Federal Energy Regulato

Office of Energy Projects Washington, DC 20426

Magnolia 

Lake Charles E

Draft Environmen

Magnolia LNG, LLC and Kinde

FERC Docket Nos. CP14

DOE Docket Nos. 12-183-LN

FERC/EIS-026

Cooperating Agencies:

U.S. Coast Guard

U.S. Department 

of Energy 

Magnolia LNG and Lake Charles Expansion Projects 

Draft Environmental Impact Statement 

FERC/EIS-0260D

Docket Nos. 

CP14-347-000 

and CP14-511-000 

July 

2015

U.S. En

Protect

FEDERAL ENERGY REGULATORY COMMISSION

WASHINGTON, D.C. 20426

OFFICE OF ENERGY PROJECTS In Reply Refer To:

OEP/DG2E/Gas Branch 4

Magnolia LNG, LLC and Kinder 

Morgan Louisiana Pipeline LLC 

Docket Nos. CP14-347-000 and 

CP14-511-000

FERC/EIS-0260D

TO THE PARTY ADDRESSED:

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

has prepared a draft environmental impact statement (EIS) for the Magnolia LNG Project 

proposed by Magnolia LNG, LLC (Magnolia) and the Lake Charles Expansion Project 

proposed by Kinder Morgan Louisiana Pipeline LLC (Kinder Morgan) in the abovereferenced dockets. The Magnolia LNG Project would include construction and 

operation of a liquefied natural gas (LNG) terminal that would include various 

liquefaction, LNG distribution, and appurtenant facilities. The Lake Charles Expansion 

Project would include reconfiguration of Kinder Morgan’s existing pipeline system in 

order to accommodate Magnolia’s request for natural gas service at the LNG terminal 

site. The projects would provide an LNG export capacity of 1.08 billion cubic feet per 

day of natural gas.

The draft EIS assesses the potential environmental effects of construction and 

operation of the Magnolia LNG and Lake Charles Expansion Projects in accordance with 

the requirements of the National Environmental Policy Act (NEPA). The FERC staff 

concludes that approval of the proposed projects would result in adverse environmental 

impacts; however, these impacts would be reduced to less-than-significant levels with the 

implementation of Magnolia’s and Kinder Morgan’s proposed mitigation and the 

additional measures recommended in the draft EIS.

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

Energy, U.S. Department of Transportation, and U.S. Environmental Protection Agency 

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

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

affected by a proposal and participate in the NEPA analysis. Although the cooperating 

agencies provided input on the conclusions and recommendations presented in the draft 

EIS, the agencies will present their own conclusions and recommendations in their 

respective records of decision or determinations for the projects.
Docket Nos. CP14-347-000

and CP14-511-000

- 2 -

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

modification, and operation of the following facilities associated with the two projects:

 a new LNG terminal that includes four liquefaction trains, two LNG storage 

tanks, liquefaction and refrigerant units, safety and control systems, and 

associated infrastructure;

 LNG truck loading facilities;

 LNG carrier and barge loading facilities;

 one new meter station;

 one new 32,000 horsepower compressor station;

 approximately 40 feet of 36-inch-diameter feed gas line to supply natural 

gas to the LNG terminal from Kinder Morgan’s existing natural gas 

transmission pipeline;

 a new 1.2-mile-long, 36-inch-diameter low pressure natural gas header 

pipeline;

 a new 700-foot-long, 24-inch-diameter high pressure natural gas header 

pipeline;

 modifications at six existing meter stations; and

 construction of miscellaneous auxiliary and appurtenant facilities.

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

government representatives and agencies; elected officials; environmental and public

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

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

areas; and parties to these proceedings. Paper copy versions of this EIS were mailed to 

those specifically requesting them; all others received a compact disc version. In 

addition, the draft EIS is available for public viewing on the FERC’s website 

(www.ferc.gov) using the eLibrary link. A limited number of 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
Docket Nos. CP14-347-000

and CP14-511-000

- 3 -

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

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

Commission receive your comments on or before September 7, 2015.

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

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

number(s) (CP14-347-000 and CP14-511-000) with your submission. The Commission 

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

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

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

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

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

on a project.

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

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

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

attaching them as a file with your submission. New eFiling users must first 

create an account by clicking on “eRegister.” If you are filing a comment 

on a particular project, please select “Comment on a Filing” as the filing type.

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

following address:

Kimberly D. Bose, Secretary

Federal Energy Regulatory Commission

888 First Street NE, Room 1A

Washington, DC 20426

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

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

area to receive comments on the draft EIS. We encourage interested groups 

and individuals to attend and present oral comments on the draft EIS. A 

transcript of the meeting will be available for review in eLibrary under the 

project docket numbers. The meeting will begin at 7:00 p.m. and is 

scheduled as follows:

Date Location

September 3, 2015 Historic Cash and Carry Building

801 Enterprise Boulevard

Lake Charles, Louisiana 70601

(337) 310-0405
Docket Nos. CP14-347-000

and CP14-511-000

- 4 -

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

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

(Title 18 Code of Federal Regulations Part 385.214). 1 Only intervenors have the right to 

seek rehearing of the Commission’s decision. The Commission grants affected 

landowners and others with environmental concerns intervenor status upon showing good 

cause by stating that they have a clear and direct interest in this proceeding that no other 

party can adequately represent. Simply filing environmental comments will not give 

you intervenor status, but you do not need intervenor status to have your comments 

considered.

Questions?

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

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

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

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

(i.e., CP14-347 and CP14-511). 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.

 

1 See the previous discussion on the methods for filing comments.
TABLE OF CONTENTS

i

Magnolia LNG, LLC and Kinder Morgan Louisiana Pipeline LLC

Magnolia LNG and Lake Charles Expansion Projects

Draft Environmental Impact Statement

Page

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

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

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

LIST OF APPENDICES............................................................................................................................xiii

TECHNICAL ACRONYMS AND ABBREVIATIONS........................................................................... xiv

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

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

PROPOSED ACTION...............................................................................................................ES-1

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

ENVIRONMENTAL IMPACTS AND MITIGATION............................................................ES-2

ALTERNATIVES CONSIDERED .........................................................................................ES-13

CONCLUSIONS .....................................................................................................................ES-15

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

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

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

1.2.1 Federal Energy Regulatory Commission............................................................1-5

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

1.2.3 U.S. Coast Guard ................................................................................................1-6

1.2.4 U.S. Department of Energy.................................................................................1-7

1.2.5 U.S. Department of Transportation.....................................................................1-7

1.2.6 U.S. Environmental Protection Agency..............................................................1-7

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

1.4 NON-JURISDICTIONAL FACILITIES.......................................................................1-11

1.4.1 LNG Trucking, Domestic Marine Distribution, and LNG Bunkering..............1-12

1.4.1.1 LNG Trucking...................................................................................1-12

1.4.1.2 Domestic Marine Distribution and LNG Bunkering.........................1-14

1.4.2 Tie-in to Calcasieu Parish District 12 Water Works’ Potable Water Line .......1-16

1.4.3 Electric Transmission Line and Switching Station for the LNG Terminal.......1-17

1.4.4 Electric Transmission Line for Compressor Station 760..................................1-18

1.5 PERMITS, APPROVALS, AND REGULATORY REVIEWS....................................1-19

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

2.1 PROPOSED FACILITIES...............................................................................................2-1

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

2.1.1.1 Magnolia Meter Station and Interconnect Pipeline.............................2-3

2.1.1.2 Liquefaction Trains.............................................................................2-3

2.1.1.3 LNG Storage Tanks.............................................................................2-6

2.1.1.4 LNG Loading and Ship Berthing Area ...............................................2-7

2.1.1.5 LNG Truck Loading............................................................................2-8

2.1.1.6 Flare Stack...........................................................................................2-8

2.1.1.7 Utilities and Support Facilities............................................................2-9
TABLE OF CONTENTS (cont’d)

Page

ii

2.1.2 LNG Transport Vessels ....................................................................................2-12

2.1.2.1 LNG Carriers.....................................................................................2-12

2.1.2.2 LNG Barges ......................................................................................2-16

2.1.2.3 LNG Trucks ......................................................................................2-16

2.1.3 KMLP Facilities................................................................................................2-17

2.1.3.1 Compressor Station 760 ....................................................................2-17

2.1.3.2 Header Pipelines................................................................................2-17

2.1.3.3 Modifications to Existing Meter Stations..........................................2-20

2.2 LAND REQUIREMENTS.............................................................................................2-20

2.2.1 LNG Terminal...................................................................................................2-20

2.2.2 KMLP Facilities................................................................................................2-24

2.2.2.1 Compressor Station 760 ....................................................................2-24

2.2.2.2 Header Pipelines................................................................................2-24

2.2.2.3 Modifications to Existing Meter Stations..........................................2-24

2.2.2.4 Access Roads ....................................................................................2-24

2.3 CONSTRUCTION SCHEDULE AND WORKFORCE ...............................................2-25

2.4 ENVIRONMENTAL COMPLIANCE..........................................................................2-25

2.5 CONSTRUCTION PROCEDURES..............................................................................2-27

2.5.1 LNG Terminal...................................................................................................2-28

2.5.1.1 Site Preparation .................................................................................2-28

2.5.1.2 Materials and Equipment Delivery and Off-site Concrete Batch

Plant..................................................................................................2-28

2.5.1.3 Facility Foundations..........................................................................2-29

2.5.1.4 LNG Loading and Ship Berthing Facilities.......................................2-30

2.5.1.5 Liquefaction Trains...........................................................................2-32

2.5.1.6 LNG Storage and Processing Facilities.............................................2-34

2.5.1.7 LNG Truck Loading Facilities..........................................................2-36

2.5.1.8 Magnolia Meter Station and Interconnect Pipeline...........................2-36

2.5.1.9 Site Restoration .................................................................................2-37

2.5.2 KMLP Facilities................................................................................................2-37

2.5.2.1 Header Pipelines................................................................................2-37

2.5.2.2 Aboveground Facility Construction Procedures...............................2-42

2.6 OPERATION AND MAINTENANCE PROCEDURES..............................................2-43

2.6.1 LNG Marine Traffic along the Waterway ........................................................2-43

2.6.2 LNG Terminal...................................................................................................2-44

2.6.3 Magnolia Meter Station, Interconnect Pipeline, and KMLP Facilities.............2-44

2.7 SAFETY AND SECURITY PROCEDURES ...............................................................2-45

2.7.1 LNG Terminal...................................................................................................2-45

2.7.2 Magnolia Meter Station, Interconnect Pipeline, and KMLP Facilities.............2-47

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

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

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

3.2.1 LNG Terminal Alternatives................................................................................3-5

3.2.1.1 Existing LNG Import Terminals with Approved, Proposed, or

Planned Liquefaction Projects............................................................3-6

3.2.1.2 Approved, Proposed, and Planned Greenfield Liquefaction

Projects.............................................................................................3-13
TABLE OF CONTENTS (cont’d)

Page

iii

3.2.2 Pipeline System Alternatives............................................................................3-22

3.3 SITE ALTERNATIVES................................................................................................3-23

3.3.1 LNG Terminal Site Alternatives.......................................................................3-23

3.3.2 Compressor and Meter Station Site Alternatives..............................................3-27

3.3.3 Header Pipeline Route Alternatives..................................................................3-30

3.3.4 Dredge Material Placement Alternatives..........................................................3-30

3.3.4.1 Proposed Site....................................................................................3-30

3.3.4.2 Confined Disposal Facility 13 ..........................................................3-30

3.3.4.3 Confined Disposal Facilities 12A, 12B, and 12C.............................3-32

3.3.4.4 Turner Bay Beneficial Use Site........................................................3-32

3.4 PROCESS ALTERNATIVES .......................................................................................3-33

3.5 POWER SOURCE ALTERNATIVES..........................................................................3-34

3.5.1 LNG Terminal Alternatives..............................................................................3-34

3.5.2 Compressor Station 760....................................................................................3-35

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

4.1 GEOLOGIC CONDITIONS, RESOURCES, HAZARDS, AND MITIGATION

DESIGN MEASURES ....................................................................................................4-1

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

4.1.2 Mineral Resources..............................................................................................4-3

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

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

4.1.3.2 Subsidence..........................................................................................4-6

4.1.3.3 Flooding and Storm Damage..............................................................4-6

4.1.3.4 Shoreline Erosion and Landslides ......................................................4-7

4.1.4 Blasting...............................................................................................................4-7

4.1.5 Paleontology .......................................................................................................4-8

4.1.6 Design and Construction of the LNG Terminal..................................................4-8

4.1.6.1 Site Grading........................................................................................4-8

4.1.6.2 Foundations........................................................................................4-8

4.1.6.3 Facility and Structure Design .............................................................4-8

4.1.6.4 Submittal of Final Design Documents................................................4-9

4.1.7 General Impacts and Mitigation........................................................................4-10

4.2 SOILS ............................................................................................................................4-11

4.2.1 Existing Soil Resources....................................................................................4-11

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

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

4.2.1.3 Compaction Potential .......................................................................4-14

4.2.1.4 Revegetation Potential......................................................................4-14

4.2.2 Soil Contamination ...........................................................................................4-14

4.2.3 General Impacts and Mitigation........................................................................4-14

4.2.3.1 LNG Terminal ..................................................................................4-14

4.2.3.2 KMLP Facilities...............................................................................4-16
TABLE OF CONTENTS (cont’d)

Page

iv

4.3 WATER RESOURCES .................................................................................................4-17

4.3.1 Groundwater Resources....................................................................................4-17

4.3.1.1 Sole Source Aquifers........................................................................4-17

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

4.3.1.3 Groundwater Quality........................................................................4-18

4.3.1.4 Groundwater Impacts and Mitigation...............................................4-19

4.3.2 Surface Water ...................................................................................................4-22

4.3.2.1 Existing Surface Water Resources ...................................................4-23

4.3.2.2 Surface Water Impacts and Mitigation.............................................4-28

4.4 WETLANDS .................................................................................................................4-38

4.4.1 Existing Wetland Resources.............................................................................4-38

4.4.1.1 LNG Terminal ..................................................................................4-39

4.4.1.2 KMLP Facilities...............................................................................4-39

4.4.2 Wetland Impacts and Mitigation.......................................................................4-40

4.4.2.1 LNG Terminal ..................................................................................4-40

4.4.2.2 KMLP Facilities...............................................................................4-41

4.4.3 Alternative Measures to the FERC Procedures ................................................4-42

4.4.3.1 LNG Terminal ..................................................................................4-42

4.4.3.2 KMLP Facilities...............................................................................4-43

4.4.4 Compensatory Mitigation .................................................................................4-43

4.5 VEGETATION..............................................................................................................4-44

4.5.1 Existing Vegetation Resources.........................................................................4-44

4.5.1.1 LNG Terminal Facilities...................................................................4-44

4.5.1.2 KMLP Facilities...............................................................................4-46

4.5.2 Vegetation Impacts and Mitigation...................................................................4-46

4.5.2.1 LNG Terminal Facilities...................................................................4-46

4.5.2.2 KMLP Facilities...............................................................................4-47

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

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

4.6 WILDLIFE AND AQUATIC RESOURCES................................................................4-49

4.6.1 Wildlife Resources............................................................................................4-49

4.6.1.1 Existing Wildlife Habitats................................................................4-49

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

4.6.1.3 Unique and Sensitive Wildlife..........................................................4-54

4.6.2 Aquatic Resources............................................................................................4-57

4.6.2.1 Existing Aquatic Resources..............................................................4-57

4.6.2.2 Impacts and Mitigation.....................................................................4-58

4.6.3 Essential Fish Habitat .......................................................................................4-67

4.6.3.1 Regulatory Background....................................................................4-67

4.6.3.2 Essential Fish Habitat at the LNG Terminal ....................................4-68

4.6.3.3 Impacts and Mitigation.....................................................................4-69

4.7 THREATENED, ENDANGERED, AND OTHER SPECIAL STATUS SPECIES .....4-71

4.7.1 Federally Listed Threatened and Endangered Species .....................................4-76

4.7.1.1 Sea Turtles........................................................................................4-76

4.7.1.2 West Indian Manatee........................................................................4-78

4.7.1.3 Whales..............................................................................................4-79
TABLE OF CONTENTS (cont’d)

Page

v

4.7.2 State-listed and Special Status Species.............................................................4-80

4.7.2.1 State-listed Species...........................................................................4-80

4.7.2.2 Marine Mammals..............................................................................4-81

4.8 LAND USE, RECREATION, AND VISUAL RESOURCES ......................................4-82

4.8.1 Land Use...........................................................................................................4-82

4.8.1.1 Environmental Setting......................................................................4-82

4.8.1.2 Impacts and Mitigation.....................................................................4-86

4.8.2 Landowner and Easement Requirements..........................................................4-90

4.8.3 Planned Developments .....................................................................................4-91

4.8.4 Recreation and Special Interest Areas ..............................................................4-91

4.8.5 Visual Resources...............................................................................................4-93

4.8.5.1 LNG Terminal ..................................................................................4-93

4.8.5.2 KMLP Facilities...............................................................................4-98

4.8.6 Coastal Zone Management ...............................................................................4-99

4.9 SOCIOECONOMICS....................................................................................................4-99

4.9.1 Population.........................................................................................................4-99

4.9.1.1 LNG Terminal ..................................................................................4-99

4.9.1.2 KMLP Facilities.............................................................................4-101

4.9.2 Economy and Employment.............................................................................4-102

4.9.2.1 LNG Terminal ................................................................................4-103

4.9.2.2 KMLP Facilities.............................................................................4-103

4.9.3 Local Taxes and Government Revenue ..........................................................4-104

4.9.4 Housing...........................................................................................................4-105

4.9.4.1 LNG Terminal ................................................................................4-105

4.9.4.2 KMLP Facilities.............................................................................4-106

4.9.5 Public Services................................................................................................4-106

4.9.5.1 LNG Terminal ................................................................................4-107

4.9.5.2 KMLP Facilities.............................................................................4-107

4.9.6 Transportation.................................................................................................4-107

4.9.6.1 LNG Terminal ................................................................................4-108

4.9.6.2 KMLP Facilities.............................................................................4-112

4.9.7 Property Values...............................................................................................4-114

4.9.8 Environmental Justice.....................................................................................4-114

4.10 CULTURAL RESOURCES........................................................................................4-116

4.10.1 Cultural Resources Survey..............................................................................4-117

4.10.1.1 Magnolia LNG Project ...................................................................4-117

4.10.1.2 Lake Charles Expansion Project.....................................................4-117

4.10.2 Unanticipated Discoveries Plan ......................................................................4-118

4.10.3 Native American Consultation........................................................................4-118

4.11 AIR QUALITY AND NOISE .....................................................................................4-119

4.11.1 Air Quality ......................................................................................................4-119

4.11.1.1 Regional Climate ............................................................................4-119

4.11.1.2 Existing Air Quality .......................................................................4-119

4.11.1.3 Regulatory Requirements for Air Quality ......................................4-122

4.11.1.4 Construction Air Emissions and Impacts and Mitigation...............4-129

4.11.1.5 Operation Air Emissions Impacts and Mitigation ..........................4-134
TABLE OF CONTENTS (cont’d)

Page

vi

4.11.2 Noise ...............................................................................................................4-141

4.11.2.1 Noise Regulations...........................................................................4-142

4.11.2.2 Existing Sound Levels and Noise Sensitive Areas.........................4-143

4.11.2.3 Construction Noise Impacts and Mitigation...................................4-145

4.11.2.4 Operation Noise Impacts and Mitigation........................................4-150

4.12 RELIABILITY AND SAFETY...................................................................................4-153

4.12.1 Regulatory Oversight......................................................................................4-153

4.12.2 LNG Facility Hazards.....................................................................................4-155

4.12.3 Technical Review of the Facility Preliminary Engineering Design................4-164

4.12.4 LNG Facility Siting Requirements .................................................................4-177

4.12.5 LNG Facility Siting Analysis .........................................................................4-180

4.12.5.1 Impoundment Sizing ......................................................................4-181

4.12.5.2 Design Spills...................................................................................4-183

4.12.5.3 Vapor Dispersion Analysis.............................................................4-184

4.12.5.4 Overpressure Analysis....................................................................4-195

4.12.5.5 Thermal Radiation Analysis...........................................................4-199

4.12.6 LNG Carriers..................................................................................................4-201

4.12.7 LNG Carrier Routes........................................................................................4-203

4.12.7.1 Hazards Resulting from Accidents.................................................4-204

4.12.7.2 Hazards Resulting from Intentional Acts .......................................4-206

4.12.7.3 Hazard Zones..................................................................................4-207

4.12.8 Regulatory Requirements for LNG Carrier Operations..................................4-211

4.12.9 Emergency Response and Evacuation ............................................................4-213

4.12.10 Conclusions on Facility Reliability and Safety...............................................4-215

4.12.11 Pipeline Safety Standards ...............................................................................4-216

4.12.11.1 Pipeline Accident Data ...................................................................4-222

4.12.11.2 Impacts on Public Safety................................................................4-223

4.13 CUMULATIVE IMPACTS.........................................................................................4-225

4.13.1 Project and Activities Considered...................................................................4-225

4.13.1.1 Liquefaction and LNG Export Projects..........................................4-226

4.13.1.2 Non-jurisdictional Facilities Associated with the LNG Terminal

and KMLP Facilities.......................................................................4-235

4.13.1.3 Pipeline System Projects ................................................................4-236

4.13.1.4 Other Industrial and Commercial Projects .....................................4-237

4.13.1.5 Utility Projects................................................................................4-239

4.13.1.6 Residential Developments..............................................................4-240

4.13.2 Potential Cumulative Impacts by Resource ....................................................4-241

4.13.2.1 Geologic Conditions.......................................................................4-246

4.13.2.2 Soils................................................................................................4-247

4.13.2.3 Water Resources.............................................................................4-248

4.13.2.4 Wetlands, Vegetation, and Wildlife ...............................................4-252

4.13.2.5 Aquatic Resources..........................................................................4-254

4.13.2.6 Threatened and Endangered Species..............................................4-256

4.13.2.7 Land Use, Recreation, and Visual Resources.................................4-258

4.13.2.8 Socioeconomics..............................................................................4-263
TABLE OF CONTENTS (cont’d)

Page

vii

4.13.2.9 Traffic.............................................................................................4-265

4.13.2.10 Cultural Resources..........................................................................4-268

4.13.2.11 Air Quality and Noise.....................................................................4-269

4.13.2.12 Safety..............................................................................................4-275

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

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

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

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

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 and Endangered Species ................................................................5-12

5.1.8 Land Use, Recreation, and Visual Resources...................................................5-13

5.1.9 Socioeconomics................................................................................................5-16

5.1.10 Cultural Resources............................................................................................5-18

5.1.11 Air Quality and Noise .......................................................................................5-18

5.1.12 Safety ................................................................................................................5-21

5.1.13 Cumulative Impacts..........................................................................................5-22

5.1.14 Alternatives.......................................................................................................5-25

5.2 FERC STAFF’S RECOMMENDED MITIGATION....................................................5-27
LIST OF TABLES

Number Title Page

viii

Table 1.3-1 Key Environmental Concerns Identified During Scoping.......................................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 Required for the Projects................1-20

Table 2.2-1 Land Requirements for the Magnolia LNG and Lake Charles Expansion

Projects....................................................................................................................2-22

Table 2.2.2-1 Access Roads Associated with the KMLP Facilities ..............................................2-25

Table 2.5.1-1 Pile Driving Activities Associated with Construction of the LNG Terminal..........2-29

Table 3.3.1-1 Comparison of Alternative Sites for the LNG Terminal .........................................3-24

Table 3.3.2-1 Comparison of Alternative Sites for the Compressor Station .................................3-28

Table 4.2.1-1 Characteristics of Soils Associated with the LNG Terminal and KMLP

Facilities..................................................................................................................4-13

Table 4.3.2-1 Waterbodies Potentially Affected by the LNG Terminal and KMLP Facilities .....4-26

Table 4.3.2-2 Estimates of LNG Carrier Cooling Water Use and Intake Rates at the LNG

Terminal ..................................................................................................................4-33

Table 4.3.2-3 Hydrostatic Test Water Requirements for the LNG Terminal ................................4-35

Table 4.4.2-1 Wetlands Affected by the LNG Terminal and KMLP Facilities.............................4-40

Table 4.4.3-1 Alternative Measures Requested for Impacts Within and Near Wetlands..............4-42

Table 4.5.1-1 Vegetation Communities Affected by Construction and Operation of the LNG 

Terminal and KMLP Facilities................................................................................4-45

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

Terminal ..................................................................................................................4-59

Table 4.6.3-1 Life Stage Occurrence for Species with Essential Fish Habitat Designated in the 

Vicinity of the LNG Terminal.................................................................................4-69

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

Magnolia LNG and Lake Charles Expansion Projects............................................4-73

Table 4.7.2-1 Non-Endangered Species Act Listed Marine Mammals Potentially Occurring

Along the LNG Transit Routes ...............................................................................4-81

Table 4.8.1-1 Land Use Types Affected by Construction and Operation of the LNG Terminal

and KMLP Facilities ...............................................................................................4-83

Table 4.9.1-1 Existing Socioeconomic Conditions in the Affected Area....................................4-100

Table 4.9.1-2 Construction Workforce and Duration Associated with the KMLP Facilities......4-102

Table 4.9.3-1 Estimated Annual Ad Valorem Taxes Paid During Operation of the LNG

Terminal and KMLP Facilities..............................................................................4-104

Table 4.9.4-1 Temporary and Short-term Housing Availability Within the Affected Area........4-105

Table 4.9.5-1 Public Services in the Affected Area ....................................................................4-106

Table 4.9.6-1 Construction Duration and Vehicle Trips per Day Associated with the KMLP 

Facilities................................................................................................................4-113

Table 4.9.8-1 Demographics in the Vicinity of the LNG Terminal and KMLP Facilities..........4-115

Table 4.9.8-2 Economic Statistics in the Vicinity of the LNG Terminal and KMLP

Facilities................................................................................................................4-116

Table 4.11.1-1 National Ambient Air Quality Standards..............................................................4-120

Table 4.11.1-2 Ambient Air Quality Concentrations for Areas Near the LNG Terminal and

KMLP Facilities....................................................................................................4-123

Table 4.11.1-3 Major Stationary Source and Prevention of Significant Deterioration Emission 

Thresholds.............................................................................................................4-126

Table 4.11.1-4 Annual LNG Terminal Construction Emissions ...................................................4-131
TABLES (cont’d)

Table Title Page

ix

Table 4.11.1-5 Compressor Station 760 Construction Emissions .................................................4-132

Table 4.11.1-6 Emissions by Source and Total Annual Emissions Associated with Operation

of the LNG Terminal.............................................................................................4-136

Table 4.11.1-7 Summary of Preliminary Air Dispersion Modeling at the LNG Terminal and 

Significant Impact Levels for Air Quality Impacts in Class II Areas ...................4-136

Table 4.11.1-8 Summary of NO2 1-Hour National Ambient Air Quality Standards Modeling

Results...................................................................................................................4-137

Table 4.11.1-9 Summary of NO2 Annual National Ambient Air Quality Standards Modeling

Results...................................................................................................................4-137

Table 4.11.1-10 Summary of NO2 Prevention of Significant Deterioration Increment Modeling 

Results...................................................................................................................4-138

Table 4.11.1-11 Compressor Station 760 Estimated Annual Emission Rates.................................4-140

Table 4.11.1-12 Summary of Preliminary Air Dispersion Modeling at Compressor Station 760

and Significant Impact Levels for Air Quality Impacts in Class II Areas.............4-140

Table 4.11.2-1 Sound Levels and Relative Loudness....................................................................4-142

Table 4.11.2-2 Acadia Parish Sound Pressure Level Limits .........................................................4-143

Table 4.11.2-3 LNG Terminal Facilities – Existing Noise Levels at Nearby Noise Sensitive

Areas......................................................................................................................4-145

Table 4.11.2-4 Compressor Station 760 – Existing Noise Levels at Nearby Noise Sensitive

Areas......................................................................................................................4-145

Table 4.11.2-5 LNG Terminal – Construction Noise Estimates....................................................4-147

Table 4.11.2-6 LNG Terminal – Pile Driving Noise Estimates.....................................................4-148

Table 4.11.2-7 KMLP Facilities Construction – Noise Estimates.................................................4-150

Table 4.11.2-8 LNG Terminal Operation – Equipment Quantities and Sound Power Levels ......4-151

Table 4.11.2-9 LNG Terminal Operation – Composite Noise Levels at Nearby Noise Sensitive

Areas......................................................................................................................4-151

Table 4.11.2-10 Compressor Station 760 Operation – Noise Levels at Nearby Noise Sensitive

Areas......................................................................................................................4-153

Table 4.12.2-1 Acute Exposure Guideline Levels of Various Material Components ...................4-160

Table 4.12.2-2 Emergency Response Planning Guidelines for Various Material Components....4-161

Table 4.12.2-3 Flammable Properties............................................................................................4-161

Table 4.12.5-1 Impoundment Area Sizing.....................................................................................4-182

Table 4.12.5-2 LNG Design Spills................................................................................................4-191

Table 4.12.5-3 Other Hazardous Fluid Design Spills....................................................................4-193

Table 4.12.5-4 Vapor Dispersion Scenarios from Refrigerants and Natural Gas Liquids

Releases.................................................................................................................4-193

Table 4.12.5-5 Distance to the 1⁄2-AEGL 1 and 2 at 10-minute Exposure Time............................4-194

Table 4.12.5-6 Ammonia Release Toxic Endpoints......................................................................4-195

Table 4.12.5-7 Overpressure Distances from Refrigerants and Natural Gas Liquids....................4-196

Table 4.12.5-8 Thermal Radiation Exclusion Zones.....................................................................4-200

Table 4.12.11-1 Natural Gas Transmission Pipeline Significant Incidents by Cause

(1994–2013) ..........................................................................................................4-222

Table 4.12.11-2 Outside Force Incidents by Cause (1994–2013) ...................................................4-223

Table 4.12.11-3 Annual Average Injuries and Fatalities (2009–2013) ...........................................4-224

Table 4.12.11-4 Nationwide Accidental Deaths from Various Causes...........................................4-224

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

Impacts Analysis for the Magnolia LNG and Lake Charles Expansion Projects..4-229
TABLES (cont’d)

Table Title Page

x

Table 4.13.2-1 Projects Included in the Cumulative Impacts Analysis for the Magnolia LNG

and Lake Charles Expansion Projects...................................................................4-242

Table 4.13.2-2 Oil and Gas Industry Facilities Within 1 Mile of the KMLP Facilities ................4-259

Table 4.13.2-3 Employment Forecast for Industrial and Large-Scale Projects Between 2015

and 2019 ................................................................................................................4-263
LIST OF FIGURES

Number Title Page

xi

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

Figure 1-2 Lake Charles Expansion Project Overview Map.......................................................1-3

Figure 1.4.1-1 Hazardous Material Shipping Routes Analyzed Between the LNG Terminal 

and Interstate 10 ......................................................................................................1-13

Figure 1.4.1-2 Potential Domestic Marine Distribution and LNG Bunkering Locations...............1-15

Figure 1.4.2-1 Tie-in to Existing Potable Water Line.....................................................................1-16

Figure 1.4.3-1 Electric Transmission Line from Entergy’s Existing System to the LNG

Terminal ..................................................................................................................1-17

Figure 1.4.4-1 Electric Transmission Line from Cleco’s Existing System to Compressor

Station 760...............................................................................................................1-18

Figure 2.1.1-1 LNG Terminal and Surrounding Area.......................................................................2-2

Figure 2.1.1-2 LNG Terminal Site Plan............................................................................................2-3

Figure 2.1.1-3 Schematic of OSMR® Process .................................................................................2-5

Figure 2.1.1-4 LNG Terminal Layout...............................................................................................2-7

Figure 2.1.3-1 KMLP Facilities Overview Map .............................................................................2-18

Figure 2.1.3-2 KMLP Facilities Located in Acadia Parish.............................................................2-19

Figure 2.2.1-1 LNG Terminal Boundary Map in Relation to the DII Construction Yard ..............2-21

Figure 2.2.1-2 Dredge Material Placement Area and Transfer Pipelines Route.............................2-23

Figure 2.5.1-1 LNG Loading and Ship Berthing Facilities.............................................................2-33

Figure 2.5.1-2 Typical LNG Storage Tank Design.........................................................................2-35

Figure 3.3.1-1 General Location Map of Alternative Sites for the LNG Terminal ........................3-25

Figure 3.3.2-1 Alternative Sites for Compressor Station 760.........................................................3-28

Figure 3.3.4-1 Alternative Dredge Placement Sites Considered.....................................................3-31

Figure 4.1.1-1 LNG Terminal Site Elevation....................................................................................4-2

Figure 4.1.2-1 Active and Shut-in Oil and Gas Wells Within 0.25 Mile of the KMLP Facilities....4-4

Figure 4.3.2-1 Waterways in the Vicinity of the LNG Terminal....................................................4-24

Figure 4.8.1-1 Development in the Vicinity of the LNG Terminal ................................................4-85

Figure 4.8.5-1 Visual Simulation of View from Calcasieu Point Landing – Daytime ...................4-95

Figure 4.8.5-2 Visual Simulation of View From Calcasieu Point Landing – Evening...................4-96

Figure 4.9.1-1 Construction Workforce Associated with the LNG Terminal and

KMLP Facilities....................................................................................................4-101

Figure 4.9.6-1 Roadway Traffic Associated with Construction of the LNG Terminal.................4-108

Figure 4.11.2-1 LNG Terminal – Nearby Noise Sensitive Areas...................................................4-144

Figure 4.11.2-2 Compressor Station 760 – Nearby Noise Sensitive Areas ....................................4-147

Figure 4.12.5-1 Vapor Barrier Locations........................................................................................4-187

Figure 4.12.5-2 LNG Release from a Guillotine Rupture of the In-tank Pump Header .................4-188

Figure 4.12.5-3 LNG Jetting and Flashing Scenario from the In-tank Pump Header at Dock .......4-188

Figure 4.12.5-4 LNG Release from the LNG Rundown Line in the Tank Area.............................4-189

Figure 4.12.5-5 LNG Release from the LNG Rundown Line in the Liquefaction Area.................4-189

Figure 4.12.5-6 LNG Jetting and Flashing Scenario from the LNG Rundown Line ......................4-190

Figure 4.12.5-7 LNG Release from the LNG Truck Loading Line ................................................4-190

Figure 4.12.5-8 LNG Jetting and Flashing Scenario from the LNG Truck Loading Line..............4-191

Figure 4.12.5-9 n-Butane Release Scenario at Refrigerant Storage Area .......................................4-193

Figure 4.12.5-10 Ethane Overpressure Scenario at Train 1 ..............................................................4-197

Figure 4.12.5-11 Natural Gas Liquids Overpressure Scenario at Train 4.........................................4-198

Figure 4.12.5-12 n-Butane Overpressure Scenario at Train 1...........................................................4-198

Figure 4.12.5-13 n-Butane Overpressure Scenario between Parallel Vapor Barriers.......................4-199
FIGURES (cont’d)

Number Title Page

xii

Figure 4.12.5-14 Thermal Radiation Zones......................................................................................4-201

Figure 4.12.7-1 Zones of Concern from Accidental Events ...........................................................4-209

Figure 4.12.7-2 Zones of Concern from Intentional Events ...........................................................4-210

Figure 4.13.1-1 Projects Considered in the Cumulative Impacts Analysis.....................................4-227
LIST OF APPENDICES

xiii

Appendix A Distribution List 

Appendix B Proposed Facilities Maps

Appendix C Birds of Conservation Concern Potentially Occurring in the Vicinity of the 

LNG Terminal and KMLP Facilities

Appendix D References and Contacts

Appendix E List of Preparers
TECHNICAL ACRONYMS AND ABBREVIATIONS

xiv

°F degrees Fahrenheit

ACHP Advisory Council on Historic Preservation

Annova Annova LNG Common Infrastructure, LLC, Annova LNG 

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

Annova LNG Brownsville C, LLC

ANR ANR Pipeline Company

ANSI American National Standards Institute

APE area of potential effects

AQCR air quality control region

ASME American Society of Mechanical Engineers

Authorization Authorization To Export Natural Gas

BA biological assessment

BACT Best Available Control Technology

Barca Barca LNG LLC

BCR Bird Conservation Region

BGEPA Bald and Golden Eagle Protection Act

BMP best management practices

Bcf/d billion cubic feet per day

BTEX benzene, toluene, ethylbenzene, and xylenes

CAA Clean Air Act

Cameron LNG Cameron LNG, LLC

CAMx Comprehensive Air Quality Model with Extensions

CB&I Chicago Bridge & Iron Company

CDF confined disposal facility

CE FLNG CE FLNG, LLC

CEQ Council on Environmental Quality

Certificate Certification of Public Convenience and Necessity

CFR Code of Federal Regulations

CGT Columbia Gulf Transmission Company

CH4 methane

CI ICE compression ignition internal combustion engines

Cleco Cleco Corporation 

CO carbon monoxide

CO2 carbon dioxide

CO2e carbon dioxide equivalents

Coast Guard U.S. Coast Guard

COE U.S. Army Corps of Engineers

COI Certificate of Inspection

Columbia Gulf Columbia Gulf Transmission, LLC 

Commission Federal Energy Regulatory Commission

Corpus Christi Corpus Christi Liquefaction, LLC

CWA Clean Water Act

dB decibels

dBA decibels on the A-weighted scale

Delfin Delfin LNG, LLC 

DHS U.S. Department of Homeland Security

DII Dynamic Industries, Inc.

DOE U.S. Department of Energy
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xv

DOT U.S. Department of Transportation

DOTD Department of Transportation and Development

DPS distinct population segments

EEZ U.S. Exclusive Economic Zone

EFH essential fish habitat

EI environmental inspector

EIS environmental impact statement

ELS Excelerate Liquefaction Solutions (Port Lavaca I), LLC, 

Excelerate Liquefaction Solutions (Port Lavaca 2), LLC, and 

Lavaca Bay Pipeline System, LLC

Entergy Entergy Gulf States Louisiana, LLC

Eos Eos LNG LLC

EPA U.S. Environmental Protection Agency

EPAct 2005 Energy Policy Act of 2005

ESA Endangered Species Act of 1973

FEED Front End Engineering Design

FEMA Federal Emergency Management Agency

FERC Federal Energy Regulatory Commission

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

FLEX FLNG Expansion and FLNG Liquefaction, LLC

FLNGV floating LNG vessel

FLSO floating liquefaction, storage, and offloading 

Freeport LNG Freeport LNG Development, LP and FLNG Liquefaction, LLC

Freeport-McMoRan Freeport-McMoRan Energy, LLC

FTA Free Trade Agreement

FWS U.S. Fish and Wildlife Service

G2 LNG G2 LNG LLC

G2X Energy G2X Energy, Inc. 

Gasfin Gasfin Development USA, LLC

GHG greenhouse gas

GIS geographic information systems

GMFMC Gulf of Mexico Fishery Management Council 

Golden Pass Golden Pass Products, LLC

Gulf Coast Gulf Coast LNG Export, LLC

Gulf LNG Gulf LNG Liquefaction Company, LLC

GWP global warming potential

HAP hazardous air pollutant

HCA high consequence area

hp horsepower

IEA International Energy Agency

IFG IFG Port Holdings, LLC

IMO International Maritime Organization

IPCC Intergovernmental Panel on Climate Change 

KMLP Kinder Morgan Louisiana Pipeline LLC

kV kilovolt

LAC Louisiana Administrative Code

Lake Charles LNG Lake Charles LNG Export Company, LLC and

Lake Charles LNG Company, LLC

lb/hr pounds per hour
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xvi

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

Live Oak Live Oak LNG, LLC 

Lmax maximum sound level observed during a measurement period or noise event 

LNG liquefied natural gas

LNHP Louisiana Natural Heritage Program

LOI Letter of Intent

LOR Letter of Recommendation

LOS Levels of Service

Louisiana LNG Louisiana LNG Energy LLC 

LPDES Louisiana Pollutant Discharge Elimination System

m3cubic meters

m3/hr cubic meters per hour 

MACT Maximum Achievable Control Technology 

Magnolia Magnolia LNG, LLC

MAOP maximum allowable operating pressure

MARPOL International Convention for the Prevention of Pollution from Ships

MBTA Migratory Bird Treaty Act

MCL Maximum Contaminant Level

mg/L milligrams per liter

MMBtu million British thermal units 

MMBtu/hr million British thermal units per hour 

MMPA Marine Mammal Protection Act of 1972

MOU Memorandum of Understanding

MSA Magnuson-Stevens Fishery Conservation and Management Act

MTPA metric tonnes per annum

MW megawatts

N2O nitrous oxide

NAAQS National Ambient Air Quality Standards 

NAVD 88 North American Vertical Datum of 1988

NEPA National Environmental Policy Act of 1969

NESHAP National Emission Standards for Hazardous Air Pollutants 

NFPA National Fire Protection Association

NGA Natural Gas Act

NGL natural gas liquids

NHPA National Historic Preservation Act

NOAA National Oceanic and Atmospheric Administration

NOAA Fisheries National Oceanic and Atmospheric Administration, National Marine 

Fisheries Service

NOI for the Lake Charles 

Expansion Project

Notice of Intent to Prepare an Environmental Impact Statement for the 

Proposed Lake Charles Expansion Project and Request for Comments on 

Environmental Issues

NOI for the Magnolia 

LNG Project

Notice of Intent to Prepare an Environmental Impact Statement for the 

Planned Magnolia Liquefied Natural Gas Project, Request for Comments on 

Environmental Issues, and Notice of Public Scoping Meeting

NOx nitrogen oxide
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xvii

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

NVIC Navigation and Vessel Inspection Circular

NWI National Wetlands Inventory

NWR National Wildlife Refuge

OEP Office of Energy Projects

OSH Act Occupational Safety and Health Act of 1970

OSHA Occupational Safety and Health Administration

OSMR® Optimized Single Mixed Refrigerant

PGA peak ground acceleration

PHMSA Pipeline and Hazardous Materials Safety Administration

Pine Prairie Pine Prairie Energy Center, LLC

Plan Upland Erosion Control, Revegetation, and Maintenance Plan 

PM10 inhalable particulate matter with an aerodynamic diameter less than or 

equal to 10 microns

PM2.5 inhalable particulate matter with an aerodynamic diameter less than or 

equal to 2.5 microns

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

ppb parts per billion

ppm parts per million

ppt parts per thousand

Procedures Wetland and Waterbody Construction and Mitigation Procedures 

PSD Prevention of Significant Deterioration

psia pounds per square inch absolute

psig pounds per square inch gauge

PSM standard Process Safety Management of Highly Hazardous Chemicals standard 

RECAP Risk Evaluation/Corrective Action Program

RHA Rivers and Harbors Act

RICE reciprocating internal combustion engines 

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

RMP Risk Management Plans

RV recreational vehicle

Sabine Pass LNG Sabine Pass LNG, LP

Sasol Sasol North America, Inc. 

SCADA Supervisory Control and Data Acquisition 

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

SHPO State Historic Preservation Office

SIL significant impact level

SO2 sulfur dioxide

SOLAS International Convention for the Safety of Life at Sea 

SONRIS Strategic Online Natural Resources Information System

SOx sulfur oxide

SPCC Plan Spill Prevention, Control, and Countermeasures Plan

SSURGO Soil Survey Geographic
TECHNICAL ACRONYMS AND ABBREVIATIONS (cont’d)

xviii

SWLA Economic 

Development 

Alliance

Southwest Louisiana Economic Development Alliance 

SWPPP Stormwater Pollution Prevention Plan

TETCO Texas Eastern Transmission, L.P.

Texas LNG Texas LNG Brownsville LLC

TGT Texas Gas Transmission, LLC

tpy tons per year

TRANSCO Transcontinental Gas Pipe Line Corporation

Trunkline Trunkline Gas Company

USC United States Code

USDA U.S. Department of Agriculture

USGCRP U.S. Global Change Research Program 

USGS U.S. Geological Survey

Venture Global Venture Global Calcasieu Pass, LLC

VOC volatile organic compound

WesPac WesPac Midstream LLC 

Westlake Chemical Westlake Chemical Corporation

WSA Waterway Suitability Assessment

yd3cubic yards

μPa microPascal
ES-1 

EXECUTIVE SUMMARY 

INTRODUCTION 

On April 30, 2014, Magnolia LNG, LLC (Magnolia) filed an application with the Federal Energy 

Regulatory Commission (Commission or FERC) for authorization pursuant to section 3(a) of the Natural 

Gas Act (NGA) and Part 153 of the Commission’s regulations. In Docket No. CP14-347-000, Magnolia 

requests authorization to site, construct, and operate facilities necessary to liquefy natural gas at a 

proposed site in Lake Charles, Calcasieu Parish, Louisiana. Magnolia’s proposed project is referred to as 

the Magnolia LNG Project. 

On June 30, 2014, Kinder Morgan Louisiana Pipeline LLC (KMLP) filed an application with the 

FERC for a Certificate of Public Convenience and Necessity (Certificate) pursuant to section 7(c) of the 

NGA and part 157 of the Commission’s regulations. In Docket No. CP14-511-000, KMLP requests 

authorization to construct and operate system modifications that would allow the delivery of natural gas 

to Magnolia’s proposed liquefied natural gas (LNG) terminal using a new north-to-south path on KMLP’s 

system. The proposed system modifications would be within Acadia, Calcasieu, and Evangeline Parishes, 

Louisiana. KMLP’s proposed project is referred to as the Lake Charles Expansion Project. 

The purpose of the environmental impact statement (EIS) is to inform FERC decision-makers, the 

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

the proposed projects and their 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 projects as required under the National Environmental 

Policy Act of 1969, as amended. Our analysis was based on information provided by Magnolia and 

KMLP, and further developed from data requests; field investigations; scoping; literature research; 

contacts with or comments from federal, state, and local agencies; and comments from individual 

members of the public. 

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

(COE), U.S. Coast Guard (Coast Guard), U.S. Department of Energy, U.S. Department of Transportation 

(DOT), and U.S. Environmental Protection Agency (EPA) are participating in the National 

Environmental Policy Act review as cooperating agencies.2

PROPOSED ACTION 

The Magnolia LNG and Lake Charles Expansion Projects consist of two main components: 

1) the construction and operation of various liquefaction facilities, LNG storage tanks, LNG distribution 

facilities, LNG vessel berthing area, a meter station (Magnolia Meter Station) and appurtenant facilities 

within the boundaries of the site leased by Magnolia near Lake Charles, Louisiana; and 2) the 

reconfiguration of KMLP’s existing pipeline system in order to accommodate Magnolia’s request for 

natural gas service at the LNG terminal site (collectively referred to as the KMLP facilities), including a 

new compressor station (Compressor Station 760), new low and high pressure natural gas header 

pipelines that would be adjacent to the existing KMLP easement, and modifications at six existing meter 

stations. 

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

approvals, Magnolia anticipates starting construction of the LNG terminal in early 2016, and placing the 

 

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 

first liquefaction train into service in December 2018. The remaining three liquefaction trains would be 

commissioned at 3-month intervals after completion of the first liquefaction train, with full service 

anticipated after a total construction period of 45 months. KMLP would construct its proposed facilities 

over an 11-month period, which is tentatively scheduled to begin in January 2017; these facilities would 

be in-service prior to startup of the first liquefaction train. 

The projects would serve the domestic and export markets for LNG, and the Magnolia LNG 

Project would have the capacity to export an LNG volume equivalent to 1.08 billion cubic feet per day. 

PUBLIC INVOLVEMENT 

On March 20, 2013, the FERC began its pre-filing review of the Magnolia LNG Project and 

established pre-filing Docket No. PF13-9-000 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 June 18, 2013, the FERC issued a Notice of Intent to Prepare an Environmental Impact 

Statement for the Planned Magnolia Liquefied Natural Gas Project, Request for Comments on 

Environmental Issues, and Notice of Public Scoping Meeting (NOI for the Magnolia LNG Project). This 

notice was sent to about 540 interested parties including federal, state, and local officials; agency 

representatives; conservation organizations; Native American tribes; local libraries and newspapers; and 

property owners in the vicinity of planned project facilities. Publication of the NOI for the Magnolia 

LNG Project established a 30-day public comment period for the submission of comments, concerns, and 

issues related to the environmental aspects of the project. 

Between May 1 and 3, 2013, the FERC met with representatives of the COE, Coast Guard, 

Louisiana Department of Environmental Quality, Louisiana Department of Natural Resources, Louisiana 

Department of Wildlife and Fisheries, and Magnolia to discuss coordination of agency review, permit 

requirements and status, and each agency’s interest in participating in our environmental review as a 

cooperating agency. On July 11, 2013, the FERC conducted a public scoping meeting in Lake Charles, 

Louisiana to provide an opportunity for the public to learn more about the Magnolia LNG Project and to 

participate in our analysis by providing oral comments on environmental issues to be included in the EIS. 

On August 11, 2014, the FERC issued a Notice of Intent to Prepare an Environmental Impact 

Statement for the Proposed Lake Charles Expansion Project and Request for Comments on 

Environmental Issues (NOI for the Lake Charles Expansion Project). 

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 projects and are available for viewing using the appropriate docket number. 

ENVIRONMENTAL IMPACTS AND MITIGATION 

We evaluated the potential impacts of construction and operation of the projects 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. 
ES-3 

Construction of the LNG terminal and KMLP facilities would affect a total of 353.5 acres of land, 

including additional construction workspaces and access roads. During operation, 144.6 acres would be 

required for operation of the LNG terminal and new or expanded KMLP facilities, and 173.9 acres would 

be allowed to revert to the pre-construction land use type. The remaining 35.0 acres within the dredge 

material placement area would be converted from open water, industrial/commercial, and forest to open 

land, but would not be retained by Magnolia following construction. 

Construction of the LNG terminal would affect a total of 277.7 acres of land, including open land, 

open water, forest, and industrial/commercial. Operation of the LNG terminal would result in permanent 

impacts on 123.8 acres of land and open water within the Industrial Canal. Over 99 percent of the area 

permanently affected by the LNG terminal is within areas that have been previously disturbed by 

commercial or industrial activities. 

Construction of the KMLP facilities would affect about 76 acres of land. Because the activities 

involve modification or expansion of existing facilities, much of the land affected by the KMLP facilities 

would be adjacent to the permanent easement associated with KMLP’s existing mainline or would be 

adjacent to or within existing meter station sites. The KMLP facilities would be constructed almost 

entirely within agricultural lands, although small areas of industrial/commercial and open lands would 

also be affected. 

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

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

endangered species, recreation, visual resources, socioeconomics, air quality and noise, safety and 

reliability, and the cumulative impacts of projects in the vicinity of the proposed Magnolia LNG and Lake 

Charles Expansion Projects. 

Water Resources 

The LNG terminal and KMLP facilities are underlain by the Chicot aquifer, which is an EPAdesignated sole-source aquifer. In some areas, groundwater withdrawals from the Chicot aquifer are 

causing lowered water levels (drawdown) and saltwater encroachment. Construction of the LNG terminal 

would require approximately 2.5 million gallons of groundwater for construction worker sanitation, dust 

suppression, hydrostatic testing of plant piping at the LNG terminal, cleaning of the LNG storage tanks 

following hydrostatic testing, and other general utility uses over the 45-month construction period (the 

majority of which would take place during the first 36 months of construction). On average, 

approximately 1,800 gallons of groundwater would be required per day, although approximately 

6,000 gallons of groundwater would be required per day during peak construction. Groundwater required 

during construction of the KMLP facilities would be limited to approximately 346,000 gallons of water, 

which would be used for hydrostatic testing. 

Groundwater use associated with operation of the LNG terminal would increase overall 

withdrawal from the Chicot aquifer by up to 167,378 gallons per day for operation of the demineralized 

water treatment plant and use as service water. Magnolia conducted a drawdown analysis, which 

indicated that operation of the new on-site well within the 500-foot sand would result in drawdown of less 

than 1.5 feet at a distance of 1,500 feet from the point of withdrawal. No groundwater would be 

necessary for the operation of the KMLP facilities. We anticipate that construction and operation of the 

projects would have long-term, but minor impacts on the Chicot aquifer. 

No private water wells are within 150 feet of the proposed LNG terminal site; two private water 

wells are within 150 feet of the KMLP facilities. KMLP would contact each affected landowner to 

confirm the locations of private wells within 150 feet and public wells within 400 feet of the construction 
ES-4 

workspace. To document impacts on water wells and verify that they are appropriately addressed, we are 

recommending that, within 30 days of placing facilities in service, KMLP file a report identifying all 

public or private water supply wells/systems damaged by construction and a description of 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. 

The Industrial Canal at the LNG terminal site is designated as essential fish habitat (EFH) under 

the Magnuson-Stevens Fishery Conservation and Management Act and a Navigable Waterway under 

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

construction of the LNG terminal would be from dredging the berthing area for LNG vessels and the 

associated suspension of sediments in the water column. These effects would be minor since they would 

be temporary and limited to the immediate area. Magnolia’s proposed use of a hydraulic dredge with a 

suction cutter head would minimize turbidity and surface water quality impacts. To further minimize 

these impacts, Magnolia would finalize and implement its Dredging Water Quality Monitoring Plan. 

However, because this plan has not been finalized, we are recommending that, prior to construction, 

Magnolia file its final Dredging Water Quality Monitoring Plan. 

In-water construction associated with the LNG loading and ship berthing facilities, ground 

disturbance, filling of one intermittent waterbody that is not hydrologically connected to the Industrial 

Canal and one man-made waterbody, and general construction activities within the terminal site would 

result in localized, temporary increases in turbidity and suspended sediment levels. To minimize impacts 

on water quality, land disturbing activities would be conducted in compliance with the Louisiana 

Pollutant Discharge Elimination System General Permit; Magnolia would implement its project-specific 

Construction Stormwater Pollution Prevention Plan, Upland Erosion Control, Revegetation, and 

Maintenance Plan (Plan), and Wetland and Waterbody Construction and Procedures (Procedures); and 

KMLP would implement the FERC Plan and Procedures. As a result, impacts on surface water quality 

are expected to be temporary and limited to the area within and immediately adjacent to the proposed 

facilities. 

During construction of the LNG terminal, 50 or fewer marine deliveries would supply large 

equipment and materials to the Dynamic Industries, Inc. construction yard. During operation, 

approximately 208 LNG vessels (104 LNG carriers and 104 LNG barges) would call on the LNG terminal 

per year. The construction and operational vessel traffic may increase shoreline erosion and temporarily 

increase turbidity levels within the Industrial Canal and along vessel transit routes. To provide protection 

from scour, Magnolia would install rock armoring both within and along the east and west ends of the 

recessed berthing area. The rock armoring would prevent erosion of the adjacent unprotected shoreline 

by wave activity from vessels maneuvering within the recessed berthing area. 

LNG carriers serving the terminal would discharge between approximately 8,711,000 to 

12,264,000 gallons of ballast water into the Industrial Canal during LNG loading. Ballast water 

discharges at the LNG terminal could impact water quality by changing the salinity, temperature, pH, and 

dissolved oxygen level of water within the Industrial Canal. The composition of ballast water in 

comparison to the water present within the Industrial Canal and Calcasieu River would vary depending on 

tidal and hydrologic conditions at the time of discharge. The primary potential impact on water quality 

due to ballast water discharge would be a temporary increase in salinity level. Because ballast water 

would be discharged near the bottom of the berthing area, and would comprise approximately 0.6 percent 

of the approximately 2 billion gallons of water within the Industrial Canal, we anticipate that natural flow 

and tidal exchange would dilute the ballast water discharge to salinity levels that typically occur within 

the Industrial Canal in the immediate vicinity of the LNG terminal and that increased salinity would 

represent a temporary and minor impact on water quality. 
ES-5 

LNG carriers and LNG barges require water for cooling of the main engine/condenser, diesel 

generators, and fire main auxiliary and hotel services. Impacts on surface waters would be primarily 

limited to an increase in water temperature in the vicinity of the LNG vessel resulting from the discharge 

of water between 2.7 degrees Fahrenheit (°F) and 7.2 °F warmer than ambient water temperatures. Due 

to the limited temperature differences, relatively small volume of discharge compared to the total water 

within the canal, and location within an active port that is already subject to withdrawals and discharges 

of vessel engine cooling water, we have determined that cooling water discharges would have temporary 

and minor impacts on water quality. 

A total of 10 waterbodies, including 3 intermittent waterbodies and 7 ephemeral ditches would be 

crossed or otherwise affected (e.g., culvert installation) by construction of the KMLP facilities. None of 

the waterbodies impacted by the KMLP facilities are listed as National Wild and Scenic Rivers, 

designated as Outstanding Natural Resource Waters, designated as EFH, or contain federally or statelisted species. KMLP would minimize potential impacts on surface waters by implementing the FERC 

Procedures and utilizing dry crossing construction techniques if flowing water is present within the 

waterbodies at the time of construction. 

With implementation of the Dredging Water Quality Monitoring Plan, Magnolia’s projectspecific Procedures, Magnolia’s and KMLP’s other project-specific plans and 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 LNG terminal would result in the permanent loss of approximately 16 acres 

of wetlands, including 8 acres of palustrine emergent wetlands, 7 acres of palustrine scrub-shrub wetland, 

1 acre of estuarine emergent intertidal wetland, and less than 1 acre of palustrine forested/scrub-shrub 

wetland. Approximately 87 percent of the wetlands would be converted to upland industrial or open land 

within the LNG terminal site, 7 percent would be converted to an upland herbaceous community within 

the dredge material placement area, and the remaining 6 percent would be converted to open water within 

the recessed berthing area or filled for shoreline stabilization. To date, access has not been granted to 

conduct the necessary wetland surveys along the dredge material and effluent pipeline route or within the 

dredge material placement area. Therefore, we are recommending that Magnolia file the results of the 

wetland and waterbody surveys within areas associated with the transport and placement of dredge 

materials as soon as they are available and prior to the start of construction. 

Because the Compensatory Mitigation Plan has not been finalized and approved by the COE, we 

are recommending that, prior to filing its Implementation Plan, Magnolia file with the Secretary its 

Compensatory Mitigation Plan and documentation of COE approval of the plan. 

Construction and operation of the KMLP facilities would permanently convert 0.3 acre of 

palustrine emergent wetlands to upland industrial use. These impacts would primarily occur within the 

expanded Texas Gas Transmission, LLC Meter Station, but would also include very small areas at the 

Transcontinental Gas Pipe Line Corporation Meter Station and where connection of the high pressure 

header pipeline would require modifications of existing interconnect facilities adjacent to the Pine Prairie 

Meter Station. In its jurisdictional determinations for the KMLP facilities, the COE determined that 

wetlands present are not jurisdictional under section 404 of the Clean Water Act; therefore, compensatory 

mitigation for these wetland impacts would not be required. KMLP would still implement the mitigation 

measures described in our Procedures during construction and operation within these wetlands. 
ES-6 

Our Procedures state that aboveground facilities should be located outside of wetlands, except where 

such siting would prohibit compliance with DOT regulations. Magnolia and KMLP have each proposed 

locating portions of aboveground facilities within wetlands. We have determined that these proposed 

deviations from our Procedures are reasonable. 

With the implementation of Magnolia’s and KMLP’s project-specific plans, the proposed mitigation 

measures discussed in this EIS, and our recommendations, we conclude that impacts on wetlands due to 

construction and operation of the projects would be permanent but minor. 

Wildlife and Aquatic Resources 

The greatest impacts on terrestrial wildlife due to construction and operation of the projects 

would result from the permanent loss of forested and open lands within the LNG terminal site 

(approximately 34 and 31 acres, respectively), which would result in a permanent reduction in these 

habitat types in the general vicinity of the LNG terminal. However, due to the site’s previous use as a 

dredge disposal site and the low diversity of vegetation species, the site’s value as habitat for wildlife is 

limited. We expect impacts due to noise, light, and human activity during operation of the LNG terminal 

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

nearby industrial facilities along the Industrial Canal. 

During construction and operation of the KMLP 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 KMLP facilities would not have a significant impact on 

local wildlife populations or habitat. 

The vegetation communities within the LNG terminal and KMLP facilities are previously 

disturbed, within or adjacent to existing facilities, and/or composed of agricultural land, all of which 

reduce bird nesting habitat value. To minimize impacts on migratory birds during construction, Magnolia 

would direct all nighttime lighting towards construction activity and use the minimum light level 

necessary to ensure site safety and security. Similarly, outdoor lighting at the KMLP aboveground 

facilities would be limited, shielded, and downward-facing to facilitate safe operations at night or during 

inclement weather. Perimeter lighting at aboveground KMLP facilities would be turned off at night and 

would only be used when necessary for work conducted at night. Magnolia has not developed its Facility 

Lighting Plan for operation; therefore, we are recommending that, prior to construction, Magnolia file its 

Facility Lighting Plan for operation of the LNG terminal that would include measures to minimize 

operational lighting impacts on birds. 

Activities associated with construction and operation of the LNG terminal with the greatest 

potential to impact aquatic resources include dredging, pile driving, and vessel traffic. The proposed 

waterbody modifications, water withdrawals for hydrostatic testing, stormwater runoff, lighting, and 

inadvertent spills could also affect aquatic resources; however, with the implementation of the proposed 

mitigation measures, these impacts are expected to be minimal. 

Construction of the recessed berthing area at the LNG terminal site would require dredging a 

16.2-acre area in the Industrial Canal. Potential impacts on aquatic resources resulting from dredging 

activities include direct take and habitat modification as well as temporary increases in noise, turbidity, 

and suspended solid levels. Most fish species are highly mobile and would be expected to leave the area 

during dredging activities. Dredging would, however, result in direct mortality of benthic organisms 

(e.g., aquatic macroinvertebrates, mollusks, and crustaceans, which are important food sources for many 

species of fish) within the 9.8-acre portion of the dredge footprint that currently provides open water 
ES-7 

habitat. 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 maintenance dredging (which is 

scheduled to occur every other year) within the Industrial Canal. To minimize impacts on aquatic 

resources due to increased turbidity and suspended solid levels, Magnolia would use a hydraulic 

cutterhead suction dredge and would implement its Dredging Water Quality Monitoring Plan. With the 

implementation of these mitigation measures and our recommendation that Magnolia file its finalized 

Dredging Water Quality Monitoring Plan, we have determined that impacts on aquatic resources would 

be localized, temporary, and minor. 

Construction of the LNG terminal would require the installation of approximately 5,000 piles 

over a 16-month period to support the proposed structures, including both in-water and onshore piles. 

The primary impacts on aquatic resources from pile driving activities would be avoidance of the area, 

stress, or injury due to the underwater sound pressure levels. Magnolia would perform hydro-acoustic 

monitoring during the initial pile testing to determine the sound pressure levels generated under sitespecific conditions at the LNG terminal. Because pile driving plans have not been finalized and an 

estimate of underwater noise has not been provided, we are recommending that Magnolia file a Pile 

Driving Noise Impact Mitigation Plan prior to the end of the draft EIS comment period. This plan should 

describe the hydroacoustic monitoring methods that Magnolia would use to determine representative 

sound pressure levels associated with in-water pile driving as well as mitigation measures to be 

implemented to reduce sound pressure levels. With the implementation of hydroacoustic monitoring and 

mitigation measures, if needed, pile driving activities would minimize underwater noise levels to a level 

that would not cause significant impacts on aquatic resources. 

During construction and operation of the LNG terminal, barges, support vessels, and LNG vessels 

would call on the LNG terminal, increasing ship traffic within the Industrial Canal, Calcasieu Ship Channel, 

Intracoastal Waterway, and Gulf of Mexico. The greatest potential impacts on aquatic resources resulting 

from increased vessel traffic include reduced dissolved oxygen levels due to ballast water discharges and 

increased water temperature due to cooling water discharges. Depending on the oxygen levels present in both 

the ballast and ambient water at the time of discharge, aquatic resources present in the vicinity of the 

discharge point could be exposed to dissolved oxygen levels considered unhealthy for aquatic life. However, 

resident species within the Industrial Canal are well adapted to natural variation in 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. 

During operation, LNG carriers require water for cooling of the main engine/condenser, diesel 

generators, and fire main auxiliary and hotel services, which would be between 2.7 °F and 7.2 °F warmer 

than ambient water temperatures when discharged. Given the amount of ballast and cooling water 

discharged into the Industrial Canal during each LNG vessel visit to the LNG terminal in relation to the 

approximately 2 billion gallons of water within the Industrial Canal, we have determined that impacts on 

aquatic resources would be intermittent and minor. 

Due to the relatively small area of EFH impacted within the Industrial Canal, the increase in the 

amount of estuarine water column habitat created during construction of the LNG vessel berthing area, 

Magnolia’s proposed mitigation measures, and preliminary agency coordination, we have determined that 

the Magnolia LNG Project would not have a significant adverse impact on EFH. We are requesting that 

the National Marine Fisheries Service consider the EIS as our EFH Assessment. 
ES-8 

Threatened and Endangered Species 

Sixteen federally listed threatened, endangered, or candidate species may occur in parishes 

affected by the projects. Within these parishes, critical habitat has been designated for one species, the 

piping plover. We determined that the projects would have no effect on four federally listed species, are 

not likely to destroy or adversely modify designated critical habitat, and would not contribute to the trend 

toward federal listing for one candidate species. 

Potentially suitable habitat for the remaining 11 federally listed species is not present within areas 

affected by construction or operation of the LNG terminal or KMLP facilities; however, potentially 

suitable habitat is present along the portion of the LNG vessel transit route in Cameron Parish and the 

Gulf of Mexico. Although rare, five species of sea turtles, five species of whales, and the West Indian 

manatee could occur along the LNG vessel transit route. Based on the species’ characteristics and habitat 

requirements, and because Magnolia would provide LNG ship captains with the National Marine 

Fisheries Service-issued Vessel Strike Avoidance Measures and Reporting for Mariners, we have 

determined that the Magnolia LNG Project may affect, but is not likely to adversely affect these federally 

listed species. 

As required by Section 7 of the Endangered Species Act, we request that the National Marine 

Fisheries Service accept the information provided in this EIS as the Biological Assessment for the 

projects. Further, we request concurrence with our findings of effect for federally listed species. The 

projects would have no effect on listed species under the jurisdiction of the U.S. Fish and Wildlife 

Service; therefore, preparation of a Biological Assessment and consultation between the FERC and 

U.S. Fish and Wildlife Service is not required by Section 7 of the Endangered Species Act. 

Recreation 

One designated recreational area, Calcasieu Point Landing, is within 1 mile of the proposed 

facilities. Calcasieu Point Landing is approximately 525 feet west of the LNG terminal site at the western 

end of Henry Pugh Boulevard. Recreational boating and fishing activities occurring within the Industrial 

Canal and near the Calcasieu Point Landing could be affected by construction and operation of the LNG 

terminal due to increased noise, delayed access to the landing, restrictions on fishing in the immediate 

vicinity of the LNG terminal, and vessel traffic. Increased noise associated with construction of the LNG 

terminal could deter recreational users from fishing in the immediate vicinity of project activities. In 

particular, dredging and pile driving activities, which would occur up to 7 days per week and 6 days per 

week, respectively, during the first 20 months of construction, could result in avoidance of the area by 

recreational users. As a result, we have determined that construction of the LNG terminal would result in 

temporary and moderate impacts on recreational use of Calcasieu Point Landing. During operation of the 

LNG terminal, delays to recreational users could occur due to the moving security zone around LNG 

vessels during transit to and from the LNG terminal; an impact that we expect would be intermittent and 

minor. 

Visual Resources 

The viewshed of the proposed LNG terminal includes a portion of the Creole Nature Trail Scenic 

Byway (Highway 27), which is approximately 2 miles west of the LNG terminal across the Calcasieu 

Ship Channel and as close as 0.3 mile west of the LNG vessel transit route along the Calcasieu Ship 

Channel; however, no other federally, state, or locally designated visual resources have been identified in 

the viewshed. Although not a designated visual resource, due to its proximity to the LNG terminal and 

lack of visual buffers, the LNG terminal would be prominent when viewed from Calcasieu Point Landing 

both during daytime hours and in the evening when the facilities would be illuminated in accordance with 
ES-9 

federal safety regulations. Activities associated with construction of the LNG terminal may be visible 

from residences to the south and southeast of the LNG terminal along Airhart and Joe Ledoux Roads. 

The primary existing structures in the viewshed of the LNG terminal include the Trunkline LNG 

Terminal, Lake Charles Carbon Company, and other industrial properties adjacent to the Industrial Canal. 

The viewshed also includes the Industrial Canal to the north and west, the Intracoastal Waterway and 

Calcasieu Ship Channel to the south, and forest and wetlands to the northwest and south of the site. 

Because the site is slightly higher in elevation than the surrounding area due to the previous placement of 

dredge spoil at the site, and the topography of the surrounding area is fairly level, visibility would extend 

outward from the site except where buffered by vegetation or existing structures. 

Permanent changes to the visual character of the area would result from operation of the LNG 

terminal due to the presence of aboveground structures that would modify the viewshed. The most 

prominent visual features at the terminal would be two LNG storage tanks and the flare stack. Magnolia 

anticipates that flaring would occur for approximately 5 days during startup of the LNG terminal. During 

operation of the terminal, use of the marine and emergency flares would only occur during process upset 

conditions. The new facilities would also require lighting for operations, safety, and to comply with 

Federal Aviation Administration requirements. To minimize visual impacts, lighting at the LNG terminal 

would be shielded and downcast to avoid interference with navigation; in addition, facilities within the 

LNG terminal site would be partially obscured by the proposed vapor barrier. To further minimize visual 

impacts, we are recommending that, prior to construction, Magnolia file its final Facility Lighting Plan

for operation of the LNG terminal. Facilities associated with the LNG terminal would be consistent with 

the viewshed presented by other industrial features along this portion of the Industrial Canal. Therefore, 

we have determined that the LNG terminal would have a permanent and moderate impact on visual 

resources when viewed from the Calcasieu Point Landing and a permanent, but minor impact on visual 

resources when viewed from other vantage points. 

Socioeconomics 

Construction of the projects would have a minor to moderate impact on local populations, 

employment, housing, provision of community services, and 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 projects. No residences or businesses would be 

displaced as a result of construction or operation of the LNG terminal or KMLP facilities. Construction 

and operation of the projects 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. 

During construction of the LNG terminal, traffic levels on area roadways would increase due to 

the presence of worker vehicles, construction vehicles, and trucks delivering concrete to the site. Due to 

its location immediately adjacent to the LNG terminal site, most materials would be delivered to the 

Dynamic Industries, Inc. construction yard via the Industrial Canal. Therefore, except for trucks 

delivering concrete to the site, minimal construction truck traffic is anticipated. Impacts on local users of 

the roadway network due to construction of the LNG terminal include potential delays due to increased 

traffic levels and diminished roadway capacity. With the implementation of the planned improvements at 

the intersections of Tank Farm and Big Lake Roads, Big Lake and Lincoln Roads, and Lincoln Road and 

Gulf Highway, we have determined that impacts from construction of the LNG terminal would have 

temporary and minor impacts on local users of the roadway network. Construction of the KMLP facilities 

would have minimal impact on traffic or roadways. Operation of the projects would not result in any 

significant impacts on traffic or roadways. 
ES-10 

Air Quality and Noise 

Air quality impacts due to construction of the projects would generally be temporary and 

localized, and are not expected to cause or contribute to a violation of applicable air quality standards. 

The LNG terminal and KMLP facilities would be located in areas currently classified as being in 

attainment for all criteria pollutant standards; however, because the area is vulnerable to being designated 

as non-attainment in the next few years, we are recommending that, prior to the end of the draft EIS 

comment period, Magnolia and KMLP file a Fugitive Dust Control Plan as well as further details 

regarding commitments to reduce pollutants from mobile and stationary construction equipment. 

During operation, the LNG terminal would be a Prevention of Significant Deterioration major 

source for nitrogen oxides and carbon monoxide. In addition, it would be a Title V major source for 

inhalable particulate matter with an aerodynamic diameter less than or equal to 10 microns and less than 

or equal to 2.5 microns and would be considered a minor source of hazardous air pollutant emissions. 

KMLP’s proposed Compressor Station 760 would be a Title V major source for carbon monoxide and 

would be considered a minor source of all other criteria pollutants, as well as hazardous air pollutant 

emissions. Magnolia and KMLP would minimize operational impacts on air quality by adhering to 

applicable federal and state regulations as described in their air permit applications to the Louisiana 

Department of Environmental Quality. 

Based on the analyses conducted and mitigation measures proposed, we conclude that 

construction and operation of the projects would result in a moderate impact on air quality; however, 

given the mitigation measures proposed by Magnolia and KMLP, and air quality controls and monitoring 

requirements to be included in the Title V/Prevention of Significant Deterioration permits for the 

facilities, the projects would not result in a degradation of regional air quality. 

Construction activities at the LNG terminal would generate temporary increases in sound levels 

over a total of 45 months. Construction activities would occur predominantly during the day, Monday 

through Saturday. However, certain activities would occur up to 24 hours per day, 7 days per week. In 

particular, dredging may occur up to 24 hours per day, 6 days per week and pile driving could occur up to 

10 hours per day, 7 days per week. 

The most prevalent sound-generating equipment and activity during construction of the projects is 

anticipated to be pile driving at the LNG terminal, although internal combustion engines associated with 

general construction equipment would also produce sound levels that would, at times, be perceptible at 

the nearest noise sensitive areas. Magnolia anticipates that impact-type pile drivers would be used during 

construction of the proposed facilities, which may be installed using both land-based and floating 

platforms. Based on the noise estimates provided by Magnolia and because of the 16-month duration of 

the pile driving activities, we have determined that sound levels may have an adverse impact at the 

nearest noise sensitive areas. Therefore, we are recommending that Magnolia include in its Pile Driving 

Noise Impact Mitigation Plan measures to reduce pile driving noise to no greater than 10 decibels on the 

A-weighted scale over ambient levels at the nearest noise sensitive areas (an increase of 10 decibels is 

perceived by the human ear as though the sound intensity has doubled). 

Operation of the LNG terminal and Compressor Station 760 would produce noise on a continuous 

basis throughout the lifetime of the facilities. Modeling results indicate that, with the incorporation of 

proposed noise mitigation measures, the noise from operation of the LNG terminal and Compressor 

Station 760 would not exceed the threshold of 55 decibels on the A-weighted scale (the noise threshold 

established to protect the public from activity interference and annoyance outdoors in residential areas) at 

any of the noise sensitive areas. We are recommending that Magnolia and KMLP conduct post-
ES-11 

construction noise surveys for the LNG terminal and Compressor Station 760 to ensure noise impacts 

resulting from the projects would not be significant. 

Based on the analyses conducted, mitigation measures proposed, and with our additional 

recommendations, we conclude that the projects would not result in significant air or noise impacts on 

residents and the surrounding communities during construction and operation. 

Safety and Reliability 

We evaluated the safety of the proposed LNG terminal, 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 Front End Engineering Design presented by Magnolia 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. 

We also analyzed whether the LNG terminal would be sited in accordance with federal 

regulations. Magnolia would be regulated by the FERC, DOT, Coast Guard, EPA, and Occupational 

Safety and Health Administration (OSHA). As a cooperating agency, the DOT assisted FERC staff in 

evaluating whether Magnolia’s proposed design would meet the DOT siting requirements. In a 

September 17, 2014 letter to FERC staff, the DOT stated that it had no objection to Magnolia’s 

methodology for determining a single accidental leakage source to establish the siting for its proposed 

LNG terminal. In addition, we are recommending that, prior to the end of the draft EIS comment period, 

Magnolia file concurrence from the DOT regarding the design spill selections. On January 13, 2015, the 

DOT determined Magnolia’s proposal to comply with EPA’s Risk Management Program and OSHA’s 

Process Safety Management program would satisfy the siting requirements for the anhydrous ammonia 

refrigerant system. Magnolia has submitted a preliminary Risk Management Program as part of its 

application to satisfy these regulations. Magnolia would comply with the comprehensive EPA’s Risk 

Management Program and OSHA Process Safety Management programs as well as DOT’s requirements 

under Title 49 Code of Federal Regulations Part 193 (49 CFR 193) and National Fire Protection 

Association Standard 59A. By complying with EPA’s Risk Management Program and OSHA Process 

Safety Management, Magnolia would comply with the same regulations as every other facility in the 

United States that uses the proposed quantities of ammonia. As a result, we conclude that potential 

hazards from the siting of the facility at this location would not have a significant impact on public safety. 

In accordance with 33 CFR 127, the Coast Guard has reviewed the proposed LNG terminal. The 

Coast Guard issued its Letter of Recommendation on February 12, 2015. The Letter of Recommendation 

stated that the Calcasieu Ship Channel is considered suitable for LNG marine traffic in accordance with 

the guidance in the Coast Guard’s Navigation and Vessel Inspection Circular 01-2011. The Waterway 

Suitability Assessment review focused on the navigation safety and maritime security aspects of LNG 

vessel transits along the affected waterway. Based on the results of the assessment of potential risks to 

navigation safety and maritime security associated with the proposed facility, the Coast Guard has 

determined that the Calcasieu Ship Channel would be suitable for accommodating the type and frequency of 

LNG marine traffic associated with this project. 

KMLP would design, construct, operate, and maintain the proposed KMLP 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 KMLP facilities would incrementally increase 
ES-12 

the risk of a pipeline accident; however, KMLP’s compliance with the DOT’s safety standards would 

ensure that KMLP’s construction and operation of the facilities would not have a significant impact on public 

safety. 

Based on our engineering design analysis and recommendations; the DOT siting requirements 

and recommendations; the Letter of Recommendation issued by the Coast Guard concluding the LNG 

vessel transit is suitable for LNG marine traffic; and the regulatory requirements for the design, 

construction, and operation of the pipeline and terminal; we conclude that the projects would not result in 

significantly increased public safety risks. 

Cumulative Impacts 

Our analysis of cumulative impacts includes other projects in the vicinity of the proposed 

Magnolia LNG and Lake Charles Expansion Projects that could affect the same resources in the same 

approximate time frame. We conclude that the proposed projects’ contribution to cumulative impacts on 

resources affected by other projects occurring in the vicinity during the same time frame would not be 

significant. The proposed projects’ contribution to cumulative impacts would be greatest on housing, 

public services, and transportation, which are discussed below. 

The influx of non-local workers would affect the availability of housing in Southwest Louisiana, 

which may result in increased rental rates and housing shortages for lodging if all of the proposed and 

planned projects are implemented according to the expected timeframes. This would benefit the local 

housing market, but could adversely affect those seeking housing. Some members of the workforce may 

be forced to commute longer distances to obtain housing in adjacent parishes or Texas. To accommodate 

the anticipated influx of construction workers, two worker housing developments are expected to be 

available for up to 6,500 workers. In addition to worker housing developments, a number of residential 

housing developments are planned or under construction in the Lake Charles area. New housing units, 

which include single-family dwellings, multi-family dwellings, hotels, and various residential projects, 

could total 8,070 units if all publicly announced projects are permitted and constructed according to 

current plans. Therefore, we conclude that cumulative impacts on housing would be moderate. 

Concurrent construction of the proposed projects and other projects in the area would result in 

increased workers in the area, which could increase the need for some public services. The need for these 

services would generally be spread throughout the parishes that house the workforce (Acadia, Calcasieu, 

Cameron, Evangeline, and Jefferson Davis Parishes), but there may be an increased need for medical and 

emergency services in Cameron and Calcasieu Parishes where the proposed project facilities and 

construction workers are expected to be concentrated. Magnolia would provide its own on-site security 

and the Calcasieu Parish Sheriff’s Office indicated that it believes it has sufficient resources available to 

provide protection services by adjusting patrol schedules or hiring additional staff with revenues allocated 

by Calcasieu Parish. In addition, Magnolia is currently in discussions with the Lake Charles Fire 

Department to identify measures for providing fire protection at the LNG terminal site. Options include 

funding fire-fighting services either independently or by entering into a mutual aid agreement with future 

industrial neighbors for the purpose of employing an industrial firefighting team trained in fighting fires 

at industrial facilities. With the increase in local taxes and government revenue associated with the 

proposed projects, the overall cumulative impact on public services would be expected to be minor. 

Construction of the proposed projects concurrent with construction and operation of the other 

projects in the area would also increase both roadway and marine traffic, which could result in delays for 

other users of local roadways and ship transit route, respectively. Between early 2016 and the end of 

2017, construction of three facilities adjacent to and within the Industrial Canal would occur, including 
ES-13 

the proposed LNG terminal, Lake Charles Liquefaction Project, and G2X Energy Lake Charles gasoline 

facility. Magnolia, the Lake Charles LNG companies, and G2X Energy commissioned a Traffic Impact 

Study to assess potential impacts of vehicular traffic associated with both construction and operation of 

the three projects, and to develop measures to mitigate impacts on local users of area roadways. The 

Traffic Impact Study found that the existing roadway network does not have sufficient capacity to 

accommodate the expected peak hour traffic volumes associated with construction of the three facilities. 

To minimize impacts on local users of the roadways, the study recommended the use of off-site and 

temporary parking for construction workers as well as roadway improvements at several driveways and 

intersections near the Industrial Canal. Magnolia, the Lake Charles LNG companies, and G2X Energy 

have agreed to the recommended measures within the Traffic Impact Study. Therefore, we conclude that 

cumulative impacts on roadway traffic would be moderate. 

Traffic within the Calcasieu Ship Channel is expected to markedly increase over the next 

10 years. In 2018, traffic within the channel is expected to be 1,668 vessels per year; in 2023, traffic 

within the channel is expected to be 2,183 vessels per year, more than twice the 2013 level. During 

operation, approximately 208 LNG vessels would call on the LNG terminal per year. Due to the 

anticipated cumulative increase in vessel traffic, the Port of Lake Charles commissioned a simulation to 

investigate the impact of increased traffic on the operations of the channel and to assess the need for 

changes to channel infrastructure and regulations. Results of the study indicate that the median wait time 

is expected to increase by 2.3 hours per vessel, and notes that LNG carriers would experience the highest 

increase in median wait time (8.9 hours). The wait times are expected to vary seasonally, and would be 

higher during the winter months and lower during the summer months. Based on the Coast Guard’s 

Letter of Recommendation for the Magnolia LNG Project and the expected increase in the median wait 

time by 2.3 hours per vessel, we have determined that operation of the LNG terminal would have a 

permanent and moderate increase in marine traffic within the Industrial Canal and Calcasieu Ship 

Channel. 

ALTERNATIVES CONSIDERED 

As alternatives to the proposed action, we evaluated the No-Action Alternative, system 

alternatives for the proposed LNG terminal and KMLP’s pipeline system, alternatives sites for the 

proposed aboveground facilities, alternative liquefaction processes, and alternative power sources for the 

LNG terminal and Compressor Station 760. While the No-Action Alternative would eliminate the shortand long-term environmental impacts identified in the EIS, the stated objectives of the proposed action 

would not be met. 

System alternatives evaluated for the LNG terminal included 7 operating LNG import terminals 

with approved, proposed, or planned expansions to provide liquefaction capabilities and 19 approved, 

proposed, or planned stand-alone liquefaction projects. All of these were eliminated from further 

consideration as viable alternatives for reasons that include insufficient capacity to meet Magnolia’s 

customer commitments without constructing facilities beyond those currently approved, planned, or 

proposed; incompatible timeframes with in-service dates that would not meet Magnolia’s customer 

commitments; and environmental impacts that were considered comparable to or greater than those of the 

proposed LNG terminal. We evaluated three system alternatives to KMLP’s pipeline system. All three 

systems were eliminated from further consideration because they would require construction of additional 

pipeline looping or greenfield construction to provide the 1.4 billion cubic feet per day of natural gas 

required by the Magnolia LNG Project (the Magnolia LNG Project would have the capacity to export an 

LNG volume equivalent up to 1.08 billion cubic feet per day). 
ES-14 

We evaluated the proposed site and four alternatives sites for the LNG terminal. We concluded 

that the proposed site represents an acceptable site for the proposed LNG terminal because it is currently 

zoned for heavy industrial use, sufficiently sized to allow optimal facility layout design, and avoids the 

need for off-site LNG piping. It is also geographically well separated from area residences, and contains 

the lowest acreage of wetlands of the alternatives considered. We did not identify any alternative 

configurations for the LNG terminal that would meet the design and configuration requirements of the 

DOT’s regulations and other industry or engineering standards while avoiding or reducing the impacts 

associated with the proposed LNG terminal configuration. We also evaluated the proposed site and two 

alternative sites for Compressor Station 760. We concluded that the proposed site represents an 

acceptable site for a compressor station and find no environmental reason to recommend one of the 

alternate sites over the proposed site. We did not identify any environmental concerns that indicate a 

need to identify and evaluate alternative sites for the meter station modifications or header pipeline routes. 

These facilities would occur within and adjacent to existing facilities, which minimize the footprint and 

associated environmental impacts. 

We evaluated the proposed site and three alternative sites for dredge material placement. We 

concluded that both the proposed site and one potential alternative, the Turner Bay site, represent 

acceptable sites for dredge material placement. 

We evaluated a total of eight liquefaction technologies, which are currently available, including 

the proposed liquefaction process. The proposed OSMR® Process is based on the single mixed refrigerant 

process, but uses aero-derivative gas turbines, combined heat and power technology, and ammonia 

auxiliary refrigeration to increase efficiency and reduce air emissions by approximately 30 percent. The 

use of anhydrous ammonia includes safety hazards due to its toxicity and farther dispersion distances to 

irreversible effects. However, the hazards associated with anhydrous ammonia are well understood, can 

be mitigated to safe levels with additional mitigation measures, and would be subject to the regulation of 

a number of federal agencies. Therefore, while there would be viable liquefaction processes that provide 

inherently safer alternatives, there would not be a significant environmental or safety advantage in the 

selection of those liquefaction processes when considering the additional mitigation measures Magnolia 

would implement during operation of the terminal. 

We evaluated and ruled out the use of electrically driven motors as an alternative to gas-fired 

turbines at the proposed LNG terminal 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. 

We performed an alternative review of four power sources for compression at Compressor 

Station 760, including gas-fired turbine driven (proposed), reciprocating gas-driven, electric motordriven, and waste heat electric generation. The analysis concluded that the proposed power source for 

Compressor Station 760 is acceptable. The use of reciprocating gas-driven compressor units would result 

in a larger number of units being required to provide the same amount of power as the proposed gas-fired, 

turbine-driven compressor units, which would result in both higher costs and a larger facility footprint. 

The use of electric-motor driven compressors would require an electric load of a magnitude serviceable 

only by a high-voltage transmission system, which would require construction of two new 138-kilovolt 

cross-country transmission lines and a new electrical substation at the compressor station. KMLP has 

stated that Compressor Station 760 would likely not operate when the LNG terminal is not producing 

LNG, which could greatly reduce the economic feasibility of using waste heat electric generation. 
ES-15 

CONCLUSIONS 

We determined that construction and operation of the proposed projects would result in adverse 

environmental impacts, but impacts would be reduced to less-than-significant levels with the 

implementation of the applicants’ proposed and our recommended mitigation measures. This 

determination is based on a review of the information provided by Magnolia and KMLP 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. 

Although many factors were considered in this determination, the principal reasons are: 

 Over 99 percent of the area permanently affected by the LNG terminal is within areas 

that have been previously disturbed by commercial or industrial activities. 

 The KMLP facilities would occur within and adjacent to existing facilities, which would 

minimize new disturbance. 

 Magnolia would mitigate impacts on jurisdictional wetlands associated with the 

construction and operation of the proposed LNG terminal in accordance with Magnolia’s 

project-specific Compensatory Mitigation Plan. 

 The FERC staff would complete the process of complying with Section 7 of the 

Endangered Species Act prior to construction. 

 The FERC staff has completed consultation under Section 106 of the National Historic 

Preservation Act and implementing regulations at 36 CFR 800 and determined that no 

historic properties would be affected by the projects. 

 Magnolia and KMLP would comply with all applicable air and noise regulatory 

requirements during construction and operation of the projects. 

 Magnolia and KMLP would minimize impacts on environmental resources during 

construction and operation of the projects by implementing, as applicable, their spill 

prevention plans; Magnolia’s Compensatory Mitigation Plan; Unanticipated Discovery 

Plans (for cultural resources); and by implementing either the FERC’s Plan and 

Procedures (KMLP) or the project-specific Plan and Procedures (Magnolia). 

 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 30 mitigation measures that Magnolia and KMLP should implement to 

further reduce the environmental impacts that would otherwise result from construction and operation of 

the projects; 75 measures the Magnolia should implement that are specific to engineering, vulnerability, 

or detailed design of the LNG terminal; and 4 measures relating to inspections, reporting, and 

notifications, and non-scheduled events that would apply throughout the life of the LNG terminal. We 

determined that these measures are necessary to reduce adverse impacts associated with the projects 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 draft EIS. 

1-1

1.0 INTRODUCTION

On April 30, 2014, Magnolia LNG, LLC (Magnolia) filed an application with the Federal Energy 

Regulatory Commission (Commission or FERC) for authorization pursuant to section 3(a) of the Natural

Gas Act (NGA) and part 153 of the Commission’s regulations. In Docket No. CP14-347-000, Magnolia 

requests authorization to site, construct, and operate facilities necessary to liquefy natural gas at a 

proposed site in Lake Charles, Calcasieu Parish, Louisiana.

On June 30, 2014, Kinder Morgan Louisiana Pipeline LLC (KMLP) filed an application with the 

FERC for a Certificate of Public Convenience and Necessity (Certificate) pursuant to section 7(c) of the 

NGA and part 157 of the Commission’s regulations. In Docket No. CP14-511-000, KMLP requests 

authorization to construct and operate system modifications that would allow the delivery of natural gas 

to Magnolia’s proposed liquefied natural gas (LNG) terminal using a new north-to-south path on KMLP’s 

existing system. The proposed system modifications would be located within Acadia, Evangeline, and 

Calcasieu Parishes, Louisiana. 

As part of the Commission’s consideration of these applications, we1 prepared this draft 

environmental impact statement (EIS) to assess the potential environmental impacts resulting from 

construction and operation of the facilities proposed by Magnolia and KMLP as connected actions in 

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

Magnolia’s proposal, referred to in this EIS as the Magnolia LNG Project, would be located on 

approximately 114 acres of a 115-acre parcel of land on the south shore of the Industrial Canal that is 

about 9 miles southwest of the city of Lake Charles, Louisiana. The Magnolia LNG Project, which is 

currently expected to begin operation at the end of 2018, would produce a nominal capacity of 

approximately 8.0 million (metric) tonnes per annum (MTPA) of LNG during the 30-year life of the 

project. The LNG terminal would receive natural gas via KMLP’s existing interstate pipeline, which

traverses the proposed terminal site. The natural gas would be liquefied using four liquefaction trains that 

each have a nominal capacity of 2.0 MTPA (total nominal capacity of approximately 8.0 MTPA), and 

stored onsite in two full containment LNG storage tanks with a capacity of approximately 160,000 cubic 

meters (m3). The LNG would be loaded onto LNG carriers for export overseas; LNG carriers and LNG 

barges for domestic marine distribution and the possibility of LNG bunkering;2and LNG trucks for road 

distribution to LNG refueling stations in Louisiana and the surrounding states. During operation of the 

project, Magnolia anticipates that an average of 208 marine vessels would make port calls at the LNG 

terminal each year, including 104 LNG carriers and 104 LNG barges, and 52 LNG trucks would be 

loaded at the LNG terminal each year. Figure 1-1 provides the general location of the Magnolia LNG 

Project. More detailed information regarding specific facility components is provided in section 2.1.1.

 

1

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

2 Bunkering is the transfer of LNG from a supply station (e.g., LNG barge) to a receiving ship for the sole purpose of use as propulsion fuel 

(U.S. Department of Transportation, Maritime Administration, 2014).
1-2

Figure 1-1 Magnolia LNG Project Location Map

KMLP operates a 133-mile-long natural gas pipeline system that originates at the Cheniere 

Sabine Pass LNG terminal in Cameron Parish, Louisiana and was designed to transport natural gas to 

various delivery points in Cameron, Calcasieu, Jefferson Davis, Acadia, and Evangeline Parishes. The 

KMLP pipeline was constructed to provide its two anchor shippers, Total Gas & Power North America 

and Chevron U.S.A. Inc., the means to import LNG into the United States using a south-to-north 

transportation path. KMLP’s proposal, referred to in this EIS as the Lake Charles Expansion Project, 

would provide the Magnolia LNG Project with up to approximately 1,400,000 dekatherms per day of firm 

capacity on its system through a new north-to-south transportation path. In order to provide service to the 

Magnolia LNG Project prior to operation of the LNG terminal, the Lake Charles Expansion Project would 

begin operation in January 2018.

The Lake Charles Expansion Project includes the following:

 construction and operation of a new interconnect pipeline and meter station within 

Magnolia’s LNG terminal site in Calcasieu Parish;

 a new compressor station in Acadia Parish;

 new low and high pressure natural gas header pipelines that would be located adjacent to 

the existing KMLP easement in Acadia Parish; and

 modifications at six existing meter stations in Acadia and Evangeline Parishes; of these, 

five would be modified to allow the bi-directional flow of natural gas and three would be 

connected to the new header pipelines (two meter stations would be both modified to 

allow the bi-directional flow of natural gas and interconnected to the new header 

pipelines). 
1-3

Figure 1-2 provides an overview of the Lake Charles Expansion Project. More detailed 

information regarding specific components of this project is provided in sections 2.1.1.1 and 2.1.3. 

Figure 1-2 Lake Charles Expansion Project Overview Map

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.

Under section 7 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.

1.1 PURPOSE AND NEED

The purpose of the Magnolia LNG Project is to construct a terminal to serve the domestic and 

export markets for LNG. The purpose of the Lake Charles Expansion Project is to provide domestic feed 

gas to the Magnolia LNG Project. Magnolia and KMLP identify the following benefits of the combined 

projects:

 provide an outlet for domestic natural gas available in the marketplace;
1-4

 support export of LNG;

 support domestic waterway transportation of LNG for use as vessel fuel in shipping and 

the offshore oil and gas industry; and

 support domestic highway distribution of LNG in trucks to serve the emerging business 

of providing LNG as fuel for long-haul trucking and other emerging domestic uses of 

LNG.

To determine the level of interest for the project, KMLP conducted an open season from 

February 14 through March 7, 2014. KMLP received one conforming bid from Magnolia for the entire 

proposed capacity of the project, which resulted in the two companies entering into a binding Precedent 

Agreement. On January 28, 2015, Magnolia announced that it had executed a Gas Pipeline Interconnect 

Agreement with KMLP that sets out the technical scope and specifications for gas supply to the LNG 

terminal. 

Magnolia entered into tolling agreements with four companies for the Magnolia LNG Project. 

Under these agreements, Magnolia would not take ownership of the natural gas feedstock after receiving 

it from KMLP, but would only provide services for natural gas pre-treatment, vaporization, LNG storage, 

and marine services, including loading of LNG carriers and barges. After loading, the LNG would enter 

into the owner’s custody (one of the four companies Magnolia has entered into tolling agreements with).

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 facilities 

proposed by Magnolia and KMLP within the LNG terminal, and KMLP’s proposed modifications to its 

existing pipeline system outside of the LNG terminal, collectively referred to as the KMLP facilities) and,

to a lesser extent, the non-jurisdictional facilities that are integrally related to the development of the 

projects (i.e., potable water line, electric transmission lines, electric switching station, and LNG trucking 

and LNG bunkering activities beyond the boundaries of the proposed LNG terminal [see detailed 

discussion in section 1.4.1]).

This EIS describes the affected environment as it currently exists, discusses the potential 

environmental consequences of the proposed projects, and compares the projects’ potential impact to that 

of alternatives. The topics addressed in this EIS include alternatives; 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; 
1-5

air quality; noise; reliability and safety; and cumulative impacts. 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), U.S. Department of Energy (DOE), U.S. 

Department of Transportation (DOT), and U.S. Environmental Protection Agency (EPA) as “cooperating 

agencies” under NEPA. Cooperating agencies have jurisdiction by law or provide special expertise with 

respect to environmental impacts involved with a proposal. The roles of the FERC, COE, Coast Guard, 

DOE, DOT, and EPA as cooperating agencies in the review and authorization 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 projects. Federal, state, and local permits, approvals, and 

consultations for the proposed projects 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, Parts 1500–1508 [40 CFR 1500–1508]),

and FERC regulations implementing NEPA (18 CFR 380). 

As the lead federal agency for the projects, 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); and Section 106 of the National Historic Preservation Act (NHPA). Each of 

these statutes has been taken into account in the preparation of this EIS. The FERC will use this 

document to consider the environmental impacts that could result if it issues an authorization to Magnolia 

under section 3(a) of the NGA and a Certificate to KMLP 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, 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 

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

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

projects and must comply with the requirements of NEPA before issuing permits under the above statutes, 

it has elected to participate as a cooperating agency in the preparation of this EIS. The COE would adopt 

the EIS 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 projects occur within the New Orleans 

District of the COE Mississippi Valley Division. Staff from the New Orleans District participated in the 

NEPA review and will evaluate COE authorizations, as applicable. 
1-6

The primary decisions to be addressed by the COE include:

 issuance of section 404 permits for wetland impacts associated with construction and 

operation of the projects, and 

 issuance of a section 10 permit for construction activities within navigable waters of the 

United States associated with the Magnolia LNG Project.

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

the coordination of this document, the COE will obtain the views of the public and natural resource 

agencies prior to reaching its decisions on the projects.

As an element of its review, the COE must consider whether a proposed action 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 decision on each of the proposed actions, including section 404(b)(1) analysis 

and required environmental mitigation commitments.

1.2.3 U.S. Coast Guard

The Coast Guard is the federal agency responsible for assessing the suitability of the Project 

Waterway (defined as the waterways that begin at the outer boundary of the navigable waters of the 

United States) for LNG marine traffic. The Coast Guard exercises regulatory authority over LNG 

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

10173; the Magnuson Act (50 USC 191); the Ports and Waterways Safety Act of 1972, as amended 

(33 USC 1221 et seq.); and the Maritime Transportation Security Act of 2002 (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 located in or adjacent to navigable waters up 

to the last valve immediately before the receiving LNG tanks. As appropriate, the Coast Guard (acting 

under the authority in 33 USC 1221 et seq.) also would inform the FERC of design- and constructionrelated issues identified as part of safety and security assessments. If the Magnolia LNG Project is

approved, constructed, and operated, the Coast Guard would continue to exercise regulatory oversight of 

the safety and security of the LNG terminal facilities, in compliance with 33 CFR 127. 

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 

submits a Letter of Intent (LOI) to the local Captain of the Port. In a letter dated March 12, 2013, 

Magnolia submitted its LOI and preliminary WSA to the Coast Guard as required by 33 CFR 127.007. 

The Coast Guard requested additional information, and a follow-on WSA was submitted 

December 12, 2013. In a letter dated February 12, 2015, the Coast Guard issued the LOR for the project,

3

which stated that the Calcasieu Ship Channel is considered suitable for LNG marine traffic in accordance 

with the guidance in Coast Guard Navigation and Vessel Inspection Circular (NVIC) 01-2011.

 

3 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
1-7

1.2.4 U.S. Department of Energy

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

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

not consistent with the public interest. On December 18, 2012 and October 15, 2013, Magnolia filed 

applications with the DOE (Fossil Energy Docket Nos. 12-183-LNG and 13-131-LNG, respectively) 

seeking authorization to export LNG to any nation with which the United States currently has, or in the 

future will have, a Free Trade Agreement (FTA) requiring national treatment for trade in natural gas

(FTA countries), and which has or in the future develops the capacity to import LNG via ocean-going 

carrier. Each application requested authorization to export the equivalent of 0.54 billion cubic feet per 

day (Bcf/d) of domestically produced natural gas (equivalent to 4 MTPA of LNG) for a 25-year period,4

commencing the earlier of the date of first export or 10 years from the date of issuance of the requested 

authorization. 

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 FTA countries be deemed consistent with the public interest and 

granted without modification or delay. On February 27, 2013 (Fossil Energy Docket No. 12-183-LNG)

and March 5, 2014 (Fossil Energy Docket No. 13-131-LNG), the DOE issued orders granting 

authorization to Magnolia to export LNG by vessel from the LNG terminal to FTA countries. 

On October 15, 2013, the DOE received an application from Magnolia (Fossil Energy Docket No. 

13-132-LNG) seeking authorization to export 1.08 Bcf/d of natural gas (equivalent to 8 MTPA of LNG) 

to any country with which the United States does not have a free trade agreement requiring national 

treatment for trade in natural gas and LNG (non-FTA countries). The DOE is currently conducting its 

review of Magnolia's application to export LNG to non-FTA countries. On August 15, 2014, the DOE’s 

Office of Fossil Energy announced that it will act on applications to export LNG from the lower-48 states 

to non-FTA countries only after the review required by the NEPA has been completed. 

1.2.5 U.S. Department of Transportation

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

with 49 USC 60101. Those standards are codified in 49 CFR 193 and apply to the siting, design, 

construction, operation, maintenance, and security of LNG facilities. The National Fire Protection 

Association (NFPA) Standard 59A, Standard for the Production, Storage, and Handling of Liquefied 

Natural Gas, is incorporated into these requirements by reference, with regulatory preemption in the 

event of conflict. In accordance with the 1985 Memorandum of Understanding on LNG facilities and the 

2004 Interagency Agreement on the safety and security review of waterfront import/export LNG 

facilities,5the DOT participates as a cooperating agency and assists in assessing any mitigation measures 

that may become conditions of approval for any project.

1.2.6 U.S. Environmental Protection Agency

The EPA is the federal agency responsible for protecting human health and safeguarding the 

natural environment. It sets and enforces national standards under a variety of environmental laws and 

 

4 The proposed life of the Magnolia LNG Project is 30 years (see section 1.0). Magnolia requested authorization from the DOE to export 

domestically produced natural gas for a 25-year period. Therefore, if market conditions indicate that the export of natural gas from the 

LNG terminal is warranted beyond a 25-year period, Magnolia would be required to seek additional authorization from the DOE.

5 These documents can be viewed online at http://ferc.gov/industries/gas/indus-act/lng/1985-mou/1985-mou.pdf and http://www.ferc.gov/

industries/gas/indus-act/lng/2004-interagency.asp, respectively.
1-8

regulations in consultation with state, tribal, and local governments. The EPA has delegated water quality 

certification (section 401 of the CWA) to the jurisdiction of individual state agencies; within Louisiana, 

jurisdictional authority under section 401 of the CWA has been delegated to the Louisiana Department of 

Environmental Quality (LDEQ). The EPA also oversees the issuance of a National Pollutant Discharge 

Elimination System (NPDES) permit by the LDEQ for point-source discharge of used water into 

waterbodies (section 402 of the CWA). The EPA shares responsibility for administering and enforcing 

section 404 of the CWA with the COE, and has authority to veto COE permit decisions.

The EPA has jurisdictional authority to control air pollution under the Clean Air Act (CAA) 

(42 USC 85) by developing and enforcing rules and regulations for all entities that emit pollutants into the 

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

source categories, and has established general conformity applicability thresholds. The EPA has 

delegated the following jurisdictional authority under the CAA to the LDEQ, unless the source would be 

located in Indian lands:

 Title 1 Part A Section 111 – New Source Performance Standards (NSPS); 

 Title 1 Part A Section 112 – National Emission Standards for Hazardous Air Pollutants 

(NESHAP);

 Title 1 Part C – Prevention of Significant Deterioration (PSD); and 

 Title V – operating permits.

Title 1 Part A Section 112(r) of the CAA Amendments require the EPA to develop regulations 

and guidance for chemical accident prevention at facilities for substances that pose the greatest risk of 

harm from an accidental release. The regulation, which is referred to as the Risk Management Program 

(RMP), is codified in 40 CFR 68. This program has not been delegated to the LDEQ, and requires 

facilities to submit a RMP to the EPA prior to commencing operation; the RMP should subsequently be 

updated and resubmitted every 5 years. The information within the RMP is intended to assist fire, police, 

and emergency response personnel that are tasked with managing potential risks at the local level.

In addition to permitting oversight and management of air quality and emission limitations, the 

EPA is required under section 309 of the CAA to review and publicly comment on the environmental 

impacts of major federal actions including actions that are the subject of draft and final EISs, and is 

responsible for implementing certain procedural provisions of NEPA (e.g., publishing the Notices of 

Availability of the draft and final EISs in the Federal Register) to establish statutory timeframes for the 

environmental review process. 

1.3 PUBLIC REVIEW AND COMMENT

On March 12, 2013, Magnolia filed a request with the FERC to use our pre-filing review process. 

This request was approved on March 20, 2013, and pre-filing Docket No. PF13-9-000 was established in 

order to place information filed by Magnolia 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.

Magnolia held an open house in Lake Charles, Louisiana on May 2, 2013, to provide information 

to the public about the Magnolia LNG Project. FERC staff participated in the meeting, describing the 

FERC process and providing those attending with information on how to file comments with the FERC. 
1-9

Between May 1 and 3, 2013, we met with representatives of the COE, Coast Guard, LDEQ, 

Louisiana Department of Natural Resources (LDNR), Louisiana Department of Wildlife and Fisheries 

(LDWF), and Magnolia to discuss coordination of agency review, permit requirements and status, and 

each agency’s interest in participating in our environmental review as a cooperating agency. 

On June 18, 2013, the FERC issued a Notice of Intent to Prepare an Environmental Impact 

Statement for the Planned Magnolia Liquefied Natural Gas Project, Request for Comments on 

Environmental Issues, and Notice of Public Scoping Meeting (NOI for the Magnolia LNG Project). This 

notice was sent to about 540 interested parties including federal, state, and local officials; agency 

representatives; conservation organizations; Native American tribes; local libraries and newspapers; and 

property owners in the vicinity of planned project facilities. Publication of the NOI for the Magnolia 

LNG Project established a 30-day public comment period for the submission of comments, concerns, and 

issues related to the environmental aspects of the project. 

On July 11, 2013, the FERC conducted a public scoping meeting in Lake Charles to provide an 

opportunity for the public to learn more about the Magnolia LNG Project and to participate in our 

analysis by providing oral comments on environmental issues to be included in the EIS. Four individuals 

elected to present comments at the scoping meeting in support of the project. A transcript of these 

comments is part of the public record for the Magnolia LNG Project and is available for viewing on the 

FERC internet website (http://www.ferc.gov).6

We received comments from one federal agency, the EPA, in response to the NOI for the 

Magnolia LNG Project. The Commission also received written comments from elected officials, public 

officials, and non-governmental agencies.

On August 11, 2014, the FERC issued a Notice of Intent to Prepare an Environmental Impact 

Statement for the Proposed Lake Charles Expansion Project and Request for Comments on 

Environmental Issues (NOI for the Lake Charles Expansion Project). This notice was sent to about 

398 interested parties including federal, state, and local officials; agency representatives; conservation 

organizations; Native American tribes; local libraries and newspapers; and property owners in the vicinity 

of proposed project facilities. Publication of the NOI for the Lake Charles Expansion Project established 

a 30-day public comment period for the submission of comments, concerns, and issues related to the 

environmental aspects of the project. No open houses or scoping meetings were held for the Lake Charles 

Expansion Project due to the limited nature of the proposal.

Issues identified after the initial open house and during and after public scoping are summarized 

in table 1.3-1 along with a listing of the EIS sections that address the comments. The most frequently 

received comments relate to LNG safety; ship traffic; cumulative impacts on air, traffic, and threatened 

and endangered species; and dredged material placement. 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. Appendix A provides the distribution list for the draft EIS. 

 

6 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., PF13-9-000). Be sure to select an appropriate date range. 
1-10

TABLE 1.3-1

Key Environmental Concerns Identified During Scoping

Issue/Specific Comment

EIS Section

Addressing Comment

General

Purpose of and need for proposed projects; natural gas markets; local and national benefits 1.1

Alternatives

No-action alternative 3.1

Alternatives to LNG as a source of energy; energy conservation 3.2

System alternatives; expansion of existing LNG terminals or industrial facilities 3.2

Groundwater 

Impacts on groundwater, existing hydrology, and drinking water supply, including wellhead protection 

and public water supply areas

4.3.1

Water Resources

Impacts on water quality from dredging, construction of in-water facilities, and ship transits 4.3.2.2

Impacts on surface water quality from discharges and stormwater pollution 4.3.2.2

Impacts on aquatic environment from contaminated sediments during construction and operation 4.3.2.2

Socioeconomics

Impact on minority and low-income populations 4.9.7

Housing impacts on communities in the vicinity 4.9.4

Employment opportunities for local contractors and laborers, and increased tax revenues 4.9.2 and 4.9.3

Assessment of and impacts on community public safety resources 4.9.5

Air Quality and Noise

Consistency with the emissions limits and standards 4.11.1.3

Emissions from the LNG terminal, Compressor Station 760, and marine vessels and mitigation 

measures

4.11.1.5

Impacts on local and global air quality and noise from the construction and operation of the LNG 

terminal and Compressor Station 760

4.11.1.5

Potential noise impacts resulting from construction activities and proposed mitigation measures to 

reduce impacts from Compressor Station 760

4.11.2.2

Reliability and Safety

Navigation safety 4.12.7

Spills from hazardous materials maintained at the LNG terminal 4.12.5.2

Emergency response plans, evacuation plans, and coordination with community public safety services 4.12.6

Cumulative Impacts

Analysis of cumulative impacts associated with multiple large-capital construction projects scheduled in 

the region

4.13.3
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TABLE 1.3-2

Issues Identified and Comments Received That Are Outside the Scope of the EIS

Issue/Specific Comment Explanation

Environmental and economic consequences of any 

induced production, especially in shale gas plays, 

as a result of increased natural gas exports

Production and gathering activities, and the pipelines and facilities used for 

these activities, are not regulated by 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 projects

are discussed in section 4.7. Impacts beyond the general project area and not 

related to the projects 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 projects.

Effects of LNG combustion in end-use/importing 

markets

Review of the projects is limited to the economic and environmental impacts of 

the proposals 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 through the 

development of a programmatic EIS

The Commission does not intend to conduct a nation-wide analysis of 

proposed LNG export terminals. The DOE determines the public benefits of 

exporting LNG from terminals in the United States. The FERC’s review and 

approval of individual projects under the NGA does not constitute a 

coordinated federal program.

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 DOE-commissioned study into the potential U.S. economic 

impacts of natural gas exports in the form of LNG. The 2012 study, which was 

completed by National Economic Research Associates (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 projects is limited to the economic and environmental impacts of 

the proposals 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.

1.4 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 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 following non-jurisdictional actions were identified in association with the projects:

 LNG trucking, domestic marine distribution, and LNG bunkering activities that would 

take place after the LNG truck or LNG vessel has departed from the LNG terminal;

 construction of a tie-in to Calcasieu Parish District 12 Water Works’ potable water line 

within the LNG terminal site;
1-12

 construction of an electric transmission line and switching station to extend power from 

Entergy Gulf States Louisiana, LLC’s (Entergy) existing system to the LNG terminal; and

 construction of an electric transmission line to extend power from Cleco Corporation’s 

(Cleco) existing system to Compressor Station 760.

These facilities are described below and are also addressed in our cumulative impacts analysis in 

section 4.13 of this EIS.

1.4.1 LNG Trucking, Domestic Marine Distribution, and LNG Bunkering 

The proposed LNG truck and LNG barge loading facilities at the LNG terminal are both 

jurisdictional facilities. However, Magnolia’s proposed LNG trucking, domestic marine distribution of 

LNG, and LNG bunkering activities that would take place after the LNG truck or LNG vessel has 

departed from the LNG terminal do not fall under the jurisdiction of the FERC.

As a general rule, FERC jurisdiction over the transportation of natural gas in either gaseous or 

liquefied state in interstate commerce is limited to transportation by pipeline (i.e., FERC jurisdiction does 

not extend to deliveries of natural gas by truck, train, or barge).

7

 Further, jurisdiction over LNG 

import/export facilities and services under section 3 of the NGA would not follow the LNG trucks after 

they exit the boundary of the LNG terminal, as the LNG would at that point be moving in either interstate 

or intrastate commerce, rather than in foreign commerce. 

While Magnolia’s LNG trucking and LNG bunkering operations fall outside of the Commission’s 

jurisdiction once the truck or barge exits the terminal boundary, we address comments received on these 

project activities in our environmental analysis. Because these activities are not under the Commission’s 

jurisdiction, we cannot require Magnolia to implement measures to mitigate environmental impacts. 

Therefore, the mitigation measures presented in this EIS, relative to LNG trucking and LNG bunkering, 

are only those proposed by Magnolia.

1.4.1.1 LNG Trucking

During operation of the Magnolia LNG Project, a portion of the LNG produced at the terminal 

would be loaded onto trucks for road distribution to refueling stations in Louisiana and the surrounding 

states. While no agreements have been executed for the transportation of LNG in trucks, Magnolia 

anticipates that, on average, one 12,500-gallon capacity LNG truck would be loaded per week at the 

terminal. LNG trucks calling on the terminal are expected to deliver the LNG to one of the nine LNG 

refueling stations currently in operation in Louisiana and Texas, or to additional LNG refueling stations 

currently under development. 

In order to quantify potential risk to the public in the event of an unexpected shipping incident 

between the LNG terminal and the Interstate Highway System, Magnolia conducted a hazardous materials 

route analysis. The analysis assigned roadways along the potential LNG truck routes a risk category of 

Low, Medium, or High based on the number of households, schools, hospitals, churches, commercial 

parcels, and waterways, as well as the estimated population. The results of the analysis indicate that the 

lowest-risk route between the LNG terminal site and Interstate 10 travels from Henry Pugh Boulevard to 

Big Lake Road, Big Lake Road to Lincoln Road, Lincoln Road to Lake Street, Lake Street to Gauthier 

Road, Gauthier Road to Ward Line Road, and Ward Line road to Interstate 10 (see figure 1.4.1-1). 

Magnolia would request that motor carriers with hazardous materials (e.g., LNG) follow this route during 

transit from the LNG terminal to Interstate 10.

 

7 See Exemption of Certain Transport and/or Sales of Liquefied Natural Gas from the Requirements of section 7(c) of the NGA, 49 FPC 

1078, at 1079 (1973). 
1-13
1-14

LNG trucking associated with the Magnolia LNG Project would be operated in compliance with 

49 CFR 178.338 – Specification MC-338. Truck operators would be trained to satisfy the minimum 

requirements of 49 CFR 193 as well as the requirements of the Louisiana Department of Transportation 

and Development (DOTD) and the Calcasieu Parish Police Jury.

1.4.1.2 Domestic Marine Distribution and LNG Bunkering

Magnolia anticipates that LNG would be loaded onto one or two barges per week for domestic 

marine distribution and the possibility of LNG bunkering. As a result of the anticipated construction of 

new ships with LNG fuel systems, LNG barges loaded at the LNG terminal would be expected to make 

bulk deliveries to the ship fueling facilities and offshore support port areas in the region (ships and 

offshore supply vessels would not be directly fueled/bunkered at the LNG terminal site). Magnolia has 

indicated that major deep-draft port facilities along the central Gulf Coast that could be supplied by the 

Magnolia LNG Project include (see figure 1.4.1-2): 

 Port of Lake Charles, Louisiana

 Port of New Orleans, Louisiana

 Port of South Louisiana, Louisiana

 Port of Baton Rouge, Louisiana

 Port of Port Arthur, Texas

 Ports of Houston/Galveston, Texas

LNG barges would also be capable of delivering LNG to offshore support port areas along the 

central Gulf Coast, including:

 Port Fourchon, Louisiana

 Port of Iberia, Louisiana

 Port of Morgan City, Louisiana

 Port of Galveston, Texas

As described above (section 1.2.3), the Coast Guard is the federal agency responsible for 

assessing the suitability of the Project Waterway for LNG marine traffic. The Coast Guard’s Hazardous 

Materials Division (CG-ENG-5) is currently developing policy regarding the design of LNG barges.8 

According to the Coast Guard, the starting point for design of LNG barges is regulations in the 

International Gas Carrier (IGC) Code and 46 CFR 154 – Safety Standards for Self Propelled Vessels 

Carrying Bulk Liquefied Gases (Coast Guard, 2015a).

 

8 Barges designed to carry LNG as cargo do not currently exist in the United States, although plans for these vessels are underway. 
1-15
1-16

The Coast Guard is developing detailed policy guidance to clarify the applicability of existing 

regulations to the transfer of LNG for use as vessel fuel. The Coast Guard’s Policy Letter No. 01-15, 

Guidelines for Liquefied Natural Gas Fuel Transfer Operations and Training of Personnel on Vessels 

Using Natural Gas as Fuel, as well as Policy Letter No. 02-15 Guidance Related to Vessels and 

Waterfront Facilities Conducting Liquefied Natural Gas (LNG) Marine Fuel Transfer (Bunkering) 

Operations (Coast Guard, 2015b; 2015c), are currently in draft form and were recently circulated to the 

public and marine industry for comment (79 Federal Register 7470). Magnolia filed comments with the 

Coast Guard on these policy letters on March 6, 2014. Once finalized, these policy letters will provide 

additional guidance to vessel and waterfront facility owner/operators on the safety, security, and training 

requirements for vessels and facilities transferring LNG for use as vessel fuel. Magnolia would 

implement the guidelines established by these two documents, as well as any applicable regulations 

(either current or potential future regulations) that should be promulgated by the Coast Guard prior to 

Magnolia’s commissioning date.

1.4.2 Tie-in to Calcasieu Parish District 12 Water Works’ Potable Water Line

The Calcasieu Parish District 12 Water Works would provide potable water for construction and 

operation of the Magnolia LNG Project. An existing 12-inch-diameter water pipeline runs along the 

entire length of the proposed LNG terminal site just north of Henry Pugh Boulevard. A permit is required 

for the tie-in to be completed. Magnolia would request permission to interconnect to the Calcasieu Parish 

District 12 Water Works, which would impact less than 0.1 acre of land within the LNG terminal site (see 

figure 1.4.2-1). This tie-in is not linked or connected to other projects and it would be under the review 

and approval of the Calcasieu Parish District 12 Water Works. 

Figure 1.4.2-1 Tie-in to Existing Potable Water Line
1-17

1.4.3 Electric Transmission Line and Switching Station for the LNG Terminal

To provide electrical power to the LNG terminal, Entergy would build a 1.3-mile-long doublecircuit 230 kilovolt (kV) electric transmission line connecting its existing Graywood substation to a new 

switching station at the LNG terminal site (see figure 1.4.3-1). Entergy would construct the transmission 

line for the use of the proposed Magnolia LNG Project. The transmission line would begin at the 

Graywood substation at the northeast corner of West Lincoln and Big Lake Roads where it would cross to 

the south side of West Lincoln Road and proceed west to the Big Lake Road intersection. At the 

intersection of Lincoln and Big Lake Roads, the transmission line would turn south and follow the

existing road and utility rights-of-way along the east side of Big Lake Road. At the intersection of Henry 

Pugh Boulevard, the transmission line, following the existing rights-of-way, would cross Big Lake Road 

and follow the Henry Pugh Boulevard right-of-way on its south side and continue in a westerly direction 

past Calcasieu Parish District 12 Water Works. From a point on the east side of the LNG terminal site, 

the line would turn north, crossing over Henry Pugh Boulevard where it would terminate at the new 

0.2 acre switching station within the LNG terminal.

Figure 1.4.3-1 Electric Transmission Line from Entergy’s Existing System to the LNG Terminal

Based on the initial design, the transmission line would be within a 170-foot-wide right-of-way, 

adjacent to or possibly overlapping with the existing road and utility rights-of-way on Lincoln and Big 

Lake Roads and Henry Pugh Boulevard. The transmission line right-of-way would occupy 26.1 acres of 

land, including 11.5 acres of open land, 10.4 acres of wetland (composed primarily of freshwater scrubshrub and forested wetland, and with small areas of freshwater emergent wetland and estuarine and 

marine wetland), and 4.2 acres of upland forest. The majority of the impacts associated with construction 

and operation of the transmission line would result from the installation of 15 to 18 poles to support the 

power lines and the removal of trees within the right-of-way. 
1-18

Entergy would conduct the necessary consultations and obtain applicable permits and approvals 

for the electric transmission line and switching station, including CWA authorization, threatened and 

endangered species consultation, and cultural resources consultation. Entergy would also submit a local 

construction permit to Calcasieu Parish after the final design is completed and conduct necessary 

coordination with the Louisiana DOTD regarding the transmission line crossings of Big Lake Road and 

Henry Pugh Boulevard. No permits have been applied for by Entergy at this time. 

1.4.4 Electric Transmission Line for Compressor Station 760

To provide electrical power to Compressor Station 760, Cleco would build a 0.3-mile-long 

34.5 kV electric transmission line from its existing 34.5 kV electric transmission line to the proposed 

compressor station (see figure 1.4.4-1). The transmission line would begin at the existing transmission 

line on the west side of Refinery Road and would proceed east across Refinery Road and agricultural land 

to the Compressor Station 760 site. 

Figure 1.4.4-1 Electric Transmission Line from Cleco’s Existing System to Compressor Station 760

Based on the initial design, the transmission line would be within a 20-foot-wide right-of-way, 

which would occupy 0.7 acre of agricultural land and less than 0.1 acre of existing road and utility rightsof-way. The poles supporting the transmission line wires are expected to be between 90 and 100 feet in 

height and spaced approximately 600 feet apart. Impacts associated with construction and operation of 

the transmission line would be due to the installation of poles to support the power line and a small 

transformer pad at the compressor station. Cleco has informed KMLP that no federal, state, or local 

permits/approvals would be required for the installation of the electrical utility line and transformer.
1-19

1.5 PERMITS, APPROVALS, AND REGULATORY REVIEWS

As the lead federal agency, the FERC is required to comply with Section 7 of the ESA, the MSA, 

Section 106 of the NHPA, EPAct 2005, and section 3 of the NGA. Each of these statutes has been taken 

into account in the preparation of this EIS. Table 1.5-1 lists the major federal, state, and local permits, 

approvals, and consultations identified for the construction and operation of the projects. Table 1.5-1 also 

identifies when Magnolia or KMLP commenced or anticipates commencing formal permit and 

consultation procedures.

Section 7 of the ESA states that any project authorized, funded, or conducted by any federal 

agency 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)(1988)). To comply with Section 7, the FERC is required to determine 

whether any federally listed or proposed threatened or endangered species or their designated critical 

habitat occur in the vicinity of the proposed projects and conduct consultations with the U.S. Fish and 

Wildlife Service (FWS) and/or the National Oceanic and Atmospheric Administration’s (NOAA) 

National Marine Fisheries Service (NOAA Fisheries), if necessary. If, upon review of existing data or 

data provided by Magnolia or KMLP, the FERC determines that these species or habitats may be affected 

by the projects, 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 section 305(b)(2)). Although absolute criteria have not been established for conducting 

EFH consultations, NOAA Fisheries recommends consolidating EFH consultations with interagency 

coordination procedures required by other statues, such as NEPA, the Fish and Wildlife Coordination Act, 

or the ESA (50 CFR 600.920(e)), to reduce duplication and improve efficiency. Section 4.6 provides 

information on the status of this review.

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. Magnolia and KMLP, as non-federal parties, are assisting the 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.

EPAct 2005 and section 3 of the NGA require us to consult with the U.S. Department of Defense

to determine if there would be any impacts associated with the Magnolia LNG Project on military training 

or activities on any military installations. In a letter dated December 11, 2014, the U.S. Department of 

Defense indicated that there would likely be no impacts from the proposed actions.

Besides the FERC, other federal agencies have responsibilities for issuing permits or approvals to 

comply with various federal laws and regulations. The Coast Guard exercises regulatory authority over 

the suitability of the Project Waterway for LNG marine traffic. As required by its regulations, the Coast 

Guard is responsible for issuing an LOR as to the suitability of the waterway for LNG marine traffic. The 

Coast Guard issued its LOR on February 12, 2015. Impacts on vessel traffic are summarized in section 

4.9.6.1 of this EIS.
1-20

TABLE 1.5-1

Major Permits, Approvals, and Consultations Required for the Projects

Agency Permit/Approval/Consultation

Status

Magnolia LNG Project

Lake Charles 

Expansion Project

FEDERAL

FERC Authorization under Section 

3(a) of the NGA 

Application filed April 28, 2014 Not applicable

Certification under Section 

7(c) of the NGA

Not applicable Application filed June 30, 2014

COE Section 404, CWA Permit  Application filed May 8, 2014

 Correction to application regarding 

acreage impacts submitted 

October 29, 2014

 Under COE review

 Application filed June 26, 2014

 Under COE review

Section 10, RHA Permit Section 10 authorization concurrent 

with COE section 404 permit

Not applicable

Coast Guard LOR as to the suitability of 

the waterway for LNG marine 

transit

LOR issued February 12, 2015 Not applicable

DOE Application for Long Term, 

Multi-Contract Authorization 

to Export Natural Gas to FTA 

Countries

 Authorization received 

February 26, 2013 to export 

4 MTPA of LNG

 Authorization received March 5, 

2014 to export an additional 4

MTPA of LNG

Not applicable

Application for Long Term, 

Multi-Contract Authorization 

to Export Natural Gas to 

Non-FTA Countries

 Application to export 8 MTPA of 

LNG received by DOE

October 15, 2013

 Under DOE review

Not applicable

FWS Section 7 ESA Consultation No effect concurrence received 

September 27, 2013

No effect concurrence received 

July 25, 2014

Migratory Bird Treaty Act

Consultation

During a conference call February 3, 

2014, the FWS indicated that 

impacts on migratory birds are not 

expected

Email dated April 24, 2015 stated 

that the FWS does not believe that 

the project would adversely affect 

migratory birds

NOAA Fisheries Section 7 ESA Consultation

Marine Mammal Protection 

Act Consultation

Conference calls held between 

Magnolia and NOAA Fisheries staff 

August 17 and October 17, 2013

Not applicable

MSA Consultation  Conference call held between 

Magnolia and NOAA Fisheries 

staff February 10, 2014

 Conference call held between 

FERC and NOAA Fisheries staff 

March 20, 2015

Not applicable

U.S. Department of 

Defense

Consultation regarding 

impacts on military operations

Letter stating that the Magnolia LNG 

Project would have minimal impact 

on military training and operations 

received December 11, 2014 

Letter stating that the Lake Charles 

Expansion Project would have 

minimal impact on military training 

and operations received 

December 11, 2014
1-21

TABLE 1.5-1 (cont’d)

Major Permits, Approvals, and Consultations Required for the Projects

Agency Permit/Approval/Consultation

Status

Magnolia LNG Project

Lake Charles 

Expansion Project

STATE

LDEQ – Water Quality 

Division

Section 401 Water Quality 

Certification

Section 401 certification concurrent 

with COE section 10/404 permit

Section 401 certification

concurrent with COE section 404 

permit

Louisiana Pollutant Discharge 

Elimination System (LPDES) 

Permit for Discharge of 

Hydrostatic Test Water

Notice of Intent would be submitted 

at least 30 days prior to the 

discharge event

Notice of Intent would be 

submitted at least 30 days prior to 

the discharge event

LPDES Permit for Industrial 

Operating Stormwater Permit

Submittal pending Not applicable

LDEQ – Air Quality 

Division

Air Quality Permit

Prevention of Significant 

Deterioration (PSD) and 

Title V Operating Permit

 Application filed June 23, 2014

 Public notice by LDEQ of an 

administratively complete 

application published in the Lake 

Charles American Press 

newspaper on July 9, 2014

 Revised Title V and PSD permit 

application along with Air 

Dispersion Modeling Protocol and 

Results filed January 27, 2015 

 Under LDEQ review

 Application filed June 20, 2014

 Revised application filed 

October 7, 2014 a

 Under LDEQ review

LDWF Threatened and Endangered 

Species Consultation

Letter from the LDWF dated 

September 13, 2013 stating that no 

impacts on rare, threatened, or 

endangered species or critical 

habitat are anticipated

Letter from the LDWF dated 

March 26, 2014 stating that no 

impacts on rare, threatened, or 

endangered species or critical 

habitat are anticipated

Louisiana State

Historic Preservation 

Office (SHPO)

Section 106, NHPA 

Consultation

 Letter from the SHPO dated 

October 28, 2013, indicating 

concurrence with the area of 

potential effect at the LNG terminal 

and no need for further 

investigation

 Letter from the SHPO dated 

April 8, 2015, indicating 

concurrence with the area of 

potential effect along the dredge 

material and effluent pipeline 

routes and within the dredge 

material placement area and no 

need for further investigation

 Letter from the SHPO dated 

May 12, 2015 providing

concurrence that no historic 

properties would be impacted at 

the DII construction yard

 Letter from the SHPO dated 

May 21, 2014, providing

concurrence that no historic 

properties would be impacted

_______________________

a The U.S. Supreme Court issued a ruling regarding greenhouse gas emissions on June 23, 2014. Prior to the ruling, 

Compressor Station 760 would have been a major stationary source under the PSD requirements. However, based on 

the Supreme Court ruling and LDEQ’s rule provisions for greenhouse gases, Compressor Station 760 facility is no longer 

required to obtain a PSD or Title V permit specifically for greenhouse gas emissions, as the EPA may no longer consider 

greenhouse gases as a pollutant for purposes of defining a “major emitting facility” in the PSD or Title V permitting 

context. See additional discussion in section 4.11.1.
1-22

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 dredging and/or filling waters 

of the United States. Before an individual section 404 permit can be issued, the CWA requires 

completion of a section 404(b)(1) guideline analysis. The section 401/404 applications for the projects 

were filed on May 8, 2014 and June 26, 2014, respectively. The FERC, in the NEPA review represented 

by this EIS, has analyzed all 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 projects, as 

well as analyses of alternatives. The results of our analysis of alternatives are provided in section 3.0 of 

this EIS; a summary of impacts on surface waters and wetlands are provided in sections 4.3.2 and 4.4.2, 

respectively, of this EIS.

In addition to CWA responsibilities, the COE has jurisdiction over section 10 of the RHA, which 

requires authorization for excavation, fill, or modification within or beneath navigable waterways. 

Magnolia’s section 10 application was filed with its section 401/404 application on May 8, 2014. Impacts 

on section 10 waterbodies are summarized in section 4.3.2.2 of this EIS.

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 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. A revised Title V and PSD permit application along with an Air 

Dispersion Modeling Protocol and Results for the Magnolia LNG Project was submitted to the LDEQ on 

January 27, 2015. KMLP submitted a Title V and PSD application to the LDEQ on June 20, 2014; 

however, on June 23, 2014, the U.S. Supreme Court issued a ruling that the EPA may no longer consider 

greenhouse gases as a pollutant for purposes of defining a “major emitting facility” in the PSD or Title V 

permitting context. Based on the Supreme Court ruling and LDEQ’s rule provisions for greenhouse 

gases, KMLP submitted a revised application to the LDEQ on October 7, 2014, that does not include PSD 

Review. Air quality impacts that could occur as a result of construction and operation of the projects are 

evaluated in sections 4.11.1.4 and 4.11.1.5 of this EIS, respectively.

The proposed projects must comply with sections 401, 402, 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 NPDES permit 

(section 402), which would be issued by the LDEQ. Potential impacts on water quality as a result of 

construction and operation of the projects is discussed in section 4.3.2.2 of this EIS. 

Magnolia and KMLP are responsible for all permits and approvals required to implement the 

projects, respectively, 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.9

 

9 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

2.1 PROPOSED FACILITIES 

The Magnolia LNG and Lake Charles Expansion Projects consist of the LNG terminal and 

KMLP facilities. A description of these facilities is provided below.

 LNG Terminal: Construction and operation of various liquefaction, LNG distribution, 

and appurtenant facilities within the boundaries of the site leased by Magnolia near Lake 

Charles, Louisiana; components of the LNG terminal include:

o Magnolia’s facilities to treat and liquefy natural gas; store LNG; and load LNG 

onto LNG carriers, barges, and trucks for domestic distribution and export; and

o KMLP’s Magnolia Meter Station and interconnect pipeline.

 KMLP Facilities: Reconfiguration of KMLP’s existing pipeline system in order to 

accommodate Magnolia’s request for natural gas service at the LNG terminal site; 

components of the KMLP facilities include:

o a new compressor station in Acadia Parish;

o new low and high pressure natural gas header pipelines that would be located 

adjacent to the existing KMLP easement in Acadia Parish; and

o modifications at six existing meter stations in Acadia and Evangeline Parishes

(described in detail in section 2.1.3.3).

Figures 1-1 and 1-2 in section 1.0 provide the general location of the Magnolia LNG and Lake 

Charles Expansion Projects, respectively. 

2.1.1 LNG Terminal

The LNG terminal would be located on the south shore of the Industrial Canal, approximately 

9 miles southwest of the city of Lake Charles, Louisiana (see figure 2.1.1-1). The site, which is Port of 

Lake Charles property, is located off the main Calcasieu Ship Channel approximately 22 miles north of 

the Gulf of Mexico.

The LNG terminal would receive natural gas via a new interconnect pipeline and meter station

(Magnolia Meter Station) to be constructed and owned by KMLP; the Magnolia Meter Station and 

interconnect pipeline would tie into KMLP’s existing interstate pipeline system that traverses the southern 

side of the LNG terminal. The natural gas would then be treated, liquefied, and stored on site in two fullcontainment LNG storage tanks. The LNG would be loaded onto LNG carriers for export overseas, LNG 

carriers and LNG barges (collectively referred to as LNG vessels) for domestic marine distribution and 

the possibility of LNG bunkering,; and LNG trucks for road distribution to LNG refueling stations in 

Louisiana and the surrounding states. Additional information regarding the LNG terminal components is 

provided in the sections below.
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2-3

2.1.1.1 Magnolia Meter Station and Interconnect Pipeline

Construction and operation of the Magnolia Meter Station would facilitate the transportation of 

up to 1.4 Bcf/d of natural gas (feed gas) from KMLP’s existing interstate pipeline system to the LNG 

terminal. The Magnolia Meter Station would connect to KMLP’s existing 42-inch-diameter pipeline 

using a 36-inch-diameter tap and about 40 feet of 36-inch-diameter pipeline riser (referred to as the 

interconnect pipeline). Both the Magnolia Meter Station and interconnect pipeline would be entirely 

within the LNG terminal (see figure 2.1.1-2). The meter station would include metering equipment, 

auxiliary equipment and controls, and one auxiliary building.

Figure 2.1.1-2 LNG Terminal Site Plan

As described above, although the Magnolia Meter Station and interconnect pipeline would be 

within the LNG terminal, these facilities would be owned and operated by KMLP. As such, the Magnolia 

Meter Station would be surrounded by a chain-link security fence and would have a separate access road 

originating from Henry Pugh Boulevard.

2.1.1.2 Liquefaction Trains

Four liquefaction trains would be constructed and operated at the LNG terminal, each with a

guaranteed capacity of 1.7 MTPA and a nominal capacity of 2.0 MTPA of LNG, resulting in a total 

nominal capacity of 8.0 MTPA of LNG. Feed gas would be supplied to the liquefaction trains via a 
2-4

36-inch-diameter feed gas line from the Magnolia Meter Station where it would be pre-treated and cooled 

into a liquid. 

Gas Pre-treatment 

Before liquefaction, feed gas would enter at the Magnolia Meter Station at a controlled pressure 

and would pass through an inlet filter to separate any liquids. The feed gas would then be pre-treated to 

remove components in the natural gas that would otherwise freeze solid or block the cold box exchangers 

at cryogenic temperatures (principally carbon dioxide (CO2); water; mercury; heavy hydrocarbons; and 

small amounts of benzene, toluene, ethylbenzene, and xylenes [BTEX]). 

CO2 and trace amounts of hydrogen sulfide (H2S) in the natural gas would be largely removed 

using an amine gas-sweetening unit, resulting in a CO2 concentration of approximately 50 parts per 

million (ppm); the separated CO2 and H2S would flow through a H2S scavenger unit to reduce the H2S 

concentration to 0.1 ppm. The resulting waste stream would be routed to the thermal oxidizer before

venting to the atmosphere (air emissions associated with operation of the LNG terminal are discussed in 

section 4.11.1.5). The water-saturated gas then would be cooled to about 59 degrees Fahrenheit (°F) (the 

hydrate point of gas is approximately 48 °F) using the auxiliary refrigeration system, passed through a 

knock-out separator to remove bulk water from the gas, and then routed through the molecular sieve bed 

dryers to remove most of the remaining water. The condensed water, along with trace amounts of amine 

removed from the cooled natural gas stream, would be recycled for use as makeup water. After this 

process, natural gas with a water content of about 20 pounds per million standard cubic feet would enter 

the dehydration plant, which would lower water content to less than 0.5 ppm. Any mercury in the natural 

gas would be removed in the mercury removal unit prior to entering the heavy hydrocarbon removal 

column. This column would remove the heavy hydrocarbons as well as small amounts of freezable 

aromatic compounds such as benzene and cyclohexane prior to entering the liquefaction unit. The 

removed heavy hydrocarbons would be vaporized and mixed with fuel gas powering the auxiliary boiler 

that supplements the steam demand in the plant. The auxiliary boiler would consist of a BTEX (heavy 

hydrocarbons) destruction burner to ensure air emissions are within acceptable limits. 

Liquefaction and Boil-off Gas

Following pre-treatment and heavy hydrocarbon removal, the natural gas would be condensed 

into a liquid at close to atmospheric pressure by cooling it to –260 °F via Magnolia’s Optimized Single 

Mixed Refrigerant (OSMR®) process. A schematic of the liquefaction process is shown on figure 2.1.1-3. 

Essentially, liquefaction of the pre-treated feed gas is achieved using a vapor compression cycle process.

The mixed refrigerant used in the process would be comprised of nitrogen, methane, ethane, and nbutane. Two independent parallel refrigeration circuits would be provided, each consisting of a mixed 

refrigerant compressor and air cooler, core-in-kettle heat exchanger, and a main plate fin heat exchanger 

(cold box) and suction scrubber. After liquefaction, the LNG would split into two feed lines, entering

each line at a pressure of 100 pounds per square inch gauge (psig) at about –260 °F, which would flow to 

the LNG storage tank. 

The refrigerant compressor would be driven by aero-derivative gas turbines. Fuel for the gas 

turbines would be provided by molecular sieve regeneration gas and by a small quantity of makeup feed 

gas. Prior to entering the cold box, the mixed refrigerant would be cooled in the core-in-kettle heat 

exchanger using ammonia at a pressure of 44 psig and temperature of 30 °F.
2-5

Figure 2.1.1-3 Schematic of OSMR® Process

The mixed refrigerant for each cold box would be compressed to 600 psig by a single-stage 

centrifugal compressor directly driven by a gas turbine. The high-pressure mixed refrigerant would then 

be fully liquefied in the cold box and expanded (partially flashed), using Joule-Thomson effect, thus 

providing the refrigeration for the system. The low pressure mixed refrigerant would provide the 

refrigeration in the cold box and cool mixed refrigerant vapor would return to the compressor via the 

suction scrubber. The partially flashed vapor and boil-off gas would be recovered by two boil-off gas

compressors. Only one compressor would operate during normal operation; the second compressor

would be used during LNG vessel loading. To maintain a constant vapor temperature entering the LNG 

storage tank and, therefore, constant suction and discharge temperature on the boil-off gas compressors, 

LNG would be sprayed into the vapor return line from the LNG vessel during loading.

The boil-off gas and flash vapor would be compressed to 100 pounds per square inch absolute 

(psia) and would return to the cold box where it would be substantially re-liquefied. The re-liquefied 

boil-off gas would be separated and liquid methane would return to the LNG storage tank. 

Refrigeration Circuits

Refrigeration to liquefy the natural gas would be provided principally by the single mixed 

refrigerant supplemented by ammonia refrigeration at the warm end of the cycle. The ammonia 

refrigeration process would be comprised of steam turbine-driven centrifugal compressor, condensers, 

separator vessels, pumps, pipework, instrumentation, and a control system. The ammonia refrigerant 
2-6

would first be applied to cooling wet gas from the amine contactor then applied to cooling inlet air to the 

gas turbines to increase power; the remainder would be used in pre-cooling the mixed refrigerant.

Cold Box and Ammonia Pre-cooler

Each liquefaction train would contain two parallel cold box/ammonia pre-cooler assemblies, each 

with a conventional core-in-kettle heat exchanger mounted on a cold box. The ammonia would cool the 

high pressure mixed refrigerant stream before it enters the cold box, thereby ensuring that low

temperature mixed refrigerant would return to the compressor suction.

Combined Heat and Power System

Combined heat and power technology would be employed to recover the waste heat from the gas 

turbines, which would be used to provide process heat and steam power for the plant, including steam 

power for the ammonia refrigeration system. Steam would be generated via once-through-steamgenerators, which would generate high-pressure steam to power a single pressure steam turbine generator, 

as well as supply the required quality of steam to various process heat users. An auxiliary boiler fueled 

by lean flash gas produced from the boil-off gas system, feed gas, and condensate from the heavy 

hydrocarbon removal unit also would be used to supplement the steam production.

2.1.1.3 LNG Storage Tanks

Two LNG storage tanks, each with a net capacity of about 160,000 m3, would store the LNG 

produced by the four liquefaction trains. The full-containment LNG storage tanks would be doublewalled and designed to meet the requirements of the NFPA Standard 59A, regulations of the DOT’s

Pipeline and Hazardous Materials Safety Administration (PHMSA) at 49 CFR 193, and other applicable 

standards.

Each LNG storage tank would have the following features:

 an inner wall (primary containment) composed of low-temperature 9-percent nickel steel;

 an outer wall (secondary containment) composed of reinforced post-tensioned concrete 

with a steel liner;

 a reinforced concrete domed roof, supporting insulated deck, LNG pumps and tank top,

and LNG and vapor pipework;

 an insulated aluminum deck, which would be located over the inner wall and suspended

from the roof of the outer wall;

 submerged motor pumps contained in watertight chambers and supported by a structure 

attached to the roof and walls;

 a base heating system;

 pressure, level, and temperature instrumentation, including monitoring of tank cool-down;

 pressure and vacuum relief systems;

 nozzles and internal pipework, including a two-phase inlet and top cool-down spray;

 a nitrogen purge and gas detection system for wall and floor insulation space;
2-7

 roof platforms, walkways, and pipe supports; and

 external stairways, ladder, and pipe supports.

The LNG storage tanks would be designed and constructed so that the self-supporting 9-percent 

nickel steel primary containment and the concrete secondary containment would be capable of 

independently containing the LNG. The 9-percent nickel steel primary containment would contain the 

LNG under normal operating conditions. The concrete secondary containment is designed to be capable 

of containing 110 percent of the capacity of the inner tank. Furthermore, an earthen berm would be 

constructed around both of the LNG storage tanks and would have a minimum containment capacity 

equal to the gross volume of one LNG storage tank. A site plan showing the location of the proposed 

LNG storage tanks in relation to other project facilities is shown on figure 2.1.1-4.

Figure 2.1.1-4 LNG Terminal Layout

2.1.1.4 LNG Loading and Ship Berthing Area

A single ship berthing area would be recessed into the northern boundary of the LNG terminal to 

accommodate LNG vessels (both LNG carriers and barges) (see figures 2.1.1-2 and 2.1.1-4). To achieve 

the proposed maximum loading rate for LNG vessels (10,000 cubic meters per hour [m3/hr]), the main 

cryogenic LNG line from the LNG storage tanks to the loading platform would be nominally sized at 

30 inches in diameter. The LNG loading platform would include three 16-inch-diameter LNG loading 

arms and one 16-inch-diameter vapor return arm. Each loading arm would be equipped with the 

following:

 a hydraulic quick connect/disconnect coupler;

 a hydraulic double-ball, valve-powered emergency release coupler;

 swivel joints with nitrogen purge;

 a mechanical locking device for arm stowing;

 nitrogen purge and drain connections; and

 breasting and mooring dolphins.
2-8

The layout would provide an additional breasting dolphin in front of the LNG loading platform to 

cover the LNG barges and ensure contact with the smaller vessels’ flat panel when spotted across from 

the dedicated combination LNG loading arm and vapor return line. Magnolia would use a dedicated allmetal articulated 8-inch-diameter LNG loading arm with a 6-inch-diameter vapor return line mounted 

piggyback on the LNG loading arm for this service. Both the LNG loading arm and vapor return line 

would be equipped with a double-ball, valve-powered emergency release system to provide near dry 

break disconnection of the LNG loading arm and vapor return line from the LNG barge in the event of an

emergency. Other operating and control equipment would be the same as that installed on the 16-inchdiameter LNG loading arms for the larger-capacity LNG carriers. 

Initially, LNG carriers with capacity of up to 180,000 m3are expected to call on the LNG 

terminal; however, the proposed berthing area would be able to accommodate LNG carriers with 

capacities between 120,000 and 218,000 m3and LNG barges with capacities of about 15,000 m3. When 

operating at full capacity, projections indicate that an average of one to two LNG carriers and an 

additional one to two LNG barges would make port calls at the LNG terminal per week. As determined 

by the Coast Guard (see section 1.2.3), the maximum number of LNG carrier and barge transits would be 

208 vessels per year, including 104 LNG carriers and 104 LNG barges.

2.1.1.5 LNG Truck Loading

The LNG terminal would include facilities that allow LNG to be loaded onto LNG trucks for road 

distribution to LNG refueling stations in Louisiana and surrounding states. The LNG truck-loading area, 

which is depicted on figures 2.1.1-2 and 2.1.1-4, would include the following main facilities: 

 cryogenic pipework (loading and vapor return) from the LNG storage tanks to the LNG 

truck-loading area;

 a truck loading vessel that provides a stable LNG flow to the LNG truck loading pumps;

 flexible cryogenic hoses (loading LNG and vapor return);

 control panel within a shelter; and

 a turning circle for LNG trucks. 

The capacity of the LNG trucks would be about 12,500 gallons (47 m3) with a loading flow rate 

of about 265 gallons per minute (60 m3/hr). As a result, LNG loading would take less than 1 hour per 

truck. After LNG loading operations are complete, the LNG truck would follow the plant road in order to 

turn around and exit the LNG terminal site. Additional information on LNG truck transit is described in 

section 1.4.1.

Current projections indicate that, once more LNG fueling stations become operational in 

Louisiana and the neighboring states, an average of one truck would be loaded per week at the LNG 

terminal when operating at full capacity. Therefore, the anticipated volume of LNG to be delivered by 

truck would be about 650,000 gallons per year during operation of the LNG terminal.

2.1.1.6 Flare Stack

A flare stack is a gas combustion device primarily used for burning off flammable gas released by 

pressure relief valves. The purpose of a pressure relief and flare system is to safely and reliably protect 

plant systems from overpressure during start-up, shutdown, plant upsets, and emergency conditions.
2-9

Upset events that require flaring or depressurizing are not planned, and the control system is designed to 

prevent such events. Planned flaring is usually associated with system cool down and planned 

maintenance shutdown scenarios.

Two separate flares would be installed at the LNG terminal: a cold flare to handle cold relief 

fluids and a warm flare to handle wet/warm relief fluids. The flares would be adjacent to one another and 

would share a common flare-stack structure supported by a common guy-wire system. The stack 

supporting the two flares would be about 100 feet in height. During normal operation, no flaring would 

take place because boil-off gas would be recovered and utilized as fuel in the combined heat and power

system’s auxiliary boiler, which would then be used as steam power in the ammonia refrigeration system

(see section 2.1.1.2).

The warm flare would be connected to the liquefaction trains and would only flare during plant 

start-up or process upset conditions. The cold flare would be connected to the vapor return line from 

vessel loading. The line would feed the LNG storage tank to maintain tank pressure during vessel

loading. The flare would be ignited only when the over-pressure valve opens and when a flammable gas 

mixture is present at the flare tip. This is a safety overpressure system and is not designed for use during

normal operations.

2.1.1.7 Utilities and Support Facilities

Demineralized Water Treatment Plant

Makeup water required by the liquefaction trains would be supplied by the demineralized water 

treatment plant. The water treatment system would be designed, supplied, installed, and monitored by a 

specialist from a water treatment company. The water treatment may include pre-filtering, reverse 

osmosis, electro-de-ionization, mixed resin bed, and chemical treatment. Water treatment option details 

would be determined during Front End Engineering Design (FEED).

Operation of the demineralized water treatment plant would require between 167,378 and 

278,964 gallons of water per day. The majority of the water required for operation (between 130,090 and 

167,378 gallons) would be obtained from an on-site water well (see section 4.3.1.4). The remaining water 

required for the operation of the demineralized water treatment plant (up to 126,802 gallons) would be 

condensed water produced by the liquefaction trains. Reject water (which is composed of dissolved 

solids and minerals removed from the water during the treatment process) from the demineralized water 

treatment plant would be drained to a holding basin and diluted with stormwater runoff prior to discharge 

to the Industrial Canal in accordance with LDEQ requirements.

Power Supply

The total power requirement for each liquefaction train is 72.5 megawatts (MW), of which 

66 MW would be generated from the two 33 MW gas turbines driving the mixed refrigerant compressors. 

As depicted on figure 2.1.1-3, a combined heat and power system would recover the waste heat from the 

gas turbines to produce high-pressure steam. This steam would be used by steam turbines that would 

drive the ammonia refrigeration plant within each liquefaction train. 

The remaining 6.5 MW required for each liquefaction train would be supplied by construction of 

a new switching station within the LNG terminal site and a new 1.3-mile-long 230-kV transmission line 

between the LNG terminal and Entergy’s existing Graywood Substation. These facilities are discussed in 

detail in section 1.4.3.
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Water Supply and Sewage Handling

Potable water required during construction and operation of the LNG terminal would be supplied 

by Calcasieu Parish District 12 Water Works’ existing 12-inch-diameter water pipeline, which runs along 

the southern boundary of the LNG terminal just north of Henry Pugh Boulevard. The water, sourced 

from off-site groundwater wells, would be used for plant personnel in buildings, safety showers, and 

eyewash stations. Discussions with the Calcasieu Parish Engineer, Terry Frelot, confirmed that the 

existing water pipeline would be sufficient for the facility’s operational potable water needs of 

2,000 gallons per day, on average. No upgrades or improvements to the existing water pipeline would be 

required. The tie-in to the 12-inch-diameter water pipeline would take place within the LNG terminal site 

boundaries and is described in additional detail in section 1.4.2.

Two groundwater wells would be drilled on site for process, service, and plant fire water. The 

depth of the wells would be between 500 and 700 feet. Although two wells would be drilled, only one 

well would be used during general operation of the LNG terminal; the second well would be used only if 

the primary well were out of service. 

Two screened water intakes would appropriate water from the Industrial Canal for operation of 

the LNG storage tank deluge system, which is a fire protection system that would distribute water over 

the roof and side walls of the LNG storage tank in the event of a fire emergency. The deluge system 

would be operated periodically for system maintenance, testing, and in the event of a fire emergency. 

When in operation, the system would appropriate water from the canal at a rate of approximately 

6,300 gallons per minute.

Each liquefaction train would produce condensed water during operations, which would be 

reused by the demineralized water treatment plant within each train. In total, all four trains are expected 

to produce an average of 126,802 gallons per day of condensed water (an average of 31,700 gallons of 

water per day per liquefaction train). As described above, groundwater would be used to supply the 

balance of water required by the demineralized water treatment plant. 

During construction of the LNG terminal, wastewater would be collected from construction 

facilities into holding tanks, the contents of which would be removed by licensed vendors via vacuum 

trucks for proper off-site disposal. In general, the workforce would be serviced by a certified portable 

toilet vendor with wastewater periodically removed via vacuum trucks for proper off-site disposal. 

A self-contained, aboveground treatment plant would be developed to handle wastewater 

generated during operation of the LNG terminal. Magnolia would employ a third-party contractor to 

operate and maintain the treatment plant as an individual system, the Louisiana Administrative Code

Title 51 (LAC 51).

Communication

The telecommunication system for the LNG terminal would include:

 telephone exchange;

 radio system;

 computer network;

 plant telecommunications network;

 electronic mail system for communication; and

 a closed-circuit television system.
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Communication with the following locations would be required:

 LNG carrier or LNG tug/barge;

 local Programmable Logic Controller;

 natural gas provider;

 Entergy (local power provider);

 local emergency services; and 

 company head office.

Marine band very-high-frequency radios would be provided for communication with the LNG 

vessels. Access to the control system would be provided to allow remote monitoring of LNG terminal

operation by approved parties. The telecommunication systems would comply with applicable

governmental rules and regulations. 

Buildings and Access Roads

The LNG terminal would include an administration and control building, workshop, and smaller 

shelters. The ground level of the administration and control building would include offices for plant 

personnel and visitors, meeting room, open area for work stations, kitchen, and bathrooms. The control 

room would be located above the administration level to provide a view of the facility. It would include 

an open area with control and monitoring stations suitable for two operators. Separate rooms would be 

provided for instrument and electrical equipment and an uninterruptible power supply/battery. The LNG

terminal would also include a workshop for the maintenance of plant equipment as well as smaller 

shelters and buildings.

Existing local roadways would be used to access the LNG terminal during construction and 

operation. Because there are no existing roads within the LNG terminal site, internal roads would be 

constructed within the site boundary, including a new heavy-haul road to transport marine deliveries and 

materials staged at the existing Dynamic Industries, Inc. (DII) construction yard to the LNG terminal (see 

additional discussion in sections 2.2.1 and 2.5.1.1). A perimeter road and site access roads would be 

constructed and maintained to provide access to and within the LNG terminal. The main LNG terminal

access would be provided on the north side of Henry Pugh Boulevard. No new access roads or 

improvements to existing off-site roadways are proposed for construction and operation of the LNG 

terminal.

Facility Drainage and Containment

Drainage, containment, and treatment systems would be provided to ensure the proper disposal of 

effluents from process, service, and surface water streams, as well as domestic effluent from the LNG 

terminal, in accordance with LDEQ requirements. No operational process waters would be discharged 

directly to surface waterbodies. 

Magnolia has designed and would implement its spill containment system within the LNG truck 

loading area, LNG storage tank area, and liquefaction area. This system would utilize curbed areas, 

troughs, open drains, and an impoundment basin to hold LNG as described in additional detail in section 

4.12.5.

Magnolia would be required to implement a Stormwater Pollution Prevention Plan (SWPPP) 

during construction in accordance with the Louisiana Pollutant Discharge Elimination System (LPDES),

General Permit for stormwater discharges. During operation of the LNG terminal, stormwater would be 
2-12

directed into two holding basins (east and west) for dilution and temperature adjustment to ambient before

being discharged into the Industrial Canal.

2.1.2 LNG Transport Vessels

2.1.2.1 LNG Carriers

LNG could be shipped to a variety of locations, including domestic facilities in Puerto Rico, 

Florida, and potentially New York, as well as FTA-countries. In addition, Magnolia has submitted an 

application to the DOE seeking authorization to export to non-FTA countries, which is currently under 

review (see discussion in section 1.2.4). Although LNG carriers and their operation are directly related to 

the use of the proposed LNG terminal, they are not subject to the authorization under section 3(a) of the 

NGA sought by Magnolia’s application with the Commission. As previously discussed, the Coast Guard 

is the federal agency responsible for determining the suitability of the waterway for LNG marine traffic

associated with Magnolia LNG Project. As required by its regulations, the Coast Guard has completed its 

review of the WSA and issued an LOR as to the suitability of the Calcasieu Ship Channel for LNG 

marine traffic on February 12, 2015.

1

The ships that transport LNG are specially designed and constructed to carry LNG for long 

distances. LNG carrier construction is highly regulated and consists of a combination of conventional 

ship design and equipment, with specialized materials and systems designed to safely contain liquids 

stored at a temperature of –260 °F.

The following sections present an overview of the main design and safety features of a typical 

LNG carrier that may transport LNG from the proposed terminal. Additional information on LNG carrier

regulations and safety measures is presented in sections 4.12.6 and 4.12.7.

Profile

LNG carriers have a distinctive appearance compared with other transport ships. An LNG carrier

has a high freeboard (i.e., that portion of the ship above water) when compared with vessels such as oil 

tankers because of the comparatively low density of the cargo. Because of the high freeboard, wind 

velocity can adversely affect the maneuverability of the ship, particularly at slow speeds.

Hull System

All LNG carriers are constructed with double hulls, which increase the structural integrity of the 

hull system and provide protection for the cargo tanks in case of an accident. The space between the 

inner and outer hulls is used for water ballast. The International Maritime Organization’s (IMO) Code for 

the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk and Coast Guard regulations 

require that LNG carriers meet a Type IIG standard of subdivision, damage stability, and cargo tank location.

The Type IIG design ensures the LNG carrier could withstand flooding of any two adjacent 

compartments without any adverse effect upon the stability of the ship. Type IIG design also requires that 

the cargo tanks must be a minimum of 30 inches from the outer hull and a minimum distance above the 

bottom of the ship equal to the beam of the ship divided by 15, or 6.5 feet, whichever is less. This 

distance is intended to prevent damage to the cargo tanks in case of low energy-type accidents that might 

 

1 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
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occur in harbors and during docking. Most large LNG carriers are designed to have 10 to 15 feet between

the outer hull and cargo tank.

Containment Systems

The LNG containment system on LNG carriers consists principally of the cargo tank (sometimes 

called a primary barrier), the secondary barrier, and insulation. The containment system also includes 

cargo monitoring and control and safety systems.

Three basic tank designs have been developed for LNG cargo containment: prismatic 

freestanding, spherical, and membrane. The earliest form of LNG containment is the prismatic 

freestanding tank. It consists of an aluminum alloy or 9 percent nickel steel, self-supporting tank that is 

supported and restrained by the hull structure. Insulation consists of reinforced polyurethane foam on the 

bottom and the sides, with fiberglass on the top. The spherical tank design, also known as the Moss 

design, uses an unstiffened, spherical, aluminum alloy tank that is supported at its equator by a vertical 

cylindrical skirt, with the bottom of the skirt integrally welded to the ship’s structure. This freestanding 

tank is insulated with multi-layer close-cell polyurethane panels. In the membrane containment system, 

the ship’s hull constitutes the outer tank wall, with an inner tank membrane separated by insulation. Two 

forms of membrane are commonly used: the Technigaz membrane using stainless steel and the GasTransport membrane using Invar.

LNG carriers are designed with double hulls regardless of the containment system used. A 

double bottom and double sides are provided for the full length of the cargo area and arranged as ballast 

tanks, independent of the cargo tanks. The double-hulled design provides greatly increased reliability of 

cargo containment in the event of grounding and collisions. Further, the segregated ballast tanks prevent 

ballast water from mixing with any residue in the cargo tanks.

Pressure/Temperature Control

A basic goal of all LNG containment systems is to maintain the LNG cargo at or near

atmospheric pressure at the boiling temperature of the LNG (about –260 F, the temperature at which 

LNG transitions from a liquid to a gas). This is accomplished using “auto-refrigeration,” a phenomenon 

that results from the constant heat flow into the tank and the removal of the associated vapor. The vapor 

ranges from 0.15 to 0.25 percent (by volume) per day and is used to supplement the bunker fuel in the 

ship’s boilers. Currently, all LNG carriers utilize this boil-off gas as fuel. The EPA does not permit 

routine venting of boil-off gas to the atmosphere in the United States (40 CFR 63). Thus, all LNG 

carriers that trade in the United States are fitted with an internalized combustion energy system that

allows the ship’s boiler to consume all of the boil-off gas to fuel the ship’s steam propulsion system. As a 

result, LNG carriers have reduced emissions when compared with conventional oil-fired ships.

Ballast Tanks

Sufficient ballast water capacity must be provided to permit the ship safe transit under various sea 

conditions. LNG cargo tanks are not used as ballast tanks because these tanks must contain a minimal 

amount of LNG to remain at cryogenic temperatures. Consequently, LNG carriers must be designed to 

provide adequate ballast capacity in other locations.

Ballast water tanks are arranged within the LNG carrier’s double hull. It is essential that ballast 

water not leak into the LNG containment system. To reduce the potential for leakage, the ballast tanks, 

cofferdams, and void spaces are typically coated to reduce corrosion. LNG carriers are also periodically 

inspected to examine the coating and to renew it as necessary.
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A ballast control system, which permits simultaneous ballasting during cargo transfer operations, 

is also incorporated into each LNG carrier. This allows the LNG carrier to maintain a constant draft 

during all phases of its operation to enhance performance. Under normal operating conditions, ballast 

water would be discharged from the ship during LNG loading at the LNG terminal. A typical LNG 

carrier of the type in service today would discharge about 9 to 12 million gallons of ballast water into the 

Industrial Canal during loading operations (see ballast water discharge discussion in section 4.3.2.2).

Safety Systems

LNG carriers calling at the LNG terminal would have to comply with all federal and international 

standards regarding LNG shipping. As such, ships that transport LNG from the LNG terminal would be 

fitted with an array of cargo monitoring and control systems. These systems would automatically monitor 

key cargo parameters while the ship is at sea and during cargo operations at the unloading facilities.

The system includes provisions for pressure monitoring and control, temperature monitoring of 

the cargo tanks and surrounding ballast tanks, emergency shutdown of cargo pumps and closing of critical 

valves, monitoring of tank cargo levels, and gas and fire detection.

The ships transporting LNG from the terminal would be fitted with many navigation and 

communication systems, including:

 two marine radar systems, including automatic radar plotting and radio direction finders;

 LORAN-C receivers;

 echo depth finders; and

 a satellite navigation system.

All LNG carriers also have redundant, independent steering control systems that are operable 

from the bridge or steering gear room to maintain rudder movement in case of a steering system failure.

Fire Protection

All LNG carriers arriving at the terminal would be constructed according to structural fire 

protection standards contained in the International Convention for the Safety of Life at Sea (SOLAS). 

This would be done under the review and approval of the Coast Guard.

LNG carriers using the terminal would also be fitted with active fire protection systems that meet 

or exceed design parameters in Coast Guard regulations and international standards, such as the Code for 

the Construction and Equipment of Ships Carrying Liquefied Gases in Bulk and SOLAS, including:

 a water spray (deluge) system that covers the accommodation house and central room, 

and all main cargo control valves;

 a traditional firewater system that provides water to fire monitors on deck and to fire 

stations found throughout the ship;

 a dry powder extinguishing system for LNG fires; and

 a CO2 system for protecting the machinery, ballast pump room, emergency generators, 

cargo compressors, etc.
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Crew Qualifications and Training

All officers and crews of the LNG carriers would comply with the International Convention 

Standards of Training, Certification and Watch Keeping for Seafarers. Key members of the crew must 

have specific training in the handling of LNG and the use of the safety equipment. Officers must receive 

simulator training in the handling of the ship and the cargo systems specific to the conditions at the LNG 

terminal. In addition, a local pilot from the Lake Charles Pilots Association would board each ship and 

guide it while transiting the Calcasieu Ship Channel and Industrial Canal.

LNG barge personnel would be required to complete familiarity training with vessel 

characteristics and basic safety training prior to assuming their duties and responsibilities, in accordance 

with 46 CFR 15.405 and 15.1105. The Coast Guard issued for comment its draft Policy Letter 01-15 

Guidance for Liquefied Natural Gas Fuel Transfer Operations and Training of Personnel on Vessels 

Using Natural Gas as Fuel on February 23, 2015, which provides additional requirements for the training 

of personnel working on LNG barges. When, and if, ratified, Policy Letter 01-15 would require that each 

mariner meet operational and training provisions appropriate for the position they hold (i.e., basic safety 

crew, deck officers, and engineer officers). To ensure adequate training, drills would be conducted at 

regular intervals to confirm that personnel are trained to perform assigned duties during fueling and 

contingency response. 

Ship Selection

The specific identity of LNG carriers that would load at the LNG terminal would depend on the 

commercial terms of the LNG purchase agreement(s). In accordance with the Coast Guard’s LOR, the 

ship loading and berthing area would accommodate up to 104 LNG carriers per year with capacities 

ranging from 120,000 to 218,000 m3. Ships using the LNG terminal would comply with the Coast Guard 

regulations for LNG carriers (46 CFR 154). This compliance is demonstrated by the operator of the LNG 

carrier having proper certificates authorizing the transport of LNG as follows:

 U.S. Flag LNG Ship: The Coast Guard Certificate of Inspection (COI) must be valid and 

endorsed for the ship to transport LNG. A COI is issued for a period of 5 years and 

retention of the COI depends upon the continued maintenance of the vessel in a safe 

operating condition and satisfactory completion of required annual inspections during the 

5-year COI period.

 Foreign Flag LNG Ship: The ship must have a valid Certificate of Compliance issued by 

the Coast Guard. The certificate is issued after the ship has proved that it complies with 

the Coast Guard regulations and after it has been satisfactorily inspected by a Coast 

Guard Marine Sector Office. A Certificate of Compliance is valid for a 2-year period and 

remains valid pending satisfactory completion of an annual mid-period examination 

between Certificate of Compliance renewals.

Both U.S. and foreign flag ships must be annually inspected by the Coast Guard and the flag 

state. A Coast Guard COI is required every 2 years. Coast Guard officers from Marine Safety Unit Lake 

Charles may board the LNG ships arriving in the Calcasieu Ship Channel to ensure safety standards are 

met. Magnolia would continually monitor ship loading operations at the LNG terminal to ensure that the 

operations are occurring according to established procedures.
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2.1.2.2 LNG Barges

Although LNG barges and their operation are directly related to the use of the proposed LNG 

terminal, they are not subject to the authorization under section 3(a) of the NGA sought by Magnolia’s 

application with the Commission. As previously discussed, the Coast Guard is the federal agency 

responsible for determining the suitability of the waterway for LNG marine traffic. The Coast Guard has 

completed its review of the WSA and issued the LOR on February 12, 2015, which stated that the 

Calcasieu Ship Channel is considered suitable for LNG marine traffic. 

Barges designed to carry LNG as cargo do not currently exist in the United States; however, the 

Coast Guard, Office of Hazardous Materials Division is currently developing policy regarding the design 

of LNG barges. The foundation for design of LNG barge requirements is being developed based on the 

International Gas Carrier Code and Title 46 CFR 154 – Safety Standards for Self Propelled Vessels 

Carrying Bulk Liquefied Gases, which is a long-established framework of regulatory requirements for 

self-propelled vessels carrying LNG as cargo (Coast Guard, 2014; Magnolia, 2014a). LNG barges, both 

domestic and foreign, would be required to comply with the Coast Guard regulations for LNG carriers as 

described above. 

Magnolia would engage in commercial discussions with LNG barge operators as these vessels are 

constructed and enter the U.S. marketplace. Based on preliminary barge design specifications, LNG 

barges would be between 296 and 504 feet in overall length, between 52 and 78 feet in width, and design 

draft (the distance between the waterline and the bottom of the vessel) would be between 15 and 23 feet. 

The preliminary containment system design on LNG barges consists of full secondary barriers, where a 

second bottom and sides are provided for the full length of the cargo area. This secondary barrier design 

would provide increased reliability of cargo containment in the event of grounding or collision. 

Fire protection and safety systems for LNG barges would be designed to comply with the Coast 

Guard International Gas Carrier Code regulations, which would require firefighting systems, cargo 

control/monitoring equipment, and gas detection system on LNG barges. The crew qualification and 

training requirements described above for LNG carriers are expected to also apply to LNG barges. Barge 

selection would be part of future commercial negotiations and contracts. Magnolia would require that all 

LNG barges calling at the LNG terminal comply with the Coast Guard international design, safety, and 

operational requirements applicable to the specific vessel type. 

2.1.2.3 LNG Trucks

As stated in section 1.4.1, LNG trucking activities that take place outside the boundaries of the 

LNG terminal do not fall under the jurisdiction of the FERC. The DOT and Louisiana DOTD have 

jurisdiction over vehicle operation within the United States and the State of Louisiana, respectively. The 

trailers that transport LNG are specially designed and constructed to transport LNG for long distances in 

accordance with applicable DOT regulations as discussed below. The following discussion presents a 

brief overview of the main design and safety features of a typical LNG truck trailer that may transport 

LNG from the terminal. Additional information on LNG trucking is presented in section 4.13.

Typical LNG trucks loading at the LNG terminal would have a capacity of approximately 

12,500 gallons (47 m3). The trailer containing the LNG would be 60 feet long, 9 feet wide, and 12 feet 

high. The inner tank of the trailer would be composed of aluminum and constructed in accordance with 

applicable standards established by the American Society of Mechanical Engineers (ASME) and

American National Standards Institute (ANSI) for pressure vessels and internal and external piping. The 

outer, structural frame would be composed of carbon steel and stainless steel jacket that would provide a 

vacuum insulation system to minimize heat loss (boil-off) of the LNG. The trailer would contain a 
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pressure relief system to protect against overpressure, emergency shutoff switches, and the maximum 

allowable operating pressure would be approximately 79 psig. Design temperatures for the inner LNG 

container would be –320 °F to 100 °F. 

LNG trucks would be required to comply with DOT regulations (49 CFR 178.338). Truck 

operators would be trained to satisfy the minimum requirements of 49 CFR 193, as well as the 

requirements of the DOT, Louisiana DOTD, and Calcasieu Parish Police Jury.

2.1.3 KMLP Facilities

In order to accommodate Magnolia’s request for natural gas service at the LNG terminal, 

KMLP’s existing pipeline system would require modifications at several locations. In addition to the 

facilities within the LNG terminal that would be owned and operated by KMLP (i.e., Magnolia Meter 

Station and interconnect pipeline), the Lake Charles Expansion Project includes the following 

components (collectively referred to as the KMLP facilities): a new compressor station; new low and high 

pressure header pipelines that would be located adjacent to the existing KMLP easement; and

modifications at a total of six existing meter stations in Acadia and Evangeline Parishes. These facilities, 

which are shown on figure 2.1.3-1 and appendix B, would be constructed, owned, and operated by 

KMLP. The proposed facilities that would be located in close proximity to one another within Acadia 

Parish are shown in additional detail on figure 2.1.3-2. The proposed KMLP facilities are described in 

additional detail below. 

2.1.3.1 Compressor Station 760

A new compressor station, Compressor Station 760, would be constructed about 6 miles 

southwest of Eunice in northern Acadia Parish, Louisiana. The compressor station would be adjacent to 

KMLP’s existing pipeline easement, the Pine Prairie Energy Center, LLC (Pine Prairie) Meter Station, 

and the proposed low and high pressure header pipelines (see figures 2.1.3-1 and 2.1.3-2).

Compressor Station 760 would include two acoustically insulated compressor buildings, each 

containing two 16,000 horsepower (hp) gas turbine compressor units and turbine auxiliary equipment and 

controls; one auxiliary building containing emergency generation facilities and motor control equipment; 

one office/warehouse building with shop space, and a control building. In addition, the compressor 

station would include a 42-inch-diameter pig launcher and receiver, filter separators, gas coolers, a 

mainline valve, and other utilities. A new paved road originating from Coulee Road would provide 

access to Compressor Station 760 during construction and operation.

2.1.3.2 Header Pipelines

Low Pressure Header Pipeline

A new 1.2-mile-long (about 6,400-foot-long), 36-inch-diameter low pressure natural gas header 

pipeline would be collocated with and constructed adjacent to KMLP’s existing 42-inch-diameter pipeline 

about 6 miles southwest of Eunice in northern Acadia Parish (see figures 2.1.3-1 and 2.1.3-2). The low 

pressure header pipeline would begin at the existing Texas Gas Transmission, LLC (TGT) Meter Station, 

connect to the proposed Compressor Station 760 and the existing Pine Prairie Meter Station, and extend 

to the existing ANR Pipeline Company (ANR) Meter Station. A pig receiving facility would be 

constructed within the permanent easement associated with the low pressure header pipeline west of the 

ANR Meter Station. The low pressure header pipeline would deliver natural gas to one of two suction 

headers at Compressor Station 760. 
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High Pressure Header Pipeline

A new 700-foot-long, 24-inch-diameter high pressure natural gas header pipeline would be 

constructed to access the Pine Prairie Meter Station. The high pressure header pipeline would also deliver 

discharged natural gas from Compressor Station 760 to KMLP’s existing pipeline via a 24-inch-diameter 

tap within the compressor station site (see figures 2.1.3-1 and 2.1.3-2).

2.1.3.3 Modifications to Existing Meter Stations

Modifications would be required at the existing Columbia Gulf Transmission Company (CGT), 

Transcontinental Gas Pipe Line Corporation (TRANSCO), and Texas Eastern Transmission, L.P. 

(TETCO) Meter Stations, which are located in Evangeline Parish. Modifications at each of the meter 

stations would include installation of valves and piping to allow for the bi-directional measurement of gas 

flow (see figure 2.1.3-1 and appendix B).

The ANR, TGT, and Pine Prairie Meter Stations are existing meter stations along the high and 

low pressure header pipeline routes in Acadia Parish, Louisiana (see figures 2.1.3-1 and 2.1.3-2). 

Modifications to the ANR and TGT Meter Stations would include installation of valves and piping to 

allow for bi-directional measurement of gas flow and connection of each meter station to the proposed 

low pressure header pipeline. In addition, a pig launching facility would be constructed within the TGT 

Meter Station. Modification of the existing interconnection facilities located directly adjacent to the Pine 

Prairie Meter Station would facilitate the connection of the meter station to the pipeline headers, which

would also connect to Compressor Station 760.

2.2 LAND REQUIREMENTS

Construction of the LNG terminal and KMLP facilities would require a total of 353.5 acres of 

land, including 277.7 acres associated with construction of the LNG terminal and 75.8 acres for the 

KMLP facilities not within the LNG terminal. Following construction, 144.6 acres of land would be 

permanently maintained for operation and maintenance of the proposed facilities, including 123.8 acres 

for the LNG terminal and 20.8 acres for the KMLP facilities.

Table 2.2-1 summarizes the land requirements for the Magnolia LNG and Lake Charles 

Expansion Projects. Section 4.8 provides a more detailed description and breakdown of land 

requirements and use.

2.2.1 LNG Terminal

Construction and operation of the LNG terminal, which includes KMLP’s Magnolia Meter 

Station and interconnect pipeline, would require 114.0 acres of the 115.0-acre site. During operation, the 

LNG terminal would permanently occupy the entire 114.0 acres. In addition, the LNG loading and ship 

berthing area would require 9.8 acres of open water within the Industrial Canal.

Magnolia plans to use a 5.2-acre portion of the existing construction yard owned by DII for 

marine deliveries, materials staging and transport, and temporary parking by construction workers. The 

DII construction yard is immediately east of the proposed LNG terminal site on the Industrial Canal (see 

figure 2.2.1-1). 
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TABLE 2.2-1

Land Requirements for the Magnolia LNG and Lake Charles Expansion Projects

Facility

Land Required for

Construction (acres)

a

Land Required for

Operation (acres) b

LNG Terminal Facilities

LNG terminal c, d 123.8 123.8

DII construction yard and parking area 5.2 0.0

Dredge material and effluent pipelines 6.9 0.0

Dredge material placement area 141.8 0.0

LNG Terminal Facilities Subtotal 277.7 123.8

KMLP Facilities

Low pressure header pipeline 20.7 8.1

High pressure header pipeline 1.1 0.7

Compressor Station 760 40.6 11.2

CGT Meter Station 2.0 0.3

TRANSCO Meter Station 1.6 0.1

TETCO Meter Station 1.7 0.0

ANR Meter Station 1.7 0.0

Pine Prairie Meter Station 2.0 0.0

TGT Meter Station 1.3 0.4

Existing access roads 3.0 0.0

KMLP Facilities Subtotal 75.8 20.8

TOTAL LAND REQUIREMENTS 353.5 144.6

____________________

a

Total land affected during construction includes construction workspaces and additional workspaces to be used during 

construction and new acreage to be maintained as the permanent facility footprint or permanent easement.

b Land permanently affected by operation includes only new permanent easement or facility footprint (i.e., pre-existing 

pipeline easement/aboveground facility acreages are not included).

c Magnolia would use 114.0 acres of the 115.0-acre site during construction and operation of the LNG terminal.

d KMLP’s Magnolia Meter Station and interconnect pipeline, Entergy’s switching station, and the tie-in to Calcasieu Parish 

District 12 Water Works’ existing water line would be entirely within the boundaries of the tract of land being leased from 

the Port of Lake Charles by Magnolia. Therefore, acreage requirements for construction and operation of these facilities 

are already accounted for in the LNG terminal land requirements.

Magnolia proposes to transport the 862,550 cubic yards (yd3) of material dredged from the 

recessed berthing area to a dredge material placement area approximately 8,000 feet east of the LNG 

terminal, across Big Lake Road. The site, which is owned by Prairie Land Company, is currently subleased to Chicago Bridge & Iron Company (CB&I) and is used for staging and laydown. Two collocated, 

1-mile-long transport pipelines would be used to transfer dredge material to the placement area and return 

effluent produced by the settlement of dredge spoil back to the Industrial Canal, as depicted on 

figure 2.2.1-2. Dredge material transport and placement would require a total of 148.7 acres of land; of 

which 6.9 acres would be required for the transport pipelines and 141.8 acres would be required for the 

dredge material placement area. 
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2.2.2 KMLP Facilities

Construction of the KMLP facilities not within the LNG terminal would require a total of 

75.8 acres of land. Of this, 20.8 acres would be retained for operation and maintenance of the facilities.

2.2.2.1 Compressor Station 760

Construction of Compressor Station 760 would impact 40.6 acres of land, of which 11.2 acres 

would be retained for use during operation of the facility. The compressor station would be sited within 

the eastern half of the site, partially overlapping the header pipeline rights-of-way. The 11.2-acre 

footprint of Compressor Station 760 would be surrounded by a chain-link security fence; the remainder of 

the 40.6-acre site would serve as a spatial and noise buffer and would be fenced. 

2.2.2.2 Header Pipelines

Construction of the 1.2-mile-long low pressure header pipeline would affect a total of 20.7 acres 

of land. The 36-inch-diameter low pressure header pipeline, which would be collocated with KMLP’s 

existing 42-inch-diameter pipeline for its entire length, would be constructed within a 125-foot-wide 

construction right-of-way. Additional construction workspaces would accommodate spoil, sensitive 

features, fence-line crossings, points of intersection, and road crossings. Following construction, a

50-foot-wide permanent easement would be retained during operation of the low pressure header pipeline, 

encompassing 8.1 acres of land and increasing KMLP’s total permanent easement width to 100 feet along 

the low pressure header pipeline.

The 700-foot-long, 24-inch-diameter high pressure header pipeline, which would be collocated 

with the proposed low pressure header pipeline as well as KMLP’s existing 42-inch-diameter pipeline,

would be constructed within a 125-foot-wide construction right-of-way, affecting 1.1 acres of land. 

Following construction, a 50-foot-wide permanent easement would be retained during operation of the 

low pressure header pipeline, encompassing about 0.7 acre of land and increasing KMLP’s total 

permanent easement width to 150 feet along the approximately 450-foot-long section of the high pressure 

header pipeline that would parallel KMLP’s proposed low pressure header pipeline and existing mainline 

(see appendix B).

2.2.2.3 Modifications to Existing Meter Stations

Construction of the proposed meter station modifications would affect a total of 10.4 acres of 

land. A total of 0.8 acre would be required for operation of the expanded facilities at the CGT, 

TRANSCO, and TGT Meter Stations. No additional land would be required for operation of the modified 

facilities within the TETCO, ANR, and Pine Prairie Meter Stations. 

The remaining land requirements include 7.6 acres within the existing meter stations and 

2.0 acres of construction workspace. These temporary construction areas would be restored and allowed 

to revert to pre-construction condition and use.

2.2.2.4 Access Roads

To the extent feasible, KMLP would use existing public and private road crossings and its 

existing permanent easement as the primary means of accessing the KMLP facilities during construction. 

In addition, KMLP would utilize three existing access roads and would construct one permanent access 

road (see table 2.2.2-1). 
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TABLE 2.2.2-1

Access Roads Associated with the KMLP Facilities

Facility/Access Point

Surface 

Type

Road Length 

(feet)

Road Width 

(feet)

Acreage of 

Disturbance

Existing Access Roads

TETCO Meter Station

access from Ashford Cemetery Road

Limestone 789 20 0.5 a

Pine Prairie Meter Station

access from Refinery Road

Limestone 845 20 0.4 a

TGT Meter Station

access from Erick Lane

Limestone 3,274 20 2.1 a

Permanent Access Road

Compressor Station 760

access from Coulee Road

Paved 230 20 0.1

____________________

a Access roads would not require widening beyond the original road footprint. However, modifications or improvements 

such as grading and/or the addition of crushed limestone may be required to safely support the anticipated sizes and loads 

of equipment and materials.

In order to safely support construction equipment and material movement, the existing access 

roads may require modifications or improvements (e.g., grading and/or addition of crushed limestone). 

However, modifications would not expand the original footprint of the access roads. After construction is 

complete, the existing access roads would be returned to pre-construction or better condition. A paved 

road would be constructed to provide permanent access from Coulee Road to Compressor Station 760. 

2.3 CONSTRUCTION SCHEDULE AND WORKFORCE

Assuming receipt of all certifications, authorizations, and necessary permits, Magnolia anticipates

starting construction of the LNG terminal in January 2016 and placing the first liquefaction train into 

service 36 months later, at the end of December 2018. However, based on the Notice of Schedule issued 

on April 30, 2015, we acknowledge that this schedule is no longer feasible. In any event, the remaining 

three liquefaction trains would be commissioned at 3-month intervals after completion of the first 

liquefaction train, with full service anticipated after a total construction period of 45 months. 

Construction of the Magnolia Meter Station, interconnect pipeline, and KMLP facilities would occur over 

an 11-month period, which is tentatively scheduled to begin in January 2017. The Magnolia Meter 

Station, interconnect pipeline, and KMLP facilities are expected to begin service prior to, but generally 

concurrent with, the Magnolia LNG Project going into service.

In total, a maximum of 781 workers would be employed during construction of the LNG terminal 

and KMLP facilities. This includes an average of 355 workers employed at the LNG terminal, which 

would increase to 542 workers during peak construction. Magnolia estimates that 60 percent of the 

construction workforce would be hired locally (see section 4.9.1.1). KMLP anticipates that an average of 

60 to 75 workers would be employed during construction of the KMLP facilities. During a 3-month 

period when construction activities would occur at each of the KMLP facilities (Compressor Station 760, 

the header pipelines, and meter station modifications), up to 270 workers would be employed, 40 percent 

of which would be hired locally (see section 4.9.1.2). 

2.4 ENVIRONMENTAL COMPLIANCE 

The FERC may impose conditions on any Certificate or authorization it grants for the Magnolia 

LNG and Lake Charles Expansion Projects. These conditions include additional requirements and 
2-26

mitigation measures recommended in this EIS to minimize the environmental impact that would result 

from construction and operation of the LNG terminal and KMLP facilities (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 Magnolia 

LNG and Lake Charles Expansion Projects. We will also recommend to the Commission that Magnolia 

and KMLP be required to implement the mitigation measures proposed as part of the projects unless 

specifically modified by other Certificate or authorization conditions. Magnolia and KMLP 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 projects.

Magnolia would employ at least one environmental inspector (EI) to monitor construction 

activities at the LNG terminal, and KMLP would employ one EI to monitor construction activities at the 

KMLP facilities during all phases of construction, including clean up and restoration. The responsibilities 

of the EI(s) employed by Magnolia are described in Magnolia’s project-specific Upland Erosion Control, 

Revegetation, and Maintenance Plan (Plan) and Wetland and Waterbody Construction and Mitigation 

Procedures (Procedures). Magnolia’s project-specific Plan and Procedures are based on the 2013 FERC 

Plan and Procedures, 2 which are a set of construction and mitigation measures developed in collaboration 

with other federal and state agencies and the natural gas pipeline industry to minimize the potential 

environmental impacts of the construction of pipeline projects in general. The EI employed by KMLP 

would monitor activities as described in the 2013 FERC Plan and Procedures.

The EIs’ responsibilities would include verifying that environmental obligations, conditions, and 

other requirements of permits and authorizations are met. Both Magnolia and KMLP have requested 

deviations from the Procedures, as described in detail in section 4.4.3. Although adequate justification 

has been provided for these alternative measures, Magnolia and KMLP would be required to otherwise 

comply with the requirements of the Procedures. The EIs would inspect construction and mitigation 

activities to verify environmental compliance.

Magnolia and KMLP would conduct environmental training for each of their EIs to familiarize 

them with project-specific issues and requirements. Magnolia and KMLP would also incorporate 

environmental requirements and specifications in contractor bid documents; provide the contractors with 

copies of environmental permits, certificates, and clearances; and conduct environmental training for 

contractor personnel prior to and during construction, as needed, to make them aware of the 

environmental requirements at each facility.

In addition to Magnolia’s and KMLP’s environmental compliance activities, 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, FERC staff would continue to monitor affected areas during operation to verify successful 

restoration. Additionally, FERC staff would conduct annual engineering safety inspections of the LNG 

terminal throughout the life of the facility.

 

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.
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2.5 CONSTRUCTION PROCEDURES

This section describes the general procedures proposed by Magnolia and KMLP for construction 

activities at the LNG terminal and KMLP facilities. Refer to section 4 for more detailed discussions of 

proposed construction and restoration procedures as well as additional measures that we are 

recommending to avoid or reduce environmental impacts.

Under the provisions of the Natural Gas Pipeline Safety Act of 1968, as amended, the proposed 

LNG terminal would be designed, constructed, operated, and maintained in accordance with the DOT’s 

Liquefied Natural Gas Facilities: Federal Safety Standards (49 CFR 193) and the NFPA’s Standards for 

the Production, Storage, and Handling of LNG (NFPA 59A). These standards specify siting, design, 

construction, equipment, and fire protection requirements for new LNG facilities. The LNG ship loading 

facilities and any appurtenances located between the LNG ships and the last valve immediately before the 

LNG storage tanks would comply with applicable sections of the Coast Guard regulations in Waterfront 

Facilities Handling Liquefied Natural Gas (33 CFR 127) and Executive Order 10173. 

The proposed pipeline facilities would be designed, constructed, operated, and maintained in 

accordance with DOT regulations in Transportation of Natural and Other Gas by Pipeline: Minimum 

Federal Safety Standards (49 CFR 192). Among other design standards, these regulations specify

pipeline material selection; minimum design requirements; protection from internal, external, and 

atmospheric corrosion; and qualification procedures for welders and operations personnel. 

Magnolia and KMLP would be required to implement all conditions in the Certificate or 

authorization issued by the Commission for the Magnolia LNG and Lake Charles Expansion Projects, 

respectively. Magnolia would implement its project-specific Plan and Procedures, which are based on the 

2013 FERC Plan and Procedures. We have reviewed Magnolia’s project-specific Plan and Procedures 

and found them to be acceptable. KMLP would implement the 2013 FERC Plan and Procedures. Both 

Magnolia and KMLP have requested deviations or variances from the FERC Procedures. Detailed 

information regarding these deviations is provided in section 4.4.3.

To prevent contamination of soils within nearby wetlands, waterbodies, and other sensitive 

resources during construction, Magnolia and KMLP would develop and implement project-specific spill 

prevention and response procedures in accordance with the requirements of 40 CFR 112. Magnolia 

would implement its project-specific Spill Prevention Plan during construction and its Spill Prevention, 

Control, and Countermeasures Plan (SPCC Plan) during operation of the LNG terminal. Similarly, 

KMLP would implement its SPCC Plan during construction and operation of the KMLP facilities. These 

plans would outline potential sources of releases at the sites, measures to prevent a release to the 

environment, and initial responses in the event of a spill. As discussed in additional detail in section 

4.2.3, at the time of this writing, Magnolia has not provided a Spill Prevention Plan for construction or 

finalized its SPCC Plan for operation of the LNG terminal. We have reviewed KMLP’s SPCC Plan for 

construction and operation and found it to be acceptable.

Magnolia and KMLP would also implement conditions resulting from other permit requirements 

and their respective project-specific plans and measures developed to avoid or minimize environmental 

impacts during construction, which are discussed throughout this EIS.
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2.5.1 LNG Terminal

2.5.1.1 Site Preparation

The existing grade at the site generally varies between 28 and 32 feet above North American 

Vertical Datum of 1988 (NAVD 88),3although the margins of the site along the Industrial Canal and the 

eastern and western boundaries have elevations as low as 0 feet NAVD 88. During site preparation, the 

site would be graded to a standard elevation of 28 feet above NAVD 88. The liquefaction trains would 

have a base elevation of 24 feet above NAVD 88. The LNG storage tanks would have a base elevation of 

17 feet above NAVD 88, but would have a secondary containment wall with a standard top elevation of 

30 feet above NAVD 88. 

The property lines, pipelines, and other features at the LNG terminal site would be surveyed, as 

appropriate, prior to the start of construction activities. In accordance with its project-specific Plan and 

Procedures, Magnolia would install temporary erosion controls along the property line and at existing 

primary property outfalls.

Site clearing would start at the southwestern property line, moving in a west-to-east direction in a 

north-south pattern. After clearing operations are complete, the topsoil would be stripped/grubbed and

stockpiled on the western end of the property for reuse on site, as needed. Debris and grubbed material 

that is not reused on site would be collected and disposed of at an approved off-site disposal facility in 

compliance with local requirements. 

Cut, fill, and rough grading operations would commence in the east-central portion of the site, 

which has the highest elevation. Fill would be moved to lower areas, the most significant of which are

located in the northeast and southwest portions of the LNG terminal site. At this time, drainage swales

would also be installed and erosion control measures would be installed and maintained as needed. 

In parallel with the cut, fill, and rough grading operations, work on the LNG truck and heavy-haul 

roads would begin. Work on the remaining plant roads, drainage system, parking lots, and temporary 

facilities would continue as the cut, fill, and rough grading operations are completed. In order to increase 

the load-bearing capacity of the soil, Magnolia would introduce an engineered grout into the ground to 

modify the physical characteristics of the soil along the heavy haul road, resulting in the surface property 

being similar to that of a soft rock (see section 4.2.3.1). The other roads at the LNG terminal would be 

composed of a limestone cover, an asphalt cover over a limestone base, or equivalent composition.

2.5.1.2 Materials and Equipment Delivery and Off-site Concrete Batch Plant

Due to the DII construction yard’s location immediately adjacent to the LNG terminal site, the 

majority of the materials required during construction of the LNG terminal (including the liquefaction 

train modules, LNG storage tank inner walls, concrete and steel pilings, sheet piling, rock armoring, 

specialized mooring equipment, and miscellaneous construction materials) would be delivered to the yard 

via barge. Water access to the DII construction yard would be via the Intracoastal Waterway, the 

Calcasieu River, and the Industrial Canal. From the construction yard, materials would be offloaded and 

delivered to the LNG terminal site using the heavy haul road. 

 

3 A vertical datum is an elevation of “0 feet” that is used as a reference point so that heights of other points can be assigned using a consistent 

system of measurement. NAVD 88 is the official vertical datum for the conterminous United States and Alaska (National Geodetic Survey, 

2014).
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Deliveries of construction materials to the site by truck are expected to be primarily limited to 

concrete trucks. Concrete required for construction of the LNG terminal would be provided during the 

first 19 months of construction by an existing, off-site concrete batch plant located within a 3- to 5-mile 

radius of the LNG terminal. Roadway and marine transportation of materials to the site during 

construction are discussed in additional detail in section 4.9.6.1.

2.5.1.3 Facility Foundations

Magnolia would support the structures at the LNG terminal site using deep foundations consisting 

of either 24-inch-diameter pre-stressed concrete piles or open-ended steel pipe piles. Most structures 

(e.g., liquefaction trains, LNG storage tanks, control/admin building) would be supported by 

24-inch-diameter precast concrete piles; the LNG loading platform, breasting dolphins, and mooring 

dolphins would be supported by open-ended steel pipe piles with 48-, 96-, and 54-inch diameters, 

respectively.

A total of approximately 5,000 pre-stressed concrete pilings would be required to create the 

foundations for the LNG storage tanks and other process equipment foundations and structures. The 

proposed foundation arrangement for each LNG storage tank includes the use of 1,508 pre-stressed 

70-foot-long concrete piles, resulting in a combined total of 3,016 piles. 

Pile driving activities would occur 10 hours per day, up to 7 days per week; however, due to prework coordination and start-up activities, actual pile driving operations (hammering) are expected to 

occur for only about 8 hours per day. Onshore piles would be driven by seven or eight hydraulic piling 

rigs. Marine piles would be driven by between two and four hydraulic pile rigs, which may include both 

land-based and floating rigs. As indicated in table 2.5.1-1, pile driving operations would take place over a 

total of about 16 months during the first 2 years of construction.

TABLE 2.5.1-1

Pile Driving Activities Associated with Construction of the LNG Terminal

Facility Component

Number of 

Pile Driving 

Rigs Duration

Year 1 Year 2

1

st

Quarter

2

nd

Quarter

3

rd

Quarter

4

th

Quarter

1

st

Quarter

2

nd

Quarter

3

rd

Quarter

Onshore Pile Driving 

Activities

7 to 8

LNG storage tanks 120 days

Liquefaction trains 180 days

Marine Pile Driving 

Activities

2 to 4

LNG loading and ship 180 days

berthing area

Magnolia has stated that it would perform hydro-acoustic monitoring during the initial pile testing 

to determine the actual sound pressure levels generated by pile driving activities. If monitoring indicates 

that sound pressures would be above acceptable thresholds (detailed discussions of acceptable thresholds 

for aquatic resources and nearby noise sensitive areas are provided in sections 4.6.2.1 and 4.11.2.2, 

respectively), mitigation measures would be considered and implemented. Magnolia has stated that the 

following mitigation measures would be considered:

 minimizing impact energy to the lowest practical level to reduce the resulting noise 

generated by driving the pile;
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 implementing soft starts (an initial series of low energy impacts on the pile) to allow 

aquatic resources an opportunity to leave the area;

 placing cushion blocks consisting of wood, nylon, or micarta between the pile and 

hammer to minimize the noise generated while driving the pile;

 using bubble curtains around the pile to reduce noise levels; and 

 using vibratory pile driving, which generates lower sound pressure levels.

2.5.1.4 LNG Loading and Ship Berthing Facilities

Construction of the LNG loading and ship berthing facilities includes the following primary tasks, 

which are described in the following sections:

 dredging of the ship berthing area;

 placement of sheet pile bulkhead and rock armoring;

 construction of the jetty platform and the breasting and mooring structures; and

 construction of the aids to navigation structures.

Dredging of the Ship Berthing Area

Magnolia would dredge the ship berthing area to an elevation of 44 feet below NAVD 88, which 

includes 2 feet of advanced maintenance and overdredge allowance.

4

 The sides of the berthing area 

would be contoured at a 3:1 slope. Magnolia would install rock armoring to provide scour protection 

from propeller wash on the slope parallel to the shoreline. A combination of onshore excavation and 

dredging would be used to remove a total of 993,750 yd3 of sediments and soils from the ship berthing

area, which would be recessed into the northern boundary of the LNG terminal site. Based on a proposed 

final grade elevation for the LNG terminal site of 28 feet above NAVD 88, the site would require 

approximately 131,200 yd3 of upland soils to be excavated and relocated on the terminal site using 

backhoes, front-end loaders, bulldozers, and similar equipment. Following the excavation and relocation 

of upland soils, approximately 862,550 yd3 of sediment and soil would be removed from the 16.2-acre 

ship berthing area (of which 6.4 acres are existing wetlands or uplands within the LNG terminal site and 

9.8 acres are existing water bottoms or submerged areas) using a hydraulic cutterhead dredge. The dredge 

would swing back and forth to slowly cut away the nearshore sediments and shoreline to establish the 

specified dimensions and depths of the berthing area.

Magnolia proposes to deposit 862,550 yd3 of material dredged from the ship berthing area within

the dredge material placement area depicted on figure 2.2.1-2. Between 2010 and 2013, CB&I excavated 

a 1,000-foot-long by 2,000-foot-wide borrow pit at the north end of the site, which is expected to have a 

potential capacity to contain approximately 300,000 to 350,000 yd3 of dredge spoil, once dewatered (as 

described in section 4.3.2.2). Because the anticipated 862,550 yd3 of dredge materials would not be 

contained within the borrow pit and would require the use of the larger 141.8-acre site, Magnolia would 

construct approximately 10,000 linear feet of 5- to 10-foot-high earthen dikes along the perimeter of the 

area in order to contain the dredge material during deposition. Once the dredge material has dewatered 

and settled, Magnolia would level the earthen dikes on the site. It is estimated that deposition of 

862,550 yd3 of dredge material, given the minimal available capacity of the borrow pit (300,000 yd3), 

 

4

In order to accommodate fully loaded LNG carriers and provide clearance during low tide, the design depth of the recessed berthing area is 

42 feet below NAVD 88.
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would permanently raise the 141.8-acre area approximately 3 feet above the current grade. A detailed 

discussion of dredge material placement alternatives considered is presented in section 3.3.4.

Dredge material would be transferred to the placement area via a 1-mile-long, 24-inch-diameter 

steel pipeline. The 252 million gallons of effluent produced by the settlement of dredge spoil within the 

placement area would be pumped back to the Turning Basin at the eastern end of the Industrial Canal 

using an effluent pipeline, where it would be discharged in accordance with federal and state permit 

requirements. 

The dredge material and effluent pipeline routes are illustrated on figure 2.2.1-2 and appendix B. 

Within the Industrial Canal, the dredge material pipeline would be temporarily floated between dredging 

operations within the recessed berthing area and the eastern end of the canal. Aboveground portions of 

the dredge material and effluent pipelines would be temporarily installed using interlocking sections of 

pipe. The two pipelines would be constructed with a 20-foot offset within a 75-foot-wide pipeline rightof-way. Land along the dredged material and effluent pipeline routes has been graded and graveled; 

therefore, no clearing or grading would be required. 

The pipe would be delivered to the construction area in straight sections and bent to conform to 

changes in the direction of the pipeline alignment and natural ground contours. Individual joints of pipe 

would be bent to the desired angle in the field using a track-mounted, hydraulic pipe-bending machine. 

Alternatively, pre-fabricated fittings may be used. Side boom tractors would be used to place the pipe on 

the right-of-way. 

The crossing of Big Lake Road would be conventionally bored per local or state permit 

requirements. To complete the horizontal bore of Big Lake Road, pits would be excavated on the east and 

west sides of the road (see appendix B). A boring machine would be lowered into one pit, and a 

horizontal hole would be bored to a diameter equal to the diameter of the pipe (or casing, if required) at 

the depth of the pipeline installation. The pipeline section would be pushed through the bore to the 

opposite pit. If additional pipeline sections are required to span the length of the bore, they would be 

welded to the first section of the pipeline in the bore pit before being pushed through the bore. After the 

pipe is lowered into the trench, the trench would be backfilled, normally using a bulldozer or tracked 

backhoe. Backfill usually consists of the material originally excavated from the trench. Any excess 

excavated materials or materials unsuitable for backfill would be disposed of in accordance with 

applicable regulations. During backfilling, special care would be taken to minimize erosion, restore the 

natural contour of the ground, and restore surface drainage patterns as close to pre-construction conditions 

as practicable.

Prior to initiating dredging operations, the dredge material and effluent pipelines would be 

hydrostatically tested using approximately 1 million gallons of water from the Industrial Canal. After the 

hydrostatic test is completed, the water would be tested and treated (if necessary), and discharged back to 

the Industrial Canal. 

Upon completion of dredging and dewatering activities, Magnolia plans to grade the earthen 

dams and interior of the dredge material placement area and reseed in order to facilitate drainage and 

minimize erosion, returning the site to upland meadow or pasture. Additional information regarding 

revegetation is included in section 4.5.2.1. The dredge material and effluent pipelines would be removed, 

with the exception of the 250-foot segment of each pipeline beneath Big Lake Road. This segment of the 

pipelines would be grouted and left in place in accordance with Louisiana DOTD and Calcasieu Parish 

Police Jury permits.
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Placement of Sheet Piling and Rock Armoring

The LNG loading facility would be constructed using a combination of 2,005 feet of steel sheet 

pile bulkhead, which is expected to be installed using a hydraulic pile driver. Rock armoring would be 

installed at the base of the steel sheet pile bulkhead, along the east and west ends of the marine basin, and 

around the base of the LNG loading platform and breasting dolphin piles to provide protection to the 

bulkhead and shoreline from erosion caused by scour from the LNG vessels. The rock armoring would be 

delivered to the DII construction yard by barge, transported to the berthing area using the heavy haul 

road, and installed by crane or long-reach backhoe placement of the rocks into the water. Magnolia 

estimates that shoreline protection at the base of the sheet pile wall around the basin would consist of an 

about 2-foot-thick bedding stone layer with a 3-foot-thick armor stone layer. 

Construction of the Jetty Platform and the Breasting and Mooring Structures

The 128-foot-long by 70-foot-wide LNG loading platform would be constructed of reinforced 

concrete (see figure 2.5.1-1). The LNG loading platform would be supported by 24 concrete cylinder 

piles driven into the bed of the Industrial Canal and by the sheet pile bulkhead. Based on preliminary 

information, the tip of these piles would be installed to a depth of 110 feet below NAVD 88 using a 

hydraulic pile driver. Installation of the sheet pile is described above. 

Four primary breasting dolphins, plus one center protective breasting dolphin with a bumper 

panel only (see figure 2.5.1-1), would be constructed by installing 96-inch-diameter steel pilings in the 

water adjacent to the terminal jetty using a hydraulic pile driver. The piles would provide support for the 

fendering system (bumpers designed to prevent damage to boats and the berthing structures during 

docking) and equipment required to moor both LNG carriers and barges. Six mooring points would be 

constructed on shore, landward of the steel sheet pile bulkhead, to provide additional mooring leads for 

the design range of LNG vessels. 

The LNG loading platform would support three 16-inch-diameter LNG loading arms and one 

16-inch-diameter vapor return arm for loading the LNG carriers, and one 8-inch-diameter LNG loading 

arm with a piggyback mounted 6-inch-diameter vapor return arm for loading LNG barges. Additional 

equipment installed on the LNG loading platform would include three elevated firewater monitor towers, 

platform-level firewater monitors, a dry chemical system, a marine gangway, LNG process piping, and 

utilities. All marine structures would be connected by walkways extending east and west to the breasting 

dolphins. A 26-foot-wide by 128-foot-long combination pipe and roadway trestle located landward of the 

sheet pile bulkhead would connect the LNG loading platform to the onshore LNG terminal, as depicted in

figure 2.5.1-1. 

2.5.1.5 Liquefaction Trains

The liquefaction trains would be designed, constructed, operated, and maintained in accordance 

with the DOT Federal Safety Standards for Liquefied Natural Gas Facilities at 49 CFR 193 and would 

meet the LNG Standards under NFPA 59A. Each liquefaction train would be broken down into five main 

process modules, which would be fabricated off site at existing fabrication yards and transported to the 

DII construction yard via barge in a specific sequence to allow efficient assembly of the liquefaction 

trains. As described in section 2.5.1.2, the barges would deliver the LNG process modules and other 

equipment to the existing dock at the DII construction yard located immediately east of the LNG terminal 

site. The modules would be transferred from the barge and into final position using self-propelled 

modular transporters. The self-propelled modular transporters would wheel each process module 

sequentially into position and then lower each module onto piled supports. Smaller modules would be 

lifted into position by a crane(s), as necessary.
2-33
2-34

2.5.1.6 LNG Storage and Processing Facilities

One of the more labor-intensive and time-consuming activities would be the construction of the 

two LNG storage tanks. After site preparation, the LNG storage tanks would be erected on site using 

conventional construction techniques. Figure 2.5.1-2 depicts the design of a typical LNG storage tank. 

The proposed foundation arrangement for each of the two LNG storage tanks includes 1,508 70-foot-long 

pre-stressed concrete piles (3,016 total piles). Installation of the piles is described in section 2.5.1.3. 

Following the installation of the foundation, construction of the tank base and post-tensioning of the outer 

concrete container wall would occur. In parallel to construction of the outer concrete container wall, the 

steel dome roof and suspended deck would be constructed on temporary supports inside the outer 

container of each storage tank, to be later air-raised into position. The bottom carbon steel vapor liner 

would then be installed. On top of the outer concrete container wall, the steel dome roof compression 

ring would be cast into the concrete and then the steel dome roof would be air-raised into position and 

secured to the compression ring.

Roof nozzles, penetrations, and studs would be installed, and steel reinforcement and concrete 

covering of the steel dome roof would occur. Concurrent with the installation of roof nozzles and 

penetrations, work would begin on the inner 9-percent nickel steel container, including the secondary 

bottom, bottom corner protection, and inner container annular and bottom plates. The inner 9-percent 

nickel steel container would be erected. Internal accessories such as pump columns, bottom and top fill, 

instrument wells, and purge and cool-down piping would be installed, followed by installation of roof 

platforms, walkways, pipework, and pipe supports. 

To ensure that the tanks are capable of operating at the design pressure, testing of the outer and 

inner tanks would be completed in accordance with the American Petroleum Institute Standard 620. The 

integrity of the outer tanks would pneumatically tested, and process piping would be installed from the

tank top down to grade. The inner 9-percent nickel steel container of the two LNG storage tanks would 

be hydrostatically tested using water from the Industrial Canal. The total duration of the hydrostatic test 

from start of filling to emptying is expected to be approximately 4 weeks. It is anticipated that each 

246-foot-diameter inner tank would be filled to a height of 73.5 feet, requiring a volume of approximately 

26.2 million gallons of water to be appropriated from the Industrial Canal. Hydrostatic testing of the 

LNG storage tanks is anticipated to be conducted one at a time, allowing the water to be reused. After the 

hydrostatic test is completed for the second LNG storage tank, the water would be pumped out of the 

tank, tested and treated (if necessary), and discharged back to the Industrial Canal. 

Because water from the nearby Industrial Canal would be used to perform the hydrostatic testing 

of the LNG storage tanks, the inside of the tank walls would be power washed using approximately 

27,000 gallons of potable water from the tie-in to the Calcasieu Parish District No. 12 Water Works line 

in order to remove any silt particles that may adhere to the inner tank walls. Typically, a small boat 

would be installed in the tank’s interior prior to the start of the hydrostatic test. The small boat floats up 

with the rising water level and, when the tank is about to be emptied, an operator gets into the boat and 

power washes the sides of the tank as the water level recedes. Magnolia does not anticipate the use of any 

biocides or additives in the hydrostatic test water. Following the discharge of hydrostatic and power wash 

water, a resilient blanket would be installed on the outside of the inner tank shell. The required 

instrumentation would then be installed inside the tank and annular space. Perlite insulation would be 

expanded into the tank annular space using vibration methods, and the suspended deck blanket insulation 

and external piping insulation would be installed. A visual inspection would be completed. The LNG 

pumps would then be installed, and the storage tanks would be purged with nitrogen to a positive gauge 

pressure, followed by the purge and cool-down.
2-35
2-36

2.5.1.7 LNG Truck Loading Facilities

After site preparation, Magnolia would install piling and foundations for the pipe rack, truck 

loading shelter, loading area, weigh scale, and associated equipment. Figures 2.1.1-2 and 2.1.1-4 depict 

the basic layout of the LNG truck loading facilities. The LNG spill containment system and truck loading 

pipe racks and shelter would then be installed. Once these components are set in place and secured on the 

foundations, piping from the LNG storage tank area to the LNG truck loading area; metering equipment; 

loading arms; and electrical, instrument, and gas detection systems would be installed. Concurrently, fire 

protection, including a high-expansion foam system and firewater system, would be installed in the LNG 

truck loading area (see discussion in section 2.7.1). 

LNG truck loading systems and controls would be verified and tested for proper functioning

before being placed into service, in accordance with ASME standards. All valves would be aligned in 

accordance with the facility commissioning procedures, including installation of car seals (valve locks)

where necessary. LNG piping systems would be purged with nitrogen and dried out in accordance with 

the facility dry-out procedures, followed by the facility cool-down phase.

2.5.1.8 Magnolia Meter Station and Interconnect Pipeline

As described in section 2.0, KMLP would construct and operate its Magnolia Meter Station and 

interconnect pipeline within the boundaries of the LNG terminal site. Construction of this meter station 

would not commence until site preparation (e.g., clearing, grading, and compacting) is completed by 

Magnolia (see section 2.5.1.1). Excavation would be performed to accommodate the reinforced concrete 

foundations required for the metering equipment, pigging equipment,5and buildings. Forms would be 

set, rebar installed, and concrete poured and cured in accordance with applicable standards. Removed 

spoil would be backfilled into the excavation and compacted in place. Excess spoil would be distributed 

across the meter station site or used as backfill elsewhere within the KMLP facilities.

Measurement equipment typically would be delivered to the meter station site via trucks (up to 

12 truck deliveries are anticipated per day). The measurement buildings would be offloaded and stored 

on site. The buildings would then be positioned on the foundation, leveled, grouted, and secured. Meter 

station piping connections would be flanged, screwed, or welded. Welded connections would be 

inspected visually, radiographically, or by some other nondestructive testing method. Welding activities 

would comply with the DOT minimum safety requirements at 49 CFR 192 and the requirements of the 

latest edition of the American Petroleum Institute Standard 1104. After welding, the pipe joints would be 

coated; the pipe coating would be inspected for defects, with special attention given to all field-applied 

coatings, and any damage would be repaired.

Hydrostatic testing of piping and related components would be conducted using water from the 

City of Lake Charles in accordance with the DOT safety standards at 49 CFR 192 and applicable permit 

conditions to verify the pipe integrity and ensure its ability to withstand the maximum allowable 

operating pressure (MAOP). Before being placed into service, all controls and safety equipment would

be checked and tested for proper functioning.

General construction activities and storage of construction materials, equipment, and spoil would

be confined to the Magnolia Meter Station and interconnect pipeline footprints. Debris and wastes 

generated during construction would be disposed at a licensed commercial disposal facility in accordance 

with applicable regulations. All construction workspaces associated with the Magnolia Meter Station

 

5 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.
2-37

would be restored and stabilization measures installed in a timely manner in accordance with the FERC 

Plan and Procedures.

2.5.1.9 Site Restoration

Following construction, the LNG terminal site would be restored in accordance with Magnolia’s

project-specific Plan and Procedures. Because the entire 114.0-acre site would be used during operation 

of the LNG terminal, no planting of native trees or restoration of the site to original grade or vegetation

communities is proposed. However, the 33.7 acres of the site not occupied by buildings, roads, 

compacted aggregate, or the recessed berthing area would be restored with native vegetation 

recommended by the U.S. Department of Agriculture’s (USDA), Natural Resources Conservation Service 

(NRCS) and maintained as open upland (e.g., upland meadow). Weather and soil conditions permitting, 

these areas would be seeded within 6 working days after final grading is complete. Seeding permanent 

vegetation is expected to occur during the growing season; however, if seeding occurs outside the 

growing season, temporary erosion control measures would be left in place until the next growing season, 

when reseeding efforts would take place. Revegetated areas would be monitored following construction 

for the first and second (as necessary) growing seasons.

2.5.2 KMLP Facilities

2.5.2.1 Header Pipelines

Site Preparation

Prior to the start of construction, KMLP would survey and mark the boundaries of the 

construction workspaces. Avoidance areas (e.g., wetland boundaries) would be marked or flagged and

appropriate fencing would be installed around the perimeter as required. As required by the FERC Plan 

and Procedures, temporary erosion controls would be installed after initial soil disturbance, where 

necessary, to minimize erosion and would be maintained throughout construction as needed.

Clearing, Grading, and Fencing

The construction workspace would be cleared and graded to remove brush, trees, roots, and other 

obstructions, such as large rocks and stumps. To minimize soil erosion, vegetation within some portions 

of the construction workspace would be left in place, and some non-woody vegetation would be mowed. 

Where necessary, the construction workspace would be graded to create a safe work area, accommodate 

pipe-bending equipment, and provide sufficient space to accommodate working and passage of heavy 

construction equipment. Pre-construction contours and drainage patterns would be maintained to the 

extent practicable. 

A fence installation crew, typically operating in conjunction with the clearing crews, would cut 

and brace fences along the proposed high and low pressure header routes where necessary and 

temporarily fence off avoidance areas. Temporary gates would be installed to control livestock and limit 

public access, where necessary.

Although no forested land occurs within the construction workspaces, any trees present would be 

removed from the construction workspaces only where necessary for construction purposes. Trees and 

other vegetation debris would be chipped, burned, or disposed of according to applicable regulations. 

Burning, if used, would be conducted in a manner to minimize fire hazard, prevent heat damage to 

surrounding vegetation, and in accordance with state and local burn permits and regulations. Stumps 

would be buried only in non-tilled land and with the agreement of the landowner. Off-site disposal of 
2-38

materials would be at commercial facilities or at other approved locations in accordance with applicable 

laws and regulations.

Grading would occur after the construction workspace has been cleared and any stumps have 

been removed; however, KMLP expects that minimal grading would be required at most facility 

locations. In annually cultivated agricultural areas (or where crops are rotated), KMLP would strip and 

segregate up to 12 inches of topsoil; if the topsoil is less than 12 inches in depth, the actual depth of the 

topsoil would be removed and segregated. In non-agricultural areas, if requested by a land management 

agency or landowner, KMLP would strip and segregate up to 12 inches of topsoil, unless topsoil 

replacement is deemed more efficient by the contractor or more desirable by the landowner. Along the 

header pipelines, excavated materials would typically be stored on the non-working side of the 

construction workspace; however, site-specific conditions may require that the topsoil be stored or placed 

on the working side adjacent to the trench or at the edge of the construction workspace.

Trenching

Rotary wheel ditching machines, backhoes, or rippers would be used to excavate the header 

pipeline trenches to a depth sufficient to allow approximately 5 feet of coverage of the header pipelines, 

which would be in accordance with the DOT standards at 49 CFR 192; the trench depth could be up to 

15 feet to facilitate construction under existing drainage canals. Before construction begins, KMLP 

would contact the Louisiana one-call service to identify and flag existing buried utilities to ensure the 

header pipelines would be constructed so as not to interfere with existing utilities. Specific procedures for 

crossing utility lines as well as agricultural areas are discussed in the Special Construction Procedures

section below. All existing permanent survey and reference monuments within the construction 

workspace would be protected during construction.

KMLP would install erosion controls in accordance with the FERC Plan and Procedures to 

minimize erosion during construction. In addition, measures would be taken to minimize the flow of 

water into and/or through the trench and into wetlands and waterbodies. KMLP’s proposed pipeline 

installation across wetlands and waterbodies, as well as other specialized construction procedures, are 

described below (see Special Construction Procedures).

Pipe Stringing, Bending, Welding, and Lowering-In

Prior to header pipeline construction, the pipe would be moved into the area by rail or truck. The 

pipe segments (or joints) would be positioned along the construction right-of-way parallel to the 

centerline of the trench so they are easily accessible to construction personnel. The joints are typically

strung on the working side of the trench for bending, welding, coating, and lowering-in operations and the 

associated inspection activities.

Track-mounted hydraulic pipe-bending machines would be used to bend the pipe in the field to 

the required alignment and to match the existing natural ground contours. Following bending, the ends of 

the pipe sections would be aligned and welded together, typically with the use of external line-up clamps 

or internal traveling line-up clamps. As each weld is completed, the pipe would be placed on supports 

adjacent to the trench. Each weld would be inspected visually, radiographically, or by some other 

nondestructive testing method. Bending, welding, and coating activities would comply with the DOT 

minimum safety requirements at 49 CFR 192 and the requirements of the latest edition of the American 

Petroleum Institute Standard 1104.

Prior to shipment to the site, an external protective coating is applied to the pipe to prevent 

corrosion, except a small area at the end of the pipe joint. After welding, the pipe joints would be coated 

with similar or compatible materials. The pipe coating would be inspected for defects, with special 
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attention given to all field-applied coatings, and any damage would be repaired prior to lowering the pipe 

into the trench.

In some locations, such as within wetlands, it may be necessary to provide negative buoyancy to 

the pipe by means of set-on concrete weights, concrete coating, pipe sacks, and/or soil anchors. Set-on 

weights and concrete coating may be fabricated or purchased off site and installed. No concrete-coating 

activities would occur within 100 feet of waterbodies or wetlands.

Side-boom tractors would be used to lower the pipe into the trench. The trench would be cleared

of any debris or foreign material. If the trench bottom is rocky, sandbags, support pillows, or other 

acceptable pipe padding material would be used to protect the pipe coating and, in areas where the 

excavated trench material may damage the pipe, the pipe would be protected with a protective wrap of 

rock shield. Topsoil would not be used to pad the pipe. The pipe would be carefully placed in the trench

to ensure proper alignment and to prevent damage to the pipe coating. Trench dewatering may be 

required in certain locations in order to prevent the pipe from floating and to allow certain limited 

activities in the trench. If required, trench dewatering would be performed in accordance with the FERC

Plan and Procedures.

Backfilling

After the pipeline is lowered into the trench and adequately protected, the trench would be 

backfilled using a bulldozer, backhoe, auger-type backfilling machine, or other suitable equipment. 

Backfill typically consists of the material originally excavated from the trench. In areas where topsoil has 

been segregated, the subsoil would be placed in the trench first and then the topsoil would be placed over 

the subsoil. Backfilling would occur to grade or higher, with use of excess material, to accommodate any 

future soil settlement. Any material unsuitable for backfill would be disposed of in accordance with 

applicable regulations. Subsoil and topsoil tilling would be done at the request of the landowner.

During backfilling, special care would be taken to minimize erosion potential by restoring the 

natural contour of the ground and surface drainage patterns as close to pre-construction conditions as 

practicable. In order to minimize the possibility of subsurface water flow into the trench due to local 

topography, sand bags or foam-type trench breakers would be installed where necessary. In other areas 

(e.g., ditch and stream crossings), the trench backfill would be solidly compacted. Where the header 

pipelines cross streams, wetlands, or groundwater, permanent trench plugs may be installed as appropriate

to minimize the flow of water from the intersected body to and from the trench.

Testing

Once pipeline installation and backfilling are completed, the header pipelines would be cleaned 

using a cleaning pig and hydrostatically tested in accordance with the DOT safety standards at 

49 CFR 192 and applicable permit conditions to verify its integrity and ensure its ability to withstand the 

MAOP. Hydrostatic testing of the header pipelines would be conducted in segments, using a total of 

approximately 336,000 gallons of water obtained from the City of Eunice. 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. After testing is 

completed, the line would be depressurized and the water discharged by means of displacement pigs. 

Hydrostatic test water discharges would be performed in accordance with all applicable state 

water regulations and federal and state discharge requirements. The water would be discharged over land 

into a well-vegetated upland area using energy dissipation devices as needed to minimize erosion and 

sedimentation. No chemicals would be added to the pipeline test water, nor would they be used to dry the 
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pipeline after the testing. Section 4.3.2.2 provides additional information on hydrostatic testing and test 

water discharge.

Cleanup and Restoration

After the trench is backfilled, KMLP 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, KMLP would finish grade and restore all disturbed areas 

as closely as practicable to pre-construction contours. Site contouring would be accomplished using 

acceptable excess soil from construction. Within agricultural lands, restoration and revegetation would be 

conducted in accordance with the FERC Plan and landowner requirements. Non-agricultural land would

be revegetated in compliance with seed, fertilizer, and soil additive recommendations obtained from the 

local soil conservation authority. 

Special Construction Procedures

Agricultural Areas

As discussed in detail in section 4.8.1, the majority of the land affected by the header pipelines 

(96 percent) would be within agricultural lands. KMLP would construct through agricultural areas in 

accordance with the FERC Plan to minimize impacts on current agricultural uses. Prior to construction 

through these areas, KMLP would consult with landowners to attempt to locate existing drain tiles.

In agricultural lands that are annually cultivated or have rotated crops, KMLP would remove the 

topsoil to its actual depth, up to a maximum of 12 inches, and stockpile it separately from the subsoil 

excavated from the pipeline trench. During construction, KMLP 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.

Following installation of the header pipelines, agricultural areas would be restored in accordance 

with the FERC Plan. If drain tiles are exposed or damaged during construction activities, KMLP would 

implement measures to repair/replace them after communication with the landowner and in accordance 

with applicable regulatory guidelines.

Road and Utility Line Crossings

The low pressure header pipeline would cross one paved road (Fournerat Road) and one gravel

road (Coulee Road). At both road crossings, the header pipeline would be installed using the 

conventional bore method. The conventional bore method involves excavating a pit on each side of the 

feature, boring a hole under the road at least equal to the diameter of the pipe, and pulling a prefabricated 

pipe section through the borehole.

The header pipeline would be installed at a minimum depth of 5 feet below the center of the road, 

or as required by applicable road crossing permits and approvals, and would be designed to withstand 

anticipated external loadings. KMLP would implement procedures to protect workers and the public

during road crossing activities; traffic warning signs, detour signs, and other traffic control devices would 

be used as required by federal, state, and local departments of transportation and other regulating bodies.

Where existing underground utilities are crossed, the header pipeline would be installed at an 

appropriate depth, either over or under the existing utility, to meet depth of cover and utility separation 

requirements in accordance with 49 CFR 192 and in compliance with pipeline crossing agreements 
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negotiated with the existing pipeline operators. At least 12 inches of separation between the header 

pipeline(s) and the existing utility line would be maintained, where feasible. 

Wetland Crossings

As discussed in section 4.4.2.1, less than 1 percent of the land affected by construction of the low 

and high pressure header pipelines would be within wetlands. Wetland impacts would be limited to a 

0.1 acre area along the high pressure header pipeline route. Within this wetland, KMLP would construct

the high pressure header pipeline in accordance with applicable federal and state permits and the FERC 

Procedures. Overall, 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.

In wetlands, vegetation would be cut just above ground level, leaving existing root systems intact. 

Immediately after initial ground disturbance, erosion control devices would be installed at the edges of the 

construction workspaces in wetlands where there is a possibility for spoil to flow into undisturbed areas 

of the wetlands. Up to 12 inches of topsoil would be stripped and segregated from the area disturbed by 

trenching, except in areas with standing water or saturated soils. If the trench contains water at the time 

of crossing, trench plugs would be installed to minimize sediment discharges into the wetland from the 

open trench. 

After the pipeline is lowered into the trench and backfilled, the disturbed areas would be graded 

to pre-construction contours and trench plugs may be installed as appropriate to minimize the flow of 

water from the intersected body to and from the trench. Restoration would be in accordance with the 

FERC Procedures and monitored until revegetation is successful.

Waterbody Crossings

Seven waterbodies (two intermittent and five ephemeral) would be affected by construction and 

operation of the low pressure and high pressure header pipelines. 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. KMLP would implement the measures in the FERC 

Procedures and appropriate best management practices (BMP) to minimize the extent and duration of 

construction disturbance of waterbodies.

In general, KMLP would construct the header pipelines across waterbodies using a 75-foot-wide 

construction right-of-way. KMLP would cross all streams that have perceivable flow at the time of 

crossing using a dry crossing method (flume or dam-and-pump). The open-cut crossing method would be 

used to cross ephemeral streams and ditches with no perceptible flow at the time of crossing. The 

equipment required to complete a dry crossing would be on site as a contingency in case flow should 

begin in ephemeral streams during construction. KMLP would obtain all necessary waterbody crossing 

permits from federal, state, and local agencies.

Temporary equipment bridges would be placed across waterbodies to allow construction 

equipment to cross with minimal impact on the waterbody. Temporary equipment bridges may consist of 

prefabricated construction mats, rail flat cars, flexi-float or other temporary bridges (Bailey bridges), or 

flume installations. Flume installations include suitably sized flumes and a travel surface consisting of 

rock fill, sand bags, timber mats, or timber riprap. At all temporary equipment bridge locations, care 

would be taken to minimize disturbance of the waterbody bank and bottom.

KMLP would place the pipeline a minimum depth of 5 feet below the bottom of the channel. 

Material excavated from the trench would be stockpiled at least 10 feet from the water’s edge and 
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generally used as backfill, except where the adjacent upland consists of actively cultivated or rotated 

cropland, or federal or state permits specify differently.

In order to limit the time required for construction of a stream crossing, the right-of-way would

be prepared on either side of the stream prior to the construction of the actual crossing. If grading is 

required, it would be directed away from the waterbody to reduce the possibility of disturbed soils being 

transported into the waterbody.

At small streams along the pipeline headers, a backhoe, clam-dredge, dragline, or other similar 

equipment would be used to excavate the trench. In accordance with the FERC Procedures, instream 

construction activities associated with minor waterbody crossings would be completed within 24 hours, 

unless blasting or other rock breaking measures are required. Sediment barriers (silt fence and/or straw 

bales) would be installed at the waterbody crossing to minimize sedimentation into the waterbody from 

disturbed upland areas.

Dam-and-Pump Crossing Method

The dam-and-pump crossing method involves installation of temporary dams upstream and 

downstream of the waterbody crossing location. For the Lake Charles Expansion Project, the temporary 

dams typically would be constructed using sandbags and plastic sheeting. Following dam installation, 

appropriately sized pumps would be used to dewater the upstream impoundment and transport the stream 

flow around the construction work area and trench to the downstream side. Intake screens would be 

installed at the pump inlets to prevent entrainment of aquatic life, and energy dissipating devices would

be installed at the pump discharge point to minimize erosion and streambed scour. Trench excavation and 

pipeline installation would then commence through the dewatered portion of the waterbody channel.

Following completion of pipeline installation, backfill of the trench, and restoration of stream banks, the

temporary dams would be removed and flow through the construction work area would be restored. 

Flume Crossing Method

The flume crossing method consists of temporarily directing the flow of water through one or 

more flume pipes over the area to be excavated. This method allows excavation of the pipe trench across 

the waterbody underneath the flume pipes without disruption of water flow in the stream. KMLP would 

divert the stream flow through the flumes by constructing two bulkheads, using sand bags or plastic dams, 

to direct the flow through the flume pipes. The bulkheads and flume pipes would be removed following 

completion of pipeline installation, backfill of the trench, and restoration of stream banks.

2.5.2.2 Aboveground Facility Construction Procedures

Construction of Compressor Station 760 and the meter station modifications would adhere to the 

same safety standards and regulations required for pipeline construction. General construction activities 

and storage of construction materials, equipment, and spoil would be confined to the approved

construction workspaces, which would be primarily within the existing meter stations on concrete- and 

gravel-covered ground surfaces. 

Excavation would be performed as needed to install the reinforced concrete foundations required 

for the compression equipment, additional metering equipment, pigging equipment, and buildings. Forms 

would be set, rebar installed, and concrete poured and cured in accordance with applicable standards. 

Removed spoil would be backfilled into the excavation and compacted in place. KMLP would distribute 

the excess spoil across the compressor or meter station sites, or use it as backfill along the header 

pipelines. Debris and wastes generated during construction would be disposed at a licensed commercial 

disposal facility in accordance with applicable regulations.
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As described in section 2.5.1.8 for the Magnolia Meter Station, measurement equipment typically 

would be delivered to the sites via trucks. The measurement buildings would be positioned on the 

foundation, leveled, grouted, and secured. Piping connections would be flanged, screwed, or welded. 

Welded connections would be inspected visually, radiographically, or by some other nondestructive 

testing method. Welding activities would comply with the DOT minimum safety requirements at 

49 CFR 192 and the requirements of the latest edition of the American Petroleum Institute Standard 1104. 

After welding, the pipe joints would be coated; the pipe coating would be inspected for defects, with 

special attention given to all field-applied coatings, and any damage would be repaired.

Hydrostatic testing of piping and related components would be conducted using approximately 

10,000 gallons of municipal water from the City of Eunice in accordance with the DOT safety standards 

at 49 CFR 192 and applicable permit conditions to verify the pipe integrity and ensure its ability to 

withstand the MAOP. Before being placed into service, all controls and safety equipment would be 

checked and tested for proper functioning.

All disturbed surface areas would be restored and stabilization measures installed in a timely 

manner in accordance with the FERC Plan and Procedures. To allow for visual screening, KMLP is 

planning to plant shrubbery along the west, north, and east sides of Compressor Station 760 (see 

additional discussion in section 4.8.5.2). 

KMLP would install chain-link security fence around the perimeter of Compressor Station 760 as 

well as a barbed-wire fence around the perimeter of the larger 40.6-acre property. KMLP would install a 

chain-link fence around the Magnolia Meter Station and would also replace portions of the existing 

security fence at the CGT, TRANSCO, and TGT Meter Stations so as to surround the proposed 

permanent facilities associated with the meter station modifications.

2.6 OPERATION AND MAINTENANCE PROCEDURES 

2.6.1 LNG Marine Traffic along the Waterway

Although LNG carriers and their operation are directly related to the use of the proposed LNG 

terminal, they are not subject to the section 3 authorization sought in this application. The LNG carriers 

arriving at the LNG terminal must comply with all federal and international standards regarding LNG 

shipping. A detailed discussion of design and safety features of LNG carriers is presented in 

sections 2.1.2.1 and 4.12.6. 

Inbound LNG vessels would embark either one or two Lake Charles Pilots at the Calcasieu “CC” 

buoy. During daytime hours, all LNG carriers transiting the Calcasieu Ship Channel with a capacity less 

than 150,000 m3are required to embark one pilot; LNG carriers transiting during nighttime hours or with 

a capacity greater than 150,000 m3are required to embark two pilots. Seagoing LNG barges would be 

required to embark one pilot; inland LNG barges would not be required to transit under the control of a 

pilot.

From the CC buoy, LNG carriers and seagoing LNG barges would transit under command of the 

pilot(s). LNG carriers and seagoing barges would transit approximately 28 nautical miles to the Cameron 

jetties (River Mile 0) and would then continue northbound in the Calcasieu Ship Channel to the channel’s 

intersection with the Intracoastal Waterway at “Devil’s Elbow.” At this intersection, inbound LNG 

vessels would make a turn to the northeast and proceed into the Industrial Canal where tugs would 

maneuver the vessel within the berthing area. The pilot(s) would direct the securing of the lines and 

would turn navigational control back to the captain when the carrier is fastened. Following loading at the 

LNG terminal, the pilot(s) would resume navigational control of the vessel when the mooring lines are let 
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go. Loaded LNG carriers would transit outbound along the reverse route described for inbound LNG 

carriers. 

LNG vessels transiting the Calcasieu River and Ship Channel are typically designated to have a 

moving security zone during transit per Coast Guard regulations at 33 CFR 165.805(a)(2). While in 

transit, LNG vessels are accompanied by a moving security zone that extends 2 miles ahead, 1 mile 

astern, and from shoreline to shoreline on the Calcasieu River (and from channel edge to channel edge in 

the offshore waters of the Calcasieu Ship Channel). As a safety and security precaution, no vessels are 

allowed to meet, cross, or overtake LNG ships in transit or otherwise enter the security zone without the 

express permission of the Coast Guard. At its discretion, the Coast Guard may elect to provide escort 

boats during LNG carrier transits to enforce the moving security zone.

The Coast Guard issued the LOR for the Magnolia LNG Project on February 12, 2015, which 

stated that the Calcasieu Ship Channel is considered suitable for LNG marine traffic The LOR outlines 

conditions for LNG marine traffic in the waterway, including additional resources or assets that would be 

required prior to allowing LNG carriers to transit up the Calcasieu Ship Channel to the LNG terminal.

The COE is responsible for maintenance dredging of the Calcasieu Ship Channel and Industrial 

Canal. Magnolia would be responsible for maintenance dredging of its berthing area. Based on estimated 

shoaling rates in the area, Magnolia estimates that approximately 65,000 yd3 of material would be 

removed from the berthing area every 4 to 5 years based on past shoaling rates within the Industrial 

Canal. Magnolia is working with the Port of Lake Charles to determine maintenance dredging 

requirements and to obtain long-term maintenance dredging capacity. 

2.6.2 LNG Terminal

Magnolia would operate and maintain its facilities in compliance with 49 CFR 193, 33 CFR 127, 

40 CFR 68, NFPA 59A, and other applicable federal and state regulations. Before commencing operation 

of the LNG terminal, Magnolia would prepare and submit to FERC for approval operation and 

maintenance manuals that address specific procedures for the safe operation and maintenance of the LNG 

storage and processing facilities. Magnolia would also prepare an operations manual that addresses 

specific procedures for the safe operation of the ship loading facilities in accordance with 

33 CFR 127.305. Operating procedures are required to address normal operations as well as safe startup, 

shutdown, and emergency conditions.

The estimated 67 personnel employed during operation of the LNG terminal would be trained to 

properly and safely perform their assigned duties. Operators would be trained in the handling of potential 

hazards associated with LNG, cryogenic operations, and the proper operation of all the equipment. The 

operators would meet all the training requirements of the Coast Guard, DOT, Louisiana State Fire 

Marshall, and other regulatory entities.

The LNG terminal’s full-time maintenance staff would conduct routine maintenance and minor 

overhauls. Major overhauls and other major maintenance would be handled by outside maintenance 

contractors specifically trained to perform the required services. All scheduled and unscheduled 

maintenance would be entered into a computerized maintenance management system.

2.6.3 Magnolia Meter Station, Interconnect Pipeline, and KMLP Facilities

KMLP would operate and maintain its facilities in compliance with the DOT regulations at 

49 CFR 192; the FERC Plan and Procedures (except where deviations are justified; see section 4.4.3.2); 

FERC Certificate conditions; and applicable federal, state, and local regulations. Facilities would be 

periodically inspected and maintained as required by applicable regulations.
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Operation of the facilities would be monitored electronically on a continuous basis, and an 

emergency shutdown system would be installed. In the event of an incident along the pipeline headers, at 

a meter station, or at Compressor Station 760, one of the four permanent employees at Compressor 

Station 760 or one of the KMLP field operations personnel in the vicinity would respond to the event.

KMLP field operations personnel would be available to be dispatched at any time by KMLP’s Gas 

Control Center via cell phone and pager communications.

In accordance PHMSA regulations (49 CFR 192.615), KMLP would be required to update its 

Emergency Response Plan to include the new and modified facilities associated with the Lake Charles 

Expansion Project, and would develop a detailed Operations, Maintenance, and Inspection Manual. The 

Emergency Response Plan would incorporate procedures for identifying an emergency event and 

establishing communication with local fire, police, and public officials. KMLP would participate in a 

One Call program for the proposed facilities and has a public awareness program for its natural gas 

facilities.

Operations activities associated with the header pipelines would be limited primarily to 

maintenance of the permanent easement and inspection, repair, and cleaning of the pipelines. KMLP 

would maintain vegetation on the permanent easement 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 

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 easement. Pipeline inspection would be 

accomplished by means identified in the pipeline integrity management program in accordance with 

applicable laws and regulations.

2.7 SAFETY AND SECURITY PROCEDURES

2.7.1 LNG Terminal 

Spill Containment System

The LNG and mixed refrigerant spill containment systems for the LNG terminal would be 

designed and constructed to comply with the DOT regulations at 49 CFR 193, the Coast Guard

regulations at 33 CFR 127, and all other applicable federal and state regulations. These regulations 

require that each LNG container and each LNG transfer system be provided with a means of secondary 

containment sized to hold the quantity of LNG that could be released as a result of the design spill 

appropriate for the area and LNG equipment. The regulations also require transfer and storage areas for 

flammable refrigerants and flammable liquids be graded, drained, or provided with impoundment in a 

manner that minimizes the possibility of accidental spills and leaks that could endanger important 

structures, equipment, or adjoining property or that could reach waterways. 

Magnolia would construct insulated concrete spill containment basins for the LNG truck loading 

area, LNG storage tank area, and liquefaction area. Materials would flow into the spill containment 

basins via insulated concrete troughs that would be alongside or beneath LNG pipelines and equipment. 

The troughs would be designed and sized to minimize vapor formation during LNG spills. Additional 

information regarding spill containment system operation, maintenance, and safety information is 

presented in section 4.12.5.

Thermal Exclusion and Vapor Dispersion Zones

The LNG storage tanks would comply with the DOT’s siting requirements at 49 CFR 193, 

subpart B, which incorporates the 2001 edition of the NFPA 59A. As specified in 49 CFR 193.2057, 
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thermal radiation protection requires that each LNG container and LNG transfer system have thermal 

exclusion zones based on three radiation flux levels in accordance with section 2.2.3.2 of NFPA 59A. 

The thermal exclusion zones are designed to protect people and property in the event of an accident and 

fire at an LNG facility. More specific information regarding vapor dispersion zones and thermal radiation

is provided in sections 4.12.5.3 and 4.12.5.5, respectively.

Hazard Detection System

Hazard detectors for the LNG terminal would be installed throughout the facilities to give 

operations personnel a means for early detection and location of released flammable gases and fires. The 

hazard detection system would be designed in accordance with NFPA requirements and other applicable 

standards. The hazard detection system would include detectors/sensors for:

 flammable gas;

 fire and flame;

 leak detection;

 high temperature;

 low temperature;

 smoke; and

 toxic gas.

Additional detail regarding the hazard detection system is provided in section 4.12.2.

Firewater System

The LNG terminal would include firewater supply and distribution systems for extinguishing 

fires, cooling structures and equipment exposed to thermal radiation, and dispersing flammable vapors. 

Additionally, hydrants, hose reel, and fixed monitors would be strategically located throughout the LNG 

terminal.

The firewater system would be designed in accordance with NFPA requirements. As described in 

section 2.1.1.7, the proposed source of water supply for the firewater system would be from groundwater 

stored in the on-site aboveground tanks. The deluge system for the LNG storage tanks would use water 

from the Industrial Canal.

High-Expansion Foam System

High-expansion foam concentrate would be metered or proportioned into the firewater system by 

means of a typical balanced pressure foam proportioning system. The resulting foam solution would be 

delivered via underground piping to the high-expansion foam generator installed in the LNG spill 

impoundment sump. The high-expansion foam generator would be water-motor powered, thus, no 

electrical power would be required. The foam generator would produce a high-expansion foam (i.e., a 

nominal 500 parts air for every 1 part foam solution). This foam would be applied to LNG spills, whether 

ignited or un-ignited. Applied to ignited spills, the foam would control the fire, greatly reducing the level 

of radiant heat to the surroundings. The high-expansion foam systems would be designed in accordance 

with NFPA 11A.

Fail Safe Shutdown System

The LNG terminal would have an emergency shutdown system with shutdown sequences and 

control devices designed to leave the facilities in a safe state. The emergency shutdown system would be 
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used for major incidents and would result in either total plant shutdown or shutdown of processes and/or 

individual pieces of equipment, depending on the type of incident.

Security

The LNG terminal would be subject to facility security regulations under the Coast Guard

Maritime Transportation Security Act (33 CFR 105) and would have a facility security plan approved by 

the Coast Guard. The LNG terminal would meet all necessary security measures required under those 

regulations including security fencing, lighting, access control, and closed-circuit television. In addition, 

DOT regulations concerning transportation of hazardous materials would be evaluated and any applicable 

DOT security requirements, not otherwise covered by the Coast Guard-approved Facility Security Plan,

would be implemented. 

The LNG terminal would include sirens that would be audible in all locations per the Coast Guard

LNG facility regulations at 33 CFR 127. The sirens would have a distinctive tone for easy recognition 

between alarms and emergency events.

Plant security would include a perimeter fence consistent with established port protocol. Access 

through the plant gate and buildings would be consistent with the requirements of the Coast Guardapproved Facility Security Plan. Closed-circuit television cameras would facilitate viewing of the 

entrance area and other locations around and within the facility including tank top and the LNG vessel 

loading platform. In addition, guard houses would be strategically located along Henry Pugh Boulevard 

to monitor activities. More detailed information regarding safety and security procedures is provided in 

section 4.12.3.

2.7.2 Magnolia Meter Station, Interconnect Pipeline, and KMLP Facilities

The KMLP facilities would be designed in accordance with the DOT regulations at 49 CFR 192

for material selection and qualification; minimum design requirements; and protection from internal, 

external, and atmospheric corrosion. The regulations also define four area classifications, based on 

population density in the vicinity of the proposed pipeline, for the purpose of ensuring more rigorous 

safety requirements for populated areas. Class locations are used to determine pipe wall thickness, 

hydrostatic test pressures, weld inspection and testing requirements, spacing of mainline valves, depth of 

cover, and frequency of pipeline patrols and leak surveys.

To protect the public, company personnel, and property, Compressor Station 760 would be

equipped with several safety devices. One of these safety systems is an emergency shutdown system. 

When activated, the emergency shutdown system would stop the gas turbine compressors, isolate and 

vent the compressor piping, and route the gas away from the station. During the venting process, natural 

gas would be released through a stack. The emergency shutdown system would react if it senses preset or 

predetermined high operating temperatures, high natural gas pressures, high flow rate, and low flow rate. 

The system would also react if fire or gas is detected within the compressor building or facility area. 

Additional detail regarding the emergency shutdown system is provided in section 4.12.9. Aboveground 

facilities would be monitored electronically on a continuous basis and would be surrounded by chain-link 

security fence. 

KMLP 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 KMLP as the pipeline operator, and provide 

telephone numbers where a KMLP representative could be reached in the event of an emergency or prior 

to any excavation in the area by a third party. 

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3.0 ALTERNATIVES

As required by NEPA and FERC policy, we evaluated alternatives to the Magnolia LNG and 

Lake Charles Expansion Projects to determine whether any such alternatives would be reasonable and 

have significant environmental advantages compared with the proposed action. The range of alternatives 

analyzed include the No-Action Alternative, system alternatives, site alternatives, process alternatives, 

and power source alternatives for the LNG terminal and Compressor Station 760.

As part of the No-Action Alternative, we considered the effects and actions that could 

conceivably result if the proposed Magnolia LNG and Lake Charles Expansion Projects 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 the proposed projects’

objectives. Our evaluation of alternative sites focused on the LNG terminal and Compressor Station 760

because the other aboveground facility components would be located within or adjacent to existing 

facilities. Our analysis of alternative liquefaction processes evaluated the potential for another 

liquefaction process to meet the proposed projects’ objectives with similar or less environmental impact. 

Our analysis of alternative power sources for the LNG terminal and Compressor Station 760 evaluated the 

potential for other sources (e.g., obtaining power from Entergy’s existing electric transmission system, 

generating power on site, using different types of compressors, generating electricity using waste heat) to 

meet the power requirements at the terminal and compressor station. 

The evaluation criteria for selecting potentially reasonable and environmentally preferable 

alternatives include whether they:

 are technically and economically feasible and practical;

 offer significant environmental advantage over the proposed projects or segments of 

either project; and

 meet the projects’ objectives of constructing and operating a terminal to serve the

domestic and export markets for LNG, including:

o export of LNG via large LNG carriers to foreign markets;

o domestic waterway transportation of LNG for use as vessel fuel in shipping and 

the offshore oil and gas industry; and

o distribution of LNG in trucks for use as a fuel for long-haul trucking and other 

emerging domestic uses of LNG.

Magnolia participated in our pre-filing process during the preliminary design stage of the 

Magnolia LNG 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 Magnolia’s field surveys, aerial 

photography, U.S. Geological Survey (USGS) topographic maps, the FWS’s 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.
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3.1 NO-ACTION ALTERNATIVE

Under the No-Action Alternative, the Magnolia LNG and Lake Charles Expansion Projects

would not be constructed and Magnolia’s and KMLP’s objective of providing the proposed liquefaction 

and transportation capacity for domestic and export markets of LNG 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. 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. LNG 

terminal developments and pipeline system expansions of similar scope and magnitude to the proposed 

projects would likely result in environmental impacts of comparable significance, especially those 

projects in a similar regional setting.

The No-Action Alternative could require that potential end users make different arrangements to 

obtain LNG from other sources, 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 Magnolia LNG 

and Lake Charles Expansion Projects. 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 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, 2015b), particularly when compared to 

potential emissions of mercury from coal combustion, which are the largest human-caused source of air 

emissions in the United States (EPA, 2005). 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 
3-3

0.5 percent on a global basis. In order to comply with this requirement, 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 produced by 

the proposed projects; 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 cleanburning 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 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, India, Korea, 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 

Magnolia LNG and Lake Charles Expansion Projects 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, 2012a, 2012b). 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 

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.
3-4

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 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 surpass 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. Although 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 of more than 50 percent in worldwide gas demand is predicted over the same timespan 

(IEA, 2014b). Based on this forecast, the increased use of renewable energy sources does not constitute a 

reasonable alternative to the Magnolia LNG and Lake Charles Expansion Projects.

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 proposed projects 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 Magnolia LNG and Lake Charles Expansion Projects. Because the purpose of the 

projects is to construct and operate a terminal to serve the domestic and export markets for LNG, 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, planned, or 

proposed facilities to meet the stated objectives of the Magnolia LNG and Lake Charles Expansion 

Projects and to determine if a system alternative exists that would have less significant adverse 

environmental impacts than those associated with the proposed projects.

1

 Our analyses of system 

alternatives for the Magnolia LNG Project and Lake Charles Expansion Project 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 LNG Terminal 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 projects. In the case of the Magnolia LNG 

Project, it must also be compatible with Magnolia’s purpose and objectives to construct a terminal to 

serve the domestic and export markets for LNG.

Magnolia 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 the determination of non-FTA would be subject 

to DOE approval. For Magnolia to obtain LNG from other facilities that have DOE approval for export,

those facilities would need to have additional, unsubscribed LNG production capacity. 

In addition to LNG export, Magnolia is proposing to load LNG onto LNG barges for domestic 

marine distribution off the coasts of Louisiana and Texas as well as onto LNG trucks for road distribution 

to refueling stations in Louisiana and the surrounding states. Therefore, obtaining LNG from other 

facilities would require those facilities to be located in the Gulf region.

An expansion of existing facilities would need a similar scope of pre-treatment and liquefaction 

facilities and possibly additional storage, LNG truck loading, and marine transfer facilities, while any new 

facility would need a similar scope of pre-treatment, liquefaction, storage, truck loading, 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 LNG terminal. 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 those for which the proponent has submitted a formal application to the FERC; planned projects are those that are 

either in pre-filing or have been announced, but have not been formally proposed.
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3.2.1.1 Existing LNG Import Terminals with Approved, Proposed, or Planned Liquefaction 

Projects

Following are the approved, proposed, and/or planned expansions in the Gulf region to provide 

liquefaction capabilities: 

Approved

 Cameron LNG, LLC (Cameron LNG) – Cameron Liquefaction Project

 Freeport LNG Development, LP (Freeport LNG) – Freeport Liquefaction Project

 Sabine Pass LNG, LP (Sabine Pass LNG) – Sabine Pass Liquefaction Project and Sabine 

Pass Liquefaction Expansion Project

Proposed

 Golden Pass Products LLC (Golden Pass) – Golden Pass Products LNG Export Project

 Gulf LNG Liquefaction Company, LLC (Gulf LNG) – Gulf LNG Liquefaction Project

 Lake Charles LNG Company, LLC (Lake Charles LNG) – Lake Charles Liquefaction 

Project

Planned

 Cameron LNG – Cameron Expansion Project

 Freeport-McMoRan Energy, LLC (Freeport-McMoRan) – Main Pass Energy Hub Project

 Freeport LNG – Freeport LNG Liquefaction Expansion Project

Liquefaction and export facilities are under construction at the Cameron, Freeport, and Sabine 

Pass LNG Terminals; facilities may be constructed at each of the other import terminals pending 

completion of regulatory review and permitting. Each of the projects was evaluated as a potential system 

alternative to the Magnolia LNG Project. 

Cameron LNG Terminal

The Cameron LNG Terminal is located on the Calcasieu Ship Channel, near Hackberry, 

Louisiana, about 5 miles south-southwest of Magnolia’s proposed LNG terminal. The Cameron site 

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-m3 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. 

Approved

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 

September 10, 2014, Cameron LNG received approval from the DOE to export LNG over 20 years to 

non-FTA countries. On May 9, 2012, Cameron LNG and Cameron Interstate received approval to enter 

our pre-filing process2for adding liquefaction and export facilities to the existing terminal (referred to as 

the Cameron Liquefaction and Pipeline Expansion Projects). The formal application for the Cameron 

 

2 Docket Nos. PF12-12-000 and PF12-13-000
3-7

Liquefaction Project and Cameron Pipeline Expansion Project was filed with the Commission on 

December 7, 20123and December 14, 2012,4respectively. The final EIS for the projects was issued on 

April 30, 2014. The FERC issued the Order for the projects on June 19, 2014. The Cameron

Liquefaction Project, which is currently under construction, includes three liquefaction trains (Trains 1 

through 3), each capable of producing approximately 5 MTPA of LNG; one 160,000-m3 LNG storage 

tank (Tank 4); and additional facilities on 502 acres of land, consisting of 70 acres within the existing 

terminal fenceline and 432 contiguous acres adjacent to the terminal. The project has an in-service target 

date of early 2018 for the first train, mid-2018 for the second train, and the end of 2018 for the third train. 

Concurrent with the terminal expansion, construction of the Cameron Pipeline Expansion Project would

include a new 56,820 hp compressor station, 21 miles of 42-inch-diameter natural gas pipeline, and 

associated facilities to supply the natural gas for liquefaction at the Cameron LNG Terminal.

As Cameron LNG has already been approved to export to FTA and non-FTA countries, Cameron 

LNG would require additional facilities similar to those of the Magnolia LNG Project to export the 

additional volume approved by the DOE for Magnolia to export to FTA countries. Any such project 

would need to be evaluated, but would not likely result in a significant environmental advantage. In 

addition, Magnolia has an agreement in place with KMLP to provide natural gas to its proposed terminal. 

Transporting natural gas to the Cameron LNG Terminal would require constructing at least 5 miles of 

additional pipeline from KMLP’s existing system or utilizing a different pipeline system, which would 

likely require additional facilities. Therefore, the Cameron Liquefaction Project was not considered to be 

a reasonable alternative and was removed from consideration.

Planned

On April 9, 2015, Cameron LNG was granted DOE authorization to export an additional

3.0 MTPA of LNG (equivalent to 0.4 Bcf/d of vaporized natural gas) over 20 years to FTA countries.

Cameron LNG’s Cameron Expansion Project would include two additional liquefaction trains (Trains 4 

and 5) each with a capacity of about 5 MTPA and one additional 160,000-m3 LNG storage tank (Tank 5). 

On March 2, 2015, the FERC initiated its pre-filing process for this expansion.5

The environmental impacts of constructing and operating the facilities needed to expand beyond 

the planned capacity would likely be similar to those described above for the Cameron Liquefaction 

Project. Therefore, the Cameron Expansion Project 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 Magnolia’s proposed LNG terminal. The Freeport import terminal, which started 

operations in 2008, includes two 160,000-m3 LNG storage tanks, vaporization units, and a single berth 

capable of handling LNG carriers with a capacity in excess of 200,000 m3. It has a peak natural gas sendout 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 MTPA (equivalent to 1.8 Bcf/d of vaporized natural gas). This project requires

 

3 Docket No. CP13-25-000

4 Docket No. CP13-27-000

5 Docket No. PF15-13-000
3-8

approximately 105 acres for three liquefaction trains (each with a nominal capacity of 4.4 MTPA) and 

ancillary facilities; one 160,000-m3 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 is 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 

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 1.4 Bcf/d to non-FTA 

countries. FLEX received final DOE approval for a total of 1.8 Bcf/d on November 14, 2014. On 

January 5, 2011, Freeport LNG received authorization to use the FERC pre-filing process and filed its 

formal application with the Commission on August 31, 2012.6 The FERC issued an Order 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. Freeport LNG anticipates that the first liquefaction train will 

enter service in 2018 and the remaining two trains will enter service in 2019. 

As Freeport LNG has already been approved to export to FTA and non-FTA countries, Freeport 

LNG would require additional facilities similar to those of the Magnolia LNG Project to export the 

additional volume approved by the DOE for Magnolia to export to FTA countries. Any such project 

would need to be evaluated, but would not likely result in a significant environmental advantage. 

Therefore, this system alternative was not evaluated further. 

Planned

On June 3, 2015, Freeport LNG 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.

Freeport LNG would need to be approved to export to FTA countries and non-FTA countries, 

which would require review of the facilities and would not likely result in a significant environmental 

advantage. Further, although some of the proposed liquefaction capacity (5.1 MTPA) may remain 

unsubscribed, with a 2.9 MTPA differential, the Freeport LNG Liquefaction Expansion Project would 

require the construction of an additional liquefaction train to meet Magnolia’s customer commitments, 

assuming Freeport Development’s proposed 5.1 MTPA could also be utilized for this purpose. Therefore, 

this system alternative was not considered further.

 

6 Docket Nos. PF11-2-000 and CP12-509-000

7 Docket Nos. CP12-509-000 and CP12-29-000

8 Docket No. PF15-25-000
3-9

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 Magnolia’s proposed LNG terminal. The 

Golden Pass import terminal occupies an approximately 477-acre site and includes five 155,000-m3 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. Natural gas is sent out from the Golden Pass 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 midwestern and northeastern United States. 

Proposed

Golden Pass is proposing to construct liquefaction and LNG export facilities at its existing LNG 

terminal. The proposed export facility would include three 5.2 MTPA liquefaction trains, providing a 

total LNG send-out capacity of 15.6 MTPA. It would also require 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 bi-directional transportation to deliver 2.6 Bcf/d of natural 

gas for liquefaction. 

On September 27, 2012, Golden Pass received approval from the DOE to export 15.6 MTPA of 

LNG (equivalent to approximately 2 Bcf/d of vaporized natural gas) over 25 years to FTA countries. On 

October 26, 2012, Golden Pass submitted an application, for which authorization is currently pending, to 

export LNG over the same period to non-FTA countries. On May 30, 2013, Golden Pass received 

authorization to use the FERC pre-filing process, and subsequently filed its application with the 

Commission on July 7, 2014.9 Golden Pass anticipates the first liquefaction train would enter service in 

2019, and the remaining two trains would enter service in 2020.

As Golden Pass has already been approved to export to FTA countries, Golden Pass would 

require additional facilities similar to those of the Magnolia LNG Project to export the additional volume 

approved by the DOE for Magnolia to export to FTA countries. Any such project would need to be 

evaluated, but would not likely result in a significant environmental advantage. Therefore, the Golden 

Pass system alternative was not evaluated further.

Gulf LNG Terminal

The Gulf LNG Terminal is located on a 40-acre site in Pascagoula, Mississippi, about 286 miles 

east of Magnolia’s proposed LNG terminal. The Gulf LNG import terminal began operations in October 

2011 and has a natural gas send-out capacity of 1.3 Bcf/d. It includes two 160,000-m3 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 and 

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 natural gas liquids and 

refrigerant storage area, a new truck loading/unloading facility, and a new dock designed to receive 

 

9 Docket Nos. PF13-14-000, CP14-517-000, and CP14-518-000
3-10

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 MTPA10 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, for which authorization is currently pending, to export the same volume of 

LNG to non-FTA countries over the same period. On May 21, 2014, Gulf LNG received authorization to 

use the FERC pre-filing process and subsequently filed its formal application with the Commission on 

June 19, 2015 for this expansion.11

As Gulf LNG has already been approved to export to FTA countries, Gulf LNG would require 

additional facilities similar to those of the Magnolia LNG Project to export the additional volume 

approved by the DOE for Magnolia to export to FTA countries. Any such project would need to be 

evaluated, but would not likely result in a significant environmental advantage. Therefore, the Gulf LNG 

Terminal system alternative was not evaluated further.

Main Pass Energy Hub Deepwater Port

The Main Pass Energy Hub Deepwater Port is located in federal waters in Main Pass Block 299, 

16 miles offshore from southeastern Louisiana and about 272 miles east-southeast of Magnolia’s 

proposed LNG terminal. The existing infrastructure includes eight platforms. 

Planned

Freeport-McMoRan plans to export LNG from existing and new facilities at its existing 

deepwater port in the Gulf of Mexico. The planned project would include delivery of natural gas via 

pipeline; storage of natural gas in new underground salt dome storage caverns; liquefaction of natural gas 

using six new floating liquefaction, storage, and offloading (FLSO) units; and transfer of LNG to 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 MTPA and storage capacity of 

1,200,000 m3. 

On May 24, 2013, Freeport-McMoRan 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 MARAD and 

the Coast Guard. At the time of this writing, Freeport-McMoRan has not filed an application with 

MARAD. 

On April 24, 2013, it was announced that Petronet LNG Limited committed to 4.0 MTPA of the 

total LNG output of 24 MTPA from the Main Pass Energy Hub Deepwater Port. Freeport-McMoRan 

would require additional facilities to meet the Magnolia LNG Project's objectives, which may result in 

similar or additional environmental impacts. In addition, as an offshore ocean facility, the Main Pass 

Energy Hub Deep Water Port would not be able to meet the project purpose of supporting the domestic 

use of LNG in long-haul trucking. Therefore, this system alternative was not considered further.

 

10 Current project design under FERC review includes export of approximately 10.0 MTPA.

11 Docket Nos. PF13-4-000 and CP15-521-000
3-11

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 Magnolia’s proposed LNG terminal. The Sabine Pass 

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 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 the 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 and 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 the Sabine Pass Liquefaction Project,12 which will allow 

Sabine Pass LNG to receive, process, and export 16.0 MTPA of domestically originated LNG. The 

project will include four 4.0 MTPA liquefaction trains (Trains 1 through 4). On February 20, 2014,13 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 and temporary 

disturbance of about 97 acres, all 288 acres of which would be 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 KMLP, interconnect 

with the Sabine Pass LNG Terminal. A third pipeline, owned by Natural Gas Pipeline Company of 

America, 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.14 The compressor station is currently under construction.

As Sabine Pass LNG has already been approved to export to FTA and non-FTA countries, Sabine 

Pass LNG would require additional facilities similar to those of the Magnolia LNG Project to export the 

additional volume approved by the DOE for Magnolia to export to FTA countries. Any such project 

would need to be evaluated, but would not likely result in a significant environmental advantage. 

Therefore, further consideration of the Sabine Pass Liquefaction Project as a system alternative is 

precluded.

On April 6, 2015, the FERC authorized the Sabine Pass Liquefaction Expansion Project and 

Cheniere Creole Trail Pipeline Expansion Project.15 The projects will result in expansion of the 

 

12 Docket No. CP11-72-000

13

 Docket No. CP14-12-000

14 Docket No. CP12-351-000

15 Docket Nos. CP13-552-000 and CP13-553-000
3-12

liquefaction facilities within the Sabine Pass LNG Terminal and the Creole Trail Pipeline system, which 

would involve the addition of two liquefaction trains (Trains 5 and 6), about 104 miles of new pipeline, 

one new compressor station, and four new meter stations. 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 already 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.

Sabine Pass LNG announced in March 2013 that Total and UK-based Centrica had collectively 

committed to 3.75 MTPA of liquefaction capacity associated with the Sabine Pass Liquefaction 

Expansion Project. Although some liquefaction capacity (5.25 MTPA) does remain unsubscribed on the 

two trains, the unsubscribed capacity is insufficient to meet Magnolia’s delivery requirements. 

Furthermore, because this capacity was approved by the DOE in its public interest determination process, 

we will not assume that any such capacity is “excess” and would remain unutilized throughout the 

lifetime of the Sabine Pass Liquefaction Expansion Project and, therefore, available to meet Magnolia’s 

project purpose. In addition, construction and operation of the facilities needed to expand beyond the 

planned capacity would have environmental impacts, which would likely be similar to those associated 

with the Magnolia LNG Project. As a result, the Sabine Pass Liquefaction Expansion Project was not 

considered to be environmentally advantageous or a reasonable system alternative to the Magnolia LNG 

Project and was not evaluated further.

Trunkline LNG Terminal

The Trunkline LNG Terminal is located in Calcasieu Parish, Louisiana, approximately 1,000 feet 

northeast of Magnolia’s proposed LNG terminal site on the north side of the Industrial Canal. 

Trunkline’s existing import terminal includes vaporization units, four aboveground LNG storage tanks, 

and a berthing dock that can accommodate two LNG carriers on an approximately 125-acre site. 

Proposed

In March 2014, Trunkline LNG Export, LLC and Trunkline LNG Company, LLC submitted an 

application to the FERC to construct and operate the Lake Charles Liquefaction Project immediately 

north of and directly adjacent to the existing Trunkline LNG Terminal.16 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 

(collectively, Lake Charles LNG). The proposed facility would include three liquefaction trains with a 

design production capacity of 16.5 MTPA (equivalent to 2.2 Bcf/d of vaporized natural gas). Feed gas 

would be delivered to the Trunkline LNG Terminal via the existing Trunkline Gas Company (Trunkline) 

pipeline facilities that connect the terminal with various existing interstate pipeline systems, and/or by 

new pipeline facilities that have been proposed by Trunkline. Subject to the receipt of FERC 

authorization and other applicable permits, authorizations, and approvals, Lake Charles LNG anticipates 

that construction of the Lake Charles Liquefaction Project and associated modifications at the Trunkline 

LNG Terminal would commence in 2015 and the in-service date of the first liquefaction train would be in 

the second quarter of 2019. The second and third liquefaction trains would be scheduled to be placed into 

service in the fourth quarter of 2019 and the second quarter of 2020, respectively. 

As Lake Charles LNG has already been approved to export to FTA countries, Lake Charles LNG 

would require additional facilities similar to those of the Magnolia LNG Project to export the additional 

volume approved by the DOE for Magnolia to export to FTA countries. Any such project would need to 

be evaluated, but would not likely result in a significant environmental advantage. Therefore, this project 

 

16 Docket Nos. CP14-119-000, CP14-120-000, and CP14-122-000
3-13

would not provide a significant environmental advantage to the Magnolia LNG Project and was not 

considered further.

3.2.1.2 Approved, Proposed, and Planned Greenfield Liquefaction Projects

In addition to the liquefaction projects proposed or planned at existing LNG terminals described 

in section 3.2.1.1, there are currently 19 approved, proposed, and planned “greenfield” liquefaction 

projects located along the Gulf Coast in the southern United States. These greenfield projects are not 

associated with existing LNG import terminals, but are considered potential system alternatives, as 

identified below.

Approved

 Corpus Christi Liquefaction Project

Proposed

 Lavaca Bay LNG Project

Planned

 Annova LNG Brownsville Project

 Calcasieu Pass Project

 CE FLNG LNG Project

 Corpus Christi Stage 3 Project

 Delfin LNG Project

 Eos LNG Project

 G2 LNG Project

 Gasfin LNG Project

 Gulf Coast Liquefaction Project

 Live Oak LNG Project

 Louisiana LNG Project

 Port Arthur Liquefaction Project

 Rio Grande Project

 SCT&E LNG Project

 Texas LNG Project

 Waller Point LNG Project

 WesPac LNG Project

Construction activities associated with the Corpus Christi Liquefaction Project commenced in 

February 2015; facilities may be constructed at each of the other locations pending completion of 

regulatory review and permitting. Each of the projects was evaluated as a potential system alternative to 

the Magnolia LNG Project, as described below.

Approved

Corpus Christi Liquefaction Project

Corpus Christi Liquefaction, LLC (Corpus Christi) is constructing a liquefaction and LNG export 

terminal about 285 miles southwest of Magnolia’s proposed LNG terminal, on the northeast side of 

Corpus Christi Bay in San Patricio County, Texas. Corpus Christi’s proposed site was originally 
3-14

authorized for the Corpus Christi LNG Import Terminal, which was not constructed due to market 

changes.17 The liquefaction and LNG export terminal includes three liquefaction trains, each with a 

capacity of approximately 5 MTPA, for a total send-out capacity of 13.5 MTPA, three 160,000-m3 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 Corpus Christi LNG Terminal with five interstate and 

intrastate natural gas transmission pipelines in south Texas, as well as two new compressor stations. In 

total, about 1,000 acres of construction workspace would be required.

On October 16, 2012, 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 export of 13.5 MTPA of LNG to non-FTA countries over 20 years (not the 22-year 

term requested).

Corpus Christi received authorization to use the FERC pre-filing process on December 22, 2011 

and submitted its application on August 31, 2012.18 On December 30, 2014, the FERC issued an Order 

authorizing the project, which began construction in February 2015.

As Corpus Christi has already been approved to export to FTA countries, Corpus Christi would 

require additional facilities similar to those of the Magnolia LNG Project to export the additional volume 

approved by the DOE for Magnolia to export to FTA countries. Any such project would need to be 

evaluated, but would not likely result in a significant environmental advantage. Therefore, it was not 

evaluated further as a system alternative.

Proposed

Lavaca Bay LNG Project

Excelerate Liquefaction Solutions (Port Lavaca I), LLC, Excelerate Liquefaction Solutions (Port 

Lavaca 2), LLC, and Lavaca Bay Pipeline System, LLC (collectively, ELS) is proposing to develop a 

liquefaction and LNG export facility at Port Lavaca in Calhoun County, Texas, about 222 miles 

southwest of Magnolia’s proposed LNG terminal. ELS’ proposed terminal 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. 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. The project would also 

include a 29.5-mile-long, 42-inch-diameter natural gas delivery pipeline and compression, metering, and 

appurtenant facilities.

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 process and filed its formal application with the 

Commission on February 6, 2014.19, 20 In a letter dated March 31, 2015, 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. 

 

17 Docket No. CP04-37-000

18 Docket Nos. PF12-3-000 and CP12-507-000

19 Docket No. PF13-1-000

20 Docket Nos. CP14-71-000, CP14-72-000, and CP14-73-000
3-15

As Lavaca Bay has already been approved to export to FTA countries, Lavaca Bay would require 

additional facilities to export the additional volume approved by the DOE for Magnolia to export to FTA 

countries. Any such project would need to be evaluated, but would not likely result in a significant 

environmental advantage. In addition, the Lavaca Bay LNG Project is on hold, and the timelines for 

permitting, construction, and operational start-up are uncertain. Therefore, this system alternative was not 

evaluated further. 

Planned

Annova LNG Brownsville Project

Annova LNG Common Infrastructure, LLC, Annova LNG Brownsville A, LLC, Annova LNG 

Brownsville B, LLC, and Annova LNG Brownsville C, LLC (collectively, Annova) is planning a 

liquefaction and LNG export terminal on a 650-acre site on the Brownsville Ship Channel in Cameron 

County, Texas. Annova’s proposed project would be located about 375 miles southwest of Magnolia’s

proposed LNG terminal and would include six liquefaction trains with an overall LNG capacity of 

approximately 7 MTPA, two 160,000-m3 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 authorization to export 7.0 MTPA of LNG 

(equivalent to 0.94 Bcf/d of vaporized natural gas) to FTA countries over 30 years;21 a corresponding 

application for LNG export to non-FTA countries is not anticipated. The FERC approved Annova LNG’s 

request to enter the FERC pre-filing process on March 27, 2015.22 If approved, Annova anticipates an inservice date of December 2019. 

As Annova has already been approved to export to FTA countries, Annova would require 

additional facilities to export the additional volume approved by the DOE for Magnolia to export to FTA 

countries. Any such project would need to be evaluated, but would not likely result in a significant 

environmental advantage. Therefore, this system alternative was not considered further.

Calcasieu Pass Project

Venture Global Calcasieu Pass, LLC (Venture Global) is planning 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 Magnolia’s proposed LNG terminal, in Cameron Parish, Louisiana. Venture Global’s

proposed project would consist of 10 liquefaction trains capable of producing a total of 10.0 MTPA of 

LNG, two 200,000-m3 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.

On September 27, 2013, Venture Global received approval from the DOE to export up to 

5.0 MTPA (equivalent to 0.67 Bcf/d) of LNG to FTA countries over 25 years; an application for DOE 

approval to export 5.0 MTPA of LNG to non-FTA countries is pending. On May 13, 2014, Venture 

Global submitted a second application to the DOE to export another 5.0 MTPA of LNG to both FTA and 

non-FTA countries. On October 10, 2014, Venture Global received approval from the DOE to export up 

to 5.0 MTPA (equivalent to 0.67 Bcf/d) of LNG to FTA countries over 25 years. An application for DOE 

approval to export 5.0 MTPA of LNG to non-FTA countries is pending. Additionally, on 

 

21 On July 17, 2014, the DOE authorized the transfer of Annova LNG, LLC’s FTA authorization to Annova LNG Common Infrastructure, LLC.

22 Docket No. PF15-15-000
3-16

February 9, 2015 Venture Global submitted a third application to the DOE to export another 2.0 MTPA of 

LNG to both FTA and non-FTA countries. The FERC approved Venture Global’s request to enter the 

FERC pre-filing process on October 10, 2014.23 According to its pre-filing request letter, Venture Global 

anticipates an in-service date of December 2019.

As Venture Global has already been approved to export to FTA countries, Venture Global would 

require additional facilities to export the additional volume approved by the DOE for Magnolia to export 

to FTA countries. Any such project would need to be evaluated, but would not likely result in a 

significant environmental advantage. Therefore, this system alternative was not considered further.

CE FLNG LNG Project

CE FLNG, LLC (CE FLNG) has announced the planned development of a floating liquefaction 

and LNG export facility on the east bank of the Mississippi River in Plaquemines Parish, Louisiana, about 

250 miles east-southeast of Magnolia’s proposed LNG terminal. CE FLNG’s facilities would be located 

on approximately 400 acres adjacent to and within the Mississippi River, and would include two FLSO 

units with a total output of 8 MTPA and storage capacity of 500,000 m3. Each FLSO would have four 

liquefaction trains capable of producing up to 4 MTPA of LNG and five LNG storage tanks with a total 

storage of 250,000-m3 of LNG. LNG carriers would berth next to the FLSO units to receive LNG. The 

project would also include a 45-mile-long, 42-inch-diameter natural gas pipeline to connect the facility 

with the existing natural gas pipeline grid.

On November 21, 2012, CE FLNG received DOE approval to export 8.0 MTPA of LNG 

(equivalent to 1.08 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 this writing, an application had not 

been filed. As of March 31, 2015, CE FLNG anticipates submitting its application in the first quarter of 

2016. If authorized, the project would commence operation during the third quarter of 2019.

As CE FLNG has already been approved to export to FTA countries, CE FLNG would require 

additional facilities to export the additional volume approved by the DOE for Magnolia to export to FTA 

countries. Any such project would need to be evaluated, but would not likely result in a significant 

environmental advantage. Therefore, this system alternative was not considered further.

Corpus Christi Stage 3 Project

On June 9, 2015, Cheniere Corpus Christi Liquefaction, LLC and Cheniere Corpus Christi 

Pipeline, LP (collectively, Cheniere Corpus Christi) entered into the FERC’s pre-filing process for the 

proposed Stage 3 Project.

25

 The project would be located immediately north of the Corpus Christi 

Liquefaction Project site (described above), which is currently under construction. The Stage 3 Project 

would include two additional liquefaction trains (Trains 4 and 5) capable of producing a total of 

10 MTPA of LNG, one additional LNG storage tank (Tank 4) with a capacity of 160,000 m3, new 

22-mile-long natural gas pipeline, additional compression at one compressor station, and appurtenant 

facilities. If approved, Cheniere Corpus Christi anticipates the project would enter service in 2021.

Cheniere Corpus Christi would need to be approved to export to FTA countries and non-FTA 

countries, which would require review of the facilities and would not likely result in a significant 

environmental advantage. Therefore, this system alternative was not considered further.

 

23 Docket No. PF15-2-000

24 Docket No. PF13-11-000

25 Docket No. PF15-26-000
3-17

Delfin LNG Project

Delfin LNG, LLC (Delfin) is planning to construct and operate a deepwater port, which would 

include four floating LNG vessels (FLNGV), which would be moored in the Gulf of Mexico, about 

50 miles offshore from Cameron Parish, Louisiana and 74 miles south of Magnolia’s proposed LNG 

terminal. Delfin’s project would qualify as a “deepwater port” under the Deepwater Port Act and, as 

such, would require a license from MARAD in conjunction with the Coast Guard. Feed gas would be 

supplied to each of the FLNGVs through one of four new pipeline laterals connected to two existing 

natural gas pipelines. The FLNGVs would then liquefy the gas, which would be stored in LNG storage 

tanks aboard each of the FLNGVs. Each vessel would have a total LNG storage capacity of 

165,000 cubic meters (m3). In total, the Delfin LNG Project would be capable of exporting up to 

9.2 MTPA (equivalent to 1.2 Bcf/d of natural gas).

On February 20, 2014, Delfin received DOE approval to export 13 MTPA of LNG (equivalent to 

1.8 Bcf/d of vaporized natural gas) to FTA countries over 20 years; a November 12, 2013 application to 

export 13 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 as well as its abbreviated application for onshore 

facilities with the FERC.26 If authorized, the onshore project components would commence operation in 

2018 and the deepwater port would begin operation in 2019.

As Delfin has already been approved to export to FTA countries, Delfin would require additional 

facilities to export the additional volume approved by the DOE for Magnolia to export to FTA countries. 

In addition, as an offshore ocean facility, the Delfin LNG Project would not be able to meet the project 

purpose of supporting the domestic use of LNG in long-haul trucking. Therefore, the Delfin LNG Project 

was not evaluated further as a system alternative.

Eos LNG Project

Eos LNG LLC (Eos) and Barca LNG LLC (Barca) are planning to develop a liquefaction and 

LNG export facility at the Port of Brownsville in Brownsville, Texas, approximately 375 miles southwest 

of Magnolia’s proposed LNG terminal. Eos/Barca’s facility is being designed and permitted for up to six 

FLSO units with aggregate peak capacity of up to 12.0 MTPA. It would include up to six 35,000-m3full 

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, both Eos and Barca received DOE authorization to export a total of 

12 MTPA of LNG (equivalent to 1.6 Bcf/d of vaporized natural gas) to FTA countries over 25 years; 

applications were also filed on August 23, 2013 to export 12 MTPA to non-FTA countries over the same 

period, which are pending approval. At the time of this writing, initiation of the FERC pre-filing process 

has not been requested. 

As Eos and Barca have already been approved to export to FTA countries, Eos and Barca would 

require additional facilities to export the additional volume approved by the DOE for Magnolia to export 

to FTA countries. Any such project would need to be evaluated, but would not likely result in a 

significant environmental advantage. In addition, as an offshore ocean facility, the Eos LNG Project 

would not be able to meet the project purpose of supporting the domestic use of LNG in long-haul 

trucking. Therefore, this system alternative was not considered further.

 

26 Docket No. CP15-490-000
3-18

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 

Magnolia’s proposed 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 MTPA of LNG (14 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 March 19, 2015, G2 LNG requested DOE authorization to export 14 MTPA of LNG 

(equivalent to 3.8 Bcf/d of vaporized natural gas) to FTA countries over 30 years and authorization to 

export the same volume of LNG to non-FTA countries over the same period. Both applications are 

pending approval. At the time of this writing, initiation of the FERC pre-filing process has not been 

requested by G2 LNG. 

G2 LNG would need to be approved to export to FTA countries and non-FTA countries, which

would require review of the facilities and would not likely result in a significant environmental advantage. 

Therefore, this system alternative was not considered further.

Gasfin LNG Project

Gasfin Development USA, LLC (Gasfin) is planning to develop a liquefaction and LNG export 

facility on the east side of the Calcasieu Ship Channel in Cameron Parish, Louisiana, approximately 

23 miles south of Magnolia’s proposed LNG terminal. Gasfin’s project would have an 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 one LNG carrier berth that could 

accommodate 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 this writing, 

initiation of the FERC pre-filing process has not been requested by Gasfin.

As Gasfin has already been approved to export to FTA countries, Gasfin would require additional 

facilities to export the additional volume approved by the DOE for Magnolia to export to FTA countries. 

Any such project would need to be evaluated, but would not likely result in a significant environmental 

advantage. Therefore, this system alternative was not considered further.

Gulf Coast Liquefaction Project

Gulf Coast LNG Export, LLC (Gulf Coast) is planning to develop a liquefaction and LNG export 

facility at the Port of Brownsville in Brownsville, Texas, about 374 miles southwest of Magnolia’s

proposed LNG terminal. Gulf Coast’s project would be located on a 500-acre site and would include 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 an interconnection with an existing natural gas 

pipeline. 

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 this writing, 

initiation of the FERC pre-filing process has not been requested by Gulf Coast. 
3-19

As Gulf Coast has already been approved to export to FTA countries, Gulf Coast would require 

additional facilities to export the additional volume approved by the DOE for Magnolia to export to FTA 

countries. Any such project would need to be evaluated, but would not likely result in a significant 

environmental advantage. Therefore, this system alternative was not considered further.

Live Oak LNG Project

Live Oak LNG, LLC (Live Oak) has announced plans for a liquefaction and LNG export facility 

in Calcasieu Parish, approximately 2 miles west of Magnolia’s proposed 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-m3 LNG storage tanks, a marine berth 

accommodating an LNG vessel with cargo capacity of up to 175,000 m3, and an interconnection with the 

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 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.

Live Oak would need to be approved to export to FTA countries and non-FTA countries, which 

would require review of the facilities and would not likely result in a significant environmental advantage. 

Therefore, this system alternative was not considered further.

Louisiana LNG Project

Louisiana LNG Energy LLC (Louisiana LNG) is planning 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 Magnolia’s proposed LNG terminal. 

Louisiana LNG’s project would include four liquefaction trains each capable of producing 0.5 MTPA of 

LNG for a total capacity of 2.0 MTPA, two 100,000-m3 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. 

On February 5, 2014, Louisiana LNG 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, Louisiana LNG 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. Louisiana LNG received authorization to use the FERC pre-filing 

process on July 18, 2014.27

As Louisiana LNG has already been approved to export to FTA countries, Louisiana LNG would 

require additional facilities to export the additional volume approved by the DOE for Magnolia to export 

to FTA countries. Any such project would need to be evaluated, but would not likely result in a 

significant environmental advantage. Therefore, this system alternative was not considered further. 

Port Arthur Liquefaction Project

Port Arthur LNG, LLC and Port Arthur Pipeline, LLC (collectively, Port Arthur) is planning a 

liquefaction and LNG export facility on the west side of the Sabine-Neches Waterway near Port Arthur, 

 

27 Docket No. PF14-17-000
3-20

Texas, which is approximately 45 miles southwest of Magnolia’s proposed 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-m3capacity LNG storage tanks, a natural gas liquids and refrigerant storage 

area, a truck loading/unloading facility, and 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 Liquefaction 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 

10 MTPA of LNG (equivalent to approximately 1.4 Bcf/d of vaporized natural gas) to FTA countries over 

25 years. The FERC approved Port Arthur’s request to enter the FERC pre-filing process on 

March 31, 2015.

28

Port Arthur would need to be approved to export to FTA countries and non-FTA countries, which 

would require review of the facilities and would not likely result in a significant environmental advantage.

Therefore, this system alternative was not evaluated further. 

Rio Grande Project

Rio Grande LNG, LLC and Rio Bravo Pipeline Company, LLC (collectively, Rio Bravo) is 

planning a liquefaction and LNG export terminal on a 1,000-acre site on northern shore of the 

Brownsville Ship Channel in Cameron County, Texas. Rio Bravo’s proposed project would be located 

about 375 miles southwest of Magnolia’s proposed LNG terminal and would include six liquefaction 

trains with an overall LNG capacity of approximately 27 MTPA, four 180,000-m3 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. 

At the time of this writing, Rio Bravo has not submitted an application to the DOE requesting 

authorization to export LNG. The FERC approved Rio Bravo’s request to enter the FERC pre-filing 

process on April 13, 2015.

29

 

Rio Bravo would need to be approved to export to FTA countries and non-FTA countries, which 

would require review of the facilities and would not likely result in a significant environmental advantage. 

Therefore, this system alternative was not considered further.

SCT&E LNG Project

Southern California Telephone & Energy LNG, LLC (SCT&E LNG) is planning a liquefaction 

and LNG export facility on Monkey Island in Cameron Parish, Louisiana, which is approximately 

22 miles south of Magnolia’s proposed LNG terminal. SCT&E’s facility would include six LNG trains 

with an overall capacity of 12.0 MTPA of LNG, multiple 160,000-m3capacity LNG storage tanks, and 

may include an interconnect with an existing natural gas pipeline system.

On July 9, 2014, SCT&E LNG submitted an application to the DOE for authorization to export 

12.0 MTPA (equivalent of 1.6 Bcf/d of natural gas) of LNG to FTA countries over 30 years. SCT&E 

LNG received authorization to export to FTA countries on December 15, 2014. On July 24, 2014, 

 

28 Docket Nos. PF15-18-000 and PF15-19-000

29 Docket No. PF15-20-000
3-21

SCT&E LNG also submitted an application to the DOE for authorization to export 12.0 MTPA of LNG to 

non-FTA countries, which is currently pending approval. At the time of this writing, SCT&E LNG has 

not yet requested initiation of the FERC pre-filing process.

As SCT&E LNG has already been approved to export to FTA countries, SCT&E LNG would 

require additional facilities to export the additional volume approved by the DOE for Magnolia to export 

to FTA countries. Any such project would need to be evaluated, but would not likely result in a 

significant environmental advantage. Therefore, this system alternative was not considered further. 

Texas LNG Project

Texas LNG Brownsville LLC (Texas LNG) is planning a liquefaction and LNG export terminal 

on a 625-acre site on the Brownsville Ship Channel in Cameron County, Texas. Texas LNG’s proposed 

project would be located about 375 miles southwest of Magnolia’s proposed LNG terminal and would 

include two liquefaction trains with an overall LNG capacity of approximately 4.0 MTPA, two 

210,000-m3 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. The FERC approved Texas LNG’s 

request to enter the FERC pre-filing process on April 14, 2015.

30

As Texas LNG has already been approved to export to FTA countries, Texas LNG would require 

additional facilities to export the additional volume approved by the DOE for Magnolia to export to FTA 

countries. Any such project would need to be evaluated, but would not likely result in a significant 

environmental advantage. Therefore, this system alternative was not considered further.

Waller Point LNG Project

Waller Point LNG is planning a liquefaction and LNG export facility on Monkey Island in 

Cameron Parish, Louisiana, which is approximately 22 miles south of Magnolia’s proposed LNG 

terminal. Waller Point LNG’s 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 LNG received DOE authorization to export 1.3 MTPA of 

LNG (equivalent to approximately 0.2 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 approximately 0.2 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 this writing, initiation of the FERC pre-filing process has not been requested.

As Waller Point LNG has already been approved to export to FTA countries, Waller Point LNG 

would require additional facilities to export the additional volume approved by the DOE for Magnolia to 

export to FTA countries. Any such project would need to be evaluated, but would not likely result in a 

significant environmental advantage. Therefore, this system alternative was not considered further.

 

30 Docket No. PF15-14-000
3-22

WesPac LNG Project

WesPac Midstream LLC (WesPac) is planning an LNG liquefaction and export facility on 

40 acres of land located on the Sabine-Neches Waterway near Port Arthur, Texas, which is approximately 

45 miles southwest of Magnolia’s proposed LNG terminal. 

On April 18, 2014, Alturas LLC, a subsidiary of WesPac, submitted an application to the DOE 

for authorization to export 1.5 MTPA of LNG (equivalent to approximately 0.2 Bcf/d of vaporized natural 

gas) to FTA countries over 20 years. As of this writing, the DOE application is still pending and the 

initiation of the FERC pre-filing process has not been requested. 

WesPac would need to be approved to export to FTA countries and non-FTA countries, which

would require review of the facilities and would not likely result in a significant environmental advantage. 

Therefore, this system alternative was not considered further.

3.2.2 Pipeline System Alternatives

To serve as a viable system alternative to the Lake Charles Expansion Project, the system would 

have to: (1) transport all or a part of the volume of natural gas required for liquefaction at the LNG 

terminal, and (2) cause significantly less impact on the environment than the proposed pipeline expansion.

There are three major natural gas pipeline systems within 3 miles of the LNG terminal site that 

we evaluated as alternatives to the Kinder Morgan Louisiana Pipeline, as follows:

 Trunkline Pipeline – The Trunkline Pipeline system includes approximately 3,000 miles 

of pipeline and has a capacity of 1.7 Bcf/d. The Trunkline system consists of two largediameter pipelines extending approximately 1,400 miles from the Gulf Coast areas of 

Texas and Louisiana through Arkansas, Mississippi, Tennessee, Kentucky, Illinois, 

Indiana and to Michigan. The Trunkline Pipeline system is proposed to supply natural 

gas for the Lake Charles Liquefaction Project, located across the Industrial Canal from 

Magnolia’s proposed LNG terminal (see additional discussion in section 4.13.2). The 

pipeline Magnolia considered is a 30-inch-diameter pipeline located 1.4 miles from the 

LNG terminal site. Magnolia stated that the Trunkline Pipeline could not supply the full 

capacity of natural gas required by the Magnolia LNG Project. In addition, the selection 

of this pipeline system would require construction of at least 1.4 miles of new pipeline to 

connect with the proposed LNG terminal.

 Gulf South Pipeline – The Gulf South Pipeline system includes approximately 

7,400 miles of pipeline and has a capacity of approximately 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. The 

pipeline Magnolia considered is a 20-inch-diameter pipeline located 1.4 miles from the 

LNG terminal site. Magnolia stated that the Gulf South Pipeline could not supply the full 

capacity of natural gas required by the Magnolia LNG Project without significant capital 

investment to increase capacity. Furthermore, the selection of this pipeline system would 

require construction of at least 1.4 miles of new pipeline to connect with the proposed 

LNG terminal.
3-23

 Chevron Sabine Pipeline – The Chevron Sabine Pipeline system includes 131 miles of 

pipeline used to transport natural gas between Erath, Louisiana and Port Arthur, Texas. 

The pipeline system crosses the western portion of the proposed LNG terminal site and is

6 inches in diameter. Magnolia stated that the Chevron Sabine Pipeline could not supply 

the full capacity of natural gas required by the Magnolia LNG Project without significant 

upgrading in size and capacity.

The KMLP traverses the LNG terminal site and can supply the required volume of natural gas via 

a new meter station and a 40-foot-long interconnect pipeline that would be within the LNG terminal site. 

Although reconfiguration of portions of the Kinder Morgan Louisiana Pipeline system would be required 

in order to accommodate Magnolia’s request for natural gas service at the LNG terminal (see 

section 2.1.3), we have determined that Trunkline Pipeline, Gulf South Pipeline, and Chevron Sabine 

Pipeline would not provide any environmental advantages over the proposed reconfigurations. Therefore, 

these pipeline system alternatives were not considered further.

3.3 SITE ALTERNATIVES

3.3.1 LNG Terminal Site Alternatives

Based in part on the information provided by Magnolia, we evaluated site alternatives in the 

general area of the proposed LNG terminal site. In order to meet the stated objectives of the Magnolia 

LNG Project, we applied screening criteria to identify sites that would be reasonable and most likely to 

provide some environmental advantage over the proposed terminal site. The screening criteria included:

 Waterfront Access – Given the need to support LNG carriers and domestic waterway 

transportation of LNG, a location on waterfront property providing direct access to deepdraft shipping channels (water depths greater than 40 feet below mean sea level) was

considered preferable to minimize or avoid dredging.

 Property Size – Based on the proposed design, a waterfront site of at least 100 acres 

would be preferable to accommodate the proposed configuration of the liquefaction 

trains, storage tanks, and vessel and truck loading facilities.

 Existing Land Use – We considered areas previously disturbed or cleared (brownfield 

sites) preferable to undisturbed areas (greenfield sites). Additionally, sites that avoid or 

minimize wetland impacts and are zoned for industrial or commercial use were 

considered preferable. 

 Site Availability – One significant challenge of siting an LNG facility is finding suitable 

property that is available for industrial development. Availability is critical since 

section 3 of the NGA does not provide the project proponent the authority of eminent 

domain in acquiring the property for the LNG terminal. In some cases, a site may 

possess the available land required for an LNG terminal but the owner is unwilling to sell 

or lease the property.

 Natural Gas Pipelines and Transmission Lines – Sites proximate to existing interstate 

pipeline systems and high voltage transmission lines were considered preferable in order 

to provide natural gas and power to the LNG terminal site.
3-24

 Population Centers/Residences – Sites that are not in close proximity to population 

centers or residences were considered preferable in order to meet the regulatory 

requirement for LNG vapor dispersion and thermal radiation exclusion zones. 

 Distance to an Interstate Highway – Sites proximate to existing interstate highway(s)

were considered preferable in order to support LNG trucking.

 Wetlands – Sites that do not contain wetlands (as indicated by the FWS’s NWI database) 

were considered preferable.

Using the screening criteria described above, we evaluated four alternative sites for the LNG

terminal (i.e., Industrial Canal – North, Westlake, Corpus Christi, and Morgan’s Pointe). The general 

locations of the four site alternatives along with the proposed site are shown on figure 3.3.1-1. A 

comparison of each alternative site to the proposed site is presented in table 3.3.1-1 and discussed below.

TABLE 3.3.1-1

Comparison of Alternative Sites for the LNG Terminal

Westlake

Corpus

Christi

Morgan’s

Point

Industrial

Canal – North Proposed Site

Screening Criteria

Waterfront access Shallow waterway Deep draft Deep draft No Deep draft

Property size (acres) 100 450 200 90 115

Existing land use Brownfield Mixed Brownfield Greenfield Greenfield

Site availability Available Not available Not available Available Available

Distance to > 30-inch-diameter 

natural gas pipeline (miles)

7.8 14.5 2.5 0.8 0.0

Distance to > 230 kV electric 

transmission line (miles)

0.6 12 2.5 0.9 0.6

Distance to nearest residence 

(miles)

0.4 0.3 0.1 0.6 0.6

Distance to interstate highway 

(miles)

2.4 22.4 14.3 7.5 8.5

NWI wetlands within site (acres) 2 16 23 10 1

Land Use Within 3 Miles

Number of residences 9,759 2,695 6,084 2,118 1,265

Industrial/commercial (acres 

[percent])

4,159 (19) 0 (0) 0 (0) 1,694 (8) 1,345 (6)

Industrial/commercial and highdensity residential (acres 

[percent])

138 (1) 432 (2) 601 (3) 12 (<1) 10 (<1)

Residential (acres [percent]) 7,246 (33) 1,484 (6) 3,399 (14) 3,955 (19) 3,469 (16)

Undeveloped (acres [percent]) 6,331 (29) 7,613 (29) 3,296 (14) 9,686 (46) 10,367 (47)

Developed open space 

(acres [percent])

446 (2) 855 (3) 2,199 (9) 387 (1) 325 (2)

Agriculture and/or open water 

(acres [percent])

3,493 (16) 15,519 (60) 14,089 (60) 5,514 (26) 6,342 (29)
3-25
3-26

Proposed Site

The proposed site is located in the Port of Lake Charles, Louisiana on a 115-acre site owned by 

the Port of Lake Charles. The site was previously used for dredge material disposal by the COE and is 

bordered to the north by the Industrial Canal, to the west by Calcasieu Point Landing, to the east by 

commercial and industrial development, and to the south by undeveloped land that is the planned location 

for the Louisiana Marine Fisheries Enhancement, Research, and Science Center (see sections 4.8.3 and 

4.13.1.4).

The proposed site meets the screening requirements of existing deep-draft waterfront access at 

least 100 acres in size that is currently available. Furthermore, the site has the shortest distance of the 

alternatives considered to electric power and natural gas pipeline systems. As described in 

section 2.1.1.1, KMLP’s existing 42-inch-diameter pipeline is located along the southern boundary of the 

LNG terminal site; approximately 40 feet of interconnect pipeline would facilitate the transportation of 

natural gas required by the Magnolia LNG Project.

Westlake Site

The Westlake site is located in the Port of Lake Charles on a 100-acre parcel that was previously 

occupied by the Lyondell Chemical plant. The brownfield site is bordered to the north, west, and east by 

commercial and industrial development and to the south by undeveloped land and the Calcasieu River.

The Westlake site is on a waterway adjacent to the Calcasieu River and is of sufficient size to 

allow development of an LNG terminal. The Westlake site is about 0.4 mile from the nearest residence

and has about 9,759 residences within 3 miles. In contrast, there are 1,265 residences within 3 miles of 

the proposed site. In addition, the Westlake site has more NWI-mapped wetlands (2 acres) than the

proposed site (1 acre). The closest natural gas pipeline system to the Westlake site is the Tennessee Gas 

Pipeline located 7.8 miles north of the site. Construction of the additional length of pipeline would 

increase the amount of land disturbance and would be extremely challenging given the dense 

development surrounding the Westlake site. For these reasons, we do not consider the Westlake site 

preferable to the proposed site.

Corpus Christi Site

The Corpus Christi site is located adjacent to the Corpus Christi Ship Canal in Corpus Christi, 

Texas on the former 450-acre Naval Station Ingleside site. The naval base was built in 1988, and was 

decommissioned and returned to the ownership of the Port of Corpus Christi in 2010. The site, which is 

considered a mixture of brownfield and greenfield, is bordered to the north and west by undeveloped land, 

to the east by commercial and industrial development, and to the south by Corpus Christi Bay.

The Corpus Christi site meets the screening criteria for waterfront access and size. However, the 

site is about 0.3 mile from the nearest residence and contains 16 acres of wetlands. In addition, of the 

alternatives considered, the Corpus Christi site is the greatest distance from electrical power, a suitable 

natural gas pipeline system, and interstate highway. Magnolia indicated that the Corpus Christi site was 

sold in November 2012 and, therefore, is no longer available for long-term lease or purchase. For these 

reasons, we do not consider the Corpus Christi site preferable to the proposed site.

Morgan’s Point Site

The Morgan’s Point site is located adjacent to Galveston Bay and the Bayport Ship Channel in 

Morgan’s Point, Texas on a 200-acre brownfield site. The site is bordered to the north by the Bayport 

Ship Channel, to the east by the Bayport Cruise Terminal and Galveston Bay, to the west by industrial 

and commercial development, and to the south by residential development.
3-27

The Morgan’s Point site meets the screening criteria for waterfront access, size, and existing land 

use; however, the site would require constructing an additional 2.5 miles of natural gas pipeline and 

1.9 miles of electric transmission line. The site is also over 14 miles from the nearest interstate highway 

system and contains 23 acres of wetlands. The biggest disadvantage of the Morgan’s Point site is that it is 

located 0.1 mile north of an existing residential community. Therefore, we do not consider the Morgan’s 

Point site preferable to the proposed site.

Industrial Canal – North Site

The Industrial Canal – North site is located in the Port of Lake Charles, Louisiana on a 90-acre 

greenfield site owned by the Port of Lake Charles. The site is primarily forested and is bordered to the 

north, west, and south by undeveloped land and to the east by commercial and industrial development.

The Industrial Canal – North site is similar to the proposed site with respect to parcel availability, 

interstate access, and location relative to electrical power and a natural gas pipeline system. The primary 

differences between the sites are that the Industrial Canal – North site does not meet the minimum 

acreage requirement needed for LNG terminal site development and it is not located adjacent to a deepdraft shipping channel. Development of the site would require modifying the facility layout to fit within 

the 90-acre site and would require obtaining an easement across the adjacent undeveloped property to the 

south to access the Industrial Canal. In addition, dredging would be required adjacent to the Industrial 

Canal to create a recessed berthing area to safely moor LNG vessels. The Industrial Canal – North site is 

also a greenfield site, which is likely to have increased environmental impacts over the brownfield sites 

under consideration, including 10 acres of NWI-mapped wetlands. For these reasons, we do not consider

the Industrial Canal – North site preferable to the proposed site.

Conclusion

We conclude that the proposed site represents an acceptable site for the proposed LNG terminal. 

The proposed site is currently zoned for heavy industrial use, sufficiently sized to allow optimal facility 

layout design, and avoids the need for off-site LNG piping. It is also geographically well separated from 

area residences, the closest of which are more than 0.6 mile distant. The proposed site contains the lowest 

acreage of NWI-mapped wetlands of the alternatives considered; therefore, the loss of habitat diversity 

and function resulting from facility development would be generally less than that anticipated at the other 

sites. From a visual impact perspective, the new LNG terminal would be consistent with the existing 

industrial development along the Industrial Canal.

3.3.2 Compressor and Meter Station Site Alternatives

KMLP indicated that siting Compressor Station 760 adjacent to the Pine Prairie Meter Station 

would reduce the construction and operational footprint, provide the most flexibility to shippers, and 

minimize costs. Other compressor station locations and configurations evaluated required constructing 

two to four compressor stations at the various receipt points, which would require an additional 44,800 to

108,800 hp of compression, respectively. An analysis of the compressor station and meter station site 

alternatives is provided below.

Compressor Station 760

We evaluated two alternative sites for the compressor station in Acadia Parish, Louisiana (see 

figure 3.3.2-1). KMLP indicated that the location of the proposed site offers engineering and hydraulic 

benefits and would limit the amount of new facilities required to meet the stated purpose of the project. 

As a result, we limited our review of alternatives to sites located in close proximity to the proposed site. 

Each site was evaluated to determine if it would be feasible and environmentally prefereable to the 

proposed site. All three sites are located on agricultural land, which is enitrely designated as prime 
3-28

farmland by the NRCS; no NWI-mapped wetlands are present within any of the sites. Other 

environmental features associated with the Fournerat Road site, Refinery Road site, and proposed site are 

compared in table 3.3.2-1. A description and brief environmental analysis of each site compared to the 

proposed site is presented below.

Figure 3.3.2-1 Alternative Sites for Compressor Station 760

TABLE 3.3.2-1

Comparison of Alternative Sites for the Compressor Station

Environmental Factor Fournerat Road Refinery Road Proposed Site

Size (acres) 75 65 75

Land use Agriculture Agriculture Agriculture

Number of pipelines 10 11 7

Number of residences within 1,200 feet 12 3 7

Number of waterbodies 0 1 1
3-29

Proposed Site

The proposed site is within agricultural land and contains one residence on the southwestern 

corner of the property. The site is bordered to the west by Refinery Road, one residence, and a Texas Gas 

Compressor Station; to the north by a residence, the Pine Prairie Meter Station, and agricultural land; to 

the east by one residence and agricultural land; and to the south by Coulee Road, three residences, and 

agricultural land.

KMLP has indicated that this site is the preferred location for the compressor station due to 

having the lowest number of natural gas and crude oil pipelines (7) located within or crossing the site. 

Seven residences are within 1,200 feet of the proposed site, six of which are on the western side of the 

site. However, KMLP has proposed to place the compressor station within the eastern half of the parcel 

to increase the distance between the compressor station and the nearest residence. We conclude that the 

Coulee Road site is an acceptable location for Compressor Station 760 and find no environmental reason 

to recommend one of the alternate sites over the proposed site.

Fournerat Road Site

The Fournerat Road site is located on agricultural land and is bordered to the north by Fournerat 

Road, a TransCanada Compressor Station, and ANR Meter Station; to the east by Valse Drive and 

residential development; to the south by agricultural land; and to the west by agricultural land and two 

residences.

Of the three sites considered, the Fournerat Road location has the highest number of residences 

(12) within 1,200 feet of the site. In addition, this site has developmental contraints associated with the 

presence of 10 natural gas and oil pipelines that cross the property, including KMLP. For these reasons, 

the Fournerat Road site was eliminated from further consideration.

Refinery Road Site

The Refinery Road site is located on agricultural land and is bordered to the west by Refinery 

Road and the Basile Gas Processing Plant; to the north by two residences and agricultural land; to the east 

by agricultural land; and to the south by a residence, the Pine Prairie Meter Station, and agricultural land.

Of the three sites considered, the Refinery Road location has the highest number of natural gas 

and crude oil pipelines (11) within or crossing the site, which would preclude development of a 

compressor station at this location. Because of this, the Refinery Road site was eliminated from further 

consideration.

Meter Stations

KMLP is proposing to modify five existing meter stations in Evangeline and Acadia Parishes, 

Louisiana to allow bi-directional flow, and to construct and operate a new meter station within the LNG 

terminal site. The proposed meter station modifications would occur adjacent to existing facilities, which 

would minimize the footprint and associated environmental impacts. The new meter station would be 

constructed within the LNG terminal site in a location designed to minimize the length of interconnect 

pipeline. No other locations within the LNG terminal site would offer any environmental benefit. We did 

not identify any environmental concerns that require the need to identify and evaluate alternative meter 

station sites or configurations, nor were any alternatives suggested during the public scoping period.
3-30

3.3.3 Header Pipeline Route Alternatives

The Lake Charles Expansion Project would include two new header pipelines: a 1.2-mile-long, 

36-inch-diameter low pressure header pipeline and a 700-foot-long, 24-inch-diameter high pressure 

header pipeline. Because the header pipelines would be wholly collocated with KMLP’s existing 

42-inch-diameter mainline, we did not identify any environmental concerns that require the need to 

identify and evaluate route alternatives, nor were any route alternatives suggested during the public 

scoping period.

3.3.4 Dredge Material Placement Alternatives

Magnolia evaluated three alternative sites for dredge material placement in addition to the 

proposed site (see figure 3.3.4-1). Two of the alternate sites considered (as well as the proposed site) are

upland placement sites; the other is a beneficial use site, which is the use of dredged sediments as 

resource materials in productive ways that provide environmental, economic, or social benefit. A 

description and comparison of each of the sites is provided below.

3.3.4.1 Proposed Site

The proposed dredge material placement area would be located on approximately 142 acres of 

land owned by Prairie Land Company and is currently leased to CB&I for staging and laydown. The 

proposed site is located approximately 8,000 feet east of the proposed LNG terminal site across Big Lake 

Road, is zoned for heavy industrial use, and is outside of the 2012 Louisiana Coastal Zone. 

Between 2010 and 2013, CB&I excavated a 35-acre borrow pit at the north end of the site to 

provide material for a recent construction project. As described in section 2.5.1.4, dredge material would 

be transported to the site by pipeline. To retain dredge material during deposition, approximately 

10,000 linear feet of 5- to 10-foot earthen dikes would be constructed along the perimeter of the 

settlement basin, which would be created from material on site. The potential capacity of the borrow pit, 

once dewatered, is between 300,000 and 350,000 yd3. Magnolia estimates that deposition of dredge 

materials would raise the elevation of the placement area by between 2.5 and 3.2 feet once material has 

settled and confinement dikes are leveled on the site. Based on our review, the proposed site is an 

acceptable location for dredge material placement and we find no environmental reason to recommend 

one of the alternate sites over the proposed site.

3.3.4.2 Confined Disposal Facility 13

An upland confined disposal facility (CDF) is an engineered structure built for the containment of 

dredged material. CDFs are bounded by confinement dikes or structures, thereby isolating the dredged 

material from its surrounding environment. CDF 13 occupies over 500 acres of land on Choupique 

Island, which is located approximately 4,000 feet southwest of the proposed LNG terminal. CDF 13 is 

zoned for heavy industrial use and is within the 2012 Louisiana Coastal Zone. 

Pine Island Oil Company owns CDF 13, a 460-acre portion of which was considered for the 

placement of dredge material removed from the recessed berthing area (identified in yellow as the PI CDF 

on figure 3.3.4-1). Dredge material would be placed onto CDF 13 either hydraulically or mechanically, 

where it would be allowed to drain, dry, and consolidate. To retain dredge material during deposition, 

approximately 22,000 linear feet of 5- to 10-foot earthen dikes would be constructed along the perimeter 

of the 460-acre workspace, which would be created from material on site. Portions of existing CDF 13 

berms may be used, if the berm elevation would effectively contain dredge material during placement and 

settling. Magnolia estimates that deposition of dredge materials would raise the elevation within the 

placement area by between 1.0 and 1.2 feet once material has settled and confinement dikes are leveled 

on the site.
3-31
3-32

CDF 13 is managed by the COE, New Orleans District in coordination with the Port of Lake 

Charles. Due to ongoing dredging within the Calcasieu Ship Channel and Industrial Canal, Magnolia 

indicated that the COE and Port of Lake Charles would require Magnolia to raise the existing dikes at 

CDF 13 by 10 feet and provide replacement dredge material disposal capacity if CDF 13 is selected for 

dredge material placement. In addition, because the site is located within the 2012 Louisiana Coastal 

Zone, Magnolia would be required to obtain a Special Coastal Use Permit from the LDNR if CDF 13 is 

selected. For these reasons, Magnolia determined that CDF 13 was not the preferred location for dredge 

material placement during construction of the LNG terminal. However, Magnolia has stated that it would 

continue to coordinate with Pine Island Oil Company, the COE, and the Port of Lake Charles to 

determine if CDF 13 may be used for maintenance dredging of the recessed berthing area.

3.3.4.3 Confined Disposal Facilities 12A, 12B, and 12C 

CDFs 12A, 12B and 12C are existing CDFs created and managed by the COE, New Orleans 

District in coordination with the Port of Lake Charles for disposal of the dredged material from 

maintenance of navigable waterways (primarily the Calcasieu Ship Channel and Industrial Canal). CDFs 

12A, 12B, and 12C are adjacent to the northern shore of the Industrial Canal and the eastern shore of the 

Calcasieu River. In relation to the proposed LNG terminal, CDF 12A is approximately 8,500 feet to the 

northwest, 12B is located approximately 6,500 feet to the west, and 12C is approximately 4,400 feet to 

the west. All three CDFs are zoned for heavy industrial use and are outside of the 2012 Louisiana Coastal 

Zone. 

Magnolia has stated that, if utilization of one or more of these CDFs is selected, it would be 

required to raise the existing containment dikes at CDFs 12A and 12B by an additional 8 feet and to 

provide replacement dredge material disposal capacity. For these reasons, Magnolia determined that 

CDFs 12A, 12B, and 12C were not the preferred location for dredge material placement during 

construction of the LNG terminal. 

3.3.4.4 Turner Bay Beneficial Use Site

The Turner Bay beneficial use site is located on over 300 acres of land between the Calcasieu 

River and Calcasieu Lake, approximately 2 miles south of the proposed LNG terminal site. The site, 

which is within the 2012 Coastal Zone, is zoned for agricultural use.

Magnolia considered a 260-acre portion of the Turner Bay beneficial use site for the placement of 

dredge material removed from the recessed berthing area (identified in blue on figure 3.3.4-1). This area 

is currently shallow, open water with an average depth of 18 to 24 inches. No submerged aquatic 

vegetation is present over the entire site. Magnolia considered the following options for dredge material 

placement within the site:

 conversion of the existing shallow, open water area to emergent wetland habitat, thus 

enhancing fish and wildlife nourishment as well as supplying additional storm buffering 

capacity to the area;

 creation of shallow retainment structures to prevent erosion; and

 creation of shallow rises within the site to function as nesting areas for mottled ducks 

(Anas fulvigula) and similar species that nest within formations of mature woodlands that 

occupy isolated elevated areas within otherwise flat marshes adjacent to open water 

habitat (known as chenieres).
3-33

To retain dredge material during deposition, approximately 15,500 feet of 5-foot earthen dikes 

would be constructed along the perimeter of the 260-acre workspace from material obtained from the 

interior of the settling basin to form a substrate for the emergent wetland. Also, four 36-inch weir board 

structures would be installed, which would help control water exchange during construction. Magnolia 

estimates that deposition of dredge materials would raise the elevation within the placement area by 

between 1.8 and 2.1 feet once material has settled and would provide sufficient material to create 

protection structures and nesting habitats in addition to emergent wetland creation. 

Selection of the Turner Bay beneficial use site would involve coordination under the Coastal 

Wetlands Planning, Protection and Restoration Act Program and the Louisiana Coastal Protection and 

Restoration Authority. Magnolia would coordinate with staff from the COE, New Orleans District; EPA, 

Water Quality Protection Division; FWS, Louisiana Ecological Services Field Office; USDA, NRCS; and 

NOAA Fisheries, Restoration Center in the development of final plans for the site. In addition, Magnolia 

would be required to modify its section 404/10 permit application, which is currently under review by the 

COE, New Orleans District, obtain a multi-sector general discharge permit from the LDEQ, and could be 

required to obtain a Special Coastal Use Permit from the LDNR. Based on our review, the Turner Bay 

site is an acceptable location for dredge material placement. However, the site does not present 

significant environmental advantages over the proposed site due to the larger area of disturbance and 

greater wetland impacts. Therefore, we find no environmental reason to recommend the Turner Bay site 

over the proposed site.

3.4 PROCESS ALTERNATIVES

There are currently several liquefaction technologies available for project proponents to choose 

from, including the following:

 Optimized Cascade® Process – ConocoPhillips 

 PRICO® – Black & Veatch 

 C3-MR Process – Air Products

 AP-XTM Process – Air Products 

 DMR Process – Shell

 Parallel Mixed Refrigerant Process – Shell

 Nitrogen Expansion – Hamworthy

 OSMR® – LNG Technology

The Optimized Cascade® Process was originally developed by ConocoPhillips in the 1960s but 

has been improved upon based on more than 40 years’ operating experience with the Kenai LNG Plant. 

Propane, ethelyne, and methane refrigerants are utilized within a series of heat exchangers to cool the 

pretreated natural gas (ConocoPhillips, 2014a, 2014b). This process is commonly used in large-scale 

LNG facilities.

The PRICO® Process is a single mixed refrigerant process that was developed by Black & Veatch

in the early 1970’s and uses a mixed component refrigerant and coil wound heat exchanger (Roberts et 

al., 2002). This process is commonly used in small-scale LNG facilities. 

The C3-MR Process was developed by Air Products to improve upon the single mixed refrigerant 

process by adding a simple propane refrigeration loop for pre-cooling (Black & Veatch, 2015; Roberts et 

al., 2002). The C3-MR Process is currently the industry standard. The AP-XTM Process was developed to 

improve the C3-MR Process by utilizing a simple nitrogen expander loop instead of a mixed refrigerant 

for precooling (Roberts et al., 2002). Both processes are utilized in large-scale LNG facilities.
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The DMR Process was developed by Shell and uses dual mixed refrigerant cycles: an ethane and 

propane mixed coolant and nitrogen-methane, ethane, and propane mixed coolant. The DMR Process has 

more flexibility than the C3-MR Process, and overcomes the inherent limitations of using a single 

component refrigerant in precooling as in the C3-MR design (Bosma and Nagelvoort, 2009). The Parallel 

Mixed Refrigerant Process was developed by Shell to meet the current challenge of the industry for larger 

train sizes. The Parallel Mixed Refrigerant Process achieves high liquefaction efficiency through the use 

of a single pre-cooling cycle and two very efficient mixed refrigerant cycles. The process can either use 

propane or a mixed refrigerant in precooling (Bosma and Nagelvoort, 2009). With the Parallel Mixed 

Refrigerant Process, gas flows through two simultaneous, parallel cooling cycles that can boost the 

maximum capacity of a single processing unit up to 11 MTPA depending on the gas turbine drivers 

(Bradley et al., 2009). The Nitrogen Expansion Process is simple and often used for small- and mid-scale 

LNG facilities. However, the process is less efficient than the mixed refrigerant processes. As a result, 

access to inexpensive natural gas is required to make this process economically viable.

The proposed OSMR® Process is based on the single mixed refrigerant process, but uses aeroderivative gas turbines, combined heat and power technology, and ammonia auxiliary refrigeration to 

increase efficiency and reduce air emissions by approximately 30 percent. The use of anhydrous 

ammonia includes safety hazards due to its toxicity and farther dispersion distances to irreversible effects. 

However, the hazards associated with anhydrous ammonia are well understood, can be mitigated to safe 

levels with additional mitigation measures, and would be subject to the regulation of a number of federal 

agencies. Therefore, while there would be viable liquefaction processes that provide inherently safer 

alternatives, there would not be a significant environmental or safety advantage in the selection of those 

liquefaction processes when considering the additional mitigation measures proposed in section 4.12.5.

3.5 POWER SOURCE ALTERNATIVES

3.5.1 LNG Terminal Alternatives

Entergy operates an existing substation and 230-kV transmission line that are located 

approximately 1.3 miles from the proposed LNG terminal site. During preliminary project design, 

Magnolia indicated that it considered two power source alternatives, including obtaining all electrical 

power from Entergy and not obtaining any electrical power from Entergy. These two alternatives are 

described and compared to the proposed power sources below. 

Proposed Power Sources

Magnolia proposes to obtain a portion of the power required for operation of the LNG terminal 

from Entergy and to generate the remaining power requirement from gas turbines. The total power 

requirement for each liquefaction train is 72.5 MW, of which 6.5 MW would be electric power provided 

by Entergy. The remaining 66 MW would be generated by two 33 MW gas turbines. The terminal would 

require an additional 5 MW of electric power during loading of LNG carriers, therefore, the maximum 

load provided by electrical power would be 31 MW (6.5 MW for each of the four liquefaction trains and 

an additional 5 MW during LNG carrier loading).

By using a combination of power sources, the single mixed refrigerant liquefaction process would 

be enhanced by the use of aero-derivative gas turbines, combined heat and power technology, and 

ammonia auxiliary refrigeration to increase efficiency by 30 percent and thereby decrease air emissions 

by 30 percent; the integration of these technologies to enhance the single mixed refrigerant process is 

referred to as Magnolia’s OSMR® process.
3-35

All Electrical Power from Entergy

The option of using all electrical power from Entergy would result in the LNG terminal replacing 

the proposed gas-fired turbines for liquefaction with electric motors. By using electric motors, there 

would be no recoverable waste heat, as would be generated through the use of gas-fired turbines. 

Magnolia proposes to use the recoverable waste heat to drive the ammonia compressors within each 

liquefaction train, which is required as part of its OSMR® liquefaction process (see additional discussion 

in section 2.1.1.2). Magnolia has indicated that its OSMR® liquefaction process would result in a 

30 percent increase in efficiency and corresponding 30 percent reduction in air emissions over the 

traditional single mixed refrigerant liquefaction process. Therefore, the use of electric motors for the 

liquefaction trains was ruled out in the design of the Magnolia LNG Project.

No Electrical Power from Entergy

The option of not using electrical power from Entergy would require that all electrical power 

requirements for the LNG terminal be produced from within the terminal. To achieve this self-sustaining 

option, some of the recoverable waste heat (high-pressure steam) produced by the gas-fired turbines 

would be used to power a steam turbine generator within each liquefaction train. This steam turbine 

generator would then meet all electrical requirements within the liquefaction train and also around the 

site. 

Magnolia has indicated that essentially all of the waste heat from the gas turbines would be 

needed to achieve a liquefaction capacity of 2.0 MTPA per liquefaction train. By using the recoverable 

waste heat to power a steam turbine generator to provide electric requirements, it would not be available 

to drive the ammonia compressors in the ammonia auxiliary refrigeration plant. As with the alternative of 

obtaining all electrical power from Entergy, this alternative would preclude the use of Magnolia’s 

OSMR® liquefaction process. Therefore, on-site electrical power generation was ruled out in the design 

of the Magnolia LNG Project.

3.5.2 Compressor Station 760

Prior to selecting gas-fired, turbine-driven (i.e., jet engine) compressors at Compressor 

Station 760, KMLP evaluated reciprocating gas-driven (i.e., piston engine) and electric motor-driven 

compressors. In addition, KMLP evaluated waste heat electric generation (cogeneration) as a power 

source for Compressor Station 760. An evaluation of these alternatives is provided below. 

When comparing reciprocating gas-driven compressor units, it was determined that the 

horsepower limitations of reciprocating gas-driven compressor units would result in a larger number of 

units being required to provide the same amount of power as the proposed gas-fired, turbine-driven 

compressor units. For example, if reciprocating gas-driven compressor units were selected, seven 

compressor units would be required instead of the four proposed gas-fired, turbine-driven compressor 

units. Additional compressor units would add both to the cost of the compressor station and its footprint. 

KMLP also indicated that down time during repair of reciprocating gas-driven compressor units would be 

longer than that of gas-fired, turbine-driven compressor units. Because the use of reciprocating gasdriven compression units would likely result in increased environmental impacts due to the larger facility 

footprint and increased emissions, we did not evaluate this option further.

Electric-driven motors were also considered for Compressor Station 760. However, KMLP 

indicated that there is an increased risk of long-term outages associated with an electric-driven system. 

Replacements for damaged electric motors, transformers, and drives can take months to obtain, whereas 

replacement for a gas-fired, turbine-driven compressor unit can be done relatively quickly because
3-36

replacement turbines are typically stocked by KMLP’s supplier. In addition, the installation of electric 

motor-driven compressor units would require 48 MW of installed electric capacity. In order to provide 

this level of service, two new 138 kV cross-country transmission lines and a new electrical substation 

located at Compressor Station 760 would be required, which would affect more land during construction 

and operation. For these reasons, electric-driven motors were not evaluated further.

KMLP also considered waste heat electric generation (cogeneration) as a power source for 

Compressor Station 760. KMLP has stated that Compressor Station 760 would likely not operate when 

the LNG terminal is not producing LNG, which could greatly reduce the economic feasibility of 

cogeneration. Furthermore, the construction and operation of a cogeneration facility would require the 

installation of additional equipment, a new 138 kV or 230 kV electric distribution line, and a new 

substation at the compressor station site. Due to the increased land disturbance and the intermittent 

operation of the compressor station, we did not evaluate cogeneration further. 
4-1

4.0 ENVIRONMENTAL ANALYSIS

The environmental consequences of constructing and operating the proposed projects would vary 

in duration and significance. Four levels of impact duration were considered: temporary, short term, long 

term, and permanent. Temporary impacts generally occur during construction with the resource returning 

to pre-construction condition almost immediately afterward. Short-term impacts could continue for up to 

3 years following construction. Impacts were considered long term if the resource would require more 

than 3 years to recover. A permanent impact could occur as a result of any activity that modified a 

resource to the extent that it would not return to pre-construction conditions during the 30-year life of the 

projects, such as the construction of an aboveground facility. We considered an impact to be significant if 

it would result in a substantial adverse change in the physical environment.

In this section, we discuss the affected environment, general construction and operational impact, 

and proposed mitigation for each resource. Magnolia and KMLP, as part of their proposals, agreed to 

implement certain measures to reduce impacts. We evaluated the proposed mitigation measures to 

determine whether additional measures are necessary to reduce impacts. These additional measures 

appear as bulleted, boldfaced paragraphs in the text. We will recommend that these measures be included 

as specific conditions to any authorization that the Commission may issue.

Conclusions in this EIS are based on our analysis of the environmental impacts and the following 

assumptions:

 Magnolia and KMLP would comply with all laws and regulations;

 the proposed facilities would be constructed as described in section 2.0 of this 

document; and

 Magnolia and KMLP would implement the mitigation measures included in its 

applications and supplemental filings to FERC.

4.1 GEOLOGIC CONDITIONS, RESOURCES, HAZARDS, AND MITIGATION DESIGN 

MEASURES

4.1.1 Geologic Setting

The projects would be in the West Gulf section of the Coastal Plain physiographic province. 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. The surface materials of the region are mainly Quaternary-age unconsolidated sands and 

clays, with scattered salt domes and sulfur deposits (Hunt, 1967). 

Geologic formations underlying the LNG terminal, which includes KMLP’s Magnolia Meter 

Station and interconnect pipeline, 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 (Louisiana Geological Survey, 2002a; Stoeser et al., 2005). Elevations 

in the vicinity of the LNG terminal site typically range from 0 to 20 feet above mean sea level. However, 

the terminal site would be built upon dredge spoils deposited during construction and maintenance of the 

industrial canals in the area. The site is referred to by the COE as CDF-A, and was in operation from 

1975 to 1984. The resulting elevations throughout the majority of the proposed terminal site range from 

28 to 32 feet above NAVD 88 (see figure 4.1.1-1). 
4-2
4-3

Magnolia performed geotechnical studies to evaluate subsurface soil and groundwater conditions 

within the site, including:

 14 geotechnical borings ranging in depth from 50 to 300 feet;

 14 cone penetration tests ranging in depth from 100 to 150 feet;

 three seismic cone penetration tests, each to a depth of 150 feet; and

 an analysis of boring logs from a previous geotechnical investigation performed at the 

site in 2006.

The investigations at the LNG terminal indicated that the materials within approximately 30 feet 

of the surface consist of the clay, silt, and sandy clay dredge materials deposited over 25 years ago; from 

approximately 30 to 200 feet below the surface, the materials are predominately clays with silty sand 

pockets (the southwest portion of the site featured a 14-foot-thick layer of loose sand); and the materials 

from approximately 200 to 300 feet below the surface consist of very dense sand (Fugro, 2014a, 2015).

The KMLP facilities in Acadia and Evangeline Parishes are underlain by Pleistocene-aged terrace 

deposits that consist of clay, sandy clay, silt, sand, and gravels deposited by alluvial processes (Louisiana 

Geological Survey, 2002b, 2003; Stoeser et al., 2005). Elevations range from approximately 35 feet at 

the TGT Meter Station, to approximately 60 feet at the CGT Meter Station. KMLP performed 

geotechnical investigations to evaluate subsurface soil and groundwater conditions at the proposed 

Compressor Station 760 site. This investigation indicated that materials consisted of medium stiff to stiff 

clays and clayey silt to a depth of 100 feet. Groundwater saturation occurred between 3 and 4 feet at the 

time of sampling (February 2015) (Terracon, 2015).

4.1.2 Mineral Resources

Nonfuel mineral resources proximate to the LNG terminal and KMLP facilities consist mainly of 

salt, 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 within 1 mile of the proposed facilities (USGS, 2013a; 2013b).

Oil and gas production is prevalent throughout Louisiana and the surrounding region. The LNG 

terminal would be proximate to various oil and gas fields, including the East Moss Lake oil and gas field, 

which underlies the LNG terminal (LDNR, 2014a). Active and producing wells drilled in the East Moss 

Lake oil and gas field have depths ranging from 9,160 to 11,160 feet. Based on a review of the LDNR’s

Strategic Online Natural Resources Information System (SONRIS), there are no active or plugged and 

abandoned oil, gas, or injection wells within 0.25 mile of the proposed LNG terminal (LDNR, 2014b). 

The closest active well identified is 0.7 mile northeast of the LNG terminal site across the Industrial Canal 

(LDNR, 2014b). 

The KMLP facilities are located in close proximity to several oil and gas fields, including the 

Basile, Teptate, Richie, Fenris, Eunice, and East Point Blue fields (LDNR, 2014a). Thirty-one oil and gas 

wells were identified within 0.25 mile of the proposed header pipelines; Compressor Station 760; and/or

the TETCO, Pine Prairie, and TGT Meter Stations (LDNR, 2014b). Twenty-seven wells are listed as 

abandoned, two wells are listed as active producers, and two wells are listed as shut-in for future use. 

One of the active wells is approximately 150 feet west of the TGT Meter Station and southern origin of 

the low pressure header pipeline. The other active well and two shut-in wells are between 600 and 

1,200 feet east of the southern origin of the low pressure header pipeline and TGT Meter Station, and 

between 1,000 to 2,000 feet south of Compressor Station 760 (see figure 4.1.2-1).
4-4

Figure 4.1.2-1 Active and Shut-in Oil and Gas Wells Within 0.25 Mile of the KMLP Facilities

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, tsunamis, 

and soil liquefaction), subsidence, flooding and storm damage, and shoreline erosion and landslides. 

Conditions necessary for the development of other geologic hazards, including avalanches, volcanism, 

and karst terrain are not present near the LNG terminal or KMLP facilities. In general, the potential for 

geologic hazards to markedly affect construction or operation of the proposed LNG terminal and KMLP 

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 (e.g., the San Andreas Fault 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 

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). The closest 

known active fault runs southwest-northeast approximately 3 miles north of the proposed LNG terminal. 

A desktop fault analysis conducted by Magnolia concluded that the site is potentially at a higher than 

normal risk of being affected by a fault due to the proximity of this fault and a multitude of others (Fugro, 

2014a, 2015). As a result, Magnolia conducted a Phase II Geologic Fault Study to assess the features 
4-5

identified and determine site vulnerability to surface faulting. Results of the Phase II study indicate there 

is no differential displacement at the LNG terminal and, therefore, surface faulting does not create a 

design concern for the LNG terminal (Tolunay-Wong Engineers, Inc., 2013). 

Historically, there have only been sporadic, low-magnitude seismic events recorded within the 

Gulf-margin normal faults. 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) (USGS, 2009c). The 1930 earthquake was the largest earthquake measured in 

Louisiana, with a magnitude of 4.2 on the Richter scale; its epicenter was about 60 miles west of New 

Orleans. The largest recorded earthquake in the vicinity of the projects occurred on October 16, 1983,

10 miles west of Lake Charles, Louisiana and was a magnitude of 3.8 on the Richter scale (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 approximately 400 miles northeast of the 

LNG terminal in the vicinity of New Madrid, Missouri. In 1811 and 1812, the 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, peak ground acceleration (PGA) for the LNG terminal and

KMLP facilities, with 2 percent probability of exceedance in 50 years, is 4 to 5 percent of gravity (USGS, 

2008). For reference, PGAs less than 9 percent of gravity would result in moderate to no perceived 

shaking and very light to no potential damage (USGS, 2006). Therefore, it is unlikely that the proposed

facilities would be affected if a small earthquake were to take place. The USGS PGA values are for rock 

sites and the ground motions on soft soil sites, such as those found at the LNG terminal, can be amplified 

by a factor of 2 or more. The proposed facilities would be designed for earthquake ground motions and, 

therefore, it is unlikely they would be affected by the design earthquake(s). 

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 along rivers, streams, lakes, and shorelines or in areas with shallow 

groundwater. The soil conditions necessary for liquefaction to occur are present at the LNG terminal and 

each of the KMLP facilities.

At the proposed LNG terminal, surficial and subsurface conditions include sandy silt and silty 

sand horizons of varying thickness to a depth of 30 feet. The water table was encountered between 4 and 

12 feet below grade, allowing for the saturation of these non-cohesive subsurface materials (Fugro, 

2014a, 2015). Liquefaction studies (Fugro, 2014a, 2015) performed across the site suggest that thin 

sandy layers (0.5 to 1.0 feet) encountered in the primarily clayey fill in the shallowest 10 to 20 feet could 

liquefy if submerged. However, these layers are generally thin and not continuous, and hence, soil 

liquefaction would be localized and discontinuous if it occurs. Conversely, cohesionless strata 

encountered at deeper depths are too dense to liquefy. Overall, liquefaction-induced settlements were 

estimated to range from negligible to a maximum of 2 inches across the site for 2-percent probability of 

exceedance in 50-year ground motion levels. The potential for liquefaction and associated loss of soil 

strength in the fill soils would be addressed in the foundation design by requiring all LNG facilities to be 

supported on pile foundations, which extend well beyond the liquefiable layers.
4-6

At the Compressor Station 760 site, results of the geotechnical investigation concluded that 

although soil saturation occurred between 3 and 4 feet below the surface, the soils present at the site 

(medium stiff to stiff fat/lean clays) are not susceptible to liquefaction (Terracon, 2015).

Soil conditions necessary for liquefaction to occur (i.e., sandy or silty textures and a shallow 

water table) may be present at the remaining KMLP facilities; however, the potential for soil liquefaction 

to occur is very low due to the low seismic ground motion potential at these facility locations.

4.1.3.2 Subsidence

Common causes of ground subsidence include the presence of karst terrain, underground mining, 

and substantial groundwater or fluid withdrawal. Underground mining poses risks to engineered 

structures due to the potential for the overlying strata to collapse into the voids 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 near the LNG terminal or KMLP facilities (USGS, 2013a, 2013b;

Epstein et al., 2002). Therefore, subsidence associated with these causes is not anticipated.

Subsidence could occur near the LNG terminal and KMLP facilities due to oil and gas extraction. 

As discussed above, these facilities would be within active oil and gas fields. In addition, the LNG 

terminal would be proximate to several active water supply wells and the TRANSCO Meter Station 

would be approximately 150 feet from a domestic supply well, as discussed in section 4.3.1.2.

Magnolia’s storm surge analysis (Moffatt and Nichol, 2013) estimated that regional subsidence 

proximate to the LNG terminal will be 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 approximately 9 inches over the 

30-year life of the LNG terminal. Subsidence rates in the vicinity of the KMLP facilities are between 

0.0 and 0.1 millimeter per year, which would equate to a loss in elevation of 0.1 inch over the 30-year life 

of the facilities (Kent, 2012). 

4.1.3.3 Flooding and Storm Damage

The Federal Emergency Management Agency (FEMA) produces flood insurance rate maps for 

municipalities across the nation. The maps are divided into 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 LNG terminal using FEMA’s Map Service Center, 

the associated flood insurance rate maps, and the National Flood Hazard Layer. The majority of the site 

is within Zone X-Unshaded, meaning the area is outside of the 500-year floodplain (FEMA, 2014). 

A small area along the shoreline and eastern boundary of the site is within areas mapped as Zone AE 

(100-year floodplain) and Zone X-Shaded. The Zone X-Shaded designation represents areas that are 

within the 100- and/or 500-year floodplain, but would have an average inundation of 1 foot for less 

(FEMA, 2014).

The LNG terminal would be 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 
4-7

157 mph that produce catastrophic damage (National Weather Service, 2014a). Based on historical data, 

the site has a greater than 85 percent exceedance probability of experiencing a hurricane, and about a 

60 percent exceedance probability of experiencing a major hurricane (Category 3 or above) within 

50 nautical miles during the LNG terminal’s 30-year design life (Moffatt and Nichol, 2013). Taking 

expected wave action, subsidence, and sea level rise over the next 30 years into consideration, water 

levels around the LNG terminal are anticipated to reach between 12 and 17 feet for 100- and 500-year 

storms. A 500-year return period storm surge level has an annual probability of 0.2 percent of being 

exceeded (Moffatt and Nichol, 2013). The elevations of the top of foundations for the LNG terminal

would range from 18 to 28 feet NAVD 88, and would be above the 500-year storm surge levels. In 

addition, rock armoring would be installed along the slope at the water’s edge. Therefore, the LNG 

terminal facilities should be able to withstand storm surges without damage from at least a Category 3 

storm. 

Magnolia conducted a tsunami hazard evaluation to assess 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 LNG 

terminal. Because the LNG terminal would be 22.4 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 LNG terminal is unlikely to be significant

(Fugro, 2014b). We concur with this determination. Tsunamis could also be generated by offshore 

landslides in the Gulf; however, the maximum estimated run-up values are substantially less than those 

from storm surge and, therefore, the tsunami hazard is inherently considered because the facility is 

designed for storm surge.

As discussed above, the KMLP facilities in Acadia and Evangeline Parishes are 50 to 70 miles 

inland of the LNG terminal at elevations ranging from 35 to 60 feet above sea level. The closest 

perennial streams are Bayou Barwick and Bayou des Cannes. Based on a review of FEMA flood 

insurance rate maps, none of the KMLP facilities are within the 100- or 500-year floodplains

(FEMA, 2014).

4.1.3.4 Shoreline Erosion and Landslides

The LNG terminal would be on the Industrial Canal, which is a dead-end, low-energy channel off 

of the Calcasieu Ship Channel. Tidal fluctuations within the canal are low, and ship traffic and 

subsequent wave action are anticipated to have a negligible impact on shoreline erosion. However, some 

limited portions of the existing slopes along the Industrial Canal of the dredged fill containment dike have 

experienced localized landslides. Magnolia plans to re-grade and armor these slopes. Therefore, no 

landslide hazards are anticipated after construction is completed.

Due to the nearly level topography and distance from streams or rivers, the proposed KMLP 

facilities would not be subject to shoreline erosion or landslide hazards. 

4.1.4 Blasting

Based on available soils and geologic maps, and the geotechnical investigations conducted by 

Magnolia and KMLP, we do not anticipate that any blasting would be required for construction of the 

LNG terminal or KMLP facilities. Should blasting be required, Magnolia and/or KMLP would submit a 

blasting plan to the Deputy Secretary of Public Safety Services in accordance with the Louisiana 

Administrative Code Title 55, Part I, Chapter 15 (LAC 55:I.15).
4-8

4.1.5 Paleontology

Outcrops of fossil-bearing sedimentary rocks are rare in Louisiana. The geologic materials of the 

state are generally young (Holocene to late-Pleistocene) and do not have a high potential to contain 

significant paleontological resources. Holocene and Pleistocene marine fossil fragments are sometimes 

found within sedimentary units deposited in these epochs, but these fragments have little scientific value. 

The LNG terminal and KMLP facilities would not impact any older underlying geologic formations or the 

fossils, if any, within them. The oldest rocks exposed within Louisiana occur as patchy Late Cretaceous 

outcrops along the edges of the Prothro and Rayburns salt domes in Bienvielle Parish (Frey and Kaiser, 

1984). Located more than 150 miles north of the proposed projects, these fossiliferous strata contain 

marine organisms from about 70 to 82 million years ago. Therefore, construction and operation of the LNG 

terminal would not likely affect paleontological resources.

4.1.6 Design and Construction of the LNG Terminal

4.1.6.1 Site Grading 

The LNG terminal site would be cleared, grubbed, and prepared using standard earthmoving and 

compaction equipment. Existing site grade elevations of the plateau region of dredged fill zone generally 

range between 25 and 32 feet above NAVD 88. The burning of brush, vegetation, and trees or burying of 

any these materials would not be permitted on site. Magnolia anticipates that site grading would be a 

balance of cut and fill of existing on-site soil materials. The final grade elevations would be 28 feet in the 

workshop area, 17 feet in the LNG storage tank area, and 24 feet in the process areas (all elevations 

represent elevation above NAVD 88). The LNG storage tank area would be surrounded by a containment 

dike with a crest elevation of 30 feet. 

4.1.6.2 Foundations

Foundations used for the LNG terminal would range from shallow foundations for lightly loaded 

structures to deep pile foundations for the LNG storage tanks and the other LNG facilities and buildings. 

Deep foundations would either be driven precast concrete piles or open-ended steel piles. The selection 

of the type and length of the pile would depend on loads, pile type, and size, downdrag loads, and 

allowable settlement of the structure and would be determined during final design. At this preliminary 

stage of design, Magnolia proposes to use 24-inch square pre-stressed concrete piles that are 105 feet long 

to support the LNG storage tanks. For the remaining LNG facilities and buildings, Magnolia proposes to 

use 24-inch square pre-stressed concrete piles that range in length from 70 to 130 feet. 

Because Compressor Station 760 would be a large, greenfield facility capable of producing over 

103,000 hp and would be in an area underlain by clay or mud, KMLP conducted geotechnical 

investigations of the site on February 26, 2015. The results indicated that the site is underlain by 

medium-stiff to stiff clay and that shallow foundation systems would be acceptable. Seismic risk at the 

site is considered low and it is not considered susceptible to liquefaction.

4.1.6.3 Facility and Structure Design

The LNG terminal would be constructed to satisfy the design requirements of 49 CFR 193, NFPA 

59A-2001, the 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.
4-9

Wind Design 

LNG facilities as defined in 49 CFR 193 would be designed for a sustained wind speed of 

150 mph, which is equivalent to a 3-second wind gust of 183 mph. 

Seismic Design Ground Motions

Geotechnical investigations of the LNG terminal 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 (Vs) that ranged between 157 and 171 meters per second (Fugro, 

2014b). Sites with soil conditions of this type would experience significant amplifications of surface 

earthquake ground motions. 

Fugro 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 a 2 percent probability of being 

exceeded in 50 years have a 0.2-second spectral acceleration value of 0.29 standard gravity (g), while the 

1.0-second spectral acceleration at the site is 0.19 g (Fugro, 2014b). These predicted spectral 

accelerations are relatively low compared to other locations in the United States.

4.1.6.4 Submittal of Final Design Documents

The design of the facility is currently at the Front End Engineering Design (FEED) level of 

completion. Magnolia has proposed a feasible design and has committed to conducting additional 

detailed design work for the proposed LNG terminal if the project is authorized by the Commission. 

Information regarding the development of the final design, as detailed below, would need to be reviewed 

by FERC staff in order to ensure that the final design addresses the requirements identified in the FEED. 

Further, the timing of the production of this information should occur prior to the stage Magnolia has 

indicated in its application and subsequent filings. Therefore, we recommend that:

 Prior to construction, Magnolia file with the Secretary the following information, 

stamped and sealed by the professional engineer-of-record:

a. site preparation drawings and specifications;

b. LNG storage tank and foundation design drawings and calculations;

c. LNG terminal structures and foundation design drawings and calculations; 

d. seismic specifications for procured equipment; and

e. quality control procedures to be used for civil/structural design and 

construction.

In addition, Magnolia should file, in its Implementation Plan, the schedule for 

producing this information.
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4.1.7 General Impacts and Mitigation

LNG Terminal

Construction and operation of the LNG terminal would impact 114.0 acres of the 115.0-acre site. 

Magnolia would clear, grade, and fill 107.6 acres of the LNG terminal site to the extent necessary to 

install the proposed facilities on a level platform with sufficient space to safely execute the work. The 

remaining 6.4 acres would become part of the recessed berthing area through the use of a combination of 

onshore excavation and dredging. As a result, the LNG terminal would permanently alter the existing 

geologic conditions at the site. Final grade surfacing and landscape would consist of gravel, asphalt, 

concrete, topsoil, and grass surface areas. Magnolia would drive approximately 5,000 precast concrete 

piles to support key terminal components and structures (see section 2.5.1.3).

The LNG terminal would also require the excavation and dredging of approximately 131,200 yd3

and 862,550 yd3, respectively, of material from a 16.2-acre area within and adjacent to the Industrial 

Canal to construct the recessed berthing area. Of this, 9.8 acres would occur within the Industrial Canal 

where sediments would be removed using a hydraulic cutterhead dredge and piped to a site approximately 

8,000 feet east of the LNG terminal. The remaining 6.4 acres of this area consists of existing onshore 

locations where soil materials would be excavated and relocated on site using backhoes, front-end 

loaders, bulldozers, and similar heavy equipment. 

Although there are oil and gas fields under the LNG terminal, these fields are typically over 

9,000 feet below ground and would not be affected by construction or operation of the LNG terminal. In 

addition, there are no active mining activities or oil and gas wells within 0.25 mile of the LNG terminal;

therefore, we do not anticipate that there would be impacts on mineral resources in the area. 

Magnolia has completed geotechnical investigations at the LNG terminal site in order to identify 

foundation design criteria for the facility. Further, the LNG terminal would be 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. The facilities would be designed and constructed to 

provide adequate protection from unstable soils, landslides, or other hazards that could cause it to move or 

sustain abnormal loads. Based on the low probability of localized earth movements in the vicinity of the 

LNG terminal and the design criteria described above, we do not anticipate any problems attributable to 

such movements.

As discussed above, critical infrastructure at the LNG terminal would have a minimum elevation 

of 24 feet above NAVD 88; therefore, substantial flooding or storm damage resulting from a hurricane is

not anticipated.

During construction and operation of the LNG terminal, Magnolia would implement measures 

outlined in its project-specific Plan and Procedures to minimize shoreline erosion. In addition, Magnolia 

conducted a scour protection analysis, which included analysis of wave characteristics at the shoreline of 

the dredge slip and property frontage. Based on the results of the analysis, Magnolia would install rock 

armoring at the base of the steel sheet pile bulkhead, along the east and west ends of the marine basin, and 

around the base of the LNG loading platform and breasting dolphin piles. This rock armoring would 

prevent erosion of the adjacent unprotected shoreline by wave activity from vessels maneuvering within 

the recessed berthing area (Moffatt and Nichol, 2014). 

Based on the above discussion, and in consideration of Magnolia’s proposed mitigation and 

design criteria, we conclude that the LNG terminal would not markedly affect or be affected by 

geological conditions in the area. 
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KMLP Facilities

Impacts on topography and geology associated with the KMLP facilities would be limited to

12.0 acres of land that would be permanently converted to industrial use. Temporary workspaces and the 

pipeline easements would be restored to pre-construction conditions, limiting geological impacts to 

temporary disturbance of slopes resulting from grading and trenching operations. KMLP would minimize 

impacts by returning contours to pre-construction conditions to the maximum extent practicable. At the 

aboveground facilities, grading and filling may be required to create a safe and stable land surface to 

support the facility.

No active mining occurs within 0.25 mile of the KMLP facilities. A total of four active or shut-in 

wells are within 0.25 mile of the KMLP facilities. One of the active wells and both shut-in wells are

between 600 and 2,000 feet from proposed Compressor Station 760, the TGT Meter Station, and the 

southern origin of the low pressure header pipeline. Due to the distance from these wells, we do not 

anticipate that there would be impacts on these resources. The other active well is 150 feet west of the 

TGT Meter Station. KMLP’s alignment sheets indicate that the existing access road for the TGT Meter 

Station is immediately adjacent to this well. To avoid impacts on this active well, KMLP has stated that 

the well’s owner would be notified 72 hours prior to construction activities near the well, and that the 

owner or owner’s representative would be on-site during construction activities.

Results of the geotechnical investigation concluded that the proposed pre-engineered steel 

buildings and compressor station equipment could be supported on shallow foundations with the native 

soils and compacted engineered fill, and that no potentially liquefiable soils occur within 100 feet of the 

surface (Terracon, 2015).

As with the LNG terminal discussed above, the potential for geologic hazards to impact the 

KMLP facilities would be low. KMLP would routinely monitor the geotechnical integrity of its facilities 

as part of its current operations and maintenance activities, and take any corrective actions necessary to 

repair damage during the life of the project.

Based on the above discussion, and in consideration of KMLP’s proposed mitigation, we 

conclude that KMLP facilities would not markedly affect or be affected by geological conditions in the 

area. 

4.2 SOILS

4.2.1 Existing Soil Resources

The soils affected by the proposed projects were identified and assessed using the Soil Survey 

Geographic (SSURGO) database (Soil Survey Staff, 2014). The SSURGO database is a digital version of 

the original county soil surveys developed by the 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. 

The soils at the LNG terminal site and the adjacent DII facility are mapped as udifluvents, which 

formed from the deposition of sandy and/or clayey dredge spoils removed from the adjacent Industrial 

Canal and turning basin. These very deep, moderately well to poorly drained soils have slopes ranging 

from 1 to 20 percent and do not contain bedrock or other root restrictive layers within 80 inches of the 

surface.
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Soils mapped within the dredge material placement area and along the dredge material and 

effluent pipelines are Mowata-Vidrine silt loams and urban land. Mowata-Vidrine silt loams have slopes 

ranging from 0 to 3 percent and do not contain bedrock or other root restrictive layers within 80 inches of 

the surface. The Mowata series consist of poorly drained soils that formed in loamy fluviomarine 

deposits on nearly level coastal prairies and depressions. The Vidrine series consist of somewhat poorly 

drained soils that formed in loamy and clayey deposits on convex circular mounds. Urban land consists 

of areas of disturbed land where more than 85 percent of the surface is covered by impervious surfaces 

such as asphalt, concrete, and buildings. 

The soils at the KMLP facilities are mapped as Acadiana silt loams, Crowley silt loams, 

Jeanerette silt loams, Mowata silt loams, Kinder-Vidrine complexes, Patoutville-Crowley complexes, and 

Crowley-Vidrine complexes. These soils have slopes ranging from 0 to 3 percent and do not contain 

bedrock or other root restrictive layers within 80 inches of the surface. The Acadiana soil series consists 

of well drained soils that formed in loamy and clayey alluvium on stream terraces. The Crowley and 

Jeanerette series consist of somewhat poorly drained soils that formed on meander scrolls from the 

deposition of clayey fluviomarine deposits and loamy alluvial material, respectively. The Kinder series 

consists of very deep, very poorly drained soils formed in loamy alluvium of late Pleistocene age or in 

loamy deltaic sediments over Pleistocene age terraces. The Patoutville series consist of somewhat poorly 

drained soils that formed in loess on gently sloping terraces. Mowata and Vidrine soils are described 

above. 

The soils within the proposed facility locations were evaluated to identify prime farmland and 

major soil characteristics that could affect construction or increase the potential for adverse constructionrelated soil impacts. The soil characteristics evaluated include erosion potential, the potential for 

compaction, and revegetation concerns. Table 4.2.1-1 summarizes the amount of prime farmland and the 

soil characteristics within each component of the projects.

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). 

None of the soils at the proposed LNG terminal site are designated as prime farmland. 

Approximately 95 percent (141.7 acres) of the soils within the dredge material placement area and along 

the associated dredge material and effluent pipeline routes are mapped as prime farmland. However, it 

should be noted that since the time of NRCS mapping, approximately 33.5 acres of this land have been 

altered due to construction of a borrow pit. Due to the loss and/or alteration of productive topsoil, the 

borrow pit would no longer meet the requirements for designation as prime farmland. Therefore, 

approximately 73 percent (108.2 acres) of the soils associated with the dredge material placement area 

and associated dredge material and effluent pipelines would be considered prime farmland. All soils 

impacted by construction of the KMLP facilities are designated as prime farmland. 
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TABLE 4.2.1-1

Characteristics of Soils Associated with the LNG Terminal and KMLP Facilities (acres) a

Facility Total

Prime 

Farmland b

Highly Erodible

Compaction 

Prone e

Revegetation 

Concerns Water c Wind d f

LNG Terminal Facilities

LNG terminal g

123.8 0.0 0.0 0.0 114.0 0.0

DII construction yard and parking area 5.2 0.0 0.0 0.0 5.2 0.0

Dredge material transport and placement 148.7 108.2h 0.0 0.0 148.7 0.0

LNG Terminal Facilities Subtotal 277.7 108.2 0.0 0.0 267.9 0.0

KMLP Facilities

Header pipelines 21.9 21.9 0.0 0.0 21.9 0.0

Compressor Station 760 40.6 40.6 0.0 0.0 40.6 0.0

CGT Meter Station 2.0 2.0 0.0 0.0 2.0 0.0

TRANSCO Meter Station 1.6 1.6 0.0 0.0 1.6 0.0

TETCO Meter Station 1.7 1.7 0.0 0.0 1.7 0.0

ANR Meter Station 1.7 1.7 0.0 0.0 1.7 0.0

Pine Prairie Meter Station 2.0 2.0 0.0 0.0 2.0 0.0

TGT Meter Station 1.3 1.3 0.0 0.0 1.3 0.0

Access roads 3.0 3.0 0.0 0.0 3.0 0.0

KMLP Facilities Subtotal 75.8 75.8 0.0 0.0 75.8 0.0

TOTAL 353.5 184.0 0.0 0.0 343.7 0.0

____________________

a The totals shown in this table may not equal the sum of the addends due to rounding.

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

Includes facilities proposed by Magnolia as well as KMLP’s Magnolia Meter Station and interconnect pipeline.

h Borrow pit (33.5 acres) is not considered to be prime farmland. See discussion above in section 4.2.1.1. 

Source: Soil Survey Staff, 2014

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, vegetation 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 vegetation

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 soil where vegetation

cover is sparse and strong winds are prevalent. Based on the soil properties reviewed, none of the soils 

impacted are considered highly susceptible to erosion by wind or water. 
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4.2.1.3 Compaction Potential

Soil compaction modifies the structure and reduces the porosity and moisture-holding capacity of 

soils. Construction equipment traveling over wet soils could disrupt soil structure, reduce pore space, 

increase runoff potential, 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. With the exception of the portion of the recessed berthing area 

within the Industrial Canal (9.8 acres) at the LNG terminal, all soils impacted are considered to be prone 

to compaction due to fine textures and poor drainage class. 

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 

was evaluated based on the soil surface texture, slope, and drainage class. 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. Based on the soil properties reviewed, we 

expect that the soils impacted would be relatively easy to restore and revegetate. 

4.2.2 Soil Contamination

Based on a review of the EPA’s Toxic Release Inventory Program sites in Louisiana, we 

identified one hazardous waste site within 1 mile of the projects. The Lake Charles Carbon Company is 

listed as being in Significant Violation for releases of benzoperylene, hydrogen fluoride, lead, mercury, 

and polycyclic aromatic compounds (EPA, 2006). This site is 0.6 mile north of the proposed LNG 

terminal, across the Industrial Canal.

Magnolia conducted a contaminated soils sampling study within the LNG terminal site. A total 

of 10 cores were taken, including four within the Industrial Canal and six on land at the terminal site. The 

cores were analyzed for contaminants of concern (e.g., heavy metals, semivolatile organic compounds, 

polychlorinated biphenyls, and pesticides). The results were compared to LDEQ’s Risk 

Evaluation/Corrective Action Program’s (RECAP) parameters for tolerable limits of hazardous 

contaminant concentrations. The findings of the investigation determined that all of the materials 

sampled met the RECAP standards and the site did not contain any contaminated dredge material 

(Ecology and Environment, Inc., 2013b). 

Based on the results of the sampling report and the distance between the LNG terminal and the 

Lake Charles Carbon Company, no contaminated soils are expected to be encountered during construction 

or operation.

4.2.3 General Impacts and Mitigation

4.2.3.1 LNG Terminal

Construction activities such as clearing, grading, excavation, backfilling, and the movement of 

construction equipment may affect soil resources. Clearing removes protective vegetation 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. 
4-15

In order to increase the load bearing capacity of soils along the heavy haul road, an engineered 

grout would be added to the subsoil that would alter the physical characteristics of the soil. The resulting 

substrate would have characteristics resembling soft rock (e.g., lightly cemented sandstone). Once soil 

alteration has taken place, it is not possible to revert to pre-existing conditions. Magnolia anticipates that 

the grout used would be left in place. Of the 7.5 acres proposed for the heavy-haul access road, 5.1 acres 

would be part of the sub-base for the LNG terminal infrastructure. The remaining 2.4 acres would be 

graded, covered with a soil base and topsoil, and seeded per NRCS recommendations to prevent erosion.

Magnolia would create a standard elevation of 28 feet above NAVD 88 throughout the majority 

of the site; a base elevation of 24 feet for the liquefaction trains; and a base elevation of 17 feet, with a 

30-foot secondary containment wall, for the LNG storage tanks. The construction of the recessed 

berthing area would also require the removal of approximately 993,750 yd3 of material from a 16.2-acre 

area within and adjacent to the Industrial Canal through a combination of mechanical excavation 

(131,200 yd3) and hydraulic dredging (862,550 yd3).

To reduce the impacts of construction on soils, Magnolia would implement measures outlined in 

its project-specific Plan and Procedures, which include measures to control erosion and sedimentation 

during construction and to ensure proper restoration of disturbed areas following construction. Relevant 

mitigation measures specified in Magnolia’s project-specific Plan and Procedures include:

 Sediment barriers would be installed before ground-disturbing activities to prevent 

sediment flow from construction areas into waterbodies, wetlands, and roads.

 Temporary erosion control measures (e.g., temporary slope breakers and mulch) would 

be installed during construction.

 Permanent erosion control measures would be maintained following construction.

 Erosion control fabric would be placed at dike and drainage swale outlets and adjacent to 

roads and waterbodies as necessary.

 Dust suppression, via water application, would be used as necessary to control and 

minimize wind erosion. 

 During periods of heavy rainfall or unusual soil saturation, rutting and compaction would 

be avoided to the extent practicable by utilizing low-ground weight construction 

equipment and/or timber mats.

 An EI would monitor field conditions daily to ensure that the erosion and sedimentation 

control measures are functional and adequate until the construction workspace is fully 

stabilized.

The majority of the soils disturbed within the LNG terminal site (90.1 acres) would be 

permanently impacted by paved or gravel plant roads, occupied by aboveground facilities, or converted to 

open water within the recessed berthing area. Magnolia would seed the remaining 33.7 acres within the 

LNG terminal site with native vegetation recommended by the NRCS. Revegetated areas would be 

monitored following construction for the first and second growing seasons to ensure successful 

restoration (see section 2.5.1.9).

To dispose of dredge materials, Magnolia would install two 24-inch-diameter pipelines, one to 

move the dredge spoils to the placement area, and the other to return effluent to the Industrial Canal. As 
4-16

described in additional detail in section 2.5.1.4 and depicted in appendix B, with the exception of a 

250-foot-long segment of the pipelines beneath Big Lake Road, the dredge material and effluent pipelines 

would be temporary. The pipelines would be installed prior to the beginning of dredging activities and 

removed following the completion of dredge placement and dewatering activities. The 75-foot-wide 

construction right-of-way would temporarily impact 6.9 acres of previously disturbed soils (e.g., paved 

dock space and storage area, dirt/aggregate road). No clearing or grading would be required for the 

pipeline rights-of-way except where the pipelines would be installed beneath Big Lake Road using the 

conventional bore method. 

Placement of dredge spoil materials at the deposition site would require clearing, grading, and 

modification of the entire 141.8-acre site. The existing 33.5-acre borrow pit would be drained, and 5- to 

10-foot earthen dikes would be constructed around the perimeter of the site using soil taken from the 

interior of the property. Once the borrow pit is drained, the interior of the site would be modified to 

facilitate sedimentation, dewatering of dredge spoil, and clarification of effluent prior to discharge into 

the Industrial Canal. Upon completion of dredging and dewatering activities, Magnolia plans to grade the 

earthen dams and interior of the dredge material placement area and reseed in order to facilitate drainage 

and minimize erosion, returning the site to upland meadow or pasture. Additional information regarding 

revegetation is included in section 4.5.2.1. Impacts on wetlands within the site would be mitigated 

through construction avoidance, wetland restoration, or compensatory mitigation (see section 4.4.3.1).

To prevent contamination of soils within nearby wetlands, waterbodies, and other sensitive 

resources during construction, Magnolia has stated that it would implement its Spill Prevention Plan

during construction and its SPCC Plan during operation of the LNG terminal. These plans would outline 

potential sources of releases at the site, measures to prevent a release to the environment, and initial 

responses in the event of a spill. As of this writing, Magnolia has submitted to the FERC a draft Spill 

Prevention Plan, but has not yet submitted its SPCC Plan. Because Magnolia has not yet provided its 

final spill plans, we recommend that:

 Prior to construction, Magnolia file with the Secretary, for review and written 

approval by the Director of the Office of Energy Projects (OEP), its Spill Prevention 

Plan for construction and SPCC Plan for operation of the project.

Given the impact minimization and mitigation measures described above, we conclude that 

impacts on soils due to construction and operation of the LNG terminal would be permanent, but minor.

4.2.3.2 KMLP Facilities

As shown in table 4.2.1-1, construction of the KMLP facilities would impact 75.8 acres of soils, 

all of which are classified as prime farmland and considered prone to compaction. Operation of the 

facilities would permanently convert 12.0 acres of land to industrial use within the new Compressor 

Station 760 and the expanded CGT, TRANSCO, and TGT Meter Stations (see table 2.2-1 in section 2.2). 

Temporary workspaces and the header pipeline easements (totaling 63.8 acres) would be restored to preconstruction conditions, replanted in accordance with the landowner’s request in agricultural land or using 

a native seed mix developed in consultation with the NRCS, and are anticipated to retain their former 

productivity. 

Soil impacts would be minimized through the implementation of the measures outlined in the 

FERC Plan and Procedures, with the exception of the measures described in section 4.4.3. Further, 

KMLP would implement its SPCC Plan to reduce potential impacts on soils from spills of hazardous 

materials used during construction and operation, which we have reviewed and found to be acceptable. 
4-17

Given the impact minimization and mitigation measures described in these plans, we conclude that

impacts on soils due to construction and operation of the KMLP facilities would be permanent, but minor.

4.3 WATER RESOURCES

4.3.1 Groundwater Resources

The LNG terminal and KMLP facilities are within the coastal lowlands aquifer system in 

southwestern Louisiana, which underlies most of the Gulf Coastal Plain, extending from southern Texas 

to the Florida panhandle (USGS, 2003). It contains numerous local aquifers, including the Chicot aquifer, 

within a complex sequence of mostly unconsolidated beds of clay, silt, sand, and gravel. The sequence, 

which ranges in age from the Oligocene to Holocene epochs, is generally wedge-shaped and thickens 

towards the Gulf of Mexico, where it is up to 14,000 feet thick. Depths in the vicinity of the LNG 

terminal and KMLP facilities are generally between 6,000 and 10,000 feet (USGS, 1998). This aquifer 

system is capable of supplying large quantities of water from properly constructed wells. In Louisiana, 

data from 2012 shows total withdrawals from the Chicot, Chicot equivalent, Evangeline, Evangeline 

equivalent, Jasper, Jasper equivalent, and Catahoula aquifers was approximately 1.1 billion gallons per 

day (USGS and LDNR, 2013). These are the principal freshwater aquifers in Louisiana that are also part 

of the Coastal Lowlands Aquifer system. 

Local surficial groundwater sources consist of discontinuous beds of sand near the surface, which 

provide small quantities of groundwater for domestic use. The shallow subsurface geology varies but 

generally consists of alternating deposits of clays, silts, and sands deposited over time by ancestral 

streams, tidal marshes, and/or estuarine environments. Depth to these surficial groundwater sources 

within Calcasieu, Acadia, and Evangeline Parishes is typically less than 50 feet but can be more than 

150 feet from the surface (DOTD and USGS, 2004).

4.3.1.1 Sole Source Aquifers

The EPA defines a sole or principal source aquifer as one that supplies at least 50 percent of the 

drinking water consumed in the area overlying the aquifer. To be defined as a sole source aquifer, there 

cannot be an alternative drinking water source(s) that could physically, legally, and economically supply 

all those who depend upon the aquifer with drinking water (EPA, 2012).

The Chicot aquifer system is an EPA-designated sole source aquifer (EPA, 2008). This system is 

approximately 9,000 square miles, extending from eastern Texas to the Atchafalaya River in eastern 

Louisiana. The Chicot aquifer is the principal source of fresh groundwater for southwest Louisiana and is

the largest provider of groundwater to the state (DOTD and USGS, 2011). It is composed of productive, 

saturated coarse sands and gravels and the adjoining silt and clay deposits which confine them (DOTD 

and USGS, 2004). Three units of the Chicot aquifer are present in the vicinity of the LNG terminal and 

KMLP facilities: the 200-foot sand, the 500-foot sand, and the 700-foot sand (Lovelace et al., 2004). 

In 2012, an average of 714 million gallons per day was withdrawn from the Chicot aquifer, which 

accounted for 44 percent of Louisiana’s total groundwater usage (USGS and LDNR, 2013).

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 
4-18

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 LNG terminal would be within seven drinking water 

protection areas (LDEQ, 2014). Each of the drinking water protection areas has a 1-mile radius centered 

on the well due to the well depths being less than 1,000 feet. Two of the protection areas are associated 

with wells immediately adjacent to the southeast corner of the LNG terminal that supply water for 

Calcasieu Parish District 12 Water Works. Three of the protection areas are associated with wells that 

supply water to the Lake Charles Carbon Company, and are between 0.4 and 0.8 mile north of the LNG 

terminal across the Industrial Canal. The final two protection areas are associated with wells that supply 

water to the existing Trunkline LNG Terminal, and are 0.3 mile north of Magnolia’s proposed LNG 

terminal, across the Industrial Canal.

Based on a review of the LDNR’s SONRIS database, no private water wells were identified 

within 150 feet of the LNG terminal (LDNR, 2014d). The closest private well is approximately 

2,400 feet east of the LNG terminal. 

No public drinking water supply wells were identified within 1 mile of the KMLP facilities

(LDNR, 2014d). The SONRIS database identified two private water wells within 150 feet of the 

proposed facilities, including a domestic supply well approximately 16 feet north of the TRANSCO 

Meter Station on the north side of Transco Road and a plugged and abandoned rig supply well 

approximately 100 feet south of the access road to the Pine Prairie Meter Station. 

4.3.1.3 Groundwater Quality

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 approximately 

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 the taste, odor, or appearance of water (LDEQ,

2009a, 2009b). 

The LDEQ’s 2009 triennial report (the most recent year for which data are available) indicates 

that the water from the Chicot aquifer is hard, of good quality when considering health risk guidelines, 

and of fair quality when considering taste, odor, or appearance. 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, several wells exceeded secondary MCLs, including 17 wells for iron, 5 wells for total dissolved 

solids, 4 for pH, 3 for chloride, and 3 for color. Over the past 12 years, the Chicot aquifer has shown an 

average increase in 6 analytical parameters: pH, alkalinity, chloride, hardness, barium, and iron. The 

aquifer has exhibited an average decrease in temperature, total phosphorus, and nitrogen. 

In some areas, groundwater withdrawals from the Chicot aquifer are causing lowered water levels 

(drawdown) and saltwater encroachment. The rate of decline in these areas is due primarily to industrial 

use in the Lake Charles area and rice irrigation, where intense pumping of the 500-foot sand has resulted 

in the water level declining by as much as 1 to 2 feet per year (LDNR, 2012c; DOTD and USGS, 2011). 

Chloride levels have remained relatively stable since the mid-1970s; however, elevated chloride levels 

(i.e., greater than 100 milligrams per liter [mg/L]) 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).
4-19

The LDNR’s Office of Conservation has the authority to regulate groundwater usage on a 

statewide basis through designation as an Area of Ground Water Concern or a Critical Area of Ground 

Water Concern. Areas of Ground Water Concern are defined as areas where the sustainability of an 

aquifer is not being maintained due to either movement of a salt water front, water level decline, or 

subsidence. A Critical Area of Groundwater Concern is defined as an Area of Ground Water Concern in 

which the Office of Conservation’s Commissioner of Conservation finds that the sustainability of the 

aquifer cannot be maintained without withdrawal restrictions. The State of Louisiana has three 

designated Areas of Ground Water Concern, all of which are in north Louisiana within the Sparta aquifer. 

Although no portion of the Chicot aquifer has been designated as an Area of Ground Water 

Concern, high water use in southwest Louisiana has been identified as one of the current major issues 

having an impact on groundwater sustainability management (LDNR, 2012c). In 2012, the LDNR and 

USGS entered into a joint partnership to increase groundwater monitoring. As a result, the number of 

wells within the State of Louisiana being monitored for water level, chlorides, and water quality has 

nearly doubled. In addition, the University of Louisiana at Lafayette has initiated a 3-year study of 

regional groundwater use and management in southwest Louisiana (LDNR, 2014c).

4.3.1.4 Groundwater Impacts and Mitigation

Excavation

The majority of the construction activities associated with the LNG terminal and KMLP facilities

would involve shallow, temporary, and localized excavation, with the exception of the installation of two 

groundwater wells and concrete and steel piles at the LNG terminal. Shallow aquifers could sustain 

minor, indirect impacts from changes in overland water flow and recharge caused by clearing and grading 

of the work areas. In addition, near-surface soil compaction caused by heavy construction vehicles could 

reduce the soil’s ability to absorb water. During construction of the LNG terminal and KMLP facilities, 

local water table elevations could be affected by excavation and backfill. In areas where groundwater is 

near the surface, excavation may intersect the water table in low-lying areas.

The two new groundwater wells would be used during operation of the LNG terminal for process, 

service, and fire water systems. Each well would be drilled to a depth between 500 and 700 feet (the 

500-foot sand). Concrete and steel piles required for the LNG storage tanks and LNG ship loading and 

berthing areas would be driven to a depth no lower than approximately 110 feet.1 These direct and 

indirect impacts would be temporary and would have a minor impact on groundwater resources. To 

further minimize or avoid potential impacts on groundwater, Magnolia would implement the measures in 

its project-specific Plan and Procedures and KMLP would implement the FERC Plan and Procedures, 

with the exception of the measures described in section 4.4.3.

Following construction of the LNG terminal and KMLP facilities, the portion of the ground 

surface that is not paved or occupied by the aboveground facilities would be revegetated or graveled to

eliminate exposed soils and to ensure restoration of overland flow and recharge patterns.

 

1 Concrete piles to be used for the LNG storage tanks are expected to be 70 feet in length. Based on a surface elevation of 17 feet above 

NAVD 88, pile tip penetration would be approximately 53 feet below NAVD 88. Both concrete and steel piles would be installed within 

the LNG loading and ship berthing area; the greatest pile lengths would be associated with the breasting dolphin and loading platform, 

which would have a pile tip penetration no lower than approximately 110 feet below NAVD 88. In the Lake Charles area, the 200-foot sand 

is overlain by about 150 feet of surficial sediments (Lovelace, 1999); therefore, piles driven to a depth of 110 feet below NAVD 88 are not 

expected to have direct impacts on the underlying aquifer.
4-20

As described above (see section 4.3.1.2), one domestic supply well is approximately 16 feet north 

of the TRANSCO Meter Station. KMLP stated that no sub-surface work greater than 10 feet in depth 

would be required at the TRANSCO Meter Station site and that it would coordinate with the well owner 

to test the well water both before and after construction. KMLP has stated that it would contact each 

affected landowner to confirm the locations of private wells within 150 feet and public wells within 

400 feet of the construction workspace. Affected landowners also would be notified at this time about 

their ability to request well testing and monitoring. KMLP would file a report with the FERC 

summarizing the findings of the landowner consultations, which would also provide the distance and 

direction of any previously unidentified drinking water supply wells and any mitigation measures 

requested by the owner of each well. To document impacts on water wells and verify that they are 

appropriately addressed, we recommend that:

 Within 30 days of placing the Lake Charles Expansion Project facilities in service, 

KMLP file with the Secretary a report identifying all public or private water supply 

wells/systems damaged by construction and a description of 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.

With the implementation of the measures described above and our recommendation regarding the 

repair of any damaged water supply wells, we conclude that potential impacts on groundwater resources 

due to excavation activities within the LNG terminal and KMLP facilities would be minimal. 

Contamination

Shallow groundwater areas could be vulnerable to contamination caused by inadvertent surface 

spills of hazardous materials used during construction and operation of the LNG terminal or KMLP 

facilities. 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 add pollutants to 

groundwater long after a spill has occurred. 

Implementation of Magnolia’s project-specific Plan and Procedures, Spill Prevention Plan, and 

SPCC Plan would minimize the potential for groundwater impacts associated with an inadvertent spill of 

hazardous materials during construction and operation. Similarly, KMLP would implement the FERC 

Plan and Procedures as well as its SPCC Plan. These plans would identify preventive measures to reduce 

the likelihood of a spill (e.g., secondary containment for petroleum products, daily vehicle inspection for 

leaks, and restrictions on the transport of potentially hazardous materials to the construction work areas)

and also specify measures to contain and clean up a spill should one occur. In addition, these plans would 

address the storage and transfer of hazardous materials and petroleum products. We are recommending in 

section 4.2.3.1 that Magnolia’s final Spill Prevention Plan and SPCC Plan be filed with the Secretary 

prior to construction. Therefore, we conclude that the potential for the projects to contaminate the Chicot

aquifer or water supply wells would be minimal.

Groundwater Withdrawals

Groundwater required during construction of the LNG terminal would be primarily be provided 

by Calcasieu Parish District No. 12 Water Works and would be used for construction worker sanitation, 

dust suppression, hydrostatic testing of plant piping at the LNG terminal, cleaning of the LNG storage 

tanks following hydrostatic testing, and other general utility uses. Construction of the LNG terminal

would require the withdrawal of up to approximately 2.5 million gallons of groundwater over the 

45-month construction period (the majority of which would take place during the first 36 months of 
4-21

construction). On average, approximately 1,800 gallons of groundwater would be required per day, 

although approximately 6,000 gallons of groundwater would be required per day during peak 

construction. Construction wastewater would be collected from temporary construction facilities into 

holding tanks and disposed of off site. Magnolia anticipates that approximately 60,000 gallons of 

groundwater would be used during the first year of construction for dust suppression. No additional dust 

suppression water would be needed for the remainder of the project. Approximately 60,000 gallons of 

groundwater would be required for hydrostatic testing of plant piping and related components within the 

LNG terminal. Following completion of hydrostatic testing, the water would be tested for quality and 

discharged to stormwater holding basins at the LNG terminal. 

In addition, approximately 13,000 gallons of water would be required for hydrostatic testing of 

the Magnolia Meter Station and interconnect pipeline; this water would be obtained from the City of Lake 

Charles. Following completion of hydrostatic testing, the water would be tested for quality and 

discharged within the southeastern portion of the Magnolia Meter Station site. 

Groundwater required during construction of the KMLP facilities would be limited to 

approximately 346,000 gallons of water for hydrostatic testing of the header pipelines and meter station 

modifications; this water would be obtained from the city of Eunice and transported to the test locations

by truck. Water used for hydrostatic testing at each of the meter stations would be returned to the water 

truck and transported to the next meter station site for reuse. Following completion of hydrostatic testing, 

the water would be tested for quality and discharged to an upland agricultural area within the Compressor 

Station 760 site using energy dissipation devices (e.g., hay bales) to minimize erosion and sedimentation 

into nearby waterbodies (see additional discussion in section 4.3.2.2).

Groundwater required during operation of the LNG terminal would be supplied by the tie-in to 

Calcasieu Parish District No. 12 Water Works’ existing potable water line and by two groundwater wells 

within the LNG terminal site. Between 740 and 3,329 gallons of potable water would be provided by 

Calcasieu Parish District 12 Water Works daily for plant personnel in buildings, safety showers, and eye 

wash stations. The two proposed groundwater wells would provide between 130,090 and 167,378 gallons 

of water per day, which would be required for operation of the demineralized water treatment plant and 

use as service water. Only one well is anticipated to be used at a time; the second well would only be 

used if the primary well is out of service.

Groundwater use associated with operation of the LNG terminal would increase overall 

withdrawal from the Chicot aquifer, potentially resulting in drawdown and saltwater encroachment. 

Approximately 714 million gallons of water are withdrawn from the Chicot aquifer daily (USGS and 

LDNR, 2013). The proposed daily maximum groundwater withdrawal for the LNG terminal during 

operation (167,378 gallons) is equivalent to about 0.023 percent of the current daily water withdrawal 

from the Chicot aquifer, or represents an increase of less than 0.001 percent. 

Using a withdrawal rate of 150 gallons per minute, which is more than the anticipated withdrawal 

rate of 120 gallons per minute, Magnolia calculated that the anticipated drawdown from the new on-site 

well within the 500-foot sand would be less than 1.5 feet at a distance of 1,500 feet from the point of 

withdrawal. The nearest water supply wells to the LNG terminal site are the two Calcasieu Parish District 

No. 12 Water Works wells, which are over 1,400 feet east of the proposed wells and have over 400 feet of 

head above their screened interval (400 feet of available water above the extraction point). Therefore, we 

conclude that the potential for operation of the LNG terminal to cause substantial drawdown, impacting 

nearby users of the Chicot aquifer, would be minimal.

As described above (see section 4.3.1.3), elevated chloride levels (i.e., greater than 100 mg/L) 

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 as a result of increased groundwater 
4-22

withdrawals (DOTD and USGS, 1999; LDEQ, 2009a). However, because the proposed groundwater 

wells at the LNG terminal would not be within an Area of Groundwater Concern, as designated by the 

LDNR, and groundwater withdrawals associated with operation of the LNG terminal would result in an 

increase of less than 0.001 percent over current withdrawals from the Chicot aquifer, we conclude that 

the potential for water withdrawals associated with operation of the LNG terminal to result in saltwater 

encroachment into the 500-foot sand of the Chicot aquifer would be minimal.

No groundwater would be necessary for the operation of the KMLP facilities; therefore, no 

impacts on groundwater resources are anticipated.

4.3.2 Surface Water

Surface Water Quality Standards and Designated Uses

Water quality standards are developed by states to enhance or maintain water quality, protect the 

public health or welfare, and provide for the designated uses of the waters of the state. In Louisiana, the 

surface water quality standards are codified in LAC 33:IX.11.

The LDEQ reports on water quality in the state by basin subsegment, which is a discrete 

hydrologic unit or watershed (LDEQ, 2008). Subsegments describe the primary waterbody within the 

watershed; however, the water quality standards and criteria apply to all tributaries and connected 

waterbodies within the boundaries of a subsegment. There are seven designated uses established for 

surface waters in Louisiana, including:

 Primary Contact Recreation: any recreational or other water contact use involving 

prolonged or regular full-body contact with the water and in which the probability of 

ingesting appreciable amounts of water is considerable;

 Secondary Contact Recreation: any recreational or other water contact activity in which 

prolonged or regular full-body contact with the water is either incidental or accidental, 

and the probability of ingesting appreciable amounts of water is minimal;

 Fish and Wildlife Propagation: the use of water for aquatic habitat, food, resting, 

reproduction, cover, and/or travel corridors for any indigenous wildlife and aquatic life 

species associated with the aquatic environment;

 Drinking Water Supply: the use of water for human consumption and general household use;

 Oyster Propagation: the use of water to maintain biological systems that support 

economically important species of oysters, clams, mussels, or other mollusks so that their 

productivity is preserved and the health of human consumers of these species is protected;

 Agricultural: the use of water for crop spraying, irrigation, livestock watering, poultry 

operations, and other farm purposes not related to human consumption; and

 Outstanding Natural Resource Waters: waterbodies designated for preservation, protection, 

reclamation, or enhancement of wilderness, aesthetic qualities, and ecological regimes.
4-23

4.3.2.1 Existing Surface Water Resources

LNG Terminal

The LNG terminal is within the Calcasieu River Basin, which drains an area of approximately 

4,105 square miles into the Gulf of Mexico. The Calcasieu Saltwater Barrier (a man-made dam across the 

Calcasieu River upstream of Lake Charles) divides the upper and lower basins and prevents saltwater 

intrusion into the upper basin (COE, 2015a; LDEQ, 2008). The LNG terminal would be on the south 

shore of the Industrial Canal. The Industrial Canal discharges into the Calcasieu River before flowing 

into Calcasieu Lake (see figure 4.3.2-1). In addition to the Calcasieu River, numerous bayous and smaller 

rivers, and the extensive surrounding marshlands discharge freshwater into Calcasieu Lake. The 

Calcasieu River Basin receives abundant rainfall and contains numerous lakes and reservoirs as well as an 

extensive estuary system. Other sources of fresh water in the estuary system include stormwater runoff 

and municipal, industrial, and agricultural return flow. 

Between July 2013 and February 2014, the LDWF collected water quality data from two 

locations within the Industrial Canal: the entrance and the turning basin. At each location, water quality 

was analyzed at the top, middle, and bottom of the water column. During this time, water temperature 

within the canal ranged from 46.1 °F to 91.6 °F. Water was typically warmer at the surface and middle of 

the water column than at the bottom, although between October and December, water was slightly 

warmer at the bottom of the water column. Salinity varied from 5.4 to 32.4 parts per thousand (ppt). 

Salinity was highest at the bottom of the water column. Dissolved oxygen levels varied from less than 

0.1 mg/L at the bottom of the water column to 11.5 mg/L at the top of the water column (LDWF, 2014b).

The LDEQ has established three designated uses for the Industrial Canal.2 The designated uses 

include primary contact recreation, secondary contact recreation, and fish and wildlife propagation. 

Based on the numerical criteria established for these designated uses, water quality within the canal fully 

supports its designated uses for secondary contact recreation. Use for primary contact recreation is not 

fully supported due to elevated temperature levels resulting from drought-related impacts and natural 

causes. Use for fish and wildlife propagation is not fully supported due to chloride, sulfate, and total 

dissolved solid levels that have been impaired as a result of changes in tidal circulation and hydrostructure 

flow regulation (e.g., flow regulation through construction and operation of the Calcasieu Saltwater 

Barrier). Due to this subsegment not fully supporting its designated uses for primary contact recreation 

and fish and wildlife propagation, it is included on Louisiana’s 2012 Section 303(d) List (LDEQ, 2013a).

LNG carriers would transit the Gulf of Mexico and lower Calcasieu River through the Calcasieu 

Ship Channel while en route to and from the LNG terminal.

3

 Tidal exchange between the Gulf of Mexico 

and Calcasieu Lake occurs through the lower Calcasieu River, including the Calcasieu Ship Channel. The 

Calcasieu Ship Channel, which connects Lake Charles to the Gulf of Mexico, is 400 feet wide and 

maintained at a depth of 40 feet (COE, 2015b). The LDEQ has established four designated uses for the 

lower Calcasieu River and the portion of the Gulf of Mexico within 3 miles of the coast, including 

primary contact recreation, secondary contact recreation, fish and wildlife propagation, and oyster 

propagation. Water quality within the river and coastal waters of the Gulf of Mexico fully support these 

designated uses (LDEQ, 2013a).

 

2 The Industrial Canal is located within subsegment LA031101, which includes the Intracoastal Waterway from the Calcasieu Lock to the 

East Calcasieu River Basin watershed boundary (LDEQ, 2013a).

3 The portion of the lower Calcasieu River transited by LNG carriers en route to and from the LNG Terminal is within subsegment

LA030401, described as the portion of the Calcasieu River from below Moss Lake to the Gulf of Mexico, including the Calcasieu Ship 

Channel and Monkey Island Loop (LDEQ, 2013a).
Intracoastal Waterway

Intracoastal Waterway

Calcasieu River / Calcasieu Ship Channel

Industrial Canal

Calcasieu River / Calcasieu Ship

Channel

Moss Lake

Calcasieu Lake

LNG 

Terminal

ST108

ST384

OP27

Calcasieu Parish

Cameron Parish

p Magnolia LNG Project

Waterbody

Parish Boundary

0 0.5 1

Miles

Figure 4.3.2-1

Waterways in the Vicinity 

of the LNG Terminal

Magnolia LNG and Lake Charles Expansion Projects

Calcasieu Parish, Louisiana

This information is for environmental review purposes only.

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2014\08\Waterways\Waterways.mxd | REVISED: 05/04/2015 | SCALE: 1:60,000 DRAWN BY: JSSuess

Louisiana

4-24
4-25

The Industrial Canal, Calcasieu River, and portions of the Gulf of Mexico have been designated 

as EFH (NOAA Fisheries, 2011b), which is discussed in section 4.6.3. The Calcasieu River and portions 

of the Gulf of Mexico also contain suitable habitat for federally listed species (NOAA Fisheries, 2012), 

which are discussed in section 4.7.1. In addition, the Calcasieu River and Industrial Canal have been 

designated as Navigable Waterways under section 10 of the RHA (COE, 2013b). Segments of the 

Calcasieu River are designated as Louisiana Natural and Scenic Rivers under the Louisiana Scenic Rivers 

Act of 1988; however, the nearest designated segment is about 10 miles north of the LNG terminal

(LDWF, 2012). 

In August 2013, Magnolia conducted a contaminated soils sampling study within the proposed 

LNG terminal site. A total of 10 cores were taken, including 4 within the Industrial Canal and 6 on land 

at the terminal site. As discussed in additional detail in section 4.2.2, the cores were analyzed for 

contaminants of concern (e.g., heavy metals, semivolatile organic compounds, polychlorinated biphenyls, 

and pesticides). The results were compared to LDEQ’s RECAP standards, which use risk evaluation to 

determine if corrective action is necessary for the protection of human health and the environment. None 

of the constituents detected in the sediment samples exceeded the RECAP standards used in the 

evaluation. The COE, New Orleans District evaluated the results of the sediment sampling and concluded 

that:

 contaminants of concern within sediments sampled at the LNG terminal site were present 

at comparable levels to those measured by the COE in 2007 from navigation shoal 

material near Devil’s Elbow;

 all LNG terminal site sediments meet the LDEQ’s working definition of uncontaminated 

dredge material; and

 conservative estimates of the concentration of contaminants of concern in dredged 

material effluent that would be discharged from the LNG terminal site would be below 

the LDEQ and EPA Water Quality Standards/Criteria (based on the COE Engineer 

Research and Development Center’s Tier II Screening Spreadsheet) (COE, 2013c).

Other waterbodies within the areas potentially affected by construction and operation of the LNG 

terminal include an intermittent waterbody at the terminal site, a borrow pit within the dredge material 

placement area, and a perennial waterbody along the dredged material and effluent pipeline route. The 

intermittent waterbody within the LNG terminal site is not hydrologically connected to either the 

Industrial Canal or Calcasieu River;4therefore, the LDEQ’s water quality designations do not apply to 

this waterbody. The perennial waterbody along the dredge material and effluent pipeline route is 

hydrologically connected to the Calcasieu River. 

Table 4.3.2-1 provides a list of the waterbodies affected by the LNG terminal and KMLP 

facilities, including the waterbody name, location, description, waterbody type, water quality 

classification, and crossing length.

 

4 The COE, New Orleans District did not include this waterbody in its May 14, 2014 jurisdictional determination for the LNG terminal site; 

therefore, this waterbody is not defined as a water of the United States under section 404 of the CWA. However, because it had flowing 

water at the time of delineation it is included in our analysis.
4-26

TABLE 4.3.2-1

Waterbodies Potentially Affected by the LNG Terminal and KMLP Facilities

Facility/Waterbody Milepost Description Type

Water Quality 

Classification a

Crossing

Width 

(feet)

Impact

Profile

LNG Terminal Facilities

LNG Terminal

Gulf of Mexico NA Gulf Open water ABCD

Section 10 b

EFH c

NA Vessel traffic

Calcasieu River NA River Open water ABCD d

Section 10 b

EFH c

NA Vessel traffic

Industrial Canal NA Canal Open water ABC/303(d) e

Section 10 b

EFH c

NA Vessel traffic

Berthing area

S1ACA001 f NA Stream Intermittent ABCE g 12 None

Dredge Material Transport and Placement 

Unnamed 

waterbody

0.2 Stream Perennial ABCE g 20 None 

Borrow pit NA Man-made 

borrow pit

Open water ABCE g NA Dredge material 

placement

KMLP Facilities

Low Pressure Header Pipeline

S1AAC011 0.0 Tributary Intermittent ABCE g 4 Wet or dry crossing

S1AAC010 h 0.0 Agricultural ditch Ephemeral ABCE g 2 Construction 

workspace for 

access road

S1AAC009 0.3 Roadside ditch Ephemeral ABCE g 1 Bored crossing

S1AAC002 0.3 Roadside ditch Ephemeral ABCE g 2 Bored crossing

S1AAC005 0.6 Agricultural ditch Intermittent ABCE g 4 Wet or dry crossing

S1AAC003 0.9 Agricultural ditch Ephemeral ABCE g 5 Wet or dry crossing

S1AAC002 1.2 Roadside ditch Ephemeral ABCE g 2 Bored crossing

S1AAC001 1.2 Roadside ditch Ephemeral ABCE g 3 Culvert Installation

High Pressure Header Pipeline

S1AAC005 0.6 i Agricultural ditch Intermittent ABCE g 4 Wet or dry crossing

Compressor Station 760

S1AAC005 NA Agricultural ditch Intermittent ABCE g 4 Construction 

workspace

S1AAC006 NA Tributary Intermittent ABCE g 4 Culvert installation

S1AAC007 h NA Agricultural ditch Ephemeral ABCE g 4 Construction 

workspace

S1AAC008 h NA Agricultural ditch Ephemeral ABCE g 4 Construction 

workspace

S1AAC002 NA Roadside ditch Ephemeral ABCE g 2 Culvert installation
4-27

TABLE 4.3.2-1 (cont’d)

Waterbodies Potentially Affected by the LNG Terminal and KMLP Facilities

Facility/Waterbody Milepost Description Type

Water Quality 

Classification a

Crossing

Width 

(feet)

Impact

Profile

ANR Meter Station 

S1AAC001 NA Roadside ditch Ephemeral ABCE g 3 Construction 

workspace

TGT Meter Station

S1AAC010 h NA Agricultural ditch Ephemeral ABCE g 1 Culvert installation

______________________

a Louisiana State Water Quality Classifications (LDEQ, 2013a). 

Designated uses include:

A = Primary Contact Recreation

B = Secondary Contact Recreation

C = Fish and Wildlife Propagation

D = Oyster Propagation

E = Agriculture

b Designated as a section 10 waterbody under the RHA. 

c Designated as EFH under the MSA.

d The portion of the Calcasieu River that LNG carriers would transit is within subsegment LA030401, which fully supports 

each of its designated uses (LDEQ, 2013a). 

e The Industrial Canal is within subsegment LA031101, which does not support its designated use for primary contact 

recreation or fish and wildlife propagation. Therefore, this subsegment is included on Louisiana’s 2012 Section 303(d) 

List (LDEQ, 2013a). 

f The COE, New Orleans District did not include waterbody S1ACA001 in its May 14, 2014 jurisdictional determination for 

the LNG terminal site; therefore, this waterbody is not defined as a water of the United States under section 404 of the 

CWA. However, because it had flowing water at the time of delineation it is included in our analysis.

g Waterbody is not classified by the LDEQ; therefore, the waterbody classification is representative of the subsegment 

watershed in which the waterbody is located (LDEQ, 2004).

h The COE, New Orleans District did not include waterbodies S1AAC007, S1AAC008, and S1AAC010 in its September 10, 

2014 jurisdictional determinations for the KMLP facilities; therefore, these waterbodies are not defined as a water of the 

United States under section 404 of the CWA. However, because they had flowing water at the time of delineation, they 

are included in our analysis.

i Because the high pressure header pipeline would be 700 feet in length, the milepost provided corresponds to the nearest 

milepost on the adjacent low pressure header pipeline.

KMLP Facilities 

The KMLP facilities would be within the Mermentau River Basin, which covers an area of 

approximately 3,710 square miles. The Mermentau River Basin is in southwestern Louisiana and is 

bordered on the north and east by the Vermilion – Teche River Basin, on the west by the Calcasieu River 

Basin, and on the south by the Gulf of Mexico. Because of relatively low relief, the basin is characterized 

by annual backwater flooding of agricultural lands, poor drainage, and salt water intrusion along the Gulf 

of Mexico. Low stream flows generally occur during warm weather in September and October (LDEQ, 

2008).

Ten waterbodies occur within the areas affected by the KMLP facilities, including three 

intermittent waterbodies and seven ephemeral waterbodies. Table 4.3.2-1 identifies the waterbodies 

affected by the KMLP facilities, including the waterbody name, location, description, waterbody type, 

water quality classification, and crossing length.

None of the waterbodies affected by the KMLP facilities are listed as Louisiana Wild and Scenic 

Rivers, designated as EFH, contain federally or state-listed species, or are suspected of containing 

contaminated sediments (LDWF, 2012; LDEQ, 2013a). All of the waterbodies currently support their 
4-28

designated uses, with the exception of fish and wildlife propagation. The suspected cause of impairment 

is identified as total dissolved solids associated with agricultural activities (LDEQ, 2013a). No surface 

water intakes are within 3 miles of the aboveground facilities or header pipeline crossing locations 

(Louisiana Department of Health and Hospitals, 2006).

4.3.2.2 Surface Water Impacts and Mitigation

Impacts on surface waters resulting from construction and operation of the LNG terminal and 

KMLP facilities and the measures proposed by Magnolia and KMLP to avoid or minimize impacts on 

surface waters are described below. 

LNG Terminal

Table 4.3.2-1 describes the surface waters that would be affected as a result of construction and 

operation of the LNG terminal. Potential impacts on surface waters during construction and operation of 

the LNG terminal are associated with dredging, construction of the LNG loading and ship berthing

facilities, vessel traffic, site modification and stormwater runoff, hydrostatic testing, operation of the LNG 

storage tank deluge system, and spills or leaks of hazardous materials. The following sections describe 

these potential impacts as well as measures proposed by Magnolia to minimize impacts on surface waters. 

Dredging

To create the recessed berthing area and accommodate a fully loaded LNG carrier, a 16.2-acre 

area (composed of 9.8 acres of existing open water within the Industrial Canal, 5.4 acres of existing 

uplands, and 1.0 acre of existing wetlands) would be dredged to an elevation of 44 feet below NAVD 88.5 

As described in additional detail in section 2.5.1.4, a combination of onshore excavation and dredging 

would be used to construct the ship berthing area, which would be recessed into the northern boundary of 

the LNG terminal site. Approximately 131,200 yd3 of upland soils along the bank of the Industrial Canal 

would be excavated and relocated on site using backhoes, front-end loaders, bulldozers, and similar 

equipment. Following the excavation and relocation of upland soils, approximately 862,550 yd3 of 

sediment and soil would be removed from the berthing area using a hydraulic cutterhead dredge. 

Dredging is currently expected to take place over a 12-week period.

Dredge material would be transported by pipeline to the placement area, which is approximately 

8,000 feet east of the LNG terminal (as depicted in figure 2.2.1-2 in section 2.2.1). The dredge material 

and effluent pipeline route would cross one perennial waterbody; however, no in-water impacts would 

occur because the pipeline would cross the waterbody along an existing road where a culvert is in place. 

A 33.5-acre borrow pit is present in the northern portion of the dredge material placement area, which 

currently contains approximately 60.6 million gallons of water. Prior to the commencement of dredging 

activities, water within the borrow pit would be removed and discharged into the Industrial Canal via the 

proposed effluent return pipeline (described in detail in section 2.5.1.4). Throughout dredging operations, 

dredge materials would be discharged to the placement area and allowed to dewater, after which the 

decanted water would be pumped through the effluent return pipeline and discharged back into the 

Industrial Canal. In total, Magnolia anticipates that a total of 252 million gallons of water from 

dewatered dredge spoil would be returned to the Industrial Canal.

Potential impacts on water quality in the Industrial Canal resulting from dredging and the 

subsequent discharge of water back to the canal would include temporary increases in suspended solids

and turbidity levels as well as potential resuspension of contaminated sediments. Increased suspended 

 

5

In order to accommodate fully loaded LNG carriers and provide clearance during low tide, the design depth of the recessed berthing area is 

42 feet below NAVD 88. An advance maintenance allowance of 2 feet is proposed.
4-29

sediment and turbidity levels could cause a reduction in light penetration through the water column,

which could lower the rate of photosynthesis, introduce organic material and/or nutrients that could lead 

to an increase in biological oxygen demand and reduce dissolved oxygen, and alter water circulation and 

flow patterns. The COE and Lake Charles Harbor and Terminal District partner to conduct maintenance 

dredging within the Industrial Canal, which is expected to occur every other year to maintain deep draft 

access (COE, 2015b). This routine dredging, combined with existing vessel traffic associated with 

operation of other facilities along the canal, causes sustained high and variable turbidity levels within the 

Industrial Canal. 

Magnolia would conduct dredging using a hydraulic cutterhead suction dredge. This dredging 

method minimizes turbidity from resuspension of the sediment in the water column and other water 

quality impacts. To further minimize these impacts, Magnolia has prepared a preliminary Dredging 

Water Quality Monitoring Plan. This plan calls for the use of best management practices during dredging 

and disposal activities and requires monitoring of turbidity, flow rate, pH, and total suspended solids at 

three locations, including two locations near dredging operations and one at the effluent outfall. If 

monitoring within the dredge area indicates that total suspended solid or turbidity levels exceed the limits 

established by the plan or the COE or EPA permit requirements, Magnolia would implement the 

following:

 reduction of cutterhead rotation speed to reduce potential for side casting sediment away 

from the suction entrance and re-suspending sediment (typically effective on relatively 

loose, fine grain sediment);

 reduction of swing speed to ensure that the dredge head does not move through the cut 

faster that it can hydraulically pump the sediment, thus reducing resuspended sediment;

 reduction or elimination of bank undercutting by removing the sediment in maximum 

lifts equal to 75 percent of the cutterhead diameter; and/or

 termination of suction pump motor after cutterhead during shutdown and commencement 

of the suction pump before cutterhead during startup to avoid a period when materials are 

resuspended without active suction occurring. 

If monitoring near the effluent outfall indicates that total suspended solid or turbidity levels 

exceed the limits established by the plan or the COE or EPA permit requirements, Magnolia would 

implement the following:

 suspension of dredging operations to allow suspended sediments to settle;

 adjustment of interior channelization within the placement area to improve sedimentation 

rate; and/or

 installation of sediment/turbidity curtains within the placement area.

Magnolia has stated that it would finalize the Dredging Water Quality Monitoring Plan prior to 

commencement of dredging operations. Therefore, we recommend that:

 Prior to construction, Magnolia file with the Secretary, for review and written 

approval by the Director of OEP, its final Dredging Water Quality Monitoring Plan.
4-30

As discussed in section 4.2.2, Magnolia’s soil sampling and analysis conducted at the LNG 

terminal site and within the Industrial Canal determined that the sediments to be dredged from within the 

Industrial Canal do not contain contaminated dredge material. As described above, the COE, New 

Orleans District reviewed the results of the sampling and determined that sediments at the LNG terminal

meet the LDEQ’s working definition of uncontaminated dredge material. In May 2014, Magnolia applied

for authorization from the COE, New Orleans District to dredge and/or fill of waters of the United States

under section 404 of the CWA and section 10 of the RHA (see discussion in section 4.4). Magnolia 

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). Therefore, we conclude that impacts on water quality 

due to the resuspension of contaminated sediments are not anticipated.

With the implementation of our recommendation, we conclude that dredging and the subsequent 

discharge of water back to the Industrial Canal would result in temporary and minor increases in turbidity 

and suspended solid levels, but would not result in permanent or long-term water quality impacts. 

During operation, maintenance dredging of the recessed berthing area would be required 

periodically to maintain adequate water depths for LNG vessel maneuvering. Magnolia would conduct 

maintenance dredging within the recessed berthing area every 4 to 5 years based on past shoaling rates 

within the Industrial Canal (COE, 2010a). Approximately 65,000 yd3 would be removed during each 

maintenance dredging episode. Maintenance material would be placed in an upland CDF in coordination 

with the Lake Charles Harbor and Terminal District. Although maintenance dredging would result in a 

temporary increase in suspended sediment and turbidity levels, these impacts are expected to be 

temporary and limited to the vicinity of dredging activity within the Industrial Canal. Therefore, we 

conclude that impacts on water quality due to maintenance dredging would be temporary and minor.

Construction of the LNG Loading and Ship Berthing Facilities

In-water construction associated with the LNG loading and ship berthing facilities would include 

the installation of:

 sheet pile bulkhead along the shoreline of the Industrial Canal;

 pilings for the breasting dolphins and LNG loading platform; and

 rock armoring at the base of the steel sheet pile bulkhead, along the east and west ends of 

the marine basin, and around the base of the LNG loading platform and breasting dolphin 

piles.

Construction of the LNG loading and ship berthing facilities would also require over-water and 

land-based equipment installation (e.g., LNG loading platform, terminal jetty/pier, pipe and roadway 

trestle, marine gangway, firewater monitor towers, and dry chemical system) (see figure 2.5.1-1 in 

section 2.5.1.4). 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 the bulkhead, pilings, and over-water structures. 

Construction of the LNG loading and ship berthing facilities would result in localized, temporary 

increases in turbidity and suspended sediment levels. However, these impacts are expected to be 

temporary (i.e., confined primarily to the period of in-water activity and shortly thereafter) and limited to 

the area within and immediately adjacent to the LNG loading and ship berthing facilities. No permanent 

or long-term water quality impacts are anticipated. 
4-31

Vessel Traffic

Shoreline Erosion and Resuspension of Sediments

During construction of the LNG terminal, barges and support vessels would deliver large 

equipment and materials to the DII construction yard. Magnolia estimates that 50 or fewer marine 

deliveries would occur during construction. During operation, approximately 208 LNG vessels 

(104 LNG carriers and 104 LNG barges) would call on the LNG terminal per year. 

During construction and operation, vessel traffic within the recessed berthing area and along 

vessel transit routes has the potential to increase shoreline erosion and suspended sediment concentrations 

due to increased wave activity. Shoreline erosion is a concern when hard structures are placed along the 

shoreline that could cause changes in wave dynamics and increase erosion of adjacent areas. As 

described above, Magnolia would install rock armoring to provide scour protection from propeller wash 

both within and along the east and west ends of the recessed berthing area. The proposed rock armoring 

would prevent erosion of the adjacent unprotected shoreline by wave activity from vessels maneuvering 

within the recessed berthing area (Moffatt and Nichol, 2014). The Industrial Canal and Calcasieu Ship 

Channel were specifically created to provide deepwater access for maritime commerce. They are 

managed by the Port of Lake Charles, a deepwater seaport, and are maintained by regular dredging (COE, 

2015b). Similarly, LNG carriers transiting the Gulf of Mexico would use established shipping channels. 

As such, use of the waterways by LNG carriers, barges, and support vessels during construction and 

operation of the LNG terminal would be consistent with the planned purpose and use of active shipping 

channels, and associated impacts on water quality within the shipping channel would be minor.

Ballast Water Discharge

LNG carriers serving the LNG terminal would likely arrive with empty cargo tanks because they 

would be loaded at the terminal with LNG destined for export. Vessels with empty cargo tanks ride 

higher in the water and can experience challenges associated with navigation due to the extra sail area 

(ship surface area above the water line). Challenges include the vessel being more susceptible to wind 

influences and less efficient as a result of reduced performance of the propeller, rudder, and propulsion 

system. To reduce or eliminate the challenges of navigating the ship without cargo aboard, water is often 

taken in from the surrounding waters and placed in ballast tanks to provide additional draft and improve 

navigation. To maintain a constant draft, ballast water is typically discharged below the water surface as 

the LNG cargo is loaded. This procedure would likely occur aboard LNG carriers calling at the LNG 

terminal; however, LNG barges have a different design and are unlikely to have the need for or capability 

of using ballast water.

Based on information provided by Magnolia, the amount of ballast water discharged during LNG 

cargo loading would range from approximately 8,711,000 to 12,264,000 gallons, depending on the size of 

the LNG carrier. Ballast water discharge periods would vary but, generally, vessels would discharge a 

volume equal to 10 percent of their LNG capacity each hour. For example, a 155,000 m3 LNG vessel 

(with a ballast of approximately 8,711,000 gallons) would discharge approximately 581,000 gallons per 

hour, or 21.5 cubic feet per second, over a 15-hour period.

As required by 33 CFR 151.2026, vessels equipped with ballast tanks must implement one of five 

options to control nonindigenous species in waters of the United States. The IMO has adopted this 

regulation and requires each vessel to install and operate a ballast water management system (option 1 as 

currently defined). Compliance dates associated with this IMO requirement will be phased, but will apply 
4-32

to all vessels beginning in 2016.6 Until this rule is fully implemented, Magnolia has stated that it would 

require LNG carriers to conduct 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 less distant from the shoreline, which is authorized under 

33 CFR 151.2040. Therefore, ballast water that is likely to be introduced into the Industrial Canal would 

be composed mainly of open ocean water collected during ballast water exchange (see additional 

discussion in section 4.6.2.2).

Ballast water discharges at the LNG terminal could impact water quality by changing the salinity, 

temperature, pH, and dissolved oxygen level of water within the Industrial Canal. The physiochemical 

composition of ballast water in comparison to the water present within the Industrial Canal and Calcasieu 

River would vary depending on tidal and hydrologic conditions at the time of discharge. 

The primary potential impact on water quality due to ballast water discharge would be a 

temporary increase in salinity level. As described above, salinity within the canal varies throughout the 

year (between about 5 and 32 ppt during the period measured) (LDWF, 2014b), and tends to increase with 

water depth. Ballast water, which would generally consist of open ocean water, would have a salinity 

between 32 and 37 ppt (U.S. Department of the Navy, Office of Naval Research, 2015). Because of the 

natural variability in salinity levels in the canal, the discharge of ballast water may not have a measurable 

impact on salinity under normal tidal cycles. However, during periods of heavy rainfall when salinity 

levels decrease in the Industrial Canal, ballast water would have a higher salinity than the surrounding 

water. Ballast water would be discharged near the bottom of the berthing area, where relatively dense 

saltwater from the Gulf of Mexico characteristically underlies freshwater from inland sources, with a 

resulting salinity range between 17 and 32 ppt. Furthermore, the amount of ballast water discharged into 

the Industrial Canal during each LNG carrier visit to the LNG terminal would make up approximately 

0.6 percent of the approximately 2 billion gallons of water within the Industrial Canal. Therefore, we 

anticipate that natural flow and tidal exchange would dilute the ballast water discharge to salinity levels 

that typically occur within the Industrial Canal in the immediate vicinity of the LNG terminal and 

conclude that increased salinity would represent a temporary and minor impact on water quality within 

the Industrial Canal. 

Ballast water is stored in the ship’s hull below the waterline; as a result, discharged water 

temperatures are not expected to deviate markedly 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). Although pH within the Industrial Canal can be lower than seawater (generally ranging from 

7.4 to 8.6), it varies over space and time (LDWF, 2014b). Therefore, impacts on water temperature and 

pH would be temporary and minor. 

Another water quality parameter that may be influenced by ballast water discharges is dissolved

oxygen level. Dissolved oxygen levels in water are dependent upon many factors including temperature, 

rainfall, tidal magnitude, depth, currents, and phytoplankton activity. Ballast water would contain low 

dissolved oxygen levels and could decrease existing dissolved oxygen levels in the immediate vicinity of 

the discharge point. However, low dissolved oxygen levels (0 to 4 mg/L) are naturally found in the 

deeper zones of the Industrial Canal, particularly during warm summer months (LDWF, 2014b). 

Additionally, as noted previously, the relative minimal volume of discharged ballast water compared to 

the water volume of the Industrial Canal (less than 0.6 percent) would make effects to dissolved oxygen

from ballast discharge temporary and minor.

 

6 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 m3that have been drydocked since January 1, 2014. Compliance by existing vessels with ballast water capacity less than 

1,500 m3 or greater than 5,000 m3 will be required as of the vessel’s first scheduled drydocking after January 1, 2016.
4-33

To minimize impacts on water quality and ensure compliance with U.S. laws and regulations 

governing ballast water discharges, upon entry into the recessed berthing area and as part of the LNG 

terminal operating procedures, Magnolia staff would review any applicable documentation that the 

visiting vessel is operating in accordance with federal standards and practices prior to discharging any 

ballast water. Therefore, we conclude that impacts on surface waters would occur as a result of ballast 

water discharge would be temporary and minor.

Cooling Water Discharge

During operation, LNG carriers and LNG barges require water for cooling of the main 

engine/condenser, diesel generators, and fire main auxiliary and hotel services (Hunt, 2003). The volume 

of water required for cooling varies depending on what mode of operation the vessel is in (i.e., transit, 

maneuvering, in-port). Transit mode would be used during open ocean transit. Magnolia indicated that 

the LNG carrier would be operating in maneuvering mode from the time it embarks the pilot at the 

Calcasieu “CC” buoy until it is berthed at the LNG terminal. While at the LNG terminal (in-port mode), 

LNG carriers would need cooling water for the auxiliary diesel engines that are used to generate electrical 

power for onboard systems while loading.

As shown in table 4.3.2-2, water required for engine cooling would vary greatly based on the type 

of vessel calling on the LNG terminal. Steam-powered LNG carriers (maximum LNG capacity of 

138,000 m3) would have the highest cooling water requirements, using 11.7 million gallons of water for 

engine cooling during maneuvering and while docked at the LNG terminal.

7

 During the same period, 

LNG carriers with dual fuel/diesel electric engines (maximum LNG capacity of 218,000 m3) would use 

5.5 million gallons of water. LNG barges would require only 535 gallons of water due to their smaller 

size (maximum LNG capacity of 15,000 m3), increased maneuverability, and reduced time spent at the 

LNG terminal. 

TABLE 4.3.2-2

Estimates of LNG Carrier Cooling Water Use and Intake Rates at the LNG Terminal

Vessel Type

Time to 

Maneuver

(hours)

Time to 

Load 

(hours)

Maneuvering

Rate 

(gallons per 

hour)

Maneuvering 

Volume 

(gallons)

In-port Rate 

(gallons per 

hour)

In-port

Volume 

(gallons)

Total Volume 

(gallons)

Duel fuel/diesel electric 

LNG carrier

2 18 1,680,000 3,360,000 120,000 2,160,000 5,520,000

Steam-powered 

LNG carrier

3 18 2,820,000 8,460,000 180,000 3,240,000 11,700,000

Articulated tug/barge 1.25 4 300 375 40 160 535

Impacts on surface waters as a result of cooling water intake and discharge would be primarily 

limited to an increase in water temperature in the vicinity of the LNG vessel. Cooling water return 

temperatures vary widely depending on the type of LNG carrier and mode of operation. Based on a 

review of available information, we anticipate that cooling water discharged at the LNG terminal could 

range between 2.7  ̊F and 7.2 °F warmer than ambient water temperatures (Caterpillar, 2007, 2011, 2012). 

Due to the limited temperature differences, relatively small volume of discharge compared to the total 

water within the Industrial Canal (approximately 0.6 percent), and location within an active port that is 

already subject to withdrawals and discharges of vessel engine cooling water, we anticipate that the 

 

7 Cooling water requirements at the LNG terminal assume that LNG carriers and LNG barges would depart the terminal immediately after 

completion of the 18-hour and 4-hour loading process, respectively. Therefore, the cooling water requirements do not take into account 

potential delays due to inclement weather or other users of the Industrial Canal and Calcasieu Ship Channel. 
4-34

increased water temperature levels would diminish shortly after discharge and, therefore, would have 

temporary and minor impacts on water quality. Information on the effects of cooling water intakes and 

discharges on aquatic resources is presented in section 4.6.2.2.

While in transit through the Gulf of Mexico, the temperature of water used for engine cooling 

could increase by as much as 9.5  ̊F. However, due to the volume of water within the Gulf of Mexico and 

the use of established shipping lanes where frequent vessel traffic would increase the speed at which the 

warmer water would be diluted to ambient temperatures, we conclude that increased water temperatures 

would have a negligible impact on water quality within the Gulf of Mexico. 

Site Modification and Stormwater Runoff

During site preparation activities at the LNG terminal, one intermittent stream within the LNG 

terminal site and the 33.5-acre borrow pit within the dredge material placement area would be filled. This 

intermittent stream is not hydrologically connected to the Industrial Canal and likely serves as a drainage 

pathway for adjacent upland areas. The COE, New Orleans District did not include this waterbody in its 

May 14, 2014 jurisdictional determination for the LNG terminal site; therefore, this waterbody is not 

defined as a water of the United States under section 404 of the CWA, and mitigation for the fill of this 

waterbody would not be required. 

Prior to the commencement of dredging activities, the borrow pit would be drained and the water

(approximately 60.6 million gallons) would be pumped back to the eastern end of the Industrial Canal 

using the temporary effluent pipeline, where it would be discharged in accordance with federal and state 

permit requirements. Dredge material placement would result in the borrow pit being permanently filled 

and converted to upland grassland or meadow habitat. Impacts on the borrow pit would be permanent; 

however, if determined to be jurisdictional by the COE, New Orleans District, impacts would be fully 

mitigated through implementation of Magnolia’s project-specific Compensatory Mitigation Plan (see our 

recommendation in section 4.4.1 as well as section 4.4.4 for additional information). Upon completion of 

dredge material placement and dewatering, the earthen dikes within the dredge material placement area 

would be graded to facilitate drainage of the site and minimize erosion, and the area would be reseeded. 

Ground disturbance and filling two waterbodies during construction would increase stormwater 

discharges, resulting in a temporary increase in suspended sediment levels. As described in section 4.2.2, 

there are no contaminated soils within the LNG terminal site, including the portion of the site within the 

Industrial Canal. Therefore, increased stormwater runoff is not expected to result in the introduction of 

contaminated sediments to surface waters within the Industrial Canal. To minimize impacts on water 

quality due to increased stormwater runoff, land disturbing activities would be conducted in compliance 

with the LPDES, General Permit for stormwater discharges from construction activities of 5 acres or 

more; Magnolia’s project-specific Construction SWPPP; and Magnolia’s Plan and Procedures. Measures 

to control erosion and sedimentation during construction are discussed in detail in section 4.2.3.

Operation of the LNG terminal would increase the amount of impervious surface, which would 

result in an increased volume of stormwater runoff. Stormwater would be directed into two holding 

basins (east and west) for dilution and temperature adjustment to ambient levels before being discharged 

into the Industrial Canal in accordance with Magnolia’s Operational SWPPP, and LDEQ and EPA 

requirements. With the implementation of these mitigation measures, we have determined that 

stormwater discharges resulting from construction and operation of the LNG terminal would result in 

temporary and minor impacts on surface waters. 
4-35

Hydrostatic Testing

Magnolia would hydrostatically test the integrity of the dredge material and effluent pipelines 

before beginning dredging activities. Similarly, before being placed into service, plant piping and the 

LNG storage tanks would be hydrostatically tested. Both municipal sources and surface waters would be 

used for hydrostatic testing. For each component requiring hydrostatic testing, table 4.3.2-3 identifies the 

volume of water required, proposed water source, and discharge location. 

TABLE 4.3.2-3

Hydrostatic Test Water Requirements for the LNG Terminal

Component Tested Water Source Discharge Location

Volume Required 

(gallons)

Dredge material and effluent 

pipelines

Borrow pit or Industrial Canal Industrial Canal 1,000,000

Plant piping Calcasieu Parish District No. 12 

Water Works

Stormwater holding basin 20,000

Magnolia Meter Station and 

interconnect pipeline

City of Lake Charles Meter station site 13,000

LNG storage tanks Industrial Canal Industrial Canal 26,200,000

LNG storage tank cleaning after 

completion of hydrostatic test

Calcasieu Parish District No. 12 

Water Works

Industrial Canal 27,000

Hydrostatic test water used for the dredge material and effluent pipelines would be obtained from 

either the borrow pit within the dredge material placement area or the Industrial Canal. Following the 

completion of hydrostatic testing, water would be discharged into the Industrial Canal.

To test plant piping, Magnolia would obtain approximately 20,000 gallons of water from the 

proposed tie-in to Calcasieu Parish District No. 12 Water Works line that runs along the southern 

boundary of the LNG terminal. To minimize the volume of water, Magnolia would recycle the water 

over five intervals; between tests, the water would be held in a water tank. Following completion of the 

final test, water would be discharged on site into a stormwater holding basin prior to ultimate discharge 

into the Industrial Canal. 

To test the Magnolia Meter Station and interconnect pipeline, KMLP would obtain approximately 

13,000 gallons of water from the City of Lake Charles, which would be trucked to the LNG terminal site. 

Following completion of the final test, water would be discharged on site to the southeastern corner of the 

Magnolia Meter Station site. 

To test the LNG storage tanks, approximately 26.2 million gallons of water would be withdrawn 

from the Industrial Canal through screened intake hoses at rates ranging from 1,500 to 3,333 gallons per 

minute. As with the plant piping, Magnolia proposes to conduct hydrostatic testing of the LNG storage 

tanks independently, allowing the water to be reused. Because water from the Industrial Canal would be 

used to test the storage tanks, as the hydrostatic test water is discharged, the tank walls would be washed

with a total of approximately 27,000 gallons of potable water to remove any silt particles that adhere to 

the walls of the tanks. Both hydrostatic test and LNG storage tank wash water would be discharged to the 

Industrial Canal. A detailed description of the hydrostatic test process for the LNG storage tanks is 

provided in section 2.5.1.6. 

To minimize potential impacts on water quality, no chemical additives would be used in 

association with hydrostatic testing, and Magnolia and KMLP would comply with all testing requirements 
4-36

and environmental conditions of the LPDES General Permit for Discharges of Hydrostatic Test Water. 

Therefore, we conclude that impacts on surface waters as a result of hydrostatic testing would be 

negligible.

LNG Storage Tank Deluge System

During operation of the LNG terminal, an LNG storage tank deluge system would be used to 

distribute water over the LNG storage tank’s outer surfaces for cooling in the event of a fire on the 

adjacent tank. The deluge system would be operated in the event of a fire emergency as well as 

periodically for system maintenance and testing. When in operation, the fire deluge pumps would 

appropriate water from the Industrial Canal at a rate of up to 6,300 gallons per minute. Water used for 

deluge purposes would be directed into two holding basins (east and west) before being discharged back 

into the Industrial Canal. Because of the infrequent operation of the system and eventual discharge of the 

water back into the Industrial Canal, we conclude that the LNG storage tank deluge system would have 

negligible impacts on water quality within the Industrial Canal. 

Spills

During construction and operation, hazardous materials resulting from spills or leaks flushed into 

waterbodies with stormwater runoff or entering the Industrial Canal and the Calcasieu River could have 

an adverse impact on water quality. To prevent spills and leaks, Magnolia would implement its projectspecific Spill Prevention Plan during construction and its SPCC Plan during operation of the LNG 

terminal, which outline potential sources of releases at the site, measures to prevent a release, and initial 

responses in the event of a spill (see our recommendation and additional discussion in section 4.2.3.1). 

Given the impact minimization and mitigation measures described above, we conclude that impacts on 

surface waters due to spills or leaks during construction and operation of the LNG terminal would be 

temporary and minor.

KMLP Facilities

Header Pipelines

Seven waterbodies (two intermittent and five ephemeral) would be affected by construction and 

operation of the low and high pressure header pipelines (see table 4.3.2-1). Two of the affected 

waterbodies are adjacent to roads that would be crossed using the conventional bore method. This 

crossing method is designed to avoid disturbing the bed or bank of the waterbodies. Three waterbodies

would be crossed using dry crossing construction techniques (i.e., dam-and-pump or flume method) if 

flowing water is present within the waterbodies at the time of construction; if no water is present at the 

time of construction, traditional upland installation techniques would be used. One waterbody is within a 

construction workspace associated with an access road, and impacts on the final waterbody would be 

limited to installation of a culvert. 

Activities associated with construction of the header pipelines include clearing and grading, 

in-stream trenching, trench dewatering, and backfilling. These activities could increase sedimentation 

rates, turbidity levels, and water temperature; decrease dissolved oxygen concentrations; and release 

chemical or nutrient pollutants from sediments. In addition, refueling of vehicles and storage of fuel, oil, 

or other hazardous materials near surface waters could result in accidental spills that could contaminate 

surface waters.

KMLP would minimize potential impacts on surface waters by implementing the FERC 

Procedures and by utilizing dry crossing techniques, if flowing water is present at the time of 
4-37

construction. Dry crossing methods isolate the in-stream trenching activities from flowing water. In 

order to minimize potential impacts associated with an accidental spill of fuel, oil, or other hazardous 

materials, KMLP would implement its project-specific SPCC Plan, which identifies potential sources of 

hazardous materials present during construction activities and the measures that would be implemented to 

prevent, contain, and clean up accidental releases. With the implementation of these plans and the FERC

Procedures, impacts on water quality in the event of a spill or leak are expected to be minor. 

Impacts on surface waters are not expected during operation of the header pipelines because no 

further in-stream activities are 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 (e.g., 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.

Aboveground Facilities

Construction of Compressor Station 760 would result in temporary impacts on two intermittent 

and three ephemeral waterbodies. One waterbody (S1AAC006) is within the permanent footprint of the 

facility; however, impacts would be limited to the installation of a culvert (no permanent fill would 

occur). 

Modifications at the ANR Meter Station would result in temporary impacts on one ephemeral 

roadside ditch, which parallels the southern boundary of the temporary workspace at the site. One 

waterbody (an ephemeral agricultural ditch) parallels the southern boundary of the TGT Meter Station; 

impacts on this waterbody would be limited to the installation of a culvert. 

Impacts on water quality associated with construction of Compressor Station 760 and 

modifications at the ANR and TGT Meter Stations would be similar to those described above and would 

be minimized through the implementation of the FERC Procedures and KMLP’s project-specific SPCC 

Plan (see Header Pipelines, above).

Hydrostatic Testing

The header pipelines would be hydrostatically tested prior to being placed into service to ensure 

structural integrity in accordance with DOT standards (49 CFR 192). A detailed description of the 

hydrostatic test process is provided in section 2.5.2.1. Approximately 346,000 gallons of water would be 

required to complete hydrostatic testing of the header pipelines and meter station modifications 

(320,000 gallons for the low pressure header, 16,000 gallons for the high pressure header, and 

10,000 gallons for the meter station modifications). To minimize the volume of water, KMLP would 

recycle the water used to test the meter station modifications; between tests, the water would be held in a 

water truck. As described in section 4.3.1.4, KMLP proposes to obtain water for hydrostatic testing 

activities from the City of Eunice, which would be transported by truck to the construction right-of-way.

After successful completion of hydrostatic testing, water would be discharged to an agricultural

area within the compressor station site using energy dissipation devices as needed to minimize erosion 

and sedimentation. KMLP would not add any chemicals to the hydrostatic test water, and the discharged 

water would be tested, monitored, and reported in accordance with the LPDES Hydrostatic Test Water 

Discharge Permit (Permit Number LAG670000).8 In addition to complying with the requirements of the 

 

8 Permit LAG670000 requires testing for flow rate, total suspended solids, oil and grease, total organic content, benzene, BTEX, lead, and pH 

prior to initiating discharge as well as daily for the first week of discharge. If the discharge extends beyond one calendar week, weekly 

sampling is required. Discharge Monitoring Reports are required to be submitted to the LDEQ on a quarterly basis.
4-38

LPDES Hydrostatic Test Water Discharge Permit, KMLP would minimize the environmental impacts 

from the discharge of hydrostatic test water by implementing the measures outlined in the FERC

Procedures, which include:

 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.

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.

Wetlands are protected under section 404 of the CWA, which is implemented by the COE, New 

Orleans District. Section 404 establishes standards to evaluate and reduce total and net impacts on 

wetlands under the jurisdiction of the COE. These standards require avoidance of wetlands where 

possible and minimization of disturbance where impacts are unavoidable, to the degree practicable. 

Magnolia and KMLP must also demonstrate that appropriate steps have been taken to minimize wetland 

impacts, in compliance with the COE’s section 404(b)(1) guidelines that restrict discharges of dredged or 

fill material where less environmentally damaging alternatives exist. 

Wetland impacts authorized under section 404 of the CWA also require state water quality 

certification under section 401 of the CWA. Water quality certification has been delegated to the state 

agencies (in the State of Louisiana, the LDEQ has jurisdiction over section 401 of the CWA), with review 

by the EPA.

4.4.1 Existing Wetland Resources

Magnolia conducted wetland delineations at the LNG terminal in July 2013; KMLP conducted 

wetland delineations at the Magnolia Meter Station and along the interconnect pipeline within the LNG 

terminal and at the KMLP facilities in March 2014. Wetland delineations were performed in accordance 

with the COE’s Wetlands Delineation Manual and the Atlantic and Gulf Coastal Plain regional 

supplement, which require the identification of wetlands based on the presence of three parameters: 

hydrophytic vegetation, hydric soils, and wetland hydrology (Environmental Laboratory, 1987; COE, 2010b).

Wetland types identified during surveys within the proposed LNG terminal site and KMLP 

facilities were classified as palustrine emergent, palustrine scrub-shrub, and estuarine intertidal emergent 

wetlands. Palustrine wetlands are defined as non-tidal wetlands dominated by trees, shrubs, persistent 

emergent vegetation, emergent mosses, or lichens, and all such wetlands that occur in tidal areas where 

salinity due to ocean-derived salts is below 0.5 parts per trillion. Palustrine wetlands have traditionally 

been called marshes, swamps, bogs, fens, and prairies, and may include small shallow permanent and 
4-39

intermittent waterbodies referred to as ponds. Estuarine wetlands are defined as tidal wetlands that are 

usually semi-enclosed by land, but have open, partly obstructed, or sporadic access to the open ocean, and 

in which ocean water is at least occasionally diluted by freshwater runoff from land (Cowardin et al., 1979). 

To date, access has not been granted to conduct the necessary wetland delineations along the 

dredge material and effluent pipeline route or within the dredge material placement area. Therefore, NWI 

data and aerial photography were used to identify wetlands within these areas. Because Magnolia has not 

yet conducted wetland delineations within these areas, we recommend that:

 As soon as they are available and prior to the start of construction, Magnolia file 

with the Secretary, for review and written approval by the Director of OEP, the 

results of the wetland and waterbody surveys within areas associated with the 

transport and placement of dredge materials.

4.4.1.1 LNG Terminal

Palustrine emergent and scrub-shrub wetlands are the most common wetland type within the 

LNG terminal site. Palustrine emergent wetlands are present within the southern and western portions of 

the site. Dominant vegetation within the four palustrine emergent wetlands at the LNG terminal includes

goldenrod (Solidago sempervirens), sand spikerush (Eleocharis montevidensis), dwarf spikerush 

(Eleocharis parvula), peppervine (Ampolopsis arborea), cattail (Typha latifolia), bulrush (Scirpus 

robustus), and salt bush (Baccharis halimifolia). One palustrine scrub-shrub wetland is present in the 

southern portion of the site in the vicinity of the Magnolia Meter Station. Species likely present within 

the scrub-shrub wetland include the species described above as well as eastern false-willow (Baccharis 

halimifolia), small spikerush (Eleocharis minima), southern bayberry (Myrica cerifera), bushy bluestem

(Andropogon glomeratus), soft rush (Juncus effusus), and Chinese tallow (Triadica sebifera).

One estuarine intertidal emergent wetland occurs along the fringe of the south bank of the 

Industrial Canal on the northern edge of the LNG terminal. This wetland is a brackish marsh with 

dominant vegetation of common reed (Phragmites austrilis), salt bush, cordgrass (Spartina alterniflora 

and S. spartinae), sea oxide daisy (Borrichia frutescens), and bulrush.

As described above, NWI data and aerial photography were used to identify wetlands along the 

dredge material and effluent pipeline routes and within the dredge material placement area. Land along 

the dredge material and effluent pipeline routes is graveled or paved, and does not appear to contain 

wetlands. Two small wetlands are present within the southern portion of the dredge material placement 

area, including one palustrine emergent wetland and one palustrine forested/scrub-shrub wetland. 

Wetland species present within the palustrine emergent wetland are likely to be similar to those described 

above within the LNG terminal site. Wetland species likely to be present within the forested/scrub-shrub 

wetland include willow (Salix nigra), slash pine (Pinus elliotti), loblolly pine (Pinus taeda), salt bush, 

American beautyberry (Callicarpa americana), yaupon (Ilex vomitoria), smartweed (Polygonum 

hydropiperoides), slender arrowhead (Sagittaria graminea), and wingleaf primrose-willow (Ludwigia 

decurrens).

4.4.1.2 KMLP Facilities

Palustrine emergent wetlands are the only wetland type within the KMLP facilities. Based on 

field observations and visual inspection of aerial photographs, wetlands within and adjacent to the KMLP 

facilities are largely within previously disturbed areas adjacent to existing facilities and roadways. 

Dominant vegetation within these emergent wetlands includes dwarf spikerush, sedge (Cyperus sp.), 

Bermudagrass (Cynodon dactylon), grassleaf rush (Juncus marginatus), and torpedograss (Panicum repens).
4-40

4.4.2 Wetland Impacts and Mitigation

4.4.2.1 LNG Terminal

Construction of the LNG terminal would result in the permanent loss of 16.2 acres of wetlands, 

including 8.1 acres of palustrine emergent wetlands, 6.6 acres of palustrine scrub-shrub wetland, 1.0 acre 

of estuarine emergent intertidal wetland, and 0.5 acre of palustrine forested/scrub-shrub wetland (see table 

4.4.2-1). Approximately 87 percent (14.0 acres) of the wetlands would be converted to upland industrial

or open land within the LNG terminal site, 7 percent (1.2 acres) would be converted to an upland 

herbaceous community within the dredge material placement area, and the remaining 6 percent (1.0 acre) 

would be converted to open water within the recessed berthing area or filled for shoreline stabilization. In 

its jurisdictional determination for the LNG terminal (COE, 2014a), the COE determined that wetlands 

delineated by KMLP in the vicinity of the Magnolia Meter Station are not jurisdictional under section 404 

of the CWA. However, because these wetlands (a 7.9-acre palustrine emergent and scrub-shrub wetland 

complex and a less than 0.1 acre palustrine emergent wetland) meet the three parameters of a wetland 

(Environmental Laboratory, 1987), they are included in our analysis.

TABLE 4.4.2-1

Wetlands Affected by the LNG Terminal and KMLP Facilities (in acres) a

Facility Wetland ID Wetland Classification

Construction 

Impact (acres)

Operation

Impact (acres)

LNG TERMINAL FACILITIES

LNG terminal WW-001-001 Palustrine emergent 0.1 0.1

WW-001-002 Estuarine emergent intertidal 1.0 1.0

WW-001-003 Palustrine emergent 6.0 6.0

W1ACA001 b Palustrine emergent 1.3 1.3

W1ACA001 b Palustrine scrub-shrub 6.6 6.6

W1ACA002 b Palustrine emergent <0.1 <0.1

Dredge material placement area NWI 1 Palustrine forested/scrub-shrub 0.5 0.5

NWI 2 Palustrine emergent 0.7 0.7

Total for LNG Terminal Facilities 16.2 16.2

KMLP FACILITIES

High pressure header pipeline W1AAC002 c Palustrine emergent 0.1 <0.1

TRANSCO Meter Station W1AEV001 c Palustrine emergent 0.1 0.1

TGT Meter Station W1AAC003 c Palustrine emergent 0.2 0.2

Total for KMLP Facilities 0.3 0.3

TOTAL 16.5 16.5

_____________________

a The totals shown in this table may not equal the sum of the addends due to rounding. 

b Wetlands W1ACA001 and W1ACA002 were delineated by KMLP as part of its review of the area within and around the 

proposed Magnolia Meter Station. In its May 14, 2014 jurisdictional determination for the LNG terminal, the COE 

determined that these wetlands are not jurisdictional under section 404 of the CWA. However, because they meet the 

three parameters of a wetland, they are included in our analysis.

c Wetlands W1AAC002, W1AAC003, and W1AEV001 were delineated by KMLP in March 2014. In its September 10, 2014 

jurisdictional determinations for the facilities, the COE determined that these wetlands are not jurisdictional under section 

404 of the CWA. However, because the wetlands meet the three parameters of a wetland, they are included in our 

analysis.

The estuarine emergent intertidal wetland that would be affected at the LNG terminal site 

comprises a portion (70 percent) of a 1.4-acre wetland fringe along the southern shore of the Industrial 
4-41

Canal. During project design, Magnolia minimized project impacts on this wetland to the extent feasible, 

while still allowing creation of the recessed berthing area. Magnolia would minimize construction-related 

impacts on the adjacent estuarine emergent intertidal wetland by implementing its project-specific 

Procedures, except where deviations are justified (see section 4.4.3.1), and the wetland mitigation 

measures determined necessary by the COE through the section 10/404 permit process. Magnolia would 

be required to mitigate for unavoidable impacts on jurisdictional wetlands as part of its project-specific 

Compensatory Mitigation Plan, which is discussed in additional detail in section 4.4.4.

During operation, vessel traffic along the Industrial Canal and within the recessed berthing area 

could result in increased shoreline erosion, potentially impacting the remaining 0.4 acre of wetland fringe 

along the Industrial Canal due to increased wave activity. As described in section 4.3.2.2, Magnolia 

would install rock armoring to provide scour protection from propeller wash both within and along the 

east and west ends of the recessed berthing area (Moffatt and Nichol, 2014). In addition to providing 

scour protection, the rock armoring would prevent erosion of the adjacent unprotected shoreline by wave 

activity from vessels maneuvering within the recessed berthing area. With the implementation of 

Magnolia’s proposed rock armor, and considering the anticipated vessel speed and the fact that the 

Industrial Canal is an existing ship channel regularly subject to commercial marine traffic, we have 

determined the increase in vessel traffic within the Industrial Canal and recessed berthing area would 

cause a negligible increase in erosion of the adjacent wetland fringe.

4.4.2.2 KMLP Facilities

Construction and operation of the KMLP facilities would permanently convert 0.3 acre of 

palustrine emergent wetlands to upland industrial use (see table 4.4.2-1), including 0.2 acre at the TGT 

Meter Station and very small areas (totaling 0.1 acre) at the TRANSCO Meter Station and where 

connection of the high pressure header pipeline would require modifications of existing interconnect 

facilities adjacent to the Pine Prairie Meter Station. In its jurisdictional determinations for the KMLP 

facilities (COE, 2014b, 2014c), the COE determined that wetlands present are not jurisdictional under 

section 404 of the CWA. However, because the wetlands meet the three parameters of a wetland 

(Environmental Laboratory, 1987), they are included in our analysis.

Ground-disturbing activities, including clearing and grading of temporary work areas, excavation 

activities associated with the meter stations and pipeline interconnection 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 pre-construction levels. If soils are 

not properly segregated during construction, the resulting mixed soil layers could alter 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. Heavy equipment could also introduce non-native and 

invasive species to the disturbed soil. Altered surface drainage patterns, stormwater runoff, runoff from 

disturbed areas, and accidental spills could also negatively affect wetland regeneration. With the 

exception of the alternative measures described in section 4.4.3.2, KMLP would minimize impacts on 

wetlands by implementing the FERC Procedures.

Following construction, the less than 0.1 acre of wetland within temporary workspace would be

restored in accordance with the FERC Procedures and allowed to revegetate naturally using the seedbank 

within the existing topsoil. Within 1 to 2 years, the area would be expected to transition back into a 

community with a function similar to that of the wetland prior to construction. In the event that a pipeline 

anomaly (i.e., corrosion, dent, rupture) is detected during routine inspections that could require pipeline 
4-42

excavation or replacement within a wetland, impacts would be similar to those described above for 

construction.

4.4.3 Alternative Measures to the FERC Procedures

4.4.3.1 LNG Terminal

Magnolia proposes to locate the administration and control building and portions of the workshop 

within wetland WW-001-003. Similarly, KMLP proposes to locate portions of the Magnolia Meter 

Station within wetland W1ACA001. Table 4.4.3-1 identifies the wetlands affected, proposed facilities, 

and justification for the alternative measure.

TABLE 4.4.3-1

Alternative Measures Requested for Impacts Within and Near Wetlands

Facility Wetland ID

Procedures 

Section 

Reference

Deviation 

Description Justification for Deviation FERC Staff Conclusion

LNG TERMINAL

Administration 

and control 

building

WW-001-003 VI.A.6 Aboveground 

facilities within a 

wetland

All areas within the site 

boundary are required for 

construction and 

operation of the LNG 

terminal.

Sufficiently justified. A 

suitable alternative location 

for the facility that would 

completely avoid wetlands 

is not available.

Workshop WW-001-003 VI.A.6 Aboveground 

facilities within a 

wetland

All areas within the site 

boundary are required for 

construction and 

operation of the LNG 

terminal.

Sufficiently justified. A 

suitable alternative location 

for the facility that would 

completely avoid wetlands 

is not available.

Magnolia Meter 

Station

W1ACA001 VI.A.6 Aboveground 

facilities within a 

wetland

All areas within the site 

boundary are required for 

construction and 

operation of the LNG 

terminal.

Sufficiently justified. A 

suitable alternative location 

for the facility that would 

completely avoid wetlands is 

not available.

KMLP FACILITIES

TGT Meter 

Station

W1AAC003 VI.A.6 Aboveground 

facilities within a 

wetland

Wetland impacts could 

not be avoided completely 

due to the locations of 

existing aboveground and 

subsurface infrastructure 

at the meter station.

Sufficiently justified.

a A 

suitable upland alternative 

location for the required 

modification is not available.

TRANSCO 

Meter Station

W1AEV001 VI.A.6 Aboveground 

facilities within a 

wetland

Wetland impacts could 

not be avoided completely 

due to the locations of 

existing aboveground and 

subsurface infrastructure 

at the meter station.

Sufficiently justified.a A 

suitable upland alternative 

location for the required 

modification is not available.

____________________

a Although adequate justification has been provided for these alternative measures, KMLP would be required to comply with 

other requirements of the FERC Procedures. Erosion and sedimentation control devices should be monitored and 

maintained in these areas more frequently than the minimum time intervals required by the FERC Procedures until final 

grading and revegetation have been completed.
4-43

Section VI.A.6 of the FERC Procedures states that aboveground facilities should be located 

outside of wetlands, except where such siting would prohibit compliance with DOT regulations. 

Construction and operation of the administration and control building, the workshop, and the Magnolia 

Meter Station would be constructed on 0.9 acre of palustrine emergent and scrub-shrub wetlands, 

permanently converting these areas to industrial land (see table 4.4.3-1). Magnolia has stated that 

construction and operation of the LNG terminal would require 114 acres of the 115-acre site, with the 

exception of approximately 0.4 acre of estuarine emergent intertidal wetland and 0.6 acre of upland 

vegetation along the Industrial Canal. Because the proposed alternative measures to section VI.A.6 of the 

FERC Procedures are necessary due to land use requirements and limitations at the LNG terminal, we 

have determined that the proposed deviations from the FERC Procedures are reasonable and adequately 

justified.

4.4.3.2 KMLP Facilities

KMLP proposes to increase the footprint of two aboveground facilities (the TRANSCO and TGT

Meter Stations) within wetlands, resulting in the permanent conversion of 0.3 acre of palustrine emergent 

wetlands to industrial use (see table 4.4.3-1). KMLP stated that wetland impacts could not be avoided 

completely due to the locations of existing aboveground and subsurface infrastructure at the existing 

aboveground facility locations. Because the proposed facilities would be located within and/or adjacent 

to existing aboveground facility locations, we have determined that the proposed siting is reasonable and 

adequately justified.

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 discussed in section 4.4.2.2, construction and operation of the LNG terminal and KMLP 

facilities would result in the permanent loss of 7.9 and 0.3 acre of wetlands, respectively, that are not 

jurisdictional under section 404 of the CWA. Therefore, Magnolia and KMLP would not be required to 

offset these impacts.

As required by 33 CFR 332.3, Magnolia is required to propose compensatory mitigation that is 

commensurate with the amount and type of wetland impacts resulting from construction and operation of 

the project. There are three mechanisms for providing compensatory mitigation: permittee-responsible 

compensatory mitigation, mitigation banks, and in-lieu fee mitigation. As part of the section 10/404 

permit process, Magnolia would be required to develop a Compensatory Mitigation Plan to mitigate 

unavoidable wetland impacts. The Compensatory Mitigation Plan would be subject to review and 

approval by the District Engineer for the COE, New Orleans District as part of the section 404/10 permit 

process. Magnolia has stated that permanent impacts on wetlands that are jurisdictional under section 404 

of the CWA would be mitigated through the purchase of credits from an established and approved 

mitigation bank. Magnolia filed its section 404/10 permit applications with the COE, New Orleans 

District in May 2014. However, because the Compensatory Mitigation Plan has not been finalized and 

approved by the COE, we recommend that:

 Prior to filing its Implementation Plan, Magnolia file with the Secretary its

Compensatory Mitigation Plan and documentation of COE approval of the plan. 
4-44

4.5 VEGETATION

The LNG terminal and KMLP facilities would be situated in the Western Gulf Coastal Plain 

ecoregion, which spans coastal portions of Texas and Louisiana. With little topographical relief, the 

ecoregion is generally favorable to grasslands and croplands (EPA, 2013b) though, historically, the region 

was dominated by longleaf pine (Pinus palustris) forests and savannas (LDWF, 2005).

4.5.1 Existing Vegetation Resources

4.5.1.1 LNG Terminal Facilities

The Louisiana Natural Heritage Program (LNHP) (2009) of the LDWF recognizes 68 natural 

vegetation communities in Louisiana. Components of some of these natural vegetation communities are 

found in the vicinity of the LNG terminal. The LNG terminal site is bordered by the Industrial Canal to 

the north and the Intracoastal Waterway to the west. To the south, a large wetland complex and 

associated drainages flow towards the Intracoastal Waterway. While these geographical characteristics 

and hydrologic connections usually typify coastal wetlands, past dredge spoil disposal activities disturbed 

the vegetation communities and raised elevations at the site from between -2 and 8 feet (USGS, 1955) to 

upwards of 25 feet (USGS, 2012). As a result of dredge spoil disposal, vegetation communities at the 

LNG terminal are limited in diversity and do not directly correlate to the natural vegetation communities 

described by the LNHP. Therefore, a combination of aerial photography and field investigation was used 

to provide a more accurate assessment of vegetation resources.

The LNG terminal site is dominated by upland shrub communities, which occur on 64 percent of 

the site and extend the width of the LNG terminal site (see table 4.5.1-1). Upland shrub communities 

present are comprised of large shrubs or small trees (less than 35 feet in height). Typical species at the 

LNG terminal include blackberry (Rubus sp.), hackberry (Celtis laevigata), salt bush, wax myrtle (Myrica 

cerifera), willow, and yaupon (Ilex vomitoria).

Forested habitat, consisting of a mixture of hardwood trees and loblolly pine (Pinus taeda), is 

present on about 29 percent of the LNG terminal site, primarily within the northern and eastern portions. 

As described previously, the LNG terminal site was used for the placement of dredge material between 

1975 and 1984. Therefore, forested vegetation is generally comprised of trees less than 30 years old. 

Loblolly trees make up about 20 percent of the forest canopy. Other species observed in this community 

include blackberry, Chinese tallow, hackberry, hickory (Carya sp.), silktree (Albizia julibrissin), and 

yaupon. Although several species and characteristics described by the LNHP as Mixed HardwoodLoblolly Pine Forest are present, the presence of Chinese tallow and silktree, which are exotic species in 

Louisiana, within this community are indicative of the site's past disturbance. In a conference call with 

Magnolia on February 3, 2014 (Magnolia, 2014b), the FWS noted that the habitat present is of very low 

quality.

Estuarine emergent wetland occurs along the northernmost boundary of the site, adjacent to the 

Industrial Canal. Although comprising less than 1 percent of the site, estuarine emergent wetlands 

provide important ecological functions including water purification, shoreline stabilization, and flood 

protection as well as support essential habitat for various life stages of many fish and wildlife species. 

Relatively small palustrine (freshwater) emergent wetlands occur on 10 percent of the site, mainly within 

the southern and northwestern portions. Typical species of these wetland communities are described in 

section 4.4.1.
4-45

TABLE 4.5.1-1 

Vegetation Communities Affected by Construction and Operation of the LNG Terminal and KMLP Facilities (in acres) a

Facilities Agriculture

Upland 

Herbaceous Upland Shrub

Mixed Hardwood 

Loblolly Forest

Estuarine

Wetland

Palustrine 

Wetland Total

Const. Oper. Const. Oper. Const. Oper. Const. Oper. Const. Oper. Const. Oper. Const. Oper.

LNG TERMINAL FACILITIES b

LNG terminal c 0.0 0.0 0.0 0.0 65.0 65.0 34.0 34.0 1.0 1.0 14.0 14.0 114.0 114.0

Dredge material placement area 0.0 0.0 106.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.2 d 1.2 d 107.3 1.2 d

Total for LNG Terminal Facilities 0.0 0.0 106.1 0.0 65.0 65.0 34.0 34.0 1.0 1.0 15.2 15.2 221.3 115.2

KMLP FACILITIES

Header Pipelines

Low pressure header 20.2 7.8 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 20.2 7.8

High pressure header 0.9 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 <0.1 1.0 0.5

Subtotal 21.1 8.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 <0.1 21.2 8.3

Aboveground Facilities

Compressor Station 760 40.4 11.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 40.4 11.2

CGT Meter Station 0.6 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.3

TRANSCO Meter Station 0.6 <0.1 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.1 0.7 0.1

TETCO Meter Station 0.5 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.5 0.0

ANR Meter Station 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.0

Pine Prairie Meter Station 0.0 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

TGT Meter Station 0.0 0.0 0.3 0.3 0.0 0.0 0.0 0.0 0.0 0.0 0.2 0.2 0.4 0.4

Subtotal 42.4 11.5 0.4 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.3 43.1 12.0

Total for KMLP Facilities 63.5 19.8 0.4 0.2 0.0 0.0 0.0 0.0 0.0 0.0 0.3 0.3 64.3 20.2

TOTAL 63.5 19.8 106.5 0.2 65.0 65.0 34.0 34.0 1.0 1.0 15.5 15.5 285.6 135.5

____________________

a The totals shown in this table may not equal the sum of the addends due to rounding.

b The DII construction yard and the dredged material and effluent pipelines occur within areas that have undergone previous disturbance and/or have been graded and 

graveled; therefore, no vegetation communities occur within these areas. 

c The LNG terminal includes those facilities that would be constructed and operated at the site by Magnolia as well as KMLP’s Magnolia Meter Station and interconnect

pipeline.

d Access to the dredge material placement area and the dredged material and effluent pipeline routes has not been granted at the time of this writing; therefore, NWI data and 

aerial photography were used to identify wetlands present. Magnolia has stated that wetlands identified during survey may be avoided, restored, or filled. Because actual 

wetland impacts have not been determined at this time, our impact analysis assumes the worst-case scenario (fill of wetlands present within the placement area and pipeline 

route). See additional discussion in section 4.4.2.1.
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Land within the DII construction yard and along the dredged material and effluent pipeline routes

has undergone previous disturbance and/or has been graded and graveled; therefore, vegetation

communities are not present within these project components. Vegetation within the dredge material 

placement area is largely composed of upland herbaceous communities. Typical species present include 

soft-leaf mimosa (Mimosa malacophylla), Canadian horseweed (Conyza canadensis), Canadian 

goldenrod (Solidago canadensis), pepper vine, and southern dewberry (Rubus trivalis). Because the 

placement area is currently used by CB&I for staging and laydown, vegetation is routinely mowed and 

maintained in a graminaceous or weedy state. Based on review of NWI data, the dredged material 

placement area also contains small palustrine emergent and forested wetlands, which are described in 

section 4.4.1.

4.5.1.2 KMLP Facilities 

The proposed KMLP facilities would be primarily within existing meter stations and on adjacent 

agricultural land, which comprises 99 percent of the vegetated communities within the affected areas. 

Small areas of upland herbaceous communities occur within the Pine Prairie and TGT Meter Stations. 

These communities contain Bermudagrass (Cynodon spp.), white clover (Trifolium repens), common 

vetch (Vicia sativa), wild geranium (Geranium maculatum), and southern dewberry (Rubus trivalis).

Small areas containing palustrine emergent wetlands are present at the TGT and TRANSCO 

Meter Stations as well as along the high pressure header pipeline route. Typical species within these 

wetlands are described in section 4.4.1.

4.5.2 Vegetation Impacts and Mitigation

As summarized in table 4.5.2-1, a total of 285.6 acres of vegetation would be cleared during 

construction of the LNG terminal and KMLP facilities. Following construction, approximately 

126.0 acres would be converted to developed land within the LNG terminal (114.0 acres) and KMLP 

facilities (12.0 acres), 124.7 acres would return to pre-construction conditions, and 34.9 acres would be 

restored to a vegetated community although it would be converted from an upland scrub or palustrine 

wetland community to an upland herbaceous community. Overall, the projects would have the greatest 

impact on upland herbaceous (106.5 acres), upland shrub (65.0 acres), and agricultural (63.5 acres) 

vegetation communities. Proposed activities within the DII construction yard, existing meter stations, and 

along the dredged material and effluent pipeline routes would not affect vegetation because these areas 

have undergone previous disturbance and/or have been graded and graveled. Therefore, they are not 

discussed further in this section.

4.5.2.1 LNG Terminal Facilities

A total of 114.0 acres of vegetation would be cleared during construction at the LNG terminal

site. Following construction, the majority of the vegetation affected at the terminal (80.3 acres) would be 

permanently converted to industrial use associated with operation of the facility, resulting in a permanent 

loss of 34.0 acres of mixed hardwood loblolly forest, 31.3 acres of upland shrub, and 15.0 acres of 

wetlands (including palustrine and estuarine emergent wetlands). Magnolia would seed the remaining 

33.7 acres of land (currently an upland shrub community) within the LNG terminal site with native 

vegetation per NRCS recommendations, which would result in the conversion of an upland shrub 

community to an upland herbaceous community.

Construction activities within the dredge material placement area, including the disposal of 

dredged material, would affect 107.3 acres of vegetation, including 106.1 acres of upland herbaceous 
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vegetation and 1.2 acres of palustrine wetlands.9 Following dredging and dewatering activities, the 

dredge material placement area (including an existing site road and a borrow pit) would be graded and 

seeded in accordance with landowner requirements. As a result, 33.5 acres of open water within the 

borrow pit, 1.0 acre currently used as a site road, and 1.2 acres of palustrine wetland habitat would be 

converted to an upland herbaceous community.

Impacts on upland herbaceous communities within the dredge material placement area would be 

short term and minor because the site would be reseeded following dredging and dewatering activities. 

We would expect these areas to revegetate to a cover similar to pre-construction conditions within one to 

two growing seasons.

Impacts on wetlands that are jurisdictional under section 404 of the CWA at the LNG terminal

and dredge material placement area would be permanent, but fully mitigated through implementation of 

Magnolia’s project-specific Compensatory Mitigation Plan, which would require review and approval by 

the COE, New Orleans District (see our recommendation in section 4.4.1 as well as section 4.4.4 for 

additional information).

Magnolia’s implementation of its project-specific Plan and Procedures, which require the use of 

temporary and permanent erosion control measures, revegetation procedures, and post-construction 

monitoring, would further minimize impacts on vegetation communities within and adjacent to the LNG 

terminal and within the dredge material placement area. Due to the limited vegetation diversity within 

these areas caused by previous disturbances, the temporary nature of impacts associated with the site, and 

the proposed mitigation measures, we have determined that impacts on vegetation from construction and 

operation of the LNG terminal would be permanent, but minor.

4.5.2.2 KMLP Facilities

As indicated in table 4.5.2-1, construction of KMLP facilities would affect a total of 64.3 acres of 

vegetation, including 21.2 acres associated with the header pipelines and 43.1 acres associated with the 

aboveground facilities. The majority of the vegetation affected by the KMLP facilities would be 

agricultural, which comprises 99 percent of the vegetation affected.

Header Pipelines

Construction of the header pipelines would affect 21.1 acres of agricultural vegetation and 

0.1 acre of palustrine wetlands. Following construction, 8.3 acres of agricultural land (7.8 acres for the 

low pressure header pipeline and 0.5 acre for the high pressure header pipeline) and less than 0.1 acre of 

wetland within the permanent easement associated with the high pressure header pipeline would be 

restored to pre-construction conditions but would be subject to routine maintenance. The remaining

12.9 acres of vegetation within construction workspaces and additional workspaces would be allowed to 

revert to pre-construction condition in accordance with the FERC Plan and Procedures, NRCS 

recommendations, other agency requirements and permit conditions, and landowner requests. 

KMLP would construct the low and high pressure header pipelines within a 125-foot-wide 

construction right-of-way. In addition, construction of the low pressure header pipeline would require 

additional workspaces at road and utility crossings. During construction, KMLP would remove surface 

vegetation and grade the construction right-of-way as necessary to facilitate pipeline installation and 

allow for safe operation of equipment. Though no forested vegetation occurs within the header pipeline 

 

9 As described in section 4.4.1, access to the dredge material placement area has not been granted at the time of this writing; therefore, NWI 

data was used to identify wetlands present. Our description and analysis of wetland impacts at the dredged material placement area will be 

updated pending receipt of the results of Magnolia’s wetland delineation.
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workspaces, any trees present would be removed only where necessary for construction purposes. 

Vegetation within some portions of the construction workspace would be left in place and some nonwoody vegetation would be mowed to minimize soil erosion. Following construction, KMLP would 

restore the construction workspaces to pre-construction conditions and contours in accordance with the 

FERC Plan and Procedures, NRCS recommendations, other agency requirements and permit conditions, 

and landowner requests. KMLP would maintain a 50-foot-wide permanent easement over each of the 

header pipelines, which would be adjacent to, but would not overlap with, the permanent easement over 

KMLP’s existing mainline.

The primary impacts on vegetation from construction of the header pipelines would be the 

cutting, clearing, and/or removal of existing vegetation within the construction workspace. 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 

permanent easement during pipeline operation. In addition, revegetation would depend on factors such as 

local climate, soil types, and land use. Impacts on agriculture and palustrine wetland communities would 

be minor and short term because we would expect these areas to revegetate to a cover similar to preconstruction conditions within one to two growing seasons. With the exception of the measures described 

in section 4.4.3.2, KMLP’s implementation of the FERC 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, and limited routine vegetation maintenance would minimize impacts on 

vegetation. In addition, disturbed areas would be routinely monitored until restoration and revegetation 

are successful in accordance with the FERC Plan and Procedures.

Aboveground Facilities

Construction of the aboveground facilities would affect a total of 43.1 acres of vegetation, 

including 42.4 acres of agriculture, 0.4 acre of upland herbaceous, and 0.3 acre of palustrine wetland 

communities. Following construction, 12.0 acres of vegetation (including 11.5 acres of agriculture, 

0.3 acre of palustrine wetland, and 0.2 acre of upland herbaceous communities) would be permanently 

converted to industrial land associated with the new or modified aboveground facilities. The remaining

31.1 acres of vegetation within construction workspaces and additional workspaces would be allowed to 

revert to pre-construction condition in accordance with the FERC Plan and Procedures, NRCS 

recommendations, other agency requirements and permit conditions, and landowner requests. 

To minimize impacts on vegetation communities during and after construction of the

aboveground facilities, KMLP would conduct the work associated with the meter station modifications 

within or adjacent to existing meter stations. With the exception of the measures described in section 

4.4.3.2, KMLP would also implement the FERC 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, post-construction monitoring, and limited routine vegetation maintenance. All disturbed 

areas would be routinely monitored in accordance with the FERC Plan and Procedures until restoration 

and revegetation are successful.

With the implementation of the mitigation measures described above, we conclude that 

construction and operation of the KMLP facilities would have a permanent, but minor impact on 

vegetation communities. 

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 
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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, 2015), and one plant has 

been designated as a noxious weed, Chinese tallow, by the State of Louisiana (Louisiana Revised Statutes 

Title 3 Part 1791). 

Field surveys at the LNG terminal site identified Chinese tallow and silktree. Chinese tallow is 

an exotic (introduced) tree that grows and spreads quickly. Intensive herbicide application is necessary to 

control this species because fire and mechanical removal (chopping and root removal) fail to control the 

aggressive seedlings (USGS, 2000). Silktree is an exotic species though it is not federally or statedesignated as a noxious weed. Magnolia would implement its project-specific Noxious Plant Control 

Plan during construction to minimize the spread of Chinese tallow. Magnolia would implement a 

Chinese tallow control and maintenance plan during operation of the LNG terminal, which would require

ongoing mechanical (mowing, cutting, and hand pulling) and potentially chemical treatment to effectively 

manage Chinese tallow while providing the opportunity for native and other preferred species to establish 

in designated areas.

In accordance with the FERC Plan and Procedures, KMLP would coordinate with the appropriate 

agencies to prevent any project-related introduction or spread of invasive plants and noxious weeds, and 

would conduct post-construction monitoring. As part of this monitoring program, KMLP would be 

required to examine disturbed non-agricultural areas (upland herbaceous and palustrine wetland 

communities) for the presence of invasive species. 

4.5.4 Vegetation Communities of Special Concern

Vegetation 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. During coordination regarding the LNG terminal and KMLP 

facilities, the LNHP (2013, 2014) determined that impacts are not anticipated on rare, threatened, or 

endangered species of vegetation or critical habitats. Therefore, we do not anticipate that construction or 

operation of the LNG terminal and KMLP facilities would affect vegetation communities of special 

concern. 

4.6 WILDLIFE AND AQUATIC RESOURCES

4.6.1 Wildlife Resources

Wildlife species occurring in the vicinity of the LNG terminal and KMLP facilities are 

characteristic of the habitats provided by the plant communities that occur in these areas. Section 4.5.1 

provides detailed information on the vegetation communities present in the vicinity of the LNG terminal

and KMLP facilities. Habitat types were identified based on aerial photography and field surveys. 

Aquatic resources and protected wildlife species are discussed in sections 4.6.2 and 4.7, respectively.

4.6.1.1 Existing Wildlife Habitats

The wildlife habitat types present in the vicinity of the LNG terminal and KMLP facilities include 

wetlands, forest, open water, open land, and agricultural land. Typical wildlife occurring within these 

habitat types are described below. 

Wetland habitats present within the affected areas include relatively small (less than 7 acres in 

size) palustrine emergent, palustrine scrub-shrub, palustrine forested/scrub-shrub, and estuarine emergent 

wetlands. Wetlands typically support a diverse ecosystem that provides nutrients, cover, shelter, and 
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water for a variety of terrestrial and aquatic wildlife species, including waterfowl, wading birds, raptors, 

mammals, reptiles, and amphibians. Typical wildlife associated with palustrine wetlands include whitetailed deer (Odocoileus virginianus), raccoon (Procyon lotor), river otter (Lutra canadensis), rice rat 

(Oryzomys palustris), swamp rabbit (Sylivagus aquaticus), wood duck (Aix sponsa), least bittern 

(Ixobrychus exilis), green heron (Butorides striatus), red-winged blackbird (Agelains phoeniceus), 

southern leopard frog (Rana utricularia), bullfrog (Rana catesbeiana), cottonmouth (Agkistrodon 

piscivorus), and mud snake (Farancia abacura). Typical wildlife associated with estuarine emergent 

wetlands include raccoon, rice rat, nutria (Myocastor coypus), brown pelican (pelecanus occidentalis), 

great blue heron (Ardea herodias), green heron, fiddler crab (Uca rapax), and salt marsh snake (Nerodia 

clarkia) (LDWF, 2014a, 2014c, 2014d; USGS, 2013c). 

Forested habitat is present within the northern and eastern portions of the LNG terminal and is 

composed of mixed hardwood loblolly forest. In addition, a small, forested/scrub-shrub wetland is within 

the dredge material placement area. No forested habitat is within areas that would be affected by the 

KMLP 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 invertebrates, reptiles, smaller 

mammals, and amphibians. Mammals typically associated with forest habitat in the vicinity of the LNG 

terminal and dredge material placement 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 prothonotary warbler (Protonotaria citrea), 

wood thrush (Hylocichla mustelina), red-shouldered hawk (Buteo lineatus), Carolina chickadee (Parus 

carolinensis), loggerhead shrike (Lanius ludovicianus), eastern kingbird (Tyrannus tyrannus), brownheaded nuthatch (Sitta pusilla), pine warbler (Dendroica pinus), Northern bobwhite (Colinus 

virginianus), and tufted titmouse (Parus bicolor). Amphibians and reptiles include the green tree frog 

(Hyla cinerea), garter snake (Thamnophis sirtalis sirtalis), racer (Coluber constrictor), and pigmy 

rattlesnake (Sistrurus miliarius) (LDWF, 2014a, 2014c, 2014d; USGS, 2013c).

Open water habitat present within the LNG terminal and dredge material placement area include 

the Industrial Canal, an intermittent waterbody in the southwestern portion of the LNG terminal site, and 

a borrow pit10 within the northeastern portion of the dredge material placement area. Open water habitats 

associated with the KMLP facilities include three intermittent waterbodies and seven ephemeral 

waterbodies. Typical wildlife associated with open water habitat includes wading birds, waterfowl, 

beavers, otters, nutria, snakes, and other wildlife species dependent on an aquatic environment (see 

additional discussion in section 4.6.2). 

Open lands (defined in this section as wildlife habitat consisting of uplands dominated by grasses, 

forbs, and shrubs) comprise the majority (81 percent) of the LNG terminal site and dredge material 

placement area. As described in section 4.5.1.1, the LNG terminal site was previously used by the COE 

for dredge material disposal. As a result, vegetation communities at the site are limited in diversity and 

do not directly correlate to the natural vegetation communities in the vicinity. The dredge material 

placement area is currently used by CB&I for staging and laydown; therefore, vegetation in this area is 

routinely mowed and maintained in a graminaceous or weedy state. Very small areas (less than 0.5 acre) 

of open lands are present within the boundaries of the existing KMLP facilities, specifically at the Pine 

Prairie and TGT Meter Stations. Mammals typically associated with open lands include white-tailed deer,

striped skunk, spotted skunk (Spilogale putorius), cotton mouse, armadillo (Dasypus novemcinctus), 

raccoon, and eastern harvest mouse (Reithrodontomys humulis). Bird species include common 

yellowthroat (Geothlypis trichas), northern bobwhite, eastern bluebird (Sialia sialis), dickcissel (Spiza 

americana), rusty blackbird (Euphagus carolinus), red-tailed hawk (Buteo jamaicensus), northern harrier 

 

10 A borrow pit is a man-made open water area that is formed when the original material is removed for use in another area, and the void 

subsequently fills with water from rainfall and stormwater runoff.
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(Circus cyaneus), American robin (Turdus migratorius), cattle egret (Bubulcus ibis), and red-winged 

blackbird. Typical reptiles and amphibians include chorus frog (Pseudacris sp.), western rat snake 

(Pantherophis obsolete), and garter snake (LDWF, 2014a, 2014c, 2014d; USGS, 2013c).

Agricultural lands, which comprise 99 percent of the vegetated wildlife habitat that would be 

affected by the KMLP facilities, include those lands used for crawfish farming and cultivated crops. No 

agricultural lands are present within areas that would be affected by the LNG terminal. Due to low 

diversity and frequent disturbance, 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 habitat for shorebirds, wading birds, and waterfowl. Many species capable of inhabiting 

open lands would also utilize agricultural lands. Typical mammal species that forage in agricultural lands 

in the vicinity of the KMLP facilities include white-tailed deer, striped skunk, eastern spotted skunk, 

cotton mouse, armadillo, raccoon, and eastern harvest mouse. Bird species occurring within agricultural 

lands include cattle egret, red-tailed hawk, northern harrier, American robin, red-winged black bird, and 

mourning dove. Typical amphibians and reptiles include rat snake, garter snake, and chorus frog (LDWF, 

2014a, 2014c, 2014d; USGS, 2013c).

4.6.1.2 Impacts and Mitigation

A total of about 329.2 acres of wildlife habitat would be affected by construction of the LNG 

terminal and KMLP facilities. Overall, the greatest impacts would be on open land (187.6 acres), 

agricultural (63.5 acres), and open water (43.6 acres) habitats. Proposed activities within the DII 

construction yard, existing meter stations, and along the dredged material and effluent pipeline routes

would not be expected to affect wildlife habitat because these areas have been graded and graveled.

LNG Terminal 

Construction of the LNG terminal would affect 114.0 acres of vegetated wildlife habitat and 

9.8 acres of open water habitat (see tables 4.5.2-1 and 4.8.1-1). Following construction, 80.3 acres of 

vegetated habitat at the LNG terminal would be permanently converted to industrial land, 33.7 acres 

would be restored and maintained as open land (although it would be converted from a shrub to an 

herbaceous community), and 6.4 acres would be permanently converted to open water habitat for the 

recessed berthing area. Open water habitat within the Industrial Canal affected during construction would 

be retained during operation of the LNG terminal, although water depth would be increased from an 

average of 40 feet to 44 feet; less than 0.1 acre of open water habitat within the intermittent waterbody 

within the terminal site would be permanently filled.

Activities at the dredge material placement area would affect 107.3 acres of vegetated wildlife 

habitat and 33.5 acres of open water habitat within the borrow pit. Following dredging and dewatering 

activities, the dredge material placement area would be graded and seeded in accordance with landowner 

requirements. As a result, 33.5 acres of open water habitat, 1.0 acre currently used as a site road, and 

0.5 acre of forested/scrub-shrub wetland would be converted to open land.

Impacts on wildlife from construction of the LNG terminal, including use of the dredge material 

placement area, would include displacement, stress, and direct mortality of some individuals. Vegetation 

clearing would potentially reduce suitable cover, nesting, and foraging habitat for some wildlife species. 

More mobile wildlife, such as birds and mammals, may relocate to similar habitats nearby when 

construction activities commence. However, smaller, less mobile wildlife (e.g., reptiles and amphibians)

could be inadvertently injured or killed by construction equipment. The permanent reduction in available 

habitat within the area as well as the influx of individuals to other nearby areas may increase population 
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densities for certain species, resulting in increased inter- and intra-specific competition and reduced 

reproductive success of individuals.

The greatest impacts on terrestrial wildlife would result from the permanent loss of approximately 

68 acres of forested and open lands within the LNG terminal site (approximately 34 and 31 acres, 

respectively), which would result in a permanent reduction in these habitat types in the general vicinity of 

the LNG terminal. Due to the site’s previous use as a dredge disposal site, vegetation species diversity is 

low, which lessens its value as habitat for wildlife.

Construction and operation of the LNG terminal would also result in the permanent loss of 

16.2 acres of wetlands, including 7.4 acres of palustrine emergent wetlands within the southern and 

western portion of the LNG terminal site, 6.6 acres of palustrine scrub-shrub wetlands in the vicinity of 

the Magnolia Meter Station, 1.0 acre of estuarine intertidal emergent wetland along the fringe of the south 

bank of the Industrial Canal on the northern edge of the LNG terminal, and 1.2 acres of palustrine 

emergent and forested/scrub-shrub wetlands within the dredge material placement area. Although these 

are relatively small areas, wetland habitats support a diverse ecosystem that provides nutrients, cover, 

shelter, and water for a variety of terrestrial and aquatic wildlife species. Magnolia would mitigate 

impacts on wetlands determined to be jurisdictional under section 404 of the CWA through 

implementation of its project-specific Compensatory Mitigation Plan, which would require review and 

approval by the COE, New Orleans District (see our recommendation in section 4.4.1 as well as section 

4.4.4 for additional information).

Operation of the LNG terminal would result in increased noise, lighting, and human activity that 

could disturb wildlife in the area. However, due to current industrial activities at other facilities on the 

Industrial Canal (i.e., Trunkline LNG Terminal, Lake Charles Carbon Company, Leevac Shipyards, DII, 

Martin Energy Services, and Marine Spill Response Corporation), wildlife species in the area are 

expected to be acclimated to the noise and artificial lighting associated with these activities (see section 

4.6.1.3 for further discussion of lighting at Magnolia’s proposed LNG terminal).

To minimize project-related impacts on wildlife, Magnolia would implement its project-specific 

Plan and Procedures as well as its Spill Prevention Plan during construction, and would develop and 

implement a SPCC Plan during operation (see our recommendation and additional discussion in section 

4.2.3.1). Magnolia would also implement BMPs, which typically include a combination of silt fencing, 

routine inspection, and good housekeeping techniques.

Based on the previous use of the site for dredge material placement, adequate similar habitat for 

wildlife in the vicinity of the site, presence of exotic and/or invasive species (e.g., Chinese tallow, 

silkweed, and nutria), limited amount of forest and wetland habitat impacts, and implementation of 

Magnolia’s proposed mitigation measures, we have determined that construction and operation of the 

proposed LNG terminal would have permanent, but minor impacts on wildlife.

KMLP Facilities

As described in tables 4.5.2-1 and 4.8.1-1, a total of 64.3 acres of vegetated wildlife habitat and 

0.3 acre of open water wildlife habitat would be affected by construction of the KMLP facilities. The 

wildlife habitats affected by construction of the KMLP facilities would include agricultural lands 

(63.5 acres), open land (0.4 acre), and wetlands and open water (0.3 acre each). Following construction, 

12.0 acres of the habitat affected by the KMLP facilities would be permanently converted to industrial 

land, 8.3 acres (7.8 acres for the low pressure header pipeline and 0.5 acre for the high pressure header 

pipeline) would be restored to the pre-construction habitat type but would be subject to routine 

maintenance, and 44.3 acres would be restored to the pre-construction habitat type.
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The majority of the impacts on wildlife habitat (40.6 acres, or 63 percent) would be associated 

with construction of Compressor Station 760 and the header pipelines (21.2 acres, or 33 percent), as 

discussed below. Activities within existing facility boundaries (i.e., CGT, TRANSCO, TETCO, ANR, 

Pine Prairie, and TGT Meter Stations), would not affect wildlife habitat because these areas have been 

graveled and occur within fenced areas.

Aboveground Facilities

Construction of Compressor Station 760 and modifications to the existing meter stations would 

affect 40.4 and 2.7 acres, respectively, of vegetated wildlife habitat. In addition, 0.2 acre of open water 

would be affected during construction associated with the aboveground facilities.

Construction of Compressor Station 760 would impact 40.6 acres of wildlife habitat; of which 

11.2 acres of agricultural land would be permanently converted to industrial use and 29.4 acres 

(29.2 acres of agricultural land and 0.2 acre of open water) would be restored to pre-construction 

conditions and surrounded with a barbed-wire fence. Fencing would be expected to limit the use of 

suitable habitat at Compressor Station 760 by larger wildlife species, particularly mammals. In addition, 

increased noise levels in the vicinity of the compressor station may result in avoidance of the area by 

wildlife until they become acclimated to the noise increase.

Modifications at the six existing meter stations would impact a total of 2.7 acres of wildlife 

habitat, including agricultural (2.0 acres), open land (0.4 acre), wetlands (0.3 acre), and open water habitat 

(less than 0.1 acre). Activities would affect relatively small areas of wildlife habitat, ranging from 0.1 to 

0.7 acre at each meter station, and would occur adjacent to the existing facilities. A total of 0.8 acre of 

vegetated wildlife habitat would be converted to industrial use for operation of the expanded facilities at 

the CGT, TRANSCO, and TGT Meter Stations. Operation of the modified facilities within the TETCO, 

ANR, and Pine Prairie Meter Stations would not result in the permanent conversion of wildlife habitat to 

industrial use.

The impacts of aboveground facility 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 the types of construction techniques used. 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 area and may result in direct mortality of less mobile wildlife (e.g., small 

rodents and reptiles). Larger or more mobile wildlife, such as birds and large mammals, would relocate to 

adjacent similar habitats. Noise and human disturbance during construction would also cause most 

wildlife to avoid areas of active construction.

Although individuals of some wildlife species would be affected by construction and operation of 

the aboveground facilities, most impacts on wildlife would be temporary or short-term. With the 

exception of the measures described in section 4.4.3.2, KMLP would implement the FERC Plan and 

Procedures, which would minimize impacts on wildlife habitat. With the implementation of these 

measures, and because abundant similar habitat is available for wildlife adjacent to the affected areas, we 

conclude that construction and operation of the KMLP facilities would have permanent, but minor

impacts on local wildlife populations and habitat.

Header Pipelines

Construction of the low and high pressure header pipelines would result in both temporary and 

permanent impacts on wildlife and wildlife habitat. Construction would affect a total of 21.3 acres of 

wildlife habitat, including 21.1 acres of agricultural land, 0.1 acre of wetland habitat, and 0.1 acre of open 
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water habitat (see tables 4.5.1-2 and 4.8.1.1). Impacts on wildlife and habitat during construction of the 

header pipelines would be similar to those described above for the aboveground facilities. Following 

construction, disturbed areas would be restored to pre-construction conditions in accordance with the 

FERC Plan and Procedures; approximately 13.0 acres would be allowed to revert to pre-construction 

conditions and the remaining 8.3 acres would be within permanent easements and subject to routine 

maintenance.

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 construction. Emergent wetland habitat 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). Because wildlife use of agricultural lands is typically limited 

to foraging activities, and the impacts from construction and operation of the header pipelines on wildlife 

would be short term in duration, we anticipate that impacts on wildlife would be minimal.

4.6.1.3 Unique and Sensitive Wildlife

No public or conservation lands have been identified within or adjacent to the proposed LNG 

terminal site or KMLP facilities. Based on information from the LNHP (2013, 2014), no state or federal 

parks, wildlife refuges, scenic streams, or wildlife management areas are within or adjacent to any project 

components. Migratory birds may be present in the vicinity of the LNG terminal and KMLP facilities, as

discussed below. Species protected under the ESA, the Bald and Golden Eagle Protection Act (BGEPA), 

and by 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 Migratory Bird Treaty Act (MBTA), which

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 

describing the Birds of Conservation Concern (FWS, 2008). The report identifies priority bird species at 

the national, regional, and Bird Conservation Region (BCR) levels. The LNG terminal and KMLP 
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facilities are within BCR 37 – Gulf Coastal Prairie (FWS, 2008). Appendix C of this EIS identifies Birds 

of Conservation Concern with potential to occur in the vicinity of the LNG terminal and KMLP facilities, 

indicates which species breed within the region, and identifies the nesting habitat of the breeding species.

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 (e.g., least terns) will nest in developed areas, many waterbirds (e.g., great blue 

heron and great egrets) are wary of human activity. No colonial waterbird rookeries were identified at the 

LNG terminal or KMLP facilities.

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, where they 

remain throughout the non-breeding season. The LNG terminal and KMLP facilities are within the 

Mississippi Flyway, which terminates at the Gulf Coast. 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 large numbers of continental duck and goose 

populations that use the Mississippi Flyway. The coastal marshes of Louisiana, Alabama, and Mississippi 

regularly hold half of the wintering duck population of the Mississippi Flyway (Esslinger and Wilson 

2003). For the reasons listed above, the Gulf Coast is considered one of the most important waterfowl 

areas in North America. 

Impacts and Mitigation

The vegetation communities within the LNG terminal and KMLP facilities provide potential 

habitat for migratory bird species, including songbirds, waterbirds, and raptors. However, much of the 

vegetated land associated with the LNG terminal and KMLP facilities is previously disturbed, within or 

adjacent to existing facilities, and/or composed of agricultural land, all of which reduce bird nesting 

habitat value. Impacts on migratory birds and their habitat due to construction and operation of the LNG 

terminal and KMLP facilities would typically be similar to impacts on general wildlife resources (see 

section 4.6.1.2). In addition, potential impacts specific to migratory birds include loss of habitat and 

injury or disorientation due to flaring and other artificial illumination.

Construction and operation of the LNG terminal would result in the permanent loss of 34.0 acres 

of upland forest, 31.3 acres of open uplands, and 16.2 acres of wetland habitat (including 1.0 acre of 

estuarine emergent wetland, 8.1 acres of palustrine emergent wetlands, 6.6 acres of palustrine scrub-shrub 

wetlands, and 0.5 acre of palustrine forested/scrub-shrub wetlands), which could directly impact the 

available nesting and foraging habitat for migratory birds. Magnolia participated in a conference call with 

the FWS regarding migratory bird impacts at the LNG terminal on February 3, 2014. During the call, the 

FWS stated that its primary project-related concern is whether fringe wetlands at the site would be 

affected. The FWS confirmed that no significant impacts on migratory birds are anticipated at the LNG 

terminal site due to low habitat quality (Magnolia, 2014b).
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Construction of the KMLP facilities would affect 64.3 acres of vegetated habitat; of which

12.0 acres would be permanently converted to industrial use. To minimize impacts on migratory birds, 

KMLP developed a Migratory Bird Review Technical Memorandum, which was submitted to the FWS 

for review and comment on April 9, 2015. KMLP’s memorandum states that the following measures 

would be implemented, where practicable, to avoid impacts on migratory birds:

 clear areas with potential nesting habitat prior to the nesting season, based on the current 

construction schedule;

 conduct nesting surveys to identify species and avoid active nests if migratory birds are 

observed prior to construction;

 inspect construction equipment regularly for opportunistic wildlife species, including 

nesting migratory birds; and 

 stabilize the right-of-way to protect soil resources and promote restoration of temporarily 

disturbed areas. 

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).

Magnolia anticipates that flaring would occur for approximately 5 days during startup of the LNG 

terminal. During operation of the LNG terminal, use of the marine and emergency flares would only 

occur during process upset conditions, which Magnolia anticipates would be no more than 12 hours 

during the first year of operation and no more than 6 hours in each subsequent year (each flaring event is 

expected to occur for between 15 and 60 minutes). Therefore, we have determined that the temporary 

flaring during construction and the occasional flaring during operation would not substantially impact 

migratory birds.

The LNG terminal and KMLP facilities would require adequate lighting for operations and safety. 

During construction, Magnolia would direct all nighttime lighting towards construction activity and use 

the minimum light level necessary to ensure site safety and security. While the Facility Lighting Plan for 

operation of the LNG terminal has not been developed, Magnolia expects the plan to include down-facing 

lights with shielding needed to meet regulatory standards and minimize illumination specifications. 

Facility lighting would be chosen to minimize the horizontal emission of light away from intended areas, 

and shielding would help minimize impacts on birds and other wildlife while providing the illumination 

needed to ensure safe operation of the facility. Because Magnolia has not yet developed its Facility 

Lighting Plan for operation of the LNG terminal, we recommend that:

 Prior to construction, Magnolia file with the Secretary, for review and written 

approval by the Director of OEP, its Facility Lighting Plan for operation of the LNG 

terminal.

Magnolia conducted visual simulations depicting anticipated nighttime lighting conditions at the 

LNG terminal (see detailed discussion in section 4.8.5.2). Based on our review of the visual simulations, 

and implementation of the above recommendation, we have determined that the overall increase in 

nighttime lighting during construction and operation of the LNG terminal would result in permanent, but 

minor impacts on migratory birds.
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To minimize the effects of artificial lighting on migratory birds, outdoor lighting at the KMLP 

facilities would be limited, shielded, and downward-facing to facilitate safe operations at night or during 

inclement weather. Perimeter lighting at aboveground facilities would be turned off at night and would 

only be used when necessary for work conducted at night. With the implementation of the mitigation 

measures described above, we conclude that impacts on migratory birds would be negligible. 

4.6.2 Aquatic Resources

4.6.2.1 Existing Aquatic Resources

LNG Terminal Facilities

Habitat for aquatic resources present within the LNG terminal and dredge material placement 

area includes the Industrial Canal, estuarine emergent wetland along the southern shoreline of the 

Industrial Canal, an intermittent stream in the southwestern portion of the terminal site, and a borrow pit 

within the northeastern portion of the dredge material placement area. Of the waterbodies within the 

LNG terminal and dredge material placement area, only the Industrial Canal, estuarine emergent 

wetlands, and the borrow pit provide year-round warmwater habitat for aquatic resources; the intermittent 

stream provides limited habitat value for aquatic resources due to restricted water flow regimes, which are 

likely dependent upon precipitation. 

Surface waters within the Industrial Canal have been designated by the LDEQ (2013) as 

supporting fish and wildlife propagation. However, based on the numerical criteria established for fish 

and wildlife propagation, water quality within the Industrial Canal does not currently support its 

designated use for fish and wildlife propagation due to chloride, sulfate, and total dissolved solid levels 

that have been impaired as a result of changes in tidal circulation and hydrostructure flow regulation 

(e.g., flow regulation through construction and operation of a dam) (see section 4.3.2.1). The Calcasieu 

Saltwater Barrier, which is within the Calcasieu River over 10 miles north of the LNG terminal site,

generally limits the distribution of freshwater species south of the barrier. As a result, the fishery 

resources in the Industrial Canal are classified as estuarine. 

Water depth within the Industrial Canal ranges from 0 feet at the shoreline to approximately 

40 feet within the navigation channel, and substrates are composed mainly of estuarine subtidal 

unconsolidated bottom sediment. Unconsolidated sediments within the canal provide foraging habitat for 

benthic (bottom-dwelling) organisms and fish and are designated as EFH for red drum, shrimp, reef fish, 

and coastal migratory pelagic species (see discussion in section 4.6.3). Substrates within the Industrial 

Canal are considered early successional due to frequent disturbance from maintenance dredging, propeller 

wash, and vessel traffic.

An estuarine emergent wetland is present along the southern shoreline of the Industrial Canal 

within the LNG terminal site. This habitat provides nutrients, cover, shelter, and water for a variety of 

aquatic wildlife species and is designated as EFH for red drum, shrimp, reef fish, and coastal migratory 

pelagic species (see discussion in section 4.6.3).

The borrow pit within the dredge material placement area was created after 2010 and was 

disturbed by construction activities until 2013. Magnolia stated that there does not appear to be a 

consistent source of water to the pond; therefore, it is assumed that rainfall and the associated runoff from 

surrounding areas is the only source of water for the borrow pit. Aquatic resources potentially present 

within the borrow pit include aquatic insects as well as tadpoles, minnows, and small fish that were 

transported to the borrow pit by terrestrial wildlife. Fishery resources present within the borrow pit are

classified as freshwater. 
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Table 4.6.2-1 lists representative fish species found in the vicinity of the LNG terminal site and 

indicates which of these species are economically important for commercial or recreational fisheries. Life 

histories of many Gulf of Mexico fish species can be characterized as estuarine-dependent because these 

species typically spawn in the Gulf, allowing their larvae to be carried inshore by currents. Juvenile fish 

generally remain in estuarine nurseries for about a year, taking advantage of the estuary’s greater 

availability of food and protection, before returning to the Gulf of Mexico to either spawn or spend the 

remainder of their lives. Estuary-dependent species potentially occurring within the proposed LNG 

terminal area include Gulf menhaden; red drum; gray snapper; Spanish mackerel; blue crab; and brown, 

pink, and white shrimp. 

No significant commercial fisheries resources occur in the vicinity of the LNG terminal; however, 

recreational fishing takes place within the Industrial Canal. Recreational fishing is discussed in more 

detail in section 4.8.4.

KMLP Facilities

Table 4.3.2-1 lists the waterbodies that would be crossed or affected by the KMLP facilities as 

well as the proposed crossing method and water quality classification for each feature. All of the 

waterbodies affected by the KMLP facilities are freshwater and classified as warmwater fisheries. Of the 

10 waterbodies affected, all are classified as intermittent or ephemeral, which typically provide limited 

habitat value for aquatic resources due to restricted water flow regimes. Representative species found 

within these waterbodies include prairie crawfish (Fallicambarus macneesei), painted crawfish 

(Orconectes hathawayi), Pine Hills crawfish (Fallicambarus dissitus), and other species that do not 

require perennial water flow regimes. No sensitive fish species, fisheries of concern, or EFH are present

within the waterbodies affected by the KMLP facilities.

4.6.2.2 Impacts and Mitigation

LNG Terminal Facilities

Potential impacts on aquatic resources during construction and operation of the LNG terminal

include those associated with dredging, pile driving, hydrostatic testing, vessel traffic, stormwater runoff, 

lighting, LNG storage tank deluge system, and inadvertent spills.

Dredging 

Construction of the recessed berthing area at the LNG terminal site would require the dredging of 

a 16.2-acre area in the Industrial Canal, which currently consists of 9.8 acres of open water, 1.0 acre of 

wetlands, and 5.4 acres of uplands. As described in section 2.2.1, dredging would remove approximately 

862,550 yd3 of sediments over a period of approximately 12 weeks using a hydraulic cutterhead suction 

dredge. Dredge material would be transported by pipeline to the placement area where it would be 

allowed to dewater, after which the decanted water would be pumped through the effluent pipeline and 

discharged back into the Industrial Canal. Potential impacts on aquatic resources resulting from dredging 

activities include direct take and habitat modification as well as temporary increases in noise, turbidity, 

and suspended solid levels, which are described below.
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TABLE 4.6.2-1

Representative Fish Species Potentially Occurring in the Vicinity of the LNG Terminal

Common Name Scientific Name Classification

Shellfish

Blue crab a Callinectes sapidus Estuarine

Brown shrimp a Farfantepenaeus aztecus Estuarine

Pink shrimp a Farfantepenaeus duorarum Estuarine

White shrimp a Litopenaeus setiferus Estuarine

Finfish

Atlantic croaker a Micropogonias undulates Estuarine

Black crappie Pomoxis nigromaculatus Freshwater

Common carp Cyprinus carpio Freshwater

Freshwater drum Aplodinotus grunniens Freshwater

Gafftopsail catfish Bagre marinus Estuarine

Golden shiner Notemigonus crysoleucas Freshwater

Gray snapper a Lutjanus griseus Estuarine

Green sunfish Lepomis cyanellus Freshwater

Gulf menhaden a Brevoortia patronus Estuarine

Hardhead catfish Arius felis Estuarine

Hogchoker Trinectes maculatus Estuarine

Killifish Fundulus spp. Estuarine

Ladyfish Elops saurus Estuarine

Mosquitofish Gambusia affinis Estuarine

Puffer Sphoeroides parvus Estuarine

Red drum a Sciaenops ocellatus Estuarine

Redear sunfish Lepomis microlophus Freshwater

Sheepshead minnow Cyprindon variegatus Estuarine

Silver perch Bairdiella chrysura Estuarine

Silverside Menidia bervllina Estuarine

Southern flounder a Paralichthys lethostigma Estuarine

Spanish mackerel a Scomberomorus maculatus Estuarine

Spot Leiostomus xanthurus Estuarine

Spotted seatrout a Cynoscion nebulosus Estuarine

Striped mullet a Mugil cephalus Estuarine

Warmouth Lepomis gulosus Freshwater

Yellow bullhead Ameiurus natalis Freshwater

____________________

a This species is considered economically important (i.e., commercially or recreationally sought after).
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Most fish species are highly mobile and would be expected to leave the area during dredging 

activities. Dredging would, however, result in direct mortality of benthic organisms (e.g., aquatic 

macroinvertebrates, mollusks, and crustaceans, which are important food sources for many species of 

fish) within the 9.8-acre portion of the dredge footprint that currently provides open water habitat. 

Slower, less mobile benthic invertebrates would also be directly affected, while larger, more mobile 

species (e.g., blue crab) would experience temporary displacement. Following construction activities, 

aquatic resources would be expected to return to the recessed berthing area, which would be similar to the 

existing habitat within the Industrial Canal, but would contain an additional 6.4 acres of open water 

habitat and have an increased water depth of 44 feet. 

Dredging of the recessed berthing area would result in the permanent conversion of 1.0 acre of 

estuarine emergent wetland habitat to open water habitat. This wetland comprises a portion (70 percent) 

of a 1.4-acre wetland fringe along the southern shore of the Industrial Canal. During project design, 

Magnolia minimized project impacts on this wetland to the extent feasible, and would mitigate 

unavoidable impacts on this wetland through the implementation of its Compensatory Mitigation Plan

(see section 4.4.4 for additional information). However, as described in section 4.6.2.1, wetlands support 

a diverse ecosystem that provides nutrients, cover, shelter, and water for a variety of fish and invertebrate 

species. The permanent reduction in estuarine emergent wetland habitat within the Industrial Canal as 

well as the influx of individuals to the adjacent 0.4 acre of wetland may increase population densities for 

certain species, resulting in increased inter- and intra-specific competition and reduced reproductive 

success of individuals. Due to the proposed creation of 6.4 acres of open water habitat and limited 

impacts on estuarine emergent wetland habitat, we have determined that impacts on aquatic resources due 

to direct take and habitat modification from dredging activities would be permanent, but minor. 

Prior to the placement of dredge material, the 33.5-acre borrow pit would be dewatered, resulting 

in direct mortality of any aquatic resources present. As described above (see section 4.6.2.1), aquatic 

resources within the man-made borrow pit are expected to be limited to aquatic insects as well as 

tadpoles, minnows, and small fish that were transported to the borrow pit by terrestrial wildlife. 

Therefore, impacts from dredge material placement on aquatic resources in the borrow pit would be 

permanent, but minor. 

Dredging activities would also temporarily increase noise, turbidity, and suspended solid levels 

within the water column, which could reduce light penetration and the corresponding primary production 

of aquatic plants, algae, and phytoplankton. Increased turbidity and suspended solid levels could also 

adversely affect fish eggs and juvenile fish survival, benthic community diversity and health, foraging 

success, and suitability of spawning habitat. Sediments in the water column could be deposited on nearby 

substrates, burying aquatic macroinvertebrates. 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 maintenance dredging (which is scheduled to occur every other year) within the Industrial 

Canal. 

To minimize impacts on aquatic resources due to increased turbidity and suspended solid levels, 

Magnolia would use a hydraulic cutterhead suction dredge. Because excavated material would be 

suctioned into a pipeline, resuspension of sediments and the associated increase in turbidity and 

suspended solid levels would be minimized. To further minimize these impacts, Magnolia has prepared a 

preliminary Dredging Water Quality Monitoring Plan. This plan, which is discussed in detail in section 

4.3.2.2, requires monitoring of turbidity and total suspended solids levels at three locations, including two 

locations near dredging operations and one at the effluent outfall. The plan also includes mitigation 

measures that would be implemented if monitoring indicates that turbidity or total suspended solid levels 

exceed the limits established by the plan or the COE or EPA permit requirements. Due to the proposed 
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use of a hydraulic cutterhead suction dredge and our recommendation that Magnolia file its final

Dredging Water Quality Monitoring Plan, we have determined that impacts on aquatic resources due to 

temporary increases in noise, turbidity, and suspended solid levels from dredging would be localized, 

temporary, and minor. 

Maintenance dredging of the recessed berthing area would be conducted by Magnolia every 4 to 

5 years during operation of the LNG terminal, and would remove approximately 65,000 yd3 of sediment 

per cycle. Maintenance material would be placed in an upland CDF in coordination with the Lake 

Charles Harbor and Terminal District. Potential impacts on aquatic resources from maintenance dredging 

include direct take and habitat modification as well as temporary increases in noise, turbidity, and 

suspended solid levels. These impacts would be similar to those described above for dredging during 

construction of the LNG terminal; however, impacts would be shorter in duration due to the reduced 

amount of material being removed from the recessed berthing area. Therefore, we conclude that 

maintenance dredging would have temporary and minor impacts on aquatic resources.

Pile Driving

Construction of the LNG terminal would require the installation of approximately 5,000 piles to 

support the proposed structures. As discussed in section 2.5.1.3, pile driving activities would take place

10 hours per day, up to 7 days per week; however, due to pre-work coordination and start-up activities, 

actual pile driving operations (hammering) are expected to occur for only about 8 hours per day. Prestressed concrete piles would be installed onshore to support the liquefaction trains, LNG storage tanks,

and other process equipment and structures. Onshore piles would be driven by seven or eight hydraulic 

piling rigs over a 10-month period. In-water pile driving would be required to install the steel sheet pile 

bulkhead along the shoreline of the Industrial Canal and the steel pipe piles supporting the LNG loading 

platform as well as the breasting and mooring dolphins. Marine piles would be installed using between 

two and four hydraulic pile drivers over a 6-month period. As depicted in table 2.5.1-1 in section 2.5.1.3, 

pile driving would occur over a total of about 16 months during the first 2 years of construction. 

The primary impacts on aquatic resources from pile driving activities would be avoidance of the 

area, stress, or injury due to the underwater sound pressure levels. Studies have shown that the sound 

waves from pile driving may result in injury or trauma to fish, sea turtles, and other animals with gasfilled cavities, such as swim bladders, lungs, sinuses, and hearing structures (Abbott and Bing-Sawyer, 

2002; Popper et al., 2006). NOAA Fisheries is currently developing guidelines for determining sound 

pressure level thresholds for fish and marine mammals. The agency’s interim guidelines use 150 decibels 

(dB) re: 1 microPascal (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).

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. In discussing the impacts of sound on aquatic 

resources, it is important to note the difference in sound intensity in air versus water. Sound in water and 

sound in air are both waves that move similarly and can be characterized the same way; however, the 

differences in density and sound speed (the speed at which the sound wave travels through the medium, in 

this case air or water) result in a different reference pressure in air than in water (see detailed discussion 

in section 4.11.2.2).
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Magnolia has stated that it intends to perform hydro-acoustic monitoring during the initial pile 

testing to determine the sound pressure levels generated under site-specific conditions at the LNG 

terminal. If these readings indicate that the sound pressures would be above acceptable thresholds (see 

discussion above), the following mitigation measures would be considered:

 minimizing impact energy to the lowest practical level to reduce the resulting noise 

generated by driving the pile;

 implementing soft starts (an initial series of low energy impacts on the pile) to allow 

aquatic resources an opportunity to leave the area;

 placing cushion blocks consisting of wood, nylon, or micarta between the pile and 

hammer to minimize the noise generated while driving the pile;

 using bubble curtains around the pile to reduce noise levels; and 

 using vibratory pile driving, which generates lower sound pressure levels.

Because Magnolia has not finalized pile driving plans, an estimate of underwater noise has not 

been provided. Magnolia does not anticipate that land-based pile driving activities would result in 

underwater noise levels in exceedance of a peak sound pressure of 206 dB re: 1 μPa or a cumulative 

sound pressure level of 183dB re: 1 μPa; however, the potential exists for water-based pile driving 

activities to exceed these levels, resulting in injury to aquatic resources. To allow for an accurate analysis 

of potential impacts on aquatic resources during pile driving, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia file with the Secretary a 

Pile Driving Noise Impact Mitigation Plan, which describes the hydroacoustic

monitoring methods that would be used to determine representative sound pressure 

levels associated with in-water pile driving as well as mitigation measures to be 

implemented to reduce sound pressure levels. The plan should include a description 

of the locations where monitoring would occur in relation to the pile being driven, 

and the maximum impact energy used on the pile during monitoring.

With the implementation of hydroacoustic monitoring and mitigation measures, if needed, pile 

driving activities would minimize underwater noise levels to a level that would not cause significant 

impacts on aquatic resources. 

Hydrostatic Testing 

Prior to being placed into service, the LNG storage tanks and dredge material and effluent 

pipelines would be hydrostatically tested with surface water to ensure their integrity. Water to be used for 

hydrostatic testing of the dredge material and effluent pipelines would be withdrawn from the borrow pit 

or the Industrial Canal; water to be used for testing of the LNG storage tanks would be withdrawn from 

the Industrial Canal, as described in section 4.3.2.2. 

The water withdrawal process could entrain fish eggs and juvenile fish present near the intake 

structures within the Industrial Canal and borrow pit. In accordance with its project-specific Procedures, 

Magnolia would screen intake hoses to limit the entrainment of larvae and pre-juvenile fish and 

invertebrates during water withdrawal. Water would be withdrawn from the borrow pit at a rate of about 

3,333 gallons per minute. Because the borrow pit would be fully dewatered prior to being permanently 

filled during dredge material placement, impacts on aquatic resources would be permanent, but minor. 
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Within the Industrial Canal, Magnolia would utilize an intake rate of 1,500 gallons per minute 

and would place screened intake structures at the lowest possible elevation to reduce the impingement of 

biological organisms and debris on intake screens. With the implementation of these measures, impacts 

on aquatic resources as a result of water intake would be temporary and negligible. 

Magnolia would not use biocides, detergents, or additives in the hydrostatic test water or powerwash water. In accordance with the LPDES Hydrostatic Test Wastewater Discharge Permit requirements, 

the water would be tested for total suspended solids, oil and grease, and pH, and treated (if test results 

indicate that the water would not meet LPDES requirements) prior to being discharged to the Industrial 

Canal. Therefore, we have determined that impacts on aquatic resources due to the discharge of 

hydrostatic test water would be temporary and negligible.

Vessel Traffic

During construction and operation of the LNG terminal, barges, support vessels, and LNG vessels 

(LNG carriers and LNG barges) would call on the LNG terminal, increasing ship traffic within the 

Industrial Canal, Calcasieu Ship Channel, Intracoastal Waterway, and Gulf of Mexico. Potential impacts 

on aquatic marine mammals resulting from vessel strikes are discussed in section 4.7.2.2. Potential 

impacts on aquatic resources resulting from increased vessel traffic include shoreline erosion and 

resuspension of sediments, ballast water discharges, cooling water discharges, and increased noise levels. 

The following sections describe these potential impacts as well as measures proposed by Magnolia to 

minimize impacts on aquatic resources. 

Shoreline Erosion and Resuspension of Sediments

During construction of the LNG terminal, barges and support vessels would deliver large 

equipment and materials to the DII construction yard. Magnolia estimates that barges and tugs would 

make 50 or fewer marine deliveries to the DII construction yard during construction. During operation, a 

maximum of 208 LNG vessels would be expected to call on the LNG terminal per year, which would be 

comprised of 104 LNG carriers and 104 LNG barges. 

Vessel traffic within and adjacent to the recessed berthing area has the potential to increase 

shoreline erosion and suspended sediment concentrations due to increased wave activity. Because 

Magnolia would modify the existing shoreline to create the recessed berthing area, there is potential for 

the modified shoreline to cause changes in wave dynamics and increase erosion of adjacent areas. 

Magnolia would install rock armoring to provide scour protection from propeller wash both within and 

along the east and west ends of the recessed berthing area. The rock armoring would prevent erosion of 

the adjacent unprotected shoreline by wave activity from vessels maneuvering within the recessed 

berthing area (Moffatt and Nichol, 2014). 

The Industrial Canal, Calcasieu Ship Channel, and Intracoastal Waterway were specifically 

created to provide deepwater access for maritime commerce and are maintained by regular dredging 

(COE, 2015b). Similarly, LNG carriers transiting the Gulf of Mexico would use established shipping 

channels. As such, use of the waterways by LNG carriers, barges, and support vessels during 

construction and operation of the LNG terminal would be consistent with the planned purpose and use of 

these active shipping channels, and associated impacts on aquatic resources due to increased shoreline 

erosion and resuspension of sediments would be negligible.
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Ballast Water Discharge

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. Ballast water is stored below the 

ship’s hull; as a result, the temperature of discharged water is not expected to deviate substantially from 

ambient water temperature. The pH of ballast water would be similar to or slightly lower than ambient 

water within the canal. However, this difference would not be outside the tolerance range of resident 

species, and impacts would be temporary and negligible.

Estuarine salinities can naturally range from freshwater (0.5 ppt), near the source of freshwater 

input, to full seawater (30 to 40 ppt) (Patillo et al., 1995). Salinity levels within the Industrial Canal 

naturally vary within this range dependent upon tidal regime and rainfall. During and immediately 

following ballast water discharges, benthic aquatic species may be affected by higher salinity levels 

because the higher salinity ballast water would sink to the lower portion of the canal due to its higher 

specific gravity relative to the ambient water. However, ships moving into and out of the Industrial Canal 

and berthing area would displace water, circulating it into, around, and out of the berthing area. 

Therefore, any increased salinity levels resulting from ballast water discharges would be temporary. 

Resident species within the Industrial Canal are euryhaline (able to live in waters with a wide range of 

salinity), and the salinity of seawater is well within their tolerance range. Therefore, we have determined 

that increases in salinity from ballast water discharges would be temporary and not likely to adversely 

affect aquatic resources.

Dissolved oxygen levels below 4 mg/L are generally considered unhealthy for aquatic life, and 

levels below 2 mg/L are considered hypoxic and inadequate to support most aquatic life. As discussed in 

section 4.3.2.2, ballast water would contain low dissolved oxygen levels and could decrease existing 

dissolved oxygen levels within the immediate vicinity of the discharge point. Depending on the oxygen 

levels present in both the ballast and ambient water at the time of discharge, aquatic resources present in 

the vicinity of the discharge point could be exposed to dissolved oxygen levels considered unhealthy for 

aquatic life. The adaptability of resident species within the Industrial Canal to natural spatiotemporal 

variation in oxygen levels, and the ability to move over a short distance to more suitable conditions, 

would minimizes the adverse impacts associated with ballast water discharges. Given that the amount of 

ballast water discharged into the Industrial Canal during each LNG vessel visit to the LNG terminal

would make up only approximately 0.6 percent of the approximately 2 billion gallons of water within the 

Industrial Canal, we have determined that impacts on aquatic resources would be temporary and minor.

Due to the volumes of ballast water often collected by vessels, a possibility exists that living 

marine organisms may enter ballast tanks. The larger macroorganisms that may be collected would likely 

die during transit; however, some of the smaller planktonic organisms could survive. An environmental 

concern associated with ballast discharge includes the risk of introducing exotic species in marine and 

estuarine ecosystems. Loaded with water from the surrounding ports and coastal waters throughout the 

world, vessels can carry a diverse assemblage of marine organisms in ballast water that may be foreign 

and exotic to the ship’s port of destination. Invasive species threaten to outcompete and exclude native 

species and the overall health of an ecosystem, causing algal blooms and hypoxic conditions and affecting 

all trophic levels resulting in a decline in biodiversity.

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 one of five strategies to 

prevent the spread of exotic aquatic nuisance species in U.S. waters. The IMO has adopted this regulation 

and requires each vessel to install and operate a ballast water management system (option 1 as currently 
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defined). Compliance dates associated with this IMO requirement will be phased, but will apply to all 

vessels beginning in 2016.11 Until this rule is fully implemented, Magnolia has stated that it would 

require LNG carriers to conduct 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 less distant from the shoreline, which is authorized under 

33 CFR 151.2040. Therefore, ballast water that is likely to be introduced into the Industrial Canal would 

be composed mainly of open ocean water collected during ballast water exchange.

A wide variety of ballast water treatment systems are currently available that may be utilized by 

LNG Carriers frequenting the LNG terminal during operation. Some treatment systems utilize chemical 

additives such as chlorine and/or sulphate/bisulphate-based products, which could have adverse impacts 

on aquatic resources if discharged in high concentrations. However, all ballast water treatment systems 

(including those using chemical additives) are required to ensure that discharged ballast water either 

meets or exceeds the Coast Guard’s regulatory limits for environmental compliance. Magnolia has stated 

that it would ensure that any visiting vessels possess documentation to demonstrate their compliance with 

ballast water regulations and BMPs prior to allowing any ballast water to be discharged into the berthing 

area. With the implementation of the mandatory practices required by the Coast Guard, we conclude that 

the impacts on aquatic resources from ballast water discharges would be temporary and minor.

The LDWF’s proposed Louisiana Marine Fisheries Enhancement, Research, and Science Center 

(Fisheries Research Center) would be immediately south of the proposed LNG terminal, across Henry 

Pugh Boulevard. The Fisheries Research Center would have a water intake within the Industrial Canal, 

which would be approximately 3,000 feet southeast of the recessed berthing area. The LDWF requested 

that Magnolia provide ballast water discharge notifications so that pumping activity associated with its 

water intake could be halted if LNG carrier discharge water would be unsuitable for its use. Magnolia has 

stated it would provide telephone notification to the LDWF prior to ballast water discharges so that water 

intake periods could be adjusted accordingly. More information regarding the LDWF’s proposed 

Fisheries Research Center is included in sections 4.8.3 and 4.13.1.7. 

Cooling Water Discharge

All ships use water to cool their boilers. The cooling water would be withdrawn along the vessel 

transit routes and from the Industrial Canal within the recessed berthing area. LNG barges would use 

approximately 535 gallons of water for engine cooling while at the LNG terminal. Depending upon 

engine type, LNG carriers would use between 5.5 and 11.7 million gallons of water for engine cooling 

while they are at the LNG terminal. Intake of water can also result in the entrainment of aquatic 

resources. Early life stages that utilize the canal for nursery habitat would be most susceptible to 

entrainment. 

Water used for engine cooling would be discharged at a temperature between 2.7 °F and 7.2 °F 

warmer than the ambient water temperature (Caterpillar, 2001, 2011, 2012). Using the most conservative 

estimates (assuming the highest ambient temperature generally found within the canal [86 °F], the 

greatest change in water temperature [7.2 °F], and the largest volume of water [11.7 million gallons]), 

discharged cooling water would be 95.5 °F and would constitute approximately 0.6 percent of the total 

water within the Industrial Canal. Fish and invertebrates within the immediate vicinity of the LNG carrier 

could be temporarily affected by this increase in temperature; however, many of the species present are 

mobile and would be expected to relocate to more suitable conditions during discharges. Given the 

volume of cooling water discharged relative to the total volume of water within the Industrial Canal, and 

 

11 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 m3that have been drydocked since January 1, 2014. Compliance by existing vessels with ballast water capacity less than 

1,500 m3 or greater than 5,000 m3 will be required as of the vessel’s first scheduled drydocking after January 1, 2016.
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the mobility of resident species, which could relocate to cooler surrounding waters if necessary, we have 

determined that impacts on aquatic resources would be intermittent and minor.

Increased Noise Levels

Engine-noise produced by LNG vessels would result in temporary increases in underwater noise 

levels near the transiting ships (see additional discussion in section 4.11.2.4). Noise generated by LNG 

vessels is generally omni-directional, emitting from all sides of the vessel (Whale and Dolphin 

Conservation Society, 2004), but are greatest on the sides of the ship and weakest on the front and rear of 

the ship. Impacts on aquatic resources due to increased noise levels would vary by species; however, the 

aquatic resources present within the LNG carrier routes are likely accustomed to regular fluctuations in 

noise levels from ongoing industrial and commercial shipping activities. Additionally, as described 

above, many of the species present within the LNG carrier routes are mobile and would be able to move 

out of areas of noise that would startle or stress aquatic resources present. Due to the existing industrial 

and shipping activities within the LNG vessel transit routes and the mobility of resident species, we have 

determined impacts to aquatic resources associated engine-noise produced by LNG carriers during 

operation of the LNG terminal would be intermittent and minor. 

Stormwater Runoff

Construction activities at the LNG terminal would remove vegetation cover at the site and expose

the underlying soils to the effects of wind and rain, which increases the potential for soil erosion and 

sedimentation of aquatic habitat. Similarly, during operation of the LNG terminal, 80.3 acres of currently 

vegetated land would be converted to impervious or semi-pervious surfaces associated with aboveground 

facilities and plant roads, which would increase stormwater runoff into adjacent vegetated and open water 

habitats. Potential impacts from stormwater runoff on aquatic resources include increased turbidity and 

suspended solid levels, which are discussed above (see section 4.6.2.2, Dredging). 

To minimize impacts on aquatic resources due to stormwater runoff, Magnolia would conduct 

land-disturbing activities in compliance with its LPDES, General Permit for stormwater discharges from 

construction activities of 5 acres or more; project-specific Construction SWPPP; and project-specific Plan 

and Procedures (see our recommendation and detailed discussion in section 4.2.3). 

Lighting

Temporary lighting would be installed and used during construction of the LNG terminal to 

facilitate construction activities during evening hours and meet applicable safety requirements. 

Construction of the LNG loading and ship berthing facilities and dredging would require additional overwater lighting during the construction period. The work areas, dredges, and smaller work boats 

associated with dredging operations would be well-lighted during construction activities to promote 

safety. Lighting associated with in-water activities would have the greatest potential to affect aquatic 

resources. To minimize potential impacts on aquatic resources, Magnolia would direct all nighttime 

lighting towards the construction activity being conducted. During operation of the LNG terminal, 

lighting would be installed and used to meet safety and security requirements. Facility lighting would be 

chosen to minimize the horizontal emission of light away from intended areas, and over-water lighting 

would be limited to the extent necessary to carry out marine operations or facility maintenance and would 

be shielded. To minimize impacts on wildlife and aquatic resources, we have recommended that 

Magnolia develop and file a final Facility Lighting Plan prior to operation (see section 4.6.1.3).

Illumination of surface waters in the vicinity could cause artificially induced aggregations of 

small organisms that rely on sun or moonlight to determine movement patterns, resulting in increased 
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predation by larger species. Generally, impacts on aquatic species would be minor as these species may 

change their feeding habits over time. Due to the industrial nature of the area surrounding the LNG 

terminal, aquatic species within the Industrial Canal are likely acclimated to ambient light from 

surrounding industrial sources. Based on the existing light conditions within the Industrial Canal and the 

likelihood that aquatic resources would acclimate over time to increased lighting at the LNG terminal, we 

have determined that impacts on aquatic resources from increased lighting during construction and 

operation of the LNG terminal would be negligible.

LNG Storage Tank Deluge System

During operation of the LNG terminal, an LNG storage tank deluge system would be used to 

distribute water over the LNG storage tank’s outer surfaces for cooling in the event of a fire on the 

adjacent tank. The deluge system would be operated in the event of a fire emergency as well as 

periodically for system maintenance and testing. When in operation, two pumps near the LNG loading 

platform would appropriate water from the Industrial Canal at a rate of up to 6,300 gallons per minute. 

Intake structures would be screened to minimize entrapment of aquatic resources and prevent debris from 

entering the system. Water used for deluge purposes would be directed into two holding basins (east and 

west) before being discharged back into the Industrial Canal. Because of the infrequent operation of the 

system and use of screening to minimize entrapment of aquatic resources, we conclude that the LNG 

storage tank deluge system would have intermittent and minor impacts on aquatic resources.

Inadvertent Spills

During construction and operation, hazardous materials resulting from spills or leaks entering the 

Industrial Canal could have adverse impacts on aquatic resources. The impacts are caused by either the 

physical nature of the material (e.g., physical contamination and smothering) or by its chemical 

components (e.g., toxic effects and bioaccumulation). These impacts would depend on the depth and 

volume of the spill, as well as the properties of the material spilled. To prevent spills and leaks, Magnolia 

would implement its project-specific Spill Prevention Plan during construction and its SPCC Plan during 

operation of the LNG terminal, which outline potential sources of releases at the site, measures to prevent 

a release, and initial responses in the event of a spill (see our recommendation and detailed discussion in 

section 4.2.3). Given the impact minimization and mitigation measures described above, we conclude

that the probability of a spill of hazardous materials is small and any resulting impacts on aquatic 

resources would be temporary and minor. 

KMLP Facilities

Construction of the KMLP facilities would require temporary impacts on 0.2 acre of open water 

habitat within 10 intermittent or ephemeral waterbodies. No waterbodies would be permanently filled by 

construction of the KMLP facilities, nor are impacts anticipated during operation. As noted in section 

4.6.2.1, due to restricted water flow regimes, these waterbodies typically provide limited habitat value for 

aquatic resources. No sensitive fish species, fisheries of concern, or EFH are known to occur within the 

waterbodies affected by the KMLP facilities. Therefore, we have determined that impacts on aquatic 

resources from construction and operation of the KMLP facilities would be negligible.

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 
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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 

affect 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, 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 

Assessment 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. For any conservation recommendation that is not adopted, the action agency 

must explain its reason to NOAA Fisheries for not following the recommendation.

The FERC proposes to incorporate EFH consultation for the Magnolia LNG Project with the 

interagency coordination procedures required under NEPA. As such, we are requesting that NOAA 

Fisheries consider this draft EIS as initiation of EFH consultation.

4.6.3.2 Essential Fish Habitat at the LNG Terminal

Between 1979 and 1987, the Gulf of Mexico Fishery Management Council (GMFMC) prepared 

fishery management plans for seven marine groups within the Gulf of Mexico: reef fish, migratory 

pelagic fish, red drum, shrimp, spiny lobster (Panulirus argus), stone crab (Menippe adina and Menippe 

mercenaria), and corals. Each fishery management plan has been amended at least several times since 

then. One important amendment that applied to all seven fishery management plans was implemented 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). 
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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, 2013d). Life stage occurrences for several species within these groups found within 

the vicinity of the LNG terminal are presented in table 4.6.3-1. The only areas classified as EFH within 

the areas affected by the Magnolia LNG Project are the Industrial Canal (including the estuarine emergent 

wetland along the shoreline and the northern boundary of the LNG terminal) and associated waterbodies 

along the LNG vessel transit route including the Calcasieu River, Intracoastal Waterway, and Gulf of 

Mexico. Three categories of EFH are present within the Industrial Canal: estuarine wetlands, mud 

substrates, and estuarine water column. Estuarine and marine water column is present within the 

Calcasieu, Intracoastal Waterway, and Gulf of Mexico along the LNG vessel transit routes. 

TABLE 4.6.3-1

Life Stage Occurrence for Species with Essential Fish Habitat Designated in the Vicinity of the LNG Terminal 

Species Adults Eggs Juveniles Larvae Spawners

Brown shrimp X – X X –

Pink shrimp X – X – –

White shrimp X – X – –

Gray snapper X – X – –

Red drum X – X – –

Spanish mackerel X – X – –

____________________

X Life stage documented within Calcasieu Lake

– Life stage not documented within Calcasieu Lake

Source: NOAA Fisheries, 2011b

The estuarine emergent wetlands within the recessed berthing area provide nursery, shelter, and 

feeding habitat for many fish and invertebrate species. The mud substrates in and near the Industrial 

Canal 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 and marine 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 remain in an early successional stage due to maintenance dredging, propeller wash from passing 

vessels, and natural sedimentation. 

4.6.3.3 Impacts and Mitigation

As described in section 4.6.2.2, construction of the LNG terminal (in particular, construction of 

the LNG loading and berthing facilities) would result in temporary increases in noise, artificial lighting, 

turbidity, and suspended solids within the estuarine water column. Impacts on managed species during 

construction and operation of the LNG terminal would be similar to those described above for aquatic 

resources (see section 4.6.2.2). Potential impacts on estuarine wetlands, mud substrates, and estuarine 

water column habitat are described below.

Estuarine Wetlands

Construction of the recessed berthing area would remove and permanently convert 1.0 acre of 

estuarine emergent wetland habitat to estuarine water column habitat within the Industrial Canal. This 

wetland comprises 70 percent of a 1.4-acre wetland fringe along the southern shore of the Industrial 
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Canal. As described above (see section 4.6.2.2, Dredging), wetlands support a diverse ecosystem that 

provides nutrients, cover, shelter, and water for a variety of fish and invertebrate species. The permanent 

reduction in estuarine emergent wetland habitat within the Industrial Canal as well as the influx of 

individuals to the adjacent 0.4 acre of wetland may increase population densities for certain species, 

resulting in increased inter- and intra-specific competition and reduced reproductive success of 

individuals. 

During project design, Magnolia minimized project impacts on this wetland to the extent feasible; 

and would mitigate unavoidable impacts on this wetland through the implementation of its Compensatory 

Mitigation Plan, which is subject to review and approval by the COE, New Orleans District as part of the 

section 404/10 permit process (see our recommendation and detailed discussion in section 4.4.4). Section 

404 of the CWA requires that unavoidable wetland impacts must be offset by the creation, restoration, 

enhancement, or preservation of at least an equal amount of wetlands. Due to the relatively small amount 

of estuarine wetland affected at the LNG terminal site, its location adjacent to an existing canal with 

regular industrial vessel traffic, and the requirement for Magnolia to offset estuarine wetland impacts, we 

have determined that the Magnolia LNG Project would not have a significant adverse impact on estuarine 

wetland habitat.

Mud Substrates

Construction of the 16.2-acre recessed berthing area would require deepening the existing 

9.8-acre open water area to a depth of 44 feet below NAVD 88 to accommodate LNG carrier traffic. 

Dredging activities would result in the removal of the existing mud substrates from a 9.8-acre area (which 

would remove the existing benthic community) and the creation of 6.4 acres of new mud substrates. In 

addition, sediments resuspended in the water column during dredging and other construction activities 

would be redeposited on nearby substrates, potentially smothering immobile fish eggs and larvae as well 

as benthic invertebrates. Dredging activities could also cause mortality of larval or post-larval shrimp and 

fish species in the immediate vicinity of the cutterhead of the dredge. Although the dredging schedule has 

not been developed at the time of this writing, impacts on mud substrates would be greatest if dredging 

occurs during a period of peak larval abundance in early spring or summer. 

Maintenance dredging within the 16.2-acre recessed berthing area would occur every 4 to 5 years, 

and would have impacts on mud substrates similar to those described above for dredging during 

construction; however, impacts would be shorter in duration due to the reduced amount of material being 

removed from the recessed berthing area. 

As described above, mud substrates within the Industrial Canal remain in an early successional 

stage due to maintenance dredging of the canal. Given that impacts on mud substrates would generally be 

limited to the period during and immediately following construction and maintenance dredging, we have 

determined that the Magnolia LNG Project would not have a significant adverse impact on mud substrate 

habitat. 

Water Column

Construction of the LNG terminal would increase noise, artificial lighting, turbidity, and 

suspended solids levels within the estuarine water column in the vicinity of the terminal. Impacts on the 

estuarine water column would be greatest during dredging and pile driving activities, but would occur 

throughout construction of the terminal. During operation of the terminal, increased noise and artificial 

lighting, stormwater runoff, and vessel traffic could impact estuarine water column habitat in the vicinity 

of the LNG terminal. Impacts would primarily be limited to the 16.2-acre recessed berthing area; 

however, some impacts (e.g., noise and suspended solids) may extend beyond the recessed berthing area, 
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although the impact would decrease with distance. Potential impacts on fisheries present within the water 

column due to project-related changes in water quality and increased noise and artificial lighting could 

include decreased survival of juvenile fish, foraging success, and suitability of spawning habitat (see 

additional discussion in section 4.6.2.2). 

Construction of the LNG loading and berthing areas would create 6.4 acres of estuarine water 

column habitat. Dock facilities and rock armor placed along the sheet piling for protection against scour 

would create a hard substrate for the growth of attached organisms as well as three-dimensional structures 

to be used by some species as refuge. Given the proposed creation of additional water column habitat, 

measures Magnolia would implement to reduce impacts on aquatic resources, and the existing, similar 

industrial activity in the Industrial Canal, we have determined that impacts on estuarine water column 

habitat would not be significant. 

Traffic associated with construction and operation of the LNG terminal could affect estuarine and 

marine water column habitat within the Industrial Canal, Calcasieu River, Intracoastal Waterway, and 

Gulf of Mexico. Impacts on water quality may occur due to resuspension of suspended solids, discharge 

of ballast water, and intake and discharge of cooling water. However, these waterways were specifically 

created to provide deepwater access for maritime commerce and support high levels of deep draft traffic; 

therefore, impacts on water quality due to the incremental increase in vessel traffic within these 

waterways during construction and operation of the Magnolia LNG Project would not have a significant 

adverse impact on water column habitat.

Conclusions

As a non-federal party assisting the FERC in meeting its obligations under the MSA, Magnolia 

coordinated with NOAA Fisheries’ Habitat Conservation Division on February 10, 2014, regarding 

impacts on EFH. During the call, NOAA Fisheries indicated that the Magnolia LNG Project would not 

have significant impacts on EFH, provided the applicant addresses stormwater management and wetland 

mitigation. As described in the preceding sections, Magnolia would conduct ground disturbing activities 

in compliance with LPDES permit requirements as well as its project-specific Construction SWPPP, Plan,

and Procedures. Magnolia would mitigate for all impacts on wetlands determined to be jurisdictional 

under section 404 of the CWA in accordance with its COE-approved Compensatory Mitigation Plan (see 

our recommendation in section 4.4.4). 

On March 20, 2015, a conference call with staff from the FERC and NOAA Fisheries was held to 

discuss project-related impacts on EFH (Piper, 2015). Concerns regarding the conversion of estuarine 

wetland habitat to water column habitat were discussed during the call. However, implementation of 

Magnolia’s Compensatory Mitigation Plan is expected to offset wetland impacts. Assuming an adequate 

plan is developed in coordination with NOAA Fisheries, the plan would address concerns regarding 

impacts on EFH. 

Due to the relatively small area of EFH impacted within the Industrial Canal (the recessed 

berthing area represents approximately 5 percent of the total acreage within the canal), the increase in the

amount of estuarine water column habitat created during construction of the berthing area, Magnolia’s 

proposed mitigation measures, and preliminary coordination with NOAA Fisheries, we have determined 

that the Magnolia LNG Project would not have a significant adverse impact on EFH.

4.7 THREATENED, ENDANGERED, AND OTHER SPECIAL STATUS SPECIES

Special status species are those species for which state or federal agencies afford an additional 

level of protection by law, regulation, or policy. Included in this category are federally listed and 
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federally proposed species that are protected under the ESA, as amended; species that are currently 

candidates for federal listing under the ESA; state-listed threatened or endangered species; and species 

otherwise granted special status at the state or federal level (e.g., protected under the Marine Mammal 

Protection Act of 1972 [MMPA]).

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 projects, 

and to determine 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 request that NOAA Fisheries accept the information 

provided in this EIS as the BA for the projects. Furthermore, we request concurrence with our findings of 

effect for the federally listed species in table 4.7-1. The projects would have no effect on listed species 

under the jurisdiction of the FWS; therefore, preparation of a BA and consultation between the FERC and 

FWS is not necessary.

To assist in compliance with Section 7 of the ESA, Magnolia, acting as the FERC’s non-federal 

representative for the Magnolia LNG Project, coordinated with the FWS Louisiana Ecological Services 

Field Office and with NOAA Fisheries Protected Resources Division in August 2013 regarding its 

project. On September 27, 2013, the FWS confirmed that Magnolia’s proposed activities would have no 

effect on federal trust resources that are under its jurisdiction and currently protected by the ESA (FWS, 

2013). Similarly, KMLP requested comments from the FWS Louisiana Ecological Services Field Office 

on June 25, 2014 regarding its project and Protected Species and Habitat Survey Report. On July 25, 

2014, the FWS confirmed that KMLP’s proposed activities would have no effect on federal trust 

resources that are under its jurisdiction and currently protected by the ESA (FWS, 2014a). Magnolia and 

KMLP also coordinated with the LDWF and requested a review of information contained within the 

LNHP’s database regarding species and habitats potentially affected by construction or operation of the 

projects, respectively. Federally and state-listed species, as well as species that are candidates for listing, 

potentially occurring in the vicinity of the projects are identified in table 4.7-1.
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TABLE 4.7-1

Federally and State-listed Species Potentially Occurring in the Vicinity of the Magnolia LNG and Lake Charles Expansion Projects

Common Name

Scientific Name

Federal

Status State Status Parish Project Components

Determination of Effect 

and Habitat Assessment

Birds

Bald eagle

Haliaeetus 

leucocephalus

Delisted a, b Endangered Calcasieu LNG terminal Impacts are not anticipated

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. No suitable habitat is present 

in or adjacent to the LNG terminal.

Brown pelican

Pelecanus occidentalis

Delisted b Endangered Cameron LNG transit routes Impacts would not be significant

The species is largely restricted to coastal waters for foraging and 

nesting. No suitable nesting habitat is present in or adjacent to the 

LNG transit routes. Although foraging habitat exists near the LNG 

transit routes, it is unlikely that brown pelicans would use these areas 

regularly due to the existing high level of ship traffic.

Piping plover

Charadrius melodus

Threatened, b

Critical 

Habitat 

Threatened / 

Endangered

Cameron LNG transit routes No effect

The species breeds in the northern United States and Canada and 

overwinters along the coast of the Gulf of Mexico. Wintering habitat 

includes sandy beaches along the shoreline of the Gulf of Mexico. 

No suitable wintering habitat would be affected by the LNG terminal.

No destruction or adverse modification of critical habitat 

The nearest designated critical habitat is over 20 miles south of the

LNG terminal site and includes the shoreline on either side of the 

entrance to the Calcasieu Ship Channel. As this is an existing 

heavily trafficked area with reinforced shorelines, the increase in 

wave activity due to the proposed LNG carrier traffic is not expected 

to cause increased shoreline erosion or otherwise impact designated 

critical habitat. 

Red-cockaded 

woodpecker

Picoides borealis

Endangered b Endangered Calcasieu

Evangeline

LNG terminal

KMLP facilities – CGT, TRANSCO, and 

TETCO Meter Stations

No effect

Species occurs in open, park-like stands of mature pine forest. No 

suitable habitat is present in or adjacent to the LNG terminal site or 

KMLP facilities.

Red knot

Calidris canutus

Threatened b- Cameron LNG transit routes No effect

The species breeds in Alaska and Canada and may overwinter along 

the coast of the Gulf of Mexico. Wintering habitat includes tidal flats 

and beaches. No suitable wintering habitat would be affected by the

LNG terminal.

Sprague’s pipit

Anthus spragueii

Candidate b- Acadia

Calcasieu

Cameron

KMLP facilities – Compressor Station

760; TGT, ANR, and Pine Prairie Meter 

Stations; header pipelines

LNG terminal

LNG transit routes

Project would not contribute to a trend toward federal listing

The species breeds in the Great Plains. Wintering habitat in 

southern Louisiana consists of native prairie. No suitable habitat is 

present within or adjacent to the project components.
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TABLE 4.7-1 (cont’d)

Federally and State-listed Species Potentially Occurring in the Vicinity of the Magnolia LNG and Lake Charles Expansion Projects

Common Name

Scientific Name

Federal

Status State Status Parish Project Components

Determination of Effect 

and Habitat Assessment

Fish

Gulf sturgeon

Acipenser 

oxyrinchus desotoi

Threatened Threatened Cameron LNG transit routes No Effect

This anadromous fish spawns in large, free-flowing freshwater 

rivers with hard substrates composed of sand, rock, or rubble in 

spring; forages in lower rivers during summer months; and returns

to coastal waters of the Gulf of Mexico during the winter. The 

western extent of the species’ present range is Lake Pontchartrain, 

which is over 125 miles east of the projects (FWS, 2009).

Marine/Aquatic Mammals

West Indian manatee

Trichechus manatus

Endangered c Endangered Cameron LNG transit routes

Recessed berthing area

Not Likely to Adversely Affect

Species inhabits large, slow-moving rivers, river mouths, and 

shallow coastal areas such as coves and bays. Though extremely 

rare, this species has been documented within the Calcasieu River 

Basin and could utilize coastal areas along LNG transit routes. 

Blue whale

Balaenoptera 

musculus

Endangered c- Cameron LNG transit routes Not Likely to Adversely Affect

The species inhabits the open ocean. Recorded twice in the Gulf 

of Mexico (1924 and 1940) (Texas Tech, 1997). The blue whale 

could utilize offshore areas along LNG vessel transit routes.

Fin whale

Balaenoptera 

physalus

Endangered c- Cameron LNG transit routes Not Likely to Adversely Affect

The species inhabits the open ocean. Though rarely documented 

in the Gulf of Mexico, this species could utilize offshore areas 

along LNG transit routes.

Humpback whale

Megaptera 

novaeangliae

Endangered c, d- Cameron LNG transit routes Not Likely to Adversely Affect

The species inhabits the open ocean, coastal waters, and 

sometimes inshore areas such as bays. Though rarely 

documented in the Gulf of Mexico, this species could utilize 

offshore areas along LNG transit routes.

Sei whale

Balaenoptera 

borealis

Endangered c- Cameron LNG transit routes Not Likely to Adversely Affect

The species inhabits the open ocean. Though rarely documented 

in the Gulf of Mexico, this species could utilize offshore areas 

along LNG transit routes.

Sperm whale

Physeter 

macrocephalus

Endangered c- Cameron LNG transit routes Not Likely to Adversely Affect

The species inhabits deep waters in the open ocean. The sperm 

whale is widely distributed throughout waters along and offshore of 

the continental slope (NOAA Fisheries, 2013f). This species could 

utilize offshore areas along LNG vessel transit routes.
4-75

TABLE 4.7-1 (cont’d)

Federally and State-listed Species Potentially Occurring in the Vicinity of the Magnolia LNG and Lake Charles Expansion Projects

Common Name

Scientific Name

Federal

Status State Status Parish Project Components

Determination of Effect 

and Habitat Assessment

Marine Reptiles

Green sea turtle

Chelonia mydas

Threatened - Cameron LNG transit routes Not Likely to Adversely Affect

Although rarely encountered in waters off the coast of western 

Louisiana, the green sea turtle could utilize areas along LNG 

vessel transit routes.

Hawksbill sea turtle

Eretmochelys 

imbricate

Endangered - Cameron LNG transit routes Not Likely to Adversely Affect

Although very rarely encountered in waters off the coast of 

Louisiana, this species was reported near Calcasieu Lake in 1986 

and could utilize areas along LNG transit routes.

Kemp’s ridley sea turtle

Lepidochelys kempii

Endangered - Cameron LNG transit routes Not Likely to Adversely Affect

Although extremely rare, this species has been documented in 

Calcasieu Lake and occurs off the coast of Louisiana within coastal 

and offshore waters more than other species of sea turtles. This 

species could utilize areas along LNG vessel transit routes.

Leatherback sea turtle

Dermochelys 

coriacea

Endangered - Cameron LNG transit routes Not Likely to Adversely Affect

Although rarely encountered in waters off the coast of western 

Louisiana, the leatherback sea turtle could utilize areas along LNG 

transit routes.

Loggerhead sea turtle

Caretta caretta

Threatened - Cameron LNG transit routes Not Likely to Adversely Affect

Although rarely encountered in waters off the coast of western 

Louisiana, the loggerhead sea turtle could utilize areas along LNG 

transit routes.

____________________

a Species protected under the BGEPA (see section 4.7.2.1)

b Species protected under the MBTA (see section 4.6.1.3)

c Species protected under the MMPA (see section 4.7.2.2)

d On April 21, 2015, NOAA Fisheries proposed to divide the humpback whale into 14 distinct population segments (DPS), remove the current species-level listing under the 

ESA, and list two DPS as endangered and two DPS as threatened. The remaining 10 DPS (including the West Indies DPS, which is the DPS that may occur along the 

vessel transit route) are not proposed for listing. 
4-76

Based upon our review of publicly available information, agency correspondence, and field 

surveys, a total of 18 federally and/or state-listed threatened and endangered, or candidate species may 

occur in parishes affected by the projects. Within these parishes, critical habitat has been designated for 

one species, the piping plover. Potentially suitable habitat for federally listed species is not present within 

areas affected by construction or operation of the LNG terminal or KMLP facilities; however, potentially 

suitable habitat is present along the portion of the LNG transit route in Cameron Parish and the Gulf of 

Mexico.

We have determined that the projects would have no effect on four federally listed species, are

not likely to destroy or adversely modify designated critical habitat, and would not contribute to the trend 

toward federal listing for the one candidate species. Because we have determined that the projects would 

not affect these species or their designated critical habitat, they are not discussed further in this EIS. 

Additional discussion of the13 remaining federally and/or state-listed species is provided in sections 4.7.1 

and 4.7.2, respectively.

4.7.1 Federally Listed Threatened and Endangered Species

Based on information obtained from the FWS and NOAA Fisheries, 15 federally listed threatened 

and endangered species and 1 species that is a candidate for listing under the ESA may occur within the 

parishes affected by the projects. Of these, four federally listed and the one candidate species do not have 

the potential to occur in the vicinity of the proposed facilities (see table 4.7-1). The remaining 

11 federally listed species are marine species (i.e., five sea turtle species, five whale species, and the West 

Indian manatee) that occur within or off the Gulf Coast of Cameron Parish, Louisiana. Therefore, 

potentially suitable habitat for these species is limited to the portion of the LNG vessel transit in Cameron 

Parish and the Gulf of Mexico. Other components of the projects (construction and operation of the LNG 

terminal and KMLP facilities) are outside of Cameron Parish, and are not discussed further. 

4.7.1.1 Sea Turtles

Sea turtles are found throughout the tropical and subtropical seas of the world where they occur at 

or near the surface of the water. All species are listed as threatened or endangered under the ESA and are 

under the shared jurisdiction of the FWS and NOAA Fisheries.12 Trade of sea turtles is restricted by the 

Convention on International Trade in Endangered Species; however, not all countries have ceased to 

harvest these species. The major threats to sea turtle populations are overharvesting, fisheries by-catch, 

disease, pollution, and coastal development of nesting beaches. Five species of federally listed sea turtles

could occur along the portion of the LNG transit routes in Cameron Parish and the Gulf of Mexico, 

including the green, hawksbill, Kemp’s ridley, leatherback, and loggerhead sea turtles. These turtles are 

further described below.

Green Sea Turtle

The green sea turtle is currently federally listed as threatened. On March 23, 2015, the FWS and 

NOAA Fisheries found that the green sea turtle population is composed of 11 distinct population 

segments (DPS) that qualify as unique species for the purposes of listing under the ESA (Federal Register 

15271–15337). As a result, the FWS and NOAA Fisheries are proposing to remove the current rangewide listing status and, in its place, to list eight DPSs as threatened and three DPSs as endangered. Green 

sea turtles occurring off the coast of Louisiana are part of the North Atlantic DPS, which is proposed for 

listing as threatened. This species occurs within coastal and offshore waters off of Louisiana, but is rarely 

documented off the western portion of the state (Fuller et al., 1987).

 

12 The FWS has jurisdiction over sea turtles on land and NOAA Fisheries has jurisdiction over sea turtles within the marine environment.
4-77

Green sea turtles are generally found in shallow waters inside bays, inlets, and reefs with an 

abundance of seagrass and algae. They use coral reefs and rocky outcrops near feeding areas to rest, and 

they feed on marine plants, mollusks, sponges, crustaceans, and jellyfish. As one of the more coastal 

species of sea turtle, adult green sea turtles forage primarily on seagrass and marine algae. Hatchlings 

feed on a variety of plants and animals and have been observed utilizing Sargassum mats for food and 

refuge. Green sea turtles can exhibit high nesting site fidelity, which can lead to common migratory 

routes between feeding grounds and nesting beaches. Green sea turtles nest on open, sloping beaches 

with minimal disturbance (FWS, 2012b). This species is not commonly known to occur in either inshore 

or offshore waters of Louisiana. Suitable nesting habitat is not present along the LNG transit routes; 

however, adult green sea turtles could potentially utilize these areas for transit and juveniles could 

potentially utilize these areas for foraging. 

Hawksbill Sea Turtle

The hawksbill sea turtle is federally listed as endangered. This species is widely distributed 

throughout the Caribbean Sea and western Atlantic Ocean. The hawksbill sea turtle is one of the most 

infrequently encountered sea turtles in offshore Louisiana (COE, 2013a). However, a hawksbill was 

reported near Calcasieu Lake in 1986 (Fuller et al., 1987). They occur in shallow coastal areas, oceanic 

islands, rocky areas, and coral reefs (FWS, 2012c). Hawksbill sea turtles feed on sponges, other 

invertebrates, and algae (NOAA Fisheries, 2013a). Young hawksbills are found foraging in association 

with Sargassum mats in the open ocean; as they mature, hawksbill sea turtles commonly forage over coral 

reefs and hard bottom substrates. They nest in low densities on scattered undisturbed deep-sand beaches 

in the tropics. (FWS, 2012c). This species is not commonly known to occur in either inshore or offshore 

waters of Louisiana. Suitable nesting habitat is not present along the LNG transit routes; however, adult 

hawksbill sea turtles could potentially utilize these areas for transit and juveniles could potentially utilize 

these areas for foraging.

Kemp’s Ridley Sea Turtle

The Kemp’s ridley sea turtle is federally listed as endangered. This species is the smallest marine 

turtle in the world and has been documented off the coast of Louisiana more than other sea turtles (Fuller 

et al., 1987). This species has been documented within Calcasieu Lake, though very rarely (Fuller et al., 

1987). Juvenile Kemp’s ridley sea turtles are generally found in Louisiana’s coastal waters from May 

through October, and adults are common during the spring and summer near the mouth of the Mississippi 

River. During the winter months, Kemp’s ridley sea turtles typically move offshore to deeper, warmer 

waters, but some of the deepwater channels and estuaries in Louisiana could provide thermal refuge

(COE, 2013a). Kemp’s ridley sea turtles feed primarily on crabs, but are also known to feed on fish, 

jellyfish, and mollusks (FWS, 2012d; NOAA Fisheries, 2013b). This species is not known to nest on the 

Louisiana coast; however, it could utilize the estuarine and offshore waters along the LNG transit routes 

for foraging and transit during the non-nesting season (LDWF, 2014f).

Leatherback Sea Turtle

The leatherback sea turtle is federally listed as endangered. The leatherback is the largest sea 

turtle and spends more of its life in the open ocean environment than other sea turtles. Because it spends 

most of its life in offshore waters, the leatherback sea turtle is rarely documented off the coast of 

Louisiana (Fuller et al., 1987). Leatherback sea turtles occur globally, and range farther north and south 

than other sea turtles, likely due to their ability to maintain warmer body temperatures. Leatherback sea 

turtles feed primarily on soft-bodied animals such as jellyfish and sea squirts; however, they are also 

known to consume sea urchins, crustaceans, fish, and floating seaweed. Females require sandy beaches 

with deepwater approach for nesting habitat. (FWS, 2012e, NOAA Fisheries, 2013c). The largest nesting 
4-78

assemblages are found in northern South America and West Africa; however, within the United States, 

southeast Florida, the U.S. Virgin Islands, and Puerto Rico are their primary nesting locations (NOAA 

Fisheries, 2013c). This species is not commonly known to occur in either inshore or offshore waters of 

Louisiana. While leatherback sea turtles could potentially utilize offshore waters along the LNG transit 

routes for foraging habitat and transit, suitable nesting habitat for this species is not present within these 

areas. 

Loggerhead Sea Turtle

The loggerhead sea turtle is federally listed as threatened. This species occurs throughout the 

world in temperate and tropical regions of the Atlantic, Pacific, and Indian Oceans. The loggerhead sea 

turtle is occasionally documented off the coast of Louisiana, although the majority of the sightings occur 

east of the Vermillion River (over 70 miles east of the LNG vessel transit route through the Gulf of 

Mexico) (Fuller et al., 1987). The loggerhead sea turtle can migrate significant distances between 

foraging areas, breeding areas, and nesting locations. They can be found in inshore areas such as bays, 

ship channels, large river mouths, and salt marshes as well as hundreds of miles offshore. Loggerhead sea 

turtles feed on mollusks, crustaceans, fish, conchs, and other marine animals (FWS, 2012f; NOAA 

Fisheries, 2013e). Young loggerheads occur in the open ocean and are often found in association with 

Sargassum mats, while juveniles and adults reside in coastal areas in between reproductive migrations 

where females return to their natal beach to nest. In the United States, loggerheads can be found nesting 

from Texas to Virginia, though the major nesting concentrations occur in Florida, Georgia, South 

Carolina, and North Carolina (FWS, 2012f). While loggerhead sea turtles could potentially utilize 

inshore and offshore waters along the LNG transit routes for foraging habitat and transit, suitable nesting 

habitat for this species is not present within these areas. 

Sea Turtle Impacts and Mitigation

No suitable nesting habitat for sea turtles is present along the LNG vessel transit routes, although 

foraging and transit habitat for these species is present within these areas. The increased traffic within the 

Calcasieu Ship Channel and Gulf of Mexico due to LNG vessel transit to and from the LNG terminal site 

could pose an increased risk to sea turtles from vessel strikes. LNG transit vessels (LNG carriers and 

LNG barges) would use well-traveled shipping lanes. In total, LNG transit vessels could make up to 

208 trips to the LNG terminal per year (up to four round trips per week). Vulnerability to collision with 

an LNG transit vessel would be greatest while sea turtles feed, swim, and rest near the surface of the 

water. LNG transit vessels operating within the U.S. Exclusive Economic Zone (EEZ) in the Gulf of 

Mexico are generally slower and generate more noise than typical large vessels, and would be more 

readily avoided by sea turtles. Additionally, LNG carriers push a considerable bow wave when underway 

on the open ocean because of their design and large displacement tonnage. This wave pushes water, 

flotsam, and other small objects (such as sea turtles) away from the vessel. To further minimize the 

potential for vessel strikes, Magnolia would provide LNG ship captains with the NOAA-issued document 

entitled Vessel Strike Avoidance Measures and Reporting for Mariners (NOAA Fisheries, 2008)” which 

outlines collision avoidance measures. Based on the sea turtle’s characteristics and habitat requirements,

and because Magnolia would provide LNG ship captains with NOAA Fisheries’ recommended strike 

avoidance measures, we have determined that the Magnolia LNG Project may affect, but is not likely to 

adversely affect sea turtles. 

4.7.1.2 West Indian Manatee

The West Indian manatee is federally listed as endangered. This species is an herbivorous marine 

mammal most commonly found in coastal estuaries and rivers in Florida and Georgia, but it has been 

documented from Texas to Massachusetts. Manatees are a sub-tropical species that are not cold-tolerant 
4-79

and reside in the warm waters of peninsular Florida during the winter; however, they may disperse great 

distances during warmer months (FWS, 2007). They feed on aquatic plants such as seagrass, water 

hyacinths, hydrilla, and eelgrass. Mating can occur at any time of year with adults usually giving birth to 

a calf every 2 to 5 years. Calves may be present throughout the year and usually remain with their mother 

for up to 2 years. The greatest threats to the manatee are collisions with boats and loss of warm water 

habitat. They often rest suspended just below the water’s surface, making them very vulnerable to being 

hit by vessels (FWS, 2014c).

Although extremely rare in the general project area, the manatee has been documented within the 

Calcasieu River Basin and could occur along the portion of the LNG transit routes in Cameron Parish and 

the Gulf of Mexico (FWS, 2014b); however, given the level of industrial activity and lack of foraging 

habitat within the Calcasieu Ship Channel, their presence within this area is unlikely (LDWF, 2014g). 

Due to its location several miles north of Calcasieu Lake within the Industrial Canal, the likelihood of 

manatees occurring in the vicinity of the recessed berthing area is so unlikely as to be discountable. 

Increased traffic within the Calcasieu Ship Channel due to LNG vessel transit to and from the 

LNG terminal could pose an increased risk to manatees from vessel strikes. In areas of intense ship 

traffic, manatees can experience propeller or collision injuries; however, most of these injuries are caused 

by small, fast moving vessels. As described in section 4.7.1.1, Magnolia proposes to provide LNG ship 

captains with a NOAA-issued guidance document that outlines collision avoidance measures in order to 

minimize impacts from vessel strikes. 

Based on the manatee’s characteristics and habitat requirements, the lack of foraging habitat 

along the LNG transit routes, and because Magnolia would provide LNG ship captains with NOAA 

Fisheries’ recommended strike avoidance measures, we have determined that the Magnolia LNG Project

may affect, but is not likely to adversely affect the West Indian manatee. 

4.7.1.3 Whales

Whales are long-lived marine mammals that occur throughout the world’s oceans. They can be 

divided into two main groups: toothed whales and baleen whales. Feeding morphology and prey are the 

major differences between these groups. Many species of whales migrate extremely long distances to 

take advantage of seasonal food resources or calm wintering grounds for rearing young. Whales 

generally utilize warm tropical waters during winter months when the polar seas are cold, ice covered, 

and food-poor, though some species will stay in these regions year-round. Whales could utilize the 

offshore areas of the Gulf of Mexico along the LNG transit routes for migration and feeding.

The sperm whale is a toothed whale that inhabits the deeper waters of the world’s oceans 

throughout the year, where they feed primarily on squid and other deep sea creatures. Migrations are not 

as distinct as other species and are thought to primarily follow food resources (NOAA Fisheries, 2010b). 

Sperm whales are present in the northern Gulf of Mexico in all seasons, but are more common during the 

summer months (NOAA Fisheries, 2014c). The sperm whale is the only federally listed whale that is 

known to commonly occur in the Gulf of Mexico (NOAA Fisheries, 2012).

The humpback whale is a baleen whale that is distributed throughout the world’s oceans. They 

generally spend winter months in lower temperate and tropical waters then migrate to higher latitudes 

during the summer months to feed in areas of high productivity. They winter in tropical waters in close 

proximity to deeper water. Calving occurs primarily during the winter months and the only breeding 

ground in U.S. waters is near Puerto Rico (NOAA Fisheries, 1991). Although humpback whales have 

been documented within the Gulf of Mexico, no population estimates are available for this area as 

sightings are uncommon (NOAA Fisheries, 2012). 
4-80

Other baleen whales, including the fin, sei, and blue whales are listed by NOAA Fisheries as 

occurring within the southeast region. Like the humpback, these whales are not commonly found in the 

Gulf of Mexico, but could occur within the area during migrations or other movements (NOAA Fisheries, 

2012). Feeding is not expected in or around the Gulf of Mexico as these species usually feed on 

zooplankton and small fish aggregations during summer months in the northern Atlantic Ocean (NOAA 

Fisheries, 1998, 2010a, 2011a). Calving and breeding grounds have not been identified for these species 

in the Gulf of Mexico.

Whales could be vulnerable to vessel strikes during operation of the proposed LNG terminal. 

Vulnerability to collision with LNG transit vessels would be greatest while these animals feed, swim, and 

rest near the surface of the water. In areas of intense ship traffic, whales can experience propeller or 

collision injuries; however, most of these injuries are caused by small, fast moving vessels. LNG transit 

vessels operating within the EEZ in the Gulf of Mexico are generally slower and generate more noise than 

typical large vessels, and would be more readily avoided by whales. These LNG transit vessels would 

use established and well-traveled shipping lanes. As described in section 4.7.1.1, Magnolia proposes to 

provide LNG ship captains with a NOAA-issued guidance document that outlines collision avoidance 

measures to be implemented in order to minimize the likelihood of a vessel strike. Based on the whales’ 

characteristics and habitat requirements, and because Magnolia would provide LNG ship captains with 

NOAA Fisheries’ recommended strike avoidance measures, we have determined that the Magnolia LNG 

Project may affect, but is not likely to adversely affect federally listed whales. 

4.7.2 State-listed and Special Status Species

4.7.2.1 State-listed Species

Based on information obtained from the LDWF, six state-listed threatened or endangered species 

are listed within the parishes that would be affected by the projects (LDWF, 2014h). Four of the six statelisted species (piping plover, red-cockaded woodpecker, Gulf sturgeon, and West Indian manatee) are 

also federally listed as threatened or endangered; as indicated in table 4.7-1 and discussed in section 4.7.1. 

The projects are expected to have no impact on one of the two remaining state-listed species (bald eagle) 

due to the absence of suitable habitat within or near the LNG terminal. The remaining state-listed 

species, the brown pelican, is discussed below.

The brown pelican is listed by the State of Louisiana as endangered and may occur within

Cameron Parish; therefore, impacts resulting from construction and operation of the LNG terminal and

KMLP facilities, which are outside of Cameron Parish, are not discussed within this section. The brown 

pelican was federally delisted in 2009, but is still federally protected by the MBTA, which prohibits the 

“taking” of brown pelicans, including their parts, nests, or eggs (see section 4.6.1.3). In Louisiana, the 

brown pelican occurs along the coasts in bays and tidal estuaries; nesting occurs primarily in southeastern 

coastal areas on barrier islands within dune shrub thickets. Brown pelicans primarily forage on fish and 

some marine invertebrates. Current threats to this species include loss of nesting habitat due to barrier 

island erosion, loss of coastal land, and the illegal take of eggs (LDWF, 2014e).

While no suitable nesting habitat is present along the LNG transit routes, the Calcasieu Ship 

Channel and coastal waters of the Gulf of Mexico may provide foraging habitat for the brown pelican. 

Although this species commonly occurs within the Sabine National Wildlife Refuge (NWR), which is 

approximately 12 miles south-southwest of the proposed LNG terminal site on the west side of the 

Calcasieu Ship Channel (Audubon, 2014), due to the high level of ship traffic, it is unlikely that brown 

pelicans would use the Calcasieu Ship Channel regularly. 
4-81

Based on Magnolia’s proposed use of existing, highly traveled shipping lanes, we have 

determined that adverse impacts on brown pelicans due to LNG transit during operation of the LNG 

terminal are not anticipated.

4.7.2.2 Marine Mammals

Marine mammals are federally protected under the MMPA. The MMPA established, with limited 

exceptions, a moratorium on the “taking” of marine mammals in waters or on lands under United States

jurisdiction. The act further regulates, with certain exceptions, the “take” of marine mammals on the high 

seas by persons, vessels, or other conveyances subject to the jurisdiction of the United States. A total of 

29 mammals protected under the MMPA may occur along the LNG transit routes (NOAA Fisheries, 

2012). Six of these species are also listed under the ESA (five whales and the West Indian manatee) and 

are included in table 4.7-1 and discussed in sections 4.7.1.2 and 4.7.1.3. The remaining 23 whale and 

dolphin species and their potential area of occurrence along the LNG transit routes are described in table 

4.7.2-1 and discussed below.

TABLE 4.7.2-1

Non-Endangered Species Act Listed Marine Mammals Potentially Occurring Along the LNG Transit Routes

Common Name Scientific Name Area Where Mammal May Occur

Dolphins

Atlantic spotted dolphin Stenella frontalis Calcasieu Ship Channel and Gulf of Mexico

Bottlenose dolphin Tursiops truncatus Calcasieu Ship Channel and Gulf of Mexico

Clymene dolphin Stenella clymene Gulf of Mexico

False killer whale Pseudorca crassidens Gulf of Mexico

Frasier’s dolphin Lagenodelphis hosei Gulf of Mexico

Killer whale Orcinus orca Gulf of Mexico

Melon-headed whale Peponocephala electra Gulf of Mexico

Pantropical spotted dolphin Stenella attenuata Gulf of Mexico

Pygmy killer whale Feresa attenuata Gulf of Mexico

Risso’s dolphin Grampus griseus Gulf of Mexico

Rough-toothed dolphin Steno bredanensis Gulf of Mexico

Short-finned pilot whale Globicephala macrorhynchus Gulf of Mexico

Spinner dolphin Stenella longirostris Gulf of Mexico

Striped dolphin Stenella coeruleoalba Gulf of Mexico

Whales

Blainville’s beaked whale Mesoplodon densirostris Gulf of Mexico

Bryde’s whale Balaenoptera edeni Gulf of Mexico

Cuvier’s beaked whale Ziphius cavirostris Gulf of Mexico

Dwarf sperm whale Kogia sima Gulf of Mexico

Gervais’ beaked whale Mesoplodon europaeus Gulf of Mexico

Minke whale Balaenoptera acutorostrata Gulf of Mexico

North Atlantic right whale Eubalaena glacialis Gulf of Mexico

Pygmy sperm whale Kogia breviceps Gulf of Mexico

Sowerby’s beaked whale Mesoplodon bidens Gulf of Mexico

____________________

Source: NOAA Fisheries, 2012
4-82

Two marine mammal species, the Atlantic spotted dolphin and bottlenose dolphin, could 

potentially occur within the Calcasieu Ship Channel. Due to the distance from the Gulf of Mexico (transit 

is 24 nautical miles from the entrance to the Calcasieu River jetties in the Gulf of Mexico [River Mile 0] 

to the LNG terminal) and the increased freshwater influence, it is unlikely that dolphins would be found

within the Industrial Canal. Atlantic spotted dolphins are widely distributed within warm tropical to 

temperate waters of the Atlantic Ocean, including the Gulf of Mexico. Their diet consists of small fish, 

squid, octopus, and benthic invertebrates. Bottlenose dolphins are found in tropical and temperate waters 

worldwide. Coastal populations commonly migrate into bays and estuaries while offshore populations 

reside along the continental shelf. The coastal populations feed on fish and benthic invertebrates while 

offshore populations feed on pelagic fish and squid. Bottlenose dolphins commonly occur in coastal 

waters of Louisiana and offshore waters within the Gulf of Mexico and could occur within the Calcasieu 

Ship Channel. Atlantic spotted dolphins could also occur within these areas due to their occasional 

association with bottlenose dolphins (NOAA Fisheries, 2014a, 2014b).

Impacts on marine mammals occurring along the LNG transit routes would be similar to those 

discussed in sections 4.7.1.2 and 4.7.1.3 regarding the West Indian manatee and federally listed whales, 

respectively. The primary threat to marine mammals resulting from LNG vessel transits would be an 

increased risk of vessel strikes during operation. LNG transit vessels operating within the EEZ in the 

Gulf of Mexico are generally slower and generate more noise than typical large vessels, and would be 

more readily avoided by marine mammals. Additionally, LNG ships push a considerable bow wave when 

underway on the open ocean because of their design and large displacement tonnage. This wave pushes 

water, flotsam, and other small objects (e.g., dolphins) away from the vessel. LNG vessels would use 

established and well-traveled shipping lanes. As described in section 4.7.1.1, Magnolia proposes to 

provide LNG ship captains with a NOAA-issued guidance document that outlines collision avoidance 

measures to be implemented in order to minimize the likelihood of a vessel strikes. Based on Magnolia’s 

proposed use of existing, highly traveled shipping lanes and proposed mitigation measure, we have 

determined that construction and operation of the LNG terminal would have no significant adverse 

impacts on marine mammals.

4.8 LAND USE, RECREATION, AND VISUAL RESOURCES

4.8.1 Land Use

4.8.1.1 Environmental Setting

The LNG terminal and KMLP facilities would affect five general land use types, including 

agricultural, industrial/commercial, open land, open water, and forest. Table 4.8.1-1 summarizes the 

acreage of each land use type that would be affected by construction and operation of the LNG terminal

and KMLP facilities. The definitions of each land use type are as follows:

 Agricultural – includes active cropland, pasture, hayfields, and crawfish ponds;

 Industrial/Commercial – includes power or utility stations, manufacturing or industrial 

plants, paved areas, commercial facilities, and roads; 

 Open Land – includes non-forested uplands, maintained (vegetated) utility rights-of-way, 

and emergent (herbaceous) and scrub-shrub wetlands; 

 Open Water – includes waterbodies such as the Industrial Canal, borrow pit, intermittent 

streams, and ditches; and

 Forest – includes upland forest and forested/scrub-shrub wetland complexes.
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TABLE 4.8.1-1

Land Use Types Affected by Construction and Operation of the LNG Terminal and KMLP Facilities (in acres) a

Facility

Agricultural

Industrial/

Commercial

Open

Land

Open

Water Forest Total

Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons. Oper. Cons.

b Oper.c

LNG TERMINAL FACILITIES

LNG terminal d 0.0 0.0 0.0 0.0 80.1 80.1 9.8 9.8 34.0 34.0 123.8 123.8

DII construction yard 0.0 0.0 5.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 5.2 0.0

Dredge material and effluent pipelines e 0.0 0.0 6.9 0.0 0.0 0.0 0.0 0.0 0.0 0.0 6.9 0.0

Dredge material placement area f 0.0 0.0 1.0 0.0 106.8 0.0 33.5 0.0 0.5 0.0 141.8 0.0

Total for LNG Terminal Facilities 0.0 0.0 13.1 0.0 186.9 80.1 43.3 9.8 34.5 34.0 277.7 123.8

KMLP FACILITIES

Header Pipelines

Low pressure header pipeline 20.2 7.8 0.4 0.3 0.0 0.0 0.1 0.0 0.0 0.0 20.7 8.1

High pressure header pipeline 0.9 0.5 0.2 0.2 0.1 0.0 <0.1 0.0 0.0 0.0 1.1 0.7

Subtotal 21.1 8.3 0.6 0.5 0.1 0.0 0.1 0.0 0.0 0.0 21.9 8.8

Aboveground Facilities

Compressor Station 760 40.4 11.2 0.0 0.0 0.0 0.0 0.2 0.0 0.0 0.0 40.6 11.2

CGT Meter Station 0.6 0.3 1.3 0.1 0.0 0.0 0.0 0.0 0.0 0.0 2.0 0.3

TRANSCO Meter Station 0.6 <0.1 0.9 0.0 0.1 0.1 0.0 0.0 0.0 0.0 1.6 0.1

TETCO Meter Station 0.5 0.0 1.2 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.7 0.0

ANR Meter Station 0.3 0.0 1.4 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.7 0.0

Pine Prairie Meter Station 0.0 0.0 1.9 0.0 0.1 0.0 0.0 0.0 0.0 0.0 2.0 0.0

TGT Meter Station 0.0 0.0 0.9 0.0 0.5 0.4 <0.1 0.0 0.0 0.0 1.3 0.4

Existing access roads 0.0 0.0 3.0 0.0 0.0 0.0 <0.1 0.0 0.0 0.0 3.0 0.0

Subtotal 42.4 11.5 10.6 0.1 0.7 0.5 0.2 0.0 0.0 0.0 54.0 12.0

Total for KMLP Facilities 63.5 19.8 11.2 0.6 0.7 0.5 0.3 0.0 0.0 0.0 75.8 20.8

TOTAL 63.5 19.8 24.3 0.6 187.6 80.6 43.6 9.8 34.5 34.0 353.5 144.6

____________________

a The totals shown in this table may not equal the sum of the addends due to rounding. 

b Total construction impacts include both temporary and permanent work areas.

c New operation impacts include only new permanent easement or facility footprint (i.e., land within the existing meter stations is not included).

d LNG terminal includes those facilities that would be constructed and operated at the site by Magnolia as well as KMLP’s Magnolia Meter Station and interconnect pipeline.

e Access to areas that would be crossed by the dredge material and effluent pipelines has not been granted at the time of this writing. Land use categories were determined based on 

review of aerial photography.

f Access to the dredge material placement area has not been granted at the time of this writing; therefore, NWI data was used to identify wetlands present. Magnolia has 

stated that wetlands identified during survey may be avoided, restored, or filled. Because actual wetland impacts have not been determined at this time, our impact analysis 

assumes the worst-case scenario (fill of wetlands present within the placement area). See additional discussion in section 4.4.2.1.
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LNG Terminal Facilities

The LNG terminal would be located on 114 acres of land within a 115-acre site along the 

southern shore of the Industrial Canal. The site, which is zoned for heavy industrial use (Calcasieu Parish 

Police Jury, 2015), was used by the COE for the placement of dredge material from within the Industrial 

Canal and turning basin between 1975 and 1984. As a result, the site is comprised of open land 

(70 percent) and relatively young forest (30 percent). In addition, 9.8 acres of open water within the 

Industrial Canal would be required during construction and operation of the recessed berthing area at the 

LNG terminal.

Utilities within the site include KMLP’s natural gas pipeline that largely parallels the southern 

portion of the site, a Chevron natural gas pipeline that transects the western corner of the site, and water 

and telephone lines along the southern boundary of the site, adjacent to Henry Pugh Boulevard. No 

buildings or aboveground structures are present within the LNG terminal site. The nearest occupied 

residences are 0.6 mile south of the site; this community is situated along a canal leading to the 

Intracoastal Waterway.

Magnolia plans to use a 5.2-acre portion of the existing DII construction yard for marine 

deliveries, materials staging and transport, and temporary parking for construction workers. Land use 

within this portion of the DII site is industrial/commercial. In addition, Magnolia plans to use a 

148.7-acre area for the temporary placement of dredge material and effluent pipelines and dredge material 

placement. Land use along the dredge material and effluent pipeline route is industrial/commercial; land 

use within the dredge material placement area is primarily open land (75 percent), although open water 

(24 percent), forest (1 percent), and industrial/commercial (less than 1 percent) are also present.

The LNG terminal would be on the southern shore of the Industrial Canal on land owned by the 

Port of Lake Charles. Land use adjacent to the Industrial Canal east and northeast of the LNG terminal is 

primarily industrial/commercial and developed. In contrast, land use to the northwest and south of the 

site consists of open land and forest. Land use in the vicinity of the LNG terminal is depicted in 

figure 4.8.1-1 and described in additional detail below:

 East of the LNG terminal along the Industrial Canal – Land use within the DII, Seabulk 

Towing, and Leevac Shipyards sites is comprised primarily of industrial/commercial. As 

described above, portions of the DII site would be used during construction of the LNG 

terminal.

 East of the Industrial Canal across Big Lake Road – The proposed dredge material and 

effluent pipelines and dredge material placement area would be within the CB&I site. 

Land use within the western portion of the CB&I site, through which the dredge material 

and effluent pipelines would be routed, is industrial/commercial. The eastern portion of 

the site, where the dredge material placement area would be located, contains primarily 

open land.

 Southeast of the LNG terminal – Land use within the Calcasieu Parish District 12 Water 

Works site, which contains two public water supply wells and one water storage tank, is 

developed (analysis relating to the water supply wells is provided in section 4.3.1). 

 Northeast of the LNG terminal – Across the Industrial Canal, land use within the 

Trunkline LNG Terminal and Lake Charles Carbon Company sites is 

industrial/commercial.
Calcasieu Parish

District 12 Water

Works

Calcasieu

Point

Landing

CB&I

DII 

Lake Charles

Carbon Company

Leevac

Shipyards

Lake Charles

Marine Spill

Response

Corporation

Martin

Energy

Services

G2X Energy, Lake Charles

Gasoline Facility

(Planned)

LDWF, Fisheries Enhancement,

Research, and Science Center

(Planned)

Seabulk

Towing

Trunkline

LNG Terminal

LNG Terminal

Industrial Canal

Calcasieu

River

This information is for environmental review purposes only.

0 500 1,000

Feet

Magnolia LNG Project p Figure 4.8.1-1

Development in the Vicinity of the LNG Terminal

1:12,000

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 West of the LNG terminal along the Industrial Canal – Land use within Martin Energy 

Services’ vessel bunkering facility and Marine Spill Response Corporation’s pier for 

supporting oil spill response services is industrial/commercial. Land use within 

Calcasieu Point Landing, a public park, is developed (analysis relating to Calcasieu Point 

Landing is provided in section 4.8.4). 

 Northwest and south of the LNG terminal – Undeveloped land occurs both to the 

northwest and south of the LNG terminal site, across the Industrial Canal and Henry 

Pugh Boulevard, respectively. Land use within these areas contains a mixture of forest 

and open land.13 

KMLP Facilities

Construction of the header pipelines, Compressor Station 760, and proposed modifications to 

KMLP’s existing meter stations would affect about 76 acres of land in Evangeline and Acadia Parishes. 

Because the activities associated with the KMLP facilities involve modification or expansion of existing 

facilities, much of the land affected by the KMLP facilities would be adjacent to the permanent easement 

associated with KMLP’s existing mainline or would be adjacent to or within existing meter station sites.

As described in table 4.8.1-1, the new facilities (the header pipelines and Compressor Station 

760) would be constructed almost entirely within agricultural lands (98 percent) currently used for rice 

and crawfish production. The nearest residence to the header pipelines is approximately 500 feet west of 

the low pressure header pipeline (milepost 0.2). The nearest residences to Compressor Station 760 

include three homesteads approximately 1,500 feet west of the compressor station site. 

Because the meter station modifications would take place within and adjacent to existing 

facilities, the majority of the land affected would be industrial/commercial (73 percent); the remaining 

land affected by the meter station modifications would be agricultural (19 percent) and open lands 

(8 percent). The nearest residence to the meter stations is approximately 100 feet northwest of the 

existing TRANSCO Meter Station.

A permanent road would be constructed for access to Compressor Station 760. With the 

exception of the installation of a culvert, the access road would be entirely within agricultural land. 

Existing access roads within industrial/commercial land would be used to provide access to the TETCO, 

Pine Prairie, and TGT Meter Stations. One residence is approximately 50 feet from the existing access 

road to the Pine Prairie Meter Station. 

4.8.1.2 Impacts and Mitigation

Construction of the LNG terminal and KMLP facilities would affect a total of 353.5 acres of land. 

Of this, 144.6 acres would be permanently affected by operation of the LNG terminal and KMLP 

facilities and 173.9 acres would be allowed to revert to the existing land use type after the completion of 

construction activities. The remaining 35.0 acres, within the dredge material placement area, would be 

converted from open water (33.5 acres), industrial/commercial (1.0 acre), and forest (0.5 acre) to open 

land in accordance with landowner requirements. Impacts on agricultural, industrial/commercial, open 

land, open water, forest, and residential land use are discussed below. 

 

13 Additional facilities planned in the vicinity of the LNG Terminal include G2X Energy’s natural gas to gasoline facility, which would be 

located north of the LNG terminal across the Industrial Canal and the LDWF’s Fisheries Research Center, which would be located 

immediately south of the LNG terminal across Henry Pugh Boulevard. These facilities, which have begun the permitting process but are 

not yet under construction, are described in detail in section 4.13. 
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LNG Terminal Facilities

Construction of the LNG terminal would affect a total of 277.7 acres of land within the LNG 

terminal site, Industrial Canal, DII construction yard, along the dredge material and effluent pipelines, and 

at the dredge material placement area. The land use types affected during construction of the LNG 

terminal would include open land (67 percent), open water (16 percent), forest (12 percent), and 

industrial/commercial (5 percent). 

Open Land

Open land affected by construction of the LNG terminal would include 80.1 acres at the LNG 

terminal site and 106.8 acres at the dredge material placement area. Within the LNG terminal site, 

impacts on open land would be permanent due to the conversion of the affected area to 

industrial/commercial use. The permanent loss of emergent wetlands determined to be jurisdictional 

under section 404 of the CWA within open land at the LNG terminal would be mitigated by Magnolia’s 

implementation of its Compensatory Mitigation Plan, as described in section 4.4.4. Open land within the 

dredge material placement area would be temporarily disturbed by the placement of dredge spoil and 

grading activities. Impacts would be short term and would be reduced by the implementation of 

Magnolia’s project-specific Plan and Procedures. Following dredge placement and dewatering, the 

dredge material placement area would be graded, reseeded, and maintained as open land, resulting in a 

35-acre increase in open land (including 33.5 acres within the borrow pit, 1.0 acre that is currently a site 

road, and 0.5 acre of forest/scrub-shrub wetland).

Open Water

Construction and operation of the LNG terminal would impact a total of 43.3 acres of open water, 

including 33.5 acres within the borrow pit at the dredge material placement area and 9.8 acres within the 

Industrial Canal. Construction of the recessed berthing area at the LNG terminal would require dredging 

a 16.2-acre area within the Industrial Canal (existing land use includes 9.8 acres of open water and 

6.4 acres of open land) to a depth of 44 feet and installation of LNG loading and berthing facilities (see 

section 2.5.1.4). Operation of the LNG terminal would result in the conversion of 9.8 acres of open water 

to industrial/commercial use associated with LNG vessel loading. Impacts on use of open water within 

the Industrial Canal associated with construction and operation of the recessed berthing area include 

reduced access for recreational users when an LNG vessel is at the LNG terminal as well as increased 

marine vessel traffic. Impacts on recreational use of the Industrial Canal and marine vessel traffic are

described in sections 4.8.4 and 4.9.6.2, respectively. 

The borrow pit occurs within a developed area owned by CB&I; although not required for 

operation of the LNG terminal, this area would be filled in accordance with the landowner agreement 

between CB&I and Magnolia. Potential impacts on surface waters and aquatic resources within the 

borrow pit are discussed in sections 4.3.2.2 and 4.6.2.2, respectively.

Forest

Forest affected by construction of the LNG terminal would include 34.0 acres of low quality

upland forest at the LNG terminal site and 0.5 acre of palustrine forest/scrub-shrub wetland at the dredge 

material placement area. Impacts on forest at the LNG terminal would be permanent, due to the 

conversion of the affected area to industrial/commercial use. Forest at the dredge material placement area 

would be converted to open land in accordance with the landowner agreement described above. Impacts 

on wetlands jurisdictional under section 404 of the CWA would be mitigated through the implementation 

of Magnolia’s Compensatory Mitigation Plan, as described in section 4.4.4.
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Industrial/Commercial

A total of 13.1 acres of industrial/commercial land would be affected by construction of the LNG 

terminal, including 5.2 acres within the DII construction yard, 6.9 acres along the dredge material and 

effluent pipelines, and 1.0 acre within the dredge material placement area. Impacts on 

industrial/commercial areas during construction would include increased dust from exposed soils, 

construction noise, and traffic congestion. Impacts on 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 the completion of construction activities, land use within 

industrial/commercial areas at the DII construction yard and along the dredge material and effluent 

pipelines would be restored to pre-construction conditions. Following the placement and dewatering of 

dredge spoil within the dredge material placement area, 1.0 acre of industrial/commercial land (an 

existing site road) would be converted to open land, in accordance with the landowner agreement.

Residential

No residential land is present within the footprint of the areas that would be affected by 

construction or operation of the LNG terminal. The nearest occupied residences are 0.6 mile south of the 

terminal site. Temporary impacts on residential areas during construction of the LNG terminal could 

include inconvenience caused by increased traffic from transporting workers, equipment, and materials to 

the work site as well as temporary increases in noise levels. Impacts on nearby residences due to 

increased traffic and noise levels are described in sections 4.9.6.1 and 4.11.2, respectively. 

Summary and Conclusions

Over 99 percent of the land permanently affected by construction of the LNG terminal is within 

areas that have been previously disturbed by commercial or industrial activities, including 113.0 acres at 

the LNG terminal that was previously used for dredge material disposal and 9.8 acres within the Industrial 

Canal.14 Impacts on the remaining 1.0 acre of land permanently affected by construction and operation of 

the LNG terminal would be fully mitigated in accordance with Magnolia’s Compensatory Mitigation 

Plan, as described in section 4.4.4. Following the completion of construction activities, the remaining 

153.9 acres of land affected by construction of the LNG terminal would be allowed revert to preconstruction use, with the exception of the 35.0-acre area within the dredge material placement area that 

would be converted to open land in accordance with the landowner agreement between CB&I and 

Magnolia. Because the areas affected by construction and operation of the LNG terminal are zoned for 

heavy industrial use (Calcasieu Parish Police Jury, 2015), we have determined that impacts on land use 

would be negligible. 

KMLP Facilities

Construction of the KMLP facilities would affect a total of 75.8 acres of land associated with the 

low and high pressure header pipelines, Compressor Station 760, and the meter station modifications. 

Construction of the KMLP facilities would primarily impact agricultural (63.5 acres) and 

industrial/commercial (11.2 acres) land. The remaining 1.0 acre of land affected would be comprised of 

open land and open water. Potential impacts on land use associated with construction and operation of 

the KMLP facilities, as well as measures proposed to minimize impacts, are described in the following 

sections.

 

14 The Industrial Canal was created to provide deepwater access for maritime commerce and is maintained by regular dredging, as described in 

more detail in section 4.3.2.2 (COE, 2015).
4-89

Agricultural

A total of 63.5 acres of agricultural land primarily used for rice and crawfish production would be 

affected by construction of the KMLP facilities, including 40.4 acres at Compressor Station 760, 

21.1 acres along the low and high pressure header pipelines, and 2.0 acres at the meter station 

modification sites. Of this, operation of the KMLP facilities would result in the permanent conversion of 

11.5 acres of agricultural land to industrial/commercial use within Compressor Station 760 and at the 

modified CGT and TRANSCO Meter Stations.

Impacts on agricultural areas would also 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. Following construction activities, the 

43.7 acres of land within temporary workspaces and 8.3 acres of land within the permanent easements for 

the header pipelines would be restored to pre-construction condition in accordance with the FERC Plan 

and landowner requests. If drain tiles are exposed or damaged during construction activities, KMLP 

would implement measures to repair/replace them after communication with the landowner and in 

accordance with applicable regulatory guidelines. Following restoration, agricultural land within these 

areas would revert to the previous land use; however, land within the permanent easements for the header 

pipelines would be subject to routine maintenance to facilitate inspection of the header pipelines.

Industrial/Commercial

Construction of the KMLP facilities would affect 11.2 acres of industrial/commercial lands 

consisting of the existing meter stations and roads. Construction impacts on industrial/commercial areas 

during construction would include increased dust from exposed soils, construction noise, and traffic 

congestion. Impacts on 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. 

Operation of the KMLP facilities would permanently affect 0.6 acre of industrial/commercial land, which 

includes two locations where the low pressure header pipeline would be beneath a road (Coulee and 

Fournerat Roads), an increased footprint at the CGT Meter Station, and areas adjacent to Pine Prairie 

Meter Station where the header pipelines would connect to existing facilities. 

Open Land

Small areas of open land totaling 0.7 acre would be affected by construction of the KMLP 

facilities. Of this, 0.5 acre would be permanently converted to industrial/commercial use at the 

TRANSCO and TGT Meter Stations. Impacts on the remaining 0.2 acre of open land temporarily 

disturbed by construction activities at the Pine Prairie and TGT Meter Stations would be short term and 

minimized by the implementation of the FERC Plan and Procedures, with the exception of the measures 

described in section 4.4.3.2. Following the completion of construction activities, the areas would be 

graded, reseeded, and allowed to revert to pre-construction conditions.

Open Water

Construction of the KMLP facilities would temporarily affect 0.3 acre of open water along the 

header pipelines and within Compressor Station 760 and the TGT Meter Station. Impacts on open water 

resulting from construction activities could include increased sedimentation rates, turbidity levels, and 

water temperature; decreased dissolved oxygen concentrations; and release of chemical or nutrient 

pollutants from sediments (see detailed discussion in section 4.3.2.2). However, these impacts would be 

temporary and would not preclude these areas from functioning as open water areas. Impacts on open 

waters would be minimized by the implementation of the FERC Procedures. No impacts on open water 

are anticipated during operation of the KMLP facilities.
4-90

Residential

No residential land is present within the footprint of the areas affected by construction or 

operation of the KMLP facilities. Two occupied residences are within approximately 100 feet of the 

proposed construction workspaces, including a residence approximately 100 feet northwest of the existing 

TRANSCO Meter Station and a residence 50 feet south of the existing access road for the Pine Prairie 

Meter Station. Temporary impacts on residential areas during construction activities at the TRANSCO 

and Pine Prairie Meter Stations could include inconvenience caused by increased traffic from transporting 

workers, equipment, and materials to the work site as well as temporary increases in noise levels. Impacts 

on nearby residences due to increased traffic and noise levels are described in sections 4.9.6.1 and 4.11.2, 

respectively. 

Summary and Conclusions

As described above, the activities associated with the KMLP facilities involve modification or 

expansion of existing facilities; as a result, much of the land affected by the KMLP facilities would be 

located adjacent to the permanent easement associated with KMLP’s existing mainline or would be 

adjacent to or within existing meter station sites. Impacts on land use associated with construction and 

operation of the KMLP facilities would be temporary and minor within 84 percent of the areas affected, 

which would be allowed to revert to pre-construction conditions, although 8.8 acres of land would be 

subject to routine maintenance over the header pipelines. Operation of Compressor Station 760 and the 

CGT, TRANSCO, and TGT Meter Stations would result in the permanent conversion of a total of 

12.0 acres of land to industrial/commercial use. However, with the implementation of the FERC Plan and 

Procedures, we have determined that impacts on land use would be negligible. 

4.8.2 Landowner and Easement Requirements

LNG Terminal

Magnolia has entered into an agreement with the Lake Charles Harbor and Terminal District to 

lease the 115-acre LNG terminal site for the minimum expected operational life of 30 years, with the 

option to extend the lease for four additional periods of 10 years each. Temporary workspaces proposed 

within the existing DII site would be subcontracted from DII. Temporary workspaces proposed along the 

dredge material and effluent pipelines would be leased from the landowners/leaseholders along the route. 

Magnolia is currently in negotiations with CB&I for use of the dredge material placement area. Aside 

from the Lake Charles Harbor and Terminal District, no federal, state, or local agency owned or managed 

lands occur within the LNG terminal site or proposed temporary workspaces.

KMLP Facilities

The lands necessary for construction and operation of the KMLP facilities would be composed of 

both land currently owned or leased by KMLP and other private land. For privately owned lands along 

the header pipeline routes, KMLP would need to secure easements that convey temporary and permanent 

rights-of-way.

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 KMLP 

and the landowner. 
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If an easement cannot be negotiated with a landowner and the project has been certificated by the 

Commission, KMLP 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 

construction workspace areas. KMLP would still be required to compensate the landowner for the rightof-way and any damages incurred during construction; however, the level of compensation would be 

determined by a court according to state or federal law.

KMLP has entered into an option agreement with a private landowner to lease the 40.6-acre 

Compressor Station 760 site. The option agreement provides KMLP with the first right of refusal on the 

property until October 2016 (the seller cannot sell the property to another entity during this time without 

first offering the property to KMLP). Applications for rights-of-way would be filed for pipeline easement 

on the proposed low and high pressure header pipelines. In addition, applications for rights-of-way would 

be filed for footprint expansion at the CGT, TRANSCO, and TGT Meter Stations and for a new right-ofway for the proposed Magnolia Meter Station and interconnect pipeline.

4.8.3 Planned Developments

LNG Terminal

There are no residential areas or subdivisions currently proposed within a 0.25-mile radius of the 

LNG terminal site (Southwest Louisiana [SWLA] Economic Development Alliance, 2015b). Three 

commercial or industrial facilities are planned within 1 mile of the LNG terminal site, including the 

proposed Lake Charles Liquefaction Project, G2X Energy’s natural gas to gasoline facility, and the 

LDWF’s Fisheries Research Center, which are depicted on figure 4.8.1-1. Certain non-jurisdictional 

facilities are also planned to provide utilities (i.e., electric power, water) to the LNG terminal and KMLP 

facilities. Each of these non-jurisdictional projects, as well as other planned residential and 

commercial/industrial development projects in the broader area, are discussed in the cumulative impact 

analysis provided in section 4.13.1. 

KMLP Facilities

There are no residential areas or subdivisions currently proposed within a 0.25-mile radius of the 

KMLP facilities (SWLA Economic Development Alliance, 2015b). One industrial facility is planned 

within 1 mile of the proposed KMLP facilities. As part of the Ohio-Louisiana Access Project, 

modifications are proposed to TGT’s existing Eunice Compressor Station. This project, as well as other 

planned commercial/industrial development projects in the broader area, is discussed in the cumulative 

impact analysis provided in section 4.13.1. 

4.8.4 Recreation and Special Interest Areas

Construction and operation of the LNG terminal would not directly affect designated recreational 

areas. One designated recreational area, Calcasieu Point Landing, is within 1 mile of the LNG terminal

site. In addition, portions of the Sabine NWR and East Cove Unit of the Cameron Prairie NWR, are in 

the vicinity of the Calcasieu Ship Channel. No recreational areas (e.g., trails, golf courses, parks) are 

within 0.25 mile of the KMLP facilities. Potential impacts on recreational areas in the vicinity of the 

LNG terminal are discussed below.

Calcasieu Point Landing

Calcasieu Point Landing is a public park that contains a boat launch, fishing pier, pavilion, picnic 

tables, amphitheater, restrooms, and seasonal store. The park is approximately 525 feet west of the 
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proposed LNG terminal site at the western end of Henry Pugh Boulevard. In 2013, eight fishing 

tournaments were held at the park that drew in a total of approximately 1,000 boats (Carter, 2015).

Recreational boating and fishing activities occurring within the Industrial Canal and near 

Calcasieu Point Landing could be affected by construction and operation of the LNG terminal due to 

increased noise, delayed access to the park, restrictions on fishing in the immediate vicinity of the LNG 

terminal, and vessel traffic. Increased noise associated with construction of the LNG terminal would 

likely deter recreational users from fishing in the immediate vicinity of project activities. In particular, 

dredging and pile driving activities, which would occur up to 7 days per week and 6 days per week, 

respectively, during the first 20 months of construction, could result in avoidance of the area by 

recreational users. As a result, we have determined that construction of the LNG terminal would result in 

temporary and moderate impacts on recreational use of Calcasieu Point Landing. 

During construction of the LNG terminal, access to Calcasieu Point Landing could be delayed 

due to dredging, construction of transmission lines along the road right-of-way, and increased roadway 

traffic on Henry Pugh Boulevard from concrete deliveries and construction workers commuting to and

from the site. Operation of the project would also result in increased traffic along Henry Pugh Boulevard. 

Magnolia anticipates that 67 workers would be employed at the LNG terminal and that up to 52 LNG 

trucks would call on the LNG terminal per year. The potential impacts of additional roadway traffic 

during construction and operation of the LNG terminal and recommendations for mitigating these impacts 

are described in detail in section 4.9.6.1. With the implementation of the proposed and recommended 

mitigation measures, traffic delays on users of Calcasieu Point Landing due to construction and operation 

of the LNG terminal would be minor.

Restrictions on fishing within the fixed security zone surrounding the LNG terminal would 

require avoidance of this area by recreational users of the Industrial Canal. However, there is extensive 

similar habitat in the Industrial Canal and the surrounding waters within the Calcasieu River for displaced 

recreational users; therefore, impacts are expected to be minimal.

Impacts on recreational users of Calcasieu Point Landing and the Industrial Canal could result 

from increased marine traffic during construction and operation of the LNG terminal. We conclude that

the impacts of construction-related barge traffic within the Industrial Canal on recreational boats would be 

minimal due to the relative infrequency of the marine deliveries (50 or fewer deliveries during 

construction) and because the ship channel, which was specifically created to provide deep draft access to 

the Port of Lake Charles, is routinely used for both recreational and industrial traffic. During operation of 

the LNG terminal, delays to recreational users could occur due to the moving security zone around LNG 

vessels during transit to and from the LNG terminal, which we expect would be intermittent and minor. 

Additional discussion of project-related impacts on marine traffic is provided in section 4.9.6.2. 

National Wildlife Refuges

The Sabine NWR is approximately 12 miles south-southwest of the proposed LNG terminal site 

on the west side of the Calcasieu Ship Channel. The Sabine NWR is a 124,511-acre coastal marsh refuge 

that was established in 1937 to provide habitat for migratory waterfowl and other birds. Over 

280,000 people visit the refuge annually, participating in recreational fishing, hunting, and wildlife 

observation (FWS, 2015). 

Users of the Sabine NWR adjacent to the ship channel may observe a small increase in barge 

traffic during the construction period and may also observe LNG vessel traffic through the channel during 

operation of the LNG terminal. However, because LNG vessel traffic would be consistent with existing 

use of the Calcasieu Ship Channel, we have determined that the resulting impact on users of the Sabine 

NWR would be minor. 
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The East Cove Unit of the Cameron Prairie NWR is approximately 19 miles south-southwest of 

the proposed LNG terminal and 1.4 miles east of the Calcasieu Ship Channel on the eastern shore of 

Calcasieu Lake. The East Cove Unit is a 14,927-acre coastal marsh refuge that was established in 1937 to 

provide wintering habitat for waterfowl (FWS, 2012a). The refuge, which is accessible only by boat, 

hosts 8,000 visitors annually, who participate in fishing, hunting, trapping, wildlife observation, and 

photography.

Because the East Cove Unit is about 1.4 miles east of the Calcasieu Ship Channel at the nearest 

point, and there is land east of the ship channel that would block views from the refuge, users of the East 

Cove Unit are not expected to be affected by marine traffic during construction or operation of the LNG 

terminal. 

4.8.5 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 that facilities or portions of facilities and their lighting are 

visible to residents and visitors. The degree of visual impact resulting from the proposed facilities would 

be highly variable among individuals, and would typically be determined by the general character of the 

existing landscape and the visually prominent features of the proposed facilities.

4.8.5.1 LNG Terminal

The primary existing structures in the viewshed of Magnolia’s proposed LNG terminal include 

the existing Trunkline LNG Terminal, Lake Charles Carbon Company, and other industrial properties 

adjacent to the Industrial Canal. The viewshed also includes the Industrial Canal to the north and west, 

the Intracoastal Waterway and Calcasieu Ship Channel to the south, and forest and wetlands to the 

northwest and south of the site (see section 4.8.1.1). Because the site is slightly higher in elevation than 

the surrounding area due to the previous placement of dredge spoil at the site, and the topography of the 

surrounding area is fairly level, visibility would extend outward from the site except where buffered by 

vegetation or existing structures. 

The LNG terminal would not affect nationally or state-designated visual resources or visually 

sensitive areas such as natural landmarks, scenic roads, trails, or scenic rivers (Marcell and Beal, ND; 

National Park Service, 2007, 2009, 2010). The viewshed of the proposed LNG terminal includes a 

portion of the Creole Nature Trail Scenic Byway (Highway 27), which is approximately 2 miles west of 

the LNG terminal across the Calcasieu Ship Channel and as close as 0.3 mile west of the LNG vessel 

transit route along the Calcasieu Ship Channel. No other federally, state, or locally designated visual 

resources have been identified in the viewshed. 

Activities associated with construction of the LNG terminal may be visible from residences to the 

south and southeast of the LNG terminal, along Airhart and Joe Ledoux Roads, and possibly residences 

along the northeastern shoreline of Calcasieu Lake on Big Lake Road (although these residences are over 

3 miles south of the site). There are no residences within 1 mile of the LNG terminal to the west, north, 

or east. Due to the distance between the residences within the viewshed, visual impacts from construction 

activities are expected to be limited to the 36-month period when the majority of construction activities 

would occur (see additional discussion in section 2.3). 

Construction activities would also be visible to recreationists using the Industrial Canal, 

Calcasieu River, and northern portions of Calcasieu Lake as well as motorists along Henry Pugh 
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Boulevard, Big Lake Road, and a segment of the Creole Nature Trail Scenic Byway. The presence of 

large construction equipment and truck traffic would change the visual quality of these waterways, 

roadways, and the scenic byway but, due to the distance from the site and short duration of impact (until 

the vehicle passes the site), impacts would be minor.

Permanent changes to the visual character of the area would result from operation of the LNG 

terminal due to the presence of aboveground structures that would modify the viewshed. The most 

prominent visual features at the terminal would be two LNG storage tanks, which would each be 

approximately 258 feet wide and 174 feet in height, and the flare stack, which would be approximately 

100 feet in height when no flame is present and approximately 229 feet in height when a flame is present. 

Magnolia anticipates that flaring would occur for approximately 5 days during startup of the LNG 

terminal. During operation of the LNG terminal, use of the marine and emergency flares would only 

occur during process upset conditions, which Magnolia anticipates would be no more than 12 hours 

during the first year of operation and no more than 6 hours in each subsequent year (each flaring event is 

expected to occur for between 15 and 60 minutes). In addition, structures present within the LNG 

terminal would include four liquefaction trains, an administration/workshop building, the Magnolia Meter 

Station, LNG truck loading facilities, and mooring and breasting dolphins within the recessed berthing 

area. The new facilities would also require lighting for operations, safety, and to comply with Federal 

Aviation Administration requirements. 

Magnolia conducted visual simulations for several scenarios at observation points in the vicinity 

of the LNG terminal. The following summarizes the visual simulations conducted as well as potential 

impacts on the viewshed based on our review:

 Calcasieu Point Landing (0.1 mile west of the property boundary) – Magnolia conducted 

visual simulations for both daytime and evening visual impacts from Calcasieu Point 

Landing (see figures 4.8.5-1 and 4.8.5-2). Due to the proximity of Calcasieu Point 

Landing to the LNG terminal and lack of visual buffers, the LNG storage tanks would be 

prominent when viewed from Calcasieu Point Landing both during daytime hours and in 

the evening when the facilities (including the LNG storage tanks) would be illuminated in 

accordance with federal safety regulations (see section 4.12.3). The tops of the 

liquefaction trains, auxiliary boilers, and vapor barrier would be also visible from this 

direction, but would not be prominent features. Neither the flare stack nor the flame 

itself would be visible from Calcasieu Point Landing; although the flame would be taller 

than the LNG storage tanks (approximately 229 feet and 174 feet, respectively), the 

position of the LNG storage tanks in the foreground would conceal the flame. 

To minimize visual impacts, lighting at the LNG terminal would be shielded and 

downcast to avoid interference with navigation (see our recommendation regarding 

Magnolia’s Facility Lighting Plan in section 4.6.1.3); in addition, facilities within the 

LNG terminal site would be partially obscured by the proposed vapor barrier. To further 

minimize visual impacts, we are recommending that, prior to construction, Magnolia file 

its Facility Lighting Plan for operation of the LNG terminal. Facilities associated with 

the LNG terminal (e.g., LNG storage tanks, flare, liquefaction trains, and lighting) would 

be consistent with the viewshed presented by other industrial features along this portion 

of the Industrial Canal. Therefore, we have determined that the LNG terminal would 

have a permanent and moderate impact on visual resources when viewed from the 

Calcasieu Point Landing.
Louisiana

Figure 4.8.5-1

 Visual Simulation of View from 

Calcasieu Point Landing - Daytime

Magnolia LNG and Lake Charles Expansion Projects

Calcasieu Parish, Louisiana

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Visual_Simulation\MLP_visual_Day.mxd | REVISED: 04/09/2015 DRAWN BY: JSSuess

This information is for environmental review purposes only.

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Louisiana

Figure 4.8.5-2

 Visual Simulation of View from 

Calcasieu Point Landing - Evening

Magnolia LNG and Lake Charles Expansion Projects

Calcasieu Parish, Louisiana

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Visual_Simulation\MLP_visual_Day_Evening.mxd | REVISED: 04/09/2015 DRAWN BY: JSSuess

This information is for environmental review purposes only.

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 Big Lake Road (0.6 and 0.8 mile east of the site) – Magnolia conducted visual 

simulations at two locations along Big Lake Road for both daytime and nighttime visual

impacts during flare operation. Although the LNG storage tanks would be visible from 

Big Lake Road, they would not be a prominent feature in the viewshed. Because the 

Trunkline LNG Terminal and Leevac Shipyards are adjacent to Big Lake Road, 

structures associated with these facilities are the prominent features. During operation of 

the flare, the flare stack and flame (with a total height of approximately 229 feet) would 

be visible to drivers traveling south along Big Lake Road for a distance of approximately 

0.6 mile. Along this segment of the road, the flare would be 0.8 mile from travelers 

along Big Lake Road and would be consistent with existing activities in the area. 

Therefore, we have determined that Magnolia’s proposed LNG terminal would have 

minimal impacts on visual resources when viewed from Big Lake Road.

 Residential neighborhood south of the LNG terminal (0.6 mile south of the site) –

Magnolia conducted visual simulations for both daytime and nighttime visual impacts 

during flare operation from the residential neighborhood approximately 0.6 mile south of 

the LNG terminal. Due to landscaping and established trees within this community, 

facilities at the LNG terminal would generally not be visible to residents, although some 

properties may have less vegetation screening, in which case the LNG storage tanks and 

tops of the liquefaction trains may be visible. In the evening, the LNG terminal would be

illuminated in accordance with federal safety regulations (see section 4.12.3). Although 

the lights are not likely to be directly visible from this neighborhood, the LNG terminal

would increase the general nighttime lighting visible to the north (toward the Industrial 

Canal) when viewed from the neighborhood. Therefore, we have determined that the 

LNG terminal would have a permanent but minor impact on visual resources within this 

neighborhood.

 Residential neighborhood north of the LNG terminal (2.3 miles north of the site) –

Magnolia conducted visual simulations for both daytime and evening visual impacts from 

the residential neighborhood approximately 2.3 miles north of the LNG terminal. Due to 

distance from the LNG terminal and established trees within this community, operation 

of the LNG terminal is expected to be difficult to see or imperceptible to residents within 

this community. Therefore, we have determined that the LNG terminal would have 

minimal impacts on visual resources within this neighborhood.

 Intracoastal Park off of the Creole Nature Trail Scenic Byway (3.9 miles southwest of the

site) – Magnolia conducted visual simulations for both daytime and evening visual 

impacts from the Intracoastal Park due to its location off of the Creole Nature Trail 

Scenic Byway. Due to distance from the LNG terminal and the visual buffer provided by 

Choupique Island, the LNG terminal would generally be difficult to see or imperceptible 

from the Intracoastal Park. It is possible that visitors who walk to the water’s edge may 

be able to see the LNG storage tanks at the site but, due to the distance, the storage tanks 

would appear small and would not be expected to diminish the quality of the viewshed. 

Therefore, we have determined that the LNG terminal would have minimal impacts on 

visual resources when viewed from the Intracoastal Park.

Residences along the shores of the Calcasieu Ship Channel would be within the viewshed of 

marine traffic. The frequency of vessels transiting the Calcasieu Ship Channel would increase during 

LNG terminal construction and operation, but marine traffic would have minimal impact on the viewshed 

for these residences because the increased ship traffic would be consistent with the current use and visual 

character of the waterway. 
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4.8.5.2 KMLP Facilities

Header Pipelines

The header pipelines would be located in a primarily agricultural area, which contains easements 

for 46 oil and gas pipelines within a 1-mile radius. As a result, the existing structures in the viewshed of 

the header pipelines are primarily meter stations (include the existing ANR, Pine Prairie, and TGT Meter 

Stations), compressor stations, and farms and agricultural outbuildings. The viewshed also includes 

forested land to the south and east within the floodplain of Bayou Barwick and Bayou des Cannes, 

respectively. 

During construction of the header pipelines, the primary 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 roads crossed by the low pressure header pipeline (Coulee and Fournerat 

Roads) and nearby residences. However, the nearest residence is approximately 500 feet west of the low 

pressure header pipeline, and the routes do not cross densely populated areas. The presence of 

construction equipment and personnel would be temporary and short term and we expect that vegetation 

would revegetate to a cover similar to pre-construction conditions within one to two growing seasons; 

therefore, we conclude that visual impacts would be short term and minor.

Compressor Station 760

Construction of Compressor Station 760 would occur within a rural area of Acadia Parish off of 

Coulee Road and east of Refinery Road (see Header Pipelines and figure 2.1.3-1 in section 2.1.3). 

Construction-related impacts, including the presence of equipment and workers, would be temporary and 

limited to the 11-month construction period. As described in section 4.8.1.2, 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 760 would be 

visible to passing motorists travelling along nearby roads in Acadia Parish. Construction and operation of 

Compressor Station 760 would not affect any designated visual resources; however, the station would be 

visible to the few nearby residences, the closest of which is about 1,200 feet west of the station perimeter. 

To minimize visual impacts on nearby residences and passing motorists, KMLP would plant shrubbery 

along the west, north, and east sides of the perimeter fence and to limit and down-shield perimeter 

lighting during nighttime hours. With the implementation of these measures, we have determined that 

visual impacts would be permanent, but minor.

Meter Stations

Construction activities at the existing meter stations would result in short-term, localized visual 

impacts similar to those described above for Compressor Station 760. There would be no permanent 

visual impacts at the existing meter stations that would not be expanded (TETCO, ANR, and Pine Prairie 

Meter Stations). The expanded meter stations (CGT, TRANSCO, and TGT Meter Stations) would result 

in new, permanent impacts on visual resources. The CGT, TRANSCO, and TGT Meter Station 

expansions would increase the footprint of the existing facility by 0.3, 0.1, and 0.4 acre, respectively. The 

expansions would result in an increased footprint along the southern boundary of the TRANSCO Meter 

Station, along the eastern boundary of the TGT Meter Station, and along the western and southern sides 

of the CGT Meter Station. The expanded footprint of each of these facilities would be consistent with the 

existing viewshed and would not affect any designated visual resources. Therefore, we conclude that the 

meter station modifications would have minimal impacts on visual resources.
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4.8.6 Coastal Zone Management

The Coastal Zone Management Act 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 Coastal Zone Management Act 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 state’s Coastal Zone Management Program and is the lead state 

agency that performs federal consistency reviews. As such, the LDNR evaluates activities or 

development affecting land within Louisiana’s coastal zone for compliance with the Coastal Zone 

Management Act through a process called a “federal consistency” review.

The inland extent of the coastal zone boundary is defined by the Intracoastal Waterway (LDNR, 

2012a). The LNG terminal site is approximately 140 feet northeast of the 2012 Louisiana Coastal Zone 

boundary at its closest point. Magnolia submitted a Solicitation of Views letter to the LDNR, dated 

October 15, 2013, requesting agency concurrence that the LNG terminal would be located outside of 

Coastal Zone Management jurisdiction and would not require a Coastal Use Permit. A response from the

LDNR, Office of Coastal Management, dated October 29, 2013, indicates that the Project is outside the 

Louisiana Coastal Zone and, therefore, a Coastal Use Permit would not be required.

4.9 SOCIOECONOMICS

Construction and operation of the LNG terminal and KMLP facilities could impact 

socioeconomic conditions, either adversely or positively, in the general project vicinity. These potential 

impacts include alteration of population levels or local demographics, increased employment 

opportunities, increased demand for housing and public services, increased traffic on area roadways and 

waterways, and an increase in government revenue associated with sales and payroll taxes. 

The socioeconomic analysis for the proposed facilities examines data from Acadia, Calcasieu, 

Cameron, Evangeline, and Jefferson Davis Parishes. The proposed facilities would be in Acadia, 

Calcasieu, and Evangeline Parishes. Of these, the greatest socioeconomic impacts would occur in 

Calcasieu Parish, where the LNG terminal would be located. Cameron and Jefferson Davis Parishes are 

also included in the socioeconomic analysis because they are close to the LNG terminal and would likely 

see an increase in non-local workers relocating to these areas due to the relatively short commute 

distances. For the purposes of our socioeconomic analysis, these five parishes are defined as the “affected 

area.” 

4.9.1 Population

Table 4.9.1-1 provides a summary of selected population and demographic information for the 

affected area.

4.9.1.1 LNG Terminal

Calcasieu Parish, anchored by the cities of Lake Charles and Sulphur, has the largest population 

of the five parishes within the affected area, with a population of approximately 195,296 residents in 2013 

and a population density of 181 persons per square mile (U.S. Census Bureau, 2014a). In comparison, the 

2013 population of the State of Louisiana was approximately 4,629,284 residents. 
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TABLE 4.9.1-1

Existing Socioeconomic Conditions in the Affected Area 

State/Parish

2010 

Population a

2013 

Population

(est.) a

Population 

Density (per 

square mile) a

Per Capita 

Income a

Civilian 

Labor

Force b

Unemployment 

Rate 

(percent) b

Top 

Industries c

Louisiana 4,533,479 4,629,284 105 $24,442 2,181,191 6.2 H, R, A

Acadia 61,773 62,204 94 $19,910 25,993 5.6 R, H, M

Calcasieu 192,768 195,296 181 $24,355 100,680 5.4 H, A, R

Cameron 6,839 6,744 5 $29,559 3,342 4.9 T, W, Q

Evangeline 33,984 33,578 51 $18,023 12,842 7.0 H, R, M

Jefferson Davis 31,594 31,301 49 $21,132 15,052 5.2 R, H, A

____________________

a U.S. Census Bureau, 2014a

b Louisiana Workforce Commission, 2014

c U.S. Census Bureau, 2014b

Industries:

A Accommodation and food services

H Health care and social services

M Manufacturing

Q Mining, quarrying, and oils and gas extraction

R Retail trade

T Transportation and warehousing

W Wholesale trade

Construction of the LNG terminal, which Magnolia tentatively expects to begin in January 2016, 

would take place over a 36-month period, with an additional 9 months until all four liquefaction trains 

would be commissioned and operational (resulting in a total construction period of approximately 

45 months). The anticipated monthly construction workforce at the LNG terminal is depicted in figure 

4.9.1-1. Magnolia has stated that construction workers would be on site during 32 months of the 

construction period and that the average construction workforce would be 355 workers. Approximately 

60 percent of the workers would be hired locally, resulting in an average of 142 and a maximum of 

217 non-resident workers. 

KMLP estimates that 30 workers would be employed over the 3-month period required to 

construct the Magnolia Meter Station (between months 16 and 18), which would be located within the 

LNG terminal. KMLP stated that the majority of the construction workers would be hired from outside of 

Calcasieu Parish; therefore, we have conservatively estimated that the number of non-resident workers 

would be 18 (60 percent of the construction workforce). 

During a 10-month period (months 18 through 27 of the construction period), the combined 

construction workforce at the LNG terminal would number over 500 construction workers, with a 

maximum of approximately 542 workers (see figure 4.9.1-1). 

Should the non-resident workers be accompanied by family members, and based on an average 

household size of 3.1 persons in Louisiana, up to 672 non-local persons could relocate to the affected area 

during the 10-month period when over 500 construction workers would be at the LNG terminal 

(U.S. Census Bureau, 2010b). Although it is unlikely that all workers would relocate with families, this 

addition would represent a 0.3 percent increase in the total population within Calcasieu, Cameron, and 

Jefferson Davis Parishes.
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Figure 4.9.1-1 Construction Workforce Associated with the LNG Terminal and KMLP Facilities

After construction, Magnolia anticipates 67 workers would be employed at the LNG terminal, of 

which 27 are expected to be non-local hires. KMLP’s Magnolia Meter Station would be unmanned 

during operation. This workforce and their families would represent a minor but permanent increase in 

the population in the vicinity of the LNG terminal site. 

4.9.1.2 KMLP Facilities

The KMLP facilities would be constructed in Acadia and Evangeline Parishes, as described 

above. The estimated 2013 population densities, an indication of the extent of development, for Acadia 

and Evangeline Parishes were approximately 94 and 51 persons per square mile, respectively. In 2013, 

the estimated population within Acadia Parish was 62,204, and the estimated population within 

Evangeline Parish was 33,578 (U.S. Census Bureau, 2014a).

For the majority of the 11-month construction period, the construction workforce for the KMLP 

facilities would be 75 workers, who would be associated with construction of Compressor Station 760. 

However, during a 3-month period occurring between months 4 and 6 of construction, up to 270 workers 

would be employed at the KMLP facilities, as summarized in table 4.9.1-2. 

KMLP stated that the majority of the construction workers would be hired from outside of Acadia 

and Evangeline Parishes. Therefore, we have conservatively estimated that the maximum the number of 

non-resident workers within Acadia and Evangeline Parishes would be 126 and 36, respectively 

(60 percent of the construction workforce). Because the peak construction period associated with the 

KMLP facilities would occur over a 3-month period, it is unlikely that non-local workers would be 

accompanied by family members. 

Within Acadia Parish, non-local construction workers associated with the KMLP facilities would 

result in an increase to the local population of 45 persons for 8 months and up to 126 persons for 

3 months. This would represent an increase of 0.2 percent in the current population. Similarly, within 

Evangeline Parish, non-local construction workers associated with the KMLP facilities would result in an 
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increase to the local population of 36 persons for 3 months, which would represent an increase of 

0.1 percent over the current population. 

TABLE 4.9.1-2

Construction Workforce and Duration Associated with the KMLP Facilities

Location / Facility Workforce

Month of Construction

1 2 3 4 5 6 7 8 9 10 11

Acadia Parish, Louisiana

Header pipelines 60 to 75

Compressor Station 760 75

ANR Meter Station 20

Pine Prairie Meter Station 20

TGT Meter Station 20

Subtotal 195 to 210

Evangeline Parish, Louisiana

CGT Meter Station 20

TRANSCO Meter Station 20

TETCO Meter Station 20

Subtotal 60

KMLP Facilities Total 255 to 270

KMLP anticipates four workers would be employed at Compressor Station 760. The header 

pipelines and meter stations would be unmanned during operation. Assuming that all four workers are 

non-local, this would represent a minor but permanent increase in the local population.

4.9.2 Economy and Employment

Table 4.9.1-1 provides selected employment and income statistics for the affected area. The top 

industries in the affected area include:

 accommodation and food services;

 health care and social services;

 manufacturing; mining, quarrying, and oils and gas extraction;

 retail trade;

 transportation and warehousing; and

 wholesale trade (U.S. Census Bureau, 2014b).

Due to forecasted industrial growth in the region (discussed in additional detail in section 4.13.5), 

the SWLA Economic Development Alliance collaborated with educational facilities and industry in the 

development of a Workforce Resource Guide. The guide is intended to provide residents with step-bystep instructions for finding employment and includes a description of the types of training required for 

each profession, as well as the training centers in Southwest Louisiana that offer the relevant 

certifications. Currently, several programs designed to increase the number of qualified local workers are 

being offered, including programs through the Associated Builders and Contractors, Pelican Southwest 

Chapter in Westlake, Calcasieu Parish School Board, SOWELA Technical Community College (both the 
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main campus in Lake Charles and Morgan Smith Campus in Jennings), and Central Louisiana Technical 

Community College (Lamar Salter Campus in Leesville).

4.9.2.1 LNG Terminal

The civilian labor force is defined as the sum of employed persons and those actively searching 

and available for work (U.S. Census Bureau, 2010a). During construction of the LNG terminal, 

approximately 60 percent of the workers would be hired from Calcasieu, Cameron, and Jefferson Davis 

Parishes. In 2014, the civilian labor force numbered 100,680 in Calcasieu Parish, 3,342 in Cameron 

Parish, and 15,052 in Jefferson Davis Parish. The average per capita income in both Calcasieu and 

Jefferson Davis Parishes ($24,255 and $21,132 respectively) was below the State of Louisiana’s average 

per capita income of $24,442. Cameron Parish had a per capita income of $29,559, which was above the 

State of Louisiana’s average. All three parishes had a lower unemployment rate than the State of

Louisiana, which was 6.2 percent. 

Construction of the LNG terminal would stimulate the economy through the $3.7 billion in total 

capital expenditures by Magnolia and KMLP, of which, an estimated $20 million would be spent on 

locally sourced construction materials (e.g., concrete, miscellaneous consumables, fuel supply). 

Additionally, a percentage of the estimated $63.5 million construction payroll would be spent locally by 

both local and non-local workers for the purchase of housing, food, gasoline, and other goods, services, 

and entertainment in the project vicinity. Typically, construction activities increase economic activity 

within an 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 direct, indirect, and induced effects would result 

in a temporary positive economic impact in the vicinity of the LNG terminal.

Anticipated operational expenditures would include $53.6 million in annual taxable expenditures 

on goods and services, approximately $5 million per year in salaries, and additional indirect and induced 

expenditures as these dollars trickle through the economy. At least half of the total annual expenditures 

would be made locally, equaling $26.8 million in local materials and consumables purchased per year. 

We conclude that the expenditures and permanent workforce associated with operation of the LNG 

terminal would result in a minor, but positive permanent impact on the local economy.

4.9.2.2 KMLP Facilities

During construction of the KMLP facilities, we have estimated that approximately 40 percent of 

the workers would be hired from Acadia and Evangeline Parishes. In 2014, the civilian labor force 

numbered 25,993 in Acadia Parish and 12,842 in Evangeline Parish. The average per capita income in

both Acadia and Evangeline Parishes ($19,910 and $18,023 respectively) was below average within the 

State of Louisiana. Acadia Parish had an unemployment rate of 5.6 percent, which was below the 
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unemployment rate for the State of Louisiana as a whole. Evangeline Parish had an unemployment 

rate of 7.0 percent, which was higher than state as a whole. 

Construction of the KMLP facilities would stimulate the economy through the $3.1 million in 

expenditures that would be spent on local and regional construction materials and fuel for KMLP 

facilities. Additionally, a percentage of the estimated $10 million construction payroll would be spent 

locally by both local and non-local workers for the purchase of housing, food, gasoline, and other goods, 

services, and entertainment in the vicinity of the KMLP facilities. The increase in economic activity 

resulting from direct, indirect, and induced effects would result in a temporary, positive economic impact 

in the vicinity of the KMLP facilities.

Operation of the KMLP facilities is expected to result in a total of $1,030,000 in annual taxable 

expenditures on goods and services, which would include $1,020,000 in Acadia Parish and $10,000 in 

Evangeline Parish. These expenditures would result in a minor, but positive permanent impact on the

local economy.

4.9.3 Local Taxes and Government Revenue

Magnolia anticipates spending approximately $20 million on construction materials in the 

affected area, which would generate increased local, state, and federal sales tax revenues. The 

expenditures on goods and services by the construction workers and their families would also generate 

increased tax revenues. In addition, local, state, and federal governments would tax the $63.5 million in 

total construction workforce payroll. This increase in tax revenue would be a minor, temporary, and 

positive impact on tax revenue within the affected area.

During operation, Magnolia would contribute property taxes to Calcasieu Parish. The land would 

not be subject to property taxes because of tax exemptions for Port of Lake Charles property; however, all 

commercial improvements and business personal property would be subject to ad valorem tax. Based on 

projected values of the LNG terminal’s commercial improvements as well as projected state tax 

incentives, the annual ad valorem taxes paid by Magnolia and KMLP to Calcasieu Parish would be 

$8.3 million (see table 4.9.3-1). Operation of the LNG terminal would also result in minor, long-term 

increases in sales tax revenue from expenditures on materials, goods, and services. Approximately 

$26.8 million is expected to be spent locally each year; assuming a Louisiana state sales tax of 4 percent 

and an average local sales tax of 4.87 percent, operation of the LNG terminal would generate 

approximately $1.1 million in state sales tax and $1.3 million in local sales tax annually. 

TABLE 4.9.3-1

Estimated Annual Ad Valorem Taxes Paid During Operation of the LNG Terminal and KMLP Facilities

Facility, Operator

Ad Valorem Tax

Calcasieu Parish Acadia Parish Evangeline Parish

LNG Terminal

Magnolia $7,800,000 -- --

KMLP $507,000 -- --

KMLP Facilities -- $5,067,000 $277,000

Total $8,307,000 $5,067,000 $277,000

During construction of the KMLP facilities, an estimated $3.1 million would be spent on local 

and regional construction materials and fuel. Due to this spending, a total of $223,000 in sales tax 

revenues would be generated for the State of Louisiana, Acadia Parish, Evangeline Parish, and other local 
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taxing authorities. KMLP anticipates that annual ad valorem taxes payments to Acadia and Evangeline 

Parishes would be approximately $5.1 million and $0.3 million, respectively. Annual ad valorem tax 

revenues associated with assets and annual operation and maintenance budgets would also result in a 

long-term, minor, and positive impact on tax revenues within the affected area.

4.9.4 Housing

The number of housing units (permanent and temporary) varies across the affected area, largely 

based on parish population and the presence or absence of a major city. Table 4.9.4-1 provides data on 

the rental and other temporary living options in the affected area. Based on the 2013 American 

Community Survey (U.S. Census Bureau, 2014c), Calcasieu Parish has the greatest number of housing 

units (82,058), and also has the greatest number of residents (195,296) within the affected area. In 

contrast, Cameron Parish has both the lowest population (6,839) and number of housing units (3,593) 

within the affected area. Rental vacancy rates in the affected area ranged from a low of 4.6 percent in 

Jefferson Davis Parish to a high of 10.3 percent in Cameron Parish.

TABLE 4.9.4-1

Temporary and Short-term Housing Availability Within the Affected Area

State/Parish Housing Units a

Vacant 

Housing Units a

Vacant 

Rental Units a

Median Rental 

Cost per Month a

Hotels and 

Motels b

Recreational 

Vehicle and Mobile 

Home Parks c

Louisiana 1,974,313 266,461 50,411 $773 1,875 N/A

Acadia 25,437 2,910 458 $524 8 7

Calcasieu 82,998 9,272 2,385 $739 85 28

Cameron 3,593 1,064 29 $723 7 6

Evangeline 14,705 2,738 326 $518 4 3

Jefferson Davis 13,377 1,743 146 $576 12 2

____________________

a U.S. Census Bureau, 2014c

b Hotels and Motels, 2015

c Yellow Pages, 2015

There are about 116 hotels/motels within the affected area that could be used by the short-term 

workforce. The area also offers temporary housing options such as campgrounds and recreational vehicle 

(RV) parks, the closest of which (Big Lake RV Park) is approximately 1 mile south of the site off of Big 

Lake Road. The Pelican Lodge industrial housing facility at the Port of Lake Charles is approximately 

12 miles northeast of the LNG terminal in Calcasieu Parish. The facility, which is currently under 

construction, is expected to be completed in mid-2015 and will have the capacity to house 

4,000 construction personnel when it begins operation (SWLA Economic Development Alliance, 2014)

(see additional discussion in section 4.13.3).

4.9.4.1 LNG Terminal

As stated previously, local residents would comprise approximately 60 percent of the workers 

hired for construction of the LNG terminal. Within the affected area, Calcasieu Parish has the highest 

number of vacant housing units that would be available to the workforce, including vacant units for rent 

(2,385 units) as well as rooms at 85 hotels and motels and Pelican Lodge (when complete). The currently 

available housing in Calcasieu, Cameron, and Jefferson Davis Parishes would be sufficient to 

accommodate the 217 non-resident workers (as well as their families, should they relocate to the area) 

during the peak construction period. 
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The proposed construction schedule for the LNG terminal could coincide with other demands for 

housing and temporary accommodations from tourism. Non-local workers hired temporarily who seek

hotel accommodations could potentially compete with seasonal visitors in Calcasieu, Cameron, and 

Jefferson Davis Parishes. Given the number of hotel rooms in the vicinity of the LNG terminal, no 

serious disruptions are anticipated, and construction of the LNG terminal would have a moderate, 

temporary impact on housing in the affected area. However, as discussed in section 4.13.3.5, housing 

constraints could occur if several of the other planned projects in the area are constructed in the same 

timeframe. 

Operation of the LNG terminal would result in approximately 27 non-local workers relocating to 

the affected area. Because an adequate number of housing units are available in the affected area, we 

anticipate that this would have a minor but permanent impact on the local housing market.

4.9.4.2 KMLP Facilities

Non-local workers would comprise approximately 60 percent of the workforce associated with 

the KMLP facilities. For the majority of the 11-month construction period, the non-local construction 

workforce for the KMLP facilities would be between 36 and 45 workers, who would be associated with 

construction of Compressor Station 760. However, up to 162 non-local workers would relocate to the 

affected area for a 3-month period when construction of the header pipelines, Compressor Station 760, 

and the meter station sites are scheduled to occur, as summarized in table 4.9.1-2. Based on the number

of available rental housing units and hotels/motels in the affected area, as discussed above, adequate

housing exists to accommodate non-resident workers and their families. Overall, construction of the 

KMLP facilities would result in temporary and minor impacts on housing.

KMLP anticipates four workers would be employed at Compressor Station 760. The header 

pipelines and meter stations would be unmanned during operation. Assuming that all four workers are 

non-local, this would represent a permanent but negligible impact on the local housing market.

4.9.5 Public Services

Table 4.9.5-1 provides an overview of public services available to the project areas. Within the 

affected area, there are a total of 118 public schools, 25 police departments and sheriff’s offices, 55 fire 

departments, and 15 hospitals.

TABLE 4.9.5-1

Public Services in the Affected Area

Parish Public Schools a

Police Departments 

and Sheriff’s Offices b

Fire 

Departments c Hospitals d, e Hospital Beds d

Acadia 28 5 14 3 218

Calcasieu 62 8 18 5 783

Cameron 3 1 6 1 25

Evangeline 12 5 7 3 303

Jefferson Davis 13 6 10 3 60

____________________

a Public School Review, 2015

b USA Cops, 2015

c Louisiana Office of State Fire Marshall, 2015

d Louisiana Hospital Association, n.d.

e Cameron Parish Police Jury, 2015
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4.9.5.1 LNG Terminal

To understand potential impacts on schools, assumptions are made based on anticipated 

workforce. Magnolia estimates that the maximum number of non-local hires during peak construction of 

the LNG terminal is expected to be 217 workers. Because construction of the Magnolia Meter Station 

would occur over a 3-month period, it is not likely that temporary workers would relocate with their 

families. Assuming that the non-local workers hired by Magnolia would each relocate to the affected area 

with one school-aged child (based on an average family size of 3.1 persons in Calcasieu Parish 

[U.S. Census Bureau, 2010b]), approximately 217 children would enroll in one of the area’s public 

schools. With the current student population of 40,403 in the three parishes affected by the LNG

terminal, this would result in a temporary increase in the student population of approximately 0.5 percent. 

Therefore, measureable impacts on student-teacher ratios are not expected.

Construction of the LNG terminal would have 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. 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 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 conclude that impacts on public services during construction of 

the LNG terminal would be temporary and minor.

Magnolia anticipates that 67 workers would be employed at the LNG terminal during operation, 

of which 27 are expected to be non-local hires that relocate to the affected area with their families. 

KMLP’s Magnolia Meter Station would be unmanned during operation. This addition of 27 families 

would represent a negligible increase in the local population. Therefore, we conclude that local public 

services would not be affected.

4.9.5.2 KMLP Facilities

Construction of Compressor Station 760 would occur over an 11-month period, and would result 

in between 36 and 45 non-local workers relocating the affected area. Based on the assumptions described 

above (see section 4.9.5.1), a maximum of 45 children would enroll in one of the area’s public schools. 

Given the short duration of construction (3 months) associated with the header pipelines and meter station 

modifications, it is not likely that workers would relocate with families. Therefore, impacts on studentteacher ratios would be negligible. Although there is potential that the temporary increase in the local 

population size could result in occasional need for police, fire, and/or medical services, those public 

services would experience only negligible impacts during construction.

The four new permanent positions would represent a negligible increase in the local population. 

Therefore, we conclude that local public services would not be affected.

4.9.6 Transportation

Several potential impacts on vehicular and marine traffic may result from the construction and 

operation of the LNG terminal and KMLP facilities. Potential impacts on vehicular traffic would 

generally be related to the construction of the LNG terminal and KMLP facilities and would be the result 

of the influx of workers commuting to and from the various construction sites as well as the transport of 

construction materials. Marine traffic impacts would generally result from the increase in large vessel 

movements in the Calcasieu Ship Channel and Industrial Canal during construction and operation of the 

LNG terminal.
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4.9.6.1 LNG Terminal

Roadway Transportation

Access for transporting equipment, materials, and personnel to the LNG terminal would largely 

be available through the use of existing roadways. The entrance to the LNG terminal would be on Henry 

Pugh Boulevard, which is accessed from Big Lake Road (LA 384). For most of its length, Henry Pugh 

Boulevard is a two-lane asphalt road; however, as it approaches the intersection with Big Lake Road, 

Henry Pugh Boulevard is a four-lane asphalt road. Traffic count data provided by the Calcasieu 

Metropolitan Planning Organization indicated that at the intersection of Big Lake Road and Tank Farm 

Road (1.3 miles northeast of the LNG terminal site), an average of 5,850 vehicles travel along Big Lake 

Road and 799 vehicles travel along Tank Farm Road each day (IMCAL, 2013).

During construction of the LNG terminal, traffic levels on area roadways would increase due to 

the presence of worker vehicles, construction vehicles, and trucks delivering concrete to the site. Due to 

its location immediately adjacent to the LNG terminal site, materials would be delivered to the DII 

construction yard via the Industrial Canal. Therefore, except for trucks delivering concrete to the site, 

minimal construction truck traffic is anticipated. A summary of the anticipated increase in roadway 

traffic associated with construction of the LNG terminal is provided in figure 4.9.6-1.

Figure 4.9.6-1 Roadway Traffic Associated with Construction of the LNG Terminal 

Magnolia estimates that construction worker commutes would result in an average of 

320 roundtrips to the LNG terminal site per day. During the peak of construction (occurring during 

months 23 and 24), approximately 488 roundtrips would be made to the LNG terminal site per day. 

In addition, the delivery of concrete to the LNG terminal site would result in 160 roundtrips per day 

during the first month of construction and 40 roundtrips per day during the subsequent 18 months. 

Construction of KMLP’s Magnolia Meter Station (located within the LNG terminal site, see 

figure 2.1.1-4 in section 2.1.1.3) would occur between months 16 and 18, and would result in an 

average of 20 roundtrips to the site per day associated with construction worker commutes and 12 trips 

to the site per day for materials deliveries.
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Impacts on local users of the roadway network due to construction of the LNG terminal include 

potential delays from increased traffic levels and diminished roadway capacity (roadway failure). To 

identify, quantify, and recommend mitigation for traffic impacts on area roadways during construction of 

projects currently proposed on the Industrial Canal, Magnolia, Lake Charles LNG, and G2X Energy 

commissioned a Traffic Impact Study (C.H. Fenstermaker and Associates, LLC, 2014). The study, which 

is discussed in additional detail in section 4.13.3.5, recommended that three intersection improvements be 

implemented to reduce impacts on area roadways, including:

 At the intersection of Tank Farm and Big Lake Roads:

o construction of an eastbound left-turn lane; 

o construction of southbound left-turn and right-turn lanes;

o construction of a northbound left-turn lane; and

o utilization of a temporary traffic signal to provide intersection control.

 At the intersection of Big Lake and Lincoln Roads:

o construction of a southbound left-turn lane;

o construction of a westbound right-turn lane; and

o utilization of a temporary traffic signal to provide intersection control.

 At the intersection of Lincoln Road and Gulf Highway:

o construction of a southbound right-turn lane;

o construction of eastbound dual-left turn lanes;

o construction of a northbound left-turn lane;

o utilization of a bypass lane for northbound thru-traffic to maintain free flow; and

o utilization of a temporary traffic signal to provide intersection control.

Magnolia has stated that the measures recommended in the Traffic Impact Study would be 

implemented prior to construction as part of a cooperative effort between Magnolia, Lake Charles LNG, 

and G2X Energy. In a letter dated September 16, 2014, the Calcasieu Parish Police Jury stated that it has 

reviewed the study, agrees with its recommendations, and has no objections. 

Magnolia, Lake Charles LNG, and G2X Energy also commissioned a Calcasieu Point Traffic 

Mitigation Pavement Analysis to complete an evaluation of the existing structural capacity of Lincoln, 

Big Lake, and Tank Farm Roads to determine the necessary overlay/rehabilitation options to sustain 

construction traffic (Advanced Materials Services, LLC, 2014). The study identified 10 segments along 

Lincoln Road and 2 segments along Tank Farm Road that, given the current condition, would fail during 

the construction period. The analysis included two recommendations for rehabilitation of the roadways, 

including overlaying segments of the road (recommended in two locations along Lincoln Road) and 

milling to a predetermined depth and then replacing the segment with new asphalt (recommended in eight 

locations along Lincoln Road and two locations along Tank Farm Road). Magnolia has stated that the 

areas of concern identified by the analysis would be upgraded as part of the effort described above 

resulting from the Traffic Impact Study. 

With the implementation of the recommendations described above, traffic generated by 

construction of the LNG terminal is not expected to impact the existing roadway network in terms of 

roadway capacity. Construction of the LNG terminal would result in temporary increases in traffic along 

area roadways, which could result in delays to local users of the roadways. With the implementation of 

the recommended improvements at the intersections of Tank Farm and Big Lake Roads, Big Lake and 

Lincoln Roads, and Lincoln Road and Gulf Highway, we have determined that impacts from construction 

of the LNG terminal would have temporary and minor impacts on local users of the roadway network. 

However, as discussed in section 4.13.3.5, constraints on the roadway network could occur if other 
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planned projects in the area (e.g., Lake Charles Liquefaction Project, G2X Energy’s natural gas to 

gasoline facility) are constructed in the same timeframe. 

Operation of the LNG terminal would result in an average of 40 roundtrips to the site per day 

associated with worker commutes. KMLP’s Magnolia Meter Station would be unmanned during 

operation, and only occasional site visits by operations personnel would occur. Given the small increase 

in traffic and implementation of the road improvement measures described above, we have determined 

that operation of the LNG terminal would have permanent but minor impacts on roadway transportation. 

Marine Transportation

During construction of the LNG terminal, the liquefaction train modules, concrete and steel 

pilings, sheet piling, rock armoring, specialized mooring equipment, and miscellaneous construction 

materials would be delivered to the DII construction yard via barge. At the DII construction yard, 

materials would be offloaded and delivered to the LNG terminal site using the heavy haul road. The most 

likely route taken by the barges, assuming the use of nearby facilities along the coast, would be via the 

Intracoastal Waterway, Calcasieu Ship Channel, and Industrial Canal.

Current vessel traffic in the Calcasieu Ship Channel is approximately 1,022 vessels per year, 

which equates to an average of about 85 vessels per month (Port of Lake Charles, 2015a). Magnolia 

estimates that 50 or fewer marine deliveries would occur during construction of the LNG terminal. 

Marine deliveries to the DII construction yard would occur between 1 and 3 times per month during the 

first year of construction, and approximately 1 time per month during the second and third years of 

construction, which would represent an increase of less than 4 percent in current vessel traffic. Because 

barges are subject to fewer restrictions and can be maneuvered between other vessels using the channel, 

an increase in barge traffic would not impact the traffic capacity of the channel (Ausenco, 2015).

During operation, approximately 208 LNG vessels (104 LNG carriers and 104 LNG barges) 

would call on the LNG terminal per year. In a letter dated February 12, 2015, the Coast Guard issued the 

LOR for the project,15 which stated that the Calcasieu Ship Channel is considered suitable for LNG 

marine traffic in accordance with the guidance in the Coast Guard’s NVIC 01-2011. The WSA review 

focused on the navigation safety and maritime security aspects of LNG vessel transits along the affected 

waterway. The WSA itself is designated Sensitive Security Information as defined in 49 CFR 1520. 

Because any unauthorized disclosure of these details could be employed to circumvent the proposed 

security measures, they are not releasable to the public.

The Coast Guard’s LOR and 33 CFR 165.805(a)(2) establish a moving security zone for LNG 

vessels during transit, which extends 2 miles ahead of and 1 mile behind the LNG vessel (as discussed in 

additional detail in section 4.12.7). LNG vessels would reach the terminal using existing shipping 

channels, with the exception of the recessed turning basin at the LNG terminal itself. Throughout 

operation, LNG carriers would enter and depart the LNG terminal by transiting the Industrial Canal, 

Calcasieu Ship Channel, and Gulf of Mexico. LNG barges transiting to or from the Gulf of Mexico 

would utilize the route described above for LNG carriers; LNG barges transiting to or from other areas 

along the coast would utilize the route described above for barge traffic associated with construction of 

the LNG terminal. 

 

15 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
4-111

Inbound LNG carriers would embark a Lake Charles Pilot at the CC buoy (also known as Pilot 

Boarding Area 4), approximately 28 nautical miles from the Cameron jetties (River Mile 0) offshore in 

the Gulf of Mexico. From this point, LNG carriers would transit the waterway under command of the 

pilot. LNG carriers would enter the Calcasieu Ship Channel, and continue northbound to the channel’s 

intersection with the Intracoastal Waterway at a location known as “Devil’s Elbow.” At this intersection, 

inbound LNG carriers would make a turn to the northeast and proceed into the Industrial Canal where the 

ship would turn around within the turning basin and subsequently be maneuvered into the recessed 

berthing area by tugs. The pilot would direct the securing of the lines and would turn navigational control 

back to the captain when the carrier is fastened. Following loading at the LNG terminal, the pilot(s) 

would resume navigational control of the vessel when the mooring lines are let go, and the loaded LNG 

carrier would transit outbound along the reverse route described for inbound LNG carriers (although 

because the LNG carrier would turn around prior to docking, it would be able to proceed directly west 

within the Industrial Canal upon leaving the LNG terminal). The total transit distance from the CC buoy 

in the Gulf of Mexico to the LNG terminal is approximately 52 nautical miles. 

Seagoing LNG barges transiting the Gulf of Mexico would embark a pilot at Pilot Boarding 

Area 1, approximately 8 nautical miles from the Cameron jetties. LNG barges would transit inbound to 

and outbound from the LNG terminal using the same route described above for LNG carriers. The total 

transit distance from Pilot Boarding Area 1 in the Gulf of Mexico to the LNG terminal is approximately 

32 nautical miles. Non-seagoing (inland) LNG barges transiting the Intracoastal Waterway would not be 

required to travel under the control of a pilot. 

The Port of Lake Charles is currently the thirteenth busiest seaport in the United States and 

accommodates 5 million tons of cargo annually at its public facilities (Port of Lake Charles, 2015b). Due 

to the existing levels of traffic within the port and the anticipated increase in traffic within the channel 

over the next 10 years (see additional discussion in section 4.13.3.5), a traffic impact study was conducted 

for the Calcasieu Ship Channel by Ausenco (2015). A model was developed for the Calcasieu Ship 

Channel that simulated the anticipated impacts on traffic within the channel between 2013 and 2033, 

assuming that the present infrastructure, operational rules, and dredging dimensions are maintained. For 

example, the simulations included Coast Guard requirements for LNG carriers (passing restrictions and 

safety zones, see detailed discussion in section 4.12.7), closures of the channel due to weather, boarding 

window restrictions, and availability of sufficient pilots and tugs. The following discussion summarizes 

the simulated traffic within the Calcasieu Ship Channel in 2018, which is the year the LNG terminal

would begin operation. 

The results of the simulation indicate that the median wait time is expected to increase by 

2.3 hours per vessel, and notes that LNG carriers would experience the highest increase in median wait 

time (8.9 hours). The wait times are expected to vary seasonally, and would be higher during the winter 

months and lower during the summer months. In addition, the simulation indicated that 4 to 10 additional 

pilots and 1 or 2 additional sets of tugs would be required to accommodate vessel traffic without further 

increasing wait times. 

To minimize impacts on other users of the Industrial Canal and Calcasieu Ship Channel, it is 

anticipated that vessels (including LNG vessels) would be organized in convoys to be handled in the most 

efficient manner. The convoy would be specifically organized to maximize efficient transit; therefore, 

vessels traveling the farthest upstream would be prioritized (to minimize delays to other vessels during 

maneuvering and docking). 
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To assess the need for changes to the channel infrastructure and regulations, the study simulated 

five scenarios where a change would be made to the existing channel operations. Although none of the 

scenarios have been proposed, they are summarized below to illustrate the resulting impacts on marine 

traffic during operation of the LNG terminal.

 Insufficient Dredging – Simulations indicate that insufficient dredging would result in 

increased delays and could impact the ability of the channel to accommodate fully laden 

vessels.

 Increased Pilot Requirements for LNG Carriers – Simulations indicate that increased 

pilot requirements would not impact vessel wait times.

 LNG Carrier Passing on the Outer Bar – Simulations indicate that changing the passing 

restrictions for LNG carriers on the outer bar would decrease the median wait time, 

resulting in an increase of 1.6 hours per vessel over current conditions (as compared to 

2.3 hours per vessel without changes to channel infrastructure).

 Inner Channel Anchorages – Simulations indicate that the addition of anchorages to the 

inner channel would not impact vessel wait times.

 Inner Channel Passing Lane – Simulations indicate that the addition of a passing lane on 

the inner channel would decrease the median wait time, resulting in an increase of 

1.0 hour per vessel over current conditions (as compared to 2.3 hours per vessel without 

changes to channel infrastructure). 

Based on the Coast Guard’s LOR for the Magnolia LNG Project and the expected increase in the 

median wait time by 2.3 hours per vessel, we have determined that operation of the LNG terminal would 

have a permanent and moderate increase in marine traffic within the Industrial Canal and Calcasieu Ship 

Channel. 

Information on potential impacts on recreational boating and fishing in the vicinity of the LNG 

terminal is provided in section 4.8.4. Additional discussion of marine traffic and transportation as it 

relates to marine safety, including potential cryogenic/thermal impacts along the LNG vessel transit route, 

is provided in section 4.12.7. 

4.9.6.2 KMLP Facilities

The local road and highway system in the vicinity of the proposed KMLP facilities is readily

accessible by interstate highways, U.S. highways, state highways, secondary state highways, county

roads, and private roads. Construction of the KMLP facilities may temporarily affect roadway traffic due 

to increased vehicle traffic associated with the commuting of the construction workforce and the delivery 

of equipment and materials to the construction work area. 

As indicated in table 4.9.6-1, construction activities associated with the KMLP facilities would 

result in a temporary increase in traffic levels on area roads over the proposed 11-month construction 

period, which would be highest during the 3-month period when construction activities occur at each of 

these facilities. KMLP estimates that approximately 41 roundtrips per day (including 6 vehicle trips 

associated with truck deliveries and 35 vehicle trips associated with construction workers) would occur 

during construction of the header pipelines. Approximately 32 roundtrips per day (including 12 truck 

deliveries and 20 construction worker trips) would occur at Compressor Station 760 and the meter station 

sites. 
4-113

TABLE 4.9.6-1

Construction Duration and Vehicle Trips per Day Associated with the KMLP Facilities

Location / Facility

Vehicle Trips 

per Day

Month of Construction

1 2 3 4 5 6 7 8 9 10 11

Near Eunice, Acadia Parish, Louisiana

Header pipelines 41

Compressor Station 760 32

ANR Meter Station 32

Pine Prairie Meter Station 32

TGT Meter Station 32

Subtotal 169

Southern Evangeline Parish, Louisiana

CGT Meter Station 32

TRANSCO Meter Station 32

TETCO Meter Station 32

Subtotal 96

KMLP Facilities Total 265

Construction of the header pipelines; Compressor Station 760; and the ANR, Pine Prairie, and 

TGT Meter Stations would occur within a localized area approximately 6 miles southwest of Eunice, 

Louisiana (see figure 2.1.3-2 in section 2.1.3). For 8 months of the 11-month construction period, the 

average daily increase in traffic on area roads would be approximately 32 vehicles; this would increase to 

approximately 169 vehicles during the 3-month period when construction is scheduled to occur at each of 

the facilities. 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 during off-peak traffic 

hours. These facilities would be located in rural areas with low existing traffic levels and alternate routes 

are available in the vicinity of the facilities. Therefore, we have determined that impacts on traffic near 

Eunice, Louisiana would be temporary and minor during the 3-month period when construction is 

scheduled to occur at each of the facilities. During the remaining 8 months of construction associated 

with these facilities, impacts on traffic would be negligible.

Construction activities at the remaining KMLP facilities (CGT, TRANSCO, and TETCO Meter 

Stations) would occur within rural areas in southern Evangeline Parish (see figure 2.1.3-1 in 

section 2.1.3). Construction activities at each of the meter station sites would result in an average 

increase of 32 vehicle trips per day on area roads. Impacts on local traffic would be similar to those 

described above for the proposed facilities near Eunice, Louisiana and are expected to be temporary and 

minor. 

KMLP anticipates that four workers would be hired for operation of Compressor Station 760. 

The header pipelines and meter stations would be unmanned during operation, and only occasional site 

visits by operations personnel would occur. Therefore, impacts on traffic or roadways resulting from 

operation of the KMLP facilities would be negligible.

In addition to increased traffic associated with construction and operation of the KMLP facilities, 

impacts on roadway traffic could occur as a result of installation of the low pressure header pipeline 

beneath Fournerat and Coulee Roads as well as construction of the gravel access road from Coulee Road 

to Compressor Station 760. KMLP would install the header pipeline beneath both roadways using the 

horizontal bore method (described in section 2.5.2.1) to prevent impacts on roadways and traffic. To 
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further minimize impacts, traffic warning signs and other traffic control devices would be used at road 

crossings, as required by federal, state, and local regulatory agencies. With the implementation of these 

measures, construction activities within and adjacent to roadways would have temporary and minor 

impacts on roadway traffic.

4.9.7 Property Values

Potential impacts on the value of a tract of land depends on many factors, including size, the 

values of adjacent properties, presence of other industrial facilities or 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 LNG 

terminal or KMLP facilities’ presence into account.

The proposed location of the LNG terminal is within an active port and is zoned for heavy 

industrial use. It is in a sparsely populated rural residential area where the nearest residences are 0.6 mile 

to the south. One study on this issue showed that the construction of industrial facilities (e.g. fossil fuel 

generation plants) in the vicinity of residential areas may have a minor negative effect on property values 

in those residential areas (Davis, 2010). However, given the number of projects and other economic 

development in the Lake Charles area (see section 4.13.2.8), it is more likely that property values of 

nearby residences would remain unchanged or would increase.

With the exception of Compressor Station 760, aboveground facilities associated with the KMLP 

facilities would be within or adjacent to existing meter station sites. KMLP would compensate the 

landowners for new easements at Compressor Station 760 and the expanded meter stations (CGT, 

TRANSCO, and TGT Meter Stations) as well as the temporary loss of land use associated with 

construction workspaces and any damages. The easement acquisition process is designed to provide fair 

compensation to the landowner for the right to use the property for facility construction and operation. 

Although not anticipated due to the amount of oil and gas infrastructure in the vicinity of the KMLP 

facilities (73 pipelines, 35 meter stations, 3 compressor stations, and 2 natural gas processing plants are 

within a 1-mile radius of the KMLP facilities), affected landowners who believe that their property values 

have been negatively affected could appeal to the local tax agency for reappraisal and potential reduction 

of taxes. The KMLP facilities would not negatively impact property values outside of the pipeline rightsof-way or aboveground facility boundaries.

Property taxes are generally based on the actual use of the land. Construction and operation of 

the header pipelines would not typically change the general use of the land, but would preclude the 

construction of aboveground structures within the permanent easements. Because the header pipelines

would be adjacent to three existing pipelines (including KMLP’s existing mainline) and would be located 

primarily within agricultural land, we have determined that use of the land, and the associated property 

value would not be negatively affected by the header pipelines.

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 effects to minority or low-income individuals; and
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 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 

projects. In order to develop a more accurate understanding of the racial and ethnic characteristics of the 

communities in the immediate vicinity of the LNG terminal and KMLP facilities, census block grouplevel data was used, as opposed to the larger geographic areas included in census tract and parish level 

data.16 In this analysis, the minority and low-income population percentages in the State of Louisiana and 

Calcasieu Parish were compared to the respective percentages within the three census blocks intersected 

by a 2-mile radius around the proposed LNG terminal. These three census block groups comprised the 

affected community based on the potential environmental impact. Similarly, the affected community 

included in our environmental justice analysis for the KMLP facilities includes four block groups within 

Acadia and Evangeline Parishes. Table 4.9.8-1 identifies racial composition and economic status of the 

seven block groups; Calcasieu, Acadia, and Evangeline Parishes; and the State of Louisiana. 

Table 4.9.8-2 provides an overview of the general economic status of these areas.

TABLE 4.9.8-1

Demographics in the Vicinity of the LNG Terminal and KMLP Facilities (in percent)

State/Parish/Block Group

White, not 

Hispanic or 

Latino

AfricanAmericanHispanic or 

Latino Asian

American 

Indian and 

Alaskan

Native

Native 

Hawaiian 

and Pacific 

Islander

Two or 

more races

Louisiana 62.6 32.0 4.2 1.5 0.7 0.0 1.6

Calcasieu Parish 70.8 24.8 2.6 1.1 0.5 0.0 1.9

Block Group: LA0190018001 94.8 2.5 0.9 0.2 0.3 0.0 1.6

Block Group: LA0190018002 93.9 2.5 3.2 1.3 0.2 0.2 1.4

Block Group: LA0190032001 92.3 3.2 2.5 0.8 0.6 0.0 1.8

Acadia Parish 79.5 18.1 1.7 0.2 0.3 0.0 1.3

Block Group: LA0019603001 92.9 5.2 1.8 0.8 0.1 0.0 0.3

Evangeline Parish 69.0 28.3 2.3 0.3 0.3 0.0 1.1

Block Group: LA0399503001 89.8 6.1 1.5 0.1 1.0 0.0 1.9

Block Group: LA0399503001 88.6 9.0 0.9 0.4 0.0 0.0 1.4

Block Group: LA0399503001 72.5 25.6 2.0 0.0 0.2 0.0 1.3

____________________

Source: U.S. Census Bureau, 2010c

 

16 In order from smallest to largest, the U.S. Census Bureau collects and tabulates data for the following hierarchical geographic levels: 

blocks, block groups, tracts, county subdivisions, counties, and states.
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TABLE 4.9.8-2

Economic Statistics in the Vicinity of the LNG Terminal and KMLP Facilities

State/Parish//Block Group Median Household Income a Population Below Poverty (percent)

Louisiana $44,673 18.7 b

Calcasieu Parish $44,247 16.8 b

Block Group: LA0190018001 $67,022 5.3 c

Block Group: LA0190018002 $117,222 5.3 c

Block Group: LA0190032001 $42,446 14.1 c

Acadia Parish $38,686 19.1 b

Block Group: LA0019603001 $60,893 13.3 c

Evangeline Parish $32,125 22.7 b

Block Group: LA0399503001 $48,086 3.3 c

Block Group: LA0399508002 $43,043 19.1 c

Block Group: LA0399508003 $34,432 9.0 c

____________________

a USA.com, 2015

b U.S. Census Bureau, 2014a

c U.S. Census Bureau, 2010c

Note: 2014 poverty status for the past 12 months is only available at the state and parish level.

None of the communities near the LNG terminal have minority populations greater than the 

general EPA guideline of 50 percent. Within two of the three block groups analyzed (LA0190078001 and 

LA0190032001), the percentage of each minority population was lower than the parish as a whole. Block 

group LA0190018002 has slightly higher percentages of Hispanic or Latino, Asian, and Native Hawaiian 

or Pacific Islanders than the parish as a whole. However, because in each of these cases the difference is 

less than 1 percent, we have determined that block group does not have any minority populations 

representing a substantially greater percentage of the population than the parish as a whole. None of the 

communities near the LNG terminal have a higher portion of the population living below the poverty 

level than Calcasieu Parish or the State of Louisiana.

None of the communities near the KMLP facilities have minority populations greater than the 

general EPA guideline of 50 percent. Within three of the four block groups, the percentage of two 

minority populations was slightly higher than the parish as a whole. However, in each of these instances, 

the minority population within the block group was less than 1 percent higher than the Parish as a whole 

(for example, in block group LA0019603001, the Asian percentage of the population is 0.6 percent higher 

than Asian population within Acadia Parish as a whole). Therefore, it was determined that the minority 

percentage differences noted above are not substantial enough to distinguish these block groups as having 

disproportionately higher percentages of a particular minority group.

None of the communities analyzed near the KMLP facilities have a higher portion of the 

population living below the poverty level than Acadia or Evangeline Parishes. Therefore, we have 

determined that the KMLP facilities would not have disproportionately high effects on low-income 

groups.

4.10 CULTURAL RESOURCES

Section 106 of the NHPA, as amended, requires the FERC to take into account the effect of its 

undertakings (including the issuance of Certificates) on properties listed in or eligible for listing in the 

NRHP and to afford the ACHP an opportunity to comment on the undertaking. Magnolia and KMLP, as 
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non-federal parties, are assisting the FERC in meeting our obligations under Section 106 by preparing the 

necessary information, analyses, and recommendations, as authorized by 36 CFR 800.2(a)(3).

Construction and operation of the projects 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 Cultural Resources Survey

4.10.1.1 Magnolia LNG Project

The area of potential effects (APE) for the Magnolia LNG Project is defined as the boundaries of 

the 115-acre parcel of land upon which the proposed LNG terminal would be constructed as well as the 

areas that would be temporarily affected by construction of the LNG terminal, including the 

approximately 5-acre DII construction yard, 142-acre dredge material placement area, and the 7 acres 

required for the dredge material and effluent pipelines. The site is zoned for heavy industrial use and is 

surrounded by industrial and commercial sites and a recreational boat launch. The potential for visually 

affecting historic structures is low. Magnolia initiated consultation with the Louisiana State Historic 

Preservation Office (SHPO) in a letter dated August 28, 2013 regarding the need for, and scope of, 

cultural resources investigations within the APE for the 115-acre LNG terminal site. In a response letter 

dated October 28, 2013, the SHPO concurred with the definition of the APE and indicated that, given the 

environmental setting and amount of fill that has been placed on the property, no cultural resources 

investigation of the proposed LNG terminal site is necessary. We concur.

In March, 2015 Magnolia consulted with the Louisiana SHPO regarding the need for cultural 

resources investigations within the APE for the Turner Bay dredge material placement site, the 142-acre 

dredge material placement area, and the 7 acres required for the dredge material and effluent pipelines. 

The SHPO recommended that the use of the Turner Bay site or the CB&I site and 7 acres for dredge 

material and effluent pipelines would have no effect on historic properties. We concur.

On April 6, 2015 Magnolia consulted with the SHPO regarding the use of the approximately

5-acre DII site as a staging area and parking lot. The SHPO recommended use of the DII site would have 

no effect on historic properties. We concur.

4.10.1.2 Lake Charles Expansion Project

KMLP completed a records review and cultural resources survey of the proposed Lake Charles 

Expansion Project. The investigations covered both archaeological and architectural resources. The 

report (Cropley and Eberwine, 2014) was provided to the FERC and the Louisiana SHPO.

The cultural resources survey included examination of a 1.2-mile and a 0.13-mile-long by 

400-foot-wide natural gas header pipeline rights-of-way, three possible compressor station construction 

locations (Compressor Station 760), six meter station locations that are proposed for modification or 

expansion, and a proposed interconnection facility location. In total, approximately 290 acres were 

surveyed. The survey identified a single non-site cultural resources locus and a 20th century standing 

structure complex within one of the areas proposed for Compressor Station 760. KMLP recommended 

that both resources were not eligible for the NRHP. 
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In a letter dated May 21, 2014, the Louisiana SHPO concurred that no historic properties would 

be affected by construction of the proposed Lake Charles Expansion Project. We concur. 

4.10.2 Unanticipated Discoveries Plan

Magnolia prepared an Unanticipated Discoveries Plan that would be implemented in the event 

that cultural resources or human remains are encountered during construction of the Magnolia LNG 

Project. Magnolia provided its plan to the Louisiana SHPO on October 21, 2013. In a letter dated 

February 10, 2014, the Louisiana SHPO responded that it has no objection to the proposed plan. 

KMLP prepared an Unanticipated Discoveries Plan that would be implemented in the event that 

cultural resources or human remains are encountered during construction of the Lake Charles Expansion 

Project. KMLP provided its plan to the Louisiana SHPO on May 24, 2014. In a letter dated October 8, 

2014, the Louisiana SHPO responded that it has no objection to the proposed plan. 

4.10.3 Native American Consultation

We mailed our NOIs for the Magnolia LNG Project to the Alabama Coushatta Tribe of Texas, the 

Caddo Nation, and the Coushatta Tribe of Louisiana. We did not receive responses to the NOIs from any 

of the tribes. We sent a letter to each of the tribes on July 1, 2013 requesting their comments on the 

project. To date, no responses have been received from any of the tribes.

We mailed our NOI for the Lake Charles Expansion Project to the Alabama Coushatta Tribe of 

Texas, the Caddo Nation, and the Coushatta Tribe of Louisiana. No responses have been received to date.

Subsequently, on August 20, 2014, we mailed letters to the Alabama Coushatta Tribe of Texas, 

the Chitimacha Tribe of Louisiana, the Jena Band of Choctaw Indians, the Mississippi Band of Choctaw 

Indians, the Choctaw Nation of Oklahoma, the Coushatta Tribe of Louisiana, and the Tunica-Biloxi 

Indians of Louisiana inviting the tribes to participate in the FERC’s review of the Lake Charles Expansion 

Project. To date, no responses have been received from any of the tribes.

Magnolia sent letters to the Alabama Coushatta Tribe of Texas, the Caddo Nation, and the 

Coushatta Tribe of Louisiana on January 17, 2014. On March 18, 2014, KMLP also sent letters to the

Alabama Coushatta Tribe of Texas and the Coushatta Tribe of Louisiana. Additionally, KMLP sent 

letters to the Chitimacha Tribe of Louisiana, the Choctaw Nation of Oklahoma, the Jena Band of Choctaw 

Indians, the Mississippi Band of Choctaw Indians, and the Tunica Biloxi Tribe of Louisiana. The letters 

requested the tribes communicate any concerns about potential impacts the proposed project may have on 

traditional cultural properties. To date, no responses have been received by Magnolia or KMLP; 

however, on August 4, 2014, the Choctaw Nation of Oklahoma sent a letter to the FERC responding to 

the letter it received from KMLP. The tribe requested a copy of the cultural resources survey report, a 

map depicting all known archaeological sites positioned within a 1-mile radius of the project APE, as well 

as GIS shapefiles for the project. On September 2, 2014, KMLP sent the requested materials to the tribe.

On September 8, 2014, the Choctaw Nation of Oklahoma filed a comment with the FERC 

providing comments on the documents received from KMLP. The tribe requested that it and the other 

federally recognized tribes that were consulted regarding the project be contacted in the event of any 

unanticipated find (not only if the discovery consists of human remains). The Unanticipated Discoveries 

Plan has been updated in response to the tribe’s request. 

Therefore, based on the information filed provided by Magnolia and KMLP and the comments of 

the SHPO and Indian tribes, we have determined that the projects as proposed would have no effect on 

any properties listed in, or eligible for listing in, the NRHP.
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4.11 AIR QUALITY AND NOISE

4.11.1 Air Quality

This section describes the air quality conditions that would be directly or indirectly affected by 

the construction and operation of the LNG terminal and KMLP facilities. The section summarizes federal 

and state air quality regulations that are applicable to the proposed facilities. The section also 

characterizes and quantifies the existing air quality and describes potential impacts the facilities may have 

on air quality. 

4.11.1.1 Regional Climate

Due to its location near the Gulf of Mexico, the area in which the LNG terminal and KMLP 

facilities would be located has a subtropical climate that 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 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 Fisheries, 

2013e).

January is typically the coolest month in the vicinity of the LNG terminal and KMLP facilities, 

followed by December and February; the months of June through September are the warmest (NOAA, 

2013). The Lake Charles area receives an annual average of 57.19 inches of rain. Precipitation is 

distributed fairly evenly throughout the year; February is typically the driest month of the year with an 

annual mean of 3.3 inches, whereas June tends to be the wettest month with an annual mean of 6.1 inches. 

Snow events are rare with an annual mean of 0.3 inch of snow, which is only likely to occur in January or 

February. Normal annual average relative humidity is 79 percent; however, humidity levels above 

85 percent frequently occur overnight throughout the year.

The predominant wind direction is from the south for much of the year, which tends to subdue 

extreme summer heat and shorten the duration of winter cold outbreaks, but also increases relative 

humidity in the area. During winter months, the highest wind speeds occur with the wind direction being 

predominantly from the north. On average, wind speed varies between 6 and 10 mph (NOAA, 1998). 

4.11.1.2 Existing Air Quality

Ambient Air Quality Standards

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” (EPA, 2014c). 

These criteria pollutants are ground-level ozone, carbon monoxide (CO), NOX, sulfur dioxide (SO2), 

respirable and fine particulate matter (inhalable particulate matter with an aerodynamic diameter less than 

or equal to 10 microns [PM10] and less than or equal to 2.5 microns [PM2.5]), and airborne lead. 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. The NAAQS are codified in 

40 CFR 50 and are summarized in table 4.11.1-1. Louisiana has adopted the NAAQS.
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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)

Lead 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

Primary and 

Secondary

Primary and 

secondary

8-hour (2008)

8-hour (1997)

1-Hour

0.075 ppmc(150 μg/m3)

0.08 ppm (157 μg/m3)

0.12 ppm (235 μg/m3)

Annual fourth-highest daily maximum 

8-hour concentration, averaged over 

3 years

Particle pollution

PM2.5 Primary 

Secondary

Primary and 

secondary

Annual

Annual

24-hour

12 μg/m3

15 μg/m3

35 μg/m3

Annual mean, averaged over 3 years

98th 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

Secondary

1-hour

3-hour

75 ppb (195 μg/m3)d

0.5 ppm (1,300 μg/m3)

99th percentile of 1-hour daily maximum 

concentrations, averaged over 3 years

Not to be exceeded more than once per 

year

____________________

a Final rule signed October 15, 2008. The 1978 lead standard (1.5 μg/m3 as 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 

standard, which 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, the 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, 2014c
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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, 2014b). The six key GHGs are:

 carbon dioxide (CO2);

 methane (CH4);

 nitrous oxide (N2O);

 hydrofluorocarbons;

 perfluorocarbons; and

 sulfur hexafluoride.

All GHGs have been assigned a Global Warming Potential (GWP). The GWP represents the 

ability of each different GHG to trap heat in the atmosphere. They are determined based on the heatabsorbing ability of each gas relative to that of CO2, as well as the rate of decay, or rate of removal from 

the atmosphere, of each gas over a given number of years. GWPs are used to define the impact 

greenhouse gases have on global warming over different time periods. Because each of the gases remains

in the atmosphere for a different amount of time and each has a varying ability to absorb solar radiation, 

the calculated GWP for each gas in relation to CO2 can vary greatly. For example, for the 100-year GWP, 

CO2 has a GWP of 1, whereas CH4 has a GWP of 25 and N2O has a GWP of 298.

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 in 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 similarly 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 are not available are considered to be unclassifiable and are treated as 

attainment areas. The LNG terminal and KMLP facilities would be located in areas classified as in 

attainment for all criteria pollutant standards.

In addition, there are no non-attainment or maintenance areas through which LNG vessels would 

transit en route to the Gulf of Mexico. Although the EPA maintains jurisdiction over portions of the outer 

continental shelf (OCS) within the Gulf of Mexico (40 CFR 55), attainment status does not apply in 

offshore areas. Therefore, LNG vessels transiting the Gulf of Mexico would not pass through nonattainment or maintenance areas.

Although currently in attainment for ozone, both the Lake Charles and Lafayette areas are 

vulnerable to being designated as non-attainment for ozone in the next few years, and the metropolitan 

planning districts responsible for air quality planning for these areas have applied for and been accepted 

into the EPA Ozone Advance program, which is a program that encourages emission reductions to assist 

areas to remain in attainment with ozone NAAQS.
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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 are

available through the EPA’s AIRDATA database, which collects air monitoring data from all over the 

country. The majority of emissions generated during construction and operation of the LNG terminal and 

KMLP facilities would occur in Calcasieu and Acadia Parishes. 

Ambient air quality monitoring data from the 3-year period of 2011 to 2013 are summarized in 

table 4.11.1-2 for those monitors that were nearest or most representative of the proposed facilities in 

Calcasieu and Acadia Parishes. 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 proposed facilities. 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, which are comparable to the applicable NAAQS. As shown in the 

table, each of the measured concentrations is below or equivalent to the applicable NAAQS for the 

pollutant and averaging period, thus indicating attainment with the standard. 

4.11.1.3 Regulatory Requirements for Air Quality

State air quality rules govern the issuance of air permits for construction and operation of a 

stationary emission source. The LDEQ is the lead air permitting authority for the LNG terminal and 

KMLP facilities. The LDEQ's air quality regulations are codified in LAC 33:III.1 through 59. The 

regulations incorporate the federal program requirements listed in 40 CFR 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. For larger facilities subject to major New 

Source Review (NSR), review and approval at the federal level may be required.

Federal Air Quality Requirements

New Source Performance Standards

Section 111 of the CAA authorized the EPA to develop technology-based standards that apply to 

specific categories of stationary sources. These standards, referred to as New Source Performance 

Standards (NSPS), are found in 40 CFR 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 of the proposed 

facilities. 

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 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 60 standards 

promulgated by the EPA, except for Subpart AAA – Standards of Performance for New Residential Wood 

Heaters, which is not applicable to either the LNG terminal or KMLP facilities. Equipment at the LNG 

terminal and KMLP facilities subject to any of the NSPS subparts listed below would all be subject to 

Subpart A.
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TABLE 4.11.1-2

Ambient Air Quality Concentrations for Areas Near the LNG Terminal and KMLP Facilities

Pollutant

Averaging 

Period Rank Location 2013 2012 2011

Applicable 

NAAQS Units Monitor

LNG Terminal – Calcasieu Parish

CO 1-hour 2

nd high Jefferson County, TX 0.7 0.7 0.9 35 ppm A

8-hour 2

nd high Jefferson County, TX 0.6 0.5 0.5 9 ppm A

NO2 Annual Mean Calcasieu Parish, LA N/A N/A 6 53 ppb B

1-hour 98th percentile Calcasieu Parish, LA 30 27 32 100 ppb B

Ozone 8-hour 4

th high Calcasieu Parish, LA 0.07 0.075 0.069 0.075 ppm B

PM2.5 24-hour 98th percentile Calcasieu Parish, LA 17 20 20 35 μg/m3 E

Annual Mean Calcasieu Parish, LA N/A N/A 8.9 12 μg/m3 E

PM10 24-hour 2

nd high Galveston County, TX 46 54 51 150 μg/m3 C

SO2 1-hour 99th percentile Calcasieu Parish, LA 31 42 37 75 ppb B

3-hour 2

nd high Calcasieu Parish, LA N/A N/A N/A 0.5 (ppm) ppb B

Lead Quarterly Maximum Harris County, TX N/A N/A N/A 0.15 μg/m3 D

KMLP Facilities – Acadia Parish

CO 1-hour 2

nd high Jefferson County, TX 0.7 0.7 0.9 35 ppm A

8-hour 2

nd high Jefferson County, TX 0.6 0.5 0.5 9 ppm A

NO2 Annual Mean Calcasieu Parish, LA N/A N/A 6 53 ppb B

1-hour 98th percentile Calcasieu Parish, LA 30 27 32 100 ppb B

Ozone 8-hour 4

th high Lafayette Parish, LA 0.07 0.07 0.07 0.075 ppm F

PM2.5 24-hour 98th percentile Lafayette Parish, LA 18 18 21 35 μg/m3 F

Annual Mean Lafayette Parish, LA 7.9 8.6 9.0 12 μg/m3 F

PM10 24-hour 2

nd high Galveston County, TX 46 54 51 150 μg/m3 C

SO2 1-hour 99th percentile Calcasieu Parish, LA 31 42 37 75 ppb B

3-hour 2

nd high Calcasieu Parish, LA N/A N/A N/A 0.5 (ppm) ppb B

Pb Quarterly Maximum Harris County, TX N/A N/A N/A 0.15 μg/m3 D

____________________

Monitor Key:

A Seattle Street, Nederland, Jefferson County, Texas (monitor no. 482451035)

B 2646 John Stine Rd, Lake Charles, Calcasieu Parish, Louisiana (monitor no. 220190008)

C 2516 Texas Avenue, Texas City, Galveston County, Texas (monitor no. 481670004)

D 1262 1⁄2 Mae Drive, Houston, Harris County, Texas (monitor no.482011034)

E Common & E. McNeese, Lake Charles, Calcasieu Parish, Louisiana (monitor no. 220190010)

F 700 Cajundome, Lafayette, Lafayette Parish LA (monitor no. 22055007)

Notes: μg/m3 = micrograms per cubic meter; ppm = parts per million; ppb = parts per billion; N/A = data not yet available

Source: EPA, 2015a

Subpart Dc – Standards of Performance for Small Industrial, Commercial, and Institutional Steam 

Generating Units 

Subpart Dc applies to steam-generating units constructed after July 9, 1989 that have maximum 

heat input capacity of 100 million British thermal units (MMBtu) per hour (MMBtu/hr) or less. The 

auxiliary boilers that are part of each liquefaction train at the LNG terminal would be subject to NSPS 

Subpart Dc because they would be constructed after the applicability date and would have maximum heat 

input capacity of less than 100 MMBtu/hr.
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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 at the LNG terminal for use with emergency electric generators and 

firewater pumps would be subject to NSPS Subpart IIII.

Subpart JJJJ – Standards of Performance for Stationary Spark Ignition Internal Combustion Engines

Subpart JJJJ provides requirements for stationary spark ignition internal combustion engines that 

are constructed, modified, or reconstructed after June 12, 2006. The natural gas-fired emergency 

generator engine at Compressor Station 760 would be subject to the requirements of this rule for 

emergency natural gas-fired engines greater than or equal to 130 hp. KMLP would comply with NSPS 

Subpart JJJJ by purchasing a certified engine.

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 MMBtu/hr 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. The eight gas turbines at the LNG terminal and four gas 

turbines at Compressor Station 760 would be subject to NSPS Subpart KKKK. 

Subpart OOOO – Standards of Performance for Crude Oil and Natural Gas Production, Transmission 

and Distribution

Subpart OOOO regulates emissions of VOC and SO2 from gas processing and transmission. The 

rule applies to compressors, pneumatic controllers, liquefied natural gas units, gas sweetening unit, and 

fugitive VOC emissions from leaking components.

National Emissions Standards for Hazardous Air Pollutants

Section 112 of the CAA authorized the EPA to develop technology-based standards that apply to 

specific categories of stationary sources that emit hazardous air pollutants (HAP). These standards are 

referred to as National Emission Standards for Hazardous Air Pollutants (NESHAP) and are found in 

40 CFR 61 and 63. Eight hazardous substances are regulated per 40 CFR 61, including asbestos, 

benzene, beryllium, coke oven emissions, inorganic arsenic, mercury, radionuclides, and vinyl chloride. 

NESHAP can apply to major and/or area (minor) sources of HAPs. The EPA develops national priorities 

for NESHAPs that focus on significant environmental risks and noncompliance patterns.

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 standards. Part 63 regulates HAPs 

from major sources of HAPs and specific source categories emitting HAPs. Some NESHAPs may apply 
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to area (minor) sources of HAPs. Major source thresholds for NESHAPs are 10 tons per year (tpy) of any 

single HAP or 25 tpy of total HAPs. 

During operation of the LNG terminal, the annual emissions of each individual HAP would be 

less than 10 tpy, and the total annual emissions of all HAPs would be less than 25 tpy. Therefore, the 

facility would be an area (minor) source of HAPs. Likewise, Compressor Station 760 also has potential 

annual emission of each individual HAP of less than 10 tpy and total annual emissions of all HAPs of less 

than 25 tpy. Therefore, Compressor Station 760 would also be an area (minor) source of HAPs. The 

following NESHAP subparts apply to the LNG terminal and/or Compressor Station 760.

Subpart A – NESHAP 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 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 LNG terminal

and Compressor Station 760 have been delegated to LDEQ. 

Subpart ZZZZ – NESHAP for Stationary Reciprocating Internal Combustion Engines

Subpart ZZZZ regulates HAP emissions from reciprocating internal combustion engines (RICE). 

Based on the potential to emit for HAPs, both the LNG terminal and Compressor Station 760 would be 

area sources. The RICE proposed for the LNG terminal includes the engines used for the emergency 

generators, the fire water pumps, and the deluge pumps. In accordance with 40 CFR 63.6590(c), 

compliance with Subpart ZZZZ would be achieved through compliance with NSPS Subpart IIII for 

compression ignition engines. The RICE proposed for Compressor Station 760 is an engine used for an 

emergency generator. Pursuant to 40 CFR 63.65909c), compliance with Subpart ZZZZ is achieved 

through compliance with NSPS Subpart JJJJ for spark ignition engines. 

Mandatory Greenhouse Gas Reporting

On November 8, 2010, the EPA signed a rule that finalizes reporting requirements for the 

petroleum and natural gas industry under 40 CFR 98. Subpart W of 40 CFR 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 LNG terminal would 

be required to report GHG emissions because annual emissions of GHGs would be above 25,000 metric 

tpy. 

Compressor stations are also subject to GHG reporting requirements under Subpart W. Reporting 

is required for CO2e from reciprocating compressor rod packing venting, centrifugal compressor venting, 

transmission storage tanks, blowdown vent stacks, natural gas pneumatic device venting, and equipment 

leaks from valves, connectors, open ended lines, pressure relief valves, and meters. Compressor Station 

760 would include four turbines and one fuel gas heater that would be included in GHG reporting.
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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. Such activities must not: 

 cause or contribute to any new violation of any standard in any area;

 increase the frequency or severity of any existing violation of any standard in any area; or

 delay timely attainment of any standard or any required interim emission reductions or 

other milestones in any area.

The areas where the LNG terminal and KMLP facilities would be located are classified as in 

attainment for all criteria pollutant standards; therefore, General Conformity requirements do not apply.

New Source Review – Prevention of Significant Deterioration

Congress established the NSR pre-construction permitting program as part of the 1977 CAA

Amendments. Federal pre-construction review under NSR is conducted under separate procedures for 

sources in attainment areas and sources in nonattainment areas. Nonattainment New Source Review 

applies to sources in nonattainment areas. Because the LNG terminal and KMLP facilities would not be 

in nonattainment areas, this process does not apply and is not discussed further. Prevention of Significant 

Deterioration (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 tpy of a 

regulated criteria pollutant (40 CFR §51.166(b)(1)(i)(b)). Table 4.11.1-3 lists the major source emission 

thresholds applicable to the LNG terminal and the KMLP facilities.

TABLE 4.11.1-3

Major Stationary Source and Prevention of Significant Deterioration Emission Thresholds

Air Pollutant

Major Stationary Source Threshold

(tpy)

PSD Significant Emission Rates

(tpy)

NOX 250 40

CO 250 100

VOCs 250 40

PM 250 25

PM10 250 15

PM2.5 250 10

SO2 250 40

GHGs (as CO2e) NA 75,000
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Once a facility is subject to PSD, the following requirements apply: 

 installation of Best Available Control Technology (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 or PSD 

air quality increment;

 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 that 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). Magnolia completed a BACT assessment for the LNG terminal as part of the Title V and 

PSD permit application for CO, NOX, VOC, PM10, PM2.5, and GHGs, the results of which were 

incorporated into subsequent facility emission calculations.

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).

There are three air quality classifications within an attainment area for purposes of PSD 

permitting review: Class I areas are designated as pristine natural areas or areas of natural significance 

and receive special protections under the CAA based on good air quality. Class III areas are heavily

industrialized zones that are established only on request and must meet all requirements outlined in 

40 CFR 51.166. The remainder of the United States is designated as Class II. The LNG terminal and 

KMLP facilities would be in Class II areas.

If a new source or major modification of an existing source is subject to the PSD permitting

requirements and is within 62 miles 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 Breton NWR is 

the closest designated Class I area to the LNG terminal and KMLP facilities, and is over 260 and 

220 miles to the east-southeast, respectively. Therefore, a PSD Class I analysis is not required. 

Title V Operating Permit

The Part 70 Operating Permit program, as described in 40 CFR 70, requires major stationary 

sources of air emissions to obtain a federally enforceable operating permit. Part 70 operating permits are 

more commonly referred to as “Title V” permits. 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;
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 10 tpy of any individual HAP; or

 25 tpy of any combination of HAPs.

Estimated potential emissions of NOX, and CO during operation of the LNG terminal are greater 

than 100 tpy. Similarly, estimated potential emissions of CO during operation of Compressor Station 760 

are greater than 100 tpy. Therefore both the LNG terminal and Compressor Station 760 would be subject 

to the Title V Operating Permit program. Magnolia submitted its Title V permit application for the LNG 

terminal on January 27, 2015. KMLP submitted its Title V permit application for Compressor Station 

760 on October 7, 2014.

Louisiana Air Quality Requirements

The LNG terminal and KMLP facilities would be subject to state standards, codified in 

LAC 33:III. The regulations listed below would apply to the new facilities associated with the Terminal 

Expansion, including governing turbines, flares, generators, fire water pumps, condensate loading, amine 

units with incinerator, and fugitive emissions:

 Chapter 9 – General Regulations on Control of Emissions and Emission Standards

 Chapter 11 – Control of Air Pollution from Smoke

o Section 1101 – Control of Air Pollution from Smoke

o Section 1103 – Impairment of Visibility on Public Roads Prohibited

o Section 1105 – Smoke from Flaring

o Section 1109 – Outdoor Burning (smoke)

 Chapter 13 – Emission Standards for Particulate Matter

o Section 1305 – Control of Fugitive Emission (particulate matter)

o Section 1311 – Emission Limits (particulate matter)

o Section 1313 – Fuel Burning Equipment (particulate matter)

 Chapter 15 – Emission Standards for Sulfur Dioxide

o Section 1503 – Emission Limits (SO2)

o Section 1509 – Reduced Sulfur Compounds

 Chapter 17 – Control of Emissions of Carbon Monoxide (New Sources)

 Chapter 21 – Control of Emissions of Organic Compounds

o Section 2103 – Storage of VOCs

o Section 2111 – Pumps and Compressors

o Section 2113 – Housekeeping

o Section 2121 – Fugitive Emission Control (VOCs)

 Chapter 22 – Control of Emissions of Nitrogen Oxides (NOX)

 Chapter 29 – Odor Regulations

 Chapter 51 – Comprehensive Toxic Air Pollutant Emission Control Program

Magnolia and KMLP 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. It is expected that the LDEQ would include permit conditions in the respective 

permits to ensure compliance with these regulations. 
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4.11.1.4 Construction Air Emissions and Impacts and Mitigation

Air pollutant emissions during construction of the LNG terminal and KMLP facilities would

result from the operation of construction vehicles, marine traffic, vehicles driven by construction workers

commuting to and from work sites, and the generation of fugitive dust during construction activities. 

Particulate emissions would result from fugitive dust generated by construction-related activities, the 

quantity of which 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. 

LNG Terminal 

Construction of the LNG terminal would occur over a 36-month period, with an additional 

9 months until all four liquefaction trains would be commissioned and operational (resulting in a total 

construction period of 45 months). 

Magnolia developed an inventory of non-road equipment, vessels, on-road vehicles, off-road vehicles, 

and expected activity levels (either hours of operation or miles travelled) based on expected duration of 

construction at the site. The level of activity for each piece of construction equipment was combined with the 

relevant emission factors to determine estimates of annual construction emissions. For the purpose of 

estimating construction emissions, construction was divided into six categories consisting of the following:

 Site Preparation – Site preparation would occur during the first year of construction and 

would consist of site clearing by removing debris, followed by stripping/grubbing topsoil 

(stockpiled on site), cut-fill and rough grading operations, construction of drainage 

swales and the short (approximately 1,500 feet) heavy-haul road from the construction 

workspace immediately east of the LNG terminal site and preparation for foundations.

 LNG Storage Tanks – Construction of the LNG storage tanks would occur during the first 

3 years of construction and would include the installation of 3,016 concrete piles driven 

by up to eight hydraulic pile drivers to support the foundation of the storage tanks, 

followed by construction and testing of the LNG storage tanks.

 Balance of Plant – Construction of other components within the LNG terminal that would 

require specialized construction equipment would occur during the second and third year 

of construction. Activities would include installation of the foundations for the 

liquefaction trains, receipt of the LNG train modules at the temporary work yard, 

transport from the work yard to the LNG terminal site using heavy crawlers, assembly of 

the four liquefaction trains, and completion of other plant equipment (e.g., emergency 

water pumps, site buildings, onshore components of the LNG vessel loading facility).

 Building Construction – Construction of on-site buildings (i.e., workshop, 

control/administration, and Magnolia Meter Station) and other architectural components

would occur during the second year of construction.
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 Marine Work – Construction of the LNG loading and ship berthing facilities would occur 

during the first and second year of construction. The recessed berthing area would be 

constructed using a combination of onshore excavation (using backhoe and trackhoe 

equipment) and dredging using a hydraulic cutterhead suction dredge mounted on a selfpropelled vessel. Bulkhead construction would consist of installing sheet pile bulkhead 

using hydraulic pile driving rigs and rock armoring at the base of the bulkhead and along 

the east and west ends of the marine basin. Breasting dolphins would be installed by 

driving 96-inch-diameter steel pilings into competent foundation soils adjacent to the 

terminal jetty using a hydraulic pile driver.

 Miscellaneous Construction – Miscellaneous construction tasks would occur throughout 

construction and would include operation of equipment that is not tied to a specific task,

but would be used for general construction activities throughout the duration of construction.

Annual emissions estimates for activities associated with construction of the LNG terminal are 

summarized in table 4.11.1-4. The fugitive emission estimate consists of contributions from general site 

construction work (acreage impacted), earth-moving fugitive dust emissions (quantity of soil moved), and 

unpaved road travel (distance of travel and weight of vehicles).

Construction materials would be delivered to the site primarily by barge. Magnolia estimates that 

50 or fewer marine deliveries would occur during construction of the LNG terminal. In addition, large 

quantities of concrete would be used to construct the LNG terminal. Cement would be sourced from 

existing concrete plants within 5 miles of the LNG terminal and would be delivered during the first 

19 months of construction. Emissions associated with truck transport of concrete are included in the 

construction emission estimate in several of the construction phases (e.g., LNG storage tanks, balance of 

plant, and building construction). 

Three types of marine vessels would be used during construction of the LNG terminal. Tugboats 

would be used for barge deliveries of construction material. A medium-sized (approximately 1,500 hp) 

dredging vessel would be used to dredge the recessed berthing area. Floating pile driving rigs would be 

used for installation of piles associated with the LNG loading and ship berthing area.

Fugitive dust emission levels would vary in relation to moisture content, composition, activity 

level, and volume of soils during construction. Fugitive dust would be produced primarily during the site 

preparation activities, when the site would be cleared of debris, leveled, and graded. In addition, 

approximately 131,200 yd3 would be placed on site during excavation of upland portions of the recessed 

berthing area (see detailed discussion in section 2.5.1.4). Existing paved roads would be used to access 

the LNG terminal. 

Because construction emissions are short term and temporary, standard EPA emission thresholds 

do not apply. As referenced in section 4.11.1.3, areas considered in non-attainment or maintenance for 

any of the NAAQS are required to assess construction emissions against General Conformity de minimis

thresholds to determine if a General Conformity analysis is required; however, because the area is in 

attainment for all NAAQS, the General Conformity de minimis thresholds do not apply. The construction 

activities proposed in association with the LNG terminal are comparable to other types of infrastructure 

projects or industrial facilities and would represent a small portion of the overall annual emissions in the 

region. The construction emissions would, therefore, not have a long-term effect on air quality in the area.
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TABLE 4.11.1-4

Annual LNG Terminal Construction Emissions

Activity

Emissions (tpy)

NOX CO SO2 PM10 PM2.5 VOC CO2e

Year 1

Site preparation 6.4 3.1 0.3 0.7 0.7 0.6 1,817

LNG tank construction 10.1 13.0 0.5 1.0 1.0 1.0 2,599

Balance of plant 5.3 5.2 0.3 0.5 0.5 0.5 1,435

Marine work (dock, jetty, dredging) 11.5 3.0 1.1 0.4 0.4 0.4 954

Material transport via tug / barge -- -- -- -- -- -- --

Construction management 

(e.g., water trucks, pickup trucks)

0.6 2.4 0.1 0.1 0.1 0.1 225

Construction mobile sources

(worker commutes)

0.1 1.6 -- -- -- -- 238

Fugitive dust -- -- -- 14.9 1.5 -- --

Total for Year 1 34.0 28.3 2.3 17.6 4.2 2.6 7,268

Year 2

LNG tank construction 25.0 93.0 1.5 2.9 2.9 4.1 8,739

Balance of plant 2.9 5.8 0.2 0.4 0.3 0.4 1,010

Building construction (workshop, 

control/admin, and Magnolia Meter Station)

3.7 49.0 0.2 0.2 0.2 1.4 856

Marine (dock, jetty) 12.0 31.0 1.0 0.8 0.8 1.2 2,523

Material transport via tug / barge 26.0 5.0 2.6 0.6 0.6 0.5 1,385

Construction management 

(e.g., water trucks, pickup trucks)

0.8 0.5 0.1 0.1 0.1 0.1 427

Construction mobile sources

(worker commutes)

0.2 2.8 -- -- -- -- 408

Fugitive dust -- -- -- 14.3 1.4 -- --

Total for Year 2 70.6 187.1 5.6 19.3 6.3 7.7 15,348

Year 3

LNG tank construction 12.0 88.0 0.7 1.5 1.5 2.9 4,022

Balance of plant 0.9 4.6 0.1 0.1 0.1 0.2 372

Architectural 2.6 46.0 0.1 0.2 0.1 1.2 654

Marine (dock, jetty) 1.7 12.0 0.1 0.2 0.2 0.4 858

Construction management 

(e.g., water trucks, pickup trucks)

0.6 0.4 0.1 0.1 0.1 0.1 396

Construction mobile sources

(worker commutes)

0.2 2.8 0.0 -- -- 0.0 408

Fugitive dust -- -- -- 14.3 1.4 -- --

Total for Year 3 18.0 153.8 1.1 16.4 3.4 4.8 6,710
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KMLP Facilities

Compressor Station 760

Construction of Compressor Station 760 would result in a temporary increase in the emissions of 

pollutants due to combustion of fuel in vehicles and equipment, dust generated from excavation, grading 

and fill activities, and general construction activities (e.g., painting and welding). KMLP anticipates that 

the construction phase of Compressor Station 760 would occur over approximately 11 months. Estimated 

emissions associated with construction of Compressor Station 760 are summarized in table 4.11.1-5.

TABLE 4.11.1-5

Compressor Station 760 Construction Emissions (Estimated)

Construction Activity

Emissions (tpy)

NOX CO SO2 PM10 PM2.5 VOC CO2e

Unpaved haul roads --- --- --- <0.1 <0.1 --- ---

Bulldozing, grading, compacting --- --- --- 4.8 0.5 --- ---

Heavy equipment operation 36.1 23.1 <0.1 1.7 1.6 5.5 4,602

On-road vehicles 0.2 2.3 <0.1 <0.1 <0.1 0.2 445

Painting --- --- --- --- --- 1.3 ---

Welding --- --- --- 0.3 0.2 --- ---

Total 36.3 25.4 <0.1 6.8 2.4 7.0 5,047

As previously referenced, standard EPA emission thresholds do not apply to construction 

emissions, and General Conformity de minimis thresholds do not apply because the area is in attainment 

for all the NAAQS. The construction activities proposed in association with the KMLP facilities are 

comparable to other types of infrastructure projects or industrial facilities and would represent a small 

portion of the overall annual emissions in the region. Therefore, the construction emissions would not 

have a long-term effect on air quality in the area. 

Meter Station Modifications and Header Pipelines

Construction emissions associated with the modified meter stations and the header pipelines 

would be minimal, localized to the construction area, and short term (3 months). These facilities would 

be in sparsely populated areas. Construction associated with each project component would require a 

small workforce ranging from an average of 20 workers for each meter station to between 60 and 

75 workers for the header pipelines. Therefore, the construction emissions are expected to be 

insignificant.

Mitigation Measures

Generation of fugitive dust associated with construction of the LNG terminal resulting from 

travel on unpaved roads would be minimized due to the compact footprint of the onshore portion of the 

site and DII construction yard (119.2 acres), short distance of the heavy haul road (2,000 feet), and slow 

speeds used to transport components and other materials from the adjacent DII construction yard to the 

LNG terminal. Magnolia has provided a draft Fugitive Dust Control Plan describing control measures 

that would be implemented to minimize fugitive dust emissions. We have reviewed Magnolia’s draft 
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Fugitive Dust Control Plan and conclude that more detail is necessary due to the sensitive nature of air 

quality in the area surrounding the LNG terminal. Therefore, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia should file with the 

Secretary, for review and written approval by the Director of OEP, a revised 

version of the Fugitive Dust Control Plan that includes a description of the following 

mitigation measures: 

a. identifying the speed limit that Magnolia would enforce on unsurfaced roads; 

b. clarifying that the EI has the authority to determine if/when water or a 

palliative needs to be used for dust control; 

c. further describing inspection procedures to identify and abate visible dust 

plumes; and

d. clarifying the individuals with the authority to stop work if the contractor 

does not comply with dust control measures.

KMLP also committed to watering the construction workspaces as needed to minimize fugitive 

dust emissions. While the measures described by KMLP would help control fugitive dust, we conclude 

that more detail is necessary due to the sensitive nature of air quality in surrounding area. Therefore, we 

recommend that:

 Prior to the end of the draft EIS comment period, KMLP should file with the 

Secretary, for review and written approval by the Director of OEP, a Fugitive Dust 

Control Plan that specifies the precautions that KMLP would take to minimize 

fugitive dust emissions from construction activities, including additional mitigation 

measures to control fugitive dust emissions of Total Suspended Particulates and 

PM10. The plan should clearly explain how KMLP would implement measures, such 

as: 

a. watering the construction workspace and access roads;

b. providing measures to limit track-out onto the roads;

c. identifying the speed limit that KMLP would enforce on unsurfaced roads; 

d. covering open-bodied haul trucks, as appropriate;

e. clarifying that the EI has the authority to determine if/when water or a 

palliative needs to be used for dust control; 

f. describing inspection procedures to identify and abate visible dust plumes; and

g. clarifying the individuals with the authority to stop work if the contractor 

does not comply with dust control measures.

Magnolia and KMLP 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 and construction emissions 

would occur during the construction period and would subside once construction activities for any given 

project component are complete. Additionally, LNG terminal construction emissions would be primarily 

limited to the construction area and would represent less than 1.3 percent of Calcasieu Parish’s yearly CO 
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emissions and less than 1 percent of the parish’s yearly emissions inventories for all other pollutants, 

based on a comparison to 2013 annual reported emissions for the Calcasieu Parish (LDEQ, 2013b). 

Construction emissions associated with the KMLP facilities in Acadia Parish would primarily be 

associated with Compressor Station 760, would be limited to the construction area, and would represent 

less than 7 percent of Acadia Parish’s yearly PM10 emissions and less than 3 percent of the parishes’ 

yearly emissions inventories for all other pollutants (LDEQ, 2013b). Construction emissions associated 

with the KMLP facilities in Evangeline Parish would be limited to a 3-month period and would represent 

a negligible portion of overall emissions within the parish. While the measures described above would 

help control construction emissions, we conclude that more detail is necessary due to the sensitive nature 

of air quality in areas surrounding the projects. Therefore, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia and KMLP should 

provide further details regarding commitments to reduce NOX, CO, PM, and SO2

from mobile and stationary construction equipment including: 

a. feasibility of leasing new, clean equipment meeting the most stringent of 

applicable federal or state standards, if practicable. In general, commit to 

the best available emissions control technology;

b. feasibility of using electric vehicles, natural gas, biodiesel, or other 

alternative fuels during construction and operation phases to reduce the 

projects’ criteria and greenhouse gas emissions;

c. commitments to limit idling of heavy equipment to less than 5 minutes and 

verify through unscheduled inspections;

d. commitments to maintain and tune engines per manufacturer’s 

specifications to perform at CARB and/or EPA certification levels, prevent 

tampering, and conduct unscheduled inspections to ensure these measures 

are followed; and

e. clarify how it would manage construction traffic and parking in order to 

maintain traffic flow and minimize vehicle trips.

4.11.1.5 Operation Air Emissions Impacts and Mitigation

LNG Terminal 

Operating Air Emissions

The emission sources associated with the four liquefaction trains are expected to operate 

continuously. Each of the four liquefaction trains at the LNG terminal would include the following 

emission sources:

 two gas turbines;

 one auxiliary boiler;

 one thermal oxidizer to treat emissions from the amine unit;

 one gas-fired regenerative fuel heater;

 one ammonia vent; and

 fugitive emissions from pipe flanges, valves, and valve stems.
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The LNG terminal also would contain the following emission sources, which would operate on an 

intermittent or as-needed basis:

 one cold gas flare for treating low temperature gases;

 one warm gas flare for treating warm and high temperature process gases;

 one emergency electric generator;

 two emergency firewater pumps;

 two water deluge pumps;

 up to 208 LNG vessels per year, and their attendant tugs; and

 miscellaneous mobile sources.

Annual emissions by source for the LNG terminal and a summary of total annual emissions are 

provided in table 4.11.1-6. Emission estimates include control technologies proposed for the LNG 

terminal, based on the completion of the required BACT assessment for CO, NOX, VOC, PM10, PM2.5, 

and GHGs. The LNG terminal would be a PSD major source for NOX and CO. In addition, it would be a 

Title V major source for PM10 and PM2.5, exceeding the major source threshold of 100 tpy. The facility 

would be considered a minor source of HAP emissions. As described in section 4.11.1.3, because 

emissions from the LNG terminal would be above the PSD significant emission rates (presented in 

table 4.11.1-3) for NOX, CO, PM10, PM2.5, VOC, and CO2e, these pollutants would be required to be 

addressed further. Magnolia would be required to show compliance with the NAAQS and PSD Increment 

requirements for NOX, CO, PM10, and PM2.5. In addition, Magnolia would be required to show 

compliance with the ozone NAAQS and to comply with the federal requirements for major sources of 

CO2e. Compliance with these requirements is discussed below.

LNG Terminal Ambient Impacts

As discussed in the PSD applicability section in section 4.11.1.3, Magnolia conducted a PSD 

Screening Analysis, NAAQS Analysis, and PSD Increment Analysis for stationary sources at the LNG 

terminal (ERM, 2015). The PSD Screening Analysis included a Significance Analysis, Area of Influence 

Analysis, and Pre-construction Monitoring Analysis. Pollutants modeled included only those that 

exceeded the PSD significant emission rates. These included NO2, CO, PM10, and PM2.5. The 

significance analysis considers the emissions associated only with the proposed LNG terminal 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 would 

be “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 Area of Influence, 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 pre-construction ambient monitoring is 

required. 
4-136

TABLE 4.11.1-6

Emissions by Source and Total Annual Emissions Associated with Operation of the LNG Terminal

Emission Source NOX CO SO2 PM10 PM2.5 VOC HAPs CO2e

Liquefaction Train 1 266.4 270.5 4.6 22.1 22.1 15.6 4.9 568,278

Liquefaction Train 2 266.4 270.5 4.6 22.1 22.1 15.6 4.9 568,278

Liquefaction Train 3 266.4 270.5 4.6 22.1 22.1 15.6 4.9 568,278

Liquefaction Train 4 266.4 270.5 4.6 22.1 22.1 15.6 4.9 568,278

Emergency generator 0.7 0.4 <0.1 <0.1 <0.1 <0.1 <0.1 77

Emergency firewater pumps 0.2 0.2 <0.1 <0.1 <0.1 <0.1 <0.1 40

Water deluge pumps 0.8 0.5 <0.1 <0.1 <0.1 <0.1 <0.1 81

Warm gas flare 8.3 45.2 <0.1 1.0 1.0 0.7 <0.1 16,559

Cold gas flare 4.5 24.5 <0.1 0.6 0.6 <0.1 <0.1 8,975

Fugitive emissions -- -- -- -- -- 14.7 0.3 2,222

LNG Terminal Stationary 

Sources Subtotal

1,080.1 1,152.8 18.5 90.1 90.1 78.0 20.1 2,301,066

LNG vessels and tugs 312 41 3 14 14 18 -- 20,487

Worker commuting <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 <0.1 111

Tug/barge/truck distribution 52 4.4 <0.1 3 3 3 -- 3,449

LNG Terminal

Mobile Sources Subtotal

364 46 3 17 17 21 <0.1 24,047

TOTAL 1,444.1 1,198.8 21.5 107.1 107.1 99.0 20.1 2,325,113

____________________

Note: All units of measurement are expressed in tpy.

In accordance with the modeling requirements outlined above, Magnolia performed significance 

analyses for NO2, CO, PM10, and PM2.5. The results of these analyses are summarized in table 4.11.1-7, 

along with the associated SIL for each pollutant.

TABLE 4.11.1-7

Summary of Preliminary Air Dispersion Modeling at the LNG Terminal and Significant Impact Levels for

Air Quality Impacts in Class II Areas

Air Pollutant

Maximum Annual 

Modeled Impact 

(SIL)

Maximum 24-hour 

Modeled Impact 

(SIL)

Maximum 8-hour 

Modeled Impact 

(SIL)

Maximum 1-hour 

Modeled Impact

(SIL)

Full Impact 

Analysis 

Required 

(Yes/No)

NO2 

a 1.35 μg/m3 

(1 μg/m3)

-- -- 31.14 μg/m3

(7.5 μg/m3)

Yes

CO -- -- 177.59 μg/m3

(500 μg/m3)

611.83 μg/m3

(2,000 μg/m3)

No

PM10 0.21 μg/m3

(1 μg/m3)

1.42 μg/m3 

(5 μg/m3)

-- -- No

PM2.5 0.19 μg/m3 

(0.3 μg/m3)

1.08 μg/m3

(1.2 μg/m3)

-- -- No

____________________

a NO2 is the compound regulated as a criteria air pollutant; however, significant emissions are based on the sum of all 

oxides of nitrogen. All impact (dispersion modeling) assessments for comparison to a NAAQS or PSD increment are 

based on NO2.
4-137

CO, PM10, and PM2.5 Significance Analysis Impacts: This analysis showed that the SILs for CO,

PM10, and PM2.5 would not be exceeded by impacts from the proposed LNG terminal. Since the modeled 

impacts do not exceed the SILs, the LNG terminal would not cause or significantly contribute to an 

exceedance of the CO, PM10, or PM2.5 NAAQS, and a full impact analysis is not required for these 

pollutants.

NO2 Significance Analysis Impacts: This analysis showed that the NO2 1‐hour and annual SILs 

would be exceeded by impacts from the proposed LNG terminal. Since the 1‐hour and annual SILs were 

exceeded, a NAAQS analysis was required to be performed for both the NO2 1‐hour and annual averaging 

periods. The impact analysis included an assessment of nearby sources within 31 miles of the LNG 

terminal’s area of impact. In the event that a potential NAAQS violation is identified, 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 LNG terminal would not cause or 

contribute to the potential NAAQS exceedance. In the case of the NO2 annual NAAQS analysis, the 

annual average design concentration is combined with the background concentration for each year for 

comparison to the NAAQS. Tables 4.11.1-8 and 4.11.1-9 show the results of this NAAQS assessment.

TABLE 4.11.1-8

Summary of NO2 1-Hour National Ambient Air Quality Standards Modeling Results

Pollutant

Averaging 

Period

Concentrations

NAAQS

Exceedance?

(Yes/No)

LNG Terminal 

Maximum

(μg/m3)

Background

(at LNG Terminal 

Max Location)

(μg/m3)

Total

(at LNG Terminal 

Max Location

(μg/m3)

SIL

(μg/m3)

NAAQS

(μg/m3)

NO2 1-Hour 5.45 192.54 197.99 7.5 188.7 No

TABLE 4.11.1-9

Summary of NO2 Annual National Ambient Air Quality Standards Modeling Results

Pollutant

Averaging 

Period Year

Model Predicted Total

(μg/m3)

NAAQS

(μg/m3)

NAAQS Exceedance?

(Yes/No)

NO2 Annual 2009 87.98 100 No

2010 87.94 100 No

2011 94.64 100 No

2012 89.09 100 No

2013 91.48 100 No

As shown in table 4.11.1-8, although the modeled concentrations exceeded the NO2 1-hour 

NAAQS, the facility contribution would be below the SIL; therefore, the LNG terminal would not cause 

or contribute to a violation of the NO2 1-hour NAAQS. As shown in table 4.11.1-9, the facility would not 

cause or contribute to a violation of the NO2 annual NAAQS.

For pollutants with a modeled concentration greater than the corresponding SIL, PSD regulations 

also require a PSD Increment Analysis. The PSD Increment analysis demonstrates that the proposed 

LNG terminal would neither cause nor contribute to an exceedance of federal ordinances on industrial 

expansion. As discussed above, the NO2 modeled concentrations exceeded the 1-hour and annual SILs. 
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Since a PSD Increment has not been promulgated for 1-hour NO2 impacts, the LNG terminal is only 

required to demonstrate compliance with the annual NO2 PSD Increment. The highest annual mean 

concentration was determined for each receptor for each year and compared to the PSD Increment. Table 

4.11.1-10 shows the results of the PSD Increment Analysis. Based on this analysis, the facility would not 

exceed PSD Increment for the modeled years. 

TABLE 4.11.1-10

Summary of NO2 Prevention of Significant Deterioration Increment Modeling Results

Year

Model Predicted Total Increment 

Consumed by PSD Sources

(μg/m3)

Class II PSD Increment

(μg/m3)

Impact Less than Increment?

(Yes/No)

2009 21.25 25 Yes

2010 21.17 25 Yes

2011 21.94 25 Yes

2012 22.76 25 Yes

2012 24.13 25 Yes

LNG Terminal Impacts on Regional Ozone

Cumulative impacts on regional ozone levels were also addressed through regional 

photochemical modeling performed for the LDEQ to determine the potential 8-hour ozone impact from 

the proposed emissions at the LNG terminal. The LNG terminal would be in Calcasieu Parish, which is 

currently designated as attainment for the 8-hour ozone NAAQS. However, it would be in proximity to

parishes in the Baton Rouge Metropolitan Statistical Area that have been designated as non-attainment for 

the 2008 8-hour ozone NAAQS, and to the Texas Houston/Galveston/Brazoria and Beaumont/Port Arthur 

areas, which are classified as ozone non-attainment/unclassifiable for the 2008 standard. As previously 

noted (see section 4.11.1.2), both the Lake Charles and Lafayette areas are vulnerable to being designated 

as non-attainment for ozone in the next few years.

No standard approach exists for modeling ozone impacts from discrete sources, and no 

significance thresholds have been established for ozone. The ozone modeling completed for the LNG 

terminal was conducted using recommendations provided by the EPA Region 6 and the LDEQ.

The potential 8-hour ozone impact from the LNG terminal was quantified using a regional ozone 

model, known as the Comprehensive Air Quality Model with Extensions (CAMx), in conjunction with 

background data from the Baton Rouge area. The LNG terminal’s potential impacts were evaluated both 

at existing ozone monitoring locations in Louisiana and Texas and at areas removed from the monitors. 

Based on the ozone modeling, the LNG terminal’s impact is estimated to contribute between less than 

0.1 and 0.3 parts per billion (ppb) of ozone in areas included in the modeling analysis. Based on the 

ozone modeling, the LNG terminal is estimated to impact daily maximum 8-hour average ozone 

concentrations in regions that have background ambient ozone concentrations of over 70 ppb by less than 

1 ppb. A review of modeled ozone levels at ozone monitor locations shows that the modeled maximum 

8-hour impacts from the LNG terminal are not likely to cause or contribute to an ozone impact that would 

exceed the 75 ppb ozone NAAQS.

LNG Terminal Hazardous Air Pollutant Impacts

LDEQ requires an ambient air impact analysis of toxic air pollutants if a proposed source is a 

major source of HAPs. Based upon the emission estimates summarized in table 4.11.1-6, the LNG 
4-139

terminal would not be a major source of HAPs; therefore, an ambient impact analysis for HAPs is not 

required. Based on the proposed level of HAP emissions, impacts from HAPs are expected to be 

insignificant.

LNG Terminal Greenhouse Gas Impacts

Based upon the emission estimates summarized in table 4.11.1-6, the LNG terminal would be a 

PSD major source of GHG emissions; therefore, Magnolia’s Title V and PSD permit application included 

a BACT assessment for GHG emissions from the facility. Magnolia has committed to complying with 

the GHG BACT requirements.

KMLP Facilities

The KMLP facilities would result in operational emissions from the proposed Compressor Station 

760 and fugitive emissions from pipeline blowdown events. These operational emissions and potential 

associated effects are discussed below.

Compressor Station 760

Compressor Station 760 would include some equipment that would operate continuously, and 

other equipment that would operate on an as-needed basis. The proposed emission generating sources at 

the compressor station would include:

 four natural gas-fired turbines;

 one fuel-gas heater;

 one natural gas-fired emergency generator engine; and

 five 7,050-gallon fixed roof storage tanks.

Emissions also would result from truck loading activities, pigging activities, pipeline blowdown

activities, traffic on facility haul roads and fugitive emissions from piping components, such as valves and 

pump seals. Estimated annual emission rates for the proposed equipment are provided in table 4.11.1-11.

Based on the emission estimates provided in table 4.11.1-11, Compressor Station 760 would be a 

Title V major source for CO, exceeding the major source threshold of 100 tpy. The facility would be 

considered a minor source of all other criteria pollutants, as well as HAP emissions. As described in 

section 4.11.1.3, because emissions would be above the PSD significant emission rates (presented in table 

4.11.1-3) for NOX, CO, PM10, PM2.5, and CO2e, these pollutants would be required to be addressed 

further. KMLP would be required to show compliance with the NAAQS for NOX, CO, PM10, and PM2.5

and to comply with the federal requirements for major sources of CO2e, as discussed below. 

KMLP submitted a PSD permit application for Compressor Station 760 to the LDEQ, based upon 

GHG emissions. Subsequent to the submittal of this application, on June 23, 2014, the U.S. Supreme 

Court reversed permitting regulations that subject a facility to PSD permit review for GHG emissions 

only. Because Compressor Station 760 would not be subject to PSD review for any other criteria 

pollutants, the proposed facility is not subject to PSD permitting. However, KMLP completed a PSD 

modeling analysis for the proposed facility along with the initial permit application with evaluations of 

compliance with applicable NAAQS and PSD increments for pollutants greater than PSD significant 

emission rates (CO, NOX, PM10, and PM2.5). The results of these the significance analyses for these 

pollutants are summarized in table 4.11.1-12, along with the associated SIL for each pollutant included in 

the analysis.
4-140

TABLE 4.11.1-11

Compressor Station 760 Estimated Annual Emission Rates

Equipment

Annual Emission Rates (tpy)

NOX CO SO2 PM10 PM2.5 VOC Total HAPs CO2e

Natural gas turbine 1 18.2 32.8 1.9 8.4 8.4 1.2 0.6 65,588

Natural gas turbine 2 18.2 32.8 1.9 8.4 8.4 1.2 0.6 65,588

Natural gas turbine 3 18.2 32.8 1.9 8.4 8.4 1.2 0.6 65,588

Natural gas turbine 4 18.2 32.8 1.9 8.4 8.4 1.2 0.6 65,588

Emergency engine 0.1 0.9 <0.1 <0.1 <0.1 0.2 <0.1 94

Fuel gas heater 0.4 0.3 <0.1 <0.1 <0.1 <0.1 <0.1 443

Fixed roof storage tanks --- --- --- --- --- 0.8 <0.1 ---

Fugitive leaking equipment --- --- --- --- --- 9.9 0.5 ---

Truck loading --- --- --- --- --- 1.0 <0.1 ---

Paved haul roads --- --- --- <0.1 <0.1 --- --- ---

Pigging --- --- --- --- --- 1.6 <0.1 ---

Blowdown --- --- --- --- --- 0.6 <0.1 ---

Total 73.3 132.4 7.6 33.7 33.7 18.9 3.1 262,889

TABLE 4.11.1-12

Summary of Preliminary Air Dispersion Modeling at Compressor Station 760 and Significant Impact Levels for 

Air Quality Impacts in Class II Areas

Air Pollutant

Maximum Annual 

Modeled Impact

(SIL)

Maximum 24-hour 

Modeled Impact

(SIL)

Maximum 8-hour 

Modeled Impact

(SIL)

Maximum 1-hour 

Modeled Impact

(SIL)

Full Impact Analysis 

Required

(Yes/No)

NO2 

a 0.2 μg/m3 

(1 μg/m3)

-- -- 5.8 μg/m3

(7.5 μg/m3)

No

CO -- -- 224 μg/m3

(500 μg/m3)

294 μg/m3

(2,000 μg/m3)

No

PM10 0.2 μg/m3

(1 μg/m3)

1.5 μg/m3 

(5 μg/m3)

-- -- No

PM2.5 0.1 μg/m3 

(0.3 μg/m3)

1.1 μg/m3

(1.2 μg/m3)

-- -- No

____________________

a NO2

is the compound regulated as a criteria air pollutant; however, significant emissions are based on the sum of all 

oxides of nitrogen. All impact (dispersion modeling) assessments for comparison to a NAAQS or PSD increment are 

based on NO2.
4-141

NOX, CO, PM10, and PM2.5 Significance Analysis Impacts: This analysis showed that SILs for 

NOX, CO, PM10, and PM2.5 were not exceeded by potential impacts from Compressor Station 760.

Because the modeled impacts do not exceed the SILs, operation of the compressor station would not 

cause or significantly contribute to an exceedance of either the NOX, CO, PM10, or PM2.5 NAAQS, and a 

full impact analysis is not required for these pollutants.

Meter Station Modifications

KMLP is not proposing to install any significant emission-generating units as a result of the 

proposed meter station modifications. Some minor fugitive VOC emissions may be generated during 

meter station operation associated with equipment leaks; however, these emissions are considered a result 

of operation of the existing meter stations, de minimis, and would not require an air permit.

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. Construction 

and operation of the proposed projects would affect overall noise levels in the vicinity of project 

components. 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 vegetation 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 preferred single value figure to describe sound levels that vary over time is Leq, 

which is defined as the sound pressure level of a noise fluctuating over a period of time, expressed as the 

amount of average energy. Ldn is defined as the 24-hour average of the equivalent average of the sound 

levels during the daytime (Ld – from 7:00 a.m. to 10:00 p.m.) and the equivalent average of the sound 

levels during the nighttime (Ln – 10:00 p.m. to 7:00 a.m.). 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 (dB) to 

account for people’s greater sensitivity to sound during nighttime hours. In general, if the sound energy 

does not vary over the given time period, the Ldn level will be equal to the Leq level plus 6.4 dB. The 6.4 dB 

difference between the Ldn and the Leq is a result of the 10 dB nighttime addition for the Ldn calculation.

Decibels (dB) are the units of measurement used to quantify the intensity of noise. To account

for the human ear’s sensitivity to low level noises the decibel values are corrected to weighted values 

known as decibels on 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. 
4-142

TABLE 4.11.2-1

Sound Levels and Relative Loudness

Noise Source or Activity

Sound Level 

(dBA) Subjective Impression a

Relative Loudness 

(perception of different 

sound levels)

Jet aircraft takeoff from carrier (50 feet) 140 Threshold of pain 64 times as loud

Loud rock concert near stage 120 Uncomfortably loud 16 times as loud

Jet takeoff (2,000 feet) 100 Very loud 4 times as loud

Garbage disposal / food blender (2 feet) 80 Loud Reference loudness

Vacuum cleaner (10 feet) 70 Moderate 1/2 as loud

Light auto traffic (100 feet) 50 Quiet 1/8 as loud

Quiet library, soft whisper (15 feet) 30 Very quiet 1/32 a loud

Wilderness with no wind or animal activity 25 Extremely quiet

0 Threshold of hearing

____________________

a Barnes et al., 1977; EPA, 1971

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 LNG terminal and Compressor Station 760. 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 LNG terminal or KMLP facilities.

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.” 

Applicable exemptions include the following:

 Section 18–99, paragraph 3: noises made by persons having obtained a permit; 
4-143

 Section 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 

 Section 18–100, paragraph 4 – Construction and Demolition: the operating of any 

equipment used in construction work within 165 feet of any residential or noise sensitive 

area (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.

Acadia Parish has adopted a noise ordinance (Code of Ordinances, Chapter 13, Article V – Loud 

and Unusual Noises) that establishes maximum permissible sound pressure levels for various land use 

types, as well as establishes limitations on construction noise. Table 4.11.2-2 provides maximum 

permissible sound pressure levels by land use type.

TABLE 4.11.2-2

Acadia Parish Sound Pressure Level Limits

District

Day – 7:00 a.m. to 11:00 p.m.

(dBA)

Night – 11:00 p.m. to 7:00 a.m.

(dBA)

Residential 50 40

Commercial 60 55

Industrial 80 75

____________________

Note: Acadia Parish code does not specify the metric for measuring sound pressure levels, but the values are presumed to 

represent Leq.

The proposed location of Compressor Station 760 would be in an agricultural area near three 

residences and several industrial facilities (28 meter stations, 2 compressor stations, and 2 natural gas 

processing plants are within 1 mile of the site). The definitions of districts within the Acadia Parish noise 

ordinances do not specifically address multi-use districts or agricultural residences. As such, KMLP 

designed the proposed compressor station to ensure compliance with the FERC’s noise standard, which is 

more stringent than the Acadia Parish sound pressure limit levels for both commercial and industrial 

zones. 

Section 13-87 of the Acadia Parish noise ordinance states that it is unlawful to conduct 

construction or non-emergency repair work between the hours of 10:00 p.m. and 7:00 a.m. within 500 feet 

of a residential or commercial zone (nearest residences to Compressor Station 760 include three 

homesteads that would be approximately 1,500 feet west of the site). Construction noise is limited to the 

maximum permissible noise level specified for industrial districts (see table 4.11.2-2) for the periods 

within which construction is to be completed pursuant to any applicable buildings permit.

4.11.2.2 Existing Sound Levels and Noise Sensitive Areas

LNG Terminal

Magnolia’s consultant (Ecology and Environment, Inc.) conducted a noise survey between 

September 23 and 25, 2013 to characterize the existing noise environment at the NSAs nearest to the 

LNG terminal site (see figure 4.11.2-1) (Ecology and Environment, Inc., 2013a). The results of the 

ambient noise survey as well as the distance and direction of each identified NSA from the LNG terminal

are provided in table 4.11.2-3.
Texas

Louisiana

Mississippi

Arkansas

NSA #1

NSA #2

NSA #3 3,820 feet

4,485 feet

7,075 feet

p Noise Sensitive Area

LNG Terminal

0 1,000 2,000

Feet

Figure 4.11.2-1

LNG Terminal

Nearby Noise Sensitive Areas

Calcasieu Parish, Louisiana

This information is for environmental review purposes only.

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\03\NSAs\NSA_LNG_Facility.mxd | REVISED: 03/24/2015 | SCALE: 1:20,000 DRAWN BY: JSSuess

LNG Terminal

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4-145

TABLE 4.11.2-3

LNG Terminal Facilities – Existing Noise Levels at Nearby Noise Sensitive Areas 

NSA

Distance from Terminal 

(feet)

Direction from 

Terminal

Average Daytime Leq

(dBA)

Average Nighttime Leq

(dBA)

Calculated Ldn

(dBA)

1 3,820 South 47 44 51

2 4,485 Southeast 49 45 52

3 7,075 East-southeast 44 40 47

KMLP Facilities

KMLP conducted a noise survey between June 3 and 11 and between September 17 and18, 2014 

to characterize the existing noise environment at the NSAs nearest to the proposed Compressor Station 

760 site (see figure 4.11.2-2). The results of the ambient noise survey as well as the distance and direction 

of each identified NSA from the compressor station site are provided in table 4.11.2-4.

TABLE 4.11.2-4

Compressor Station 760 – Existing Noise Levels at Nearby Noise Sensitive Areas 

NSA

Distance from Station 

(feet) Direction from Station

Average Daytime Leq

(dBA)

Average Nighttime Leq

(dBA)

Calculated Ldn

(dBA)

1 1,125 West-northwest 59 59 65

2 1,260 East-southeast 52 57 63

3 1,280 West-southwest 54 53 60

4 2,900 Northeast 49 58 64

4.11.2.3 Construction Noise Impacts and Mitigation

LNG Terminal

Construction activities at the LNG terminal would generate temporary increases in sound levels 

over a total of 45 months, which includes the primary 36-month construction period, as well as an 

additional 9 months until the LNG terminal is fully operational. Construction activities would occur 

predominantly during the day, between 7:00 a.m. and 7:00 p.m., Monday through Saturday. However, 

certain activities would occur up to 24 hours per day, 7 days per week. In particular, dredging may occur 

up to 24 hours per day, 6 days per week and pile driving could occur up to 10 hours per day, 7 days per 

week. Construction activities at the LNG terminal site would involve clearing and grading associated 

with site preparation; materials and equipment delivery; installation of the facility foundations (e.g., pile 

driving) and liquefaction trains; construction of the LNG loading and ship berthing facilities, LNG 

storage tanks and processing facilities, LNG truck loading facilities, and Magnolia Meter Station and 

interconnect pipeline; and site restoration, as described in detail in section 2.5.1. 

The most prevalent sound-generating equipment and activity during construction of the LNG 

terminal is anticipated to be pile driving, although internal combustion engines associated with general 

construction equipment and dredging would also produce sound levels that would be perceptible in the 

vicinity of the site. The various types of construction activities proposed at the LNG terminal and 

associated noise levels are described below. 
Texas

Louisiana

Mississippi

Arkansas

NSA #2

NSA #3

NSA #1

NSA #4

1,125 feet

1,260 feet

1,280 feet

2,900 feet

p Noise Sensitive Area

Compressor Station

0 250 500

Feet

Figure 4.11.2-2

Compressor Station 760

Nearby Noise Sensitive Areas

Acadia Parish, Louisiana

This information is for environmental review purposes only.

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\03\NSAs\NSA_Station760.mxd | REVISED: 03/24/2015 | SCALE: 1:9,250 DRAWN BY: JSSuess

Compressor

Station 760

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4-147

Facility Construction Activities

Noise levels resulting from construction would vary over time and would depend upon the 

number and type of equipment operating, the level of operation, and the distance between sources and 

receptors. Magnolia estimated construction equipment needs for site preparation (clearing and grading) 

and facility construction as well as the composite noise levels for these two activities (a composite noise 

level is typically used to describe the overall noise generated by multiple noise-generating units operating 

at the same time). Table 4.11.2-5 provides the estimated composite noise levels for site preparation and 

facility construction at various distances from the LNG terminal site.

TABLE 4.11.2-5

LNG Terminal – Construction Noise Estimates

Distance from Right-of-Way or 

Property Line (feet)

Site Preparation

Noise Level (dBA Lmax 

a

)

Facility Construction

Noise Level (dBA Lmax 

a

)

50 90 89

250 76 75

500 70 69

1,000 64 63

1,500 61 59

3,820 (NSA 1) 52 51

____________________

a Lmax is a sound measurement typically used with variable noise sources, such as construction equipment or vehicles, that 

corresponds to the maximum sound level observed during a measurement period or noise event (EPA, 1974).

The nearest NSA to the LNG terminal site is approximately 3,820 feet to the south. During site 

preparation activities, the composite noise level at the nearest NSA is estimated to be 52 dBA; during 

facility construction, the composite noise level at the nearest NSA is estimated to be 51 dBA. The current 

daytime noise level at the nearest NSA is 47 dBA (see table 4.11.2-3). Sound pressure levels are 

measured on a logarithmic scale; therefore, although the construction noise would, at times, be 

perceptible at the NSA, it would not be substantially above existing daytime noise levels. 

Pile Driving Activities

Magnolia anticipates that impact-type pile drivers would be used during construction of the 

proposed facilities, which may be installed using both land-based and floating platforms. Magnolia 

estimated the maximum sound level observed during a measurement period or noise event (Lmax) for one 

pile driver to be 101 dBA. Onshore piles would be driven by seven or eight hydraulic piling rigs. Marine 

piles would be driven by between two and four hydraulic pile rigs, which may include both land-based 

and floating rigs. Based upon the construction schedule provided by Magnolia (see table 2.5.1-1 in 

section 2.5.1.3), onshore pile driving to create the foundations for the LNG storage tanks and other 

process equipment foundations and structures would occur over a period of 10 months, and pile driving 

associated with construction of the LNG loading and ship berthing area would occur over a period of 

6 months. Based upon Magnolia’s current construction schedule, land and water-based pile driving 

would not occur simultaneously. Table 4.11.2-6 provides estimates of pile driving noise based upon the 

various proposed pile-driving scenarios.
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TABLE 4.11.2-6

LNG Terminal – Pile Driving Noise Estimates 

Distance from Pile Driving (feet)

Land-based 

Pile Driving Noise Level 

(dBA Lmax

a

)

Water-based 

Pile Driving Noise Level 

(dBA Lmax

a

)

50 110 107

3,820 (NSA 1) 72 69

4,485 (NSA 2) 71 68

7,075 (NSA 3) 67 64

____________________

a Lmax is a sound measurement typically used with variable noise sources, such as construction equipment or vehicles, that 

corresponds to the maximum sound level observed during a measurement period or noise event (EPA, 1974).

Pile driving is scheduled to occur over 10-hour shifts, 7 days per week over a total of about 

16 months; however, due to start-up coordination, actual pile driving operations are expected to occur for 

approximately 8 hours per day, 7 days per week. During land-based pile driving operations, the estimated 

sound level at the nearest NSA (NSA 1) when the maximum number of pile-driving platforms are in use

(8 land-based pile driving rigs) would be 72 dBA Lmax. During water-based pile driving operations, the 

corresponding sound level at NSA 1 when the maximum number of pile-driving platforms are in use 

(a total of 4 land-based or floating rigs) would be 69 dBA Lmax. These levels would correspond to a 

moderate sound level (similar to operation of a vacuum cleaner) on the Relative Loudness Scale presented 

in table 4.11.2-1 and would be clearly audible. Based on the estimates provided by Magnolia and because 

of the 16-month duration of the pile driving activities, these sound levels may have an adverse impact at 

the nearest NSAs. Therefore, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia should include in its

Pile Driving Noise Impact Mitigation Plan (see our recommended condition in 

section 4.6.2.2) measures to reduce pile driving noise (Lmax) to no greater than 

10 dBA over Leq ambient levels at the three nearest NSAs.

Vibration levels detectable to humans would not extend beyond about 500 feet from the pile 

driving operation (Maekawa, 1994). As described above, the three nearest NSAs range from about 

3,820 feet to 7,075 feet from the proposed pile driving activities. No structures were identified within 

500 feet of the proposed pile driving activities. 

The construction of the proposed facility, particularly pile driving, would also result in the 

generation and propagation of underwater noise energy. As referenced in section 4.6.2.2, Magnolia has 

not finalized pile driving plans, and an estimate of underwater noise associated with either land-based or 

in-water pile driving activities has not been provided. Magnolia stated that it does not anticipate that 

land-based pile driving activities would result in underwater noise levels in exceedance of levels that 

would result in fish injuries; however, the potential exists for water-based pile driving activities to exceed 

these levels. Therefore, FERC staff included a recommendation in section 4.6.2.2 regarding the 

development of a Pile Driving Noise Impact Mitigation Plan including noise monitoring, reporting 

requirements, and mitigation implementation triggers for underwater noise. 

With the implementation of our recommended hydroacoustic monitoring and mitigation 

measures, if needed, pile driving activities would not result in underwater noise levels that would cause 

injury to aquatic resources. As previously noted, pile driving activities would result in overland noise 

levels that would be clearly audible at the nearest NSAs. As currently proposed, these sound levels may 
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have an impact at the nearest NSAs over the course of pile driving activities. Our recommendation above 

addresses this.

Dredging Activities

Dredging activities may occur 24 hours per day, 7 days per week. Dredging would be 

accomplished by use of a hydraulic cutterhead suction dredge. Magnolia has estimated noise levels 

associated with the dredging activities to be approximately 60 to 80 dBA at a distance of 50 feet. 

Predicted noise levels attributable to dredging activities at the nearest NSAs would range from about 37 to 

41 dBA Leq, which are below existing ambient noise levels. Therefore, noise associated with dredging 

activities is not expected to be perceptible at the nearest NSAs.

Proposed Mitigation Measures and Conclusion

Magnolia has stated that it may implement one of more of the following mitigation measures to 

control construction noise:

 turn off idling equipment when not in use;

 install temporary acoustic barriers around stationary construction equipment, as feasible; and

 ensure that all equipment has sound control devices no less effective than those provided 

by the manufacturer.

Based upon the construction noise estimates provided by Magnolia, the maximum noise levels 

generated by construction activities, with the exception of pile driving activities discussed in further detail 

above (which we address with our recommendation), would be below the existing daytime background 

noise at the nearest NSA. Therefore, we conclude that construction of the LNG terminal would result in 

temporary and moderate noise impacts on residents and the surrounding communities.

KMLP Facilities

Construction activities associated with the header pipelines and meter station modifications 

would occur over a 3-month period, while construction of Compressor Station 760 would occur over a 

period of approximately 11 months. KMLP has stated that noisy construction activities would take place 

during the day, between 7:00 a.m. and 7:00 p.m., Monday through Friday. 

Construction activities associated with the KMLP facilities would involve clearing and grading 

associated with site preparation; materials and equipment delivery; installation of the header pipelines; 

construction of aboveground facilities associated with Compressor Station 760; and installation of 

additional metering equipment, pigging equipment, and interconnects at the existing meter stations, as 

described in detail in section 2.5.2. 

The most prevalent sound-generating equipment and activity during construction of the KMLP 

facilities is anticipated to be the operation of internal combustion engines associated with general 

construction equipment. Noise levels resulting from construction would vary over time and would 

depend upon the number and type of equipment operating, the level of operation, and the distance 

between sources and receptors. KMLP estimated equipment needs for construction of the KMLP 

facilities as well as the resulting composite noise level from construction activities. Table 4.11.2-7

provides the estimated composite noise levels from construction of the KMLP facilities at various 

distances from the property boundary or right-of-way. 
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TABLE 4.11.2-7

KMLP Facilities Construction – Noise Estimates

Distance from the Right-of-way or Property Line (feet) Estimated Noise Level Leq (dBA)

50 83

100 79

200 74

400 69

800 63

1,600 58

3,200 52

6,400 46

The nearest NSA (NSA 1) to Compressor Station 760 (where noise generating activities would 

occur over the longest period of time) is approximately 1,125 feet west of the site. During construction 

activities, the composite noise level at NSA 1 is estimated to be between 58 Leq (dBA) and 63 Leq (dBA). 

The current daytime noise level at this NSA is 59 dBA Leq (see table 4.11.2-4). Although construction 

noise would, at times, be perceptible at NSA 1, it would not be substantially above existing daytime noise 

levels. Based upon the distance to NSAs 2 and 3 from the compressor station site and the existing 

background noise levels at these two locations, noise attributable to the construction activities is estimated 

to be lower than the current background noise levels and would, therefore, likely be imperceptible at the 

NSAs. Therefore, we conclude that construction of the KMLP facilities would result in temporary and 

minor noise impacts on residents and the surrounding communities.

4.11.2.4 Operation Noise Impacts and Mitigation

LNG Terminal

Operation of the LNG terminal would produce noise on a continual basis. Magnolia performed 

modeling to calculate noise levels that would be generated by operation of the LNG terminal. Sound 

level data for the proposed equipment were obtained either from vendors or from measurements at other 

LNG facilities. The modeling also included three noise mitigation measures (gas turbine exhaust silencer,

boil-off gas building enclosures, and liquefaction train pipe insulation), which Magnolia has committed to 

implementing in the facility design. Table 4.11.2-8 provides the estimated equipment quantities and 

sound power levels used in the modeling. Table 4.11.2-9 presents the results of the modeling, along with 

a comparison with the existing ambient noise level, the expected noise level during operation of the LNG 

terminal compared to the ambient noise level, and the resulting increase in ambient noise level due to 

operation of the LNG terminal. Based on these estimates, the noise generated by the operation of the 

LNG terminal is likely to be slightly perceptible at NSAs 1 and 2, but imperceptible at NSA 3.
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TABLE 4.11.2-8

LNG Terminal Operation – Equipment Quantities and Sound Power Levels

Equipment Quantity Sound Power Level Per Item (dBA)

Gas turbine compressor/generator package 8 105

Gas turbine compressor exhaust 8 135

Solution cooler fan unit 128 103

Cooler fan 40 94

Steam generator 8 105

Amine charge pumps 8 102

Miscellaneous pumps 54 101

Instrument air package 12 98

Boil-off gas compressor 5 112

Boil-off gas compressor motor 5 108

Ammonia compressor 8 85

Liquefaction train piping 4 116

TABLE 4.11.2-9

LNG Terminal Operation – Composite Noise Levels at Nearby Noise Sensitive Areas

NSA

Distance and Direction 

from LNG Terminal

(feet)

Existing Ambient Ldn

(dBA)

Predicted LNG Terminal 

Contribution Ldn

(dBA)

Ambient + LNG 

Terminal Ldn

(dBA) a

Predicted Increase 

in Ambient Noise 

Level (dBA)

1 3,820 south 51 46 52 1

2 4,485 southeast 52 45 53 1

3 7,075 east-southeast 47 24 47 0

____________________

a Sound pressure levels are measured on a logarithmic scale; therefore, the predicted increase in ambient noise level at the 

NSAs during operation of the LNG terminal would not be the sum of the two noise levels.

The results of the noise impact analysis indicate that the noise attributable to the project would be 

lower than the FERC sound level requirement of 55 dBA Ldn at the nearest NSA. We recognize, 

however, that actual results may be different from those obtained from modeling. Therefore, we 

recommend that:

 Magnolia make all reasonable efforts to ensure that predicted noise levels during 

operation of the LNG terminal are not exceeded at nearby NSAs and should file 

with the Secretary a full load noise survey no later than 60 days after each of the 

first three liquefaction trains is placed into service. If the noise attributable to the 

operation of the LNG terminal exceeds an Ldn of 55 dBA at any nearby NSAs, 

Magnolia should reduce operation of the LNG terminal or install additional noise 

controls until a noise level below an Ldn of 55 dBA at nearby NSAs is achieved. 

Magnolia 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.
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In addition, we recommend that:

 Magnolia file a noise survey with the Secretary no later than 60 days after placing 

the entire LNG terminal into service. If a full load condition noise survey is not 

possible, Magnolia should provide an interim survey at the maximum possible 

horsepower load within 60 days of placing the LNG terminal into service and 

provide the full load survey within 6 months. If the noise attributable to the 

operation of all of the equipment at the LNG terminal under interim or full 

horsepower load conditions exceeds an Ldn of 55 dBA at any nearby NSAs, Magnolia 

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. Magnolia should

confirm compliance with the above requirement by filing an additional noise survey 

with the Secretary no later than 60 days after it installs the additional noise controls.

The purpose of a flare system is to safely and reliably protect plant systems from overpressure 

during start-up, shutdown, plant upsets, and emergency conditions. Magnolia anticipates that flaring 

would occur for approximately 5 days during startup of the LNG terminal. During operation, use of the 

flares would only occur during process upset conditions, which Magnolia anticipates would be no more 

than 12 hours during the first year of operation and no more than 6 hours in each subsequent year (each 

flaring event is expected to occur for between 15 and 60 minutes). The flaring creates noise with a lowpitched ‘roaring’ character. Magnolia has estimated the peak sound pressure level for a high pressure 

flare as measured at 1,500 feet from the flare to be 80 dBA. The estimated sound pressure level at the 

nearest NSA during a flaring event would be 72 dBA. Based upon the Relative Loudness Scale presented 

in table 4.11.2-1, this would be a moderate sound level impact, which Magnolia anticipates would occur 

no more than 12 hours during the first year of operation and no more than 6 hours in each subsequent year

(each flaring event is expected to occur for between 15 and 60 minutes).

Vessel traffic associated with operation of the LNG terminal would generate underwater sounds. 

Cargo vessels, which are in the same category as LNG vessels, are known to emit high levels of low 

frequency sound (6.8 to 7.7 hertz at 181 to 190 decibels (re: 1 μPa)) capable of traveling long distances 

(Richardson, et al., 1995). Noise generated by LNG vessels is generally omni-directional, emitting from 

all sides of the vessel (Whale and Dolphin Conservation Society, 2004). However, noise levels are 

greatest on the sides of the ship and weakest on the front and rear of the ship. Above-water noise 

associated with the LNG vessels would be similar to other large vessel traffic along the waterway and 

would result in temporary and minor noise impacts along the vessel transit route.

KMLP Facilities

The primary source of operational noise associated with the KMLP facilities would be from 

Compressor Station 760. Operation of Compressor Station 760 would produce noise on a continual basis. 

KMLP performed modeling to calculate noise levels that would be generated by operation of Compressor 

Station 760. Sound level data for the proposed equipment were obtained from vendor information and 

included combustion air intake, exhaust, and turbine/compressor-radiated mechanical noise. The 

modeling also assumed the installation of noise mitigation measures, including acoustical enclosures and 

barriers; pipe insulation; and acoustical-rated wall, ceiling, and door assemblies for the compressor 

building. Table 4.11.2-10 presents the results of the modeling, along with a comparison with the existing 

ambient level, the expected future noise level after adding the facility noise to the ambient, and the 

increase in ambient level as a result of adding the facility. Based on these estimates, the noise generated 

by the operation of Compressor Station 760 is likely to be slightly perceptible at NSAs 2 and 3, but

imperceptible at NSAs 1 and 4. Kinder Morgan also evaluated the proposed equipment and determined 

that the proposed compressor station would result in no detectible increase in vibration at nearby NSAs.
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TABLE 4.11.2-10

Compressor Station 760 Operation – Noise Levels at Nearby Noise Sensitive Areas

NSA

Distance and Direction

from Station (feet)

Existing 

Ambient Ldn

(dBA)

Predicted Compressor 

Station Contribution Ldn

(dBA)

Ambient + Compressor 

Station Ldn

(dBA) a

Predicted Increase in 

Ambient Noise Level 

(dBA)

1 1,125 west-northwest 65 55 65 0

2 1,260 east-southeast 63 55 64 1

3 1,280 west-southwest 60 54 61 1

4 2,900 northeast 64 50 64 0

____________________

a Sound pressure levels are measured on a logarithmic scale; therefore, the predicted increase in ambient noise level at the 

NSAs during operation of Compressor Station 760 would not be the sum of the two noise levels.

The results of the noise impact analysis indicate that the noise attributable to operation of 

Compressor Station 760 would be in compliance with the FERC sound level requirement of 55 dBA Ldn

at the nearest NSA. We recognize, however, that actual results may be different from those obtained from 

modeling. Therefore, we recommend that:

 KMLP file a noise survey with the Secretary no later than 60 days after placing 

Compressor Station 760 in service. If a full load condition noise survey is not 

possible, KMLP should provide an interim survey at the maximum possible 

horsepower load within 60 days of placing the station into service and provide the 

full load survey within 6 months. If the noise attributable to the operation of all of 

the equipment at Compressor Station 760 under interim or full horsepower load 

conditions exceeds an Ldn of 55 dBA at any nearby NSAs, KMLP 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. KMLP should confirm compliance 

with the above requirement by filing an additional noise survey with the Secretary 

no later than 60 days after it installs the additional noise controls.

The KMLP facilities also include modifications to six existing meter stations in Acadia and 

Evangeline Parishes. There are several NSAs within 0.5 mile of the all of the six existing meter stations. 

Because the changes proposed to these metering stations would be limited to the installation of valves and 

piping to allow for the bi-directional measurement of gas flow, installation of a pig launching facility, 

and/or interconnects to the proposed header pipelines, it is unlikely that the modifications would 

markedly alter existing noise levels. However, KMLP has committed to installing noise mitigation 

measures (e.g., low noise valves, acoustical insulation, noise barriers, and blowdown silencer) as needed 

to ensure that noise attributable to the meter stations does not exceed 55 dBA Ldn at the nearest NSA.

4.12 RELIABILITY AND SAFETY

4.12.1 Regulatory Oversight

Multiple federal agencies share regulatory authority over the siting, design, construction, and 

operation of LNG import and export terminals.

The FERC authorizes the siting and construction of LNG import and export facilities under the 

NGA and delegated authority from the DOE. The FERC requires standard information to be submitted to 

perform safety and reliability engineering reviews. FERC’s filing regulations are codified in 

18 CFR 380.12(m) and (o) and require each applicant to identify how its proposed design would comply 
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with the 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 the DOT’s regulations, to assess whether or not 

a facility would have a public safety impact. As a cooperating agency, the 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 the 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.

The DOT establishes federal safety regulations 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 regulations are codified in 49 CFR 193. 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 the DOT, impose more stringent safety requirements than 

those in Part 193.

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. The 

Coast Guard regulations over LNG facilities are codified in 33 CFR Parts 105 and 127. In accordance 

with 33 CFR 127, the Coast Guard has provided FERC with the LOR for the project in a letter dated 

February 12, 2015,

17 regarding the suitability of the waterway for the type and frequency of planned LNG 

carrier traffic. 

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. 

The EPA establishes federal safety regulations to prevent the accidental release and to minimize 

the consequences of any such release of extremely hazardous substances under the CAA. These 

regulations are codified in 40 CFR 68, Chemical Accident Prevention Provisions, also called the EPA’s

Risk Management Program (RMP). Typically, these regulations would not apply to LNG facilities as 

clarified in the EPA’s preamble to its final rule in 63 Federal Register 640-645 (January 6, 1998), that 

exempted substances in transportation, including storage incident to transportation, subject to oversight or 

regulation under 49 CFR 193. This would include facilities used to liquefy natural gas or used to transfer, 

store, or vaporize LNG in conjunction with pipeline transportation. However, the EPA has indicated that 

this exemption did not envision the use of toxic materials above threshold quantities to liquefy natural 

gas. Magnolia’s proposed use of approximately 140,000 pounds of anhydrous ammonia (ammonia) in 

each train (4 trains) would be above the 10,000-pound threshold listed in the EPA’s RMP regulations (40 

CFR §68.130). Due to the quantities of ammonia stored on site, the EPA has asserted their jurisdiction 

over Magnolia’s facility. 

 

17 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
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The Occupational Safety and Health Administration (OSHA) establishes federal safety standards 

for the protection of the health and safety of on-site personnel under the Occupational Safety and Health 

Act. These standards are codified in 29 CFR 1910.119, Process Safety Management of Highly Hazardous 

Chemicals (PSM). Typically, LNG facilities would not be subjected to PSM regulations as clarified in 

letter issued on October 30, 1992 and December 9, 1998, which precluded the enforcement of PSM 

regulations over gas and LNG transmission and distribution facilities. However, this letter stated that the 

DOT regulations indicate that fire and explosion hazards were adequately covered and did not reference 

the potential use of toxic hazards. Magnolia’s proposed use of approximately 140,000 pounds of 

ammonia in each train would be above the 10,000-pound threshold listed in OSHA’s PSM regulations (29 

CFR §1910.119 App A). Due to the quantities of ammonia stored on site, OSHA has asserted their 

jurisdiction over Magnolia’s facility. 

As part of the review required for a FERC authorization, Commission staff must ensure that all 

proposed facilities would operate safely and securely. The design information that must be filed in the 

application to the Commission is specified by 18 CFR 380.12 (m) and (o). The level of detail necessary 

for this submittal requires the project sponsor to perform substantial front-end engineering of the 

complete facility. The design information is required to be 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 DOT, Coast Guard, and EPA are participating as cooperating agencies, and 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.

4.12.2 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.

18

 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 

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 

 

18 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.
4-156

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, 

Magnolia 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.

For past incidents of facilities handling ammonia, over 1,200 ammonia refrigeration incidents 

have occurred at ammonia facilities regulated under the EPA’s RMP between 1994 and 2013. These

incidents have resulted in 84 injuries to the public and 1 public fatality. Lessons learned from these 

incidents have resulted in updates to codes and standards to reduce the risk of any incident from 

impacting the public. Recently on January 15, 2015, the Chemical Safety Board released a report 

investigating a release of 32,000 pounds of ammonia at Theodore, Alabama on August 23, 2010, after 

hydraulic shock caused a pipe to catastrophically fail.

19

 We are recommending an evaluation of dynamic 

surge to prevent failures associated with hydraulic shock. Additional recommendations have been placed 

on Magnolia’s proposed ammonia systems design and mitigation measures to further reduce the risk of 

any incidents from impacting the public. 

Hazards Associated with the Proposed Equipment

Before liquefaction, Magnolia 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. Additionally, the feed gas may contain pentane and heavier hydrocarbons, including freezable 

aromatic hydrocarbons such as benzene and cyclohexane. Although a small amount is expected, they are 

still considered hazardous substances.

Magnolia proposes a design capacity to handle up to 4 ppm by volume H2S, 2 percent by volume 

CO2, and trace amounts of Hg. 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 methyl diethanolamine (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 240 ppm by mole H2S and 99.98 mole percent CO2 would be separated 

from the contaminated amine solution and routed to a H2S scavenger unit. The H2S scavenger unit would

reduce the H2S content to 0.1 ppm. Magnolia expects to replace the H2S adsorbent material once every 

 

19 “Key Lessons for Preventing Hydraulic Shock in Industrial Refrigeration Systems,” CSB Safety Bulletin No. 2010-13-A-AL, 

http://www.csb.gov/assets/1/19/final_CSB_CaseStudy_Millard_0114_0543PM.pdf, (January 15, 2015).
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9.5 months. The resulting waste gas stream would then be sent to the Thermal Oxidizer for treatment 

prior to discharge to the atmosphere. 

Following CO2 and H2S removal, the water-saturated feed gas stream would be cooled using the 

auxiliary refrigeration system and would pass through a knock-out separator to remove bulk H2O. Then 

the feed gas would flow through the molecular sieve vessels to lower H2O content to less than 0.5 ppm. 

The molecular sieve vessels would regenerate via a side stream of heated dry gas. The spent regeneration 

gas would then be routed to the high pressure fuel gas system. After H2O removal, mercury in the feed 

gas would be removed by absorption in non-regenerative mercury guard beds. Magnolia expects to 

replace the mercury adsorbent once every 15 years (per LNG train). Maintenance and safety procedures 

would cover the proper replacement of the spent adsorbent. 

In addition to the removal of H2S, CO2, H2O, and Hg, Magnolia would remove heavier 

hydrocarbons that may be present in the feed gas. During this removal process, heavy hydrocarbons 

including benzene, toluene, ethylbenzene, and xylenes (BTEX) would be extracted and the heavy liquids 

would be vaporized and used as auxiliary boiler fuel. The BTEX would be 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. In the event the BTEX vaporizer is out of service, any 

liquid BTEX would be contained within the Heavy Hydrocarbon ISO Container. A loss of containment 

from the Heavy Hydrocarbon ISO Container would primarily result in a liquid release. 

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 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 or toxic 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

A loss of the containment is the initial event that results in all other potential hazards. The initial 

loss of containment can result in a liquid and/or gaseous release with the formation of vapor at the release 

location, as well as from any liquid that pooled. The fluid released may present low or high temperature 

hazards, and may result in the formation of toxic and flammable vapors. The extent of the hazard will 

depend on the material released, the storage and process conditions, and the volumes released.

Magnolia would store the following on site: LNG at atmospheric pressure and at a cryogenic 

temperature of about –260 °F; ethane at ambient temperature and 535 pounds per square in gauge (psig); 

compressed liquid n-butane at ambient temperature and 261 psig; liquid nitrogen at about –320 °F and 

116 psig; and ammonia would be provided via ammonia tank trucks. The temperature of the amine 

process used to pretreat the feed gas would range from 109 °F to 260 °F. The temperature of natural gas 

liquids (NGL) in the heavy hydrocarbon removal process would be as low as –44 °F. The mixed 

refrigerant process stream would consist of nitrogen, methane, ethane, and n-butane. Cryogenic 

temperatures as low as –253 °F would occur within the mixed refrigerant process stream used to liquefy 

the feed gas. The ammonia refrigeration process would operate in temperatures as low as 2.8 °F.

Loss of containment of LNG, liquid nitrogen, and mixed refrigerant 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 to the 
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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, liquid nitrogen, and portions of the mixed refrigerant 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 (–296 oF) 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.20 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, n-butane, liquid nitrogen, mixed refrigerant, 

NGL, and ammonia would vaporize on release from any storage or process facilities. Depending on the 

size of the release, cryogenic liquids 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 270 ft3 of gas for each cubic foot of liquid. 

n-Butane will produce about 230 ft3 of gas for each cubic foot of liquid. Liquid nitrogen will produce 

about 700 ft3 of 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 ft3 of gas for each 

cubic foot of liquid. Ammonia will produce about 900 ft3 of gas for each cubic foot of liquid. 

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, an 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 an 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). An 

ethane release could form a denser-than-air vapor cloud that sinks to the ground. As the ethane vapor 

cloud disperses downwind and mixes with warm surrounding air, it would become neutrally buoyant. An 

 

20 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.
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n-butane release would form a denser-than-air vapor cloud that would sink to the ground; however, 

n-butane would remain denser than the surrounding air, even after warming to ambient temperatures. 

Any NGL release would form a denser-than-air vapor cloud, even after warming to ambient temperatures. 

An ammonia release would initially form a denser-than-air vapor cloud that sinks to the ground. As the 

ammonia cloud disperses downwind and mixes with warm surrounding air, it may raise into the 

atmosphere. 

A vapor cloud formed following an accidental release would continue to be hazardous until it 

dispersed below toxic levels and/or flammable limits. Toxicity is primarily dependent on the airborne 

concentration of the toxic component 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.21 Other federal agencies, such as the DOE, EPA, and NOAA, use AEGLs and ERPGs as the 

primary measure of toxicity.

22, 23, 24

There are three AEGLs and three 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 above which it is predicted 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. 

The EPA directs the development of AEGLs in a collaborative effort consisting of committee 

members from public and private sectors across the world. FERC staff uses AEGLs preferentially as they 

are more inclusive and provide toxicity levels at various exposure times (10 minutes, 30 minutes, 1 hour, 

4 hours, and 8 hours). The use of AEGLs is also preferred by the DOE and NOAA. Under the RMP 

regulation, the EPA currently requires the determination of distances to toxic concentrations based on 

 

21 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-exposure-hazardous-air-pollutants, 

July 3, 2014.

22 U.S. Department of Energy, Temporary Emergency Exposure Limits for Chemicals: Methods and Practice, DOE Handbook, DOE-HDBK1046-2008, August 2008.

23 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.

24 U.S. National Oceanic and Atmospheric Administration, Public Exposure Guidelines, http://response.restoration.noaa.gov/oil-andchemical-spills/chemical-spills/resources/public-exposure-guidelines.html, December 3, 2013.
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ERPG-2 levels.

25, 26 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) for a list 

of chemicals. These toxic concentration endpoints are comparable to AEGLs endpoints. The endpoints for 

various toxic components are presented in tables 4.12.2-1 and 4.12.2-2 below for both AEGL and ERPG.

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.

TABLE 4.12.2-1

Acute Exposure Guideline Levels of Various Material Components (in ppm) a

Material Components

Acute Exposure 

Guideline Level 10 minutes 30 minutes 1 hour 4 hours 8 hours

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 b 1,100 800 400 200

AEGL 3 9,700 c 5,600 b 4,000 b 2,000 b 990

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 d AEGL 1 67 67 67 67 67

AEGL 2 1,400 b 760 560 310 250

AEGL 3 10,000 c 5,200 b 3,700 b 1,800 b 1,400 b

Xylenes AEGL 1 130 130 130 130 130

AEGL 2 2,500 b 1,300 b 920 b 500 400

AEGL 3 7,200 c 3,600 b 2,500 b 1,300 b 1,000 b

____________________

a U.S. Environmental Protection Agency, Acute Exposure Guideline Levels, http://www.epa.gov/oppt/aegl/pubs/

chemlist.htm, October 3, 2014. 

b Greater than or equal to 10 percent LFL.

c Greater than or equal to 50 percent LFL.

d Toluene AEGLs updated in 2014. Magnolia’s toluene toxicity modeling is based on previous 10-minute values of 200 

ppm for AEGL-1; 3,100 ppm for AEGL-2; and 13,000 ppm for AEGL-3.

 

25 The EPA has issued a request for information that is exploring the use of AEGL in lieu of ERPG. Available online at 

https://www.federalregister.gov/articles/2014/07/31/2014-18037/accidental-release-prevention-requirements-risk-management-programsunder-the-clean-air-act-section. 

26 RMP toxic endpoints are based on ERPG-2 levels where these levels are available. For substances that do not have established ERPG-2 

levels, the toxic endpoint is the level of concern from the EPA’s 1987 Technical Guidance for Hazards Analysis.
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TABLE 4.12.2-2

Emergency Response Planning Guidelines for Various Material Components (in ppm) a

Material Components ERPG-1 ERPG-2 ERPG-3

Ammonia 25 b 150 c 1,500 c

Benzene 50 b 150 1,000

Hydrogen Sulfide 0.1 b 30 100

Toluene 50 b 300 1,000

Xylenes None available None available None available

____________________

a American Industrial Hygiene Association (AIHA), 2014 ERPG/WEEL Handbook, https://www.aiha.org/getinvolved/AIHAGuidelineFoundation/EmergencyResponsePlanningGuidelines/Pages/default.aspx, 2014. 

b Odor detectable near ERPG-1

c In 1992, the EPA RMP and OSHA PSM regulations used values from the 1988 and 1991 AIHA ERPG levels. At the time, 

ERPG-2 was 200 ppm and ERPG-3 was 1,000 ppm for ammonia. 

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 4.12.2-3. 

TABLE 4.12.2-3

Flammable Properties a

Material Component Flash Point

LFL

(percent volume)

UFL

(percent volume)

Methane –283 °F 5.0 15.0

Ethane –211 °F 3.0 12.5

n-Butane –76 °F 1.8 8.5

Ammonia –71 °F b 15.0 28

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 12 °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 4.3 c 45.5 c

____________________

a Society of Fire Protection Engineers, The SFPE Handbook of Fire Protection Engineering, Fourth Edition, 2008

b SIGTTO, Liquefied Gas Fire Hazard Management, First Edition, 2004

c Air Liquide Gas Encyclopedia, 2013

While ammonia is combustible, it has a very narrow flammability range and is not easy to ignite. 

As a result, ammonia is regulated based upon its toxicity. Under ambient conditions, ammonia would be 

a toxic gas, and exposure to ammonia vapors could be hazardous to human health if inhaled at high 
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concentrations. Without properly designed, constructed, operated, and maintained ammonia refrigerant 

systems, a release could disperse downwind and cause exposure injuries, including death, to the public.

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. Magnolia has 

modeled the extent of the potential vapor dispersion hazards for the project, which is discussed in 

section 4.12.5.

Flammable Vapor Ignition

If the flammable portion of a vapor cloud encounters an ignition source, a flame would propagate 

through the flammable portions of the cloud. In most circumstances, the flame would be driven by the 

heat it generates. This process is known as a deflagration, or a flash fire, because of its relatively short 

duration. However, exposure to a deflagration, or flash fire, can cause severe burns and death, and can 

ignite combustible materials within the cloud. Magnolia 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. Magnolia 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 will transition to a pool or jet fire back at 

the source. If ignition occurs soon after the release begins, a fireball may 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. Magnolia has modeled the extent of the potential 

radiant heat hazards from a pool fire for the project, which is discussed in section 4.12.5.5. 

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 

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.
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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, Magnolia would take measures to mitigate the vapor dispersion and ignition into confined 

areas, such as buildings. Magnolia 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.27 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. Magnolia proposes to use methane (low 

reactivity), ethane (medium reactivity), and n-butane (medium reactivity) in the mixed refrigerant stream. 

In addition, the NGL process stream 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.

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, 

 

27 Pierorazio, A.J., Thomas, K., Baker, Q.A., Ketchum, D.E., An Update to the Baker–Strehlow–Tang Vapor Cloud Explosion Prediction 

Methodology Flame Speed Table, Process Safety Progress (Vol.24, No.1), March 2005.
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failure of a pressurized vessel when the liquid is at a temperature significantly above its normal boiling 

point could result in a boiling-liquid-expanding-vapor explosion (BLEVE). BLEVEs can produce 

overpressures when the superheated liquid rapidly changes from a liquid to a vapor upon the release from 

the vessel. BLEVEs of flammable fluids may also ignite upon its release and cause a subsequent fireball. 

Discussion of these hazards and potential mitigation are in section 4.12.5 for the project facilities. 

Magnolia also has mitigated the risk for cascading event hazards for the project, which is also 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;

 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 
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further used to minimize impacts to public safety. As discussed in section 4.12.4, the DOT’s regulations 

in 49 CFR 193, Subpart B require a siting analysis be performed by Magnolia.

As part of the application, Magnolia provided a FEED for the project. In developing the FEED, 

Magnolia performed a hazard identification (HAZID) analysis on the project’s preliminary design based 

on the proposed plot plans, process flow diagrams, and heat and material balances. The HAZID analysis 

identifies potential hazards in the early stage of the project’s design that could produce undesirable 

consequences through the occurrence of an incident by evaluating the materials, systems, process, and 

plant design. In addition, we have analyzed the information filed by Magnolia 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 as well as ASME B31.5 in 

accordance with IIAR standards for ammonia refrigerant piping. The ammonia piping would consist of 

welded connections on the majority of the piping connections to minimize the possibility of flange leaks. 

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). Both 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 mph, which converts to 

183 mph at a 3-second gust per 49 CFR §193.2067.

28

 The ground surface of the liquefaction facilities 

would be elevated to about 24 feet above NAVD 88 in order to be above 12 and 17 feet for the 100- and 

500-year storm flood elevations. The LNG storage tanks would be 17 feet above NAVD 88 and would 

have a secondary containment wall elevated to about 30 feet above NAVD 88. The dock would be 

44 feet below NAVD 88 and the loading platform would be 30 feet above NAVD 88. The proposed site 

would be located 22 miles north of the Gulf of Mexico shoreline. 

Magnolia has consulted with Lake Charles Regional Airport and submitted FAA 

Form 7460-1_2017 to notify the FAA of any proposed construction or alterations associated with the 

project. The proposed facility would be located outside of the flight path from the airport and would be 

approximately 22,000 feet from the secondary runway. Magnolia’s design does not include any structure 

at or over 200 feet above ground level and Magnolia does not anticipate any hazard to air travel from 

structures or flare operation during startup, shutdown, and upset conditions. On February 17, 2015, the 

FAA issued a determination of no hazard to air navigation.

Magnolia 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. 

Magnolia 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 Magnolia 

 

28 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 0.36percent probability of 

exceedance in a 50-year period for the site based on ASCE 7-05 wind speed return period conversions.
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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 made recommendations for measures such as labeling of 

instrumentation and valves, piping, and equipment and car-seals/locks, to address human factor 

considerations and improve facility safety. Magnolia would also install robust barricades to prevent 

vehicles from impacting ammonia equipment. We also have made a recommendation to ensure an alarm 

management program would be in place to ensure effectiveness of the alarms.

Safety valves and instrumentation would be installed to monitor, alarm, shutdown, and isolate 

equipment and piping during process upsets or emergency conditions. Safety instrumented systems 

would comply with International Society for Automation (ISA) Standard 84.01 and other recommended 

and generally accepted good engineering practices. We also made recommendations on the design, 

installation, and commissioning of instrumentation and emergency shutdown equipment to ensure 

appropriate cause and effect alarm or shutdown logic and enhanced representation of the emergency 

shutdown valves in the facility control system. In addition, Magnolia would install remotely actuated 

shut-off valves to enable rapid isolation of ammonia inventories, remote isolation capability on the 

ammonia truck unloading valve, and excess flow valves on ammonia truck liquid and vapor transfer lines

to limit the quantity of ammonia releases. 

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, 526, 527, and

other recommended and generally accepted good engineering practices. In addition, we made 

recommendations to ensure the design and installation of pressure and vacuum relief devices are 

adequate. 

The security requirements for the 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 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 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;
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 ensuring the Transportation Worker Identification Credential program is properly 

implemented; and

 reporting all breaches of security and security incidents to the National Response Center.

Magnolia proposed to install a security fence with limited access openings as well as security 

cameras to monitor the marine facilities, the fence line, active access points, the waters along the 

proposed facility, and the facility interior. The site would be illuminated with not less than 2.2 lux 

between sunset and sunrise. Intrusion detection systems would be installed at the security fence and in all 

buildings. In addition, under 33 CFR 105, Magnolia would be required to submit a Facility Security Plan 

to the Coast Guard for review and approval before commencement of operations. 

In the event of a release, drainage systems from LNG storage and liquefaction process facilities 

would direct a spill away from equipment in order to minimize flammable vapors from dispersing to 

confined, occupied, or public areas and to minimize heat from impacting adjacent equipment and public 

areas if ignition occurs. In addition, Magnolia proposes to install grading under vessels to divert any 

ammonia spilled on the ground to containment sumps. 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. 

Magnolia 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 fireproofing and cryogenic protection, proposed to prevent failure of structural 

supports of equipment and pipe racks, would comply with NFPA 59A and other recommended and 

generally accepted good engineering practices. Magnolia would also install hazard detection systems to 

detect, alarm, and alert personnel in the area and control room to initiate an emergency shutdown and/or 

initiate appropriate procedures, and would meet NFPA 72, ISA 12.13, and other recommended and 

generally accepted good engineering practices. Magnolia would install ammonia detection systems 

throughout the plant that would initiate automated shutdown systems in the event of an ammonia release.

Hazard control devices would be installed to extinguish or control incipient fires and releases, and

would meet NFPA 59A and NFPA 10, 13, 15, 17, and other recommended and generally accepted good 

engineering practices. Magnolia would provide automatic firewater systems and monitors for use during 

an emergency to cool the surface of storage vessels, piping, and equipment exposed to heat from a fire, 

and would meet NFPA 59A, 20, 22, and 24 requirements. Magnolia would also install a high expansion 

foam system to reduce vaporization rates from LNG pools and would meet NFPA 59A and NFPA 11. 

We have made recommendations for Magnolia to provide more information on the design, installation, 

and commissioning of hazard detection, hazard control, and firewater systems as Magnolia would further 

develop this information during the final design phase. In addition, Magnolia proposes to install remotely 

operated firewater monitors, sprinkler systems, fixed water spray systems, and firewater hydrants and 

hoses with fog nozzles to mitigate dispersion of released ammonia. We have included specific 

recommendations on Magnolia’s final design of the firewater system that would mitigate ammonia 

releases.

Magnolia 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. Personnel 

training would include the characteristics, hazards, and response steps for an ammonia release. The 

facility would also provide appropriate personnel protective equipment to enable operations personnel and 

first responders access to the area. Magnolia would also be required to develop an Emergency Response 

Plan in accordance with EPAct 2005, as discussed further in section 4.12.9. 
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The use of these protection layers would minimize the potential for an initiating event to develop 

into an incident that could impact the safety of the off-site public. As a result of the technical review of 

the information provided by Magnolia in the submittal documents, we identified a number of concerns in 

information data request letters issued on December 9, 2014, March 20, 2015, and April 1, 2015 relating 

to the reliability, operability, and safety of the proposed design. Magnolia provided written responses to 

these information data requests on December 29, 2014, April 1, 2015, and April 20, 2015. Some of these 

responses indicated that Magnolia would correct or modify its design in order to address issues raised in 

the information request. As a result, we recommend that:

 Prior to construction of the final design, Magnolia should file with the Secretary, for 

review and written approval by the Director of OEP, information/revisions 

pertaining to Magnolia’s response to numbers 5, 10, 11, 12, 13, 16, 19, 20, 22, 24, 31, 

33, 37, 38, 40, 41, 43, 44, 45, 50, 52, 53, 55, 56, 57, 64, 65, 66, 67, 70, 72, 73, 74, 76, 78, 

82, 85, 90, and 92 of its December 29, 2014 filing, which indicated features to be 

included or considered in the final design.

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.

While the RMP prevention program would only apply to ammonia, Magnolia plans to apply 

OSHA’s PSM program to the entire plant. OSHA’s PSM program requires a prevention program 

including a process hazard analysis (PHA) that identifies, evaluates, and controls the hazards involved. 

The PHA evaluates deviations from normal operating conditions and confirms mitigation measures 

needed to prevent, detect, mitigate, or respond to a range of hazard scenarios (including an unintentional 

release of ammonia). Magnolia would utilize a range of risk assessment processes to evaluate the 

mitigation systems including a Preliminary Hazard Identification, Hazard and Operability Analysis 

(HAZOP), Layer of Protection Analysis (LOPA), Safety Integrity Level (SIL) Assignment, and SIL 

Verification. In addition, Magnolia would include a prevention program that complies with the relevant 

EPA and OSHA regulations and incorporates a written plan of action to implement employee 

participation, mandatory training for all employees whose job functions include the operation of the 

ammonia systems, the completion of a process hazard analysis prior to start-up in order to identify and 

control all hazards of the process, and the preparation and implementation of procedures to maintain the 

on-going mechanical integrity of the entire facility, including the ammonia process equipment once in 

operation. Recommendations to prevent or minimize these hazards would be generated from the results 

of the HAZOP and LOPA reviews. 

Once the design has been subjected to the HAZOP and LOPA evaluations, Magnolia’s design 

development team would track changes in the facility design, operations, documentation, and personnel. 

The project would also utilize a Management of Change process to ensure that all design changes receive 

appropriate reviews to analyze any potential safety impacts. Magnolia 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 and LOPA reviews would be 

monitored by FERC staff. We have included a recommendation that Magnolia should file HAZOP and 

LOPA reviews on the completed final design.
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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 Magnolia, 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 Magnolia LNG Project 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 Federal Register 58,273 (October 3, 2006), FERC Stats. & Regs. 

¶31,228 (2006). Information pertaining to items such as: off-site 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, Magnolia should provide procedures for controlling 

access during construction.

 Prior to initial site preparation, Magnolia should file the issued for construction 

quality assurance and quality control procedures for construction activities.

 Prior to initial site preparation, Magnolia should file an overall project schedule, 

which includes the proposed stages of the commissioning plan. 

 Prior to initial site preparation, Magnolia 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 Magnolia’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 P&IDs. The P&IDs should include the following 

information: 

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness; 

c. storage tank pipe penetration size and nozzle schedule;

d. piping with line number, piping class specification, size, and insulation type 

and thickness; 

e. piping specification breaks and insulation limits; 
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f. all control and manual valves numbered; 

g. valve high pressure side and cryogenic ball valve internal and external vent 

locations;

h. relief valves with set points; and

i. drawing revision number and date. 

 The final design should include the car seal philosophy with a list of all car-sealed 

and locked valves consistent with the P&IDs.

 The final design should provide an up-to-date complete equipment list, process and 

mechanical data sheets, and specifications.

 The final design EPC contractor should conduct a HAZID to review and verify that 

the recommendations from the FEED HAZID are complete and consistent with the 

requirements of the final design as determined by the EPC contractor.

 The final design should include a hazard and operability review and a LOPA of the 

completed design prior to issuing the P&IDs for construction. These reviews should 

include initial startup as well as shutdown operations. A copy of each review with a

list of recommendations, and actions taken on the recommendations, should be filed.

 The final design hazard and operability review should include participants with 

years of relevant design and operating experience and an evaluation of past 

incidents, such as dynamic surge associated with hydraulic shock.

 The final design hazard and operability review should include consideration of 

basket strainers at the bottom outlet of the Molecular Sieve Vessels to prevent 

molecular sieve and support material from entering the piping 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 §193.2801. 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 provide complete drawings and a list of the hazard detection 

equipment. Plan 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 install a technical review of facility design that: 

a. identifies all combustion/ventilation air intake equipment and the distances 

to any possible flammable gas or toxic release; and 

b. demonstrates that these areas are adequately covered by hazard detection 

devices and indicates how these devices would isolate or shut down any 
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combustion or HVAC equipment whose continued operation could add to or 

sustain an emergency.

 The final design of the hazard detectors should account for the calibration gas when 

determining the lower flammable limit set points for flammable refrigerants, NGL, 

and LNG. Include a list of alarm and shutdown set points for each hazard detector.

 The final design of the hazard detectors should account for the calibration gas when 

determining the set points for toxic components such as ammonia, NGL, and 

hydrogen sulfide. Include a list of alarm and shutdown set points for each hazard 

detector.

 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 any foam systems. Plan 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 piping and instrumentation diagrams of the 

firewater and foam system.

 The final design of the water spray and deluge systems should specify a water 

density of 0.4 gallon per minute per square foot to mitigate ammonia releases.

 The final design should provide calculations for the firewater spray systems sized to 

provide cooling for mitigation of BLEVEs.

 The final design of the firewater system should include the water required for foam 

generation in calculating the total water required for 2 hours of supply.

 The final design should specify that two firewater jockey pumps are to be installed.

 The final design should specify a 2-hour fire duration for passive fire protection 

systems.

 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 set points.

 The final design should specify an alarm management program to ensure 

effectiveness of process alarms. 

 The final design should include a drawing showing the location of the emergency 

shutdown buttons. Emergency shutdown buttons should be easily accessible, 
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conspicuously labeled, and located in an area which would be accessible during an 

emergency.

 The final design should specify emergency shutdown valve closure time and release 

volumes. Include an analysis that describes the time to detect an upset condition, 

notify plant personnel, and close the emergency shutdown valve.

 The final design should specify the bypass valves around the ESDV-11001 to be 

locked closed.

 The final design should provide the safe operating limits (upper and lower), alarm 

and shutdown set points for all instrumentation (i.e., temperature, pressures, flows, 

and compositions).

 The final design should evaluate the voting logic and voting degradation for 

flammable and toxic gas detectors.

 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 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, and are designed to withstand external 

loads, including vibrational loads in the vicinity of rotating equipment and operator 

live loads in areas accessible by operators.

 The final design should specify welded connections on ammonia piping to minimize 

flange leaks or provide justification for the use of flanges with mitigation to reduce 

likelihood and consequences from flange leaks.

 The final design should include a piping flexibility and valve dynamic surge analysis 

to consider the impact forces caused by external (i.e., thermal cycling, equipment 

vibration) and internal conditions (i.e., hammer effects) when designing the nozzles 

and selecting the piping schedules for the ammonia 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 clean-out, dryout, purging, and tightness testing.
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 The final design should provide the procedures for pressure/leak tests which 

address the requirements of ASME VIII and ASME B31.3.

 The final design should include the sizing basis and capacity for the flare stacks and 

the pressure and vacuum relief valves for major process equipment, vessels, and 

storage tanks.

 The final design of the ammonia relief valves should include a relief discharge 

collection header with knockout drum for safe discharge of ammonia vapors to the 

atmosphere. An evaluation of the vapor dispersion should be provided to 

demonstrate the ammonia vapors can be safely discharged to the atmosphere.

 The final design should include provisions to vent the heavy hydrocarbon isocontainer to the flare system.

 The final design should provide a human error/reliability analysis. This analysis 

should include human machine interface considerations, fatigue prevention 

guidelines, alarm management, and healthy work environments (i.e., bright lighting, 

glare, eye strain) to increase operator awareness and reduce risk of hazardous 

conditions. 

 The final design should provide appropriate operator camera coverage to enable 

rapid monitoring of the facility from the control room.

 The final design should include complete plan drawings of the security fencing and 

of facility access and egress.

 The final design should include an analysis of the structural integrity of the outer 

containment of the full containment storage tanks when exposed to a roof tank top 

fire or adjacent tank top fire.

 The final design should include the details of the LNG storage tank structural 

design that demonstrate the tanks can withstand overpressures from ignition of 

design spills.

 The final design should specify the forward pressure regulating valves PV-11001 

and PV-11002 should be provided with an automatic shutoff activated interlock 

through PAHH-11004/5/6.

 The final design should specify isolation valves at the base of each loading arm.

 The final design should specify an automatic shutoff valve in the liquid line to the 

heavy hydrocarbon iso-container.

 The final design should specify double isolation valves at the suction and discharge 

of all ammonia pumps.

 The final design should specify that the ball valve upstream of the hose connection 

to the ammonia truck be a shutoff valve closed by local and remote actuation.
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 The final design should specify that the Reboiler Steam Condensate Pot, V-1307, 

should have the same pressure rating as the 6C2 piping specification.

 Prior to commissioning, Magnolia 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. Magnolia should file documentation 

certifying that each of these milestones has been completed before authorization to 

commence the next phase of commissioning and startup will be issued.

 Prior to commissioning, Magnolia 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, Magnolia should maintain a detailed training log to 

demonstrate that operating staff has completed the required training.

 Prior to commissioning, Magnolia should file results of the LNG storage tank 

hydrostatic test and foundation settlement results. At a minimum, foundation 

settlement results should be provided thereafter annually.

 Prior to commissioning, Magnolia 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 commissioning, Magnolia 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, Magnolia 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, Magnolia should file the operation and maintenance 

procedures and manuals, as well as safety procedures, hot work procedures and 

permits, abnormal operating conditions reporting procedures, and management of 

change procedures and forms.

 Prior to introduction of hazardous fluids, Magnolia should complete a prestartup 

safety review to ensure that installed equipment meets the design and operating 

intent of the facility. The prestartup safety review should include any changes since 

the last hazard review, operating procedures, and operator training. A copy of the 

review with a list of recommendations, and actions taken on each recommendation, 

should be filed. 

 Prior to introduction of hazardous fluids, Magnolia 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).
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 Prior to introduction of hazardous fluids, Magnolia 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 demonstrate full functionality and operability of the system.

 Prior to introduction of hazardous fluids, Magnolia should specify the personal 

protective equipment required to minimize disabling of personnel from ammonia 

releases.

 Prior to commencement of service, Magnolia should include a preventative and 

predictive maintenance program that performs periodic or continuous equipment 

condition monitoring.

 Prior to commencement of service, Magnolia should develop procedures for off-site 

contractors’ responsibilities, restrictions, and limitations and for supervision of 

these contractors by Magnolia staff. 

 Prior to commencement of service, Magnolia should notify FERC staff of any 

proposed revisions to the security plan and physical security of the facility. 

 Prior to commencement of service, Magnolia should file progress on the 

construction of the proposed systems 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 that the following measures should apply throughout the life of 

the facility:

 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, Magnolia should 

respond to a specific data request, including information relating to possible design 

and operating conditions that may have been imposed by other agencies or 

organizations. Up-to-date detailed piping and instrumentation diagrams reflecting 

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, and liquefied, 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 offsite 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, 
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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.

 In the event the temperature of any region of any secondary containment, including 

imbedded pipe supports, becomes less than the minimum specified operating 

temperature for the material, the Commission should be notified within 24 hours

and procedures for corrective action should be specified.

 Significant non-scheduled events, including safety-related incidents (e.g., hazardous 

fluid releases, fires, explosions, mechanical failures, unusual over pressurization, 

and major injuries) and security-related incidents (e.g., attempts to enter site, 

suspicious activities) should be reported to FERC staff. In the event an abnormality 

is of significant magnitude to threaten public or employee safety, cause significant 

property damage, or interrupt service, notification should be made immediately, 

without unduly interfering with any necessary or appropriate emergency repair, 

alarm, or other 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 

facility that contains or processes hazardous fluids to rise above its 

maximum allowable operating pressure (or working pressure for LNG 

facilities) plus the build-up allowed for operation of pressure limiting or 

control devices; 
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i. a leak in a 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 a facility that contains or 

processes hazardous fluids; 

l. safety-related incidents to hazardous material transportations 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 

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. Magnolia would include a periodic inspection program to review the ammonia safety 

systems. We are recommending for Magnolia to provide more information on a predictive maintenance 

program that would periodically monitor the condition of process equipment. Based on our analysis and 

recommendations presented above, we believe that the FEED presented by Magnolia 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 and storage 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 the 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 Magnolia to identify how the proposed 

design complies with the siting requirements of the DOT’s regulations in 49 CFR 193, Subpart B. As 
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part of our review, we used Magnolia’s information, developed to comply with the 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).

For the LNG facilities proposed for the project, these Part 193 siting requirements would be 

applicable to the following equipment:

 Two 42,000,000 gallon (160,000 m3) nominal full containment LNG storage tanks and 

associated piping and appurtenances – Parts 193.2057 and 2059 require the establishment 

of thermal and flammable vapor exclusion zones for LNG tanks. NFPA 59A (2001), 

section 2.2.3.2 specifies three thermal exclusion zones based on the LNG container 

impounding area and one based on the LNG container design spill. NFPA 59A (2001), 

sections 2.2.3.3 and 2.2.3.4 specify a flammable vapor exclusion zone for the design spill 

which is determined with section 2.2.3.5.

 One 30-inch-diameter LNG transfer line to the proposed ship loading dock – Parts 

193.2001, 2057, and 2059 require thermal and flammable vapor exclusion zones for the 

marine cargo transfer system. NFPA 59A (2001) does not address LNG transfer systems.

 Six 11,007-gallon-per-minute in-tank pumps (three pumps per LNG storage tank) used 

for ship 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.
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 Eight liquefaction heat exchangers (two per liquefaction train) and associated piping and 

appurtenances, including eight 8-inch-diameter LNG rundown lines that combine into 

four 10-inch-diameter lines that further combine into one 20-inch-diameter LNG 

rundown header – 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.

The DOT has addressed some of these issues in a March 2010 letter of interpretation.29 In that 

letter, the DOT stated that: (1) the requirements in the NFPA 59A (2001) for transfer areas for LNG apply 

to the marine cargo transfer system at a proposed waterfront LNG facility, except where preempted by the 

regulations in Part 193; (2) the regulations in Part 193 for LNG transfer systems conflict with NFPA 59A 

(2001) on whether an exclusion zone analysis is required for transfer piping or permanent plant piping; 

and (3) the regulations in Part 193 prevailed as a result of that conflict. The DOT has determined that an 

exclusion zone analysis of the marine cargo transfer system is required.

In FERC environmental assessments/impact statements for past projects, we have also noted that 

when the DOT incorporated NFPA 59A into its regulations, it removed the regulation that required 

impounding systems around transfer piping. As a result of that change, it is unclear whether Part 193 or 

the adopted sections of NFPA 59A (2001) require impoundments for LNG transfer systems. We note that 

Part 193 requires exclusion zones for LNG transfer systems, and that those zones were historically 

calculated based on impoundment systems. We also note that the omission of containment for transfer 

piping is not a sound engineering practice. For these reasons, we consider it prudent design practice to 

provide containment for all LNG transfer piping within a plant’s property lines.

As stated in section 193.2051, LNG facilities must be provided with the siting requirements of 

NFPA 59A (2001 edition). The siting requirements for hazardous fluids 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.

 

29 PHMSA Interpretation “Re: Application of the Siting Requirements in Subpart B of 49 CFR Part 193 to the Mount Hope Bay Liquefied 

Natural Gas Transfer System” (March 25, 2010). 
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 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 the 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 the 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:

 eight liquefaction heat exchangers (two per liquefaction train) and associated piping and 

appurtenances;

 one 5,945-gallon ethane ISO Frame (in 10-tube cylinder bank) and associated piping;

 one 6,500-gallon n-butane ISO container and associated piping; and

 one 6,500-gallon heavy hydrocarbon liquids ISO container and associated piping.

Furthermore on January 13, 2015, the DOT determined Magnolia’s proposal to comply with the 

EPA’s RMP and OSHA’s PSM would satisfy the requirements of NFPA 59A (2001) section 2.1.1(d) for 

the anhydrous ammonia refrigerant system.30

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 

 

30 Accession number: 20150121-5190.
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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

Part 193.2181 references NFPA 59A (2001) for siting, which specifies each impounding system 

serving an LNG storage tank must have a minimum volumetric liquid capacity of 110 percent of the LNG 

tank’s maximum design liquid capacity for an impoundment serving a single tank. We also consider it 

prudent design practice to provide a barrier to prevent liquid from flowing to an unintended area 

(i.e., outside the plant property) in the event that the full containment storage tank primary and secondary 

containers have a common cause failure. The purpose of the barrier is to prevent liquid from flowing off 

the plant property, and does not define containment or an impounding area for thermal radiation or 

flammable vapor exclusion zone calculations or other code requirements already met by sumps and 

impoundments throughout the site.

Table 4.12.5-1 lists the spill volumes and their corresponding impoundment systems. Magnolia 

proposes two full containment LNG storage tanks where the outer tank wall would serve as the 

impoundment system. The proposed LNG storage tanks would have a design maximum volume of 

44,442,844 gallons with a maximum potential capacity of 45,835,387 gallons. As shown in 

table 4.12.5-1, the outer tank would have a volumetric capacity of 52,687,046 gallons, which exceeds the 

110 percent requirement by 3,799,918 gallons. The outer tank would contain 119 percent of the design 

maximum volume and 115 percent of the maximum potential capacity of the inner tank, meeting the Part 

193 requirements. Magnolia would construct an earthen berm around both of the LNG storage tanks to 

limit liquid from flowing off the plant property in the case of a common cause failure of the existing full 

containment storage tank primary and secondary containers. This earthen berm would have a minimum 

containment capacity equal to the gross volume of one LNG tank and would meet our recommendation 

that a barrier be provided to prevent liquid from flowing off plant property.

Potential spills occurring from the LNG Tank withdrawal lines, ship transfer lines, LNG trucking 

lines, LNG rundown lines, and associated pumps, vessels, equipment, piping and appurtenances located 

within the earthen berm would drain toward trenches and would be directed to the LNG Tank Area 

Impound Basin. The LNG Tank Area Impound Basin would be a square impoundment, 75-feet-long, 

75-feet-wide, and 15-feet-deep, with a usable capacity of approximately 631,169 gallons. Each LNG 

storage tank would be equipped with three in-tank pumps, each rated at 11,007 gallons per minute with a 

maximum runout flow rate of 14,578 gallons per minute. With four in-tank pumps utilized for ship 

loading operations, the maximum 10-minute spill volume from the 30-inch-diameter in-tank pump header 

would be 583,116 gallons. Any volume contained within the piping after 10 minutes would also be 

contained within the LNG Tank Area Impound Basin.
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TABLE 4.12.5-1

Impoundment Area Sizing

Source

Spill Size

(gallons) Impoundment System

Impoundment Size

(gallons)

LNG storage tank 45,835,387 Outer tank concrete wall 52,687,046

30-inch-diameter in-tank pump withdrawal header 583,116 LNG tank area impound basin 631,169

10-inch-diameter LNG rundown line (process area) 14,196 Process area impound basin 21,843

12-inch-diameter HP ammonia receiver discharge line 18,367 Process area impound basin 21,843

16-inch-diameter ammonia/mixed refrigerant precooler 

discharge line

21,843 Process area impound basin 21,843

LNG truck 12,500 LNG truck loading impound basin 16,831

3-inch LNG truck loading line 2,683 LNG truck loading impound basin 16,831

n-Butane ISO container 6,500 Process area impound basin 21,843

Heavy hydrocarbon liquids ISO container 6,500 Process area impound basin 21,843

Lean amine tank 3,800 Module 1 curbed area 23,665

Liquid nitrogen tank 44,000 Module 5 curbed area 68,663

Potential spills occurring in the liquefaction area would drain toward trenches and would be 

directed to the Process Area Impound Basin. The Process Area Impound Basin would be a square 

impoundment, 20-feet-long, 20-feet-wide, and 7.3-feet-deep, with a usable capacity of approximately 

21,843 gallons. This impoundment would contain the largest 10-minute LNG spill volume of 

14,196 gallons from the 10-inch-diameter LNG rundown line, the largest 10-minute ammonia spill 

volume of 18,367 gallons from the 12-inch-diameter HP Ammonia Receiver discharge line, and the 

largest mixed refrigerant 10-minute spill volume of 21,843 gallons from the 16-inch-diameter 

Ammonia/Mixed Refrigerant Precooler discharge line. 

Potential spills occurring from LNG truck loading lines and associated pumps, vessels, 

equipment, piping and appurtenances located outside the earthen berm would drain toward trenches and 

would be directed to the LNG Truck Loading Impound Basin. The LNG Truck Loading Impound Basin 

would be square impoundment, 15-feet-long, 15-feet-wide, and 10-feet-deep, with a usable capacity of 

approximately 16,831 gallons. This volume capacity would hold the entire contents of a full LNG truck 

(approximately 12,500 gallons) as well as a 10-minute spill volume of 2,683 gallons from the 

3-inch-diameter truck loading line. 

The refrigerant storage area would be located to the north of liquefaction Train 1. Ethane would 

be stored as a high pressure gas in a 10 tube cylinder bank in an ISO Frame with a nominal volume of 

5,945 gallons. n-Butane would be stored as compressed liquid within IMO 5 type ISO containers with a 

volume of 6,500 gallons. The ISO Frame and ISO container would be located within a 25-feet-long by 

100-feet-wide curbed area that would connect via a sloped trench to the 21,843-gallon Process Area 

Impound Basin.

Magnolia proposes to vaporize the heavy hydrocarbon liquids and mix it with fuel gas powering 

the Auxiliary Boiler. In the event the vaporizer is out of service, temporary storage for the heavy 

hydrocarbons would be provided by a 6,500 gallon Heavy Hydrocarbon Liquids ISO Container. This ISO 

container would be located within an 18-feet-long by 38-feet-wide curbed area that would connect via a 

sloped trench to the 21,843 gallon Process Area Impound Basin.

The amine systems as well as the 3,800 gallon Lean Amine Tank would be installed within 

module 1 of each train. Any liquid amine released from the amine process or the Lean Amine Tank 
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would be contained within an irregularly shaped 6-inch curbed area in module 1. This curbed area would 

have a containment volume of approximately 23,665 gallons. Nitrogen piping as well as a 44,000 gallon 

Liquid Nitrogen Tank would be installed within module 5 of each train. A liquid nitrogen release would 

be contained within the irregularly shaped 6-inch curbed area in module 5. This curbed area would have 

a containment volume of approximately 68,663 gallons.

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, the DOT requested that LNG facility applicants 

contact the Office of Pipeline Safety's Engineering and Research Division regarding the Part 193 siting 

requirements.31 Specifically, the letter stated that the 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.

In response, Magnolia provided the DOT with their design spill criteria and identified leakage 

scenarios for the proposed equipment. The DOT reviewed the data and methodology that Magnolia 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. Magnolia’s methodology considers the failure probability of over 700 piping segments, 

valves, hose connections, and process vessels containing hazardous fluids for the purpose of selecting 

credible design spills using a list of nominal failure rates developed by FERC staff and presented by the 

DOT on its webpage for “LNG Facility Siting” (http://primis.phmsa.dot.gov/lng/index.htm). 

NFPA 59A, section 2.1.1 requires consideration of clearances between flammable refrigerant 

storage tanks, flammable liquid storage tanks, structures and plant equipment, both with respect to plant 

property lines and each other. This section also requires that other factors applicable to the specific site 

that have a bearing on the safety of plant personnel and surrounding public be considered, including an 

evaluation of potential incidents and safety measures incorporated in the design or operation of the 

facility. Other factors include toxic releases and overpressure considerations from ignition of a 

flammable vapor cloud.

Initially, the DOT also evaluated ammonia spills as part of their design spill review. While the 

DOT’s Part 193 and NFPA 59A address the flammable hazards of process fluids, these regulations do not 

have the same level of siting requirements for toxic hazards associated with a release from the ammonia 

refrigeration system. As discussed in section 4.12.2.1, ammonia is a toxic gas under ambient conditions 

and exposure to ammonia vapors could be hazardous to human health and result in death if inhaled at high 

concentrations. Magnolia’s proposed design would consist of four liquefaction trains, each containing

approximately 140,000 pounds of ammonia. As this quantity would exceed the 10,000 pound threshold 

listed under 40 CFR §68.130 and 29 §CFR 1910.119 App A, both the EPA and OSHA have asserted 

jurisdiction over the regulatory requirements governing the ammonia refrigeration system. Furthermore, 

on January 13, 2015, the DOT determined that Magnolia’s compliance with the EPA’s RMP and OSHA’s 

 

31 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 PF13-9-000 on August 13, 2013. Accession 

Number 20130813-4017.
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PSM would satisfy the requirements of NFPA 59A (2001) section 2.1.1(d) for the anhydrous ammonia 

refrigerant system.

Under the EPA’s RMP, Magnolia would be required to evaluate a worst-case release as well as 

alternative release scenarios. The EPA has defined (40 CFR §68.3) a worst-case release as the release of 

the largest quantity of a regulated substance from a vessel or process line (pipe) failure that results in the 

greatest distance to a specified endpoint. Magnolia selected a 10-minute release from the largest 

ammonia containing vessel, the Mixed Refrigerant/Ammonia Precooler, as the worst-case scenario. 

Alternative release scenarios are scenarios that are more likely to occur than the worst case scenario. As 

directed under 40 CFR §68.28, Magnolia selected three releases scenarios: a failure of the ammonia 

unloading hose, a leak from high pressure ammonia piping, and a leak from the intermediate pressure 

ammonia piping. 

On September 17, 2014, the DOT provided a letter to FERC staff stating that the DOT had no 

objection to Magnolia’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.32, 33 The design spills produced by this method were identified in the documents reviewed by

the DOT and have been filed in the FERC docket for this project. These are the same design spills 

described in the following sections.

The 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 the Magnolia’s design or operation of the proposed facility differs from the details 

provided in the documents on which the 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, Magnolia file with the Secretary, for 

review and written approval by the Director of OEP, certification that the final 

design is consistent with the information provided to the DOT as described in the 

design spill determination letter dated September 17, 2014 (Accession Number 

20140918-4009). In the event that any modifications to the design alter the 

candidate design spills on which the 49 CFR 193 siting analysis was based, Magnolia 

should consult with the 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 project’s siting analysis 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, 

 

32 September 17, 2014 Letter “Re: Magnolia LNG, LLC, FERC Docket No. CP14-347-000, Design Spill Determination” from Kenneth Lee to 

Rich McGuire. Filed in Docket Number CP14-347-000 on September 18, 2014. Accession Number 20140918-4009. 

33 PHMSA based this decision on the following documents: (1) April 30, 2014 initial submittal to FERC/PHMSA, FERC Accession Numbers 

20140430-5336, -5337, and -5338; (2) Supplemental submission on June 25, 2014, FERC Accession Numbers 20140625-5092, -5093, and -

5094; and (3) Supplemental submission on September 16, 2014, FERC Accession Numbers 20140916-5181, and -5182. 
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structures and plant equipment, both with respect to plant property lines and each other. This section also 

requires that other factors applicable to the specific site that have a bearing on the safety of plant 

personnel and surrounding public be considered, including an evaluation of potential incidents and safety 

measures incorporated in the design or operation of the facility. NFPA 59A section 2.2.3.4 also requires 

provisions to minimize the possibility of any flammable mixture of vapors from a design spill from 

reaching a property line that can be built upon and that would result in a distinct hazard. Taken together, 

Part 193 and NFPA 59A (2001) require that flammable vapors either from an LNG tank impoundment or 

a single accidental leakage source do not extend beyond a facility property line that can be built upon and 

that other potential incidents (e.g., toxic releases) must also be considered. 

Title 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 0.03 m 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. In October 2011, two additional dispersion models were 

approved by the 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. In addition, the EPA and NOAA have developed a software program, RMP*Comp, 

to calculate the estimated distance to the toxic endpoint associated with ERPG-2 for the worst case 

scenario and each alternative release scenario. Magnolia has utilized RMP*Comp to calculate the toxic 

endpoints for each ammonia release scenario. 

As discussed under “Design Spills” in section 4.12.5.2, 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:

 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

 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 the DOT.
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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.

Magnolia reviewed multiple releases for the liquid scenarios and for the flashing and jetting 

scenarios. Magnolia used the following conditions, corresponding to 49 CFR §193.2059, for the vapor 

dispersion calculations: ambient temperature of 69.2 °F, relative humidity of 50 percent, 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. For ammonia release scenarios, 

RMP*Comp assumes an ambient temperature of 77 °F and 50 percent relative humidity.

For scenarios modeled using FLACS, Magnolia 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 and allows for inclusion of mitigation 

measures, such as vapor barriers. 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. PHAST and RMP*Comp account for surface/ground roughness, but do not account 

for the effects of obstructions (e.g., structures) on the flow field in simulating vapor dispersion. 

Excluding obstructions will generally over-predict the hazard area for vapor dispersion and overpressures. 

The endpoints specified within RMP*Comp for each toxic substance are intended to be protective of the 

general public.

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.34 Design spills from process areas should be single 

accidental leakage sources for a 10-minute duration.

Magnolia used the failure rate methodology discussed in section 4.12.5.2 to select the following 

design spills: a guillotine rupture and a 2-inch-diameter hole in the 30-inch-diameter LNG in-tank 

withdrawal header, a guillotine rupture and a 2-inch-diameter hole in the 10-inch-diameter LNG rundown 

line, and a guillotine rupture and a 2-inch-diameter hole in the 3-inch-diameter LNG truck loading line. 

However, Magnolia’s design spill methodology did not account for full guillotine ruptures of connections 

less than 6 inches in diameter. Since the issuance of the letter by the DOT approving the design spill 

methodology, the DOT has expressed that connections less than 6 inches in diameter should be 

considered. Therefore, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia should file with the 

Secretary concurrence from the DOT as to whether full guillotine ruptures of 

connections less than 6 inches in diameter should be considered for LNG design 

spills. 

 

34 49 CFR 193.2059 incorporates by reference table 2.2.3.5 of NFPA 59A (2001 edition).
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Magnolia proposes to install two sets of vapor barriers in order to control vapor clouds and limit 

the extent of the vapor dispersion zones: an outer set of 30-feet tall barriers placed along the property 

boundaries, and an inner set of 10-feet tall barriers located closer to the liquefaction trains and other 

potential release locations, as shown in figure 4.12.5-1. 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, Magnolia 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.

Figure 4.12.5-1 Vapor Barrier Locations

Magnolia’s submitted simulations included different release directions, wind speeds, and wind 

directions. Figures 4.12.5-2 to 4.12.5-8 show the 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, 

liquefaction area, and LNG trucking area. Table 4.12.5-2 summarizes the LNG release scenarios from the 

LNG storage tank area and liquefaction area.
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Figure 4.12.5-2 LNG Release from a Guillotine Rupture of the In-tank Pump Header

Figure 4.12.5-3 LNG Jetting and Flashing Scenario from the In-tank Pump Header at Dock
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Figure 4.12.5-4 LNG Release from the LNG Rundown Line in the Tank Area

Figure 4.12.5-5 LNG Release from the LNG Rundown Line in the Liquefaction Area
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Figure 4.12.5-6 LNG Jetting and Flashing Scenario from the LNG Rundown Line

Figure 4.12.5-7 LNG Release from the LNG Truck Loading Line
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Figure 4.12.5-8 LNG Jetting and Flashing Scenario from the LNG Truck Loading Line

TABLE 4.12.5-2

LNG Design Spills

Scenario Type Location

Hole

Diameter

Pressure

(psig)

Temperature

(°F)

Flow Rate

(lb/hr)

Liquid Release In-tank Pump Withdrawal Header 30-inch guillotine 57.8 -262.2 9,722,286

Jetting and Flashing In-tank Pump Withdrawal Header 2-inch 57.8 -262.2 174,606a

Liquid Release LNG Rundown Line 10-inch guillotine 108.6 -242.3 605,750

Jetting and Flashing LNG Rundown Line 4-inch 108.6 -242.3 609,534a

Liquid Release LNG Truck Loading Line 3-inch guillotine 57.8 -254.6 46,257

Jetting and Flashing LNG Truck Loading Line 2-inch 57.8 -254.6 84,128a

____________________

a Flow rates through hole approximated using orifice equation.

With four in-tank pumps running in parallel at their maximum pump runout, the maximum flow 

rate from the LNG storage tank withdrawal line would be 58,312 gallons per minute. FLACS was used to 

predict the extent of the 1⁄2-LFL vapor cloud from a guillotine rupture of the 30-inch-diameter in-tank 

pump withdrawal header (i.e., liquid scenario). For the jetting and flashing scenario from this piping 

segment, Magnolia also used FLACS to perform a vapor dispersion analysis from a 2-inch-diameter hole 

on the in-tank pump withdrawal header at the marine loading berth. As shown in figures 4.12.5-2 and 

4.12.5-3, the FLACS modeling shows that the flammable vapor cloud would remain within Magnolia’s 

property. 

The LNG rundown lines would deliver LNG product from the Main Cryogenic Heat Exchangers 

to the LNG storage tanks. FLACS was used to predict the extent of the 1⁄2-LFL vapor cloud from a 

guillotine rupture of the 10-inch-diameter LNG rundown header from each train (i.e., liquid scenario). 

For the jetting and flashing scenario from this piping segment, Magnolia used PHAST to perform a hole 

sensitivity analysis to determine that a 4-inch-diameter hole would result in the worst flashing and jetting 
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scenario. Then FLACS was used to perform a vapor dispersion analysis from the 4-inch-diameter hole. 

As shown in figures 4.12.5-4, 4.12.5-5, and 4.12.5-6, the FLACS modeling shows that the flammable 

vapor cloud would remain within Magnolia’s property.

For LNG trucking operations, FLACS was used to predict the extent of the 1⁄2-LFL vapor cloud 

from a guillotine rupture of the 3-inch-diameter LNG truck loading header from the LNG storage tank 

(i.e., liquid scenario). For the jetting and flashing scenario from this piping segment, Magnolia used 

PHAST to perform a hole sensitivity analysis to determine that a 2-inch-diameter hole would result in the 

worst flashing and jetting scenario. Then FLACS was used to perform a vapor dispersion analysis from 

the 2-inch-diameter hole. As shown in figures 4.12.5-7, and 4.12.5-8, the FLACS modeling shows that 

the flammable vapor cloud would remain within Magnolia’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 

the DOT inspection and enforcement program.

Vapor Dispersion Analyses for Other Hazardous Fluids

In addition to the LNG releases evaluated above, Magnolia considered other release scenarios for 

ethane, n-butane, NGL, and H2S based on the design spill methodology selected by Magnolia and 

reviewed by the DOT. Design spills from process areas would be a 10-minute duration. Only the spills 

that produced the highest release rates and consequently the longest 1⁄2-LFL vapor clouds are discussed in 

this section.

Magnolia used the failure rate methodology discussed under “Design Spills” above to select the 

following design spills: a guillotine rupture from a 2-inch-diameter ethane hose connection, a guillotine 

rupture from a 2-inch-diameter n-butane hose connection, a guillotine rupture on the 4-inch-diameter 

Heavy Hydrocarbon Liquids (NGL) reflux pump discharge piping, and a 1.2-inch-diameter hole on the 

12-inch-diameter Thermal Oxidizer inlet piping (H2S). However, Magnolia’s design spill methodology 

did not account for full guillotine ruptures of connections less than 6 inches in diameter. As a result, the 

design spill methodology did not include a mixed refrigerant scenario. Since the issuance of the letter by 

the DOT approving the design spill methodology, the DOT has expressed that connections less than 6 

inches in diameter should be considered. Therefore, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia should file with the 

Secretary concurrence from the DOT as to whether full guillotine ruptures of 

connections less than 6 inches in diameter should be considered for mixed 

refrigerant and other hazardous fluid design spills.

Magnolia modeled the 1⁄2-LFL vapor cloud dispersion distances for the ethane, n-butane, and 

NGL releases and the 1⁄2-AEGLs for toxicity for the NGL and H2S releases. Table 4.12.5-3 summarizes 

the design spills selections.
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TABLE 4.12.5-3

Other Hazardous Fluid Design Spills

Location Release Size

Pressure

(psig)

Temperature

(°F)

Flow Rate a

(lb/hr)

Ethane hose connection 2-inch-diameter guillotine 535 69.2 157,391

n-Butane hose connection 2-inch-diameter guillotine 261 69.2 456,877

NGL piping 4-inch-diameter guillotine 811.3 -61.5 15,290

H2S piping 1.2-inch-diameter hole 848.3 140 23,289

____________________

a Flow rates calculated in PHAST.

Magnolia used both PHAST and FLACS to predict the distances to the 1⁄2-LFL vapor cloud. 

Table 4.12.5-4 provides the PHAST results and figure 4.12.5-9 provides the FLACS results. 

TABLE 4.12.5-4

Vapor Dispersion Scenarios from Refrigerants and Natural Gas Liquids Releases

Released Material Release Location Approximate Downwind Distance to 1⁄2-LFL (feet)

Ethane Refrigerant storage area 365

n-Butane Refrigerant storage area See FLACS (see figure 4.12.5-9)

NGL Liquefaction process 115

Figure 4.12.5-9 n-Butane Release Scenario at Refrigerant Storage Area

As Magnolia’s calculations show the flammable vapor dispersion would stay within the 

Magnolia’s property, we conclude that the siting of the proposed project would not have a significant 

impact on public safety from ethane, n-butane, and NGL releases. If the facility is constructed and 

operated, compliance with the requirements of 49 CFR 193 would be addressed as part of the DOT’s 

inspection and enforcement program.
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Since the NGL and H2S releases would also contain toxic components, Magnolia used PHAST to 

calculate the dispersion distances to toxic threshold exposure limit 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 H2S and 

NGL (i.e., benzene and toluene) at the 10-minute exposure time. The toxicity effects associated with 

AEGL-1 are non-disabling and reversible. The distances to the 1⁄2-AEGL 1 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, and toluene). If the facility is constructed and operated, compliance with the 

requirements of 49 CFR 193 would be addressed as part of the DOT’s inspection and enforcement 

program.

TABLE 4.12.5-5

Distance to the 1⁄2-AEGL 1 and 2 at 10-minute Exposure Time

Substance

1⁄2-AEGL 1

(feet)

1⁄2-AEGL 2

(feet)

Hydrogen Sulfide 304 No hazard a

Benzene No hazard a No hazard a

Toluene No hazard a No hazard a

____________________

a PHAST results show concentrations below the AEGL levels at any distance.

As discussed in section 4.12.2.1, ammonia is a toxic gas under ambient conditions and exposure

to ammonia vapors could be hazardous to human health and result in death if inhaled at high 

concentrations. Since the ammonia inventory at the proposed facility would be above the 10,000 pound 

threshold listed in 40 CFR §68.130 and 29 CFR 1910.119 App A, the EPA and OSHA would have 

regulatory oversight over equipment containing ammonia. The DOT’s Part 193 regulations and NFPA 

59A primarily focus on the flammability of hazardous fluids. To address the regulatory requirements for 

the toxic characteristics of ammonia, the DOT has determined that compliance with the EPA’s RMP and 

OSHA’s PSM would satisfy the requirements of NFPA 59A (2001) section 2.1.1(d) for the ammonia 

refrigerant system. Magnolia has proposed to comply with the relevant EPA and OSHA regulations to 

ensure the safe siting and operation of the ammonia refrigerant systems.

The EPA has defined (40 CFR 68.3) a worst-case release as the release of the largest quantity of a 

regulated substance from a vessel or process line (pipe) failure that results in the greatest distance to a 

specified endpoint. Magnolia selected a 10-minute release from the largest ammonia vessel, Mixed 

Refrigerant/Ammonia Precooler, and the RMP*Comp results indicate that the toxic endpoint would reach 

2.6 miles to the ERPG-2 level and could impact a population of approximately 1,429 people (2010 census 

data) and would extend over the Calcasieu Point Landing recreational area that includes a boat launch, a 

fishing pier, a store, and public restrooms. The distance to the toxic endpoint estimated under worst-case 

conditions should not be considered a zone in which the public would likely be in danger; instead, it is 

intended to provide an estimate of the maximum possible area that might be affected in the unlikely event 

of catastrophic conditions. Because the assumptions required for the worst case analysis are very 

conservative (including the omission of mitigating measures such as vapor barriers), the results likely will 

also be very conservative. 

Alternative release scenarios are scenarios that are more likely to occur than the worst case 

scenario. 40 CFR §68.28 provides examples of alternative releases scenarios that should be considered 

when conducting an off-site consequence analysis. Magnolia selected three releases scenarios: a 2-inchdiameter failure of the ammonia unloading hose for 20 seconds, a 10-mm leak from high pressure 
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ammonia piping for 30 seconds, and a 10-mm leak from the intermediate pressure ammonia piping for 30 

seconds. The RMP*Comp results for each alternative release scenario indicate that the toxic endpoint 

would reach beyond the property boundaries and a release scenario from Train 1 would potentially impact 

the Calcasieu Point Landing area. The toxic endpoint from the alternative release scenarios would not 

impact public receptors. The EPA’s RMP toxic endpoints are summarized in table 4.12.5-6. 

TABLE 4.12.5-6

Ammonia Release Toxic Endpoints 

Scenario Type Scenario Release Duration Distance to ERPG-2

Worst Case Mixed Refrigerant/Ammonia 

Precooler release

10 minutes 2.6 miles

Alternative Release 2-inch-diameter failure of 

ammonia unloading hose

20 seconds 0.6 mile

Alternative Release 10-mm hole from high pressure 

ammonia piping

30 seconds 0.3 mile

Alternative Release 10-mm hole from intermediate 

pressure ammonia piping

30 seconds 0.3 mile

Magnolia’s use of ammonia in the liquefaction process would therefore by regulated by the DOT, 

EPA, and OSHA. Magnolia would comply with the comprehensive EPA RMP and OSHA PSM 

programs as well as the DOT’s requirements under Part 193 and NFPA 59A. By complying with the 

EPA RMP and OSHA PSM, Magnolia would comply with the same regulations as every other facility in 

the United States that uses quantities of ammonia above the regulatory threshold. As a result, we 

conclude that the siting of the proposed project would not have a significant impact on public safety due 

to other hazardous fluid releases. If the facility is constructed and operated, compliance with the 

requirements of 40 CFR 68, 29 CFR 1910.119, and 49 CFR 193 would be addressed as part of the EPA, 

OSHA, and DOT inspection and enforcement programs.

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 4.12.2.1, 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.
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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. 

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, Magnolia’s project would be designed to receive feed gas with methane 

concentrations as low as 91 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, Magnolia 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 refrigerants used in the 

liquefaction process streams to produce damaging overpressures when ignited. In order to evaluate this 

hazard, Magnolia used both PHAST and FLACS to perform an overpressure analysis. Table 4.12.5-7 

summarizes the overpressure scenarios and results.

TABLE 4.12.5-7

Overpressure Distances from Refrigerants and Natural Gas Liquids

Release Scenario

Overpressure Threshold 

(psi)

Overpressure Distance 

(feet)

2-inch-diameter guillotine rupture from ethane hose 1 620 (figure 4.12.5-10)

4-inch-diameter guillotine rupture from NGL piping 1 201 (figure 4.12.5-11)

2-inch-diameter guillotine rupture from n-butane hose 0.5 See FLACS (figure 4.12.5-12)

n-Butane released between parallel vapor barriers 0.5 See FLACS (figure 4.12.5-13)
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Magnolia used the Baker-Strehlow-Tang Explosion model in PHAST to perform an overpressure 

analysis for ethane and NGL. The model assumed that the obstructed volume includes the entire vapor 

cloud and estimated the 1-psig threshold at different wind speeds. As shown in figures 4.12.5-10 and 

4.12.5-11, the PHAST results show that the maximum overpressure for the ignition of ethane or NGL 

vapor clouds would remain on Magnolia’s property. However the PHAST results show that the distance 

to 1-psig for n-butane would extend beyond Magnolia’s property boundary. Therefore the n-butane 

overpressure scenarios were identified for modeling using FLACS to account for the detailed geometry of 

the facility. Distances were determined with a safety factor of 2 (i.e., 1⁄2 psi), as a result of previous 

validation studies and peak-pressure averaging.35 The levels of confinement are input parameters in the 

overpressure modeling software. The overpressure threshold were calculated by placing an uniform, 

stoichiometric fuel/air mixture within each congested region and several vapor cloud explosion 

simulations were performed on FLACS. As shown in figure 4.12.5-12, the distance to 1⁄2 psig 

overpressure from vapor cloud explosion would remain within Magnolia’s boundary. This overpressure 

would not reach the LNG storage tanks. 

Figure 4.12.5-10 Ethane Overpressure Scenario at Train 1

 

35 Hansen, O.R., Hinze, P., Engel, D., Davis, S. 2010. Using Computation Fluid Dynamics (CFD) for Blast Wave Predictions, Journal 

of Loss Prevention in the Process Industries, Vol 23, 885-906, 2010.
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Figure 4.12.5-11 Natural Gas Liquids Overpressure Scenario at Train 4

Figure 4.12.5-12 n-Butane Overpressure Scenario at Train 1

FLACS also calculated an overpressure scenario from the ignition of an n-butane vapor cloud 

between parallel 10-foot vapor barriers. As shown in figure 4.12.5-13, the distance to 1⁄2 psig 

overpressure from vapor cloud explosion would remain within Magnolia’s boundary and would not reach 

the LNG storage tanks. All of the overpressure scenarios, as calculated by PHAST and FLACS, would 

remain within the Magnolia’s property. As a result, we conclude that the siting of the proposed Project 

would not have a significant impact on public safety due to vapor cloud explosion events. If the facility is 
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constructed and operated, compliance with the requirements of 49 CFR 193 would be addressed as part of 

the DOT inspection and enforcement program.

Figure 4.12.5-13 n-Butane Overpressure Scenario between Parallel Vapor Barriers

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 a fire in an LNG storage tank 

impoundment, there are three radiant heat flux levels which must be considered:

 1,600 Btu/ft2-hr – This level can extend beyond the facility’s property line that can be 

built upon but cannot include areas that, at the time of facility siting, are used for outdoor 

assembly by groups of 50 or more persons;

 3,000 Btu/ft2-hr – This level can extend beyond the facility’s property line that can be 

built upon but cannot include areas that, at the time of facility siting, contain assembly, 

educational, health care, detention or residential buildings or structures; and

 10,000 Btu/ft2-hr – This level cannot extend beyond the facility’s property line that can 

be built upon.

The requirements for spills from process or transfer areas are more stringent. For these 

impoundments, the 1,600 Btu/ft2-hr flux level cannot extend beyond the facility’s property line that can 

be built upon. 
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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. Magnolia 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 the Magnolia’s selection of atmospheric conditions.

For the proposed liquefaction project, Magnolia used LNGFIRE3 to predict the thermal radiation 

distances as a result of fires from the LNG Storage Tank Outer Containment, the Tank Area 

Impoundment Basin, the Liquefaction Area Impoundment Basin, and the Truck Loading Area 

Impoundment Basin. 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, n-butane, and NGL. 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, n-butane, and NGL 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, n-butane, and NGL 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 4.12.5-8 and 

figure 4.12.5-14. As shown in figure 4.12.5-14, the 1,600 Btu/ft2-hr flux level would extend beyond the 

southern property line of the proposed terminal and onto Port of Lake Charles property. Magnolia has 

signed an Exclusion Zone Agreement to limit the activities that can be done on this property to 

demonstrate compliance with 49 CFR 193. However, the DOT has not reviewed this agreement. 

Therefore, we recommend that:

 Prior to the end of the draft EIS comment period, Magnolia should file with the 

Secretary concurrence from the DOT that the restriction of property use between 

Lake Charles Harbor and Terminal District and Magnolia would satisfy the 

exclusion zone requirements of 49 CFR 193.2057.

TABLE 4.12.5-8

Thermal Radiation Exclusion Zones 

Thermal Flux Level (Btu/ft2-hr)

10,000 3,000 1,600

Distance from LNG Storage Tank Outer Containment (feet) 403 744 951

Distance from Tank Area Impoundment Basin (feet) 250 331 390

Distance from Liquefaction Area Impoundment Basin (feet) 92 117 134

Distance from Truck Loading Area Impoundment Basin (feet) 74 92 106
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Figure 4.12.5-14 Thermal Radiation Zones

If the DOT concurs with the land use agreement, we conclude that the siting of the proposed 

project would not have a significant impact on public safety with respect to radiant heat from the LNG 

Storage Tank fire or from the proposed impoundment basins. If the facility is constructed and operated, 

compliance with the requirements of 49 CFR 193 would be addressed as part of the DOT’s inspection and 

enforcement program.

The refrigerant storage area would be located about 55 feet to the north of Train 1. We identified 

that the refrigerant vessels as well as equipment within Train 1could be exposed to damaging heat flux 

from an LNG storage tank roof fire. On April 1, 2015, Magnolia clarified that the design would install 

mitigation measures for these process vessels including firewater spray systems to provide cooling to 

prevent BLEVEs. We believe these mitigation measures would reduce the likelihood of a BLEVE 

occurring in these areas and recommended in section 4.12.3 that Magnolia 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 due to fire radiation impacts.

4.12.6 LNG Carriers

Since 1959, ships have transported LNG without a major release of cargo or a major accident 

involving an LNG carrier. There are more than 370 LNG carriers in operation routinely transporting 

LNG between more than 100 import/export terminals currently in operation worldwide. Since U.S. LNG 

terminals first began operating under FERC jurisdiction in the 1970s, there have been more than 

2,600 individual LNG carrier arrivals at terminals in the U.S. For more than 40 years, LNG shipping 

operations have been safely conducted in U.S. ports and waterways.
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Design and Operating Requirements

The LNG carriers used to import and export LNG to and from the United States are constructed 

and operated in accordance with the IMO’s Code for the Construction and Equipment of Ships Carrying 

Liquefied Gases in Bulk, the International Convention for the Safety of Life at Sea, and 46 CFR 154, 

which contains the United States safety standards for vessels carrying liquefied natural gas in bulk. 

As required by the IMO’s conventions and design standards, hold spaces and insulation areas on 

an LNG carrier must be equipped with gas detection and low temperature alarms. These devices monitor 

for leaks of LNG into the insulation between primary and secondary LNG cargo tank barriers. In 

addition, hazard detection systems must also be provided to monitor the hull structure adjacent to the 

cargo tank, compressor rooms, motor rooms, cargo control rooms, enclosed spaces in the cargo area, 

specific ventilation hoods and gas ducts, and air locks.

In 1993, amendments to the IMO’s Code for the Construction and Equipment of Ships Carrying 

Dangerous Chemicals in Bulk required all vessels to have monitoring equipment with an alarm facility 

which is activated by detection of over-pressure or under-pressure conditions within a cargo tank. In 

addition, cargo tanks must be heavily instrumented, with gas detection equipment in the hold and interbarrier spaces, temperature sensors, and pressure gauges. LNG carriers are to be equipped with a 

firewater system with the ability to supply at least two jets of water to any part of the deck in the cargo 

area and parts of the cargo containment and tank covers above-deck. A water spray system is also 

available for cooling, fire prevention, and crew protection in specific areas. In addition, certain areas of 

LNG carriers are fitted with dry chemical powder-type extinguishing systems and carbon dioxide 

smothering systems for fighting fires. Fire protection must include the following systems:

 a water spray (deluge) system that covers the accommodation house control room and all 

main cargo valves;

 a traditional firewater system that provides water to fire monitors on deck and to fire 

stations found throughout the vessel;

 a dry chemical fire extinguishing system for hydrocarbon fires; and

 a carbon dioxide system for protecting machinery including the ballast pump room, 

emergency generators, and compressors.

All LNG vessels entering U.S. waters are required to possess a valid IMO Certificate of Fitness 

and either a Coast Guard Certificate of Inspection (for U.S. flag vessels) or a Coast Guard Certificate of 

Compliance (for foreign flag vessels). These documents certify that the vessel is designed and operating 

in accordance with both international standards and the U.S. regulations for bulk LNG carriers under

46 CFR 154.

The LNG carriers which would receive LNG from the proposed facility would also need to 

comply with various U.S. and international security requirements. The IMO adopted the International 

Ship and Port Facility Security Code in 2003. This code requires both ships and ports to conduct 

vulnerability assessments and to develop security plans. The purpose of the code is to prevent and 

suppress terrorism against ships; improve security aboard ships and ashore; and reduce the risk to 

passengers, crew, and port personnel on board ships and in port areas. All LNG vessels, as well as other 
4-203

cargo vessels 500 gross tons and larger, and ports servicing those regulated vessels, must adhere to the 

IMO standards. Some of the IMO requirements for ships are as follows: 

 ships must develop security plans and have a Vessel Security Officer;

 ships must have a ship security alert system. These alarms transmit ship-to-shore security 

alerts identifying the ship, its location, and indication that the security of the ship is under 

threat or has been compromised;

 ships must have a comprehensive security plan for international port facilities, focusing 

on areas having direct contact with ships; and

 ships may have equipment onboard to help maintain or enhance the physical security of 

the ship.

In 2002, the Maritime Transportation Security Act (MTSA) was enacted by the U.S. Congress 

and aligned domestic regulations with the maritime security standards of the International Ship and Port 

Facility Security Code and the International Convention for the Safety of Life at Sea. The resulting Coast 

Guard regulations, contained in 33 CFR 104, require vessels to conduct vulnerability assessments and 

develop corresponding security plans. All LNG carriers servicing the facility comply with the MTSA 

requirements and associated regulations while in U.S. waters.

4.12.7 LNG Carrier Routes

The Project would be located on the Industrial Canal South Shore PLC Tract 475 at the Port of 

Lake Charles, Louisiana, on the U.S. Gulf Coast, with access via the Calcasieu Ship Channel. The 

Calcasieu Ship Channel runs inland for approximately 30 nautical miles from the Gulf of Mexico to Lake 

Charles. The proposed site would be located approximately 22 nautical miles from the Gulf of Mexico. 

Inbound LNG carriers with capacities between 125,000 and 218,000 m3 would enter the southern 

entrance to the Calcasieu Pass Safety Fairway and would continue north within the limits of the Calcasieu 

Pass Safety Fairway to the entrance of the Calcasieu Ship Channel located approximately 26 nautical 

miles offshore from Calcasieu Pass in the Gulf of Mexico. In the northern portion of the Calcasieu Pass 

Safety Fairway, inbound LNG carriers would embark a Lake Charles Pilot and enter the Calcasieu Ship 

Channel at the CC buoy. During daylight hours, one Pilot would meet the inbound LNG carrier at the 

CC buoy and a second Pilot boards the vessel inside the jetties at Cameron. Larger LNG Q-Flex carriers 

(between 210,000 and 216,000 m3capacity) and LNG carriers transiting the channel at night would 

require two Pilots at all times. From this point, the deep-draft LNG carriers would be confined to the 

Calcasieu Ship Channel because of surrounding shallow water depths. Inbound ships would proceed into 

the entrance of the Calcasieu Jetties and continue northbound in the Calcasieu Ship Channel to the 

channel’s intersection with the Gulf Intracoastal Waterway at “Devil’s Elbow.” At this intersection, 

inbound LNG carriers would make a turn to the northeast and proceed into the Industrial Canal where the 

ships would moor at the Magnolia LNG terminal. Loaded LNG carriers would transit outbound along the 

reverse route described for inbound ships. LNG barges with a capacity up to 15,000 m3 would also transit 

inbound and outbound from the Magnolia terminal using these same channels and safety fairways. 
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4.12.7.1 Hazards Resulting from Accidents 

A review of the history of LNG maritime transportation indicates that there has not been a serious 

accident at sea or in a port which resulted in a spill due to rupturing of the cargo tanks. However, 

insurance records, industry sources, and public websites identify a number of incidents involving LNG 

vessels, including minor collisions with other vessels of all sizes, groundings, minor LNG releases during 

cargo unloading operations, and mechanical/equipment failures typical of large vessels. Some of the 

more significant occurrences, representing the range of incidents experienced by the worldwide LNG 

vessel fleet, are described below:

 El Paso Paul Kayser grounded on a rock in June 1979 in the Straits of Gibraltar during a 

loaded voyage from Algeria to the United States. Extensive bottom damage to the ballast 

tanks resulted; however, no cargo was released because no damage was done to the cargo 

tanks. The entire cargo of LNG was subsequently transferred to another LNG vessel and 

delivered to its U.S. destination.

 Tellier was blown by severe winds from its docking berth at Skikda, Algeria in February 

1989 causing damage to the loading arms and the vessel and shore piping. The cargo 

loading had been secured just before the wind struck, but the loading arms had not been 

drained. Consequently, the LNG remaining in the loading arms spilled onto the deck, 

causing fracture of some plating.

 Mostefa Ben Boulaid had an electrical fire in the engine control room during unloading 

at Everett, Massachusetts. The ship crew extinguished the fire and the ship completed 

unloading. 

 Khannur had a cargo tank overfill into the vessel’s vapor handling system on September 

10, 2001, during unloading at Everett, Massachusetts. Approximately 100 gallons of 

LNG were vented and sprayed onto the protective decking over the cargo tank dome, 

resulting in several cracks. After inspection by the Coast Guard, the Khannur was 

allowed to discharge its LNG cargo.

 Mostefa Ben Boulaid had LNG spill onto its deck during loading operations in Algeria 

in 2002. The spill, which is believed to have been caused by overflow rather than a 

mechanical failure, caused significant brittle fracturing of the steelwork. The vessel was 

required to discharge its cargo, after which it proceeded to dock for repair.

 Norman Lady was struck by the USS Oklahoma City nuclear submarine while the 

submarine was rising to periscope depth near the Strait of Gibraltar in November 2002. 

The 87,000 cubic meter (m3) LNG vessel, which had just unloaded its cargo at 

Barcelona, Spain, sustained only minor damage to the outer layer of its double hull but no 

damage to its cargo tanks.

 Tenaga Lima grounded on rocks while proceeding to open sea east of Mopko, South 

Korea due to strong current in November 2004. The shell plating was torn open and 

fractured over an approximate area of 20 by 80 feet, and internal breaches allowed water 

to enter the insulation space between the primary and secondary membranes. The vessel 

was refloated, repaired, and returned to service.
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 Golar Freeze moved away from its docking berth during unloading on March 14, 2006, 

in Savannah, Georgia. The powered emergency release couplings on the unloading arms 

activated as designed, and transfer operations were shut down.

 Catalunya Spirit lost propulsion and became adrift 35 miles east of Chatham, 

Massachusetts on February 11, 2008. Four tugs towed the vessel to a safe anchorage for 

repairs. The Catalunya Spirit was repaired and taken to port to discharge its cargo.

 Suez Matthew grounded on the reef off Cayo Maria Langa, near Guayanilla, Puerto Rico 

on December 19, 2009. The ship was refloated and no damage was found to the hull.

 Al Gharrafa collided with a container ship, Hanjin Italy, in the Malacca Strait off 

Singapore on December 19, 2013. The bow of the Al Gharrafa and the middle of the 

starboard side of the Hanjin were damaged. Both ships were safely anchored after the 

incident. No loss of LNG, fatalities, or injuries were reported.

Although the history of LNG shipping has been free of major incidents, and no incidents have 

resulted in significant quantities of cargo being released, the possibility of an LNG spill from a vessel 

over the duration of the proposed project must be considered. If an LNG spill were to occur, the primary 

hazard to the public would be from radiant heat from a pool fire. If an LNG release were to occur without 

ignition, an ignitable gas cloud could form and also present a hazard. Historically, the events most likely 

to cause a significant release of LNG were a vessel casualty such as: 

 a grounding sufficiently severe to puncture an LNG cargo tank;

 a vessel colliding with an LNG vessel in transit;

 an LNG vessel alliding with the terminal or a structure in the waterway; or

 a vessel alliding with an LNG vessel while moored at the terminal.

To result in a spill of LNG, any of the above events would need to occur with sufficient impact to 

breach an LNG vessel’s double hull and cargo tanks. All LNG vessels used to deliver LNG to the 

proposed project would have double-hull construction, with the inner and outer hulls separated by about 

10 feet. Furthermore, the cargo tanks are normally separated from the inner hull by a layer of insulation 

approximately 1-foot thick.

As a result, many grounding incidents severe enough to cause a cargo spill on a single-bottom oil 

tanker would be unable to penetrate both inner and outer hulls of an LNG vessel. Previous incidents with 

LNG vessels have primarily involved grounding, and none of these have resulted in the breach of the 

double hull and subsequent release of LNG cargo. The likelihood of an LNG vessel sustaining cargo tank 

damage in a collision would depend on several factors: 

 the displacement and construction of both the struck and striking vessels;

 the velocity of the striking vessel and its angle of impact with the struck vessel; and 

 the location of the point of impact.
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In December 2004, the DOE released a study on the potential for an LNG vessel breach. At the 

request of the DOE, Sandia conducted the research and wrote the 2004 Sandia Report. The 2004 Sandia 

Report included an LNG cargo tank breach analysis using modern finite element modeling and explosive 

shock physics modeling to estimate a range of breach sizes for both credible accidental and intentional 

LNG spill events. Accidental breaching evaluations were based on finite element modeling of collisions 

of double-hulled oil tankers similar in size and design to LNG ships. The analysis of accidental events 

found that groundings, collisions with small vessels, and low-speed (less than 7 knots) collisions with 

large vessels striking at 90 degrees could cause minor vessel damage but would not result in a cargo spill. 

This is due to the protection provided by the double-hull structure, the insulation layer, and the primary 

cargo tank of an LNG vessel. High-speed (12 knots) collisions with large vessels striking at 90 degrees 

were found to potentially cause cargo tank breach areas of from 0.5 to 1.5 meters squared (m2).

The possibility of an LNG release due to an accident, such as a collision or grounding, is 

considered minimal. In addition, current operational procedures in use by the Coast Guard, such as 

managing ship traffic, coordinating ship speeds, and active ship control in inner and outer harbors, would 

also further reduce the potential of LNG spill from accidental causes. 

4.12.7.2 Hazards Resulting from Intentional Acts

The 2004 Sandia Report also analyzed credible intentional breaches on LNG carriers up to 

145,000 m3in capacity using modern finite element modeling and explosive shock physics modeling. 

The events considered for credible intentional acts were based on intelligence and historical data ranging 

from sabotage and hijacking to other types of physical attacks. Physical attacks included those 

documented to have occurred to several types of international shipping vessels, including attacks with 

small missiles and rockets, and attacks with bulk explosives.

For intentional scenarios, the size of the cargo tank hole depends on the location of the ship and 

source of threat. Intentional breach areas were estimated to range from 2 to 12 m2. In most cases, an 

intentional breaching scenario would not result in a nominal hole area of more than 5 to 7 m2, which is a 

more appropriate range to use in calculating potential hazards from spills. These hole sizes are equivalent 

to circular hole diameters of 2.5 and 3 meters.

The 2004 Sandia Report evaluated cascading damage due to brittle fracture from exposure to 

cryogenic liquid or fire-induced damage to foam insulation. While possible under certain conditions, the 

cascading damage was found to not likely involve more than two or three cargo tanks. Cascading events 

were expected to increase the fire duration but not to significantly increase the overall fire hazard.

The 2004 Sandia Report also included guidance on risk management for intentional spills, based 

on the findings that the most significant impacts to public safety and property exist within approximately 

500 meters (1,640 feet) of a spill due to thermal hazards from a fire, with lower public health and safety 

impacts beyond 1,600 meters (approximately 1 mile). Large un-ignited LNG vapor releases were found 

to be unlikely, but could extend from nominally 2,500 meters (8,200 feet) to a conservative maximum 

distance of 3,500 meters (2.2 miles) for an intentional spill.

In 2008, the DOE released another study prepared by Sandia, entitled Breach and Safety Analysis 

of Spills Over Water from Large Liquefied Natural Gas Carriers, May 2008 (2008 Sandia Report). The 

2008 Sandia Report assessed the scale of possible hazards for newer LNG vessels with capacities up to 

265,000 m3. Using the same methodology as the 2004 Sandia Report, the 2008 Sandia Report concluded 

thermal hazard distances would be only 7 to 8 percent greater than those from vessels carrying 145,000 
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m3 of LNG, due primarily to the slightly greater height of LNG above the waterline. The 2008 Sandia 

Report also noted the general design of the larger vessels was similar to the previously analyzed ship 

designs and, for near-shore facilities; the calculated breach size for intentional scenarios would remain the 

same. Overall, the 2008 Sandia Report maintained the same impact zones as with the smaller vessels that 

were analyzed in the 2004 Sandia Report.

In February 2007, the U.S. Government Accountability Office (GAO) published a report 

assessing several studies, including the 2004 Sandia Report that had been conducted on the consequences 

of an LNG spill resulting from a terrorist attack on an LNG vessel (GAO, 2007). The GAO’s panel of 

experts agreed that the most likely public safety impact of an LNG spill would be the radiant heat from a 

pool fire and suggested that further study was needed to eliminate uncertainties in the assumptions used in 

modeling large LNG spills on water. After the GAO report, Congress requested the DOE to further 

address these research needs. In May 2012, a report entitled Liquefied Natural Gas Safety Research 

Report to Congress was released and is summarized below. 

DOE contracted Sandia to conduct a series of large-scale LNG fire and cryogenic damage tests to 

investigate the larger classes of LNG carriers with capacities up to 260,000 m3, representative of the 

largest LNG vessels in operation. Sandia conducted the largest LNG pool fire tests done to date and 

performed advanced computational modeling and ship simulations between 2008 and 2011. As in the 

earlier studies, Sandia worked with marine safety, law enforcement, and intelligence agencies to assess 

threats and credible intentional acts. Scenarios included attacks with shoulder-fired weapons, explosives, 

and attacks by aircraft and other boats. Sandia identified several ranges of possible hull breaches ranging 

from 0.005 m2(Very Small) to 15 m2(Very Large). Based on the collected pool fire test data and the ship 

simulations, Sandia concluded that thermal hazard distances to the public from a large LNG pool fire was 

smaller, by at least 2 to 7 percent, than the results listed in the 2004 and 2008 Sandia Reports. 

In order to more robustly analyze the potential for cascading failure of LNG carrier cargo tanks, 

Sandia use detailed vessel structural and thermal damage models to simulate the effects to an LNG carrier 

from a spill. For the large breaches considered, Sandia predicts that as much as 40 percent of the LNG 

released from the cargo tank would remain within the ship’s structure. Due to both the cold temperature 

of the LNG and the heat from a pool fire, the LNG carrier’s structural steel would be degraded. The 

effects could be significant enough to cause the ship to be disabled, severely damaged, and at risk of 

sinking.

Although LNG ship design and construction practices render simultaneous, multiple tank failures 

as extremely unlikely, Sandia concluded that sequential multi-tank spills may be possible. If sequential 

failures were to occur, they would not increase the size of the area impacted by the pool fire but could 

increase the duration of the fire hazards. Based on this research, Sandia concluded that use of a nominal 

one-tank spill, with a maximum of a three-tank spill, as was recommended in the 2004 Sandia report, is 

still appropriate for estimating hazard distances. 

4.12.7.3 Hazard Zones

On June 14, 2005, the Coast Guard published a Navigation and Vessel Inspection Circular –

Guidance on Assessing the Suitability of a Waterway for Liquefied Natural Gas (LNG) Marine Traffic 

(NVIC 05-05). The purpose of NVIC 05-05 was to provide the Coast Guard COTPs/Federal Maritime 

Security Coordinators, members of the LNG industry, and port stakeholders with guidance on assessing 

the suitability of a waterway for LNG marine traffic. Since 2005, the Coast Guard updated this guidance 

twice, publishing NVIC 05-08 and NVIC 01-11. The current guidance from the Coast Guard is contained 

in NVIC 01-11.
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All three NVICs direct the use of the 2004 Sandia Report as the best available information on 

LNG spills. NVIC 05-08 and NVIC 01-11 also include use of the 2008 Sandia Report. Three concentric 

Zones of Concern, based on LNG carriers with a cargo carrying capacity up to 265,000 m3, are used to 

assess the maritime safety and security risks of LNG marine traffic. The Zones of Concern are:

 Zone 1 – impacts on structures and organisms are expected to be significant within 

500 meters (1,640 feet). The outer perimeter of Zone 1 is approximately the distance to 

thermal hazards of 37.5 kW/m2(12,000 Btu/ft2-hr) from a pool fire.

 Zone 2 – impacts would be significant but reduced, and damage from radiant heat levels 

are expected to transition from severe to minimal between 500 and 1,600 meters 

(1,640 and 5,250 feet).The outer perimeter of Zone 2 is approximately the distance to 

thermal hazards of 5 kW/m2(1,600 Btu/ft2-hr) from a pool fire.

 Zone 3 – impacts on people and property from a pool fire or an un-ignited LNG spill are 

expected to be minimal between 1,600 meters (5,250 feet) and a conservative maximum 

distance of 3,500 meters (11,500 feet or 2.2 miles). The outer perimeter of Zone 3 should 

be considered the vapor cloud dispersion distance to the LFL from a worst case 

un-ignited release. Impacts to people and property could be significant if the vapor cloud 

reaches an ignition source and burns back to the source.

As LNG carriers proceed along the intended track line, Hazard Zone 1 would encompass coastal 

areas along the Calcasieu Ship Channel, including multiple residential buildings within and near 

Hackberry, the Cameron LNG Terminal, portions of the Intracoastal Park, and the easternmost portion of 

the Sabine NWR. Hazard Zone 1 would also encircle coastal areas along the Industrial Canal, which are 

comprised of industrial and commercials facilities as well as Calcasieu Point Landing (see discussion in 

sections 4.8.3 and 4.8.4). Portions of Monkey Island, St. John’s Island, Hog Island, Choupique Island, 

and Hackberry would also be within Zone 1. Commercial vessels, recreational and fishing vessels may 

also fall within Zone 1, depending on their course. Transit of such vessels through a Zone 1 area of 

concern can be avoided by timing and course changes, if conditions permit.

Zone 2 would cover a wider swath of coastal areas along the Calcasieu River, Cameron, and 

Hackberry, including multiple residential, commercial, and industrial buildings. 

Zone 3 would span Monkey Island, St. John’s Island, Hog Island, and Choupique Island, as well 

as larger portions of both Hackberry and Cameron, including two volunteer fire departments, two sheriff’s 

departments, and multiple residential, commercial, industrial, and institutional (e.g., church, school, 

library) buildings.

The areas impacted by the three different hazard zones are illustrated for both accidental and 

intentional events in figures 4.12.7-1 and 4.12.7-2.
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4.12.8 Regulatory Requirements for LNG Carrier Operations

The Coast Guard exercises regulatory authority over LNG facilities that affect the safety and 

security of port areas and navigable waterways under Executive Order 10173; the Magnuson Act 

(50 USC 191); the Ports and Waterways Safety Act of 1972, as amended (33 USC 1221, et seq.); and the 

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

carrier engineering and safety standards, and all matters pertaining to the safety of facilities or equipment 

located in or adjacent to navigable waters up to the last valve immediately before the receiving tanks. 

The Coast Guard also has authority for LNG facility security plan review, approval, and compliance 

verification as provided in 33 CFR 105. 

The Coast Guard regulations in 33 CFR 127 apply to the marine transfer area of waterfront 

facilities between the LNG vessel and the first manifold or valve located inside the containment. 

33 CFR 127 regulates the design, construction, equipment, operations, inspections, maintenance, testing, 

personnel training, firefighting, and security of LNG waterfront facilities. The safety systems, including 

communications, emergency shutdown, gas detection, and fire protection, must comply with the 

regulations in 33 CFR 127. Under 33 CFR §127.019, Magnolia would be required to submit two copies 

of its Operations and Emergency Manuals to the Coast Guard Captain of the Port (COTP) for 

examination at least 30 days prior to the first LNG transfer.

Both the Coast Guard regulations under 33 CFR 127 and FERC regulations under 

18 CFR §157.21, require an applicant who intends to build an LNG terminal facility to submit a Letter of 

Intent (LOI) to the Coast Guard at the same time the pre-filing process is initiated with the Commission. 

Consequently, Magnolia notified the Coast Guard that it proposed to construct a waterfront facility 

handling LNG located on the Industrial Canal South Shore in Lake Charles, Louisiana and submitted an 

LOI to the COTP, Marine Safety Unit Port Arthur, on March 12, 2013.

In addition to the LOI, 33 CFR 127 and FERC regulations require each LNG project applicant to 

submit a Waterway Suitability Assessment (WSA) to the cognizant COTP no later than the start of the 

FERC pre-filing process. Until a facility begins operation, applicants must annually review their WSAs 

and submit a report to the COTP as to whether changes are required. The WSA must include the 

following information: 

 port characterization;

 risk assessment for maritime safety and security; 

 risk management strategies; and 

 resource needs for maritime safety, security, and response. 

As described in 33 CFR 127 and in NVIC 01-11, the applicant develops the WSA in two phases. 

The first phase is the submittal of the Preliminary WSA, which begins the Coast Guard’s review process 

to determine the suitability of the waterway for LNG marine traffic. The second phase is the submittal of 

the Follow-On WSA. This document is reviewed and validated by the Coast Guard and forms the basis 

for the agency’s LOR to the FERC.

The Preliminary WSA provides an outline which characterizes the port community and the 

proposed facility and transit routes. It provides an overview of the expected major impacts LNG 

operations may have on the port, but does not contain detailed studies or conclusions. This document is 

used to start the Coast Guard’s scoping process for evaluating the suitability of the waterway for LNG 

marine traffic. Magnolia submitted the Preliminary WSA with its LOI to the Coast Guard on 

March 12, 2013. 
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A Follow-On WSA is required to provide a detailed and accurate characterization of the LNG 

facility, the LNG tanker route, and the port area. The assessment is to identify appropriate risk mitigation 

measures for credible security threats and safety hazards. According to NVIC 01-11, the Follow-on WSA 

should provide a complete analysis of the topics outlined in the Preliminary WSA. It should identify 

credible security threats and navigational safety hazards for the LNG marine traffic, along with 

appropriate risk management measures and the resources (federal, state, local, and private sector) needed 

to carry out those measures. Based on feedback from the Coast Guard and other stakeholders, Magnolia 

prepared and submitted the Follow-on WSA to the Coast Guard on December 12, 2013.

As required by its regulations (33 CFR §127.009), the Coast Guard is responsible for issuing an

LOR to the FERC regarding the suitability of the waterway for LNG marine traffic with respect to the 

following items:

 physical location and description of the facility;

 the LNG vessel’s characteristics and the frequency of LNG shipments to or from the facility;

 waterway channels and commercial, industrial, environmentally sensitive, and residential 

areas in and adjacent to the waterway used by LNG vessels en route to the facility, within 

25 kilometers (15.5 miles) of the facility;

 density and character of marine traffic in the waterway;

 locks, bridges, or other manmade obstructions in the waterway;

 depth of water;

 tidal range;

 protection from high seas;

 natural hazards, including reefs, rocks, and sandbars;

 underwater pipes and cables; and

 distance of berthed vessels from the channel and the width of the channel.

Once the applicant submits a complete Follow-On WSA, the Coast Guard reviews the document 

to determine if it presents a realistic and credible analysis of the public safety and security implications 

from LNG marine traffic in the port. Finally, the Coast Guard issues a LOR. The Coast Guard may also 

prepare an LOR Analysis, which serves as a record of review of the LOR and contains detailed 

information along with the rationale used in assessing the suitability of the waterway for LNG marine 

traffic. On September 15, 2014, the COTP issued an LOR and an LOR Analysis which summarized the 

Coast Guard’s recommended risk mitigation measures. Following discussions between the Coast Guard 

and FERC staff, the Coast Guard re-issued an updated LOR and LOR Analysis on February 12, 2015.36

Based on the results of the assessment of potential risks to navigation safety and maritime 

security associated with the proposed facility, the Coast Guard has determined that the Calcasieu Ship 

Channel would be suitable for accommodating the type and frequency of LNG marine traffic associated with 

this project.

 

36 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
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The Coast Guard’s LOR is a recommendation on the current status of the waterway to the FERC, 

the lead agency responsible for siting the proposed LNG facility. Neither the Coast Guard nor the FERC 

has authority to require waterway resources of anyone other than the applicant under any statutory 

authority or under the Emergency Response Plan or the Cost Sharing Plan (see section 4.12.9). However, 

if the project is approved and if the appropriate resources are not in place, then neither agency would 

allow the project to go into operation. Measures proposed by Magnolia in the WSA would be needed to 

responsibly manage the maritime safety and security risks associated with LNG marine traffic. Therefore,

we recommend that:

 Prior to commencement of service, Magnolia should receive written authorization 

from the Director of OEP. Such authorization will only be granted following a 

determination by the Coast Guard, under its authorities under the Ports and 

Waterways Safety Act, the Magnuson Act, the Maritime Transportation Security 

Act of 2002, and the Safety and Accountability For Every Port Act, that appropriate 

measures to ensure the safety and security of the facility and the waterway have 

been put into place by Magnolia or other appropriate parties.

4.12.9 Emergency Response and Evacuation

As required by 49 CFR 193.2059, Magnolia would need to prepare emergency procedures 

manuals that provide for: a) responding to controllable emergencies and recognizing an uncontrollable 

emergency; b) taking action to minimize harm to the public including the possible need to evacuate the 

public; and c) coordination and cooperation with appropriate local officials. Specifically, 

§193.2509(b)(3) requires “Coordinating with appropriate local officials in preparation of an emergency 

evacuation plan...”

Section 3A(e) of the NGA, added by section 311 of the EPAct 2005, stipulates that in any order 

authorizing an LNG terminal, the Commission must require the LNG terminal operator to develop an 

Emergency Response Plan in consultation with the Coast Guard and state and local agencies. The FERC 

must approve the Emergency Response Plan prior to any final approval to begin construction. Therefore, we 

recommend that:

 Prior to initial site preparation, Magnolia should develop an Emergency Response 

Plan (including evacuation) and coordinate procedures with the Coast Guard; state, 

county, and local emergency planning groups; fire departments; state and local law 

enforcement; and appropriate federal agencies. This plan should include at a 

minimum:

a. designated contacts with state and local emergency response agencies;

b. scalable procedures for the prompt notification of appropriate local officials 

and emergency response agencies based on the level and severity of potential 

incidents;

c. procedures for notifying residents and recreational users within areas of 

potential hazard;
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d. evacuation routes/methods for residents and public use areas that are within 

any transient hazard areas along the route of the LNG marine transit;

e. locations of permanent sirens and other warning devices; and

f. an “emergency coordinator” on each LNG carrier to activate sirens and 

other warning devices.

The Emergency Response Plan should be filed with the Secretary for review and 

written approval by the Director of OEP. Magnolia should notify the FERC staff of 

all planning meetings in advance and should report progress on the development of 

its Emergency Response Plan at 3-month intervals.

A number of organizations and individuals have expressed concern that the local community 

would have to bear some of the cost of ensuring the security and emergency management of the LNG 

facility and the LNG carriers while in transit and unloading/loading at the berth. Section 3A(e) of the 

NGA (as amended by EPAct 2005) specifies that the Emergency Response Plan must include a CostSharing Plan that contains a description of any direct cost reimbursements the applicants agree to provide 

to any state and local agencies with responsibility for security and safety at the LNG terminal and in 

proximity to LNG carriers that serve the facility. Therefore, we recommend that:

 The Emergency Response Plan should include a Cost-Sharing Plan identifying the 

mechanisms for funding all project-specific security/emergency management costs 

that would be imposed on state and local agencies. In addition to the funding of 

direct 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. 

Magnolia should file the Cost-Sharing Plan for review and written approval by the 

Director of OEP prior to initial site preparation. Magnolia should notify the FERC 

staff of all planning meetings in advance and should report progress on the 

development of its Cost-Sharing Plan at 3-month intervals.

The Cost-Sharing Plan must specify what the LNG terminal operator would provide to cover the 

cost of the state and local resources required to manage the security of the LNG terminal and LNG 

carrier, and the state and local resources required for safety and emergency management, including:

 direct reimbursement for any per-transit security and/or emergency management costs 

(for example, overtime for police or fire department personnel);

 capital costs associated with security/emergency management equipment and personnel 

base (for example, patrol boats, firefighting equipment); and

 annual costs for providing specialized training for local fire departments, mutual aid 

departments, and emergency response personnel, and for conducting exercises.

The cost-sharing plan must include the LNG terminal operator’s letter of commitment with 

agency acknowledgement for each state and local agency designated to receive resources.
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4.12.10 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 Magnolia 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.

In addition, we analyzed whether Magnolia would be sited consistently with federal regulations. 

As a cooperating agency, the DOT assisted FERC staff in evaluating whether Magnolia’s proposed design 

would meet the DOT siting requirements. The DOT reviewed the data and methodology Magnolia used 

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

containing hazardous liquids. Magnolia used those design spills to model hazardous releases. On 

September 17, 2014, the DOT provided a letter to the FERC staff stating that the DOT had no objection to 

Magnolia’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. 

Since the issuance of the letter by the DOT approving the design spill methodology, the DOT has 

expressed that connections less than 6 inches in diameter should be considered; therefore, FERC staff 

recommends Magnolia receive confirmation from the DOT on the design spills prior to the end of the 

draft EIS comment period. If a facility is constructed and becomes operational, the facility would be 

subject to the DOT inspection and enforcement program. Final determination of whether a facility is in 

compliance with the requirements of 49 CFR 193 would be made by the DOT staff.

As the quantity of ammonia refrigerant would exceed the 10,000 pound threshold listed under

40 CFR §68.130 and 29 §CFR 1910.119 App A, both the EPA and OSHA have asserted jurisdiction over 

the regulatory requirements governing the ammonia refrigeration system. In addition, the DOT has 

determined that applying the EPA’s RMP and OSHA’s PSM would satisfy the requirements of NFPA 

59A (2001) section 2.1.1(d) for the toxic hazards from potential ammonia releases. Magnolia’s use of 

ammonia in the liquefaction process would, therefore, be regulated by the DOT, EPA, and OSHA. 

Magnolia would comply with the comprehensive EPA RMP and OSHA PSM programs as well as the 

DOT’s requirements under Part 193 and NFPA 59A. By complying with the EPA RMP and OSHA PSM, 

Magnolia would comply with the same regulations as every other facility in the United States that uses 

quantities of ammonia above the regulatory threshold. As a result, 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, compliance with the requirements of 40 CFR 68, 

29 CFR 1910.119, and 49 CFR 193 would be addressed as part of the EPA, OSHA, and DOT inspection 

and enforcement programs. We also analyzed the potential impacts along the waterway from LNG 

marine traffic. As a cooperating agency, the Coast Guard analyzed the suitability of the waterway for 

LNG marine traffic. On September 15, 2014, the COTP issued an LOR and an LOR Analysis, which 

summarized the Coast Guard’s recommended risk mitigation measures. Following discussions between 

the Coast Guard and FERC staff, the Coast Guard re-issued an updated LOR and LOR Analysis on 

February 12, 2015.37 Based on the results of the assessment of potential risks to navigation safety and 

maritime security associated with the proposed facility, the Coast Guard has determined that the 

Calcasieu Ship Channel would be suitable for accommodating the type and frequency of LNG marine traffic 

 

37 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
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associated with this project. The recommendation was based on full implementation of the strategies and 

risk management measures identified to the Coast Guard by Magnolia in its WSA. Under the Ports and 

Waterways Safety Act, the Magnuson Act, the MTSA, and the Safety and Accountability For Every Port 

Act, the COTP has the authority to prohibit LNG transfer or LNG carrier movements within his or her 

area of responsibility if he or she determines that such action is necessary to protect the waterway, port, or 

marine environment. If appropriate resources are not in place prior to LNG carrier movement along the 

waterway, then the COTP would consider at that time what, if any, vessel traffic and/or facility control 

measures would be appropriate to adequately address navigational safety and maritime security 

considerations. FERC staff recommends Magnolia receive written authorization from the Director of 

OEP before commencement of service at the LNG terminal to ensure the Coast Guard has determined that 

appropriate measures to ensure the safety and security of the facility and the waterway have been put into 

place by Magnolia or other appropriate parties.

Based on our engineering design analysis and recommendations, the DOT siting requirements 

and recommendations, the LOR issued by the Coast Guard concluding the LNG vessel transit is suitable 

for LNG marine traffic, and the regulatory requirements for the design, construction, and operation of the 

Terminal, we conclude that the project would not result in significantly increased public safety risks.

4.12.11 Pipeline Safety Standards

The transportation of natural gas by pipeline involves some incremental risk to the public due to 

the potential for accidental release of natural gas. The greatest hazard is a fire or explosion following a 

major pipeline rupture.

Methane, the primary component of natural gas, is colorless, odorless, and tasteless. It is not 

toxic, but is classified as a simple asphyxiate, possessing a slight inhalation hazard. If breathed in high 

concentration, oxygen deficiency can result in serious injury or death. 

Methane has an auto-ignition temperature of 1,000 °F and is flammable at concentrations 

between 5.0 percent and 15.0 percent in air. An unconfined mixture of methane and air is not explosive, 

however it may ignite and burn if there is an ignition source. A flammable concentration within an 

enclosed space in the presence of an ignition source can explode. It is buoyant at atmospheric 

temperatures and disperses rapidly in air.

The DOT 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 state of Louisiana has section 5(a) certification.

The 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 
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(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 the 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.

The header pipelines and aboveground facilities associated with the KMLP facilities would be 

designed, constructed, operated, and maintained in accordance with the DOT Minimum Federal Safety 

Standards in 49 CFR 192. The regulations are intended to ensure adequate protection for the public and 

to prevent natural gas facility accidents and failures. The DOT specifies material selection and 

qualification; minimum design requirements; and protection from internal, external, and atmospheric 

corrosion. 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 below:

 Class 1 – location with 10 or fewer buildings intended for human occupancy;

 Class 2 – location with more than 10 but less than 46 buildings intended for human 

occupancy;

 Class 3 – location with 46 or more buildings intended for human occupancy, or where the 

pipeline lies within 100 yards of any building or small well-defined outside area 

(e.g., playground, recreation area, outdoor theater, or other place of public assembly) 

occupied by 20 or more people for at least 5 days a week for 10 days in any 12-month 

period (the days and weeks need not be consecutive); 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, 
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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 low pressure header pipeline, which consists of 

1.2 miles of 36-inch-diameter pipeline, and the high pressure header pipeline, which consists of 700 feet 

of 24-inch-diameter pipeline would be entirely located within Class 1 areas. KMLP would provide 

approximately 70 inches of cover, compared to the DOT-required 30 inches. 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, KMLP 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 Federal Register 69778, 69 Federal Register

18228, and 69 Federal Register 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 Federal 

Register 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.

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 radius is greater than 

660 feet and there are 20 or more buildings intended for human occupancy within the 

potential impact circle; 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.
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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. The 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. No 

HCAs are present along the proposed header pipeline routes. 

The minimum standards for operating and maintaining pipeline facilities are prescribed in 

49 CFR 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; 

 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 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. KMLP’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. KMLP 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.

KMLP would provide training to all employees responsible for operation and maintenance of the 

pipelines, compressor station, and meter stations installed or modified as part of the 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 in-house 

training, equipment vendors would provide training prior to start-up of new facilities.

The pipelines, compressor station, and meter stations associated with the KMLP facilities would 

be designed, constructed, operated, and maintained in accordance with the DOT Minimum Federal Safety 

Standards in 49 CFR 192. The regulations are intended to ensure adequate protection for the public and 

to prevent natural gas facility accidents and failures. The DOT specifies material selection and 

qualification; minimum design requirements; and protection from internal, external, and atmospheric 

corrosion. As a new pipeline and compressor station, and with the continuing advancements in materials 
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and pipeline operating and maintenance practices, the chances of a failure of the proposed facilities is 

extremely low. In addition, the safety and reliability of the KMLP facilities would be based on safe 

design, appropriate equipment selection, code compliance, thorough review, careful construction, and 

competent maintenance and operation. Measures would be incorporated according to approved design 

practices and standards. 

Measures to protect the public from inadvertent natural gas releases due to accidents or natural 

catastrophes can be grouped into three categories: passive protection, active controls, and procedural 

controls as described below. 

Passive Protection Measures

Passive protection minimizes the hazards by process and equipment design features, which 

reduce either the frequency or consequence of a hazard without the active functioning of a device. 

Passive protection would include the following measures:

 pipeline design, construction, commissioning, and operation would be conducted in strict 

accordance with applicable DOT regulations found at 49 CFR 192;

 pipeline design factor, wall thickness, and other parameters would be established 

according to a classification system based on the number, proximity to the pipeline, and 

occupation levels of buildings intended for human occupancy located along the right-ofway, in accordance with DOT regulations;

 KMLP would comply with the applicable sections of the ASME/ANSI B31.8, which is 

the most widely used industry code for the design, operation, maintenance, and repair of 

natural gas distribution and transmission pipelines;

 header pipelines would be externally coated with fusion-bonded epoxy to protect against 

corrosion; and

 construction specifications would be developed for installation of the proposed facilities 

incorporating relevant sections of FERC’s Plan and Procedures. These specifications 

along with project-specific plans and procedures for unique construction techniques 

would be included in a project-specific Environmental Management and Construction 

Plan.

Active Control Measures

Active (or engineering) controls use instruments, valves, safety interlocks, traffic control, and 

emergency shutdown systems to detect and correct process deviations; (e.g., line break detection 

systems). Active controls would include:

 KMLP’s gas control center in Houston, Texas monitors system pressures, flows, and 

customer deliveries. The gas control center is manned 24 hours per day, 365 days per 

year. KMLP also operates area offices along its pipeline system that allow personnel to 

respond appropriately to emergency situations and direct safety operations as necessary. 

Additionally, KMLP maintains a backup location for gas control operations in the event 

the primary location is placed out of service; 
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 to protect the integrity of the KMLP system, an overpressure protection system, set at 

104 percent of the MAOP of the pipeline, would be employed;

 to protect the integrity of the pipeline system, an impressed current cathodic protection 

system would be installed as a corrosion prevention measure;

 a Supervisory Control and Data Acquisition (SCADA) system would provide for and 

enable pipeline monitoring and the control of the gas pipeline;

 Remote Terminal Units for the SCADA system would be located at every interconnect 

manifold, and at the start and end point of the pipeline;

 all field girth welds would be tested via x-ray or ultrasonic;

 an increase in local traffic is anticipated as a result of construction activities. KMLP 

would coordinate with local authorities to provide for traffic control as necessary. If 

required, signage and flaggers would be provided to ensure public safety;

 the pipeline and associated facilities would be hydrostatically tested for structural 

integrity before commencing operation; and

 the pipeline would be equipped with facilities to accommodate smart pigging operations 

for the purpose of locating anomalies in the pipeline wall thickness that may indicate 

corrosion, and out-of-roundness than may indicate the pipe has been subjected to external forces.

Procedural Control Measures

Procedural (or administrative) controls use operating procedures, administrative checks, 

emergency response, and other management approaches to prevent incidents, or to minimize the effects of 

an accident (e.g., operating procedures, safe work practices, inspections and testing, and training). 

Procedural controls would include:

 procedures for testing, start-up, operation, and training of operations and maintenance 

staff on operational procedures;

 regularly scheduled preventative maintenance programs to meet government regulations 

for pipeline segments and metering stations;

 an Emergency Response Plan, to be developed with local fire departments and other 

agencies, to respond to hazardous conditions caused by the pipeline (KMLP would 

establish and maintain liaison with the appropriate fire, police, and public officials to 

coordinate mutual assistance during emergencies);

 a continuing education program to enable customers, the public, government officials, 

and those engaged in excavation to recognize a natural gas pipeline emergency and report 

it to appropriate public officials and the company; and

 procedures for aerial surveillance flights, on-ground leak detection surveys, internal 

pipeline inspection with pigging equipment, and cathodic protection system inspection 

and maintenance.
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4.12.11.1 Pipeline Accident Data

Title 49 CFR 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.38

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 4.12.11-1 provides the number of significant incidents by cause 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 4.12.11-1 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, required on all pipelines installed after July 1971, substantially reduces the corrosion 

rate compared to unprotected or partially protected pipe.

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 4.12.11-1 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. 

TABLE 4.12.11-1

Natural Gas Transmission Pipeline Significant Incidents by Cause (1994–2013)

Cause Number of Incidents Percentage of Total Incidents a

Corrosion 293 23.6

Excavation b 211 17.0

Pipeline material, weld, or equipment failure 309 24.9

Natural force damage 143 11.5

Outside forces c 75 6.0

Incorrect operation 34 2.7

All other causes d 173 13.9

Total 1,238 --

____________________

Source PHMSA, 2014a

a Due to rounding, column does not total 100 percent.

b

Includes third-party damage.

c Fire, explosion, vehicle damage, intentional damage.

d Miscellaneous or unknown causes.

 

38 $50,000 in 1984 dollars is about $113,000 dollars as of March 2015 (Bureau of Labor Statistics, 2015).
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TABLE 4.12.11-2

Outside Force Incidents by Cause (1994–2013) a

Cause Number of Incidents Percentage of Total Incidents b

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 --

____________________

Source PHMSA, 2014a

a Excavation, outside forces, and natural force damage from table 4.12.9-1.

b Due to rounding, column does not total 100 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.

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 pre-construction information to contractors or other 

maintenance workers on the underground location of pipes, cables, and culverts.

4.12.11.2 Impacts on Public Safety

The significant incident data summarized in table 4.12.11-1 include pipeline failures with varying 

magnitudes and consequences. Although the transportation of natural gas via 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 costefficient way to transport natural gas (PHMSA, 2014a). Table 4.12.11-3 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.
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TABLE 4.12.11-3

Annual Average Injuries and Fatalities (2009–2013)

Year

Injuries Fatalities

Employees Public Employees Public

2009 4 7 0 0

2010 a 10 51 2 8

2011 1 0 0 0

2012 3 4 0 0

2013 0 2 0 0

____________________

Source PHMSA, 2014b

a All of the public injuries and fatalities in 2010 were due to the Pacific Gas and Electric pipeline rupture and fire in San 

Bruno, California on September 9, 2010.

The 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 4.12.11-4 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.

TABLE 4.12.11-4

Nationwide Accidental Deaths from Various Causes

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

Flood 89 a

Lightning 52 a

Tornado 74 a

Natural gas distribution lines 14 b

Natural gas transmission lines 2 b

____________________

Source U.S. Census Bureau, 2010d

a National Weather Service, 2014b

b PHMSA, 2014b
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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 KMLP facilities would be constructed and operated in accordance with 

DOT requirements; therefore we conclude operation of the KMLP facilities would be safe and would 

represent only a slight increase in risk to the nearby public.

As discussed in section 4.12.9, the risk associated with the proposed facilities would be small. 

Although operation of the KMLP facilities would have a very small incremental increase in the risk of a 

pipeline accident. As a result, the cumulative impact and risks associated with constructing or operating 

the 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 Magnolia LNG and Lake Charles Expansion Projects 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 proposed projects along with

other projects in the vicinity that could affect the same resources in the same approximate timeframe. 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 projects;

 impact that resource within all or part of the time span encompassed by the proposed or 

reasonably expected construction or operation schedule of the projects; and

 impact that resource within all or part of the same geographical area affected by the 

projects. The geographical area considered varies depending on the resource being 

discussed, which is the general area (region of influence) in which the projects could 

contribute to cumulative impacts on that particular resource. 

4.13.1 Project and Activities Considered

With respect to past actions, CEQ 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 currently supports a large 

amount of industrial and commercial infrastructure, forms the environmental baseline described in other 

sections of this EIS and against which the impacts of reasonably foreseeable future actions are considered. 

Recently completed projects are included with past projects as part of the environmental baseline. 

Reasonably foreseeable projects that might cause cumulative impacts in combination with the proposed 

projects include projects that are under construction, approved, proposed, or planned. For FERCregulated 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 
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have been identified through publically available information such as press releases, internet searches, 

Magnolia’s and KMLP’s communications with local agencies, and information available from the 

Southwest Louisiana Economic Development Alliance (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, 

including the location, distance from the projects, workforce, construction timeframe, and resources 

cumulatively affected in conjunction with the proposed facilities. Project locations are identified in 

figures 4.13.1-1 and 4.13.1-2. 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. 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.

4.13.1.1 Liquefaction and LNG Export Projects

We identified 17 projects associated with the liquefaction and export of LNG that are proposed, 

planned, or under construction in the vicinity of the proposed projects that have the potential to contribute 

to cumulative impacts (see table 4.13.1-1 and figure 4.13.1-1). Of the 17 projects, 8 are associated with 

existing LNG terminals, including the Trunkline, Cameron, Sabine Pass, and Golden Pass LNG 

Terminals. Three of these projects (Cameron Liquefaction Project, Cameron Pipeline Expansion Project, 

and Sabine Pass Liquefaction Project) have been permitted and are currently under construction. One 

project (the Sabine Pass Liquefaction Expansion Project) has been authorized by the Commission, but has 

not yet begun construction. The four other projects at existing LNG terminals are undergoing the FERC’s 

environmental review. In addition to projects at existing LNG terminals, nine new liquefaction and LNG 

export terminals are planned or proposed in the area. These include three projects that have entered the 

FERC’s review process (Calcasieu Pass Project, Delfin LNG Project, and Port Arthur Liquefaction 

Project) and seven projects that have been announced but have not yet entered into the FERC’s review 

process. Brief descriptions of each of the projects associated with liquefaction and LNG export are 

provided below. 

Liquefaction and LNG Export Projects at Existing LNG Terminals

Cameron LNG Terminal

The existing Cameron LNG Terminal is in Cameron Parish, Louisiana, approximately 5 miles 

south of Magnolia’s proposed LNG terminal on the western shoreline of the Calcasieu Ship Channel. 

Four expansion projects associated with the Cameron LNG Terminal are currently under construction 

(Cameron Liquefaction Project and Cameron Pipeline Expansion Project), proposed (Cameron Access 

Project), or planned (Cameron Expansion Project). 

The Cameron Liquefaction Project,

39 which will have a send-out capacity of approximately 

15 MTPA of LNG, was authorized by the Commission in June 2014 and is currently under construction 

within and immediately adjacent to the existing Cameron LNG Terminal. The project, which is 

scheduled to begin operation in 2018, includes three liquefaction trains (Trains 1 through 3) and one LNG 

storage tank (Tank 4).

 

39 The Cameron Liquefaction Project, Cameron Pipeline Expansion Project, and Cameron Expansion Project are discussed in more detail in 

section 3.2.1.1.
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See Page 2

WesPac 

LNG 

Project

Port Arthur 

LNG Project

Delfin

LNG 

Project

Liberty Gas Storage 

Expansion Project

Compressor Station 760

Magnolia

LNG Terminal

Audubon

Trace

Cleco - Electric Transmission

for Compressor Station 760

Ohio-Louisiana Access Projects

G2 LNG

Project

SCT&E LNG

Project

Waller Point

LNG Project Calcasieu

Pass Project

Sabine Pass

LNG Terminal

Golden 

Pass

LNG 

Terminal

Gasfin LNG

Project

Acadia

Allen

Calcasieu

Cameron

Evangeline

Jefferson

Davis

Vermilion

Jasper

Beauregard

Jefferson

Newton

Orange

This information is for environmental review purposes only.

0 5 10

Miles

KMLP System

^ Agency Projects

^ Commercial Developments

^ Existing LNG Terminal Expansions

^ Greenfield LNG Terminal Projects

^ Industrial Projects

^ Pipeline Expansion Project

^ Residential Developments

^ Utility Projects

Page 2 Extent

p Figure 4.13.1-1

Projects Considered in the Cumulative 

Impacts Analysis

Magnolia LNG and Lake Charles 

Expansion Projects

1:600,000

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an ERM Group company

4-227
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Magnolia 

LNG Terminal

24

19

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5

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8

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21

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12

25

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Calcasieu

Cameron

Calcasieu

Jefferson Davis

This information is for environmental review purposes only.

0 1.5 3

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KMLP System

^ Agency Projects

^ Commercial Developments

^ Existing LNG Terminal Expansions

^ Greenfield LNG Terminal Projects

^ Industrial Projects

^ Residential Developments

^ Utility Projects p an ERM Group company

Figure 4.13.1-1

Projects Considered in the Cumulative 

Impacts Analysis

Magnolia LNG and Lake Charles 

Expansion Projects

1:175,000

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Page 2 of 2

Number Name

1 Belle Savanne

2 Calcasieu Parish District 12 Water Works

3 Calcasieu Point Development Project

4 Cameron LNG Terminal

5 DOTD Cove Lane Interchange Project

6 Entergy - Electric Transmission and Substation for 

Lake Charles Liquefaction Project

7 Entergy - Electric Transmission and Substation for 

Magnolia LNG Project

8 Entergy - Electric Transmission and Switching 

Station for the Cameron Liquefaction Project

9 Entergy - Lake Charles Transmission Project

10 G2X Energy Lake Charles Gasoline Facility

11 Graywood

12 IFG Export Grain Terminal

13 Juniper GTL Plant

14 LDWF's Fisheries Research Center

15 Live Oak LNG Project

16 Maintenance Dredging of Industrial Canal

17 Matheson Tri-Gas Air Seperation Unit

18 Moss Lake Worker Village

19 Pelican Lodge

20 Port of Lake Charles Docks at Bulk Terminal 1

21 Sasol Ethane Cracker and Derivatives Complex

22 Sasol Gas-to-liquids Facility

23 Trunkline LNG Terminal

24 Walnut Grove

25 Westlake Chemical Corporation

4-228
4-229 

TABLE 4.13.1-1

Reasonably Foreseeable Projects and Resources Considered in the Cumulative Impacts Analysis for the 

Magnolia LNG and Lake Charles Expansion Projects 

Project/Activity Location 

Distance from 

Facilities 

Estimated 

Timeframe 

Included in 

Cumulative 

Impact 

Analysis 

INDUSTRIAL DEVELOPMENTS 

Liquefaction and LNG Export Projects Associated with Existing LNG Terminals

Cameron LNG Terminal 

Cameron Liquefaction Project Calcasieu Ship Channel, 

Cameron Parish, LA 

5 miles Construction 2014 

Operation 2018 

Yes 

Cameron Expansion Project Calcasieu Ship Channel, 

Cameron Parish, LA 

5 miles Construction 2016 

Operation 2019 

Yes 

Cameron Pipeline Expansion 

Project 

Cameron and Beauregard 

Parishes, LA 

14 miles Construction 2014 

Operation 2017 

Yes 

Cameron Access Project Cameron, Calcasieu, and 

Jefferson Davis Parishes, LA 

3 miles Construction 2016 

Operation 2017 

Yes 

Golden Pass LNG Terminal 

Golden Pass Products LNG 

Export Project 

Sabine Pass, 

Jefferson County, TX 

44 miles Construction 2015 

Operation 2018 

No 

Trunkline LNG Terminal 

Lake Charles Liquefaction 

Project 

Industrial Canal, 

Calcasieu Parish, LA 

1,000 feet Construction 2015 

Operation 2019 

Yes 

Sabine Pass LNG Terminal 

Sabine Pass Liquefaction 

Project 

Sabine Pass, 

Cameron Parish, LA 

42 miles Construction 2013 

Operation 2017 

Yes 

Sabine Pass Liquefaction 

Expansion Project 

Sabine Pass, 

Cameron Parish, LA 

42 miles Construction 2015 

Operation 2019 

Yes 

Greenfield Liquefaction and LNG Export Projects

Calcasieu Pass Project Calcasieu Ship Channel, 

Cameron Parish, LA 

23 miles Construction 2016 

Operation 2019 

Yes 

Delfin LNG Project Gulf of Mexico 74 miles Construction 2017 

Operation 2018 

Yes 

G2 LNG Project Calcasieu Ship Channel, 

Cameron Parish, LA 

20 miles Construction TBD 

Operation 2019 

Yes 

Gasfin LNG Project Calcasieu Ship Channel, 

Cameron Parish, LA 

22 miles Not Available No 

Live Oak LNG Project Calcasieu Ship Channel, 

Calcasieu Parish, LA 

2 miles Construction NA 

Operation 2019 

Yes 

Port Arthur Liquefaction Project Jefferson County, TX 45 miles Construction 2017 

Operation 2021 

No 

SCT&E LNG Project Calcasieu Ship Channel, 

Cameron Parish, LA 

22 miles Not Available No 

Waller Point LNG Project Calcasieu Ship Channel, 

Cameron Parish, LA 

23 miles Not Available No 

WesPac LNG Project Jefferson County, TX 45 miles Not Available No 
4-230

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Projects and Resources Considered in the Cumulative Impacts Analysis for the 

Magnolia LNG and Lake Charles Expansion Projects

Project/Activity Location

Distance from 

Facilities

Estimated

Timeframe

Included in 

Cumulative 

Impact 

Analysis

Non-jurisdictional Facilities Associated with the Magnolia LNG and Lake Charles Expansion Projects

LNG Trucking Lake Charles, 

Calcasieu Parish, LA

0 feet 

(property 

boundary) 

Begin operation in 2018 Yes

LNG Bunkering and Domestic 

Marine Distribution

Calcasieu Ship Channel

Calcasieu and Cameron 

Parishes, LA

0 feet 

(upon exiting 

the berthing 

area)

Begin operation in 2018 Yes

Calcasieu Parish District 12 Water 

Works’ Tie-in to the LNG Terminal

Lake Charles, 

Calcasieu Parish, LA

0 feet

(within LNG 

terminal)

Dependent on proposed 

LNG terminal schedule

Yes

Entergy’s Electric Transmission 

Line for the LNG Terminal

Lake Charles, 

Calcasieu Parish, LA

0 feet

(within and 

adjacent to 

LNG terminal)

Dependent on proposed

LNG terminal schedule

Yes

Cleco’s Electric Transmission Line 

for Compressor Station 760

Acadia Parish, LA 0 feet 

(adjacent to 

Compressor 

Station 760)

Dependent on KMLP 

facilities schedule

Yes

Pipeline System Modification Projects

Ohio–Louisiana Access Project Acadia Parish, LA 0.4 mile Construction 2015

Operation 2016

No

Other Industrial and Commercial Projects

G2X Energy’s Natural Gas to 

Gasoline Facility

Industrial Canal, 

Calcasieu Parish, LA

1,000 feet Construction 2015

Operation 2017

Yes

IFG Port Holdings, LLC’s Export 

Grain Terminal Expansion

Port of Lake Charles, 

Calcasieu Parish, LA

8 miles Construction 2012

Operation 2015

No

Juniper GTL Plant Westlake, 

Calcasieu Parish, LA

9 miles Construction 2014

Operation 2015

No

Liberty Gas Storage, LLC’s Liberty 

Gas Storage Expansion Project

Calcasieu and Cameron 

Parishes, LA

5 miles Construction 2015

Operation 2017

Yes

Matheson Tri-Gas’ Air 

Separation Unit

Westlake, 

Calcasieu Parish, LA

10 miles Construction 2015

Operation 2016

Yes

Port of Lake Charles’ Docks at 

Bulk Terminal 1

Lake Charles, 

Calcasieu Parish, LA

7 miles Not Available Yes

Sasol’s Ethane Cracker and 

Derivatives Complex

Westlake, 

Calcasieu Parish, LA

10 miles Construction 2014

Operation 2018

Yes

Sasol’s Gas-to-Liquids Facility Westlake, 

Calcasieu Parish, LA

10 miles Investment Decision 

Delayed

No

Westlake Chemical Corporation Lake Charles, 

Calcasieu Parish, LA

6 miles Construction 2015

Operation 2016

Yes

Other Utility Projects

Calcasieu Point Development 

Project

Lake Charles,

Calcasieu Parish, LA

0.6 mile Construction 2015

Operation 2016

No

Entergy’s Lake Charles 

Transmission Project

Lake Charles, 

Calcasieu Parish, LA

5 miles Construction 2016

Operation 2018

Yes
4-231

TABLE 4.13.1-1 (cont’d)

Reasonably Foreseeable Projects and Resources Considered in the Cumulative Impacts Analysis for the 

Magnolia LNG and Lake Charles Expansion Projects

Project/Activity Location

Distance from 

Facilities

Estimated

Timeframe

Included in 

Cumulative 

Impact 

Analysis

Entergy’s Transmission Line and 

Substation for the Lake Charles 

Liquefaction Project

Calcasieu and Beauregard 

Parishes, LA

0.7 mile Dependent on an 

LNG Project

Yes

Entergy’s Transmission Line for 

the Cameron Liquefaction Project

Cameron and Calcasieu 

Parishes, LA

5 miles Dependent on an LNG 

Project

Yes

RESIDENTIAL DEVELOPMENTS

Audubon Trace Moss Bluff, 

Calcasieu Parish, LA

15 miles Construction 2015

Operation unknown

Yes

Belle Savanne Sulphur, 

Calcasieu Parish, LA

7 miles Construction 2013

Operation unknown

Yes

Moss Lake Worker Village Carlyss, 

Calcasieu Parish, LA

4 miles Construction 2015

Operation TBD

Yes

Pelican Lodge Workforce Housing Lake Charles,

Calcasieu Parish, LA

12 miles Construction 2014

Operation TBD

Yes

Walnut Grove Development Lake Charles,

Calcasieu Parish, LA

8 miles Construction 2010

Operation 2019

Yes

FEDERAL AND STATE AGENCY PROJECTS

DOTD’s Cove Lane Interchange 

Project

Cameron and Calcasieu 

Parishes, LA

6 miles Construction 2015

Operation 2015

No

LDWF’s Fisheries Research 

Center

Lake Charles,

Calcasieu Parish, LA

100 feet

(adjacent to 

LNG terminal)

Construction 2016

Operation 2020–2021

Yes

COE and Lake Charles Harbor 

and Terminal District’s 

Maintenance Dredging of the 

Calcasieu Ship Channel

Cameron and Calcasieu

Parishes, LA

0 feet

(adjacent to 

LNG terminal)

Ongoing Yes

____________________

Notes: NA = Not applicable; TBD = To be determined

Modifications to Cameron Interstate’s existing natural gas pipeline system are required to provide 

feed gas for the Cameron Liquefaction Project. The modifications, known as the Cameron Pipeline 

Expansion Project, were authorized by the Commission in June 2014 and include the construction and 

operation of about 21 miles of natural gas pipeline, one compressor station, one new interconnect, and 

associated facility modifications to provide for bi-directional transportation of natural gas. The closest

component of the project to Magnolia’s proposed LNG terminal is the natural gas pipeline, which is 

approximately 14 miles north-northwest of the site. Construction of the Cameron Pipeline Expansion 

Project began in 2014; the facilities are expected to begin operation in 2017.

Cameron LNG entered into the FERC’s pre-filing process for the Cameron Expansion Project in 

March 2015, which would increase the LNG send-out capacity by 10 MTPA over the capacity authorized 

by the Cameron Liquefaction Project. The project would include the construction and operation of two 

additional liquefaction trains (Trains 4 and 5) and one additional LNG storage tank (Tank 5), which 

would be adjacent to and integrated with the Cameron Liquefaction Project. If approved by the 

Commission, the project would begin construction in May 2016 and begin operation in 2019. 
4-232

Columbia Gulf Transmission, LLC (Columbia Gulf) filed an application with the FERC in March 

2015 for a project (known as the Cameron Access Project) that would involve the construction of 

approximately 27 miles of 36-inch-diameter greenfield pipeline, approximately 10 miles of

30-inch-diameter loop pipeline, and a new 10,200-hp compressor station in Cameron, Calcasieu, and 

Jefferson Davis Parishes.40 At its closest point, the pipeline would be about 3 miles south of Magnolia’s

proposed LNG terminal. If approved by the Commission, construction of the Cameron Access Project 

would begin in September 2016; operation of the project would begin in July 2017.

Due to the overlapping construction schedules and proximity to the projects, construction and 

operation of the four expansion projects associated with the Cameron LNG Terminal have been included 

in our cumulative impacts analysis, as indicated in table 4.13.1-1. 

Golden Pass LNG Terminal

The Golden Pass LNG Terminal is in Jefferson County, Texas, about 44 miles southwest of 

Magnolia’s proposed LNG terminal. As discussed in section 3.2.1.1, Golden Pass submitted an 

application with the FERC in July 2014 for the Golden Pass Products LNG Export Project, which would 

be 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 projects as well as its location on the 

western shoreline of the Sabine Pass Channel in Texas, the Golden Pass Products LNG Export Project 

would not contribute to cumulative impacts on any resources affected by the projects, as indicated in table 

4.13.1-1.

Sabine Pass LNG Terminal

The Sabine Pass LNG Terminal is in Cameron Parish, Louisiana, approximately 42 miles 

southwest of Magnolia’s proposed LNG terminal. Two liquefaction and LNG export projects associated 

with the Sabine Pass LNG Terminal have been authorized by the Commission, including the Sabine Pass 

Liquefaction Project and the Sabine Pass Liquefaction Expansion Project.

The Sabine Pass Liquefaction Project was authorized by the Commission in April 2012 and is 

currently under construction within the existing 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. 

The Sabine Pass Liquefaction Expansion Project was authorized by the Commission in April 

2015, and it is expected that construction of two additional liquefaction trains (Trains 5 and 6) will begin

in 2015 with an anticipated in-service date in 2019. 

Due to the overlapping construction schedules and proximity to the projects, construction and 

operation of the two expansion projects associated with the Sabine Pass LNG Terminal have been 

included in our cumulative impacts analysis, as indicated in table 4.13.1-1.

Trunkline LNG Terminal

The Trunkline LNG Terminal is in Calcasieu Parish, Louisiana, approximately 1,000 feet 

northeast of Magnolia’s proposed LNG terminal on the north side of the Industrial Canal. The existing 

 

40 Docket No. CP15-109-000
4-233

import terminal includes vaporization units, four aboveground LNG storage tanks, and two LNG carrier 

berths on an approximately 125-acre site. 

In March 2014, the Lake Charles LNG companies submitted an application to the FERC to 

construct and operate a liquefaction and LNG export project (the Lake Charles Liquefaction Project) that 

would be contiguous to and integrated with the existing Trunkline LNG Terminal (see section 3.2.1.1). 

The proposed liquefaction facilities would be immediately north of and adjacent to the existing Trunkline 

LNG Terminal and would include three liquefaction trains with a design production capacity of 

approximately 16.5 MTPA. Feed gas would be delivered via existing pipeline facilities that connect the 

terminal with various existing interstate pipeline systems, and/or by new pipeline facilities that have been 

proposed by the Lake Charles LNG companies. 

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

approvals, construction of the Lake Charles Liquefaction Project would commence in 2015, and the first 

liquefaction train would be placed into service in 2019. The second and third liquefaction trains would be

placed into service in 6-month intervals following start-up of the first train. Due to the overlapping 

construction schedules and proximity to the projects, the construction and operation of the Lake Charles 

Liquefaction Project has been included in our cumulative impacts analysis, as indicated in table 4.13.1-1.

Greenfield Liquefaction and LNG Export Projects

Calcasieu Pass Project

Venture Global plans to develop a liquefaction and LNG export terminal in Cameron Parish

approximately 23 miles south of Magnolia’s proposed LNG terminal 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 for the Calcasieu Pass Project in October 2014. The project is 

described in detail in section 3.2.1.2. Subject to the receipt of the necessary approvals, Venture Global 

plans to begin construction of the project in October 2016 and would begin operation in December 2019. 

Due to the overlapping construction schedules and proximity to the projects, construction and operation 

of the Calcasieu Pass Project has been included in our cumulative impacts analysis, as indicated in table 

4.13.1-1. 

Delfin LNG Project

Delfin plans to develop a floating liquefaction and LNG export terminal in the West Cameron 

Block 167 in the Gulf of Mexico. Delfin’s facility would qualify as a “deepwater port” under the 

Deepwater Port Act and, as such, would require a license from MARAD in conjunction with the Coast 

Guard. The facility would be approximately 50 miles offshore from Cameron Parish, Louisiana and 

74 miles south of Magnolia’s proposed LNG terminal (see figure 4.13.1-1). The project is described in 

detail in section 3.2.1.2. On May 8, 2015, Delfin filed its deepwater port application with MARAD as 

well as its application for onshore facilities with the FERC. 

Subject to the receipt of the necessary approvals, Delfin plans to begin construction of the 

offshore components of the project in 2018. Construction of the first phase of the onshore facilities 

would begin in the third quarter of 2017 and would be completed in October 2018. The second phase of 

construction of the onshore facilities (installation of additional compression) is expected to take place in 

2020. Due to the overlapping construction schedules and the potential for cumulative impacts within the 

Gulf of Mexico, construction and operation of the Delfin LNG Project has been included in our 

cumulative impacts analysis, as indicated in table 4.13.1-1. 
4-234

G2 LNG Project

G2 LNG plans to develop a liquefaction and LNG export terminal on the Calcasieu Ship Channel 

in Cameron Parish, Louisiana, approximately 20 miles south of Magnolia’s proposed LNG terminal (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 potential for overlapping construction schedules and 

proximity to Magnolia’s proposed LNG terminal, construction and operation of the G2 LNG Project has 

been included in our cumulative impacts analysis, as indicated in table 4.13.1-1.

Gasfin LNG Project

Gasfin has announced plans for a liquefaction and LNG export terminal on the east side of the 

Calcasieu Ship Channel in Cameron Parish, Louisiana, approximately 23 miles south of Magnolia’s

proposed LNG terminal (see figure 4.13.1-1). The project is in the initial development phase and Gasfin 

has not requested initiation of 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, as indicated in table 4.13.1-1. 

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 Magnolia’s

proposed LNG terminal (see figure 4.13.1-1). The project, which is described in additional detail in 

section 3.2.1.2, 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. Due to the potential for overlapping construction schedules and 

proximity to Magnolia’s proposed LNG terminal, construction and operation of the Live Oak LNG 

Project has been included in our cumulative impacts analysis, as indicated in table 4.13.1-1.

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 Magnolia’s proposed LNG terminal (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. 

The project is described in detail in section 3.2.1.2. 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 

distance of the Port Arthur Liquefaction Project from the proposed projects as well as its location on the 

western shoreline of the Sabine-Neches Waterway in Texas, the Port Arthur Liquefaction Project would

not contribute to cumulative impacts on any resources affected by the projects, as indicated in 

table 4.13.1-1.

SCT&E LNG Project

SCT&E LNG has announced plans for a liquefaction and LNG export terminal on Monkey Island 

in Cameron Parish, Louisiana, approximately 22 miles south of Magnolia’s proposed LNG terminal (see 

figure 4.13.1-1). The project is in the initial development phase and SCT&E LNG has not requested 

initiation of 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, as indicated in table 4.13.1-1. 
4-235

Waller Point LNG Project

Waller Point LNG announced plans for a liquefaction and LNG export terminal on the western 

shore of the Calcasieu Ship Channel in Cameron Parish, Louisiana, approximately 23 miles south of 

Magnolia’s proposed LNG terminal (see figure 4.13-1). The project is in the initial development phase,

and Waller Point LNG 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, as indicated in table 4.13.1-1.

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 Magnolia’s proposed LNG terminal

(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, as indicated in table 4.13.1-1.

4.13.1.2 Non-jurisdictional Facilities Associated with the LNG Terminal and KMLP Facilities

LNG Trucking

As described in section 1.4.1, the proposed LNG trucking facilities within the LNG terminal

would be jurisdictional facilities. However, Magnolia’s LNG trucking activities that occur after the LNG 

truck has departed from the terminal do not fall under the jurisdiction of the FERC. 

During operation of the LNG terminal, a portion of the LNG would be loaded onto trucks for road 

distribution to refueling stations in Louisiana and the surrounding states. While no agreements have been 

executed for the transportation of LNG in trucks, Magnolia anticipates that, on average, one

12,500-gallon capacity LNG truck would be loaded per week at the LNG terminal. LNG trucks calling 

on the proposed terminal are expected to deliver the LNG to one of the nine LNG refueling stations 

currently in operation in Louisiana and Texas, or to additional LNG refueling stations currently under 

development. As part of the non-jurisdictional facilities associated with the proposed project, LNG 

trucking has been included in our cumulative impacts analysis, as indicated in table 4.13.1-1. 

LNG Bunkering and Domestic Marine Distribution

The proposed LNG barge loading facilities at the LNG terminal would be jurisdictional facilities. 

However, Magnolia’s LNG bunkering and domestic marine distribution of LNG would occur after the 

LNG vessel has departed from the LNG terminal and, therefore, do not fall under the jurisdiction of the 

FERC.

Magnolia anticipates that LNG would be loaded onto one or two LNG barges per week (up to 

104 per year) for domestic marine distribution and the possibility of LNG bunkering. LNG barges loaded 

at the LNG terminal would be expected to deliver LNG to the ship fueling facilities and offshore support 

port areas along the central Gulf Coast (ships and offshore supply vessels would not be directly 

fueled/bunkered at the LNG terminal). As part of the non-jurisdictional facilities associated with the 

proposed project, LNG bunkering and domestic marine distribution have been included in our cumulative 

impacts analysis, as indicated in table 4.13.1-1. 
4-236

Calcasieu Parish District 12 Water Works’ Existing Water Pipeline 

Calcasieu Parish District 12 Water Works’ existing 12-inch-diameter water pipeline runs along 

the entire length of the proposed LNG terminal site just north of Henry Pugh Boulevard. In order to 

provide potable water during operation of the LNG terminal, Magnolia would request installation of an 

interconnect with the existing water pipeline, which would affect less than 0.1 acre of land within the 

LNG terminal site (see figure 1.4.2-1 in section 1.4.2). As part of the non-jurisdictional facilities 

associated with the proposed project, the water tie-in has been included in our cumulative impacts 

analysis, as indicated in table 4.13.1-1. 

Entergy’s Electric Transmission Line and Switching Station for the LNG Terminal

To provide electrical power to the LNG terminal, Entergy would build a 1.3-mile-long, doublecircuit 230 kV electric transmission line connecting its existing Graywood substation to a new switching 

station at the LNG terminal site, as described in section 1.4.3 and depicted on figure 1.4.3-1.

Based on the preliminary design, Entergy would construct the electric transmission line within a 

170-foot-wide right-of-way, which would be adjacent to, or possibly overlap with, the existing road and 

utility rights-of-way on Lincoln Road, Big Lake Road, and Henry Pugh Boulevard. The transmission line 

right-of-way would occupy 26.1 acres of land, including 11.5 acres of open land, 10.4 acres of wetland, 

and 4.2 acres of upland forest. The majority of the impacts associated with construction and operation of 

the transmission line would result from the installation of 15 to 18 poles to support the power lines, and 

the removal of select trees within the right-of-way. As part of the non-jurisdictional facilities associated 

with the proposed project, the electric transmission line and switching station have been included in our 

cumulative impacts analysis, as indicated in table 4.13.1-1. 

Cleco’s Electric Transmission Line for Compressor Station 760

To provide electrical power to Compressor Station 760, Cleco would construct a 0.3-mile-long 

34.5 kV electric transmission line from its existing 34.5 kV electric transmission line to the proposed 

compressor station, as described in section 1.4.4. The transmission line would begin at the existing 

transmission line on the west side of Refinery Road and would proceed east across Refinery Road and 

agricultural land to the Compressor Station 760 site.

Based on the initial design, the transmission line would be located within a 20-foot-wide right-ofway, which would occupy 0.7 acre of agricultural land and less than 0.1 acre of existing road and utility 

rights-of-way. The poles supporting the transmission line wires are expected to be between 90 and 

100 feet in height and spaced approximately 600 feet apart (resulting in the installation of three poles). 

Impacts associated with construction and operation of the transmission line would be due to the 

installation of poles to support the power line and a small transformer pad at Compressor Station 760. As 

part of the non-jurisdictional facilities associated with the proposed project, the electric transmission line 

and switching station have been included in our cumulative impacts analysis, as indicated in table 4.13.1-1. 

4.13.1.3 Pipeline System Projects

Ohio–Louisiana Access Project

TGT filed an application with the FERC in September 2014 for a project that would include one 

new compressor station in Ouachita Parish, Louisiana (Bosco Compressor Station); yard and station 

piping modifications at existing compressor stations in Caldwell, Acadia, and Rapides Parishes, Louisiana 

and Dearborn, Indiana; and piping and valve modifications and installation of bi-directional metering at 
4-237

an existing meter station in Ouachita Parish, Louisiana.41 The proposed modifications at the existing 

Eunice Compressor Station would occur in Acadia Parish, Louisiana about 0.4 mile west of KMLP’s 

proposed Compressor Station 760. FERC issued the Notice of Schedule for Environmental Review of the 

Proposed Ohio–Louisiana Access Project on March 13, 2015, which indicates that the Federal 

Authorization Decision Deadline for the project is July 2015. Pending regulatory approvals, TGT 

anticipates construction would begin in August 2015 and service of the modified compressor station 

would begin in June 2016. Because the Ohio–Louisiana Access Project would be in service prior to the 

beginning of construction activities at KMLP’s Compressor Station 760, it is considered part of the 

environmental baseline and is not discussed further in this cumulative impact analysis.

4.13.1.4 Other Industrial and Commercial Projects

G2X Energy’s Natural Gas to Gasoline Facility

G2X Energy, Inc. (G2X Energy) plans to construct a natural gas to gasoline facility along the 

Industrial Canal on a 200-acre site owned by the Lake Charles Harbor and Terminal District about 

1,000 feet north-northwest of the proposed LNG terminal. The facility would convert domestic natural 

gas into approximately 12,500 barrels per day of sulfur, gasoline, and/or methanol. The product would 

then be supplied 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 facility would contribute to the cumulative effects on resources in the vicinity of the 

projects; therefore this facility has been included in our cumulative impacts analysis, as indicated in

table 4.13.1-1.

IFG Port Holdings, LLC’s Export Grain Terminal Expansion

IFG Port Holdings, LLC’s (IFG) export grain terminal at the Port of Lake Charles, is about 

7 miles north of the proposed LNG terminal. 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. Because the expansion of the export grain terminal would be 

completed before construction begins for the LNG terminal, it is considered part of the environmental 

baseline and is not discussed further in this cumulative impact analysis.

Juniper GTL Project

Juniper GTL, LLC is renovating a dormant steam methane reformer at its Westlake chemical 

plant, about 9 miles north of the proposed LNG terminal. The steam methane reformer will convert 

natural gas into synthesis gas, a combination of hydrogen and CO, which is used to make products such 

as methanol and ammonia. The methane reformer will be part of a new $100 million natural gas-toliquids facility, producing about 1,100 barrels per day of waxes, drilling fluids, diesel, and naphtha. The 

new plant infrastructure is under construction and expected to begin operation in late 2015. Because the 

natural gas-to-liquids facility would begin operation before construction begins for the LNG terminal, it is 

considered part of the environmental baseline and is not discussed further in this cumulative impact 

analysis.

 

41 Docket No. CP14-553
4-238

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.

42

 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 proposed LNG terminal. 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 LNG terminal site as well as a 

4.0-mile-long brine disposal pipeline and four salt water disposal wells 10 miles south-southwest of the 

LNG terminal site. The Liberty Gas Storage Expansion Project is expected to begin operation in 2017. 

Due to overlapping construction schedules and proximity to the proposed LNG terminal, construction and 

operation of the Liberty Gas Storage Expansion Project has been included in our cumulative impacts 

analysis, as indicated in table 4.13.1-1.

Matheson Tri-Gas’ Air Separation Unit

Matheson Tri-Gas announced in January 2015 that it will supply industrial gases (oxygen and 

nitrogen) to the ethane cracker and derivatives complex under construction by Sasol North America, Inc. 

(Sasol) (see discussion below). Matheson Tri-Gas has begun construction of a new air separation unit 

near Sasol’s existing chemical complex in Westlake, Louisiana, approximately 10 miles north of the 

proposed LNG terminal. The new air separation unit is expected to begin operation in 2016. Due to the 

potential for overlapping construction schedules and proximity to the proposed LNG terminal, 

construction and operation of the air separation unit has been included in our cumulative impacts analysis, 

as indicated in table 4.13.1-1. 

Port of Lake Charles

The Port of Lake Charles is planning to add two docks at Bulk Terminal 1, which would triple the

port’s ability to accommodate vessels. The schedule for construction of the new docks has not been 

released at the time of this writing. However, due to the potential for the construction schedules to 

overlap, and the proximity of the planned facilities within the Port of Lake Charles to the proposed LNG 

terminal, the new docks have been included in our cumulative impacts analysis, as indicated in table 4.13.1-1. 

Sasol Projects

Ethane Cracker and Derivatives Complex

Sasol operates a chemical complex in Westlake, Louisiana, approximately 10 miles north of the 

proposed LNG terminal. Sasol began construction of an ethane cracker and derivatives complex adjacent 

to Sasol’s existing facilities. The ethane cracker would convert ethane contained in natural gas to 

ethylene, with a planned production rate of 1.5 million tons of ethylene and derivatives per year. The 

complex is expected to begin operation in 2018. Due to overlapping construction schedules and 

proximity to the proposed LNG terminal, construction and operation of Sasol’s ethane cracker and 

derivatives complex has been included in our cumulative impacts analysis, as indicated in table 4.13.1-1.

 

42 Docket No. CP08-454-000
4-239

Gas-to-Liquids Facility

Sasol has also announced plans to construct and operate a natural gas-to-liquids facility adjacent 

to its existing chemical complex. The facility would use domestic natural gas to produce more than 

96,000 barrels per day of liquid fuels and chemicals. On January 28, 2015, Sasol announced that it was 

delaying the final investment decision on the gas-to-liquids facility. Because the project has been placed 

on hold and a schedule is not available, Sasol’s proposed gas-to-liquids facility has not been included in 

this cumulative impact analysis.

Westlake Chemical Corporation

Westlake Chemical Corporation’s (Westlake Chemical) Lake Charles complex consists of three 

tracts within 2 miles of one another on over 1,300 acres, about 6 miles northwest of the proposed LNG 

terminal. The complex includes two ethylene plants, two polyethylene plants, and a styrene monomer 

plant. The combined capacity of the two ethylene plants is approximately 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 

approximately 240 million pounds annually. Westlake Chemical plans to begin expansion of the capacity 

of the other ethylene unit (Petro 1) in 2015 and to complete construction in early 2016. Due to the 

potential for overlapping construction schedules and proximity to the proposed LNG terminal, 

construction and operation of the air separation unit has been included in our cumulative impacts analysis, 

as indicated in table 4.13.1-1.

4.13.1.5 Utility Projects

The Calcasieu Point Development Project includes intersection improvements in three locations 

(Tank Farm and Big Lake Roads, Big Lake and Lincoln Roads, and Lincoln Road and Gulf Highway) to 

reduce impacts on local users of the roadways during construction of the G2X Energy natural gas-togasoline facility, Lake Charles Liquefaction Project, and proposed LNG terminal. Roadway 

improvements are expected to begin in the second quarter of 2015 and be complete prior to beginning of 

construction of the LNG terminal. Because the Calcasieu Point Development Project would be completed 

before construction begins for the LNG terminal, it is considered part of the environmental baseline and is 

not discussed further in this cumulative impact analysis.

The Cameron Liquefaction and Lake Charles Liquefaction Projects each require the construction 

of non-jurisdictional electric facilities to serve the new or expanded facilities. Specifically, Entergy will

construct a 12-mile-long electrical transmission line to provide power for the Cameron Liquefaction 

Project. In addition, if the project is authorized, Entergy would construct a 19-mile-long 230 kV electric 

transmission line and a new substation to provide incremental power for the Lake Charles Liquefaction 

Project. Due to overlapping construction schedules and proximity to the LNG terminal, construction and 

operation of Entergy’s electric utilities described above have been included in our cumulative impacts 

analysis, as indicated in table 4.13.1-1. 

Entergy’s Lake Charles Transmission Project would consist of about 25 miles of new 

transmission lines (including 500-kV and 230-kV lines), two new substations, and the expansion of one 

existing substation. If the project is authorized, construction is expected to begin in 2016 and be complete 

in 2018. Due to overlapping construction schedules and proximity to the LNG terminal, construction and 

operation of Entergy’s Lake Charles Transmission Project has been included in our cumulative impacts 

analysis, as indicated in table 4.13.1-1. 
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4.13.1.6 Residential Developments 

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 LNG terminal. 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.

The Belle Savanne residential/commercial development is in Sulphur, Louisiana, approximately 

7 miles northwest of the proposed LNG terminal. Phase I of the development involves the construction of 

single-family residences on about 200 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 will likely be ongoing for several years.

The Moss Lake Worker Village is expected to be constructed on 100 acres of leased property at 

the Southland Field West Calcasieu Airport in Carlyss, approximately 4 miles west-northwest of the 

proposed LNG terminal. The community is designed to accommodate varying workforce numbers, with 

2,500 personnel at peak occupancy. In addition to temporary housing and recreational amenities, workers 

would be provided transportation to and from job sites. 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 schedule for construction of the Moss Lake Worker Village has not 

been released at the time of this writing; however, the SWLA Economic Development Alliance’s 

2015 Estimated Workforce Needs Report (2015) indicates that operation of the Moss Lake Worker 

Village will begin in 2015. 

Construction of Pelican Lodge Workforce Housing began in November 2013 on a 200-acre 

property owned by the Port of Lake Charles approximately 12 miles northeast of the proposed LNG 

terminal. The complex is providing about 400 construction jobs and is currently designed to 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 are being

provided transportation to and from job sites.

The Walnut Grove Development is on a 60-acre property on the north side of Contraband Bayou 

in Lake Charles, approximately 8 miles north-northeast of the proposed LNG terminal. The development 

includes various residence types (a total of 180 homes), parks, and a town square. Construction began in 

2010 and is ongoing.

Due to overlapping construction schedules and proximity to the projects, construction and 

operation of the residential developments described above have been included in our cumulative impacts 

analysis, as indicated in table 4.13.1-1. 

4.13.1.7 Federal, State, and Local Agency Projects

Louisiana Department of Transportation and Development’s Cove Lane Interchange Project

The primary interstate roadways in the vicinity of Magnolia’s proposed LNG terminal are I-210 

and I-10. The Louisiana DOTD’s Cove Lane Interchange Project in Calcasieu and Cameron Parishes is a 

three-phase 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 currently 

under construction and is anticipated to be completed in summer 2015. Because the interchange project 
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will be complete before construction of the LNG terminal begins, it is considered part of the 

environmental baseline and is not discussed further in this cumulative impact analysis. 

Louisiana Department of Wildlife and Fisheries’ Fisheries Research Center

The LDWF’s Fisheries Research 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 Fisheries Research Center would occupy two sites, in 

Calcasieu and Plaquemines Parishes, Louisiana. The stated goal of the Fisheries Research Center is to 

establish state of the art facilities to responsibly develop aquaculture-based techniques for marine fishery 

management. 

The portion of the Fisheries Research Center in Calcasieu Parish would be on a 320-acre 

undeveloped tract of land approximately 100 feet south of the LNG terminal across Henry Pugh 

Boulevard. The proposed aboveground facilities associated with the Fisheries Research Center include a

laboratory, library, and visitor complex to provide education on fisheries and restoration programs. A 

meeting complex/dormitory for staff and visiting researchers also is planned. The hatchery facility would

be focused on the production of spotted seatrout, red drum, and southern flounder. The site would also 

include a recreational fishing pond, walking trails, three 0.5-acre ponds for propagation and research, a 

water reservoir with pipeline and water intake station, and an effluent pump station.

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

as part of the Natural Resource Damage Assessment for the Deepwater Horizon Oil Spill, which included 

a detailed discussion of the Fisheries Research Center (U.S. Department of the Interior, 2014). A 

subsequent Record of Decision was issued in October 2014 in which the trustee agencies decided to 

implement 44 projects, including the center. Construction of the Fisheries Research Center is expected to 

begin in 2016 and would occur over a 4- to 5-year period. Due to overlapping construction schedules and 

proximity to the LNG terminal, construction and operation of the Fisheries Research Center has been 

included in our cumulative impacts analysis, as indicated in table 4.13.1-1. 

U.S. Army Corps of Engineers and Lake Charles Harbor and Terminal District’s Maintenance 

Dredging of the Calcasieu Ship Channel

The COE and Lake Charles Harbor and Terminal District partner to conduct maintenance 

dredging within the Calcasieu Ship Channel, which includes the Industrial Canal. Dredging is expected 

to occur every other year to maintain deep draft access (COE, 2015). If maintenance dredging within the 

Industrial Canal coincides with construction of the LNG terminal, it would contribute to the cumulative 

impact on some resources in the project area. Similarly, maintenance dredging during operation of the 

LNG terminal would contribute to cumulative impacts on some resources, as indicated in table 4.13.1-1.

4.13.2 Potential Cumulative Impacts by Resource

The following sections address the potential cumulative impacts of the projects and the other

reasonably foreseeable projects identified within the cumulative impact area on specific environmental 

resources as identified in tables 4.13.1-1 and 4.13.2-1. 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 proposed projects and would occur within the same timeframe.
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TABLE 4.13.2-1

Projects Included in the Cumulative Impacts Analysis for the Magnolia LNG and Lake Charles Expansion Projects

Project / Activity

Workforce

Geology 

& Soils

GroundwaterSurface 

Water 

Wetlands 

Veg. & 

Wildlife

Aquatic 

Res. T&E Socio

Road 

Traffic

Vessel 

Traffic

Land 

Const. Oper. Use Rec. Air Noise

INDUSTRIAL DEVELOPMENTS

Liquefaction and LNG Export Projects Associated with Existing LNG Terminals

Cameron LNG 

Terminal

Cameron 

Liquefaction 

Project

2,300 130 – + + – + + + + + – + + –

Cameron 

Expansion Project

3,900 135 – + + – + + + + + – + + –

Cameron Pipeline 

Expansion

470 5 – + – – – – + + – – – + –

Cameron Access 

Project

200 0 – + – – – – + + – – – – –

Trunkline LNG 

Terminal

–

Lake Charles 

Liquefaction 

Project

5,600 176 – + + + + + + + + + + + +

Sabine Pass LNG 

Terminal

Sabine Pass 

Liquefaction 

Project 

3,000 356 – – – – – – + – – – – – –

Sabine Pass 

Liquefaction 

Expansion Project

1,441 123 – – – – – – + – – – – – –
4-243

TABLE 4.13.2-1 (cont’d)

Projects Included in the Cumulative Impacts Analysis for the Magnolia LNG and Lake Charles Expansion Projects

Project / Activity

Workforce

Geology 

& Soils

GroundwaterSurface 

Water

Wetlands

Veg. & 

Wildlife

Aquatic 

Res. T&E Socio

Road 

Traffic

Vessel 

Traffic

Land 

Const. Oper. Use Rec. Air Noise

Greenfield Liquefaction and LNG Export Projects

Calcasieu Pass 

Project

625 93 – + + – + + + + + – + – –

Delfin LNG Project 170 9 – – – – – + + – + – – – –

G2 LNG Project NA NA – + + – + + + + + – + – –

Live Oak LNG 

Project

250 75 – + + – + + + + + – + + –

Non-jurisdictional Facilities Associated with the Magnolia LNG and Lake Charles Expansion Projects

LNG Trucking 0 0 o o o o o o + + o o o + +

LNG Bunkering and 

Domestic Marine 

Distribution

0 0 o o + o + + + o + o + + +

Calcasieu Parish 

District 12 Water 

Works’ tie-in to the 

LNG terminal

10 0 + + – + – – + + – + + + +

Entergy’s electric 

transmission line 

and switching 

station for the LNG 

terminal

55 0 + o – + – – + + – + + + +

Cleco’s electric 

transmission line for 

Compressor Station 

760

NA 0 + o – + – – + + – + – + +
4-244

TABLE 4.13.2-1 (cont’d)

Projects Included in the Cumulative Impacts Analysis for the Magnolia LNG and Lake Charles Expansion Projects

Project / Activity

Workforce

Geology 

& Soils

GroundwaterSurface 

Water

Wetlands

Veg. & 

Wildlife

Aquatic 

Res. T&E Socio

Road 

Traffic

Vessel 

Traffic

Land 

Const. Oper. Use Rec. Air Noise

Other Industrial Projects

G2X Energy’s

Natural Gas to 

Gasoline Facility

1,500 243 – + + + + + + + + + + + +

Liberty Gas Storage 

Expansion Project

630 3 – + – – – – + + – – – + –

Matheson Tri-Gas’ 

Air Separation Unit

350 27 – + – – – – + + – – – – –

Port of Lake 

Charles’ Docks at 

Bulk Terminal 1

NA 80 – o – – – – + + + – – – –

Sasol’s Ethane 

Cracker and 

Derivatives 

Complex

5,000 500 – + – – – – + + – – – – –

Westlake Chemical 

Corporation

1,000 25 – + – – – – + + – – – – –

Other Utility Projects

Entergy’s Lake 

Charles 

Transmission 

Project

NA NA – + – – – – + + – – – + –

Entergy’s 

transmission line 

and substation for 

the Lake Charles 

Liquefaction Project

NA 0 – o – + – – + + – + + + +

Entergy’s 

transmission line for 

the Cameron 

Liquefaction Project

NA 0 – o – – – – + + – – + + –
4-245

TABLE 4.13.2-1 (cont’d)

Projects Included in the Cumulative Impacts Analysis for the Magnolia LNG and Lake Charles Expansion Projects

Project / Activity

Workforce

Geology 

& Soils

GroundwaterSurface 

Water

Wetlands

Veg. & 

Wildlife

Aquatic 

Res. T&E Socio

Road 

Traffic

Vessel 

Traffic

Land 

Const. Oper. Use Rec. Air Noise

RESIDENTIAL DEVELOPMENTS

Audubon Trace NA NA – + – – – – + + – – – – –

Belle Savanne NA NA – + – – – – + + – – – – –

Moss Lake Worker 

Village

NA 400 – + – – – – + + – – – + –

Pelican Lodge 

Workforce Housing

400 230 – + – – – – + + – – – – –

Walnut Grove 

Development

NA NA – + – – – – + + – – – – –

FEDERAL, STATE, AND LOCAL AGENCY PROJECTS

LDWF’s Fisheries 

Research Center

30 8 + + + + + + + + o + + + +

COE and Lake 

Charles Harbor and 

Terminal District’s 

Maintenance 

Dredging of the 

Calcasieu Ship 

Channel

NA NA + o + o + + o o + o + + +

____________________

Key:

– Cumulative impacts precluded based on degree of geographic separation.

o The defined geographic sphere of influence for this resource indicates that the project/activity may result in cumulative impacts on the resource as a result of the projects. 

However, because the project/activity does not impact this resource, cumulative impacts would not occur and were not considered further.

+ Project-related impacts are included in the cumulative impacts analysis described in section 4.13.2.

Notes: NA = Not available
4-246

4.13.2.1 Geologic Conditions

The cumulative impact area for geologic resources was considered to be the area that would be 

affected by and adjacent to the LNG terminal and KMLP facilities. As identified in table 4.13.2-1, the 

other projects encompassed by this impact area include the following:

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

At the proposed LNG terminal site, Magnolia would modify the existing topographic contours to 

accommodate its equipment and facilities and maintain adequate drainage from the site. No blasting or 

removal of bedrock would be required. The central portion of the site currently ranges in elevation from 

28 to 32 feet above NAVD 88 and would be graded to a standard elevation of 28 feet above NAVD 88. 

The liquefaction trains would have a base elevation of 24 feet. The LNG storage tanks would have a base 

elevation of 17 feet above NAVD 88, but would have a secondary containment wall with a standard top 

elevation of 30 feet above NAVD 88. 

To create the recessed berthing area, a combination of onshore excavation and dredging would be 

required at the site. Approximately 131,200 yd3 of soils within a 6.4-acre portion of the recessed 

berthing area would be excavated and redistributed elsewhere on the terminal site. Following 

excavation, the 16.2-acre area required for the recessed berthing area would be dredged and an 

additional 862,550 yd3 of sediment and soil would be removed. Magnolia would transport dredge 

material to a borrow pit approximately 8,000 feet east of the LNG terminal site using a dredge material 

pipeline. Dredge material would be placed within a 141.8-acre area. Excavation, dredging, and 

relocation of soils and sediments associated with construction of the LNG terminal would alter the 

existing site topography but would not markedly impact the geology of the area.

As described in section 4.1.3, the potential for impacts on or by the projects from a geologic 

hazards perspective would be low. The proposed LNG terminal is located in an area vulnerable to storm 

surge, particularly from tropical cyclones that can reach hurricane strength, due to its proximity to the 

Gulf of Mexico and the presence of the Calcasieu Lake-Calcasieu River system. In addition, regional 

subsidence and anticipated sea level rise can exacerbate flooding from significant weather events. 

Critical infrastructure at the LNG terminal would have a minimum elevation of 24 feet NAVD 88, which 

is above the water levels associated with both a 100- and 500-year storm event; therefore, significant 

flooding at the facility is not expected. In order to maintain a constant channel depth, maintenance 

dredging is scheduled to occur every other year within the Industrial Canal and Calcasieu Ship Channel. 

Because an increase in channel depth does not occur, maintenance dredging does not change the 

topography or geology; therefore, no cumulative impacts on topography or geologic resources would 

occur. Due to the location of the tie-in to Calcasieu Parish District 12 Water Works’ existing waterline 

and Entergy’s switching station within the LNG terminal site, we do not expect that these facilities would 

have a cumulative impact on geologic resources. Similarly, Entergy’s 1.3-mile-long electric transmission 

line to the LNG terminal site would be expected to have a similar effect on geologic resources within the 

areas where the poles supporting the transmission line wires would be installed. Therefore, cumulative 

impacts on the topography and geology of the area would be negligible.

The LNG terminal would not materially impact (i.e., permanently curtail or preclude the 

extraction of) marketable mineral resources in the area. Fuel and non-fuel mineral resources are not 

anticipated to be affected by the LNG terminal because no active mining activities or oil and gas wells are 
4-247

within 0.25 mile of the LNG terminal. Therefore, cumulative impacts on mineral resources due to the 

construction or operation of the LNG terminal are not anticipated.

Construction and operation of the proposed KMLP facilities would not contribute markedly to 

cumulative impacts on geologic resources. The proposed header pipelines and meter station 

modifications would occur largely within previously disturbed areas. One active well is located 

approximately 150 feet west of the TGT Meter Station and the origin of the low pressure header pipeline; 

the well is also adjacent to the existing access road for the TGT Meter Station. As discussed in section 

4.3.1.4, due to the shallow, temporary, and localized geological impacts associated with the proposed 

modifications at this existing meter station and installation of the low pressure header pipeline, we do not 

anticipate that there would be impacts on this active well. Therefore, we do not anticipate an increase in 

cumulative impacts on mineral resources due to the construction or operation of the KMLP facilities.

The KMLP facilities would affect 75.8 acres of land, of which 12.0 acres would be permanently 

converted to industrial use associated with Compressor Station 760 and the expanded facilities at the 

CGT, TRANSCO, and TGT Meter Stations. No blasting is anticipated to be necessary and any 

modifications to the existing topography where grading and trenching are required are expected to be 

temporary. Cleco’s 0.3-mile-long transmission line to Compressor Station 760 would be expected to 

have a similar effect on geologic resources within the areas where the poles supporting the transmission 

line wires would be installed. Therefore, cumulative impacts on the topography and geology of the area 

would be negligible.

4.13.2.2 Soils 

The cumulative impact area for soils was considered to be the area that would be affected by and 

adjacent to the LNG terminal and KMLP facilities. As identified in table 4.13.2-1, the other projects

encompassed by this impact area include the following:

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel

Construction activities associated with the LNG terminal and KMLP facilities such as clearing, 

grading, excavation, backfilling, and the movement of construction equipment may affect soil resources. 

Clearing removes protective vegetation 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. 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. However, these areas have 

been previously disturbed due to past and ongoing maintenance of the adjacent Industrial Canal and 

Calcasieu Ship Channel; agricultural practices; commercial activities; and construction and maintenance 

of existing roads, railroads, natural gas and oil pipelines, transmission lines, and other utility lines. 

To protect soil resources and minimize impacts on soils, Magnolia would implement its projectspecific Plan and Procedures and KMLP would implement the FERC’s Plan and Procedures, except 

where alternative measures are justified. 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 impacts on soils would be short term. It is anticipated that similar mitigation measures 

would be employed for each of the five projects described above. The tie-in to the existing water line and 
4-248

construction of the electric facilities (transmission lines and switching station) to provide power to the 

LNG terminal and Compressor Station 760 would result in short-term and localized soil impacts, with the

exception of the soils that would be permanently affected by the foundations for the power poles used to 

hold up the transmission wires.

Development of the LDWF’s Fisheries Research Center would result in soil impacts similar to the 

LNG terminal, including the loss of approximately 12 additional acres of soils associated with 

aboveground facilities and roadways. However, the combined impacts on soils resulting from both of 

these facilities would be relatively minor relative to the amount of similar soils in the surrounding area. 

Therefore, cumulative impacts on the soils in the vicinity of the LNG terminal and KMLP facilities would 

be negligible.

4.13.2.3 Water Resources

Groundwater

The cumulative impact area established for groundwater resources includes the Chicot aquifer, 

which underlies both the LNG terminal and KMLP facilities. As identified in table 4.13.2-1, the other 

projects encompassed by the impact area that may have impacts on groundwater resources include the 

following:

 Cameron LNG Terminal – four projects under construction, proposed, or planned;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 G2X Energy’s Natural Gas to Gasoline Facility;

 Liberty Gas Storage Expansion Project;

 Matheson Tri-Gas’s Air Separation Unit;

 Port of Lake Charles’ addition of two docks at Bulk Terminal 1;

 Sasol’s Ethane Cracker and Derivatives Complex;

 Westlake Chemical Corporation;

 Entergy’s Lake Charles Transmission Project;

 five residential developments; and

 LDWF’s Fisheries Research Center.

In some areas, groundwater withdrawals from the Chicot aquifer are causing lowered water levels 

and saltwater encroachment. The rate of decline in these areas is due primarily to industrial use in the 

Lake Charles area and rice irrigation, where intense pumping of the 500-foot sand has resulted in the 

water level declining by as much as 1 to 2 feet per year (LDNR, 2012; DOTD and USGS, 2011). 

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).

Although no portion of the Chicot aquifer has been designated as an Area of Ground Water 

Concern due to movement of the salt water front or water level decline or subsidence, high water use in 

southwest Louisiana has been identified as one of the current major issues having an impact on 

groundwater sustainability management (LDNR, 2012). In 2012, the LDNR and USGS entered into a 
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joint partnership to increase groundwater monitoring. As a result, the number of wells within the State of 

Louisiana being monitored for water level, chlorides, and water quality has nearly doubled. In addition, 

the University of Louisiana at Lafayette has initiated a 3-year study of regional groundwater use and 

management in southwest Louisiana (LDNR, 2014a).

Construction activities associated with the LNG terminal and KMLP facilities, such as 

excavation; installation of groundwater wells, piles, and sheet piling; and groundwater withdrawals (an 

average of 1,800 gallons per day) would be expected to have temporary and minor impacts on 

groundwater within the Chicot aquifer (see discussion in section 4.3.1.4). For the majority of the projects

listed above, groundwater requirements during construction are not publicly available, so the potential 

impact of those projects on groundwater has been considered qualitatively. Groundwater requirements 

for those projects where data are available are provided below:

 Cameron Liquefaction Project – an average of 50,000 gallons per day;

 Cameron Pipeline Expansion Project – no groundwater required;

 Cameron Access Project – no groundwater required;

 Lake Charles Liquefaction Project – an average of 30,800 gallons per day; and 

 Liberty Gas Storage Expansion Project – an average of 6,192,000 gallons per day.

During the period when each of the projects described above would be under construction, 

groundwater requirements would result in an increase of approximately 1 percent over current daily

withdrawals from the Chicot aquifer (714 million gallons per day). The duration of this cumulative effect 

would be temporary, occurring primarily during the period when the Liberty Gas Storage Expansion 

Project withdraws approximately 4,300 gallons of groundwater per minute to create the new salt dome 

storage cavern in Cameron Parish (expected to be complete in June 2017), and the overall cumulative 

impact would be minor compared to the overall withdrawals from the Chicot aquifer.

During operations, Magnolia would obtain groundwater from one of two on-site wells and the 

proposed tie-in to Calcasieu Parish District 12 Water Works’ existing water line. The total volume of 

water used during operation (0.2 million gallons per day) would represent slightly less than 0.03 percent 

of the 714 million gallons per day withdrawn from the Chicot aquifer on a daily basis (USGS and LDNR, 

2013). Magnolia calculated that the anticipated drawdown from the new on-site wells would be less than 

1.5 feet at a distance of 1,500 feet from the point of withdrawal. The nearest water supply wells to the 

LNG terminal site are the two Calcasieu Parish District No. 12 Water Works’ wells, which are over 

1,400 feet east of the proposed wells and have over 400 feet of head above their screened interval 

(400 feet of available water above the extraction point). Therefore, the potential for operation of the LNG 

terminal to cause significant drawdown, impacting nearby users of the Chicot aquifer, would be minimal.

For the majority of the projects listed above, groundwater requirements during operation are not 

publicly available, so the potential impact of those projects on groundwater has been considered 

qualitatively. Groundwater requirements for those projects where data are available are provided below:

 Cameron Access Project – no groundwater required;

 Lake Charles Liquefaction Project – an average of 158,400 gallons per day; and

 Calcasieu Pass Project – an average of 600,000 gallons per day.

Operation of the projects listed above would increase daily withdrawal from the Chicot aquifer by 

less than 1 percent. While there would be localized effects, such as the lowering of the water table near 

the points of withdrawal, we conclude that the cumulative impact on groundwater or municipal water 

systems during construction and operation of these facilities would be permanent, but minor.
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Surface Water

The cumulative impact area associated with surface water resources affected by construction and 

operation of the LNG terminal includes the Industrial Canal and the portion of the Calcasieu River

downstream of the LNG terminal site. As identified in table 4.13.2-1, the other projects encompassed by 

the impact area for surface water at the LNG terminal include the following:

 Cameron LNG Terminal – Cameron Liquefaction and Expansion Projects;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Magnolia’s LNG bunkering and domestic marine distribution;

 G2X Energy’s Natural Gas to Gasoline Facility;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

The cumulative impact area associated with surface waters affected by the KMLP facilities

includes those areas immediately downstream of construction activities. This distance was selected due 

to the low flow rates within the waterbodies that would be affected by construction activities. However, 

because no other reasonably foreseeable projects have been identified within the impact area, cumulative 

impacts on surface waters are not anticipated as a result of construction and operation of the KMLP 

facilities.

Potential impacts on surface waters during construction and operation of the LNG terminal would 

be associated with dredging, construction of the LNG loading and ship berthing facilities, vessel traffic, 

site modification and stormwater runoff, hydrostatic testing, operation of the LNG storage tank deluge 

system, and spills or leaks of hazardous materials.

The activity with the greatest potential impacts on surface waters would be dredging the 16.2-acre 

recessed berthing area at the LNG terminal. As described above (see section 4.13.2.1), a combination of 

onshore excavation and dredging would be used to construct the ship berthing area, which would be

recessed into the northern boundary of the LNG terminal site. Dredging activities are expected to occur 

over a 12-week period using a hydraulic cutterhead dredge. Dredge material would be transported by 

pipeline to a placement area approximately 8,000 feet east of the LNG terminal. Throughout dredging 

operations, dredge materials would be placed in the disposal area and allowed to dewater, after which the 

decanted water would be pumped through the effluent return pipeline and discharged back into the 

Industrial Canal. 

Potential impacts on water quality in the Industrial Canal resulting from dredging and the 

subsequent discharge of water back to the Industrial Canal would include temporary increases in 

suspended solids and turbidity levels as well as potential resuspension of contaminated sediments. 

Impacts on water quality due to dredging would be minimized through the use of a hydraulic cutterhead 

dredge, which minimizes turbidity from resuspension of the sediment in the water column and other water 

quality impacts. In addition, Magnolia would implement its Dredging Water Quality Monitoring Plan

(discussed in detail in section 4.3.2.2). Therefore, dredging and the subsequent discharge of water back to 

the Industrial Canal are expected to result in temporary and minor increases in turbidity and suspended 

solid levels. In addition, Magnolia would conduct maintenance dredging of the ship berthing area every 

4 to 5 years during operation of the LNG terminal. Given the naturally high turbidity levels that already 

exist in the Industrial Canal, we expect these impacts would be minor, temporary, and localized due to the 
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methods that Magnolia would use to minimize the effects of suspended sediments, and the relatively short 

period of time the sediments would be suspended before they resettle on the canal bed. 

If dredging at Magnolia’s proposed LNG terminal were to occur at the same time as dredging for 

the Trunkline LNG Terminal, Live Oak LNG Project, G2X Energy’s natural gas to gasoline facility, 

and/or maintenance dredging of the Calcasieu Ship Channel, the adverse impacts on water quality 

(e.g., increased turbidity and total suspended solids) could be exacerbated in the vicinity of the Industrial 

Canal. 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). Similarly, if pile driving and sheet pile installation associated with 

Magnolia’s proposed LNG terminal, the Lake Charles Liquefaction Project, and/or G2X Energy’s natural 

gas to gasoline facility were to occur concurrently, they could result in cumulative impacts on water 

quality within the Industrial Canal; however, as with dredging, these impacts would be localized, short 

term, and temporary. 

Before any dredging or pile driving can occur, Magnolia and the proponents of the other projects

would need to obtain authorization under section 10/404 of the CWA from the COE and corresponding 

section 401 Water Quality Certification 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 there are no long-term cumulative impacts on water quality as a result of foreseeable 

dredging and pile-driving activities in the Industrial Canal.

In addition to the COE permit and section 401 water quality certification, Magnolia and the 

proponents of the other projects listed above 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 the 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 waters.

Magnolia estimates that 50 or fewer marine deliveries would be made to the LNG terminal during 

construction. During operation, approximately 208 LNG vessels (104 LNG carriers and 104 LNG barges) 

would call on the LNG terminal per year. As discussed in section 4.3.2.2, vessel traffic within the 

recessed berthing area and along vessel transit routes has the potential to increase shoreline erosion and 

suspended sediment concentrations due to increased wave activity. To provide scour protection from 

propeller wash, Magnolia would install rock armoring both within and along the east and west ends of the 

recessed berthing area. The proposed rock armoring would prevent erosion of the adjacent unprotected 

shoreline by wave activity from vessels maneuvering within the recessed berthing area. 

If Magnolia’s proposed LNG terminal, the four projects proposed at the Cameron LNG Terminal, 

Live Oak LNG Project, G2 LNG Project, G2X Energy’s natural gas to gasoline facility, and Calcasieu 

Pass Project all receive the necessary authorizations and permits and are constructed, a substantial

increase in marine vessel traffic would occur (see detailed discussion in section 4.13.2.9). The combined 

marine vessel traffic associated with these projects would increase the potential for shoreline erosion 

impacts along the Calcasieu Ship Channel (which includes the Industrial Canal). In addition, surface 

water quality could be affected by a cumulative increase in discharged engine cooling water. The volume 

of water discharged while each vessel is at port could range from 535 gallons for barges, to 5.5 million 

gallons for LNG carriers with dual fuel/diesel electric engines (maximum LNG capacity of 218,000 m3), 

to 11.7 million gallons for steam-powered LNG carriers (maximum LNG capacity of 138,000 m3). 

Impacts on surface waters as a result of cooling water discharges would be primarily limited to an 
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increase in water temperature in the vicinity of the vessel. Cooling water return temperatures vary widely 

depending on the type of LNG carrier and mode of operation. However, based on a review of available 

information, we anticipate that cooling water discharged could range between 2.7  ̊F and 7.2 °F warmer 

than ambient water temperatures (Caterpillar, 2007, 2011, 2012). The Calcasieu Ship Channel was 

specifically created to provide deepwater access for maritime commerce. As such, use of the waterways 

by LNG carriers, barges, and support vessels during construction and operation of the projects would be 

consistent with the planned purpose and use of this active shipping channel and cumulative impacts on 

water quality due to shoreline erosion and engine cooling water discharges would be permanent, but minor.

LNG carriers serving the LNG terminal would likely arrive with empty cargo tanks because they 

would be loaded at the terminal with LNG destined for export. Vessels with empty cargo tanks ride 

higher in the water and can experience challenges associated with navigation due to the extra sail area 

(ship surface area above the water line). Therefore, water is often taken in from the surrounding waters 

and placed in ballast tanks to provide additional draft and improve navigation. To maintain a constant 

draft, ballast water is typically discharged below the water surface as the LNG cargo is loaded. Based on 

information provided by Magnolia, the amount of ballast water discharged during LNG cargo loading

would range from approximately 8,711,000 to 12,264,000 gallons, depending on the size of the LNG 

carrier. Ballast water discharges at the LNG terminal could impact water quality by changing the salinity, 

temperature, pH, and dissolved oxygen level of water within the Industrial Canal. The physiochemical 

composition of ballast water in comparison to the water present within the Industrial Canal and Calcasieu 

River would vary depending on tidal and hydrologic conditions at the time of discharge, but is expected to 

result in temporary and minor impacts on water quality in the vicinity of the discharge.

LNG vessels calling on the Trunkline, Cameron, Calcasieu Pass, G2, and Live Oak LNG 

Terminals would also be expected to discharge ballast water into the Calcasieu Ship Channel. Barges do 

not have ballast tanks; therefore, operation of G2X Energy’s natural gas to gasoline facility would not be 

expected to contribute to cumulative impacts on water quality due to ballast discharge. Ballast water 

discharges would be composed of mainly open ocean water collected during vessel transit. Assuming a 

similar volume of water would be discharged by vessels associated with these projects, the cumulative 

impact on the salinity, pH, temperature, and dissolved oxygen of the water in the Industrial Canal would 

be expected to be the greatest if ballast water discharges occur concurrently. However, due to the large 

volume of water in the Industrial Canal and Calcasieu River, dilution from tidal exchange and freshwater 

input, and mixing as a result of vessel traffic, the overall cumulative impact on water quality would be 

intermittent and minor. 

4.13.2.4 Wetlands, Vegetation, and Wildlife

The cumulative impact area for wetlands, vegetation, and wildlife was considered to be the area 

that would be affected by the LNG terminal and KMLP facilities, as well as areas within approximately 

1 mile of the proposed facilities. As identified in table 4.13.2-1, the other projects encompassed by this 

impact area that may impact wetlands, vegetation, or wildlife include the following:

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 G2X Energy’s natural gas to gasoline facility;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.
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Wetlands

As described in section 4.4.2, construction of the LNG terminal and KMLP facilities would result 

in the permanent loss of 16.2 acres of wetlands, including 8.1 acres of palustrine emergent, 6.6 acres of 

palustrine scrub-shrub, 1.0 acre of estuarine intertidal emergent, and 0.5 acre of palustrine forested/scrubshrub wetlands.

Construction of the Lake Charles Liquefaction Project would result in the permanent loss of 

approximately 215 acres of wetlands, the majority of which would be forested mosaic, forested, and 

scrub-shrub wetlands. A review of aerial photography and NWI wetland data indicates that construction 

of G2X Energy’s natural gas to gasoline facility also has the potential to affect emergent wetlands in the 

northern part of the site and that construction of the Fisheries Research Center is expected to have impacts 

on approximately 4 acres of predominately emergent wetlands. Based on available information, the 

proposed tie-in to the existing water line, construction and operation of the electric transmission facilities, 

and dredging of the Calcasieu Ship Channel would have negligible, if any, cumulative impacts on 

wetlands. 

As noted previously, the proponents of each of the projects identified near the LNG terminal and 

KMLP facilities would need to obtain applicable permits from the COE. Therefore, although construction 

of the LNG terminal, KMLP facilities, and the other projects in the impact area could result in the 

conversion or reduction in the amount of existing wetlands in the vicinity, the creation of new wetlands 

and restoration or enhancement of existing wetlands, as required by the COE, are expected to 

appropriately mitigate for impacts on wetland resources and minimize any cumulative wetland effects.

Vegetation and Wildlife

A total of 285.6 acres of vegetation would be cleared during construction of the LNG terminal

and KMLP facilities. Following construction, approximately 126.0 acres would be permanently 

converted to developed land, 124.7 acres would return to pre-construction conditions, and 34.9 acres 

would return to a vegetated community although it would be converted from an upland scrub or palustrine 

wetland community to an upland herbaceous community. Overall, the facilities would have the greatest 

impact on upland herbaceous (106.5 acres), upland shrub (65.0 acres), and agricultural (63.5 acres) 

vegetation communities. 

Construction and operation of projects listed above would also result in the permanent conversion 

of nearby vegetated habitats to developed, industrial land. Development of the Lake Charles Liquefaction 

Project would result in the permanent removal of about 568 acres of vegetation communities, most 

notably, the permanent loss of 420 acres of forested uplands and wetlands. The extent of clearing 

required within G2X Energy’s approximately 200-acre site for the natural gas to gasoline facility is not 

known. Based on desktop review, the site appears to consist primarily of open lands and emergent 

wetlands. Development impacts on vegetation from the LDWF’s Fisheries Research Center are not fully 

known, but it is anticipated that approximately 12 acres of vegetation would be permanently replaced with 

aboveground facilities and roadways. 

Due to the location of the tie-in to Calcasieu Parish District 12 Water Works’ existing waterline 

and Entergy’s switching station within the LNG terminal site, we do not expect that these facilities would 

have a cumulative impact on vegetation and wildlife resources. Similarly, Entergy’s 1.3-mile-long 

electric transmission line to the LNG terminal and 19-mile-long transmission line to the Trunkline LNG 

Terminal would be adjacent to existing roadways and utility lines, and clearing is expected to be primarily 

limited to the areas where the poles supporting the transmission line wires would be installed, although 

select tree clearing would occur in order to prevent damage to the transmission line wires.
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Cumulative impacts on vegetation and wildlife from construction of the LNG terminal, Lake 

Charles Liquefaction Project, G2X Energy’s natural gas to gasoline facility, and the LDWF’s Fisheries 

Research Center 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 adjacent to the Industrial Canal (including operation of the 

existing Trunkline LNG Terminal), 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 area could also be affected by flaring at both the proposed LNG terminal

and the Lake Charles Liquefaction Project sites. Flaring would be required during start-up of the 

facilities; during operation of the facilities, use of the emergency flares would only occur occasionally. It 

is unlikely, but possible, that the start-up 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. We are not aware of any reported impacts of flaring on migratory birds in the area; therefore, 

we conclude that the cumulative impacts on birds from flaring would be minimal.

Vegetation and wildlife habitat in the vicinity of the proposed KMLP facilities have been affected 

by ongoing agricultural practices, 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 KMLP facilities would affect a total of 64.3 acres of vegetation. Of this total, 44.1 acres 

would be in temporary work areas that would be allowed to revert to pre-construction condition after 

construction is completed. About 8.3 acres would be within the permanent easements for the header 

pipelines, and 12.0 acres would be within the new or modified aboveground facility footprints. 

The proposed KMLP facilities would be primarily within existing meter stations and on adjacent 

agricultural land. The agricultural land, which comprises 99 percent of the vegetated communities within 

the KMLP facilities, consists of crayfish ponds and cropland. Agricultural land is expected to recover 

quickly after construction and continue to provide similar habitat during operations. Cumulative impacts 

resulting from construction and operation of Cleco’s 0.3-mile-long electric transmission line to 

Compressor Station 760 would be limited to agricultural areas. Given the limited impacts on vegetation 

and wildlife, and the lack of other project activity in the vicinity of the KMLP facilities, cumulative 

impacts on vegetation and wildlife would be minimal.

4.13.2.5 Aquatic Resources

The cumulative impact area associated with aquatic resources affected by construction and 

operation of the LNG terminal includes the Industrial Canal and the portion of the Calcasieu River 

downstream of the LNG terminal. As identified in table 4.13.2-1, the other projects encompassed by the 

impact area for aquatic resources at the LNG terminal include the following:

 Cameron LNG Terminal – Cameron Liquefaction and Expansion Projects;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Magnolia’s LNG bunkering and domestic marine distribution;

 G2X Energy’s natural gas to gasoline facility;
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 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

The cumulative impact area associated with aquatic resources affected by the KMLP facilities

includes those areas immediately downstream of construction activities. This distance was selected due 

to the low flow rates within the waterbodies that would be affected by construction activities. However, 

because no other reasonably foreseeable projects have been identified within the impact area that would 

affect aquatic resources, cumulative impacts on aquatic resources are not anticipated as a result of 

construction and operation of the KMLP facilities.

Potential impacts on aquatic resources during construction and operation of the LNG terminal

include those associated with dredging, pile driving, hydrostatic testing, vessel traffic, stormwater runoff, 

lighting, the LNG storage tank deluge system, and inadvertent spills. 

The activities with the greatest potential impacts on aquatic resources would be dredging and pile 

driving within the 16.2-acre recessed berthing area. As discussed above and in section 4.6.2.2, dredging 

associated with construction of the recessed berthing area would occur over a period of approximately 

12 weeks, and would be accomplished using a hydraulic cutterhead suction dredge. Dredge material 

would be transported by pipeline to the placement area where it would be allowed to dewater, after which 

the decanted water would be pumped through the effluent return pipeline and discharged back into the 

Industrial Canal. Potential impacts on aquatic resources resulting from dredging activities include direct 

take and habitat modification as well as avoidance of the area due to increases in noise, turbidity, and 

suspended solid levels. Most fish species are highly mobile and would be expected to leave the area 

during dredging activities. However, dredging would result in direct mortality of benthic organisms 

within the 16.2-acre dredge footprint. Slower, less mobile benthic invertebrates would also be directly 

affected, while larger, more mobile species would experience temporary displacement. Following 

construction activities, aquatic resources would be expected to return to the recessed berthing area, which 

would be similar to the existing open water habitat within the Industrial Canal. 

Construction of the LNG terminal would require the installation of approximately 5,000 piles to 

support the proposed structures at the LNG terminal, including onshore installation of piles to support the 

liquefaction trains, LNG storage tanks, and other process equipment and structures as well as in-water 

installation of the steel sheet pile bulkhead along the shoreline of the Industrial Canal and the piles 

supporting the LNG loading platform and the breasting and mooring dolphins. Onshore piles would be 

driven by seven or eight hydraulic piling rigs over a 10-month period. Marine piles would be installed 

using between two and four hydraulic pile drivers over a 6-month period. As depicted in table 2.5.1-1 in 

section 2.5.1.3, onshore and in-water pile driving operations would occur over a total of approximately 

16 months. Pile driving would occur 10 hours per day, up to 7 days per week; however, due to pre-work 

coordination and start-up activities, actual pile driving operations (hammering) are expected to occur for 

approximately 8 hours per day.

The primary impacts on aquatic resources from pile driving activities would be avoidance of the 

area, stress, or injury due to the underwater sound pressure levels produced by pile drivers. To avoid 

injury of aquatic resources, we have recommended in section 4.6.2.2 that Magnolia develop and 

implement a Pile Driving Noise Impact Mitigation Plan. The plan would include hydroacoustic 

monitoring and mitigation measures that would be implemented, if needed, to ensure that sound pressure 

levels would be below the NOAA Fisheries interim thresholds for the onset of injury to fish. With the 

implementation of these measures, impacts on aquatic resources due to pile driving activities are expected 

to include avoidance of the area by most fish species and behavioral changes for immobile or less mobile 

species. 
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If dredging and pile driving activities at the LNG terminal occur concurrently with those required 

for the Lake Charles Liquefaction Project, Live Oak LNG Project, and/or G2X Energy’s natural gas to 

gasoline facility, impacts on aquatic resources are likely to be exacerbated as a direct result of each of the 

projects’ dredge activities and as sediments resettle following construction. Similarly, if the LDWF’s 

Fisheries Research Center were to install its water intake (located east of the recessed berthing area within 

the Industrial Canal) at the same time as dredging and pile driving activities associated with the other 

projects, it would slightly exacerbate impacts on aquatic resources. However, these impacts would occur 

within the Calcasieu Ship Channel, which is maintained (including periodic maintenance dredging) to 

support shipping for industrial activity. Additionally, benthos in soft bottom habitats (like that occurring 

within the Industrial Canal) 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, cumulative impacts would primarily be those associated with the 

transit and operation of vessels serving the various project facilities while in the Calcasieu Ship Channel. 

As described in detail above (section 4.13.2.3), the primary impacts on surface water, and thus aquatic 

resources, due to vessel traffic include increased shoreline erosion and changes in water quality due to the 

discharges of ballast and engine cooling water (see detailed discussion in sections 4.3.2.2 and 4.6.2.2). 

The Calcasieu Ship Channel was specifically created to provide deepwater access for maritime 

commerce. As such, use of the waterways by LNG carriers, barges, and support vessels during 

construction and operation of the projects would be consistent with the planned purpose and use of this 

active shipping channel and cumulative impacts on water quality due to shoreline erosion and engine 

cooling water discharges would be permanent, but minor. Further, due to the large volume of water in the 

Industrial Canal and Calcasieu River; dilution from tidal exchange and freshwater input; mixing as a 

result of vessel traffic; and tolerance of estuarine aquatic species to fluctuations in temperature, salinity, 

pH, and dissolved oxygen levels; the overall cumulative impact on water quality is expected to be 

intermittent and minor.

Because the Calcasieu River and Industrial Canal are designated as EFH, each of the projects

listed above would be required to comply with the MSA. As federally authorized projects, NOAA 

Fisheries will review each of the project’s potential impacts on EFH and ensure that the project would 

have a de minimis effect on EFH. Therefore, we conclude that cumulative impacts on aquatic resources 

would be minimal.

4.13.2.6 Threatened and Endangered Species

The cumulative impact area associated with threatened and endangered species potentially 

affected by construction and operation of the LNG terminal includes the areas affected by and adjacent to 

the LNG terminal, and the portion of the vessel transit route within the EEZ (including the Industrial 

Canal, Calcasieu River downstream of the LNG terminal, and the transit route through the Gulf of Mexico 

to the EEZ boundary). As identified in table 4.13.2-1, the other projects encompassed by the impact area 

include the following:

 Cameron LNG Terminal – Cameron Liquefaction and Expansion Projects;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 Delfin LNG Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Magnolia’s LNG bunkering and domestic marine distribution;
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 G2X Energy’s natural gas to gasoline facility;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

The cumulative impact area associated with threatened and endangered species potentially 

affected by the KMLP facilities includes those areas affected by and adjacent to the proposed construction 

activities. However, construction and operation of the KMLP facilities would have no effect on listed 

species (see section 4.7 and table 4.7.1-1). Consequently, the KMLP facilities would not contribute to 

cumulative impacts on threatened and endangered species. 

We identified 15 federally listed threatened and endangered species and 1 species that is a 

candidate for listing under the ESA that may occur within the impact area for the LNG terminal. As 

discussed in section 4.7, we determined that the project would have no effect on four federally listed 

species, and would not contribute to the trend toward federal listing for the candidate species. 

Consequently, the project would not contribute to cumulative impacts on these species. 

A total of 11 federally listed species (including the West Indian manatee, five species of whales, 

and five species of sea turtles) were identified as potentially occurring along the LNG vessel transit route 

through and offshore of Cameron Parish, Louisiana. The increased traffic within the Calcasieu Ship 

Channel and Gulf of Mexico due to vessel transit to and from the LNG terminal site during construction 

and operation could pose an increased risk to federally listed species from vessel strikes. However, 

marine vessels (LNG carriers, LNG barges, and construction delivery barges) would use well-traveled 

shipping lanes. Magnolia anticipates that 50 or fewer marine deliveries would be made during 

construction of the LNG terminal. During operation of the LNG terminal, up to 208 LNG vessels 

(104 LNG carriers and 104 LNG barges) would call on the LNG terminal per year. For each of the 

federally listed species occurring along the transit route, vulnerability to collision with a transiting vessel 

would be greatest while the animal feeds, swims, and rests near the surface of the water. 

LNG transit vessels operating within Industrial Canal, Calcasieu River, and the portion of the 

Gulf of Mexico within the EEZ are generally slower, generate more noise than typical large vessels, and 

would be more readily avoided by West Indian manatees, sea turtles, and whales. Additionally, LNG 

carriers push a considerable bow wave when underway on the open ocean because of their design and 

large displacement tonnage. This wave pushes water, flotsam, and other small objects (such as sea turtles 

and manatees) away from the vessel. To further minimize the potential for vessel strikes, Magnolia 

would provide LNG ship captains with the NOAA-issued document entitled “Vessel Strike Avoidance 

Measures and Reporting for Mariners, NOAA Fisheries Service (2008),” which outlines collision 

avoidance measures. Based on the characteristics and habitat requirements of the federally listed species 

potentially present along the transit route and Magnolia’s proposed mitigation measure, we have 

determined that the LNG terminal may affect, but is not likely to adversely affect the West Indian 

manatee, sea turtles, and whales. 

Each of the projects listed above has federal permit requirements, and each of the projects has 

(Cameron Liquefaction Project, Lake Charles Liquefaction Project, LDWF’s Fisheries Research Center, 

and the COE and Lake Charles Harbor District’s maintenance dredging of the Calcasieu Ship Channel) or 

would be required to (Cameron Expansion Project, Calcasieu Pass Project, Delfin LNG Project, G2 LNG 

Project, Live Oak LNG Project, and G2X Energy’s natural gas to gasoline facility) comply with section 7 

of the ESA (described in detail in section 4.7). As a result of the Section 7 consultation process, NOAA 

Fisheries will review each project’s potential impacts on federally listed species and either provide 

concurrence that the project would not adversely affect listed species or issue a Biological Opinion as to 

whether the project would likely jeopardize the continued existence of listed species. Therefore, we 

conclude that cumulative impacts on threatened and endangered species would be less than significant.
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4.13.2.7 Land Use, Recreation, and Visual Resources 

Land Use

The cumulative impact area for land use was considered to be the area that would be affected by 

the LNG terminal and KMLP facilities, as well as areas within approximately 1 mile of the proposed 

facilities. As identified in table 4.13.2-1, the other projects encompassed by this impact area that would 

affect land use include the following:

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 G2X Energy’s natural gas to gasoline facility;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction 

Project; and

 LDWF’s Fisheries Research Center.

The proposed LNG terminal site is currently zoned for heavy industrial use. The site was used by 

the COE for the placement of dredge material from within the Industrial Canal between 1975 and 1984. 

As a result, the site is comprised of open land (70 percent) and forest (30 percent). The nearest occupied 

residences are 0.6 mile south of the LNG terminal site within a community situated along a canal leading 

to the Intracoastal Waterway.

Land use adjacent to the Industrial Canal east and northeast of the LNG terminal is primarily 

industrial/commercial and developed. In contrast, land use to the northwest and south of the site consists 

of open land and forest. If the Lake Charles Liquefaction Project is permitted and constructed, the 

liquefaction facility would convert approximately 286 acres of industrial, wetland, forest, and open water 

land to industrial use (the land is currently zoned for heavy industrial use). Similarly, if G2X Energy’s 

natural gas to gasoline facility is permitted and constructed, it could result in the conversion of all or 

portions of the approximately 200-acre site to industrial use (the land is currently zoned for heavy 

industrial use). Because the LNG terminal, Lake Charles Liquefaction Project, and G2X’s natural gas to 

gasoline facility are on an existing industrial port (the Port of Lake Charles) and the lands affected by 

construction and operation of the facilities are zoned for industrial use, we have determined that the 

projects would result in a permanent, but minor cumulative impact on land use.

Construction of LDWF’s Fisheries Research Center would result in the conversion of a small 

amount (approximately 12 acres) of open land to developed land. However, because the majority of the 

320-acre site would not be affected, cumulative impacts on land use would be negligible. 

Construction of Entergy’s transmission lines would be within or adjacent to existing road and 

utility rights-of-way. Similarly, the switching station and substation would be located within the 

proposed LNG terminal and adjacent to the Trunkline LNG Terminal, respectively. Therefore, these 

facilities would have a negligible cumulative impact on land use. 

The proposed KMLP facilities would affect about 76 acres of land. Because the activities 

associated with the KMLP facilities involve modification or expansion of existing facilities, much of the 
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land affected by the KMLP facilities would be adjacent to the permanent easement associated with 

KMLP’s existing mainline or would be adjacent to or within existing meter station sites. Construction of 

the KMLP facilities would primarily impact agricultural (63.5 acres) and industrial/commercial 

(11.2 acres) land. The remaining 1.0 acre of land affected would be comprised of open land and open 

water. Operation of the KMLP facilities would result in the permanent conversion of 12 acres of land to 

industrial use within Compressor Station 760, and the expanded CGT, TRANSCO, and TGT Meter 

Stations. The remaining 64 acres of land would be restored and existing land uses would be allowed to 

resume following construction, which would minimize impacts on land use. Construction of Cleco’s 

electric transmission line to Compressor Station 760 would affect a total of 0.8 acre of land, of which 

0.7 acre is agricultural and 0.1 acre is within existing road/utility rights-of-way. Permanent impacts on 

land use would be limited to the areas where poles would be installed to support the transmission wires.

Although the majority of the land affected by the KMLP facilities would be agricultural, the area 

also contains a large number of facilities associated with oil and gas, as identified in table 4.13.2-2. This 

is particularly true in the vicinity of the proposed facilities near Eunice, Louisiana (the low and high 

pressure header pipelines; Compressor Station 760; and the ANR, Pine Prairie, and TGT Meter Stations), 

where 46 pipelines occur within a 1-mile radius. As described previously, the header pipelines would be 

collocated with KMLP’s existing mainline. Two TransCanada pipelines are also within this corridor. If 

the KMLP facilities are permitted and constructed, the total number of pipelines within this 250- to 

300-foot-wide corridor would be five or six (five along the low pressure header pipeline and six where the 

high pressure header pipeline would be adjacent to the low pressure header pipeline). Given the existing 

level of oil and gas infrastructure within an otherwise agricultural area, and the fact that agricultural land 

use can continue in areas where underground oil and gas pipelines are present, we have determined that 

cumulative impacts on land use would be negligible.

TABLE 4.13.2-2

Oil and Gas Industry Facilities Within 1 Mile of the KMLP Facilities

Facility

Oil and Gas

Pipelines

Meter

Stations

Compressor

Stations

Natural Gas 

Processing Plants

Eunice Facilities a 46 28 2 2

CGT Meter Station 12 3 0 0

TRANSCO Meter Station 10 1 1 0

TETCO Meter Station 5 3 0 0

____________________

a Eunice facilities include the low and high pressure header pipelines; Compressor Station 760; and modifications at the 

ANR, Pine Prairie, and TGT Meter Stations.

Recreation

The cumulative impact area for recreational facilities was considered to be the area adjacent to 

and in the vicinity of the proposed LNG terminal. As identified in table 4.13.2-1, the other projects

encompassed by this impact area include the following:

 Cameron LNG Terminal – Cameron Liquefaction and Expansion Projects;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Magnolia’s LNG bunkering and domestic marine distribution;
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 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 G2X Energy’s natural gas to gasoline facility;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 Entergy’s electric transmission line for the Cameron Liquefaction Project;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

There are no recreational facilities within 0.25 mile of the KMLP facilities. Consequently, the 

KMLP facilities would not contribute to cumulative impacts on recreation. 

Construction and operation of the LNG terminal would not directly affect designated recreational 

areas. One designated recreational area, Calcasieu Point Landing, is approximately 525 feet west of the 

LNG terminal site. In addition, a portion of the Sabine NWR is in the vicinity of the Calcasieu Ship 

Channel and could be affected by cumulative impacts. Given current use of Calcasieu Point Landing and 

the Sabine NWR in the vicinity of project-related activities, cumulative impacts on recreational areas 

would primarily be limited to dredging and pile driving activities within the Industrial Canal as well as 

increased vessel traffic during both construction and operation of the projects listed above (see discussion 

of potential cumulative impacts on visual resources, below). 

The greatest potential impact on recreational users of Calcasieu Point Landing associated with 

construction of the projects would be related to dredging and pile driving activities within the Industrial 

Canal. During these activities, described in detail in sections 4.13.2.3 and 4.13.2.5, it is likely that 

recreational fishers and boaters would avoid the area due to increased noise, construction activities, and 

suspended sediment levels. Although noise levels would be greater if the projects were to conduct 

dredging and pile driving activities during the same period, because it is likely that recreational users 

would avoid the area during these activities, cumulative impacts would not be anticipated. In contrast, if 

dredging and pile driving activities associated with these projects were to be staggered, it may result in a 

cumulative impact due to the increased duration that users would avoid the area.

Magnolia estimates that 50 or fewer marine deliveries would occur during construction of the 

LNG terminal. Marine deliveries to the DII construction yard would occur between one and three times 

per month during the first year of construction, and approximately one time per month during the second 

and third years of construction, which would represent an increase of less than 4 percent in current vessel 

traffic. However, as described in detail in section 4.13.2.9, Marine Traffic, when combined with 

construction of the other projects listed above (an addition of more than 400 marine deliveries per month),

there would be a substantial increase in the number of barges transiting the Calcasieu Ship Channel. 

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, because barges do not have moving security 

zones, impacts on other recreational users of the waterway would be intermittent, minor, and consistent 

with existing use of the waterway. 

During operation, Magnolia estimates that up to 208 LNG vessels would call on the LNG 

terminal per year (up to 104 LNG carriers and 104 LNG barges). Because number of LNG carriers 

calling on the Cameron and Trunkline LNG Terminals would not increase beyond what has been 

previously authorized (210 and 225, respectively), they are not included in the cumulative impact analysis 

because they are considered part of the environmental baseline. During transit of LNG vessels, a moving 

security zone would be established 2 miles ahead and 1 mile astern of LNG vessels and barges 

(33 CFR 165.805(a)(2)). Based on average vessel speed, recreational fishing and boating activities would 

be required to exit the immediate area of the Calcasieu Ship Channel for approximately 20 to 30 minutes 
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as each LNG vessel traverses the area. However, recreational users would be allowed to fish or boat in 

adjacent waters while the LNG vessel passed through the area. Therefore, although cumulative impacts 

on recreational users of the Calcasieu River and Industrial Canal would be intermittent, but moderate if 

each of the projects listed above were to be permitted and constructed, because these waterways were 

designed for and currently support deepwater maritime commerce, we have determined that cumulative 

impacts on recreation would be less than significant.

Visual Resources

The cumulative impact area for visual resources was considered to be the area within the 

viewsheds of the LNG terminal and KMLP facilities. Because of the height of the structures at the 

proposed LNG terminal, the viewshed of the facility would extend for up to several miles, depending on 

the direction. The viewshed for the proposed KMLP facilities is about 0.5 mile from the header pipelines 

and the modified meter station locations. The other projects encompassed by this impact area include the 

following:

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Live Oak LNG Project;

 Magnolia’s LNG bunkering and domestic marine distribution;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 G2X Energy’s natural gas to gasoline facility;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

The area surrounding the LNG terminal site is flat and relatively open, but trees block the views 

into the LNG terminal site from Tank Farm Road to the north and Airhart Road, Joe Ledoux Road, and 

the nearest private road off of Big Lake Road to the south. To determine how visible the terminal would 

be and from what vantage points, Magnolia conducted visual simulations from six observation points. As 

described in detail in section 4.8.5.1, these included the Calcasieu Point Landing boat launch 0.1 mile to 

the west, two locations on Big Lake Road about 0.6 and 0.8 mile to the east, a residential neighborhood 

0.6 mile to the south, another residential neighborhood 2.3 miles to the north, and the Intracoastal Park 

3.9 miles to the southwest. Based on these simulations and our evaluation of other sources and maps, we 

determined that the LNG terminal would be visible from Big Lake Road to the east, the Industrial Canal 

to the north, the existing Calcasieu Point Landing to the west, and likely the LDWF’s Fisheries Research 

Center to the south. The views from Tank Farm Road to the north would not be significantly affected by 

the LNG terminal because the terminal would be shielded by the trees growing along the south side of the 

road. Vegetation would also shield views of the site from residences and travelers on Airhart Road, Joe 

Ledoux Road, and the private road off Big Lake Road (that is just north of Airhart Road) to the south and 

southeast. 

There would be little potential for cumulative visual impacts. While some of the views from the 

surrounding roads that could see the LNG terminal would also include the existing Trunkline LNG 

Terminal, the facility does not dominate the viewshed and is consistent with existing development 

adjacent to the Industrial Canal. If permitted and constructed, G2X Energy’s natural gas to gasoline 

facility, the Lake Charles Liquefaction Project, and to a lesser extent the Live Oak LNG Project and 

LDWF’s Fisheries Research Center may result in cumulative impacts within the viewshed of the LNG 

terminal. However, the increase would be minor because, depending on the viewer’s location, the 
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primary visual impact on the viewshed would be either the LNG terminal (particularly the two LNG 

storage tanks and flare stack), the expanded Trunkline LNG Terminal (particularly the four LNG storage 

tanks and flare stacks), or the Live Oak LNG Terminal. Due to their location in relation to the existing 

roads, one of these three facilities would dominate the viewshed and the other facilities would be 

consistent with the surrounding area. 

For the reasons listed above, the LNG terminal would contribute more than the other projects to 

cumulative visual impacts from Calcasieu Point Landing. People using this park currently see buildings, 

small tanks, and various size ships; however, the existing viewshed does not have extensive views of the 

existing Trunkline LNG Terminal. The LNG terminal would also contribute more than the other nearby 

projects to cumulative visual impacts from the future LDWF’s Fisheries Research Center, due to the 

location of the proposed LNG terminal north of the Fisheries Research Center, across Henry Pugh 

Boulevard. It is likely that the LNG terminal and existing Trunkline LNG Terminal would largely screen 

visual impacts associated with G2X Energy’s natural gas to gasoline facility and the Lake Charles 

Liquefaction Project. The cumulative visual impact of Magnolia’s proposed LNG terminal and Live Oak 

LNG Project on fisherman and recreational boaters would be incremental as it would add to the number 

of industrial facilities and ships already visible from the waterway. The new electric transmission line 

required for the LNG terminal would also contribute to the cumulative visual impact on the area; 

however, because the installation of the roughly 15 new poles and wires associated with the transmission 

line would be located along Big Lake Road and Henry Pugh Road where there are already similar existing 

high voltage power lines and poles, the cumulative visual impact would be permanent, but minor. 

In summary, the LNG terminal would be within an existing industrial area and would be 

consistent with the surrounding land use. Although the LNG terminal would be clearly visible from some 

of the surrounding areas (Calcasieu Point Landing), we conclude that cumulative impacts on visual 

resources would be moderate because the LNG terminal and other facilities would be consistent with 

existing development in the area.

Construction and operation of the KMLP facilities would have only minor aesthetic impacts.

Construction activities at the CGT Meter Station, Transco Meter Station, TETCO Meter Station, ANR 

Meter Station, Pine Prairie Meter Station, and the TGT Meter Station would be limited to small areas 

within or around the perimeters of existing meter station facilities and thus, except for temporary impacts, 

would not permanently affect the visual character of the areas in which they are built. The current visual 

character along the low and high pressure header pipelines is primarily agricultural, interspersed with 

surface waters, wetlands, and existing oil and gas facilities (compressor and meter stations). The visual 

character of these areas would be temporarily affected during construction, but the disturbed areas and 

visual character of the land would be restored following construction of the pipeline, which would 

minimize any visual impacts.

The visual character of the proposed Compressor Station 760 site is dominated by agricultural 

land, an existing compressor station, and an existing natural gas processing plant. In addition, three 

houses are approximately 1,500 feet west of the site, and one set of structures associated with 

management of agricultural lands is within 50 feet of the site. Construction and operation of the new 

compressor station would introduce a third industrial facility within the viewshed. This effect would not 

be compounded by construction of the 0.3-mile-long electric transmission line to the compressor station 

because the line would continue from and be consistent with Cleco’s existing transmission line, which is 

located along Refinery Road. Therefore, the KMLP facilities and transmission line would result in 

permanent, but minor cumulative impacts on visual resources.
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4.13.2.8 Socioeconomics

We considered the cumulative impact area for socioeconomics to include Acadia, Calcasieu, 

Cameron, Evangeline, and Jefferson Davis Parishes. The proposed facilities would be located in Acadia, 

Calcasieu, and Evangeline Parishes. Of these, the greatest socioeconomic impacts would occur in 

Calcasieu Parish, where the LNG terminal would be located. Cameron and Jefferson Davis Parishes are 

also included in the socioeconomic analysis because they are would likely see an increase in non-local 

workers relocating to these areas during construction and operation of the LNG terminal. Each of the 

projects identified in table 4.13.2-1 is included in the analysis.

Population and Employment

During construction of the LNG terminal, Magnolia has stated that construction workers would 

be on site during 32 months of the 45-month construction period. The average workforce during this 

period would be 355 workers, of which approximately 142 would be non-resident workers. Over a 

9-month period, the construction workforce at the LNG terminal would number over 500 workers, of 

which, up to 217 are expected to be non-resident workers. Although unlikely, if all non-resident workers 

relocate with families, this addition would represent a 0.3 percent increase in population in Calcasieu, 

Cameron, and Jefferson Davis Parishes. Operation of the LNG terminal would result in the creation of 

67 permanent positions.

For the majority of the 11-month construction period associated with the KMLP facilities, the 

construction workforce would be 75 workers. However, during a 3-month period, up to 270 construction 

workers would be employed. We have estimated that an average of 36 workers and peak of 126 of these 

workers would be non-residents. This would represent an increase in the population within Acadia and 

Evangeline Parishes of 0.1 percent. Operation of Compressor Station 760 would result in the creation of 

four permanent positions.

The projects listed in table 4.13.2-1 would also require construction workers during the same 

period as the LNG terminal and KMLP facilities. Table 4.13.2-3 provides a summary of the estimated 

workforce needs for industrial and large-scale projects between 2015 and 2019 (SWLA Economic 

Development Alliance, 2015a). Construction labor requirements for the LNG terminal and KMLP 

facilities in 2017 and 2018, when employment associated with construction would be highest, would 

represent between 9 and 14 percent of the projected construction jobs for those years, respectively. In 

total, the projects constructed in Southwest Louisiana are expected to employ over 31,000 construction 

workers during the peak construction years, which are anticipated to conclude between 2018 and 2020 

(Adrian and Icaza, 2015). Following the completion of construction, collectively, the projects in 

Southwest Louisiana are expected to result in the addition of 18,000 or more permanent jobs due to direct 

and induced growth.

TABLE 4.13.2-3

Employment Forecast for Industrial and Large-Scale Projects Between 2015 and 2019

Year Construction Jobs Permanent Direct Jobs Permanent Indirect Jobs Permanent Induced Jobs

2015 4,475 974 475 470

2016 13,500 682 845 867

2017 5,475 415 2,080 1,859

2018 3,500 1,153 1,843 1,742

2019 700 965 1,250 350

____________________

Source SWLA Economic Development Alliance, 2015a
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Due to forecasted long-term industrial growth in the region, several programs designed to 

increase the number of qualified local workers have been developed, including programs through the 

Associated Builders and Contractors, Pelican Southwest Chapter in Westlake, Calcasieu Parish School 

Board, SOWELA Technical Community College, and Central Louisiana Technical Community College. 

The SWLA Economic Development Alliance is also collaborating with educational facilities and industry 

in the development of a Workforce Resource Guide, which provides residents with step-by-step 

instructions for finding employment and includes a description of the types of training required for each 

profession, as well as the training centers in Southwest Louisiana that offer the relevant certifications. 

Given that the planned construction projects would likely have staggered timelines for specific 

labor needs, it is likely that some construction personnel could work on multiple projects, which would 

have the effect of decreasing the overall labor requirement. In addition, some of the projects identified in 

table 4.13.2-1 may not be built, which would reduce the overall labor need. The cumulative effect would 

be a substantial reduction in unemployment in the area and potentially the need to train and hire 

construction workers from outside Southwest Louisiana. 

Housing and Public Services

The influx of non-local workers would affect the availability of housing in Southwest Louisiana. 

The cumulative impact on local housing may result in increased rental rates and housing shortages for 

lodging if all of the proposed and planned projects are implemented according to the expected 

timeframes. This would benefit the local housing market, but would adversely affect those seeking 

housing. Some members of the workforce may be forced to commute longer distances to obtain housing 

in adjacent parishes or Texas. 

To accommodate the anticipated influx of construction workers, two worker housing 

developments (Pelican Lodge and Moss Lake) are expected to be available for construction workers in 

2015 (SWLA Economic Development Alliance, 2015a). The two worker housing developments would 

accommodate up to 6,500 of the 13,500 anticipated workers. In addition to worker housing 

developments, a number of residential housing developments are planned or under construction in the 

Lake Charles area. New housing units, which include single-family dwellings, multi-family dwellings, 

hotels, and various residential projects, could total 8,070 if all publicly announced projects are permitted 

and constructed according to current plans (SWLA Economic Development Alliance, 2013).

The combined construction workforces of the projects listed in table 4.13.2-1 would increase the 

need for some public services, such as police, medical services, and schools. The need for these services 

would generally be spread throughout the parishes that house the workforce (Acadia, Calcasieu, Cameron, 

Evangeline, and Jefferson Davis Parishes), but there may be an increased need for medical and 

emergency services in Cameron and Calcasieu Parishes where the proposed project facilities and 

construction workers are expected to be concentrated. Magnolia would provide its own on-site security 

and the Calcasieu Parish Sheriff’s Office indicated that it believes it has sufficient resources available to 

provide protection services by adjusting patrol schedules or hiring additional staff with revenues allocated 

by the parish. In addition, Magnolia is currently in discussions with the Lake Charles Fire Department to 

identify measures for providing fire protection at the LNG terminal site. Options include funding firefighting services either independently or by entering into a mutual aid agreement with future industrial 

neighbors for the purpose of employing an industrial firefighting team trained in fighting fires at 

industrial facilities. With the increase in local taxes and government revenue associated with the 

proposed projects, the overall cumulative impact on public services would be expected to be minor.
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With construction of some of the major projects listed in table 4.13.2-1 lasting several years, it is 

likely that some construction workers would bring their families, including school-age children. This 

would increase the population in some schools in parishes housing the workers with families. However, 

it is likely that those families would be housed throughout many school districts in the five parishes and 

the increase in school population would be distributed through many schools. As a result, it is expected 

that the cumulative impact on schools would be minor.

4.13.2.9Traffic

Roadway Traffic

We considered the cumulative impact area for roadway traffic to include Acadia, Calcasieu, 

Cameron, Evangeline, and Jefferson Davis Parishes. Of these, the greatest impacts on roadway traffic 

would occur in Calcasieu Parish, where the LNG terminal would be located. Cameron and Jefferson 

Davis Parishes are included in the roadway traffic analysis due to the number of construction workers 

residing in and commuting from these areas to the proposed LNG terminal as well as the other proposed 

and planned projects in the area. As identified in table 4.13.2-1, the other projects encompassed by the 

impact area with the potential to impact roadway traffic include the following:

 Cameron LNG Terminal – four projects under construction, proposed, or planned;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Magnolia’s LNG trucking;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric facilities associated with the LNG terminal;

 Cleco’s transmission line to Compressor Station 760;

 G2X Energy’s natural gas to gasoline facility;

 Liberty Gas Storage Expansion Project;

 Matheson Tri-Gas’s Air Separation Unit;

 Port of Lake Charles’ addition of two docks at Bulk Terminal 1;

 Sasol’s Ethane Cracker and Derivatives Complex;

 Westlake Chemical Corporation;

 Entergy’s Lake Charles Transmission Project;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 Entergy’s electric transmission line for the Cameron Liquefaction Project;

 five residential developments; and 

 LDWF’s Fisheries Research Center.

The greatest potential for cumulative impacts on roadway traffic during construction and 

operation of the LNG terminal and KMLP facilities is associated with construction of the LNG terminal. 

Construction-related traffic associated with the KMLP facilities and the Cleco transmission line to 

Compressor Station 760 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 projects. 

During construction and operation of the LNG terminal and the other Lake Charles area projects

described above and in table 4.13.2-1, 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. Due to staggered construction schedules and the distance between 
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the project sites, cumulative impacts on traffic from the projects listed above that are not located adjacent 

to the Industrial Canal would be substantial at times, but are expected to be intermittent, short term, and 

localized. 

Between early 2016 and the end of 2017, three facilities adjacent to and within the Industrial 

Canal could be constructed if they receive the necessary regulatory approvals. These include the 

proposed LNG terminal, Lake Charles Liquefaction Project, and G2X Energy Lake Charles gasoline 

facility (see figure 4.13.1-2). Magnolia, the Lake Charles LNG companies, and G2X Energy 

commissioned a Traffic Impact Study to assess potential impacts of vehicular traffic associated with both 

construction and operation of the three projects, and to develop measures to mitigate impacts on local 

users of area roadways (Fenstermaker, 2014). The study found that the existing roadway network does 

not have sufficient capacity to accommodate the expected peak hour traffic volumes associated with 

construction of the three facilities. Therefore, the following mitigation measures were considered and 

agreed upon by Magnolia, the Lake Charles LNG companies, G2X, Louisiana DOTD, and the Calcasieu 

Parish Police Jury:

 Lake Charles LNG companies would provide off-site parking for 1,000 construction 

workers.

 Lake Charles LNG companies would provide temporary parking facilities near-site on the 

north side of Lincoln Road, east of Big Lake Road.

 Lake Charles LNG companies would provide temporary parking facilities near-site on the 

south side of Lincoln Road, east of Elliot Road.

 Buses would be utilized to transport construction workers from the off-site and near-site 

parking facilities to the Lake Charles Liquefaction Project site.

 Lake Charles LNG companies would provide right-turn and left-turn lanes at the 

following driveways:

o two temporary driveways on Big Lake Road, north of Tank Farm Road that 

would be used for construction laydown; 

o temporary delivery driveway on Big Lake Road, south of Tank Farm Road; 

o permanent driveway on Big Lake Road, approximately 300 feet south of Granger 

Road;

o two driveways into the temporary parking facility on Lincoln Road, east of Big 

Lake Road; and 

o driveway into the temporary parking facility on Lincoln Road, east of Elliot 

Road.

 Improvements would be made at three intersections (described in detail in section 4.9.6.1):

o Tank Farm and Big Lake Roads;

o Big Lake and Lincoln Roads; and

o Lincoln Road and Gulf Highway.
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Magnolia has stated that the measures recommended in the Traffic Impact Study would be 

implemented prior to construction as part of a cooperative effort between Magnolia, the Lake Charles 

LNG companies, and G2X Energy, which is known as the Calcasieu Point Development Project (see 

section 4.13.1.5). In a letter dated September 16, 2014, the Calcasieu Parish Police Jury stated that it has 

reviewed the study, agrees with the study’s recommendations, and has no objections. 

Six Levels of Service (LOS) (A through F) identify the operating conditions of a roadway 

(Transportation Research Board, 2010). A designation of LOS A represents a roadway with the best 

operating conditions, and a designation of LOS F represents the worst operating conditions. With the 

implementation of the proposed mitigation measures, all intersections included in the study would operate 

at a peak hour LOS D or above during construction of the three facilities. A designation of LOS D 

indicates that the roadway is approaching unstable flow; speeds slightly decrease as traffic volumes

slightly increase. Therefore, we conclude that impacts on local users of the roadways during construction 

would be moderate. Following construction of the facilities, all intersections would operate with a peak 

hour LOS A, which indicates that traffic would be flowing freely (Fenstermaker, 2014; Transportation 

Research Board, 2010). As such, we conclude that impacts on local users of the roadways due to 

increased traffic during operation of the projects would be negligible.

Marine Traffic

We considered the cumulative impact area for marine traffic to be the Calcasieu Ship Channel, 

which includes the Industrial Canal. As identified in table 4.13.2-1, the other projects encompassed by 

the impact area with the potential to impact marine traffic include the following:

 Cameron LNG Terminal – Cameron Liquefaction and Expansion Projects;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Pass Project;

 Delfin LNG Project;

 G2 LNG Project;

 Live Oak LNG Project;

 Magnolia’s LNG bunkering and domestic marine distribution;

 G2X Energy’s natural gas to gasoline facility; and

 maintenance dredging of the Calcasieu Ship Channel.

The Port of Lake Charles is currently the thirteenth busiest seaport in the United States and 

accommodates 5 million tons of cargo annually at its public facilities (Port of Lake Charles, 2015a). 

Current vessel traffic in the Calcasieu Ship Channel is approximately 1,022 vessels per year, which 

equates to an average of about 85 vessels per month (Port of Lake Charles, 2015b).

Magnolia estimates that 50 or fewer marine deliveries would occur during construction of the 

LNG terminal. Marine deliveries to the DII construction yard would occur between one and three times 

per month during the first year of construction, and approximately one time per month during the second 

and third years of construction, which would represent an increase of less than 4 percent in current vessel 

traffic. When combined with deliveries associated with construction of the Cameron Liquefaction Project 

(275 per month initially, decreasing to 125 per month after 11 months, and to 10 per month after 

15 months); Lake Charles Liquefaction Project (120 per month); and the G2X Energy natural gas to 

gasoline facility, Cameron Expansion Project, and Calcasieu Pass Project (for which the number of 

deliveries is not publicly available), cumulative impacts on vessel traffic within the Calcasieu Ship 

Channel would noticeably increase the number of barges transiting the channel. However, because barges 
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do not have moving security zones, impacts on other users of the waterway would be temporary, minor, 

and consistent with existing use of the waterway. 

During operation, Magnolia estimates that up to 208 LNG vessels would call on the proposed 

LNG terminal per year (up to 104 LNG carriers and 104 LNG barges). Although 225 and 210 LNG 

carriers would call on the Trunkline and Cameron LNG Terminals per year during operation, respectively, 

because the number of vessels would not increase beyond what is already authorized at the LNG 

terminals, they are not included in the cumulative impact analysis because they are considered part of the 

environmental baseline. During transit of LNG vessels, a moving security zone would be established 

2 miles ahead and 1 mile astern of LNG vessels and barges (33 CFR 165.805(a)(2)). 

Traffic within the Calcasieu Ship Channel is expected to markedly increase over the next 

10 years. In 2018, traffic within the channel is expected be 1,668 vessels per year; in 2023, traffic within 

the channel is expected to be 2,183 vessels per year, more than twice the 2013 level. For this reason, the 

Port of Lake Charles commissioned a simulation to investigate the impact of increased traffic on the 

operations of the channel and to assess the need for changes to channel infrastructure and regulations. 

The study evaluated the cumulative impact of expanded operations by existing channel users 

(e.g., Trunkline and Cameron LNG Terminals) and the construction of several additional facilities 

(e.g., Calcasieu Pass Project and Magnolia’s proposed LNG terminal).43 

As discussed in section 4.9.6.1, the results of the simulation indicate that although the Calcasieu 

Ship Channel has the capacity to accommodate the cumulative increase in vessel traffic, the median wait 

time is expected to increase by 2.3 hours per vessel (Ausenco, 2015). The study further notes that LNG 

carriers would experience the highest increase in median wait time (8.9 hours). The wait times are 

expected to vary seasonally, and would be higher during the winter months and lower during the summer 

months. In addition, the simulation indicated that 4 to 10 additional pilots and 1 or 2 additional sets of 

tugs would be required to accommodate vessel traffic without further increasing wait times. 

To minimize impacts on other users of the Industrial Canal and Calcasieu Ship Channel, it is 

anticipated that vessels (including LNG vessels) would be organized in convoys to be handled in the most 

efficient manner. The convoy would be specifically organized to maximize efficient transit; therefore, 

vessels traveling the farthest upstream would be prioritized (to minimize delays to other vessels during 

maneuvering and docking). The study indicated that changing the passing restrictions for LNG carriers 

on the outer bar and adding a passing lane on the inner channel would decrease the median wait times 

(see additional discussion in section 4.9.6.1). However, because these measures have not been proposed 

at the time of this writing, they are not evaluated further. Due to the expected increase in the median wait 

time by 2.3 hours per vessel, we expect that cumulative impacts on marine traffic within the Calcasieu 

Ship Channel and Industrial Canal during operation of the proposed projects as well as other projects 

along the waterways would be permanent and moderate.

4.13.2.10 Cultural Resources

The cumulative impact area for cultural resources was considered to be the area within and near 

the proposed LNG terminal and KMLP facilities. Magnolia and KMLP have consulted with the 

appropriate SHPO and completed the necessary cultural resource surveys and reports. The SHPO has 

concurred that construction of the projects would not affect historic properties, and we also concur. 

Therefore, the projects would not contribute to cumulative impacts on cultural resources.

 

43 G2X Energy’s natural gas to gasoline facility was not included in the simulation because it is expected to handle only barge traffic, which 

would not affect other users of the channel (Ausenco, 2015).
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4.13.2.11 Air Quality and Noise

Air Quality

Construction Impacts

The cumulative impact area for air quality during construction of the proposed LNG terminal and 

KMLP facilities is the area adjacent to the proposed facilities. The other projects encompassed by this 

impact area include the following:

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 G2X Energy’s natural gas to gasoline facility;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 LDWF’s Fisheries Research Center; and 

 maintenance dredging of the Calcasieu Ship Channel.

Construction of the LNG terminal would temporarily affect air quality due to emissions from the 

combustion engines used to power construction equipment, vehicle emissions traveling to and from the 

LNG terminal site, marine deliveries of construction materials, and from fugitive dust emissions resulting 

from earth-disturbing activities and equipment movement on dirt roads. 

We have determined that the other projects most likely to result in and contribute to cumulative 

air impacts include the Lake Charles Liquefaction Project, G2X Energy’s Lake Charles Gasoline Project, 

maintenance dredging of the Calcasieu Ship Channel, and the LDWF’s Fisheries Research Center, along 

with several smaller projects described above. 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. Magnolia, the Lake Charles LNG 

companies, and G2X Energy would implement mitigation measures to minimize construction impacts on 

air quality, including application of water to minimize fugitive dust, compliance with applicable EPA 

mobile source emission performance standards, and use of equipment manufactured to meet air quality 

standards. Based on the temporary nature of construction and the implementation of appropriate 

mitigation measures, we conclude that cumulative impacts on air quality due to construction of these 

facilities would be temporary and minor. 

Due to the limited amount of combustion engines required to construct transmission lines and the 

short duration of construction activities associated with construction of Cleco’s 0.3-mile-long electric 

transmission line, we have determined that cumulative impacts on air quality due to construction of the 

KMLP facilities would be negligible.

Operational Impacts

The cumulative impact area for air quality during the operation of the LNG terminal and KMLP 

facilities is the PSD Area of Impact of 6.2 miles (10 km). The PSD Area of Impact is a circular area 

around the emission source with a radius equal to the distance to the farthest receptor with a concentration 
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exceeding the SIL, otherwise known as the radius of impact. As identified in table 4.13.2-1, the other 

projects encompassed by this impact area include the following:

 Cameron LNG Terminal – Cameron Liquefaction, Expansion, and Access Projects;

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Live Oak LNG Project;

 Magnolia’s LNG trucking;

 Magnolia’s LNG bunkering and domestic marine distribution;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 G2X Energy’s natural gas to gasoline facility;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 Entergy’s Lake Charles Transmission Project;

 Entergy’s electric transmission line for the Cameron Liquefaction Project;

 LDWF’s Fisheries Research Center;

 Moss Lake Worker Village; and

 maintenance dredging of the Calcasieu Ship Channel.

Air pollutant emissions during construction of the LNG terminal 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. 

The region in the vicinity of the proposed LNG terminal is currently in attainment with air quality 

standards; however, increases in industrial point sources could affect local and regional air quality. Under 

federal and LDEQ regulations, the LNG terminal would be considered a major PSD emission source and 

would contribute to cumulative impacts on air quality within the cumulative impact area. Magnolia has 

supplied estimated operational emissions for the LNG terminal, 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, Area of 

Influence Analysis, and Pre-construction Monitoring Analysis. This analysis showed that the NO2 1‐hour

and annual SILs would be exceeded by impacts from the proposed LNG terminal. Because the 

1‐hour and annual SILs were exceeded, a NAAQS analysis was performed for both the NO2 1‐hour and 

annual averaging periods. The cumulative NAAQS impact analysis included an assessment of nearby 

sources (within 31 miles) of the LNG terminal’s determined area of impact. Results of the NAAQS 

assessment revealed that modeled concentrations are predicted to exceed the NO2 1-hour NAAQS; 

however, the LNG terminal contribution would be below the SIL; therefore, the LNG terminal would not 

cause or contribute to a violation of the NO2 1-hour NAAQS.

Projects that could contribute to cumulative impacts on air quality, and that are considered to be 

major sources of air emissions, would be required to conduct a PSD analysis. Should operation of a 

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 LNG terminal would be required to comply with LDEQ permit conditions 

during operation, which would include emission control requirements to limit the emissions of certain 

criteria pollutants, HAPs, and/or GHGs. Therefore, cumulative impacts on regional air quality as a result 

of the operation of these facilities would be permanent, but minor. 

In addition to operation of the various components of the LNG terminal described in 

section 4.11.1.5, air emissions from LNG marine traffic and other project-related vessels, considered 
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mobile sources of air emissions, would occur along the entire waterway from the boundary of the U.S. 

EEZ to the recessed berthing area at the proposed LNG terminal. However, due to the transitory nature of 

these mobile sources and the large area covered, cumulative impacts on air quality along the waterway 

due to these associated mobile source emissions would be temporary and minor.

KMLP has supplied facility emission estimates for Compressor Station 760. Because 

Compressor Station 760 would not be subject to PSD review for any criteria pollutants, the proposed 

facility is not subject to PSD permitting. However, KMLP completed a PSD modeling analysis for the 

proposed facility along with the initial permit application with evaluations of compliance with applicable 

NAAQS and PSD increments for pollutants greater than PSD significant emission rates (CO, NOX, PM10,

and PM2.5) (see section 4.11.1.3). This analysis showed that SILs for NOX, CO, PM10, and PM2.5 were not 

exceeded by potential impacts from Compressor Station 760. Because the modeled impacts did not 

exceed the SILs, operation of the compressor station would not cause or significantly contribute to an 

exceedance of either the NOX, CO, PM10, or PM2.5 NAAQS, and a full impact analysis was not required. 

As outlined in section 4.11.1.6, emissions from operation of the other KMLP facilities (low and high 

pressure header pipelines and meter station modifications) would be minor or insignificant. We anticipate 

that cumulative air quality impacts due to the proximity of KMLP’s proposed Compressor Station 760 

and Cleco’s 0.3-mile-long electric transmission line would be negligible.

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.
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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 U.S. Climate Change Science Program (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.

 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 0.3 inch 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 groundwater 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.
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 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 projects are 

identified in sections 4.11.4 and 4.11.5. A GHG BACT analysis has been performed for the LNG 

terminal; proposed GHG BACT for the LNG terminal 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 the EPA GHG BACT guidance, and a leak detection and 

repair program for monitoring piping and storage tank components to limit the impact of methane 

emissions. Compressor Station 760 would not be subject to PSD permitting 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 projects’ 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 projects’ contribution to 

cumulative impacts on climate change would be significant.

Noise

The cumulative impact area for noise was conservatively estimated to be the area within 1.5 miles 

of the LNG terminal and within 1-mile of the KMLP facilities. The other projects encompassed by this 

impact area include the following:

 Trunkline LNG Terminal – Lake Charles Liquefaction Project;

 Magnolia’s LNG trucking;

 Magnolia’s LNG bunkering and domestic marine distribution;

 Calcasieu Parish District 12 Water Works’ tie-in for the LNG terminal;

 Entergy’s electric transmission line and switching station for the LNG terminal;

 Cleco’s electric transmission line for Compressor Station 760;

 G2X Energy’s natural gas to gasoline facility;

 Entergy’s electric transmission line and substation for the Lake Charles Liquefaction Project;

 LDWF’s Fisheries Research Center; and

 maintenance dredging of the Calcasieu Ship Channel.

The greatest potential for cumulative noise impacts associated with the LNG terminal and KMLP 

facilities would be during construction from internal combustion engines and pile driving activities. In 

general, the estimated noise generated from construction associated with the LNG terminal would not 

exceed 55 dBA Ldn at the nearest NSAs (approximately 0.7 mile south of the site). However, pile driving 

activities have the potential to produce sound levels of up to 72 dBA Lmax at the nearest NSAs. Therefore, 

we have included a recommendation in section 4.11.2.3 that outlines measures to reduce pile driving 

noise (Leq) to no greater than 10 dBA over ambient levels at the nearest NSA. Although construction of 
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G2X Energy’s natural gas to gasoline facility, the Lake Charles Liquefaction Project, the LDWF’s 

Fisheries Research Center, and the utilities associated with these projects could overlap with the 

construction of the LNG terminal and contribute to noise levels in the area, all of these projects, except 

for the LDWF’s Fisheries Research Center, are farther from the nearest NSA. As a result, we conclude 

that construction of the LNG terminal along with the projects other than the LDWF’s Fisheries Research 

Center would result in a temporary and insignificant cumulative impact on noise levels at the nearest 

NSA. If construction activities at the Fisheries Research Center were to coincide with pile driving 

activities at the LNG terminal, cumulative noise impacts at the nearest NSAs could occur. However, due 

to the distance between the proposed aboveground facilities within the Fisheries Research Center and the 

LNG terminal (approximately 1 mile), these impacts are expected to be temporary and minor.

The estimated operational noise level of the LNG terminal, when combined with the existing 

ambient noise levels, at the nearest NSA is 52 dBA Ldn, which is 1 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 LNG terminal would result in minor impacts on the NSA. 

Noise decreases logarithmically with increasing distance from a noise source; therefore,

cumulative operational noise impacts would only occur where other facilities or activities would occur 

very close to the projects. We have determined that the other projects most likely to result in and 

contribute to cumulative noise impacts include the Lake Charles Liquefaction Project, G2X Energy’s 

Lake Charles Gasoline Project, maintenance dredging of the Calcasieu Ship Channel, Magnolia’s LNG 

trucking, Magnolia’s LNG bunkering and domestic marine distribution, and the LDWF’s Fisheries 

Research Center, along with several smaller projects described above. 

The cumulative noise during operation of these facilities would likely be less than during 

construction because many of the projects including the electric transmission lines and substations, 

waterline tie-in, and the LDWF’s Fisheries Research Center would generate little to no noise after they 

are built. The bi-annual maintenance dredging of the Calcasieu Ship Channel could contribute to the 

cumulative noise impact of NSAs near the LNG terminal, but the effect would be temporary and limited 

to when dredging is occurring very close by. The two projects with the greatest potential to contribute to 

the long-term cumulative noise impacts are the Lake Charles Liquefaction Project and G2X Energy’s 

Lake Charles Gasoline Project, both of which are within 1,000 feet of the LNG terminal. As part of its 

application to the FERC, the Lake Charles LNG companies evaluated the potential for cumulative noise 

impacts at the NSAs near each site. This assessment, which was performed by Hoover and Keith, 

indicates that the sound level due to the concurrent operation of both facilities would not exceed an Ldn of 

55 dBA at any of the existing NSAs. Overall, the expected contribution from Lake Charles Liquefaction 

Project at Magnolia NSAs 1 and 2 would be lower than the contribution from the LNG terminal. At 

NSA 3, the estimated contribution from Lake Charles Liquefaction Project would be higher than the LNG 

terminal, but the expected increase from ambient at this location is 0.7 dBA, which would be unnoticeable 

or barely noticeable at the nearest NSA. The Hoover and Keith assessment did not evaluate the potential 

noise contribution of the G2X Energy’s Lake Charles Gasoline Project. This facility is not regulated by 

FERC and thus not subject to the FERC noise threshold; however, the facility would be subject to 

Calcasieu Parish noise regulations found in the Calcasieu Parish Police Jury Code of Ordinances, Chapter 

18, Article VIII. Thus, the G2X Energy facility would not be expected to contribute markedly to the 

noise levels at the NSAs closest to Magnolia’s proposed LNG terminal.

Construction of the KMLP facilities would generate temporary increases in sound levels over a

period of approximately 11 months, predominantly during the day. Construction activities would involve 

clearing and grading, installation of the header pipelines, construction of Compressor Station 760, and 

installation of proposed modifications at existing meter stations. The estimated noise levels associated 
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with construction of Compressor Station 760 at the nearest NSA (approximately 1,125 feet west of the 

site) would be between 63 Leq (dBA) and 58 Leq (dBA). While the construction activities may be audible 

at nearby NSAs, these noise levels would be limited to daytime and would be minor. Construction of 

Cleco’s electric transmission line to Compressor Station 760 may result in temporary increases in noise 

levels at the NSAs west of the compressor station (NSAs 1 and 3). Although noise levels generated by 

construction of the transmission line are not available, it is expected that cumulative impacts on noise 

levels at NSAs 1 and 3 would be temporary, minor, and primarily limited to the period when poles are 

driven to support the transmission wires. 

4.13.2.12 Safety 

We considered the cumulative impact area for the projects to be the area adjacent to and in the 

vicinity of the LNG terminal site and KMLP facilities. 

Magnolia would mitigate impacts on public safety through the implementation of applicable 

federal, state, and local rules and regulations for the proposed LNG terminal 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 

the project would require an increase in the number of LNG carriers transiting the Calcasieu Ship Channel 

and Industrial Canal, it would 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. In accordance with our 

regulations, Magnolia 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 Lake Charles Liquefaction Project, Cameron Liquefaction and Expansion Projects, and other 

liquefaction and LNG export projects listed in table 4.13.2-1, 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 project proponents in the Lake Charles area 

(e.g., G2X Energy, IFG, Sasol, and Juniper GTL, LLC) 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 adverse 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/or Cameron Parishes. That impact could 

be mitigated by assistance from emergency service providers from surrounding parishes.

As discussed in section 4.12.11.2, the risk associated with the proposed KMLP facilities would be 

small. Although operation of the proposed 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 KMLP facilities would be negligible.

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, DOT, and EPA, 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 Magnolia LNG and Lake Charles 

Expansion Projects would result in limited adverse environmental impacts. Most adverse 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 

projects. This determination is based on a review of the information provided by Magnolia and KMLP

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 projects. Therefore, we are recommending that our mitigation measures 

be attached as conditions to any authorization issued by the Commission. If the proposed projects are

constructed and operated in accordance with applicable laws and regulations, the mitigating measures 

discussed in this EIS, and our recommendations, adverse environmental impacts would be reduced to less 

than significant levels. A summary of the anticipated impacts from the projects and our conclusions 

regarding impacts are provided below by resource area.

5.1.1 Geologic Resources

Construction and operation of the projects would not affect active mining or nonfuel mineral 

resources during construction or operation. One active oil producing well is 150 feet west of the TGT 

Meter Station and immediately adjacent to an existing access road. To avoid impacts on this active well, 

KMLP has stated that the well’s owner would be notified 72 hours prior to construction activities near the 

well, and that the owner or owner’s representative would be on site during construction activities.

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

facilities is low. However, some hazards such as flooding and hurricanes could affect the projects during 

operation. Magnolia and KMLP would design and construct the aboveground facilities at the LNG 

terminal, Compressor Station 760, and modified meter stations at an elevation to minimize potential 

impacts from flooding and hurricanes. 

Subsidence could occur in the project vicinity, particularly at the LNG terminal, due to oil and 

gas extraction and groundwater withdrawal. Magnolia estimated that regional subsidence proximate to 

the LNG terminal will be 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 approximately 9 inches over the 30-year life of 

the LNG terminal. Subsidence in the vicinity of the KMLP facilities is expected to result in a loss in 

elevation of 0.1 inch over the 30-year life of the facilities. 
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The overall effect of the projects on topography and geology would be minor. The primary 

impacts on geologic resources would be due to the permanent alteration of geologic conditions at the 

LNG terminal and to a lesser extent at Compressor Station 760. Final grade surfacing and landscape 

within these facilities would consist of gravel, asphalt, concrete, topsoil, and grass surface areas. 

Magnolia would drive approximately 5,000 precast concrete piles to support key terminal components 

and structures. Impacts on geologic resources due to installation of the header pipelines and meter station 

modifications would be primarily limited to construction activities and include disturbance of slopes 

within the work areas. Such impacts resulting from grading and trenching would be temporary because 

KMLP would restore these areas to preconstruction contours to the maximum extent practicable.

The design of the LNG terminal is currently at the FEED level of completion. Magnolia has

proposed a feasible design and committed to conducting additional detailed design work for the LNG 

terminal if the project 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 Magnolia file site 

preparation drawings and specifications, LNG storage tank and foundation design drawings and 

calculations, LNG terminal structures and foundation design drawings and calculations, seismic 

specifications for procured equipment, 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 proposed 

facilities. Based on the above discussion, in consideration of Magnolia’s and KMLP’s proposed 

mitigation and design criteria, and based on our recommendations, we conclude that the projects would 

not markedly affect or be affected by geological conditions in the area.

5.1.2 Soils

Construction of the projects could affect soil resources by increasing the potential for erosion, 

compaction, and rutting. Based on the soil properties reviewed, none of the soils potentially affected by 

the projects are considered highly susceptible to erosion by wind or water. Due to fine textured soils and 

nearly level topography, no revegetation concerns were identified. However, approximately 97 percent of 

the soils are prone to compaction. About 108 acres within the dredge material placement area and all of 

the soils potentially affected by the KMLP facilities are designated as prime farmland. 

Construction activities such as clearing, grading, excavation, backfilling, and the movement of 

construction equipment may affect soil resources at the LNG terminal. In order to increase the load 

bearing capacity of soils along the heavy haul road, an engineered grout would be added to the subsoil 

that would permanently alter the physical characteristics of 7.5 acres of soils at the terminal site. 

Following construction, approximately 90 acres of soils at the terminal would be permanently impacted 

by paved or gravel plant roads, occupied by aboveground facilities, or converted to open water within the 

recessed berthing area. Magnolia would seed the remaining 33.7 acres within the LNG terminal site with 

native vegetation recommended by the NRCS. Operation of the KMLP facilities would permanently 

convert 12.0 acres to industrial use for operation of Compressor Station 760 and the expanded CGT, 

TRANSCO, and TGT Meter Stations. The remaining 63.8 acres of prime farmland soils would be 

restored to pre-construction conditions and are anticipated to retain their former productivity. 

Contamination from spills or leaks of fuels, lubricants, and coolant from construction equipment 

could also adversely affect soils. To prevent contamination of soils during construction, Magnolia has 

stated that it would implement its Spill Prevention Plan during construction and its SPCC Plan during 

operation of the LNG terminal. However, because Magnolia has not yet provided its final spill plans, we 

are recommending that, prior to construction, Magnolia file its final Spill Prevention Plan for construction 
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and SPCC Plan for operation of the project. KMLP would employ the mitigation measures included in its 

project-specific SPCC Plan, which would specify cleanup procedures to minimize the potential for soil 

contamination from such spills or leaks. 

One hazardous waste site was identified within 1 mile of the LNG terminal. The Lake Charles 

Carbon Company is 0.6 mile north of the terminal site across the Industrial Canal. The results of soil 

sampling performed by Magnolia within the Industrial Canal and on land at the terminal site determined 

that the materials sampled do not contain contaminated material. Based on the results of the sampling 

report and the distance between the LNG terminal and the Lake Charles Carbon Company, no 

contaminated soils are expected to be encountered during construction or operation.

To reduce the impacts of construction on soils, Magnolia would implement measures outlined in 

its project-specific Plan and Procedures, which include measures to control erosion and sedimentation 

during construction and to ensure proper restoration of disturbed areas following construction. Similarly, 

KMLP would implement the mitigation measures contained in the FERC Plan and Procedures to control 

erosion, enhance successful revegetation, and minimize any potential adverse impacts on soil resources. 

In addition, disturbed areas would be monitored by Magnolia and KMLP 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 recommendation, we conclude that impacts on soil resources would be 

adequately minimized.

5.1.3 Water Resources

Groundwater

The LNG terminal and KMLP facilities are underlain by the Chicot aquifer, which is an EPAdesignated sole-source aquifer. In some areas, groundwater withdrawals from the Chicot aquifer are 

causing lowered water levels (drawdown) and saltwater encroachment. Although no portion of the Chicot 

aquifer has been designated as an Area of Ground Water Concern, high water use in southwest Louisiana 

has been identified as one of the current major issues having an impact on groundwater sustainability 

management. In 2012, the LDNR and USGS entered into a joint partnership to increase groundwater 

monitoring. Construction of the LNG terminal would require approximately 2.5 million gallons of 

groundwater for construction worker sanitation, dust suppression, hydrostatic testing of plant piping at the 

LNG terminal, cleaning of the LNG storage tanks following hydrostatic testing, and other general utility 

uses over the 45-month construction period (the majority of which would take place during the first 

36 months of construction). On average, approximately 1,800 gallons of groundwater would be required 

per day, although approximately 6,000 gallons of groundwater would be required per day during peak 

construction. Groundwater required during construction of the KMLP facilities would be limited to 

approximately 346,000 gallons of water, which would be used for hydrostatic testing.

The majority of the construction activities associated with the LNG terminal and KMLP facilities

would involve shallow, temporary, and localized excavation, with the exception of the installation of two 

groundwater wells and concrete and steel piles at the LNG terminal. The two new groundwater wells 

would be installed at the LNG terminal, which would be used during operation for process, service, and 

fire water systems. Each well would be drilled to a depth between 500 and 700 feet (the 500-foot sand). 

Concrete and steel piles required for the LNG storage tanks and LNG ship loading and berthing areas 

would be driven to a depth no lower than approximately 110 feet, and are not expected to have direct 

impacts on the underlying aquifer, which is overlain by about 150 feet of surficial sediments.
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The LNG terminal would be within seven drinking water protection areas, each of which has a 

1-mile radius centered on the well. Two of the protection areas are associated with wells immediately 

adjacent to the southeast corner of the terminal site that supply water for Calcasieu Parish District 12 

Water Works. The other five wells are associated with the Lake Charles Carbon Company and Trunkline 

LNG Terminal; these wells are between 0.3 and 0.8 mile north of Magnolia’s proposed LNG terminal 

site, across the Industrial Canal.

No private water wells are within 150 feet of the proposed LNG terminal site. Two private water 

wells are within 150 feet of the KMLP facilities, including a domestic supply well approximately 16 feet 

north of the TRANSCO Meter Station on the north side of Transco Road and a plugged and abandoned 

rig supply well approximately 100 feet south of the access road to the Pine Prairie Meter Station. KMLP 

stated that no sub-surface work greater than 10 feet in depth would be required at the TRANSCO Meter 

Station site and that it would coordinate with the well owner to test the well water both before and after 

construction. In addition, KMLP would contact each affected landowner to confirm the locations of 

private wells within 150 feet and public wells within 400 feet of the construction workspace. To 

document impacts on water wells and verify that they are appropriately addressed, we are recommending 

that, within 30 days of placing facilities in service, KMLP file a report identifying all public or private 

water supply wells/systems damaged by construction and a description of 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.

Groundwater use associated with operation of the LNG terminal would increase overall 

withdrawal from the Chicot aquifer by up to 167,378 gallons per day for operation of the demineralized 

water treatment plant and use as service water, which is equivalent to about 0.023 percent of the current 

daily water withdrawal from the Chicot aquifer. Magnolia conducted a drawdown analysis, which 

indicated that operation of the new on-site well within the 500-foot sand would result in drawdown of less 

than 1.5 feet at a distance of 1,500 feet from the point of withdrawal. No groundwater would be 

necessary for the operation of the KMLP facilities. We anticipate that construction and operation of the 

projects would have long-term, but minor impacts on the Chicot aquifer. 

Surface Water

The Industrial Canal at the LNG terminal site 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 

the canal during construction of the LNG terminal would be associated with dredging the berthing area 

for LNG vessels and the associated suspension of sediments in the water column. Magnolia proposes to 

use a hydraulic cutterhead suction dredge, which would minimize turbidity and surface water quality 

impacts. Dredge material would subsequently be transported by pipeline approximately 8,000 feet east to 

the placement area. Throughout dredging operations, dredge materials would be discharged to the 

placement area and allowed to dewater, after which the decanted water would be pumped through the 

effluent return pipeline and discharged back into the Industrial Canal. Potential impacts on water quality 

in the Industrial Canal resulting from dredging and the subsequent discharge of water back to the canal 

would include temporary increases in suspended solids and turbidity levels as well as potential 

resuspension of contaminated sediments. Use of a hydraulic cutterhead suction dredge would minimize 

turbidity from resuspension of the sediment in the water column and other surface water quality impacts. 

To further minimize these impacts, Magnolia would implement its Dredging Water Quality Monitoring 

Plan. Because this plan has not been finalized, we are recommending that, prior to construction, 

Magnolia file the final Dredging Water Quality Monitoring Plan. During operation, maintenance 

dredging of the recessed berthing area would be required every 4 to 5 years to maintain adequate water 

depths for LNG vessel maneuvering. Although maintenance dredging would result in a temporary 
5-5

increase in suspended sediment and turbidity levels, these impacts are expected to be temporary and 

limited to the vicinity of dredging activity within the Industrial Canal. 

In-water construction associated with the LNG loading and ship berthing facilities, ground 

disturbance, filling of one intermittent waterbody that is not hydrologically connected to the Industrial 

Canal and one man-made waterbody, and general construction activities within the terminal site would 

result in localized, temporary increases in turbidity and suspended sediment levels. To minimize impacts 

on water quality, land disturbing activities would be conducted in compliance with the LPDES General 

Permit. In addition, Magnolia would implement its project-specific Construction SWPPP, Plan, and 

Procedures; and KMLP would implement the FERC Plan and Procedures. As a result, impacts on water 

quality are expected to be temporary and limited to the area within and immediately adjacent to the LNG 

loading and ship berthing facilities. Operation of the LNG terminal would increase the amount of 

impervious surface, which would result in an increased volume of stormwater runoff. Stormwater would 

be directed into two holding basins for dilution and temperature adjustment to ambient levels before being 

discharged into the Industrial Canal in accordance with Magnolia’s Operational SWPPP, and LDEQ and 

EPA requirements.

A total of 10 waterbodies, including 3 intermittent waterbodies and 7 ephemeral ditches would be 

crossed or otherwise affected (e.g., culvert installation) by construction of the KMLP facilities. None of 

the waterbodies that would be impacted by the KMLP facilities are listed as National Wild and Scenic 

Rivers, designated as Outstanding Natural Resource Waters, designated as EFH, or contain federally or 

state-listed species. KMLP would minimize potential impacts on surface waters by implementing the 

FERC Procedures and utilizing dry crossing construction techniques, if flowing water is present within 

the waterbodies at the time of construction.

During construction of the LNG terminal, barges and support vessels would deliver large 

equipment and materials to the DII construction yard. Magnolia estimates that 50 or fewer marine 

deliveries would occur during construction. During operation, approximately 208 LNG vessels 

(104 LNG carriers and 104 LNG barges) would call on the LNG terminal per year. The construction and 

operational vessel traffic may increase shoreline erosion and temporarily increase turbidity levels within 

the Industrial Canal and along vessel transit routes. Magnolia would install rock armoring to provide 

scour protection from propeller wash both within and along the east and west ends of the recessed 

berthing area. The rock armoring would prevent erosion of the adjacent unprotected shoreline by wave 

activity from vessels maneuvering within the recessed berthing area. The Industrial Canal and Calcasieu 

Ship Channel were specifically created to provide deepwater access for maritime commerce. As such, 

use of the waterways by LNG carriers, barges, and support vessels during construction and operation of 

the LNG terminal would be consistent with the planned purpose and use of active shipping channels, and 

associated impacts on water quality within the shipping channel would be minor.

LNG carriers serving the terminal would discharge between approximately 8,711,000 and

12,264,000 gallons of ballast water into the Industrial Canal during LNG loading. Ballast water 

discharges at the LNG terminal could impact water quality by changing the salinity, temperature, pH, and 

dissolved oxygen level of water within the Industrial Canal. The physiochemical composition of ballast 

water in comparison to the water present within the Industrial Canal and Calcasieu River would vary 

depending on tidal and hydrologic conditions at the time of discharge. The primary potential impact on 

water quality due to ballast water discharge would be a temporary increase in salinity level. Salinity 

within the canal varies throughout the year, and tends to increase with water depth. Ballast water, which 

would generally consist of open ocean water, would have a higher salinity than the surrounding water. 

Because ballast water would be discharged near the bottom of the berthing area, and would comprise 

approximately 0.6 percent of the approximately 2 billion gallons of water within the Industrial Canal, we 

anticipate that natural flow and tidal exchange would dilute the ballast water discharge to salinity levels 
5-6

that typically occur within the Industrial Canal in the immediate vicinity of the LNG terminal and that 

increased salinity would represent a temporary and minor impact on water quality.

During operation, LNG carriers and LNG barges require water for cooling of the main 

engine/condenser, diesel generators, and fire main auxiliary and hotel services. Steam-powered LNG 

carriers would have the highest cooling water requirements (11.7 million gallons), LNG carriers with dual 

fuel/diesel electric engines would use 5.5 million gallons of water, and LNG barges would require 

535 gallons of water. Impacts on surface waters would be primarily limited to an increase in water 

temperature in the vicinity of the LNG vessel resulting from the discharge of water between 2.7 °F and 

7.2 °F warmer than ambient water temperatures. Due to the limited temperature differences, relatively 

small volume of discharge compared to the total water within the canal, and location within an active port 

that is already subject to withdrawals and discharges of vessel engine cooling water, we have determined 

that cooling water discharges would have temporary and minor impacts on water quality.

Approximately 27.5 million gallons of water would be required for hydrostatic testing of the 

LNG terminal and KMLP facilities, which would be obtained using both municipal sources and surface 

waters. Hydrostatic test water would be withdrawn from the Industrial Canal through screened intake 

hoses at rates ranging from 1,500 to 3,333 gallons per minute. Following completion of testing, water 

would be discharged directly to the Industrial Canal (i.e., LNG storage tanks, dredge material and effluent 

pipelines), within the LNG terminal site (i.e., Magnolia Meter Station, interconnect pipeline, and plant 

piping), or within the Compressor Station 760 site (i.e., header pipelines and meter station modifications). 

To minimize potential impacts on water quality, no chemical additives would be used in association with 

hydrostatic testing, and Magnolia and KMLP would each comply with all testing requirements and 

environmental conditions of the LPDES General Permit for Discharges of Hydrostatic Test Water. 

During construction and operation, hazardous materials resulting from spills or leaks flushed into 

waterbodies with stormwater runoff or entering the Industrial Canal and the Calcasieu River could have 

an adverse impact on water quality. To prevent spills and leaks, Magnolia would implement its projectspecific Spill Prevention Plan during construction and its SPCC Plan during operation of the LNG 

terminal, which outline potential sources of releases at the site, measures to prevent a release, and initial 

responses in the event of a spill. Similarly, KMLP would implement its project-specific SPCC Plan, 

which identifies potential sources of hazardous materials present during construction activities and the 

measures that would be implemented to prevent, contain, and clean up accidental releases.

With implementation of Magnolia’s and KMLP’s project-specific plans, the proposed mitigation 

measures discussed in this EIS, and our recommendation, we conclude that impacts on surface waters 

would be adequately minimized.

5.1.4 Wetlands 

Construction of the LNG terminal would result in the permanent loss of approximately 16 acres 

of wetlands, including 8 acres of palustrine emergent wetlands, 7 acres of palustrine scrub-shrub wetland, 

1 acre of estuarine emergent intertidal wetland, and less than 1 acre of palustrine forested/scrub-shrub 

wetland. Approximately 87 percent of the wetlands would be converted to upland industrial or open land 

within the LNG terminal site, 7 percent would be converted to an upland herbaceous community within 

the dredge material placement area, and the remaining 6 percent would be converted to open water within 

the recessed berthing area or filled for shoreline stabilization. To date, access has not been granted to 

conduct the necessary wetland surveys along the dredge material and effluent pipeline route or within the 

dredge material placement area. Therefore, we are recommending that, as soon as they are available and 

prior to the start of construction, Magnolia file the results of the wetland and waterbody surveys within 

areas associated with the transport and placement of dredge materials. Magnolia would also be required 
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to mitigate for unavoidable impacts on jurisdictional wetlands as part of its project-specific Compensatory 

Mitigation Plan.

During operation, vessel traffic along the Industrial Canal and within the recessed berthing area 

could result in increased shoreline erosion, potentially impacting the wetland fringe along the Industrial 

Canal due to increased wave activity. To avoid impacts on this wetland, Magnolia would install rock 

armoring both within and along the east and west ends of the recessed berthing area, which would prevent 

erosion of the adjacent unprotected shoreline by wave activity from vessels maneuvering within the 

recessed berthing area. With the implementation of Magnolia’s proposed rock armor, and considering the 

anticipated vessel speed and the fact that the Industrial Canal is an existing ship channel regularly subject 

to commercial marine traffic, we have determined the increase in vessel traffic within the Industrial Canal 

and recessed berthing area would cause a negligible increase in erosion of the adjacent wetland.

Magnolia filed its section 404 permit applications with the COE, New Orleans District in May 

2014. Because the Compensatory Mitigation Plan has not been finalized and approved by the COE, we 

are recommending that, prior to filing its Implementation Plan, Magnolia file its Compensatory 

Mitigation Plan and documentation of COE approval of the plan. 

Construction and operation of the KMLP facilities would permanently convert 0.3 acre of 

palustrine emergent wetlands to upland industrial use. These impacts would primarily occur within the 

expanded TGT Meter Station, but would also include very small areas at the TRANSCO Meter Station 

and where connection of the high pressure header pipeline would require modifications of existing 

interconnect facilities adjacent to the Pine Prairie Meter Station. In its jurisdictional determinations for 

the KMLP facilities, the COE determined that wetlands present are not jurisdictional under section 404 of 

the CWA; therefore, compensatory mitigation for these wetland impacts would not be required. KMLP 

would still implement the mitigation measures described in the FERC Procedures during construction and 

operation within these wetlands. Following construction, the less than 0.1 acre of wetland within 

temporary workspace would be restored in accordance with the FERC Procedures and allowed to 

revegetate naturally using the seedbank within the existing topsoil.

Our Procedures state that aboveground facilities should be located outside of wetlands, except where 

such siting would prohibit compliance with DOT regulations. Magnolia and KMLP have each proposed 

locating portions of aboveground facilities within wetlands. We have determined that these proposed 

deviations from the FERC Procedures are reasonable. 

With the implementation of Magnolia’s and KMLP’s project-specific plans, the proposed 

mitigation measures discussed in this EIS, and our recommendations, we conclude that impacts on 

wetlands due to construction and operation of the projects would be permanent but minor.

5.1.5 Vegetation

A total of 114.0 acres of vegetation would be cleared during construction at the LNG terminal 

site. Following construction, the majority of the vegetation affected at the terminal (80.3 acres) would be 

permanently converted to industrial use associated with operation of the facility, resulting in a permanent 

loss of 34.0 acres of mixed hardwood loblolly forest, 31.3 acres of upland shrub, and 15.0 acres of 

wetlands. Magnolia would seed the remaining 33.7 acres of land within the LNG terminal site with 

native vegetation per NRCS recommendations, with the site being maintained as an upland herbaceous 

community. Although impacts on the majority of the vegetation affected by the LNG terminal would be 

permanent, because the site was previously used for dredge material disposal, vegetation communities 

within the site are limited in diversity. Therefore, impacts on vegetation communities would be 

permanent, but minor.
5-8

Vegetation within the dredge material placement area is largely composed of upland herbaceous 

communities. Because the placement area is currently used for staging and laydown, vegetation is 

routinely mowed and maintained in a graminaceous or weedy state. Dredge material placement would 

affect 107.3 acres of vegetation, including 106.1 acres of upland herbaceous vegetation and 

approximately 1.2 acres of wetlands. Following dredging and dewatering activities, the dredge material 

placement area would be graded and seeded in accordance with landowner requirements.

The KMLP facilities would be primarily within existing meter stations and on adjacent 

agricultural land, which comprises 99 percent of the vegetated communities within the affected areas. 

Small areas of upland herbaceous communities and emergent wetlands are also present within the KMLP 

facilities. During construction, 64.3 acres of vegetation would be impacted, including 40.4 acres 

associated with the new compressor station, 21.2 acres associated with the header pipelines, and 2.7 acres 

associated with the meter station modifications. The primary impacts on vegetation from construction of 

the KMLP facilities would be the cutting, clearing, and/or removal of existing vegetation within the 

construction workspace. Following construction, 12.0 acres of vegetation would be permanently 

converted to industrial land associated with the new or modified aboveground facilities. The remaining 

52.3 acres would be allowed to revert to pre-construction condition in accordance with the FERC Plan 

and Procedures, NRCS recommendations, other agency requirements and permit conditions, and 

landowner requests. However, 8.3 acres of this would be subject to routine maintenance over each of the 

header pipelines. To further minimize impacts on vegetation communities during and after construction, 

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

facility sites. Impacts would be minor and short term because we would expect these areas to revegetate 

to a cover similar to pre-construction conditions within one to two growing seasons. 

Field surveys at the LNG terminal site identified Chinese tallow, a noxious weed that grows and 

spreads quickly. In addition, silktree was identified during surveys, which is an exotic species though it is 

not federally or state-designated as a noxious weed. To control and prevent the spread of Chinese tallow, 

Magnolia would implement its project-specific Noxious Plant Control Plan during construction and a 

Chinese tallow control and maintenance plan during operation of the LNG terminal. The Chinese tallow 

control and maintenance plan would require ongoing mechanical and potentially chemical treatment to 

effectively manage Chinese tallow while providing the opportunity for native and other preferred species 

to establish in designated areas. In addition, the FERC 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.

Due to previous disturbance within the majority of the areas impacted, and with the 

implementation of Magnolia’s and KMLP’s project-specific plans, the proposed mitigation measures 

discussed in this EIS, and our recommendations, we conclude that impacts on vegetation due to 

construction and operation of the projects would be permanent but minor.

5.1.6 Wildlife and Aquatic Resources

Wildlife

Wildlife species in the vicinity of the LNG terminal and KMLP facilities are characteristic of the 

habitats provided by the plant communities that occur in these areas. About 329.2 acres of wildlife 

habitat would be affected by construction of the LNG terminal and KMLP facilities. Overall, the greatest 

impacts would be on open land (187.6 acres), agricultural (63.5 acres), and open water (43.6 acres) 

habitats. The greatest impacts on terrestrial wildlife would result from the permanent loss of 

approximately 68 acres of forested and open lands within the LNG terminal site (approximately 34 and 

31 acres, respectively), which would result in a permanent reduction in these habitat types in the general 
5-9

vicinity of the LNG terminal. However, due to the site’s previous use as a dredge disposal site, 

vegetation species diversity is low, which lessens its value as habitat for wildlife.

Operation of Magnolia’s LNG terminal would result in increased noise, lighting, and human 

activity that could disturb wildlife in the area. However, due to current industrial activities at other 

facilities on the Industrial Canal (i.e., Trunkline LNG Terminal, Lake Charles Carbon Company, Leevac 

Shipyards, DII, Martin Energy Services, and Marine Spill Response Corporation), wildlife species in the 

area are expected to be 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 LNG 

terminal to be negligible. Birds could also be affected by flaring at the terminal. Magnolia anticipates 

that flaring would occur for approximately 5 days during startup of the LNG terminal. During operation 

of the terminal, use of the marine and emergency flares would only occur during process upset conditions, 

which Magnolia anticipates would be no more than 12 hours during the first year of operation and no 

more than 6 hours in each subsequent year (each flaring event is expected to occur for between 15 and 

60 minutes). Therefore, we find that occasional flaring during operation would not substantially impact 

migratory birds passing through the area.

Construction of the KMLP facilities would affect 64.3 acres of vegetated wildlife habitat, nearly 

all of which would be agricultural lands. In addition, 0.3 acre of open water habitat would be affected by 

construction of the KMLP facilities. Operation of the KMLP facilities would permanently convert 

12.0 acres of wildlife habitat to industrial land. The remaining 52.3 acres would be restored to the preconstruction habitat type, although 8.3 acres of wildlife habitat within the permanent easements 

associated with the header pipelines would be subject to routine maintenance. Individuals of some 

wildlife species would be affected by construction and operation of the facilities; however, most impacts 

on wildlife would be short term and limited predominantly to the construction period. In accordance with 

the FERC Plan, KMLP would not conduct routine vegetation mowing or clearing over the full width of 

the permanent easements in uplands more frequently than every 3 years, and routine vegetation mowing 

or clearing would not occur between April 15 and August 1 unless specifically approved in writing by the 

FWS. With the implementation of the FERC 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 KMLP facilities would have permanent but minor impacts on local wildlife populations 

and habitat.

The vegetation communities within the areas affected by the proposed LNG terminal and KMLP 

facilities provide potential habitat for migratory bird species, including songbirds, waterbirds, and raptors. 

However, much of the vegetated land associated with the sites is previously disturbed, within or adjacent 

to existing facilities, and/or composed of agricultural land, all of which reduce bird nesting habitat value. 

Impacts on migratory birds and their habitat due to construction and operation of the LNG terminal and 

KMLP facilities would typically be similar to impacts on general wildlife resources described above. 

Potential impacts specific to migratory birds could result from artificial illumination. During 

construction, Magnolia would direct all nighttime lighting towards construction activity and use the 

minimum light level necessary to ensure site safety and security. Similarly, outdoor lighting at the KMLP 

aboveground facilities would be limited, shielded, and downward-facing to facilitate safe operations at 

night or during inclement weather. Perimeter lighting at aboveground KMLP facilities would be turned 

off at night and would only be used when necessary for work conducted at night. Magnolia has not 

developed its Facility Lighting Plan for LNG terminal operation; therefore, we are recommending that, 

prior to construction, Magnolia file its Facility Lighting Plan for operation of the LNG terminal that 

would include measures to minimize operational lighting impacts on birds. With our recommendation

and with the implementation of Magnolia’s and KMLP’s project-specific plans, we conclude that impacts 

on wildlife, including migratory birds, would be permanent but minor.
5-10

Aquatic Resources

All waterbodies potentially affected by the projects support warmwater fisheries; the Industrial 

Canal and Calcasieu River are estuarine, and the borrow pit, intermittent, and ephemeral waterbodies are 

freshwater. Of the waterbodies that would be affected by construction of the LNG terminal site, only the 

Industrial Canal, estuarine emergent wetlands, and the borrow pit provide year-round habitat for aquatic 

resources. The waterbodies potentially affected by the KMLP facilities are classified as intermittent or 

ephemeral, which typically provide limited habitat value for aquatic resources due to restricted water flow 

regimes. 

Activities associated with construction and operation of the LNG terminal with the greatest 

potential to impact aquatic resources include dredging, pile driving, and vessel traffic. The proposed 

waterbody modifications, water withdrawals for hydrostatic testing, stormwater runoff, lighting, and 

inadvertent spills could also affect aquatic resources; although the implementation of the proposed 

mitigation measures, would reduce these impacts to minimal levels.

Construction of the recessed berthing area at the LNG terminal site would require the dredging of 

a 16.2-acre area in the Industrial Canal, which currently consists of 9.8 acres of open water, 1.0 acre of 

wetlands, and 5.4 acres of uplands. Dredge material would be excavated with a suction dredge and 

transported by pipeline to the placement area where it would be allowed to dewater, after which the 

decanted water would be pumped through an effluent pipeline and discharged back into the Industrial 

Canal. Potential impacts on aquatic resources resulting from dredging activities include direct take and 

habitat modification as well as temporary increases in noise, turbidity, and suspended solid levels.

Most fish species are highly mobile and would be expected to leave the area during dredging 

activities. Dredging would, however, result in direct mortality of benthic organisms (e.g., aquatic 

macroinvertebrates, mollusks, and crustaceans, which are important food sources for many species of 

fish) within the 9.8-acre portion of the dredge footprint that currently provides open water habitat. 

Slower, less mobile benthic invertebrates would also be directly affected, while larger, more mobile 

species would experience temporary displacement. Following construction activities, aquatic resources 

would be expected to return to the recessed berthing area, which would be similar to the existing habitat 

within the Industrial Canal.

Dredging activities would also temporarily increase noise, turbidity, and suspended solid levels 

within the water column, which could reduce light penetration and the corresponding primary production 

of aquatic plants, algae, and phytoplankton. Increased turbidity and suspended solid levels could also 

adversely affect fish eggs and juvenile fish survival, benthic community diversity and health, foraging 

success, and suitability of spawning habitat. Sediments in the water column could be deposited on nearby 

substrates, burying aquatic macroinvertebrates. 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 maintenance dredging (which is scheduled to occur every other year) within the Industrial 

Canal. To minimize impacts on aquatic resources due to increased turbidity and suspended solid levels, 

Magnolia would use a hydraulic cutterhead suction dredge and would implement its Dredging Water 

Quality Monitoring Plan. With the implementation of these mitigation measures and our 

recommendation that Magnolia file its final Dredging Water Quality Monitoring Plan, we have 

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

Maintenance dredging of the recessed berthing area would be conducted by Magnolia every 4 to 

5 years during operation of the terminal. Potential impacts on aquatic resources from maintenance 

dredging would be similar to those described above for dredging during construction of the LNG 
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terminal; however, impacts would be shorter in duration due to the reduced amount of material being 

removed from the recessed berthing area. Therefore, we conclude that maintenance dredging would have 

temporary and minor impacts on aquatic resources.

Construction of the LNG terminal would require the installation of approximately 5,000 piles 

over a 16-month period to support the proposed structures, including both in-water and onshore hydraulic 

piling rigs. It is anticipated that aquatic resources would largely avoid the pile driving area when the piles 

are being installed, although some aquatic resources could experience stress or injury due to the 

underwater sound pressure levels. Magnolia would perform hydro-acoustic monitoring during the initial 

pile testing to determine the sound pressure levels generated under site-specific conditions at the LNG 

terminal. Because pile driving plans have not been finalized and an estimate of underwater noise has not 

been provided, we are recommending that, prior to the end of the draft EIS comment period, Magnolia 

file a Pile Driving Noise Impact Mitigation Plan. This plan should describe the hydroacoustic monitoring 

methods that Magnolia would use to determine representative sound pressure levels associated with inwater pile driving as well as mitigation measures to be implemented to reduce sound pressure levels. The 

plan should include a description of the locations where monitoring would occur in relation to the pile 

being driven, and the maximum impact energy used on the pile during monitoring. With the 

implementation of hydroacoustic monitoring and mitigation measures, if needed, pile driving activities 

would minimize underwater noise levels to a level that would not cause significant impacts on aquatic 

resources.

During construction and operation of the LNG terminal, barges, support vessels, and LNG vessels 

(LNG carriers and LNG barges) would call on the LNG terminal, increasing ship traffic within the 

Industrial Canal, Calcasieu Ship Channel, Intracoastal Waterway, and Gulf of Mexico. Potential impacts 

on aquatic resources resulting from increased vessel traffic include shoreline erosion and resuspension of 

sediments, ballast water discharges, cooling water discharges, and increased noise levels.

Because Magnolia would modify the existing shoreline to create the recessed berthing area, there 

is potential for the modified shoreline to cause changes in wave dynamics and increase erosion of 

adjacent areas. Magnolia would install rock armoring to provide scour protection from propeller wash 

both within and along the east and west ends of the recessed berthing area. The rock armoring would 

prevent erosion of the adjacent unprotected shoreline by wave activity from vessels maneuvering within 

the recessed berthing area. The Industrial Canal, Calcasieu Ship Channel, and Intracoastal Waterway

were specifically created to provide deepwater access for maritime commerce. Similarly, LNG carriers 

transiting the Gulf of Mexico would use established shipping channels. As such, use of the waterways 

during construction and operation of the LNG terminal would be consistent with the planned purpose and 

use of these active shipping channels, and associated impacts on aquatic resources due to increased 

shoreline erosion and resuspension of sediments would be negligible.

Ballast water discharges at the terminal would modify the temperature, pH, dissolved oxygen, and 

salinity of the water in the vicinity of the discharge. However, the impacts on water quality, and thus 

aquatic resources, due to changes in temperature and pH would be temporary and negligible. Salinity 

levels within the Industrial Canal are naturally variable, depending upon tidal regime and rainfall. During 

and immediately following ballast water discharges, benthic aquatic species may be affected by higher 

salinity levels, although ships moving into and out of the Industrial Canal and berthing area would 

displace water, circulating it into, around, and out of the berthing area. Therefore, any increased salinity 

levels resulting from ballast water discharges would be temporary and unlikely to adversely affect aquatic 

resources.

Depending on the oxygen levels present in both the ballast and ambient water at the time of 

discharge, aquatic resources present in the vicinity of the discharge point could be exposed to dissolved 
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oxygen levels considered unhealthy for aquatic life. The adaptability of resident species within the 

Industrial Canal to natural variation in oxygen levels would mitigate this effect. It is also anticipated that 

mobile aquatic species would relocate short distances to more suitable conditions, which would minimize 

the adverse impacts associated with ballast water discharges. Given that the amount of ballast water 

discharged into the Industrial Canal during each LNG vessel visit to the LNG terminal would make up 

only approximately 0.6 percent of the approximately 2 billion gallons of water within the Industrial 

Canal, we have determined that impacts on aquatic resources would be temporary and minor.

During operation, LNG vessels require water for cooling of the main engine/condenser, diesel 

generators, and fire main auxiliary and hotel services. Each LNG carrier calling on the terminal would 

require between 5.5 and 11.7 million gallons of water, and each LNG barge would require 535 gallons of 

water. Impacts on aquatic resources would be primarily limited to an increase in water temperature in the 

vicinity of the LNG vessel resulting from the discharge of water between 2.7 °F and 7.2 °F warmer than 

ambient water temperatures. Given the volume of cooling water discharged relative to the total volume of 

water within the Industrial Canal, and the mobility of resident species, which could relocate to cooler 

surrounding waters if necessary, we have determined that impacts on aquatic resources would be 

intermittent and minor.

As a non-federal party assisting the FERC in meeting its obligations under the MSA, Magnolia

coordinated with NOAA Fisheries’ regarding potential project impacts on EFH. NOAA Fisheries has 

indicated that the Magnolia LNG Project would not have significant impacts on EFH, provided the 

applicant addresses stormwater management and wetland mitigation. As described in the preceding 

sections, Magnolia would conduct ground disturbing activities in compliance with LPDES permit 

requirements as well as its project-specific Construction SWPPP, Plan, and Procedures. Magnolia would 

mitigate for all impacts on wetlands determined to be jurisdictional under section 404 of the CWA in 

accordance with its COE-approved Compensatory Mitigation Plan.

Due to the relatively small area of EFH that would be impacted within the Industrial Canal (the 

recessed berthing area represents approximately 5 percent of the total acreage within the canal), the 

increase in the amount of estuarine water column habitat created during construction of the LNG vessel 

berthing area, Magnolia’s proposed mitigation measures, and preliminary coordination with NOAA 

Fisheries, we have determined that the Magnolia LNG Project would not have a significant adverse 

impact on EFH. We are requesting that NOAA Fisheries consider the EIS as our EFH Assessment.

5.1.7 Threatened and Endangered Species

Based upon our review of publicly available information, agency correspondence, and field 

surveys, a total of 16 federally listed threatened, endangered, or candidate species may occur in parishes

affected by the projects. Additionally, within these parishes, critical habitat has been designated for one 

species, the piping plover. 

We have determined that the projects would have no effect on 4 of the 16 federally listed species

potentially occurring in the area. We have also determined that the projects are not likely to destroy or 

adversely modify designated critical habitat, and would not contribute to the trend toward federal listing 

for the one candidate species.

There is no potentially suitable habitat within areas affected by construction or operation of the 

LNG terminal or KMLP facilities for the remaining 11 federally listed species (five species of sea turtles, 

five species of whales, and the West Indian manatee); however, potentially suitable habitat is present for 

these species along the portion of the LNG transit route in Cameron Parish and the Gulf of Mexico. 

However, sightings of these species are rare and, based on the their characteristics and habitat 
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requirements, and because Magnolia would provide LNG ship captains with the NOAA Fisheries-issued 

Vessel Strike Avoidance Measures and Reporting for Mariners, we have determined that the Magnolia 

LNG Project may affect, but is not likely to adversely affect these federally listed species. As required by 

section 7 of the ESA, we request that NOAA Fisheries accept the information provided in this EIS as the 

BA for the projects. Further, we request concurrence with our findings of effect for federally listed 

species. The projects would have no effect on listed species under the jurisdiction of the FWS; therefore, 

preparation of a BA and consultation between the FERC and FWS is not necessary.

Based on information obtained from the LDWF, six state-listed threatened or endangered species 

occur within the parishes that would be affected by the projects. Four of these species are also federally 

listed as threatened or endangered. The projects are expected to have no impact on one of the two 

remaining state-listed species (bald eagle) due to the absence of suitable habitat within or near the LNG 

terminal. Although the remaining state-listed species (brown pelican) may occur within the Calcasieu 

Ship Channel and coastal waters of the Gulf of Mexico, because LNG vessels would transit within 

existing, highly traveled shipping lanes, adverse impacts on brown pelicans during operation of the LNG 

terminal are not anticipated.

5.1.8 Land Use, Recreation, and Visual Resources

Construction of the LNG terminal and KMLP facilities would affect a total of 353.5 acres of land. 

Of this, 144.6 acres would be permanently affected by operation of the LNG terminal and KMLP 

facilities and 173.9 acres would be allowed to revert to the existing land use type after the completion of 

construction. The remaining 35.0 acres within the dredge material placement area would be converted 

from open water, industrial/commercial, and forest to open land.

Construction of the LNG terminal would affect a total of 277.7 acres of land within the LNG 

terminal site, Industrial Canal, DII construction yard, along the dredge material and effluent pipelines, and 

at the dredge material placement area. The land use types affected during construction of the LNG 

terminal would include open land (67 percent), open water (16 percent), forest (12 percent), and 

industrial/commercial (5 percent). Over 99 percent of the land that would be permanently affected by 

construction of the LNG terminal is within areas that have been previously disturbed by commercial or 

industrial activities. Impacts on the remaining 1.0 acre of permanently affected land would be mitigated 

by Magnolia’s implementation of its Compensatory Mitigation Plan. Because the areas affected by 

construction and operation of the LNG terminal are zoned for heavy industrial use (Calcasieu Parish 

Police Jury, 2015), we have determined that impacts on land use would be negligible.

Magnolia has entered into an agreement with the Lake Charles Harbor and Terminal District to 

lease the 115-acre LNG terminal site for the minimum expected operational life of 30 years, with the 

option to extend the lease for four additional periods of 10 years each. Temporary workspaces proposed 

within the existing DII site would be subcontracted from DII. Temporary workspaces proposed along the 

dredge material and effluent pipelines would be leased from the landowners/leaseholders along the route. 

Magnolia is currently in negotiations with CB&I for use of the dredge material placement area. Aside 

from the Port of Lake Charles, no federal, state, or local agency owned or managed lands would be 

directly affected by the LNG terminal. 

Construction of the KMLP facilities would affect about 76 acres of land. Because the activities 

involve modification or expansion of existing facilities, much of the land affected by the KMLP facilities 

would be adjacent to the permanent easement associated with KMLP’s existing mainline or would be 

adjacent to or within existing meter station sites. The KMLP facilities would be constructed almost 

entirely within agricultural lands, although small areas of industrial/commercial and open lands would 

also be affected. Impacts on land use associated with construction and operation of the KMLP facilities 
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would be temporary and minor within 84 percent of the areas that would be affected, as these areas would 

be allowed to revert to pre-construction conditions. KMLP would retain permanent easements over the 

header pipelines, which would be subject to vegetation maintenance. The lands necessary for 

construction and operation of the KMLP facilities would be composed of both land currently owned or 

leased by KMLP and other private land.

No residential land is within the footprint of the areas that would be affected by construction or 

operation of the LNG terminal. The nearest occupied residences are 0.6 mile south of the terminal site. 

Two occupied residences are within approximately 100 feet of the proposed construction workspaces for 

the KMLP facilities, including a residence approximately 100 feet northwest of the existing TRANSCO 

Meter Station and a residence 50 feet south of the existing access road for the Pine Prairie Meter Station. 

There are no planned residential or commercial developments within 0.25 mile of the projects. However, 

three commercial or industrial facilities are planned within 1 mile of the proposed LNG terminal. Certain 

non-jurisdictional facilities are also planned to provide utilities (i.e., electric power, water) to the LNG 

terminal and KMLP facilities.

There is one designated recreational area, Calcasieu Point Landing, within 1 mile of the LNG 

terminal site (approximately 525 feet west of the terminal site). Recreational boating and fishing 

activities occurring within the Industrial Canal and near Calcasieu Point Landing could be affected by 

construction and operation of the LNG terminal due to increased noise, delayed access to the park, 

restrictions on fishing in the immediate vicinity of the LNG terminal, and vessel traffic. Increased noise 

associated with construction of the LNG terminal would likely deter recreational users from fishing in the 

immediate vicinity of project activities. In particular, dredging and pile driving activities, which would 

occur up to 7 days per week and 6 days per week, respectively, during the first 20 months of construction, 

could result in avoidance of the area by recreational users. As a result, we have determined that 

construction of the LNG terminal would result in temporary and moderate impacts on recreational use of 

Calcasieu Point Landing. During operation of the LNG terminal, delays to recreational users could occur 

due to the moving security zone around LNG vessels during transit to and from the LNG terminal, which 

we expect would be intermittent and minor.

The Sabine NWR is approximately 12 miles south-southwest of the proposed LNG terminal site 

on the west side of the Calcasieu Ship Channel. Users of the Sabine NWR adjacent to the ship channel 

may observe a small increase in barge traffic during the construction period and may also observe LNG 

vessel traffic through the channel during operation of the LNG terminal. Because LNG vessel traffic 

would be consistent with existing use of the Calcasieu Ship Channel, we have determined that the 

resulting impact on users of the Sabine NWR would be minor. 

The viewshed of Magnolia’s proposed LNG terminal includes a portion of the Creole Nature 

Trail Scenic Byway (Highway 27), which is approximately 2 miles west of the LNG terminal across the 

Calcasieu Ship Channel and as close as 0.3 mile west of the LNG vessel transit route along the Calcasieu 

Ship Channel. No other federally, state, or locally designated visual resources have been identified in the 

viewshed. The primary existing structures in the viewshed of the LNG terminal include the existing 

Trunkline LNG Terminal, Lake Charles Carbon Company, and other industrial properties adjacent to the 

Industrial Canal. The viewshed also includes the Industrial Canal to the north and west, the Intracoastal 

Waterway and Calcasieu Ship Channel to the south, and forest and wetlands to the northwest and south of 

the site. Because the site is slightly higher in elevation than the surrounding area due to the previous 

placement of dredge spoil at the site, and the topography of the surrounding area is fairly level, visibility 

would extend outward from the site except where buffered by vegetation or existing structures. 

Activities associated with construction of the LNG terminal may be visible from residences to the 

south and southeast of the LNG terminal, along Airhart and Joe Ledoux Roads, and possibly residences 
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along the northeastern shoreline of Calcasieu Lake on Big Lake Road (although these residences are over 

3 miles south of the site). Construction activities would also be visible to recreationists using the 

Industrial Canal, Calcasieu River, and northern portions of Calcasieu Lake as well as motorists along 

Henry Pugh Boulevard, Big Lake Road, and a segment of the Creole Nature Trail Scenic Byway. The 

presence of large construction equipment and truck traffic would change the visual quality of these 

waterways, roadways, and the scenic byway but, due to the distance from the site and short duration of 

impact (until the vehicle passes the site), impacts would be minor.

Visually, the facilities associated with the LNG terminal would be consistent with other industrial 

features along this portion of the Industrial Canal. Although permanent changes to the visual character of 

the area would result from operation of the LNG terminal due to the presence of aboveground structures 

that would modify the viewshed. The most prominent visual features at the terminal would be two LNG 

storage tanks, each approximately 258 feet wide and 174 feet in height, and the flare stack, which would 

be approximately 100 feet in height when no flame is present and approximately 229 feet in height when 

a flame is present. Magnolia anticipates that flaring would occur for approximately 5 days during startup 

of the LNG terminal. During operation of the LNG terminal, use of the marine and emergency flares 

would only occur during process upset conditions, which Magnolia anticipates would be no more than 

12 hours during the first year of operation and no more than 6 hours in each subsequent year. The new 

facilities would also require lighting for operations, safety, and to comply with Federal Aviation 

Administration requirements.

Due to the proximity of Calcasieu Point Landing to the LNG terminal and lack of visual buffers, 

the LNG terminal would be prominent when viewed from the landing both during daytime hours and in 

the evening when the facilities (including the LNG storage tanks) would be illuminated in accordance 

with federal safety regulations. Neither the flare stack nor the flame itself would be visible from 

Calcasieu Point Landing; although the flame would be taller than the LNG storage tanks, the position of 

the LNG storage tanks in the foreground would conceal the flame. To minimize visual impacts, lighting 

at the LNG terminal would be shielded and downcast to avoid interference with navigation; in addition, 

facilities within the LNG terminal site would be partially obscured by the proposed vapor barrier. To 

further minimize visual impacts, we are recommending that, prior to construction, Magnolia file its 

Facility Lighting Plan for operation of the LNG terminal. Therefore, we have determined that the LNG 

terminal would have a permanent and moderate impact on visual resources when viewed from the 

Calcasieu Point Landing.

The KMLP facilities in Acadia Parish would be located in a primarily agricultural area, which 

contains easements for 46 oil and gas pipelines within a 1-mile radius. As a result, the existing structures 

in the viewshed of these facilities are primarily meter stations, compressor stations, and farms and 

agricultural outbuildings. During construction activities, the primary 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 Coulee and Fournerat Road and nearby residences. However, the nearest 

residence is approximately 500 feet west of the low pressure header pipeline, and the facilities would not 

be in densely populated areas. The presence of construction equipment and personnel would be 

temporary and short term. During operation, the compressor station would be visible to passing motorists

travelling along nearby roads in Acadia Parish. To minimize visual impacts on nearby residences and 

passing motorists, KMLP proposes to plant shrubbery along the west, north, and east sides of the 

perimeter fence and to limit and down-shield perimeter lighting during nighttime hours. There would be 

no permanent visual impacts at the existing meter stations that would not be expanded (ANR, and Pine 

Prairie Meter Stations). The expanded TGT Meter Station would result in new, permanent impacts on 

visual resources; however, the expanded meter station footprint would be consistent with the existing 

viewshed and would not affect any designated visual resources. Therefore, we conclude that visual 

impacts would be permanent, but minor.
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Construction activities at the existing meter stations in Evangeline Parish would result in shortterm, localized visual impacts similar to those described above for the facilities in Acadia Parish. There 

would be no permanent visual impacts at the TETCO Meter Station, which would not be expanded. The 

expanded CGT and TRANSCO Meter Stations would result in new, permanent impacts on visual 

resources; however, the expanded footprint of these meter stations would be consistent with the existing 

viewshed and would not affect any designated visual resources. Therefore, we conclude that the meter 

station modifications would have minimal impacts on visual resources.

5.1.9 Socioeconomics 

Construction of the projects would have a minor to moderate impact on local populations, 

employment, provision of community services, and 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 projects. No residences or businesses would be 

displaced as a result of construction or operation of the LNG terminal or KMLP facilities.

Construction of the LNG terminal would take place over an approximate 45-month period. 

Magnolia expects that construction workers would be on site during 32 months of the construction period 

and that the average construction workforce would be 355 workers. KMLP estimates that an additional 

30 workers would be employed at the terminal over the 3-month period required to construct the 

Magnolia Meter Station (which would be within the LNG terminal site). The combined workforce 

associated the terminal and meter station would peak during a 10 month period during which it would 

exceed 500 construction workers (at its highest, approximately 542 workers would be working at the site). 

Of this, approximately 307 workers would be hired locally and 235 would be non-local workers.

Assuming non-resident workers would be accompanied by family members and based on the average

household size in Louisiana, the peak construction non-resident workforce could result in up to 672 nonlocal persons temporarily relocating to the area, which would represent a 0.3 percent increase in the total 

population within Calcasieu, Cameron, and Jefferson Davis Parishes. Given the number of hotel rooms in 

the vicinity of the LNG terminal, no serious disruptions to housing and temporary accommodations are 

anticipated, and construction of the LNG terminal would have a moderate, temporary impact on housing 

in the affected area. After construction, Magnolia anticipates 67 workers would be employed at the LNG 

terminal, of which 27 are expected to be non-local hires. KMLP’s Magnolia Meter Station would be 

unmanned during operation. This workforce and their families would represent a minor but permanent 

increase in the population in the vicinity of the LNG terminal site.

The construction workforce for the KMLP facilities would be 75 workers for the majority of the 

11 months that it would take to construct Compressor Station 760. However, during a 3-month period

when construction of the compressor station would coincide with construction of the header pipelines and 

modifications at KMLP’s existing meter stations, up to 270 workers would be employed at the KMLP 

facilities. The majority of these construction workers (up to 162 during peak construction) are expected 

to be hired from outside of Acadia and Evangeline Parishes, which would result in a temporary increase 

in the local population of less than 0.2 percent. Because the peak construction period associated with the 

KMLP facilities would occur over a 3-month period, it is unlikely that non-local workers would be 

accompanied by family members. Based on the number of available rental housing units and 

hotels/motels in the vicinity of the KMLP facilities, adequate housing exists to accommodate non-resident 

workers. As such, construction of the proposed KMLP facilities would have only a temporary and minor 

impact on housing in the area. Operation of the KMLP facilities would require four new permanent 

employees. The relocation of these four individuals to the project area, even if they bring their families,

would have a negligible impact on the local housing market.
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Impacts on local users of the roadway network due to construction of the LNG terminal include 

potential delays from increased traffic levels and diminished roadway capacity. To identify, quantify, and 

recommend mitigation for traffic impacts on area roadways during construction of projects currently 

proposed on the Industrial Canal, Magnolia, Lake Charles LNG, and G2X Energy commissioned a Traffic 

Impact Study, which recommended that three intersection improvements be implemented to reduce 

impacts on area roadways. The measures recommended in the Traffic Impact Study would be 

implemented prior to construction as part of a cooperative effort between Magnolia, Lake Charles LNG, 

and G2X Energy. In addition, Magnolia, Lake Charles LNG, and G2X Energy commissioned a pavement 

analysis, which evaluated the existing structural capacity of Lincoln, Big Lake, and Tank Farm Roads in 

order to determine the necessary overlay/rehabilitation options to sustain construction traffic. The study 

identified 10 segments along Lincoln Road and 2 segments along Tank Farm Road that, given the current 

condition, would fail during the construction period. The analysis included two recommendations for 

rehabilitation of the roadways, which would be implemented as part of the effort resulting from the 

Traffic Impact Study.

With the implementation of the recommendations described above, traffic generated by 

construction of the LNG terminal is not expected to impact the existing roadway network in terms of 

roadway capacity. Construction of the LNG terminal would result in temporary increases in traffic along 

area roadways, which could result in delays to local users of the roadways. With the implementation of 

the recommended improvements at the intersections of Tank Farm and Big Lake Roads, Big Lake and 

Lincoln Roads, and Lincoln Road and Gulf Highway, we have determined that impacts from construction 

of the LNG terminal would have temporary and minor impacts on local users of the roadway network. 

Construction of the KMLP facilities would have minimal impact on traffic or roadways.

Current vessel traffic in the Calcasieu Ship Channel is approximately 1,022 vessels per year, 

which equates to an average of about 85 vessels per month. Magnolia estimates that 50 or fewer marine 

deliveries would occur during construction of the LNG terminal. Marine deliveries to the DII 

construction yard would occur between 1 and 3 times per month during the first year of construction, and 

approximately 1 time per month during the second and third years of construction, which would represent 

an increase of less than 4 percent in current vessel traffic. Because barges are subject to fewer restrictions 

and can be maneuvered between other vessels using the channel, an increase in construction barge traffic 

would not impact the traffic capacity of the channel.

During operation, approximately 208 LNG vessels (104 LNG carriers and 104 LNG barges) 

would call on the LNG terminal per year. In a letter dated February 12, 2015,1the Coast Guard issued the 

LOR for the project, which stated that the Calcasieu Ship Channel is considered suitable for LNG marine 

traffic in accordance with the guidance in the Coast Guard’s NVIC 01-2011. Due to the existing levels of 

traffic within the port and the anticipated increase in traffic within the channel over the next 10 years, a 

traffic impact study was conducted for the Calcasieu Ship Channel that simulated the anticipated impacts 

on traffic within the channel between 2013 and 2033, assuming that the present infrastructure, operational 

rules, and dredging dimensions are maintained. The results of the simulation indicate that the median 

wait time is expected to increase by 2.3 hours per vessel, and notes that LNG carriers would experience 

the highest increase in median wait time (8.9 hours). The wait times are expected to vary seasonally, and 

would be higher during the winter months and lower during the summer months. In addition, the 

simulation indicated that 4 to 10 additional pilots and 1 or 2 additional sets of tugs would be required to 

accommodate vessel traffic without further increasing wait times.

 

1 Using the “eLibrary” link, select “General Search” from the eLibrary menu and enter the docket number, excluding the last three digits, in 

the “Docket Number” field (i.e., CP14-347). The LOR for the project was filed with the FERC on March 2, 2015.
5-18

To minimize impacts on other users of the Industrial Canal and Calcasieu Ship Channel, it is 

anticipated that vessels (including LNG vessels) would be organized in convoys to be handled in the most 

efficient manner. The convoy would be specifically organized to maximize efficient transit; therefore, 

vessels traveling the farthest upstream would be prioritized (to minimize delays to other vessels during 

maneuvering and docking). Based on the Coast Guard’s LOR for the Magnolia LNG Project and the 

expected increase in the median wait time by 2.3 hours per vessel, we have determined that operation of 

the LNG terminal would have a permanent and moderate increase in marine traffic within the Industrial 

Canal and Calcasieu Ship Channel.

Construction of the projects 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 projects 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 

Due to the environmental setting, no cultural resource surveys were required within the areas 

affected by construction of the LNG terminal. In letters dated October 28, 2014, April 8, 2015, and 

May 12, 2015, the Louisiana SHPO concurred that no historic properties would be affected by 

construction of the proposed Magnolia LNG Project. We concur. Therefore, the process of complying 

with section 106 of the NHPA has been completed for the Magnolia LNG Project.

Cultural resources surveys have been completed where necessary for the KMLP facilities. The 

surveys identified a single non-site cultural resources locus and a 20th century standing structure complex 

within one of the areas proposed for Compressor Station 760. KMLP recommended that both resources 

were not eligible for the NRHP. In a letter dated May 21, 2014, the Louisiana SHPO concurred that no 

historic properties would be affected by construction of the proposed Lake Charles Expansion Project. 

We concur. Therefore, the process of complying with section 106 of the NHPA has been completed for 

the Lake Charles Expansion Project.

Magnolia, KMLP, and FERC staff contacted several Native American tribes to identify properties 

of traditional, religious, or cultural importance that may be affected by the proposed projects. On August 

4, 2014, the Choctaw Nation of Oklahoma sent a letter to the FERC requesting a copy of the cultural 

resources survey report, a map depicting all known archaeological sites positioned within a 1-mile radius 

of the project APE, as well as GIS shapefiles for the project. These materials were subsequently sent to 

the tribe. In addition, the Choctaw Nation of Oklahoma requested that it and the other federally 

recognized tribes that were consulted regarding the Lake Charles Expansion Project be contacted in the 

event of any unanticipated find (not only if the discovery consists of human remains). The Unanticipated 

Discoveries Plan has been updated in response to the tribe’s request. 

5.1.11 Air Quality and Noise

Air Quality

The LNG terminal and KMLP facilities would be located in areas currently classified as being in 

attainment for all criteria pollutant standards. However, both the Lake Charles and Lafayette areas are 

vulnerable to being designated as non-attainment for ozone in the next few years. Air pollutant emissions 

during construction of the projects would result from the operation of construction vehicles, marine 

traffic, vehicles driven by construction workers commuting to and from work sites, and the generation of 

fugitive dust during construction activities. Air quality impacts due to construction of the projects would 

generally be temporary and localized, and are not expected to cause or contribute to a violation of 
5-19

applicable air quality standards. Magnolia and KMLP 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 during the first year of 

construction (during site preparation). However, due to the sensitive nature of air quality in areas 

surrounding the projects, we are recommending that, prior to the end of the draft EIS comment period, 

Magnolia file a revised Fugitive Dust Control Plan and KMLP file a Fugitive Dust Control Plan; each 

plan should specify the precautions that would be taken to minimize fugitive dust emissions from 

construction activities.

LNG terminal construction emissions would be primarily limited to the construction area and 

would represent less than 1.3 percent of Calcasieu Parish’s yearly CO emissions and less than 1 percent of 

the parish’s yearly emissions inventories for all other pollutants. Construction emissions associated with 

the KMLP facilities in Acadia Parish would primarily be associated with Compressor Station 760, limited 

to the construction area, and represent less than 7 percent of Acadia Parish’s yearly PM10 emissions and 

less than 3 percent of the parishes’ yearly emissions inventories for all other pollutants. Construction 

emissions associated with the KMLP facilities in Evangeline Parish would represent a negligible portion 

of overall emissions within the parish. However, due to the sensitive nature of air quality in areas 

surrounding the projects, we are recommending that, prior to the end of the draft EIS comment period, 

Magnolia and KMLP each provide further details regarding commitments to reduce NOX, CO, PM, and 

SO2 from mobile and stationary construction equipment.

The LNG terminal would be a PSD major source for NOX and CO. In addition, it would be a 

Title V major source for PM10 and PM2.5. The facility would be considered a minor source of HAP 

emissions. Therefore, operation of the LNG terminal would result in long-term impacts on air quality. 

Magnolia would minimize these impacts by adhering to applicable federal and state regulations and 

installing BACT as described in its January 2015 revised Title V and PSD permit application to the 

LDEQ.

Compressor Station 760 would be a Title V major source for CO and would be considered a 

minor source of all other criteria pollutants, as well as HAP emissions. KMLP would minimize potential 

impacts on air quality due to operation of the compressor station by adhering to applicable federal and 

state regulations described in its air permit application.

Based on the analyses conducted and mitigation measures proposed, we conclude that 

construction and operation of the projects would result in a moderate impact on air quality; however, 

given the mitigation measures proposed by Magnolia and KMLP, and air quality controls and monitoring 

requirements to be included in the Title V/PSD permits for the facilities, the projects would not result in a 

degradation of regional air quality.

Noise

Construction activities at the LNG terminal would generate temporary increases in sound levels 

over a total of 45 months. Construction activities would occur predominantly during the day, Monday 

through Saturday. However, certain activities would occur up to 24 hours per day, 7 days per week. In 

particular, dredging may occur up to 24 hours per day, 6 days per week and pile driving could occur up to 

10 hours per day, 7 days per week.

The most prevalent sound-generating equipment and activity during construction of the LNG 

terminal is anticipated to be pile driving, although internal combustion engines associated with general 

construction equipment would also produce sound levels that would, at times, be perceptible at the nearest 
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NSAs. Magnolia anticipates that impact-type pile drivers would be used during construction of the 

facilities, which may be installed using both land-based and floating platforms. Onshore piles would be 

driven by seven or eight hydraulic piling rigs. Marine piles would be driven by between two and four 

hydraulic pile rigs, which may include both land-based and floating rigs. Based upon the construction 

schedule provided by Magnolia, onshore pile driving to create the foundations for the LNG storage tanks 

and other process equipment foundations and structures would occur over a period of 10 months, and pile 

driving associated with construction of the LNG loading and ship berthing area would occur over a period 

of 6 months. Based upon Magnolia’s current construction schedule, land and water-based pile driving 

would not occur simultaneously.

Pile driving is scheduled to occur over 10-hour shifts, 7 days per week over a total of about 

16 months; however, due to start-up coordination, actual pile driving operations are expected to occur for 

approximately 8 hours per day, 7 days per week. During land-based pile driving operations, the estimated 

sound level at the nearest NSA when the maximum number of land-based pile-driving platforms are in 

use would be 72 dBA Lmax. During water-based pile driving operations, the corresponding sound level at 

NSA 1 when the maximum number of pile-driving platforms are in use would be 69 dBA Lmax. These 

levels would correspond to a moderate sound level (similar to operation of a vacuum cleaner) and would 

be clearly audible. Based on the estimates provided by Magnolia and because of the 16-month duration 

of the pile driving activities, these sound levels may have an adverse impact at the nearest NSAs. 

Therefore, we are recommending that Magnolia include in its Pile Driving Noise Impact Mitigation Plan

measures to reduce pile driving noise (Lmax) to no greater than 10 dBA over Leq ambient levels (an 

increase of 10 dBA is perceived by the human ear as though the sound intensity has doubled) at the three 

nearest NSAs.

The most prevalent sound-generating equipment and activity during construction of the KMLP 

facilities is anticipated to be the operation of internal combustion engines associated with general 

construction equipment. Noise levels resulting from construction would vary over time and would 

depend upon the number and type of equipment operating, the level of operation, and the distance 

between sources and receptors. KMLP has stated that noisy construction activities would take place 

during the day, Monday through Friday. Based on estimated equipment needs for construction of the 

KMLP facilities, the resulting composite noise level from construction activities at the nearest NSA 

(NSA 1, which is 1,125 feet west) is estimated to be between 58 Leq (dBA) and 63 Leq (dBA). The current 

daytime noise level at NSA 1 is 59 Leq (dBA); therefore, although construction noise would be perceptible 

at times, it would not be substantially above existing daytime noise levels. Due to the greater distance 

between NSAs 2 and 3 and construction activities (each is over 1,250 feet away), and because noise 

decreases logarithmically with increasing distance from a noise source, we have determined that noise 

attributable to construction activities is likely to be imperceptible at the other NSAs.

Operation of the LNG terminal 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 generated by the operation of the LNG terminal is likely to increase the

ambient noise level at NSAs 1 and 2 (3,820 and 4,485 feet from the terminal site, respectively) by 1 dBA, 

which may be slightly perceptible. Due to its greater distance from the terminal (7,075 feet), noise 

generated during operation of the terminal would likely be imperceptible at NSA 3. The noise from 

operation of the LNG terminal would not exceed the 55-dBA threshold (the noise threshold established to 

protect the public from activity interference and annoyance outdoors in residential areas) at any of the 

NSAs. To ensure that NSAs are not adversely impacted by operation of the LNG terminal, we are 

recommending that Magnolia file a full load noise survey with the Secretary after each of the first three 

liquefaction trains is placed into service. If noise attributable to operation of the LNG terminal exceeds 

the FERC threshold at nearby NSAs, Magnolia should reduce operation or install additional noise 

controls until the noise level at nearby NSAs is below the FERC threshold. In addition, Magnolia should 
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file noise surveys after placing the entire LNG terminal into service. If the noise attributable to operation 

of all of the equipment at the LNG terminal exceeds the FERC threshold, Magnolia should file a report on 

what changes are needed and should install additional noise controls to meet the level within 1 year of the 

in-service date. Magnolia should confirm compliance with these requirements by filing an additional

noise survey with the Secretary no later than 60 days after it installs the additional noise controls. With 

the implementation of these recommendations, we conclude that operational noise from the LNG terminal 

would result in minor impacts on the nearest NSA.

The primary source of operational noise associated with the KMLP facilities would be from 

Compressor Station 760, which would produce noise on a continual basis. The modeling analysis 

conducted for the compressor station indicates that the noise attributable to operation of Compressor 

Station 760 would be in compliance with the FERC sound level requirement of 55 dBA Ldn at the nearest 

NSA. We recognize, however, that actual results may be different from those obtained from modeling. 

Therefore, we are recommending that KMLP file a noise survey with the Secretary after placing 

Compressor Station 760 into service. If the noise attributable to operation of Compressor Station 760

exceeds the FERC threshold at any nearby NSAs, KMLP should file a report on what changes are needed 

and should install additional noise controls to meet the level within 1 year of the in-service date. KMLP 

should confirm compliance with these requirements by filing an additional noise survey with the 

Secretary no later than 60 days after it installs the additional noise controls. With the incorporation of the 

proposed mitigation measures, operational noise at Compressor Station 760 would not exceed the 55-dBA 

Ldn noise threshold at any of the nearby NSAs.

Based on the analyses conducted, mitigation measures proposed, and with our additional 

recommendations, we conclude that construction of the projects would result in temporary and moderate 

noise impacts on residents and the surrounding communities and that operation of the projects would 

result in permanent and minor impacts on the surrounding communities.

5.1.12 Safety

We evaluated the safety of the proposed LNG terminal, the related LNG vessel transit, and the 

pipeline facilities. As part of our evaluation of the LNG terminal, we reviewed existing regulations, 

including assessments of hazards, preliminary engineering design, siting, emergency response, and 

security systems. 

We also analyzed whether the LNG terminal would be sited consistent with federal regulations. 

Magnolia would be regulated by the FERC, DOT, Coast Guard, EPA, and OSHA. As a cooperating 

agency, the DOT assisted FERC staff in evaluating whether Magnolia’s proposed design would meet the 

DOT siting requirements. In a September 17, 2014 letter to FERC staff, the DOT stated that it had no 

objection to Magnolia’s methodology for determining a single accidental leakage source to establish the 

siting for its proposed LNG export facility. In addition, we are recommending that, prior to the end of the 

draft EIS comment period, Magnolia file concurrence from the DOT regarding the design spill selections. 

On January 13, 2015, the DOT determined Magnolia’s proposal to comply with the EPA’s RMP and 

OSHA’s PSM would also satisfy the siting requirements of NFPA 59A (2001) section 2.1.1(d) for the 

anhydrous ammonia refrigerant system. Magnolia has submitted a preliminary RMP as part of its

application to satisfy these regulations. Magnolia would comply with the comprehensive EPA RMP and 

OSHA PSM programs as well as the DOT’s requirements under Part 193 and NFPA 59A. Under EPA’s 

RMP, the worst-case releases of anhydrous ammonia would result in toxic concentrations that could 

potentially affect up to 1,429 people.

While toxic concentrations would extend beyond the property line that could be built upon and 

onto populated areas, this is not abnormal for EPA RMP regulated facilities. We have consulted with 
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EPA staff on the preliminary RMP to address identified gaps in order to comply with all EPA RMP 

requirements and guidance. In addition, we identified specific recommendations to be addressed by 

Magnolia 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 

facilities. We would also 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. In addition, the DOT, Coast Guard, EPA, and OSHA remain responsible for enforcing their 

regulations covering design, construction, and operation. All four agencies have some oversight and 

responsibility for inspection and compliance during the facility’s operation. Therefore, based on the 

federal regulations and oversight of the Magnolia LNG Project and our technical review of the 

preliminary engineering design, we conclude that with the incorporation of our recommendations,

Magnolia’s LNG terminal would include acceptable layers of protection or safeguards to reduce the risk 

of a potentially hazardous scenario from developing into an event that could significantly impact the 

safety of the public. 

For LNG carrier transit, the Coast Guard issued its LOR for the project on February 12, 2015, 

which stated that the Calcasieu Ship Channel is considered suitable for LNG marine traffic in accordance 

with the guidance in the Coast Guard’s NVIC 01-2011. The WSA review focused on the navigation 

safety and maritime security aspects of LNG vessel transits along the affected waterway. Based on the 

LOR issued by the Coast Guard and our review of LNG ship simulations, we conclude that with the 

incorporation of our recommendations, the LNG carrier transit would include acceptable mitigation 

measures or safeguards to reduce the risk of a potentially hazardous scenario from developing into an 

event that could significantly impact the safety of the public.

KMLP would design, construct, operate, and maintain its proposed pipeline and aboveground

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 KMLP facilities would have a very 

small incremental increase in the risk of a pipeline accident; however, KMLP’s compliance with the 

DOT’s safety standards would ensure that KMLP’s construction and operation of the facilities would not 

have a significant impact on public safety.

Based on our engineering design analysis and recommendations; the DOT siting requirements 

and recommendations; the LOR issued by the Coast Guard concluding the LNG vessel transit is suitable 

for LNG marine traffic; and the regulatory requirements for the design, construction, and operation of the 

pipeline and terminal; we conclude that the project would not result in significantly increased public 

safety risks.

5.1.13 Cumulative Impacts

Three types of projects (past, present, and reasonably foreseeable) could potentially contribute to 

a cumulative impact when considered with the proposed projects. Such projects 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 projects 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 the proposed projects’ contributions to cumulative impacts on resources affected by the 
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other projects occurring in the vicinity during the same time frame would not be significant, and that the 

potential cumulative impacts of the Magnolia LNG and Lake Charles Expansion Projects and the other 

projects considered would be moderate, minor, or insignificant.

The construction period for the Magnolia LNG and Lake Charles Expansion Projects is expected 

to coincide with at least some of the other major Lake Charles area projects. Groundwater withdrawals 

from the Chicot aquifer are causing lowered water levels and saltwater encroachment in some areas. The 

rate of decline is due primarily to industrial use in the Lake Charles area and rice irrigation, where intense 

pumping of the 500-foot sand has resulted in the water level declining by as much as 1 to 2 feet per year. 

Cumulative groundwater requirements from construction of other projects in the area are expected to 

result in an increase of approximately 1 percent over current daily withdrawals from the Chicot aquifer. 

During operation, cumulative groundwater requirements are expected to increase groundwater 

withdrawals from the Chicot aquifer by less than 1 percent over current daily withdrawals. While there 

would be localized effects on groundwater, such as the lowering of the water table near the points of 

withdrawal, we conclude that the cumulative impact on groundwater or municipal water systems during 

construction and operation of these facilities would be permanent, but minor.

A large workforce for the simultaneously constructed projects would have a beneficial cumulative 

effect on revenues for the state and for Calcasieu, Cameron, and Jefferson Davis 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 projects.

In total, the projects constructed in Southwest Louisiana are expected to employ over 

31,000 construction workers during the peak construction years, which are anticipated to conclude 

between 2018 and 2020. Construction labor requirements for the LNG terminal and KMLP facilities in 

2017 and 2018, when employment associated with construction would be highest, would represent 

between 9 and 14 percent of the projected regional construction jobs for those years, respectively. 

Following the completion of construction, collectively, the projects in Southwest Louisiana are expected 

to result in the addition of 18,000 or more permanent jobs due to direct and induced growth.

To increase the number of qualified local workers, several regional programs have been 

developed in coordination with and through the Associated Builders and Contractors, Pelican Southwest 

Chapter in Westlake, Calcasieu Parish School Board, SOWELA Technical Community College, and 

Central Louisiana Technical Community College. The SWLA Economic Development Alliance is also 

collaborating with educational facilities and industry in the development of a Workforce Resource Guide, 

which provides residents with step-by-step instructions for finding employment and includes a description 

of the types of training required for each profession, as well as the training centers in Southwest Louisiana 

that offer the relevant certifications. Given that the planned construction projects would likely have 

staggered timelines for specific labor needs, it is likely that some construction personnel could work on 

multiple projects, which would have the effect of decreasing the overall labor requirement. In addition, 

some of the projects included in the cumulative impact analysis may not be built, which would further 

reduce the overall labor need. The cumulative effect would be a substantial reduction in unemployment 

in the area and potentially the need to train and hire construction workers from outside Southwest 

Louisiana. 

The influx of non-local workers would affect the availability of housing in Southwest Louisiana. 

The cumulative impact on local housing may result in increased rental rates and housing shortages for 

lodging if all of the proposed and planned projects are implemented according to the expected 

timeframes. This would benefit the local housing market, but could adversely affect those seeking 

housing. Some members of the workforce may be forced to commute longer distances to obtain housing 
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in adjacent parishes or Texas. To accommodate the anticipated influx of construction workers, two 

worker housing developments (Pelican Lodge and Moss Lake) are being developed that would 

accommodate up to 6,500 of the 13,500 anticipated workers. In addition to worker housing 

developments, a number of residential housing developments are planned or under construction in the 

Lake Charles area. New housing units, which include single-family dwellings, multi-family dwellings, 

hotels, and various residential projects, could total 8,070 if all publicly announced projects are permitted 

and constructed according to current plans. Therefore, we conclude that cumulative impacts on housing 

would be moderate.

The combined construction workforces of the projects listed in table 4.13.2-1 would increase the 

need for some public services, such as police, medical services, and schools. The need for these services 

would generally be spread throughout the parishes that house the workforce (Acadia, Calcasieu, Cameron, 

Evangeline, and Jefferson Davis Parishes), but there may be an increased need for medical and 

emergency services in Cameron and Calcasieu Parishes where the proposed project facilities and 

construction workers are expected to be concentrated. Magnolia would provide its own on-site security,

and the Calcasieu Parish Sheriff’s Office indicated that it believes it has sufficient resources available to 

provide protection services by adjusting patrol schedules or hiring additional staff with revenues allocated 

by the parish. In addition, Magnolia is currently in discussions with the Lake Charles Fire Department to 

identify measures for providing fire protection at the LNG terminal site. Options include funding firefighting services either independently or by entering into a mutual aid agreement with future industrial 

neighbors for the purpose of employing an industrial firefighting team trained in fighting fires at 

industrial facilities. With the increase in local taxes and government revenue associated with the 

proposed projects, the anticipated overall cumulative impact on public services would be minor.

Between early 2016 and the end of 2017, three facilities adjacent to and within the Industrial 

Canal could be constructed if they receive the necessary regulatory approvals. These include the 

proposed LNG terminal, Lake Charles Liquefaction Project, and G2X Energy Lake Charles gasoline 

facility. Magnolia, the Lake Charles LNG companies, and G2X Energy commissioned a Traffic Impact 

Study to assess potential impacts of vehicular traffic associated with both construction and operation of 

the three projects, and to develop measures to mitigate impacts on local users of area roadways, which

found that the existing roadway network does not have sufficient capacity to accommodate the expected 

peak hour traffic volumes associated with construction of the three facilities. Based on the results of the 

study, and to minimize impacts on area roadways, the Lake Charles LNG companies would provide offsite parking for 1,000 construction workers, temporary parking facilities near its proposed liquefaction 

facility site, right-turn and left-turn lanes at the seven driveways, and would utilize buses to transport 

construction workers from the off-site and near-site parking facilities to the construction site. In addition 

improvements would be made at three intersections in the vicinity of the Industrial Canal. With 

implementation of the planned mitigation measures, roadways would approach unstable flow; with speeds 

slightly decreasing as traffic volumes increase. Magnolia has agreed to implement the recommended 

mitigation measures within the Traffic Impact Study. Therefore, we conclude that cumulative impacts on 

roadway traffic during construction would be temporary and moderate.

Traffic within the Calcasieu Ship Channel is expected to markedly increase over the next 

10 years. In 2018, traffic within the channel is expected to be 1,668 vessels per year; in 2023, traffic 

within the channel is expected to be 2,183 vessels per year, more than twice the 2013 level. For this 

reason, the Port of Lake Charles commissioned a simulation to investigate the impact of increased traffic 

on the operations of the channel and to assess the need for changes to channel infrastructure and 

regulations. The results of the simulation indicate that although the Calcasieu Ship Channel has the 

capacity to accommodate the cumulative increase in vessel traffic, the median wait time is expected to 

increase by 2.3 hours per vessel. The study further notes that LNG carriers would experience the highest 

increase in median wait time (8.9 hours). The wait times are expected to vary seasonally, and would be 
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higher during the winter months and lower during the summer months. In addition, the simulation 

indicated that 4 to 10 additional pilots and 1 or 2 additional sets of tugs would be required to 

accommodate vessel traffic without further increasing wait times. To minimize impacts on other users of 

the Industrial Canal and Calcasieu Ship Channel, it is anticipated that vessels would be organized in 

convoys to be handled in the most efficient manner. Due to the expected increase in the median wait time 

by 2.3 hours per vessel, we expect that cumulative impacts on marine traffic within the Calcasieu Ship 

Channel and Industrial Canal during operation of the proposed projects as well as other projects along the 

waterways would be permanent and moderate.

Based on the cumulative modeling analysis and the required emission controls at the LNG 

terminal, compressor station, and other facilities requiring an air emission permit, we conclude that 

cumulative impacts on regional air quality as a result of the operation of these facilities would be 

permanent, but minor. There is no current methodology or policy guidance to determine how the 

projects’ 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 projects’

contribution to cumulative impacts on climate change would be significant.

The potential for cumulative noise impacts during construction of the proposed projects would be 

greatest during pile driving activities associated with construction of the LNG terminal, which have the 

potential to produce sound levels of up to 72 dBA Lmax at the nearest NSAs. Therefore, we are including 

a recommendation that outlines measures to reduce pile driving noise (Leq) to no greater than 10 dBA 

over ambient levels at the nearest NSA. Although construction of G2X Energy’s natural gas to gasoline 

facility, the Lake Charles Liquefaction Project, the LDWF’s Fisheries Research Center, and the utilities 

associated with these projects could overlap with the construction of the LNG terminal and contribute to 

noise levels in the area, all of these projects, except for the LDWF’s Fisheries Research Center, are farther 

from the nearest NSA. Because noise decreases logarithmically with increasing distance from a noise 

source, we conclude that construction of the LNG terminal along with the projects other than LDWF’s 

Fisheries Research Center would result in a temporary and insignificant cumulative impact on noise levels 

at the nearest NSA. If construction activities at the Fisheries Research Center were to coincide with pile 

driving activities at the LNG terminal, cumulative noise impacts at the nearest NSAs could occur. 

However, due to the distance between the proposed aboveground facilities within the Fisheries Research 

Center and the LNG terminal (approximately 1 mile), these impacts are expected to be temporary and 

minor.

5.1.14 Alternatives

As alternatives to the proposed action, we evaluated the No-Action Alternative, system 

alternatives for the proposed LNG terminal and KMLP’s pipeline system, alternatives sites for the 

proposed aboveground facilities, alternative liquefaction processes, and alternative power sources for the 

LNG terminal and Compressor Station 760. While the No-Action Alternative would eliminate the shortand 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 LNG terminal, including 7 operating LNG import 

terminals with approved, proposed, or planned expansions to provide liquefaction and export capabilities,

and 19 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 with in-service dates that would not meet
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Magnolia’s customer commitments and environmental impacts that were considered comparable to or 

greater than those of the proposed LNG terminal.

We evaluated three system alternatives to KMLP’s pipeline system. To serve as a viable system 

alternative to KMLP, the system would have to transport all or a part of the volume of natural gas 

required for liquefaction at the proposed terminal and cause less impact on the environment than the 

proposed pipeline system modifications. All three systems were eliminated from further consideration 

because they would require construction of additional pipeline looping or greenfield construction to 

provide the 1.4 Bcf/d required by the Magnolia LNG Project (the Magnolia LNG Project would have the 

capacity to export an LNG volume equivalent up to 1.08 billion cubic feet per day).

We evaluated five sites for the LNG terminal, including the proposed site and four alternatives. 

In order to meet the stated objectives of the Magnolia LNG Project, we applied screening criteria to 

identify sites that would be reasonable and most likely to provide some environmental advantage over the 

proposed terminal site. The screening criteria included waterfront access, property size, existing land use, 

site availability, proximity to natural gas pipelines and transmission lines, distance from population 

centers and residences, distance to the interstate highway system, and presence of wetlands within the 

site. The alternatives analysis concluded that the proposed site represents an acceptable site for the 

proposed LNG terminal because it is currently zoned for heavy industrial use, and is sufficiently sized to 

allow optimal facility layout design. The proposed site also contains the lowest acreage of wetlands of 

the alternatives considered; therefore, the loss of habitat diversity and function resulting from facility 

development would be generally less than that anticipated at the other sites. Additionally, from a visual

impact perspective, the new LNG terminal would be consistent with the existing industrial development 

along the Industrial Canal.

We evaluated three sites for Compressor Station 760, including the proposed site and two

alternatives. KMLP indicated that the location of the proposed site offers engineering and hydraulic 

benefits and would limit the amount of new facilities required to meet the stated purpose of the project. 

As a result, we limited our review of alternatives to sites in close proximity to the proposed site. Our

alternatives analysis concluded that the proposed site represents an acceptable site for the compressor 

station because it has the lowest number of natural gas and crude oil pipelines within or crossing the site. 

Although seven residences are within 1,200 feet of the proposed site, six are on the western side of the 

site. Therefore, KMLP has proposed to place the compressor station within the eastern half of the parcel 

to increase the distance between the compressor station and the nearest residence. We conclude that the 

Coulee Road site is an acceptable location for Compressor Station 760 and find no environmental reason 

to recommend one of the alternate sites over the proposed site. 

The proposed meter station modifications would occur within and adjacent to existing facilities, 

which would minimize the footprint and associated environmental impacts. The new meter station would

be constructed within the LNG terminal site in a location designed to minimize the length of interconnect 

pipeline. The header pipelines would be wholly collocated with KMLP’s existing 42-inch-diameter 

mainline. We did not identify any environmental concerns that require the need to identify and evaluate 

alternative meter station sites or header pipeline routes, nor were any alternatives suggested during the 

public scoping period.

We evaluated four sites for dredge material placement, including the proposed site and three 

alternatives. The proposed site, which is currently zoned for heavy industrial use, is outside of the 

2012 Louisiana Coastal Zone and is currently used for construction staging and laydown. Because 

Magnolia would be required to raise the existing containment dikes if either of the two existing CDFs 

were selected, we determined that these sites were not preferred locations for dredge material disposal. 

Because it is within the 2012 Louisiana Coastal Zone and is a beneficial use site, selection of the Turner 
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Bay site would involve additional agency coordination under the Coastal Wetlands Planning, Protection 

and Restoration Act Program and the Louisiana Coastal Protection and Restoration Authority. While this 

would be a disadvantage from a regulatory process perspective compared to the proposed dredge 

placement site, it would not negate the potential use of the site. Therefore, we conclude that both the 

proposed site and one potential alternative, the Turner Bay site, represent acceptable sites for dredge 

material placement.

We evaluated a total of eight liquefaction technologies, which are currently available, including 

the proposed liquefaction process. The proposed OSMR® Process is based on the single mixed refrigerant 

process, but uses aero-derivative gas turbines, combined heat and power technology, and ammonia 

auxiliary refrigeration to increase efficiency and reduce air emissions by approximately 30 percent. The 

use of anhydrous ammonia includes safety hazards due to its toxicity and farther dispersion distances to 

irreversible toxic effects. However, the hazards associated with anhydrous ammonia are well understood, 

can be mitigated to safe levels with additional mitigation measures, and would be subject to the regulation 

of a number of federal agencies. Therefore, while there would be viable liquefaction processes that 

provide inherently safer alternatives, there would not be a significant environmental or safety advantage 

in the selection of those liquefaction processes when considering the additional mitigation measures 

Magnolia would implement during operation of the terminal.

We evaluated and ruled out the use of electric-driven motors as an alternative to gas-fired 

turbines at the proposed LNG terminal 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. 

We performed an alternative review of four power sources for compression at Compressor 

Station 760, including gas-fired turbine driven (proposed), reciprocating gas-driven, electric motordriven, and waste heat electric generation. Our alternatives analysis concluded that the proposed power 

source (gas-fired turbine driven compressors) for Compressor Station 760 is acceptable. The use of 

reciprocating gas-driven compressor units would result in a larger number of units being required to 

provide the same amount of power as the proposed gas-fired, turbine-driven compressor units, which 

would result in both higher costs and a larger facility footprint. The use of electric-motor driven 

compressors would require an electric load of a magnitude serviceable only by a high-voltage 

transmission system, which would require construction of two new 138 kV cross-country transmission 

lines and a new electrical substation located at the compressor station. KMLP has stated that Compressor 

Station 760 would likely not operate when the LNG terminal is not producing LNG, which could greatly 

reduce the economic feasibility of using waste heat electric generation.

5.2 FERC STAFF’S RECOMMENDED MITIGATION

If the Commission authorizes the Magnolia LNG and Lake Charles Expansion Projects, we are 

recommending that the following measures be included as specific conditions in the Commission’s Order. 

We have determined that these measures would further mitigate the environmental impacts associated 

with the construction and operation of the proposed projects.

1. Magnolia and KMLP 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. Magnolia and KMLP must:

a. request any modification to these procedures, measures, or conditions in a filing with the 

Secretary;
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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 KMLP’s 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, Magnolia and KMLP 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 projects.

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, Magnolia and 

KMLP shall file with the Secretary any revised detailed survey alignment maps/sheets at a scale 

not smaller than 1:6,000 with station positions for all facilities approved by the Order. All 

requests for modifications of environmental conditions of the Order or site-specific clearances 

must be written and must reference locations designated on these alignment maps/sheets.

KMLP’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. KMLP’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. Magnolia and KMLP 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, 
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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, Magnolia and 

KMLP shall file Implementation Plans with the Secretary for review and written approval by the 

Director of OEP. Magnolia and KMLP must file revisions to the plans as schedules change. The 

plans shall identify:

a. how Magnolia and KMLP 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 Magnolia and KMLP 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;

c. the number of EIs assigned per spread and/or facility, and how Magnolia and KMLP 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 

Magnolia and KMLP 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 Magnolia’s and KMLP’s

organizations having responsibility for compliance;
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g. the procedures (including use of contract penalties) Magnolia and KMLP 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. Magnolia and KMLP shall employ a team of EIs, including at least one EI for the LNG terminal 

and one or more EIs for the KMLP facilities. 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.

9. Beginning with the filing of the Implementation Plans, Magnolia and KMLP shall file updated 

status reports with the Secretary on a monthly basis for the LNG terminal and a bi-weekly basis 

for the KMLP 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 Magnolia’s and KMLP’s efforts to obtain the necessary federal 

authorizations;

b. the current construction status of the LNG terminal and KMLP 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);
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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 Magnolia or KMLP from other federal, state, 

or local permitting agencies concerning instances of noncompliance, and Magnolia’s or 

KMLP’s response.

10. Prior to receiving written authorization from the Director of OEP to commence 

construction of any project facilities, Magnolia and KMLP shall file with the Secretary 

documentation that they have received all applicable authorizations required under federal law (or 

evidence of waiver thereof).

11. Magnolia must receive written authorization from the Director of OEP prior to introducing 

hazardous fluids into the LNG terminal facilities. Instrumentation and controls, hazard 

detection, hazard control, and security components/systems necessary for the safe introduction of 

such fluids shall be installed and functional.

12. Magnolia and KMLP must each receive written authorization from the Director of OEP before 

placing into service the LNG terminal and the KMLP 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.

13. Within 30 days of placing the authorized facilities in service, Magnolia and KMLP 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 Magnolia and KMLP 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, Magnolia 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 storage tank and foundation design drawings and calculations;

c. LNG terminal structures and foundation design drawings and calculations; 

d. seismic specifications for procured equipment; and

e. quality control procedures to be used for civil/structural design and construction.

In addition, Magnolia shall file, in its Implementation Plan, the schedule for producing this 

information. (Section 4.1.6.4)
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15. Prior to construction, Magnolia shall file with the Secretary, for review and written approval by 

the Director of OEP, its Spill Prevention Plan for construction and SPCC Plan for operation of 

the project. (Section 4.2.3.2)

16. Within 30 days of placing the Lake Charles Expansion Project facilities in service, KMLP 

shall file with the Secretary a report identifying all public or private water supply wells/systems 

damaged by construction and a description of 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)

17. Prior to construction, Magnolia shall file with the Secretary, for review and written approval by 

the Director of OEP, its final Dredging Water Quality Monitoring Plan. (Section 4.3.2.2)

18. As soon as they are available and prior to the start of construction, Magnolia shall file with 

the Secretary, for review and written approval by the Director of OEP, the results of the wetland 

and waterbody surveys within areas associated with the transport and placement of dredge 

materials. (Section 4.4.1)

19. Prior to filing its Implementation Plan, Magnolia shall file with the Secretary its Compensatory 

Mitigation Plan and documentation of COE approval of the plan. (Section 4.4.4) 

20. Prior to construction, Magnolia shall file with the Secretary, for review and written approval by 

the Director of OEP, its Facility Lighting Plan for operation of the LNG terminal. 

(Section 4.6.1.3)

21. Prior to the end of the draft EIS comment period, Magnolia shall file with the Secretary a Pile 

Driving Noise Impact Mitigation Plan, which describes the hydroacoustic monitoring methods 

that will be used to determine representative sound pressure levels associated with in-water pile 

driving as well as mitigation measures to be implemented to reduce sound pressure levels. The 

plan shall include a description of the locations where monitoring will occur in relation to the pile 

being driven, and the maximum impact energy used on the pile during monitoring. 

(Section 4.6.2.2)

22. Prior to the end of the draft EIS comment period, Magnolia and KMLP shall file with the 

Secretary, for review and written approval by the Director or OEP, a Fugitive Dust Control Plan

that specifies the precautions that will be taken to minimize fugitive dust emissions from 

construction activities, including additional mitigation measures to control fugitive dust emissions 

of Total Suspended Particulates and PM10. Each plan shall clearly explain how Magnolia and 

KMLP will implement measures, such as: 

a. watering the construction workspace and access roads;

b. providing measures to limit track-out onto the roads;

c. identifying the speed limit that Magnolia and KMLP will enforce on unsurfaced roads; 

d. covering open-bodied haul trucks, as appropriate;

e. clarifying that the EI has the authority to determine if/when water or a palliative needs to 

be used for dust control; 
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f. describing inspection procedures to identify and abate visible dust plumes; and

g. clarifying the individuals with the authority to stop work if the contractor does not 

comply with dust control measures. (Section 4.11.1.4)

23. Prior to the end of the draft EIS comment period, Magnolia and KMLP shall provide further 

details regarding commitments to reduce NOX, CO, PM, and SO2 from mobile and stationary 

construction equipment including: 

a. feasibility of leasing new, clean equipment meeting the most stringent of applicable 

federal or state standards, if practicable. In general, commit to the best available 

emissions control technology;

b. feasibility of using electric vehicles, natural gas, biodiesel, or other alternative fuels 

during construction and operation phases to reduce the projects’ criteria and greenhouse 

gas emissions;

c. commitments to limit idling of heavy equipment to less than 5 minutes and verify through 

unscheduled inspections;

d. commitments to maintain and tune engines per manufacturer’s specifications to perform 

at CARB and/or EPA certification levels, prevent tampering, and conduct unscheduled 

inspections to ensure these measures are followed; and

e. clarify how it would manage construction traffic and parking in order to maintain traffic 

flow and minimize vehicle trips. (Section 4.11.1.4)

24. Prior to the end of the draft EIS comment period, Magnolia shall include in its Pile Driving 

Noise Impact Mitigation Plan (required by recommended condition 21) measures to reduce pile 

driving noise (Lmax) to no greater than 10 dBA over Leq ambient levels at the three nearest NSAs. 

(Section 4.11.2.3)

25. Magnolia shall make all reasonable efforts to ensure that predicted noise levels during operation 

of the LNG terminal are not exceeded at nearby NSAs and shall file with the Secretary a full load 

noise survey no later than 60 days after each of the first three liquefaction trains is placed into 

service. If the noise attributable to the operation of the LNG terminal exceeds an Ldn of 55 dBA 

at any nearby NSAs, Magnolia shall reduce operation of the LNG terminal or install additional

noise controls until a noise level below an Ldn of 55 dBA at nearby NSAs is achieved. Magnolia 

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)

26. Magnolia shall file a noise survey with the Secretary no later than 60 days after placing the 

entire LNG terminal into service. If a full load condition noise survey is not possible, Magnolia

shall provide an interim survey at the maximum possible horsepower load within 60 days of 

placing the LNG terminal into service and provide the full load survey within 6 months. If the 

noise attributable to the operation of all of the equipment at the LNG terminal under interim or 

full horsepower load conditions exceeds an Ldn of 55 dBA at any nearby NSAs, Magnolia 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. Magnolia shall confirm compliance with the above 

requirement by filing an additional noise survey with the Secretary no later than 60 days after it 

installs the additional noise controls. (Section 4.11.2.4)
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27. KMLP shall file a noise survey with the Secretary no later than 60 days after placing 

Compressor Station 760 in service. If a full load condition noise survey is not possible, KMLP

shall provide an interim survey at the maximum possible horsepower load within 60 days of 

placing the station into service and provide the full load survey within 6 months. If the noise 

attributable to the operation of all of the equipment at Compressor Station 760 under interim or 

full horsepower load conditions exceeds an Ldn of 55 dBA at any nearby NSAs, KMLP 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. KMLP shall confirm compliance with the above 

requirement by filing an additional noise survey with the Secretary no later than 60 days after it 

installs the additional noise controls. (Section 4.11.2.4)

28. Prior to the end of the draft EIS comment period, Magnolia shall file with the Secretary 

concurrence from the DOT as to whether full guillotine ruptures of connections less than 6 inches 

in diameter should be considered for LNG design spills. (Section 4.12.5.3)

29. Prior to the end of the draft EIS comment period, Magnolia shall file with the Secretary 

concurrence from the DOT as to whether full guillotine ruptures of connections less than 6 inches 

in diameter should be considered for mixed refrigerant and other hazardous fluid design spills. 

(Section 4.12.5.3)

30. Prior to the end of the draft EIS comment period, Magnolia shall file with the Secretary 

concurrence from the DOT that the restriction of property use between Lake Charles Harbor and

Terminal District and Magnolia would satisfy the exclusion zone requirements of 

49 CFR 193.2057. (Section 4.12.5.5)

Recommendations 31 through 105 apply to the LNG terminal 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 No. RM06-24-000), including security 

information, shall be submitted as 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: off-site 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.

31. Prior to initial site preparation, Magnolia shall provide procedures for controlling access 

during construction. (Section 4.12.3)

32. Prior to initial site preparation, Magnolia shall file the issued for construction quality assurance 

and quality control procedures for construction activities. (Section 4.12.3)

33. Prior to initial site preparation, Magnolia shall file an overall project schedule, which includes 

the proposed stages of the commissioning plan. (Section 4.12.3)

34. Prior to initial site preparation, Magnolia shall file a plot plan of the final design showing all 

major equipment, structures, buildings, and impoundment systems. (Section 4.12.3)
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35. Prior to initial site preparation, Magnolia shall develop an Emergency Response Plan

(including evacuation) and coordinate procedures with the Coast Guard; state, county, and local 

emergency planning groups; fire departments; state and local law enforcement; and appropriate 

federal agencies. This plan shall include at a minimum:

a. designated contacts with state and local emergency response agencies;

b. scalable procedures for the prompt notification of appropriate local officials and 

emergency response agencies based on the level and severity of potential incidents;

c. procedures for notifying residents and recreational users within areas of potential hazard;

d. evacuation routes/methods for residents and public use areas that are within any transient 

hazard areas along the route of the LNG marine transit;

e. locations of permanent sirens and other warning devices; and

f. an “emergency coordinator” on each LNG carrier to activate sirens and other warning 

devices.

Magnolia shall notify the FERC staff of all planning meetings in advance and shall report 

progress on the development of its Emergency Response Plan at 3-month intervals. 

(Section 4.12.9)

36. Prior to initial site preparation, Magnolia shall file 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 shall include funding 

mechanisms for the capital costs associated with any necessary security/emergency management 

equipment and personnel base. Magnolia shall notify the FERC staff of all planning meetings in 

advance and shall report progress on the development of its Cost-Sharing Plan at 3-month 

intervals. (Section 4.12.9)

37. The final design shall include information/revisions pertaining to Magnolia’s response to 

numbers 5, 10, 11, 12, 13, 16, 19, 20, 22, 24, 31, 33, 37, 38, 40, 41, 43, 44, 45, 50, 52, 53, 55, 56, 

57, 64, 65, 66, 67, 70, 72, 73, 74, 76, 78, 82, 85, 90, and 92 of its December 29, 2014 filing, 

which indicated features to be included or considered in the final design. (Section 4.12.3)

38. The final design shall include change logs that list and explain any changes made from the FEED

provided in Magnolia’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)

39. The final design shall provide up-to-date Process Flow Diagrams with heat and material balances 

and P&IDs. The P&IDs shall include the following information: 

a. equipment tag number, name, size, duty, capacity, and design conditions; 

b. equipment insulation type and thickness; 

c. storage tank pipe penetration size and nozzle schedule;
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d. piping with line number, piping class specification, size, and insulation type and 

thickness; 

e. piping specification breaks and insulation limits; 

f. all control and manual valves numbered; 

g. valve high pressure side and cryogenic ball valve internal and external vent locations;

h. relief valves with set points; and

i. drawing revision number and date. (Section 4.12.3)

40. The final design shall include the car seal philosophy with a list of all car-sealed and locked 

valves consistent with the P&IDs. (Section 4.12.3)

41. The final design shall provide an up-to-date complete equipment list, process and mechanical 

data sheets, and specifications. (Section 4.12.3)

42. The final design EPC contractor shall conduct a HAZID to review and verify that the 

recommendations from the FEED Design HAZID are complete and consistent with the 

requirements of the final design as determined by the EPC contractor. (Section 4.12.3)

43. The final design shall include a hazard and operability review and a LOPA of the completed 

design prior to issuing the P&IDs for construction. These reviews shall include initial startup as 

well as shutdown operations. A copy of each review with a list of recommendations, and actions 

taken on the recommendations, shall be filed. (Section 4.12.3)

44. The final design hazard and operability review shall include participants with years of relevant 

design and operating experience and an evaluation of past incidents, such as dynamic surge 

associated with hydraulic shock. (Section 4.12.3)

45. The final design hazard and operability review shall include consideration of basket strainers at 

the bottom outlet of the Molecular Sieve Vessels to prevent molecular sieve and support material 

from entering the piping system. (Section 4.12.3)

46. The final design shall include an updated fire protection evaluation of the proposed facilities 

carried out in accordance with the requirements of NFPA 59A 2001, chapter 9.1.2 as required by 

49 CFR §193.2801. 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)

47. The final design shall provide complete drawings and a list of the hazard detection equipment. 

Plan drawings shall clearly show the location and elevation of all detection equipment. The list 

shall include the instrument tag number, type and location, alarm indication locations, and 

shutdown functions of the hazard detection equipment. (Section 4.12.3)

48. The final design shall install a technical review of facility design that: 

a. identifies all combustion/ventilation air intake equipment and the distances to any 

possible flammable gas or toxic release; and 
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b. demonstrates that these areas are adequately covered by hazard detection devices and 

indicates how these devices will isolate or shut down any combustion or HVAC 

equipment whose continued operation could add to or sustain an emergency. 

(Section 4.12.3)

49. The final design of the hazard detectors shall account for the calibration gas when determining 

the lower flammable limit set points for flammable refrigerants, NGL, and LNG. Include a list of 

alarm and shutdown set points for each hazard detector. (Section 4.12.3)

50. The final design of the hazard detectors shall account for the calibration gas when determining 

the set points for toxic components such as ammonia, NGL, and hydrogen sulfide. Include a list 

of alarm and shutdown set points for each hazard detector. (Section 4.12.3)

51. 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)

52. The final design shall provide facility plans and drawings that show the location of the firewater 

and any foam systems. Plan 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 piping and 

instrumentation diagrams of the firewater and foam system. (Section 4.12.3)

53. The final design of the water spray and deluge systems shall specify a water density of 0.4 gallon 

per minute per square foot to mitigate ammonia releases. (Section 4.12.3)

54. The final design shall provide calculations for the firewater spray systems sized to provide 

cooling for mitigation of BLEVEs. (Section 4.12.3)

55. The final design of the firewater system shall include the water required for foam generation in 

calculating the total water required for 2 hours of supply. (Section 4.12.3)

56. The final design shall specify that two firewater jockey pumps are to be installed. 

(Section 4.12.3)

57. The final design shall specify a 2-hour fire duration for passive fire protection systems. 

(Section 4.12.3)

58. 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 set points. 

(Section 4.12.3)

59. The final design shall specify an alarm management program to ensure effectiveness of process 

alarms. (Section 4.12.3)

60. 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 which would be accessible during an emergency. (Section 4.12.3)
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61. The final design shall specify emergency shutdown valve closure time and release volumes. 

Include an analysis that describes the time to detect an upset condition, notify plant personnel, 

and close the emergency shutdown valve. (Section 4.12.3)

62. The final design shall specify the bypass valves around the ESDV-11001 to be locked closed. 

(Section 4.12.3)

63. The final design shall provide the safe operating limits (upper and lower), alarm and shutdown 

set points for all instrumentation (i.e., temperature, pressures, flows, and compositions). 

(Section 4.12.3)

64. The final design shall evaluate the voting logic and voting degradation for flammable and toxic 

gas detectors. (Section 4.12.3)

65. 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)

66. The final design shall provide electrical area classification drawings. (Section 4.12.3)

67. The final design shall provide spill containment system drawings with dimensions and slopes of 

curbing, trenches, and impoundments. (Section 4.12.3)

68. 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, and are designed to withstand external loads, including vibrational loads in the 

vicinity of rotating equipment and operator live loads in areas accessible by operators. 

(Section 4.12.3)

69. The final design shall specify welded connections on ammonia piping to minimize flange leaks 

or provide justification for the use of flanges with mitigation to reduce likelihood and 

consequences from flange leaks. (Section 4.12.3)

70. The final design shall include a piping flexibility and valve dynamic surge analysis to consider 

the impact forces caused by external (i.e., thermal cycling, equipment vibration) and internal 

conditions (i.e., hammer effects) when designing the nozzles and selecting the piping schedules 

for the ammonia system. (Section 4.12.3)

71. 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 clean-out, dry-out, purging, and tightness testing. (Section 4.12.3)

72. The final design shall provide the procedures for pressure/leak tests which address the 

requirements of ASME VIII and ASME B31.3. (Section 4.12.3)

73. The final design shall include the sizing basis and capacity for the flare stacks and the pressure

and vacuum relief valves for major process equipment, vessels, and storage tanks. 

(Section 4.12.3)
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74. The final design of the ammonia relief valves shall include a relief discharge collection header 

with knockout drum for safe discharge of ammonia vapors to the atmosphere. An evaluation of 

the vapor dispersion shall be provided to demonstrate the ammonia vapors can be safely 

discharged to the atmosphere. (Section 4.12.3)

75. The final design shall include provisions to vent the heavy hydrocarbon iso-container to the flare 

system. (Section 4.12.3)

76. The final design shall provide a human error/reliability analysis. This analysis shall include 

human machine interface considerations, fatigue prevention guidelines, alarm management, and 

healthy work environments (i.e., bright lighting, glare, eye strain) to increase operator awareness 

and reduce risk of hazardous conditions. (Section 4.12.3)

77. The final design shall provide appropriate operator camera coverage to enable rapid monitoring 

of the facility from the control room. (Section 4.12.3)

78. The final design shall include complete plan drawings of the security fencing and of facility 

access and egress. (Section 4.12.3)

79. The final design shall include an analysis of the structural integrity of the outer containment of

the full containment storage tanks when exposed to a roof tank top fire or adjacent tank top fire. 

(Section 4.12.3)

80. The final design shall include the details of the LNG storage tank structural design that 

demonstrate the tanks can withstand overpressures from ignition of design spills. (Section 4.12.3)

81. The final design shall specify the forward pressure regulating valves PV-11001 and PV-11002 

shall be provided with an automatic shutoff activated interlock through PAHH-11004/5/6. 

(Section 4.12.3)

82. The final design shall specify isolation valves at the base of each loading arm. (Section 4.12.3)

83. The final design shall specify an automatic shutoff valve in the liquid line to the heavy 

hydrocarbon iso-container. (Section 4.12.3)

84. The final design shall specify double isolation valves at the suction and discharge of all ammonia

pumps. (Section 4.12.3)

85. The final design shall specify that the ball valve upstream of the hose connection to the ammonia 

truck be a shutoff valve closed by local and remote actuation. (Section 4.12.3)

86. The final design shall specify that the Reboiler Steam Condensate Pot, V-1307, shall have the 

same pressure rating as the 6C2 piping specification. (Section 4.12.3)

87. Magnolia shall certify that the final design is consistent with the information provided to the 

DOT as described in the design spill determination letter dated September 17, 2014 (Accession 

Number 20140918-4009). In the event that any modifications to the design alter the candidate 

design spills on which the 49 CFR 193 siting analysis was based, Magnolia shall consult with the 

DOT on any actions necessary to comply with Part 193. (Section 4.12.5.2)
5-40

88. The final design shall include procedures to maintain and inspect the vapor barriers provided to 

meet the siting provisions of 49 CFR §193.2059. (Section 4.12.5.3)

89. Prior to commissioning, Magnolia 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. 

Magnolia 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)

90. Prior to commissioning, Magnolia 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)

91. Prior to commissioning, Magnolia shall maintain a detailed training log to demonstrate that 

operating staff has completed the required training. (Section 4.12.3)

92. Prior to commissioning, Magnolia shall file results of the LNG storage tank hydrostatic test and 

foundation settlement results. At a minimum, foundation settlement results shall be provided 

thereafter annually. (Section 4.12.3)

93. Prior to commissioning, Magnolia 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)

94. Prior to commissioning, Magnolia 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)

95. Prior to commissioning, Magnolia shall file a tabulated list and drawings of the proposed handheld 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)

96. Prior to commissioning, Magnolia shall file the operation and maintenance procedures and 

manuals, as well as safety procedures, hot work procedures and permits, abnormal operating 

conditions reporting procedures, and management of change procedures and forms.

(Section 4.12.3)

97. Prior to introduction of hazardous fluids, Magnolia shall complete a prestartup safety review 

to ensure that installed equipment meets the design and operating intent of the facility. The 

prestartup safety review shall include any changes since the last hazard review, operating 

procedures, and operator training. A copy of the review with a list of recommendations, and 

actions taken on each recommendation, shall be filed. (Section 4.12.3)

98. Prior to introduction of hazardous fluids, Magnolia 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)

99. Prior to introduction of hazardous fluids, Magnolia shall complete all pertinent tests (Factory 

Acceptance Tests, Site Acceptance Tests, Site Integration Tests) associated with the Distributed 
5-41

Control System and the Safety Instrumented System that demonstrate full functionality and 

operability of the system. (Section 4.12.3)

100. Prior to introduction of hazardous fluids, Magnolia shall specify the personal protective 

equipment required to minimize disabling of personnel from ammonia releases. (Section 4.12.3)

101. Prior to commencement of service, Magnolia shall include a preventative and predictive 

maintenance program that performs periodic or continuous equipment condition monitoring.

(Section 4.12.3)

102. Prior to commencement of service, Magnolia shall develop procedures for off-site contractors’ 

responsibilities, restrictions, and limitations and for supervision of these contractors by Magnolia

staff. (Section 4.12.3)

103. Prior to commencement of service, Magnolia shall notify FERC staff of any proposed revisions 

to the security plan and physical security of the facility. (Section 4.12.3)

104. Prior to commencement of service, Magnolia shall file progress on the construction of the 

proposed systems 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)

105. Prior to commencement of service, Magnolia shall receive written authorization from the 

Director of OEP. Such authorization will only be granted following a determination by the Coast 

Guard, under its authorities under the Ports and Waterways Safety Act, the Magnuson Act, the 

Maritime Transportation Security Act of 2002, and the Safety and Accountability For Every Port 

Act, that appropriate measures to ensure the safety and security of the facility and the waterway 

have been put into place by Magnolia or other appropriate parties. (Section 4.12.8)

In addition, recommendations 106 through 109 apply throughout the life of the LNG facility:

106. 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, Magnolia shall respond to a specific data request, including 

information relating to possible design and operating conditions that may have been imposed by 

other agencies or organizations. Up-to-date detailed piping and instrumentation diagrams 

reflecting facility modifications and provision of other pertinent information not included in the 

semi-annual reports described below, including facility events that have taken place since the 

previously submitted semi-annual report, shall be submitted. (Section 4.12.3)

107. 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, and liquefied, 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 
5-42

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)

108. In the event the temperature of any region of any secondary containment, including imbedded 

pipe supports, becomes less than the minimum specified operating temperature for the material, 

the Commission shall be notified within 24 hours and procedures for corrective action shall be 

specified. (Section 4.12.3)

109. Significant non-scheduled events, including safety-related incidents (e.g., hazardous fluid 

releases, fires, explosions, mechanical failures, unusual over pressurization, and major injuries) 

and security-related incidents (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, 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 facility that 

contains or processes hazardous fluids to rise above its maximum allowable operating 

pressure (or working pressure for LNG facilities) plus the build-up allowed for operation 

of pressure limiting or control devices; 

i. a leak in a facility that contains or processes 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;
5-43

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 a facility that contains or processes hazardous fluids; 

l. safety-related incidents to hazardous material transportations 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

Advisory Council on Historic Preservation, 

Office of Federal Programs, Charlene D.

Vaughn, DC

Council on Environmental Quality, Horst 

Greczmiel, DC

Council on Environmental Quality, Manisha 

Patel, DC

Federal Energy Regulatory Commission, 

Division of Gas, Environment, and 

Engineering, Terry Turpin, DC

U.S. Army Corps of Engineers, Calix MVN, LA

U.S. Army Corps of Engineers, Darrell S. 

Barbara, LA

U.S. Army Corps of Engineers, Ed Creef, LA

U.S. Army Corps of Engineers, James Little, LA

U.S. Army Corps of Engineers, Lieutenant 

Colonel Nathan Joseph, LA

U.S. Army Corps of Engineers, Martin Mayer, LA

U.S. Army Corps of Engineers, New Orleans 

District, Pete Serlo, LA 

U.S. Army Corps of Engineers, Planning and 

Policy Division, John Furry, DC

U.S. Army Corps of Engineers, Tracy Falk, LA

U.S. Coast Guard, Commandant (CG-OES-4) 

Chief (Acting), Deepwater Ports Standards 

Division, Curtis E. Borland, DC

U.S. Coast Guard, Department of Homeland 

Security, Captain George (Joe) Paitl, TX

U.S. Coast Guard, Leon McClain, LA

U.S. Coast Guard, Lieutenant Anthony Walter, LA

U.S. Coast Guard, Lieutenant Jennifer Andrews, LA

U.S. Coast Guard, Lieutenant Tom Moore, LA

U.S. Coast Guard, Lieutenant Trey Gonzales, LA

U.S. Coast Guard, Marine Safety Unit Lake 

Charles, Commander Will E. Watson, LA

U.S. Coast Guard, Marine Safety Unit Lake 

Charles, Facilities and Waterways, Lieutenant 

(junior grade) Dimitri Wiener, LA

U.S. Coast Guard, Prevention Department, Clint 

Smith, LA

U.S. Department of Agriculture, Conservation, and 

Environmental Program Division, Farm 

Service Agency, 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, Steve 

Leathery, MD

U.S. Department of Commerce, National 

Oceanic and Atmospheric Administration, 

Tim Osborn, LA

U.S. Department of Commerce, National 

Oceanic and Atmospheric Administration,

Steve Kokkinakis, MD

U.S. Department of Commerce, Richard 

Hartman, LA

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, Steve Sample, DC

U.S. Department of Defense, Office of the 

Assistant Secretary of the Army for Civil 

Works, Assistant for Environment, Tribal 

and Regulatory Affairs, DC

U.S. Department of Defense, Office of the Assistant 

Secretary of the Navy (Energy, Installations 

and Environment), DC

U.S. Department of Defense, Office of the Deputy 

under Secretary of Defense (Installations 

and Environment), Chief, Mission 

Evaluation Branch, DC
APPENDIX A (cont’d)

A-2

Federal Government Agencies (cont’d)

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, Edward Le Duc, DC

U.S. Department of Energy, Office of Fossil 

Energy, James Ward, DC

U.S. Department of Energy, Office of Fossil 

Energy, John A. Anderson, DC

U.S. Department of Energy, Office of Fossil 

Energy, Kyle Moorman, 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, 

National Center for Environmental Health, 

Centers for Disease Control and Prevention, 

Sharunda Buchanan, GA

U.S. Department of Homeland Security, 

Customs and Border Protection, 

Christopher Oh, DC

U.S. Department of Interior, Director, 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 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, National Park 

Service, Patrick Walsh, CO

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,

Bill Lowry, TX

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, Surface 

Transportation Board, Victoria Rutson, DC

U.S. Environmental Protection Agency, Cliff 

Rader, DC

U.S. Environmental Protection Agency, Cynthia 

Giles, DC

U.S. Environmental Protection Agency, Jerome 

Blackman, DC

U.S. Environmental Protection Agency, 

Region 6, Debra A. Griffin, TX

U.S. Environmental Protection Agency,

Region 6, John Blevins, TX

U.S. Environmental Protection Agency, 

Region 6, Raul Gutierrez, Ph.D., TX
APPENDIX A (cont’d)

A-3

Federal Government Agencies (cont’d)

U.S. Environmental Protection Agency, 

Susan E. Bromm, DC

U.S. Fish and Wildlife Service, Josh Marceaux, LA

U.S. Fish and Wildlife Service, Lafayette 

Ecological Services Field Office, Jeff 

Welier, LA

U.S. Geological Survey, Esther Eng, VA

U.S. Housing and Urban Development 

Department, Office of Environment and 

Energy, Danielle Schopp, DC

Federal Senators and Representatives

U.S. House of Representatives, Representative 

Ralph Abraham, DC

U.S. House of Representatives, Representative 

Charles W. Boustany, Jr, M.D., DC

U.S. House of Representatives, Representative 

John Fleming, LA

U.S. House of Representatives, Representative 

Cedric Richmond, LA

U.S. House of Representatives, Representative 

Steve Scalise, LA

U.S. Senate, Senator Jeff Sessions, DC

U.S. Senate, Senator Richard Shelby, DC

U.S. Senate, Senator Bill Cassidy, DC

U.S. Senate, Senator Lisa Murkowski, DC

U.S. Senate, Senator David Vitter, LA

State Senators and Representatives

Louisiana House of Representatives, District 33, 

Representative Mike Danahay, LA

Louisiana House of Representatives, District 34, 

Representative A.B. Franklin, LA

Louisiana House of Representatives, District 35, 

Representative Brett Geymann, LA

Louisiana House of Representatives, District 36, 

Representative Chuck Kleckley, LA

Louisiana House of Representatives, District 38, 

Representative H. Bernard LeBas, LA

Louisiana House of Representatives, District 41, 

Representative Mickey J. Guillory, LA

Louisiana State Senate, District 25, Senator Dan 

Morrish, LA

Louisiana State Senate, District 27, Senator 

Ronnie Johns, LA

Louisiana State Senate, District 28, Senator 

Eric LaFleur, LA

State Government Agencies

Alabama Public Service Commission, Secretary, AL

Coastal Protection and Restoration Authority, 

Garret Graves, LA

Coastal Protection and Restoration Authority, 

Science Director, Natalie Snider, LA

Coastal Protection Restoration Authority, 

Bill Feazel, LA

Louisiana Department of Agriculture and Forestry, 

Commissioner Michael G. Strain, LA

Louisiana Department of Conservation, 

Commissioner Jim Welsh, LA

Louisiana Department of Culture, Recreation 

and Tourism, State Archaeologist and 

Director, Dr. Charles McGimsey, LA

Louisiana Department of Environmental 

Quality, Assistant Secretary, Waste Permits 

Division, Sanford Phillips, LA

Louisiana Department of Environmental 

Quality, Bryan Johnston, LA

Louisiana Department of Environmental 

Quality, Jamie Phillippe, LA

Louisiana Department of Environmental 

Quality, Jennifer Sheppard, LA

Louisiana Department of Environmental Quality, 

Regional Manager, Billy Eakin, LA

Louisiana Department of Environmental 

Quality, Secretary, Peggy Hatch, LA

Louisiana Department of Environmental 

Quality, Special Assistant to the Secretary, 

Paul Miller, LA
APPENDIX A (cont’d)

A-4

State Government Agencies (cont’d)

Louisiana Department of Environmental 

Quality, Tegan Treadaway, LA

Louisiana Department of Natural Resources, 

Administrator, Karl Morgan, LA

Louisiana Department of Natural Resources, 

Conservation / Engineering, Brent 

Campbell, LA

Louisiana Department of Natural Resources, 

Conservation / Pipeline Division, James 

Mergist, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management, Jessica 

Williamson, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management, Kelley 

Templet, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management, Ontario 

James, LA

Louisiana Department of Natural Resources, 

Office of Coastal Management, Regina 

Stone, LA

Louisiana Department of Natural Resources, 

Secretary, Stephen Chustz, LA

Louisiana Department of Transportation and 

Development, Secretary, Sherri Lebas, LA

Louisiana Department of Wildlife and Fisheries, 

Amity Bass, LA

Louisiana Department of Wildlife and Fisheries, 

Assistant Secretary, Randall Pausina, LA

Louisiana Department of Wildlife and Fisheries, 

Biologist Program Manager, Kyle Balkum, LA

Louisiana Department of Wildlife and Fisheries, 

Chris Davis, LA

Louisiana Department of Wildlife and Fisheries, 

Dave Butler, LA

Louisiana Department of Wildlife and Fisheries, 

Secretary, Robert Barham, LA

Louisiana Office of Cultural Development, State 

Historic Preservation Officer, Pamela 

Breaux, LA

Louisiana State Police, Sean LeFleur, LA

Louisiana State Police, Superintendent, Colonel 

Mike Edmonson, LA

Secretary of State, Tom Schedler, LA

State of Alabama, Governor Robert J. Bentley, AL

State of Louisiana, Attorney General James D. 

Caldwell, LA

State of Louisiana, Governor Bobby Jindal, LA

State of Louisiana, Governor's Office of 

Homeland Security and Emergency 

Preparedness, Kevin Davis, LA

State of Louisiana, Lieutenant Governor Jay 

Dardenne, LA

Local Government Agencies

Acadia Parish Clerk of Court, Robert Barousse, LA

Calcasieu Parish Homeland Security and Emergency 

Preparedness, Dick Gremillion, LA

Calcasieu Parish Police Jury, Administrator, 

Bryan Beam, LA

Calcasieu Parish Police Jury, Director of 

Economic Development, Clair Hebert, LA

Calcasieu Parish Police Jury, District 1, 

Shannon Spell, LA

Calcasieu Parish Police Jury, District 2, 

Marshall Simien, Jr., LA

Calcasieu Parish Police Jury, District 3, 

Elizabeth C. Griffin, LA

Calcasieu Parish Police Jury, District 4, 

Tony Guillory, LA

Calcasieu Parish Police Jury, District 5, 

Nicholas Hunter, LA

Calcasieu Parish Police Jury, District 6, Dennis 

Scott, LA

Calcasieu Parish Police Jury, District 7, 

Chris Landry, LA

Calcasieu Parish Police Jury, District 8, 

Guy Brame, LA

Calcasieu Parish Police Jury, District 9, 

Kevin Guidry, LA
APPENDIX A (cont’d)

A-5

Local Government Agencies (cont’d)

Calcasieu Parish Police Jury, District 10, 

Tony Stelly, LA

Calcasieu Parish Police Jury, District 11, 

Sandy Treme, LA

Calcasieu Parish Police Jury, District 12, 

Ray Taylor, LA

Calcasieu Parish Police Jury, District 13, 

Francis Andrepont, LA

Calcasieu Parish Police Jury, District 14, 

Hal McMillin, LA

Calcasieu Parish Police Jury, District 15, 

Les Farnum, LA

Calcasieu Parish Police Jury, President, Nicholas 

E. Hunter, LA

Calcasieu Parish Sheriff Department, 

Community/Media Relations Director, Kim 

Myers, LA

Calcasieu Parish Sheriff Department, Sheriff 

Tony Mancuso, LA

Calcasieu Parish, Assessor, Wendy Curphy 

Aguillard, LA

Calcasieu Parish, Clerk of Court, Lynn Jones, LA

Calcasieu Parish, Coroner, Terry Welke, LA

Calcasieu Parish, Fourteenth Judicial District, 

District Attorney, John DeRosier, LA

Calcasieu Parish School Board, Superintendent, 

Karl Bruchaus, LA

Calcasieu Parish, School Board, District 2, 

Fred Hardy, LA

Calcasieu Parish, School Board, District 3, 

Clara F. Duhon, LA

Calcasieu Parish, School Board, District 4, 

Annette Ballard, LA

Calcasieu Parish, School Board, District 5, 

Dale Bernard, LA

Calcasieu Parish, School Board, District 6, 

Bill Jongbloed, LA

Calcasieu Parish, School Board, District 7, 

Mack Dellafosse, Jr., LA

Calcasieu Parish, School Board, District 8, 

Jim Schooler, LA

Calcasieu Parish, School Board, District 15, 

Bryan Larocque, LA

Cameron Parish Chamber of Commerce, LA

Cameron Parish Office of Emergency 

Preparedness, Danny Lavergne, LA

Cameron Parish Office of Emergency Preparedness, 

Secretary, Cassandra Duhon, LA

Cameron Parish Police Jury, Administrator, Tina 

Horn, LA

Cameron Parish School Board, Superintendent, 

Stephanie Rodrique, LA

City of DeQuincy, Mayor Lawrence Henagan, LA

City of Lake Charles, Clerk of the City Council, 

Lynn Thibodeaux, LA

City of Lake Charles, District A, Councilwoman 

Mary Morris, LA

City of Lake Charles, District B, Councilwoman 

Luvertha August, LA

City of Lake Charles, District C, Councilman 

Rodney Geyen, LA

City of Lake Charles, District D, Councilman 

John Leyoub, LA

City of Lake Charles, District E, Councilman 

Stuart Weatherford, LA

City of Lake Charles, District F, Councilman 

Dana Carl Jackson, LA

City of Lake Charles, District G, Councilman 

Mark Eckard, LA

City of Lake Charles, Mayor Randy Roach, LA

City of Lake Charles, Police Chief Don Dixon, LA

City of Sulphur, Mayor Christopher L. Duncan, LA

Evangeline Parish Clerk of Court, Randy 

Deshotel, LA

Lake Charles Fire Department, Fire Chief, Keith 

Murray, LA

Lake Charles Harbor and Terminal District, 

Commissioner Barbara McManus, LA
APPENDIX A (cont’d)

A-6

Local Government Agencies (cont’d)

Lake Charles Harbor and Terminal District, 

Commissioner Daryl Burckel, LA

Lake Charles Harbor and Terminal District, 

Commissioner Dudley Dixon, LA

Lake Charles Harbor and Terminal District, 

Commissioner Elcie Guillory, LA

Lake Charles Harbor and Terminal District, 

Commissioner Harry Hank, LA

Lake Charles Harbor and Terminal District, 

Commissioner John LeBlanc, LA

Lake Charles Harbor and Terminal District, 

Commissioner Mike Eason, LA

Lake Charles Harbor and Terminal District, 

Commissioner Walter Sanches, LA

Lake Charles Harbor and Terminal District, 

Director of Navigation and Security, 

Channing Hayden, LA

Lake Charles Harbor and Terminal District, 

Executive Director, William Rase III, LA

Lake Charles School Board, District 1, Shannon 

Spell, LA

Lake Charles School Board, District 2, Marshall 

Simien, Jr., LA

Lake Charles School Board, District 3, Elizabeth 

C. Griffin, LA

Lake Charles School Board, District 4, Tony 

Guillory, LA

Lake Charles School Board, District 5, Nicholas 

Hunter, LA

Lake Charles School Board, District 6, Dennis 

Scott, LA

Lake Charles School Board, District 7, Chris 

Landry, LA

Lake Charles School Board, District 8, Guy 

Brame, LA

Lake Charles School Board, District 9, Kevin 

Guidry, LA

Lake Charles School Board, District 10, Tony 

Stelly, LA

Lake Charles School Board, District 11, Sandy 

Treme, LA

Lake Charles School Board, District 12, Ray 

Taylor, LA

Lake Charles School Board, District 13, Francis 

Andrepont, LA

Lake Charles School Board, District 14, Hal 

McMillin, LA

Lake Charles School Board, District 15, Les 

Farnum

West Calcasieu Port, Port Director, E Lynn 

Hohensee, LA

West Cameron Port, Port Director, Stephen 

Broussard, LA

Native American Groups

Alabama Coushatta Tribe of Texas, Chairman

Kyle Williams, TX

Alabama Coushatta Tribe of Texas, Chief 

Oscola Clayton Sylestine, TX

Alabama Coushatta Tribe of Texas, Historic 

Preservation, Bryant Celestine, TX

Alabama Coushatta Tribe of Texas, Principal 

Chief Clem Sylestine, TX

Caddo Nation, Chairperson Brenda Shemayme 

Edwards, OK

Caddo Nation, Bobby Gonzalez, 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, Senior Section 

106 Reviewer, Lindsey D. Bilyeu, OK

Choctaw Nation of Oklahoma, Tribal Historic 

Preservation, Ian Thompson, OK

Coushatta Tribe of Louisiana, Chairman, Kevin 

Sickey, LA
APPENDIX A (cont’d)

A-7

Native American Groups (cont’d)

Coushatta Tribe of Louisiana, Chairman, 

Lovelin Poncho, LA

Jena Band of Choctaw Indians, Chief B. Cheryl 

Smith, LA

Jena Band of Choctaw Indians, Deputy Tribal 

Historic Preservation Officer, Alina J. 

Shively, 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 

Historic Preservation Officer/ 

Archaeologist, Kenneth Carleton, MS

Tunica-Biloxi Tribe of Louisiana, Chairman

Earl Barbry, LA

Tunica-Biloxi Tribe of Louisiana, Earl J. Barbry, 

Sr., LA

Libraries

Acadia Parish Library, Crowley Headquarters, LA

Calcasieu Parish Public Library, LA

Evangeline Parish Library, LA

Southwest Louisiana Genealogical and 

Historical Library, LA

Media

American Press, LA

Crowly Post-Signal, LA

Fox29, LA

KPLC-TV, LA

Sulphur Daily News, LA

Ville Platte Gazette, LA

Companies and Organizations

3N75 Trust, LA

4-T Investments, Brian Tanner, LA

Alcoa Carbon Products, Mack Whittaker, LA

Alleghany Defense Project, Ryan Talbott, OR

Alliance for Affordable Energy, LA

Allied Barton Security Services, Suzanne 

Chisholm, TX

American Red Cross of Southwest Louisiana, 

Bobbi Zaunbrecher, LA

ASCO, LA

Audubon Louisiana, LA

Basden Agencies Inc., Alan Basden, LA

BG LNG Services, Lisa Yoho, TX

BG LNG Services, Scott Ervin, TX

BG LNG Services, Marc Hopkins, TX

Bollinger Calcasieu, L.L.C., LA

Boudreau-Calhoun LLC, Patricia B. Calhoun, LA

Boyer Properties, LLC, LA

Calcasieu Council on Aging, Rosalind Berry, LA

Calcasieu Land and Minerals, LLC, LA

Calcasieu League for Environmental Action 

Now, LA

Cameron LNG, LLC, Randy Oakley, LA

Cameron LNG, Steve Trahan, LA

Cashin Family Offices, Bonnie Cashin Englert, CA

Cashin Family Offices, D'Arcy Michael Cashin, CA

Cashin Family Offices, Emmet J. Cashin III, CA

CDI Engineering Solutions, Mario Espinosa, LA

Center for Biological Diversity, AZ

CH2M Hill, Allen Dupont, LA

Cheniere LNG, Inc., James Ducote, LA

CITGO, Ken Rodericks, LA

CITGO, Alirio Zambrano, LA

CITGO, Captain Thomas Fanning, TX

CITGO, Charles Harper, LA

CITGO, Steve Newman, TX

CITGO, Winston Ebarb, TX

Clark Real Estate Enterprises, Inc., LA

Clatrax, Inc., LA

CLM Equipment Co., Inc., Tony Colletta, LA
APPENDIX A (cont’d)

A-8

Companies and Organizations (cont’d)

Conoco Phillips, Willie Tempton, LA

ConocoPhillips, Captain Kurt Hallier, TX

CPRA, Natalie Peyronnin, LA

Crowe Property Investments, LLC, LA

Crowley Marine Services, Captain Stephen 

Porter, LA

Crowley Marine Services, Rick Bastian, LA

CSRS, INC, Lyles Budden, LA

Devall Towing, Joe Devall, LA

Diocese of Lake Charles, Daniel Torres, LA

Dorothy Colletta House, Oscar J. Colletta, LA

Dunham Price Group, LLC, Dav Godsey, LA

Dynamic Industries, Inc., Don Darbonne, LA

Dynamic Industries, Inc., Ralph Clements, LA

Dynamic Industries, Inc., Robert Ward, LA

Ecology and Environment, Bill Daughdrill, FL

Empire of the Seed, Rick Richard, LA

Environmental Defense Fund, NY

Environmental Response Services, Neil Clark, LA

Erwin Heirs, Inc., Elliot Godwin, LA

Farley Testamentary Trusts et al., Richard 

Michael Farley, TX

First Church of Christ, LA

Gayle Brothers, LLC, LA

Gulf Intracoastal Canal Association, Jim 

Stark, LA

Gray Law Firm, Jack Gray, LA

Gulf Coast Environmental Labor Coalition, LA

Gulf Restoration Network, LA

Halco-Kisatchie Properties, Inc., LA

Harbor Docking and Towing, Dwayne 

Chatoney, LA

Holiday Inn Express, Rhonda Colletta, LA

Hotels of Lake Charles, Nimesh Zaver, LA

Hottel Family Partnership, CT

IFG Port Holdings, LLC, Kabir Ahmad, NY

Imperial Calcasieu Museum, LA

Inchcape Shipping Services, Mark Pippin, LA

ISC Constructors, LLC, Craig Messer, TX

Jats Real Estate, LLC, LA

John and Sallye Hammett Trust, Richard 

Hammett, TX

K&L Gates, David Wochner, DC

K&L Gates, Sandra Safro, DC

King Minerals, LLC, LA

Kisatchie Title Management, Inc., LA

Knights of Columbus, Donald Laurent, LA

Lake Area Industry Alliance, Larry DeRoussel, LA

Lake Charles Pilots, Brett Palmer, LA

Lake Charles Pilots, Captain Charles Morrison, LA

Lake Charles Pilots, Dan Morrish, LA

Lake Charles Pilots, Dave Trent, LA

Lake Charles Pilots, George Mowbray, LA

Landry Granger Estate, Pauline Sonnier, TX

Lawrence Granger Estate, Howard Wayne 

Granger, LA

LEEVAC, Richard Ortego, LA

Leucadia National Corporation, Cliff Kerr, TX

Locke Lord LLP, James Moriarty, ESQ., DC

Locke Lord LLP, Thomas Knight, DC

Louise Solari, Ivy Benoit Fruge, LA

Louisiana Bucket Brigade, LA

Louisiana Economic Development, Secretary, 

Stephen Moret, LA

Louisiana Economic Development, Senior 

Director of Business Development, Don 

Pierson, LA

Louisiana Environmental Action Network, 

Michael Orr, LA

Louisiana Environmental Justice Program, 

Darryl Malek Wiley, LA 
APPENDIX A (cont’d)

A-9

Companies and Organizations (cont’d)

Louisiana Farm and Livestock Co., Robert O. 

Gayle, LA

Louisiana State University, Ag Center, SW 

Region, Kevin Savoie, LA

Louisiana Wildlife Federation, Fred Borel, LA

Magnolia LNG, Ernie Megginson, LA

Magnolia LNG, Lincoln Clark, LA

Marine Spill Response Corp., LA

Mayo Realty Company Inc., Bob Mayo, LA

MCPC, LLC, LA

Mixing and Process Equipment Company, Ward 

Howard, LA

MJL Louisiana, LLC, CA

Montell USA, Inc., LA

Moran-Gulf Shipping Agency, Alan Courmier, LA

Moreno Group LLC, John Alford, LA

Morris Revocable Living Trust, Charles William 

and Barbara Pizanie, LA

Morton Group LLC,, LA

Mossville Environmental Action Now, Dorothy 

Felix, LA

Natural Gas Pipeline Company of America LLC, 

Bruce Newsome, IL

Natural Gas Pipeline Company of America LLC, 

Maria Kyres Pavlou, ESQ, IL

Natural Resources Defense Council, NY

Oil Spill Response Vessel Gulf Coast 

Responder, Fred Eason, LA

Panhandle Energy Pipelines, Frazier King, Jr., TX

Panhandle Energy Pipelines, Michael T. 

Langston, TX

Panhandle Energy Pipelines, Stephen Veatch, TX

Panhandle Energy, Dennis Odum, LA

Pine Island Oil Corporation, LA

Port Aggregates, Andrew Guinn, LA

Port Aggregates, Tim Guinn, LA

Powell Land Holdings, LLC, LA

PPG Chlor-Alkali and Derivatives, Terri 

Angelini, LA

Prairie Land Company, LA

Raymond Klumpp Farms, Inc., Hilda Ortego, LA

Recon, Bob Emerson, TX

Reynolds Metals Co. Alcoa Inc., PA

Reynolds Metals, LA

Salvation Army, Major David Craddock, LA

Seabulk Towing, Inc., Aaron Andrus, LA

Seabulk Towing, Inc., Brian Kennedy, LA

Sempra Energy, Mark Nelson, TX

Ship to Shore, Sheron Faulk, LA

Sierra Club, Delta Chapter, LA

Sierra Club, Hayward Martin, LA

Sierra Club, Kathleen Krust, CA

Sierra Club, Natalie Spiegel, CA

Sierra Club, Nathan Matthews, CA

Southwest Louisiana Economic Development 

Alliance, George Swift, LA

Texas Gas Transmission, LLC, David Hardesty, KY

The Nature Conservancy, Southwest Louisiana, 

Rick Jacob, LA

The People's Advocate Southwest Louisiana, 

Director, Beth Zilbert, LA

Thomas Barr IV Louisiana Properties, LLC, NY

Total Gas and Power NA, Fundi Mwamba, TX

Tower Land Company, LLC, LA

Trunkline LNG, Jeffrey Brightwell, LA

Trunkline LNG, Property Tax Department, TX

Trunkline LNG, Scott Hancock, LA

Trunkline LNG, Steven Couch, LA

Union of Concerned Scientists, MA

United Way of Southwest Louisiana, Inc., 

Denise Durel, LA

Van Ness Feldman, LLP, Michael Pincus, DC
APPENDIX A (cont’d)

A-10

Companies and Organizations (cont’d)

Van Ness Feldman, LLP, Robert Francis 

Christin, DC

Venco, LA

Vessel Traffic Service, Frank LaBarbera, LA

Vessel Traffic Service, Michael Measells, TX

Vinson and Elkins LLP, David Tavares Andril, DC

Vinson and Elkins LLP, Elizabeth Kade, DC

West Calcasieu Chamber of Commerce, Stuart 

A. Moss, LA

West Gulf Maritime Association, Niels Aalund, TX

West Gulf Maritime Association, Niels Lyngso, TX

Westlake Polymers Corporation, Mike Shell, LA

Willis Noland Testamentary Trust ET AL, LA

Wingate by Windham, Jay Kumar, LA

Wingate Hotel, Heather Jabusch, LA

Individuals

Alfred Devall and Fausta 

Devall, LA

Allan C. House, LA

Amelia Nell Fuselier and 

Mitchell Fuselier, LA

Ann Crowe Lindsay, LA

Azima Benoit Granger and 

George Lee 

LaGrange, AL

Barbara Jean Stevenson 

Levine, MD

Bea Morrison Thibodeaux, LA

Belvin L. Fontenot and 

Louise Solari, LA

Benson Lyons Palmer Jr., TX

Berna Dean Veillon Johnson,LA

Billie Jewel Trahan Goux and 

John A. Trahan, LA

Boyd Smith, LA

Brenda E. Bell Roberts, LA

Brenda Sue Sumpter ET VIR, LA

Cameron Boyd Barr, LA

Carol Sonnier, LA

Cary Ross McKee, LA

Charlie Atherton, LA

Clarence Benoit Estate and 

Louise Solari, LA

Clarence L. Cooper, TX

Curtis Claude Benoit, LA

Curtis Conkle, TX

Dalton Ray Sonnier, LA

Darcy Jean Owens, CA

Darryl Altalies, LA

Dave Benoit Estate and 

Judith B. Sonnier, LA

David and Jean Harris, LA

David Wayne Bertrand, LA

Donald Lee Benoit, LA

Donna Blackwell LaGrange 

Turner, AL

Doris Dey Taylor, TX

Elizabeth Ann Fontenot 

Oliver and Paul 

Chamerlain, LA

Ernest F. Clooney Jr., LA

Evelyn Devall Reed, LA

Glenda Benoit Oliver, LA

Glenn C. House Jr. et al., TX

Gloria Lone Kiplinger Brown 

et al., LA

Grace Davison, LA

James Ray Clooney III, LA

James Richard Smith, LA

James T. Quinn, LA

Janet Mayo, NY

Jennie Sue Pearson et al., MD

Jeremie Wayne Veillon, LA

John Arthur Fleig, LA

John F. Hennessey et al., LA

John Lemeur and Lorrain 

Jackson, OH

Joseph B. Powell et al., and 

J. Brent Powell, LA

Joseph David Painter, LA

Kathryn House, LA

Kerry Arthur House, LA

Kevin Anthony and Anita 

Richard, LA

Lena Benoit King and 

Michelle Koonce, LA

Linda Cooper, TX

Lois Meril Cassidy Benoit 

et al., LA

Major V W Humphrey, 

Helen Clooney 

Humphrey Esq., AR

Margaret A. Garlinghouse 

and David Pettus, CA

Marjorie Nalley Campbell, LA

Mary Benoit Ortego and 

Louise Solari, LA

Mary Beth Russell, TX

Mary Leonise Broussard 

Perrin, LA

Matt Young, LA

Murphy and Rosette Bellard, LA

Nancy Tugwell, LA

Natalie Lewis Miciotto, LA
APPENDIX A (cont’d)

A-11

Individuals (cont’d)

Natalie Rogers Murphy, NY

Necil Benoit LeBouef and 

Brenda Foreman, LA

Patrick Fusilier, LA

Philip Anthony Gayle et al.

and W.J. Gayle and 

Sons, LA

R Brooks Fleig and Catherine 

Fleig Sharpe, LA

Ray Sonnier, LA

Raymond Klumpp, LA

Simon and Sonja Davidson, LA

Stephen Brown III, LA

Stephen Robert Bollich, LA

Terry Fontenot, Jr, LA

Thomas McClelland, LA

Thomas Raymond Howell Jr. 

et al., CA

Tom Miller, LA

Vera Watkins House, TX

Vernon W. Humphrey et 

al., AR

Vito A. Tramonte, LA

Wilda Rose K. Fontenot, LA

William Richard Neff, PA

Winifred Vetha Adkins 

Hutchinson and Clif 

Walters, TX

Winston Frey, et ux, LA

APPENDIX %

PRO326(' FACILITIES MAPS

Louisiana

LNG Terminal Site

p LNG Terminal Site

0 500 1,000

Feet

Appendix B

Overview Topographic Map

Magnolia LNG Project

Calcasieu Parish, Louisiana

This information is for environmental review purposes only.

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Overview\MLP_Overview_Topo.mxd | REVISED: 04/16/2015 | SCALE: 1:24,000 DRAWN BY: JSSuess

Figure 1 of 29

B-1
Louisiana

LNG Terminal Site

Tank Farm W Rd

Bud Stell Rd

Cal Locks Rd

Joe Ledoux Rd

Granger Rd

Clara

Bazile Rd

Lincoln W Rd

Airhart Rd

Henry Pugh Blvd

Ta n k Farm Rd

Canal

Big L ake Rd

ST384

p LNG Terminal Site

0 500 1,000

Feet

Appendix B

Overview Aerial Map

Magnolia LNG Project

Calcasieu Parish, Louisiana

This information is for environmental review purposes only.

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Overview\MLP_Overview_Aerial.mxd | REVISED: 04/16/2015 | SCALE: 1:24,000 DRAWN BY: JSSuess

Figure 2 of 29

B-2
Appendix B

Dredge Spoil Plan View

Overview

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 11/7/2014

0 200 400 600 Feet

Big Lake Rd

Industrial Canal

CB&I Internal Access Rd

Elliott Rd

W Lincoln Rd

FRAME - 8

FRAME - 2

FRAME - 1

FRAME - 3

FRAME - 4

FRAME - 6

FRAME - 5

FRAME - 7

1.0

1.06

0.5

0.0

0.94

0.75

0.25

Document Path: C:\GIS\Moore_Support\DredgeSoilPlan\Maps\mxd\LNG_Drawings_Sept2014\Overview_2014_09_02.mxd

Legend

CL 24" Pipeline

Limits of Construction

Borrow Pit

Bulkhead

Fence

Railroad

Road Edge

Milepost Stream

Building

Map Frame Index

Figure 3 of 29

B-3
Appendix B

Dredge Spoil Plan View

Frame 1

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 11/7/2014

0 50 100 150 Feet

End Surface Lay/

Effluent Out-fall

End Floating Line/

Begin Surface Lay

Building

Building

Bldg.

384Big Lake Rd

End Bore/Begin 

Surface Lay

End Surface Lay/

Begin Bore

100'

35'

35'

85'

145'

100'

40'

85'

145'

End Surface Lay/

Begin Bore

End Bore/Begin 

Surface Lay

75'

310'

305'

92'

163'

144' 69'

154'

170'

365'

379'

Industrial Canal

0.0

0.25

35' TEMP WORKSPACE

20' TEMP WORKSPACE

20' TEMP WORKSPACE

Limits of Construction

CL 24 Dredge Spoil Pipeline

CL 24 Effluent Return Pipeline

Limits of Construction

TYPICAL CONSTRUCTION 

CORRIODR (NTS)

Document Path: C:\GIS\Moore_Support\DredgeSoilPlan\Maps\mxd\LNG_Drawings_Sept2014\Frame1.mxd

Legend

Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Milepost

Figure 4 of 29

B-4
Appendix B

Dredge Spoil Plan View

Frame 2

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 11/7/2014

0 50 100 150 Feet

Building

557'

486'

630'

670'

75'

1,363'

1,390'

10'

0.5

0.25

35' TEMP WORKSPACE

20' TEMP WORKSPACE

20' TEMP WORKSPACE

CL 24” Effluent Return Pipeline

CL 24” Dredge Spoil Pipeline

Limits of Construction

Limits of Construction

TYPICAL CONSTRUCTION 

CORRIODR (NTS)

Legend

Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Milepost

Figure 5 of 29

B-5
Appendix B

Dredge Spoil Plan View

Frame 3

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 11/7/2014

0 50 100 150 Feet

CB&I Internal Access Rd

1,363'

1,390'

1,170'

Begin Surface Lay/

Effluent Intake

0.94

0.75

Legend

Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Milepost

Figure 6 of 29

B-6
Appendix B

Dredge Spoil Plan View

Frame 4

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 11/7/2014

0 50 100 150 Feet

W Lincoln Rd

Joe Ledoux Rd

110'

593'

1,565'

End Surface Lay/

Spoil Out-fall

257'

1,170'

0.94

1.0

1.06

Legend

Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Milepost

Figure 7 of 29

B-7
Appendix B

Dredge Spoil Plan View

Frame 5

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 9/3/2014

0 50 100 150 Feet μ

Elliott Rd

2,157'

628'

1,565'

W Lincoln Rd

Legend

!> Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

[ Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Figure 8 of 29

B-8
Appendix B

Dredge Spoil Plan View

Frame 6

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 9/3/2014

0 50 100 150 Feet μ

Elliott Rd

2,157'

Legend

!> Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

[ Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Figure 9 of 29

B-9
Appendix B

Dredge Spoil Plan View

Frame 7

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 9/3/2014

0 50 100 150 Feet μ

Elliott Rd

2,108'

391'

312'

2,157'

Legend

!> Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

[ Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Figure 10 of 29

B-10
Appendix B

Dredge Spoil Plan View

Frame 8

Magnolia LNG Project

Calcasieu Parish, Louisiana Date: 9/3/2014

0 50 100 150 Feet μ [ [ [ [ [ [ [ [ [ [

[ [ [ [ [ [ [ [ [ [ [

[ [ [ [ [ [ [ [ [ [ [ [ [ [ [ [

CB&I Internal Access Rd

2,108'

684'

Legend

!> Pipeline Transition

CL 24" Pipeline

Limits of Construction Bulkhead

[ Fence

Railroad

Stream

Road Edge

Road Centerline

Borrow Pit

Figure 11 of 29

B-11
UNKNOWN P/L

KINDER MORGAN P/L

TRANSCANADA P/L

WATERLINE

CROSSTEX P/L

CROSSTEX P/L

FLORIDA GAS P/L FLORIDA GAS P/L

KINDER MORGAN P/L

TRANSCANADA P/L

TEXAS GAS P/L

CROSSTEX P/L BOARDWALK P/L

CROSSTEX P/L

L/P KLAWDRAOB

TEXAS GAS P/L

TEXAS GAS P/L

TEXAS GAS P/L

KINDER MORGAN P/L

TRANSCANADA P/L

TRANSCANADA P/L

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COULEE ROAD

PLAINS P/L PLAINS P/L

ERICK LANE

TGT METER SITE

PINE PRAIRIE ME

PROPO

PROPOSED EUNICE

COMPRESSOR STATION 760

REFERENCE DRAWINGS

NO. DATE BY DESCRIPTION

REVISIONS EN

200 0 200 400

DRAWN BY

CHECKED B

APPROVED

PLOT BY 

PHOTO BY

DATE

REF. DRAWING NO. DRAWING TITLE

LEGEND NOTES

C/L ROAD

PX

POWER LINEFENCE LINE

PL

EXISTING PIPELINEPROPERTY LINE

TRACT NUMBER

W WATER LINE

XX

C/L DITCH\DRAINAGE

MAY NOT BE LOCATED.

ALL UNDERGROUND OBSTRUCTIONS

CAUTION !

PROPOSED AND EXISTING PIPELINES,

ALONG WITH ALL UNDERGROUND

OBSTRUCTIONS TO BE STAKED PRIOR TOCONSTRUCTION.

ALL PIPELINE DESIGN PROVIDED

BY KINDER MORGAN INC.

POWER POLE

MIN. COVERWETLAND\STREAM I.D. 

50 0 50 100

LEVEE CL/ EDGE

1 5/13/14 PHG ADDED WORSPACE2 5/21/14 PHG UPDATED WS HATCH3 5/22/14 PHG ADDED LATERAL AND PROPOSED COMPRESSOR SITE4 5/28/14 PHG LEGEND UPDATES5 6/10/14 PHG WORKSPACE CHANGES

6 6/17/14 PHG WORKSPACE CHANGES

B-12
CR

FLORIDA GAS P/L FLORIDA GAS P/L

KINDER MORGAN P/L

TRANSCANADA P/L

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LP

LP

LP

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

LP

LP

PL

LP

LP

PL

PL

LP

LP

PL

PL

PL

PL

PL

PL

PL

PL

PL

PL

LP LP

PL

PL

PL

L

LP

PL

LP

PL

PL

PL

PL

PL

PL

PL

PL

COULEE ROAD

KINDER MORGAN P/L

TRANSCANADA P/L

TRANSCANADA P/L

ANE

FOURNERAT ROAD

ST

PINE PRAIRIE METER SITE

ANR M

PROPOSED PINE PRAIRIE LATERAL

PROPOSED EUNICE

COMPRESSOR STATION 760

REFERENCE DRAWINGS

NO. DATE BY DESCRIPTION

REVISIONS EN

200 0 200 400

DRAWN BY

CHECKED B

APPROVED

PLOT BY 

PHOTO BY

DATE

REF. DRAWING NO. DRAWING TITLE

LEGEND NOTES

C/L ROAD

PX

POWER LINEFENCE LINE

PL

EXISTING PIPELINEPROPERTY LINE

TRACT NUMBER

W WATER LINE

XX

C/L DITCH\DRAINAGE

MAY NOT BE LOCATED.

ALL UNDERGROUND OBSTRUCTIONS

CAUTION !

PROPOSED AND EXISTING PIPELINES,

ALONG WITH ALL UNDERGROUND

OBSTRUCTIONS TO BE STAKED PRIOR TOCONSTRUCTION.

ALL PIPELINE DESIGN PROVIDED

BY KINDER MORGAN INC.

POWER POLE

MIN. COVERWETLAND\STREAM I.D. 

50 0 50 100

LEVEE CL/ EDGE

1 5/13/14 PHG ADDED WORKSPACE

2 5/21/14 PHG UPDATED WS HATCH

3 5/22/14 PHG ADDED LATERAL AND PROPOSED COMPRESSOR SITE

4 5/28/14 PHG LEGEND UPDATES

5 6/10/14 PHG WORKSPACE CHANGES

6 6/17/14 PHG WORKSPACE CHANGES

B-13
Louisiana

0.3

0.4

0.8

0.7

0.6

0.2

0.5

Compressor Station 760

Pine Prairie

Meter Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

24-inch High Pressure Header

Pipeline

36-inch Low Pressure Header

Pipeline

Access Road

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Topographic Site Map

Compressor Station 760

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/16/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 14 of 29

B-14
Louisiana

Refinery Rd

Leroy Ln

Erick Ln

Par Rd

Coulee Rd

0.3

0.4

0.8

0.7

0.6

0.2

0.5

Compressor

Station 760

Pine Prairie

Meter Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

24-inch High Pressure Header

Pipeline

36-inch Low Pressure Header

Pipeline

Access Road

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Aerial Site Map

Compressor Station 760

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/16/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 15 of 29

B-15
Louisiana

CGT Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Permanent Workspace

Temporary Workspace p Appendix B

Topographic Site Map

CGT Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 16 of 29

B-16
Louisiana

Attales Rd

Terrace Bonnet Rd

CGT Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Permanent Workspace

Temporary Workspace p Appendix B

Aerial Site Map

CGT Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 17 of 29

B-17
Louisiana

TRANSCO

Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Permanent Workspace

Temporary Workspace p Appendix B

Topographic Site Map

TRANSCO Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 18 of 29

B-18
Louisiana

Old School House Rd Old Shcool Hse Rd

Transco Rd

TRANSCO

Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Permanent Workspace

Temporary Workspace p Appendix B

Aerial Site Map

TRANSCO Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 19 of 29

B-19
Louisiana

TETCO

Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Access Road Temporary Workspace

p Appendix B

Topographic Site Map

TETCO Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 20 of 29

B-20
Louisiana

Ashford Cemetry Rd

Mcclelland Rd

Pierre Manu e l Rd

TETCO

Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Access Road Temporary Workspace

p Appendix B

Aerial Site Map

TETCO Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 21 of 29

B-21
Louisiana

1.1

1

0.9

0.8

1.2

ANR Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

36-inch Low Pressure Header

Pipeline

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Topographic Site Map

ANR Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 22 of 29

B-22
Louisiana

Par Rd

Fournerat Rd

Unatex Rd

Stacy Ln Valse Dr

1.1

1

0.9

0.8

1.2

ANR Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

36-inch Low Pressure Header

Pipeline

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Aerial Site Map

ANR Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 23 of 29

B-23
Louisiana

0.3

0.4

0.8

0.7

0.6

0.2

0.5

Compressor Station 760

Pine Prairie

Meter Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

24-inch High Pressure Header

Pipeline

36-inch Low Pressure Header

Pipeline

Access Road

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Topographic Site Map

High Pressure Header Pipeline

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/16/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 24 of 29

B-24
Louisiana

Refinery Rd

Leroy Ln

Erick Ln

Par Rd

Coulee Rd

0.3

0.4

0.8

0.7

0.6

0.2

0.5

Compressor

Station 760

Pine Prairie

Meter Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

24-inch High Pressure Header

Pipeline

36-inch Low Pressure Header

Pipeline

Access Road

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Aerial Site Map

High Pressure Header Pipeline

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/16/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 25 of 29

B-25
Louisiana

0.3

0.1

0

0.2

TGT Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

36-inch Low Pressure Header

Pipeline

Access Road

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Topographic Site Map

TGT Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 26 of 29

B-26
Louisiana

Coulee Rd

Erick Ln

0.3

0.1

0

0.2

TGT Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Mileposts

36-inch Low Pressure Header

Pipeline

Access Road

Permanent Workspace

Temporary Workspace

Additional Temporary Workspace p Appendix B

Aerial Site Map

TGT Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 27 of 29

B-27
Louisiana

Magnolia

Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Access Road Permanent Workspace

Temporary Workspace p Appendix B

Topographic Site Map

Magnolia Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Topo_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 28 of 29

B-28
Louisiana

Henry Pugh Blvd

Magnolia

Meter

Station

This information is for environmental review purposes only.

0 250 500

Feet

Access Road Permanent Workspace

Temporary Workspace p Appendix B

Aerial Site Map

Magnolia Meter Station

Lake Charles Expansion Project 1:6,000

FILE: M:\Clients\M-O\MLP\Terminal\_ArcGIS\2015\04\Topo_Aerial_Maps\Aerial_Series.mxd | REVISED: 04/15/2015 | SCALE: 1:6,000 DRAWN BY: JSSuess

Figure 29 of 29

B-29

APPENDIX C 

BIRDS OF CONSERVATION CONCERN POTENTIALLY OCCURRING 

IN THE VICINITY OF THE LNG TERMINAL AND KMLP FACILITIES 

 

C-1 

APPENDIX C 

Birds of Conservation Concern Potentially Occurring in the Vicinity of the LNG Terminal and KMLP Facilities

Common Name Scientific Name 

Colonial 

Waterbird 

Breeds in 

Region 

Nesting Habitat a

Ground Shrub Tree 

American bittern Botaurus lentiginosus X X X o o 

American oystercatcher Haematopus palliates - X X o o 

Audubon’s shearwater Puffinus iherminieri X - - - - 

Bald eagle Haliaeetus leucocephalus - X o o X 

Band-rumped storm-petrel b Oceanodroma castro X - - - - 

Black rail Laterallus jamaicensis X X X o o 

Black skimmer Rynchops niger X X X o o 

Botteri’s sparrow Peucaea botterii - X X o o 

Buff-breasted sandpiper Tryngites subruficollis - - - - - 

Dickcissel Spiza americana - X o X o 

Grasshopper sparrow Ammodramus savannarum - X X o o 

Gull-billed tern Gelochelidon nilotic X X X o o 

Henslow’s sparrow Ammodramus henslowii - - - - - 

Hudsonian godwit Limosa haemastica - - - - - 

Least bittern Ixobrychus exilis X X X o o 

Least tern Sternula antillarum X X X o o 

LeConte’s sparrow Ammodramus leconteii - - - - - 

Lesser yellowlegs Tringa flavipes - - - - - 

Loggerhead shrike Lanius ludovicianus - X o o X 

Long-billed curlew Numenius americanus - X X o o 

Marbled godwit Limosa fedoa - - - - - 

Mountain plover Caradrius montanus - - - - - 

Nelson’s sharp-tailed sparrow Ammodramus nelson - - - - - 

Painted bunting Passerina ciris - X o X o 

Peregrine falcon Falco peregrinus - - - - - 

Prothonotary warbler Protonotaria citrea - X o o X 

Red knot Calidris canutus roselaari - - - - - 

Red knot c Calidris canutus rufa - - - - - 

Reddish egret Egretta rufescens X X o o X 

Sandwich tern Thalasseus sandvicensis X X X o o 

Seaside sparrow Ammodramus maritimus - X o X o 

Sedge wren Cistothorus platensi - - - - - 

Short-billed dowitcher Limnodromus griseus - - - - - 

Short-eared owl Asio flammeus - - - - - 

Snowy plover Charadrius nivosus - X X o o 

Solitary sandpiper Tringa solitary - - - - - 

Sprague’s pipit Anthus spragueii - - - - - 

Swainson’s warbler Limnothlypis swainsonii - X o X o 

Swallow-tailed kite Elanoides forficatus - X o o X 

Upland sandpiper Bartramia longicauda - - - - - 

Whimbrel Numenius phaeopus - - - - - 

White-tailed hawk Geranoaetus albicaudatus - X o o X 

Wilson’s plover Charadrius wilsonia - X X o o 

Yellow rail Coturnicops noveboracensis X - - - - 

____________________ 

Note: “-“ = not applicable; “o” = does not nest in habitat type 

a Nesting habitat type is only provided for those species who breed in Bird Conservation Region 37. b Candidate species under the Endangered Species Act. c Species recently listed as threatened under the Endangered Species Act and discussed further in section 4.7. 

Sources: U.S. Fish and Wildlife Service, 2008; Cornell Lab of Ornithology, 2015. 

APPENDIX D 

REFERENCES AND CONTACTS 

 

APPENDIX D

REFERENCES AND CONTACTS

D-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.

Adrian, M. and J. Icaza. 2015. Estimations for Job Growth in the Tertiary and Quaternary Sectors in 

Southwest Louisiana: Predicting Permanent “Post Boom” Employment Based Upon Anticipated 

Population Growth. Available online at http://allianceswla.org/Images/Interior/PageDisplay. 

asp?p1=2645estimations%20for%20job%20growth%20in%20the%20tertiary%20and%20quatern

ary%20sectors%20in%20southwest%20louisiana-%20predicting%20permanent%PageDisplay. 

asp?p1=264520post%20boom%20employment%20(2nd%20.pdf. Accessed April 2015.

Advanced Materials Services, LLC. 2014. Calcasieu Point Traffic Mitigation Pavement Analysis. 

Prepared for Lake Charles LNG, Magnolia LNG, and G2X Energy.

Air Liquide. 2013. Air Liquide Gas Encyclopedia. Available online at http://encyclopedia.airliquide.com/

encyclopedia.asp. Accessed June 2015.

Audubon. 2014. Christmas Bird Count. Available online at http://www.audubon.org/conservation/

science/christmas-bird-count. Accessed April 2015.

Ausenco. 2015. Port of Lake Charles, Calcasieu Ship Channel Traffic Study. Final Report. Report 

100218-01-RPT-0001. January 6, 2015.

Barnes et al. 1977. Power Plant Construction Noise Guide. Bolt, Beranek and Newman, Incorporated. 

Black & Veatch. 2015. LNG. Available online at http://bv.com/home/capabilities/market/Energy/OilAND-Gas/LNG. Accessed January 2015.

Bosma, P. and R.K. Nagelvoort. 2009. Liquefaction Technology; Developments through History. Shell 

Global Solutions International BV. Proceedings of the 1st Annual Gas Processing Symposium.

Bradley, A., H. Duan, W. Elion, E. Soest-Vercammen, and R.K. Nagelvoort. 2009. Innovation in the LNG 

Industry: Shell’s Approach. Shell Global Solutions International BV.

C.H. Fenstermaker and Associates, LLC. 2014. Traffic Impact Study. Prepared for Lake Charles LNG, 

Magnolia LNG, and G2X Energy.

Calcasieu Parish Police Jury. 2015. Calcasieu Parish Mapping Application for Zoning. Available online 

at http://cppj.totaland.com/. Accessed March 2015.

Cameron Parish Police Jury. 2015. Hospital. Available online at http://www.parishofcameron.net/

PageDisplay.asp?p1=2645. Accessed March 2015.

Cameron Parish Tourist Commission. 2014. Hotels/Motels. Available online at http://cameronparish

touristcommission.org/sleep/. Accessed May 2014.

Carter, L. 2015. Email communication on April 1, between L. Thomas (Natural Resource Group, LLC) 

and L. Carter (Parks Superintendent, Calcasieu Parish Police Jury, Lake Charles, Louisiana).

Caterpillar. 2007. VM 20 C Project Guide: Generator Set. Caterpillar Motorem Gmblt & Co. KG. Kiel 

Germany. April 2007.
APPENDIX D

REFERENCES AND CONTACTS (cont’d)

D-2

Caterpillar. 2011. VM 25 C Project Guide: Generator Set. Caterpillar Motorem Gmblt & Co. KG. Kiel 

Germany. August 2011.

Caterpillar. 2012. VM 32 C Project Guide: Generator Set. Caterpillar Motorem Gmblt & Co. KG. Kiel 

Germany. August 2012. 

ConocoPhillips. 2014a. Kenai LNG Plant and North Cook Inlet Fact Sheet. Available online at 

http://alaska.conocophillips.com/Documents/Fact%20Sheet_Kenai%20LNG_CURRENT.pdf. 

Accessed August 2014.

ConocoPhillips. 2014b. Optimized Cascade Process. Available online at http://lnglicensing.

conocophillips.com/what-we-do/lng-technology-licensing/Pages/optimized-cascade-process.aspx. 

Accessed April 2015. 

Cowardin, L.M., V. Carter, F.C. Golet, and E.T. LaRoe. 1979. Classification of Wetlands and Deepwater 

Habitats of the United States. Prepared for the U.S. Fish and Wildlife Service. FWS/OBS-79/31. 

December 1979.

Crone, A.J. and R.L. Wheeler. 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.

Cropley, P. and Eberwine, J. 2014. Negative Findings: Phase I Cultural Resources Survey of the Proposed 

Lake Charles Expansion Project in Acadia, Calcasieu, and Evangeline Parishes, Louisiana. 

R. Christopher Goodwin & Associates, Inc., New Orleans, Louisiana.

Davis, Lucas. 2010. The Effect of Power Plants on Local Housing Values and Rents. Available online at 

http://faculty.haas.berkeley.edu/ldavis/pp.pdf. Accessed May 2015.

Ecology and Environment Inc. 2013a. Baseline Noise Study Report. Prepared for Magnolia LNG, LLC. 

November 2013. 

Ecology and Environment, Inc. 2013b. Dredge Area Sampling Summary Report for the Magnolia LNG 

Berth Area. Baton Rouge, Louisiana.

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.

Environmental Resources Management. 2015. Air Dispersion Modeling Report. Prepared for Magnolia 

LNG, LLC. January 2015.

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.
APPENDIX D

REFERENCES AND CONTACTS (cont’d)

D-3

Federal Emergency Management Agency. 2014. Flood Insurance Rate Maps. Available online at 

https://msc.fema.gov/webapp/wcs/stores/servlet/FemaWelcomeView?storeId=10001&catalogId=

10001&langId=-1&userType=G. Accessed April 2014. 

Fontenot, T. 2013. Email communication on September 11, between K. Welder (Ecology and 

Environment Inc.) and T. Fontenot (Executive Assistant, Jefferson Davis Parish Economic 

Development Commission).

Frey, R.C. and R.D. Kaiser. 1984. Surface exposures of Late Cretaceous strata at the Rayburns Dome, 

Bienville Parish, Louisiana. Gulf Coast Association of Geological Societies Transactions 

(34):357–361.

Fugro Consultants, Inc. 2014a. Geotechnical Investigation for Magnolia LNG Project. Prepared for CHIV International, LLC. Port of Lake Charles, Louisiana. Report No. 04.10130048. April 23, 2014.

Fugro Consultants, Inc. 2014b. Seismic Studies for Magnolia LNG Facility, Port of Lake Charles, 

Louisiana. Prepared for CH-IV International, LLC. Report No. 04.10130048-1. October 7, 2014.

Fugro Consultants, Inc. 2015. Geotechnical Investigation for Magnolia LNG Project. Prepared for CHIV International, LLC. Port of Lake Charles, Louisiana. Report No. 04.10130048. 

January 8, 2015.

Fuller, D.A., A.M. Tappan, and M.C. Hester. 1987. Sea Turtles in Louisiana’s Coastal Waters. Prepared 

for Coastal Fisheries Institute and Louisiana Sea Grant College Program, Louisiana State 

University. August 1987. Available online at http://www.seagrantfish.lsu.edu/pdfs/seaturtles.pdf. 

Accessed April 2015.

Google. 2014. Goople Maps. Available online at https://maps.google.com/. Accessed May 2014.

Google. 2015. Google Earth aerial photography. March 2015.

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 2015.

Gulf of Mexico Fishery Management Council. 2010. Fishery Management Plans and Amendments. Available 

online at http://www.gulfcouncil.org/fishery_management_plans/index.php. Accessed April 2014.

HotelsMotels.info. 2015. Hotels and Motels in Louisiana. Available online at 

http://www.hotelmotels.info/Louisiana/. Accessed March 2015.

Hunt, C.B. 1967. Physiography of the United States. W. H. Freeman and Company, San Francisco, 

California. 
APPENDIX D

REFERENCES AND CONTACTS (cont’d)

D-4

Hunt, E.C., G. Bourneuf. 2003. Modern Engineer’s Manual, Volume 1, 3rd Edition. Eds. D. Augustine 

and J. Tiratto. Cornell Maritime Press, Inc. Centreville, Maryland.

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.

IMCAL. 2013. Traffic Counts, 2008 – 2013. Available online at https://sites.google.com/site/

countsimcal/2008---2013. 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. Accessed August 2014.

International Energy Agency. 2012b. World Energy Outlook 2012, Renewable Energy Outlook. Available 

online at http://www.worldenergyoutlook.org/publications/weo-2012/. Accessed August 2014.

International Energy Agency. 2014a. Hydropower. Available online at http://www.iea.org/topics/

renewables/subtopics/hydropower/. Accessed August 2014.

International Energy Agency. 2014b. 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.

Interstate Natural Gas Association of America. 2001. Natural Gas Pipeline Impact on Land Values. 

INGAA Foundation. Houston, Texas. Available online at http://www.ingaa.org/Foundation/

Studies/FoundationReports/207.aspx. Accessed March 2015.

Kent, J.D. 2012. Assessing the Long-term Impact of Subsidence and Global Climate Change on 

Emergency Evacuation Routes in Coastal Louisiana: A report of findings for the Gulf Coast center 

for evacuation and transportation resiliency. Gulf Coast Center for Evacuation and Transportation 

Resiliency. Report No. 11-09. Baton Rouge, Louisiana.

Louisiana Department of Environmental Quality. 2004. Basin Subsegments from LDEQ Source Data, 

200406, Geographic NAD83, LOSCO [basin_subsegments_LDEQ_2004]. Baton Rouge, 

Louisiana. Available online at https://catalog.data.gov/dataset/basin-subsegments-from-ldeq-sourcedata-geographic-nad83-losco-2004-basin-subsegments-ldeq-2004#. Accessed January 2015.

Louisiana Department of Environmental Quality. 2008. Water Quality Management Plan: Volume 4. 

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REFERENCES AND CONTACTS (cont’d)

D-5

Louisiana Department of Environmental Quality. 2013a. 2012 Louisiana Water Quality Inventory: 

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Study3Sep14.pdf. Accessed January 2015.

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.

U.S. Department of Transportation, Pipeline and Hazardous Materials Safety Administration. 2015. 

Pipeline Incidents 20 Year Trends. Available online at http://www.phmsa.dot.gov/pipeline/

library/datastatistics/pipelineincidenttrends. Accessed March 2015.

U.S. Energy Information Administration. 2014a. Annual Energy Outlook 2014. Report No. DOE/EIA0383ER(2014). Available online at http://www.eia.gov/forecasts/aeo/pdf/0383(2014).pdf. 

Accessed January 2015.

U.S. Energy Information Administration. 2014b. U.S. Wood Pellet Exports Double in 2013 in Response 

to Growing European Demand. Available online at http://www.eia.gov/todayinenergy/

detail.cfm?id=16391. Accessed April 2015.

U.S. Environmental Protection Agency. 1971. Noise from Construction Equipment and Operations, 

Building Equipment, and Home Appliances. Office of Noise Abatement and Control. December 1971.
APPENDIX D

REFERENCES AND CONTACTS (cont’d)

D-14

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. Office of Noise 

Abatement and Control. March 1974.

U.S. Environmental Protection Agency. 2005. 2005 National Emissions Inventory Data & Documentation. 

Available online at http://www.epa.gov/ttn/chief/net/2005inventory.html. Accessed April 2015.

U.S. Environmental Protection Agency. 2006. 2004 Toxic Release Inventory Sites in Louisiana, 

Geographic NAD83 (2006). Available online at https://catalog.data.gov/dataset/2004-toxicrelease-inventory-sites-in-louisiana-geographic-nad83-epa-2006-toxic-release-in-2004. Accessed 

January 2015.

U.S. Environmental Protection Agency. 2008. Sole Source Aquifers. EPA Region 6. Dallas, Texas. 

Available online at http://www.epa.gov/region6/water/swp/ssa/maps.htm. Accessed May 2015.

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. Accessed August 2014.

U.S. Environmental Protection Agency. 2013b. 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. 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. 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. 2014c. National Ambient Air Quality Standards (NAAQS). 

Available online at http://www.epa.gov/air/criteria.html. Accessed April 2014. 

U.S. Environmental Protection Agency. 2014d. Prevention of Significant Deterioration (PSD) Basic 

Information. Available online at http://www.epa.gov/NSR/psd.html#best. Accessed April 2014. 

U.S. Environmental Protection Agency. 2015a. Access to monitored air quality data from EPA’s Air 

Quality System (AQS) Data Mart. Available online at http://www.epa.gov/airdata/. Accessed May 2015.

U.S. Environmental Protection Agency. 2015b. Natural Gas. Available online at 

http://www.epa.gov/cleanenergy/energy-and-you/affect/natural-gas.html. Accessed April 2015.

U.S. Fish and Wildlife Service 2012d. Kemp’s Ridley Sea Turtle Factsheet. Available online at 

http://www.fws.gov/northflorida/seaturtles/turtle%20factsheets/kemps-ridley-sea-turtle.htm. Accessed 

June 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.
APPENDIX D

REFERENCES AND CONTACTS (cont’d)

D-15

U.S. Fish and Wildlife Service. 2007. West Indian Manatee (Trichechus manatus) 5-Year Review: 

Evaluation and Summary. Available online at http://ecos.fws.gov/speciesProfile/profile/

speciesProfile.action?spcode=A007. Accessed June 2014.

U.S. Fish and Wildlife Service. 2008. 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. 2009. Gulf Sturgeon (Acienser oxyrinchus desotoi) 5-Year Review: 

Summary and Evaluation. Available online at http://ecos.fws.gov/docs/five_year_review

/doc2620.pdf. Accessed July 2014. 

U.S. Fish and Wildlife Service. 2012a. East Cove Unit National Wildlife Refuge. Available online at 

http://www.fws.gov/swlarefugecomplex/cameronprairie/eastcove/. Accessed March 2015. 

U.S. Fish and Wildlife Service. 2012b. Green Sea Turtle Factsheet. Available online at

http://www.fws.gov/northflorida/seaturtles/turtle%20factsheets/green-sea-turtle.htm. Accessed 

June 2014. 

U.S. Fish and Wildlife Service. 2012c. Hawksbill Sea Turtle Factsheet. Available online at

http://www.fws.gov/northflorida/seaturtles/turtle%20factsheets/hawksbill-sea-turtle.htm. 

Accessed June 2014.

U.S. Fish and Wildlife Service. 2012e. Leatherback Sea Turtle Factsheet. Available online at 

http://www.fws.gov/northflorida/seaturtles/turtle%20factsheets/leatherback-sea-turtle.htm. Accessed 

June 2014.

U.S. Fish and Wildlife Service. 2012f. Loggerhead Sea Turtle Factsheet. Available online at 

http://www.fws.gov/northflorida/seaturtles/turtle%20factsheets/loggerhead-sea-turtle.htm. Accessed 

June 2014. 

U.S. Fish and Wildlife Service. 2013. Letter dated September 27, from Deborah Fuller (Acting Supervisor) 

to Bill Daughdrill (Ecology & Environment).

U.S. Fish and Wildlife Service. 2014a. Letter dated July 25, from Deborah Fuller (Acting Supervisor) to 

Blake Amos (CH2MHILL).

U.S. Fish and Wildlife Service. 2014b. Email correspondence on May 16, between J. Weller (Field 

Supervisor) and H. Herod (DWH Case Management Office, ESA Coordinator).

U.S. Fish and Wildlife Service. 2014c. West Indian Manatee (Trichechus manatus). Available online at

http://ecos.fws.gov/speciesProfile/profile/speciesProfile.action?spcode=A007. Accessed July 2014.

U.S. Fish and Wildlife Service. 2015. Sabine National Wildlife Refuge. Available online at 

http://www.fws.gov/refuges/profiles/index.cfm?id=43640. Accessed March 2015.

U.S. Geological Survey and Louisiana Department of Natural Resources. 2013. Louisiana Water Use 2012. 

Available online at http://la.water.usgs.gov/WaterUse/default.asp. Accessed December 2014. 

U.S. Geological Survey. 1955. Moss Lake Quadrangle, Louisiana, 7.5-Minute Series [map]. 1:24,000. 

Reston, Virginia.
APPENDIX D

REFERENCES AND CONTACTS (cont’d)

D-16

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 December 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. 2006. ShakeMap Manual: Technical Manual, Users Guide, and Software Guide. 

Available online at http://pubs.usgs.gov/tm/2005/12A01/. Accessed April 2014.

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://minerals.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. 2012. Moss Lake Quadrangle, Louisiana, 7.5-Minute Series [map]. 1:24,000. 

Reston, Virginia.

U.S. Geological Survey. 2013a. 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. 2013b. Mineral Resource Data System. Available online at http://mrdata.

usgs.gov/mineral-resources/mrds-us.html. Accessed April 2014.

U.S. Geological Survey. 2013c. South Central Amphibian Research and Monitoring Initiative Guide to 

Louisiana Amphibians, Frogs and Toads (Order Anura). Available online at

http://www.nwrc.usgs.gov/topics/sc_armi/frogs_and_toads/index.html. Accessed February 2015. 

U.S. Global Change Research Program. 2014. Climate Change Impacts in the United States, U.S. National 

Climate Assessment. Available online at http://nca2014.globalchange.gov/report. Accessed 

May 2015.

USA Cops. 2015. Parish Police and Sheriff’s Departments. Available online at http://www.usacops.

com/la/. Accessed March 2015.

USA.com. 2015. 2010 County Census Tract Data. Available at http://www.usa.com/. Accessed March 2015.

Whale and Dolphin Conservation Society. 2004. Oceans of Noise 2004 – A WDCS Science Report. Eds.

M. Simmonds, S. Dolman, and L. Weilgart. Wiltshire, England. 

Yellow Pages. 2015. Louisiana, RV Park. Available online at http://www.yellowpages.com/

search?search_terms=rv+park&geo_location_terms=Lake+Charles%2C+LA. Accessed March 2015.
APPENDIX E 

LIST OF PREPARERS 

APPENDIX E

LIST OF PREPARERS

E-1

Federal Energy Regulatory Commission

Cefalu, Janine – Environmental Project Manager, Proposed Action, Water, Wetlands, Fisheries, 

Wildlife, Vegetation, Special Status Species, Socioeconomics

M.E.S., Environmental Studies, 2005, The Evergreen State College

B.A., International Relations, 1996, San Francisco State University

Kopka, Robert – Deputy Project Manager, Alternatives, Land Use, Recreation, Visual Resources, 

Cumulative Impacts

M.S., Soil Science, 1990, Cornell University

B.S., Agronomy, 1987, Delaware Valley College of Science and Agriculture

Anis, Shahid – Air Quality and Noise, Pipeline Reliability and Safety

M.S., Energy, Resources, and Environment, 1977, George Washington University

B.S., Mechanical Engineering, 1974, University of Maryland

Armbruster, Ellen – Cultural Resources

M.A., Anthropology, 1986, University of Pennsylvania

B.A., Anthropology, 1979, Bryn Mawr College

Glaze, James – Geology, Soils

B.S., Geology, 1975, California Lutheran University

Patel, Ghanshyam – Liquefied Natural Gas (LNG) Reliability and Safety

B.S., Chemical Engineering, 2004, Pennsylvania State University

Silvera, Liliana – LNG Reliability and Safety

B.S., Chemical Engineering, 2003, University of Maryland

Natural Resource Group, LLC

Rieland, Janelle – Project Manager, Quality Assurance Review, Introduction, Proposed Action

B.S., Wildlife and Fisheries, 2002, University of Minnesota, Twin Cities

Piper, Erin – Deputy Project Manager, Special Status Species, Fisheries, Wildlife

M.S., Oceanography, 2010, Texas A&M University, Texas

B.S., Ocean and Coastal Resources, 2007, Texas A&M University, Galveston, Texas

Brown, Larry – Cumulative Impacts

B.S., Biology, 1981, Bates College

Buckless, Michael – Geology, Soils

B.S., Environmental Soil Science and Management, 2013, University of Rhode Island

D’Auben, Dan, P.E. – Air Quality

B.S., Mechanical Engineering, 1973, University of Illinois, Urbana, Illinois

Enright, Troy – Noise

B.S., Environmental Science, 2003, University of Minnesota, Twin Cities
APPENDIX E

LIST OF PREPARERS (cont’d)

E-2

Hacker, Miriam – Air Quality

M.S., Civil and Environmental Engineering, 1995, University of Wisconsin

B.A., Mathematics, 1991, Skidmore College

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, Twin Cities

Koester, Mike – Pipeline Reliability and Safety

B.S., Environmental Management, 2001, University of South Alabama

Lyons, Tina – Quality Assurance Review, Technical Editor, Socioeconomics

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, Stony Brook

Thomas, Lindsay – Land Use, Recreation, Visual Resources, Socioeconomics

B.S., Biological Engineering, 2007, Louisiana State University, Baton Rouge, Louisiana

Throndson, Sara – Surface Water, Wetlands, Vegetation

M.S., Soil Science, 2007, University of Minnesota, Twin Cities

B.S., Environmental Studies, 2002, Northland College, Ashland, Wisconsin