, relative humidity of 50 percent, 

wind speeds of 1 to 2 m/s in various directions, atmospheric stability class of F and a ground surface 

roughness of 0.03 m. 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.

Lake Charles LNG 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

As required by 49 CFR 193, 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.14 With 3 in-tank pumps running in parallel at their 

maximum pump runout, the maximum flow rate from the LNG storage tank withdrawal line would be 

16,527 gpm. FLACS was used to predict the extent of the 1⁄2-LFL vapor cloud from a guillotine rupture 

of the 20-inch-diameter in-tank pump withdrawal header (i.e., liquid scenario). For the jetting and 

flashing scenario from this piping segment, Lake Charles LNG used PHAST to perform a vapor 

dispersion analysis for releases from a 1-inch hole at various elevations along the LNG storage tank 

height. The results showed that the longest 1⁄2-LFL distance would be from a jetting and flashing scenario 

at the base of the LNG storage tank. 

The liquefaction area would be located about 2,000 feet north of the existing LNG storage tank 

area. The LNG rundown lines that deliver LNG product to the LNG storage tanks would be installed 

within the trench system. Lake Charles LNG proposed to install shrouds over the entire length of the 

trenches in order to mitigate the high momentum jetting and flashing releases and induced liquid rainout. 

However, during consultation with the DOT, the DOT determined that the proposed design for a shroud 

over the trench was a covered impoundment which is prohibited in 49 CFR § 193.2167. On January 23, 

2015, Lake Charles LNG filed a revised mitigation design using vacuum insulated piping instead of the 

shroud for the entire LNG rundown piping segment from the LNG product pump discharge to the 

24-inch-diameter rundown header at the LNG storage tank area. The proposed vacuum insulated piping 

design would include an outer piping that would be designed to withstand the mechanical stress and 

thermal environment of an LNG release from the inner piping, and instrumentation would be installed in 

the annular space between the inner piping and the outer piping to monitor any leaks from the inner 

piping. On January 30, 2015, DOT indicated that it has no objection to Lake Charles LNG’s 

methodology for determining single accidental leakage sources with the use of the proposed vacuum

insulated piping design. Lake Charles LNG has established provisions for maintaining the integrity of the 

 

14 Title 49 § 193.2059 incorporates by reference Table 2.2.3.5 of NFPA 59A (2001 edition).
4-181

vacuum insulated piping system in the event of potential mechanical stress and thermal movements which 

would be further developed in the final design phase. Therefore, we recommend that:

 Prior to construction of the final design, Lake Charles LNG should file with the 

Secretary, for review and written approval by the Director of OEP, the details of 

how the vacuum-insulated piping account for mechanical stress and thermal 

movements of the outer piping under cryogenic conditions. This information should 

be filed a minimum of 30 days before approval to proceed is requested.

Lake Charles LNG submitted vapor dispersion analyses for releases from the LNG rundown lines 

impinging on the shroud. It assumed that a release inside the shroud would result in longer vapor 

dispersion than a similar release from the inner piping of the vacuum insulated piping design. Therefore, 

if the vapor dispersion from LNG releases inside the shroud can be maintained within Lake Charles 

LNG’s property, similar LNG releases from the inner piping of the vacuum insulated piping system could 

be assumed to also remain within Lake Charles LNG’s property. We agree with this assumption. Lake 

Charles LNG used ANSYS CFX, a commercially available computational fluid dynamics code, to 

determine the liquid rainout production. The resulting liquid and vapor mass flow rates were used as 

input to FLACS. Lake Charles LNG considered various LNG release locations along the LNG rundown 

lines between the liquefaction area and the LNG storage tank area. These LNG release scenarios would 

be from the 16-inch-diameter LNG product pump discharge header at the liquefaction area, the 20-inchdiameter dual LNG rundown lines between the liquefaction trains and the LNG storage tanks, and the 

24-inch-diameter rundown header at the LNG storage tank area. Table 4.12.5-2 shows LNG release 

scenarios from the LNG storage tank area and liquefaction area.

TABLE 4.12.5-2

LNG Design Spills

Scenario Location Hole Diameter

Pressure

(psig)

Temperature

(°F)

Flow Rate

(lb/hr)

1 In-tank pump header (liquid scenario) 20-inch 98 –257 3.58E6

2 In-tank pump header (jetting and flashing 

scenario)

1-inch 98 –257 5.72E4

3 LNG product pump at liquefaction area 5.3-inch 80 –254 1.44E6

4 Dual LNG rundown lines 6.7-inch 80 –254 2.32E6

5 LNG rundown header at storage tank area 8-inch 60 –244 2.89E6

Lake Charles LNG proposes to install a 20-foot-high vapor barrier along a portion of the east 

property line and a 12-foot-high vapor barrier adjacent to the rundown line, as shown in figure 4.12.5-1, 

to limit the extent of the vapor dispersion zones. 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, Lake Charles LNG should file with the 

Secretary for review and written approval by the Director of OEP the 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.

Lake Charles LNG’s submitted simulations included different release directions, wind speeds, 

and wind directions. Figures 4.12.5-2 to 4.12.5-6 show the PHAST and FLACS results to the longest 

1⁄2-LFL vapor clouds for LNG liquid release scenarios and jetting and flashing scenarios from the LNG 

storage tanks area and liquefaction area.
4-182

Figure 4.12.5-1 – Vapor Fences at Lake Charles LNG’s Facility
4-183

Figure 4.12.5-2 – LNG Release From a Guillotine Rupture of the In-tank Pump Header (1 m/s)

Figure 4.12.5-3 – Jetting and Flashing Scenario From the In-tank Pump Header
4-184

Figure 4.12.5-4 – Release from LNG Product Pump Header at the Liquefaction Area (1 m/s)
4-185

Figure 4.12.5-5 – Release from the LNG Rundown Lines (1 m/s)
4-186

Figure 4.12.5-6 – Release from the LNG Rundown Header at the LNG Storage Tank Area (1 m/s)

The vapor dispersion simulation results shown in figures 4.12.5-2 through 4.12.5-6 indicate the 

1⁄2-LFL vapor clouds for LNG release scenarios would remain within Lake Charles LNG’s property. As 

Lake Charles LNG demonstrated that the vapor dispersion from LNG releases inside the shroud can be 

maintained within its property, similar LNG releases from the inner piping of the vacuum insulated piping 

system would also remain within Lake Charles LNG’s property. Therefore, we conclude that the siting of 

the proposed project would not have a significant impact on public safety with respect to flammable vapor 

dispersion from LNG releases. 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. 

Vapor Dispersion Analyses for Other Hazardous Fluids

In addition to the LNG releases evaluated above, Lake Charles LNG considered other release 

scenarios for the MR, NGL, ethane, propane, and stabilized condensate. Only the spills that produced the 

highest release rates and consequently the longest 1⁄2-LFL vapor clouds are discussed in this section. At 

the liquefaction area, the highest rate of MR release would be from a 1-inch-diameter hole on the MR 

process piping between the propane chillers and the MR separator. Heavy hydrocarbon would be 

extracted from the feed gas stream, and the highest rate of NGL release would be from a 2-inch-diameter 

hole on the piping to the demethanizer. Propane would be used in the liquefaction cycle to pre-cool the 

feed gas and MR vapor. The worst-case scenario for a propane release at the liquefaction process area 

would be a guillotine rupture of the 4-inch-diameter propane process line to the Reclaimer Condenser. 

The refrigerant make-up tanks would be mounded. For process releases outside of the refrigerant 

make-up tanks, a guillotine rupture of the 6-inch-diameter ethane make-up line would result in the highest 

rate of vapor flow. Lake Charles LNG also considered a guillotine rupture of the 4-inch-diameter 

condensate pump discharge piping at the stabilized condensate storage tank area. 
4-187

At the truck unloading area, Lake Charles LNG considered design spills from the guillotine 

rupture of the 3-inch-diameter transfer hoses from the propane and ethane trucks to the propane and 

ethane make-up tanks. Table 4.12.5-3 shows the hole diameters that result in the highest rate of vapor 

flow for refrigerant, NGL, and condensate release scenarios from the liquefaction area, refrigerant storage 

area, condensate storage area, and refrigerant truck loading area.

TABLE 4.12.5-3

Other Hazardous Fluid Design Spills

Scenario Location

Hole

Diameter

Pressure

(psig)

Temperature

(°F)

Flow Rate

(lb/hr)

1 MR to MR separator 1-inch 786 –29 1.42E5

2 NGL to demethanizer 2-inch 573 –123 2.08E5

3 Propane reclaim condenser 4-inch 94 44 5.62E5

4 Ethane make-up line 6-inch 866 47 3.09E4

5 Propane trucking hose 1.3-inch 94 44 1.05E5

6 Ethane trucking hose 3-inch 866 46 7.67E4

7 Condensate pump discharge 4-inch 310 100 3.86E4

Lake Charles LNG used PHAST to predict the distances to the 1⁄2-LFL vapor cloud. 

Table 4.12.5-4 provides the PHAST results for the MRL, NGL and refrigerants jetting and flashing 

scenarios as well as condensate liquid spill scenario. 

TABLE 4.12.5-4

Vapor Dispersion Scenarios from MRL, NGL, Refrigerant, and Condensate Releases

Scenario Material Release Location

Approximate Downwind 

Distance to 1⁄2-LFL (feet)

1 MRL Liquefaction process 355

2 NGL Liquefaction process 450

3 Propane Liquefaction process 735

4 Ethane Refrigerant storage 210

5 Propane Truck unloading 490

6 Ethane Truck unloading 225

7 Condensate Condensate storage 230

As Lake Charles LNG’s calculations show the vapor dispersion would stay within Lake Charles 

LNG’s property, 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.

Since the stabilized condensate would contain benzene, a toxic product, Lake Charles LNG used 

PHAST to calculate the dispersion distances to toxic threshold exposure limit based on the AEGLs. 

Additionally, Lake Charles LNG calculated the AEGLs for other toxic components present in the acid gas 

stream (i.e., hydrogen sulfide) and the NGL extraction process (i.e., toluene and xylene). Lake Charles 

LNG also considered an ammonia release from the aqueous ammonia vessel. Lake Charles LNG used 

PHAST to calculate the dispersion distances to toxic threshold exposure limits based on the toxicity levels 

that were at or below 1⁄2-AEGLs. Table 4.12.5-5 shows the distances to the 1⁄2-AEGLs for releases for 

hydrogen sulfide, benzene, toluene, xylene, and ammonia at the 10-minute exposure time. 
4-188

TABLE 4.12.5-5

Distance (in feet) to the 1⁄2-AEGL 1

Substance

Exposure Time

(minutes)

1⁄2-AEGL 1

(feet)

Ammonia 10 660

Benzene 10 605

Hydrogen Sulfide 10 3,000

Toluene 10 385

Xylene 10 275

The maximum dispersion distance to the 0.375 ppm hydrogen sulfide concentration (i.e., 

1⁄2 AEGL-1 at 10 minutes) was found to extend approximately 3,000 feet. The PHAST modeling did not 

show a hazardous result to the concentration associated with the 1⁄2 AEGL-2 and -3. TLNG stated that 

this toxic vapor cloud would extend over 3 businesses and no homes, schools, hospitals, or parks. The 

businesses within the 1⁄2 AEGL-1 distances include Alcoa, Targa, and Waste Water Plant. TLNG will 

update its Emergency Response Plan to notify all business owners in the event of an emergency that 

involves a hydrogen sulfide release. Additionally, the toxicity effects associated with AEGL-1 are nondisabling and reversible. The distances to the 1⁄2-AEGL-1 for the other substances listed in table 4.12.5-5 

would remain within the facility boundary. As a result, we conclude that the siting of the proposed 

project would not have a significant impact on public safety with respect to the presence of the toxic 

components (i.e., hydrogen sulfide, benzene, toluene, xylene, and ammonia). 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.

4.12.5.4 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. 

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 4.13.2.1, 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 methane-propane. The tests indicated that 

the addition of heavier hydrocarbons influenced the tendency of an unconfined natural gas vapor cloud to 
4-189

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, Lake Charles LNG’s project would be designed to receive feed gas with methane 

concentrations as low as 95 percent, which are not in the range shown to exhibit overpressures and flame 

speeds associated with high-order explosions and detonations. 

Ignition of a confined LNG vapor cloud could result in higher overpressures. In order to prevent 

such an occurrence, Lake Charles LNG would take measures to mitigate the vapor dispersion and ignition 

into confined areas, such as buildings. Buildings would be located away from process 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.

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. 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 confinement.15 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 

refrigerant.

In order to evaluate this hazard, Lake Charles LNG used FLACS to perform an overpressure 

analysis. Lake Charles LNG used the vapor dispersion results, previously discussed in “Vapor Dispersion 

Analysis.” Releases of the 4-inch-diameter propane process line 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. Figures 4.12.5-7 and 4.12.5-8 show the FLACS results of 1 psi overpressures with an

uncertainty factor of 2 (i.e., 1⁄2 psi overpressure) for MR vapor cloud explosions at the liquefaction area. 

 

15 Pierorazio, 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.
4-190

Figure 4.12.5-7 – Propane Overpressure Scenario at Train 1
4-191

Figure 4.12.5-8 – Propane Overpressure Scenario at Train 3

FLACS results indicate that the 1⁄2 psi overpressure distances from the liquefaction area would 

remain within Lake Charles LNG’s property. 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.

4.12.5.5 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, 49 CFR § 193.2057 requires each LNG container and LNG transfer system 

to have a thermal exclusion zone in accordance with Section 2.2.3.2 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
4-192

 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. 

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. Lake Charles LNG selected the following ambient conditions to produce the maximum 

exclusion distances: wind speeds of 0 to 24 mph, ambient temperature of 34°F, and 25 percent relative 

humidity. We agree with Lake Charles LNG’s selection of atmospheric conditions.

As discussed in the EA for the Trunkline LNG Expansion Project (Docket No. CP02-60-000), the 

1,600 BTU/ft2-hr thermal flux from the existing Tank Area Impoundment Sump would remain within 

TLNG property. For the proposed liquefaction project, Lake Charles LNG used LNGFIRE3 to predict 

the thermal radiation distances as a result of fires from the Liquefaction Area Sump, NGL Impoundment, 

Rundown Line Sumps, Refrigerant Storage Impoundment, and Condensate Containment. 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 ethane, propane, NGL, and condensate. Two of the parameters used by LNGFIRE3 

to calculate the thermal radiation flux is 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 ethane, propane, NGL, and 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 ethane, propane, NGL, and condensate fires would not 

extend as far as the exclusion zone distances previously calculated for an LNG fire in the same sump. 

The resulting maximum thermal radiation distances are shown in table 4.12.5-6 and 

figures 4.12.5-9 and 4.12.5-10. The 1,600-Btu/ft2-hr heat fluxes from the proposed impoundment basins 

and secondary containment would remain within the facility property lines. FERC staff also evaluated jet 

fires from various piping and found that the jet fires radiant heat to 1,600 BTU/ft2-hr would not extend 

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 with respect to radiant heat from these impoundments. 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.

TABLE 4.12.5-6

Thermal Radiation Exclusion Zone for Impoundment Basins

Thermal Flux Level (Btu/ft2-hr)

10,000 3,000 1,600

Distance from Liquefaction Area Sump (feet) N/A N/A 281

Distance from NGL Impoundment (feet) N/A N/A 134

Distance from Rundown Line Sump (feet) N/A N/A 281

Distance from Refrigerant Storage Impoundment (feet) N/A N/A 211

Distance from Condensate Containment (feet) N/A N/A 563 (front)

628 (side)
4-193

Figure 4.12.5-9 – Thermal Radiation Zones from the proposed Impoundment Sumps

Figure 4.12.5-10 – Thermal Radiation Zones from the Condensate Containment
4-194

4.12.5.6 Cascading Events

The refrigerant and condensate storage tank area would be located about 700 feet to the north of 

the liquefaction area. The refrigerant storage bullets would be mounded, and the stabilized condensate 

would be stored in floating roof tanks at ambient pressure, which would not allow pressure buildup in the 

event of an adjacent fire. Moreover, Lake Charles LNG proposes to relocate the truck 

loading/unloading area outside of the 3,000 and 10,000 BTU/ft2-hr heat flux levels. Therefore, the 

risk of a BLEVE at the refrigerant and condensate storage tanks would be negligible. We identified 

several process vessels that could be exposed to damaging heat flux due to a fire event from the 

impoundment sumps at the liquefaction area. On November 25, 2014, Lake Charles LNG proposed to 

install mitigation measures for these process vessels including passive protections such as thermal 

insulation and fireproofing as well as active protections such as automatic water spray systems and 

automatic blowdown system. In addition, Lake Charles LNG proposed to install pressure and level 

instrumentation, fire detection, emergency isolation and depressurization valves, passive fire protection, 

fire suppression units, and remotely activated firewater monitors for equipment at the liquefaction area to 

mitigate the potential of a BLEVE from an adjacent jet fire. We believe these mitigation measures would 

prevent the likelihood of a BLEVE occurring at the liquefaction area and recommended in section 4.12.3 

for Lake Charles LNG to provide the final design information for these mitigation measures. As a result, 

we conclude that the siting of the proposed project would not have a significant impact on public safety.

4.12.6 Emergency Response 

Section 3A(e) of the NGA, added by Section 311 of the EPAct, stipulated that in any order 

authorizing an LNG terminal, the Commission shall require the LNG terminal operator to develop an ERP 

in consultation with the Coast Guard and state and local agencies. The ERP has been in place since Lake 

Charles LNG re-commissioned the import of LNG in 1989 and has been updated as new projects have 

changed the configuration of the LNG Terminal. The existing ERP would need to be updated to include 

the proposed liquefaction facilities and emergencies related to refrigerant handling. Therefore, we 

recommend that: 

 Prior to initial site preparation, Lake Charles LNG should file the updated ERP to 

include the Liquefaction Facilities as well as instructions to handle on-site 

refrigerant and NGL-related emergencies. Lake Charles LNG should file the 

updated ERP with the Secretary for review and written approval by the Director of 

OEP.

 Prior to initial site preparation, Lake Charles LNG should file an ERP that includes

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 transit-related security/emergency 

management costs, this comprehensive plan should include funding mechanisms for 

the capital costs associated with any necessary security/emergency management 

equipment and personnel base. Lake Charles LNG should file the ERP, including 

the Cost-Sharing Plan, with the Secretary for review and written approval by the 

Director of OEP.

4.12.7 LNG Vessel Safety 

The Trunkline LNG Terminal received authorization to re-commission the import of LNG in 

November 1989 and has been receiving LNG import shipments. Exporting operations would alter the 

direction of loaded LNG carrier transits, with ships arriving empty but departing with a full cargo. 

However, there would be no changes in the expected number of vessels for the export project. 
4-195

In a letter to the Coast Guard dated February 17, 2012, Lake Charles LNG detailed the proposed 

project modifications and estimated the ship traffic would not exceed the previously approved 225 vessels 

per year in Docket CP02-60-004. In a letter dated March 5, 2012, the Coast Guard stated that a new LOI 

would not be required for the service associated with the proposed project. However, the Coast Guard 

specified that applicable amendments to the Operations Manual, Emergency Manual, and Facility 

Security Plan must be made that capture changes to the operations associated with the project. As 

required by 33 CFR 105 and 127, Lake Charles LNG would amend these documents and submit them to 

the Coast Guard prior to operation of the facility as an export terminal. 

4.12.8 Conclusions on Facility Reliability and Safety

As part of the NEPA review, Commission staff must assess whether the proposed facilities would 

be able to operate safely and securely. As a result of our technical review of the preliminary engineering 

design, 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. Based on our analysis and 

recommended mitigation, we believe that the facility design proposed by Lake Charles LNG includes 

acceptable 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.

As a cooperating agency, DOT assisted FERC staff in evaluating whether Lake Charles LNG’s 

proposed design would meet the DOT siting requirements. DOT reviewed the data and methodology 

Lake Charles LNG used to determine the design spills from various leakage sources, including piping, 

containers, and equipment containing hazardous liquids. Lake Charles LNG used those design spills to 

model hazardous releases. On September 19, 2014, DOT provided a letter to the FERC staff stating that 

DOT had no objection to Lake Charles LNG’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. Based on the hazardous area calculations we reviewed, we 

conclude that potential hazards from the siting of the facility at this location would not have a significant 

impact on public safety. If the 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 49 CFR 193 would be made by DOT staff. 

The Coast Guard has also reviewed the proposed liquefaction facilities and stated that the existing 

waterway suitability assessment and Letter of Recommendation are adequate for the service associated 

with the proposed modifications.

4.12.9 Pipeline Safety Standards

The transportation of natural gas by pipeline involves some risk to the public in the event of an 

accident and subsequent release of 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 a slight inhalation hazard. If breathed in high 

concentration, oxygen deficiency can result in serious injury or death.

Methane has an ignition temperature of 1,000 degrees Fahrenheit and is flammable at 

concentrations between 5 and 15 percent in air. Unconfined mixtures of methane in air are not explosive. 

However, 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.
4-196

The DOT regulates and enforces a regulatory program to provide adequate protection against 

risks to life and property posed by pipeline transportation and pipeline facilities under 49 USC 601. The

Pipeline and Hazardous Materials Safety Administration (PHMSA) Office of Pipeline Safety (OPS)

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 the required safety standard. PHMSA's mission is to protect people and the 

environment from the risks of pipeline incidents. This work is shared with state agency partners and

others at the federal, state, and local level. Section 5(a) of the Natural Gas Pipeline Safety Act provides

for a state agency to assume all aspects of the safety program for intrastate facilities by adopting and

enforcing the federal standards, while section 5(b) permits a state agency that does not qualify under

section 5(a) to perform certain inspection and monitoring functions. The states of Louisiana, Mississippi, 

and Arkansas all have section 5(a) certifications.

DOT pipeline standards are published in 49 CFR 190 to 199. Part 192 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 the FERC’s 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, or

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 other than the DOT standards. If the Commission

becomes aware of an existing or potential safety problem, there is a provision in the Memorandum to

promptly alert t h e DOT. The Memorandum also 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.

Trunkline would design, construct, operate, and maintain the proposed Non-Liquefaction 

Facilities in accordance with the DOT’s Minimum Federal Safety Standards in 49 CFR 192. The 

regulations at 49 CFR 192 are intended to ensure adequate protection for the public and to prevent natural 

gas facility accidents and failures. Part 192 specifies material selection and qualification, minimum 

design requirements, and protection from internal, external, and atmospheric corrosion. Part 192 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 as follows:

 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;
4-197

 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 well-defined outside area occupied 

by 20 or more people during normal use; and

 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. Buried pipelines constructed on land in Class 1 locations must be provided

with a minimum coverage 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. All pipelines installed in navigable

rivers, streams, and harbors must have a minimum cover of 48 inches in normal soil or 24 inches in 

consolidated rock.

Section 192.179 specifies the maximum distance from a point on a pipeline to a 

sectionalizing block valve: each point on a pipeline in a Class 1 location must be within 10.0 miles of a 

block valve, in Class 2 locations the distance is 7.5 miles, and in Class 3 and 4 locations, the distance is 

4.0 and 2.5 miles respectively. 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.

Based on the definitions in 49 CFR 192, both the Mainline Connector, which consists of 

11.4 miles of 42-inch-diameter greenfield pipeline, and the Mainline 200-3 Loop, which consists of 

6.5 miles of 24-inch-diameter loop pipeline would be entirely located within Class 1 areas. Trunkline 

would provide 36 to 48 inches of cover, compared to the DOT-required 30 inches, for the entire length of 

pipelines, unless alternative measures are required on a site-specific basis as identified during easement 

acquisitions and permitting. Additionally, Trunkline would place block valves a maximum of 10 miles 

apart, and would install automatic shut-off valves. During operations, if a subsequent increase in 

population density adjacent to the right-of-way results in a change in class location for the pipeline, 

Trunkline may meet the new class location standard by reducing the operating pressure or by replacing 

the pipeline segment with pipe of sufficient grade and wall thickness to comply with the applicable DOT 

code of regulations for the new class location.

In 2002, Congress passed an act to strengthen the nation’s pipeline safety laws. The 

Pipeline Safety Improvement Act of 2002 (HR 3609) was passed by Congress on November 15, 2002,

and signed into law by the President in December 2002. Since December 17, 2004, gas transmission

operators are required to develop and follow a written integrity management program that contains all the 

elements described in 49 CFR 192.911 and addresses the risks on each covered transmission pipeline 

segment. Specifically, the law requires pipeline operators to establish an integrity management program 

which applies to all high consequence areas (HCA). The DOT (68 FR 69778, 69 FR 18228, and

69 FR 29903) defines HCAs as they relate to the different class zones, potential impact circles, or

areas containing an identified site as defined in 49 CFR 192.903.

The OPS published a series of rules from August 6, 2002, to May 26, 2004, (69 FR 29903) that 

defines HCAs where a gas pipeline accident could do considerable harm to people and their property and

require an integrity management program to minimize the potential for an accident. This definition 

satisfies, in part, the Congressional mandate in 49 USC 60109 for OPS to prescribe standards that 

establish criteria for identifying each gas pipeline facility in a high-density population area.
4-198

The HCA 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 locations where the potential impact radius16 is greater than

660 feet and there are 20 or more buildings intended for human occupancy within the

potential impact circle;17 or

 any area in Class 1 or 2 locations where the potential impact circle includes an 

identified site.

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.

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.

Once a pipeline operator has determined the HCAs on its pipeline, it must apply the elements of 

its integrity management program to those segments of the pipeline within the HCAs. DOT regulations 

specify the requirements for the integrity management plan in 49 CFR 192.911. The pipeline integrity 

management rule for HCAs requires inspection of the entire pipeline in HCAs every 7 years.

Trunkline has determined that there are no HCAs along the proposed pipelines.

Trunkline’s gas control center in Houston, Texas monitors system pressures, flows, and customer 

deliveries. The gas control center is manned 24 a day, 365 days a year. Trunkline also operates a 

district office in Lake Charles and area offices at compressor stations along the proposed pipeline route

where personnel can respond appropriately to emergency situations and direct safety operations as 

necessary. Data acquisition systems are present at all meter stations along Trunkline’s system. If system 

pressures fall outside a predetermined range, an alarm is activated and notice is transmitted to the gas 

control center, indicating that pressures at the station are not within an acceptable range. Trunkline has a 

pipeline construction crew and qualified contractors who are available to respond in the event of an 

emergency, and employs qualified field personnel who can be immediately dispatched to the scene of an 

emergency if the need should arise. 

Trunkline conducts aerial and vehicle patrols of its existing pipeline facilities along with scheduled 

preventative maintenance, and performs annual patrol and leak detection surveys (semi-annual in Class 3 

areas). Similar procedures would be implemented for the proposed Non-Liquefaction Facilities. The leak 

surveys are instrumental in early detection of leaks and can reduce the likelihood of pipeline failure. To 

prevent potential damage from external forces, Trunkline uses pipeline markers and right-of-way mowing 

to keep the pipeline route highly visible. Trunkline is also a member of the “One Call” and related preexcavation notification organizations in Louisiana, which further reduces the potential for damage to the 

 

16 The potential impact radius is calculated as the product of 0.69 and the square root of the MAOP of the pipeline in pounds 

per square inch multiplied by the pipeline diameter in inches.

17 The potential impact circle is a circle of radius equal to the potential impact radius.
4-199

pipeline from third parties. To guard against corrosion, Trunkline would use cathodic protection systems 

on the proposed pipelines.

Safety features that would be installed at the new Compressor Station 203-A include, but are not 

limited to: back-up auxiliary power, fire detection system, gas detection system, emergency block and 

blowdown valves, compressor unit alarm and shutdowns, emergency lighting and exits, safety and 

warning signs, fire extinguishers, and security gate and fence. Additionally, the station would have 

remote and local systems in place to continually monitor station activities, alarms, and shutdowns. 

Station design also includes overpressure protection and line break monitors.

The minimum standards for operating and maintaining pipeline facilities are prescribed in 

49 CFR Part 192, including the requirement to establish a written plan governing these activities. Under

49 CFR 192.615, each pipeline operator must establish an emergency plan that includes written 

procedures to minimize the hazards in a natural gas pipeline emergency. Key elements of the plan 

include procedures for the following: 

 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 shutdown of system and safe restoration of service; and

 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.

Under 49 CFR 192.616, each operator must 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 written continuing public 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. Trunkline’s existing liaison program encompasses the areas crossed by the 

proposed pipelines. Key elements of the liaison program include periodic safety training, special 

informational meetings and trainings at the request of the parishes, and periodic distribution of emergency 

telephone numbers and other pertinent information. Trunkline also uses a Public Awareness Program that 

requires the company to communicate with the affected public, emergency response officials, public 

officials, and excavators/contractors on a regular basis.

Trunkline would provide training to all employees responsible for operation and maintenance of 

the pipelines, compressor station, and meter stations installed or upgraded as part of the proposed project, 

including review of routine and emergency procedures. Employees responsible for future support of the 

facilities would be given hands-on training to familiarize them with new equipment. In addition to inhouse training, equipment vendors would provide training prior to start-up of new facilities.
4-200

We received comments related to traffic and safety impacts of offsite staging areas. During 

construction, special care would be taken to protect the public, and to minimize traffic disruption, and 

control noise and dust to the extent practicable. Trunkline would implement safety measures which 

would include marking the construction work area boundary to ensure construction equipment, materials, 

and spoil would remain within the construction work areas; limiting access to the construction work areas 

to public roadways and designated access roads; welding and installing the pipeline as quickly as 

reasonably possible consistent with pipeline construction practices; and completing final cleanup and 

installation of permanent erosion control measures in a timely manner as required by the FERC Plan and 

Procedures. Prior to the initiation of construction, affected landowners would be informed of the 

schedule for upcoming construction activities and would be provided with a toll free number for questions 

or to report concerns. 

Trunkline would also conduct safety training for construction personnel regarding safe 

construction practices to be implemented when working above, or excavating under, operating pipelines; 

working around electric powerlines or other aboveground or belowground utilities; traffic control; and 

protecting landowners and livestock from construction hazards. 

4.12.9.1 Pipeline Accident Data

Title 49 CFR Part 191 requires all operators of natural gas transmission pipelines to notify the

DOT of any significant incidents and to submit a report within 20 days. Significant incidents are defined 

as any leaks that:

 cause a death or personal injury requiring hospitalization; or

 involve property damage of more than $50,000 in 1984 dollars.18

During the 20-year period from 1994 through 2013, a total of 1,238 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 4.12.8-1 provides the number of each incident by cause and the 

distribution of the causal factors from 1994 to 2013. The dominant causes of pipeline incidents are 

pipeline material, weld or equipment failure and corrosion, collectively constituting 48.5 percent of all 

significant incidents. The pipelines included in the data set in table 4.12.8-1 vary widely in terms of age, 

pipe 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 are time-dependent processes. The use of both an external protective coating and a cathodic 

protection system,19 required on all pipelines installed after July 1971, significantly reduces the corrosion 

rate compared to unprotected or partially protected pipe.

 

18 $50,000 in 1984 dollars is about $115,000 as of January 2014 (Bureau of Labor Statistics, 2013.)

19 Cathodic protection is a technique to reduce corrosion (rust) of the natural gas pipeline that includes the use of an induced

current or a sacrificial anode (like zinc) that corrodes at faster rate to reduce corrosion.
4-201

TABLE 4.12.8-1

Natural Gas Transmission Pipeline Significant Incidents by Cause (1994 to 2013)a

Cause Number of Incidents Percentage of Total Incidentsb

Corrosion 293 23.6

Excavationc211 17.0

Pipeline Material, Weld or Equipment 

Failure

309 24.9

Natural Force Damage 143 11.5

Outside Forcesd75 6.0

Incorrect Operation 34 2.7

All Other Causese173 13.9

TOTAL 1,238 -

____________________

a

From PHMSA (PHMSA, 2014b)

b Due to rounding, column does not total 100 percent.

c

Includes third-party damage.

d

Fire, explosion, vehicle damage, previous damage, intentional damage.

e Miscellaneous causes or unknown causes.

Outside forces, excavation, and natural forces are the cause in 34.5 percent of significant pipeline 

incidents. These mostly 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 4.12.8-2 provides a breakdown of outside 

force incidents by cause.

TABLE 4.12.8-2

Outside Force Incidents by Cause (1994 to 2013)a

Cause Number of Incidents Percent of all Incidentsb

Third-party excavation damage 176 14.2

Operator excavation damage 25 2.0

Unspecified equipment damage/Previous damage 10 0.7

Heavy Rain/Floods 72 5.8

Earth Movement 35 2.8

Lightning/Temperature/High Winds 21 1.6

Unspecified Natural Force 15 1.2

Vehicle (not engaged with excavation) 45 3.6

Fire/Explosion 8 0.6

Previous mechanical damage 6 0.4

Intentional damage 1 0.1

Fishing or maritime activity 7 0.4

Electrical arcing from other equipment/facility 1 0.1

Unspecified outside force 7 0.4

TOTAL 429 -

____________________

a Excavation, outside forces, and natural force damage from table 4.12.8-1.

b Due to rounding, column does not equal 34.5 percent.

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 pipeline systems

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 movements.
4-202

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 (for example, oil

pipelines and cable television) to provide preconstruction information to contractors or other maintenance

workers on the underground location of pipes, cables, and culverts.

4.12.9.2 Impacts on Public Safety

The service incident data summarized in table 4.12.8-1 include pipeline failures of all magnitudes 

with widely varying consequences.

Although the transportation of natural gas via the pipeline involves some degree of risk to the 

public in the event of an accident and subsequent release of gas, it is important to examine the 

probabilistic level of risks for pipeline-related events. According to the PHMSA, there are 2.6 million 

miles of pipelines that cross the United States, and those pipelines offer a safe and cost-efficient way to 

transport natural gas (PHMSA, 2014a). Table 4.12.8-3 presents the average annual injuries and fatalities 

that occurred on natural gas transmission lines between 2009 and 2013. The data has been separated into 

employees and nonemployees to better identify a fatality rate experienced by the general public.

TABLE 4.12.8-3

Annual Average Injuries and Fatalities – Natural Gas Transmission Pipelines (2009 to 2013)a

Year

Injuries Fatalities

Employees Public Employees Public

2009 4 7 0 0

2010b10 51 2 8

2011 1 0 0 0

2012 3 4 0 0

2013 0 2 0 0

____________________

a

From PHMSA (PHMSA, 2014b)

b 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 majority of fatalities from pipelines involve local distribution pipelines. These are natural

gas pipelines that are not regulated by the FERC and 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, often made of plastic or cast iron rather than welded steel, and tend to

be older pipelines that are more susceptible to damage. In addition, distribution systems do not have

large rights-of-way and pipeline markers common to the FERC-regulated natural gas transmission 

pipelines.

The nationwide totals of accidental fatalities from various manmade and natural hazards are listed

in table 4.12.8-4 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. Furthermore,

the fatality rate is more than 25 times lower than the fatalities from natural hazards such as lightning, 

tornados, and floods.
4-203

TABLE 4.12.8-4

Nationwide Accidental Deathsa

Type of Accident Annual Number of Deaths

All accidents 123,706

Motor Vehicle 43,945

Poisoning 29,846

Falls 22,631

Drowning 3,443

Fire, smoke inhalation, burns 3,286

Floodsb89

Lightningb52

Tornadob74

Natural gas distribution linesc14

Natural gas transmission pipelinesc2

____________________

a All data, unless otherwise noted, reflects 2007 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

From PHMSA (PHMSA, 2014b)

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 and 

two fatalities per year (PHMSA, 2014b). 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. As described above, the Lake Charles Liquefaction Project would be constructed and operated

in accordance with DOT requirements; therefore we believe that operation of the Lake Charles 

Liquefaction Project would be safe and would represent only a slight increase in risk to the nearby public.

As discussed in section 4.12.8, the risk associated with the proposed Non-Liquefaction Facilities 

would be small. Although operation of the proposed Non-Liquefaction Facilities would incrementally 

increase the risk of a pipeline accident, the increase would be minor. As a result, the cumulative impact 

and risks associated with constructing or operating the Non-Liquefaction Facilities would be negligible.

4.13 CUMULATIVE IMPACTS

NEPA requires the lead federal agency to consider the potential cumulative impacts of proposals 

under its 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. 

The project-specific impacts of the Lake Charles Liquefaction Project are discussed in detail in 

other sections of this EIS. The purpose of this section is to identify and describe cumulative impacts that 

would potentially result from implementation of the Lake Charles Liquefaction Project. Our analysis of 

cumulative impacts includes other projects in the vicinity of the proposed Lake Charles Liquefaction 

Project that could affect the same resources as the proposed project in the same approximate time frame. 

To ensure that this analysis focuses on relevant projects and potentially significant impacts, the actions 

included in the cumulative impact analysis include projects that:

 impact a resource potentially affected by the proposed Lake Charles Liquefaction Project;
4-204

 impact that resource within all or part of the time span encompassed by the proposed 

construction or operation schedule of the Lake Charles Liquefaction Project; and

 impact that resource within all or part of the same geographical area affected by the Lake 

Charles Liquefaction Project. The geographical area considered varies depending on the 

resource being discussed, which is the general area (region of influence) in which the 

Lake Charles Liquefaction Project could contribute to cumulative impacts on that 

particular resource. 

4.13.1 Projects and Activities Considered

With respect to past actions, Council on Environmental Quality guidance (2005) allows agencies 

to adopt a broad, aggregated approach without “delving into the historical details of individual past 

actions,” an approach we have taken here. The current regional landscape in the Lake Charles area, 

which supports significant industrial and commercial components as well as existing infrastructure, forms 

the environmental baseline described in other sections of this EIS and against which the impacts of 

reasonably foreseeable future actions are considered. Present and recently completed projects are 

generally included with past projects as part of the environmental baseline. Reasonably foreseeable 

projects that might cause cumulative impacts in combination with the Lake Charles Liquefaction Project 

include projects that are under construction, approved, proposed, or planned. For FERC-regulated 

projects, proposed projects are those for which the proponent has submitted a formal application to the 

FERC, and planned projects are projects that are either in pre-filing or have been announced, but have not 

been proposed. Planned projects also include projects not under the FERC’s jurisdiction that have been 

identified through publically available information such as press releases, internet searches, Lake Charles 

LNG’s and Trunkline’s communications with local agencies, and information available from the 

Southwest Louisiana (SWLA) Economic Development Alliance, which monitors proposed development 

activities in southwest Louisiana.

Table 4.13.1-1 lists the projects and activities we considered in this cumulative impact analysis

based on information available at the time this EIS went to print. For each project, the table includes the 

location, a brief description, distance from the Lake Charles Liquefaction Project, status, or timeframe, 

and resources cumulatively affected in conjunction with the Lake Charles Liquefaction Facility. Project 

locations are identified in figure 4.13.1-1. As noted in the following subsections, some projects were 

eliminated from further discussion if it was determined that they would not meet the criteria listed above 

or if sufficient information is not available to allow for a meaningful analysis. Descriptions of potential 

cumulative impacts by resource category are presented in section 4.13.2. Impacts associated with 

maintenance of the existing Trunkline LNG Terminal and Trunkline pipeline facilities and permanent 

rights-of-way near the proposed new and modified pipeline facilities would also contribute to cumulative 

impacts and were considered in this analysis. In cases where quantitative information is not available for 

projects considered in this analysis (e.g. projects in the planning stages, or those contingent on economic 

conditions, availability of financing, or the issuance of permits), the potential impacts of those projects are 

considered qualitatively. 

As discussed in other sections of this EIS, Lake Charles LNG proposes not to restore the ACWs 

that would be used during construction of the liquefaction facility to preconstruction condition after 

construction is complete. In accordance with landowner agreements, these areas would be cleared and 

slightly elevated, making them more suitable for landowners’ future development plans. Although it is 

possible that some or all of these areas may be developed in the future, no specific plans have been 

announced, proposed, or approved. Therefore, potential cumulative impacts associated with possible 

future development of the ACWs cannot be evaluated. 
4-205

TABLE 4.13.1-1

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

INDUSTRIAL DEVELOPMENTS

LNG Export Projects

Sabine Pass LNG Sabine Pass, 

TX

42 Sabine Pass LNG is building a liquefaction 

facility with a send out capacity of 4.16 Bcf/d on 

288 acres of land within its existing Sabine Pass 

LNG Terminal. The project sponsor estimates 

that the facilities will create 356 permanent jobs, 

589 new indirect jobs, and 3,000 construction 

jobs.

Construction in progress with two 

trains scheduled to be in service in 

2016, two trains scheduled to be in 

service in 2017. Application for 

two additional trains filed in 

September 2013 is undergoing 

FERC review. If approved, these 

two trains are scheduled to be in 

service in 2019.

None Anticipated

Golden Pass LNG 

Liquefaction

Jefferson 

County, TX

44 Golden Pass Products LLC and Golden Pass 

Pipeline LLC propose to build a liquefaction 

facility with a send out capacity of 2.6 Bcf/d. 

The facility would be contiguous to and 

integrated with the existing 300-acre Golden 

Pass LNG terminal site, with about 275 

additional acres required, as well as associated 

natural gas pipeline, compression, and other 

related facilities. The project sponsor estimates 

the project would create 45,000 direct and 

indirect construction jobs for 5 years, and 

3,800 direct and indirect operational jobs over 

the life of the project.

FERC application was filed in July 

2014 and is under review. 

Application indicated terminal 

construction start June 2015 (no 

longer possible as project is still 

under FERC review), pipeline 

construction start June 2017. 

Anticipated start-up dates for the 

three proposed liquefaction trains 

in September 2019, March 2020, 

and September 2020. 

None Anticipated

Cameron LNG 

Liquefaction

Cameron 

Parish, LA

5 Cameron LNG is building a liquefaction facility 

with a send out capacity of 1.7 Bcf/d, including 

three liquefaction trains (Trains 1 through 3), 

one additional LNG storage tank (Tank 4), truck 

loading facilities, and other related facilities. The 

liquefaction facility will be located on a 503-acre 

site that is north of and partially within the 

existing Cameron LNG Terminal near 

Hackberry, Louisiana on the Calcasieu Ship 

Channel. In addition, Cameron LNG plans to 

construct two additional liquefaction trains 

(Trains 4 and 5) with a capacity of 4.985 MTPA 

and a fifth 160,000-m3 LNG storage tank (Tank 

5). The project sponsor estimates the project 

will create 135 permanent jobs, and up to 3,900 

construction jobs.

FERC authorized the project in 

June 2014 and issued a Notice to 

Proceed with Site Preparation in 

July 2014. Construction 

commenced in October 2014. 

Anticipated operations for Trains 1, 

2, and 3 in early, mid, and end of 

2018, respectively. On March 2, 

2015, the FERC initiated its prefiling process for Trains 4 and 5, 

with a capacity of 4.985 MTPA, 

and a fifth 160,000-m3 LNG 

storage tank (Tank 5). Trains 4 

and 5 are anticipated to begin 

operation in 2019.

GW, SW, AR, LS, S, 

RT, VT, R, A
4-206

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

Magnolia LNG Project Lake 

Charles, LA

(Calcasieu 

Parish)

<1 Magnolia proposes to build a liquefaction facility 

with a send out capacity of 1.08 Bcf/d. The 

facility would be located on approximately 

115-acre tract of land adjacent to the Industrial 

Canal, off the Calcasieu Ship Channel. The 

project would create approximately 

67 permanent jobs and a peak construction 

workforce of approximately 542 workers.

FERC application was filed in April 

2014. Scheduled in-service dates 

for the four proposed liquefaction 

trains, assuming receipt of 

regulatory approvals, are 

December 2018 for the first 

liquefaction train, with the 

remaining three liquefaction trains 

being commissioned at 3-month 

intervals thereafter.

GW, SW, W, VW, AR, 

LS, S, RT, VT, LU, R, 

A, N

Venture Global 

Calcasieu Pass 

Project

Cameron 

Parish, LA

23 Venture Global plans to develop an LNG export 

facility with a send out capacity of 1.34 Bcf/d. 

The facility would be located on a 203-acre site 

adjacent to the Calcasieu Ship Channel. The 

facility would use single mixed refrigerant blocks 

capable of producing a total of 10 million metric 

tons per annum of LNG. The project would 

include two marine berths and two LNG storage 

tanks, as well as two natural gas lateral

pipelines, 19 miles long and 24 miles long. The 

project sponsor estimates that the project would 

create 625 construction jobs and 175 indirect 

jobs during construction, and about 93 full-time 

jobs during operation. 

FERC initiated its pre-filing process

on October 10, 2014. Anticipated 

construction start in October 2016 

to meet December 2019 in-service 

date.

None Anticipated

Live Oak LNG Project Lake 

Charles, LA

(Calcasieu 

Parish)

2 Live Oak has announced plans to develop a 

liquefaction and LNG export facility with a send 

out capacity of 0.68 Bcf/d. The facility would be 

located on a 200-acre site on the western 

shoreline of the Calcasieu Ship Channel and 

would include two LNG storage tanks, a marine 

berth, LNG truck loading facilities, electric power 

generation facilities, a compressor station, and 

two header pipelines connecting the facility to 

existing natural gas pipeline system 

infrastructure. The project sponsor estimates 

that the project would create 250 construction 

jobs and 75 full-time jobs during operation. 

Live Oak has announced intent to 

begin operation in 2019; however, 

Live Oak has not yet requested to 

initiate the FERC’s pre-filing 

process. 

GW, SW, W, VW, AR, 

LS, S, RT, VT, LU, R, 

A, N 
4-207

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

G2 LNG Project Cameron 

Parish, LA

20 G2 LNG has announced plans to develop a 

liquefaction and LNG export facility with a send 

out capacity of 3.8 Bcf/d. The facility would be 

located on a 500-acre site on the Calcasieu Ship 

Channel. Only limited public information is 

currently available for the G2 LNG Project. As 

such, it is considered tentative at this stage.

G2 LNG has not requested to 

initiate the FERC’s pre-filing 

process. If authorized, G2 LNG 

intends to begin operation in 2019.

None Anticipated

Gasfin LNG Export 

Project

Cameron 

Parish, LA

23 Gasfin plans to construct, own, and operate an 

LNG liquefaction and export facility with a send 

out capacity of 0.2 Bcf/d. The facility would be 

located on a 35-acre site along the Calcasieu 

River. Only limited public information is 

currently available for the Gasfin LNG Project. 

As such, it is considered tentative at this stage.

Gasfin has not requested to initiate 

the FERC’s pre-filing process, and 

has not announced a schedule.

None Anticipated

Port Arthur 

Liquefaction Project

Jefferson 

County, TX

45 Port Arthur LNG, LLC and Port Arthur Pipeline, 

LLC (collectively, Port Arthur) have announced 

plans to develop a liquefaction and LNG export 

facility with a send out capacity of 1.4 Bcf/d. 

The facility would be located on a portion of 

Sempra’s 2,900-acre site on the Sabine-Neches 

and Gulf Intracoastal Waterways and would 

include two liquefaction trains, two LNG storage 

tanks, two marine berths, LNG truck loading 

facilities, and natural gas liquids and refrigerant 

storage facilities. In order to supply natural gas 

for the facility, the project would also include two 

natural gas pipelines, two compressor stations, 

metering stations, and appurtenant facilities. 

The project sponsor estimates that the project 

would create 3,000 construction jobs and 

200 full-time jobs during operation. 

Port Arthur entered the FERC’s 

pre-filing process on March 31, 

2015. Anticipated construction 

start in 2017 to begin operation in 

2021.

None Anticipated

WesPac LNG Project Jefferson 

County, TX

45 WesPac has announced plans to develop a 

liquefaction and LNG export facility with a send 

out capacity of 0.2 Bcf/d. The facility would be 

located on a 40-acre site on the Sabine-Neches 

Waterway. Only limited public information is 

currently available for the WesPac LNG Project. 

As such, it is considered tentative at this stage.

WesPac has not requested to 

initiate the FERC’s pre-filing 

process, and has not announced a 

schedule.

None Anticipated
4-208

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

Waller Point LNG Cameron 

Parish, LA

22 Waller LNG has announced plans to develop a 

liquefaction facility with a send out capacity of 

0.16 Bcf/d. The facility would be located on a 

180-acre site. The project sponsor estimates 

the project would create 100 to 200 permanent 

jobs and 250 to 350 construction jobs. Only 

limited public information is currently available 

for the Waller LNG project. As such, it is 

considered tentative at this stage.

Waller LNG has not requested to 

initiate the FERC’s pre-filing 

process and has not announced a 

schedule.

None Anticipated

SCT&E LNG Cameron 

Parish, LA

22 SCT&E LNG has announced plans to develop a 

liquefaction facility with a send out capacity of 

1.6 Bcf/d. The facility would be located on a 

246-acre site on Monkey Island near the 

Calcasieu River and the Calcasieu 

Pass/Cameron Loop. SCT&E LNG plans for six 

liquefaction trains, each capable of producing up 

to 2 million tons of LNG per year.

SCT&E LNG has not requested to 

initiate the FERC’s pre-filing 

process and has not announced a 

schedule.

None Anticipated

Pipeline System Projects

Kinder Morgan

Louisiana Pipeline 

LLC (KMLP) Lake 

Charles Expansion 

Project

Acadia, 

Calcasieu, 

and 

Evangeline 

Parishes, LA

<1 KMLP proposes to construct a new greenfield 

compressor station consisting of four 16,000 hp 

gas-fired turbine units near Eunice, LA, as well 

as one new meter station and two header 

pipelines, and modify six existing meter stations 

to provide a connection to a new delivery point 

at the proposed Magnolia LNG Terminal. 

FERC application was filed June 

2014. KMLP anticipates beginning 

construction in January 2017 to 

meet a January 2018 in-service 

date.

GW, S, RT, A

Cameron Interstate 

Pipeline, LLC 

(Cameron Interstate) 

– Cameron Pipeline 

Expansion

Cameron 

and 

Beauregard 

Parishes, 

Louisiana

14 Cameron Interstate will construct and operate 

about 21 miles of new 42-inch-diameter pipeline 

to enable bi-directional flow on its existing 

pipeline system, as well as a new 56,820 hp 

compressor station and interconnection facilities.

FERC granted Notice to Proceed 

with construction on October 31, 

2014. Construction started in late 

2014 with an anticipated 2017 inservice date.

GW, S, RT, A

Columbia Gulf 

Transmission, 

LLC/Cameron Access 

Project

Jefferson 

Davis, 

Calcasieu, 

and 

Cameron 

Parishes, LA

3 Columbia Gas Transmission plans to construct 

about 27 miles of greenfield pipeline, about 

7 miles of loop pipeline, and a greenfield 

compressor station.

FERC application was filed March 

2014, applicant anticipates starting 

construction in September 2016 

and a December 2017 in-service 

date.

GW, S, RT, A
4-209

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

Other Industrial Facilities

G2X Energy, Inc. /Big 

Lake Fuels LLC

Lake 

Charles, LA

(Calcasieu 

Parish)

<1 G2X proposes to build a natural gas-to-gasoline 

plant on 200 acres of land along the Industrial 

Canal at the Port of Lake Charles. The 

company estimates the project would create 243 

new direct jobs and 748 new indirect jobs.

Air permits to construct and 

operate the facility were received 

in May 2014. Construction 

anticipated to begin in 2015. The 

facility is anticipated to be in 

operation in 2017.

GW, SW, W, VW, AR, 

LS, S, RT, VT, LU, R, 

A, N

IFG Port Holdings Lake 

Charles, LA

(Calcasieu 

Parish)

7 IFG is dismantling its existing facility and 

building a new export grain terminal. The 

project is expected to create 36 new direct jobs, 

and 20 indirect jobs will be created along with 

200 temporary construction jobs. 

Under construction. Anticipated to 

be completed in 2015.

VT, RT

Juniper GTL, LLC Westlake,

Calcasieu 

Parish, 

Louisiana

8 Juniper GTL, LLC plans to convert a dormant 

steam methane reformer to a natural gas-toliquids facility. The project is estimated to create 

125 construction jobs, 29 new direct jobs, and 

112 new indirect jobs

Under construction. Anticipated 

completion in November 2015.

GW, S, RT, A

Liberty Gas Storage 

Expansion Project

Calcasieu 

and

Cameron 

Parishes, LA

5 Liberty Natural Gas, LLC (Liberty) is 

constructing one new compressor station, one 

new salt dome natural gas storage cavern, and 

several support facilities. In addition, Liberty is 

converting three existing salt dome brine storage 

caverns to natural gas storage caverns. The 

project is expected to create 630 construction 

jobs and 3 new direct jobs.

Under construction. Expected to 

begin operation in 2017.

GW, S, RT, A

Sasol North America, 

Inc.

Westlake, LA

(Calcasieu 

Parish)

9 Sasol proposes to build an ethane cracker 

complex in Westlake, LA. This new facility is 

expected to create 500 direct jobs. 

Subject to regulatory approvals, 

the new ethane cracker is 

scheduled to be completed and 

operational by 2018. 

GW, S, RT, A

Westlake Chemical 

Corporation

Lake 

Charles, LA

(Calcasieu 

Parish)

5 Westlake Chemical Corporation plans to expand 

the capacity of its Petro 1 ethylene unit at the 

existing Lake Charles facility. Very limited 

information is publicly available at this time.

Late 2015 or early 2016 timeframe. GW, S, RT, A

Utilities and Transportation

Cove Lane 

Interchange Project

Cameron 

and 

Calcasieu 

Parishes, LA

5 The DOTD is constructing a three-phase road 

improvement project.

Under construction; anticipated to 

be completed in 2015.

None Anticipated
4-210

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

Entergy 230 kV 

Electrical 

Transmission Line

Cameron 

and 

Calcasieu 

Parishes, LA

5 Entergy planning 12-mile-long electrical 

transmission line to provide power to the 

Cameron LNG Liquefaction Project.

To be constructed concurrently 

with Cameron LNG Liquefaction 

Project.

S, RT, R, A

Entergy Electrical 

Transmission Line 

and Substation

Calcasieu 

and 

Beauregard 

Parishes, LA

0 Entergy plans to construct a 19-mile-long 230 kV 

electric transmission line and a new substation 

to provide incremental power for the proposed 

Lake Charles LNG’s liquefaction facility.

Timing dependent on approval of 

Lake Charles Liquefaction Project.

W, VW, S, RT, LU, R, 

A, N

Entergy Electric 

Transmission Line 

and Substation

Calcasieu 

Parish, LA

0 Entergy plans to construct a 1.3-mile-long, 230 

kV electric transmission line from the existing 

Graywood substation to a new switching station 

to provide power for the Magnolia LNG Project.

Timing dependent on approval of 

Magnolia LNG and Lake Charles 

Expansion Projects.

W, VW, S, RT, LU, R, 

A, N

Cleco Electric 

Transmission Line

Acadia 

Parish, LA

<1 Cleco plans to construct a 0.3-mile-long, 34.5 kV 

electric transmission line from its existing 

distribution line to provide power for the Lake 

Charles Expansion Project.

Timing dependent on approval of 

Magnolia LNG and Lake Charles 

Expansion Projects.

GS, W, VW, S, RT, LU, 

A, N

Calcasieu Parish 

District 12 Water 

Works Tie-in

Calcasieu 

Parish, LA

<1 Calcasieu Parish District 12 Water Works would 

install an interconnect with its existing 12-inchdiameter water pipeline to provide potable water 

for the Magnolia LNG Project.

Timing dependent on approval of 

Magnolia LNG and KMLP Lake 

Charles Expansion Projects.

GS, GW, VW, S, RT, 

LU, R, A, N

COMMERCIAL DEVELOPMENTS

Golden Nugget

Casino 

Lake 

Charles, LA

(Calcasieu 

Parish)

6 The 740-room Golden Nugget Casino and resort 

was constructed on 242 acres of land owned by 

Lake Charles Harbor and Terminal District. The 

project will provide 1,500 permanent jobs. 

Opened for business in December 

2014.

GW, SWAR, S, RT A

Chennault 

International Airport 

Lake 

Charles, LA

(Calcasieu 

Parish)

11 Chennault International Airport recently 

expanded the airport facilities to include the 

addition of a 112,000- to 115,000-square-foot 

maintenance and repair hanger. It is estimated 

that this hanger will provide 500 jobs.

Construction completed in October 

2014.

GW, S, RT, A

Northrop Grumman Lake 

Charles, LA

(Calcasieu 

Parish)

11 Northrop Grumman is adding a 25,000-squarefoot multi-purpose building at the Chennault 

International Airport that will result in additional 

employment.

Construction completed. GW, S, RT, A
4-211

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

Port of Lake Charles Lake 

Charles, LA

(Calcasieu 

Parish)

6 Project to improve the railroads to handle traffic 

associated with transit between the Chennault 

International Airport and City Docks. Two more 

docks will also be added to Bulk Terminal 1. 

Anticipate 60 to 80 jobs to accommodate growth 

and 150 permanent operational jobs. 

Railroad improvements completed. 

Dock schedule unavailable.

S, RT

Sowela Training 

Facility 

Lake 

Charles, LA

(Calcasieu 

Parish)

10 The State of Louisiana has invested $20 million 

for a training center at SOWELA Technical 

Community College to support the construction 

for Sasol Ltd.

Complete and in operation. None Anticipated

GOVERNMENT FACILITIES/ACTIVITIES

COE Maintenance 

Dredging of Calcasieu 

River 

Cameron 

and 

Calcasieu 

Parishes, LA

2 The COE conducts periodic dredging along the 

68-mile Calcasieu River and navigation channel.

Dredging is ongoing on a bi-annual 

basis in the project area.

GS, SW, AR, LS, VT, 

R, A, N

Louisiana Marine 

Fisheries 

Enhancement, 

Research, and 

Science Center

Lake 

Charles,

Calcasieu 

Parish, 

Louisiana

1 A new marine fisheries research center would 

be constructed on about 12 acres within a larger 

property. Construction would require about 30 

people. Facility would be operated by 8 

permanent staff.

In permitting. Final design and 

permitting would require about 18 

months once funding is procured. 

Construction anticipated to begin in 

2016 with the facility entering 

operation between 2020 and 2021. 

GS, GW, SW, W, VW, 

AR, S, RT, LU, R, A, N

RESIDENTIAL DEVELOPMENTS

Graywood Lake 

Charles,

Calcasieu 

Parish, 

Louisiana

2 Planned community consisting of five 

neighborhoods and sports facilities.

Under construction GW, S, RT, A

Belle Savanne Sulphur,

Calcasieu 

Parish, 

Louisiana

7 Mixed residential and commercial development, 

initially on 27 acres, to expand to about 300 

acres.

Under construction GW, S, RT, A

Pelican Lodge 

Workforce Housing

Lake 

Charles,

Calcasieu 

Parish, 

Louisiana

11 New industrial employee temporary housing 

facility on 200 acres of Port of Lake Charles 

property. Anticipate 400 construction jobs. This 

facility will accommodate 4,000 workers.

Under construction. Anticipated to 

be completed in mid-2015. 

GW, S, RT, A
4-212

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Activities and Projects Considered in the Cumulative Impact Analysisa

for the Lake Charles Liquefaction Project

Activity/Project Location

Distance from 

Project (miles) Description Timeframe

Resources

Cumulatively Affectedb

Walnut Grove 

Development

Lake 

Charles,

Calcasieu 

Parish, 

Louisiana

8 Mixed residential and commercial development Construction 2010 to 2019

Operation 2012 to 2019

GW, S, RT, A

Moss Lake Worker 

Village

Carlyss, 

Calcasieu 

Parish, 

Louisiana

5 Temporary housing project by First Flight 

Holdings, LLC on 100 acres of land on the 

Southland Field West Calcasieu Airport 

Property. The facility is intended to provide 

temporary housing for up to 2,500 workers

Under construction GW, S, RT, A

Audubon Trace Moss Bluff, 

Calcasieu 

Parish, 

Louisiana

15 miles New residential development on about 

200 acres of land.

Construction 2015

Operation unknown

GW, S, RT, A

_____________________

a

This table lists those projects that are most likely to contribute to the cumulative impacts within the vicinity of the proposed Lake Charles Liquefaction Project; it is not 

intended to provide an all-inclusive listing of projects in the region.

b A – Air

AR – Aquatic Resources

GS – Geology and Soils

GW – Groundwater

LS – Listed Species

LU – Land Use

N – Noise

R – Recreation

RT – Road Traffic

S – Socioeconomics

SW – Surface Water

VW – Vegetation and Wildlife

VT – Vessel Traffic

W – Wetlands
4-213

[Insert figure 4.13.1-1 Lake Charles Area Projects]
4-214

[Insert figure 4.13.1-1 pg 2 Project Locations]
4-215

4.13.1.1 LNG Liquefaction and Export Projects

We identified several liquefaction and export projects that are proposed, planned, or under 

construction in the vicinity of the proposed Lake Charles Liquefaction Project that have the potential to 

contribute to cumulative impacts when combined with the Lake Charles Liquefaction Project (see 

figure 4.13.1-1). In addition to the proposed Lake Charles Liquefaction Project, new liquefaction and 

export projects are proposed or underway at three other existing LNG terminals including the Sabine 

Pass, Golden Pass, and Cameron LNG terminals. The Sabine Pass and Cameron LNG liquefaction 

facilities are currently under construction, and the Golden Pass LNG Project is undergoing the FERC’s 

environmental review. Three stand-alone liquefaction projects considered include the Magnolia LNG 

Project, which is undergoing the FERC’s environmental review, and the Venture Global Calcasieu Pass 

and Port Arthur Liquefaction Projects, which are in the FERC’s pre-filing process. Other planned 

liquefaction and export facilities in the general project area include the G2, Gasfin, Live Oak, Waller 

Point, WesPac, and SCT&E liquefaction projects, which have been announced but have yet not initiated 

the FERC’s pre-filing process. Brief descriptions of each of the liquefaction and export projects are 

provided below. This cumulative impacts analysis considers the impacts of the potential construction and 

operation of the planned or proposed liquefaction and export projects.

Sabine Pass LNG Terminal and Liquefaction Project

The Sabine Pass LNG Terminal is in Cameron Parish, about 42 miles southwest of the proposed 

Lake Charles Liquefaction Project. The Sabine Pass Liquefaction Project was authorized by the 

Commission in April 201220 and is currently under construction adjacent to the Sabine Pass LNG 

Terminal. The project will include four liquefaction trains (Trains 1 through 4) that are expected to be 

placed into service in phases. The first liquefaction train is expected to begin service in late 2015; the 

remaining three liquefaction trains will be placed into service on a 6- to 9-month staggered basis 

thereafter. In September 2013, Sabine Pass filed an application to construct two additional liquefaction 

trains, Trains 5 and 6.

21

 On December 12, 2014, the Commission issued an Environmental Assessment 

concluding that the approval of the project would not constitute a major federal action significantly 

affecting the quality of the human environment. If approved by the Commission, construction of Trains 5 

and 6 could begin in 2015, with an anticipated in-service date of December 2019. Due to the distance of 

Sabine Pass LNG Terminal and Liquefaction Project from the proposed project, we do not believe it 

would contribute to the cumulative effects on any resources in the Lake Charles Liquefaction Project area, 

including air quality impacts as discussed in section 4.13.2.11.

Golden Pass LNG Terminal and Liquefaction Project

The Golden Pass LNG Terminal is in Jefferson County, Texas, about 44 miles southwest of the 

proposed Lake Charles Liquefaction Project (Golden Pass Products, LLC, 2014). Golden Pass Products, 

LLC filed its application with the FERC on July 7, 201422 to construct its Golden Pass Terminal 

Expansion Project for liquefaction of LNG at a facility contiguous to and integrated with the existing 

Golden Pass LNG terminal. The project would also include about 2.5 miles of natural gas pipeline, 

additional compression, and associated facility modifications. Due to the distance of this facility from the 

proposed Lake Charles Liquefaction Project, we do not believe the Golden Pass LNG terminal or the 

associated liquefaction project would contribute to the cumulative effects on any resources in the Lake 

Charles Liquefaction Project area, including air quality impacts as discussed in section 4.13.2.11.

 

20 Docket No. CP11-72.

21 Docket No. CP13-552

22 Docket Nos. CP14-517 and CP14-518
4-216

Cameron LNG Terminal and Liquefaction Project and Pipeline Expansion

The Cameron Liquefaction Project,

23 which was approved by the Commission in June 2014, will 

be located about 5 miles southwest of the Lake Charles Liquefaction Project within and immediately 

adjacent to the existing Cameron LNG Terminal in Cameron and Calcasieu Parishes, Louisiana (see 

figure 4.13.1-1) (FERC, 2014c). The project will include the construction and operation of three new 

liquefaction trains (about 5 MTPA for each train) scheduled to be completed in July 2017 (Train 1), 

January 2018 (Train 2), and July 2018 (Train 3). Also as part of this project, Cameron Interstate Pipeline, 

LLC will construct and operate 20.9 miles of new 42-inch-diameter natural gas pipeline, a new 56,280 hp 

compressor station, and appurtenant facilities in Cameron, Calcasieu, and Beauregard Parishes. Due to 

the potential overlapping construction schedules and proximity to the Lake Charles Liquefaction Project, 

the construction and/or operation of Cameron Liquefaction Project have the potential to contribute to the 

cumulative impacts on resources in the Lake Charles Liquefaction Project area. 

Magnolia LNG Project, KMLP Lake Charles Expansion Project

Magnolia filed an application with the FERC on April 30, 2014 for a stand-alone liquefaction and 

export facility in Calcasieu Parish, Louisiana less than 1 mile from the Lake Charles Liquefaction Project. 

The Magnolia LNG facility would be located west-southwest of the existing Trunkline LNG Terminal on 

the opposite (south) shore of the Industrial Canal off the Calcasieu Ship Channel (see figure 4.13.1-1). 

Magnolia’s application is currently under review by the FERC.24 If approved, Magnolia proposes to 

begin construction of four liquefaction trains (2 MTPA for each train) in 2015 and start commercial 

operation of the trains in a staggered fashion from the end of December 2018 through 2019. In an 

associated filing,

25 KMLP proposes to construct new natural gas header pipelines, modify certain existing 

meter stations, and construct one new meter station and one new compressor station, to connect the 

proposed Magnolia LNG terminal to its existing pipeline system. Construction and operation of the 

Magnolia LNG and Lake Charles Expansion Projects would contribute to the cumulative impacts on 

resources in the Lake Charles Liquefaction Project area. 

Venture Global Calcasieu Pass Project

Venture Global announced plans for a stand-alone LNG export terminal in Cameron Parish and 

has received DOE authorization for export to FTA countries (DOE, 2013b). Applications to increase 

export volumes and to export to non-FTA countries are pending before the DOE. The Venture Global 

Calcasieu Pass Project would be constructed about 23 miles south of the Lake Charles Liquefaction 

Project on the east side of the Calcasieu Ship Channel near the Gulf of Mexico (see figure 4.13.1-1). The 

Commission approved Venture Global’s request to begin the pre-filing process on October 10, 2014.

26

 

Subject to the receipt of the necessary approvals, Venture Global plans to begin construction of the 

project in October 2016 to meet a December 2019 in-service date. Due to the location of this project, we 

do not believe construction and operation of the Venture Global Calcasieu Pass Project would contribute 

to cumulative impacts on resources in the Lake Charles Liquefaction Project area; therefore, we have not 

considered Venture Global Calcasieu Pass Project in this analysis.

 

23 Docket No. CP13-25

24 Docket No. CP14-347

25 Docket No. CP14-511

26 PF15-2-000
4-217

G2 LNG Project

G2 LNG plans to develop a stand-alone liquefaction and LNG export terminal on the Calcasieu 

Ship Channel in Cameron Parish, Louisiana, approximately 20 miles south of the Lake Charles 

Liquefaction Project (see figure 4.13.1-1). The project is in the initial development phase; G2 LNG has 

not submitted a request to enter the Commission’s pre-filing process, but has stated that, if authorized, the 

G2 LNG Project is expected to begin operation in 2019. Due to the location of this project, we do not 

believe construction and operation of the G2 LNG Project would contribute to cumulative impacts on 

resources in the Lake Charles Liquefaction Project area; therefore, we have not considered the G2 LNG

Project in this analysis.

Gasfin LNG Export Project

Gasfin announced plans for a stand-alone liquefaction and export project in Cameron Parish. The 

Gasfin LNG Export Project would be constructed about 23 miles south of the Lake Charles Liquefaction 

Project, on the east side of the Calcasieu Ship Channel (see figure 4.13.1-1). Gasfin has received DOE 

authorization for export to FTA countries, and has an application pending before the DOE for 

authorization to export to non-FTA countries (DOE, 2013a). The project is in the initial development 

phase and Gasfin has not requested initiation of the Commission’s pre-filing process, nor released an 

anticipated schedule. Because the schedule and potential effects of the Gasfin LNG Project are unknown, 

it has not been included in this cumulative impact analysis.

Live Oak LNG Project

Live Oak has announced plans for a liquefaction and LNG export facility on the west side of the 

Calcasieu Ship Channel in Calcasieu Parish, Louisiana, approximately 2 miles west of the Lake Charles 

Liquefaction Project (see figure 4.13.1-1). The project is in the initial development phase; Live Oak has 

not submitted a request to enter the Commission’s pre-filing process, but has stated that, if authorized, the 

Live Oak LNG Project is expected to begin operation at the end of 2019. Construction and operation of 

the Live Oak LNG Project could contribute to the cumulative impacts on resources in the Lake Charles 

Liquefaction Project area. However, because the schedule and potential effects of the Live Oak LNG 

Project are unknown, it has not been included in this cumulative impact analysis, 

Port Arthur Liquefaction Project

Port Arthur has announced plans for a liquefaction and LNG export facility on the west side of 

the Sabine-Neches Waterway near Port Arthur, Texas. The facility would be approximately 45 miles 

southwest of the Lake Charles Liquefaction Project (see figure 4.13.1-1). The Commission approved Port 

Arthur’s request to begin the pre-filing process for the Port Arthur Liquefaction Project in March 2015. 

Subject to the receipt of the necessary approvals, Port Arthur plans to begin construction of the project in 

2017 and would begin operation in 2021. Due to the location of this project, we do not believe 

construction and operation of the Port Arthur Liquefaction Project would contribute to cumulative 

impacts on resources in the Lake Charles Liquefaction Project area; therefore, we have not considered the 

Port Arthur Liquefaction Project in this analysis.

Waller Point Liquefaction Project

Waller Point LNG announced plans for a stand-alone LNG export terminal in Cameron Parish. 

The Waller Point LNG Project would be constructed about 22 miles south of the Lake Charles 

Liquefaction Project on the western shore of the entrance to the Calcasieu Ship Channel (see figure 

4.13.1-1). The project is in the initial development phase. Waller Point LNG has not submitted a request 
4-218

to enter the Commission’s pre-filing process and a schedule has not been announced. Because the 

schedule and potential effects of this project are as yet unknown, it has not been included in this 

cumulative impact analysis.

WesPac LNG Project

WesPac announced plans for a liquefaction and LNG export terminal on the Sabine-Neches 

Waterway near Port Arthur, Texas, approximately 45 miles south of the Lake Charles Liquefaction 

Project (see figure 4.13-1). The project is in the initial development phase and WesPac has not submitted 

a request to enter the Commission’s pre-filing process nor has it released an anticipated schedule. 

Because the schedule and potential effects of this project are as yet unknown, it has not been included in 

our cumulative impacts analysis.

Southern California Telephone & Energy Liquefaction Project

SCT&E LNG announced plans for a stand-alone LNG export terminal in Cameron Parish. The 

SCT&E LNG Project would be constructed about 22 miles south of the Lake Charles Liquefaction Project 

on Monkey Island near the eastern shore of the entrance to the Calcasieu Ship Channel (see figure 4.13.1-

1). The project is in the initial development phase. SCT&E LNG submitted applications to the DOE to 

export to FTA and non-FTA countries in July 2014, but has not submitted a request to enter the 

Commission’s pre-filing process or released an anticipated schedule. Because the schedule and potential 

effects of this project are as yet unknown, it has not been included in this cumulative impact analysis.

4.13.1.2 Pipeline System Projects

The KMLP Lake Charles Expansion Project and the Cameron Interstate Pipeline, LLC pipeline 

expansion are discussed above in conjunction with the Magnolia LNG Project and the Cameron LNG 

Liquefaction Project, respectively. 

Cameron Access Project

Columbia Gulf Transmission, LLC (Columbia Gulf) has initiated the FERC’s pre-filing process 

for a project that would involve the construction of about 27 miles of 36-inch-diameter greenfield 

pipeline, about 7 miles of 30-inch-diameter loop pipeline, and a new 12,260-hp compressor station in 

Cameron, Calcasieu, and Jefferson Davis Parishes.27 At its closest point, the pipeline would be located 

about 3 miles south of the Lake Charles Liquefaction Facility. Columbia Gulf filed its application with 

the Commission in March 2015 and is requesting that the Commission provide a decision in time to allow 

for a September 2016 construction start and a December 2017 in-service date. Construction and operation 

of the Cameron Access Project has the potential to contribute to cumulative impacts on resources in the

Lake Charles Liquefaction Project area.

4.13.1.3 Other Industrial Facilities

G2X Energy Natural Gas-to-Gasoline Plant

G2X Energy’s subsidiary, Big Lake Fuels LLC, plans to construct a natural gas-to-gasoline plant 

along the Industrial Canal of the Port of Lake Charles on a 200-acre site owned by the Lake Charles 

Harbor and Terminal District less than 1 mile west of the Lake Charles Liquefaction Project. The facility 

would convert domestic natural gas into about 12,500 barrels per day of sulfur, gasoline, and/or methanol. 

 

27 FERC Docket No. PF14-16-000
4-219

The project would be shipped to customers by marine vessels or by pipeline. Air permits for the project 

were issued in May 2014. G2X Energy expects to have construction of the facility completed by 2017. 

At the time this EIS was prepared, construction had not started on the project. If constructed, the G2X 

Energy Natural Gas-to-Gasoline Plant would contribute to the cumulative effects on resources in the Lake 

Charles Liquefaction Project area.

IFG Port Holdings, LLC Export Grain Terminal Expansion

IFG Port Holdings, LLC’s export grain terminal at the Port of Lake Charles, is about 7 miles 

north-northeast of the Lake Charles Liquefaction Project site. The grain terminal is currently undergoing 

an extensive expansion and renovation while continuing to operate. When completed, the expanded and 

renovated facility will handle agricultural products such as rice, wheat, corn, soybeans, and dried 

distillers’ grain for shipment to other countries. Construction of the expansion and renovations began in 

2012 and is expected to be completed in 2015. These activities would be completed before the Lake 

Charles Liquefaction Project construction period, although operation of the facility would have the 

potential to contribute to the cumulative impacts on some resources in the Lake Charles Liquefaction 

Project area. 

Juniper GTL, LLC – Gas-to Liquids Project

Juniper GTL, LLC (Juniper GTL) is renovating a dormant steam methane reformer at its 

Westlake chemical plant, about 8 miles north of the Lake Charles liquefaction facility site. The steam 

methane reformer will convert natural gas into synthesis gas, a combination of hydrogen and carbon 

monoxide, which is used to make products such as methanol and ammonia. The methane reformer will 

be part of a new $100 million natural gas-to-liquids facility, producing about 1,100 barrels per day of 

waxes, drilling fluids, diesel, and naptha. The new plant infrastructure is under construction and expected 

to be completed in late 2015. Operation of the new facility would have the potential to contribute to 

cumulative impacts on some resources in the Lake Charles Liquefaction Project area. 

Liberty Natural Gas, LLC’s Liberty Gas Storage Expansion Project 

Liberty Natural Gas, LLC’s (Liberty) Liberty Gas Storage Expansion Project was authorized by 

the Commission in April 2012 and is currently under construction.

28

 The project will include one new 

compressor station, one new salt dome natural gas storage cavern, conversion of three existing salt dome 

brine storage caverns to natural gas storage caverns, and several support facilities approximately 10 miles 

southwest of the Lake Charles Liquefaction Project. In addition, Liberty is constructing a 5.1-mile-long, 

36-inch-diameter natural gas pipeline and one new meter station, which will interconnect with the 

Cameron Interstate Pipeline approximately 5 miles southwest of the liquefaction facility as well as a 

4.0-mile-long brine disposal pipeline and four salt water disposal wells 10 miles south-southwest of the 

liquefaction facility. The Liberty Gas Storage Expansion Project is expected to begin operation in 2017. 

Construction and operation of the Liberty Gas Storage Expansion Project would contribute to the 

cumulative impacts on resources in the Lake Charles Liquefaction Project area.

Sasol North America, Inc. Projects

Sasol North America, Inc. (Sasol) operates a chemical complex in Westlake, Louisiana, just 

northwest of Lake Charles and the City of Lake Charles and about 9 miles directly north of the Lake 

Charles Liquefaction Project (Sasol, 2014). Construction of an ethane cracker at the complex is currently 

underway, which will convert ethane contained in natural gas to ethylene, with a planned production rate 

 

28 Docket No. CP08-454-000
4-220

of 1.5 million tons of ethylene and derivatives per year. Construction is anticipated to be completed by 

2018, when the project is expected to become operational. The project will have the potential to 

contribute to cumulative impacts on some resources in the Lake Charles Liquefaction Project area.

Westlake Chemical Corporation – Petro 1 Ethylene Unit Expansion

Westlake Chemical Corporation’s (Westlake Chemical) Lake Charles complex consists of three 

tracts within 2 miles of one another on over 1,300 acres, located about 5 miles northwest of the Lake 

Charles Liquefaction Project. The complex includes two ethylene plants, two polyethylene plants, and a 

styrene monomer plant. The combined capacity of the two ethylene plants is about 2.7 billion pounds per 

year. In the first quarter of 2013, Westlake Chemical completed the expansion of one of the ethylene 

units (Petro 2) and its conversion to 100 percent ethane feedstock capability, increasing ethylene capacity 

by about 240 million pounds annually. Westlake Chemical plans to expand the capacity of the other 

ethylene unit (Petro 1) in the late 2015 to early 2016 time frame. If constructed, construction and/or 

operation of this expansion would have the potential to contribute to cumulative impacts on some 

resources in the Lake Charles Liquefaction Project area. 

4.13.1.4 Utilities and Transportation Projects

Louisiana Department of Transportation and Development Cove Lane Interchange Project

The primary roadways in the vicinity of the proposed Lake Charles Liquefaction Project are I-210 

and I-10. The DOTD’s Cove Lane Interchange Project in Calcasieu and Cameron Parishes is a threephase project that includes a full interchange at Cove Lane and I-210, a roundabout at the intersection of 

Cove Lane and W. Prien Lake Road, and extension of Cove Lane north to connect with a new public 

roadway that will parallel I-210 on the north side of the interstate. The project is under construction and 

anticipated to be completed by spring 2015, prior to the commencement of construction for the Lake 

Charles Liquefaction Project. As a result, this project is not expected to contribute to the cumulative 

impact on resources in the Lake Charles Liquefaction Project area.

According to a review of public information on the Southwest Louisiana Alliance website for 

Calcasieu, Jefferson Davis, and Beauregard Parishes, there are no other new roadways planned in these 

parishes in the foreseeable future, and the only roadway projects likely to occur are maintenance projects, 

including resurfacing. As a result, land transportation projects are not expected to contribute to the 

cumulative impact on resources in the Lake Charles Liquefaction Project area. 

Utilities

In the event that the Lake Charles Liquefaction and/or Magnolia LNG/KMLP Lake Charles 

Expansion Projects are approved, certain non-jurisdictional facilities would be constructed to serve the 

new facilities. Specifically, Entergy would to construct a 19-mile-long, 230 kV electric transmission line 

and a new substation to provide incremental power for the proposed Lake Charles LNG’s liquefaction 

facility, and a 1.3-mile-long, 230 kV electric transmission line from the existing Graywood substation to a 

new switching station to provide power for the Magnolia LNG Project. Entergy would also construct 

minor facilities to provide power to Trunkline’s proposed new Compressor Station 203-A and certain 

meter stations. Cleco would construct a 0.3-mile-long, 34.5 kV electric transmission line to provide 

power to the KMLP Lake Charles Expansion Project. Entergy also plans to construct a 12-mile-long,

230 kV electrical transmission line to provide power to the Cameron LNG Liquefaction Project.

In addition to the electric utilities, the Calcasieu Parish District 12 Water Works would construct 

an interconnect with an existing water pipeline to provide potable water for the Magnolia LNG terminal. 
4-221

4.13.1.5 Commercial and Residential Developments 

Golden Nugget Casino and Hotel

Ameristar Casinos, Inc. began construction of a dockside casino and hotel on Lake Charles with 

an 18-hole golf course and other sport facilities in 2012. The project was sold in November 2013 to 

Golden Nugget, and construction was completed in December 2014. The resort is about 6 miles northnortheast of the Lake Charles Liquefaction Project site on a 242-acre site adjacent to the L’Auberge Lake 

Charles Casino Resort. Operation of the casino could contribute to the cumulative impacts on some 

resources in the Lake Charles Liquefaction Project area.

Chennault International Airport Expansions

Chennault Airport, which is about 11 miles northeast of the Lake Charles Liquefaction Project, 

was expanded to include the addition of a 112,000-square-foot maintenance and repair hangar at the 

Chennault International Airport in Lake Charles, Louisiana. Northrop Grumman is also adding a 

25,000-square-foot maintenance repair center at the Chennault International Airport (Chennault 

International Airport, 2014). These expansions could potentially contribute to the cumulative impacts on 

certain resources in the Lake Charles Liquefaction Project area; however, the cumulative impacts would 

likely be minor given the distance and localized nature of the airport activities.

Port of Lake Charles

The Port of Lake Charles has completed rail improvements to handle traffic associated with 

transit between Chennault International Airport and the City Docks. In addition, two more docks will be 

added to Bulk Terminal 1. The proposed improvements could contribute to the cumulative impact on 

some resources in the Lake Charles Liquefaction Project area; however, the cumulative impacts would 

likely be minor given that some of the work has been completed.

Southwest Louisiana Technical Community College Training Facility

The Southwest Louisiana Technical Community College (SOWELA) has completed construction 

of a training facility to provide work programs and training services to meet the demands of new and 

expanded petrochemical facilities in southwestern Louisiana. The SOWELA Training Facility could 

potentially contribute to the cumulative impact on some resources in the Lake Charles Liquefaction 

Project area; however, the cumulative impacts would likely be minor given the distance between the two 

projects.

Graywood Community

Graywood Community is a planned community in South Lake Charles, Louisiana located about

2 miles north of the Lake Charles Liquefaction Project facility site. The complex encompasses about

2,000 acres and includes five neighborhoods with mixed housing options, sports facilities, and other 

amenities. A sixth land tract is in the preliminary planning phase. The Graywood Community would 

have the potential to contribute to cumulative impacts on some resources in the Lake Charles 

Liquefaction Project given the short distance between the two projects, particularly if construction 

activities occur during the same timeframe. 
4-222

Belle Savanne Residential/Commercial Development

The proposed Belle Savanne residential/commercial development is located in the 

Sulphur/Carlyss west of Lake Charles, about 7 miles northwest of the Lake Charles Liquefaction Project 

facility site. Phase I of the greenfield project would involve the construction of single-family residences 

on about 100 acres; Phase II would include multi-family residences and about 100,000 square feet of 

commercial development. Phase I land clearing began in late 2013/early 2014 and phased construction 

would likely be ongoing for several years. Construction of the Belle Savanne residential/commercial 

development would have the potential to contribute to cumulative impacts on some resources in the Lake 

Charles Liquefaction Project area, particularly if the construction activities occur during the same 

timeframe.

Pelican Lodge Workforce Housing

In November 2013, Greenfield Logistical Solutions of Louisiana LLC (Greenfield) began 

construction of the Pelican Lodge workforce housing complex located on a 200-acre property owned by 

the Port of Lake Charles about 11 miles northeast of the Lake Charles Liquefaction Project facility site. 

The $70 million complex will provide about 400 construction jobs and house up to 4,000 temporary

construction personnel working on multiple development projects in the Lake Charles area over the next 

several years. In addition to housing and recreational amenities, workers will be provided transportation 

to and from job sites. Construction will follow a three-phased approach and is expected to be completed 

in mid-2015. The Pelican Lodge workforce housing complex would have the potential to contribute to 

cumulative impacts on some resources in the Lake Charles Liquefaction Project area.

Walnut Grove Development

The proposed Walnut Grove residential/commercial development is located on a 60-acre property 

on the north side of Contraband Bayou in Lake Charles, about 7 miles north northeast of the Lake Charles 

Liquefaction Project facility site. The proposed development includes various residence types, parks, and 

a town square. Construction began in 2009/2010 and is ongoing. The Walnut Grove development would 

have the potential to contribute to cumulative impacts on some resources in the Lake Charles 

Liquefaction Project area, particularly if the construction activities occur during the same timeframe.

Moss Lake Worker Village 

First Flight Holdings, LLC (First Flight) is developing a temporary workforce housing complex 

on 100 acres of leased property at the Southland Field West Calcasieu Airport in Carlyss, about 5 miles 

west northwest of the Lake Charles Liquefaction Project site. The planned community is designed to 

accommodate varying workforce numbers, with 2,500 personnel at peak occupancy. In addition to 

temporary housing and recreational amenities, workers will be provided transportation to and from job 

sites. Based on First Flight's initial proposal, permanent infrastructure would remain in place after the 

temporary village has been removed allowing the complex to shelter families during any future natural 

disaster. In June 2014, the Calcasieu Parish Planning and Zoning board voted to approve a conditioned 

zoning exception to allow the workforce housing project. When the facility is no longer needed for 

construction workers, First Flight would have 6 months to remove the residential pods. The Moss Lake 

Worker Village would have the potential to contribute to cumulative impacts on some resources in the 

Lake Charles Liquefaction Project area, particularly if the construction activities occur during the same 

timeframe.
4-223

Audubon Trace

The Audubon Trace residential development would be on approximately 200 acres of land in 

Moss Bluff, Louisiana, approximately 15 miles north-northeast of the proposed liquefaction facility. 

Phase I of the development involves the construction of approximately 100 single-family residences; 

Phase II would include approximately 80 single-family residences. Construction of Phase I is expected to 

begin in 2015.

4.13.1.6 Government Activities

Dredging Projects

The COE conducts maintenance dredging in the Calcasieu Ship Channel. The frequency of 

dredging varies by reach, and is generally every other year in the portion of the channel adjacent to the 

Industrial Canal and existing Trunkline LNG terminal. The next anticipated dredging of the channel in 

the project area is currently anticipated to take place in 2015 (American Press, 2014). If maintenance 

dredging in the project area coincides with construction of the Lake Charles Liquefaction Project, it 

would contribute to the cumulative impact on some resources in the project area.

Louisiana Department of Wildlife and Fisheries – Louisiana Marine Fisheries Enhancement, 

Research, and Science Center

The Louisiana Marine Fisheries Enhancement, Research, and Science Center (Marine Center) 

would be a new facility developed as part of the compensation proposed under the Natural Resources 

Damage Assessment for the 2010 Deepwater Horizon Oil Spill in the Gulf of Mexico. The Marine Center 

would occupy two sites, one in Calcasieu Parish and one in Plaquemines Parish, Louisiana. The stated 

project goal is to establish state of the art facilities to responsibly develop aquaculture-based techniques 

for marine fishery management. 

The Marine Center would be located on a 320-acre privately owned undeveloped tract, located 

about 1 mile south of the Lake Charles Liquefaction Project site, south of the Turning Basin and Henry 

Pugh Boulevard. The actual facility would occupy a small portion (about 12 acres) of the full tract. The 

proposed facilities include a multi-purpose building (including a hatchery) and pond complex to be used 

for marine fisheries research, production, education, and outreach. Water would be sourced from 

proposed on-site wells and the Turning Basin in the Industrial Canal. Water from the Turning Basin

would enter a submersed intake structure and would be pumped to the site through a buried 10-inchdiameter pipeline. Two on-site wells are proposed, one for potable water and another for process water. 

Treated effluent would be discharged through a buried 24-inch-diameter pipeline and an outfall structure 

to an un-named tributary of the Calcasieu River and the Gulf Intracoastal Waterway, about 1,000 feet to 

the north. 

In June 2014, the federal and state natural resource trustee agencies issued a Programmatic and 

Phase III Early Restoration Plan and Early Restoration Programmatic Environmental Impact Statement 

(Phase III ERP/PEIS) as part of the Natural Resource Damage Assessment for the Deepwater Horizon Oil 

Spill. The Phase III ERP/PEIS includes a detailed discussion of the Marine Center. A subsequent Record 

of Decision was issued in October 2014 in which the trustee agencies decided to implement 44 projects, 

including the center.
4-224

4.13.2 Potential Cumulative Impacts by Resource

The following sections address the potential cumulative impacts of the Lake Charles Liquefaction 

Project and the other projects identified within the cumulative impact area on specific environmental 

resources. The other projects considered in each section are those for which impacts on the resource(s) 

discussed would be within the same region of influence as those that would result from the Lake Charles 

Liquefaction Project and would occur within the same timeframe. 

4.13.2.1 Geologic Conditions

The cumulative impact area for geologic resources and hazards was considered to be the area that 

would be affected by and adjacent to proposed construction areas for the Lake Charles Liquefaction 

Project. 

The Lake Charles Liquefaction Project would not materially impact (i.e., permanently curtail or 

preclude the extraction of) marketable mineral resources in the project area. As discussed in section 

4.1.2, there is an active gas and condensate producing well within the proposed liquefaction facility site. 

Lake Charles LNG are discussing a buyout of the active well with the well owner (i.e., Jordan Oil) and 

royalty owners, and have indicated that the well would be plugged and abandoned by Jordan Oil prior to 

the start of construction. 

At the proposed liquefaction facility site, Lake Charles LNG would modify the existing 

topographic contours to accommodate its equipment and facilities and maintain adequate drainage from 

the site. This would involve cutting, filling, and grading activities as well as raising the elevation of the 

site and at the ACWs. The original topography and contours of the site and raised ACWs would not be 

restored following construction. Additionally, Lake Charles LNG would construct buildings and critical 

equipment at the liquefaction facility to an elevation of 15 feet AMSL to minimize the risk of flash flood 

and/or storm surge damage. These changes in elevation and topography would reduce the flood retention 

capacity of the liquefaction facility site and ACWs, which are located within the 100-year floodplain of 

the Calcasieu River. In the event of a major river flood, floodwater that would have normally spilled out 

onto the site and ACWs would be diverted to other areas, potentially increasing the risk of flooding in 

these areas. To the extent that the Magnolia LNG and G2X Energy Projects also require minor 

topographic changes at their respective sites that result in similar losses of flood retention capacity, there 

could be a cumulative impact on the floodplain of the river. However, given the acreages involved 

compared to the total flood retention capacity of the entire river basin, the effect would be likely be 

insignificant. The potential for cumulative impacts on other geologic conditions would be minor. 

Construction and operation of the Non-Liquefaction Facilities would not contribute significantly 

to cumulative geology impacts. The proposed pipeline facilities and existing facility modifications would 

occur largely within previously disturbed areas, and the proposed new aboveground facilities would 

occupy relatively small footprints at various locations. Trunkline does not anticipate any blasting would 

be necessary in these areas and, following construction, would restore topographic contours along the 

pipeline rights-of-way and temporary workspaces for aboveground facilities to preconstruction conditions 

to the extent practicable. Therefore, the cumulative impact of the Non-Liquefaction Facilities on geologic 

resources would be negligible.

4.13.2.2 Soils 

The cumulative impact area for soils was considered to be the area affected by and adjacent to the 

proposed construction areas for the Lake Charles Liquefaction Project. Soil resources in the vicinity of 

the proposed project have been affected by past and ongoing agricultural and commercial forestry 
4-225

processes and construction and maintenance of existing roads, railroads, natural gas and oil pipelines, 

utility lines, electrical transmission line rights-of-way, and the existing Trunkline LNG terminal. 

Construction activities such as clearing, grading, trench excavation, backfilling, and the movement of 

construction equipment may affect soil resources. Clearing would remove the protective vegetative cover 

and expose the soil to the effects of wind and rain, which would increase the potential for soil erosion and 

sedimentation of sensitive areas. Grading, spoil storage, and equipment traffic could compact soil, 

reducing porosity and increasing runoff potential. Lake Charles LNG and Trunkline would implement 

the FERC’s Plan and Procedures, or alternative measures where justified, to protect soil resources and 

minimize soil impacts. This would include applying measures to control erosion and sedimentation 

during construction and ensuring proper restoration and revegetation of disturbed areas. As a result, most 

project-related impacts on soils would be short term. The greatest impact on soils would occur within 

areas permanently occupied by the proposed new aboveground facilities that would be paved, graveled, or 

covered with other fill material, and within the ACWs to be used during construction of the liquefaction 

facility that would not be restored to preconstruction condition. 

Entergy’s construction of the new non-jurisdictional substation and electric transmission line to 

provide power to the liquefaction facility would require some soil disturbance during construction that 

would result in similar short-term, localized impacts to those described above, and small areas of 

permanent conversion to impervious ground surface. The other Lake Charles area projects would not 

affect soils resources within the Lake Charles Liquefaction Project construction area. Additionally, the 

permanent or long-term soil impacts that would occur as a result of the Lake Charles Liquefaction Project 

would be localized within the area of the liquefaction facility and would not contribute significantly to 

cumulative impacts on soils.

4.13.2.3 Water Resources

The cumulative impact area established for groundwater resources includes the Chicot aquifer

underlying the majority of the proposed Lake Charles Liquefaction Project. The cumulative impact areas 

associated with surface water resources are the Industrial Canal, Turning Basin, the Calcasieu Ship 

Channel, and the pipeline stream crossings. Beyond these areas, we expect suspended sediments would 

settle out from the water column and be re-deposited as a result of the relatively low flow rates of the 

affected waterbodies. 

Several other LNG export projects are planned within the same region as the Lake Charles 

Liquefaction Project which would also result in ballast water discharges in the Calcasieu Ship Channel.

However, all of the projects are expected to follow Coast Guard regulations with regard to ballast water. 

We do not anticipate the Lake Charles Liquefaction Project would contribute significantly to cumulative 

impacts associated with the intake or discharge of ballast water. Lake Charles LNG anticipates that a 

minimal number of the barges used for construction of the proposed liquefaction facility would have to 

take on or discharge ballast water, and Lake Charles LNG did not request an increase in the number of 

LNG carriers currently authorized to use the existing terminal during operation of the new liquefaction 

facility. 

Lake Charles LNG would use about 65 million gallons of groundwater from the Chicot aquifer 

for construction of the proposed liquefaction facility. About 45 million gallons of this water would be 

obtained from two existing on-site wells and from two proposed new wells at the liquefaction facility site. 

This water would be obtained at a typical withdrawal rate of 56 gpm, with an anticipated peak withdrawal 

rate of 166 gpm. These withdrawal rates would be minor relative to the more than 10 million gpm that 

are currently withdrawn from the Chicot aquifer (DOTD and USGS, 2011). The remaining 20 million 

gallons of groundwater would come from the City of Lake Charles via its 17 municipal supply water 

wells. Lake Charles LNG has received the City’s approval for this water.
4-226

The nearest offsite well (also drawing water from the Chicot aquifer) is more than 150 feet from 

the Lake Charles Liquefaction Project site. We were unable to quantify the water withdrawal from this 

well. We were also unable to accurately quantify the groundwater withdrawals required for construction 

of all of the other planned and proposed projects, but we assume their requirements would be similar in 

magnitude to the Lake Charles Liquefaction Project. If so, the greatest cumulative use of groundwater 

would occur during the construction of these projects to the extent they are built at the same time. 

However, the duration of this cumulative effect would be temporary, primarily limited to the construction 

period, and the overall cumulative impact would be negligible compared to the overall aquifer withdrawal 

rates.

During operation of the Lake Charles Liquefaction Project, water would be obtained from the 

City of Lake Charles municipal supply and the two proposed wells at the liquefaction facility. Lake 

Charles LNG estimates that the total daily average water consumption for plant operations would be 

158,400 gallons per day, which would represent about 0.024 percent of the 648 million gallons withdrawn 

from the Chicot aquifer on a daily basis (DODT and USGS, 2011). Based on its FERC application, 

operation of the Magnolia LNG Project would require 170,707 gallons per day, which would be obtained 

from the Calcasieu Parish District No. 12 Water Works and from one of two new on-site groundwater 

wells. We were unable to quantify the groundwater withdrawals that would be required during operation 

of the other reasonably foreseeable projects listed in table 4.13.1-1; it is possible that several of these 

projects would have similar water requirements as the Lake Charles Liquefaction Project. The project is 

not located in an “Area of Groundwater Concern” or “Critical Area of Groundwater Concern,” which are 

areas that could require groundwater withdrawal restrictions. As a result, while there would be localized 

minor effects, such as the lowering of the water table at the point of withdrawal, we do not expect there to 

be a significant cumulative impact on groundwater during the concurrent operation of these facilities.

Construction of the proposed work docks would include dredging about 26,000 cubic yards of 

material from 22.1 acres within the Industrial Canal/Turning Basin adjacent to the existing Trunkline 

LNG terminal. Lake Charles LNG’s contribution to cumulative impacts from dredging would be smaller 

than those of other projects since the project would make use of the existing marine berths at the 

Trunkline LNG Terminal. Based on available information, the Magnolia LNG and G2X Projects may 

require dredging of about 863,000 cubic yards and 650,000 cubic yards, respectively, for development of 

their new marine berths.

If the proposed dredging for the Lake Charles Liquefaction Project in the Industrial 

Canal/Turning Basin were to occur at the same time as the dredging for G2X and Magnolia LNG Projects 

and/or concurrently with nearby COE maintenance dredging of the Calcasieu Ship Channel, the adverse 

impacts on water quality (e.g., increased turbidity, total suspended solids, release of nutrient-bound 

contaminants) in the project area could be exacerbated. However, dredging impacts tend to be localized 

(i.e., generally confined to the areas close to the dredging activity) and limited primarily to the time when 

the dredging is taking place (i.e., the effects cease soon after the dredging stops). Pile driving and sheet 

pile installation during in-water construction of the Lake Charles Liquefaction, Magnolia LNG, and G2X 

Projects, if these activities should occur concurrently for the three projects, could also cumulatively affect 

water quality; however, as with dredging, these impacts would be localized, short-term, and temporary. 

Before any dredging or pile driving can occur, Lake Charles LNG and the proponents of the other 

projects would need to obtain Section 10 Rivers and Harbors Act/Section 404 Clean Water Act 

authorizations from the COE and corresponding Section 401 (Clean Water Act) Water Quality 

Certifications from the state. These authorizations would be contingent on the companies’ use of best 

management practices to minimize effects on water quality and to ensure that state water quality 

standards are not violated. Additionally, the permits would require that the dredged material be tested 

before being disposed of in an approved offshore or onshore location. These measures would ensure that
4-227

there are no long-term cumulative impacts on water quality as a result of foreseeable dredging and pile

driving activities in the Industrial Canal/Turning Basin.

Shoreline erosion is a concern along the Gulf Intracoastal Waterway and the Calcasieu Ship 

Channel. Erosion may be caused by ship traffic or by engineered structures, such as levees along beaches 

or rivers. Natural processes, such as tide-induced currents, sea level changes, wind waves, and hurricanes 

or other extreme storms, also contribute to shoreline erosion. If the Lake Charles Liquefaction, Cameron 

LNG Liquefaction, Magnolia LNG, and G2X Projects all receive the necessary authorizations and permits 

and are constructed concurrently or in close succession, there could be several years of increased barge 

traffic. The combined barge traffic of these projects would increase the potential for cumulative shoreline 

erosion impacts in the Gulf Intracoastal Waterway and the Calcasieu Ship Channel. 

Construction of the proposed Mainline Connector and Mainline 200-3 Loop pipelines would 

require a total of 71 open-cut waterbody crossings, 56 of which are agricultural and roadside ditches. 

Impacts on water quality due to open-cut waterbody crossings can include short-term increases in 

sedimentation and turbidity, alteration or removal of in-stream and stream bank cover, and introduction of 

water pollutants from inadvertent equipment spills or leaks. Trunkline’s use of the HDD crossing method 

would avoid direct impacts on 18 waterbodies, including all of the major waterbodies crossed by the 

pipelines. Although impacts on surface waters could occur during the HDD installation process (e.g., 

through an inadvertent release of drilling fluid), Trunkline would reduce the likelihood and potential 

impacts associated with such events by the implementation of its HDD Contingency Plan. Trunkline

would minimize the potential for impacts on water quality during waterbody crossings through 

implementation of our Procedures and its SPAR and SPCC plans. Operation of the pipelines would not 

affect surface waters.

Due to the temporary, short-term, and localized nature of impacts associated with the waterbody 

crossings during construction of the Mainline Connector and Mainline 200-3 Loop pipelines and the 

distance of these pipelines from most of the other projects listed in table 4.13.1-1, we believe these 

activities would result in only a minor contribution to cumulative impacts on surface waters in the project 

area even if construction periods overlap. Moreover, the impacts of each of the projects identified near 

the Lake Charles Liquefaction Project on jurisdictional waters of the United States (e.g., wetlands and 

waterbodies) would be evaluated by the COE and permitted accordingly. Although stormwater runoff 

from construction activities near waterbodies upstream or downstream of the proposed construction rightof-way could result in impacts, we are not aware of any other substantial construction projects that would 

affect surface water quality near Trunkline’s proposed waterbody crossings. As a result, the cumulative 

impact on surface water resources in these areas due to stormwater runoff would be minor.

In addition to the COE permit and section 401 water quality certification, the Lake Charles 

Liquefaction Project and other projects near the Lake Charles Liquefaction Project would be required to 

comply with the LDEQ LPDES regulations for discharge of pollutants in stormwater or point source 

discharges. Compliance by the proponents of the other projects with these regulations, implementation of 

FERC’s Plan and Procedures and other project erosion and sediment control plans, and project-specific 

best management practices would minimize cumulative effects on surface water and groundwater quality.

We did not identify any other projects that would contribute to the cumulative impacts from 

hydrostatic test water withdrawal and discharge on water resources in the cumulative impact area for the 

proposed Non-Liquefaction Facilities. Therefore, we believe the cumulative impacts due to the 

withdrawal and discharge of hydrostatic test water for the Non-Liquefaction Facilities would be 

temporary and minor. 
4-228

4.13.2.4 Wetlands

The cumulative impact area for wetlands was considered to be the areas adjacent to and near the 

proposed Lake Charles Liquefaction Project construction areas.

Construction of the Lake Charles Liquefaction Project liquefaction facility would result in the 

permanent loss of 215.4 acres of wetlands within the facility site and ACWs. The majority of the 

wetlands affected at the site are forested mosaic, forested, and scrub-shrub wetlands. Although this would 

represent a significant impact on wetlands in the immediate project area, Lake Charles LNG and 

Trunkline are working with a specialty contractor to develop a Compensatory Mitigation Plan to offset 

permanent impacts on wetlands. The plan is anticipated to include the use of approved mitigation banks 

as well as a single permittee-responsible mitigation site. The Compensatory Mitigation Plan would 

require review and approval by the COE, and would ensure no net loss of wetlands in the broader area. 

Based on available information, construction of the other foreseeable projects in the vicinity of 

Lake Charles LNG’s proposed liquefaction facility would also affect wetlands in the area, including the 

permanent loss of 16.2 acres of wetlands (composed predominantly of emergent and scrub-shrub 

wetlands) associated with the Magnolia LNG terminal, and impacts on about 4.0 acres of predominantly 

emergent wetlands at the Marine Center. A review of aerial photography and NWI wetland data indicates 

that construction of the G2X Energy Project also has the potential to affect emergent wetlands in the 

northern part of the site. 

As noted previously, the proponents of each of the projects identified near the Lake Charles 

Liquefaction Project would need to obtain applicable permits from the COE. As part of the permitting 

process, each project would be required to develop and implement a mitigation plan to ensure that there is 

no net loss of waters of the United States and therefore no cumulative effects. 

Construction of Trunkline’s proposed Non-Liquefaction Facilities would affect a total of 

37.9 acres of wetlands. The majority of these impacts would result from construction of the pipelines, 

and most of the impacts would be temporary because they would occur within temporary construction 

workspace that would be allowed to revert to preconstruction condition after construction is completed. 

Construction and operation of the aboveground facilities would permanently affect less than 1 acre of 

wetlands, including less than 0.2 acre of forested wetland. 

About 6.0 acres of wetlands would be within the permanent pipeline rights-of-way, where 

maintenance practices during operation would include periodic mowing and tree removal. As a result of 

these maintenance practices, 0.4 acre of forested wetlands would be converted to scrub-shrub or emergent 

wetlands. Trunkline would minimize impacts on wetlands by implementing the measures in our Plan and 

Procedures and its own best management practices during construction and operation of the NonLiquefaction Facilities. Permanent impacts on wetlands resulting from construction and operation of the 

Non-Liquefaction Facilities would be addressed in the Compensatory Mitigation Plan mentioned above. 

We did not identify any other projects that would contribute significantly to wetland impacts in the 

cumulative impact area for the proposed Non-Liquefaction Facilities, and conclude that construction of 

the proposed Non-Liquefaction Facilities would have only a minor cumulative impact on wetlands. 

4.13.2.5 Vegetation and Wildlife

The cumulative impact area for vegetation and wildlife was considered to be the area adjacent to 

and near the proposed Lake Charles Liquefaction Project construction areas. 
4-229

A total of 568.3 acres of vegetation would be cleared during construction of the proposed Lake 

Charles Liquefaction Project liquefaction facility. Of this, about 245.4 acres would be permanently 

converted to industrial use within the operational footprint of the liquefaction facility, and 322.9 acres that 

would be cleared within the ACWs would be graveled or stabilized by seeding. The clearing of 

vegetation would reduce suitable cover, nesting, and foraging habitat for some wildlife species. The 

greatest contribution to cumulative impacts on wildlife habitat would result from the permanent loss of 

about 420.3 acres of forested uplands and forested wetlands. As noted previously, this effect would be 

partially offset (i.e., loss of forested wetlands) by Lake Charles LNG’s implementation of compensatory 

mitigation. To minimize impacts on migratory birds that may use forested habitat in the project area, 

Lake Charles LNG would initiate clearing activities outside of the nesting season.

Construction and operation of other projects in the area would also result in the permanent 

conversion of nearby vegetated habitats to developed, industrial land. In addition to the emergent 

wetlands mentioned previously, development of the Magnolia LNG Project site would result in the 

permanent removal of about 108 acres of upland shrub and forest habitat in areas that were previously 

disturbed by activities associated with construction and maintenance of the Industrial Canal, including 

areas used for disposal of excavated and dredged material. Previous activities have resulted in the 

degradation of wildlife habitat, which has reduced the number and diversity of species inhabiting the area. 

The extent of clearing required at the about 200-acre G2X Energy Project site is not known. Based on 

desktop review, the site appears to consist primarily of open-land habitat and emergent wetlands. Impacts 

on wildlife from construction of the Lake Charles Liquefaction Project and the other nearby projects 

would include displacement, stress, and direct mortality of some individuals. To the extent that 

construction periods overlap, these impacts may be exacerbated. 

Operation of the facilities would result in increased noise, lighting, and human activity that could 

disturb wildlife in the area. However, due to current industrial activities at the existing LNG terminal and 

the other industrial facilities in the project area, most wildlife in the area are acclimated to these 

conditions. Therefore, we expect cumulative impacts due to noise, light, and human activity during 

operation of the facilities to be negligible. Birds flying through the project area could also be affected by 

flaring at both the Lake Charles Liquefaction Project and Magnolia LNG Project facilities. Startup flaring 

would be required during startup of the liquefaction facilities. During operation of the liquefaction 

facilities, use of the emergency flares would only occur occasionally. It is unlikely that the startup flares 

from the two facilities would be in use at the same time due to schedule variability. Upset conditions that 

would require the use of flares cannot be predicted; however, it is unlikely that upset conditions requiring 

flaring would occur at the same time at both facilities. The FWS has not raised flaring as an issue of 

concern in the area and we are not aware of any reported significant impacts of flaring on migratory birds 

in the project area. Therefore, we believe that the cumulative impacts on birds from flaring would be 

minimal. 

Vegetation and wildlife habitat in the vicinity of the proposed Non-Liquefaction Facilities have 

been affected by past and ongoing agricultural and commercial forestry processes and construction and 

maintenance of existing roads, railroads, natural gas and oil pipelines, utility lines, and electrical 

transmission line rights-of-way. Construction and operation of the Non-Liquefaction Facilities would 

affect a total of 375.8 acres of vegetation. Of this total, 218.4 acres would be in temporary work areas 

and allowed to revert to preconstruction condition after construction is completed. About 103.2 acres 

would be within the permanent pipeline rights-of-way (including the Calcasieu River modification), and 

54.2 acres would be within the new or modified aboveground facility footprints. 

The majority of the habitat affected by the pipelines is agricultural and open land that would 

recover quickly after construction and continue to provide similar habitat during operations. The greatest 

impact on vegetation and wildlife habitat would result from the permanent conversion of forested habit to 
4-230

herbaceous cover in the permanent pipeline rights-of-way. Trunkline would minimize impacts on 

vegetation and wildlife habitat by collocating the Mainline 200-3 Loop with an existing pipeline and 

overlapping the construction area and permanent right-of-way with the existing maintained right-of-way, 

using the HDD method at several locations, refraining from maintaining the pipeline right-of-way 

between HDD exit and entrance points during operation, and implementing the FERC’s Plan and 

Procedures. With the implementation of these measures and given the lack of other project activity in the 

vicinity of the Non-Liquefaction Facilities, cumulative impacts on vegetation and wildlife would be 

minimal.

4.13.2.6 Aquatic Resources 

We considered the cumulative impact area for aquatic resources to be the about 1.5-mile-long 

Industrial Canal adjacent to the existing Trunkline LNG Terminal from the Turning Basin to where the 

canal joins the Calcasieu Ship Channel, and the proposed pipeline stream crossings. 

Dredging and pile driving at the existing Trunkline LNG Terminal during construction of the 

construction docks would disturb the estuarine bed and potentially result in mortality of some benthic and 

aquatic organisms if present. If Lake Charles LNG’s dredging and pile driving activities occur 

concurrently with those required for the Magnolia LNG and/or G2X Energy Projects, this impact would 

be exacerbated as a direct result of each of the projects’ dredge activities and as sediments resettle 

following construction. However, these impacts would occur within an Industrial Canal and Turning 

Basin that is maintained (including periodic dredging) to support shipping for industrial activity. 

Additionally, benthos in soft bottom habitats recover rapidly through various reproductive and 

recolonization mechanisms. Impacts on estuarine fisheries, including those related to changes in benthic 

forage, should be temporary, with habitat use reverting to normal conditions following completion of 

construction. During project operations, Lake Charles LNG would not discharge process water into the 

Industrial Canal. Cumulative impacts would primarily be those associated with the transit and operation 

of vessels serving the various project facilities while in the Industrial Canal and Turning Basin. NOAA 

Fisheries has reviewed the Lake Charles Liquefaction Project and concurred that the proposed activities 

would have a de minimis effect on fisheries. It is assumed that NOAA Fisheries would issue similar 

opinions for work conducted by the other projects in the Industrial Canal and Turning Basin. Therefore, 

we conclude that cumulative impacts on aquatic resources affected by construction and operation of the 

proposed liquefaction facility would be minimal.

Potential impacts on fisheries resources resulting from construction of the proposed NonLiquefaction Facility pipelines include sedimentation and turbidity, alteration or removal of in-stream and 

stream bank cover, water withdrawal during hydrostatic testing, and introduction of pollutants from 

inadvertent equipment spills or leaks. The aquatic impacts associated with the proposed NonLiquefaction Facilities would be temporary and limited to the construction period. Trunkline’s 

implementation of our Plan and Procedures would minimize these impacts. Water withdrawal and 

discharge for hydrostatic testing of the proposed pipelines would be conducted in compliance with the 

Procedures and applicable permits. As a result, cumulative impacts on aquatic resources associated with 

construction and operation of the proposed Non-Liquefaction Facility pipelines would not be significant.

4.13.2.7 Threatened and Endangered Species 

The cumulative impact area for threatened and endangered species is the area adjacent to and near 

the proposed Lake Charles Liquefaction Project. 

We identified 23 federally listed threatened and endangered species, 1 species proposed for 

federal listing under the ESA, and 2 species that are candidates for listing under the ESA that may occur 
4-231

within the parishes and/or counties affected by the Lake Charles Liquefaction Project. As discussed in 

section 4.7, we determined that the project would have no effect on 22 federally listed species, is not 

likely to cause the jeopardy of the 1 proposed species, and would not contribute to the trend toward 

federal listing for the 2 candidate species. Consequently, the project would not contribute to cumulative 

impacts on these species. 

One federally listed species, the endangered red-cockaded woodpecker, was identified as 

potentially occurring in Allen, Beauregard, Calcasieu, and Grant Parishes, Louisiana. The only work 

proposed for the Lake Charles Liquefaction Project in Grant Parish is at the existing Pollock Compressor 

Station. The closest recorded occurrence of red-cockaded woodpecker is about 0.1 mile southwest of the 

Pollock Compressor Station within the Kisatchie National Forest. Trunkline would conduct the proposed 

work at the Pollock Compressor Station in accordance with its existing Blanket Clearance, which includes 

stipulations for work conducted adjacent to habitat containing cavity trees used by red-cockaded 

woodpeckers. The FWS has concurred that by adhering to the Blanket Clearance’s stipulations, work at 

the Pollock Compressor Station is not likely to adversely affect the red-cockaded woodpecker. Suitable 

habitat for the red-cockaded woodpecker was not identified during the field surveys in Allen, Beauregard, 

and Calcasieu Parishes, and the FWS has confirmed that activities at the liquefaction facility site would 

have no effect on federally listed species. Therefore, we have determined that the project may affect, but 

is not likely to adversely affect the red-cockaded woodpecker. 

Based on available information and review of aerial photography, the Magnolia LNG Project, the 

G2X Energy Project, and the Entergy substation and transmission line appear unlikely to affect suitable 

habitat for the red-cockaded woodpecker. In conclusion, we have determined that there would not be 

cumulative impacts on threatened or endangered species due to construction and operation of the 

proposed Lake Charles Liquefaction Project.

4.13.2.8 Land Use, Recreation, and Visual Resources

Land Use

The cumulative impact area for land use was considered to be the area adjacent to and in the 

vicinity of the proposed Lake Charles Liquefaction Project.

The existing Trunkline LNG Terminal site is dedicated to industrial use. Construction of the 

Lake Charles Liquefaction Project would impact industrial, wetland, forest, and open water land uses and 

convert them to industrial use. In addition, construction of the G2X Energy Project, Magnolia LNG 

Project, and the Marine Center would result in a cumulative increase in the conversion of a variety of land 

uses to industrial/commercial use in the cumulative impact area. However, the COE and LDEQ would 

require compensatory mitigation for wetland loss for the Lake Charles Liquefaction Project and the other 

projects that would result in a loss of jurisdictional wetlands. Because there are many areas of wetlands, 

forest, and open water in the project area, we believe that the Lake Charles Liquefaction Project would 

not result in a significant cumulative impact on land use.

Construction of the Non-Liquefaction Facility pipelines would impact wetlands, agriculture, 

forested, industrial, and open water land uses. Most of these impacts would be temporary and previous 

land uses would be restored following construction. We did not identify any other projects in the 

cumulative impact area for the Non-Liquefaction Facilities. Because the majority of land use effects 

would be temporary and the permanent and long-term forest land impacts would be small relative to the 

amount of forest land in the adjacent areas, the cumulative impact of the Non-Liquefaction Facilities on 

land use would not be significant.
4-232

Recreation

The cumulative impact area for recreational facilities was considered to be the area adjacent to 

and in the vicinity of the proposed Lake Charles Liquefaction Project. There are no recreational facilities 

located within 0.25 mile of the Lake Charles Liquefaction Project. Therefore, the project would not 

contribute to cumulative impacts on recreational facilities.

The cumulative impact area for recreational fishing and boating was considered to be the barge 

delivery routes within the Industrial Canal/Turning basin, Intracoastal Waterway, and the Calcasieu Ship 

Channel. Operation of the liquefaction facility would not require an increase in the number of LNG 

vessels currently authorized to call on the existing Trunkline LNG Terminal; therefore, the operation of 

the Lake Charles Liquefaction Project would not contribute to cumulative impacts on recreational fishing 

and boating. Nevertheless, as discussed in the Marine Transportation section below, operation of the 

existing and proposed or planned projects could substantially increase vessel traffic in the Calcasieu Ship 

Channel, which could affect the experience of recreational users.

Construction of the Liquefaction Facility and other planned projects may temporarily impact local 

recreational fishing and boating activities. During construction, barges delivering materials and 

equipment to the Trunkline LNG Terminal, and possibly the G2X Energy and Magnolia LNG Project 

docks, may impede or delay recreational boat traffic. During construction, Lake Charles LNG expects an 

average of five barge deliveries per day. The Magnolia LNG Project would expect less than two barge 

deliveries per month. Assuming similar barge deliveries are required for the G2X Energy Project, the 

Lake Charles Liquefaction Project would have the potential for the greatest impact on recreational fishing 

and boating activities. However, the cumulative impact of the three projects would be mitigated 

somewhat by the fact that recreational boating and fishing occurs more often on weekends and holidays 

and construction activities would likely be reduced during these peak times. Moreover, the cumulative 

impact of project vessel traffic during construction would be short term. As a result, we do not believe 

that the Lake Charles Liquefaction Project would result in a significant cumulative impact on recreational 

fishing and boating. 

Visual Resources

The cumulative impact area for visual resources was considered to be the area within the 

viewsheds of the proposed Lake Charles Liquefaction Project facilities. Because of the height of the 

structures at the proposed liquefaction facility, the viewshed of the facility would extend for several miles 

in all directions. The viewshed for the proposed Non-Liquefaction Facilities is about 0.5 mile from the 

pipeline corridor and the aboveground facilities.

The visual character of the liquefaction facility would be similar to and consistent with the visual 

character of the adjacent existing LNG terminal, the ongoing industrial facilities and activities along the 

Calcasieu Ship Channel, and the many small oil and gas facilities near the Lake Charles Liquefaction 

Project site. Construction of the liquefaction facility would include three liquefaction trains, seven flares, 

mooring and breasting dolphins, and facility lighting. In addition, construction of the G2X Energy and 

Magnolia LNG Project would involve constructing similar facilities that would contribute to cumulative 

visual impacts. The flares associated with the Liquefaction Terminal would be 201 to 351 feet in height 

and the two flares associated with the Magnolia LNG Project would be 100 feet in height. The flares 

would operate during facility start up or upset conditions. If flaring were to occur at both facilities 

simultaneously, the temporary visual impact on observers would be exacerbated. However, it is unlikely 

that the startup flares from the two facilities would be in use at the same time due to schedule variability. 

Moreover, upset conditions that would require the use of flares cannot be predicted, but it is unlikely that 

upset conditions requiring flaring would occur at the same time at both facilities. Therefore, we do not 
4-233

believe that the proposed liquefaction facility would result in significant cumulative impact on visual 

resources.

The pipeline facilities proposed as part of the Lake Charles Liquefaction Project NonLiquefaction Facilities would be in rural areas and would not be in close proximity to the other planned 

and proposed projects identified in table 4.13.1-1. As such, impacts resulting from the construction and 

operation of these facilities would not contribute significantly to cumulative visual impacts. Additionally, 

the visual impacts associated with construction of these facilities would be short term and minor as 

described in section 4.8.6. No additional impacts would occur during operation. 

Aboveground facilities, such as the 203-A Compressor Station and new and expanded meter 

stations, would have additional visual impacts. However, the interconnections would be installed 

adjacent to existing aboveground natural gas facilities, and Compressor Station 203-A would not be in the 

viewshed of many observers. Moreover, Trunkline would use materials and/or paint the structures at the 

station to be harmonious with the surrounding landscape and infrastructure to minimize visual impacts on 

nearby residences. Therefore, the aboveground facilities would not contribute significantly to the 

cumulative impact on visual resources associated with the other past, present, and reasonably foreseeable 

projects.

4.13.2.9 Socioeconomics

Socioeconomic Conditions

We considered the cumulative impact area for socioeconomics to include Cameron, Calcasieu, 

Jefferson Davis, and Beauregard Parishes, where Lake Charles LNG and Trunkline would construct the 

majority of the proposed facilities and where most workers would be expected to reside during 

construction and operation of the project.

Construction of Lake Charles Liquefaction Project would generate a substantial number of jobs 

for a period of about 5 years starting in 2015. Construction of many other projects listed in table 4.13.1-1 

would also occur during portions of that time period, including the major projects in the Lake Charles 

area. Simultaneous construction of those projects would require a large number of workers from the local 

labor pool. The cumulative effect would be a reduction in local and perhaps regional unemployment. 

The abundance of jobs resulting from the Lake Charles Liquefaction Project would lead to an 

influx of non-local workers, which would impact transient housing in Calcasieu, Jefferson Davis, and 

Beauregard Parishes. As described in section 4.9.4, there is adequate vacant housing in these parishes to 

house these workers except during an about 9-month period when the peak workforce required to 

construct the liquefaction facility may be present. During that period, workers might need to find housing 

more distant from the project area. Similarly, the amount of available housing may not be sufficient if 

some of the other major projects listed above are constructed at the same time. Some of the housing 

constraints may be alleviated in part by worker housing facilities such as Pelican Lodge and Moss Lake 

Village to the extent that vacancies are available. Otherwise, the non-local workers unable to find 

acceptable housing in Calcasieu, Jefferson Davis, and Beauregard Parishes may need to find housing in 

adjacent Allen Parish. If peak construction workforce periods of many of the projects coincide, it is 

possible the available housing in Allen Parish could also be exceeded. As a result, some members of the 

workforce and others seeking transient housing may have to obtain housing in Texas or more distant 

parishes with longer commutes. 

If several of the projects listed in table 4.13.1-1 are constructed at the same time, the combined 

construction workforces of these projects would increase the need for some public services, such as 
4-234

police, medical services, and schools. Construction of the liquefaction facility would result in little or no 

short-term impact on the availability of local community facilities and services such as police, fire, and 

medical because the non-local workforces would be small relative to the current population in Calcasieu 

Parish. The proposed liquefaction facility would not materially change the emergency response 

requirements from those associated with existing operations at the terminal. However, if construction of 

the other projects overlap with the proposed project, there is greater potential for cumulative impact on 

such services, particularly in Calcasieu Parish. If the medical and emergency services, or other public 

services, are adversely affected during construction, the project sponsors may mitigate the impact by 

providing funding for temporarily increasing the staff and equipment of the public services affected.

With construction of some of the major projects listed in table 4.13.1-1 lasting several years, it is 

likely that some construction workers would bring their families, including school-age children. That 

would increase the population in some schools in the parishes housing the workers with families. 

However, the children of these families would likely be spread across many school districts in the five 

parishes and the increases in children attending any particular school would likely be small. As a result, 

there would not likely be a significant cumulative impact on schools during the concurrent construction 

periods.

A large workforce for the simultaneously constructed projects would have a beneficial cumulative 

effect on revenues for the state and for Cameron, Calcasieu, Jefferson Davis, and Beauregard Parishes due 

to expenditures for services and materials for the projects, increased expenditures by local workers, and 

expenditures by the non-local workforce and any family members accompanying the non-local workers. 

The parishes would also receive a substantial increase in property taxes from the combined projects.

Marine Transportation

 As previously described, construction of the major Lake Charles area projects would increase 

barge and support vessel traffic in the Gulf Intracoastal Waterway and the Calcasieu Channel. A 

simulation study conducted by Ausenco, described further below, included a construction traffic 

assessment based on assumed bulk carrier and barge traffic associated with construction of the Lake 

Charles Liquefaction Project. The study concluded that the construction-related marine traffic for the 

project would not affect existing users of the channel. Concurrent construction of the other projects and 

the Lake Charles Liquefaction Project would likely result in a cumulative impact on vessel traffic in the 

waterway, primarily by increasing congestion and vessel travel times. However, these impacts would be 

temporary and the extent of the impacts would depend on the frequency and number of deliveries being 

made for various projects at any given time during the respective construction periods. 

Operation of the liquefaction facility would not require an increase in the number of LNG vessels 

currently authorized to call on the existing Trunkline LNG Terminal. Ausenco (2014) conducted a 

simulation study for nine proposed terminals in the general project area including the Waller Point LNG, 

Venture Global Calcasieu Pass, Gasfin LNG, Magnolia LNG, G2X Energy, Lake Charles Liquefaction, 

Lake Charles Clean Energy, IFG Holdings, and Sasol Projects, to evaluate the cumulative effect of these 

projects and the existing projects on marine vessel traffic. The study modeled two simulation cases– one 

with traffic to only the existing terminals and one with traffic to both the existing and proposed terminals 

– to observe the impact of the additional traffic from the proposed terminals on the operations of the 

existing Trunkline LNG Terminal. The study determined there could be a potential increase in vessel 

traffic in the Calcasieu Channel from 1,359 vessels to 2,543 vessels per year. The study found that in 

both cases the lost production and berth commitment were below the key performance indicator 

thresholds (1 percent and 85 percent respectively) to enable Lake Charles LNG to export its expected 

LNG quantities under either case. While this study addressed impacts of increased marine traffic on the 

Lake Charles Liquefaction Project, the results would likely apply to the other facilities in the area as well. 
4-235

Moreover, LNG vessel traffic associated with operation of the LNG facilities would be governed by Coast 

Guard requirements. Therefore, we believe that cumulative impacts on marine transportation would not 

be significant. 

Land Transportation 

We considered the cumulative impact area for land transportation to include Calcasieu, Jefferson 

Davis, and Beauregard Parishes. The greatest potential for cumulative impacts on vehicular traffic and 

roads during construction and operation of the Lake Charles Liquefaction Project is associated with the 

proposed liquefaction facility. Construction-related traffic associated with the Non-Liquefaction 

Facilities would result in only minor, temporary impacts on traffic, would be relatively short-term at any 

given location, and would not be in close proximity to other known large projects. 

During construction of the liquefaction facility and the Lake Charles area projects, roadways in 

the area would experience a substantial increase in daily vehicle trips as a result of material and 

equipment deliveries and commuting of construction personnel to and from the project sites. Lake 

Charles LNG and Trunkline commissioned a traffic impact study to assess potential impacts of vehicular 

traffic associated with the project, including potential cumulative impacts that could result if construction 

of the proposed liquefaction facility overlaps with the construction of the G2X Energy and Magnolia 

LNG Projects. The study is based on current traffic conditions, projected traffic volumes, projected 

numbers of temporary and permanent workers, and assumptions (listed in the report) about where 

members of the workforce would reside during project construction and operation. 

The traffic study concluded that construction and operation of the Lake Charles Liquefaction 

Project itself, if not constructed concurrently with other projects, would not be expected to affect the 

existing road network or exceed roadway capacity with the exception of Country Club Road, where road 

capacity could be exceeded along two segments during construction, and along one segment during 

operation. The Calcasieu Police Jury is engaging a consultant to design an extension of Ham Reid Road 

that, if constructed in time, might alleviate some of the potential capacity deficiencies identified on 

Country Club Road. However, the study determined that the cumulative impact from concurrent 

development of the Lake Charles Liquefaction Project, Magnolia LNG Project, and G2X Energy Project 

could include deficiencies in roadway capacities. The study indicates that Lake Charles LNG plans to 

specify shipping routes during construction between the facility site and interstate highway system to 

keep commercial traffic out of the more developed areas of Lake Charles. Lake Charles LNG has also 

indicated that it would avoid receiving large truck deliveries during peak traffic periods, and that it may 

consider bussing workers to and from the construction site. The study identifies several other mitigation 

strategies that might alleviate the cumulative impact of the three projects, including off-site parking, the 

use of shuttles, controlled shift times, coordination among the projects to reduce peak hour vehicular trips, 

traffic signal coordination/retiming, intersection and road improvements, and use of law enforcement to 

control traffic. Lake Charles LNG, Magnolia LNG, and G2X Energy are coordinating to further evaluate 

cumulative impacts of the three projects on area traffic and roadways. Moreover, we have recommended 

that Lake Charles LNG file a traffic management plan prior to construction for review and approval by 

the Director of OEP. 

4.13.2.10 Cultural Resources 

The cumulative impact area for cultural resources was considered to be the area within and near 

the proposed Lake Charles Liquefaction Project. Lake Charles LNG and Trunkline have consulted with 

the appropriate SHPOs and completed the necessary cultural resource surveys and reports. The SHPOs 

have concurred that construction of the other project facilities would not affect historic properties, and we 

also concur. Therefore, the project would not contribute to cumulative impacts on cultural resources.
4-236

4.13.2.11 Air Quality and Noise 

Air Quality

Construction Cumulative Impacts

The cumulative impact area for air quality during construction of the proposed liquefaction 

facility, modifications to the existing LNG terminal, Compressor Station 203-A, and modifications to the 

Longview Compressor Station is the area adjacent to and near these proposed facility borders. The 

cumulative impact area for air quality during the operation of the proposed liquefaction facility and the 

existing LNG terminal is the PSD AOI of 6.2 miles (10 km). A similar PSD AOI exists for the proposed 

Compressor Station 203-A and Longview Compressor Station. Potential existing and proposed projects 

that could be expected to contribute to cumulative construction impacts on air quality include the 

Cameron LNG, Magnolia LNG, Leucidia, G2X, and Sasol projects. Because the various project facilities 

are located over a large geographic area, the cumulative air quality impacts of these construction projects 

would be minimal and temporary. 

Construction of the Lake Charles Liquefaction Project would temporarily impact air quality due 

to emissions from the combustion engines used to power construction equipment, vehicle emissions 

traveling to and from the construction site, and from fugitive emission dust resulting from equipment 

movement on dirt roads and earth-disturbing activities. An analysis of the future projects in the vicinity 

(within 10 miles) of the proposed Lake Charles Liquefaction Project indicates that project construction 

may overlap with the construction period for the Magnolia LNG Project and, possibly the G2X Energy 

Project. The potential for cumulative construction emissions impacts would be greatest during site 

preparation when fugitive dust production would likely be at its peak. Emissions from equipment engines 

and vehicles operating concurrently for the different projects would also result in cumulative air quality 

impacts in the local area. Lake Charles LNG and Magnolia LNG would implement mitigation measures 

to minimize construction impacts on air quality such as applying water or dust control chemicals to 

minimize fugitive dust, and by complying with applicable EPA mobile source emission performance 

standards and using equipment manufactured to meet these standards. We assume that G2X would 

implement similar measures. As discussed in section 4.11.1.4, we have also recommended that Lake 

Charles LNG and Trunkline develop a Fugitive Dust Control Plan providing more detail on the 

mitigation measures they would employ to minimize fugitive dust emissions during construction of the 

proposed facilities. Based on the temporary nature of construction and the implementation of appropriate 

mitigation measures, we believe that cumulative impacts on air quality due to construction of these 

facilities would be temporary and minor. 

Operational Cumulative Impacts

The region in the vicinity of the proposed Lake Charles Liquefaction Project is currently in 

attainment with air quality standards, but increases in industrial point sources could affect local and 

regional air quality. Under federal and LDEQ regulations, the liquefaction facility is considered a major 

PSD emission source and would contribute to cumulative impacts on air quality within the cumulative 

impact area. Lake Charles LNG has supplied estimated operational emissions for the liquefaction facility, 

and conducted a dispersion modeling analysis (see section 4.11.1.3). This analysis included a PSD 

Screening Analysis, NAAQS Analysis, and PSD Increment Analysis. The PSD Screening Analysis 

included a Significance Analysis, the AOI Analysis, and the Preconstruction Monitoring Analysis. In 

case of the 1-hour NO2 model, Lake Charles LNG modeled inventory sources within 10 kilometers 

(6.2 miles) of the facility. Lake Charles LNG has also determined that there would be no increase in ship 

and support vessel traffic for the proposed Lake Charles Liquefaction Project from what is currently 

authorized for the existing LNG terminal. Table 4.13.2-1 summarizes the Lake Charles Liquefaction 
4-237

Project emissions from LNG marine traffic and other project-related vessels. As required by EPA 

modeling guidelines, monitored background concentrations must be added to modeled impacts 

(liquefaction facility sources and an inventory of industrial emission sources surrounding the facility). 

The background concentrations include emissions from non-industrial emissions sources such as marine 

vessels, vehicles, etc., and may also include industrial sources that are already accounted for in the 

inventory. Therefore, due to the transitory nature of these mobile sources and the large area covered, 

these associated mobile source emissions should not have a significant cumulative impact on air quality 

along the waterway.

TABLE 4.13.2-1

Total Support Vessel Emissions

Vessel Types

NOX

(tpy)

SO2

(tpy)

CO

(tpy)

PM10/2.5

(tpy)

VOC

(tpy)

LNG Carriers

Inbound berthing and unberthing 36 0.02 133 0.03 90

14 hours loading,10 hours hoteling 30 0.01 101 0.04 66

Outbound trips 49 0.01 183 0.02 124

Total LNG Carriers 115 0.04 417 0.09 280

Tugs

Inbound, berthing 244 0.15 26 6.1 2

Standby 22 0.01 5 1.6 2

Unberthing, outbound support 67 0.04 7 1.7 1

Total Tugs 333 0.02 38 9.4 5

Total All Vessels 448 0.24 455 9.49 285

Under all applicable analyses required by PSD regulations, the emission impacts including 

liquefaction facility point sources, an inventory of industrial sources surrounding the facility, and air 

quality background concentrations, were in compliance with modeling impact standards.

Trunkline has supplied facility emission estimates for Compressor Station 203-A and the 

Longview Compressor Station. Since Compressor Station 203-A is not a major PSD source, no air 

quality impact analysis modeling or PSD increment consumption analysis was required. In addition, the 

proposed modifications to the Longville Compressor Station would not result in the exceedance of any 

criteria pollutant SER, were also not subject to PSD modeling requirements. However, to assist us in 

preparing this EIS, Trunkline performed an air dispersion screening analysis using the AERSCREEN 

model to assess the impact of the proposed new facility emissions at Compressor Station 203-A and the 

emissions associated with the modifications at the Longville Compressor Station on the NAAQS. The 

AERSCREEN model results summarized in section 4.11.1.5 demonstrate that the proposed new 

Compressor Station 203-A and modifications to the Longville Compressor Station would not significantly 

impact the air quality in the surrounding area. As outlined in section 4.11.1.5, emissions from other 

facilities (Shaw Compressor Station, Mainline 100-3 and 200-1 Loop modifications, and metering 

stations along the main pipeline) would be minor or insignificant. 

Projects that would potentially be constructed in the future, and are considered to be major 

sources of air emissions, would be required to conduct a PSD analysis. Should operation of a new project 

result in a significant impact on air quality, the LDEQ would enforce operational limitations or require 

emissions controls that ensure the facility’s compliance with the SIP and attainment with the NAAQS. In 

addition, the Lake Charles Liquefaction Project facilities would be required to comply with LDEQ permit 

conditions during operation of the various facilities which include emission control requirements to limit 

the emissions of certain criteria pollutants, HAPs, and/or GHGs. The LDEQ issued a Part 70 Operating 

Permit for the liquefaction facility on May 1, 2015.
4-238

Therefore, based on the cumulative modeling analysis and the required emission controls at the 

various Lake Charles Liquefaction Project facilities, we conclude that there would be no significant 

cumulative impact on air quality as a result of the operation of these facilities. 

Climate Change

Climate change is the change in climate over time, whether due to natural variability or as a result 

of human activity, and cannot be represented by single annual events or individual anomalies. For 

example, a single large flood event or particularly hot summer are not indications of climate change, 

while a series of floods or warm years that statistically change the average precipitation or temperature 

over years or decades may indicate climate change.

The Intergovernmental Panel on Climate Change (IPCC) is the leading international, multigovernmental scientific body for the assessment of climate change. The United States is a member of the 

IPCC and participates in the IPCC working groups to develop reports. The leading U.S. scientific body 

on climate change is the U.S. Global Change Research Program (USGCRP). Thirteen federal 

departments and agencies participate in the USGCRP, which began as a presidential initiative in 1989 and 

was mandated by Congress in the Global Change Research Act of 1990.

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 this accumulation of GHG; 

 these 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.

Although climate change is a global phenomenon, this GHG emissions/climate change 

cumulative impact analysis focuses on the impacts of climate change in the Southeast region of the United 

States. The USGCRP (2014), NOAA (2011), and CCSP (2008) reports include the following impacts of 

climate change in the Southeast and Coastal regions:

 The region's climate is generally warm and wet, with mild and humid winters. Since 

1970, average annual temperatures in the region have increased by about 2 °F. Winters, 

in particular, are getting warmer. The average number of freezing days has declined by 4 

to 7 days per year since the mid-1970s.

 Average annual temperatures in the region are projected to increase by 4 to 9 °F by 2080.

 Most areas, with the exception of southern Florida, are getting wetter. Autumn 

precipitation has increased by 30 percent since 1901. The number of heavy downpours 

has increased in many parts of the region.
4-239

 Despite increases in fall precipitation, the area affected by moderate and severe drought, 

especially in the spring and summer, has increased since the mid-1970s.

 The coasts will likely experience stronger hurricanes and sea level rise. Storm surge 

could present problems for coastal communities and ecosystems.

 Many coastal areas in Texas and Louisiana are subsiding; local land elevation is sinking 

relative to sea level. Combined with global sea level rise, local subsidence will lead to a 

higher "relative" change in sea level at the local scale. Observed subsidence rates in the 

southeast are significant. For example, in Grand Isle, Louisiana and the plain of the 

Mississippi River delta, sea level is already rising at rates as high as 0.32 inches per year.

 Higher temperatures increase evaporation and water loss from plants. Projected increases 

in temperature will likely increase the frequency, duration, and intensity of droughts in 

the area.

 Projected changes in surface water runoff to the coast and groundwater recharge will 

likely allow saltwater to intrude and mix with shallow aquifers in some coastal areas of 

the Southeast, particularly in Florida and Louisiana.

 If the region increases groundwater pumping to offset water shortfalls, then aquifers will 

be further depleted. In the long term, the depletion of ground water supplies would place 

additional strain on surface water resources.

 Growth in demand will also likely strain water resources. The Southeast region is 

attracting people, investment, and industry. The population of Florida has more than 

doubled during the past 30 years. Growth rates in most other southeastern states were 45 

to 75 percent over the same period. Decreased water availability will challenge future 

growth and the quality of life of residents in the region.

 Higher temperatures and more frequent heat waves will likely increase heat stress, 

respiratory illnesses, and heat-related deaths in the Southeast. High temperatures also 

correlate with poor air quality and pose a risk to people with respiratory problems. While 

the number of cold-related deaths is projected to decrease, net climate-related mortality 

will likely increase.

 Increased flooding and hurricanes could present extreme public health and emergency 

management challenges.

 The spread of some types of bacteria has been linked to warmer temperatures. For 

example, food poisoning from eating shellfish infected with Vibrio parahaemolyticus

bacteria has increased by 41 percent from 1996 to 2006 in the United States. As 

temperatures increase, the frequency of these types of shellfish-borne disease outbreaks 

in coastal waters is likely to increase.

The GHG emissions associated with the construction and the operation of the Lake Charles 

Liquefaction Project are identified in the Air Quality Section above, and a GHG BACT analysis 

performed for the Liquefaction Facility and a summary is also included. Proposed GHG BACT for the 

Liquefaction Facility includes use of low carbon fuels, combustion equipment (turbines, thermal 

oxidizers, emergency back-up and firewater pump engines) designed as operational energy efficient in 

accordance with EPA GHG BACT standards, and a leak detection and repair (LDAR) program for 
4-240

monitoring piping and storage tank components to limit the impact of methane emissions. Proposed 

modifications to the Longview Compressor station include the replacement of the existing turbine with a 

more energy efficient turbine. Compression Station 203-A is not a PSD major source and therefore a 

GHG BACT analysis is not required for this facility. However, the installation of new turbines and 

internal combustion engines would also be designed for energy efficient operations. 

There is no current methodology or policy guidance to determine how the Lake Charles 

Liquefaction Project’s incremental contribution to GHGs would translate into physical effects on the 

global environment. The emissions would increase the atmospheric concentration of GHGs, in 

combination with past and future emissions from all other sources, and contribute incrementally to 

climate change that produces the impacts described above. However, it cannot be determined whether or 

not the Lake Charles Liquefaction Project’s contribution to cumulative impacts on climate change would 

be significant.

Noise

We considered the cumulative impact area for noise to include the NSAs in the vicinity of the 

Lake Charles Liquefaction Project. 

The greatest potential for cumulative noise impacts would be during construction from internal 

combustion engines and pile driving activities. The estimated noise generated from construction 

associated with the liquefaction facility would not exceed 55 dBA Ldn at the nearest NSAs. Although 

construction of the G2X Energy and Magnolia LNG Projects could overlap with the construction of the 

Lake Charles Liquefaction Project and contribute to noise levels in the area, these projects are located 

farther from the nearest NSA. As a result, we do not believe that construction of the liquefaction facility 

along with the G2X Energy and Magnolia LNG Projects would result in a significant noise impact on the 

nearest NSA.

The estimated operational noise level of the liquefaction facility at the nearest NSA (about 

0.8 mile to the north/northeast) is 53.6 dBA Ldn, which is 2.5 dBA greater than the estimated ambient 

noise level. The threshold of perception of change in sound levels for human hearing is about 3 dB; 

therefore, the increase would be unnoticeable or barely noticeable at the nearest NSA. As a result, 

operational noise from the liquefaction facility would result in minor impacts on the NSA. Other projects 

near the liquefaction facility that could contribute to the cumulative noise impacts include the Magnolia 

LNG Project and the G2X Energy Project. The Magnolia LNG Project is located about 1,000 feet south 

of the liquefaction facility and farther from the NSAs associated with the liquefaction facility. Lake 

Charles LNG completed a noise assessment that evaluated the sound levels from the operation of the 

liquefaction facility and the Magnolia LNG Project on NSAs near each site. Based on the results of the 

study, the sound levels associated with operation of both facilities would not exceed 55 dBA Ldn at any of 

the existing NSAs. As a result, the Magnolia LNG Project would not be expected to contribute 

significantly to the noise levels at the liquefaction facility NSAs. The G2X Energy Project is located 

adjacent to the west of the liquefaction facility and, while not regulated by the FERC, would be subject to 

the Calcasieu Parish noise regulations found in the Calcasieu Parish Police Jury Code of Ordinances, 

Chapter 18, Article VIII. As a result, the G2X Energy facility would not be expected to contribute 

significantly to the noise levels at the NSAs during operations.

Noise associated with construction of the pipeline facilities, including aboveground facilities, 

would affect ambient noise levels at some nearby residences. The noise levels attributable to the 

construction equipment would attenuate quickly as the distance from the noise source increases and 

construction proceeds along the pipeline right-of-way. The duration of construction activities, and 

therefore noise impacts, at any one location would be temporary.
4-241

We did not identify any other projects that would contribute to operational noise impacts in the 

cumulative impact area for Compressor Station 203-A or the Longville Compressor Station.

4.13.2.12 Safety 

We considered the cumulative impact area for the Lake Charles Liquefaction Project to be the 

area adjacent to and in the vicinity of the liquefaction facility site, and the cumulative impact area for the 

proposed pipeline facilities was considered to be within about 660 feet of the pipeline centerline. The 

cumulative impact area for emergency services includes the area in the general vicinity of the proposed 

Lake Charles Liquefaction Project and the other Lake Charles area projects listed in table 4.13.1-1.

Lake Charles LNG would mitigate impacts on public safety through the implementation of 

applicable federal, state, and local rules and regulations for the proposed Lake Charles Liquefaction 

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. Because Lake Charles LNG has not requested an increase in the number of LNG

carriers calling on the terminal, the Lake Charles Liquefaction Project would not add to the current public 

safety risk associated with vessel traffic in the Calcasieu Ship Channel or at berth in the Industrial Canal.

Emergency response time is a key aspect of public health and safety. Key emergency services are 

provided by the existing Trunkline LNG Terminal in Calcasieu Parish, and those services would expand 

to include the associated proposed liquefaction facility. In accordance with our regulations, Lake Charles 

LNG would prepare a comprehensive plan that identifies the cost sharing mechanisms for funding these 

emergency response costs. This plan would minimize the potential for a cumulative public safety impact 

associated with the project. 

The Magnolia LNG Project, Cameron LNG Liquefaction Project, and other stand-alone LNG 

liquefaction projects listed in table 4.13.1-1, if authorized, constructed, and operated, each would also 

have to prepare and implement a similar comprehensive plan to provide emergency services. In addition, 

we anticipate that the other major projects in the Lake Charles area (e.g., the G2X Energy, IFG Port 

Holdings, Sasol, and Juniper GTL Projects) would include emergency services within their facilities, and 

have emergency response plans developed with the appropriate agencies. Emergency responses at any of 

those facilities could temporarily stress emergency services in the area, but we would not expect them to 

result in a long-term significant impact on those services. In the unlikely event of major emergencies at 

several of the facilities at the same time, there could be a short-term but significant cumulative impact on 

emergency services within Calcasieu and Cameron Parishes. That impact could be mitigated by 

assistance from emergency service providers from surrounding parishes.

5-1

5.0 CONCLUSIONS AND RECOMMENDATIONS

5.1 SUMMARY OF THE ENVIRONMENTAL ANALYSIS

The conclusions and recommendations presented in this section are those of the FERC 

environmental staff. Our conclusions and recommendations were developed with input from the COE, 

Coast Guard, DOE, FWS, and DOT, as cooperating agencies. The federal cooperating agencies may 

adopt the EIS per 40 CFR 1506.13 if, after an independent review of the document, they conclude that 

their permitting requirements and/or regulatory responsibilities have been satisfied. However, these 

agencies would present their own conclusions and recommendations in their respective and applicable 

records of decision or determinations. Otherwise, they may elect to conduct their own supplemental 

environmental analysis, if necessary.

We determined that construction and operation of the Lake Charles Liquefaction Project would 

result in adverse environmental impacts. Most of these environmental impacts would be temporary or 

short term during construction and operation, but long-term and permanent environmental impacts on 

wetlands, vegetation, and land use would also occur as part of the project. This determination is based on 

a review of the information provided by Lake Charles LNG and Trunkline and further developed from 

data requests; field investigations; scoping; literature research; alternatives analysis; and contacts with 

federal, state, and local agencies as well as Indian tribes and individual members of the public. As part of 

our review, we developed specific mitigation measures that we determined would appropriately and 

reasonably reduce the environmental impacts resulting from construction and operation of the project. 

Therefore, we are recommending that our mitigation measures be attached as conditions to any 

authorization issued by the Commission. If the proposed project is constructed and operated in 

accordance with applicable laws and regulations, the mitigating measures discussed in this EIS, and our 

recommendations, most of the adverse environmental impacts (with the exception of impacts on upland 

forest as discussed below) would be reduced to less than significant levels. A summary of the anticipated 

impacts from the project and our conclusions regarding impacts are provided below by resource area.

5.1.1 Geology Resources 

Construction and operation of the project would not affect active mining or nonfuel mineral 

resources during construction or operation. One active gas and condensate producing well is located 

within the proposed liquefaction facility site. Lake Charles LNG stated that it was discussing a buyout of 

the well with the well owner (i.e., Jordan Oil) and indicated that Jordan Oil would plug and abandon the 

well prior to the start of construction. We received comments from three of the royalty owners of the well 

expressing their interest in the disposition of the well and concern about the potential effects on their 

mineral rights. In comments on the draft EIS, the same royalty owners stated that negotiations they have 

had to date with Lake Charles LNG and Jordan Oil have not resulted in resolution of this issue. In 

response to draft recommendations included in the draft EIS, Lake Charles LNG said it had reached 

agreement with several of the royalty interest owners, and that it plans to continue to work to reach 

agreement with respect to Jordan Oil and all royalty/mineral interest owners prior to taking a positive 

final investment decision and commencing work on the site.

In general, the potential for geologic hazards such as earthquakes, soil liquefaction, landslides, or 

a seismically generated tsunami or seiche to significantly affect construction or operation of the proposed 

project facilities is low. However, some hazards such as flooding and hurricanes could affect the project 

during operation. Lake Charles LNG and Trunkline would design and construct the aboveground 

facilities at the liquefaction facility and the compressor/meter stations at an elevation to minimize the 

potential impacts from flooding and hurricanes. Subsidence could occur in the project area, particularly 

at the liquefaction facility and ACWs, due to oil and gas extraction and groundwater withdrawal. Lake 
5-2

Charles LNG stated that monitoring can be done through periodic topographic surveying of the site, but 

did not commit to conduct such monitoring because it does not anticipate that any mitigation would be 

required based on the estimated subsidence rate. However, we find that periodic monitoring should be 

completed; therefore, we are recommending that, prior to construction, Lake Charles LNG file a plan for 

periodic monitoring and reporting of ground subsidence and foundation settlement for the design life of 

the liquefaction facility. 

The overall effect of the project on topography and geology would be minor. The primary 

impacts would be limited to construction activities and would include disturbance of slopes within the 

work areas. Such impacts resulting from grading and trenching along the pipeline rights-of-way would be 

temporary because Trunkline would restore these areas to preconstruction contours to the maximum 

extent practicable. However, impacts at the liquefaction facility and other aboveground facilities would 

be permanent where grading and filling is required to create a safe and stable land surface to support the 

facilities. In addition, the ACWs required for construction of the liquefaction facilities would not be 

restored to preconstruction contours following construction. 

Utilization of the HDD method would eliminate surface impacts on existing geologic conditions 

between the HDD entry and exit points at the locations where this method is used. Trunkline has not yet 

conducted its planned geotechnical surveys for the proposed HDD crossings to evaluate the suitability of 

the geologic materials, but proposes to conduct these investigations within 1 year prior to construction of 

the proposed pipelines. Therefore, we are recommending that, prior to construction, Trunkline file the 

geotechnical investigations, which are necessary to evaluate the performance of the proposed HDD 

crossings. 

The design of the liquefaction facility is currently at the FEED level of completion. Lake Charles 

LNG has proposed a feasible design and committed to conducting a significant amount of detailed design 

work for the project if it is authorized by the Commission. Information regarding the development of the 

final design would need to be reviewed by FERC staff in order to ensure that the final design addresses 

the requirements identified in the FEED. Therefore, we are recommending that Lake Charles LNG file 

site preparation drawings and specifications; LNG liquefaction facility structures and foundation design 

drawings and calculations; and quality control procedures to be used for civil/structural design and 

construction on a schedule to be identified in its Implementation Plan. 

We do not anticipate that any blasting would be required for the construction of the project 

facilities. Based on the above discussion, in consideration of Trunkline’s and Lake Charles LNG’s

proposed mitigation and design criteria, and based on our recommendations, we conclude that the project

would not significantly impact or be impacted by geological conditions in the area.

5.1.2 Soils

Construction of the project could affect soil resources by increasing the potential for erosion, 

compaction, and rutting. Based on the soil properties reviewed, none of the soils in the Lake Charles 

Liquefaction Project area are considered highly susceptible to erosion by wind or water. Due to the fine 

textured soils and nearly level topography in the project area, no revegetation concerns were identified. 

However, the majority of the soils in the project area are prone to compaction. About 953.6 acres of soils 

affected by the project are designated as prime farmland. Of these soils, 300.7 acres would be 

permanently converted to urban land for operation of the liquefaction facility and Trunkline’s 

aboveground facilities, and 276.3 acres of prime farmland in the ACWs would be permanently affected

due to the deposition of fill. The remaining 376.6 acres of prime farmland soils would be restored to 

preconstruction conditions and are anticipated to retain their former productivity. 
5-3

As agreed upon by the landowner, Lake Charles LNG would not restore the ACWs to 

preconstruction condition, but would stabilize the ACWs with gravel or herbaceous vegetation, and install 

additional temporary or permanent erosion control devices to prevent off-site erosion and sedimentation. 

To ensure that the ACWs are adequately stabilized and to ensure that runoff does not result in impacts on 

surrounding areas, we are recommending that, prior to construction, Lake Charles LNG file final design 

plans for the ACWs. The recommended plan should detail how each ACW would be stabilized after 

construction is complete, and any planned mitigation to address altered drainage patterns resulting from 

the modified elevation and clearing of these sites.

Contamination from spills or leaks of fuels, lubricants, and coolant from construction equipment 

could also adversely affect soils. Lake Charles LNG and Trunkline would employ the mitigation

measures included in the SPAR Plan and project-specific SPCC Plans, which would specify cleanup 

procedures to minimize the potential for soil contamination from such spills or leaks. Lake Charles LNG 

and Trunkline have not updated the SPAR plan to include project-specific emergency contacts and local 

authorities. Additionally, the project-specific SPCC Plan(s) is not yet available because it would be 

prepared by the construction contractor(s). Therefore, we are recommending that Lake Charles LNG and 

Trunkline file copies of an updated SPAR Plan and the project-specific SPCC Plan(s) prior to 

construction.

One hazardous waste site is located at the Lake Charles Carbon Company facility just west of the 

liquefaction facility site. The results of soil sampling performed along the western boundary of the LNG 

terminal site indicated the presence, in a number of soil samples, of PAHs and PCBs above the LDEQ’s 

industrial site standards. Excavated contaminated material would be managed in accordance with 

applicable regulations and in coordination with Alcoa (the current owner of the contaminated site). If 

previously unidentified contaminants are encountered during construction, Lake Charles LNG and 

Trunkline would follow the steps in their Plan for Unanticipated Discovery of Contaminated Soils or 

Groundwater, which specifies measures to ensure that contaminated material is managed in accordance 

with state and federal regulations.

Lake Charles LNG and Trunkline would implement the mitigation measures contained in the 

FERC Plan and Procedures and other project-specific plans to control erosion, enhance successful 

revegetation, and minimize any potential adverse impacts on soil resources. In addition, disturbed areas 

would be monitored following construction for the first and second (as necessary) growing seasons in 

upland areas and at least 3 years in wetlands to ensure successful restoration. With implementation of the 

proposed mitigation measures and project-specific plans, and with our additional recommendations, we 

conclude that impacts on soil resources would be adequately minimized.

5.1.3 Water Resources

The majority of the Lake Charles Liquefaction Project facilities are underlain by the Chicot 

aquifer, which is an EPA-designated sole-source aquifer. We do not anticipate any long-term or 

significant impacts on the aquifer due to construction or operation of the project. Some of the NonLiquefaction Facilities are underlain by the Mississippi River Valley alluvial aquifer system, which is not 

designated as a sole-source aquifer. 

There are eight active water wells within 150 feet of the project, including six domestic supply 

wells near or within the footprint of the proposed liquefaction facility and/or ACWs, one domestic supply 

well near the proposed contractor yard, and one rural public supply well within the footprint of the 

Pollock Compressor Station. Lake Charles LNG and Trunkline propose to conduct pre- and postconstruction monitoring of well yield and water quality for all water supply wells located within 150 feet 

of construction activities. If the project results in adverse impacts, Lake Charles LNG or Trunkline would 
5-4

provide a temporary source of water to those affected and repair or replace the affected water wells. To 

document any project impacts on water wells and verify that they are appropriately addressed, we are 

recommending that, within 30 days of placing facilities in service, Lake Charles LNG and Trunkline file a 

report identifying all public or private water supply wells/systems damaged by construction and how they 

were repaired. The report should also include a discussion of any other complaints concerning well yield 

or water quality and how each problem was resolved. 

During construction and operation of the liquefaction facility, Lake Charles LNG would 

withdraw water for hydrostatic testing of new piping systems, construction personnel sanitation, and other 

general utility uses from two existing on-site wells and two proposed new wells on the liquefaction 

facility property. Lake Charles LNG estimates that about 45 million gallons of water would be 

withdrawn from the Chicot aquifer during construction at typical flow rates of 56 gpm and peak 

consumption of about 166 gpm. These withdrawal rates would be negligible relative to the more than 

10 million gpm that are currently withdrawn from the Chicot aquifer. During operation of the facilities, 

potable water for employees, utility/service water, and process water would be supplied from the local 

municipal system and the two new wells on the liquefaction facility property. Lake Charles LNG would 

coordinate with the City of Lake Charles and other developers as needed to assure that the local water 

supply systems can provide adequate supply.

Water used during construction of the Non-Liquefaction Facilities (e.g., for hydrostatic testing, 

HDD drilling mud, and dust control) would be from both municipal and surface water sources. A water 

well would be installed at Compressor Station 203-A for non-potable water. Trunkline would not require 

any potable water sources at Compressor Station 203-A or the other Non-Liquefaction Facilities. 

The installation of piles for the liquefaction facilities, which are anticipated to be driven to a 

depth of 70 feet, is not expected to have direct impacts on the underlying aquifer, which is about 200 feet 

below the surface. Other construction activities are not likely to significantly affect groundwater 

resources because the majority of construction would involve shallow, temporary, and localized 

excavation. Lake Charles LNG and Trunkline would use specialized construction techniques such as 

sheet piling and earthen berms to control surficial water flow and infiltration, and well pointing and/or 

pit-to-pit dewatering techniques to temporarily lower the water table in the immediate area during 

trenching and backfilling. Spills or leaks of hazardous materials (e.g., fuel, lubricants) from equipment 

working in the onshore areas could also result in adverse impacts on water resources. However, with the 

implementation of the measures in the FERC Plan and Procedures, SPAR Plan, SPCC Plan(s), impacts on

groundwater resources from construction and spills/leaks would be minimized to the extent possible.

The Industrial Canal/Turning Basin has been designated as EFH and a Navigable Waterway 

under section 10 of the Rivers and Harbors Act. The primary impacts on water quality within this area 

would be associated with dredging and the associated suspension of sediments in the water column. Lake 

Charles LNG proposes to use a hydraulic dredge with a suction cutter head, which would minimize

turbidity and water quality impacts. Additionally, any effects would be minor since they would be 

temporary and limited to the immediate area. Information in recent sampling plans prepared by Tetra 

Tech, Inc. on behalf of Alcoa indicates that sediments within the Industrial Canal/Turning Basin contain 

contaminants associated with historical operations of Reynolds’ Lake Charles Carbon Company (owned 

by Alcoa). Sediment samples were collected and analyzed in accordance with the LDEQ RECAP 

methods, and affected sediments were fully delineated. Reynolds is in the process of dredging and 

disposing of affected sediments at certain locations in the proposed project dock work area as part of a 

remediation effort approved by the LDEQ. Removal of the affected sediment was initiated in March 

2015 and is anticipated to be completed prior to any project construction activities. Therefore, 

contaminated sediments that might otherwise have been disturbed during project activities will be

removed by the time construction of the proposed project begins. Additionally, Lake Charles LNG would 
5-5

be required to implement the measures incorporated into its COE permit, including any special 

requirements/procedures for handling contaminated sediments, if such measures remain necessary. 

Fifteen unnamed waterbodies are present within the liquefaction facility site. Fourteen of the 

waterbodies would be filled during construction of the liquefaction facility, and one perennial waterbody 

would be armored and realigned. Impacts on these surface waters would be mitigated through 

implementation of Lake Charles LNG’s and Trunkline’s final Compensatory Mitigation Plan. During 

construction, land disturbance and vegetation removal could increase stormwater discharges to surface 

waters at and adjacent to the liquefaction facility, resulting in a temporary increase in suspended sediment 

levels. Operation of the liquefaction facility would increase the amount of impervious surface area at the 

site, which would result in an increased volume of stormwater runoff. Stormwater would be managed in 

accordance with LDEQ and EPA requirements. Therefore, we conclude that impacts from stormwater 

runoff would not be significant.

During construction of the project, barges and support vessels would deliver large equipment and 

materials to the TCDs. This traffic may increase shoreline erosion and temporarily increase turbidity 

levels within the Industrial Canal/Turning Basin and along vessel transit routes. The Calcasieu Ship 

Channel was specifically created to provide deepwater access for maritime commerce. It is managed by 

the Port of Lake Charles, a deepwater seaport, and is maintained by regular dredging. As such, use of the 

channel by barges and support vessels to deliver materials during construction of the liquefaction facility 

would be consistent with the planned purpose and use of this active shipping channel, and associated 

impacts on water quality within the channel would be minor. 

Lake Charles LNG is not proposing to change the frequency or size of LNG carriers that would 

call on the LNG terminal. However, operation of the LNG terminal as an export facility rather than an 

import facility would require that LNG carriers discharge ballast water (for LNG loading) rather than take 

on ballast water (for offloading of LNG). To ensure compliance with U.S. laws and regulations 

governing ballast water discharges, Lake Charles LNG would review applicable documentation that the 

visiting LNG carrier’s operation is in accordance with the federal standards and practices. Therefore, we 

conclude that significant impacts on surface waters would not occur as a result of ballast water 

discharges.

A total of 104 waterbodies, including 16 perennial, 12 intermittent, 8 ephemeral, 4 open water 

(pond), and 64 agricultural ditches and canals would be crossed or otherwise affected (e.g., matted) by 

construction of the Non-Liquefaction Facilities. The Calcasieu River is designated as an Outstanding 

Natural Resource Water by LDEQ, a Louisiana Natural and Scenic River by LDWF, and a Navigable 

Waterway under section 10 of the Rivers and Harbors Act. The segment of the Calcasieu River crossed 

by the project, as well as Bayou Lacassine, is listed on the 303(d) list. None of the waterbodies impacted 

by the Non-Liquefaction Facilities are listed as National Wild and Scenic Rivers, designated as EFH, or 

contain federally or state-listed species.

Trunkline proposes to conduct six HDD operations that would avoid impacts on a total of 

22 waterbodies, including the Calcasieu River, and East Bayou Lacassine. The remaining waterbodies 

would be crossed by the open-cut method. Trunkline provided site-specific plan and profile drawings for 

the proposed HDD crossings with its application; however, some of the HDD crossing designs were 

subsequently modified to reduce impacts on wetlands. Therefore, we are recommending that Trunkline

file the final HDD plan and profile drawings prior to construction. Four drainage canals and one 

agricultural ditch would be permanently filled during construction of Compressor Station 203-A. To 

minimize surface water impacts, Trunkline would implement the construction and mitigation measures 

described in the FERC Procedures except where we have determined that Trunkline provided sufficient

site-specific alternative measures. In addition, the use of the HDD method would eliminate or 
5-6

significantly reduce the potential for construction-related impacts because the HDD method avoids 

disturbance of the stream beds, banks, and associated riparian vegetation. Trunkline would finalize an 

HDD Contingency Plan with the selected contractor; therefore, we are recommending that the finalized 

plan be filed for review and approval by the Director of OEP.

With implementation of the HDD method, final Compensatory Mitigation Plan, site-specific 

SWPPPs, FERC Procedures, other project-specific plans, and the additional mitigation measures included 

in the EIS, we conclude that impacts on water resources would be adequately minimized.

5.1.4 Wetlands 

Construction of the liquefaction facility would result in the permanent loss of 215.4 acres of 

wetlands. The wetlands located within the liquefaction facility site would be permanently filled and 

converted to upland industrial land. Wetlands within ACWs would be filled, elevated, and converted to 

industrial use for the 5-year construction period, and would not be restored following construction per the 

landowners’ request. The majority of the wetlands affected would be forested wetlands or forested 

wetland mosaics (pimple-mounds). Lake Charles LNG would be required to mitigate wetland impacts 

associated with construction and operation of the project, and conversion of the ACW wetlands, as part of 

its project-specific Compensatory Mitigation Plan.

Construction of the Non-Liquefaction Facilities would affect a total of 37.9 acres of wetlands, the 

majority of which (35.6 acres) would be a result of pipeline construction, with the remainder being

associated with construction or modification of six meter stations. About 6.5 acres of wetland would be 

affected during operation of the pipeline and meter stations, including 6.0 acres located within the 

permanent pipeline easement that would not be permanently filled or drained, and 0.5 acre that would be 

permanently converted to upland industrial land during meter station site preparation activities. Trunkline

would minimize wetland impacts by collocating the 6.5-mile Mainline 200-3 Loop, placing temporary 

workspaces associated with the Calcasieu River HDD within the existing permanent easement for 

Mainline 200-1, and implementing the HDD method for installation of the pipelines beneath several

wetlands. Additionally, Trunkline revised its plans for the Mainline Connector to reduce wetland impacts 

and reconfigured the layout of Compressor Station 203-A to avoid a wetland present within the southeast 

corner of the site. 

Trunkline would reduce impacts on wetland areas by implementing the Procedures, except where 

it has justified alternative measures. In addition, Lake Charles LNG and Trunkline would be required to 

mitigate wetland impacts associated with construction and operation of the project as part of their projectspecific Compensatory Mitigation Plan. Lake Charles LNG and Trunkline filed their section 404 permit 

application with the COE on August 6, 2014, and submitted a proposed permittee responsible mitigation 

plan to the COE on May 29, 2015. They also proposed to use approved mitigation bank credits to 

compensate for some of the project-related impacts. The COE has not yet provided approval of the 

proposed plan. Therefore, we are recommending that Lake Charles LNG and Trunkline file a copy of the 

final Compensatory Mitigation Plan and documentation of COE approval of the plan prior to 

construction. 

Our Procedures state that the width of the construction right-of-way should be limited to 75 feet or 

less in wetlands. Trunkline has proposed a right-of-way width of 100 feet in nine wetlands that would be 

crossed by the Mainline Connector. We determined that these proposed deviations are reasonable for 

eight of the locations, but recommended in the draft EIS that Trunkline evaluate the feasibility of moving 

the Little Bayou HDD entry point to the northeast beyond the boundary of a forested wetland. Based on 

the evaluation Trunkline provided in response to this recommendation, we agree that the initially 

proposed design is adequately justified. Trunkline has also proposed alternative measures to our 
5-7

Procedures to place certain ATWS and aboveground facilities within wetlands. We conclude that the 

alternative measures are adequately justified.

With the implementation of the FERC Procedures, proposed mitigation measures discussed in 

this EIS, and our recommendations, we conclude that impacts on the majority of wetlands due to 

construction and operation of the Non-Liquefaction Facilities would be minor. While the construction of 

the liquefaction facility would result in the loss of a large portion of the forested wetlands in the 

immediate area, Lake Charles LNG would mitigate these impacts through the implementation of the 

project-specific Compensatory Mitigation Plan.

5.1.5 Vegetation

A total of 568.3 acres of vegetation would be cleared during construction of the liquefaction 

facility, including the ACWs. Of this, 245.4 acres would be permanently converted to industrial use for 

operation of the liquefaction facility. The 322.9 acres of vegetated areas within the ACWs would also be 

permanently affected because they would not be restored to preconstruction conditions. In total,

construction and operation of the liquefaction facility, including the ACWs, would result in the loss or 

conversion of 261.7 acres of forested uplands, 158.6 acres of forested wetlands, 56.9 acres of non-forested 

wetlands, and 91.1 acres of herbaceous upland. Although impacts on herbaceous upland vegetation 

affected by the liquefaction facility would be permanent, similar vegetative communities occur within the 

surrounding area. Therefore, impacts on herbaceous upland vegetation communities would not be 

significant. Additional forested communities are located in the project vicinity, but construction of the 

project would result in the loss of a large portion of upland and wetland forested communities in the 

immediate area. Impacts on wetland vegetation would be mitigated to less than significant levels through 

the implementation of Lake Charles LNG’s Compensatory Mitigation Plan. However, the construction 

and operation of the liquefaction facility and the permanent conversion of the ACWs would result in the 

unmitigated loss of 261.7 acres of upland forest.

Construction of the Non-Liquefaction Facilities would affect about 375.8 acres of vegetation, 

including 275.8 acres for the pipelines, and 100.0 acres for aboveground facilities and Mainline 200-1 

modifications. Vegetation communities affected would include agricultural vegetation, pine plantation, 

forested wetland and inundated forest, non-forested wetland, herbaceous upland, and upland forest. The 

primary impacts on vegetation from construction of the Non-Liquefaction Facilities would be the cutting, 

clearing, and/or removal of existing vegetation within the construction work areas. Impacts resulting 

from operation of the facilities would include conversion of some forested or scrub-shrub vegetation to 

herbaceous vegetation due to maintenance of the pipeline rights-of-way, and conversion of vegetation 

within new or expanded aboveground facilities to non-vegetated industrial land. Impacts on agricultural, 

scrub-shrub, and herbaceous vegetation within the pipeline rights-of-way and ATWSs would be 

temporary and relatively short term because we would expect these areas to revegetate to a cover similar 

to preconstruction conditions within one to two growing seasons. 

The project would affect two vegetation communities of special concern in Louisiana, including 

Bayhead Swamp and Bottomland Hardwood Forest. A total of 4.5 acres of Bayhead Swamp would be 

located within the pipeline easements; of this, 2.7 acres would be permanently converted to emergent 

wetland to facilitate pipeline inspections and maintenance, the remaining 1.8 acres would be allowed to 

naturally revegetate. Trunkline would minimize impacts on Bayhead Swamp communities by using the 

HDD method to install the pipelines beneath the potential communities adjacent to Bayou Lacassine and 

Arceneaux Bayou. Bottomland Hardwood Forest communities occupy a total of 29.6 acres within the 

liquefaction facility site, along the Mainline Connector, and at three meter stations. Of this, 22.8 acres 

would be permanently converted to industrial use, 1.7 acres would be converted to emergent wetland due 
5-8

to routine maintenance of the pipeline right-of-way, and the remaining 5.1 acres would be allowed to 

revegetate to pre-existing conditions.

To minimize impacts on vegetative communities during and after construction of the NonLiquefaction Facilities, Trunkline would conduct much of the work within or adjacent to existing 

maintained rights-of-way and facility sites. Additionally, Trunkline would install erosion control 

measures and revegetate temporary workspaces in accordance with our Plan and Procedures, and would 

monitor disturbed areas until restoration and revegetation are successful. With the implementation of the 

proposed mitigation measures, we conclude that construction and operation of the Non-Liquefaction 

Facilities would not have a significant impact on vegetation communities in the project area. 

Field surveys identified Chinese tallow, a noxious weed, within project areas associated with both 

the liquefaction facility and Non-Liquefaction Facilities. Additionally, two nuisance species, Chinese 

privet and Japanese climbing fern, were identified along the Mainline Connector route. As part of their 

post-construction monitoring programs, Lake Charles LNG and Trunkline would be required to examine 

the project area for the presence of invasive species within the project area. In addition, our Plan and 

Procedures require coordination with the appropriate land management and/or state agencies to prevent 

the introduction or spread of invasive species, noxious weeds, and soil pests. Lake Charles LNG and 

Trunkline have not proposed measures to be implemented during construction and operation of the project 

to control the spread of noxious weeds; therefore, we are recommending that they coordinate with the 

NRCS and LDWF to develop a project-specific noxious weed control plan to be filed with the FERC 

prior to construction.

5.1.6 Wildlife and Aquatic Resources

Wildlife

Wildlife species inhabiting the project area are characteristic of the habitats provided by the 

vegetation communities that occur in the vicinity of the project. The greatest impact on wildlife habitat 

would result from the permanent conversion of forested land within the liquefaction facility site and 

ACWs, which would result in a permanent reduction in forested habitat in the general vicinity of the 

liquefaction facility, where the surrounding area is largely composed of developed, open, and agricultural 

lands. Lake Charles LNG would provide compensatory mitigation for permanent impacts on about

158.6 acres of forested wetland that would be permanently converted to upland. Although the 

implementation of these and other proposed mitigation measures would lessen impacts on wildlife 

species, we have determined that construction and operation of the proposed liquefaction facility, and the 

permanent conversion of the ACWs, would have long-term impacts on wildlife species due to the loss of 

forested habitat.

Operation of the liquefaction facility would result in increased noise, lighting, and human activity 

that could disturb wildlife in the area. However, due to current industrial activities at the existing LNG 

terminal and other industrial facilities in the vicinity, most wildlife in the area are acclimated to the noise 

and artificial lighting associated with these activities. Therefore, we expect impacts due to noise, light, 

and human activity during operation of the liquefaction facility to be negligible. Birds could also be 

affected by flaring at the liquefaction terminal. Flaring would be required during startup of the 

liquefaction facility, which may require up to 1 month for each liquefaction train. During operation, use 

of the marine and emergency flares would only occur occasionally. The FWS has not raised flaring as an 

issue of concern in the area and we are not aware of any reported significant impacts of flaring on 

migratory birds in the project area. As a result, we find that the temporary flaring during construction and 

the occasional flaring during operation would not represent a significant impact on migratory birds 

passing through the area.
5-9

Construction of the Non-Liquefaction Facilities would affect 375.8 acres of vegetated wildlife 

habitat, the majority of which would be associated with construction of the proposed pipeline facilities 

and construction and operation of the new and expanded aboveground facilities. Although individuals of 

some wildlife species would be affected by construction and operation of the proposed pipelines and

aboveground facilities, most impacts on wildlife would be short term and limited predominantly to the 

construction period. During operation of the proposed pipeline facilities, Trunkline would not conduct 

routine vegetation mowing or clearing over the full width of the permanent rights-of-way in uplands more 

frequently than every 3 years, and routine vegetation mowing or clearing would not occur during the 

majority of the migratory bird nesting season between April 15 and August 1 unless specifically approved 

in writing by the FWS. With the implementation of our Plan and Procedures, and due to the fact that 

abundant similar habitat is available for wildlife adjacent to the affected areas, we conclude that 

construction and operation of the Non-Liquefaction Facilities would not have a significant impact on local 

wildlife populations or habitat.

The vegetative communities in the project area provide potential habitat for migratory bird 

species, including songbirds, waterbirds, and raptors. Much of the vegetated land associated with the 

Non-Liquefaction Facilities is previously disturbed and/or currently maintained by mowing and other land 

management practices that reduce nesting habitat value. However, the undisturbed areas contain higher 

quality nesting habitat which would be more attractive to breeding bird species. The FWS commented 

that the liquefaction facility site, which is mostly mature mixed pine hardwoods, is expected to provide 

nesting habitat for bird species of concern. Lake Charles LNG’s compensatory mitigation would offset 

some of this habitat loss. Additionally, to minimize impacts from vegetation clearing on migratory birds, 

the FWS recommended that no habitat alteration work be performed during the nesting period (March 1 

to July 31). Lake Charles LNG and Trunkline have affirmed that all clearing of forested areas would be 

conducted outside of the specified migratory bird nesting season and that, if the construction schedule 

changes such that clearing during migratory bird nesting season is necessary, Lake Charles LNG and 

Trunkline would obtain written approval from the FWS, prior to clearing. If clearing during the bird 

nesting season is necessary in non-forested areas, we are recommending that Lake Charles LNG and 

Trunkline consult with the FWS and file with the Secretary written documentation of FWS approval prior 

to construction in those areas.

During coordination with Trunkline, the LDWF identified records of two colonial waterbird 

nesting areas (or rookeries) within 1 mile of proposed workspaces associated with the Mainline 200-3 

Loop and the NGPL–Lakeside meter station. The LDWF stated that a field visit should be conducted no 

more than 2 weeks prior to commencing construction if construction would commence during nesting 

season. If the field visit identifies nesting colonies within 400 meters (700 meters for brown pelicans) of 

the project, a survey should be performed to document the species present and the extent of the colonies, 

and further consultation with the LDWF should be conducted. The LDWF also provided specific distance 

and timing restrictions to be observed to minimize disturbance of colonial nesting birds depending on the 

species present. The FWS also recommended that Lake Charles LNG and Trunkline contact the FWS and 

LDWF if surveys identify undocumented rookeries during nesting season, and stated that activities within 

1,000 feet of a rookery should be restricted to non-nesting season. No rookeries were identified within 

the project area during environmental field surveys conducted during 2012, 2013, and 2014. Trunkline

and Lake Charles LNG have stated that wading birds are the most likely species to occur in the area and 

that, if construction of the Mainline 200-3 Loop or the NGPL-Lakeside Meter Station would commence 

between February 16 and August 31, Trunkline would conduct a field visit within 2 weeks prior to 

starting construction and would consult with the FWS and LDWF if nesting colonies are found within 

300 meters. To ensure that the FWS and LDWF recommendations are fully implemented, we are 

recommending that, prior to construction of the Mainline 200-3 Loop and the NGPL-Lakeside Meter 

Station, Trunkline provide documentation that the FWS and LDWF are in agreement with Trunkline’s 

proposed approach for addressing colonial waterbirds, including a description of the final agreed-upon 
5-10

mitigation measures that Trunkline would implement if construction of these facilities would occur during 

the colonial waterbird nesting seasons identified by the FWS and LDWF.

With our recommendations and the implementation of the measures recommended by the FWS 

and LDWF, we conclude that impacts on migratory birds, including colonial waterbirds, would be 

avoided or minimized.

Aquatic Resources

All waterbodies within the project area support warmwater fisheries and, with the exception of 

the Industrial Canal/Turning Basin, which is estuarine, all waterbodies in the project area are freshwater. 

Of the waterbodies located within the liquefaction facility site, only the Industrial Canal/Turning Basin 

and the one perennial stream provide year-round habitat for aquatic resources. Potential impacts on 

aquatic resources during construction and operation of the liquefaction facility primarily include those 

associated with the two TCDs and berthing dock modifications. The proposed waterbody modifications 

and water withdrawals within the liquefaction facility area, ballast water exchanges, inadvertent spills, 

and barge traffic could also affect aquatic resources; however, with the implementation of the proposed 

mitigation measures, these impacts are expected to be minimal.

Construction of the two TCDs and berthing dock modifications would require dredging a 

22.1-acre area in the Industrial Canal/Turning Basin, driving sheet piles, and installation of the docks’ 

surface features and berthing structure modifications. Potential impacts on aquatic resources due to these 

activities include increased sedimentation, turbidity, and noise levels. These impacts can adversely affect 

fish eggs and juvenile fish survival, benthic community diversity and health, foraging success, and 

suitability of spawning habitat. Impacts on aquatic resources due to increased turbidity and suspended 

solid levels would vary by species. Most fish species are highly mobile and would be expected to leave 

the project area during in- and over-water activities. However, dredging would result in direct mortality 

of benthic organisms such as mollusks and crustaceans within the dredge footprint, and might also affect 

slower, less mobile benthic invertebrates. The aquatic resources present within the project area are likely 

accustomed to regular fluctuations in noise and turbidity levels from industrial activity and regular 

maintenance dredging within the existing Industrial Canal/Turning Basin. Following construction 

activities, aquatic resources would be expected to return to the newly dredged area, which would be 

similar to the existing habitat, but would have an increased water depth. Further, Lake Charles LNG

would use a cutter head suction dredge, which would minimize resuspension of sediments and the 

resulting increases in turbidity and suspended sediment levels. Due to the small volume of materials 

being dredged (about 26,000 cubic yards), short duration of dredging activities (30 days), and limited 

deepening of the existing open water habitat, we have determined impacts on aquatic resources from 

dredging would be localized, temporary, and minor.

Sound waves from pile driving may result in injury or trauma to fish, sea turtles, and other 

animals with gas-filled cavities, such as swim bladders, lungs, sinuses, and hearing structures. In order to 

allow for an accurate analysis of potential impacts on aquatic resources during pile driving, we are 

recommending that, prior to construction, Lake Charles LNG file a description of the proposed in-water 

pile installation process including the number and type of pile driver(s), duration of in-water pile driving 

activities, and anticipated peak and cumulative underwater sound pressure levels, and that Lake Charles 

LNG propose mitigation measures if the peak or cumulative noise levels would exceed the thresholds for 

injury to fish identified in NOAA Fisheries’ interim guidelines.

Construction of the proposed pipeline facilities would require crossing 16 perennial streams and 

4 ponds that provide suitable habitat for aquatic resources. As noted previously, Trunkline proposes to 

use the HDD method to cross several of these waterbodies, which would avoid or minimize impacts on 
5-11

fisheries, fish habitat, and other aquatic resources within and adjacent to waterbodies unless an 

inadvertent release of drilling mud were to occur. If an inadvertent release occurs, Trunkline would 

implement the measures outlined in its Horizontal Directional Drill Contingency Plan to minimize 

potential impacts on aquatic resources.

Use of the open-cut crossing method would result in temporary loss or modification of aquatic 

habitat, increase in sedimentation and turbidity levels, and alteration of riparian vegetative cover. The 

majority of fish present within the waterbody at the time of construction activities would likely be 

displaced to similar adjacent habitats up or down stream; however, stress, injury, or death of individual 

fish may occur. Increased suspended sediment and turbidity levels may also cause degradation of benthic 

and spawning habitat and decreased dissolved oxygen levels within and downstream of the crossing 

location. This temporary increase in suspended solids would decrease rapidly following the completion 

of instream activities. The clearing of riparian vegetation during construction may reduce shade, 

indirectly causing a temporary increase in water temperature in localized areas. Clearing would be 

adjacent to existing rights-of-way at the three open-cut perennial waterbody crossings along the Mainline 

200-3 Loop, which would minimize changes in water temperature because much of the vegetation is 

already maintained in an herbaceous state. Operation of the pipeline facilities would not affect aquatic 

resources. Due to the relatively small number of crossings, limited construction workspace and duration, 

and implementation of the proposed mitigation measures, we anticipate that construction and operation of

the Non-Liquefaction Facilities would have minimal and localized impacts on aquatic resources.

As a non-federal party assisting the FERC in meeting its obligations under the MSA, Lake 

Charles LNG coordinated with NOAA Fisheries’ regarding potential project impacts on EFH. NOAA 

Fisheries concurred with the determination that the dock work and related activity in the vicinity of the 

Industrial Canal/Turning Basin would not result in significant adverse impact on EFH. Based on the 

largely temporary nature of project-related impacts and concurrence from NOAA Fisheries’ Southeast 

Regional Office, we have determined that the project would not have a significant adverse impact on 

EFH. We requested that NOAA Fisheries consider the draft EIS as our EFH Assessment. In a letter 

dated May 21, 2015, NOAA Fisheries concurred with our determination and confirmed that no further 

EFH consultation is required.

5.1.7 Threatened, Endangered, and Other Special Status Species 

Based on input from the FWS and NOAA Fisheries, 23 federally listed threatened and 

endangered species, 2 species that are candidates for listing under the ESA, and 1 species proposed for 

listing under the ESA may occur within the parishes and/or counties affected by the project. In addition, 

critical habitat has been designated for the Louisiana black bear in Richland and West Carroll Parishes, 

Louisiana. The FWS confirmed that the proposed project activities within Trunkline’s existing facilities 

and easements in Louisiana would be covered under Trunkline’s existing Blanket Clearance (dated 

January 9, 2014). With certain conditions, the existing Blanket Clearance authorizes Trunkline to 

perform minor and routine pipeline construction and maintenance activities under the FERC’s jurisdiction 

within the State of Louisiana.

We determined that the project would have no effect on 22 of the 23 federally listed species, is 

not likely to cause the jeopardy of the 1 proposed species, and would not contribute to the trend toward 

federal listing for the 2 candidate species. No designated critical habitat for the Louisiana black bear is 

within or adjacent to the project area. One federally listed endangered species, the red-cockaded 

woodpecker, has the potential to be located in the Kisatchie National Forest, 0.1 mile southwest of the 

Pollock Compressor Station. In a letter dated March 31, 2014, the FWS concurred that by adhering to the 

stipulations in Trunkline’s Blanket Clearance for work at the Pollock Compressor Station, the project is 

not likely to adversely affect the red-cockaded woodpecker. Therefore, we have determined that the 
5-12

project may affect, but is not likely to adversely affect the red-cockaded woodpecker. However, because 

the Blanket Clearance only covers activities conducted in 2014, and to ensure that the stipulations do not 

materially change by the time the project goes to construction, we are recommending that, prior to 

construction, Trunkline file an updated Blanket Clearance or updated documentation from the FWS that 

the previous determinations of effect are still current.

As required by Section 7 of the ESA, we requested that the FWS accept the information provided 

in the draft EIS as the BA for the project, and we requested concurrence with our findings of effect for 

federally listed species. The FWS concurred with our findings on July 16, 2015; therefore, consultation 

between the FERC and the FWS is concluded. The project would have no effect on listed species under 

the jurisdiction of NOAA Fisheries; therefore, no formal section 7 consultation between the FERC and 

NOAA Fisheries is required.

Based on information obtained from the appropriate Louisiana, Mississippi, and Arkansas state 

agencies, seven state-listed threatened or endangered species and one candidate species are listed within 

the parishes/counties affected by the project. Six of the eight state-listed species are also federally listed 

or candidate species. The project is expected to have no impact on one of the two non-federally listed 

species (brown pelican) due to the absence of suitable habitat within the project area. The bald eagle is 

state-listed as endangered in Louisiana within several parishes crossed by the project; however, no bald 

eagles or bald eagle nests were identified during field surveys conducted in September 2012 and March 

through May 2013. Because no nesting sites were observed during field surveys, and the HDD method 

would be used to minimize potential impacts, we have determined the project would not significantly 

impact the bald eagle. In the event a bald eagle or its nest is identified within 660 feet of a project area 

prior to construction, Lake Charles LNG and Trunkline have agreed to notify the FWS and LDWF in 

accordance with the National Bald Eagle Management Guidelines. 

5.1.8 Land Use, Recreation, and Visual Resources

Construction of the project would affect a total of 1,516.3 acres. Operation of the new and 

expanded facilities would require 439.5 acres of new permanent right-of-way and aboveground facility 

area. The operational land requirements would also include 402.4 acres of existing aboveground facilities 

to be modified and existing Trunkline pipeline easement that would be overlapped by the Mainline 200-3 

Loop. Of the remaining 674.4 acres, 349.2 acres would be allowed to revert to preconstruction land use 

type. The other 325.2 acres consist of the ACWs that would not be retained following construction, but 

would not be restored to preconstruction condition in accordance with landowner agreements.

The new liquefaction facility would be constructed on a 285.9-acre site located immediately 

adjacent to and north of the existing LNG terminal. The majority of the proposed liquefaction facility site 

is forest land, followed by open land, industrial/commercial land, and open water. Lake Charles LNG

would convert the entire liquefaction facility site to industrial use. The ACWs required during 

construction are mainly composed of forest land and open land (including forested, scrub-shrub, and 

emergent wetlands), and industrial/commercial land. Lake Charles LNG currently leases 46 acres within 

the proposed liquefaction facility site from the Lake Charles Port Authority, and plans to acquire 80 acres 

of land within the liquefaction facility site from Alcoa. The remainder of the land required for the 

liquefaction facility and ACWs would be leased from the Lake Charles Port Authority. All work at the 

existing LNG terminal would occur within the existing facility. Aside from the Lake Charles Port 

Authority properties, no federal, state, or local agency owned or managed lands would be directly affected 

by the liquefaction facility. 

Construction of the Non-Liquefaction Facilities would affect a total of about 731.3 acres of land 

and open water. In addition to the 250.6 acres of land that are already within the operational boundaries 
5-13

of existing Trunkline facilities to be modified or used temporarily for construction, operation of the new 

and modified Non-Liquefaction Facilities would require 153.6 acres of newly affected land. The lands 

necessary for construction and operation of the Non-Liquefaction Facilities would be composed of both 

land currently owned or leased by Trunkline and other private land.

The proposed Mainline Connector would be constructed on newly created right-of-way. The 

predominant land use types affected by construction of the pipeline, including the construction right-ofway and ATWS, would be agricultural, pine plantation, and forest land, followed by open and 

industrial/commercial land, residential land, and open water. The entire Mainline 200-3 Loop would be 

collocated with an existing Trunkline pipeline right-of-way; 25 feet of the permanent right-of-way would 

overlap the existing permanent easement. The predominant land use types affected by construction of the 

Mainline 200-3 Loop, including the construction right-of-way and ATWS, would be agricultural and open 

land, followed by forest, industrial/commercial land, pine plantation, and open water. Following 

construction of the Non-Liquefaction Facilities, Trunkline would follow the restoration and revegetation 

practices outlined in the FERC Plan and Procedures. Most lands affected by the Non-Liquefaction 

Facilities would be allowed to revert to their previous use, except for limited areas of the pipeline rightof-way that would be routinely maintained and land that is converted to industrial use for new or 

expanded aboveground facilities. 

A single residence within the liquefaction facility site has been purchased by Lake Charles LNG; 

no other residential lands would be affected during construction or operation of the proposed liquefaction 

facility. No residential structures or buildings are located within 50 feet of any of the Non-Liquefaction 

Facilities. There are no planned residential or commercial developments within 0.25 mile of the project. 

However, four commercial/industrial facilities are planned within 1 mile of the proposed liquefaction 

facility. Certain non-jurisdictional facilities are also planned to provide utilities (i.e., electric power, 

water) to the Lake Charles Liquefaction Project. 

Construction and operation of the liquefaction facility would result in minor, temporary impacts 

on recreational boating and fishing. Construction-related dust and noise could also be a nuisance to the 

recreational users of two nearby golf courses, but these impacts would be temporary, and Lake Charles 

LNG would implement mitigation measures to minimize them. Construction of the Non-Liquefaction 

Facilities could potentially be noticeable by users of the Lacassine NWR, which is about 0.4 mile from 

the NGPL–Lakeside Meter Station, or the Kisatchie National Forest, which is in proximity to the Pollock 

Compressor Station. However, construction at these locations would be temporary and would occur 

within or immediately adjacent to existing industrial facilities. We find that visitors to the NWR or the 

national forest would not be adversely affected. Trunkline’s use of the HDD method for the Calcasieu 

River crossing would avoid direct surface impacts on this Louisiana Natural and Scenic River and its 

riparian area, and would eliminate the need for in-water work and any resultant disruption of boating. 

Additionally, Trunkline would implement the measures in the FERC Procedures and its HDD 

Contingency Plan to further minimize the extent and duration of construction disturbance on this 

waterbody. With implementation of these measures, we do not find that the natural and scenic 

characteristics of the river would be affected by the project.

Alcoa is currently working with the LDEQ regarding impacts on soil and sediment from historical 

uses of PCBs and other materials at the Alcoa facility east of the proposed liquefaction facility. Lake 

Charles LNG is working closely with Alcoa to determine what contaminants may be encountered during 

construction of the liquefaction facility. Lake Charles LNG would manage and dispose of impacted 

materials in accordance with applicable regulations and in coordination with Alcoa and the LDEQ. 

Should contaminated soils, sediments, or groundwater be encountered unexpectedly during construction, 

Lake Charles LNG would implement its Plan for Unanticipated Discovery of Contaminated Soils or 

Groundwater. In addition, Lake Charles LNG and Trunkline would implement their SPAR and SPCC 
5-14

Plans to minimize potential contamination of soil and water resources from spills or releases of fuel, other 

mechanical fluids, or other hazardous materials.

Construction activities at the proposed liquefaction facility, particularly at ACW A, might be 

visible from residences to the north; however, most of these residences would be visually shielded from 

the construction activity by forest land. Visual impacts would be more significant for the residences east 

of Big Lake Road where there is more open land and fewer forested buffers. Clearing and construction 

activities at ACW D would result in visual impacts on residences north of the ACW along West Lincoln 

Road. Visual impacts on residential areas south of the Industrial Canal along Airhart Road would be 

negligible due to distance and the presence of vegetation. There are no nearby residences west of the 

liquefaction facility site or the existing LNG terminal, but activities may be visible to recreationists using 

the Calcasieu Ship Channel. The impact on visual resources during construction would be due to the 

presence of workers and equipment for the approximately 5-year construction period, but the impacts 

resulting from operation of the facilities would be permanent. To minimize impacts on the surrounding 

visual landscape to the extent feasible, we are recommending that Lake Charles LNG file visual screening 

plans for ACWs A and D prior to the start of construction. Because the liquefaction facility would be 

constructed immediately adjacent to the existing terminal, views of the facility would be consistent with 

the existing industrial area. Additionally, implementation of visual screening plans, as recommended 

above, would minimize impacts. Overall, we conclude that visual impacts of the proposed liquefaction 

facility and LNG terminal modifications would generally be in character with the existing landscape.

In addition to the structures at the liquefaction facility, another potential source of visual impacts 

is the flare system that would be constructed as part of the project. When in use, the flares would be 

visible from varying distances. However, flares would only operate on a limited basis. The startup flare 

would be in use throughout the initial start-up period prior to beginning operation of each liquefaction 

train, and is expected to be used for up to 1 month for each train. The other flares would be used only on 

an emergency basis. Therefore, visual impacts resulting from the flares during operation of the facility 

would be temporary and infrequent.

During construction of the pipelines, visual impacts would result from the presence of personnel, 

large construction equipment, and vehicles, all of which could be visible in areas accessible to the public, 

such as roadways crossed by the route and nearby residences. However, no residences are located within 

50 feet of the construction right-of-way and the pipeline routes do not cross densely populated areas. 

Visual impacts due to the presence of construction equipment and personnel would be temporary and 

short term; therefore, we conclude that those visual impacts would not be significant. The primary impact 

on visual resources during construction and operation of the pipelines would result from vegetation 

clearing in the construction rights-of-way and ATWS. Clearing of forest land within the construction 

right-of-way, and maintenance of the permanent right-of-way in an herbaceous or scrub-shrub state, 

would change the viewscape for viewers in the area. Trunkline would allow forest land in ATWSs to 

revert to preconstruction conditions, but it could take up to 50 years for forest vegetation to reach a 

mature stage, resulting in long-term visual impacts in those areas. The permanent visual impact would be 

most noticeable for the Mainline Connector, which would result in the creation of a new right-of-way. 

Operational impacts along the Mainline 200-3 Loop, where the new right-of-way would overlap an 

existing pipeline right-of-way, would be less evident. Once the disturbed areas are restored and 

revegetated in accordance with the FERC Plan and Procedures, operation of the pipeline would result in 

negligible impacts in open areas, where the permanent right-of-way would largely revert to 

preconstruction condition and use.

Construction at Trunkline’s existing aboveground facilities would result in negligible, short-term 

visual impacts. Construction and operation of Compressor Station 203-A would occur within a rural area 

of Calcasieu Parish off of low-density, two-lane roads. Construction related impacts including the 
5-15

presence of equipment and workers would be temporary and limited to the construction period. The areas 

that would be cleared and graded predominantly consist of agricultural land, which would be converted to 

industrial/commercial land. During both construction and operation, Compressor Station 203-A would be 

visible to motorists passing through the immediate area, and the station would be visible to the few 

nearby residences. To minimize visual impacts of Compressor Station 203-A on nearby residences, 

Trunkline committed to using materials and/or painting the structures at the station to be harmonious with 

the surrounding landscape and infrastructure. The new and expanded meter stations would result in new, 

permanent impacts on visual resources. A fence would be erected around each of the new meter stations 

and the existing fencelines would be expanded at certain existing stations. However, the new and 

expanded meter stations would be in rural areas and would not affect any designated visual resources. 

Therefore, we conclude that these facilities would have a minimal impact on visual resources.

The proposed new Kinder Morgan-Lake Charles Meter Station and the existing NGPL–Lakeside 

Meter Station fall within the coastal zone boundary. In an August 27, 2014 letter, the LDNR Office of 

Coastal Management stated that the proposed work at the NGPL–Lakeside Meter Station would have no 

direct and significant impact on coastal waters and that the Kinder Morgan–Lake Charles Meter Station is 

exempt; therefore, neither facility would require a CUP.

5.1.9 Socioeconomics 

Construction of the project would not have a significant adverse impact on local populations, 

employment, provision of community services, or property values. There would not be any 

disproportionately high or adverse environmental and human health impacts on low-income and minority 

populations from construction or operation of the project. One residence and one business would be 

displaced as a result of construction of the liquefaction facility; however, both have been purchased by 

Lake Charles LNG and the occupants have relocated. It is not anticipated that any residences or 

businesses would be displaced during construction or operation of the Non-Liquefaction Facilities.

Construction of the liquefaction facility would increase the local population for the 5-year 

construction period. The average workforce would be about 2,100 workers over the 5-year period. The 

peak construction workforce is anticipated to be about 5,600 workers, about 20 percent of which would be 

workers from the local area, requiring an estimated non-resident workforce of about 4,480 workers during

the less than 9 months of peak construction. Assuming non-resident workers would be accompanied by 

family members and based on the average Calcasieu Parish household size, the peak construction nonresident workforce could result in an up to 5.9 percent temporary increase in the Calcasieu Parish 

population. The currently available transient housing in Calcasieu Parish may not be sufficient to

accommodate the maximum peak non-resident workforce, which would result in temporary impacts on

housing availability in the project area during peak construction. Outside of the time when the workforce 

peaks, the impact on transient housing would be minor. To ensure adequate available housing for nonresident workers, Lake Charles LNG has committed to requiring its contractor to develop a plan for 

addressing worker housing and monitoring availability of housing from the start of construction through 

the workforce peak. During operation of the liquefaction facility, an additional 176 permanent staff 

would be required, which would have a minor permanent impact on the local housing market.

Construction of the Non-Liquefaction Facilities would require a peak workforce of about 

690 workers; however, nearly all of the workers are anticipated to be local hires. Based on the number of

available rental housing units and hotels/motels in the vicinity of the Non-Liquefaction Facilities,

adequate housing exists to accommodate non-resident workers and their families. Overall, construction 

of the proposed Non-Liquefaction Facilities would not result in significant impacts on transient housing 

in the area. Operation of the Non-Liquefaction Facilities would require eight new permanent employees
5-16

who would relocate to the project area, which would have a negligible impact on the local housing 

market.

There would be a temporary increase in traffic levels due to the commuting of the construction 

workforce to the project area as well as the movement of construction vehicles and delivery of equipment 

and materials to the construction work area. Traffic is anticipated to increase substantially during 

construction of the liquefaction facility due to the presence of worker vehicles, construction vehicles, and 

trucks taking materials and equipment to and from the site. However, Lake Charles LNG would consider

bussing of construction workers to and from the site using a remote parking location and expects truck 

deliveries to occur during off-peak traffic period. A majority of the large deliveries, including equipment 

and construction materials, are anticipated to be delivered via barge, reducing the number of truck trips

to and from the l iquefaction facility, the potential for damage to local roadways, and traffic

congestion. To reduce potential cumulative impacts of the proposed project and other anticipated or 

recently completed developments in the project area that may create roadway capacity deficiencies, we 

are recommending that Lake Charles LNG file a traffic management plan that details specific measures 

that would be implemented to minimize impacts on traffic.

Construction of the Non-Liquefaction Facilities would result in minor, temporary impacts on 

traffic in the project area. Contractors may bus workers from common parking areas to the construction 

work areas, and Trunkline would encourage construction workers to leave their personal vehicles at the 

contractor yards and carpool to the construction areas when possible. Operation of the Non-Liquefaction 

Facilities would not result in any significant impacts on traffic or roadways within the project area.

A marine traffic study found that there was sufficient capacity in Calcasieu Channel for the 

increase in bulk carrier and barge traffic due to construction of the liquefaction facility, and the 

construction traffic would not impact existing users of Calcasieu Channel. Lake Charles LNG has not 

requested an increase in the number of LNG carriers that would call on the existing LNG terminal during 

operation of the liquefaction facility.

Construction of the project would result in positive impacts due to increases in construction jobs, 

payroll taxes, purchases made by the workforce, and expenses associated with the acquisition of material 

goods and equipment. Operation of the project would have a positive effect on the local governments’ tax 

revenues due to the increase in property taxes that would be collected.

5.1.10 Cultural Resources 

Cultural resources surveys have been completed where necessary for the liquefaction facility, 

ACWs, and Non-Liquefaction Facilities. No cultural resource surveys were required within the existing 

LNG terminal or the existing portions of the Non-Liquefaction Facilities in Louisiana per a May 2014 

agreement with the Louisiana SHPO that no consultation would be necessary for construction or 

maintenance projects within existing rights-of-way, fenced aboveground facilities, or for use of existing 

access roads. The Louisiana, Mississippi, and Arkansas SHPOs, as well the FERC staff, agree that no 

historic properties would be affected by these facilities. Therefore, the process of complying with Section 

106 of the NHPA has been completed for the project.

Lake Charles LNG, Trunkline, and FERC staff contacted several Native American tribes to 

identify properties of traditional, religious, or cultural importance that may be affected by the proposed 

project. In a June 20, 2014 letter, the Choctaw Nation of Oklahoma indicated it was unaware of any 

cultural or sacred sites within the immediate project area, and in an April 2, 2014 letter, the Coushatta 

Tribe of Louisiana concurred that no historic properties would be affected by the proposed project. Both

tribes requested that they be notified if cultural resources or human remains are discovered during 
5-17

construction activities. In a response dated April 4, 2014, the Chitimacha Tribe of Louisiana noted that it

had no concerns or comments regarding the project. None of the other Native American tribes contacted 

have provided comments to date. 

5.1.11 Air Quality and Noise

Air pollutant emissions during construction of the project would result from the operation of 

construction vehicles, marine traffic, vehicles driven by construction workers commuting to and from 

project work sites, and the generation of fugitive dust during construction activities. Air quality impacts 

due to construction would generally be temporary and localized, and are not expected to cause or 

contribute to a violation of applicable air quality standards. Lake Charles LNG and Trunkline would 

minimize emissions from gasoline and diesel engines by complying with applicable EPA mobile source 

emission performance standards and by using equipment manufactured to meet these standards. Fugitive 

dust emissions would be limited or mitigated, if necessary, by spraying water to dampen dry work 

surfaces and/or by the application of dust suppressants. However, in its June 1, 2015 comments on the 

draft EIS, the EPA recommended that, in addition to complying with applicable local, state, or federal 

requirements, Lake Charles LNG and Trunkline develop a Fugitive Dust Control Plan to reduce air 

quality impacts, including PM10 and PM2.5 emissions. We agree with the EPA that more detail is 

necessary, particularly in light of the other planned development activities in the project area as discussed 

in section 4.13, some of which may be in construction concurrently with the Lake Charles Liquefaction 

Project. Therefore, we are recommending that Lake Charles LNG and Trunkline file a Fugitive Dust 

Control Plan describing mitigation measures they would implement to minimize fugitive dust emissions 

from construction activities and incorporating, as appropriate, recommended measures provided by the 

EPA. In conclusion, with the proposed mitigation measures and our recommendation, we find that 

construction-related impacts on local air quality would not be significant.

Operation of the proposed liquefaction facility would result in long-term impacts on air quality. 

However, Lake Charles LNG would minimize these impacts by adhering to applicable federal and state 

regulations and installing BACT as described in its July 2014 revised Title V permit application to the 

LDEQ, and by complying with the conditions of the Part 70 Operating Permit issued by the LDEQ on 

May 1, 2015. Although operation of the proposed new Compressor Station 203-A and the modified 

Longville Compressor Station would also emit air pollutants, Trunkline’s AERSCREEN model results 

demonstrate that the emissions from Compressor Station 203-A and from the modifications at the 

Longville Compressor Station would not significantly impact the air quality in the surrounding area. 

However, Trunkline’s AERSCREEN analysis only included the proposed modifications, and not the 

existing facilities. Therefore, we are recommending that Trunkline provide further analysis of the 

incremental increase in emissions of criteria pollutants from the modifications prior to construction.. 

Trunkline would minimize potential impacts on air quality due to the operation of both compressor 

stations by adhering to applicable federal and state regulations described in its air permit applications.

Noise impacts associated with the construction of the liquefaction facility and modifications to 

the LNG terminal would primarily be attributed to the operation of construction equipment and pile 

driving activities. The increases in noise levels would be intermittent, would generally occur during 

daylight hours (although certain activities may need to be conducted at night to avoid construction 

schedule delays), and would vary over the course of the 5-year construction period. The noise modeling 

conducted by Lake Charles LNG found that the estimated noise impact at the nearest NSAs would be less 

than 55 dBA Ldn. 

The most significant noise-generating activities during construction of the Non-Liquefaction

facilities would be associated with Compressor Station 203-A, the Longville Compressor Station 

modifications, and HDD crossings. Trunkline conducted an acoustical analysis to identify the estimated 
5-18

noise impacts at the nearest NSAs during construction of Compressor Station 203-A and modifications to 

the Longville Compressor Station. The results indicate that the noise levels at the NSAs nearest to these 

compressor stations could exceed the 55-dBA threshold when construction equipment is operating 

simultaneously resulting in peak noise levels. However, construction would occur during daytime hours,

would be temporary and localized, and would not cause a significant long-term impact on ambient noise 

levels at any of the identified NSAs. 

Trunkline also conducted an acoustical assessment to estimate the sound contribution of the 

HDDs for NSAs within 0.5 mile of each HDD entry or exit point. The results of this assessment 

demonstrate that HDD noise is estimated to exceed a 55-dBA noise level (Ldn) and/or result in a greater 

than 10-dBA increase over ambient conditions at the Indian Bayou Channel at eight NSAs. Trunkline

would implement applicable noise mitigation measures to bring HDD noise levels into compliance with 

the FERC guideline. To ensure that HDD-related noise does not exceed the FERC guidelines, we are 

recommending that Trunkline file in its biweekly construction status reports information for the Indian 

Bayou Canal HDD entry and exit points, including noise measurements from the nearest NSA, obtained 

at the start of drilling operations, the noise mitigation that Trunkline implemented at the start of drilling 

operations, and any additional mitigation measures Trunkline would implement if the initial noise 

measurements exceeded the FERC guidelines. Because an acoustical assessment has not yet been 

completed for the revised Calcasieu River HDD alignment, we are recommending that Trunkline file an 

acoustical assessment for this crossing prior to construction. Noise associated with construction of the 

other pipeline facilities would be short term and temporary at any one location because of the assemblyline method of pipeline construction. Because Trunkline would primarily limit construction to daytime 

hours and implement noise mitigation measures at HDD sites, we conclude that construction noise would 

not have a significant impact on landowners and residents near the Non-Liquefaction Facilities.

Operation of the liquefaction facility would produce noise on a continuous basis throughout the 

lifetime of the facility. The modeling results indicate that, with the incorporation of proposed noisemitigation measures, the noise from operation of the liquefaction facility would not exceed the 55-dBA 

threshold at any of the NSAs. To ensure that NSAs are not adversely impacted by the phased operation of 

the liquefaction facility, we are recommending that Lake Charles LNG file a full-load noise survey no 

later than 60 days after each liquefaction train is put in service for the first and second liquefaction trains, 

and if noise levels attributable to operation of the liquefaction facility exceed the FERC guideline, that 

Lake Charles LNG reduce the facility’s noise contribution to result in a noise level that is no higher than 

the FERC guideline. We are also recommending that Lake Charles LNG file a full-load noise survey no 

later than 60 days after placing the liquefaction facility in service, or, if a full load noise survey is not 

possible, that it provide an interim survey at the maximum possible load and provide the full load survey 

within 6 months. If the noise levels attributable to operation of the liquefaction facility exceed the FERC 

guideline at the nearest NSA, Lake Charles LNG should file a report on what changes are needed and 

install noise controls to meet the level within 1 year of service. In addition, both recommendations

include having Lake Charles LNG confirm compliance by filing a second noise survey no later than 

60 days after installing the additional noise controls. Therefore, we conclude that operational noise from 

the expanded terminal would result in minor impacts on the nearest NSA. 

Although not part of day-to-day operations, Lake Charles LNG would use flares during startup 

procedures and, if necessary, during emergency situations. Lake Charles LNG’s noise consultant

conducted a noise assessment for both planned flaring events and unplanned emergency flaring events 

based on assumptions detailed in the report. The results of the assessment indicate that of the 15 types of 

planned flaring operations assessed, only two, both of which would be startup flare operations, would 

exceed the 55-dBA Ldn noise threshold at five of the seven NSAs evaluated. Each of these events is

assumed to occur once a year per LNG train with a possible duration of 24 hours per event. With respect 

to unplanned emergency flaring, three of the seven types of flaring operations evaluated would exceed 
5-19

55 dBA Ldn at some or all of the NSAs. These particular events are also expected to occur infrequently, 

and the duration of each would range from 0.5 to 2 hours per event. The highest noise levels expected to 

result from planned and unplanned flaring events at the NSAs would be approximately comparable to 

conversation at close range and classroom chatter, respectively. To minimize impacts on local residents, 

Lake Charles LNG has stated that details of planned flaring events would be posted in advance on the 

Lake Charles LNG project website. Additionally, landowners in the vicinity would be notified of planned 

flaring events by information leaflets that would be delivered to their properties. While flaring noise 

might be a nuisance for nearby residents during flaring events, these events would occur infrequently and, 

therefore, would not result in significant noise impacts.

The primary noise impacts associated with the operation of the Non-Liquefaction Facilities would 

be attributable to proposed Compressor Station 203-A and the proposed compressor unit replacement at 

the Longville Compressor Station. The modeling analyses conducted for the compressor stations indicate 

that with the incorporation of the proposed mitigation measures, operational noise at Compressor Station 

203-A would not exceed the 55-dBA Ldn noise threshold at any of the nearby NSAs. The noise 

contribution from the proposed compressor unit replacement itself at the Longville Compressor Station 

would not exceed the 55-dBA Ldn noise threshold at any of the nearby NSAs; however, the noise levels 

from the existing equipment, which were placed in service before the Commission adopted the current 

noise standards, are above an Ldn of 55 dBA at three of the four nearby NSAs. To ensure that noise levels 

resulting from Compressor Station 203-A would be below the FERC guideline, and to ensure that there is 

no perceptible increase in noise levels resulting from the modification of the Longville Compressor 

Station, we are recommending that Trunkline file noise surveys during full load no later than 60 days after 

placing Compressor Station 203-A, and the new compressor unit at the Longville Compressor Station,

into service. If a full power load condition noise survey is not possible, Trunkline should file an interim 

survey at the maximum possible power load within 60 days of placing the station/new compressor unit

into service and file the full power load survey within 6 months. If the noise attributable to operation of 

all equipment at Compressor Station 203-A under interim or full power load conditions exceeds the 

FERC guideline at any nearby NSA, or if the noise attributable to the operation of the modified Longville 

Compressor Station at full or interim power load conditions exceeds predicted noise levels at any nearby 

NSAs, Trunkline should file a report on what changes are needed, install additional noise controls to meet 

that level within 1 year of the in-service date; and confirm compliance with this requirement by filing a 

second full power load noise survey no later than 60 days after it installs the additional noise controls.

Based on the analyses conducted, mitigation measures proposed, and with our additional 

recommendations, we conclude that the project would not result in significant air or noise impacts on 

residents and the surrounding communities during construction and operation of the project. 

5.1.12 Safety 

We evaluated the safety of the proposed liquefaction facility and LNG terminal modifications, 

including assessments of hazards, preliminary engineering design, siting, emergency response, and 

security systems. Based on our technical review of the preliminary engineering design, we conclude that, 

with the incorporation of our recommendations, the FEED presented by Lake Charles LNG would include 

acceptable layers of protection or safeguards to reduce the risk of a potentially hazardous scenario from 

developing into an event that could impact the off-site public. 

As a cooperating agency, the DOT assisted FERC staff in evaluating whether Lake Charles 

LNG’s proposed design would meet the DOT siting requirements. In a September 19, 2014 letter to 

FERC staff, the DOT stated that it had no objection to Lake Charles LNG’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 liquefaction facilities. Additionally, on January 30, 2015, the DOT 
5-20

indicated that it has no objection to Lake Charles LNG’s use of the proposed vacuum insulated piping in 

the methodology for determining single accidental leakage sources. We conclude that the siting of the 

proposed project would not have a significant impact on public safety. 

In accordance with 33 CFR 127, the Coast Guard has reviewed the proposed liquefaction 

facilities. In a letter dated March 5, 2012, the Coast Guard stated that the existing WSA and LOR are 

adequate for the service associated with the proposed modifications because the proposed modifications 

for the liquefaction facilities would lie outside of the Marine Transfer Area and because Lake Charles 

LNG is not proposing to increase the size or frequency of LNG carrier traffic at the Trunkline LNG 

Terminal. As required by 33 CFR 105 and 127, Lake Charles LNG would amend the Operations Manual, 

Emergency Manual, and Facility Security Plan to capture changes to the operations associated with the 

project and would submit these documents to the Coast Guard prior to operation of the facility as an 

export terminal.

We identify specific recommendations to be addressed by Lake Charles LNG 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 proposed facilities. In 

addition to the final design review, we would conduct inspections during construction and operation of 

the facility to ensure that the installed design is consistent with the safety and operability characteristics of 

the FEED, and that the facility is operated and maintained in accordance with the filed design throughout 

the life of the facility. 

Trunkline would design, construct, operate, and maintain the proposed Non-Liquefaction 

Facilities in accordance with the DOT Minimum Federal Safety Standards in 49 CFR 192. These 

regulations, which are intended to protect the public and to prevent natural gas facility accidents and 

failures, include specifications for material selection and qualification, minimum design requirements, 

and protection of pipelines from corrosion. We conclude that the proposed Non-Liquefaction Facilities 

would incrementally increase the risk of a pipeline accident; however Trunkline’s compliance with the 

DOT’s safety standards will ensure that Trunkline’s construction and operation of the facilities would not 

have a significant impact on public safety.

5.1.13 Cumulative Impacts

Three types of projects (past, present, and reasonably foreseeable projects) could potentially 

contribute to a cumulative impact when considered with the proposed project. Such projects in the Lake 

Charles Liquefaction Project area include existing LNG terminals and future liquefaction projects, oil and 

gas facilities, other industrial facilities, utility and transportation projects, commercial and residential 

developments, and government facilities/activities. 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 provide a detailed discussion about potential cumulative impacts by resource in section 4.13. 

We conclude that, for most resources, the project’s contribution to cumulative impacts on resources 

affected by the project would not be significant, and that the potential cumulative impacts of the Lake 

Charles Liquefaction Project and the other projects considered would be minor or insignificant.

The construction period for the Lake Charles Liquefaction Project would likely coincide with at 

least some of the other major Lake Charles area projects. A large workforce for the simultaneously 

constructed projects would have a beneficial cumulative effect on revenues for the state and for Cameron, 

Calcasieu, Jefferson Davis, and Beauregard Parishes due to expenditures for services and materials for the 

projects, increased expenditures by local workers, and expenditures by the non-local workforce and any 
5-21

family members accompanying the non-local workers. The parishes would also receive a substantial 

increase in property taxes from the projects. 

Based on the size of some of the projects and the large number of construction workers required, 

the qualified construction workers in the local labor force would likely be exceeded by the available jobs. 

Therefore, there would be an influx of non-local workers to fill the gap. This would potentially impact 

transient housing in Calcasieu, Jefferson Davis, and Beauregard Parishes, where the amount of available 

housing may not be sufficient if some of the other major projects are constructed at the same time. Nonlocal workers unable to find acceptable housing in Calcasieu, Jefferson Davis, and Beauregard Parishes 

may need to find housing in adjacent Allen Parish. If peak construction workforce periods of many of the 

projects coincide, it is possible the available housing in Allen Parish could also be exceeded. As a result, 

some members of the workforce and others seeking transient housing may be forced to obtain housing in 

more distant parishes with longer commutes.

The combined construction workforces of these projects would also potentially increase the need 

for some public services, such as police, medical services, and schools. If the medical and emergency 

services, or other public services, are adversely affected during construction, the project sponsors may 

mitigate the impact by providing funding for temporarily increasing the staff and equipment of the public 

services affected. Emergency response time is a key aspect of public health and safety. In accordance 

with FERC regulations, Lake Charles LNG would prepare a comprehensive plan that identifies the cost 

sharing mechanisms for funding these emergency response costs. This plan would minimize the potential 

for a cumulative public safety impact associated with the project. Any or all of the other stand-alone 

LNG liquefaction projects (e.g., Magnolia LNG Project), if authorized, constructed, and operated, would 

also have to prepare and implement a similar comprehensive plan to provide emergency services. In 

addition, we anticipate that the other major projects in the Lake Charles area would include emergency 

services within their facilities, and have emergency response plans developed with the appropriate 

agencies. Emergency responses at any of those facilities may temporarily stress emergency services in 

the area, but we would not expect them to result in a long-term significant impact on those services. In 

the unlikely event of major emergencies at several of the facilities at the same time, there could be a short 

term but significant cumulative impact on emergency services within Beauregard, Jefferson Davis, and 

Calcasieu Parishes. That impact could be mitigated by assistance from emergency service providers from 

surrounding parishes.

Cumulative traffic impacts from concurrent development of the Lake Charles Liquefaction 

Project, Magnolia LNG Project, and G2X Energy Project could include deficiencies in roadway 

capacities. A traffic study indicates that Lake Charles LNG plans to specify shipping routes during 

construction between the facility site and interstate highway system that would keep commercial traffic 

out of the more developed areas of Lake Charles. Lake Charles LNG has also indicated that it would 

avoid receiving large truck deliveries during peak traffic periods, and that it may consider bussing 

workers to and from the construction site. The study identifies several other mitigation strategies that 

might alleviate the cumulative impact of the three projects, including off-site parking, the use of shuttles, 

controlled shift times, coordination among the projects to reduce peak hour vehicular trips, traffic signal 

coordination/retiming, intersection and road improvements, and use of law enforcement to control traffic. 

Lake Charles LNG, Magnolia LNG, and G2X Energy are coordinating to further evaluate cumulative 

impacts of the three projects on area traffic and roadways. Additionally, we are recommending that Lake 

Charles LNG file a traffic management plan prior to construction.

Based on the cumulative modeling analysis and the required emission controls at the various Lake 

Charles Liquefaction Project facilities, we conclude that there would be no significant cumulative impact 

on air quality as a result of the operation of these facilities. There is no current methodology or policy 

guidance to determine how the Lake Charles Liquefaction Project’s incremental contribution to GHGs 
5-22

would translate into physical effects on the global environment. The emissions would increase the 

atmospheric concentration of GHGs, in combination with past and future emissions from all other 

sources, and contribute incrementally to climate change that produces the impacts described above. 

However, it cannot be determined whether or not the Lake Charles Liquefaction Project’s contribution to 

cumulative impacts on climate change would be significant.

The greatest potential for cumulative noise impacts would be during construction from internal 

combustion engines and pile driving activities associated with construction of the proposed liquefaction 

facility. The estimated noise generated from construction associated with the liquefaction facility would 

not exceed 55 dBA Ldn at the nearest NSAs. Although construction of the G2X Energy and Magnolia 

LNG Projects could overlap with the construction of the Lake Charles Liquefaction Project and contribute 

to noise levels in the area, these projects are located farther from the nearest NSA. As a result, we do not 

find that construction of the liquefaction facility along with the G2X Energy and Magnolia LNG Projects 

would result in a significant noise impact on the nearest NSA.

5.1.14 Alternatives

As alternatives to the proposed action, we evaluated the No-Action Alternative, system 

alternatives for the proposed liquefaction facility and Trunkline’s proposed pipelines, alternatives sites for 

the liquefaction facility, alternative configurations for the liquefaction facility, alternative pipeline routes, 

alternative aboveground facility sites for the Non-Liquefaction Facilities, and alternative power sources 

for the liquefaction facility and Compressor Station 203-A. While the No-Action Alternative would 

eliminate the short- and long-term environmental impacts identified in the EIS, the stated objectives of the 

proposed action would not be met. 

We evaluated system alternatives for the liquefaction facility, including 6 operating LNG import 

terminals with approved, proposed, or planned expansions to provide liquefaction capabilities, and 

20 approved, proposed, or planned stand-alone (greenfield) liquefaction projects along the Gulf Coast in 

the southern United States. All of these were eliminated from further consideration as viable alternatives

for reasons that include incompatible timeframes that would not meet Lake Charles LNG’s customer 

commitments and environmental impacts that were considered comparable to or greater than those of the 

proposed project.

We evaluated three system alternatives to Trunkline’s proposed pipelines. To serve as a viable 

system alternative to Trunkline’s proposed pipelines, the system would have to transport all or a part of 

the volume of natural gas required for liquefaction at the proposed new facility and cause significantly 

less impact on the environment than the proposed pipeline expansion. All three systems were eliminated 

from further consideration because they would require construction of additional pipeline looping or 

greenfield construction to provide the 2.6 Bcf/d required by the Lake Charles Liquefaction Project and/or 

the alternative would not provide significant environmental advantage over the proposed project.

We evaluated five sites for the liquefaction facility, including the proposed site and four 

alternatives. The sites were selected based on proximity to the existing LNG terminal and property 

considerations (e.g., parcel size and contiguity, current ownership, potential availability). Various 

environmental criteria were applied for site prioritization and selection when compared to the proposed 

site, including potential impacts on threatened, endangered, and protected species and wetlands; 

proximity to residential areas; land use and zoning; and road access. The alternatives analysis concluded 

that the currently proposed site represents the preferred site for the proposed liquefaction facility because 

it is sufficiently sized to allow optimal facility layout design and contiguity with the existing LNG 

terminal, avoids the need for off-site LNG piping, and is geographically well separated from area 

residences. While the proposed site does contain wetlands and forested cover, the loss of habitat diversity 
5-23

and function resulting from facility development would be generally comparable with that anticipated at 

the other sites, with the advantage that no estuarine wetlands would be affected.

We did not find any alternative configurations for the liquefaction facility that would meet the 

design and configuration requirements of 49 CFR 193 and other industry or engineering standards while 

at the same time avoiding or reducing the impacts associated with the proposed terminal configuration. 

The proposed location for the liquefaction trains and pretreatment units, for which most of the modeling 

for thermal exclusion and vapor dispersion zones was focused, represents the area on site that is farthest 

from publicly accessible land and closest to the existing LNG terminal, thereby minimizing the length of 

interconnecting LNG transfer piping. While other locations for the liquefaction trains and pretreatment 

units may satisfy regulatory siting requirements equally, these two factors confer a significant advantage 

for the currently proposed layout.

As part of our analysis of alternative terminal configurations, we considered whether Lake 

Charles LNG’s planned permanent conversion of all land to industrial use is necessary across the entire 

liquefaction facility site. According to Lake Charles LNG, the perimeter of the site cannot be reduced or 

adjusted and still meet operational noise and vapor dispersion requirements. Within this perimeter, Lake 

Charles LNG’s grading plan calls for the import of suitable fill material and a significant elevation 

increase across the whole site to meet safety requirements, within both the operational footprint of plant 

infrastructure and adjacent construction workspaces. The increased elevation would facilitate 

maneuverability, staging, fabrication, etc. during construction and would reduce the threat of flooding 

during both construction and operation. 

We have analyzed the regional setting of Trunkline’s proposed Mainline Connector pipeline route 

and have determined that a different route (which would likely be longer) between other points of 

interconnection would not offer any environmental advantage. Also, the proposed pipeline 

interconnection between MLV 203-A and MLV 303-A is an integral part of a wider system plan 

involving the construction of the proposed new aboveground facilities and modifications to existing 

aboveground facilities. We did not identify any environmental concerns that indicate a need to identify 

and evaluate alternative routes for the Mainline Connector. 

The Mainline 200-3 Loop would be collocated with an existing pipeline, precluding the need for 

an alternatives analysis beyond determining the side of the existing pipeline on which to collocate. The 

entire loop segment parallels the existing pipeline on the western/southern side. Collocation on the 

northern/eastern side was ruled out because construction would require crossing two existing pipelines 

and would create a conflict with the Tennessee Kaplan Meter Station at the northern terminus. The 

proposed right-of-way for the Mainline 200-3 Loop would partially overlap the previously disturbed 

right-of-way of the existing Mainline 200-3 pipeline, minimizing environmental impacts. 

We evaluated one potential site alternative for Compressor Station 203-A: alternative site CSA-1. 

Although a ditch located in the southeast portion of the proposed site would be permanently filled, the 

environmental impact would be significantly less than that associated with the riparian woodland removal 

and stream rerouting that would be required at CSA-1. CSA-1 is also in a more densely populated area, 

with about 59 residences located within 0.5 mile, the closet being 145 feet away. Based on the above 

comparison between the two sites, we conclude that CSA-1 would not be environmentally preferable to 

the proposed location. 

Feasible alternatives for the bidirectional piping modifications and the compression upgrade 

proposed at four existing compressor stations do not exist and, given that construction would take place 

within the fencelines of the existing facilities, environmental impacts would be minimized. Therefore, the 

need to consider alternatives for these facilities was not warranted or feasible.
5-24

Alternative sites for the LCLNG Export Meter Station are all within either the existing LNG 

terminal or the liquefaction facility site. Since these two areas are either fully developed or would be 

fully developed under the proposed action, there is no net difference in anticipated environmental impacts 

between alternative site locations. The other four new meter stations are located at existing Trunkline

pipeline crossings with Gulf Crossing, Midcontinent Express, Kinder Morgan, and Columbia Gulf 

Transmission. By necessity of system function and design, the proposed meter stations must be located at 

or in the immediate vicinity of the intersections between Trunkline and these other suppliers; therefore, 

materially different alternative sites were not identified for evaluation. The potential impacts of 

construction and operation of the meter stations would be minimal and we determined that no alternative 

sites would provide a significant environmental advantage over the proposed sites. Because the 

modifications to the existing meter stations would take place at existing facilities, there are no feasible 

alternatives for these project components. In addition, the locations of the remaining Non-Liquefaction

Facilities, including the Mainline 100-3 Modifications and the Mainline 200-1 Modifications, would be 

located at existing facilities and, as such, there are no feasible alternatives to these locations.

The use of electrically driven motors as an alternative to gas-fired turbines at the proposed 

liquefaction facility was evaluated during pre-FEED and ruled out due to the excessive amount of 

electrical power required. To use electric-powered motors, power would either have to be generated on 

site or imported from the municipal power grid, neither of which would be a feasible alternative supply 

source. 

Trunkline performed a review of electric motor-driven compressors at Compressor Station 203-A. 

The results indicated that the electric load for this design would be of a magnitude serviceable only by a 

high-voltage transmission system for which the nearest potential interconnect is more than 2 miles away. 

Due to the required capital cost for the electric system expansion and the ongoing cost of electricity for 

facility operation, Trunkline eliminated this option from initial consideration. However, Trunkline

requested that Entergy (service provider) provide a high-level feasibility of service analysis, which 

Trunkline filed during the draft EIS comment period along with a comparison of capital and operating 

costs for electric motor-driven versus gas-fired compressor units. Entergy’s study identifies the additional 

infrastructure and modifications to existing electrical infrastructure that would be required to support the 

use of electric-driven compressor units at Compressor Station 203-A. Required new infrastructure would 

include a new switching station, which would be constructed at the compressor station, as well as two

138-kV transmission lines estimated to be 3.2 and 3.6 miles long. In addition to the land use impacts, 

construction of the transmission lines would affect wetlands and result in visual impacts from the required 

transmission line structures. The primary environmental benefit to electric compression at Compressor 

Station 203-A would be the elimination of local air emissions during routine operation, although 

generation of the electricity would likely result in similar (or increased) emissions at a power plant in the 

region. Noise levels could potentially remain unchanged. While there would be a reduction in air 

emissions from the station using electric-driven compression, the proposed station would be a minor 

source of air emissions under PSD regulations. Therefore, taking into account both the environmental 

impacts identified in the Entergy study and the cost implications associated with the use of electric motordriven compressor units, we conclude that Trunkline’s proposed use of gas-fired compressor units at 

Compressor Station 203-A is reasonable and justified, and that electric compression would not provide a 

significant advantage over the proposed facility. 
5-25

5.2 FERC STAFF’S RECOMMENDED MITIGATION

If the Commission authorizes the Lake Charles Liquefaction Project, we are recommending that 

the following measures be included as specific conditions in the Commission’s Order. We believe that 

these measures would further mitigate the environmental impacts associated with the construction and 

operation of the proposed project.

1. Lake Charles LNG and Trunkline shall follow the construction procedures and mitigation 

measures described in their applications and supplements (including responses to staff data 

requests) and as identified in the EIS, unless modified by the Order. Lake Charles LNG and 

Trunkline 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

d. receive approval in writing from the Director of OEP before using that modification.

2. For LNG facilities, the Director of 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 project. 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 assure 

continued compliance with the intent of the conditions of the Order.

3. For pipeline facilities, 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 project. 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 or mitigation of adverse environmental impact 

resulting from construction and operation of the project.

4. Prior to any construction, Lake Charles LNG and Trunkline each shall file affirmative 

statements with the Secretary, certified by senior company officials, that all company personnel, 

EIs, and contractor personnel will be informed of the EIs’ 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 for the project.

5. The authorized facility locations shall be as shown in the EIS, as supplemented by filed alignment 

sheets. As soon as they are available and before the start of construction, Lake Charles LNG 

and Trunkline shall file with the Secretary any revised detailed survey alignment maps/sheets at a 
5-26

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 site-specific clearances 

must be written and must reference locations designated on these alignment maps/sheets.

Trunkline’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. Trunkline’s right of eminent domain granted under NGA section 7(h) does not 

authorize it to increase the size of its natural gas pipeline or facilities to accommodate future 

needs or to acquire a right-of-way for a pipeline to transport a commodity other than natural gas.

6. Lake Charles LNG and Trunkline shall file with the Secretary 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 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. All areas must be 

approved in writing by the Director of OEP before construction in or near that area.

This requirement does not apply to extra workspace allowed by the FERC Plan and/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 Order and before construction begins, Lake Charles 

LNG and Trunkline shall file Implementation Plans with the Secretary for review and written 

approval by the Director of OEP. Lake Charles LNG and Trunkline must file revisions to the 

plans as schedules change. The plans shall identify:

a. how Lake Charles LNG and Trunkline will implement the construction procedures and 

mitigation measures described in its application and supplements (including responses to 

staff data requests), identified in the EIS, and required by the Order;

b. how Lake Charles LNG and Trunkline 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 on-site construction and inspection personnel;
5-27

c. the number of EIs assigned per spread and/or facility, and how Lake Charles LNG and 

Trunkline 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 material;

e. the location and dates of the environmental compliance training and instructions Lake 

Charles LNG and Trunkline will give to all personnel involved with construction and 

restoration (initial and refresher training as the project progresses and personnel changes), 

with the opportunity for OEP staff to participate in the training session(s);

f. the company personnel (if known) and specific portion of Lake Charles LNG’s and 

Trunkline's organizations having responsibility for compliance;

g. the procedures (including use of contract penalties) Lake Charles LNG and Trunkline 

will follow if noncompliance occurs; and

h. for each discrete facility, a Gantt or PERT chart (or similar project scheduling diagram), 

and dates for:

i. the completion of all required surveys and reports;

ii. the environmental compliance training of on-site personnel;

iii. the start of construction; and

iv. the start and completion of restoration.

8. Lake Charles LNG and Trunkline shall employ a team of EIs, including at least one EI for the 

liquefaction facility/LNG terminal modifications, and one or more EIs per pipeline spread. The 

EIs shall be:

a. responsible for monitoring and ensuring compliance with all mitigation measures 

required by the Order and other grants, permits, certificates, or other 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.
5-28

9. Beginning with the filing of the Implementation Plans, Lake Charles LNG and Trunkline shall 

file updated status reports with the Secretary on a monthly basis for the liquefaction facility/LNG 

terminal modifications and a biweekly basis for the Non-Liquefaction Facilities 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 Lake Charles LNG’s and Trunkline’s efforts to obtain the necessary federal 

authorizations;

b. the current construction status of the liquefaction facility/LNG terminal modifications 

and Non-Liquefaction Facilities, 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 the 

EIs 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;

f. a description of any landowner/resident complaints that 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 Lake Charles LNG and Trunkline from other 

federal, state, or local permitting agencies concerning instances of noncompliance, and 

Lake Charles LNG’s and/or Trunkline’s response.

10. Prior to receiving written authorization from the Director of OEP to commence 

construction of any project facilities, Lake Charles LNG and Trunkline shall file with the 

Secretary documentation that they have received all applicable authorizations required under 

federal law (or evidence of waiver thereof).

11. Lake Charles LNG must receive written authorization from the Director of OEP prior to 

introducing hazardous fluids into the liquefaction 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. Lake Charles LNG and Trunkline must each receive written authorization from the Director of 

OEP before placing into service the liquefaction facility/LNG terminal modifications and the 

Non-Liquefaction Facilities. 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 right-of-way and other areas affected by the project are proceeding satisfactorily.
5-29

13. Within 30 days of placing the authorized facilities in service, Lake Charles LNG and 

Trunkline each 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 conditions of the Order Lake Charles LNG and Trunkline have 

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.

14. Prior to construction, Lake Charles LNG shall file with the Secretary a plan for periodic 

monitoring and reporting of ground subsidence and foundation settlement for the design life of 

the liquefaction facility. (Section 4.1.3.3)

15. Lake Charles LNG shall file with the Secretary the following information, stamped and sealed by 

the professional engineer-of-record:

a. site preparation drawings and specifications;

b. LNG liquefaction facility structures and foundation design drawings and calculations;

and

c. quality control procedures to be used for civil/structural design and construction.

In addition, Lake Charles LNG shall file, in its Implementation Plan, the schedule for producing 

this information. (Section 4.1.4.1)

16. Prior to construction, Trunkline shall file with the Secretary the geotechnical investigations, 

stamped and sealed by the professional engineer-of-record, which are necessary to evaluate the 

suitability of the proposed HDD crossings. (Section 4.1.5)

17. Prior to construction, Lake Charles LNG shall file with the Secretary, for review and written 

approval by the Director of OEP, final design plans for the ACWs that detail how each ACW 

would be stabilized after construction is complete to prevent off-site erosion impacts on the 

surrounding areas, and any planned mitigation to address altered drainage patterns resulting from 

the modified elevation and clearing of these sites. (Section 4.2.3)

18. Prior to construction, Lake Charles LNG and Trunkline shall file with the Secretary an updated 

SPAR Plan that includes project-specific emergency contacts and local authorities, and the 

project-specific SPCC Plan(s) for review and written approval by the Director of OEP. 

(Section 4.2.3)

19. Within 30 days of placing facilities in service, Lake Charles LNG and Trunkline shall file with 

the Secretary a report identifying all public or private water supply wells/systems damaged by 

construction and how they were repaired. The report shall also include a discussion of any other 

complaints concerning well yield or water quality and how each problem was resolved. 

(Section 4.3.1.4)
5-30

20. Prior to construction, Trunkline shall file with the Secretary copies of the final HDD plan and 

profile drawings for review and written approval by the Director of OEP. (Section 4.3.2.2)

21. Prior to construction, Trunkline shall file its final HDD Contingency Plan with the Secretary for 

review and written approval by the Director of OEP. (Section 4.3.2.2)

22. Prior to construction, Lake Charles LNG and Trunkline shall file with the Secretary a copy of 

the final Compensatory Mitigation Plan and documentation of COE approval of the plan. 

(Section 4.4.4)

23. Prior to construction, Lake Charles LNG and Trunkline shall coordinate with the NRCS and 

LDWF to develop a project-specific noxious weed control plan. The plan shall be filed with the 

Secretary for review and approval by the Director of OEP. (Section 4.5.3)

24. If clearing during the migratory bird nesting season is necessary in non-forested vegetated habitat, 

Lake Charles LNG and Trunkline shall consult with the FWS and file with the Secretary written 

documentation of FWS approval prior to construction in those areas. (Section 4.6.1.3)

25. Prior to construction of the Mainline 200-3 Loop and the NGPL-Lakeside Meter Station, 

Trunkline shall file with the Secretary documentation that the FWS and LDWF are in agreement 

with Trunkline’s proposed approach for addressing colonial waterbirds, including a description of 

the final agreed-upon mitigation measures that Trunkline would implement if construction of 

these facilities would occur during the colonial waterbird nesting seasons identified by the FWS 

and LDWF. (Section 4.6.1.3)

26. Prior to construction, Lake Charles LNG shall file with the Secretary, for review and written 

approval by the Director of OEP, a description of the proposed in-water pile installation process, 

including the number and type of pile driver(s) (e.g., impact or vibratory hammer) and duration of 

in-water pile driving activities, and an analysis of anticipated peak and cumulative underwater 

sound pressure levels. If the analysis determines that pile driving activities would exceed a peak 

sound pressure of 206 dB re: 1 μPa or a cumulative sound pressure level of 183 dB re: 1 μPa, 

Lake Charles LNG shall provide a description of measures it would implement to minimize 

impacts on aquatic resources in the vicinity of on-land and in-water pile driving activities. 

(Section 4.6.2.1)

27. Prior to construction, Trunkline shall file with the Secretary an updated Blanket Clearance 

regarding federally listed species under the ESA and/or, if an updated Blanket Clearance is not 

issued or the stipulations of the Blanket Clearance change, updated documentation from the FWS 

that the previous determinations of effect are still current. Trunkline shall not begin construction 

activities until it receives written notification from the Director of OEP that construction or use 

of mitigation may begin. (Section 4.7.1)

28. Prior to construction, Lake Charles LNG shall file with the Secretary, for review and written 

approval of the Director of OEP, visual screening plans for ACWs A and D. At a minimum, each 

plan shall include the retention of a forested buffer of sufficient width to provide an effective 

visual screen between the liquefaction facilities or ACW and the nearest residences located to the 

east (for ACW A) and to the north (for ACW D). (Section 4.8.6.1)
5-31

29. Prior to construction, Lake Charles LNG shall file with the Secretary, for review and written 

approval by the Director of OEP, a traffic management plan that details specific measures that 

will be implemented to minimize impacts on traffic. The traffic management plan shall identify 

off-site vehicle parking areas, alternative worker transportation methods, traffic control measures, 

infrastructure improvement, traffic control personnel, and construction and delivery areas. 

(Section 4.9.6.1)

30. Prior to construction, Lake Charles LNG and Trunkline shall file with the Secretary, for review 

and written approval by the Director of OEP, a Fugitive Dust Control Plan that includes a 

description of mitigation measures they will implement to minimize fugitive dust emissions from 

construction activities, including measures to reduce PM10 and PM2.5 emissions. The plan shall 

clearly explain how Lake Charles LNG and Trunkline will implement such measures and specify 

the individuals that will have the authority to determine the need for implementation of dust 

control measures, and to stop work if the contractor does not comply. In developing the plan, 

Lake Charles LNG and Trunkline shall consider and incorporate as appropriate the 

recommendations provided by the EPA in Attachment 1 of its June 1, 2015 comment letter. 

(Section 4.11.1.4)

31. Prior to construction of modifications to the Longville Compressor Station, Trunkline shall 

file with the Secretary, for review and written approval by the Director of OEP, the results of an 

air quality screening (AERSCREEN) or refined modeling analysis (AERMOD or EPA-approved 

alternative). This modeling analysis shall demonstrate that the incremental increase in emissions 

of criteria pollutants from the modifications either: results in local concentrations below the 

NAAQS where current concentrations are currently below the NAAQS; or does not cause or 

contribute to local concentrations above the NAAQS where the current concentrations are above 

the NAAQS. (Section 4.11.1.5)

32. Prior to construction of the Calcasieu River HDD, Trunkline shall file an acoustical 

assessment identifying NSAs within 0.5 mile of the HDD entry and exit points and describing

noise mitigation measures it will implement if the estimated sound contribution of the HDD 

would exceed an Ldn of 55 dBA and/or result in a greater than 10-dBA increase over noise 

ambient conditions at any NSA. (Section 4.11.2.3)

33. Trunkline shall file in the biweekly construction status reports the following for the Indian 

Bayou Canal HDD entry and exit points:

a. the noise measurements from the nearest NSA, obtained at the start of drilling operations;

b. the noise mitigation that Trunkline implemented at the start of drilling operations; and

c. any additional mitigation measures that Trunkline will implement if the initial noise 

measurements exceeded an Ldn of 55 dBA at the nearest NSA and/or increased noise 

more than 10 dBA over ambient conditions. (Section 4.11.2.3)

34. Lake Charles LNG shall file a full load noise survey with the Secretary for the liquefaction 

facility no later than 60 days after each liquefaction train is placed into service for the first and 

second liquefaction train. If the noise attributable to the operation of the equipment at the 

liquefaction facility exceeds an Ldn of 55 dBA at the nearest NSA, Lake Charles LNG shall 

reduce operation of the liquefaction facilities or install additional noise controls until a noise level 

below an Ldn of 55 dBA at the nearest NSA is achieved. Lake Charles LNG shall confirm 
5-32

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 4.11.2.4)

35. Lake Charles LNG shall file a noise survey with the Secretary no later than 60 days after 

placing the entire liquefaction facility into service. If a full load noise survey is not possible, 

Lake Charles LNG shall provide an interim survey at the maximum possible load and provide the 

full load survey within 6 months. If the noise attributable to the operation of all of the 

equipment at the liquefaction facility under interim or full load conditions exceeds an Ldn of 55 

dBA at the nearest NSA, Lake Charles LNG shall file a report on what changes are needed and 

shall install the additional noise controls to meet the level within 1 year of the in-service date. 

Lake Charles LNG 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 4.11.2.4)

36. Trunkline shall file a noise survey for Compressor Station 203-A no later than 60 days after 

placing the station into service. If a full power load condition noise survey is not possible, 

Trunkline shall file an interim survey at the maximum possible power load within 60 days of 

placing the station into service and file the full power load survey within 6 months. If the noise 

attributable to operation of all equipment at the station under interim or full power load 

conditions exceeds an Ldn of 55 dBA at any nearby NSA, Trunkline shall:

a. file a report with the Secretary, for review and written approval by the Director of OEP,

on what changes are needed;

b. install additional noise controls to meet that level within 1 year of the in-service date; 

and

c. confirm compliance with this requirement by filing a second full power load noise survey 

with the Secretary for review and written approval by the Director of OEP no later than 

60 days after it installs the additional noise controls. (Section 4.11.2.4)

37. Trunkline shall conduct noise surveys at the Longville Compressor Station to verify that the noise 

from all the equipment operated at full power load does not exceed the predicted noise levels 

above an Ldn of 55 dBA at any nearby NSAs. The results of the noise surveys shall be filed with 

the Secretary no later than 60 days after placing the new compressor unit in service. If a full 

load condition noise survey is not possible, Trunkline shall provide an interim survey at the 

maximum possible horsepower load within 60 days of placing the new compressor unit into 

service and provide the full load survey within 6 months. If the noise attributable to the 

operation of the modified compressor station at full or interim power load conditions exceeds 

predicted noise levels at any nearby NSAs, Trunkline shall file a report on what changes are 

needed and shall install the additional noise controls to meet the level within 1 year of the inservice date. Trunkline shall confirm compliance with this requirement by filing a second noise 

survey with the Secretary no later than 60 days after it installs the additional noise controls. 

(Section 4.11.2.4):

Recommendations 38 through 93 shall apply to the Lake Charles Liquefaction Project LNG 

facilities. Information pertaining to these 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 
5-33

No. RM06-24-000), including security information, shall be submitted as critical energy infrastructure 

information (CEII) 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 shall be filed a minimum of 30 days before approval to proceed is requested. 

(Section 4.12.3).

38. Prior to initial site preparation, Lake Charles LNG shall provide procedures for controlling 

access during construction. (Section 4.12.3)

39. Prior to initial site preparation, Lake Charles LNG shall file the quality assurance and quality 

control procedures for construction activities. (Section 4.12.3)

40. Prior to initial site preparation, Lake Charles LNG shall file a plot plan of the final design 

showing all major equipment, structures, buildings, and impoundment systems. (Section 4.12.3)

41. Prior to initial site preparation, Lake Charles LNG shall file the updated ERP to include the 

Liquefaction Facilities as well as instructions to handle on-site refrigerant and NGL-related 

emergencies. (Section 4.12.6)

42. Prior to initial site preparation, Lake Charles LNG shall file an ERP that includes a CostSharing 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 transit-related 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 4.12.6)

43. The final design shall include information/revisions pertaining to Lake Charles LNG’s response 

to the Engineering Information Requests identified in table 4.12.3-1 of the EIS. (Section 4.12.3)

44. The final design shall include change logs that list and explain any changes made from the FEED 

provided in Lake Charles LNG’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)

45. The final design shall provide up-to-date Process Flow Diagrams with heat and material balances 

and P&ID, which include the following information: 

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness;

c. storage tank (i.e., condensate) pipe penetration size or nozzle schedule;

d. valve high pressure side and internal and external vent locations;

e. piping with line number, piping class specification, size, and insulation type and 

thickness; 

f. piping specification breaks and insulation limits; 
5-34

g. all control and manual valves numbered; 

h. relief valves with size and set points; and

i. drawing revision number and date. (Section 4.12.3)

46. The final design shall provide P&IDs, specifications, and procedures that clearly show and 

specify the tie-in details required to safely connect the project to the existing facility. 

(Section 4.12.3)

47. The final design shall provide an up-to-date complete equipment list, process and mechanical 

data sheets, and specifications. (Section 4.12.3)

48. The final design shall include three-dimensional plant drawings to confirm plant layout for 

maintenance, access, egress, and congestion. (Section 4.12.3)

49. The final design shall provide complete drawings and a list of the hazard detection equipment. 

The 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 hazard detection equipment. (Section 4.12.3)

50. The final design shall provide complete plan drawings and a list of the fixed and wheeled drychemical, hand-held fire extinguishers, and other hazard control equipment. Drawings shall 

clearly show the location by tag number of all fixed, wheeled, and hand-held 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)

51. The final design shall provide facility plans and drawings that show the location of the firewater 

and foam systems. Drawings shall clearly show: firewater and foam piping; post indicator 

valves; and the location, and area covered by, each monitor, hydrant, deluge system, foam 

system, water-mist system, and sprinkler. The drawings shall also include P&IDs of the firewater 

and foam system. (Section 4.12.3)

52. 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 Part 193. The evaluation shall consider the need for clean agent fire suppression in the 

new switchgears and motor control centers. 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)

53. 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 for carbon steel and no less than schedule 80 for 

stainless steel, or are designed to withstand external loads, including vibrational loads in the 

vicinity of rotating equipment and live loads of operators in areas accessible by operators. 

(Section 4.12.3)

54. The final design shall include drawings and 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)
5-35

55. 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)

56. The final design shall provide electrical area classification drawings. (Section 4.12.3)

57. The final design shall provide spill containment system drawings with dimensions and slopes of 

curbing, trenches, and impoundments. (Section 4.12.3)

58. The final design of the hazard detectors shall account for the calibration gas when determining 

the LFL set points for methane, propane, ethane, and condensate. (Section 4.12.3)

59. The final design shall include a hazard and operability review of the completed design prior to 

issuing the P&IDs for construction. A copy of the review, a list of recommendations, and actions 

taken on the recommendations, shall be filed. (Section 4.12.3)

60. 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)

61. The final design shall include a drawing showing the location of the emergency shutdown 

buttons. Emergency shutdown buttons shall be easily accessible, conspicuously labeled, and 

located in an area that would be accessible during an emergency. (Section 4.12.3)

62. The final design shall specify that all emergency shutdown valves are to be equipped with open 

and closed position switches connected to the Distributed Control System/Safety Instrumented 

System. (Section 4.12.3)

63. 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 49 CFR 193, and shall provide justification if not using an inert or nonflammable gas for cleanout, dry-out, purging, and tightness testing. (Section 4.12.3)

64. 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, and storage tanks. (Section 4.12.3)

65. The final design shall provide the procedures for pressure/leak tests that address the requirements 

of ASME VIII and ASME B31.3, as required by 49 CFR 193. (Section 4.12.3)

66. The final design shall include a structural evaluation of each LNG storage tank that accounts for 

the modifications to the tanks, internal pump columns, and piping systems. The evaluation shall 

include the following: 

a. modification details; 

b. structural design loading and acceptance criteria used to evaluate the structural integrity 

of the LNG storage tanks, internal pump columns, piping and associated supports; 
5-36

c. effects of the modifications on the tanks’ structural design; and

d. review and approval by the tank manufacturer to verify the structural integrity of the tank 

is adequate to support the modifications and proposed operating conditions and other 

design loadings. (Section 4.12.3)

67. The final design of the thermal relief valve PSV-880 discharge shall not be directed downstream 

of emergency shutdown valve ESDV-510. (Section 4.12.3)

68. The final design shall specify that the design pressure of the Hot Oil Expansion Drum, A801-F, 

shall be consistent with the design pressure of the hot oil system. (Section 4.12.3)

69. The final design of the inlet and discharge piping to/from PSV-060A/B on the Rich Amine Flash 

Drum shall be stainless steel and shall discharge to the low pressure flare header to be consistent 

with the flare pressure design philosophy. (Section 4.12.3)

70. The final design shall include a piping specification that applies to the design conditions of the 

regeneration piping systems associated with the dehydrators. (Section 4.12.3)

71. The final design of the discharge from pressure controlled vents PV-144 and PV-124 on the 

mixed refrigerant system shall be directed to the low pressure cold flare header. (Section 4.12.3)

72. The final design shall include a full evaluation and justification for the exclusion of suction 

drums for the medium pressure and high pressure stages of the medium and high pressure mixed 

refrigerant compressors. The evaluation shall include consideration for settle out condensation 

under all conditions. (Section 4.12.3)

73. The final design of the firewater pump testing system shall include flow and pressure transmitters 

that connect to the distributed control system. The P&IDs shall show the test piping from the 

discharge of each pump connecting to a common header upstream of the flow and pressure 

transmitters. (Section 4.12.3)

74. The final design shall provide details of the heating element for the Flare Knockout Drums and 

the method of insertion and removal. (Section 4.12.3)

75. The final design shall evaluate the installation of a forward pressure control valve with flow 

reset, rather than a flow control valve (i.e., FV-82127), on the regeneration stream to the Ethane 

Treatment Beds. (Section 4.12.3)

76. The final design shall demonstrate that the design pressure of the Propane Transfer Pump, 8202-

J, and the set pressure of the discharge relief valve PSV-82087 would be consistent with the 

propane transfer pump shutoff pressure conditions. (Section 4.12.3)

77. The final design shall provide procedures for how to prevent the flare system from overloading 

due to excessive intentional and inadvertent venting from the blowdown valves. (Section 4.12.3)

78. The final design of the refrigerant storage system shall allow the isolation of individual pressure 

relief valves while providing full relief capacity, during pressure relief valve maintenance or 

testing. (Section 4.12.3)
5-37

79. Lake Charles LNG shall certify that the final design is consistent with the information provided 

to DOT as described in the design spill determination letter dated September 19, 2014 (Accession 

Number 20140919-4005). In the event that any modifications to the design alters the candidate 

design spills on which the Title 49 CFR Part 193 siting analysis was based, Lake Charles LNG

shall consult with DOT on any actions necessary to comply with Part 193. (Section 4.12.5.2)

80. The final design shall include the details of how the vacuum insulated piping account for 

mechanical stress and thermal movements of the outer piping under cryogenic conditions. 

(Section 4.12.5.3)

81. The final design shall include the procedures to maintain and inspect the vapor barriers provided 

to meet the siting provisions of 49 CFR § 193.2059. (Section 4.12.5.3) 

82. Prior to commissioning, procedures shall be developed for providing the facility with fire water 

coverage during such times as the fire water system would be out of service, in particular for 

removing and flushing brackish water from the system. (Section 4.12.3)

83. Prior to commissioning, Lake Charles LNG shall file plans and detailed procedures for: testing 

the integrity of on-site mechanical installation; functional tests; introduction of hazardous fluids; 

operational tests; and placing the equipment into service. (Section 4.12.3)

84. Prior to commissioning, Lake Charles LNG 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. 

Lake Charles LNG shall file documentation certifying that each of these milestones has been 

completed before authorization to commence the next phase of commissioning and startup would 

be issued. (Section 4.12.3)

85. Prior to commissioning, Lake Charles LNG shall tag all equipment, instrumentation, and valves 

in the field, including drain valves, vent valves, main valves, and car-sealed or locked valves. 

(Section 4.12.3)

86. Prior to commissioning, Lake Charles LNG 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)

87. Prior to commissioning, Lake Charles LNG shall file updates addressing the liquefaction 

facilities in the operation and maintenance procedures and manuals, as well as safety procedures. 

(Section 4.12.3)

88. Prior to commissioning, Lake Charles LNG shall maintain a detailed training log to demonstrate 

that operating staff has completed the required training. (Section 4.12.3)

89. Prior to introduction of hazardous fluids, Lake Charles LNG 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)

90. Prior to introduction of hazardous fluids, Lake Charles LNG shall complete all pertinent tests 

(Factory Acceptance Tests, Site Acceptance Tests, Site Integration Tests) associated with the 
5-38

Distributed Control System and the Safety Instrumented System that demonstrates full 

functionality and operability of the system. (Section 4.12.3)

91. Prior to commencement of service, Lake Charles LNG shall label 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)

92. Prior to commencement of service, Lake Charles LNG shall notify FERC staff of any proposed 

revisions to the security plan and physical security of the facility. (Section 4.12.3)

93. Prior to commencement of service, progress on the construction of the proposed systems shall 

be reported in monthly reports filed with the Secretary. 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)

In addition, recommendations 94 through 96 shall apply throughout the life of the LNG facility:

94. 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, Lake Charles LNG 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 P&IDs 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 

semi-annual report, shall be submitted. (Section 4.12.3)

95. 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, quantity and composition of imported and exported LNG, liquefied and vaporized 

quantities, boil-off/flash gas, etc.), plant modifications, including future plans and progress 

thereof. Abnormalities shall include, but not be limited to: unloading/loading/shipping problems, 

potential hazardous conditions from 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, non-scheduled maintenance or repair (and 

reasons therefore), relative movement of storage tank inner vessels, hazardous fluids releases, 

fires involving hazardous fluids 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 also shall be reported. Reports shall 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)” also shall be included 

in the semi-annual operational reports. Such information would provide FERC staff with early 

notice of anticipated future construction/maintenance projects at the LNG facility. 

(Section 4.12.3)

96. Significant non-scheduled events, including safety-related incidents (e.g., LNG, condensate, 

refrigerant, or natural gas releases, fires, explosions, mechanical failures, unusual over 

pressurization, and major injuries) and security-related incidents (e.g., 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, 
5-39

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 fluids 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 

LNG facility that contains, controls, or processes hazardous fluids; 

h. any malfunction or operating error that causes the pressure of a pipeline or LNG facility 

that contains or processes hazardous fluids to rise above its MAOP (or working pressure 

for LNG facilities) plus the build-up allowed for operation of pressure limiting or control 

devices; 

i. a leak in an LNG facility that contains or processes hazardous fluids that constitutes an 

emergency; 

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 operating pressure or shutdown of operation of a 

pipeline or an LNG facility that contains or processes hazardous fluids; 

l. safety-related incidents to hazardous fluids vessels 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 investigation 

results and recommendations to minimize a reoccurrence of the incident. (Section 4.12.3)

APPENDIX A

DISTRIBUTION LIST

APPENDIX A

DISTRIBUTION LIST

A-1

Federal Government Agencies

Council on Environmental Quality, 

Manisha Patel, DC

Federal Aviation Administration (FAA), 

Air Space Branch, TX

Office of Federal Programs, Advisory Council 

on Historic Preservation, Charlene D.

Vaughn, DC

Office of the Assistant Secretary of the Army for 

Civil Works, Assistant for Environment, 

Tribal and Regulatory Affairs, DC

Office of the Assistant Secretary of the Navy 

(Energy, Installations, and Environment), DC

Office of the Deputy under Secretary of Defense 

(Installations and Environment), Chief, 

Mission Evaluation Branch, DC

Senate Energy and Natural Resources 

Committee, Mary L. Landrieu, DC

U.S. Army Corps of Engineers, Civil Works, 

Operations, Regulatory Branch, DC

U.S. Army Corps of Engineers, New Orleans 

District, Brian Breaux, LA

U.S. Army Corps of Engineers, New Orleans 

District, James W. Little, Jr., LA

U.S. Army Corps of Engineers, New Orleans 

District, Ronnie Duke, LA

U.S. Army Corps of Engineers, Planning and 

Policy Division, John Furry, DC

U.S. Coast Guard, Deepwater Ports Standards 

Division, Commandant Chief (Acting), 

Curtis E. Borland, DC

U.S. Coast Guard, Lieutenant Commander 

R.C. Compher, P.E., LA

U.S. Coast Guard, Lieutenant Julio "Tony" 

Moré, LA

U.S. Department of Agriculture, Farm Service 

Agency, Conservation and Environmental 

Program Division, Nell Fuller, DC

U.S. Department of Agriculture, Forest Service, 

Ecosystem Management Coordination, 

Joe Carbone, DC

U.S. Department of Agriculture, Natural 

Resources Conservation Service, 

Andree DuVarney, DC

U.S. Department of Commerce, National 

Oceanic and Atmospheric Administration, 

National Marine Fisheries Service, Lisa 

Abernathy, LA

U.S. Department of Commerce, National 

Oceanic and Atmospheric Administration, 

Steve Kokkinakis, MD

U.S. Department of Commerce, National 

Oceanic and Atmospheric Administration, 

National Marine Fisheries Services, 

Richard “Rick” Hartman, LA

U.S. Department of Commerce, National 

Oceanic and Atmospheric Administration, 

National Marine Fisheries Service, 

Steve Leathery, MD

U.S. Department of Defense Siting 

Clearinghouse, Mike Aimone, DC

U.S. Department of Defense Siting 

Clearinghouse, Office of the Deputy 

Assistant Secretary of the Air Force 

(Installations), Liaison, DC

U.S. Department of Defense Siting 

Clearinghouse, Office of the Deputy 

Assistant Secretary of the Army (Energy 

and Sustainability), Liaison, DC

U.S. Department of Defense Siting 

Clearinghouse, Office of the Deputy under 

Secretary of Defense, Installations and 

Environment/Business Enterprise 

Integration, VA

U.S. Department of Defense Siting 

Clearinghouse, Steve Sample, DC

U.S. Department of Energy, John Anderson, DC

U.S. Department of Energy, Office of 

Environmental Management, 

Mark Whitney, DC

U.S. Department of Energy, Office of Fossil 

Energy, Kyle W. Moorman, DC

U.S. Department of Energy, Office of General 

Counsel, Ed LeDuc, DC
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-2

Federal Government Agencies (cont’d) 

U.S. Department of Energy, Office of General 

Counsel, Stephen Smith, DC

U.S. Department of Energy, Office of National 

Environmental Policy Act, Policy and 

Compliance, Carol M. Borgstrom, DC

U.S. Department of Health and Human Services, 

Edward Pfister, DC

U.S. Department of Health and Human Services, 

U.S. Centers for Disease Control and 

Prevention, National Center for 

Environmental Health, Sharunda 

Buchanan, GA

U.S. Department of Homeland Security, 

U.S. Customs and Border Protection,

Christopher Oh, DC

U.S. Department of Housing and Urban 

Development, Office of Environment and 

Energy, Danielle Schopp, DC

U.S. Department of Justice, Environment and 

Natural Resources Division, Beverly Li, DC

U.S. Department of State, Bureau of Oceans and 

International Environmental and Scientific 

Affairs, Alexander Yuan, DC

U.S. Department of the Interior, Bureau of 

Indian Affairs, Marv Keller, VA

U.S. Department of the Interior, Bureau of Land 

Management, Kerry Rogers, DC

U.S. Department of the Interior, Bureau of 

Ocean Energy Management, James F. 

Bennett, VA

U.S. Department of the Interior, Bureau of 

Safety and Environmental Enforcement, 

Charles B. Barbee, VA

U.S. Department of the Interior, Director, DC

U.S. Department of the Interior, Fish and 

Wildlife Service, Jeff Weller, LA

U.S. Department of the Interior, Fish and 

Wildlife Service, Joshua Marceaux, LA

U.S. Department of the Interior, Fish and 

Wildlife Service, Pat Carter, VA

U.S. Department of the Interior, Fish and 

Wildlife Service, Southeast Region 4, 

Patti Holland, LA

U.S. Department of the Interior, National Park 

Service, Patrick Walsh, CO

U.S. Department of the Interior, National Park 

Service, Southeast Region, Bryan Faehner, DC

U.S. Department of Transportation, Office of 

Assistant Secretary for Transportation 

Policy, Camille Mittelholtz, DC

U.S. Department of Transportation, Office of 

Assistant Secretary for Transportation 

Policy, Helen Serassio, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Office of Pipeline Safety, Bryn Karaus, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Office of Pipeline Safety, Kenneth Y. Lee, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Magdy El-Sibaie, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Office of Pipeline Safety, Karen Lynch, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Jeffrey Wiese, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Sherri Pappas, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Joseph Sieve, DC

U.S. Department of Transportation, Pipeline and 

Hazardous Materials Safety Administration, 

Kenneth Lee, DC

U.S. Department of Transportation, Surface 

Transportation Board, Victoria Rutson, DC

U.S. Environmental Protection Agency, 

Cliff Rader, DC
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-3

Federal Government Agencies (cont’d) 

U.S. Environmental Protection Agency, 

Cynthia Giles, DC

U.S. Environmental Protection Agency, 

Jerome Blackman, DC

U.S. Environmental Protection Agency, Region 6, 

Michael Jansky, TX

U.S. Environmental Protection Agency, 

Susan E. Bromm, DC

U.S. Geological Survey, Esther Eng, VA

Federal Senators and Representatives

U.S. House of Representatives, Representative, The 

Honorable Charles W. Boustany, M.D., DC

U.S. House of Representatives, Representative, 

The Honorable John C. Fleming, M.D., DC

U.S. Senate, Senator, The Honorable David 

Vitter, DC

U.S. Senate, Senator, The Honorable Lisa 

Murkowski, DC

State Senators and Representatives

Louisiana House of Representatives, State 

Representative, District 36, The Honorable 

Chuck Kleckley, LA

Louisiana House of Representatives, State 

Representative, District 47, The Honorable 

Bob Hensgens, LA

Louisiana State Senate, State Senator, District 25, 

The Honorable Dan "Blade" Morrish, LA

Louisiana State Senate, State Senator, 

District 27, The Honorable Ronnie 

Johns, LA

State Government Agencies

Louisiana Department of Environmental Quality

– Air Permits, Tegan Treadaway, LA

Louisiana Department of Environmental Quality

– Water Quality Certifications, Jamie 

Phillippe, LA

Louisiana Department of Environmental Quality

– Water Quality Division, Melvin “Mitch”

Mitchell, LA

Louisiana Department of Environmental 

Quality, Sam Phillips, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management, 

Christian Seifert, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management,

Charrier, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management, 

Sharon McCarthy, LA

Louisiana Department of Natural Resources, 

Scott Angelle, LA

Louisiana Department of Wildlife and Fisheries, 

Chris Davis, LA

Louisiana Department of Wildlife and Fisheries, 

Dave Butler, LA

Louisiana State Historic Preservation Office, 

Rachel Watson, LA

Mississippi Department of Archives and 

History, Historic Preservation Division, 

J. Wood, MS

Mississippi Department of Environmental 

Quality, Trudy Fisher, MS

Mississippi Department of Wildlife, Fisheries, 

and Parks, MS

State Archaeologist and Director, Dr. Charles 

"Chip" McGimsey, LA

State of Louisiana, The Honorable Bobby Jindal, LA

Local Government Agencies

Beauregard Parish School Board, LA

Calcasieu Parish, Office of Homeland Security 

and Emergency Preparedness, Director, 

Dick Gremillion, LA

Calcasieu Parish, Parish Administrator, Bryan 

Beam, LA

Calcasieu Parish, Sheriff Tony Mancuso, LA

City of Lake Charles, Mayor Randy Roach, LA

Council on Environmental Quality, Associate 

Director for National Environmental Policy 

Act Oversight, Horst Greczmiel, DC
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-4

Local Government Agencies (cont’d)

Council on Environmental Quality, Senior 

Counsel, Ellen Athas, DC

Fire Protection District No. 2, LA

Lake Charles Harbor and Terminal District, LA

Native American Groups

Alabama Coushatta Tribe of Texas, Chief 

Oscola Clayton Sylestine, TX

Alabama Coushatta Tribe of Texas, Historic 

Preservation Officer, Bryant Celestine, TX

Caddo Nation, Chairperson, Brenda Shemayme 

Edwards, OK

Caddo Nation, Tribal Historic Preservation 

Officer, Robert Cast, OK

Chitimacha Tribe of Louisiana, Chairman, 

John Paul Darden, LA

Chitimacha Tribe of Louisiana, Cultural 

Director, Kimberly Walden, LA

Choctaw Nation of Oklahoma, Chief Gregory 

Pyle, OK

Choctaw Nation of Oklahoma, Tribal Historic 

Preservation Officer, Ian Thompson, OK

Coushatta Tribe of Louisiana, Chief Kevin 

Sickey, LA

Coushatta Tribe of Louisiana, Cultural 

Preservation Officer, Dr. Linda Langley, LA

Jena Band of Choctaw Indians, Chief B. Cheryl 

Smith, LA

Jena Band of Choctaw Indians, Tribal Historic 

Preservation Officer, Dana Masters, LA

Mississippi Band of Choctaw Indians, 

Chief Phyllis J. Anderson, MS

Mississippi Band of Choctaw Indians, Tribal 

Archaeologist and Historic Preservation 

Officer, Kenneth Carleton, MS

Tunica-Biloxi Tribe of Louisiana, Chairman, 

Earl J. Barbry, Sr., LA

Libraries

Grant Parish Library, LA

Richland Parish Library, LA

West Carroll Parish Library, LA

Media

Eunice News, LA

Rayne Acadian Tribune, LA

Richland Beacon-News, LA

Southwest Daily News, LA

Companies and Organizations

Abear – Nunez Farms LLC, LA

Abraham Five, Jonathan R. Abraham, LA

Alcoa Carbon Products, Steven Thompson, LA

Alvin M. Bordelon Trust, et ux., LA

Alvin R. and Mary S. Haggart Revocable Trust, WI

Amelia S. Beard Estate, GA

Andean Chemical LTD, TX

AT&T Mobility, LLC, MO

Bio-Eco Green Energy Solutions, LLC, WA

C.A. Mewis and Anita H. Mewis Trust, TX

Christine Marie Hartwell, LA

Clyde Watson Jr. and Bank One Trust 

Company NA, TX

Corbello Investors LP, LA

David G. Hughey Living Trust, c/o Matthew 

Hughey, MS

Diamond Development Inc., LA

First Baptist Church of Longville, LA

First Church of Christ, LA

George B. Franklin & Son, Inc., LA

Gulf South Pipeline, TX

Harwood Land, LP, AR
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-5

Companies and Organizations (cont’d)

HGPC, LLC, LA

Jeanette M. Gaudet, Texas Conference 

Association of Seventh-Day, Walter E. 

McNabb, Richard R. McNabb, Sherry M. 

Snider, LA

Jiwani Properties, Inc., LA

JWG, LLC, TX

KBR, Benson Pair, TX

Kinder Canal Co., LA

Lacassane Co., Inc., LA

Lakeport Wildlife and Timber Co., LLC, MS

Lewis Farm Properties, LLC, MS

Longville Church of Christ, Inc., LA

Louisiana Farm and Livestock Co., Inc., 

Robert O. Gayle, LA

Magnolia LNG, Ernie Megginson, TX

Magnolia LNG, John Bagelley, TX

Magnolia LNG, Tammy Truax, LA

Mallett Family Properties LLC, LA

McKinley Augustine Farm, Inc., LA

Meriwether Louisiana Land and Timber LLC, LA

Natural Resource Group, LLC

NCI/Presidential Towers, VA

North American Land Co., Inc., LA

North American Land Company LLC, LA

Ogletree Timber Company, LTD, TX

PBA Properties LLC, et al., LA

Plauche–Shaddock Farms, LA

Prairie Investment, LLC, LA

Prairie Land Company, LA

PWK Timberland Corporation, LA

R2K, LLC, LA

Ray and Cynthia B. Harrington Revocable

Living Trust, LA

Rayonier Gulf Timberlands, LLC, FL

Reynolds Metal Company Alcoa Inc., PA

Richard Ledoux Farms, LLC, LA

Roger Dale Boudreaux Estate, et al., LA

Rosa Heyd Corbello Family Trust, LA

Roy J. Jr. and Sylvia Sue Dugas Revocable 

Living Trust, LA

Sabine Uplift Mineral Corporation, LA

Scotty Blain Huval, et ux., LA

Secundus Corporation, TX

Serpent Bayou Recreational Properties, LA

Shope Endeavors, LLC, LA

Soaring Eagle Enterprises, LLC, LA

Stream Companies, Bruce Kirkpatrick, LA

Stream Companies, David Richard, LA

Stream Companies, Dean Roberts, LA

Stream Family Limited Partnership, LA

Sweet Lake Land and Oil Company, LLC, LA

TCR Holdings, LLC, LA

Temple Holdings, LLC, LA

The Balanced Timberland Fund B, GA

The Fred B. and Ruth B. Foundation, LA

The Sweet Lake Land & Oil Co., LLC, LA

Tobe Chretien, Estate, TX

Tower Land Company, LLC, LA

TRC, Keith Suderman, GA

Trunkline LNG Company, TX

Trunkline LNG, Stephen Veatch, TX

Whitehead Family Revocable Living Trust, TX

Woodbrook, Inc., LA
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-6

Individuals

Aaron Steven Justelien, LA

Adeline D. Savoy, LA

Adolf Ramon Robledo, 

et ux., LA

Adrian Scott Voyght, et ux., LA

Alan Pierce Booth, LA

Albert Hayes, LA

Alfred Paul Douglas, LA

Alice Mae Lorraine Nunez, LA

Allen Charles, LA

Alvin Joseph Miller, et ux., LA

Alvin Perkins, Jr., LA

Alvin Ricky Ogea, et ux., LA

Angela Dawn Foreman 

Cooper, LA

Anita H. Mewis, TX

Anita Midkiff, et al., LA

Annabelle Hebert Denison, LA

Anne Alexander, MS

Anthony Moreaux, TX

Anthony Valentine Frederick, 

et ux., LA

Anthony Zaunbrecher, LA

Arlene Orphy, LA

Arnold James Burke, LA

Arnold Keith Harrell, LA

Artis Dugas, TX

Audrey Joyce, LA

Azena Corbello, LA

Barabara Jean Stevenson 

Levine, MD

Bea Schwarze, LA

Benny Ray Stracener, LA

Billy Dewbre, TX

Bobbi B. Nunez, LA

Bobby Ray Marcantel, LA

Bonnie Ann Trahan, LA

Bonnie Rose Bowman 

Barbery, LA

Bradley Edward Foreman, 

et ux., LA

Brandel Johnson, LA

Brenda E. Bell Roberts, TX

Brenda J. Dugas, LA

Brent Joshua Duga, LA

Brian Lynn Boenig, LA

Bridget H. Schultz, LA

Bryan Anthony Keller, LA

Burnell Nunez, Jr., LA

Calvin Coleman, LA

Carl Bernard Labiche, LA

Carla Sue Smith, LA

Carol Hauser, LA

Carol Louise Bodin, LA

Carol R. Bebee, LA

Carrie Mae Hillard Slaughter, LA

Carroll Jo Barham, LA

Catherine R. Hard Hicks, LA

Charles Ronald Rayon, LA

Charles Roy Soileau, et ux., LA

Chester Joseph McFarlain, LA

Christon N. Nelson, et al., LA

Christopher Joseph Habetz, 

et al., LA

Clifford Kershaw, LA

Cody Lane Booth, LA

Conrad W. King, LA

Curtis Bennett, LA

Curtis James Parker, et ux., LA

Curtis James Primeaux, LA

Dan Deason, LA

Dana Ray Henry, LA

Daniel AJ Fruge, et al., LA

Daniel Henry Stanley, et ux., LA

David Kiley Gibson, et ux., LA

David M. Airhart, LA

David P. Lindsay, LA

David Paul Brown, LA

Debra Kay Wilds, LA

Dennis Wayne Nelson, LA

Dewey Derouen, LA

Dickie James Fournerat, 

et ux., LA

Dixie Diane Nelson, LA

Dominic J. Doucet, LA

Donald LeBlanc, LA

Donna Lynn Ezell, LA

Donovan Lee Elliott, et ux., LA

Dorothy Clooney Kerr, TX

Douglas J. David, et al., LA

Douglas Ray Nunez, et ux., LA

D'Ryan C. Green, LA

Duncan Miller, Jr., LA

Earnest F. Clooney, Jr., LA

Edna Declouette Arceneaux 

et vir, LA

Effie Gatewood, AR

Elizabeth Hymes Beissel, TX

Ellen Gwen Cannon, LA

Elwin Faulk, Jr., LA

Emmett Powell, LA

Estelle L. O'Meara Estate, LA

Esther Lynn Lambert, LA

Eve Derouen Estate, LA
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-7

Individuals (cont’d)

Faye Guilliams Haggart 

Quedodeaux, LA

Felix Joseph Thibodeaux Jr., 

et ux., LA

Felix Joseph Thibodeaux, 

et ux., LA

Firdous Jamal Abbasi, LA

Forrest LeBlanc, LA

Francis L. Benoit Estate, LA

Francis S. Fabacher et us, LA

Frank James Fontenot, 

et ux., LA

Fred G. Denison, LA

Gary L. Crosby, LA

Gary Matthews, et ux., LA

Gaynell T. Verrett, LA

Gene Cradeur, et ux., LA

Geneva D. Prudhomme, LA

George Brown, LA

Geraldine M. Marcantel, LA

Glen Roy Navarre, LA

Gloria L. Richard, LA

Gregory Lee Celetine, LA

Gretchen McCown, LA

Harold Harrington Jr., LA

Harris Dale O'Blanc, LA

Helen Netherland, LA

Herbert Fuselier, LA

Herman Ashford, Sr., LA

Huey R. Brooks, et ux., LA

Irving Freeman, Sr., LA

Jack S. Lasha Sr., et ux., LA

Jackie John Credeur, LA

James John Becnel, et ux., FL

James Kennedy, LA

James Langley, LA

James Nelson Desjardine, LA

James Netherland, LA

James P. Hymes, TX

James Patrick Poullard, 

et ux., LA

James Ray Clooney, III, TX

James Russell Gross, LA

James S. Pelican, LA

James Thomas Jr. Lambert, LA

Jane B. Arrington, LA

Janice Mary Veillon Monroe, LA

Janie Ann Elliott, LA

Jean Claude Theriot, TX

Jeffery G. Fuller, et ux., LA

Jeffery W. Lebert, et al., LA

Jennifer S. Lantz et vir, LA

Jeremy Dewitt Gaskin, et al., LA

Jeremy N. Gwatney, LA

Jeremy Touchet, LA

Jesse Deville, LA

Jimmy Louis Gwatney Jr., 

et ux., LA

Jimmy Mullins, LA

Jockquernetta P. Jackson, LA

Joe K. Powell, Sr., LA

John Bergstedt, LA

John Brent Meaux, LA

John Bush Robinette, LA

John D. Nunez, et ux., LA

John Denison, LA

John Frederick Denison, 

et ux., LA

John H. Williams, LA

John Ladoux, LA

John LeBlanc, Jr., TX

John R Higgins, LA

John R. Denison, LA

John Russell Denison, et al., LA

John Steven Newman, et ux., LA

John Taylor, Sr., TX

Johnnie Bennett, LA

Johnny B. Arrington, LA

Johnny Brooks Arrington Jr., 

et ux., LA

Jonathan D. Hardy, LA

Jose N. Diaz Jr., LA

Joseph G. Lambert, et ux., LA

Joseph Pierce Roberts, et ux., LA

Joseph Trent Hall, LA

Karen Ardoin, LA

Karen Corbello Jongbloed, LA

Karen Elizabeth Hoyt Faulk, LA

Katherine Bell Garrison 

Brewer, LA

Kathleen Fournerat Fontenot 

et vir, LA

Kathleen R. Stevens, LA

Kelsey Roy Richard, LA

Kenneth Gerald Merchant, LA

Kenneth Lane Simien, et ux., LA

Keri L. Airhart, LA

Kevin Marshall, LA

Kimberly Watters, LA

Kristy Dawn Hebert, LA

Kristy Lynn Hoffpauir, LA

Kyle W. Coleman, LA

Larry Allen Manuel, LA

Larry F. Guidry, LA

Larry J. Guidry, LA
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-8

Individuals (cont’d)

Larry Wayne Aymond, LA

Laura Alexander Landrum, MS

Laurie Ellis, LA

Lawrence Anthony 

Thibodeaux, et ux., LA

Ledia LeBlanc, LA

Lee Baggett, LA

Lee Roy Clark, LA

Leland Lloyd Jackson, LA

Leon Edward Larce, et ux., LA

Leroy Thomas Bertrand, LA

Lesley A. Gardiner Moreaux, TX

Linda Berchey, LA

Linda F. Guidry, LA

Linda J. Guidry, LA

Linda Marie Sonnier, LA

Lisa Pellerin, LA

Lorena Bellard, LA

Lori Lacy Levingston, LA

Louis Hudson, et al., TX

Lula M. Fuselier, LA

Lynda Ann P. Dugas, LA

Lynette Lewis, et al., LA

Mack Joyce, LA

Margaret Deville, LA

Margaret Kuttner, LA

Margie Johnson, LA

Margie Miller, LA

Marilyn Breaux, LA

Mark Kevin Self, LA

Mark Leslie Roy, et ux., LA

Mark Wayne Foreman, 

et ux., LA

Mary Ann Elliot, LA

Mary Maynor, LA

Marylin D. Pelican, LA

Matthew James Church, LA

Matthew Martin, LA

Melvin Troy Jones, et ux., LA

Merrilee H. Batty, LA

Michael D. Moreaux, LA

Michael David Moreaux, LA

Michael Gordon Irving, 

et ux., LA

Michael Jade Conner, et ux., LA

Michael McKinley Butler, LA

Michael T. Tezeno, et ux., LA

Michael Wayne Monceaux, 

et ux., LA

Michael William Wilds, LA

Michelle Lee Hebert, LA

Mike Edward Marcantel, LA

Mike Jongbloed, LA

Milton Wayne Self, et ux., LA

Mohammad Akram, LA

Molly Suzanne Frank Bond 

et vir, LA

Nadio Cristiani, LA

Nancy Cooper, LA

Nancy Miller Vidrine, LA

Nanette Clooney Edwards, TX

Natalie Burnett, LA

Nathan R. Fontenot, et al., LA

Nedia L. Sonnier, LA

Nola B. Prudhomme, LA

Norma Carroll Morin 

Voilleque, TX

Norma Puckett, LA

Olin Lacy, Jr., LA

Osmay Woolridge, LA

Patricia Ann Mullins, LA

Patricia Cobb Preston, LA

Patricia Faye Burke, LA

Patrick Ardoin, LA

Patrick Carl Aguillard, et al., LA

Patrick Labruyer, Jr., LA

Paul Gerard Bushnell, 

et ux., LA

Pauline L. Poole, LA

Phyllis Bennett, LA

Phyllis Davis, LA

Priscilla Ardoin LeBlanc, 

et al., LA

Priscilla Ardoin, LA

Rachiel Burnett, LA

Ralph Wilbert Foreman, 

et ux., LA

Randall Anderson, LA

Randall Dale Mott, et ux., LA

Randall Lane Guillory, et ux., LA

Randell L. Miller, LA

Randy Joseph Soileau, et ux., LA

Randy Paul Booth, LA

Rhonda M. Dewbre, TX

Richard Dean Ford, et ux., LA

Richard Farmer, MS

Richard H. Evans Jr., LA

Richard J. Breaux, LA

Richard James Magnuson, 

et ux., LA

Richard S. Nunez, LA

Ricky J Faulk, LA

Ricky Lee Church, et ux., LA

Robert Bertrand, LA

Robert Carnahan, Jr., LA

Robert Fontenot, LA
APPENDIX A

DISTRIBUTION LIST (cont’d)

A-9

Individuals (cont’d)

Robert Hamilton Denison, 

et ux., LA

Robert M. Webre, LA

Rodeny Dwayne Buckley, LA

Rollin Ellis, LA

Ronald G. Nunez, Sr., LA

Rosa Clampton, TN

Russell Clinton Denison, LA

Samuel Fontenot, LA

Sandra Marie Robinette, LA

Sandra Miller, LA

Sarah Lou Ezell, LA

Scott Jospeh Haggart, et al., LA

Shannon Crosley, MD

Shannon Ellis Ezell, et ux., LA

Sharon Kay Denison 

Broussard, LA

Sharon Marie Booth, LA

Sherry H. Fontenot, et al., LA

Shirley F. Goss, TX

Shirley June Magnuson, LA

Silas P. Booth, LA

South Beauregard Water 

System, Inc., LA

Steve J. Orgeron, Sr., LA

Steven Lee Barg, Jr., LA

Stuart Benjamin Guillory, LA

Susie Ann O'Blanc, LA

Sylvia Bertrand, LA

Tammy Lynn Dugas Davis, LA

Thomas Anderson, LA

Thomas Bergstedt, LA

Thomas Gregory Kramer, LA

Thomas H. Shields III, et al., LA

Thomas John Gaspard, et ux., LA

Thomas Switzer, III, LA

Thomas Switzer, Jr., LA

Timothy Dean Maple Sr., 

et ux., LA

Toni Johnson, LA

Tremayne Picou, LA

Trent Joseph Hall, LA

W. R. Long, LA

Walter Philbert Mallet, et al., LA

Wayne W. Thibodeaux, LA

Wendi Carol Dugas Conner, LA

Wendi Dugas Conner, LA

William D. Brown, LA

William J. Ross, LA

William James Ross, et al., TX

William M. Benoit, et al., MS

William Matthew Stevens, LA

Willie Leo Bowman Jr., 

et ux., LA

Willis Nelson Desjardine, LA

Wilmer Pinder, LA

Windborne Sonnier, LA

Yvonne F. Bebee, LA

APPENDIX B 

NON-JURISDICTIONAL FACILITIES MAPS 

#0

#0

Nelson

Substation

Graywood

Substation

CALCASIEU PARISH

Louisiana

Mississippi

Texas

Arkansas

0 1 2

Mile

K

Legend

Preferred Route

Alternate Route D-L

#0 Substations

Study_Area

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 1 of 9

 Appendix B

 230kV TPINSS

Nelson Substation Route

B-1
Graywood Substation

230 kV

TPINSS Substation (future)

230 kV

CALCASIEU PARISH

Louisiana

Mississippi

Texas

Arkansas

0 100 200

Feet

K

Legend

Structures to be Replaced

Existing Line 

69kV Line (future)

TPINSS Substation (future)

Graywood Substation

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 2 of 9

 Appendix B

 230kV TPINSS

Substation (future)

B-2
1 CALCASIEU PARISH Power

Louisiana

Mississippi

Texas

Arkansas

0 100 200

Feet

K

Legend

Pole Locations

Proposed Permanent Easement

Temporary Workspace

Access Road

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

 Page 3 of 9

 Appendix B

 Meter Station Power Station Poles

 /&/1*([SRUW0HWHU6WDWLRQ

B-3
Power

CALCASIEU PARISH

Louisiana

Mississippi

Texas

Arkansas

 Appendix B

Meter Station Power Station Poles

0 100 200

Feet

K

Legend

Pole Locations

Proposed Permanent Easement

Temporary Workspace

Access Road

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 4 of 9

Kinder Morgan - Lake Charles

B-4
7

6

5

4

3

2

1

Power

ACADIA PARISH

Louisiana

Mississippi

Texas

Arkansas

 Appendix B

Meter Station Power Station Poles

0 100 200

Feet

K

Legend

Pole Locations

Proposed Permanent Easement

Temporary Workspace

Access Road

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 5 of 9

Columbia Gulf - Eagan

B-5
3

2

1

Power

ALLEN PARISH

Louisiana

Mississippi

Texas

Arkansas

 Appendix B

Meter Station Power Station Poles

0 100 200

Feet

K

Legend

Pole Locations

Proposed Permanent Easement

Temporary Workspace

Access Road

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 6 of 9

 TETCO - Allen

B-6
3

2

1

Power

RICHLAND PARISH

Louisiana

Mississippi

Texas

Arkansas

 Appendix B

Meter Station Power Station Poles

0 100 200

Feet

K

Legend

Pole Locations

Proposed Permanent Easement

Temporary Workspace

Access Road

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 7 of 9

 Gulf Crossing - Perryville

B-7
4

3

2

1

Power

RICHLAND PARISH

Louisiana

Mississippi

Texas

Arkansas

 Appendix B

Meter Station Power Station Poles

0 100 200

Feet

K

Legend

Pole Locations

Proposed Permanent Easement

Temporary Workspace

Access Road

Sources: LDOTD, Bing, LCLP, TRC

Lake Charles

Liquefaction Project

Page 8 of 9

MEP - Perryville

B-8
!>

CALCASIEU PARISH

Louisiana

Mississippi

Texas

Arkansas

Louisiana

0 500 1,000

Feet

K

Legend

!> Active Oil Well Location

Permanent Easement

Additional Construction Workspace

Sources: LDOTD, Bing, TLNG, TRC

 Lake Charles

Liquefaction Project

 Appendix B

Active Oil Well to be 

Plugged & Abandoned

3DJHRI

ACW Area B

ACW Area C

L&/1* Export

0HWHU6WDWLRQ

LNG Terminal

Proposed Liquefaction Facility

Active Oil Well Location

ACW Area A

B-9

APPENDIX C 

PROJECT FACILITIES MAPS

ACW Area A

LNG Terminal

ACW Area B

Proposed

Liquefaction

Facility

ACW Area D

ACW Area C

/&LNG Export

0HWHU6WDWLon

ACW Area B

CALCASIEU PARISH

¬«2

¬«0

¬«1

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Moss Lake Quadrangle

Page 1 of 21

C-1
Compressor Station 203-A

Mainline Connector

LA-JEFW-0008-2AR

CS 203-A AR

LA-JEFW-0001-1AR

LA-CALC-0011

LA-JEFW-006-1AR

LA-JEFW-008-3AR

MLV 203-A

CALCASIEU PARISH JEFFERSON DAVIS PARISH

¬«0

¬«3

¬«2

¬«1

¬«191

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Hecker Quadrangle

Page 2 of 21

C-2
Mainline Connector

LA-JEFW-0008-2AR

LA-JEFW-0012-1AR

LA-JEFW-0009-1AR

LA-JEFW-0012-2AR

LA-JEFW-0008-1AR

LA-JEFW-0013-1AR

LA-JEFW-0008-2AR

LA-JEFW-006-1AR

LA-JEFW-008-3AR

JEFFERSON DAVIS PARISH

¬«7

¬«6

¬«5

¬«4

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Fenton Quadrangle

Page 3 of 21

C-3
Mainline Connector

LA-JEFW-0019-2AR

LA-JEFW-0019-1AR

LA-JEFW-0017-1AR

LA-JEFW-0026-2AR

LA-JEFW-0015-1AR

JEFFERSON DAVIS PARISH

¬«9

¬«8

¬«7

¬«10

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Indian Village Quadrangle

Page 4 of 21

C-4
Mainline Connector

LA-JEFW-0026-1AR

LA-JEFW-0027-1AR MLV 303-A

JEFFERSON DAVIS PARISH

ALLEN PARISH

¬«189

¬«188

¬«187

¬«11

¬«10

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Indian Village Quadrangle

Page 5 of 21

C-5
Loop Line 200-3

LA-CALS-0017-1AR

LA-CALS-0020-1AR

LA-CALS-0006-1AR

LA-JEFF-033-1AR

LA-JEFF-0038-1AR

CALCASIEU PARISH

JEFFERSON DAVIS PARISH

JEFFERSON DAVIS PARISH

¬«177

¬«179

¬«178

¬«176

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Lacassine Quadrangle

Page 6 of 21

C-6
Loop Line 200-3

LA-JEFF-0016-1AR

LA-JEFF-002-1AR

LA-JEFF-0005-1AR

LA-JEFF-0015-1AR

LA-JEFF-0003-1AR

LA-JEFF-0016-2AR

LA-JEFF-033-1AR

LA-JEFF-0015-2AR

JEFFERSON DAVIS PARISH

¬«182

¬«181

¬«180

¬«179

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Lacassine Quadrangle

Page 7 of 21

C-7
Longville Compressor Station

BEAUREGARD PARISH

¬«211

¬«210

¬«209

¬«214

¬«213

¬«2

¬«1

¬«0

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Longville Quadrangle

Page 8 of 21

C-8
Pollock Compressor Station

GRANT PARISH

¬«87

¬«86

¬«85

¬«84

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Pollock Quadrangle

Page 9 of 21

C-9
WEST CARROLL PARISH Epps Compressor Station

¬«173

¬«172

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Congo Creek Quadrangle

Page 10 of 21

C-10
Shaw Compressor Station

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Cleveland Quadrangle

Page 11 of 21

C-11
Kinder Morgan -

Lake Charles

CALCASIEU PARISH

¬«6

¬«5

¬«4

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Lake Charles SW Quadrangle

Page 12 of 21

C-12
Columbia Gulf - Eagan

Columbia Gulf Egan AR

ACADIA PARISH

¬«158

¬«157

¬«156

¬«155

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Crowley West Quadrangle

Page 13 of 21

C-13
NGPL - Lakeside

CAMERON PARISH

JEFFERSON DAVIS PARISH

¬«167

¬«166

¬«165

¬«164

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Thornwell Quadrangle

Page 14 of 21

C-14
TETCO - Allen

TETCO Allen AR

TETCO - Allen - Existing Meter Station

ALLEN PARISH

¬«198

¬«196

¬«197

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Topsy Quadrangle

Page 15 of 21

C-15
MEP - Perryville

Gulf Crossing - Perryville

MEP AR

Gulf Crossing AR

RICHLAND PARISH

¬«167

¬«166

¬«165

¬«164

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Whitney Island South Quadrangle

Page 16 of 21

C-16
Contractor Yard

Texas Gas Woodlawn

200-1 AR-5

CALCASIEU PARISH

JEFFERSON DAVIS PARISH

¬«190

¬«188

¬«189

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Hecker Quadrangle

Page 17 of 21

C-17
Transco Ragley

BEAUREGARD PARISH Transco Ragley AR

ALLEN PARISH

¬«205

¬«204

¬«203

¬«202

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Gaytine Quadrangle

Page 18 of 21

C-18
Mississippi Barrel East

Mississippi Barrel West

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Avon Quadrangle

Page 19 of 21

C-19
Calcasieu River HDD

Marsh Bayou Rd # 1

Hecker Rd # 1

Hecker Rd # 2

200-1 AR-2

Marsh Bayou Rd # 3

Marsh Bayou Rd # 2

200-1 AR-3

200-1 AR-4

CALCASIEU PARISH

¬«198

¬«197

¬«196

¬«194

¬«195

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

\\appesri1\gis\PROJECTS\AUGUSTA\Trunkline_LNG\MXD\2015\LCLP_DEIS_Appendix_C_8x11p.mxd

¬«10

Lake Charles

Liquefaction Project

6/25/2015 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Hecker Quadrangle

Page 20 of 21

C-20
US 190 Meter

US 190 Meter AR

BEAUREGARD PARISH

¬«209

¬«208

¬«207

0 1,000 2,000

Feet

K Legend

Existing Facility

Proposed Permanent Easement

Temporary Workspace

Additional Temporary Workspace

Proposed Mainline 200-3 Loop

Proposed Mainline Connector

Additional Construction Workspace

HDD - Permanent Easement

Access Road

Contractor Yard

Existing TGC Pipelines

Mile Post

Sources: USGS, LDOTD, Tiger, LCLP, TRC

¬«10

Lake Charles

Liquefaction Project

12/30/2014 

Louisiana

Texas

Mississippi

Arkansas

Oklahoma

Appendix C

USGS Map Sheets of the Project

Longville Quadrangle

Page 21 of 21

C-21

APPENDIX D 

DRAFT HORIZONTAL DIRECTIONAL DRILL PLAN AND 

PROFILE DRAWINGS, AND HORIZONTAL DIRECTIONAL DRILL 

CONTINGENCY PLAN 

D-1
D-2
D-3
D-4
D-5
D-6
HORIZONTAL DIRECTIONAL DRILL CONTINGENCY PLAN 

TRUNKLINE GAS COMPANY, LLC

Lake Charles Liquefaction Project

1.0 INTRODUCTION 

For the Federal Energy Regulatory Commission (FERC) regulated Trunkline Gas 

Company (TGC) Lake Charles Liquefaction Project (Project), portions of the pipeline will 

be installed using horizontal directional drilling method (HDD). This directional drill 

contingency plan provides specific procedures and steps to detect and respond to any 

inadvertent release of drilling fluids for the above-described canal crossings. 

Elements of this plan include: 

• Preparation; 

• Monitoring Procedures; 

• Notification Procedures; 

• Corrective Action and Cleanup; and 

• Abandonment. 

2.0 PREPARATION 

An Environmental Inspector will be employed throughout construction and restoration of 

this Project. All work will be performed in compliance with environmental permits, laws, 

and regulations. Construction personnel will be provided environmental training prior to 

commencing work, and the Contractors will be provided a Project specific Environmental 

Clearance Package including copies of all environmental permits secured for the Project 

in advance of commencing activities. 

Best management practices employed during this Project will meet or exceed the 

measures outlined in the FERC’s Upland Erosion Control, Revegetation and 

Maintenance Plan as well as the Wetland and Waterbody Construction and Mitigation 

Procedures (copies provided in Project Environmental Clearance Package). This 

includes the use of erosion control devices and turbidity control measures to protect 

sensitive resources (e.g. wetlands and waterbodies). Furthermore, containment 

equipment including earth-moving equipment, portable pumps, hand tools, sand, hay 

bales, silt fencing, turbidity screens, and/or lumber will be readily available at the Project 

site in the event of a frac-out and vac truck will be employed as necessary. 

3.0 MONITORING PROCEDURES 

The Environmental Inspector and construction personnel will monitor operations during 

drilling activities. Monitoring will include: 

• Inspection along the drill path, including surface waters along the path for 

evidence of a release. 

• Continuous examination of drilling fluid pressures and return flows. 

• The drilling operator will provide information regarding drilling conditions to the 

Page 1 of 3 

D-7
Environmental Inspector and Chief Inspector during the course of drilling 

activities. 

• Monitoring will be documented by the Environmental Inspector. TGC will keep 

photographs of release events on record. 

4.0 NOTIFICATION PROCEDURES 

If an inadvertent release is discovered, steps will be taken by construction personnel to 

contain the release as described below in the Corrective Action and Cleanup Section 

below (Section 5.0). 

If monitoring indicates an in-stream or wetland release has occurred, the Environmental 

Inspector(s) will immediately notify TGC’s construction management and environmental 

management personnel. The drilling crew will take immediate corrective action to contain 

the release and to prevent or minimize impacts. TGC will notify the U.S. Army Corps of 

Engineers (USACE), and County Environmental Department as soon as possible (within

24 hours), and provide details of the nature of the release and corrective actions being 

taken, completed, and/or planned. TGC will work with the respective agencies regarding 

additional measures that may be warranted. If it is determined that the release cannot 

be remedied without causing additional negative environmental impacts, TGC will 

request that drilling operations continue. 

5.0 CORRECTIVE ACTION AND CLEANUP 

By monitoring drilling operations continuously, TGC intends to correct problems before 

they occur. However, if a release does occur, the following measures will be 

implemented to stop or minimize the release and to clean it up: 

 The drilling contractor will decide what modifications to make to the drilling technique 

or composition of drilling fluid (i.e., thickening of fluid by increasing bentonite content) 

to reduce or stop minor losses of drilling fluid. 

 If a minor bore path void is encountered during drilling, making a slight change in the 

direction of the bore path may avoid loss of circulation. 

 If the borehead becomes lodged resulting in loss of drilling pressure, the borehole 

may be sized by moving the borehead back and forth to dislodge the stuck materials. 

 If public health and safety are threatened, drilling fluid circulation pumps will be 

turned off. This measure will be taken as a last resort because of the potential for 

drill hole collapse resulting from loss of down-hole pressure. 

Land Release: 

 If a land release is detected, the drilling crew will take immediate corrective action to 

contain the release and to prevent or minimize migration off site. 

 Steps will be taken (such as installing berms, silt fence and/or hay bales) to prevent 

silt-laden water from flowing into protected resources. 

 The contractor will construct pits and/or berms around the frac-out point to contain 

inadvertent releases onto the ground. 

 Vacuum trucks may be called in as necessary to assist in the removal of released 

material. 

Page 2 of 3 

D-8
 If the amount of an on-land release does not allow practical collection, the affected 

area will be diluted with fresh water and allowed to dry. 

 If hand tools cannot contain a small on-land release, small collection sumps (less 

than 5 cubic yards) may be constructed to pump the release material into the mudprocessing system. 

 Once the release is contained and materials are removed, it will be disposed of

properly. 

Wetland or Waterbody Release: 

 If a release occurs within a waterbody, USACE will be contacted as soon as possible 

(within 24 hours) by TGC. TGC will inform USACE about any threat to public health 

and safety and explain whether or not the release can be corrected without incurring 

additional environment impact. If necessary, drilling operations will be reduced or 

suspended to assess the extent of the release and to implement corrective actions. 

 Temporary dams (e.g. sand bags) may be installed to isolate the fluid from a 

frac-within a protected feature.

 Vacuum trucks will be called in as necessary to assist in timely, effective removal 

of released drilling mud. 

 Once the release is contained and materials are removed, it will be properly 

disposed of. 

6.0 ABANDONMENT 

If corrective actions do not prevent or control releases from occurring into a protected 

feature, TGC may opt to re-drill the hole along a different alignment within their 

easement rights or suspend the installation altogether. Other issues may require 

abandoning the hole, such as refusal or misalignment. In any case, the following 

procedures will be implemented to abandon the drill hole: 

 The method for sealing the abandoned drill hole is to pump thickened drilling fluid 

into the hole as the drill assembly is extracted and using cement grout to make a 

cap. 

 Closer to the surface (within approximately 10 feet of the surface), a soil cap will be 

installed by filling with soil extracted during construction of the pit and berms. 

 The borehole entry location will be graded and seeded by the contractor to its 

original grade and condition after the drill hole has been abandoned. 

Page 3 of 3 

D-9

APPENDIX E 

UNANTICIPATED DISCOVERY 

PLAN FOR CONTAMINATED SOILS OR GROUNDWATER 

 

TLNG/TGC

Unanticipated Discovery 

Plan for Contaminated Soils or Groundwater

The environmental inspectors and construction contractor personnel will be adequately trained 

on identification of contaminated soils and/or groundwater during construction. Indicators of 

possible contamination include:

x Rusted (or otherwise poor condition) drums or containers

x Stained or otherwise discolored soil (in contrast to adjoining materials)

x Spoil material containing debris other than obvious construction material

x Chemical or hydrocarbon odors emanating from excavations

x Oily residues

x Visible sheen or other discoloration on groundwater

x Structures such as pipelines (concrete, PVC or steel) or underground storage tanks.

The EI and appropriate contractor personnel will be trained in hazard identification and worker 

protection and these topics will be discussed regularly in safety meetings. Thorough preconstruction inspections shall be conducted prior to beginning work in each area of the project. 

The following activities will be implemented in the event that suspected contamination is 

encountered:

x Immediately cease construction activities within that area and notify the Environmental 

Inspector and Project Environmental Manager.

x Upon notification, the Project Environmental Manager will perform a hazard assessment 

to determine appropriate control measures to be implemented at the specific site. If 

warranted by the assessment, the Project Environmental Manager will notify all 

appropriate Federal, State and Local agencies. 

x The Contractor will ensure that potentially contaminated groundwater or soils are 

contained to minimize the spread of further contamination and to prevent the 

contamination from reaching wetlands or waterbodies.

x If potentially contaminated groundwater or soil reaches (or has potential to reach) 

surface waters, booms and/or absorbent materials shall be immediately deployed to 

contain and reduce downstream migration of the spilled material. If conditions are 

warranted, the response contractor as specified in the project SPCC plan shall be 

mobilized to assist in the response. Trunkline has developed a Spill Prevention and 

Response Plan for use by its contractors in developing project specific Spill Prevention, 

Control, and Countermeasures Plans (SPCCP). These SPCCPs will be filed with the 

FERC prior to construction.

Trunkline Gas Company, LLC 2014

E-1
x The applicable regulatory agencies shall be consulted to develop a site specific plan for 

removal and disposal or treatment of the contaminated area. All 

identification/characterization, handling, labeling, storage, manifesting, transportation, 

record keeping, and disposal of potentially contaminated materials shall be conducted in 

accordance with all applicable federal, state, and local regulations and guidance.

Trunkline Gas Company, LLC 2014

E-2
APPENDIX F 

WATERBODIES POTENTIALLY AFFECTED BY THE 

LAKE CHARLES LIQUEFACTION PROJECT 

APPENDIX F 

F-1 

TABLE F-1

Waterbodies Potentially Affected by the Liquefaction Facility

Associated With the Lake Charles Liquefaction Project

Waterbody Name

Waterbody 

Unique ID

Waterbody

Type

Affected

Area

Waterbody 

Classifications a

Impact

Profile

LNG Terminal

Industrial Canal/Turning Basin Not applicable Open water 22.1 acres ABCF b,c Dredge and 

construction of inwater structures

Liquefaction Facility

Unnamed stream S103 Perennial 4,824.3 feet ABCF Armor and realign

Unnamed stream S108 Intermittent 443.9 feet ABCF Fill

Unnamed stream S120 Intermittent 513.7 feet ABCF Fill

Unnamed pond WB115 Open water 1.2 acres ABCF Fill

Unnamed drainage D100 Road drainage 224.2 feet NA Fill

Unnamed drainage D101 Road drainage 3,008.0 feet NA Fill

Unnamed drainage D102 Road drainage 717.3 feet NA Fill

Unnamed drainage D103 Road drainage 3,636.8 feet NA Fill

Unnamed drainage D104 Road drainage 103.1 feet NA Fill

Unnamed drainage D105 Road drainage 1,542.1 feet NA Fill

Unnamed drainage D112 Road drainage 787.8 feet NA Fill

Unnamed drainage D113 Road drainage 2,529.4 feet NA Fill

Unnamed drainage D116 Road drainage 436.4 feet NA Fill

Unnamed drainage D117 Road drainage 234.3 feet NA Fill

Unnamed drainage D118 Road drainage 285.4 feet NA Fill

TOTAL – INTERMITTENT 957.6 feet

TOTAL – PERENNIAL 4,824.3 feet

TOTAL – DRAINAGE 13,504.6 feet

TOTAL – OPEN WATER 23.3 acres

____________________

a Louisiana State Water Quality Classifications (Louisiana Department of Environmental Quality):

A = Primary Contact Recreation

B = Secondary Contact Recreation

C = Propagation of Fish and Wildlife

F = Agriculture

b Designated as a section 10 waterbody under the Rivers and Harbors Act.

c Designated as an impaired waterbody on the State of Louisiana’s 2012 Clean Water Act §303(d) List.

NA These waterbodies have not been designated as streams.
APPENDIX F (cont’d) 

F-2 

TABLE F-2

Waterbodies Potentially Affected by the Non-Liquefaction Facilities

Associated With the Lake Charles Liquefaction Project

Waterbody Name

Waterbody 

Unique ID Milepost Stream Type

Crossing 

Width 

(feet)

Water Quality 

Classification a

Crossing 

Method

NEW PIPELINES

Mainline Connector

Unnamed agricultural canal WB-C-162 0.3 Agricultural 

ditch

25 ABCF Open-cut

Unnamed agricultural canal D-T-120 0.6 Agricultural 

ditch

10 ABCF Open-cut

Unnamed drainage D-T-119 0.6 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-T-118 0.6 Drainage 

canal

5 NA c Open-cut

Unnamed tributary to Arceneaux 

Bayou

S-T-115 1.2 Perennial 40 ABCF Horizontal 

directional 

drill (HDD)

Arceneaux Bayou S-T-117 1.2 Perennial 80 ABCF HDD

Unnamed tributary to Arceneaux 

Bayou

S-B-139 1.7 Intermittent 30 ABCF HDD

Unnamed agricultural canal WB-C-140 1.9 Agricultural 

ditch

30 ABCF Open-cut

Unnamed agricultural canal WB-C-139 2.3 Agricultural

ditch

30 ABCF Open-cut

Unnamed agricultural canal WB-C-136 2.5 Agricultural 

ditch

45 ABCF Open-cut

Unnamed drainage D-C-135 2.5 Drainage 

canal

5 NA c Open-cut

Unnamed tributary to Arceneaux 

Bayou

S-C-138 2.5 Ephemeral 1 ABCF Open-cut

Unnamed tributary to Arceneaux 

Bayou

S-C-134 2.8 Ephemeral 1.5 ABCF Open-cut

Unnamed pond WB-C-133 2.8 Pond 150 ABCF Open-cut

Unnamed drainage D-C-132 2.8 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-131 2.9 Drainage 

canal

5 NA c Open-cut

Unnamed pond WB-D-114 3.1 Pond 30 ABCF Open-cut

Unnamed tributary to Arceneaux 

Bayou

S-D-109 3.1 Intermittent 40 ABCF Open-cut

Unnamed pond WB-D-110 3.2 Pond 55 ABCF Open-cut

Unnamed stream S-D-105 3.2 Intermittent 14 ABCF Open-cut

Unnamed drainage D-D-102 3.6 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-D-100 3.6 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-T-123 3.7 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-B-145 4.3 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-B-146 4.4 Drainage 

canal

5 NA c Open-cut

Unnamed tributary to Little Bayou S-B-117 5.0 Perennial 15 ABCF Open-cut

Unnamed tributary to Little Bayou S-B-116 5.1 Intermittent 15 ABCF Open-cut

Unnamed tributary to Little Bayou S-B-119 5.7 Intermittent 8 ABCF HDD

Little Bayou S-B-109 5.9 Perennial 150 ABCF HDD
APPENDIX F (cont’d) 

F-3 

TABLE F-2 (cont’d)

Waterbodies Potentially Affected by the Non-Liquefaction Facilities

Associated With the Lake Charles Liquefaction Project

Waterbody Name

Waterbody 

Unique ID Milepost Stream Type

Crossing 

Width 

(feet)

Water Quality 

Classification a

Crossing 

Method

Unnamed tributary to Little Bayou S-B-108B 5.9 Intermittent 30 ABCF HDD

Unnamed tributary to Little Bayou S-B-106 6.0 Intermittent 15 ABCF HDD

Unnamed tributary to Little Bayou S-B-105 6.1 Intermittent 6 ABCF HDD

Unnamed drainage D-B-100 7.2 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-109 7.2 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-110 7.2 Drainage 

canal

5 NA c Open-cut

Unnamed tributary to Serpent Bayou S-C-125 8.2 Ephemeral 4 ABCF Open-cut

Unnamed tributary to Serpent Bayou S-C-119 8.2 Ephemeral 7 ABCF Open-cut

Unnamed pond WB-C-118 8.3 Pond 40 ABCF Open-cut

Unnamed tributary to Serpent Bayou S-C-124 8.3 Ephemeral 2 ABCF Open-cut

Unnamed tributary to Serpent Bayou S-C-123 8.3 Ephemeral 2 ABCF Open-cut

Unnamed tributary to Serpent Bayou S-C-122 8.3 Ephemeral 3 ABCF Open-cut

Unnamed tributary to Serpent Bayou S-C-126 8.3 Perennial 8 ABCF Open-cut

Unnamed drainage D-C-201 9.2 Drainage 

canal

5 NA c HDD

Serpent Bayou S-T-110 9.5 Perennial 150 ABCF HDD

Unnamed drainage D-T-107 10.1 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-T-108 10.1 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-T-108 10.3 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-T-107 10.3 Drainage 

canal

2 NA c Open-cut

Unnamed tributary to Serpent Bayou S-T-103 10.5 Perennial 10 ABCF Open-cut

Unnamed tributary to Serpent Bayou S-C-102 10.5 Intermittent 5 ABCF Open-cut

Unnamed drainage D-C-101 10.8 Drainage 

canal

1 NA c Open-cut

Unnamed drainage D-T-101 10.8 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-100 11.3 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-155 11.4 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-T-107 11.4 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-C-153 11.4 Drainage 

canal

3 NA c Open-cut

Mainline 200-3 Loop

Unnamed tributary to East Bayou 

Lacassine

S-B-204 176.0 Intermittent 20 ABCF Open-cut

East Bayou Lacassine S-A-100 176.5 Perennial 135 ABCF d HDD

Unnamed drainage D-T-120 176.9 Drainage 

canal

5 NA c HDD

Unnamed drainage D-T-119 176.9 Drainage 

canal

5 NA c HDD

Unnamed drainage D-T-118 177.1 Drainage 

canal

5 NA c HDD
APPENDIX F (cont’d) 

F-4 

TABLE F-2 (cont’d)

Waterbodies Potentially Affected by the Non-Liquefaction Facilities

Associated With the Lake Charles Liquefaction Project

Waterbody Name

Waterbody 

Unique ID Milepost Stream Type

Crossing 

Width 

(feet)

Water Quality 

Classification a

Crossing 

Method

Unnamed drainage D-C-111 177.3 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-112 177.3 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-C-113 177.3 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-C-114 177.4 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-C-115 177.4 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-B-100 178.5 Drainage 

canal

2 NA c HDD

Unnamed drainage D-T-116 178.5 Drainage 

canal

3 NA c HDD

Unnamed drainage D-C-117 178.6 Drainage 

canal

3 NA c HDD

Indian Bayou Canal S-C-116 178.6 Perennial 70 ABCF HDD

Unnamed drainage D-T-114 178.7 Drainage 

canal

3 NA c HDD

Unnamed drainage D-T-113 178.7 Drainage 

canal

3 NA c HDD

Unnamed drainage D-T-111 179.0 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-T-109 179.0 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-T-109 179.0 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-T-109 179.1 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-T-108 179.4 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-T-107 179.5 Drainage 

canal

3 NA c Open-cut

Unnamed tributary to West Bayou 

Lacassine

S-T-106 179.8 Perennial 20 ABCF Open-cut

Unnamed drainage D-T-105 179.9 Drainage 

canal

3 NA c Open-cut

Unnamed tributary to West Bayou 

Lacassine

S-C-104 180.1 Perennial 8 ABCF Open-cut

Unnamed drainage D-C-105 180.3 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-C-106 180.4 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-C-107 180.6 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-C-108 180.9 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-C-109 181.3 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-C-110 181.3 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-C-126 181.6 Drainage 

canal

3 NA c Open-cut
APPENDIX F (cont’d) 

F-5 

TABLE F-2 (cont’d)

Waterbodies Potentially Affected by the Non-Liquefaction Facilities

Associated With the Lake Charles Liquefaction Project

Waterbody Name

Waterbody 

Unique ID Milepost Stream Type

Crossing 

Width 

(feet)

Water Quality 

Classification a

Crossing 

Method

Unnamed tributary to West Bayou 

Lacassine

S-T-104 181.7 Perennial 8 ABCF Open-cut

Unnamed drainage D-T-102 182.1 Drainage 

canal

3 NA c Open-cut

Unnamed drainage D-C-102 182.1 Drainage 

canal

3 NA c Open-cut

Mainline 200-1 Modifications

Calcasieu River NHD-1 195.6 Perennial 325 ABCFG b,d,f HDD

Unnamed waterbody WB-B-CA621194.8 Perennialg 4,368 NA c HDD

Unnamed stream S-B-CA604194.6 Ephemeral 112 NA c Matted e

Unknown None 195.3 Perennial 8 NA c Matted e

Marsh Bayou None Access 

Road

Perennial 31 ABC Matted e

ABOVEGROUND FACILITIES

Compressor Station 203-A

Unnamed stream WB-C-167 Intermittent 10 ABCF Open-cut

Unnamed agricultural canal D-C-166 Agricultural 

ditch

660 NA c Fill

Unnamed drainage D-T-122 Drainage 

canal

5 NA c Open-cut

Unnamed drainage D-C-170 Drainage 

canal

2 NA c Open-cut

Unnamed drainage D-C-171 Drainage 

canal

2 NA c Open-cut

Columbia Gulf Egan Meter Station

Unnamed tributary to Bayou 

Plaquemine Brule

S-AV-030 Intermittent 8 ABCF Matted e

Unnamed drainage D-D-118 Drainage 

canal

- NA c Matted e

Unnamed drainage None Drainage 

canal

- NA c Matted e

___________________

a Louisiana State Water Quality Classifications (Louisiana Department of Environmental Quality):

A = Primary Contact Recreation

B = Secondary Contact Recreation

C = Propagation of Fish and Wildlife

D = Drinking Supply

E = Oyster Propagation

F = Agriculture

G = Outstanding Natural Resource Waters

b Designated as a section 10 waterbody under the Rivers and Harbors Act. 

c NA = Waterbody has not been designated as a stream by the State of Louisiana.

d Designated as an impaired waterbody on the State of Louisiana’s 2012 Clean Water Act §303(d) List.

e Matted = Waterbody would be matted over during construction activities. In-water pipe installation is not proposed.

f Designated as a Louisiana Natural and Scenic River by the Louisiana Department of Wildlife and Fisheries.

g Delineated as perennial waterbody; subsequently described in Trunkline Gas Company, LLC’s June 29, 2015 filing as 

inundated forest.

APPENDIX G 

WETLANDS AFFECTED BY THE

LAKE CHARLES LIQUEFACTION PROJECT 

APPENDIX G 

G-1 

TABLE G-1

Wetlands Affected by the Lake Charles Liquefaction Project

Milepost/

Facility

Wetland ID

Number

Wetland

Type a

Length 

Crossed 

(feet)

Construction 

Impact 

(acres) b

Operation 

Impact 

(acres)

Impact

Type

PFO 

Conversion 

(acres)c

LIQUEFACTION FACILITY

NA Mosaic 1 Mosaic (PFO) – 42.37 42.37 Fill –

NA Mosaic 2 Mosaic (PFO) – 9.58 9.58 Fill –

NA W105 PEM – 0.32 0.32 Fill –

NA W106 PFO – 1.75 1.75 Fill –

NA W107 PEM – 2.25 2.25 Fill –

NA W109 PFO – 0.05 0.05 Fill –

NA W110 PEM – 0.05 0.05 Fill –

NA W114 PEM – 5.38 5.38 Fill –

NA W115 PSS – 2.00 2.00 Fill –

NA WM-1 PFO – 1.74 1.74 Fill –

NA WM-2 PFO – 2.23 2.23 Fill –

NA WM-3 PFO – 1.01 1.01 Fill –

NA WM-4 PFO – 3.82 3.82 Fill –

NA WM-5 PFO – 1.54 1.54 Fill –

NA WM-6 PFO – 1.76 1.76 Fill –

NA WM-7 PFO – 0.73 0.73 Fill –

NA WM-8 PSS – 2.07 2.07 Fill –

NA WM-9 PFO – 1.93 1.93 Fill –

NA WM-10 PFO – 4.16 4.16 Fill –

NA WM-11 PSS – 19.54 19.54 Fill –

NA WM-12 PFO – 0.99 0.99 Fill –

Liquefaction Facility Subtotal - 105.27 105.27 Fill -

PEM – 8.00 8.00 Fill –

PFO – 21.71 21.71 Fill –

PSS – 23.61 23.61 Fill –

Mosaic (PFO) – 51.95 51.95 Fill –

ADDITIONAL CONSTRUCTION WORKSPACES (ACW)

ACW A W-B-803 PEM – 2.58 2.58 Fill –

W-B-802 PSS – 1.49 1.49 Fill –

WA-808 PSS – 2.36 2.36 Fill –

Mosaic 4 Mosaic (PFO) – 69.50 69.50 Fill –

ACW B W-AV-054 PEM – 0.01 0.01 Fill –

W-AV-055 PEM – 0.54 0.54 Fill –

W-AV-047 PSS – 4.90 4.90 Fill –

Mosaic-MV-7 Mosaic (PEM) – 7.88 7.88 Fill –

Mosaic-MV-8 Mosaic (PFO) – 2.15 2.15 Fill –

ACW C Mosaic-MV-9 Mosaic (PEM) – 1.72 1.72 Fill –

Mosaic-MV-10 Mosaic (PSS) – 1.91 1.91 Fill –

Mosaic-MV-11 Mosaic (PFO) – 0.68 0.68 Fill –
APPENDIX G (cont’d) 

G-2 

TABLE G-1 (cont’d)

Wetlands Affected by the Lake Charles Liquefaction Project

Milepost/

Facility

Wetland ID 

Number

Wetland

Type a

Length 

Crossed 

(feet)

Construction 

Impact 

(acres) b

Operation 

Impact 

(acres)

Impact

Type

PFO 

Conversion 

(acres)c

ACW D Mosaic-MV13Mosaic (PSS) – 1.91 1.91 Fill –

Mosaic-MV14

Mosaic (PFO) – 12.52 12.52 Fill –

ACW Subtotal – 110.15 110.15 Fill –

PEM – 3.13 3.13 Fill –

PFO – 0.00 0.00 Fill –

PSS – 8.75 8.75 Fill –

Mosaic (PEM) – 9.60 9.60 Fill –

Mosaic (PFO) – 84.85 84.85 Fill –

Mosaic (PSS) – 3.82 3.82 Fill –

PIPELINES

Mainline 200-3 Loop

176.0 W-B-200A PEM 2 1.09 0.08 Temp 0.00

176.1 W-B-200C PFO 1,280 0.37 0.03 Temp 0.01

182.1 W-C-100 PSS 1,673 3.92 1.92 Temp 0.00

182.4 W-AV-131 PSS 0 0.00 0.00 Temp 0.00

182.4 W-AV-132 PSS 0 0.01 0.00 Temp 0.00

182.5 W-AV-133 PSS 181 0.33 0.19 Temp 0.00

Mainline 200-3 Loop Subtotal 3,137 5.72 2.22 Temp 0.01

PEM 2 1.09 0.08 Temp 0.00

PFO 1,280 0.37 0.03 Temp 0.01

PSS 1,854 4.26 2.11 Temp 0.00

Mainline Connector

2.6 W-C-137 PSS 1,219 3.12 1.40 Temp 0.00

3.4 W-AT-11 PEM 173 0.41 0.20 Temp 0.00

3.6 W-AT-12 PSS 147 0.51 0.19 Temp 0.00

3.7 W-AT-10 PSS 0 0.25 0.00 Temp 0.00

4.2 W-AT-7 PEM 835 1.96 0.97 Temp 0.00

5.1 W-AT-6 PFO 305 0.74 0.34 Temp 0.21

5.9 W-B-120 PFO 0 0.25 0.00 Temp 0.00

5.9 W-B-121 PSS 0 0.31 0.00 Temp 0.00

5.9 W-B-122 PFO 0 0.11 0.00 Temp 0.00

5.9 W-B-123 PSS 0 0.01 0.00 Temp 0.00

6.3 W-AT-15 PFO 64 0.17 0.08 Temp 0.04

8.3 W-C-121 PFO 188 0.41 0.21 Temp 0.13

10.5 W-AT-3 PSS 367 1.12 0.43 Temp 0.00

11.0 W-C-148 PEM 0 0.05 0.00 Temp 0.00

11.0 W-C-149 PEM 0 0.14 0.00 Temp 0.00

11.4 W-D-125 PEM 0 2.04 0.00 Temp 0.00

Mainline Connector Subtotal 3,297 11.62 3.82 Temp 0.38

PEM 1,008 4.61 1.17 Temp 0.00

PFO 556 1.68 0.63 Temp 0.38

PSS 1,733 5.33 2.02 Temp 0.00
APPENDIX G (cont’d) 

G-3 

TABLE G-1 (cont’d)

Wetlands Affected by the Lake Charles Liquefaction Project

Milepost/

Facility

Wetland ID 

Number

Wetland

Type a

Length 

Crossed 

(feet)

Construction 

Impact 

(acres) b

Operation 

Impact 

(acres)

Impact

Type

PFO 

Conversion 

(acres)c

Mainline 200-1 Modifications- Calcasieu River HDD

194.2 W-B-CA-623 PEM 239 0.71 0.00 Temp 0.00

194.3 W-B-CA-622 PEM 797 2.00 0.00 Temp 0.00

194.5 W-B-CA-606 PFO 0 0.16 0.00 Temp 0.00

194.5 W-B-CA-605 PEM 1,645 3.89 0.00 Temp 0.00

194.7 W-B-CA-607 PSS 0 0.06 0.00 Temp 0.00

195.6 W-E-005 PFO 0 0.64 0.00 Temp 0.00

195.7 W-E-004 PFO 0 0.07 0.00 Temp 0.00

195.7 W-E-001 PEM 3,158 10.61 0.00 Temp 0.00

196.1 W-E-003 PFO 0 0.02 0.00 Temp 0.00

197.6 W-B-CA-619 PFO 0 0.01 0.00 Temp 0.00

197.6 W-B-CA-620 PFO 0 0.20 0.00 Temp 0.00

Mainline 200-1 Subtotal 5,839 18.37 0.00 Temp 0.00

PEM 5,839 17.21 0.00 Temp 0.00

PFO 0 1.10 0.00 Temp 0.00

PSS 0 0.06 0.00 Temp 0.00

PIPELINE TOTALS 12,273 35.71 6.04 Temp 0.39

PEM 6,849 22.91 1.25 Temp 0

PFO 1,836 3.15 0.66 Temp 0.39

PSS 3,587 9.65 4.13 Temp 0

METER STATIONS

Kinder Morgan–Lake Charles

NA W-AV-039 PSS NA 0.18 0.08 Temp and fill 0.00

NA W-AV-041 PSS NA 0.21 0.06 Temp and fill 0.00

Subtotal NA 0.39 0.14 Temp and fill 0.00

PSS NA 0.39 0.14 Temp and fill 0.00

Columbia Gulf–Eagan

NA W-AV-034 PFO NA 0.32 0.16 Temp and fill 0.16

Subtotal NA 0.32 0.16 Temp and fill 0.16

PFO NA 0.32 0.16 Temp and fill 0.16

NGPL–Lakeside

NA W-C-108A PEM NA 0.08 0.08 Fill 0.00

Subtotal NA 0.08 0.08 Fill 0.00

PEM NA 0.08 0.08 Fill 0.00

Gulf Crossing–Perryville

NA W-C-172 PEM NA 0.07 0.00 Temp 0.00

Subtotal NA 0.07 0.00 Temp 0.00

PEM NA 0.07 0.00 Temp 0.00

Texas Gas–Woodlawn

NA W-AV-045 PFO NA 0.04 0.00 Temp 0.00

Subtotal NA 0.04 0.00 Temp 0.00

PFO NA 0.04 0.00 Temp 0.00
APPENDIX G (cont’d) 

G-4 

TABLE G-1 (cont’d)

Wetlands Affected by the Lake Charles Liquefaction Project

Milepost/

Facility

Wetland ID 

Number

Wetland

Type a

Length 

Crossed 

(feet)

Construction 

Impact 

(acres) b

Operation 

Impact 

(acres)

Impact

Type

PFO 

Conversion 

(acres)c

Transco Ragley

NA W-B-CA-603 PEM NA 1.35 0.10 Temp and fill 0.00

Subtotal NA 1.35 0.10 Temp and fill 0.00

PEM NA 1.35 0.10 Temp and fill 0.00

METER STATIONS SUBTOTAL NA 2.25 0.48 Temp and fill 0.16

PEM NA 1.50 0.18 Temp and fill 0.00

PFO NA 0.36 0.16 Temp and fill 0.16

PSS NA 0.39 0.14 Temp and fill 0.00

PROJECT TOTALS 12,273 253.38 221.94 Temp and fill 0.55

PEM 6,849 35.54 12.55 Temp and fill 0.00

PFO 1,836 25.22 22.53 Temp and fill 0.55

PSS 3,587 42.40 36.64 Temp and fill 0.00

Mosaic (PEM) 0 9.60 9.60 Temp and fill 0.00

Mosaic (PFO) 0 136.80 136.80 Temp and fill 0.00

Mosaic (PSS) 0 3.82 3.82 Temp and fill 0.00

____________________

a PEM Palustrine emergent

PFO Palustrine forested

PSS Palustrine scrub-shrub

b Construction Impact (acres) includes both temporary and permanent right-of-way impacts.

c PFO Conversion refers to areas within the PFO systems that, during operation, will be maintained as either a PEM or 

PSS wetland.

NA = Not applicable
APPENDIX H 

BIRDS OF CONSERVATION CONCERN LIKELY TO OCCUR IN THE 

VICINITY OF THE LAKE CHARLES LIQUEFACTION PROJECT 

APPENDIX H 

H-1 

TABLE H-1

Birds of Conservation Concern Likely to Occur in the

Vicinity of the Lake Charles Liquefaction Project

Common Name

Gulf Coastal Prairie 

Region 37

West Gulf Coastal 

Plain/Ouachitas Region 25

Mississippi Alluvial Valley 

Region 26

Audubon’s shearwater 

Band-rumped storm-petrel 

American bittern  

Least bittern   

Little blue heron 

Reddish egret 

Swallow-tailed kite   

Bald eagle   

American kestrel 

White-tailed hawk 

Peregrine falcon  

Yellow rail   

Black rail  

Snowy plover 

Wilson’s plover 

Mountain plover 

American oystercatcher 

Solitary sandpiper   

Lesser yellowlegs 

Upland sandpiper 

Whimbrel 

Long-billed curlew 

Hudsonian godwit   

Marbled dodwit  

Red knot 

Buff-breasted sandpiper   

Chuck-will’s-widow 

Red-headed woodpecker  

Short-billed dowitcher  

Least tern 

Gull-billed tern 

Sandwich tern 

Black skimmer 

Short-eared owl  

Loggerhead shrike  

Sedge wren  

Brown-headed nuthatch 
APPENDIX H (cont’d)

H-2 

TABLE H-1 (cont’d)

Birds of Conservation Concern Likely to Occur in the

Vicinity of the Lake Charles Liquefaction Project

Common Name

Gulf Coastal Prairie 

Region 37

West Gulf Coastal 

Plain/Ouachitas Region 25

Mississippi Alluvial Valley 

Region 26

Bewick’s wren 

Wood thrush  

Sprague’s pipit  

Prairie warbler 

Cerulean warbler  

Prothonotary warbler   

Worm-eating warbler 

Swainson’s warbler   

Louisiana waterthrush 

Kentucky warbler  

Bachman’s sparrow 

Botteri’s sparrow 

Grasshopper sparrow 

Henslow’s sparrow   

LeConte’s sparrow  

Nelson’s sharp-tailed sparrow 

Seaside sparrow 

Smith’s longspur 

Painted bunting   

Orchard oriole  

Dickcissel  

Rusty blackbird 
APPENDIX I 

ACCESS ROADS IDENTIFIED FOR THE 

LAKE CHARLES LIQUEFACTION PROJECT 

APPENDIX I 

I-1 

TABLE I-1

Access Roads Identified for the Lake Charles Liquefaction Project 

Facility/ 

Milepost Road Name 

Permanent or 

Temporary 

Length 

(feet) 

Existing 

Condition 

Upgrades or Improvements 

Needed 

Mainline Connector 

1.1 LA-CALC-0011 Temporary 3,003.4 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

1.9 LA-JEFW-0001-1AR Temporary 4,325.2 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

3.6 LA-JEFW-006-1AR Temporary 200.2 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

3.7 LA-JEFW-008-3AR Temporary 22.1 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

4.0 LA-JEFW-0008-2AR Temporary 3,462.9 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

4.3 LA-JEFW-0008-1AR Temporary 2,883.5 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

4.7 LA-JEFW-0009-1AR Temporary 7,829.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

5.3 LA-JEFW-0012-2AR Temporary 4,777.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

5.8 LA-JEFW-0012-1AR Temporary 8,806.7 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

6.5 LA-JEFW-0013-1AR Temporary 3,590.1 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

7.8 LA-JEFW-0015-1AR Temporary 2,129.7 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

8.3 LA-JEFW-0017-1AR Temporary 4,058.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

8.7 LA-JEFW-0019-1AR Temporary 2,550.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

8.8 LA-JEFW-0019-2AR Temporary 420.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

10.1 LA-JEFW-0026-2AR Temporary 2,716.6 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

10.2 LA-JEFW-0026-1AR Temporary 15,244.6 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

11.4 LA-JEFW-0027-1AR Temporary 6,690.6 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 
APPENDIX I (cont’d) 

I-2 

TABLE I-1 (cont’d)

Access Roads Identified for the Lake Charles Liquefaction Project 

Facility/ 

Milepost Road Name 

Permanent or 

Temporary 

Length 

(feet) 

Existing 

Condition 

Upgrades or Improvements 

Needed 

Mainline 200-3 Loop 

176.0 LA-JEFF-0038-1AR Temporary 340.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

177.7 LA-CALS-0020-1AR Temporary 1,251.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

177.9 LA-CALS-0017-1AR Temporary 2,028.4 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

178.3 LA-CALS-0006-1AR Temporary 557.8 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

178.8 LA-JEFF-033-1AR Temporary 483.5 Open Land Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

179.4 LA-JEFF-0016-1AR Temporary 3,299.4 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

179.6 LA-JEFF-0015-2AR Temporary 450.4 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

179.7 LA-JEFF-0015-1AR Temporary 1,528.6 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

179.7 LA-JEFF-0016-2AR Temporary 769.6 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

180.9 LA-JEFF-0005-1AR Temporary 1,666.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

181.5 LA-JEFF-0003-1AR Temporary 892.4 Agriculture Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

181.7 LA-JEFF-002-1AR Temporary 1,729.2 Agriculture Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

Compressor Station 

Compressor Station 203-A 

CS-203-A Access Road Permanent 1,393.0 Agriculture Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming

Meter Stations 

Texas Gas–Woodlawn 

190.3 200-1 AR-5 Temporary 499.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

Transco Ragley 

203.4 Transco Ragley 

Access Road 

Permanent 151.8 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 
APPENDIX I (cont’d) 

I-3 

TABLE I-1 (cont’d)

Access Roads Identified for the Lake Charles Liquefaction Project 

Facility/ 

Milepost Road Name 

Permanent or 

Temporary 

Length 

(feet) 

Existing 

Condition 

Upgrades or Improvements 

Needed 

US 190 Meter 

208.1 US 190 Meter 

Access Road 

Permanent 7.4 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

Columbia Gulf–Egan 

156.6 Columbia Gulf-Egan 

Access Road 

Permanent 1,687.0 Open Land Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

Gulf Crossing–Perryville 

164.9 Gulf Crossing 

Access Road 

Permanent 335.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

MEP–Perryville 

165.9 MEP Access Road Permanent 1,594.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

TETCO–Allen 

197.0 TETCO Allen 

Access Road 

Permanent 796.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

Mainline 200-1 – Modifications 

Calcasieu River HDD 

194.2 Hecker Road #1 Temporary 909.3 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

194.5 200-1 AR-4 Temporary 1,295.6 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

194.7 200-1 AR-3 Temporary 1,454.4 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

195.7 Hecker Rd # 2 Temporary 6,394.5 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

196.19 200-1 AR-2 Temporary 7,891.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

196.9 Marsh Bayou Rd # 3 Temporary 3,158.7 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

197.6 Marsh Bayou Rd # 1 Temporary 12,622.0 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

197.6 Marsh Bayou Rd # 2 Temporary 6,174.8 Existing dirt 

path 

Depending on weather and 

ground conditions, board road, 

gravel, grading, or side trimming 

Total Temporary 128,107.3 

Total Permanent 5,964.2 

Grand Total 134,071.5 

APPENDIX J 

REFERENCES AND CONTACTS 

APPENDIX J

REFERENCES AND CONTACTS

J-1 

Abbott, R., and E. Bing-Sawyer. 2002. Assessment of Pile-Driving Impacts on the Sacramento Blackfish 

(Othodon microlepidotus). Draft report prepared for the California Department of 

Transportation, District 4. 

Air Quality Dispersion Modeling Report. July 2014. Addendum to PSD Permit Application submitted 

by Trunkline LNG Export, LLC for the Lake Charles Liquefaction Export Terminal to the 

Louisiana Department of Environmental Quality.

American Industrial Hygiene Association. 2013. 2013 ERPG/WEEL Handbook. Available online at 

http://www.aiha.org/get-involved/AIHAGuidelineFoundation/EmergencyResponsePlanning

Guidelines. 

American Press. 2014. Calcasieu River dredging to begin this fall. DiCesare, Frank. July 10, 2014. 

Available online at http://www.americanpress.com/Calcasieu-River-dredging. 

Arkansas Natural Heritage Commission. 2010. Rare Species Search Engine: Find Arkansas Endangered 

Species. Available online at http://www.naturalheritage.com/research-data/rarespeciessearch.aspx. Accessed April 2014. 

Ausenco. 2013. Calcasieu Marine Traffic Simulation Study – Final Report. Prepared for the Port of 

Lake Charles. 

Ausenco. 2014. BG LNG Services, LLC Calcasieu Marine Traffic Simulation Study – Final Report. 

March 2014. 

Bureau of Labor Statistics. 2013. Consumer Price Index – All Urban Consumers. 2014. Available 

online at http://data.bls.gov/cgi-bin/surveymost.

Burt and Grossenheider. 1976. A Field Guide to the Mammals: Field Marks of all North American 

Species Found North of Mexico. 3rd Edition. Houghton Mifflin Company. New York, New 

York. 

C.H. Fenstermaker and Associates, LLC. 2014. Lake Charles LNG Traffic Assessment Study. 

Chennault International Airport. 2014. News & Resources. Available online at http://www.chennault.

org/news-resources/112000-square-foot-hangar-being-built. Accessed July 25, 2014. 

City-Data. 2013. City-Data.com Available online at http://www.city-data.com/. Accessed on 

May 30, 2013. 

Council on Environmental Quality. 1997. Environmental Justice, Guidance under the National 

Environmental Policy Act. Executive Office of the President, Washington, D.C. 

Council on Environmental Quality. 2005. Guidance on the Consideration of Past Actions in Cumulative 

Effects Analysis. June 24, 2005. Executive Office of the President, Council on Environmental 

Quality. Washington, D.C. 

Cowardin, L.M., V. Carter V., F.C. Golet, E.T. LaRoe. 1979. Classification of Wetlands and Deepwater 

Habitats of the United States. U.S. Fish and Wildlife Service Report No. FWS/OBS/-

79/31.Washington, D.C. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-2 

Crone, Anthony J. and Wheeler, Russell L. 2000. Data for Quaternary faults, liquefaction features, and 

possible tectonic features in the Central and Eastern United States, east of the Rocky Mountain 

front. U.S. Geological Survey Open-File Report 00-260. Geological Hazards Team, 

Denver, Colorado. 

Entergy Services/Entergy Gulf State Louisiana/Entergy Gulf States Texas. 2015. Trunkline LNG Iowa: 

Build 138kV Switch Station and Transmission Line Facility Study. April 15, 2015. 

EJO #F4PPGS0549. Available online at http://elibrary.ferc.gov/idmws/DOC_family.asp?

document_id=14340776. Accessed June 2015. 

Environmental Laboratory. 1987. U.S. Army Corps of Engineers Wetland Delineation Manual. 

Technical Report Y-87-1. U.S. Army Engineer Waterways Experiment Station, Vicksburg, 

Mississippi. 

Epstein, J.B., D.J. Weary, R.C. Orndorff, Z.C. Bailey, and R.C. Kerbo. 2002. National Karst Map 

Project. Available online at http://water.usgs.gov/ogw/karst/kig2002/jbe_map.html. Accessed 

April 2014. 

Esslinger, C.G., and B.C. Wilson. 2003. North American Waterfowl Management Plan, Gulf Coast Joint 

Venture: Chenier Plain Initiative. North American Waterfowl Management Plan. Albuquerque, 

New Mexico. Available online at http://www.gcjv.org/docs/ChenierPlainpub.pdf. Accessed May 

2014. 

Federal Emergency Management Agency. 2014. Flood Insurance Rate Map. Panels 0635F and 0470F. 

Available online at https://msc.fema.gov/webapp/wcs/stores/servlet/FemaWelcomeView?storeId

=10001&catalogId=10001&langId=-1. Accessed April 2014. 

Federal Energy Regulatory Commission. 2005. Order amending certificate re Trunkline Gas Company, 

LLC. February 11, 2005. Federal Energy Regulatory Commission. Docket No. CP04-64. 

Federal Energy Regulatory Commission. 2014a. Notice of Applications, CP14-347-000, PF13-9-000. 

Available online at http://elibrary.ferc.gov/idmws/file_list.asp. Accessed July 24, 2014. 

Federal Energy Regulatory Commission. 2014b. Notice of Applications, CP14-517-000, CP14-518-000, 

PF13-14-000. Available online at http://elibrary.ferc.gov/idmws/file_list.asp. Accessed 

July 24, 2014. 

Federal Energy Regulatory Commission. 2014c. Notice to Proceed with Site Preparation for Cameron 

LNG, LLC. Available online at http://elibrary.ferc.gov/idmws/file_list.asp. Accessed 

July 24, 2014. 

Federal Energy Regulatory Commission. 2014d. Order Granting Authorization Under Section 3 of the 

Natural Gas Act and Issuing Certificates, CP13-25-000, CP13-27-000. Available online at 

http://elibrary.ferc.gov/idmws/file_list.asp. Accessed July 24, 2014. 

Fenneman, N.M. and D.W. Johnson. 1946. Physical Divisions of the United States: U.S. Geological 

Survey, scale 1:7,000,000. 

Golden Pass Products. 2014. Golden Pass Products Project Overview; Golden Pass Terminal Expansion 

Project. Available online at http://goldenpassproducts.com/index.cfm/page/8. Accessed 

July 24, 2014. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-3 

Grunden, R., Thomas, L., and Holland, J. 2013. Phase I Cultural Resource Investigations for the Lake 

Charles Liquefaction Project, Calcasieu Parish, Louisiana. TRC Companies, Inc., 

Norcross, Georgia. 

Gulf of Mexico Fishery Management Council. 2005. FINAL Generic Amendment Number 3 for 

Addressing Essential Fish Habitat Requirements, Habitat Areas of Particular Concern, and 

Adverse Effects of Fishing in the following Fishery Management Plans of the Gulf of Mexico: 

Shrimp Fishery of the Gulf of Mexico, United States Water; Red Drum Fishery of the Gulf of 

Mexico; Reef Fish Fishery of the Gulf of Mexico; Coastal Migratory Pelagic Resources 

(Mackerels) in the Gulf of Mexico and South Atlantic; Stone Crab Fishery of the Gulf of Mexico; 

Spiny Lobster in the Gulf of Mexico and South Atlantic; Coral and Coral Reefs of the Gulf of 

Mexico. Available online at 

http://www.gulfcouncil.org/Beta/GMFMCWeb/downloads/FINAL3_EFH_Amendment.pdf. 

Accessed April 2014. 

Gulf of Mexico Fishery Management Council. 2010. Fishery Management Plans & Amendments. 

Available online at http://www.gulfcouncil.org/fishery_management_plans/index.php. Accessed 

April 2014. 

HDR Engineering, Inc. 2012. Trunkline LNG Desktop Investigation of Storm Surge. Lafayette, 

Louisiana. 

Hospitals Center. 2013. County Hospitals. Available online at http://www.hospitalscenter.com/countyhospitals.html. Accessed on May 30, 2013. 

Hunt, C.B. 1967. Physiography of the United States. W. H. Freeman and Company, San 

Francisco, California. 

ICF Jones and Stokes. 2012. Technical Guidance for Assessment and Mitigation of the Hydroacoustic 

Effects of Pile Driving on Fish. Updated October 2012. Available online at http://www.dot.

ca.gov/hq/env/bio/files/Guidance_Manual_2_09.pdf. Accessed March 2015. 

International Energy Agency. 2012a. World Energy Outlook 2012, Executive Summary. Available 

online at http://www.iea.org/publications/freepublications/publication/English.pdf.

International Energy Agency. 2012b. World Energy Outlook 2012, Renewable Energy Outlook. 

Available online at http://www.worldenergyoutlook.org/media/weowebsite/2012/WEO2012 

_Renewables.pdf. 

International Energy Agency. 2013. World Energy Outlook 2013 Factsheet - How will global energy 

markets evolve to 2035? Available online at http://www.worldenergyoutlook.org/media/

weowebsite/factsheets/WEO2013_Factsheets.pdf. 

International Energy Agency. 2014a. World Energy Outlook 2014 Factsheet - How will global energy 

markets evolve to 2040? Available online at http://www.worldenergyoutlook.org/media/

weowebsite/2014/WEO2014FactSheets.pdf. Accessed January 2015. 

International Energy Agency. 2014b. Hydropower. Available online at http://www.iea.org/topics/

renewables/subtopics/hydropower/. Accessed August 2014. 

Interstate Natural Gas Association of America. 2001. INGAA Foundation Natural Gas Pipeline Impact 

Study. Washington, D.C. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-4 

Knezovich, J.P. 1994. Chemical and Biological Factors Affecting Bioavailability of Contaminants in 

Seawater. In J.L. Hamelink, P.F. Landrum, H.L. Bergman, and W.H. Benson (eds.). 

Bioavailability: Physical, Chemical, and Biological Interactions. Lewis Publishers, Boca 

Raton, Florida. 

Laird, P.K. 2014a. Addendum 1: Phase I Cultural Resource Investigations for the Trunkline Lake 

Charles Liquefaction Project, Calcasieu Parish, Louisiana. TRC Companies, Inc., Norcross, 

Georgia. 

Laird, P.K. 2014b. Addendum 1: Phase I Cultural Resource Investigations for the Trunkline Lake 

Charles Liquefaction Project Above-Ground Facilities, Acadia, Allen, Beauregard, Calcasieu, 

Cameron, Jefferson Davis, and Richland Parishes, Louisiana. TRC Companies, Inc., Norcross, 

Georgia. 

Laird, P.K., Thomas, L., and Holland, J. 2013a. Phase I Cultural Resource Investigations for the 

Trunkline Lake Charles Liquefaction Project Mainline 200-3 Loop, Calcasieu and Jefferson 

Davis Parishes, Louisiana. TRC Companies, Inc., Norcross, Georgia. 

Laird, P.K., Thomas, L., and Holland, J. 2013b. Phase I Cultural Resource Investigations for the 

Trunkline Lake Charles Liquefaction Project Mainline Connector, Calcasieu and Jefferson Davis 

Parishes, Louisiana. TRC Companies, Inc., Norcross, Georgia. 

Laird, P.K., Thomas, L., and Holland, J. 2013c. Phase I Cultural Resource Investigations for the 

Trunkline Lake Charles Liquefaction Project Above-Ground Facilities, Acadia, Allen, 

Beauregard, Calcasieu, Cameron, Jefferson Davis, and Richland Parishes, Louisiana. TRC 

Companies, Inc., Norcross, Georgia. 

Lake Charles Clean Energy. 2014. Regulatory Status. Available online at http://lakecharlesclean

energy.com/regulatory-status/. Accessed July 25, 2014. 

Louisiana Department of Environmental Quality. 2000. Descriptions of Louisiana Natural and Scenic 

Rivers. Available online at http://www.deq.louisiana.gov/portal/Portals/0/planning/305b/2002/ 

pdf/305b-AppenidixB.pdf. Accessed April 2014. 

Louisiana Department of Environmental Quality. 2007a. Beauregard Parish Maintenance Plan. 

Available online at http://www.deq.louisiana.gov/portal/Default.aspx?tabid=2381. Accessed 

April 2014. 

Louisiana Department of Environmental Quality. 2007b. Calcasieu Parish Maintenance Plan. Available 

online at http://www.deq.louisiana.gov/portal/tabid/2698/Default.aspx. Accessed April 2014. 

Louisiana Department of Environmental Quality. 2009a. Chicot Aquifer Summary, 2008. Appendix 10 

to the 2009 Triennial Summary Report. Baton Rouge, Louisiana. 

Louisiana Department of Environmental Quality. 2009b. Mississippi River Alluvial Aquifer Summary, 

2008. Appendix 10 to the 2009 Triennial Summary Report. Baton Rouge, Louisiana. 

Louisiana Department of Environmental Quality. 2013a. Email correspondence between Melinda 

Molieri (Louisiana Department of Environmental Quality) and Mike Buckless (Natural Resource 

Group) regarding source water protection areas. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-5 

Louisiana Department of Environmental Quality. 2013b. Water Quality Standards Document. Available 

online at www.deq.louisiana.gov/.../Water%20Quality%20Standards.doc‎. Accessed April 2014. 

Louisiana Department of Environmental Quality. 2013c. 2012 Louisiana Water Quality Inventory: 

Integrated Report (305(b)/303(d)) Final. Available online at http://www.deq.louisiana.gov/portal/

DIVISIONS/WaterPermits/WaterQualityStandardsAssessment/WaterQualityInventorySection305

b/2012IntegratedReport.aspx. Accessed April 2014. 

Louisiana Department of Environmental Quality. 2013d. Email correspondence from Melinda Molieri to 

Jason Sean Lancaster (TRC) regarding source water protection areas. 

Louisiana Department of Environmental Quality. 2014a. Louisiana Ambient Water Monitoring Data. 

http://www.deq.louisiana.gov/portal/tabid/2739/Default.aspx. Accessed October 2014. 

Louisiana Department of Environmental Quality. 2014b. Ambient Air Monitoring Operations. 

Available online at 

http://www.deq.louisiana.gov/portal/DIVISIONS/Assessment/AirFieldServices/Ambient

AirMonitoringProgram.aspx. Accessed April 2014. 

Louisiana Department of Natural Resources, Office of Coastal Management. 2014. Letter dated August 

27, from Karl Morgan (Administrator) to Jason Lancaster (TRC). 

Louisiana Department of Natural Resources. 2007a. Oil and Gas Field Locations, Geographic NAD83. 

Vector Digital Data. Available online at http://dnr.louisiana.gov. Accessed April 2014. 

Louisiana Department of Natural Resources. 2007b. Oil, Gas, and Injection Wells in Louisiana, 

Geographic NAD83. Vector Digital Data. Available online at http://dnr.louisiana.gov. Accessed 

April 2014. 

Louisiana Department of Natural Resources. 2014. Strategic Online Natural Resources Information 

System. Available online at http://sonris.com/. Accessed April 2014. 

Louisiana Department of Transportation and Development and U.S. Geological Survey. 1999. 

Distribution of Saltwater in the Chicot Aquifer System of Southwestern Louisiana, 1995-96. 

Water Resources Technical Report No. 66. Baton Rouge, Louisiana. 

Louisiana Department of Transportation and Development and U.S. Geological Survey. 2004. Thickness 

of the Chicot Aquifer System Surficial Confining Unit and Location of Shallow Sands, 

Southwestern Louisiana. Water Resources Technical Report No. 73. Baton Rouge, Louisiana. 

Louisiana Department of Transportation and Development and U.S. Geological Survey. 2011. Water 

Use in Louisiana, 2010. Water Resources Special Report No. 17. Revised December 2012. 

Baton Rouge, Louisiana. 

Louisiana Department of Wildlife and Fisheries. 2012. Louisiana Natural and Scenic Rivers 

Descriptions and Map. Available online at http://www.wlf.louisiana.gov/louisiana-natural-andscenic-rivers-descriptions-and-map. Accessed May 2014. 

Louisiana Department of Wildlife and Fisheries. 2014a. Telephone and email communications on 

November 10, between J. Rieland (Natural Resource Group, LLC) and C. Gothreaux (LDWF). 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-6 

Louisiana Department of Wildlife and Fisheries. 2014b. Species by Parish List. Available online at 

http://www.wlf.louisiana.gov/wildlife/species-parish-list. Accessed April 2014. 

Louisiana Department of Wildlife and Fisheries. 2014c. Bald Eagle: Haliaeetus leucocephalus. 

Available online at http://www.wlf.louisiana.gov/sites/default/files/pdf/fact_sheet_animal/32259-

Haliaeetus%20leucocephalus/haliaeetus_leucocephalus.pdf. Accessed April 2014. 

Louisiana Geological Society. 2002. Lake Charles 30 x 60 Minute Geologic Quadrangle. Louisiana 

State University, Baton Rouge, LA. 

Louisiana Geological Society. 2003. Crowley 30 x 60 Minute Geologic Quadrangle. Louisiana State 

University, Baton Rouge, LA. 

Louisiana Natural Heritage Program. 2009. Natural Communities of Louisiana. Louisiana Department 

of Wildlife and Fisheries. Available online at 

http://www.wlf.louisiana.gov/sites/default/files/pdf/page_wildlife/6776-

Rare%20Natural%20Communities/LA_NAT_COM.pdf. Accessed May 2014. 

Louisiana Natural Heritage Program. 2013. Letter dated March 7, from Amity Bass (Coordinator) to 

Jason Sean Lancaster (TRC). 

Louisiana Natural Heritage Program. 2014. Natural Communities Tracking List and Fact Sheets. 

Louisiana Department of Wildlife and Fisheries. Available online at http://www.wlf.louis 

iana.gov/wildlife/natural-communities-fact-sheets. Accessed April 2014. 

Louisiana Workforce Commission. 2013. Louisiana Works Department of Labor-Louisiana Labor Force 

Diversity Data. Available online at http://www.laworks.net/Downloads/Employment/

AffirmativeActionPublication_2013.pdf. Accessed on May 27, 2014. 

Maupin M.A. and N.L. Barber. 2005. Estimated Withdrawals from Principal Aquifers in the United 

States, 2000. U.S. Geological Survey Circular 1279. 

Mississippi Museum of Natural Science. 2013. Natural Heritage Program, Seek and Study. Available 

online at http://www.mdwfp.com/seek-study/heritage-program/nhp-online-data.aspx. Accessed 

April 2014. 

Moffatt & Nichol. 2014. Trunkline LNG Export LLC, Lake Charles Liquefaction Project, Marine 

Statistical Analysis. Prepared for Technip. 

National Economic Research Associates. 2014. Updated Macroeconomic Impacts of LNG Exports from 

the United States. NERA Economic Consulting. March 24, 2014. Available online at 

http://www.nera.com/content/dam/nera/publications/archive2/PUB_LNG_Update_0214_FINAL.

pdf. Accessed July 2015. 

National Marine Fisheries Service. 2013. NOAA Habitat Conservation-Habitat Protection-EFH Text 

Descriptions & GIS Data Inventory. Available online at http://www.habitat.noaa.gov/protection/ 

efh/newInv/index.html. Accessed April 2014. 

National Oceanic and Atmospheric Administration. 1998. Climatic Wind Data for the United States. 

Available online at http://www.ncdc.noaa.gov/sites/default/files/attachments/wind1996.pdf. 

Accessed May 2014. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-7 

National Oceanic and Atmospheric Administration. 2004. Climatography of the United States No. 20 

1971-2000. Available online at http://hurricane.ncdc.noaa.gov/climatenormals/clim20/la/

165078.pdf. Accessed April 2014. 

National Oceanic and Atmospheric Administration. 2011. Ocean and Coastal Resource Management in 

Your State: States and Territories Working With NOAA on Ocean and Coastal Management. 

National Oceanic and Atmospheric Administration. Accessed June 15, 2011. 

National Oceanic and Atmospheric Administration. 2013. Public Exposure Guidelines. http://response.

restoration.noaa.gov/oil-and-chemical-spills/chemical-spills/resources/public-exposureguidelines.

html. Accessed December 3, 2013. 

National Oceanic and Atmospheric Association, National Marine Fisheries Service. 2013. Regional 

Climate Trends and Scenarios for the U.S. National Climate Assessment Part 2. Climate of the 

Southeast U.S. Available online at http://www.sercc.com/NOAA_NESDIS_Tech_Report

_Climate_of_the_Southeast_U.S.pdf. Accessed April 2014. 

National Oceanic and Atmospheric Administration, National Marine Fisheries Service. 2015. NMFS 

Pile Driving Calculations. Available online at http://www.dot.ca.gov/hq/env/bio/files/NMFS%

20Pile%20Driving%20Calculations.xls. Accessed June 2015. 

National Weather Service. 2014. National Hurricane Center, Tropical Cyclone Climatology. Available 

online at http://www.nhc.noaa.gov/climo/. Accessed April 2014. 

O’Rourke,‎ T.D.,‎ and‎ M.C.‎ Palmer.‎ ‎ 1996.‎ ‎ Earthquake‎ Performance‎ of‎ Gas‎ Transmission‎ Pipelines.‎

Earthquake Spectra, Vol. 12, No. 3, pp. 493 – 527. 

Observ’ER.‎ ‎ 2013.‎ ‎ Worldwide‎ Electricity‎ Production‎ from‎ Renewable‎ Energy‎ Sources‎ – Facts and 

Figures Series. Fifteenth Inventory. Available online at http://www.energiesrenouvelables.org/observer/html/inventaire/pdf/15e-inventaire-Chap01-Eng.pdf.

Occupational Safety and Health Administration. 1999. OSHA Technical Manual. Available online at 

https://www.osha.gov/dts/osta/otm/otm_i/otm_i_1.html. Accessed November 2014. 

Oestman, R., D. Buehler, J. Reyff, and R. Rodkin. 2009. Technical Guidance for Assessment and 

Mitigation of the Hydroacoustic Effects of Pile Driving on Fish. Report by ICF Jones & Stokes 

and Illingworth and Rodkin Inc. Available online at http://www.dot.ca.gov/hq/env/bio/

files/Guidance_Manual_2_09.pdf. Accessed May 2014. 

Orr, T., S. Herz, and D. Oakley. 2013. Evaluation of Lighting Schemes for Offshore Wind Facilities and 

Impacts to Local Environments. U.S. Dept. of the Interior, Bureau of Ocean Energy 

Management, Office of Renewable Energy Programs, Herndon, Virginia. Available online at 

http://www.data.boem.gov/PI/PDFImages/ESPIS/5/5298.pdf. Accessed April 2014. 

Peterson, R.T. 1980. Peterson Field Guide to Eastern Birds: Fourth Edition (Peterson Field Guides). 

Houghton Mifflin Company. New York, New York. 

Philips, J. 2014. Some councilmen losing patience with Mardi Gras Boardwalk. Available online at 

http://www.americanpress.com/news/local/City-Council-2-25-14. Accessed July 25, 2014. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-8 

Pierorazio, A.J., K. Thomas, K, Q.A. Baker, D.E. Ketchum. 2005. An Update to the Baker–Strehlow–

Tang Vapor Cloud Explosion Prediction Methodology Flame Speed Table, Process Safety 

Progress (Vol.24, No.1), March 2005. 

Port of Lake Charles. 2014. Port Reveals Findings of New Calcasieu Ship Channel Traffic Study. 

Available online at http://portlc.com/port-reveals-findings-of-new-calcasieu-ship-channel-trafficstudy/. Accessed November 2014. 

Professional Service Industries, Inc. 2014. Geotechnical Engineering Report. Trunkline LNG Lake 

Charles Plant Liquefaction Project. Oakbrook Terrace, IL. 

Public Schools K12. 2014. Public Schools K12. Available online at http://publicschoolsk12.com/. 

Accessed on May 27, 2014. 

Radbruch-Hall, D.H., R.B. Colton, W.E. Davies, Ivo Lucchitta, B.A. Skipp, and D.J. Varnes. 1982. 

Landslide Overview Map of the Conterminous United States, Geological Survey Professional 

Paper 1183, U.S. Geological Survey, Washington. 

Sasol Ltd. 2014. Sasol Louisiana Project. Available online at http://www.sasollouisianaprojects.com/

page.php?page=projects. Accessed July 24, 2014. 

SCT&E LNG, LLC. 2014. Application for Long-Term, Multi-Contract Authorization to Export 

Liquefied Natural Gas to Free Trade Counties, FE Docket No, 14-89-LNG. Available online at 

http://energy.gov/sites/prod/files/2014/07/f17/14_89_lng.pdf. Accessed July 24, 2014. 

Society of Fire Protection Engineers. 2008. The SFPE Handbook of Fire Protection Engineering. 

Soil Survey Staff. 1993. Soil survey manual. Soil Conservation Service. U.S. Department of 

Agriculture Handbook 18. Washington, D.C. 

Soil Survey Staff. 2014. Web Soil Survey. Natural Resources Conservation Service, United States 

Department of Agriculture. Available online at http://websoilsurvey.nrcs.usda.gov/. Accessed 

April 2014. 

Southwest Louisiana Economic Development Alliance. 2014a. 2012-2019 Southwest Louisiana 

Economic Development Alliance Projects Report: Detailed. Available online at 

http://allianceswla.org/Images/Interior/2012-2019%20swla%20projects%20%20report%20detai

led%201.7.14.pdf. Accessed June 2014. 

Southwest Louisiana Economic Development Alliance. 2014b. Southwest Louisiana Project Report 

2012-2019. Updated 5.13.14. Available online at 

http://allianceswla.org/Images/Interior/20122019%20

cap%20ex%20totals%20with%20job%20numbers%205.13.14.pdf. Accessed June 2014. 

Stadlar, J.H. and D.P. Woodbury. 2009. Assessing the Effects to Fishes from Pile Driving: Application 

of new hydroacoustic criteria. Inter-noise 2009. August 23-26, 2009, Ottawa, Canada. 

Stevenson, D.A. and R.P. McCulloh. 2001. Earthquakes in Louisiana. Public Information Series 7. 

Louisiana Geological Survey, Baton Rouge, Louisiana, USA. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-9 

Stoeser, D.B., G.N. Green, L.C. Morath, W.D. Heran, A.B. Wilson, D.W. Moore, and B.S. Van Gosen. 

2005. Preliminary Integrated Geologic Map Databases for the United States Central States: 

Montana, Wyoming, Colorado, New Mexico, Kansas, Oklahoma, Texas, Missouri, Arkansas, and 

Louisiana. USGS Open-File Report. 2005-1351. Denver, CO. Available online at http://pubs.

usgs.gov/of/2005/1351/. Accessed April 2014. 

Stroud, Hubert B., and Hanson, Gerald T. 1981. Arkansas Geography: The Physical Landscape and the 

Historical-Cultural Setting. Little Rock: Rose Publishing Company. 

Sutton, A. and M. Sutton. 1985. Eastern Forests. Alfred A. Knopf, Inc., New York. 

Tetra Tech, Inc. 2014. Trunkline LNG Supplemental Soil Investigation August 2013. Austin, TX. 

Tolunay-Wong Engineers, Inc. 2015. Geotechnical Investigation, 203A Compressor Station, Calcasieu 

Parish, LA. TWEI No. 14.14.178. Prepared for Wood Group Mustang, Inc. July 2015. 

Houston, Texas.

Trinity Consultants. 2014a. Air Quality Dispersion Modeling Report – Addendum to PSD Permit 

Application (submitted in July 2014). Trunkline LNG Export, LLC Lake Charles Liquefaction 

Export Terminal. 

Trinity Consultants. 2014b. Title V/PSD Permit Application-Revised, Trunkline LNG Export, LLC Lake 

Charles Liquefaction Export Terminal. 

Trinity Consultants. 2014c. Part 70 Title V Permit Application, Trunkline Gas Company – 203-A 

Compressor Station, Part 70 Minor Source Permit Permit Application. 

Trinity Consultants. 2014d. Title V Permit Amendment, Trunkline Gas Company-Longville Compressor 

Station, Permit Amendment: Minor Modification. 

Trunkline LNG Company, LLC. 2014. Trunkline LNG Company, LLC Semi-Annual Report as required 

by Opinion No. 796 issued April 29, 1977, for the period July 1 through December 31, 2013. 

February 13, 2014. Federal Energy Regulatory Commission. Docket No. CP74-138 et al. 

U.S. Army Corps of Engineers. 2010. Regional Supplement to the Corps of Engineers Wetland 

Delineation Manual: Atlantic and Gulf Coastal Plain Region (Version 2.0), ed. J. S. Wakeley, R. 

W. Lichvar, and C. V. Noble. ERDC/EL TR-10-20. Vicksburg, MS: U.S. Army Engineer 

Research and Development Center. 

U.S. Army Corps of Engineers. 2013a. Mississippi Valley Division Navigable Waters (Section 10) of 

the United States. Available online at 

http://www.mvd.usace.army.mil/Portals/52/docs/11_MVD_navigable_waters.pdf. Accessed May 

2014. 

U.S. Army Corps of Engineers. 2013b. Letter dated March 19, from Martin Mayer (Chief, Regulatory 

Branch) to Jason Lancaster (TRC). 

U.S. Army Corps of Engineers. 2015. Projects – Calcasieu River & Pass. Available online at 

http://www.mvn.usace.army.mil/About/Projects/CalcasieuRiverPass,LA.aspx. Accessed 

February 2015. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-10 

U.S. Census Bureau. 2014a. State & County QuickFacts. Available online at http://quickfacts.census.

gov/qfd/index.html. Accessed on February 14, 2014. 

U.S. Census Bureau. 2014b. American Fact Finder. Available online at http://factfinder2.census.gov/

faces/tableservices/jsf/pages/productview.xhtml?pid=DEC_10_DP_DPDP1. Accessed May 27, 

2014. 

U.S. Climate Change Science Program. 2008. Impacts of Climate Change and Variability on 

Transportation Systems and Infrastructure: Gulf Coast Study, Phase I. A Report by the U.S. 

Climate Change Science Program and the Subcommittee on Global Change Research Savonis, M. 

J., V.R. Burkett, and J.R. Potter (eds.). Department of Transportation, Washington, D.C., 445 pp. 

U.S. Department of Agriculture, Natural Resources Conservation Service. 2005. Plant Guide: Chinese 

Privet. Available online at http://plants.usda.gov/plantguide/pdf/pg_lisi.pdf. Accessed April 

2014. 

U.S. Department of Agriculture, Natural Resources Conservation Service. 2012. Introduced, Invasive, 

and Noxious Plants, Federal Noxious Weed List. Available online at http://plants.usda.gov/java/

AdvancedSearchServlet?pfa=l48&statefips=US22&fed_nox_status_ind=nw&Synonyms=all&vie

wby=sciname. Accessed May 2014. 

U.S. Department of Agriculture. 2014. Kisatchie National Forest: Silviculture and Timber. Forest 

Service. Available online at 

http://www.fs.usda.gov/detail/kisatchie/landmanagement/resourcemanage

ment/?cid=fsbdev3_024690. Accessed April 2014. 

U.S. Department of Energy, Office of Fossil Energy. 2013a. Order Granting Long-term Multi-contract 

Authorization to Export Liquefied Natural Gas by Vessel From the Proposed Gasfin LNG Export 

Project in Cameron Parish, Louisiana, to Free Trade Agreement Nations. Available online at 

http://www.fossil.energy.gov/programs/gasregulation/authorizations/Orders_Issued_2013/ord325

3.pdf. Accessed July 24, 2014. 

U.S. Department of Energy, Office of Fossil Energy. 2013b. Order Granting Long-term Multi-contract 

Authorization to Export Liquefied Natural Gas by Vessel From the Proposed Venture Global 

LNG Project in Cameron Parish, Louisiana to Free Trade Agreement Nations. Available online 

at http://venturegloballng.com/wp-content/uploads/2013/09/ord3345.pdf. Accessed July 24, 

2014. 

U.S. Department of Energy. 2008. Temporary Emergency Exposure Limits for Chemicals: Methods and 

Practice, DOE Handbook, DOE-HDBK-1046-2008. 

U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration. 2014a. 

Facts and Stats. Available online at 

http://opsweb.phmsa.dot.gov/pipelineforum/factsandstats/pipeline-101/. Accessed October 2014. 

U.S. Department of Transportation, Pipeline, and Hazardous Materials Safety Administration. 2014b. 

Pipeline Incidents Reports. Available online at http://primis.phmsa.dot.gov/comm/reports/safety/

PSI.html?nocache=9681. Accessed October 2014. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-11 

U.S. Energy Information Administration. 2013. Annual Energy Outlook 2014 Early Release Overview. 

Report No. DOE/EIA-0383ER(2014). Available online at http://www.eia.gov/forecasts/aeo/

er/early_elecgen.cfm?src=Nuclear-b3.

U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards. New Source 

Review Workshop Manual. 

U.S. Environmental Protection Agency. 1974. Information on Levels of Environmental Noise Requisite 

to Protect Public Health and Welfare with an Adequate Margin of Safety. EPA/550/9-74-004. 

242 pp. 

U.S. Environmental Protection Agency. 1990. Draft New Source Review Workship Manual. Available 

on: http://www.epa.gov/ttn/nsr/gen/wkshpman.pdf. Accessed April 2014. 

U.S. Environmental Protection Agency. 1996. 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. 

U.S. Environmental Protection Agency. 2005a. State/Area/County Report Areas with a Maintenance 

Plan Requirement Under Section 110(a) (1) of the CAA. Available online at http://www.epa.gov/

airquality/greenbook/fmcs.html#LOUISIANA. Accessed April 2014. 

U.S. Environmental Protection Agency. 2006. 2004 Toxic Release Inventory Sites in Louisiana, 

Geographic NAD83, [toxic_release_inventory_site_LA_EPA_2004]: US EPA, Dallas, TX. 

Available online at https://catalog.data.gov/dataset/2004-toxic-release-inventory-sites-inlouisiana

-geographic-nad83-epa-2006-toxic-release-in-2004. Assessed April 2014. 

U.S. Environmental Protection Agency. 2008. Sole Source Aquifers. EPA Region 6. Dallas, Texas. 

U.S. Environmental Protection Agency. 2012. Sole Source Aquifer Protection Program. Available 

online at http://www.epa.gov/region6/water/swp/ssa/factshee.htm. Accessed April 2014. 

U.S. Environmental Protection Agency. 2013a. Clean Energy. Available online at http://www.epa.

gov/cleanenergy/energy-and-you/affect/natural-gas.html. 

U.S. Environmental Protection Agency. 2013b. EPA’s Region 6 Office, Sole Source Aquifers. 

Available online at http://www.epa.gov/region6/water/swp/ssa/maps.htm. Accessed May 2014. 

U.S. Environmental Protection Agency. 2013c. Level III and IV Ecoregions of the Continental United 

States. Available online at http://www.epa.gov/wed/pages/ecoregions/level_iii_iv.htm. Accessed 

April 2014. 

U.S. Environmental Protection Agency. 2013d. National Priorities List. Available online at http://www.

epa.gov/superfund/sites/query/queryhtm/nplfin.htm#LA. Accessed May 2013. 

U.S. Environmental Protection Agency. 2014a. Climate Impacts in the Southeast. Available online at 

http://www.epa.gov/climatechange/impacts-adaptation/southeast.html. Accessed April 2014. 

U.S. Environmental Protection Agency. 2014b. National Ambient Air Quality Standards. Available 

online at http://www.epa.gov/air/criteria.html. Accessed April 2014. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-12 

U.S. Environmental Protection Agency. 2014c. Endangerment and Cause or Contribute Findings for 

Greenhouse Gases under Section 202(a) of the Clean Air Act. Available online at 

http://www.epa.gov/climatechange/endangerment/index.html. Accessed April 2014. 

U.S. Environmental Protection Agency. 2014d. Prevention of Significant Deterioration Basic 

Information. Available online at http://www.epa.gov/NSR/psd.html#best. Accessed April 2014. 

U.S. Environmental Protection Agency. Acute Exposure Guideline Levels. Available online at 

http://www.epa.gov/oppt/aegl/pubs/chemlist.htm. December 3, 2013. 

U.S. Environmental Protection Agency. Dose-Response Assessment for Assessing Health Risks 

Associated With Exposure to Hazardous Air Pollutants. http://www2.epa.gov/fera/doseresponse-assessment-assessing-health-risks-associated-exposure-hazardous-air-pollutants. 

Accessed July 3, 2014. 

U.S. Fish and Wildlife Service. 2002. Colonial-Nesting Waterbirds, a Glorious and Gregarious Group. 

Arlington, Virginia. Available online at http://www.fws.gov/birds/waterbird-fact-sheet.pdf. 

Accessed May 2014. 

U.S. Fish and Wildlife Service. 2003. Recovery plan for the red-cockaded woodpecker (Picoides 

borealis): second revision. U.S. Fish and Wildlife Service, Atlanta, Georgia. Available online at 

http://www.fws.gov/rcwrecovery/recovery_plan.html. Accessed April 2014. 

U.S. Fish and Wildlife Service. 2008a. Birds of Conservation Concern 2008. Arlington, Virginia. 

Available online at http://www.fws.gov/migratorybirds/NewReportsPublications/SpecialTopics/ 

BCC2008/BCC2008.pdf. Accessed April 2014. 

U.S. Fish and Wildlife Service. 2008b. Red-cockaded Woodpecker Factsheet. Available online at 

http://www.fws.gov/rcwrecovery/files/rcwoodpecker.pdf. Accessed April 2014. 

U.S. Fish and Wildlife Service. 2011. American Chaffseed (Schwalbea americana). Available online at 

http://www.fws.gov/raleigh/species/es_american_chaffseed.html. Accessed May 2014. 

U.S. Fish and Wildlife Service. 2012. Email dated November 27, from Patti Holland (Acting Field 

Supervisor) to Jason Lancaster (TRC). 

U.S. Fish and Wildlife Service. 2013a. National Wetland Inventory. Online: http://www.fws.gov/wet

lands/. Accessed on March 19, 2014. 

U.S. Fish and Wildlife Service. 2013b. Division of Bird Habitat Conservation-Migratory Bird Joint 

Ventures. Available online at http://www.fws.gov/birdhabitat/JointVentures/index.shtm. 

Accessed April 2014. 

U.S. Fish and Wildlife Service. 2013c. Email dated March 11, from Joshua Marceaux (Fish and Wildlife 

Biologist) to Jason Lancaster (TRC). 

U.S. Fish and Wildlife Service. 2014a. Letter dated January 9, from Brad Rieck (Deputy Field 

Supervisor) to Bill Kendrick (Trunkline Gas Company, LLC). 

U.S. Fish and Wildlife Service. 2014b. Letter dated March 31, from Deborah Fuller (Acting Supervisor) 

to Jason Lancaster (TRC). 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-13 

U.S. Fish and Wildlife Service. 2014c. Lacassine National Wildlife Refuge. Available online at 

http://www.fws.gov/swlarefugecomplex/lacassine/. Accessed June 2014. 

U.S. Forest Service. 2014. Lygodium japonicum. Available online at http://www.fs.fed.us/database/feis/ 

plants/fern/lygspp/all.html. Accessed April 2014. 

U.S. Geological Survey. 1998. Ground Water Atlas of the United States: Arkansas, Louisiana, 

Mississippi. Hydrologic Investigations Atlas 730-F. Robert A. Renken. Reston, Virginia. 

U.S. Geological Survey. 2000. Chinese Tallow: Invading the Southeastern Coastal Plain. Available 

online at http://www.nwrc.usgs.gov/factshts/154-00.pdf. Accessed July 2014. 

U.S. Geological Survey. 2003. Principal Aquifers of the 48 Conterminous United States, Hawaii, Puerto 

Rico, and the U.S. Virgin Islands: U.S. Geological Survey, Madison, Wisconsin. 

U.S. Geological Survey. 2008. National Seismic Hazard Maps. Available online at http://earthquake.

usgs.gov/hazards/apps/map/ Accessed April 2014. 

U.S. Geological Survey. 2009a. 2009 Minerals Yearbook: Louisiana. Available online at 

http://minerals.usgs.gov/minerals/pubs/state/2009/myb2-2009-la.pdf. Accessed April 2014. 

U.S. Geological Survey. 2009b. 2009 Minerals Yearbook: Mississippi. Available online at http://miner

als.usgs.gov/minerals/pubs/state/2009/myb2-2009-ms.pdf. Accessed April 2014. 

U.S. Geological Survey. 2009c. Significant United States Earthquakes, 1568-2009. Available online at 

http://nationalatlas.gov/mld/quksigx.html. Accessed July 2014.

U.S. Geological Survey. 2013a. The Severity of an Earthquake. Available online at http://pubs.

usgs.gov/gip/earthq4/severitygip.html. Accessed February 2015. 

U.S. Geological Survey. 2013b. Active Mines and Mineral Processing Plants in the United States. 

Available online at http://mrdata.usgs.gov/mineral-resources/active-mines.html. Accessed 

April 2014. 

U.S. Geological Survey. 2013c. Mineral Resource Data System. Available online at http://mrdata.

usgs.gov/mineral-resources/mrds-us.html. Accessed April 2014. 

U.S. Global Change Research Program. 2014. Climate Change Impacts in the United States, U.S. 

National Climate Assessment. Available on line at http://www.nca2014.globalchange.gov/report. 

Accessed July 24, 2014 

URS Corporation. 2014. Site-Specific Seismic and Tsunami Hazard Evaluation of the Trunkline LNG 

Facility in Lake Charles, Louisiana. Revised March 17, 2014. Oakland, California. 

USA Cops. 2013. USA Cops. Available online at http://www.usacops.com. Accessed on May 30, 2013. 

USA Fire & Rescue. 2013. USA Fire & Rescue. Available online at http://www.usafireandrescue.com/. 

Accessed on May 30, 2013. 
APPENDIX J

REFERENCES AND CONTACTS (cont’d)

J-14 

Venture Global LNG, LLC. 2013. Application for Long-Term Authorization to Export Liquefied 

Natural Gas to Free Trade Counties, FE Docket No, 13-69-LNG. Available online at 

http://www.fossil.

energy.gov/programs/gasregulation/authorizations/2013_applications/13_69_lng.pdf. Accessed 

July 24, 2014. 

Venture Global LNG, LLC. 2014. Application for Long-Term Authorization to Export Liquefied 

Natural Gas to Free Trade Counties, FE Docket No, 14-88-LNG. Available online at 

http://energy.gov/fe/downloads/venture-global-lng-llc-14-88-lng. Accessed September 8, 2014. 

Waller LNG Services, LLC. 2012. Application for Long-Term Authorization to Export Liquefied 

Natural Gas to Free Trade Counties, FE Docket No, 12-152-LNG. 2012. Available online 

at http://www.fossil.energy.gov/programs/gasregulation/authorizations/2012_applications/

Waller_LNG_Services,_LLC_12-152-LNG_.html. Accessed July 24, 2014. 

Yellowbook. 2013. Yellowbook. Available online at http://www.yellowbook.com/yellow-pages/?what= 

hotels&where=louisiana. Accessed on May 30, 2013. 
APPENDIX K 

LIST OF PREPARERS 

APPENDIX K 

LIST OF PREPARERS

K-1 

Federal Energy Regulatory Commission

Crosley, Shannon – Environmental Project Manager, Executive Summary, Proposed Action, Soils, 

Cumulative Impacts 

B.S., Natural Resources Management, 1998, University of Maryland 

Harris, Jessica – Deputy Project Manager, Alternatives, Air Quality and Noise, Pipeline Reliability 

and Safety 

M.S., Energy Policy and Climate, 2015, Johns Hopkins University 

B.S., Mechanical Engineering, 2006, Clark Atlanta University

Allen, Christine –Water Resources, Wetlands, Vegetation, Wildlife and Aquatic Resources, Special 

Status Species 

B.S., Marine Biology, 2005, University of North Carolina at Wilmington 

Bathrick, Karla – LNG Reliability and Safety 

M.E., Environmental Engineering/Project Management, 2008, University of Maryland 

B.S., Chemical Engineering, 2003, University of Maryland 

Boros, Laurie – Cultural Resources 

B.A., Anthropology/Archaeology, 1980, Queens College, C.U.N.Y. 

Bowman, Kevin – Land Use 

B.S., Chemistry, McDaniel College, 2010 

B.S., Environmental Science, 2009, McDaniel College 

Glaze, James – Geology 

B.S., Geology, 1975, California Lutheran University 

Nguyen, Thach – LNG Reliability and Safety 

B.S., Mechanical Engineering 2004, University of Texas at Austin 

Natural Resource Group, LLC

Lowell, Fran – Principal and Project Manager, Quality Assurance Review, Cumulative Impacts 

M.A., Public Affairs – Energy, Environment, and Technology, 1992, University of Minnesota 

B.A., Biology, 1976, Dowling College, New York

Cole, Brian – Deputy Project Manager, Proposed Action 

B.S., Environmental Biology, 1998, University of South Carolina 

Buckless, Michael – Geology, Soils 

B.S., Environmental Soil Science and Management, 2013, University of Rhode Island 

Garvin, Claire – Surface Water, Wetlands, Vegetation 

M.S., Marine Science, 2005, College of William and Mary, Virginia 

B.S., Biology, 2000, University of Pittsburgh at Johnstown 

Grissom, Lindsay – Socioeconomics 

B.S., Marine Biology, 2003, Texas A&M University, Galveston 
APPENDIX K 

LIST OF PREPARERS (cont’d)

K-2 

Holden, Steve – Groundwater, Geology, Soils 

M.S., Natural Resources, 2004, University of Rhode Island, Kingston 

B.S., Water and Soil Science, 2001, University of Rhode Island, Kingston 

Jensen, Bart– Alternatives 

B.S., Natural Resources and Environmental Studies, 1992, University of Minnesota 

Koester, Mike – Pipeline Reliability and Safety 

B.S., Environmental Management, 2001, University of South Alabama 

Lee, Jennifer – Land Use 

B.A., Environmental Studies and Geography, 1995, University of St. Thomas, Minnesota 

Lyons, Tina – Quality Assurance Review, Technical Editor, Introduction 

B.S., Genetics and Cell Biology, 1999, University of Minnesota, Twin Cities 

B.S., Ecology, Evolution, and Behavior, 1996, University of Minnesota, Twin Cities 

Pincoske, Jeremy – Cultural Resources 

B.A., Anthropology, 1988, State University of New York at Stony Brook 

Piper, Erin –Aquatic Resources, Essential Fish Habitat 

M.S., Oceanography, 2010, Texas A&M University, Texas 

B.S., Ocean and Coastal Resources, 2007, Texas A&M University at Galveston, Texas 

Rieland, Janelle –Wildlife, Threatened and Endangered Species 

B.S., Wildlife and Fisheries, 2002, University of Minnesota 

Wright, Kevin – Air Quality, Noise 

B.S., Science Education, 1976, University of Maryland, College Park 

B.S., Environmental Sciences, 1974, University of Maryland, College Park 
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL 

IMPACT STATEMENT

L-i

Trunkline Gas Company, LLC, Lake Charles LNG Company, LLC,

and Lake Charles LNG Export, LLC

LAKE CHARLES LIQUEFACTION PROJECT 

Appendix L – Responses to Comments on the Draft Environmental Impact Statement

INDEX

Document Number/Commentor Page

FEDERAL AGENCIES.......................................................................................................................L-1

FA1 – U.S. Department of the Interior, Office of Environmental Policy and Compliance ......L-1

FA2 – National Oceanic and Atmospheric Administration, National Marine Fisheries

Service ...........................................................................................................................L-2

FA3 – U.S. Environmental Protection Agency .........................................................................L-3

STATE AGENCIES...........................................................................................................................L-10

SA1 – Louisiana Department of Wildlife and Fisheries .........................................................L-10

COMPANIES AND ORGANIZATIONS.........................................................................................L-13

CO1 – Magnolia LNG LLC ....................................................................................................L-13

CO2 – Sierra Club...................................................................................................................L-19

INDIVIDUALS...................................................................................................................................L-38

IND1 – Margaret Kuttner, Thomas M. Bergstedt, John E. Bergstedt.....................................L-38

APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT

Federal Agencies

L-1

FEDERAL AGENCIES

FA1 – U.S. Department of the Interior, Office of Environmental 

Policy and Compliance

FA1-1 Comment acknowledged.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-2

FA2 – National Oceanic and Atmospheric Administration, 

National Marine Fisheries Service

FA2-1 Comment acknowledged. Table 1.5-1 and section 4.6.3.3 of the final

environmental impact statement (EIS) have been updated to reflect that 

essential fish habitat consultation has been completed.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-3

FA3 – U.S. Environmental Protection Agency
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-4

FA3 – U.S. Environmental Protection Agency (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-5

FA3 – U.S. Environmental Protection Agency (cont’d)

FA3-1 We disagree. While the U.S. Department of Energy (DOE) Addendum 

provides certain general estimates and characterizations regarding potential 

environmental impacts associated with natural gas production, it does not 

specifically relate to impacts from the Lake Charles Liquefaction Project. 

Moreover, the DOE Addendum states that by preparing this discussion, the 

DOE "... is going beyond what NEPA [the National Environmental Policy 

Act] requires. While DOE has made broad projections about the types of 

resources from which additional production may come, DOE cannot 

meaningfully estimate where, when, or by what method any additional natural 

gas would be produced. Therefore, DOE cannot meaningfully analyze the 

specific environmental impacts of such production, which are nearly all local 

or regional in nature." 
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-6

FA3 – U.S. Environmental Protection Agency (cont’d)

FA3-2 Greenhouse gas emissions associated with construction and operation of the 

project are discussed in sections 4.11.1.3, 4.11.14, and 4.11.1.5. Greenhouse 

gas emissions associated with construction and operation of the proposed 

liquefaction facility are shown in tables 4.11.1-7 and 4.11.1-12.

FA3-3 The greenhouse gas emissions associated with construction and operation of the 

project are discussed in section 4.11.1. Federal Energy Regulatory 

Commission (FERC or Commission) staff completed an impact analysis that 

was appropriate for the scale of the project. In reference to predicting climate 

change impacts, FERC staff used guidance provided by the Council on 

Environmental Quality (CEQ) in its February 18, 2010 memorandum titled 

"Draft NEPA Guidance on Consideration of the Effect of Climate Change and 

Greenhouse Gas Emissions," which states that "agencies should recognize the 

scientific limits of their ability to accurately predict climate change effects, 

especially of a short-term nature, and not devote effort to analyzing wholly 

speculative effects." On December 18, 2014, the CEQ released a revised draft 

greenhouse gas emission guidance memo. As recommended in this new 

guidance, to the extent practicable, FERC staff incorporated additional 

guidance provided by this memo into the greenhouse gas emission analysis 

completed for the project. As such, FERC staff has presented the greenhouse 

gas emissions associated with the project and the potential impacts of 

greenhouse gas emissions in relation to climate change. There is no current 

methodology or policy guidance to determine how the project’s incremental 

contribution to greenhouse gases would translate into physical effects on the 

global environment. The emissions would increase the atmospheric 

concentration of greenhouse gases, in combination with past and future 

emissions from all other sources, and contribute incrementally to climate 

change that produces the impacts described in sections 4.11.1 and 4.13.2.11 of 

the EIS. However, it cannot be determined whether or not the project’s 

contribution to cumulative impacts on climate change would be significant. 

See the response to comment FA3-1 regarding impacts from natural gas 

production. We recognize that greenhouse gases are also emitted from the 

combustion of natural gas by end users. However, these emissions should not 

be attributed to this project because fuel supply is generally demand-driven 

rather than supply-driven. As such, regardless of whether the project is 

constructed, end users would still have a need for fuel, and would need to either 

rely on the importation of natural gas from another source or on another fuel. 

Depending on that other fuel, the end use could potentially generate more or 

fewer greenhouse gas emissions (per unit of energy supplied) than natural gas. 
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-7

FA3 – U.S. Environmental Protection Agency (cont’d)

FA3-4 A greenhouse gas Best Available Control Technology (BACT) analysis was 

performed for the proposed liquefaction facility as summarized in 

section 4.11.13 and provided to the Louisiana Department of Environmental 

Quality (LDEQ) in Lake Charles LNG Export Company, LLC and Lake 

Charles LNG Company, LLC’s (Lake Charles LNG, collectively) air permit 

application. Proposed greenhouse gas BACT for the liquefaction facility 

includes use of low carbon fuels, combustion equipment (turbines, thermal 

oxidizers, emergency back-up and firewater pump engines) designed as 

operational energy efficient in accordance with U.S. Environmental Protection 

Agency (EPA) greenhouse gas BACT standards, and a leak detection and repair 

program for monitoring piping and storage tank components to limit the impact 

of methane emissions. Proposed modifications to the Longview Compressor 

Station include the replacement of the existing turbine with a more energy 

efficient turbine. Compression Station 203-A is not a Prevention of Significant 

Deterioration (PSD) major source and, therefore, a greenhouse gas BACT 

analysis is not required for this facility. However, the installation of new 

turbines and internal combustion engines would also be designed for energy 

efficient operations. The LDEQ issued an air permit for the liquefaction 

facility on May 1, 2015.

FA3-5 In accordance with the air permit issued for the project, Lake Charles LNG 

would be required to implement a leak detection and repair program to 

minimize methane emissions, which is determined as BACT for greenhouse 

gases.

FA3-6 Climate change, including sea-level rise, is discussed in section 4.13.2.11. The 

potential for ground subsidence due to sea-level rise and other factors is also 

discussed in section 4.1.3.3. In addition to the inspections that Lake Charles 

LNG would conduct in accordance with Title 49 Code of Federal Regulations 

(CFR) Part 193, we have included a recommended condition that the company 

develop and file with the Secretary of the Commission (Secretary) a plan for 

periodic monitoring and reporting of ground subsidence and foundation 

settlement for the design life of the facility. 

FA3-7 Sections 4.11.1.4 and 5.2 have been revised to include a recommended 

condition that Lake Charles LNG and Trunkline Gas Company, LLC 

(Trunkline) develop and file with the Secretary a Fugitive Dust Control Plan

that incorporates, as appropriate, measures included in the EPA's attachment.

FA3-8 Correspondence with resource agencies mentioned in the draft EIS is publicly 

available on the FERC’s website under Docket Nos. CP14-119-000, CP14-120-

000, and CP14-122-000. Table 1.5-1 has been updated to reflect the status of 

permits required for the project as of the development of this final EIS. 
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-8

FA3 – U.S. Environmental Protection Agency (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Federal Agencies

L-9

FA3 – U.S. Environmental Protection Agency (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

State Agencies

L-10

STATE AGENCIES

SA1 – Louisiana Department of Wildlife and Fisheries

SA1-1 Table 1.5-1 and section 4.3.2.2 identify authorization from the Louisiana 

Department of Wildlife and Fisheries (LDWF), Scenic Rivers Program as one 

of the permits or approvals required for the project. In addition, designation 

of the Calcasieu River as a Louisiana Natural and Scenic River is noted in 

several sections of the EIS (see sections 4.3.2.1, 4.3.2.2, 4.8.4.2, and 4.8.6.2). 

As reflected in table 1.5-1, Trunkline anticipates submitting its application for 

this permit to the LDWF in the second half of 2016.

SA1-2 Section 4.5 describes vegetative communities affected by the project and 

measures Lake Charles LNG and Trunkline would implement to avoid or 

minimize impacts on these resources. Based on field surveys conducted by 

Lake Charles LNG and Trunkline, no coastal prairie or western acidic 

longleaf pine savannah communities were identified within project work 

areas. Lake Charles LNG and Trunkline have proposed compensatory 

mitigation that would include a Permittee Responsible Mitigation project 

involving the re-establishment and rehabilitation of coastal prairie and 

bottomland hardwood habitat, as well as credit purchases from a U.S. Army 

Corps of Engineers (COE)-approved mitigation bank. The COE is reviewing 

the proposed compensatory mitigation plan. We anticipate that, if the COE 

issues a section 404 (Clean Water Act) permit for the project, it will be 

conditional upon implementation of a COE-approved compensatory 

mitigation plan, including approved performance standards. 
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

State Agencies

L-11

SA1 – Louisiana Department of Wildlife and Fisheries (cont’d)

SA1-3 Comment noted. The LDWF's recommendations regarding bird nesting 

colonies are addressed in sections 4.6.1.3 and 5.2.

SA1-4 Lake Charles LNG and Trunkline have committed to implementing the 

erosion and sediment control measures specified in the FERC's Upland 

Erosion Control, Revegetation, and Maintenance Plan (Plan) and Wetland 

and Waterbody Construction and Mitigation Procedures (Procedures). The 

Plan and Procedures were developed by FERC staff with input from other 

federal and state agencies, environmental consultants, inspectors, construction 

contractors, non-governmental organizations, and the natural gas pipeline 

industry to minimize the potential environmental impacts of the construction 

of pipeline projects. We believe that implementation of these measures and 

other mitigation measures proposed by Lake Charles LNG and Trunkline, as 

described in various sections of the EIS (see sections 2.6, 4.2.3, 4.3.2.2, and 

4.4.2), would minimize the potential for sediment or project-related debris to 

enter adjacent wetlands or waterbodies.

SA1-5 As noted in section 2.6.3.2, Lake Charles LNG and Trunkline would remove 

clearing debris from wetlands and stockpile it in an upland portion of the 

right-of-way for proper disposal.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

State Agencies

L-12

SA1 – Louisiana Department of Wildlife and Fisheries (cont’d)

SA1-6 Access roads and equipment bridges would be constructed in accordance with 

the FERC Plan and Procedures. Additionally, Lake Charles LNG and 

Trunkline would be required to comply with the conditions of the Department 

of Army permit anticipated to be issued for the project.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-13

COMPANIES AND ORGANIZATIONS

CO1 – Magnolia LNG LLC
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-14

CO1 – Magnolia LNG LLC (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-15

CO1 – Magnolia LNG LLC (cont’d)

CO1-1 Comment noted. Relevant sections of the final EIS have been revised as 

noted below to update/correct the referenced information based on the 

Magnolia LNG LLC comments or, where superseded by more current 

information, the draft EIS that was recently issued for the Magnolia LNG 

Project.

CO1-2 Comment noted. The potential contributions of other projects discussed in the 

Cumulative Impacts section are based on publicly available information. At 

the time the draft EIS was prepared, potential impact contributions of the 

Magnolia LNG Project were based predominantly on information provided in 

Magnolia LNG's application. As noted in response to comment CO1-1, 

information regarding the Magnolia LNG Project has been revised/updated to 

reflect the most current, publicly available information.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-16

CO1 – Magnolia LNG LLC (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-17

CO1 – Magnolia LNG LLC (cont’d)

CO1-3 Section 3.2.1-2 has been updated to reflect the more current information 

provided in this comment.

CO1-4 Table 4.13.1-1 and section 4.13.2 have been revised/updated to reflect the 

most current available information on the Magnolia LNG Project.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-18

CO1 – Magnolia LNG LLC (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-19

CO2 – Sierra Club
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-20

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-21

CO2 – Sierra Club (cont’d)

CO2-1 Comment noted.

CO2-2 Our responses to the issues are provided below with more specific comments.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-22

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-23

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-24

CO2 – Sierra Club (cont’d)

CO2-3 Comment acknowledged. The environmental review and EIS evaluated the 

potential environmental impacts of the proposed project. Portions of the EIS 

have been revised to present information made public after the draft EIS was 

issued.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-25

CO2 – Sierra Club (cont’d)

CO2-4 Our responses to the issues are provided below with more specific comments.

CO2-5 The EIS specifically evaluates the siting and operation of the proposed project. 

The project purpose and need as stated in sections 1.1 and 3.1 of the EIS are 

summarized to serve the reader, but provide an accurate description of the 

applicants’ stated purpose and provide the basis for developing a reasonable 

range of alternatives. Our assessment of alternatives considered the volume of 

LNG and the timing required to meet Lake Charles LNG’s contractual 

obligations.

CO2-6 The EIS is not intended to be a determination of project need. It is the duty 

and authority of the FERC’s Commissioners to determine if the project is in 

the public’s convenience and necessity during its evaluation and review prior 

to authorization. The FERC is not a proponent of the proposed project and,

therefore, does not define the project’s purpose and need. The purpose is 

defined by Lake Charles LNG and Trunkline in their application to the FERC, 

and we use that stated purpose in the EIS for the project. The purpose and 

need statement in the EIS serves as a disclosure of Lake Charles LNG’s and 

Trunkline’s stated purpose to which the FERC is responding and provides the 

basis for developing a reasonable range of alternatives. FERC staff neither 

endorses nor opposes Lake Charles LNG’s and Trunkline’s assertions of need. 

Need is not an environmental issue to be addressed at length in the EIS to 

justify the project. (Continued on next page)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-26

CO2 – Sierra Club (cont’d)

CO2-6 

(cont’d)

Applicants propose projects and present their objectives, and the FERC 

reviews those proposals, including producing an environmental document to 

satisfy NEPA. The CEQ regulations for implementing NEPA (at 40 CFR 

1502.13) only require that the EIS “briefly specify the underlying purpose and 

need to which the agency is responding...” The Commission will more fully 

consider the need for the project when making its decision on whether or not to 

authorize the project. Section 3 of the final EIS contains a thorough analysis of 

alternatives to the Lake Charles Liquefaction Project, including the No-Action 

alternative.

CO2-7 The alternatives analysis is consistent with CEQ regulations, particularly 40 CFR 

1502.14, which, in addition to requiring detailed analysis of alternatives in 

comparative form, states “and for alternatives which were eliminated from 

detailed study, briefly discuss the reasons for their having been eliminated.” For 

each alternative eliminated, the EIS states why the alternative was eliminated; 

therefore, we do not need a detailed analysis of those alternatives for comparison. 

The timeline and capacity for each alternative are components of the evaluation 

of alternatives, but the lack of providing a significant environmental advantage is 

the main reason for most alternatives’ elimination. The system alternatives 

addressed in section 3.2 of the EIS were not eliminated solely on the basis of the 

timing of in-service dates, although many of the projects were in such an early 

stage of development that, if approved, they would not be completed within years 

of the anticipated in-service date of the proposed project. Additionally, while the 

proposed project would involve development of a new site for the liquefaction 

facility, it is not strictly a greenfield project in that it would make use of the 

existing storage and marine facilities at the existing Trunkline LNG Terminal. As 

noted in section 3.2, the majority of projects eliminated did not offer a significant 

environmental advantage over the proposed project.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-27

CO2 – Sierra Club (cont’d)

CO2-8 Downstream market uses and any potential impacts are not within the 

Commission’s jurisdiction. Because end users have not been and cannot be 

identified at this time, it is not possible to consider impacts of end use. 

Further, the impacts of end use in foreign, likely non-adjacent, countries are

beyond the scope of a project proposed within the United States and evaluated 

under NEPA and CEQ regulations. NEPA requires the Commission to 

disclose the potential impacts resulting from its action to authorize the 

construction and operation of an LNG terminal.

CO2-9 In order to address alternatives, we must make the assumption that the purpose 

and need of the project (and competing projects) is valid. Our assessment of 

the No-Action alternative states that “other LNG import/export projects could

also be developed...” [emphasis ours], but also recognizes that potential end 

users could seek other forms of energy. The market will ultimately decide 

which and how many LNG export facilities will be built and operated. 

Additionally, our assessment of the No-Action alternatives clearly states that 

with the No-Action Alternative, “...the potential adverse and beneficial 

environmental impacts identified in section 4.0 of this EIS would not occur.”

CO2-10 See responses to FA3-1, CO2-8, CO2-12, and CO2-13.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-28

CO2 – Sierra Club (cont’d)

CO2-11 See responses to FA3-1, CO2-8, CO2-12, and CO2-13.

CO2-12 We agree that consumption by end users of exported LNG would cause 

environmental impacts; however, neither the location nor the footprint of these 

impacts is known. Consequently, any attempt to analyze these impacts would 

be speculative and provide no meaningful data for decision makers to consider. 

Also see responses to FA3-1, CO2-8, and CO2-13.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-29

CO2 – Sierra Club (cont’d)

CO2-13 The commentor contends that the proposed project and other planned LNG 

export projects, if constructed and operated, would cause an increase in 

environmental impacts from induced gas production. With regard to 

environmental impacts associated with natural gas production from shale 

sources, the project does not depend on additional shale gas production, which 

may occur for reasons unrelated to the project and over which FERC has no 

control, such as state permitting for additional gas wells. The development of 

natural gas in shale by hydraulic fracturing is not the subject of this EIS, nor is 

the issue directly related to the project. Determining the well and gathering 

line locations and the environmental impacts associated with their development 

and operation is not feasible, as the market and gas availability at any given 

time would determine the source of the natural gas. Further, future shale 

production is not reasonably foreseeable, because local governments make the 

decisions concerning siting and timing of wells and gathering lines. 

Consequently, we cannot know the specifics of when, where, or even if natural 

gas production would occur. The same is true for natural gas production from 

conventional sources. An environmental analysis of increased natural gas 

production would be too speculative for inclusion in the final EIS, because the 

impact cannot be described with sufficient specificity to make its consideration 

useful to reasoned decision makers.

(Continued on next page)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-30

CO2 – Sierra Club (cont’d)

CO2-13 

(cont’d)

CEQ regulations require agencies to consider environmental effects of 

proposed actions, including direct and indirect effects, if these effects are 

“reasonably foreseeable.” Where appropriate, the FERC evaluates the specific 

facts to determine whether natural gas production and development is a 

“reasonably foreseeable” direct or indirect result of construction and operation 

of the project under consideration, or whether such activities are too 

speculative or attenuated to warrant inclusion in the EIS. In this case, the 

environmental impacts from any potential induced production are not 

“reasonably foreseeable” and such additional development, or any correlative 

potential impact, is not an “effect” of the proposed project for purposes of a 

cumulative impacts analysis. Therefore, induced gas production and the 

impacts associated with gas production are outside of the scope of this EIS. 

Also see responses to FA3-1 and CO2-12.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-31

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-32

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-33

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-34

CO2 – Sierra Club (cont’d)

CO2-14 The DOE has exclusive jurisdiction over the export of natural gas as a 

commodity. Consequently, consideration of impacts related to increased exports 

of LNG is not included in this EIS. However, we note that studies conducted by 

National Economic Research Associates indicate that LNG exports is selflimiting, in that little or no natural gas would be exported if the price of natural 

gas in the United States increases much above current expectations (National 

Economic Research Associates, 2014).
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-35

CO2 – Sierra Club (cont’d)

CO2-15 See response to CO2-14.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-36

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Companies and Organizations

L-37

CO2 – Sierra Club (cont’d)
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Individuals

L-38

INDIVIDUALS

IND1 – Margaret Kuttner, Thomas M. Bergstedt, 

John E. Bergstedt

IND1-1 Comment acknowledged. The referenced producing oil and gas well is 

discussed in section 4.1.2, which has been updated based on this comment and 

Lake Charles LNG's response to FERC staff's recommended mitigation item 15 

in the draft EIS.
APPENDIX L

RESPONSES TO COMMENTS ON THE DRAFT ENVIRONMENTAL IMPACT STATEMENT (cont’d)

Individuals

L-39

IND1-1 – Margaret Kuttner, Thomas M. Bergstedt, 

John E. Bergstedt (cont’d)

IND1-2 In its May 14, 2015 response to FERC staff's recommended mitigation item 15 in 

the draft EIS, Lake Charles LNG indicated that it plans to continue to work with 

Jordan Oil and all royalty/mineral interest owners to reach agreement prior to 

commencing work at the liquefaction facility site. The FERC is responsible for 

evaluating applications it receives from project sponsors seeking authorization to 

construct and operate interstate natural gas facilities and determining whether 

these projects are in the public interest and represent environmentally acceptable 

actions. While we acknowledge that the royalty owners could be adversely 

affected by the closure of the currently active oil and gas well on the liquefaction 

facility site, the negotiations among Lake Charles LNG, Jordan Oil, and the 

affected royalty owners are beyond the scope of the EIS process and fall outside 

of the FERC's jurisdiction. If the parties cannot reach agreement, royalty owners 

may elect to pursue the matter through the appropriate legal process. 

APPENDIX M

INDEX

APPENDIX M

INDEX

M-1

above mean sea level, 2-19, 2-20, 4-2, 4-33, 

4-224

access roads, 1-13, 2-9, 2-15, 2-16, 2-17, 3-8, 4-

4, 4-35, 4-46, 4-76, 4-79, 4-81, 4-82, 4-84, 4-

94, 4-105, 4-106, 4-107, 4-200, 5-16, 5-26

Acute Exposure Guideline Level, 4-156, 4-157, 

4-179, 4-188

additional construction workspace, 2-10, 2-13, 

3-33, 4-15, 4-17, 4-23, 4-27, 4-34, 4-38, 4-43, 

4-77, 4-85, 4-89, 4-91, 4-92, 4-105, 4-106, 5-

3, 5-6, 5-14, 5-29, 5-30

additional temporary workspace, 2-14, 2-16, 3-

37, 4-30, 4-31, 4-37, 4-39, 4-40, 4-41, 4-46, 

4-47, 4-76, 4-77, 4-80, 4-83, 4-85, 4-86, 4-87, 

4-88, 4-92, 5-7, 5-13, 5-14

Advisory Council on Historic Preservation, 1-

16, 4-105

air emissions, 3-2, 3-3, 3-4, 3-37, 3-38, 3-39, 3-

40, 4-119, 4-123, 4-237, 5-24

air quality control region, 4-112

alternatives, 1-4, 1-10, 1-11, 1-17, 2-16, 2-18, 2-

27, 3-1, 3-2, 3-3, 3-4, 3-5, 3-6, 3-7, 3-8, 3-9, 

3-10, 3-11, 3-12, 3-13, 3-14, 3-15, 3-17, 3-18, 

3-19, 3-20, 3-21, 3-22, 3-23, 3-24, 3-25, 3-26, 

3-27, 3-28, 3-30, 3-31, 3-32, 3-33, 3-34, 3-35, 

3-36, 3-37, 3-38, 3-39, 4-14, 4-16, 4-30, 4-31, 

4-32, 4-36, 4-37, 4-38, 4-39, 4-40, 4-41, 4-

102, 4-116, 4-133, 4-162, 4-174, 4-179, 4-

197, 4-225, 5-1, 5-5, 5-6, 5-22, 5-23, 5-24, 

5-31

Alturas LLC, 3-25

American Petroleum Institute, 2-30, 4-161, 

4-162

American Society of Civil Engineers, 4-8, 4-161

American Society of Mechanical Engineers, 2-

20, 4-161, 4-162, 4-167, 5-35

Annova LNG Common Infrastructure, LLC, 

Annova LNG Brownsville A, LLC, Annova 

LNG Brownsville B, LLC, and Annova LNG 

Brownsville C, LLC, 3-13, 3-15, 3-20

Approval of Emissions, 4-120, 4-122, 4-125, 4-

132, 4-133

area of impact, 4-120, 4-128, 4-131, 4-236

Bald and Golden Eagle Protection Act, 1-7, 1-

10, 4-55, 4-75

bald eagle, 4-69, 4-75, 5-12

Barca LNG LLC, 3-14

Best Available Control Technology, 4-115, 4-

116, 4-117, 4-118, 4-119, 4-128, 4-131, 4-

132, 4-239, 5-17

best management practices, 4-24, 4-27, 4-226, 4-

227, 4-228

BG LNG Services LLC, 1-2, 1-3, 3-1, 3-8, 3-9

Biological Assessment, 1-16, 4-68, 5-12

Bird Conservation Region, 4-56

Birds of Conservation Concern, 4-56

blasting, 4-10, 4-173, 4-224, 5-2

blowdown, 4-53, 4-148, 4-149, 4-151, 4-168, 4-

194, 4-199, 5-36

Boardwalk Pipeline Partners, L.P., 1-13

boiling-liquid expanding vapor explosion, 4-

160, 4-177, 4-194

bore, 2-26, 2-28, 4-39, 4-40

Cameron LNG, LLC, 1-9, 3-6, 3-7, 3-8, 3-28, 4-

205, 4-210, 4-215, 4-216, 4-218, 4-220, 4-

227, 4-236, 4-241

casing, 2-26, 4-150

CE FLNG, LLC, 3-13, 3-15, 3-18

Cheniere Corpus Christi Liquefaction, LLC and 

Cheniere Corpus Christi Pipeline, LP, 3-13, 3-

14, 3-16, 3-21

Clean Air Act, 1-13, 1-17, 4-110, 4-113, 4-116, 

4-120, 4-122, 4-123, 4-124, 4-156

Clean Water Act, 1-5, 1-13, 1-14, 1-17, 4-20, 4-

24, 4-27, 4-32, 4-226

climate change, 1-11, 4-238, 4-240, 5-22

Coastal Use Permit, 1-15, 1-17, 4-32, 4-94, 5-15

Coastal Zone Management Act, 1-4, 1-13, 1-17, 

4-94

Coastal Zone Management Program, 1-17, 4-94

Code of Federal Regulations, 1-4, 1-5, 1-7, 1-8, 

1-16, 1-17, 2-18, 2-21, 2-25, 2-26, 2-27, 2-31, 

2-32, 2-33, 3-33, 4-6, 4-8, 4-10, 4-25, 4-31, 4-

42, 4-63, 4-66, 4-105, 4-113, 4-114, 4-115, 4-

116, 4-117, 4-118, 4-120, 4-121, 4-122, 4-

123, 4-124, 4-135, 4-151, 4-152, 4-156, 4-

161, 4-162, 4-163, 4-165, 4-166, 4-167, 4-

172, 4-173, 4-178, 4-179, 4-180, 4-181, 4-

186, 4-187, 4-188, 4-191, 4-192, 4-195, 4-

196, 4-197, 4-198, 4-199, 4-200, 5-1, 5-20, 5-

23, 5-33, 5-34, 5-35, 5-37
APPENDIX M

INDEX (cont’d)

M-2

Columbia Gulf Transmission, LLC, 2-12, 2-15, 

2-17, 3-38, 4-3, 4-7, 4-11, 4-22, 4-30, 4-32, 4-

35, 4-37, 4-42, 4-45, 4-50, 4-55, 4-65, 4-70, 

4-78, 4-81, 4-82, 4-106, 4-208, 4-218, 5-24

compression ignition internal combustion 

engines, 4-121, 4-123

Compressor Station Alternative site, 3-35, 3-37, 

5-23

construction emissions, 4-114, 4-126, 4-127, 4-

128, 4-236

construction noise, 4-84, 4-141, 4-142, 4-144, 

5-18

construction procedures, 2-25, 5-25, 5-26

contamination, 4-13, 4-14, 4-15, 4-19, 4-90, 5-3, 

5-14

Corpus Christi Liquefaction, LLC, 3-13, 3-14, 3-

15, 3-16, 3-21

Council on Environmental Quality, 1-4, 1-12, 4-

104, 4-204

critical energy infrastructure information, 4-165, 

5-33

day-night sound level, 4-134

Delfin LNG LLC, 3-14, 3-15, 3-22, 3-23

dry crossing method, 2-28

earthquake, 4-5, 4-9, 4-10, 4-171, 5-39

easement, 2-13, 2-15, 2-21, 4-36, 4-46, 4-47, 4-

50, 4-54, 4-76, 4-80, 4-87, 4-88, 4-103, 4-104, 

4-197, 5-6, 5-12, 5-13

economy, 1-11, 4-97

emergency response plan, 4-163, 4-194, 4-223, 

4-241, 5-21, 5-33

Emergency Response Planning Guidelines, 4-

156, 4-157

emergency shutdown, 2-10, 2-30, 2-31, 2-32, 2-

33, 4-160, 4-162, 4-163, 4-167, 4-168, 4-179, 

4-199, 5-35, 5-36

eminent domain, 3-31, 4-88, 5-26

employment, 1-10, 4-95, 4-96, 4-97, 4-210, 5-15

Endangered Species Act of 1973, 1-4, 1-7, 1-13, 

1-14, 1-16, 4-55, 4-66, 4-68, 4-73, 4-74, 4-

230, 5-11, 5-12, 5-30

energy conservation, 3-2

Energy Policy Act of 2005, 1-4, 1-17, 4-163

Entergy Gulf States Louisiana, LLC, 1-13, 2-9, 

3-39, 3-40, 4-210, 4-220, 4-225, 4-231, 5-24

entrainment, 4-32, 4-63, 4-64, 4-65

environmental impact statement, 1-1, 1-4, 1-5, 

1-7, 1-8, 1-9, 1-10, 1-11, 1-12, 1-13, 1-14, 1-

15, 1-17, 1-18, 2-17, 2-18, 2-28, 3-2, 3-5, 3-8, 

3-26, 3-39, 4-1, 4-2, 4-4, 4-6, 4-9, 4-24, 4-31, 

4-38, 4-39, 4-41, 4-42, 4-56, 4-58, 4-61, 4-62, 

4-66, 4-67, 4-68, 4-73, 4-93, 4-107, 4-126, 4-

127, 4-132, 4-147, 4-164, 4-203, 4-204, 4-

219, 4-237, 5-1, 5-6, 5-7, 5-11, 5-12, 5-17, 5-

22, 5-24, 5-25, 5-26, 5-33

environmental inspector, 2-17, 4-161, 5-27

Environmental Justice, 1-10, 4-104

Eos LNG LLC, 3-14, 3-15, 3-24

equivalent sound level, 4-134

essential fish habitat, 1-4, 1-14, 1-16, 4-20, 4-23, 

4-59, 4-62, 4-64, 4-66, 4-67, 5-4, 5-5, 5-11

Excelerate Liquefaction Solutions, LLC, 3-13, 

3-16

Executive Order, 1-5, 1-10, 4-55, 4-104

Federal Aviation Administration, 1-14, 4-91, 

4-161

Federal Emergency Management Agency, 2-19, 

3-29, 3-31, 4-7, 4-8

fire department, 4-100, 4-101

First Flight Holdings, LLC, 4-212, 4-222

fishery management plans, 4-67

FLNG Expansion and FLNG Liquefaction, LLC, 

3-8

floating liquefaction storage and offloading unit, 

3-12, 3-16, 3-17, 3-18, 3-23

flooding, 2-19, 2-20, 3-33, 4-1, 4-4, 4-7, 4-12, 4-

32, 4-160, 4-161, 4-171, 4-224, 4-238, 4-239, 

5-1, 5-23, 5-39

floodplain, 3-29, 3-31, 4-7, 4-8, 4-34, 4-46, 4-

50, 4-75, 4-161, 4-224

Florida Gas Transmission Company, LLC, 3-12, 

3-27, 3-28

fossil fuel, 3-2, 3-3, 3-4, 4-114, 4-238

Free Trade Agreement, 1-6, 1-7, 1-14, 3-5, 3-7, 

3-8, 3-10, 3-11, 3-12, 3-13, 3-14, 3-16, 3-17, 

3-18, 3-19, 3-20, 3-21, 3-22, 3-23, 3-24, 3-25, 

4-216, 4-217, 4-218

Freeport – McMoRan Energy LLC, 3-12, 3-13

Freeport LNG Development, LP, 3-6, 3-7, 3-8, 

3-9
APPENDIX M

INDEX (cont’d)

M-3

front-end engineering design, 4-9, 4-161, 4-164, 

4-165, 4-171, 4-172, 5-2, 5-19, 5-20, 5-24, 

5-33

fugitive dust, 4-125, 4-126, 4-127, 4-128, 4-236, 

5-17, 5-31

G2 LNG LLC, 3-14, 3-15, 3-25, 4-207, 4-217

Gasfin Development USA, LLC, 3-14, 3-15, 3-

21, 3-22, 4-207, 4-215, 4-217, 4-234

geographic information systems, 4-10

geologic hazards, 4-4, 4-201, 5-1

geology, 1-4, 4-9, 4-224, 5-2

geotechnical, 4-2, 4-8, 4-9, 4-10, 5-2, 5-29

geotechnical investigation, 4-9, 4-10, 5-2, 5-29

global warming potential, 4-110

Golden Pass LNG, LLC, 3-6, 3-7, 3-11, 4-205, 

4-215

Golden Pass Products, LLC, 3-11, 4-215

greenhouse gases, 4-110, 4-114, 4-116, 4-131, 4-

134, 4-238, 4-239

groundwater, 1-10, 2-25, 2-33, 4-5, 4-6, 4-14, 4-

16, 4-18, 4-19, 4-27, 4-32, 4-90, 4-225, 4-226, 

4-227, 4-239, 5-1, 5-4, 5-13

Gulf LNG Liquefaction Company, LLC, 3-6, 3-

7, 3-12

Gulf of Mexico Fishery Management Council, 

4-67

Gulf South Pipeline Company, 3-27, 3-28, 4-31

hazard and operability review, 4-164, 4-167, 

5-35

Hazardous Air Pollutants, 4-122, 4-123, 4-128, 

4-156, 4-237

hazardous waste, 4-13, 5-3

health and safety, 4-135, 4-241, 5-21

high consequence area, 4-197, 4-198

historic properties, 4-105, 4-106, 4-107, 4-108, 

4-109, 4-235, 5-16

Hoover & Keith, Inc., 4-136, 4-138, 4-141, 4-

143, 4-146, 4-147

horizontal directional drill, 2-11, 2-14, 2-15, 2-

16, 2-26, 2-28, 2-29, 2-32, 4-3, 4-10, 4-11, 4-

22, 4-28, 4-29, 4-30, 4-31, 4-33, 4-35, 4-36, 

4-39, 4-40, 4-41, 4-45, 4-47, 4-49, 4-53, 4-54, 

4-64, 4-69, 4-70, 4-75, 4-77, 4-80, 4-82, 4-85, 

4-86, 4-90, 4-93, 4-107, 4-135, 4-138, 4-143, 

4-144, 4-145, 4-227, 4-230, 5-2, 5-4, 5-5, 5-6, 

5-7, 5-10, 5-12, 5-13, 5-17, 5-18, 5-29, 5-30, 

5-31

Horizontal Directional Drill Contingency Plan, 

2-29, 4-30, 4-64, 4-90, 4-227, 5-6, 5-11, 5-13, 

5-30

hospital, 4-144

housing, 3-31, 4-95, 4-98, 4-99, 4-100, 4-103, 4-

211, 4-212, 4-221, 4-222, 4-233, 4-234, 5-15, 

5-21

hurricane, 4-7, 4-8, 4-161

hydrofluorocarbons, 4-110

hydrogen sulfide, 4-153, 4-187, 4-188

hydrostatic testing, 1-17, 2-20, 2-26, 4-19, 4-31, 

4-36, 4-39, 4-41, 4-64, 4-65, 4-197, 4-227, 4-

230, 5-4

Intergovernmental Panel on Climate Change, 

4-238

International Convention for the Prevention of 

Pollution from Ships, 3-2

International Energy Agency, 3-2, 3-3, 3-4

International Society for Automation, 4-162

Interstate Natural Gas Association, 4-103

invasive species, 1-10, 4-36, 4-48, 4-49, 5-8

Juniper GTL, LLC, 4-209, 4-219, 4-241

Kinder Morgan Louisiana Pipeline LLC, 3-25, 

4-88, 4-208, 4-210, 4-216, 4-218, 4-220

Lake Charles Exports, LLC, 1-6, 1-7, 1-14

Lake Charles LNG Export Meter Station, 2-7, 2-

9, 2-12, 2-15, 2-17, 3-37, 4-11, 4-17, 4-42, 4-

43, 4-69, 4-70, 4-81, 5-24

land requirements, 2-15, 2-17, 5-12

land use, 1-4, 1-10, 2-13, 2-29, 2-30, 3-35, 3-37, 

3-40, 4-12, 4-47, 4-75, 4-76, 4-77, 4-78, 4-80, 

4-81, 4-82, 4-83, 4-84, 4-87, 4-103, 4-212, 4-

231, 5-1, 5-12, 5-13, 5-22, 5-24, 5-26

leak detection and repair, 4-239

Letter of Intent, 1-6, 1-14, 4-195

Letter of Recommendation, 1-5, 4-152, 4-195, 

5-20

Liberty Natural Gas, LLC, 4-209, 4-219

Liquefaction Facility Site, 3-17, 3-29, 3-30, 3-

31, 3-32

liquid petroleum gas, 4-153, 4-175
APPENDIX M

INDEX (cont’d)

M-4

Live Oak LNG, LLC, 3-14, 3-15, 3-25, 3-26, 4-

206, 4-215, 4-217

Louisiana Administrative Code, 4-113, 4-123, 

4-124

Louisiana Department of Environmental 

Quality, 1-9, 1-13, 1-15, 1-17, 4-13, 4-14, 4-

17, 4-18, 4-19, 4-20, 4-22, 4-23, 4-24, 4-27, 

4-33, 4-90, 4-112, 4-113, 4-116, 4-120, 4-122, 

4-123, 4-124, 4-125, 4-128, 4-131, 4-227, 4-

231, 4-236, 4-237, 5-3, 5-4, 5-5, 5-13, 5-17

Louisiana Department of Natural Resources, 1-

9, 1-15, 1-17, 4-2, 4-4, 4-17, 4-33, 4-94, 5-15

Louisiana Department of Transportation and 

Development, 4-16, 4-19, 4-209, 4-220, 4-225

Louisiana Department of Wildlife and Fisheries, 

1-9, 1-15, 4-22, 4-26, 4-28, 4-29, 4-30, 4-31, 

4-49, 4-58, 4-59, 4-69, 4-75, 4-223, 5-5, 5-8, 

5-9, 5-10, 5-12, 5-30

Louisiana LNG Energy LLC, 3-13, 3-17, 3-18

Louisiana Marine Fisheries Enhancement, 

Research, and Science Center, 4-88, 4-211, 4-

223, 4-228, 4-231

Louisiana Natural Heritage Program, 4-49, 4-50, 

4-58, 4-59, 4-68, 4-74, 4-75

Louisiana Pollutant Discharge Elimination 

System, 4-27, 4-32, 4-227

lower flammable limit, 4-155, 4-157, 4-167, 4-

179, 4-180, 4-181, 4-186, 4-187, 5-35

Magnolia LNG, 3-13, 3-15, 3-17, 3-29, 4-88, 4-

206, 4-208, 4-210, 4-215, 4-216, 4-218, 4-

220, 4-224, 4-226, 4-227, 4-228, 4-229, 4-

230, 4-231, 4-232, 4-234, 4-235, 4-236, 4-

240, 4-241, 5-21, 5-22

Magnuson-Stevens Fishery Conservation and 

Management Act, 1-4, 1-13, 1-14, 1-16, 4-66, 

4-67, 5-11

mainline valve, 2-11, 2-14, 2-15, 3-34, 3-35, 4-

3, 4-45, 4-69, 4-71, 4-72, 4-76, 4-79, 4-81, 4-

84, 5-23

Maritime Transportation Security Act, 1-5, 

4-162

Maximum Achievable Control Technology, 

4-122

maximum allowable operating pressure, 2-26, 4-

171, 4-197, 4-198, 5-39

Maximum Contaminant Level, 4-18

Memorandum of Understanding, 4-55, 4-151, 

4-196

Midcontinent Express Pipeline, 2-12, 2-15, 2-17, 

4-1, 4-3, 4-11, 4-16, 4-43, 4-45, 4-69, 4-70, 4-

78, 4-81, 4-82, 4-106

Migratory Bird Treaty Act, 1-7, 1-10, 1-14, 4-

55, 4-75

migratory birds, 1-7, 3-31, 4-55, 4-56, 4-57, 4-

59, 4-89, 4-229, 5-8, 5-9, 5-10, 5-30

minority population, 4-104, 4-105, 5-15

Mississippi Department of Environmental 

Quality, 1-16, 4-113, 4-123, 4-133

mitigation, 1-4, 1-5, 1-10, 2-17, 2-18, 2-27, 3-

33, 3-38, 4-1, 4-6, 4-10, 4-14, 4-15, 4-24, 4-

28, 4-32, 4-38, 4-42, 4-47, 4-48, 4-49, 4-50, 

4-52, 4-56, 4-57, 4-58, 4-65, 4-66, 4-74, 4-84, 

4-86, 4-102, 4-127, 4-128, 4-143, 4-144, 4-

146, 4-147, 4-149, 4-159, 4-161, 4-180, 4-

194, 4-195, 4-228, 4-229, 4-231, 4-235, 4-

236, 5-1, 5-2, 5-3, 5-5, 5-6, 5-7, 5-8, 5-9, 5-

10, 5-11, 5-13, 5-17, 5-18, 5-19, 5-21, 5-25, 

5-26, 5-27, 5-29, 5-30, 5-31

mixed refrigerant liquid, 4-154, 4-155, 4-159, 

4-187

national ambient air quality standards, 4-110, 4-

112, 4-115, 4-116, 4-119, 4-120, 4-128, 4-

129, 4-130, 4-131, 4-132, 4-133, 4-236, 4-

237, 5-31

National Emissions Standards for Hazardous Air 

Pollutants, 4-122, 4-123

National Environmental Policy Act of 1969, 1-1, 

1-4, 1-5, 1-7, 1-10, 1-11, 1-12, 1-13, 1-16, 1-

17, 3-1, 4-66, 4-67, 4-104, 4-151, 4-152, 4-

195, 4-203

National Fire Protection Association, 2-18, 2-31, 

4-8, 4-121, 4-161, 4-162, 4-163, 4-166, 4-169, 

4-172, 4-173, 4-174, 4-175, 4-177, 4-178, 4-

180, 4-188, 4-191, 5-34, 5-38

National Historic Preservation Act, 1-4, 1-10, 1-

13, 1-15, 1-16, 4-105, 4-106, 4-108, 5-16

National Oceanic and Atmospheric 

Administration, 1-9, 1-14, 1-16, 4-61, 4-66, 4-

67, 4-68, 4-74, 4-109, 4-156, 4-203, 4-230, 4-

238, 5-10, 5-11, 5-12
APPENDIX M

INDEX (cont’d)

M-5

National Oceanic and Atmospheric 

Administration, National Marine Fisheries 

Service, 1-9, 1-14, 1-16, 4-61, 4-66, 4-67, 4-

68, 4-74, 4-230, 5-10, 5-11, 5-12

National Pollutant Discharge Elimination 

System, 1-17

National Register of Historic Places, 1-16, 4-

105, 4-106

National Wetlands Inventory, 3-1, 3-31, 3-33, 3-

37, 4-41, 4-228

National Wildlife Refuge, 4-59, 4-88, 4-89, 5-13

Natural Gas Act, 1-1, 1-3, 1-4, 1-5, 1-6, 1-7, 1-

12, 1-14, 1-17, 3-8, 3-9, 3-16, 3-31, 4-55, 4-

88, 4-151, 4-194, 5-26

natural gas liquid, 2-1, 2-6, 2-31, 3-20, 4-154, 4-

155, 4-156, 4-159, 4-174, 4-176, 4-186, 4-

187, 4-192, 4-194, 4-207, 5-33

Natural Gas Pipeline Company of America, 1-

15, 1-17, 2-11, 2-12, 2-15, 2-17, 3-10, 3-23, 

3-27, 3-37, 4-3, 4-7, 4-11, 4-22, 4-33, 4-35, 4-

37, 4-41, 4-42, 4-45, 4-58, 4-59, 4-69, 4-70, 

4-71, 4-72, 4-73, 4-78, 4-81, 4-89, 4-94, 4-

106, 5-9, 5-13, 5-15, 5-30

Natural Resources Conservation Service, 4-10, 

4-11, 4-46, 4-48, 4-49, 5-8, 5-30

New Source Performance Standards, 4-120, 4-

121, 4-123

New Source Review, 4-113

noise-sensitive area, 4-136, 4-138, 4-142, 4-143, 

4-144, 4-145, 4-146, 4-147, 4-148, 4-149, 4-

150, 4-151, 4-240, 5-18, 5-19, 5-22, 5-31, 

5-32

non-jurisdictional facilities, 1-12, 2-9, 4-88, 4-

220, 5-13

northern long-eared bat, 4-70, 4-73

notice of availability, 1-12

Notice of Intent to Prepare an Environmental 

Impact Statement for the Planned Lake 

Charles Liquefaction Project, Request for 

Comments on Environmental Issues, and 

Notice of Public Scoping Meeting, 1-8, 1-9, 

4-108

Occupational Safety and Health Administration, 

4-31, 4-135, 4-173

Office of Energy Projects, 1-1, 4-15, 4-28, 4-30, 

4-49, 4-62, 4-74, 4-92, 4-102, 4-127, 4-133, 

4-149, 4-164, 4-171, 4-177, 4-178, 4-181, 4-

194, 4-235, 5-6, 5-25, 5-26, 5-27, 5-28, 5-29, 

5-30, 5-31, 5-32, 5-39

Office of Pipeline Safety, 4-177, 4-196, 4-197

oil and gas well, 1-11, 4-2, 4-4

open-cut crossing method, 2-25, 2-26, 2-28, 4-

28, 4-30, 4-64, 4-65, 4-102, 4-227, 5-5, 5-11

operational noise, 3-33, 3-38, 3-39, 4-146, 4-

149, 4-151, 4-240, 4-241, 5-18, 5-19, 5-23

particulate matter less than 10 microns in 

aerodynamic diameter, 4-110, 4-111, 4-112, 

4-113, 4-116, 4-125, 4-126, 4-127, 4-128, 4-

129, 4-131, 4-132, 4-133, 4-237, 5-17, 5-31

particulate matter less than 2.5 microns in 

aerodynamic diameter, 4-110, 4-111, 4-112, 

4-113, 4-116, 4-125, 4-126, 4-127, 4-128, 4-

129, 4-130, 4-131, 4-132, 4-133, 5-17, 5-31

perfluorocarbons, 4-110

Phase III Early Restoration Plan and Early 

Restoration Programmatic Environmental 

Impact Statement, 4-223

Pipeline and Hazardous Materials Safety 

Administration, 1-8, 4-178, 4-196, 4-201, 4-

202, 4-203

piping and instrumentation diagrams, 4-165, 4-

166, 4-167, 4-168, 4-170, 5-33, 5-34, 5-35, 5-

36, 5-38

polychlorinated biphenyls, 4-13, 4-24, 4-90, 5-3, 

5-13

polycyclic aromatic hydrocarbons, 4-13, 4-24, 

5-3

Prevention of Significant Deterioration, 1-17, 3-

40, 4-113, 4-114, 4-115, 4-116, 4-119, 4-128, 

4-129, 4-130, 4-131, 4-132, 4-236, 4-237, 4-

240, 5-24

Process Safety Management, 4-173

public safety, 4-152, 4-160, 4-161, 4-172, 4-186, 

4-187, 4-188, 4-191, 4-192, 4-194, 4-195, 4-

241, 5-20, 5-21

public services, 4-95, 4-100, 4-101, 4-233, 5-21

public utilities, 4-202
APPENDIX M

INDEX (cont’d)

M-6

rapid phase transition, 4-155

red-cockaded woodpecker, 4-59, 4-69, 4-74, 4-

231, 5-11

renewable energy, 3-2, 3-3, 3-4

residences, 2-29, 3-31, 3-32, 3-35, 3-37, 4-40, 4-

87, 4-91, 4-92, 4-93, 4-99, 4-100, 4-103, 4-

110, 4-135, 4-222, 4-223, 4-233, 4-240, 5-13, 

5-14, 5-15, 5-22, 5-23, 5-30

Rio Grande LNG, LLC and Rio Bravo Pipeline 

Company, LLC, 3-13, 3-21

Risk Evaluation/Corrective Action Program, 4-

24, 5-4

rookeries, 4-57, 4-58, 5-9

Sabine Pass LNG, LP, 3-6, 3-7, 3-9, 3-10, 3-27, 

4-205, 4-215

Sasol North America, Inc., 4-209, 4-211, 4-219, 

4-234, 4-236, 4-241

schools, 4-100, 4-101, 4-188, 4-234, 5-21

scoping meetings, 1-8, 1-12, 4-108

Secretary of the Commission, 4-6, 4-9, 4-10, 4-

15, 4-20, 4-28, 4-30, 4-42, 4-49, 4-57, 4-58, 

4-62, 4-74, 4-92, 4-102, 4-127, 4-133, 4-146, 

4-147, 4-149, 4-150, 4-164, 4-169, 4-170, 4-

178, 4-181, 4-194, 5-9, 5-25, 5-26, 5-28, 5-29, 

5-30, 5-31, 5-32, 5-38

seismicity, 4-4, 4-5, 4-7, 4-10

significant emission rate, 4-114, 4-123, 4-132, 

4-237

significant impact levels, 4-119, 4-128, 4-129, 

4-130, 4-131

significant incident, 4-200, 4-203

socioeconomics, 1-4, 1-10, 4-212, 4-233, 5-15

soil contamination, 4-13, 4-15, 5-3

Soil Survey Geographic database, 4-10

sole source aquifer, 4-16

Southern California Telephone and Energy 

LNG, LLC, 3-14, 3-15, 3-24, 4-208, 4-218

Southwest Louisiana Technical Community 

College, 4-211, 4-221

Spill Prevention and Response, 4-15, 4-19, 4-25, 

4-27, 4-32, 4-52, 4-63, 4-66, 4-90, 4-227, 5-3, 

5-4, 5-13, 5-29

Spill Prevention, Control, and Countermeasure, 

4-15, 4-19, 4-25, 4-27, 4-32, 4-52, 4-63, 4-66, 

4-90, 4-227, 5-3, 5-4, 5-13, 5-29

State Historic Preservation Office, 1-9, 4-105, 4-

106, 4-107, 4-108, 5-16

State Implementation Plan, 4-124, 4-237

stationary spark ignition internal combustion 

engines, 4-121

stormwater, 1-10, 1-13, 2-21, 4-20, 4-23, 4-26, 

4-27, 4-36, 4-63, 4-227, 5-5

Stormwater Pollution Prevention Plan, 2-21, 

4-27

Strategic Online Natural Resources Information 

System Database, 4-17

surface emissive power, 4-192

tax revenue, 1-3, 4-97, 4-98, 5-16

temporary construction dock, 2-10, 2-19, 4-23, 

4-24

Tennessee Gas Pipeline Company, 3-27, 3-28

Texas Eastern Gas Transmission, 1-13, 2-12, 2-

15, 2-17, 3-27, 3-28, 3-37, 4-3, 4-11, 4-43, 4-

45, 4-50, 4-69, 4-70, 4-72, 4-78, 4-81, 4-82, 

4-106

Texas LNG Brownsville LLC, 3-13, 3-15, 3-19, 

3-20, 3-21

traffic, 1-5, 1-9, 1-10, 2-25, 2-26, 2-27, 3-31, 4-

14, 4-23, 4-25, 4-38, 4-59, 4-60, 4-64, 4-80, 

4-84, 4-88, 4-89, 4-91, 4-101, 4-102, 4-103, 

4-125, 4-151, 4-195, 4-200, 4-211, 4-212, 4-

221, 4-225, 4-227, 4-232, 4-234, 4-235, 4-

236, 4-241, 5-5, 5-10, 5-16, 5-17, 5-20, 5-21, 

5-31

Transcontinental Gas Pipeline Company, LLC, 

2-11, 2-12, 2-15, 2-17, 3-12, 3-23, 3-27, 3-28, 

3-37, 4-3, 4-11, 4-35, 4-37, 4-41, 4-43, 4-45, 

4-69, 4-71, 4-72, 4-78, 4-81, 4-82, 4-106, 

4-107

transportation, 1-2, 1-3, 1-4, 1-5, 1-8, 2-26, 2-33, 

3-2, 3-11, 3-24, 4-10, 4-16, 4-84, 4-90, 4-95, 

4-101, 4-102, 4-155, 4-162, 4-163, 4-173, 4-

195, 4-196, 4-202, 4-203, 4-209, 4-220, 4-

222, 4-232, 4-234, 4-235, 4-238, 5-20, 5-31
APPENDIX M

INDEX (cont’d)

M-7

U.S. Army Corps of Engineers, 1-4, 1-5, 1-9, 1-

13, 1-14, 1-15, 1-17, 4-20, 4-22, 4-23, 4-24, 

4-27, 4-30, 4-31, 4-32, 4-33, 4-38, 4-39, 4-42, 

4-46, 4-52, 4-86, 4-211, 4-223, 4-226, 4-227, 

4-228, 4-231, 5-1, 5-5, 5-6, 5-30

U.S. Coast Guard, 1-4, 1-5, 1-9, 1-14, 2-31, 3-7, 

3-13, 3-15, 3-23, 4-25, 4-63, 4-151, 4-152, 4-

159, 4-162, 4-188, 4-189, 4-194, 4-195, 4-

225, 4-235, 5-1, 5-20

U.S. Department of Agriculture, 4-10, 4-12, 

4-50

U.S. Department of Defense, 1-9, 1-17

U.S. Department of Energy, 1-3, 1-4, 1-6, 1-7, 1-

11, 1-16, 3-5, 3-6, 3-7, 3-8, 3-10, 3-11, 3-12, 

3-13, 3-14, 3-15, 3-16, 3-17, 3-18, 3-19, 3-20, 

3-21, 3-22, 3-23, 3-24, 3-25, 3-26, 3-27, 4-

151, 4-156, 4-216, 4-217, 4-218, 5-1

U.S. Department of Transportation, 1-4, 1-8, 2-

18, 2-21, 2-25, 2-26, 2-27, 2-31, 2-32, 2-33, 

4-10, 4-31, 4-38, 4-151, 4-152, 4-161, 4-172, 

4-173, 4-174, 4-175, 4-177, 4-178, 4-179, 4-

180, 4-186, 4-187, 4-188, 4-191, 4-192, 4-

195, 4-196, 4-197, 4-198, 4-200, 4-203, 5-1, 

5-19, 5-20, 5-37

U.S. Environmental Protection Agency, 1-1, 1-8, 

1-9, 1-12, 1-17, 3-2, 4-13, 4-15, 4-16, 4-18, 4-

23, 4-27, 4-43, 4-52, 4-90, 4-104, 4-109, 4-

110, 4-111, 4-112, 4-113, 4-114, 4-115, 4-

116, 4-120, 4-122, 4-123, 4-124, 4-127, 4-

128, 4-129, 4-133, 4-135, 4-138, 4-145, 4-

156, 4-157, 4-173, 4-236, 4-237, 4-239, 5-3, 

5-5, 5-17, 5-31

U.S. Fish and Wildlife Service, 1-4, 1-7, 1-8, 1-

9, 1-14, 1-16, 4-55, 4-56, 4-57, 4-58, 4-68, 4-

69, 4-71, 4-73, 4-74, 4-75, 4-89, 4-229, 4-231, 

5-1, 5-8, 5-9, 5-10, 5-11, 5-12, 5-30

U.S. Geological Survey, 3-1, 4-2, 4-5, 4-6, 4-16, 

4-17, 4-19, 4-48, 4-225, 4-226

U.S. Global Change Research Program, 4-238

U.S. Maritime Administration, 3-7, 3-13, 3-15, 

3-23

United States Code, 1-5, 1-7, 4-48, 4-112, 4-196, 

4-197

upper flammable material, 4-157, 4-158

Variable Frequency Drives, 3-39

vegetation, 1-4, 1-10, 2-16, 2-21, 2-27, 2-29, 2-

32, 3-29, 3-31, 4-8, 4-13, 4-15, 4-27, 4-30, 4-

32, 4-33, 4-35, 4-36, 4-37, 4-43, 4-44, 4-45, 

4-46, 4-47, 4-48, 4-49, 4-50, 4-52, 4-53, 4-54, 

4-56, 4-57, 4-65, 4-82, 4-85, 4-86, 4-91, 4-92, 

4-93, 4-115, 4-119, 4-120, 4-212, 4-228, 4-

229, 5-1, 5-3, 5-5, 5-6, 5-7, 5-8, 5-9, 5-11, 

5-14

Venture Global Calcasieu Pass, LLC, 3-13, 3-

14, 3-19, 4-206, 4-215, 4-216, 4-234

vibration, 4-170, 5-38

visual resources, 1-4, 4-91, 4-92, 4-93, 4-94, 4-

232, 4-233, 5-14, 5-15

volatile organic compounds, 4-110, 4-116, 4-

117, 4-123, 4-125, 4-126, 4-127, 4-128, 4-

131, 4-132, 4-133, 4-134, 4-237

Waller Point LNG, 3-14, 3-15, 3-22, 4-208, 4-

215, 4-217, 4-234

water quality, 1-10, 1-17, 2-19, 2-25, 4-20, 4-23, 

4-24, 4-25, 4-26, 4-27, 4-28, 4-30, 4-32, 4-33, 

4-63, 4-64, 4-226, 4-227, 5-3, 5-4, 5-5, 5-29

water wells, 4-17, 4-20, 4-225, 5-3, 5-4

Waterway Suitability Assessment, 1-5, 4-152, 

5-20

WesPac Midstream LLC, 3-14, 3-15, 3-25, 4-

207, 4-215, 4-218

Westlake Chemical Corporation, 4-209, 4-220

wildlife habitat, 4-32, 4-50, 4-51, 4-52, 4-53, 4-

54, 4-55, 4-229, 5-8, 5-9

workforce, 4-96, 4-97, 4-98, 4-99, 4-100, 4-102, 

4-103, 4-127, 4-206, 4-222, 4-233, 4-234, 4-

235, 5-15, 5-16, 5-20, 5-21