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Corpus Christi Liquefaction, LLC Cheniere Corpus Christi Pipeline, L.P.

Stage 3 Project

DRAFT Resource Report 1 — General Project Description Docket No. PF15-26-000

July 2015

RESOURCE REPORT 1 – GENERAL PROJECT DESCRIPTION

STAGE 3 PROJECT

Corpus Christi Liquefaction, LLC i July 2015

Cheniere Corpus Christi Pipeline, L.P.

TABLE OF CONTENTS

Section Page

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

LIST OF APPENDICES ............................................................................................................................... ii

LIST OF TABLES ........................................................................................................................................ ii

LIST OF FIGURES ...................................................................................................................................... ii

ACRONYMS AND ABBREVIATIONS .................................................................................................... iii

CHECKLIST OF FILING REQUIREMENTS ............................................................................................. v

1.0 PROJECT DESCRIPTION ........................................................................................................... 1-1

1.1 INTRODUCTION ........................................................................................................... 1-1

1.2 PURPOSE AND NEED ................................................................................................... 1-1

1.3 LOCATION AND DESCRIPTION OF PROPOSED FACILITIES ............................... 1-2 1.3.1 LNG Facilities ................................................................................................. 1-2 1.3.2 Pipeline Facilities ............................................................................................ 1-7

1.4 PROJECT MAPS AND DRAWINGS ............................................................................. 1-8

1.5 LAND REQUIREMENTS............................................................................................. 1-13 1.5.1 LNG Facilities ............................................................................................... 1-13 1.5.2 Pipeline Facilities .......................................................................................... 1-15

1.6 CONSTRUCTION SCHEDULE AND WORKFORCE ............................................... 1-18

1.7 CONSTRUCTION PROCEDURES .............................................................................. 1-18 1.7.1 Stage 3 LNG Facilities .................................................................................. 1-19 1.7.2 Pipeline Facilities .......................................................................................... 1-21

1.8 OPERATIONS AND MAINTENANCE ....................................................................... 1-26 1.8.1 Stage 3 Project LNG Facilities ...................................................................... 1-26 1.8.2 Pipeline .......................................................................................................... 1-27

1.9 FUTURE PLANS AND ABANDONMENT ................................................................ 1-28 1.9.1 Future Plans ................................................................................................... 1-28 1.9.2 Abandonment of Facilities............................................................................. 1-28

1.10 PERMITS AND APPROVALS ..................................................................................... 1-28

1.11 AFFECTED LANDOWNERS ...................................................................................... 1-30

1.12 NONJURISDICTIONAL FACILITIES ........................................................................ 1-30 1.12.1 Identified Nonjurisdictional Facilities ........................................................... 1-30 1.12.2 Determination of the Need for FERC to Conduct an Environmental

Review ........................................................................................................... 1-30

1.13 CUMULATIVE EFFECTS ........................................................................................... 1-31 1.13.1 Other Projects Potentially Contributing to Cumulative Effects ..................... 1-33 1.13.2 Potential Cumulative Effects ......................................................................... 1-37

1.14 REFERENCES AND CONTACTS ............................................................................... 1-40


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Corpus Christi Liquefaction, LLC ii July 2015


LIST OF APPENDICES

Appendix 1A Agency Correspondence

Appendix 1B Adjacent and Affected Landowners (Privileged and Confidential)

LIST OF TABLES

Table 1.3-1 Summary of Proposed Stage 3 Pipeline and Appurtenant Facilities................................ 1-7 Table 1.5-1 Land Requirements for the Stage 3 Project Liquefaction Facilities .............................. 1-13 Table 1.5-2 Land Requirements for the Stage 3 Pipeline and Associated Facilities ......................... 1-17 Table 1.10-1 Permits and Consultations for the Stage 3 Project ......................................................... 1-29 Table 1.13-1 Other Projects Potentially Contributing to Cumulative Impacts.................................... 1-34 Table 1.13-2 Cumulative Impacts of the Stage 3 and Other Projects in the Project Area .................. 1-38

LIST OF FIGURES

Figure 1.3-1 Artist Impression of Stage 3 Project (view to the South) ................................................ 1-3 Figure 1.3-2 Artist Impression of Stage 3 Project (foreground) and Liquefaction Project

(background) (view to the South) .................................................................................... 1-6 Figure 1.4-1 Project Location Map ....................................................................................................... 1-9 Figure 1.4-2 Terminal Site Plan ......................................................................................................... 1-10 Figure 1.4-3 LNGC Transit Route ...................................................................................................... 1-11 Figure 1.4-4 Stage 3 Pipeline Route ................................................................................................... 1-12 Figure 1.5-1 Land Requirements for Stage 3 Project LNG Facilities ................................................ 1-14 Figure 1.5-2 Stage 3 Pipeline Right-of-Way ...................................................................................... 1-16


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Corpus Christi Liquefaction, LLC iii July 2015


ACRONYMS AND ABBREVIATIONS

AEP American Electric Power

API American Petroleum Institute

AQCR air quality control regions

ASME American Society of Mechanical Engineers

ATWS additional temporary workspace

Bcf/d billion standard cubic feet per day

BTEX benzene, toluene, ethylbenzene, and xylene

CEII critical energy infrastructure information

CEQ Council on Environmental Quality

CFR Code of Federal Regulations

CCL Corpus Christi Liquefaction, LLC

CCPL Cheniere Corpus Christi Pipeline, L.P.

CI Chief Inspector

CMMS computerized maintenance management system

CO2 carbon dioxide

Commission Federal Energy Regulatory Commission

DLE dry low emissions

DMPA Dredged Material Placement Area

DRI Direct Reduced Iron

EI Environmental Inspector

ESD emergency shutdown

EPA U.S. Environmental Protection Agency

FERC Federal Energy Regulatory Commission

GOM Gulf of Mexico

H2S hydrogen sulfide

HDD horizontal directional drill

hp horsepower

HUC Hydrologic Unit Code

LNG liquefied natural gas

LNGC LNG carrier

m3

cubic meters

M&R meter and regulation

MAOP maximum allowable operating pressure

MLV mainline valve

MMcf/d million cubic feet per day

MP milepost

MW megawatts

NFPA National Fire Protection Association

NGA Natural Gas Act

NGL Natural Gas Liquids


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Corpus Christi Liquefaction, LLC iv July 2015


NPDES National Pollution Discharge Elimination System

OEP Office of Energy Projects

O&M operations and maintenance

PCB polychlorinated biphenyls

PERC powered emergency release coupling

POCCA Port of Corpus Christi Authority

Plan FERC’s Upland Erosion Control, Revegetation, and Maintenance Plan

Procedures FERC’s Wetland and Waterbody Construction and Mitigation Procedures

Project Stage 3 Project and Stage 3 Pipeline

psig pounds per square inch gauge

Stage 3 Pipeline 22-mile-long, 42-inch-diameter pipeline

Stage 3 Project proposed expansion of the Corpus Christi Liquefaction Project

T&E threatened and endangered

TCEQ Texas Commission on Environmental Quality

TEU twenty-foot equivalent unit

USACE U.S. Army Corps of Engineers

USCG U.S. Coast Guard

USDOT U.S. Department of Transportation


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Corpus Christi Liquefaction, LLC v July 2015



Filing Requirement Location in

Environmental Report

1. Provide a detailed description and location map of the project facilities. (§ 380.12(c)(1))

Include all pipeline and aboveground facilities.

Include support areas for construction or operation.

Identify facilities to be abandoned.

Sections 1.3 and 1.4; Figure

1.4-1 and Figure 1.4-2

2. Describe any nonjurisdictional facilities that would be built in association with the

project.(§ 380.12(c)(2))

Include auxiliary facilities (See § 2.55(a)).

Describe the relationship to the jurisdictional facilities.

Include ownership, land requirements, gas consumption, megawatt size, construction status, and an update of the latest status of Federal, state, and local

permits/approvals.

Include the length and diameter of any interconnecting pipeline.

Apply the four-factor test to each facility (see § 380.12(c) (2) (ii)).

Section 1.12

3. Provide current original U.S. Geological Survey (USGS) 7.5-minute-series topographic

maps with mileposts showing the project facilities. (§ 380.12(c)(3))

Maps of equivalent detail are acceptable if legible (check with staff)

Show locations of all linear project elements, and label them.

Show locations of all significant aboveground facilities, and label them.

Section 1.4, Appendix 1A

4. Provide aerial images or photographs or alignment sheets based on these sources with

mileposts showing the project facilities. (§ 380.12(c)(3))

No more than 1-year old

Scale no smaller than 1:6,000

Future Draft of Resource

Report 1

5. Provide plot/site plans of compressor stations showing the location of the nearest noise

sensitive areas (NSA) within 1 mile. (§ 380.12(c)(3,4))

Scale no smaller than 1:3,600

Show reference to topographic maps and aerial alignments provided above.

NSA figures in Resource

Report 9

6. Describe construction and restoration methods. (§ 380.12(c)(6))

Include this information by milepost

Make sure this is provided for offshore construction as well. For the offshore construction, this information is needed on a mile-by-mile basis and will require completion of geophysical and other surveys before filing.

Section 1.7

7. Identify the permits required for construction across surface waters. (§ 380.12(c)(9))

Include the status of all permits.

For construction in the Federal offshore area be sure to include consultation with the MMS. File with the MMS for rights-of-way grants at the same time or before

you file with the FERC.

Section 1.10

8. Provide the names and address of all affected landowners and certify that all affected

landowners will be notified as required in § 157.6(d). (§ 380.12(c)(10))

Affected landowners are defined in § 157.6(d)

Provide an electronic copy directly to the environmental staff.

Section 1.11,

Appendix 1B

9. Describe all authorizations required to complete the proposed action and the status of applications for such authorizations.

Section 1.10


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Corpus Christi Liquefaction, LLC vi July 2015



Filing Requirement Location in

Environmental Report

10. Provide detailed typical construction right-of-way cross-section diagrams showing

information such as widths and relative locations of existing rights-of-way, new permanent

right-of-way, and temporary construction right-of-way. See Resource Report 8.

Figure 1.5-2

11. Summarize the total acreage of land affected by construction and operation of the

project.

Section 1.5

12. If Resource Report 5, Socioeconomics is not provided, provide the start and end dates of

construction, the number of pipeline spreads that would be used, and the workforce per

spread.

Section 1.6; also see Resource

Report 5

13. Send two (2) additional copies of topographic maps and aerial images/photographs

directly to the environmental staff of the Office of Energy Projects (OEP).

Future Draft of Resource

Report 1

14. Identify other projects in the area that could contribute to cumulative impacts. Section 1.13


STAGE 3 PROJECT

Corpus Christi Liquefaction, LLC 1-1 July 2015


1.0 PROJECT DESCRIPTION

1.1 INTRODUCTION

Corpus Christi Liquefaction, LLC (“CCL”) and Cheniere Corpus Christi Pipeline, L.P. (“CCPL”) propose

to construct and operate an expansion (“Stage 3 Project”) of the Corpus Christi Liquefaction Project

approved by the Federal Energy Regulatory Commission (“FERC” or “Commission”) in Docket No.

CP12-507-000 and currently under construction (“Liquefaction Project”), as well as new associated bi-

directional interstate natural gas pipeline facilities (“Stage 3 Pipeline”). The Stage 3 Project consists of

the addition of two liquefaction trains and a fourth liquefied natural gas (“LNG”) tank to the Liquefaction

Project. In order to deliver feed gas to the Stage 3 Project, CCPL is proposing to construct and operate

the Stage 3 Pipeline, a new 22-mile-long, 42-inch-diameter pipeline that would run parallel to the

48-inch-diameter Corpus Christi Pipeline approved by the Commission in Docket No. CP12-508-000.

The Stage 3 Project and Stage 3 Pipeline are referred to collectively as the “Project”.

Resource Report 1 describes the facilities associated with the Project, the purpose and need for the

Project, land requirements, construction procedures, operation procedures, Project schedule, permits and

approvals that will be required, non-jurisdictional facilities, and cumulative effects. Resource Reports 2

through 9 describe the resources at the Project site, the potential impacts on those resources from

construction and operation of the Project, and measures proposed to mitigate those impacts. Resource

Report 10 describes the “No Action” alternative as well as possible system and facility siting and

configuration alternatives. Resource Report 11 describes the design, construction, operation, and

maintenance measures to maximize Project reliability and minimize potential hazards to the public from

failure of Project components as a result of accidents or natural catastrophes. Resource Report 12,

pertaining to polychlorinated biphenyls (“PCB”), is not applicable, as the Project does not involve the

removal, replacement, or abandonment of PCB-contaminated facilities. Resource Report 13 provides a

detailed description of the liquefaction facilities, as well as detailed engineering and design information.

Two versions of Resource Report 13 are included with the Stage 3 Project Application, a public version

and a version that contains critical energy infrastructure information (“CEII”) or confidential and

proprietary engineering and design material that will not be available to the public.

1.2 PURPOSE AND NEED

The natural gas industry in the U.S. has enjoyed significant growth the past several years based on

technological improvements that have made the exploration and production of gas more economical.

International demand for natural gas has been enhanced by its favorable environmental properties

compared to many fuels and its potential role as a backup fuel to intermittent renewable energy sources.

Developing economies around the world are also in need of low-cost, environmentally-friendly fuels to

facilitate growth.

The Project would be consistent with ongoing development of U.S. natural gas resources and expanding

access to world markets. The ability to export domestic gas as LNG greatly expands the market scope and

access for domestic natural gas producers.


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1.3 LOCATION AND DESCRIPTION OF PROPOSED FACILITIES

The following sections provide detailed descriptions of the LNG facilities (Section 1.3.1) and pipeline

facilities (Section 1.3.2) associated with the Project.

1.3.1 LNG Facilities

The facilities to be constructed for the Stage 3 LNG Facilities include LNG liquefaction facilities

(Section 1.3.1.1), LNG storage facilities (Section 1.3.1.2), and other infrastructure (Section 1.3.1.3). All

components will be sited, constructed, operated, and maintained in accordance with applicable federal and

state regulations. The Stage 3 LNG Facilities will utilize the marine facilities currently authorized for the

Liquefaction Project (Section 1.3.1.4).

1.3.1.1 Liquefaction Facilities

The liquefaction portion of the Stage 3 Project will consist of two ConocoPhillips Optimized Cascade®

LNG liquefaction trains designed to produce a maximum of approximately 5 million tonnes per annum of

LNG. The LNG liquefaction trains will be an identical design to those being constructed for the

Liquefaction Project.

Each LNG liquefaction train will contain the following equipment:

Facilities to remove carbon dioxide, hydrogen sulfide and other sulfur compounds from the feed

gas;

Facilities to remove water and mercury from the feed gas;

Facilities to remove heavy hydrocarbons from the feed gas;

A thermal oxidizer for combusting waste gas;

Six aeroderivative mechanical drive LM2500 G4+ gas turbines with dry low emissions (“DLE”)

combustion systems for emissions control;

Inlet air chilling exchanger for gas turbines;

Multiple ethylene, propane and methane refrigerant compressors and associated cold boxes;

Waste heat recovery systems;

Induced draft air coolers;

Associated fire and gas and safety systems; and

Associated control systems and electrical infrastructure.


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Figure 1.3-1 Artist Impression of Stage 3 Project (view to the South)

Impurities removed from the natural gas stream prior to liquefaction will be disposed of as follows:

Benzene, toluene, ethylbenzene, and xylene (“BTEX”) and acid gas are passed through a triazine

scavenger bed which absorbs any hydrogen sulfide (“H2S”). The remaining waste gas (with

carbon dioxide [“CO2”) is then mixed with a small amount of fuel gas and sent to a thermal

oxidizer. The spent solvent is sent to a licensed disposal facility.

Mercury is absent from the feed gas. However, as a precaution, mercury removal beds will be

provided, and any collected will be sent to a licensed disposal facility.

1.3.1.2 LNG Storage

The LNG will be stored in one full-containment storage tank. The tank will be designed to store a

nominal volume of 160,000 cubic meters (m3) (1,006,400 barrels) of LNG at a temperature of -270ºF and

a maximum internal pressure of 3.5 pounds per square inch gauge (“psig”) (though the normal operating

conditions will be -260ºF and 1.5 psig). The tank system will meet the requirements of National Fire

Protection Association (“NFPA”) 59A, 49 Code of Federal Regulations (“CFR”) Part 193, and American

Petroleum Institute (“API”) Standard 620 Appendix Q. A typical full containment LNG storage tank is

shown in a figure included in Appendix 1A. The major components of the tank will consist of:

A 9% nickel steel inner container, designed to withstand the hydrostatic pressures and cryogenic

temperatures of the LNG, as well as the predicted seismic, insulation, and thermal gradient loads.

The space between the inner container and the outer container will be insulated with expanded

perlite to maintain the outer container at near ambient temperature. The insulation beneath the

inner container will be cellular glass load-bearing insulation that will support the weight of the

inner container and the LNG.


STAGE 3 PROJECT



An outer tank comprised of reinforced concrete with a domed concrete roof. The outer tank is

designed for the following conditions:

o The specified internal pressure of 3.5 psig;

o Sustained wind velocity of 150 miles per hour without the loss of structural or functional

integrity, which meets or exceeds the requirements of 49 CFR § 193.2067;

o Seismic loads in accordance with NFPA 59A and the site specific seismic reports;

o Internal pressure imposed by insulation loads; and

o Roof and platform dead loads.

An insulated aluminum deck over the inner container, suspended from the roof. The aluminum

support deck will be insulated with fiberglass blankets so that the outer tank roof and vapor space

above the suspended deck are essentially at ambient temperature. The vapor pressure from the

LNG will be equalized through ports in the suspended deck and will be contained by the outer

container.

The tank will be supported on a reinforced concrete foundation. Electric base heating will be installed in

the concrete foundation to prevent frost heave.

Tank Accessories

Five in-tank pump well columns will be installed in the tank. Four pump well columns will be fully

installed with foot valve, electrical, supports, instrumentation, piping, etc., for a complete system. The

fifth pump well column will be equipped with a foot valve only for a future spare pump. All LNG piping

will enter the tank through the concrete tank roof. All piping systems will be in accordance with

American Society of Mechanical Engineers (“ASME”) B31.3 and NFPA 59A Chapter 6.

The LNG tank will also be provided with the following accessories:

A cool down temperature detection system to monitor the inner tank bottom plate and inner tank

shell continuously during cool-down procedures;

Foundation temperature sensors located at strategic locations under the tank;

Instrumentation to monitor the quality and level of LNG in the tank and to monitor tank contents

for stratification;

A safety-rated control system to monitor the LNG level and control the fill line shutoff valves;

Pressure and vacuum relief systems;

Platforms, elevators, and stairways with intermediate landings attached to the outer tank;

Spill protection of the tank roof over the edge of the roof dome;

Lighting and aircraft warning lights;

Electrical grounding system;


STAGE 3 PROJECT



A settlement monitoring system to measure and record inner and outer container movements

during construction, hydrostatic testing, and operation; and

Seismic monitors.

Although the LNG storage tank is full containment and does not require additional full spill containment

per code, a berm will be constructed around the LNG storage tank and LNG trains to contain 100 percent

of the volume of the LNG storage tank.

1.3.1.3 Other Terminal Infrastructure

In addition to the facilities listed above, the Project will require the following terminal facilities and

infrastructure:

Expansion of Liquefaction Project control building to accommodate Stage 3 Project facilities;

Miscellaneous buildings and other structures to accommodate employees, equipment, utilities and support services infrastructure;

Warehouse to store spare parts and consumables for the liquefaction, regasification and utility facilities;

Maintenance building;

Remote I/O buildings and substations;

Storage tanks for ethylene refrigerants, amine make up and liquid nitrogen;

Spill containment facilities;

Emergency shutdown (“ESD”) systems;

Firewater system, including diesel driven pumps and storage tank;

Wet and dry flares;

Instrument air compressor packages;

Security and perimeter control systems;

Telecoms, IT, CCTV and other systems;

Potable water, service water, and demineralized water systems;

Pipeline gas compressor;

Inlet air chilling equipment;

Pipeline interconnect for the receipt of natural gas as well as export to the pipeline;

Electric facilities, switchgear, transformers, and other electrical accessories; and

LNG transfer line to Liquefaction Project storage tanks.


STAGE 3 PROJECT



Figure 1.3-2 Artist Impression of Stage 3 Project (foreground) and Liquefaction Project (background)

(view to the South)

1.3.1.4 Marine Facilities

The marine terminal facilities required for mooring and loading LNG carriers (“LNGCs”) for the Stage 3

Project will be the same facilities utilized by the currently-authorized the Liquefaction Project. No new

marine facilities will be required for the Stage 3 Project.

The only impact that the Stage 3 Project will have on marine operations is an anticipated increase in the

maximum marine vessel traffic from the currently-authorized 300 LNGCs up to 400 LNGCs per year.

CCL has been in contact with the U.S. Coast Guard (“USCG”) and is preparing a follow-on Waterway

Suitability Assessment for submittal to the USCG to seek approval for the increase of 100 LNGCs per

year.

The same tugs used for the currently-authorized Liquefaction Project will be available to facilitate

maneuvering of LNGCs for the Stage 3 Project.

Deepwater access from the Gulf of Mexico (“GOM”) to the Stage 3 Project is via a federally-maintained

channel that extends from the open GOM, through the entrance jetties at Aransas Pass, along the Corpus

Christi Ship Channel and up the La Quinta Ship Channel. This is the same route already analyzed by the


STAGE 3 PROJECT



USCG for the currently-authorized Liquefaction Project. The general access route is shown on Figure 1.4-

3.

1.3.2 Pipeline Facilities

The Stage 3 Pipeline will consist of:

An approximately 22-mile-long, 42-inch-diameter pipeline originating north of the City of

Sinton, Texas and terminating at the Stage 3 Project LNG facilities;

Additional compression at the Sinton Compressor Station;

Appurtenant facilities including metering, pressure regulation and filter separation;

Launcher/receiver facilities at both ends of the 22-mile-long pipeline; and

Mainline valve (“MLV”) facilities.

The Stage 3 Pipeline operating facilities will be designed for a maximum allowable operating pressure

(“MAOP”) of 1,440 psig and a capacity of approximately 1.5 billion standard cubic feet per day

(“Bcf/d”). The pipeline facilities will be located entirely within San Patricio County, Texas.

The Stage 3 Pipeline facilities are summarized in Table 1.3-1 and are described in detail in the following

sections.

TABLE 1.3-1

Summary of Proposed Stage 3 Pipeline and Appurtenant Facilities

Facility Length (miles)

Diameter (inches)

Location (MP)

Megawatts Description

Pipeline

Stage 3 Pipeline 22.0 42 N/A N/A New pipeline to connect Stage 3 Project LNG facilities to natural gas pipeline supply points

Compressor Station

Sinton Compressor Station Expansion

N/A N/A 22.0 32 Electric motor drive compression

Meter and Regulation Stations

Stage 3 LNG Facilities M&R Station

N/A N/A 0.0 N/A Install M&R station to feed gas into the Stage 3 Project LNG Facilities

M&R Stations N/A N/A TBD N/A TBD

Appurtenant Facilities

Pig Launcher N/A 42 22.0 N/A Pig launcher at Stage 3 Liquefaction M&R Station

Pig Receiver N/A 42 0.0 N/A Pig receiver at pipeline terminus

Mainline Valves N/A 42 TBD N/A TBD

N/A – not applicable.

TBD – to be determined.


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1.3.2.1 Pipeline

CCPL will construct approximately 22 miles of new 42-inch-diameter natural gas pipeline, originating at

the Sinton Compressor Station and generally routed parallel to the currently-authorized 48-inch-diameter

Corpus Christi Pipeline (Docket Number CP12-508-000). The Stage 3 Pipeline will terminate at the Stage

3 Project LNG facilities.

1.3.2.2 Compressor Station

The Sinton Compressor Station has been authorized and is being built as part of the Liquefaction Project

(Docket Numbers CP12-507-000 and CP12-508-000). The Stage 3 Pipeline will require additional

compression at the Sinton Compressor Station, which will consist of the addition of approximately 32

megawatts (“MW”) of electric motor drive compression (two 16 MW units). The Sinton Compressor

Station, including the facilities to be added for the Stage 3 Project, will be remotely operated.

1.3.2.3 Meter and Regulation Stations

CCPL is still in the process of pipeline design and therefore has not identified the locations of all meter

and regulation (“M&R”) stations. Typically these will be installed at locations where the Stage 3 Pipeline

intersects other third-party pipelines. CCPL will provide additional information on these facilities in a

subsequent version of Resource Report 1. Typically, these M&R stations are remotely operated and the

following facilities are installed.

M&R facilities;

Filter separators;

Liquid handling tanks;

Gas chromatograph building; and

Pressure/flow control.

1.4 PROJECT MAPS AND DRAWINGS

The general location of the proposed Stage 3 Project is shown in Figure 1.4-1, and a site plan drawing for

the Stage 3 Project LNG Facilities is shown in Figure 1.4-2. Figure 1.4-3, LNGC Transit Route, identifies

the LNGC route from the U.S. territorial waters to the marine berth approved as part of the Liquefaction

Project. Figure 1.4-4 identifies the Stage 3 Pipeline route. Figure 1.5-1 identifies land requirements for

the Stage 3 LNG Facilities. Figure 1.5-2 is an illustration of the Stage 3 Pipeline right-of-way.


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Figure 1.4-1 Project Location Map


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Figure 1.4-2 Terminal Site Plan


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Figure 1.4-3 LNGC Transit Route


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Figure 1.4-4 Stage 3 Pipeline Route


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1.5 LAND REQUIREMENTS

The land requirements for the Stage 3 LNG Facilities and Stage 3 Pipeline are presented in Sections 1.5.1

and 1.5.2, respectively.

1.5.1 LNG Facilities

Nearly all of the Stage 3 LNG facilities will be constructed within Dredged Material Placement Area

(“DMPA”) 2, which was formerly used as a bauxite residue disposal bed and has been authorized for use

for dredged material placement for the construction of the marine berths for the Liquefaction Project.

DMPA 2 is approximately 385 acres in size.

Table 1.5-1 lists the land requirements for the Stage 3 Project Liquefaction Facilities. Construction of the

Stage 3 Project LNG facilities will require approximately 826 acres of land, of which 658 acres (80%)

will have been impacted by the currently-authorized Liquefaction Project. Operation of the Stage 3

Project will require approximately 368 acres of land, of which 351 acres was previously approved for

operation of the Liquefaction Project. Details on any necessary exclusion zones have not yet been

finalized and will be provided in a subsequent version of Resource Report 1.

TABLE 1.5-1

Land Requirements for the Stage 3 Project Liquefaction Facilities

Facility

Construction Operation

Land Impacted by Liquefaction Project (acres)

New Land Impacts (acres)

Total (acres)

Land Impacted by Liquefaction Project (acres)

New Land Impacts (acres)

Total (acres)

Stage 3 LNG Facilities 351 17 368 351 17 368

Construction Parking / Laydown Areas

307 151 458 0 0 0

Total 658 168 826 351 17 368


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Figure 1.5-1 Land Requirements for Stage 3 Project LNG Facilities


STAGE 3 PROJECT




The land requirements for the Stage 3 Pipeline facilities are presented in the following sections.

1.5.2.1 Pipeline

The proposed 42-inch-diameter Stage 3 Pipeline will be installed generally parallel to the previously-

approved 48-inch-diameter Corpus Christi Pipeline. The Stage 3 Pipeline will be constructed utilizing a

nominal 105-foot-wide construction right-of-way and a permanent right-of-way width of 75 feet shared

with the 48-inch-diameter Corpus Christi Pipeline. In wetlands, the construction right-of-way will be a

nominal 75 feet wide.

The 105-foot-wide nominal pipeline construction right-of-way is necessary to accommodate the trench

depth and width necessary to install a 42-inch-diameter pipe and to accommodate the segregation of

topsoil along much of the length of the pipeline. The proposed right-of-way will also provide heavy

equipment operators the necessary workspace to maintain safe and efficient separation distances between

the potentially unstable trench sidewalls and their equipment. In addition, this workspace will ensure that

heavy equipment has adequate separation between the construction activities and the parallel 48-inch-

diameter Corpus Christi Pipeline and other nearby foreign pipelines.

Additional temporary work space (“ATWS”) areas of varying dimensions (located immediately adjacent

to the proposed nominal right-of-way) will also be required to account for site-specific constructability

issues such as road and waterbody crossings.

Following construction, 25 feet of additional permanent easement will be required adjacent to the 50-foot-

wide permanent easement for the 48-inch-diameter pipeline, making the total permanent easement 75 feet

wide. The remaining 80 feet of temporary workspace and all of the ATWS areas utilized during

construction will be allowed to return to pre-construction land use.

Figure 1.5-2 shows the configuration of the workspace for the 42-inch-diameter and 48-inch-diameter

pipelines. Table 1.5-2 shows the workspace acreages associated with construction and operation of the

Stage 3 Pipeline facilities.


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Figure 1.5-2 Stage 3 Pipeline Right-of-Way


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TABLE 1.5-2

Land Requirements for the Stage 3 Pipeline and Associated Facilities

Facility

Construction Operation

Land Impacted by Liquefaction

Project (acres)

New Land

Impacts (acres)

Total (acres)

Land Impacted by Liquefaction

Project (acres)

New Land

Impacts (acres)

Total (acres)

Pipeline Right-of-Way

Pipeline 213.3 110 323.3 0 110 110

Additional Temporary Workspace 0 38 38 0 0 0

Compressor Station

Sinton Compressor Station 17.2 9.3 26.5 7.3 TBD TBD

M&R Stations

Liquefaction M&R Station (MP 0.0) TBD TBD TBD TBD TBD TBD

M&R Stations TBD TBD TBD TBD TBD TBD

Launchers/MLVs

Pig Launcher and MLV (MP 0.0) 0 0 0 0 0 0

Pig Receiver and MLV (MP 22.0) 0 0 0 0 0 0

Access Roads/Yards

Access Roads TBD TBD TBD TBD TBD TBD

Contractor and Pipe Yard TBD TBD TBD 0 0 0

Total

TBD – to be determined.

1.5.2.2 Compressor Station

The Sinton Compressor Station is being constructed as part of the currently-authorized 48-inch-diameter

Corpus Christi Pipeline. The new Stage 3 facilities at the Sinton Compressor Station will be constructed

within a 26.5 acre area, of which 17.2 acres is within the existing Sinton Compressor Station boundary

and 9.3 acres are new impacts associated with the Stage 3 Pipeline. New land impacts associated with

operation of the Sinton Compressor Station have yet to be determined.

1.5.2.3 M&R Stations

The details of the M&R stations are still under development. M&R stations will be required at the Stage 3

LNG Facilities to source the 1.5 Bcf/d of gas to the terminal. There will also be an expansion to the

existing M&R station at the terminus of the Stage 3 Pipeline.


STAGE 3 PROJECT



1.5.2.4 Launcher/Receiver

CCPL will construct and operate permanent pig launcher/receiver facilities at each end of the Stage 3

Pipeline. The launcher and receiver will not have additional land requirements outside of the pipeline

right-of-way.

1.5.2.5 Mainline Valves

The placement of MLV’s along the Stage 3 Pipeline is under development and will be provided in a

subsequent version of Resource Report 1. The MLVs will be located within the permanent easement of

the Stage 3 Pipeline and will generally require a construction and operation area of 0.2 acre.

1.6 CONSTRUCTION SCHEDULE AND WORKFORCE

CCL anticipates starting construction of the Stage 3 LNG Facilities in the 2nd

Quarter of 2017.

Construction of the Stage 3 LNG Facilities is estimated to take approximately 3.5 years to complete.

Construction of the Stage 3 Pipeline and aboveground facilities is expected to take approximately one

year to complete. The Stage 3 Pipeline is currently planned for a start of construction in the 2nd

Quarter

of 2018.

Information regarding anticipated construction workforce is provided in Resource Report 5.

1.7 CONSTRUCTION PROCEDURES

All Project components will be sited, constructed, operated, and maintained in accordance with all

applicable federal and state regulations. The Stage 3 Project will implement and adhere to the FERC’s

Upland Erosion Control, Revegetation, and Maintenance Plan (“Plan”) and the Wetland and Waterbody

Construction and Mitigation Procedures (“Procedures”)1. Wetland areas that will be temporarily or

permanently impacted during construction and operation of the Project will be mitigated as agreed upon

with the state and federal resource and regulatory agencies. Wetland impacts and mitigation will be

addressed in a Project wetland mitigation plan. CCL and CCPL will work with the U.S. Army Corps of

Engineers (“USACE”) to develop any necessary mitigation plan.

CCL and CCPL will employ a tracking system to ensure that relevant clearances and permits are received

prior to requesting approval to begin construction from the FERC. For purposes of quality assurance and

compliance with mitigation measures, other applicable regulatory requirements, and Project

specifications, the Stage 3 Project will be represented on site by a Chief Inspector (“CI”). One or more

craft inspectors and one or more Environmental Inspectors (“EIs”) will assist the CI. All Stage 3 Project

inspectors will have access to the relevant compliance specifications and other documents contained in

the construction contracts. The EI’s duties will be fully consistent with those contained in paragraph II.B

(Responsibilities of the Environmental Inspector) of the Plan to ensure that the environmental conditions

associated with other permits or authorizations are satisfied. The EI(s) will have authority to stop work or

1 Available on the FERC website at: http://www.ferc.gov/industries/gas/enviro/guidelines.asp.


STAGE 3 PROJECT



require other corrective action(s) to achieve environmental compliance. In addition to monitoring

compliance, the EI’s duties will include training Project personnel about environmental requirements and

reporting compliance status to the contractors, Stage 3 Project management, the FERC, and other

agencies, as required.

An environmental training program tailored to construction and management personnel will be

developed. The program will be designed to ensure that:

Qualified environmental training personnel provide thorough and well-focused training sessions

regarding the environmental requirements applicable to the trainees’ activities;

All individuals receive environmental training before they begin work;

Adequate training records are kept; and

Refresher training is provided as needed to maintain high awareness of environmental

requirements.

1.7.1 Stage 3 LNG Facilities

1.7.1.1 Temporary Construction Facilities

The main construction offices will be located either on-site or in a nearby construction laydown or

parking area approved by the Commission for construction use. Support/satellite offices, warehousing,

lunchrooms, temporary access roads, parking lots, and material laydown storage will be erected as

necessary to support craft labor.

Additional temporary facilities, primarily laydown areas and parking, will be located on site or in close

proximity to the site. Detailed information regarding temporary use areas will be provided in Resource

Report 8.

1.7.1.2 LNG Facilities (LNG Trains)

There are two critical paths for this Project; the erection of the ConocoPhillips Optimized Cascade® LNG

Trains and the construction of the full containment tank. The execution strategy will be structured to

prevent slowing construction in these areas.

The foundation types for equipment, buildings, and pipe racks have yet to be determined and will be

described in a subsequent version of Resource Report 1. Pipe installation on the pipe racks will be

implemented from multiple directions after installation of the pipe racks. Pipe spool fabrication will be

done in a covered area on or off-site. Structural steel members will be prefabricated off-site and erected

upon arrival.

The majority of the straight run pipe will be field fabricated prior to placement on the pipe racks. Pipe

expansion loops will be pre-fabricated in a shop, transported to position, and then erected with the straight

run piping. Pipe will also be painted to the maximum extent at the shops, after shop welds have been


STAGE 3 PROJECT



tested in accordance with the applicable codes. Pipe spool size will be as large as can be practically

trucked to site to minimize site work and the number of deliveries.

Wherever practical, large equipment will arrive at site in preassembled packages that will facilitate final

hook-up and testing. All equipment will be designed, fabricated, and tested by highly qualified specialist

suppliers at their respective facilities, and shipped to site only after the necessary inspections and testing

have taken place and the equipment is released. The larger equipment, such as the cold boxes, acid gas

absorber, and the refrigerant compressors, will be offloaded at the Corpus Christi Liquefaction

construction dock on multi-wheel transport crawlers, and transported to their foundations. Other material

and equipment will be delivered to site by truck.

When construction is approximately 70% complete, the focus will shift from construction by area to

completion by systems. The civil and structural work will be substantially complete, the equipment set,

and most of the large bore piping installed. The Project schedule will be driven by the mechanical

completion and pre-commissioning requirements. The system completion and turnover packages will be

defined and scoped by engineering, and assembled by the construction team. A turnover coordinator will

prepare the systems completion and turnover packages which will include the following documentation:

Marked-up drawings to show the limit of the system and the location of blinds;

Line list by system with pressure testing documentation;

List of equipment including motors with data sheets and inspection reports;

Marked-up Single Line Diagrams with inspection/test reports for electrical equipment;

Cable reports;

Instrument Index with data sheets and calibration sheets;

Loop Diagrams;

Any applicable vendor documentation/drawings;

Turnover Exception Lists; and

Detailed punchlist.

As the piping installation, hydrostatic testing, pneumatic testing, and equipment erection work is

completed and the density of craft personnel and construction equipment is reduced within each of the

areas, the balance of the painting and insulation work will be completed. The pipe racks will be

completed first followed by the process and utility areas. After the installation of the equipment and

piping has been completed, the final road paving, site grading, landscaping and cleanup will be done. The

temporary construction facilities will be demobilized on a progressive basis when they are no longer

needed.

Construction of other necessary facilities and other buildings, as well as foundations and major utility

equipment will commence once construction of the LNG Trains has begun. Emphasis will be placed on

coordinating the arrival of the major equipment with the completion and curing of the respective


STAGE 3 PROJECT



foundation so that the equipment can be placed on its foundation when it arrives. This will avoid double

handling and intermediate storage on site.

The buildings are independent sites and will be constructed simultaneously with the liquefaction facilities,

so that electrical and instrument contractors can install their equipment according to their respective

schedules.

1.7.1.3 LNG Storage

Construction of the LNG storage tank will follow the sequence shown in a figure included to be included

in Appendix 1A.

1.7.1.4 Site Access and Traffic

Construction traffic will access the site via U.S. Highway 181. Once at the site, construction traffic will

utilize La Quinta Road, which parallels the western boundary of the property. Material deliveries to the

site will be via truck using the same access point as construction traffic. Heavy material delivery will

occur via barge to the on-site construction dock. Additional information on construction traffic and

material deliveries will be provided in Resource Report 5.


All Stage 3 Pipeline facilities will be sited, constructed, operated, and maintained in accordance with all

applicable federal and state regulations and industry standards. The following sections identify the general

construction procedures for routine pipeline construction, as well as the specialized construction

techniques that will be utilized in environmentally sensitive areas.

1.7.2.1 Standard Construction and Restoration Techniques

The following sections identify the general construction procedures for routine pipeline construction.

Right-of-Way Survey

Prior to the start of construction, land surveys will be conducted and the Stage 3 Pipeline centerline and

the boundaries of the construction workspace will be marked with stakes. Existing utility lines and other

sensitive resources, identified in landowner easement agreements or by federal/state/local agencies, will

be located and marked to prevent accidental damage during Pipeline construction. Prior to construction,

CCPL’s contractors will contact the “Call Before You Dig” or “One Call” system to verify and mark all

utilities along the Pipeline workspaces to minimize the potential for damage to other buried facilities in

the area.

Vegetation Clearing

Clearing operations will include the removal of vegetation within the Stage 3 Pipeline right-of-way and

the temporary construction workspace by mechanical or hand cutting. The limits of clearing will be

identified and marked as part of the right-of-way survey activities described above.


STAGE 3 PROJECT



Workspace Grading

The entire width of the construction right-of-way, including the temporary construction workspace, may

be rough graded as necessary to allow for the safe passage of equipment and to prepare the work surface

for Stage 3 Pipeline installation activities. Typically, the grading of the right-of-way will be completed

with bulldozers.

Topsoil segregation methods will be used in agricultural areas (there are no residential areas along the

route), unless otherwise approved in writing by the landowner prior to the start of grading activities.

Topsoil will be stripped and stockpiled along the right-of-way from either the full work area or the ditch

plus spoil area through agricultural lands. The topsoil will remain segregated to prevent mixing with the

subsoil during construction activities. Topsoil may be replaced with appropriate imported material, as

necessary.

Trench Excavation

A trench will be excavated to the appropriate depth to allow for the burial of the pipe with a minimum of

three feet of cover as required by 49 CFR Part 192 of the U.S. Department of Transportation’s

(“USDOT”) regulations. The trench will be dug with an excavator or ditching machine and the excavated

material will be placed next to the trench within the construction right-of-way.

If it becomes necessary to remove water from the trench, it will be pumped to a well-vegetated upland

area (where practical) off the right-of-way and/or filtered through a filter bag or siltation barrier.

Stringing

Following excavation of the trench, stringing of the Pipeline along the trench will proceed. Stringing

involves hauling the pipe sections to the right-of-way via truck from the pipe storage yard and then off-

loading the pipe and placing the sections next to the trench using a sideboom tractor or vacuum hoe. The

pipe joints will then be lined up end-to-end to allow for welding into continuous lengths known as strings.

Bending

Following stringing, the pipe sections will be bent as necessary so that they fit the horizontal and vertical

contours. A Bending Engineer will survey the trench to determine the location and amount of each field

bend and then the appropriate bends will be made with a hydraulic pipe-bending machine.

Welding

All welding will be performed in accordance with API Standard No. 1104. Individual pipe sections will

be welded in two steps. A front-end welding crew will perform the first step, which will be to clean and

align the pipe bevels in preparation for welding and to place at least the first two passes in the welding

process. Back-end welders will perform the second step, which will be to complete the welds started by

the front-end welders. The pipe will be welded into long strings to minimize the number of welds that

have to be made in the trench (tie-in welds). Gaps in the welding process will often be left at


STAGE 3 PROJECT



waterbody/wetland crossings, road crossings, and other locations where access across the work area is

required. Automatic welding may be used on the Project.

Nondestructive Weld Inspection

Following welding, each weld will be inspected to ensure the structural integrity is consistent with

49 CFR Part 192 of the USDOT’s regulations. Radiographs or ultrasonic images will be taken and

processed on site for real-time results and those welds that do not meet the requirements established by

the API Standard 1104 will be marked for repair or replacement.

Weld Repair

The construction contractor may have a separate weld repair crew to follow the welding inspection crew

to make any necessary weld repairs. All repaired and replaced welds will be inspected to ensure proper

repair and integrity.

Coating Inspection and Repair

The pipe lengths will be coated (usually with a heat-applied epoxy) at a coating mill prior to being

delivered to the Project. The ends of each pipe section will be left bare to allow for welding. After welds

have been inspected and approved, the weld areas will be field coated by a coating crew. The pipe coating

will be inspected using equipment that emits an electrical charge, since pipeline coatings are electrically

insulating.

Lowering-In

Once the pipe string has been welded, coated, and inspected, the trench will be cleared of any debris and

any water will be pumped out of the trench and into a well-vegetated upland area and/or into an approved

filter bag. The pipe strings will be lowered in with sideboom tractors.

Tie-Ins

Once the pipe strings have been lowered-in, a tie-in crew will make the final welds in the trench. The

ends of each pipe string will be welded together, inspected, and coated.

Backfilling

All suitable material excavated from the trench will be replaced during backfilling. In areas where

excavated material is unsuitable for backfilling, additional fill may be brought in from off-site. The

subsoil will be placed into the trench first and then the topsoil will be spread over top. The top of the

trench may be slightly crowned, except in wetlands, to compensate for potential settling. The soil will be

inspected for compaction and scarified as necessary.

Cleaning

Following the completion of the Stage 3 Pipeline tie-ins, the Stage 3 Pipeline will be internally cleaned

with “pigs.” A manifold will be installed on one end of a long pipeline section and pigs will be propelled

by compressed air through the Pipeline and into an open pig catcher. The pigs will remove any dirt, water,


STAGE 3 PROJECT



or debris that inadvertently collected within the Pipeline during the construction process. Collections from

the pipeline produced by the cleaning procedure will be properly disposed.

Hydrostatic Testing

Following cleaning, the Stage 3 Pipeline will be pressure tested to ensure its integrity for the intended

service and operating pressure. Water will be used to hydrostatically test the Stage 3 Pipeline and the

water is normally obtained from water sources crossed by the Stage 3 Pipeline, including available

municipal supply lines. The water will be pumped from the water source into the Stage 3 Pipeline and

will propel a pig through the Stage 3 Pipeline in a manner that fills the Stage 3 Pipeline with water. A

high pressure pump will be used to add water to the test section and to increase the test pressure. At the

completion of the hydrostatic test, the pressure will be removed from the test section by propelling the pig

with air and dewatering the pipe. Additional “drying” pig runs will be made, as necessary, to remove any

residual water from the Pipeline.

Restoration and Revegetation

A cleanup crew will complete the restoration and revegetation of the right-of-way and temporary

construction workspace. Every effort will be made, weather and soil conditions permitting, to complete

final cleanup and installation of permanent erosion control measures within 20 days after the trench is

backfilled. The right-of-way will be fine-graded to prepare for restoration. If needed, permanent slope

breakers or diversion berms will be constructed and maintained in accordance with the Plan and

Procedures. Fences will be restored or repaired as necessary.

Revegetation will be completed in accordance with the permit requirements and any written

recommendations on seeding mixes, rates, and dates obtained from the local soil conservation district

and/or resource agencies. The right-of-way will be seeded within six working days following final

grading, weather and soil conditions permitting, or according to recommendations from the local soil

conservation district. Alternative seed mixes specifically requested by a landowner may be used.

1.7.2.2 Waterbody Construction Methods

To minimize potential impacts, waterbodies will be crossed in accordance with the FERC’s Procedures

and the crossings will be completed as quickly and safely as possible. Initial evaluation has identified that

some areas may be crossed by horizontal directional drill (“HDD”) (see Section 1.7.2.3); however,

waterbodies will generally be crossed using conventional excavator-type equipment and wet-crossing

techniques, or by horizontal bore. Upland and agricultural swales, ditches, and other such conveyances

will be crossed using either a wet-crossing technique if water is flowing at the time of crossing or best

management practices as determined by the EI if there is no flow at the time of crossing. Proposed

waterbody crossing methods will be described in Resource Report 2.

Except where reasonable alternative access is available, temporary construction equipment crossings will

be installed across waterbodies to gain access along the right-of-way for construction. After equipment

crossings are established, construction equipment will not be permitted to drive through a waterbody for


STAGE 3 PROJECT



access and the equipment crossings will be removed once access in the area is no longer needed. Only the

equipment necessary to construct the crossing and install the pipe will be allowed to work in the

waterbody.

To facilitate pipeline construction across waterbodies, ATWS may be needed adjacent to waterbodies to

assemble and fabricate the pipe necessary to complete the crossings. The ATWS will be located at least

50 feet away from the waterbody, except in actively cultivated or rotated croplands or other disturbed

areas. In areas where the ATWS is required to be set back from the waterbody, vegetation will not be

cleared between the ATWS area and the waterbody.

Following installation, a minimum of three feet of cover will be placed over the Stage 3 Pipeline.

Waterbody bed and bank contours will be restored to pre-construction conditions and the banks will be

stabilized as soon as possible following construction activities. Permanent erosion control structures will

be installed in accordance with the FERC Plan and Procedures, and temporary erosion control measures

will be maintained to minimize erosion. Following construction, waterbody crossings will be inspected

regularly to ensure that temporary erosion controls are functioning properly and that revegetation is

progressing satisfactorily.

1.7.2.3 Horizontal Directional Drill

HDD is a pipeline construction method that avoids or minimizes impact to the ground surface by drilling

a hole and pulling the pipeline through it rather than digging a trench. HDD requires the drilling of a

small diameter hole, or pilot hole, along a predetermined design path that originates and terminates on the

surface. The pilot hole is then enlarged sufficiently to accommodate the pipeline to be installed. The

pipeline may or may not be installed concurrently with the hole enlargement depending upon the final

diameter of the enlarged hole and the soil conditions encountered. Because the entry and exit angles are

relatively shallow, HDD pipe installations are relatively long and expensive compared to conventional

boring.

CCPL is currently evaluating the use of HDD methodology and information on this evaluation will be

provided in a subsequent version of Resource Report 1.

1.7.2.4 Rugged Topography

No areas of rugged topography will be crossed by the Stage 3 Pipeline. The topography of the Project

area consists of coastal plains.

1.7.2.5 Residential Areas

There are no residences within 50 feet of the construction work area.

1.7.2.6 Active Cropland

In accordance with the FERC Plan, topsoil will be segregated in actively cultivated or rotated agricultural

lands, pastures, and hayfields, unless otherwise approved in writing from the landowner prior to the


STAGE 3 PROJECT



commencement of grading activities. After the Stage 3 Pipeline has been lowered into the ditch, the

subsoil will be used for backfilling and the topsoil will then be spread across the graded right-of-way. The

Stage 3 Pipeline will be installed with a minimum of three feet of soil cover. In active cropland areas the

depth of cover will be a minimum of four feet. Soil compaction will be treated, as necessary, in

accordance with FERC’s Plan.

Prior to construction, CCPL will work with the affected landowners to identify any drain tiles within the

construction workspace. Any drain tiles damaged during construction will be repaired to landowner

specifications or to pre-construction condition. At this time, CCPL is not aware of any existing drain tiles

along the proposed Pipeline route.

1.7.2.7 Road Crossings

All road crossings will be open-cut, bored, or installed by HDD, depending upon site-specific conditions

and state and local statutes. Prior to construction, the “Call Before You Dig” or “One Call” system will be

contacted to verify and mark all utilities along the Project workspace areas. Where there is a question as

to the location of utilities, such as, water, cable, gas, and sewer lines, they will be located by field

instrumentation and test pits.

Generally, boring will be required under paved roadways. Boring entails drilling a hole below the

roadways through which the pipe will pass. First, a bore pit is dug on one side of the roadway and a

receiving pit dug on the other. The bore pit is excavated to a depth equal to the depth of the ditch and is

graded such that the bore will follow the grade of the pipe. A boring machine is lowered to the bottom of

the bore pit and placed on supports. The machine cuts a shaft under the roadway or canal using a cutting

head mounted on an auger. The auger rotates in a casing, both of which are pushed forward as the hole is

cut. The pipeline is then pushed through the casing.

During the open-cut method of roadway crossing, at least one lane of traffic is typically kept open when

constructing on or across residential streets. During the brief period when a road is completely cut, steel

plates will be available on-site to cover the trench to permit travel by emergency vehicles. Traffic lanes

and home access will be maintained except for the temporary periods essential for installing the Stage 3

Pipeline.

1.7.2.8 Blasting

No blasting is anticipated for construction of the Stage 3 Pipeline facilities.

1.8 OPERATIONS AND MAINTENANCE

1.8.1 Stage 3 Project LNG Facilities

All permanent personnel will be trained in LNG safety, cryogenic operations, and the proper operation of

all equipment. Operators will meet all the training requirements of the USDOT minimum federal safety

standards specified in 49 CFR Parts 192 and 193. Safety procedures will be discussed further in Resource

Report 11.


STAGE 3 PROJECT



Operating procedures will be the same as those developed for the Liquefaction Project. Extensive training

will be provided for operational personnel to ensure that they are familiar with and understand the

importance of adherence to safe procedures. These procedures will provide functional requirements for

the control and safeguarding systems, to include addressing safe start-up, normal shutdowns, emergency

shutdowns, fire, gas and spills, etc., as well as routine operation and monitoring.

A security guardhouse will be located at the facility entrance and continuously staffed 24-hours a day,

seven days a week.

Facility maintenance will be conducted in accordance with 49 CFR Part 193, Subpart G. The full-time

plant maintenance staff will conduct routine maintenance and minor overhauls. Major overhauls and other

major maintenance will be handled by soliciting the services of trained contract personnel to perform the

maintenance. All scheduled and unscheduled maintenance will be entered into a computerized

maintenance management system (“CMMS”). All personnel, operations, maintenance, and others will be

trained on the use of CMMS. The CMMS will print out work orders every morning. These work orders

will be distributed to the maintenance personnel during morning meetings.

Scheduled maintenance, such as preventive and predictive maintenance of equipment, will be input into

the system to automatically print out work orders either on a time basis or on hours of operation,

depending on the requirement. Scheduled maintenance will be performed on safety and environmental

equipment, instrumentation, and any other equipment that requires maintenance on a routine basis. When

a problem is detected that requires unscheduled maintenance attention, the person that detects the problem

will enter it into the CMMS. If a problem requires immediate attention, the appropriate person will be

notified.

The normal flow of maintenance orders will be as follows:

Scheduled preventative and predictive maintenance will be input to the CMMS upon installation

of each piece of equipment and once placed in-service;

Unscheduled maintenance will be input to the CMMS when a problem is detected;

CMMS will print out work orders every morning;

The work orders will be distributed to the appropriate maintenance personnel in their morning

meetings; and

The person that completes the maintenance work will close out the work order on the CMMS.

1.8.2 Pipeline

CCPL will operate and maintain the proposed facilities in accordance with the applicable safety standards

established by the USDOT (49 CFR Part 192). The standards imposed are in accordance with the Natural

Gas Pipeline Safety Act of 1968, as amended.


STAGE 3 PROJECT



The Stage 3 Pipeline will be patrolled on a routine basis, and personnel well qualified to perform both

emergency and routine maintenance on interstate natural gas pipeline facilities will handle all

maintenance.

The proposed facilities will be operated and maintained in a manner such that pipeline integrity is

maintained in the interest of assuring that a safe, continuous supply of natural gas reaches its ultimate

destination. Maintenance activities will include regularly scheduled gas leak surveys and measures

necessary to repair any potential leaks. The latter may include repair or replacement of pipe segments. All

fence posts, signs, marker posts, aerial markers, and decals will be painted or replaced to ensure that the

pipeline locations will be visible from the air and ground. All valves will be periodically inspected and

greased.

The Stage 3 Pipeline will be patrolled from the air on a periodic basis. This will provide information on

possible leaks, construction activities, erosion, exposed pipe, population density, possible encroachment

and other potential problems that may affect the safety and operation of the Stage 3 Pipeline.

Other maintenance functions will include: (1) periodic seasonal mowing of the permanent easement in

accordance with the vegetative maintenance restrictions outlined in the FERC’s Plan and Procedures,

(2) terrace repair, backfill replacement, and (3) periodic inspection of water crossings. During pipeline

easement maintenance, CCPL will not use herbicides or pesticides within 100 feet of a wetland or

waterbody unless approved by appropriate state and local agencies.

Cathodic protection units installed along the pipeline will be regularly monitored to maintain required

pipe-to-soil potential. This will be achieved in accordance with the specifications set forth by CCPL that

meet or exceed USDOT regulations.

1.9 FUTURE PLANS AND ABANDONMENT

1.9.1 Future Plans

CCL and CCPL have no plans for further expansion beyond the Project. To the extent that consideration

for expansion of the facilities becomes warranted in response to additional demand for liquefaction or

vaporization services, any new facilities would be designed to be compatible with the proposed facilities

and all necessary permits and approvals would be obtained for those new facilities.

1.9.2 Abandonment of Facilities

No facilities are proposed for abandonment or removal at this time.

1.10 PERMITS AND APPROVALS

CCL and CCPL will obtain all necessary permits, clearances, and licenses relating to the construction and

operation of the Project. Table 1.10-1 provides a list of permits that CCL and CCPL will obtain for the

Project. CCL and CCPL will file any additional correspondence and approvals with the FERC upon

receipt.


STAGE 3 PROJECT



CCL and CCPL will include copies of all relevant environmental permits and approvals in the

construction bid packages and contracts. Construction contractor(s) employed on the Project will be

required to be familiar with all Project permits and licenses and comply with all federal, state, and local

laws, ordinances, and regulations that apply to construction of the facility and to restoration of any areas

temporarily disturbed during construction. Should other safety, design, and construction codes and

regulations be enacted or adopted by governmental agencies having jurisdiction over the locations where

the work is to be performed, the contractor(s) will be required to observe and abide by all provisions that

are applicable.

TABLE 1.10-1

Permits and Consultations for the Stage 3 Project

Agency and Agency Contact

Permit/Approval/Consultation Anticipated Submittal

Anticipated Receipt

U.S. Fish & Wildlife Service

Section 7 Endangered Species Act Consultation/Clearance; Migratory bird consultation; Fish and Wildlife Coordination Act

Initiated 2nd

Quarter 2015

4th

Quarter 2015

USACE Clean Water Act Section 404 Permit Amendment January 2016 3rd

Quarter 2016

NOAA Fisheries Essential Fish Habitat; Endangered Species Act Aquatic Threatened and Endangered Species; Marine Mammal Protection Act; Fish and Wildlife Coordination Act

Initiated 2nd

Quarter 2015

4th

Quarter 2015

USCG Waterway Suitability Assessment Initiated 2nd

Quarter 2015

1st Quarter 2016

U.S. Environmental Protection Agency

NPDES Industrial Water Discharge; Hydrostatic Test Water Discharge

January 2016 3rd

Quarter 2016

U.S. Department of Energy

Authorization to Export LNG Initiated 2nd

Quarter 2015

1st Quarter 2016 for FTA nations; 2

nd

Quarter 2017 for non-FTA

nations

Federal Aviation Administration

Determination of No Hazard to Air Navigation (14 CFR Part 77)

January 2016 April 2016

Railroad Commission of Texas

Water Quality Certification under Section 401; Hydrostatic Test Water Discharge Permit; Coastal Zone Consistency Determination

January 2016 3rd

Quarter 2016

Texas Commission on Environmental Quality

Air Permits for CCL Terminal (Title V & PSD) and Sinton Compressor Station (minor permit)

November 2015

3rd

Quarter 2016

Texas Parks and Wildlife Department

State threatened and endangered species review Initiated 2nd

Quarter 2015

4th

Quarter 2015

Texas Historical Commission

Section 106 National Historic Preservation Act Consultation, Clearance

Initiated 2nd

Quarter 2015

4th

Quarter 2015


STAGE 3 PROJECT



1.11 AFFECTED LANDOWNERS

There are six landowners adjacent to, and within 0.5 mile of, the proposed Stage 3 Liquefaction Facilities,

all of which are commercial and/or industrial facilities: Port of Corpus Christi Authority (“POCCA”),

Sherwin Alumina, Voestalpine Texas, Bradleys, Inc., TPCO America, and Alcoa. There are numerous

other landowners directly crossed by and adjacent to the proposed Stage 3 Pipeline and within 0.5 mile of

the Sinton Compressor Station site. Names and addresses of these landowners are provided in Appendix

1B, as required in 18 CFR §157.6(d) of the FERC’s regulations. Further, in accordance with 18 CFR

§157.21(f) (3) and 18 CFR §157.6(d) (2), CCL and CCPL have contacted each of these entities and

individuals regarding the Project.

1.12 NONJURISDICTIONAL FACILITIES

1.12.1 Identified Nonjurisdictional Facilities

Terminal

An electrical power line will be installed between a substation currently being constructed by American

Electric Power (“AEP”) (approximately 500 feet to the west of the Stage 3 LNG Facilities) and the

proposed Stage 3 LNG Facilities. Coordination with AEP regarding installation of the new power line is

ongoing. Additional detail regarding the installation of this project feature will be provided in a

subsequent version of Resource Report 1.

A water line will be installed to the by the San Patricio County Municipal Water District to the Stage 3

LNG Facilities. The water line will be designed, built, owned, and operated by the San Patricio County

Municipal Water District and CCL will not determine the route or location of the water line.

Pipeline

High voltage power lines are located approximately 500 feet to the northwest of the Sinton Compressor

Station. An electrical power line extension and a substation will be required for operation of the new

electric-driven compression at the Sinton Compressor Station. CCPL is in discussions with AEP

regarding bringing the necessary power to the Sinton Compressor Station. The power line and substation

would be designed, built, owned, and operated by AEP.

1.12.2 Determination of the Need for FERC to Conduct an Environmental Review

Under certain circumstances, nonjurisdictional facilities may be subject to FERC’s environmental review.

In making this determination, FERC requires applicants to address four factors that indicate the need for

the FERC to do an environmental review of project-related nonjurisdictional facilities. These factors are:

(1) Whether or not the regulated activity comprises “merely a link” in a corridor type project

(such as a transportation or utility transmission project);

(2) Whether there are aspects of the nonjurisdictional facility in the immediate vicinity of the

regulated activity which affect the location and configuration of the regulated activity;


STAGE 3 PROJECT



(3) The extent to which the entire project will be within FERC’s jurisdiction; and

(4) The extent of cumulative federal control and responsibility.

The application of this procedure to the nonjurisdictional facilities follows:

With respect to factor (1), the regulated activities are not a corridor-type project or a link in a

corridor type project. Therefore, this factor does not support a review of the nonjurisdictional

facilities.

With respect to factor (2), there are no aspects of the nonjurisdictional facilities that affect the

location and configuration of the proposed Stage 3 Project. Therefore, this factor does not support

a review of the nonjurisdictional facilities.

With respect to factor (3), the nonjurisdictional facilities are entirely outside of the FERC’s

jurisdiction as the construction of these facilities is under the jurisdiction of the State of Texas

regulatory agencies. This factor weighs against inclusion of the nonjurisdictional facility in a

review by FERC.

With respect to factor (4), the cumulative level of federal control and responsibility over the

project, federal control is determined by the amount of federal financing, assistance, direction,

regulation, or approval inherent in a project. The nonjurisdictional facilities will be developed by

private entities, and no federal financing or guarantees will be granted for construction of these

facilities. Some federal permits may be involved, but no federal lands are involved. Therefore,

cumulative federal control is minimal and this factor does counsel FERC environmental review.

1.13 CUMULATIVE EFFECTS

The Council on Environmental Quality (“CEQ”) regulations that implement the National Environmental

Policy Act define cumulative effects as “the impact on the environment which results from the

incremental consequences of an action when added to other past, present, and reasonably foreseeable

future actions, regardless of what agency or person undertakes such other actions” (40 CFR 1508.7).

Cumulative effects include both direct and indirect effects that would result from the proposed Project, as

well as the effects from other projects (past, present, and reasonably foreseeable future actions) not

related to or caused by the Project. Cumulative impacts may result when the environmental effects

associated with a proposed Project are added to temporary (construction-related) or permanent

(operations-related) impacts associated with other past, present, or reasonably foreseeable future projects.

Although the individual impact of each separate project might not be significant, the additive or

synergistic effects of multiple projects could be significant. The cumulative effects analysis evaluates the

magnitude of cumulative effects on natural resources such as wetlands, water quality, floodplains, and

threatened and endangered species, as well as cumulative effects on land use, socioeconomics, air quality,

noise, and cultural resources. CEQ regulations (40 CFR 1508.8) also require that the cumulative effects

analysis consider the indirect effects which are caused by the action and are later in time or farther

removed in distance, but are still reasonably foreseeable.


STAGE 3 PROJECT



The purpose of the cumulative impacts analysis is to identify and describe cumulative impacts that would

potentially result from implementation of the Project. Inclusion of actions within the analysis is based on

identifying commonalities of impacts from other actions to potential impacts that would result from the

Project. In order to avoid unnecessary discussions of insignificant impacts and projects and to adequately

address and accomplish the purposes of this analysis, the cumulative impacts analysis for the proposed

Project will be conducted using the following guidelines:

A project must impact a resource category potentially affected by the proposed Project. For the

most part, these projects are located in the same general area that would be directly affected by

construction of the proposed Project. The effects of more distant projects are in most cases not

assessed, because their impacts would tend to be localized and not contribute significantly to the

impacts of the proposed project. Potential cumulative impacts on air quality and watersheds,

however, were considered on a broader, more regional basis.

The distance into the past and future which other projects could potentially cumulatively impact

the area of the proposed Project was based on whether the impacts are short-term, long-term, or

permanent. Most of the impacts related to the other proposed projects would occur during the

construction phase, and would be short-term impacts. Timing will be evaluated based

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